1 

Chapter 4: Impacts on Cost of Renewable Fuels, 

Gasoline, and Diesel 

4.1 Renewable Fuel Production Costs 

4.1.1 Ethanol Production Costs 

4.1.1.1 Corn Ethanol 

 Corn ethanol costs for our work were estimated using a model developed by USDA that 

was documented in a peer-reviewed journal paper on cost modeling of the dry-grind corn ethanol 

process.i The USDA model considers a 40 MMgal/yr corn plant producing ethanol with a 

primary co-product of distillers dried grains with solubles (DDGS). The ethanol yield used in 

the model is 2.76 gallons per bushel with 2.0% gasoline denaturant. The model is based on work 

done in chemical process simulation software to generate equipment sizes, stream flowrates, and 

material and energy balances. These results can then be put together with feedstock, energy, and 

equipment cost information in a spreadsheet format to generate a per-gallon cost estimate. 

 For our primary case scenario, we used corn prices of $3.60/bu in 2022 with 

corresponding DDGS prices of $124.74/ton (all 2007$). These estimates are taken from 

agricultural economics modeling work done for this proposal using the Forestry and Agricultural 

Sector Optimization Model. Energy prices also play a significant role in the cost of ethanol 

production. For this we relied on the AEO 2009 report for projections of energy costs in 2022 

and intermediate years of interest. According to the AEO 2009 updated report the relevant costs 

are as follows: $7.75 per MMBTU natural gas, $2.57 per MMBTU coal, $30.32 per MMBTU 

gasoline (~$3.49 per gallon), and $19.31 per MMBTU electricity ($0.066 per kWh). All of these 

prices are in 2007 dollars. 

Using the USDA models and the feedstock and energy prices mentioned above we were 

able to generate a per gallon cost of ethanol production from a dry mill plant that produces dry 

DGS, uses natural gas as it’s primary fuel source, and utilized no advanced technologies. We 

did, however, assume that by 2022 the combination of process improvements and more efficient 

boilers and motors allow the plant described here to produce ethanol with an energy input of 

28,660 BTU natural gas per gallon and 2,251 BTU of electricity per gallon. These energy use 

values are described in more detail in Section 1.5.1.3. The only modification that was made to 

the USDA model, other than updating the energy and feedstock costs in line with our 2022 

projections, was to change the energy demand of the plant to match our projections1

. The 

projected cost of ethanol production from this modified USDA model was $1.63 per gallon. For 

this scenario corn feedstock minus DDGS sale credit represents about 54% of the final per-gallon 

cost, while utilities, facility, chemical and enzymes, and labor comprise about 22%, 13%, 7%, 

and 4%, respectively. Figure 4.1-1 shows the cost breakdown for production of a gallon of 

ethanol. Note that this production model does not account for the cost to ship the DDGS. Those 

 

1

 An Excel spreadsheet showing a summary of the outputs of this model and the modifications that were made has 

been placed in the docket (EPA-HQ-OAR-2005-0161- 2726). 
costs are external and are expected to increase the price of DDGS the further an end user is 

located from the plant. While we do not expect this to be the average cost of ethanol production 

in 2022 it serves as a baseline cost to which the cost impacts of different types of fuel used for 

primary process energy, new technologies, and DGS drying will be applied below. 

Figure 4.1-1. 

Cost Breakdown of Natural Gas Dry Mill Corn Ethanol Production (2007$). 

 The price of energy can vary greatly depending on the source of the energy. We expect, 

therefore, that the cost of ethanol production would also vary depending on whether the 

production facility uses natural gas, coal, or biomass as its primary thermal energy source. In 

order to determine the impact that different fuel sources had on the cost of ethanol production in 

2022 we first had to project how much of the corn ethanol industry will use each fuel type in 

2022. For these projections we relied on our own current industry characterization as well as 

projections made by Steffen Mueller of the University of Illinois at Chicago. The resulting mix 

of primary fuel type used in the corn ethanol industry is shown in Table 4.1-1 below. 
3 

Table 4.1-1. 

Breakdown of fuel types used in estimating production cost of corn ethanol 

 Fuel Type Total by Plant Type 

Plant Type Biomass Coal Natural Gas Biogas All Fuels 

Coal/Biomass Boiler 11% 0% - - 11% 

Coal/Biomass Boiler + 

CHP 

10% 4% - - 14% 

Natural Gas Boiler - - 49% 14% 63% 

Natural Gas Boiler + 

CHP 

- - 12% - 12% 

Total by Fuel Type 21% 4% 61% 14% 100% 

To determine per-gallon cost impact of coal, biomass, and biogas as a process energy 

source we relied on the modeling work done by the USDA. The USDA modeled dry mill corn 

ethanol plants using both natural gas and coal as a primary energy source. Their models take 

into account the differences in capital costs that result from the differences in materials handling 

and boiler types necessary to use gaseous and solid fuels. We assumed that on average, coal and 

biomass combustion systems would have the same capital cost due to similarities in feed, ash 

handling, and emission controls; the same argument can be made for use of biogas combustion 

relative to natural gas combustion (excluding the digesters or other source). Tables 4.1-2 shows 

the impact that different primary fuel sources has on the overall cost per gallon of corn ethanol 

production. The overall impact of using different fuel types is very small, less than $0.01 per 

gallon. Thus, a change in process fuel type has very little impact on the projected future cost of 

corn ethanol. 

Table 4.1-2. 

Breakdown of cost impacts by fuel type used in estimating production cost of corn ethanol 

 Fuel Type Total by Plant 

Type 

Plant Type Biomass a Coal Natural Gas Biogas b All Fuels 

Coal/Biomass Boiler +$0.009 +$0.009 - - - 

Coal/Biomass Boiler + 

CHP 

-$0.021 -$0.021 - - - 

Natural Gas Boiler - - baseline +$0.00 - 

Natural Gas Boiler + 

CHP 

- - -$0.032 - - 

Total by Fuel Type - - - - $-0.006 

Table 4.1-2 shows that for our cost analysis we made the assumption that biomass firing 

has the same overall cost impact on ethanol production as coal firing. One reason for this is that 

our analysis of biomass feedstock costs suggests a range of $72 per ton in future years which is 

comparable to the cost of coal supplied to non-electric-power industries after transportation is 

included.ii Wood and stover biomass has on average approximately 85% of the energy content 

of coal on a mass basis, varying by type of biomass and coal, again suggesting that they are 

comparable on an energy per mass basis.iii Nevertheless, we still project that biomass will 

displace some coal in the future. If biomass transportation and storage costs are small it is 
plausible that some ethanol producers near biomass sources (such as the Midwest and Southeast) 

may have a cost incentive to transition from coal to biomass for process heat. In addition, 

ethanol plant owners may want to improve their greenhouse gas performance to increase 

capacity. 

 Similarly, for our cost analysis we made the assumption that biogas combustion for 

process heat would have the same cost impact on ethanol production as natural gas combustion. 

Use of biogas is somewhat different from biomass in that it would require some capital 

investment for on-site anaerobic digesters and related feedstock and gas handling equipment. 

However, we anticipate the digester feedstock itself would have very low or no cost, thus it is 

reasonable to assume that the ongoing operating costs besides capital would be considerably less 

than purchasing natural gas. As with biomass combustion, most plants utilizing biogas would 

take advantage of situations such as co-location with feedlots or MSW facilities where suitable 

biomass resources are available. 

Another factor that we expect to have a significant impact on the cost of ethanol 

production in 2022 is the development and adoption of new technologies. There are several new 

technologies currently available or under development that reduce the energy requirements of 

ethanol production facilities. These include more efficient boilers, motors and turbines, raw 

starch hydrolysis, corn fractionation, corn oil extraction, and ethanol membrane dehydration. 

These technologies, and their impact on the projected average energy usage of an ethanol plant in 

2022, are discussed in section 1.5.1.3. In addition to reducing cost by decreasing an ethanol 

plant’s energy demand, two of these technologies, corn fractionation and corn oil extraction, 

produce new co-product streams that also have an impact on the cost of ethanol production. We 

have adjusted the USDA cost model to reflect the impact that reduced energy usage of ethanol 

plants in 2022 and new co-products have on the average cost of ethanol production2

. The impact 

of these technologies is outlined in Tables 4.1-3 and 4.1-4 below. 

Table 4.1-3. 

New Technology Impacts on Corn Ethanol Cost 

 Capital Cost 

(40MMGY) 

Capital Charge 

(per gallon) 

Operating 

cost change 

New coproduct profit Additional 

Profit 

More Efficient 

Boilers, etc. 

None (included 

in baseline) 

N/A N/A N/A $0.00 

Raw Starch 

Hydrolysis 

$0 $0.00 -$0.066 N/A $0.066 

Corn 

Fractionation 

$14,000,000 $0.016 -$0.003 $0.106 $0.093 

Corn Oil 

Extraction 

$5,100,000 $0.019 -$0.037 $0.060 $0.079 

Membrane 

Separation 

$1,500,000 $0.006 -$0.070 N/A $0.064 

 

2

 As an example, the spreadsheet with adjusted values for corn oil extraction has been placed in the docket (EPAHQ-OAR-2005-0161-2727). 
5 

Table 4.1-4. 

Breakdown of cost impacts by technology for estimating production cost of corn ethanol 

Technology Percent of Plants 

Adopting Technology

Cost Impact (Change 

from Baseline)

Weighted 

Cost Impact 

More Efficient 

Boilers/Motors/Turbines 

100% Included in Baseline $0.00 

Raw Starch Hydrolysis 22% -$0.066 -$0.015 

Corn Fractionation 20% -$0.093 -$0.019 

Corn Oil Extraction 70% -$0.079 -$0.055 

Membrane Separation 5% -$0.064 -$0.003 

Total N/A N/A -$0.092 

Whether or not the distillers grains and solubles (DGS) are dried also has an impact on the 

cost of ethanol production. Drying the DGS is an energy intensive process and results in a 

significant increase energy usages as well as cost. The advantages of dry DGS are reduced 

transportation costs and a product that is less susceptible to spoilage, and can therefore be sold to a 

much wider market. If the DGS can be sold wet, the cost of ethanol production can be reduced by 

$0.083 per gallon. A 2007 survey of ethanol producers indicated that 37% of DGS were being sold 

wet. We anticipate that this percentage of wet DGS will remain constant in 2022. The net cost 

impact of selling 37% of the DGS wet is an average cost reduction of $0.031 per gallon. 

 

 The effect of plant scaling on production cost can be estimated by applying an 

engineering scaling factor to all plant equipment. In past rulemakings involving modifications to 

refineries we have used a material scaling factor of 0.65. This factor is applied as an exponent to 

the ratio of the new size to the original size, the result of which is then multiplied by the original 

capital cost. The fact that this figure is less than 1.0 reflects the per-unit or per-gallon savings 

that is often realized when processes are scaled up. However, there is information suggesting 

that a general factor may be considerably higher for ethanol plants. A factor of 0.84 was put 

forth in a recent publication on dry mill ethanol production.iv Using this larger factor, we find 

that the change in per-gallon production cost due to economies of scale is very small over the 

range of typical plant sizes, on the order of $0.02 between 40 and 100 MMgal/yr. Thus, in 

computing production costs for this rulemaking we chose to ignore effects of any changes 

average plant size. 

In order to generate a cost estimate for the production of corn ethanol in the year 2022 the 

cost impact of each of these factors, primary fuel type, advanced technologies, and DGS drying, 

were applied to the baseline cost produced by the USDA model. When each of these cost 

reduction have been applied to the baseline cost, the result is a projected cost of production for 

corn ethanol of $1.50 per gallon in 2022. As with the energy and input costs, this production 

cost is also in 2007 dollars. We believe this number is an accurate projection of the cost of 

ethanol in 2022 based on the best available information. For a summary of the cost analysis, 

including the baseline cost and all the adjustments, see Table 4.1-5 below. 
Table 4.1-5 

Average Ethanol Cost of Production in 2022 

Baseline Cost of Production (Natural Gas, 

 no new technologies, 100% dry DGS) 

$1.627/gal 

Fuel Type Cost Impact -$0.006/gal 

New Technology Cost Impact -$0.092/gal 

DGS Drying Cost Impact -$0.031/gal 

Average Cost of Ethanol Production (2022) $1.499/gal 

4.1.1.2 Cellulosic Ethanol 

4.1.1.2.1 Feedstock Costs 

 In order to allow for an accurate estimate of the cost of production for cellulosic biofuels 

in 2022 we must first determine the cost of the cellulosic feedstocks. We relied on the Forest 

and Agriculture Sector Optimization Model (FASOM) to project the roadside cost of agricultural 

residues, energy crops, and wood residues for 2022. For more details on the FASOM model see 

Chapter 5 of the RIA. FASOM does not model MSW costs. We therefore relied on 

conversations with companies who intend to use MSW as a renewable fuel feedstock, as well as 

our own analysis of the necessary steps required to acquire appropriate feedstock streams from 

MSW to help inform our feedstock cost estimates. In order to validate the reasonableness of the 

FASOM cost estimates we also conducted an internal assessment of the potential agricultural 

residue, energy crop, wood residue, and MSW feedstock systems. The description of this 

analysis is discussed in Section 4.1.1.2.2. 

To each of these roadside costs we added the cost of transportation and secondary storage 

where appropriate based on our own modeling of cost of secondary storage and transportation. 

The framework of this modeling is discussed in Section 1.3.3 and a more detailed discussion of 

the assumptions and equations used in this model can be found below. Table 4.1-6 shows a 

summary of the individual roadside costs for each of the feedstock sources, as well as average 

costs for storage and transport and grinding of the materials. A weighted average cost, based on 

the percentage of the overall feedstock supply each of the categories is expected to represent 

according to the FASOM model, is also given. 
7 

Table 4.1-6 

Summary of Cellulosic Feedstock Costs 

Ag Residue Switchgrass Forest Residue MSW 

36% of Total 

Feedstock 

49% of total 

Feedstock 

1% of Total 

Feedstock 

15% of Total 

Feedstock 

Mowing, 

Raking, Baling, 

Hauling, 

Nutrients and 

Farmer 

Payment 

$34.49/ton 

Land Rent, 

Mowing, 

Raking, Baling, 

Hauling, 

Nutrients and 

Farmer 

Payment 

$40.85/ton 

Harvesting, 

Hauling to 

Forest Edge, 

$20.79/ton 

Sorting, 

Contaminant 

Removal, 

Tipping Fees 

Avoided 

$15/ton 

Hauling to Secondary Storage, Secondary Storage, Hauling to Plant 

$21.53/ton (average) 

Grinding 

$11/ton 

Total 

$67.42/ton 

Crop Residue Costs 

The FASOM agricultural econometric model described in Chapter 5 estimated the 

roadside price for corn stover, which we used to be representative of all agricultural residues. 

The FASOM model accounted for harvesting, shredding, raking, baling and hauling the corn 

stover to the farm edge, and replenishing the soil with nutrients. It predicts a roadside price of 

$34.49 per dry ton in 2022 for corn residue. In order to validate FASOM’s cost estimate we also 

performed an analysis of a possible agricultural residue harvest system. We based our analysis 

on a Purdue University study of the logistics of corn stover storage and transportation. Our 

analysis, described in Section 4.1.1.2.2, predicts a roadside cost for corn stover ranging from 

$44.97 to $46.20 per dry ton, depending on the size of the farms from which the stover is 

harvested. The FASOM cost is approximately $10 per ton lower than the price calculated in our 

analysis. While this is a significant price difference it is in the same vicinity as the FASOM 

estimate, and it is not unreasonable to expect that advances in technology and changes in 

harvesting practice for corn stover and other agricultural residues will significantly reduce the 

cost for these feedstocks. For all of the biofuel production cost analysis work, the FASOM price 

was used as the projected price of agricultural residue. To this roadside cost was added the cost 

of transportation and secondary storage as calculated by the model discussed in Section 1.3. A 

detailed description of our analysis of a likely agricultural residue harvest system using existing 

machinery can be found below. 

Energy Crops 
The FASOM model predicts a roadside cost for switchgrass and similar energy crops of 

$40.85 per dry ton in 2022. While this costs is higher than the cost of agricultural residues the 

delivered cost of energy crops is expected to be slightly lower because of the lower 

transportation and secondary storage costs associated with the higher production density of 

energy crops. The $40.85 per dry ton roadside cost has been used in our cost analysis of biofuel 

production, with appropriate transportation and storage costs added using the model described in 

Section 1.3. See Table 4.1-6 for a summary of the expected delivered costs of various 

feedstocks.Wood Residue 

The FASOM model estimates costs for two different types of wood residues, hardwood 

logging residue ($21.16 per dry ton) and softwood logging residue ($18.37 per dry ton). We 

decided to use $19.77 per dry ton, an average of these two prices, as the roadside cost of wood 

residue for our analysis of biofuel production costs. Despite the low roadside cost of wood 

residues, FASOM predicts that few biofuels production facilities (less than 1%) will use wood 

residues. We believe that the reason for this is that the high transportation costs for wood residue 

in the FASOM model cause the delivered cost of wood residue to be relatively high. The 

FASOM model allowed biofuel producers to use only one type of feedstock (wood residue, 

agricultural residue, energy crops, or MSW). Therefore, in order for a facility to use wood 

residues, the entire feedstock supply must come from wood residues. Logging operations are 

less likely to be concentrated in a small area than other potential feedstock supply systems such 

as agricultural residues or energy crops. The result is that in order to supply a 100 million gallon 

per year biofuel production plant (the size specified in the FASOM model) with sufficient 

feedstock from wood residues the residues must be transported long distances. In most cases 

these high transportation costs outweighed the low roadside costs despite the fact that no 

secondary storage will be required for wood residues. If this assumption were relaxed and the 

FASOM model allowed biofuel production facilities to use locally available wood residues in 

combination with other feedstocks such as agricultural residues, energy crops, or MSW, we 

believe that much more wood residues would be selected for biofuel production. At this point, 

however, it is not clear whether biofuel production facilities would require uniform feedstock or 

be able to process a diverse feedstock stream. This uncertainty was one of the factors in our 

decision to use the FASOM estimates for our cost analysis work. 

Municipal Solid Waste 

Unlike the other three sources of cellulosic feedstock, the FASOM model does not 

predict a roadside cost for MSW. We therefore relied on our own analysis, together with input 

from the Office of Solid Waste and conversations with companies who intend to use MSW as a 

feedstock for producing biofuels. One of the biggest costs associated with using MSW as a 

biofuel feedstock is the cost to sort the waste material. Some materials, such as metals and 

contaminated materials, must be removed so that they do not interfere with the biofuel 

production process. Other materials, such as paper or plastics, may also be separated due to their 

value as recovered materials or in order to increase the renewability content of the resulting fuel. 

The Office of Solid Waste has estimated that sorting costs will likely be $20 - $30 per ton. In 

addition to sorting costs, the biofuel producer would also have to pay for the transportation and 

disposal of unusable material. These costs may be relatively high due to the nature of this 
9 

contaminated material. Offsetting these costs would be tipping fees received by the biofuel 

producer, which we estimate would be in the $30 per ton range. 

In addition to our own analyses presented in Section 4.1.1.2.2, we also contacted companies 

that intend to use MSW as a feedstock for biofuel production. In confidential conversations 

these companies indicated that they believed that MSW would be available, at least initially, at 

close to zero net cost, after accounting for the receipt of tipping fees and the sale of recoverable 

materials. One company told us that whether the MSW was sorted or unsorted was not expected 

to make much of a difference from a cost perspective, as they expected that the higher tipping 

fees received for unsorted MSW and the money received from the sale of the recovered materials 

would pay for the cost of sorting. We believe that while these costs may be accurate, they are 

likely only representative of the cheapest and most readily available sources of MSW. It is likely 

that as more biofuel producers seek to use MSW as a feedstock, the cost of this feedstock source 

will increase. Competition from waste to energy companies may be another driver for the cost 

increase of MSW. Taking all this into account, we have conservatively estimated that the 

average cost of MSW will be $15 per dry ton in 2022. While this is an admittedly conservative 

estimate, MSW remains the cheapest source of feedstock for the production of biofuels. More 

details of our cost assessment for MSW can be found below. 

4.1.1.2.2 EPA Internal Assessment of Potential Roadside Cellulosic Feedstock Costs 

 While the FASOM model provides an estimate for the roadside costs of agricultural 

residue, energy crops, and wood residue, we were also interested in performing our own internal 

assessment of the potential roadside cost of these feedstocks. This assessment served as a second 

estimate for the costs of these feedstocks, and allowed us to verify the costs generated by 

FASOM. They also allowed us to have a better understanding of the costs of each of the steps in 

the harvest process. In each of these cases we found that our own assessments matched 

reasonably well with the roadside costs reported by FASOM. Our internal assessment of the 

roadside costs of crop residue, energy crops, wood residue, and MSW is shown in detail in the 

following sections. 

Crop Residue 

We could have used any of the crop residues as an example feedstock in the following 

discussion, since similar logistics apply to all of them. We chose to use corn stover, e.g., the 

stalks, leaves, and cobs that remain following grain harvest, since it is likely to represent a 

significant portion of cellulosic feedstocks in the future. Since there is no equipment specifically 

designed to harvest corn, the system we describe below uses combines, mowers, rakes, balers, 

and bale haulers already in use for harvesting hay or straw. Differences in stalk or stem diameter 

and density, bale density, moisture content, machine field speeds and efficiencies are a few 

things that make it relatively more difficult to harvest stover than hay or straw. One of the main 

concerns is that the density of the large stover bales, whether round or rectangular, can be as 

little as one-half that of similar dimension hay bales, which usually translates into higher 

transportation costs.v
Most biomass feedstocks must be harvested, stored, and transported to a processing 

facility before they can be converted into ethanol. At present, there are no commercial sized 

cellulosic ethanol plants in the U.S. Likewise, there are no commercially proven, fullyintegrated feedstock supply systems dedicated to providing any of the crop residues or other 

feedstocks to ethanol facilities of any size. We emphasize ‘integrated feedstock supply systems’ 

because logistically the delivery of a feedstock to a processing facility will require the planning, 

executing, and controlling of several different, closely integrated operations, e.g., feedstock 

harvesting, gathering, storing, and moving by road and rail. Apart from the large numbers and 

wide variety of equipment, these operations will require professional and technical support 

services and personnel such as office space, staff, and office equipment such as computers and 

printers. Also, engineers, light- and heavy-duty equipment operators, vehicle maintenance 

personnel and repair and storage facilities for tractors, rakes, balers, loaders, and trucks and 

trailers, as well as transportation infrastructure planning and management. 

Ordinarily, to determine the operational sufficiency and efficiency of such a system, we 

would ‘analyze’ it. We would first break it down into its component parts or essential features 

and then study them, e.g., how much they cost, and how and/or whether they operate efficiently 

within the ‘system.’ However, no such system currently exists. Therefore, we ‘synthesized’ a 

feedstock supply system in order to analyze it. We used a Purdue University, School of 

Industrial Engineering simulation study of corn stover logistics from satellite storage to an 

ethanol plant, to set up our feedstock harvesting and gathering operation. Purdue’s notional 

cellulosic ethanol plant was to be constructed next to an actual existing corn grain plant in 

northern Indiana. They used discrete event simulation software and GIS tools to study the 

transportation logistics associated with supplying the conversion facility directly from satellite 

storage. They identified 785,200 available acres out of 848,453 potential acres, on 2,052 actual 

farms, of 200-, 400-, or 800-acres, in 12 northern Indiana counties within 50-miles of the 

production facility (they disregarded fields or farms of less than 200-acres). We reproduced their 

original table as Table. 4.1-7. 

Table 4.1-7 

Feedstock Availability at Various Distances From South Bend, IN 

 Average Farm Size 

Average 200 400 800 

Distance County Actual Acres 

Cumulative 

Acres Acres 

Available 

Acres 

Cumulative 

Acres 

bales/ 

day 

bales/day 

/farm set 

12 St Joseph 69 69 74 51 35 63 63 4,956 4,956 

25 Elkhart 150 219 90 47 23 55 118 4,328 10,257 

 Marshall 110 52 41 76 194 5,928 

30 La Porte 113 332 113 73 70 108 302 8,453 8,453 

35 Starke 60 392 34 39 41 55 357 4,328 4,328 

40 Kosciusk

o 93 485 108 66 43 82 439 6,461 6,461 

45 Lagrange 132 617 53 47 20 45 485 3,560 9,049 

 Fulton 86 66 43 70 555 5,489 

50 Porter 225 842 76 59 34 66 621 5,175 18,224 

 Noble 115 47 21 59 679 4,595 

 Pulaski 39 72 64 108 787 8,453 

 842 998 619 435 787 61,726 61,728 
11 

We initially assumed that the stover had been harvested (square bales), gathered, fieldtransported, and stored at seven-satellite storage areas located near the corn fields.vi However, 

upon further study, we determined the counties that Purdue combined into each of the farm sets, 

weren’t anywhere near each other. In reality, it would have been far too costly to gather all the 

bales from the Porter, Noble, and Pulaski counties into one site, because these three counties are 

actually separated by other counties. Rather than try to construct seven satellite storage sites, we 

constructed a site at the center of each county. This was done in order to estimate the cost to 

collect the bales from all the fields in each county. We determined that the distance from the 

center of each of the Porter, Noble, and Pulaski counties, as well as the other two so-called 

farm-sets, to the ethanol plant was about equal, so regardless of whether we treat them as single 

sites, the transport costs for the bales to the ethanol plant will be the same. We ‘synthesized’ the 

feedstock system to harvest, gather, field transport, and store stover bales at the 11-notional 

satellite storage units rather than the seven farm-set units used in the Purdue transportation model 

(our study was not done in conjunction with the Purdue study; rather we used their 

information/data as the basis from which to synthesize our notional operation). The format we 

chose to analyze was to shred, rake, square-bale, gather, field-side, and then load and haul the 

bales to satellite storage; then, as needed, haul the bales to the processing plant. 

Rather than guess at how such a system should look and function, we carefully studied 

several similar systems that were put forward by various agricultural and biological experts.vii, viii, 

ix, x, xi, xii, xiii, xiv, xv We used the American Society of Agricultural and Biological Engineers 

(ASABE), 2007 Standards, Engineering Practices, and Data as the primary source for our 

equipment capital and operating cost estimates. It has a machinery management section, ASE 

EP496.3, FEB2006, devoted to providing helpful information in making management decisions 

involving machine power requirements, capacities, cost, selection, and replacement, as well 

section ASAE D497.5 FEB2006, with data which includes representative values of farm 

machinery operating parameters, to aid managers, planners, and designers in estimating the 

performance of field machines. These data are intended for use with ASAE EP496 (some data 

are also presented in equation form for easier use with computers, etc.).xvi We used these 

sections along with other examples by other experts to estimate the machinery capital and 

operating costs for our analysis.xvii, xviii, xix, xx, xxi We were able to get some machinery purchase 

prices from vendors whose identities are confidential. We reduced the equipment listed price by 

10% to determine the purchase price, a standard industry estimating practice. Otherwise, most of 

the data used to calculate machinery costs were generated with equations and appropriate data 

from the ASABE 2007 Standards. We used the equipment, list and purchase prices, along with 

their power and size estimates, with the suggested data and equations, mentioned previously, to 

calculate the lifetime hours and years, annual use, field efficiency, salvage value, fuel and oil use 

and cost (we obtained vendor quotes for oil cost), capital charge, repairs, insurance, housing, 

taxes, and labor. We compared our data, where appropriate, with the USDA 2006 Price 

Summary, published July 2007.xxii We also compared our results with those generated by the 

experts we listed earlier in this paragraph. 

The Purdue study was based on supplying a 100-million gallon per year ethanol 

production facility, which they assumed would convert the stover-to-ethanol at 72-gallons per 

ton; they assumed that 2-dry tons corn stover could be harvested per acre, as did we. We used 

National Agricultural Statistical Service (NASS) data to determine the actual corn grain yield in 
2005 (the data year for the Purdue study) for the counties studied in the simulation. We 

determined how much corn each county produced and from that how much stover was produced, 

2,455,000 tons or 3.12 dry tons per acre, with an assumed harvest index (HI) of 1:1 (see Table. 

4.1.1.2.2.)xxiii HI is based on the assumption that, for a single corn plant, half of the above ground 

dry matter is made up of stover and the other half is made up of grain. This is a fairly common 

assumption, although more than one group of researchers has found that this 1:1 ratio may not be 

the most accurate under some conditions. When considering above ground dry matter before and 

after full grain physiological maturation, they found that a stover to grain ratio of 0.8 to 1 may be 

more realistic especially when grain moisture is between 18 and 31 percent.xxiv 

Table 4.1-8 

NASS Indiana Data and Purdue Data Comparison 

USDA-NASS – Counties in State of Indiana - 2005 Purdue Model Year – 2005 

 Planted Harvested Grain 

Yield 

Grain 

Production Model Available Acres 

Prorated 

Grain 

Production 

Wet Tons 

Stover 

Dry Tons 

Stover 

County acres x 

103

acres 

x 103

bu/ 

acre bu x 106 acres x 

103

acres x 

103 bu x 106

 x 103 x 103

St Joseph 71 70 147 10.2 69 65 9.5 266 225 

Elkhart 60 53 142 7.6 150 52 7.4 206 174 

Marshall 94 89 150 13.4 0 87 13.1 366 309 

La Porte 117 112 137 15.3 113 104 14.2 398 336 

Starke 61 60 137 8.2 60 56 7.7 214 181 

Kosciusko 102 100 149 14.9 93 93 13.8 386 326 

Lagrange 55 51 113 5.8 132 45 5.0 141 119 

Fulton 90 89 159 14.1 0 78 12.3 345 291 

Porter 68 67 137 9.2 225 61 8.4 234 198 

Noble 65 62 142 8.8 0 57 8.0 225 190 

Pulaski 103 101 152 15.3 0 92 13.9 390 330 

 855 842 787 3,172 2,455 

However, a professor of agricultural engineering at the University of Wisconsin found 

that several researchers, going back to 1973 reported a grain mass fraction of 45% to 55% of 

total corn crop DM yield. On average, the variations seem to confirm the common rule of thumb 

of one unit mass of stover for a unit mass of grain. However, differences among harvesting 

methods, stages of maturity, and harvest dates can no doubt lead to much of the variation the 

researchers found in this estimate. His research indicates that the ratio of grain dry mass to total 

mass increased from about 38% in late August to about 59% in mid-October, during a recent 

harvest. Therefore, the stover to total ratio declined from 62% to 41%. During the typical 

harvest period in the Upper Midwest when grain moisture is between 20% and 30%, the ratio of 

stover to total dry mass was less than 45% and averaged 43%. These results are similar to those 

found by others.xxv Mainly, because we have no information upon which to base a reason to use 

something different, we chose to use the 1:1 ratio for corn stover to corn grain. We also assumed 

56-lbs per wet bushel (15.5% moisture) and 47.3-lbs per dry bushel, for the corn grain, to make 

our stover yield calculations.xxvi Table 4.1-9 summarizes the general operating parameters for our 

study. 
13 

Table 4.1-9 Operating Parameters 

EtOH Operating Year 350-days/yr 

 On Stream Factor 0.96 

 Hours per year 8,400-hr/yr 

EtOH Production Rate 100,000,000-gal/yr 

EtOH Yield 72-gal/dry ton 

Feedstock Required 

 per year 1,389,000-dry tons/yr 

 per day 3,970-dry tons/day 

Expected Dry Matter Loss 11.8% 

 Feedstock Harvested 1,574,000-dry tons/yr 

 Feedstock Yield 2-dry tons/acre 

Harvest Period 

 Days, 50-days 

 Hours per Day 16-hr/day 

 Harvest Hours 800-hr 

Format: Shred/Rake, 

Bale - Lg. Sq. - 3'x4'x8' 

Field Side - Self-Propelled 

Wagon 

Satellite Storage – 

Pole Barn on Concrete 

Transport to EtOH Facility – 

Truck & Trailer 

At 72 gallons per dry ton, the processing plant would require 1,389,000 dry tons of stover 

per year. However, we believe storage and transportation losses can be significant and should be 

taken into account. If, as stated in the report, they harvested 2-tons per acre, they actually 

harvested 1,574,000 tons of stover, or 64% of the 2,455,000 tons of available dry stover. The 

quantity of stover used versus the quantity harvested represents an 11.8% loss.3 Thus, we 

assumed that with an 11% loss, we would need to harvest 4,500- dry tons of stover per day, 

which by the time it reaches the plant will actually equal 3,970-dry tons – the amount required 

per day at the ethanol plant. During a 350-day production year, 1.574-million tons of stover 

would have be stored in about 3.5-million, 900-lb bales (Purdue study bale weight), at the 

various satellite storage areas. For this study, we assumed all the loss took place between the 

satellite storage areas and the ethanol plant, rather than guess what the losses would be at various 

points within the harvest/transport scheme. 

In the following analysis, we did not account for the extra time or equipment that would 

be necessary for inevitable break-downs. Nor was time and equipment factored in for driving 

between fields and for weather delays. Stover suppliers face several, in some cases, difficult 

problems. At best, the actual harvest period is nearly always too short; winter weather can 

suddenly set in, which in some cases may completely stop a potential stover or straw harvest. 

Once the grain is harvested and the stalks are mowed, stover usually must be left in the field for 

three or four days to dry to below 20% moisture before it’s baled, otherwise spoilage or rot as 

well as spontaneous combustion are possible. If it rains, additional time is required for drying 

and muddy roads and fields can be badly damaged and the field-soil compacted by the increased 

 

3 We indicated in a previous section that there may be as little as 25% to 50% stover actually available; however, 

since we didn’t have the computer software and database Purdue used and therefore couldn’t rerun the simulation, 

we chose to use the data we had. 
heavy-weight harvest and transport equipment traffic. One expert commented that, “If there’s a 

rainy harvest, you might as well forget about it. Also, the longer the wet material is left in the 

field, there’s more of a chance for microbes to eat away at the hemicellulose.”xxvii Delayed baling 

also raises the chances of dry matter loss. The stover needs to field-dry, so the stover harvest 

can’t actually begin for at least a few days after the grain harvest starts. But, once it begins it can 

continue until either it’s finished or until winter weather stops it. 

For reasons that weren’t explained in the report, the researchers at Purdue chose 50-days 

for the harvest period, which at their 16-hr per day schedule, provided a total of 800-hrs to 

complete the harvest and store the stover. In this harvest format (800-hrs), most of the 

machinery will be stored for the balance of the year. Crop harvest schedules in the Midwest and 

upper-Midwest are determined by the length of the growing season, the time of year when the 

crops are mature enough to harvest, and the time when winter weather sets in. Under ordinary 

conditions, farmers use their harvesting machinery during just a few weeks each year. During 

the past few years, as machinery costs have risen, many farmers have turned to custom 

harvesters, that move into an area and harvest several farms. A farmer must always weigh the 

differences in the custom rates and what it would cost him to own the equipment and complete 

the harvest himself, but then store most of the harvesting machinery for the rest of the year. In 

the South, winters are milder and it’s possible to harvest some crops all year long. In such cases, 

feedstocks could conceivably be harvested and shipped to a conversion facility on an ‘as needed’ 

basis; storage costs could be saved and machinery would be used all year long. However, an 

important factor, when it comes to harvest machinery, is the usable-life of the equipment. The 

more hours used each year, the more often the machine will need to be replaced. A machine 

lasts only so many hours, whether it’s used 800-hrs per year or 8,000-hours per year. We 

obviously could have arbitrarily chosen some longer period, but in order to maintain at least 

some consistency with the Purdue study, we chose to use the 50-day schedule for our study. 

This short period means we must harvest and store a full year’s inventory within a few weeks. 

Mow, Shred, Rake: Modern corn combines strip most of the leaves from a corn stalk, but 

leave up to about half of the stalk standing when they cut it off just below the bottom ear. In the 

combine, the corn grain is stripped from the cob, and the top part of the stalk, the leaves, and the 

cobs are subsequently discharged out the spreader at the rear of the machine. According to a 

group of researchers, at the time of grain harvest, of the total stover dry mass, 16% resides in the 

cob, 7% in the husk, 16% in the leaves, and 60% in the stalk fractions. Of the stalk dry mass, 

roughly 45% is found in the bottom one-quarter and 80% in bottom one-half of the stalk. If 

stover yield is to be maximized, harvesting systems must be developed that allow the bottom half 

of the stalk to be fully harvested.xxviii We summarized the costs to shred and rake in Table 4.1-10 
15 

Table 4.1-10 Corn Stover Shredding & Raking Operation 

Tractor – 

245-hp 

FlailShredder -30’ Tractor 

75-hp MFWD 

Wheeled 

V-Rake - 20 ft 

Equipment Factors 

 Purchase price $ 144,502 28,733 59,383 3,660 

 Useful life yrs 11.3 3.1 11.3 15 

 Discounted Salvage value $ 11,736 0.00 7,861 

 Annual use hr 800 800 800 800 

Fixed Costs $/hr 

 Depreciation and interest 25.47 14.51 10.06 1.87 

 Taxes Insurance Housing (THI) $/hr 3.97 0.79 1.63 0.10 

Total Fixed Costs $/hr 29.44 15.30 11.69 1.97 

Variable Costs 

 Repairs and maintenance $/hr 19.62 14.05 8.06 1.63 

 Fuel consumption4 gal/hr 9.6 8 5.6 

 Fuel and lubrication $/hr 23.82 19.87 13.81 4.27 

 Operating Interest 1.70 1.21 0.82 0.21 

 Labor $/hr 15.91 15.91 15.91 4.00 

Total Variable Cost $/hr 61.05 51.04 38.60 10.11 

Total Costs 

 Total $/hr 90.49 66.34 50.29 12.08 

 Equipment capacity MT/hr 32.7 13.27 

Total $/ton 4.80 4.70 

It will likely be necessary to flail-cut or mow the standing-stalks, and then rake and bale 

the windrows. We estimated that it cost about $4.80 per ton of stover for shredding and about 

$4.70 per ton for raking. 

Bale: As previously discussed, large square bales will likely be the bale-format for this 

system, although large round bales could be used. There are currently more round balers than 

square balers in use, mainly because large square balers are more expensive. However, 

gathering, stacking, and transporting large, round bales is much less efficient. It is difficult to 

stack round bales more than about three high, since they tend to deform rather badly, during even 

short storage periods; square bale stacks can be stacked up to five or six bales high, which 

translates into a more efficient use of storage area as well as more stable stacks that are far less 

prone to deformation over extended storage periods. Although large round bales tend to weather 

better out in the open, for the reasons just stated as well as those given in the Purdue report, we 

used large square bales in this analysis. Table 4.1-11 summarizes the cost of the baling 

operation, which we estimate to be $10.87 per ton.xxix, xxx

 

4

 We have received comment that it may be inappropriate to assign a fuel usage to both the 245-hp tractor and the 

flail shredder. We were unable to determine whether this was the case. The impact of not including such fuel would 

be a decrease in the price per ton cost of $0.61. 
Table 4.1-11 Corn Stover Baling Operation 

Tractor - 

 275-hp 

Lg. Sq. 

Baler - 3' x 4' x 8' 

Equipment Factors 

 Purchase price $ 147,102 110,723 

 Useful life yrs 11.3 3.8 

 Discounted Salvage value $ 7,553 32,455 

 Annual use hr 800 800 

Fixed Costs $/hr 

 Depreciation and interest 25.93 36.74 

 Taxes Insurance Housing (THI) $/hr 4.05 3.04 

Total Fixed Costs $/hr 29.98 39.78 

Variable Costs 

 Repairs and maintenance $/hr 19.98 45.11 

 Fuel consumption5 gal/hr 10 8 

 Fuel and lubrication $/hr 24.84 19.87 

 Operating Interest 1.71 2.38 

 Labor $/hr 15.91 10.66 

Total Variable Cost $/hr 62.44 78.02 

Total Costs 

 Total $/hr 92.42 117.80 

 Equipment capacity DMT/hr 19.4 

Total $/ton 10.87 

Bale Pick-Up & Field Side: It is important to remove the stover bales from off the fields. 

Few farmers will tolerate bales left for long periods on their fields, especially if there is a chance 

spring planting will be negatively affected. Nor do we expect farmers will allow random piles of 

bales left at field edges, for retrieval over the winter and spring months. Aside from the 

likelihood that trucks and other equipment would get stuck in muddy roads and fields, thus 

slowing down deliveries and running up operating costs, farmers would have little tolerance for 

torn-up roads and fields. This may not be a big problem, if the farmer/grower intends to plow a 

field in the spring. However, it could be highly problematic for a farmer/grower who “no till” 

farms and would be forced to repair ruts and holes in fields and roads before spring planting. 

Apart from this, dry matter losses from bales, left out in the open on dirt, can be as high as 10% 

to 20%. At harvest time, the bales, regardless of format, must be picked up and hauled either to 

a satellite storage site for intermediate storage or hauled directly to the processing plant. 

Several variables must be taken into account for bale pickup and the field-side haul 

operation that could easily affect the cost. Because the exact location on a field where a bale 

lands as it falls from a baler varies according to stover yield and harvest efficiency, there is no 

easy or accurate method for predicting the exact location of each bale on the field, either relative 

to each other or to the field edges or entry. The distance between bales and the potential 

variability in the area, shape, and relative dimensions of each field add to the difficulty of 

estimating bale pickup costs. If it was possible to somehow tag each bale with GPS coordinates 

as it fell to the ground, theoretically the coordinates could be used in some type of ‘bale 

retrieval’ program to optimize the time and pickup distance traveled.xxxi, xxxii 

 

5

 We have received comment that it may be inappropriate to assign a fuel usage to both the 275-hp tractor and the 

baler. We were unable to determine whether this was the case. The impact of not including such fuel would be a 

decrease in the price per ton cost of $1.06. 
17 

For this study, we used the theoretical stover density on the field, the speed and width of 

the harvester to estimate the distance between bales. We used a spreadsheet with these data to 

position the bales in a variety of patterns on a notional rectangular 100-acre field. We devised 

three or four drive-patterns in which the bales could be retrieved, by using simple visual 

inspection. We calculated the time to pick up the bales using each pattern and the average speed 

of the self-propelled bale-wagon. There were a few variables for which we couldn’t adjust our 

numbers because we simply had no way of knowing their effect. For example, if the field was 

furrowed, it seemed that the less time spent driving across the furrows, at, as we assumed a 

slower speed than could be traveled along the furrows, the more efficient would be the pick up. 

Table 4.1-12 summarizes the information we used for our calculations. 

Table 4.1-12 Bale Pickup and Field-Side 

Ft. Between Each Bale 490 

Pickup One 10-Bale Load - Ft/Load 4,901 

Bales/Acre 4.4 

Bales/Load 10 

Tons/Load 4.5 

Loader Speed - mph 7.5 

Field Size - Acres 200 400 800 

 Number of Loads per Field Size 89 178 356 

 Bales/Field Size - Total 889 1,778 3,556 

 Miles Traveled per Load 1.74 2.05 2.51 

 Tons/Hour 26 22 18 

Cost per Ton – Pickup & Field-Side $2.82 $3.31 $ 4.05 

In any case, using our basic assumptions, the time it took to retrieve a 10-bale load didn’t 

vary significantly for any of our plots. Table 4.1-13 presents the operating data for the bale 

wagon. 
Table 4.1-13 Self-Propelled Bale-Wagon 

Bale Wagon 

Equipment Factors 

 Purchase price $ 153,716 

 Useful life yrs 18.1 

 Discounted Salvage value 6,013 

 Annual use hr 800 

Fixed Costs $/hr 

 Depreciation and Interest $/hr 20.70 

 Taxes Insurance Housing (THI) $/hr 4.23 

Total Fixed Costs $/hr 24.93 

Variable Costs 

 Repairs and Maintenance $/hr 12.96 

 Fuel Consumption gal/hr 7 

 Fuel and Lubrication $/hr 17.39 

 Operating Interest 1.21 

 Labor $/hr 15.91 

Total Variable Cost $/hr 47.47 

Total Costs $/hr 72.40 

Total $/hr 72.40 

Equipment capacity DMT/hr 23 

Total $/ton 3.15 

Since the fields were no smaller than 200-acres, we piled the bales at one of the corners, 

which we assumed as the field-entry. We calculated the cost to haul bales for each of the 200-, 

400-, and 800-acre fields. We assumed the 20-ft rake made 148-passes across the 200-acre field; 

209-passes across the 400-ft field; and 295-passes across the 800-ft field. We used the number 

of windrows the rake left to determine the number of passes the baler would make. The baler 

dropped a bale every 490-ft; to collect a 10-bale load the loader would need to travel 4,900-ft. 

We estimated that the average distance every bale would need to travel to the corner of the field, 

e.g., the field entry, would be the distance from the field center to the corner (field-entry); we 

assumed the fields were square. The loader would need to travel that distance and then return 

empty, for the next load. Therefore, each loader would travel 4,900-ft to pickup the load, and 

then an additional 4,174-ft for the 200-acre field; 5,903-ft for the 400-acre field; and 8,348-ft for 

the 800-acre field to haul to the field edge (corner) and return. We chose to pick up 10-bales per 

load with a self-propelled bale wagon with an average speed of about 10-mph. We assumed the 

bales would be picked up, transported, and dumped at the field-edge at a cost of $2.82-per ton for 

the 200-acre fields; $3.31-per ton for the 400-acre fields; and $4.05-per ton for the 800-acre 

fields. We weighted the DM hauled for each field size by the total tons recovered from each 

size, to arrive at 23-weighted dry tons/hr hauled for $3.15-per ton 

Haul to Satellite Storage: Theoretically, we could store all the bales at the ethanol plant. 

If so, we would need to move 3,149,000-bales or about 100-loads per hour for 16 hours each day 

during the 50-day harvest. It would require 50-stacks, each, eight-bales wide by 5-bales high, by 

1,577-bales (12,615-ft.) long, with 51 x 20-ft aprons and isles, between each stack and along 

two-sides of the entire area, plus a 20-ft apron, across the entire front and rear. The area would 

total ~33-million square feet or 1.19-square miles. 
19 

We stored the bales at satellite facilities near the center of each county. As previously 

discussed, the Purdue study established ‘farm-sets,’ but did not describe how they were 

configured and how bales were to be hauled to each storage site, nor did the study specify 

exactly where each storage site was. Rather, they only estimated the distance between each 

storage area and the ethanol plant. The following table summarizes the cost factors used to 

estimate the costs to haul the bales to satellite storage. 

Table 4.1-14 

Haul - Field Side to Satellite Storage

High-Speed 

Tractor 

Bale 

Wagon 

2-

Telescopic 

Handlers 

Equipment Factors 

 Purchase price $ 133,865 23,851 130,106 

 Useful life yrs 15 15 12.5 

 Discounted Salvage Value $ 10,782 4,803 6,490 

 Annual use hr 800 800 800 

Fixed Costs $/hr 

 Depreciation and Interest $/hr 19.62 3.34 21.48 

Taxes Insurance Housing(THI) $/hr 3.68 0.66 3.58 

Total Fixed Costs $/hr 23.30 4.00 25.06 

Variable Costs 

 Repairs and Maintenance $/hr 13.63 1.94 15.90 

 Fuel Consumption gal/hr 6 0 2 

 Fuel and Lubrication $/hr 14.90 0 9.94 

 Operating Interest $/hr 1.13 0.09 1.02 

 Labor $/hr 15.91 7.95 31.82 

Total Variable Cost $/hr 45.57 9.98 58.68 

Total Costs $/hr 68.87 13.98 83.74 

Total $/hr 166.59 

Equipment capacity DMT/hr 9.3 

Total $/ton 17.91 

We assumed that a telescopic loader would load the bales at the field-edges onto 20-bale, 

2-axle, 30-ft long wagons, each pulled by a high-speed tractor to the storage area located at the 

center of each county, where they were unloaded by another telescopic loader and the bales 

stacked for temporary storage. Several variables make the cost of this operation difficult to 

estimate. A cursory inspection of the general outline/shape of many of the counties in the study 

reveals that they are by no means square. However, to make our calculations manageable, we 

assumed they were in order to determine the average distance each bale would need to be 

transported to its respective storage area in each county. We estimated that the average distance 

any load would travel from any position in the counties, e.g., from the furthest to the nearest, 

would be equal to one-half the distance from the corner of the county to its center. We used the 

published area of each county, from which we determined the distance from one-corner to the 

center; that distance equaled the trip to the storage area and the return. We multiplied each by a 

30% winding factor (rather than a straight-line drive, this accounts for turns and other 

meanderings).xxxiii We estimated the operation would cost about $17.91 per ton. 
Satellite Storage: We assumed each storage unit would consist of a concrete slab with 

open sides and pole-supported tin roof. Smooth paved surfaces are safer and make work easier. 

Gravel and dirt do not stick to the bottoms of the bales. If winter (wet, muddy) access is 

necessary, this cost should be included in the overall costs for storage; particularly from the 

highway to the stack. Beyond the need to keep the area around the stack accessible and clean, 

the could be problems with local authorities, if trucks leaving the property carry significant 

quantities of mud onto a public highway. Ordinarily, in an agricultural area a certain amount of 

mud is expected to be left on highways during wet weather. However, at the truck and trailer 

volumes we’re anticipating, the amount being tracked onto highways and possibly through 

municipalities, would increase rapidly. We used 1% of construction costs for upkeep, and 2% of 

the construction cost for the storage unit to cover the cost of access. These are incurred costs 

within the overall maintenance of stored stacks of biomass. These costs are essentially 

insignificant in the overall storage costs, are subject to great fluctuations due to weather and 

equipment availability, and, therefore, were rolled up into a percentage of the overall storage 

costs of stacked bales. The following table summarizes our storage area construction cost factors 

and costs. 

Table 4.1-15 

Satellite Storage Construction & Maintenance Costs – For Each of 11-Areas

Land Rent ($/acre/yr) 100

Land Preparation ($/acre) 30,000

Construction ($/sq ft) 3.75

Upkeep – 1% of Construction 

($/ton) 0.91

Access – 2% of Construction ($/ton) 1.81

Depreciation Period (yrs) 12

Number 

of Bales 

Bale 

Storage 

Area (sq ft) 

Bale 

Storage 

Area (acres) 

Tons 

Stover 

per site 

Supply 

days 

Total 

Storage 

Cost 

St Joseph 280,889 2,943,716 67.6 126,400 28.1 $1,123,463 

Elkhart 245,333 2,571,093 59.0 110,400 24.5 $981,252 

Marshall 336,000 3,521,280 80.8 151,200 33.6 $1,343,889 

La Porte 479,111 5,021,084 115.3 215,600 47.9 $1,916,286 

Starke 245,333 2,571,093 59.0 110,400 24.5 $981,252 

Kosciusko 366,222 3,838,009 88.1 164,800 36.6 $1,464,768 

Lagrange 201,778 2,114,631 48.6 90,800 20.2 $807,044 

Fulton 311,111 3,260,444 74.8 140,000 31.1 $1,244,342 

Porter 293,333 3,074,133 70.6 132,000 29.3 $1,173,236 

Noble 260,444 2,729,458 62.7 117,200 26.1 $1,041,692 

Pulaski 479,111 5,021,084 115.3 215,600 47.9 $1,916,286 

Total 1,574,400 350 $13,993,510 

Total Cost $8.89/ton 

 With well-paved surfaces, equipment can be maneuvered regardless of weather, and 

surfaces can be sloped to enhance drainage. We also assumed the bales would be stored in 

multiple stacks, 8-bales wide and 5-bales high, and long enough to accommodate the number of 

bales we expect; there would 20-ft aprons along the outside of the stacks and 20-ft isles between 

stacks for stacking, stack management, and for general and fire safety.xxxiv One researcher 

determined that the economics of scale, in the current situation, did not really apply. The cost for 
21 

secondary storage would therefore be approximately equal on a per ton basis regardless of the 

size of the biofuel production facility. Based on the numbers above, we estimated that storage 

would cost about $8.89 per ton.xxxv We used this as the cost per ton for the satellite storage as 

well as for storage at the plant. 

We used 11-telehandlers at the storage areas. (However, once the harvest is complete the 

telehandlers being used for loading and unloading bale wagons during the field-side to storage 

area operation could possibly be pressed into transport – load, unload service (see Table 4.1-15). 

If so, the cost to use the telehandlers could be reduced from $3.28 to $3.08 per ton.) Plus 11-

telehandlers at the plant to load and unload trucks and trailers that deliver the stover from 

satellite storage to the plant; extra telehandler time at the plant will be used to move feedstock as 

needed. The following table summarizes the cost associated with the transportation. The 

following table summarizes the cost associated with the transportation. 

Table 4.1-16 Haul From Satellite Storage to Plant 

 Class 8 

Truck 

53-ft Flatbed 

Trailer 

22-Telescopic 

Handlers 

Equipment Factors 

 Purchase price $ 103,839 42,173 130,106 

 Useful life yrs 20 22 13 

 Discounted Salvage Value $ 4,025 931 6,490 

 Annual use hr 5,600 5,600 800 

Fixed Costs $/hr 

 Depreciation and Interest $/hr 1.91 0.74 236.28 

Taxes Insurance Housing(THI) $/hr 0.41 0.71 39.38 

Total Fixed Costs $/hr 2.31 1.45 275.66 

Variable Costs 

 Repairs and Maintenance $/hr 1.13 3.16 174.90 

 Fuel Consumption gal/hr 9 0 2 

 Fuel and Lubrication $/hr 33.95 0 109.34 

 Operating Interest $/hr 0.37 0.14 11.22 

 Labor $/hr 17.46 350.02 

Total Variable Cost $/hr 52.91 2.31 $645.48 

Total Costs $/hr 55.22 3.76 921.14 

Total $/hr 58.97 921.14 

Equipment capacity DMT/hr 4.5 281 

Total, each $/ton 13.10 3.28 

Total $/ton 16.38 

To transport the bales to the ethanol plant, we calculated the ton-weighted average triptime to be 4.09 hr. We plan to ship 4,497-tons of stover to the plant on each of the 350-operating 

days. At 17.5-tons per load, we anticipate there will be about 256-loads per day. Using the 4.09-

ton weighted trip time, we estimated that it would require 63-trucks and trailers to haul 4 x 17.5-

ton per day. The cost of transportation plus loading and unloading is estimated to be $16.38 per 

dry ton. The following table summarizes all the costs to harvest, bale, field-side, haul to satellite 

storage, store, and haul to the plant. 
Table 4.1-17 

Ag Residue Cost Summary

Farm-Set Size, acres 200 400 800 Total Tons 

Tons per Farm-Set, t 756,4

39 476,402 341,559 1,574,400 

Farmer/Grower $/t 10.00 10.00 10.00 

Nutrient Replace $/t 11.81 11.81 11.81 

Shred $/t 4.80 4.80 4.80 

Rake $/t 4.70 4.70 4.70 

Bale $/t 10.84 10.84 10.84 

Haul – Edge $/t 2.82 3.31 4.05 

Total Farm Edge Cost $/t 44.97 45.46 46.20 

Haul – SS $/t 17.91 17.91 17.91 

Storage $/t 8.89 8.89 8.89 

Haul to Ethanol Plant $/t 16.38 16.38 16.38 

Field to Plant – Total $/t 43.18 43.18 43.18 

 

Per Farm- Set – 

Total $/t 88.15 88.64 89.38 

 Avg. Total Cost $/t 88.71 

 We anticipate that by 2022 the industry will improve the efficiency of feedstock 

delivery and reduce the cost of feedstocks. The current harvest-system is usually referred to as a 

multipass system: the corn grain is first combined, and then the stover is shredded, raked, baled, 

and the bales hauled to the field side. Each field-pass adds to the final cost and further compacts 

the soil; soil compaction is especially critical if the soil is prone to compaction or in no-till 

situations.xxxvi Because the combine-spreader drops the stover on to the ground, not only are 

fewer cobs collected, but dirt, dirt clods, and other debris, including metal, are inevitably 

gathered up with the stover by the baler.xxxvii, xxxviii Thus, extra effort and money must be expended 

to remove the debris before processing can begin, apart from the fact that dry matter is also lost 

during this operation. In their 2002 study report, NREL included a wash table to remove dirt and 

grit and had magnets to remove tramp iron, e.g., wire, etc. from the stover.xxxix 

According to a few sources, which for reasons of confidentiality, we can’t quote, there 

appears to be active interest in restructuring the system we just described to move the 

preprocessing (feedstock preparation) forward in the chain, away from the ethanol plant, and 

closer to the fields. Including the issues highlighted in the previous paragraphs, a major concern 

has to do with the use of standard hay and forage equipment, for which the overall collection 

efficiency of stover (ratio of stover collected to the total above-ground stover excluding grain) 

using flail choppers, rakes, and balers was less than 30%.xl Until now, most research has been 

based on a multi-pass system similar to the one we synthesized.xli,xlii In addition, the timeliness 

for collection (weather concerns) and moisture content issues are major problems associated with 

a multi-pass corn stover harvest.xliii 

The restructuring efforts also include exploring other methods to more efficiently gather 

the stover that avoids the need to pick it up from the ground, e.g., gather or catch it before it hits 
23 

the ground.xliv In one early case, a baler was hitched directly onto a combine, to capture the 

combine effluent and square-bale it. The problem was that there was a strict need to limit 

moisture to under 20% if bales are to be stored, plus the extra equipment slowed the grain 

harvest.xlv Ideally, the stover harvest system should be capable of harvesting stover at any level 

of moisture even while the grain is being harvested. All the cobs would be collected, the stover 

wouldn’t touch the ground and a controlled amount of residue would be left to meet any 

conservation requirements (we believe finding a way to leave the correct amount of residue 

behind will be difficult, and should be a top priority). 

A modification of the system we previously described would be to use a mobile tub 

grinder that could be towed from one satellite storage area to the next. A telehandler would feed 

the grinder to directly fill trucks for transport to the production facility. The ‘walking floor,’ 

rear-dump, or belly-dump trailers would unload the ground-up stover into silos or tanks at the 

facility. These silos or tanks could be sized to provide as much feed surge capacity as the facility 

required to maintain continuous operation.xlvi 

Again, ideally, the corn stover harvest should be reduced to a single-pass operation 

during which the amount of residue left on the field will be less a function of harvest efficiency 

and more a function of the farmer/grower and the harvesting company being able to determine 

how much residue must be left to maintain soil health. In reality, most of the equipment doesn’t 

yet exist that could perform some of the operations we will describe. Nevertheless, we believe 

this reflects some of the forward thinking that is currently taking place. For example, a combine 

designed specifically for the job must still be constructed. A single-pass harvester would cut the 

whole stalk a few inches above the soil, leaving some stalk anchored to the ground. It would pull 

the entire plant, e.g., stalks, leaves, and cobs with grain into the combine, where they are mixed 

into a single, clean, grain and stover stream. It would then blow the entire stream into tractorpulled grain-carts that run along-side the harvester. It is important to be able to change full carts 

for empties without stopping the harvester. As a cart is filled, it is pulled from beneath the 

discharge tube, as an empty cart is pulled under it. The full cart is hauled to the field side, where 

the harvested material is unloaded directly into bulk ‘walking-floor’ semi trailers, for transport to 

a co-op or depot type elevator/facility. After the biomass stream is unloaded, equipment at the 

elevator/depot separates the stover from the grain, following which the stover is chopped, dried, 

and sent to tanks or silos for intermediate storage. Currently, there are no simple methods for 

drying wet corn stover, other than to let it field-dry. However, if the single-pass harvest is to 

become a reality, the stover will need to be dried or else stored in much the same way silage is 

stored.xlvii At harvest, corn grain has a moisture content of 25%, while at the same time, the 

stover ordinarily ranges from 35% to well over 50% moisture. There have been studies to 

artificially dry corn stover as well as other biomass types; there will likely be changes to the 

reported results of these and other studies, but, then we expect advancements and certainly 

changes in several parts of the feedstock supply system.xlviii, xlix, l Given that these changes take 

place, the stover, would have flowability characteristics similar to small cereal grains, and could 

be moved by standard grain loading and unloading systems into large corrugated steel bins 

(silos) for intermediate storage. In this harvest format, the stover is handled by only two 

machines before it reaches the roadside and never hits the ground. Dry matter losses should be 

significantly reduced.li

 
Harvesting, storing, and transporting a denser feedstock should offer significant savings.lii 

Using this and other anticipated improvements, it appears possible that in the out years, e.g., by 

2022, corn stover and other residues could be commoditized, much as is the case with grain, and 

then purchased by a processor on an as-needed basis. 

However, commoditization offers its own set of issues, among which are both tangible 

and non-tangible infrastructures. Although tangible infrastructure with regard to ethanol 

distribution are discussed in greater detail in Section 4.2, we believe the following comments fit 

within the context of our preceding information. The impact of both feedstock and finished 

ethanol on rural road, highway and railroad infrastructure is likely to be even greater than the 

current and anticipated impact of corn based ethanol. Raw cellulosic feedstocks have lower 

levels of concentrated fermentable carbohydrates and therefore require a greater mass of 

feedstock to produce an equivalent level of ethanol. Thus, public and private transportation 

infrastructure must move a greater volume of feedstock per gallon of ethanol produced. The 

magnitude of the impact will depend on the field density of feedstocks near the plant and 

whether feedstock densification will make it possible to ship more dense carbohydrate product to 

the cellulosic ethanol plant. 

Intangible infrastructure is essentially absent for crop residue type cellulosic feedstocks. 

Intangible infrastructure includes such things as uniform grade and quality standards, market 

price discovery mechanisms, collateral warehouse receipts, regulatory structure and other 

marketing institutions. Grain market institutions have been developed and fine-tuned over the 

past century that give corn ethanol plants a decided benefit. Daily price information, as well as a 

wealth of crop condition, and supply and demand information from a variety of public and 

private sources is available on corn grain. Well known institutions such Uniform Grade and 

Quality Standards, FGIS, Grain Warehouse Regulations, Collateral Warehouse Receipts, Trade 

Associations, Non-Recourse Government Commodity Loans, and a set of futures markets that 

efficiently price grain over time and space are all readily available. This infrastructure is already 

in place, tested and readily accessible to corn grain ethanol producers. Although not highly 

visible and frequently taken for granted, it plays a critical role in efficient feedstock pricing, risk 

management, trading and financing. The cellulosic marketing infrastructure required for similar 

efficient commercial transactions will need to be established from top to bottom. 

Pricing infrastructure is one of the most pressing needs. Large daily volumes of corn and 

other grains are traded on well established exchanges with a great deal of confidence on the part 

of buyers and sellers that the other party will perform. Initially, it could be difficult, at best, to 

develop these infrastructure benefits for crop residues such as corn stover. Cellulosic feedstocks 

will be starting from a relatively small production base with no pricing institutions in place. 

There are no existing grades and quality standards to underpin transactions over distance and 

time. Nor are there any trade rules or established patterns for prompt and efficient settlement of 

trade disputes between buyers and sellers. The absence of these factors does not mean that they 

won’t develop, but there could be a stressful transition period. 

Also, there is no regulatory infrastructure to protect producers who wish to hold 

inventory after harvest in a public warehouse or handlers warehouse. This kind of infrastructure 

serves an important role in underpinning warehouse receipts and producer financing by creating 
25 

a higher and more reliable collateral value for inventory. Nor are there equivalents to the U.S. 

grain grades and quality standards or Federal Grain Inspection Service. While there are other 

ways these functions can be provided some type of commodity grades and standards will be 

necessary to permit trading. Another possibility would be to have the production of cellulosic 

feedstocks and the production of ethanol vertically integrated in some fashion so that the 

responsibility for quality is internalized.liii

Energy Crops 

Energy crops such as switchgrass and miscanthus would be harvested, baled, stored and 

transported very similar to crop residues. Because energy crops are not currently grown on a 

commercial scale, and are therefore not harvested, it is difficult to model the costs of harvesting 

these crops. Given the process for harvesting is likely to resemble the corn stover harvesting 

system described in our internal analysis of agricultural residue costs, we believe the costs would 

also be similar. Despite these similarities, there are several key differences that will cause the 

price of energy crops to differ from that of corn stover and other agricultural residues. 

One of the main advantages of growing energy crops is the low nutrient inputs, and 

therefore low nutrient replacement costs, that are required as compared to traditional crops. 

Energy crops are also expected to produce higher yields per acre than the harvesting of 

agricultural residues. This higher density is likely to increase the number of tons of feedstock 

than can be harvested per hour, while at the same time decreasing the transportation distance 

between the farms where the feedstock is produced and the biofuel production facility. Both of 

these factors would further decrease the cost of energy crop production, as labor and 

transportation costs would be lower and less secondary storage facilities would be required. 

Not all of the traits of energy crops would indicate lower costs of production, however. 

Energy crops will also incur a land rent cost. In the scenario described in our internal analysis 

for corn stover no land rent cost was charged to the production of corn stover. This is because 

the stover is assumed to be a secondary crop, and therefore all the land rent charges are assumed 

to be included in the cost of grain production. Because energy crops will likely be grown as 

primary crops there will be some land rent cost associated with their production. How big this 

cost is will vary greatly, depending on where and on what type of land the energy crops are 

grown. If energy crops are grown on marginal land that is unsuitable for traditional crops, as has 

been suggested, this cost may be low. In any case, it will be an increase when compared with 

agricultural residues, which do not have any associated land rent costs6

. 

Wood Residue 

As we did with agricultural residues, we also examined the costs associated with wood 

residue harvesting to validate the cost generated with FASOM. Harvest and transport costs for 

woody biomass in its different forms vary due to tract size, tree species, volumes removed, 

distance to the wood-using/storage facility, terrain, road condition, and other many other 

considerations. There is a significant variation in these factors within the United States, so 

timber harvest and delivery systems must be designed to meet constraints at the local level. 

 

6

 Land rent charges are included in the FASOM estimate of the roadside cost of energy crops. 
Harvesting costs also depend on the type of equipment used, season in which the operation 

occurs, along with a host of other factors. Much of the forest residue is already being harvested 

by logging operations, or is available from milling operations. However, the smaller branches 

and smaller trees proposed to be used for biofuel production are not collected for their lumber so 

they are normally left behind. Thus, this forest residue would simply have to be collected and 

transported out of the forest, although it would still have to be chipped before transport to the 

biofuel plant. 

In general, most operators in the near future will chip at roadside in the forest, blowing 

the chips directly into a chip van. When the van is full it will be hauled to an end user's facility 

and a new van will be moved into position at the chipper. The process might change in the 

future as baling systems become economically feasible or as roll-off containers are proven as a 

way to handle logging slash. At present, most of the chipping for biomass production is done in 

connection with fuel-reduction treatments. This could change if the price of raw biomass 

increases to a point where it becomes feasible to recover logging residues associated with normal 

commercial operations. The major problem associated with collecting logging residues and 

biomass from small trees is handling the material in the forest before it gets to the chipper. 

Balers and roll-off containers offer some promise to reduce this cost. Whether the material is 

collected from a fuel-reduction treatment or a commercial logging operation, chips from residues 

will be dirty and will require screening or some type of filtration at the end-user's facility.7 

Results from a study in South Georgia show that under the right conditions, a small 

chipper can be added to a larger operation to obtain additional chip production without adversely 

impacting roundwood production, and chips can be produced from limbs and tops of harvested 

trees at costs ranging from $11 per ton and up. Harvesting understory (the layer formed by 

grasses, shrubs, and small trees under the canopy of larger trees and plants) for use in making 

fuel chips is about $1 per ton more expensive. 

Per ton costs decrease as the volume chipped increases per acre. Some estimates suggest 

that if no more than 10 loads of roundwood are produced before a load of chips is made, that 

chipper-modified system could break even. Cost projections suggest that removing only limbs 

and tops may be marginal in terms of cost since one load of chips is produced for about every 15 

loads of roundwood. 

 The U.S. Forest Service provided us a cost curve for different categories of forest residue, 

including logging residue, other removals (i.e., clearing trees for new building construction), 

timberland trimmings (forest fire prevention strategy) and mill residues.liv The data was 

provided to us on a county-by-county basis. The national forest lands are omitted from 

consideration, and the urban forest residue is not considered here, but in the section discussing 

MSW. The information was also provided at different price points. The quantities of forest 

residue are summarized by source type in Tables 4.1-18, 4.1-19 and 4.1-20. To avoid presenting 

a huge amount of data, we aggregated the county data by state, and we are presenting the data at 

specific price points: $30/dry ton, $45/dry ton and $70/dry ton. 

 

7

 Personal Communication, Eini C. Lowell, Research Scientist, USDA Forest Service 
27 

Table 4.1-18. 

Volume of Wood Residue Available for Producing Biofuel 

Biomass Available at $30/ton (dry tons) 

 Logging 

Residue 

Other 

Removals 

Timberland 

Thinnings 

Unused Mill 

Residue 

 Total 

Quantity 

Alabama 1,202,541 253,620 433,519 7,117 1,896,798

Arizona 8,849 22,436 33,085 1,351 65,721

Arkansas 851,772 385,492 369,083 12,889 1,619,236

California 334,870 0 871,351 65,088 1,271,309

Colorado 9,203 7 0 2,302 11,511

Connecticut 4,195 15,339 10,465 3,949 33,949

Delaware 15,051 12,109 4,918 0 32,077

Florida 535,215 257,704 240,947 2,202 1,036,067

Georgia 1,556,954 496,631 553,627 45,138 2,652,350

Idaho 126,573 0 41,548 6,006 174,126

Illinois 139,101 117,589 115,431 18,523 390,644

Indiana 281,242 52,087 198,112 10,627 542,068

Iowa 56,049 27,580 48,991 159 132,780

Kansas 7,329 44,202 9,676 8,720 69,928

Kentucky 513,989 332,179 344,948 55,196 1,246,311

Louisiana 1,317,139 440,293 300,924 30,075 2,088,431

Maine 1,206,438 470 80,314 42,483 1,329,705

Maryland 90,722 415 40,994 17,067 149,197

Massachusetts 35,461 31,043 13,801 0 80,305

Michigan 379,463 122,476 327,640 13,763 843,343

Minnesota 348,807 331,492 132,712 26,878 839,889

Mississippi 1,548,534 355,071 425,344 95,138 2,424,088

Missouri 387,434 265,146 342,077 79,787 1,074,443

Montana 131,335 0 66,592 9,136 207,063

Nebraska 10,572 9,386 11,707 4,971 36,637

Nevada 15 53 0 0 67

New Hampshire 157,321 174 47,802 7,019 212,316

New Jersey 2,959 39 2,288 1,437 6,723

New Mexico 11,929 1,279 25,898 4,902 44,008

New York 367,003 54,671 163,336 27,390 612,400

North Carolina 1,013,165 629,632 560,814 12,811 2,216,422

North Dakota 1,453 7,601 3,822 265 13,141

Ohio 185,398 9,053 83,676 22,600 300,726

Oklahoma 173,869 98,794 53,043 495 326,200

Oregon 760,276 31 527,702 16,316 1,304,326

Pennsylvania 543,663 699 224,978 170,972 940,312

Rhode Island 884 22,860 2,800 389 26,934

South Carolina 714,551 348,289 301,850 1,051 1,365,741

South Dakota 6,972 14,436 2,993 2,294 26,695

Tennessee 316,706 244,920 423,906 187,583 1,173,115

Texas 616,777 218,464 185,718 3,021 1,023,979

Utah 2,973 7 9,909 4,437 17,325

Vermont 104,876 18,652 48,395 0 171,923

Virginia 741,673 406,800 436,870 39,366 1,624,709

Washington 641,144 22 925,479 21,446 1,588,091

West Virginia 488,356 24,714 161,653 118,779 793,502

Wisconsin 568,800 491,132 260,293 60,410 1,380,636

Wyoming 11,343 0 14,050 34,014 59,407

Total 18,530,943 6,165,088 9,485,083 1,295,560 35,476,674
Table 4.1-19. 

Tons of Wood Residue Available for Producing Biofuel 

Biomass Available at $45/ton (dry tons) 

 Logging 

Residue 

Other 

Removals 

Timberland 

Thinnings 

Unused Mill 

Residue 

 Total 

Quantity 

Alabama 1,202,541 253,620 506,045 7,117 1,969,324

Arizona 13,566 21,210 34,967 1,351 71,094

Arkansas 851,772 385,492 429,414 12,889 1,679,567

California 583,478 0 949,468 65,088 1,598,034

Colorado 10,056 11 30,619 2,302 42,988

Connecticut 4,301 16,095 10,465 3,949 34,810

Delaware 17,932 14,145 6,700 0 38,777

Florida 535,215 257,704 266,597 2,202 1,061,718

Georgia 1,556,954 496,631 644,295 45,138 2,743,018

Idaho 216,303 0 52,594 6,006 274,902

Illinois 139,153 117,589 115,431 18,523 390,696

Indiana 281,464 52,087 221,845 10,627 566,023

Iowa 56,050 27,607 49,551 159 133,367

Kansas 7,329 44,202 9,676 8,720 69,928

Kentucky 513,989 332,179 407,371 55,196 1,308,735

Louisiana 1,317,139 440,293 330,512 30,075 2,118,019

Maine 1,280,511 495 102,442 42,483 1,425,931

Maryland 94,579 421 40,994 17,067 153,060

Massachusetts 39,127 33,191 13,801 0 86,119

Michigan 391,732 128,600 410,302 13,763 944,398

Minnesota 358,518 341,894 159,990 26,878 887,280

Mississippi 1,548,534 355,071 467,935 95,138 2,466,679

Missouri 387,434 265,146 466,082 79,787 1,198,448

Montana 215,597 0 70,775 9,136 295,507

Nebraska 10,710 9,434 11,707 4,971 36,822

Nevada 22 71 0 0 93

New Hampshire 165,519 197 57,566 7,019 230,301

New Jersey 3,184 40 2,423 1,437 7,084

New Mexico 17,239 1,287 26,862 4,902 50,291

New York 384,457 56,552 189,696 27,390 658,094

North Carolina 1,013,165 629,632 668,420 12,811 2,324,028

North Dakota 1,454 7,601 3,822 265 13,142

Ohio 186,022 9,069 88,572 22,600 306,263

Oklahoma 173,869 98,794 62,700 495 335,858

Oregon 1,341,835 34 574,948 16,316 1,933,133

Pennsylvania 1,341,835 34 574,948 170,972 2,087,789

Rhode Island 957 25,039 2,800 389 29,185

South Carolina 714,551 348,289 352,018 1,051 1,415,909

South Dakota 11,872 15,581 3,253 2,294 32,999

Tennessee 316,706 244,920 507,698 187,583 1,256,906

Texas 616,777 218,464 219,187 3,021 1,057,448

Utah 3,758 0 10,786 4,437 18,980

Vermont 108,542 19,182 53,836 0 181,560

Virginia 741,673 406,800 524,372 39,366 1,712,212

Washington 1,067,587 23 981,839 21,446 2,070,895

West Virginia 488,356 24,714 241,184 118,779 873,033

Wisconsin 576,938 499,302 327,027 60,410 1,463,677

Wyoming 18,163 0 18,202 34,014 70,380

Total 20,928,463 6,198,742 11,301,737 1,295,560 39,724,502
29 

Table 4.1-20. 

Tons of Wood Residue Available for Producing Biofuels 

Biomass available at $70/ton (dry tons) 

 Logging 

Residue 

Other 

Removals 

Timberland 

Thinnings 

Unused Mill 

Residue 

 Total 

Quantity 

Alabama 1,202,541 253,620 581,654 7,117 2,044,933

Arizona 13,566 24,510 38,678 1,351 78,105

Arkansas 851,772 385,492 492,094 12,889 1,742,247

California 583,478 0 1,000,615 65,088 1,649,181

Colorado 10,056 11 30,619 2,302 42,988

Connecticut 4,301 16,095 10,465 3,949 34,810

Delaware 17,932 14,145 6,700 0 38,777

Florida 535,215 257,704 332,353 2,202 1,127,474

Georgia 1,556,954 496,631 776,911 45,138 2,875,634

Idaho 216,303 0 61,926 6,006 284,235

Illinois 139,153 117,589 115,431 18,523 390,696

Indiana 281,464 52,087 221,845 10,627 566,023

Iowa 56,050 27,607 49,551 159 133,367

Kansas 7,329 44,202 9,676 8,720 69,928

Kentucky 513,989 332,179 463,904 55,196 1,365,268

Louisiana 1,317,139 440,293 375,052 30,075 2,162,559

Maine 1,280,511 495 166,117 42,483 1,489,605

Maryland 94,579 421 40,994 17,067 153,060

Massachusetts 39,127 33,191 13,801 0 86,119

Michigan 391,732 128,600 533,107 13,763 1,067,203

Minnesota 358,518 341,894 200,599 26,878 927,889

Mississippi 1,548,534 355,071 516,598 95,138 2,515,342

Missouri 387,434 265,146 643,929 79,787 1,376,295

Montana 215,597 0 83,023 9,136 307,755

Nebraska 10,710 9,434 11,707 4,971 36,822

Nevada 22 71 0 0 93

New Hampshire 165,519 197 58,098 7,019 230,833

New Jersey 3,184 40 2,423 1,437 7,084

New Mexico 17,239 1,287 32,187 4,902 55,616

New York 384,457 56,552 192,851 27,390 661,249

North Carolina 1,013,165 629,632 800,455 12,811 2,456,063

North Dakota 1,454 7,601 3,822 265 13,142

Ohio 186,022 9,069 88,572 22,600 306,263

Oklahoma 173,869 98,794 81,634 495 354,792

Oregon 1,251,094 34 566,594 16,316 1,834,037

Pennsylvania 546,418 707 340,497 170,972 1,058,594

Rhode Island 957 25,039 2,800 389 29,185

South Carolina 714,551 348,289 395,555 1,051 1,459,446

South Dakota 11,872 15,581 4,129 2,294 33,875

Tennessee 316,706 244,920 516,550 187,583 1,265,759

Texas 616,777 218,464 253,670 3,021 1,091,931

Utah 3,758 7 14,717 4,437 22,918

Vermont 108,542 19,182 71,105 0 198,829

Virginia 741,673 406,800 630,366 39,366 1,818,206

Washington 1,067,587 23 1,029,985 21,446 2,119,041

West Virginia 488,356 24,714 287,639 118,779 919,489

Wisconsin 576,938 499,302 420,775 60,410 1,557,425

Wyoming 18,163 0 21,598 34,014 73,775

Total 20,042,304 6,202,722 12,593,373 1,295,560 40,133,959
 The relatively flat supply curve indicates that small changes in the demand for wood 

residues could have a significant impact on the cost of these residues. This makes predicting an 

appropriate cost for these residues a difficult task. The FASOM model estimates that 1.67 

million dry tons of wood residues will be used in cellulosic biofuel production in 2022. This 

number is far less than the 35.5 million dry tons of wood residue that the US Forestry service 

estimates will be available at $30 a ton. This would suggest that the low costs estimated by 

FASOM ($19.77 per dry ton) are reasonable. 

 Delivery of woody biomass from the harvesting site to a conversion facility, like delivery 

of more conventional forest products, accounts for a significant portion of the delivered cost. In 

fact, transportation of wood fiber (including hauling within the forest) accounts for about 25 to 

50 percent of the total delivered costs and highly depends on fuel prices, haul distance, material 

moisture content, and vehicle capacity and utilization. Also, beyond a certain distance, 

transportation becomes the limiting factor and the costs become directly proportional to haul 

distance. We believe Class 8 over-the-road hauling will be used to transport the wood residues 

from the roadside to the biofuel production facilities. The cost for the transportation of wood 

residues was determined using the transportation and secondary storage model presented in 

Section 1.3 and in further detail below. Because wood residues can be harvested throughout the 

year and delivered to the biofuel production plant on an as needed basis no secondary storage 

costs were included. 

Municipal Solid Waste 

Million of tons of municipal solid waste (MSW) continue to be disposed of in landfills 

across the country, despite recent large gains in waste reduction and diversion. The biomass 

fraction of this total stream represents a potentially significant resource for renewable energy 

(including electricity and biofuels). Because this waste material is already being generated, 

collected and transported (it would solely need to be transported to a different location), its use is 

likely to be less expensive than other cellulosic feedstocks. One important difficulty facing those 

who plan to use MSW fractions for fuel production is that in many places, even today, MSW is a 

mixture of all types of wastes, including biomaterials such as animal fats and grease, tin, iron, 

aluminum, and other metals, painted woods, plastics, and glass. Many of these materials can’t be 

used in biochemical and thermochemical ethanol production, and, in fact, would inflate the 

transportation costs, impede the operations at the biofuel plant and leave an expensive waste 

stream for biofuel producers. 

Thus, accessing sorted MSW would likely be a requirement for firms planning on using 

MSW for producing cellulosic biofuels. In a confidential conversation, a potential producer who 

plans to use MSW to produce ethanol indicated that their plant plans are based on the obtaining 

cellulosic biowaste which has already been sorted at the waste source (e.g., at the curbside, 

where the refuse hauler picks up waste already sorted by the generating home-owner or 

business). For example, in a tract of homes, one refuse truck would pick up glass, plastic, and 

perhaps other types of waste destined for a specific disposal depot, whereas a different truck 

would follow to pick up wood, paper, and other cellulosic materials to be hauled to a depot that 

supplies an ethanol plant. However, only a small fraction of the MSW generated today is sorted 

at the curbside. 
31 

Another alternative would be to sort the waste either at a sorting facility, or at the landfill, 

prior to dumping. There are two prominent options here. The first is that there is no sorting at 

the waste creation site, the home or business, and thus a single waste stream must be sorted at the 

facility. This operation would likely be done by hand or by automated equipment at the facility. 

To do so by hand is very labor intensive and somewhat slower than using an automated system. 

In most cases the ‘by-hand’ system produces a slightly cleaner stream, but the high cost of labor 

usually makes the automated system more cost-effective. Perhaps the best approach for low cost 

and a clean stream is the combination of hand sorting with automated sorting. 

The third option is a combination of the two which requires that there is at least some 

sorting at the home or business which helps to prevent contamination of the waste material, but 

then the final sorting occurs downstream at a sorting site, or at the landfill. 

We have little data and few estimates for the cost to sort MSW. One estimate from our 

Office of Solid Waste for a combination of mechanically and manually sorting of a single waste 

stream downstream of where the waste is generated puts the cost in the $20 to $30 per ton range. 

There is a risk, though, that the waste stream could still be contaminated and this would increase 

the cost of both transporting and using this material at the biofuel plant due to the toxic ash 

produced which would require disposal at a toxic waste facility. If a less contaminated stream is 

desired it would probably require sorting at the generation site – the home or business - which 

would likely be more costly since many more people in society would then have to be involved 

and special trucks would need to be used. Also, widespread participation is difficult when a 

change in human behavior is required as some may not be so willing to participate. Offering 

incentives could help to speed the transition to curbside recycling (i.e., charging fee for 

nonsorted waste, or paying a small amount for sorted tree trimmings and construction and 

demolition waste). Assuming that curbside sorting is involved, at least in a minor way, total 

sorting costs might be in the $30 to $40 per ton range. 

These sorting costs would be offset by the cost savings for not disposing of the waste 

material as well as the value of the recovered materials. Most landfills charge tipping fees, the 

cost to dump a load of waste, a societal cost that would be avoided. In the United States, the 

national average nominal tipping fee increased fourfold from 1985 to 2000. The real tipping fee 

almost doubled, up from a national average (in 1997 dollars) of about $12 per ton in 1985 to just 

over $30 in 2000. Equally important, it is apparent that the tipping fee is much higher in densely 

populated regions. Statewide averages also varied widely, from $8 a ton in New Mexico to $75 

in New Jersey. Tipping fees ranged from $21 to 98 per ton in 2006 for MSW and $18/ton to 

$120/ton for construction and demolition waste. It is likely that the tipping fees are highest for 

waste contaminated by toxic materials that require the disposal at Resource Conservation and 

Recovery Act (RCRA) certified toxic waste sites as opposed to a composting site. However, this 

same contaminated material would not be desirable to biofuel producers. Presuming that only 

the noncontaminated cellulosic waste (yard and food wastes, building construction and 

demolition waste and some paper) is collected as feedstocks for biofuel plants, the handling and 

tipping fees are likely much lower, in the $30 per ton range.8

 

 

8

 A much more thorough analysis of tipping fees by waste type is planned for the final rulemaking analysis. 
The avoidance of tipping fees, however, is a complex issue since landfills are generally 

not owned by municipalities anymore. Both large and small municipalities recognized their 

inability to handle the new and complex solid waste regulations at a reasonable cost. Only 38 

out of the 100 largest cities own their own landfills. To deal with the solid waste, large private 

companies built massive amounts of landfill capacity. The economic incentive is for private 

landfill operators to fill their landfills with garbage as early as possible to pay off their capital 

investment (landfill site) quickly. Also, the longer the landfill is operating the greater is its 

exposure to liability due to leakages and leaching. Furthermore, landfills can more costeffectively manage the waste as the scale of the landfill is enlarged. As a result, there are fewer 

landfills and landfill owners, and an expansion of market share by large private waste 

management firms, thus decreasing the leverage a biofuel producer may have.9 Hence, MSWbiofuel plants could be opposed by landfill operators. This may also be true in the case of a 

waste-to-energy (WTE) facility, which burns as much garbage as possible to produce electricity. 

For sustainable operation, a certain amount of daily waste supply should be guaranteed. A 

MSW-biofuel plant may therefore be seen as an unwelcome competition to both landfill owners 

and WTE facilities. This competition may increase the cost of cellulosic biomass to the biofuel 

producers. 

Once the cellulosic biomass has been sorted from the rest of MSW, it would have to be 

transported to the biofuels plant. Transportation is different for MSW biomass compared to 

forest and crop residues. Forest and crop residues are collected from forests and farms, which 

are both rural sites, and transported to the biofuel plant which likely is located at a rural site. The 

trucks which transport the forest and crop residues are large over-the-road trucks which can 

average moderate speeds because of the lower amount of traffic that they experience. 

Conversely, MSW is collected from throughout urban areas and would have to transported 

through those urban areas to the plant site. If the cellulosic biomass is being collected at 

curbside, it would likely be collected in more conventional refuse trucks. If the biofuel plant is 

nearby, then the refuse trucks could transport the cellulosic biomass directly to the plant. In this 

case, the refuse trucks would simply be delivering the MSW to the biofuel producer instead of a 

landfill or waste sorting facility, and therefore would not result in any additional cost to the 

biofuel producer. If, however, the plant is located far away from where the waste is collected, 

then the refuse trucks would probably to be offloaded to more conventional over-the-road trucks 

with sizable trailers to make transport more cost-effective. This would likely be an additional 

cost charged to the biofuel producer, as the MSW is now being transported farther to be used as a 

biofuel feedstock instead of disposed of at a local landfill. Because the roadside cost of MSW is 

significantly lower than the other feedstock sources it may still be cheaper to import MSW from 

some distance away rather than use an alternative, locally available feedstock. 

Cellulosic biomass sourced from MSW is generated year-round. If a steady enough 

stream of this material is available, then secondary storage would not be necessary, thus avoiding 

the need to install secondary storage. We assumed that no secondary storage costs would be 

incurred for MSW-sourced cellulosic biomass. If the MSW is sourced from within the same 

county as the biofuel plant we have assumed that there is no cost to the biofuel producer for the 

 

9

 Osamu Sakamoto, The Financial Feasibility Analysis of Municipal Solid Waste to Ethanol Conversion, Michigan 

State University, Plan B Master Research Paper in partial fulfillment of the requirement for the degree of Master of 

Science, Department of Agricultural Economics, 2004 
33 

transportation of the feedstock. If, however, the feedstock comes from a county other than the 

one in which the biofuel plant is located we assume that the biofuel producer must pay to have 

the MSW transported in large over-the-road trucks. These assumptions are used for the 

transportation and secondary storage model discussed in Section 1.3 and in detail in the 

following section. 

4.1.1.2.3 Transportation and Secondary Storage 

4.1.1.2.4 Cellulosic Ethanol Production Costs 

 Two different technologies served as the basis for estimating the costs for converting 

cellulose into ethanol. One technology relies on the biochemical conversion of the cellulose to 

ethanol. The second technology converts the cellulose to a syngas and then reacts the syngas to 

mixed alcohols over a catalyst. 

Biochemical Conversion of Cellulose to Ethanol 

We contracted with the National Renewable Energy Laboratory (NREL) to estimate the 

cost to convert corn stover into ethanol for the years 2010, 2015, and 2022. It is of particular 

importance for the following discussion, to note the following: NREL used the same feedstock 

mass (772,168 dry tons of corn stover) in all three cases. 

For the three cases, NREL assumed the feedstock, ‘as-needed,’ was hauled to the plant by 

trucks and trailers from satellite storage, already shredded to the appropriate size for processing, 

and free of dirt, iron, and other contaminates; in other words – process ready. The transport 

vehicles were unloaded into surge tanks, large enough to hold feedstock for three days of 

operation. The pretreatment and hydrolysis reactors are charged from these feed surge tanks. 

The following is background information for our discussion of both operating and capital 

costs, some of which is also included in our brief discussion of the process flow description and 

capital equipment charges. The first step was to develop a set of process flow diagrams that set 

the arrangement of the equipment. Based on the desired production volume, these diagrams, 

were used within an ASPEN Plus4© model to develop complete mass and energy balance. The 

model consists of 164 unit operation blocks, 457 streams (247 material and 210 heat or work), 63 

components, and 82 control blocks. 

The overall model is thermodynamically rigorous and uses physical properties for the 

feedstock and process chemicals included in the ASPEN software as well as property data 

developed at NREL. The individual unit models are also thermodynamically consistent and can 

be either rigorous (for example, the simulation of the distillation) or simple. The reactors could 

be modeled with kinetic expressions, but because of the level of development of the 

experimental data, they were modeled as experimentally determined conversions of specific 

reactions. This type of model still satisfies the rigorous mass and energy balance. Other unit 

operations, such as liquid-solid separations, are typically modeled with fixed solids removal and 
liquid retention (in the solids stream) data from vendor tests.10 Using the process flow diagrams 

and the mass and energy balance information, NREL estimated stream flows and conditions, 

along with the estimated quantities of raw materials and other process chemicals. 

The following table presents NREL’s summary of each of the three year’s total project 

investment. For each year’s total project investment, NREL provided capital charge, which 

includes income tax, depreciation, and average return on investment, the cost of raw materials, 

waste handling charges, and by-product credits. 

Table 4.1-23. Summary of NREL’s Capital Charges and Operating Costs 

Year Technology 2010 2015 2022 

Plant Size 

MMgal/yr 56 69 71 

Capital Cost $MM 

(TPI) 232 220 199 

 $MM/yr ¢/gal $MM/yr ¢/gal $MM/yr ¢/gal 

Capital Charge 

10% after tax ROI 42 75 39 56 35 50 

Fixed Costs 9 16 9 12 8 12 

Feedstock Cost 84 46 51 35 50 35 

Other Raw Matl. 

Costs 17 30 4 5 16 16 

Enzyme Cost 18 32 7 10 5 8 

Enzyme Nutrients 8 14 2 3 2 2 

Electricity -6 -10 -7 -9 -12 -16 

Waste Disposal 1 2 3 4 1 1 

Total Costs 173 205 108 116 105 108 

 

 

The quantities of all raw material, generated electricity, and produced wastes were 

determined using the ASPEN mass and energy balance model. These costs include: Feedstock – 

corn stover, CSL – purchased corn steep liquor (a nutrient); Cellulase – purchased cellulase 

enzymes; Other Raw Materials – sulfuric acid, diammonium phosphate, make-up water, boiler 

 

10 A. Aden, M. Ruth, K. Ibsen, J. Jechura, K. Neeves, J. Sheehan, and B. Wallace 

National Renewable Energy Laboratory (NREL); L. Montague, A. Slayton, and J. Lukas Harris Group, Seattle, 

Washington, Ethanol Process Design and Economics Utilizing Co-Current Dilute Acid Prehydrolysis and Enzymatic 

Hydrolysis for Corn Stover; June 2002; NREL is a U.S. Department of Energy Laboratory Operated by Midwest 

Research Institute • Battelle • Bechtel; Contract No. DE-AC36-99-GO10337 
35 

feed water chemicals, cooling water chemicals. Waste Disposal – waste water chemicals, waste 

water polymers, ash disposal, gypsum disposal. Electricity – marketing and distribution of 

surplus electricity to the grid for credit. 

We note that the percent change in total project investment from year to year is not 

insignificant and reflects improvements in mechanical process efficiencies among other general 

improvements in the process technology, including the automatic distributed process control 

system, all of which are off-set to some extent by increases in the real cost of the technology 

improvements, as well as those of constructions materials. We discuss capital costs following 

this discussion of operating costs. 

The most notable reductions in NREL’s operating costs are in the price per dry ton of the 

corn stover feedstock and in the cost of cellulase enzyme. NREL anticipates significant 

improvement in the efficiency of these enzymes, especially those that saccharify glucan to 

glucose and xylose oligomers11 generated during hydrolysis. They also expect improvement in 

the yeasts that ferment xylose. According to the 2007 NREL – State of Technology report, they 

anticipate that as a first step, the relationship between corn stover hydrolysate conditioning and 

fermentation will be better defined and understood. Commercial cellulase preparations will 

continue to be analyzed for baseline performance (specific activity), and due to increased 

research efforts, cellulase function will be better understood, which should lead to efficiency 

improvements. Integrated testing of whole slurry and recycle options will also be conducted 

resulting in potential improvements in that area. Last, the efficacy of advanced enzyme 

preparations (including oligomerases and/or hemicellulases) will continue to be tested in 

conjunction with alternative pretreatment technologies. NREL expects that the cost of 

pretreatment will deminish, hydrolysis time will decrease, and the sugar (xylose and glucose) 

yields will increase.12 

As the process costs decline over time, the feedstock costs become a larger fraction of the 

overall costs. We also note that in the following table that the cost of the feedstock makes up 

50% of the total cost in 2010; 67% in 2015; and 68% in 2022. The reduction in feedstock cost, 

from $60 per dry ton in 2010, to $45.90 per dry ton in both 2015 and 2022 also has a significant 

effect on operating costs. In addition, NREL did not include payments to the farmers/growers 

nor for soil nutrients (fertilizer, etc.) that were removed with the harvested corn stover. The cost 

of the cellulase enzyme is the next highest contributor, with percent reductions contributed to 

total cost that reduced from ~19% in 2010, to 13% in 2015 and 10% in 2022. It should be 

obvious that any reductions in these costs have significant effects on the total operating cost. 

The majority of research going forward will be focused on these two items, although some work 

will be done to reduce the cost of the others. Table 4.1-24 summarizes NREL’s operating costs 

for a biochemical cellulosic ethanol plant. 

 

11 Xylan polymer chains, with considerably fewer residue numbers in the chain than were in the original xylan 

polymer; they were broken off the polymer as these short chains rather than as single molecule sugars. 

12 Andy Aden, National Renewable Energy Laboratory, Golden, Colorado, Biochemical Production of Ethanol from 

Corn Stover: 2007 State of Technology Model, Technical Report NREL/TP-510-43205, Task No. BB07.2410; May 

2008 
Table 4.1-24. 

Percent of the total operating cost for each actual operating cost item 

 2010 2015 2022 

 ¢/gal % of 

Total ¢/gal % of Total ¢/gal % of Total 

Feedstock 84 50 51 67 50 68 

Biomass to 

Boiler 0.0 0.0 0.0 0.0 0.0 0.0 

CSLa 14 8 3 4 2 3 

Cellulase 32 19 9 13 8 10 

Other Raw 

Matl. Costs 31 18 5 7 16 22 

Waste Disposal 2 1 4 5 2 2 

Electricity -10 -6 -9 -12 -16 -22 

Fixed Costs 16 10 12 16 12 16 

 168 76 72 

 aCorn steep liquor – provides nutrients for the enzymes. 

 

 The following table includes our adjustments to NREL’s variable or operating cost data 

for the three years studied. We note that the two main differences between NREL’s and our 

estimates are in the feedstock costs and in the way we calculate capital charges. We adjusted 

NREL’s capital charges which were calculated using a 10% after tax return on investment, to 

reflect a 7 percent before tax rate of return, which is the capital cost basis for our cost analyses. 

We also adjusted the NREL feedstock costs to those that we estimated in Table 4.1-21, which 

was $67.4 per dry ton. This significant difference between their and our feedstock cost estimates 

is due to our including payments to farmers/growers plus covering the cost to replace nutrients 

(fertilizer, etc.) removed at the time the stover was harvested. According to a personal 

communication, NREL used unpublished data from the Idaho National Laboratory that indicate 

feedstock costs will be significantly reduced between 2010 and 2015. 
37 

Table 4.1-25. 

Adjusted Capital Charges and Operating Costs 

Year 

Technology 2010 2015 2022 

Plant Size 

MMgal/yr 56 69 71 

Capital Cost $MM 232 220 199 

 $MM/yr ¢/gal $MM/yr ¢/gal $MM/yr ¢/gal 

Capital Cost 7% 

ROI before taxes 25 46 24 35 22 31 

Fixed Costs 9 16 9 12 8 12 

Feedstock Cost 52 94 55 75 52 73 

Other Raw Matl. 

Costs 17 30 4 5 16 16 

Enzyme Cost 18 32 7 10 5 8 

Enzyme Nutrients 8 14 2 3 2 2 

Electricity -6 -10 -7 -9 -12 -16 

Waste Disposal 1 2 3 4 1 1 

Total Costs 124 224 94 135 90 127 

 The changes in the minimum ethanol selling prices for the three years studied are 

partially due to the changes in necessary capital investments. In order to determine capital costs, 

NREL developed specifications for pieces of equipment that fall within different areas of a 

biochemical plant. A biochemical plant is divided up into 8 different areas (Area 200 through 

Area 900)._ For each equipment specification, they developed individual purchased equipment 

and installation costs. Vendors supplied installation costs where possible; in other cases 

installation factors were used. Equipment costs were obtained from vendor quotations when 

possible, especially for uncommon equipment such as pretreatment reactors. These costs reflect 

the base case for which the equipment was designed. If process changes were made and the 

equipment size changed, the equipment is not generally re-costed, in detail. Rather, the cost was 

adjusted by scaling using the following exponential scaling expression, [New Cost = Original 

Cost x (New Size/Original Size)^exp]. They also scaled the size of equipment that was known to 

change linearly with a change in inlet flow. The scaling exponents (exp) were obtained from 

vendor quotes, or from a standard reference, such as Garrett.13 

 

13 Garrett, D.E., Chemical Engineering Economics, Van Nostrand Reinhold, New York, 1989 
Installation costs were taken primarily from Delta-T, a process consultant’s experience. 

Once the scaled, installed equipment costs (total installed capital costs) were determined, they 

applied overhead and contingency factors to determine a total plant investment cost. That cost, 

along with the plant operating expenses (generally developed from the ASPEN model) was used 

in a discounted cash flow analysis to determine the cost of ethanol production, using a set 

discount rate. NREL use a discount rate of 10%, whereas we used 7%, a factor generally used in 

our financial calculations. For this analysis, the minimum ethanol selling price was the primary 

value used to compare cases. 

The total project investment was briefly discussed previously in our summary discussion 

of operating costs; we used NREL’s total project investment for our estimates. The following 

summarizes the capital expenditures that account for that capital investment. 

Area 200: Pretreatment and Hydrolysis. The equipment in this area consists of an 

assortment of pipe, pumps, tanks, tank-agitators, tank-mixers, coolers, 3-pneumapress filters, as 

well as three separate process trains, each of which includes a presteamer, a blow tank, and a 

reactor. The presteamer uses low-pressure steam to heat the feedstock to about 212 oF. It 

discharges the hot, saturated mix into a blow tank that serves as a seal between the presteamer 

and the hydrolysis reactor. The mix is charged to the reactor and dilute sulfuric acid is added; 

the reactor operates at 191 psia and 547 o

F. Most of the hemicellulose, e.g., primarily xylose, 

mannose, arabinose, and galactose are converted into sugars. Glucan in the hemicellulose and a 

small portion of the glucan in the cellulose are converted to glucose. These conditions also 

solubilize some of the lignin in the feedstock and ‘expose’ the cellulose for subsequent 

enzymatic hydrolysis, in a downstream section. In addition, acetic acid is liberated from the 

hemicellulose hydrolysis. Degradation products of pentose sugars (primarily furfural) and hexose 

sugars (primarily hydroxymethyl furfural (HMF)) are also formed. 

Following the pretreatment reactor, the hydrolyzate liquid and solids are flash cooled, 

which vaporizes a large amount of water, a portion of the acetic acid, and much of the furfural 

and HMF, which can be toxic to downstream fermentation microorganisms. 

In addition to the flash removal of aldehydes, the solids are washed and filter-pressed to 

remove the liquid portion of the hydrolyzate, which contains sulfuric acid. The liquid is then 

neutralized to pH 10 with ammonia and held until the gypsum precipitates and is filtered out. 

The hydrolyzate, which contains the hydrolyzed xylose sugars and some glucose sugars, is 

mixed back with dilution water and the filter cake, which contains the unhydrolyzed cellulose 

and is sent to saccharification and co-fermentation (Area 300) 

An important issue on an industrial scale is accurate pH control. By pH 11, as much as 

30% of the glucose may be lost to HMF and other side reactions. Several factors increase the 

probability of overshooting pH endpoints during neutralization. The natural buffering capacity 

of hydrolyzates causes neutralization reactions to be slow. Plus, measurements using pH 

membrane probes are affected by temperature and the presence of dissolved organic compounds 

(sugars and lignin). 
39 

 Since we are handling the same mass of feedstock in each of the modeled years, we don’t 

expect the cost of the equipment for pretreatment and hydrolysis will change much over the 

2010-2022 time period. The equipment costs for Area 200 – Pretreatment & Hydrolysis are 

2010: $23-million; 2015: $22.7-million; and 2022: $18.9-million. Neutralization and 

Conditioning costs were separated out from the Pretreatment & Hydrolysis costs, even though 

the NREL’s design report includes both cost centers in Area 200. Neutralization and 

Conditioning costs are as follows: 2010: $8.4-million; 2015: $9.4-million; and 2022: $7.7-

million. The combined cost for Area 200 is as follows: 2010: $31.4-million; 2015: $32.1-

million; and 2022: $26.6-million. In total, this area contributed about 23.5% to the total installed 

capital cost of the project in 2010; about 25.3% in 2015; an 23.2% in 2022 

 Area 300: Saccharification and Co-Fermentation. The equipment in this area consists of 

pumps, tanks, tank-agitators, coolers, and heaters. Two different operations take place in this 

process area — the saccharification of the cellulose to glucose using cellulase enzymes, and the 

fermentation to ethanol of that glucose plus the xylose and glucose sugars from the dilute acid 

pretreatment of hemicellulose from Area 200. 

Glucan from the cellulose undergoes hydrolysis or saccharification, at about 149 oF, prior 

to fermentation. This slightly higher temperature increases enzyme activity and reduces the time 

and amount of enzyme required for saccharification. Saccharification or cellulase enzymes, 

purchased from an enzyme manufacturer, and the diluted, detoxified hydrolyzate are 

continuously added to a train of five 1-million gallon saccharification vessels; residence time is 

estimated to be 36-hours. 

Cellulase enzyme is actually a ‘cocktail’ of enzymes, comprised of: (1) endoglucanases, 

which attack randomly along the cellulose fiber to reduce polymer size rapidly; (2) 

exoglucanases, which attack the ends of cellulose fibers, allowing it to hydrolyze highly 

crystalline cellulose; and (3) β-glucosidase, which hydrolyzes cellobiose to glucose. Several 

bacteria and fungi naturally produce these enzymes, including bacteria in ruminant and termite 

guts and white rot fungus. The most common organism used to produce cellulase industrially is 

Trichoderma reesei. Genencor International and Novozymes Biotech are developing more cost 

effective cellulase enzymes. DOE is funding this important work, which should improve the 

economic viability of biomass conversion. 

The recombinant Z. mobilis bacterium is used as the biocatalyst to ferment glucoses and 

xyloses to ethanol. Several research institutions are genetically engineering strains, such as Z. 

mobilis, to treat additional sugars and identifying other naturally occurring organisms that 

metabolize hemicellulosic sugars. 

The Z. mobilis must be ‘grown’ in increasingly higher volume stages. Initially, a small 

amount of saccharified slurry and nutrients are combined in a very small vessel with a seed 

inoculum, that’s been grown in the laboratory. This initial seed batch is used as the inoculum for 

the next larger size seed batch, and so on. This series of batch scale-ups continues until the last 

batch is large enough to support the actual production fermentation. 
Finally, the seed inoculum, nutrients (corn steep liquor) & (diammonium phosphate – a 

source of nitrogen for the yeast), and saccharified slurry are cooled to about 106 oF and added to 

a train of five 1-million gallon continuous fermentors. At this point, the process actually 

becomes a simultaneous saccharification and co-fermentation (SSCF) process. Even though the 

temperature in the fermentation tanks has been reduced to account for the ethanologen’s 

intolerance to heat, the enzymes do continue to hydrolyze cellulose, albeit at a slightly reduced 

rate. The main byproduct, produced during fermentation is carbon dioxide (CO2), which is 

removed in a later process stage. The ethanol broth called ‘beer’ is collected in a storage tank, 

called a beer well, before it’s pumped to distillation. 

NREL anticipates significant capital savings for saccharification and co-fermentation

between 2010 and 2015, with fewer between 2015 and 2022. We note that this area contributed 

15.4% to the total installed capital cost in 2010, but only 8.8% in 2015 and 8.8% in 2022. The 

equipment costs for Area 300 – Saccharification and Fermentation are 2010: $20.5-million; 

2015: $11.2-million; and 2022: $10.1-million. 

Area 400 – In earlier studies, NREL included plans to produce enzymes in Area 400. For 

the current studies, Area 400 has been removed and enzymes will be purchased and grown on 

site under licensing agreements with enzyme suppliers. 

Area 500 – Product, Solids, and Water Recovery (Distillation, Dehydration, Evaporation, 

and Solid-Liquid Separation). The equipment in this area includes distillation and rectification 

columns, pumps, condensers and coolers, pumps, pipe, filter-presses, and evaporators. 

Beer, from the beer well in Area 300, is preheated and fed to a distillation column. The 

column overhead containing all the CO2 and about 0.2% of the ethanol and a small quantity of 

water is sent to a scrubber, which recovers and recycles about 99% of the vented ethanol. In the 

tower bottoms, about 90% of the water has been removed and it contains approximately 0.7% of 

the total volume of ethanol fed to the tower. Over 99% of the total ethanol fed to the tower is 

removed as a 39.4% w/w mixture with water vapor through a side draw and fed directly to a 

rectification column for further ethanol enrichment. We discuss the distillation column bottoms 

in the evaporation and solid-liquid separation section of this area. 

The rectification tower operating conditions are set to produce an overhead 92.5% w/w 

ethanol/water saturated vapor mixture. The tower bottoms are a 0.05% w/w ethanol/water 

mixture. In fact, only 0.1% of the total ethanol from the fermentation area is lost to the bottoms. 

The rectification column overhead is superheated and fed to one of two adsorption 

columns in a molecular sieve adsorption unit. The two columns operate alternately; while one 

bed is operated to remove water from the ethanol, the other is regenerated by passing a very 

small slipstream of pure ethanol vapor back through the loaded bed that strips the water off the 

adsorbent, while the column is under a vacuum. The mixture is condensed and returned to the 

rectification column feed stream. The adsorption column removes 95% of the water and a small 

quantity of ethanol. The 99.5% pure ethanol vapor is condensed, cooled, and pumped to storage. 
41 

Evaporation, and Solid-Liquid Separation: The beer column bottoms, with about 5.8% 

insoluble solids, are fed to the first effect evaporator, where 24% of the water in the feed is 

evaporated. The evaporator bottom slurry, cooled from ~243 oF to ~189 oF, is sent to a filterpress, from which the filtrate is returned to the second evaporator effect; the filter cake is not 

washed. In the second effect evaporator, 44% of the feed water is evaporated. The third effect 

evaporates 76% of the remaining water. The final vapor is condensed and fed to a condensate 

drum. Of the total feed to the evaporation/separation system, 10.5% remains as syrup, 11.5% is 

removed as a wet cake in the pressure filter, 17% is recycled back to the process as recycle 

water, and 61% is evaporated. The syrup from the third evaporator bottoms is 60% water, e.g., 

the maximum dissolved solids level that can be achieved without rapid fouling of the evaporator; 

the flow of very low-pressure steam to the evaporator is set to achieve this level. This syrup is 

mixed with the cake from the filter-press and sent to the combustor for disposal. Air from the 

filter-press is used for combustion air. 

The equipment costs for Area 500 – Product, Solids, and Water Recovery (Distillation, 

Dehydration, Evaporation, and Solid-Liquid Separation) are for 2010: $23.4-million; 2015: 

$26.1-million; and 2022: $23.3-million. This area’s contribution to the total installed capital 

cost in 2010 is 17.5%; in 2015, 20.6%; and in 2022, 20.3%. We believe that some of the 

increase from 2010 to 2015 has to do with the increased liquid flow due to the conversion 

improvements; larger pipe, pumps, tanks, etc may be necessary to handle the increased flow. 

The changes from 2015 to 2022 are not that significant, as reflected by the percent contribution 

of the area to total installed equipment cost. 

Area 600 – Wastewater Treatment: The equipment in Area 600 consists mainly of 

aerobic and anaerobic digesters, digester agitators, tanks (basins), a biogas emergency flare, 

coolers, and pumps. The main purpose of the wastewater treatment section is to reduce the plant 

makeup water requirement by recovering, treating and recycling as much process water as 

possible. The feed to the wastewater treatment section consists of: condensed pretreatment flash 

vapor, condensate from the hydrolyzate filter-press vent, boiler blowdown, cooling tower 

blowdown, clean-in-place waste, and the non-recycled evaporator condensate. Rain and snow 

run-off, equipment washing, and other non-process wastewater are assumed to flow to the 

municipal wastewater treatment system. The stream is screened to remove large waste particles 

that are sent to a landfill; any remaining organic matter is anaerobically and aerobically digested. 

Anaerobic digestion produces a methane rich (75%-methane, 25%-carbon dioxide) biogas that’s 

fed to the combustor. Aerobic digestion produces relatively clean water that’s recycled back to 

the process and sludge that’s burned in the combustor. 

NREL didn’t expect much change over the 2010 to 2022 time period. In 2010 the 

installed capital cost for this area was $3.4-million; in 2015, $3.7-million; and in 2022 it was 3.1-

million. As important as this area is to the entire operation its contribution to the total project 

installed capital cost is relatively minor. In 2010 the contribution was 2.5%; in 2015, 2.9%; and 

in 2022 it was 2.7%. 

Area 700: Bulk Storage of Chemicals. This section of the plant stors chemicals in bulk 

for the process and for finished, fuel-grade ethanol. The feedstock feed surge tanks we discussed 

just prior to the discussion of Area 200 are not included in this area. Process chemicals stored in 
this area include: corn steep liquor (a nutrient), sulfuric acid, cellulase enzyme, gasoline (used as 

a denaturant finish the fuel grade ethanol), and water for fire suppression. 

There is approximately five-days of SS316-stainless steel14 tank sulfuric acid storage. 

Corn steep liquor (CSL), a nutrient for fermentation seed growth and ethanol production, also 

has about five-days of SS304-stainless steel15 storage; NREL expects the plant will require about 

three-25,000 gallon rail cars of CSL every three-days. There are seven-days of storage for 

diammonium phosphate (DAP), delivered as pellets via rail car. Appropriate quantities of CSL 

and DAP are mixed in a day-tank and used in Area 300 for fermentation seed production and 

ethanol production. A producer that supplies cellulase enzymes is expected to set up an enzyme 

production operation either on site or on a nearby location. Liquid enzyme storage is set for 

four-days in SS304 stainless steel tanks. The carbon steel fire-fighting water storage tanks 

provide about four-hours of operating time; the firewater pump delivers 2,500 gpm. Other pumps 

are sized per process requirements 

There is seven-days of ethanol product storage in two 600,000 gallon carbon steel tanks. 

Five percent gasoline (v/v), a denaturant, is added to the ethanol as it’s loaded for shipment to 

customers. The pumps in this section are generally sized to load a 10,000 gallon truck and trailer 

in about 15 min. to 20 min. maximum filling time. They can also be used to fill process day 

tanks. 

The installed capital costs for bulk storage are, for 2010, $3.8-million; for 2015, $2.4-

million; and for 2022, $2.4-million. The contribution to total project installed capital costs are, 

for 2010, 2.8%; for 2015, 1.9%; and for 2022, 2.1%. 

Area 800: Combustor, Boiler, and Turbogenerator. The purpose of the combustor, 

boiler, and turbogenerator is to burn various by-product or waste streams to produce steam and to 

generate electricity. All of the feedstock lignin and some of the cellulose and hemicellulose are 

not hydrolyzed in Area 300. 

As previously discussed, a high soluble, solids syrup is generated in Area 600 and 

anaerobic and aerobic digestion of the remaining wastewater produced biogas and a small 

quantity of biomass sludge which are burned to generate steam and produce electricity. This 

contributes to over-all plant energy self-sufficiency, reduces solid waste disposal costs, and 

generates additional revenue through sales of excess electricity. Because of heightened interest 

in using biomass, pulping wastes, and sewage sludge in place of fossil fuels, new methods are 

being developed to handle higher moisture feeds. Traditional methods include blending the wet 

feed with dry material or adding auxiliary fuel to maintain the combustion temperature. When 

the dry solids from the filter-press cake are combined with the high soluble, solids syrup, it helps 

 

14 SS316 is an improved version of SS304, with the addition of molybdenum and a slightly higher nickel content. 

The resultant composition of 316 gives it much increased corrosion resistance in many aggressive environments. 

The molybdenum makes the steel more resistant to pitting and crevice corrosion in chloride-contaminated media, 

sea water and acid vapors.

15 SS304-stainless steel is the most versatile and the most widely used of all stainless steels. Its chemical 

composition, mechanical properties, weldability and corrosion/oxidation resistance provide the best all-round 

performance stainless steel at relatively low cost. 
43 

ensure a stable combustion bed temperature and improved boiler efficiency. In these studies 

NREL used a circulating fluidized bed combustor that is suitable for varying feeds and feed 

characteristics; however, this flexibility makes the unit more expensive than a grate or pile 

combustor. A Lower Heating Value (LHV) of 2,000-2,500 BTU/lb is considered the minimum 

for maintaining combustion.16 The combined feed to the combustor has a LHV of 4,179 Btu/lb. 

Thus, the total higher-heating value energy of the combined feed streams to the combustor is 706 

MMBtu/hr. The solids contribute 59% of this energy and the syrup contributes 37%. A 

baghouse removes particulates from the combustion flue gas after it preheats the incoming 

combustion air and before it’s discharged through the stack. 

The boiler feed water (BFW) system includes a softener for makeup and condensate 

water, a deaerator to remove air and other non-condensables, surge tanks and pumps. The 

amount of water pretreatment necessary depends on the incoming water quality, metallurgy of 

the boiler, and the ratio of makeup to condensate in the feed water. Pretreatment chemicals for 

pH control, scale removal, and oxygen removal are added. Treated well water used for makeup 

and condensate are softened, deaerated, preheated and mixed to provide BFW that’s converted to 

steam that’s superheated to 950 o

F at 1,265 psia at the rate of 407,420 lb/hr. Support equipment 

includes BFW pumps, deaerator, automatic water pretreatment chemical injection, and 

condensate gathered from the various heat exchangers in the process. Boiler efficiency, the 

percentage of the feed heat converted to steam heat, is estimated to be 68%. Boiler blowdown is 

3% of steam production. The turbine efficiency was estimated to be 85%. 

The turbogenerator consisting of a multistage turbine with extraction ports, a generator, 

and condenser is used to generate electricity. After high pressure steam drives the multistage 

turbines, it is extracted at three different conditions for injection into the pretreatment reactor and 

heat exchange in distillation and evaporation. Twenty-eight percent of the steam is extracted 

from the turbine at 191 psia and 514°F, 60% at 65 psia and 327°F, and 3% at 25 psia and 239°F 

for process needs, as described. The remaining steam (9%) is condensed at 1.5 psia with cooling 

water and returned to the BFW system. For this design, a total of 30.4 megawatts (MW) of 

power is generated from the system. The process uses 11.7 MW, leaving 18.7 MW that is sold to 

the grid. 

The installed capital cost for Area 800 are, for 2010, $45.5-million; for 2015, $46-

million; and for 2022, $43.3-million. This area’s contribution to the total installed capital cost is, 

for 2010, 34.1%; for 2015, 36.2%; and for 2022, 37.7%. 

Area 900: Utilities. All utilities, except steam and electricity, necessary for the 

production of ethanol are accounted for in this area. The utilities provided include cooling water, 

chilled water, plant and instrument air, process water, and the clean-in-place (CIP) system. No 

chilled water is used in the plant; the required process temperatures can be achieved by cooling 

water year-round. 

 

16 Steam and Electricity Generation Options For the Biomass-To-Ethanol Process, NREL Subcontract ACO-8-

18019-01, Reaction Engineering International, Salt Lake City, UT, March 16, 1998. 

http://www.ott.doe.gov/biofuels/process_engineering.html 
The plant and instrument air systems provide compressed air for air-driven equipment, 

instrument operation, for clean up, and the filter-press units in the post-distillation dewatering. 

The process water system mixes fresh well water with treated wastewater and provides water at a 

constant pressure to the facility. Water is provided to seed production, boiler feed water, cooling 

tower make-up, the CIP system, and the scrubber. It is also mixed with recycle water for dilution 

before saccharification. Process water is also used throughout the facility for cleaning on an asneeded basis. The CIP system provides a solution that can be heated and includes cleaning and 

sterilization chemicals to saccharification and co-fermentation, seed vessels, and the distillation 

system. 

The installed capital costs for the utilities area are, for 2010, $5.6-million; for 2015, $5.5-

million; and for 2022, $6.1-million. This area’s contribution to the total project installed 

equipment costs are, for 2010, 4.2%; for 2015, 4.3%; and for 2022, 5.3%. 

Table 4.1-26 summarizes the total projected capital costs for a biochemical cellulosic 

ethanol plant for the years 2010, 2015 and 2022. 
45 

Table 4.1-26. 

Projected Capital Costs for a Biochemical Cellulosic Ethanol Plant 

($million/yr)

 2010 2015 2022 

Total Capital 

Investment 

133.5 127 114.8 

Added Costs* 98.2 93.1 83.8 

Total Project 

Investment 

231.7 220.1 198.6 

*

Added costs include the following: 

Warehouse: This is estimated to be 1.5% of total installed cost 

Site Development: This includes fencing, curbing, parking, lot, roads, well drainage, rail system, 

soil borings, and general paving. This factor allows for minimum site development assuming a 

clear site, with no unusual problems such as right-of-way, difficult land clearing, or unusual 

environmental problems, usually calculated as 9% of the installed cost of process equipment. 

Prorateable Costs: This includes fringe benefits, burdens, and insurance of the construction 

contractor, usually calculated as 10% of total installed cost. 

Field Expenses: This includes consumables, small tool equip. rental, field services, temporary 

construction facilities, and field construction supervision, usually calculated as 10% of total 

installed cost. 

Home Office and Const.: This includes engineering plus incidentals, purchasing, and 

construction, usually calculated as 25% of total installed cost. 

Project Contingency: These costs are small because of the detail included in the process design 

usually calculated as 3% of total installed cost. 

Other Costs: This includes start-up and commissioning costs; land, rights-of-way, permits, 

surveys, and fees; piling, soil compaction/dewatering, unusual foundations; sales, use, and other 

taxes; freight, insurance in transit and import duties on equipment, piping, steel, instrumentation, 

etc.; overtime pay during construction; field insurance; project team; transportation equipment, 

bulk shipping containers, plant vehicles, etc.; escalation or inflation of costs over time; interest 

on construction loan. These other costs are usually calculated as 10% of total capital investment. 

The costs for cellulosic ethanol produced biochemically could be lower if not all the 

water would have to be removed from the ethanol. Separating the water from ethanol is costly 

because water forms an azeotrope with ethanol. Removing the last of the water above the 

azeotrope requires additional capital and operating costs. Some research conducted with hydrous 

ethanol as well as practical experience in Brazil suggests that by not removing the last few 

percent of water from ethanol, the ethanol production costs would be lower and the water 

contained in ethanol might not cause driveability, not cause corrosion problems and not lower 

the fuel economy. A lot more research needs to be conducted before hydrous ethanol would be 

proven as a viable and safe motor vehicle fuel in existing U.S. vehicles. 
Thermochemical Conversion of Cellulose to Ethanol 

Thermochemical conversion is another reaction pathway which exists for converting 

cellulose to ethanol. Thermochemical technology is based on the heat and pressure-based 

gasification or pyrolysis of nearly any biomass feedstock, including those we’ve highlighted as 

likely biochemical feedstocks. The syngas could then be converted into mixed alcohols, 

hydrocarbon fuels, chemicals, and power. To produce ethanol, the syngas is passed over a 

catalyst which converts the syngas to mixed alcohols – mainly methanol. The methanol can be 

reacted further to ethanol. 

NREL has authored a thermochemical report which already provided a cost estimate.lv 

However, this report only hypothesized how a thermochemical ethanol plant could achieve 

production costs at a very low cost of $1 per gallon. However, to obtain a more detailed cost 

assessment that may be achievable within the timeframe of our program, EPA contracted NREL 

to assess the costs for a thermochemical technology which produces mixed alcohols for years 

2010, 2015 and 2022.lvi Table 4.1-27 summarizes the cost information provided by NREL. 

Table 4.1-27 

Summary of Mixed Cellulosic Alcohol Production Costs by NREL 

(2007 dollars, 10% after tax ROI) 

2010 2015 2022 

Annual Ethanol Production 48.8 56.7 61.9 

Annual Total Alcohol Production 57.5 66.6 72.7 

Ethanol Yield 63.2 73.4 80.1 

Total Alcohol Yield 74.5 86.2 94.1 

 

Capital Costs 

 Feed Handling and Drying 25.2 25.2 25.2 

 Gasification 14.0 14.0 14.0 

 Tar Reforming and Quench 53.4 38.6 41.6 

 Acid Gas and Sulfur Removal 20.4 14.6 15.8 

 Alcohol Synthesis Compression 35.4 18.5 17.3 

 Other Synthesis Costs 6.1 4.7 5.1 

 Alcohol Separation and Purification 6.8 7.5 7.8 

 Steam System and Power Generation 19.2 19.7 18.2 

 Cooling Water and other Utilities 4.2 4.3 3.9 

 Total Installed Equipment Cost 184.7 147.1 148.9 

 Added Cost Factors 72.1 57.5 58.1 

Total Project Investment 256.8 204.6 207.0 

 

Operating and 

Amortized Capital Costs 

$MM/yr $/gal 

Ethanol 

$MM/yr $/gal 

Ethanol 

$MM/yr $/gal 

Ethanol 

 Feedstock 46.4 0.95 35.4 0.63 35.6 0.58 

 Catalysts 7.6 0.16 0.2 0.003 0.2 0.003 

 Olivine 0.5 0.01 0.5 0.01 0.5 0.01 

 Other Raw Materials 0.4 0.02 0.4 0.02 0.3 0.02 

 Waste Disposal 0.3 0.01 0.3 0.01 0.3 0.01 

 Electricity -1.8 -0.04 0.0 0.00 0.0 0.00 

 Fixed Costs 14.8 0.30 12.7 0.23 12.8 0.21 

 Co-Product Credits -10.4 -0.21 -11.8 -0.21 -12.9 -0.21 

 Capital Depreciation, Income Tax and 

 Return on Investment 

46.3 0.95 37.1 0.66 37.5 0.61 

Total 104.1 2.15 74.8 1.33 74.3 1.21 
47 

 In its mixed cellulosic alcohol report, NREL did not assess the technology’s costs on the 

same basis that EPA is using. NREL used a feedstock cost of $46.1/dry ton which is lower than 

our estimate of $67.4/dry ton. Also, NREL amortized the capital costs based on a 10 percent 

after tax return on investment (ROI) compared to our 7% before tax ROI. Thus, we adjusted the 

NREL cellulosic mixed alcohol costs to reflect our feedstock costs and capital cost amortization 

assumptions. Table 4.1-28 contains a summary of the mixed cellulosic alcohol costs based on 

our feedstock and capital amortization cost assumptions. 

Table 4.1-28 

Summary of Adjusted Mixed Cellulosic Alcohol Production Costs by NREL 

(2007 dollars, 7% before tax ROI)

2010 2015 2022 

Operating and 

Amortized Capital Costs 

$MM/yr $/gal 

Ethanol 

$MM/yr $/gal 

Ethanol 

$MM/yr $/gal 

Ethanol 

Feedstock 67.8 1.39 51.8 0.92 52.1 0.85 

Catalysts 7.6 0.16 0.2 0.003 0.2 0.003 

Olivine 0.5 0.01 0.5 0.01 0.5 0.01 

Other Raw Materials 0.4 0.02 0.4 0.02 0.3 0.02 

Waste Disposal 0.3 0.01 0.3 0.01 0.3 0.01 

Electricity -1.8 -0.04 0.0 0.00 0.0 0.00 

Fixed Costs 14.8 0.30 12.7 0.23 12.8 0.21 

Co-Product Credits -10.4 -0.21 -11.8 -0.21 -12.9 -0.21 

Capital Depreciation, Income Tax and 

Return on Investment 

28.3 0.58 22.8 0.40 22.8 0.37 

Total 107.5 2.22 76.8 1.38 76.0 1.26 

4.1.1.3 Imported Sugarcane Ethanol Costs 

Our analysis of imported ethanol costs began with a literature search of recent estimates 

for production costs for sugar cane ethanol in Brazil. Since the liberalization of ethanol prices in 

Brazil, few cost estimation studies have been made and most of the cost analyses refer to the 

same study.lvii This study was carried out by the Brazilian Ministry of Science and Technology 

(MC&T), based on 1990 data, and referred to a production cost of $0.87/gallon. Table 4.1-29 

gives a breakdown of costs based on this data. 
Table 4.1-29. Sugarcane Ethanol Production Costs in Brazil, circa 1990 

 Average cost 

(US$ per gallon) 

Operating costs

 Labor 

 Maintenance 

 Chemicals 

 Energy 

 Other 

 Interest payments on working capital 

 Feedstock (cane) 

$0.64 

$0.02 

$0.02 

$0.01 

$0.01 

$0.02 

$0.08 

$0.48 

Fixed costs

 Capital at 12% depreciation rate 

 Other 

$0.23 

$0.19 

$0.04 

Total $0.87 

 Since then, there have been significant variations in exchange rates, costs of sugarcane 

and oil products, etc. For example, earlier estimates may underestimate crude and natural gas 

costs which influence the cost of feedstock as well as energy costs at the plant. Another possible 

difference in production cost estimates is whether or not the estimates are referring to hydrous or 

anhydrous ethanol. Costs for anhydrous ethanol (for blending with gasoline) are typically 

several cents per gallon higher than hydrous ethanol (for use in dedicated ethanol vehicles in 

Brazil).lviii It is not entirely clear from the majority of studies whether reported costs are for 

hydrous or anhydrous ethanol. Yet another difference could be the slate of products the plant is 

producing, for example, future plants may be dedicated ethanol facilities while others involve the 

production of both sugar and ethanol in the same facility. Due to economies of scale, production 

costs are also typically smaller per gallon for larger facilities. Table 4.1-30 summarizes the 

various estimates reported by others. Production costs range from as low as $0.57 per gallon of 

ethanol to as high as $1.48 per gallon of ethanol. 
49 

Table 4.1-30. Other Sugarcane Ethanol Production Cost Estimates

Reference Cost (US$ per gallon) 

AgraFNP. 2007. Sugar and Ethanol in Brazil: A 

Study of the Brazilian Sugar Cane, Sugar and 

Ethanol Industries. 

$0.80-$1.07 per gallon (in 2006 $’s depending on 

region in Brazil), avg. is $0.78 per gallon for cane 

production cost and $0.13 per gallon for industrial 

costs 

IEA. 2004. Biofuels for Transport: An 

International Perspective. 

$0.87 per gallon (in 1990 $’s) references MC&T 

study; also reports recent production cost estimates 

for hydrous ethanol as low as $0.57 per gallon (at 

the prevailing exchange rate in Jan. 2004) 

USDA. 2006. The Economic Feasibility of 

Ethanol Production from Sugar in the United 

States. 

Avg. is $0.81 per gallon 

Von Lampe, Martin. OECD. 2006. Working 

Party on Agricultural Policies and Markets: 

Agricultural Market Impacts of Future Growth in 

the Production of Biofuels. 

$0.83 per gallon 

Brazil Institute. April 2007. The Global 

Dynamics of Biofuels: Potential Supply and 

Demand for Ethanol. Issue No. 3. 

$0.83 per gallon. 

ESMAP. October 2005. Potential for Biofuels 

for Transport in Developing Countries. 

$.87-$1.10 per gallon 

OECD, March 2008. ITF Round Tables No. 138. 

Biofuels: Linking Support to Performance. 

Avg. is $1.40 per gallon 

Bain, R. December 2007. World Biofuels 

Assessment Worldwide Biomass Potential: 

Technology Characterizations. NREL/MP-510-

42467. 

$1.04-$1.48 per gallon depending on size of plant, 

i.e. 100 MGY-4.6 MGY; Sugarcane feedstock 

costs $0.68 per gallon, Variable operating costs 

$0.27 per gallon, Fixed costs $0.02-0.13 per gallon, 

and Capital costs $0.07-0.40 per gallon 

Macedo, I.C. and L.A.H. Nogueira. 2005. 

“Biocombusíveis”. Cadernos NAE, No. 2. 

Núcleo de Assuntos Estratégicos da Presidência 

da República, Brasilia; As sited in OECD, op. 

sit. 

$0.79 per gallon in the Center-South Brazil 

Kojima, M. and T. Johnson. 2006. “Potential for 

Biofuels for Transport in Developing Countries”. 

ESMAP Knowledge Exchange Series, No. 4.; As 

sited in OECD, op sit.

$0.87-$1.09 per gallon 

Smeets, E. 2008. The Sustainability of Brazilian 

Ethanol-An Assessment of the Possibilities of 

Certified Production. Biomass and Bioenergy 

$1.18 assuming exchange rate of $1.20= 1 Euro 

Van den Wall Bake, J.D., et. al. 2009. 

Explaining the experience curve: Cost reductions 

of Brazilian ethanol from sugarcane 

$1.29 per gallon presently; Estimates for 2020 

range from $0.76-$0.98 per gallon, Sugarcane costs 

$0.35-$0.46 per gallon, rest from industrial costs17

 

17 Costs were given in $/TC and $/m3

, conversions were used to translate to per gallon numbers. 
 The study by OECD (2008) entitled “Biofuels: Linking Support to Performance”, appears 

to provide the most recent and detailed set of assumptions and production costs. As such, our 

estimate of sugarcane production costs primarily relies on the assumptions made for the study, 

which are shown in Table 4.1-31. The estimate assumes an ethanol-dedicated mill and is based 

off an internal rate of return of 12%, a debt/equity ratio of 50% with an 8% interest rate and a 

selling of surplus power at $57 per MWh. 

Table 4.1-31. Cost of Production in a Standard Ethanol Project in Brazil

Sugarcane Productivity 71.5 t/ha 

Sugarcane Consumption 2 million tons/year 

Harvesting days 167 

Ethanol productivity 85 liters/ton (22.5 gal/ton) 

Ethanol Production 170 million liters/year (45 MGY) 

Surplus power produced 40 kWh/ton sugarcane 

Investment cost in mill USD 97 million 

Investment cost for sugarcane production USD 36 million 

O & M (Operating & Maintenance) costs $0.26/gal 

Variable sugarcane production costs $0.64/gal 

Capital costs $0.49/gal 

Total production costs $1.40/gal 

 The estimate above is based on the costs of producing ethanol in Brazil on average, 

today. However, we are interested in how the costs of producing ethanol will change by the year 

2022. Although various cost estimates exist, analysis of the cost trends over time shows that the 

cost of producing ethanol in Brazil has been steadily declining due to efficiency improvements in 

cane production and ethanol conversion processes. Between 1980 and 1998 (total span of 19 

years) ethanol cost declined by approximately 30.8%.lix This change in the cost of production 

over time in Brazil is known as the ethanol cost “Learning Curve”. See Figure 4.1-2. 

Figure 4.1-2. Ethanol Cost “Learning Curve” 

 

 The change in ethanol costs will depend on the likely productivity gains and 

technological innovations that can be made in the future. As the majority of learning has already 

occurred, it is likely that the decline in ethanol costs will be less drastic in the future as the 
51 

production process and cane practices have matured. Industrial efficiency gains are already at 

about 85% and are expected to increase to 90% in 2015.lx Most of the productivity growth is 

expected to come from sugarcane production, where yields are expected to grow from the current 

70 tons/ha, to 96 tons/ha in 2025.lxi Sugarcane quality is also expected to improve, with sucrose 

content growing from 14.5% to 17.3% in 2025. lxii All productivity gains together could allow 

the increase in the production of ethanol from 6,000 liters/ha (at 85 liters/ton sugarcane) to 

10,400 liters/ha (at 109 liters/ton sugarcane) in 2025. lxiii 

Assuming that ethanol productivity increases to 100 liters/ton by 2015 and 109 liters/ton 

by 2025, variable sugarcane ethanol production costs are be expected to decrease to 

approximately $0.51/gal from $0.64/gal since less feedstock is needed to produce the same 

volume of ethanol using the estimates from Table 4.1-31, above. Table 4.1-32 shows the 

calculated decrease for the years 2005-2025. We assumed a linear decrease between data points 

for 2005, 2015, and 2025. Adding operating ($0.26/gal) and capital costs ($0.49/gal) from Table 

4.1-27, to a sugarcane cost of $0.51/gal, total production costs are $1.26/gal in 2022. 

Table 4.1-32. 

Estimated Decrease in Sugarcane Production Cost by 2022 

Due to Increases in Ethanol Productivity 

 

Sugarcane 

Production Cost 

$/gal liters/ton gal/ton 

2005 0.64 85 22.46 

2006 0.63 86.5 22.85 

2007 0.62 88 23.25 

2008 0.61 89.5 23.65 

2009 0.60 91 24.04 

2010 0.59 92.5 24.44 

2011 0.58 94 24.83 

2012 0.57 95.5 25.23 

2013 0.56 97 25.63 

2014 0.55 98.5 26.02 

2015 0.54 100 26.42 

2016 0.54 100.9 26.66 

2017 0.53 101.8 26.90 

2018 0.53 102.7 27.13 

2019 0.53 103.6 27.37 

2020 0.52 104.5 27.61 

2021 0.52 105.4 27.85 

2022 0.51 106.3 28.08 

2023 0.51 107.2 28.32 

2024 0.50 108.1 28.56 

2025 0.50 109 28.80 

 Brazil sugarcane producers are also expected to move from burned cane manual 

harvesting to mechanical harvesting. See Figure 4.1-3.lxiv As a result, large amounts of straw are 

expected to be available. Costs of mechanical harvesting are lower compared to manually 
harvesting, therefore, we would expect costs for sugarcane to decline as greater sugarcane 

producers move to mechanical harvesting. However, diesel use increases with mechanical 

harvesting and with diesel fuel prices expected to increase in the future, costs may be higher than 

expected. Therefore, we have not assumed any changes to harvesting costs due to the switchover 

from manual harvesting to mechanical harvesting. 

Figure 4.1-3. Phase-out Schedule for Trash Burning Practices 

 As more straw is expected to be collected at future sugarcane ethanol facilities, there is 

greater potential for production of excess electricity. The production cost estimates in the OECD 

study assumes an excess of 40 kWh per ton sugarcane, however, future sugarcane plants are 

expected to produce 135 kWh per ton sugarcane assuming the use of higher efficiency 

condensing-extraction steam turbine (CEST) systems and use of 40% of available straw.lxv 

Assuming excess electricity is sold for $57 per MWh, the production of an additional 95 kWh 

per ton would be equivalent to a credit of $0.22 per gallon ethanol produced. We have included 

this potential additional credit from greater use of bagasse and straw in our estimates at this time, 

calculated as a decrease in operating costs from $0.26 per gallon to $0.04 per gallon. 

 It is also important to note that ethanol production costs can increase if the costs of 

compliance with various sustainability criteria are taken into account. For instance, using 

organic or green cane production, adopting higher wages, etc. could increase production costs for 

sugarcane ethanol.lxvi Such sustainability criteria could also be applicable to other feedstocks, for 

example, those used in corn- or soy-based biofuel production. If these measures are adopted in 

the future, production costs will be higher than we have projected. 
53 

 In addition to production costs, there are also logistical and port costs. We used the 

report from AgraFNP to estimate such costs since it was the only resource that included both 

logistical and port costs. The total average logistical and port cost for sugarcane ethanol is 

$0.20/gal and $0.09/gal, respectively, as shown in Table 4.1-33. 

Table 4.1-33. 

Imported Ethanol Cost at Port in Brazil (2007 $’s) 

Logistical Costs Port Cost 

Region US ($/gal) US ($/gal) 

NE Sao Paulo 0.150 0.097 

W Sao Paulo 0.210 0.097 

SE Sao Paulo 0.103 0.097 

S Sao Paulo 0.175 0.097 

N Parana 0.238 0.097 

S Goias 0.337 0.097 

E Mato Grosso do sul 0.331 0.097 

Triangulo mineiro 0.207 0.097 

NE Cost 0.027 0.060 

Sao Francisco Valley 0.193 0.060 

Average 0.197 0.089 

 Total fuel costs must also include the cost to ship ethanol from Brazil to the U.S. The 

average cost from 2006-2008 was estimated to be approximately $0.17 per gallon of ethanol.lxvii

Costs were estimated as the difference between the unit value cost of insurance and freight (CIF) 

and the unit value customs price. The average cost to ship ethanol from Caribbean countries 

(e.g. El Salvador, Jamaica, etc.) to the U.S. from 2006-2008 was approximately $0.13 per gallon 

of ethanol. Although this may seem to be an advantage for Caribbean countries, it should be 

noted that there would be some additional cost for shipping ethanol from Brazil to the Caribbean 

country. Therefore, we assume all costs for shipping ethanol to be $0.17 per gallon regardless of 

the country importing ethanol to the U.S. 

 The total imported ethanol fuel costs (at U.S. ports) over the time period of 2010 to 2022 

are shown in Table 4.1-34. In 2022, the total sugarcane ethanol cost estimate prior to tariffs and 

taxes is $1.50/gallon. Direct Brazilian imports are also subject to an additional $0.54 per gallon 

tariff, whereas those imports arriving in the U.S. from Caribbean Basin Initiative (CBI) countries 

are exempt from the tariff. In addition, all imports are given an ad valorem tax of 2.5% for 

undenatured ethanol and a 1.9% tax for denatured ethanol. We assumed an ad valorem tax of 

2.5% for all ethanol. Thus, including tariffs and ad valorem taxes, the average cost of imported 

ethanol is shown in Table 4.1-35 in the “Brazil Direct w/ Tax & Tariff” and “CBI w/ Tax” 

columns for the years 2010-2022. 
Table 4.1-34. Average Imported Ethanol Costs Prior to Tariff and Taxes 

 

Sugarcane 

Production 

Cost ($/gal) 

Operating 

Cost 

($/gal) 

Capital 

Cost 

($/gal) 

Logistical 

Cost 

($/gal) 

Port 

Cost 

($/gal) 

Transport Cost 

from Port to US 

($/gal) 

Total 

Cost 

($/gal) 

2010 0.59 0.04 0.49 0.20 0.09 0.17 1.58 

2011 0.58 0.04 0.49 0.20 0.09 0.17 1.57 

2012 0.57 0.04 0.49 0.20 0.09 0.17 1.56 

2013 0.56 0.04 0.49 0.20 0.09 0.17 1.55 

2014 0.55 0.04 0.49 0.20 0.09 0.17 1.54 

2015 0.54 0.04 0.49 0.20 0.09 0.17 1.53 

2016 0.54 0.04 0.49 0.20 0.09 0.17 1.53 

2017 0.53 0.04 0.49 0.20 0.09 0.17 1.52 

2018 0.53 0.04 0.49 0.20 0.09 0.17 1.52 

2019 0.53 0.04 0.49 0.20 0.09 0.17 1.52 

2020 0.52 0.04 0.49 0.20 0.09 0.17 1.51 

2021 0.52 0.04 0.49 0.20 0.09 0.17 1.51 

2022 0.51 0.04 0.49 0.20 0.09 0.17 1.50 

Table 4.1-35. Average Imported Ethanol Costs 

 

Brazil 

Direct 

($/gal) 

Brazil Direct w/ 

Tax & Tariff ($/gal) 

CBI 

($/gal) 

CBI w/ Tax 

($/gal) 

2010 1.58 2.16 1.58 1.62 

2011 1.57 2.15 1.57 1.61 

2012 1.56 2.14 1.56 1.60 

2013 1.55 2.13 1.55 1.59 

2014 1.54 2.12 1.54 1.58 

2015 1.53 2.11 1.53 1.57 

2016 1.53 2.11 1.53 1.57 

2017 1.52 2.10 1.52 1.56 

2018 1.52 2.10 1.52 1.56 

2019 1.52 2.10 1.52 1.56 

2020 1.51 2.09 1.51 1.55 

2021 1.51 2.09 1.51 1.55 

2022 1.50 2.08 1.50 1.54 
55 

4.1.2 Biodiesel Production Costs 

Virgin vegetable oils, fats, waste oils and greases costs 

 The feedstocks that we project to make up the largest share of biodiesel are virgin 

vegetable oil (primarily soy oil) and non-food-grade corn oil generated as a co-product of dry 

mill ethanol production. These feedstock streams were included in the agricultural commodity 

modeling done for this rulemaking using the FASOM model. This work is described in detail in 

Section 2.5 of this RIA. Table 4.1-36 summarizes the volumes and costs of these feedstocks. 

 Rendered fats and other waste greases are expected to make up a smaller, but still 

important, source of biodiesel feedstock. These were not explicitly modeled by FASOM; 

18therefore their value was estimated to be 70% that of soy oil, based on historical trends. 

Table 4.1-36. Summary of biodiesel feedstock use and cost 

 for primary control case in 2022 (2007$). 

Fuel / Feedstock Feedstock Price 

($/lb) 

Projected use in 2022 

(MMgal) 

Soy oil 0.33 a 660 

Corn oil from dry mill ethanol production 0.17 a 680 

Yellow grease or other rendered fats 0.23 b 230 

Algae oil or other advanced feedstock 0.58 c 100 

Algae-derived oils costs 

Algae oil cost projections are based on Aspen modeling completed by NREL and are 

reported in 2007 dollars. Detailed cost information is provided in their report submitted to the 

docket.lxviii The results are summarized below in Figure 4.1-4. Two production pathways were 

assumed, open pond (OP) and photobioreactor (PBR) systems. For each production pathway a 

base case, aggressive case, and maximum development case were evaluated based on 

assumptions on key variables e.g., yield, lipid content on algae, etc. The oil production cost for 

the open pond case ranged from $11.25/gal in the base case to $3.99/gal for the max case. The 

oil production cost for the PBR case ranged from $19.49/gal in the base case to $6.62/gal in the 

max case. 

 

18 Data available from various sources suggests that tallow and yellow grease prices have been closer to half the 

value of crude soy oil, but we have chosen to assume 70% as this is what USDA/ARS had assumed during some 

initial cost modeling they had done for us. Also, given that rendered fat volumes will be more limited than 

vegetable feedstocks, we might expect their prices to rise against the alternative (and still more expensive) vegetable 

feedstocks in a climate of higher biofuel production. 
Figure 4.1-4. 

Cost to Produce 10 MMgal/yr oil at growth rate scenarios developed by NREL for open 

pond (op) and photobioreactor (PBR) production. TAG = 

triacylglyceride

Since algal biofuel technology is still in a relatively early stage of development, there is a 

higher degree of uncertainty associated with potential performance and cost relative to more 

established technologies. It is important to note that the “max” case merely means the maximum 

algae growth and oil content applied to the specific configuration and associated assumptions 

analyzed and does not imply that these are the absolute lowest costs that can ever be achieved as 

technology develops. For the algal technology systems analyzed, the report indicated that the 

areas with the highest economic impact include the optimum amount of nutrients required, the 

CO2 delivery cost, the flocculant requirement for harvesting, and the material costs for the PBR 

production system. The economic modeling assumptions and results from NREL for 

microalgae-derived oil correspond well with other studies which report the cost of production for 

algae oil from $1 to >$40/gal.lxix 

 NREL also investigated the uncertainty in key assumptions and the associated potential 

cost impact of such assumptions in a sensitivity analysis. Figure 4.1-5 shows that for open 

ponds, the amount of nutrients required has the highest impact on production cost of the 

variables evaluated. Figure 4.1-6 shows that the single largest cost item in the PBR system is the 

cost of the tubes themselves. 
57 

Figure 4.1-5. Open Pond Sensitivity Analysis 

Figure 4.1-6: PBR Sensitivity Analysis 

For this rulemaking, we made the simplifying assumption of using the production cost of 

the open pond aggressive case of $5.11/gal or $0.68/lb for this feedstock to estimate costs of 

algae-derived fuel. Given the uncertainties in estimating costs for algae as well as the need for a 

single-value estimate for algal oil for cost analyses purposes, we chose the open pond aggressive 

case which appears to represent a somewhat middle value as well as a more reasonably 

competitive feedstock with alternatives, such as soy oil. 

Biodiesel production costs 
Biodiesel production costs for this rule were estimated using two variations of a model 

generated by USDA for a 10 million gallon-per-year transesterification biodiesel plant. One 

version uses degummed soy oil as feedstock, and a second version includes acid pre-treatment 

steps required to utilize feedstocks such as rendered fat and yellow grease, which have higher 

free fatty acid content. USDA used the SuperPro Designer chemical process simulation software 

to build up a process model with estimates of heat and material flowrates and equipment sizing. 

Outputs from this model were then combined in a spreadsheet with capital, energy, labor, and 

feedstock costs to generate a final estimate of production cost. Additional details on the model 

are given in a 2006 technical publication in the peer-reviewed scientific journal Bioresource 

Technology.lxx At 10 million gallons per year, the modeled plant size is between the mean and 

median plant sizes (16 million and 6 million gal/yr, respectively) as given in our industry 

characterization. Therefore, the model cost estimate is believed to be sufficiently accurate for 

our analyses and no further work was done to determine the effect of scale on production cost. 

 This model is periodically updated by USDA to reflect technology upgrades, changes to 

cost of capital, etc. Such an update was made to the model just before its outputs were used in 

the analyses presented here. We also made modifications to the capital cost to be consistent with 

typical cost amortization schemes used for regulatory programs. The capital charge estimate was 

derived as shown in Table 4.1-37. Installed capital cost was $11.9 million; adding 3% annual 

maintenance charge, we arrive at a final capital charge of 14% annually. Energy prices were 

taken from AEO 2009: natural gas at $7.75/MMBtu and electricity at $0.066/kWh for 2022 in 

2007 dollars. 
59 

Table 4.1-37. Economic Factors Used in Deriving the Capital Cost Amortization Factor 

Amortization 

Scheme

Depreciation 

Life

Economic 

and Project 

Life

Federal and 

State Tax 

Rate

Return on 

Investment 

(ROI)

Annual 

Maintenance 

Charge 

Resulting 

Capital 

Amortization 

Factor

Societal Cost 10 Years 15 Years 0% 7% 3% 0.14 

 The value of the glycerin co-product has been depressed and volatile in recent years due 

to a large increase in production in biodiesel facilities. This has been balanced at times by new 

uses coming online as feedstocks for traditionally petrochemical-based products as well as 

increased demand in personal care and other consumer products as the standard of living 

increases in many parts of the world. Some facilities are even experimenting with using it as a 

supplemental fuel along with biomass or other materials. We can expect that new uses for 

glycerin will continue to be found as long as it is plentiful and cheap. For a simple and 

conservative projection of its value in the future, we have assumed an energy-equivalent value 

based on residual heating oil. Using a heating value of 7,979 Btu/lb and a heating oil value of 

$18.90/MMBtu in 2022, we arrive at $0.15/lb as a co-product value. Table 4.1-38 shows the 

overall process material balance output by the model. 

Table 4.1-38. Material Balance and Values for Biodiesel Production Model in 2022 

Stream By weight Estimated value (2007$) 

Soy oil input 100 $0.33/lb 

Methanol input 11 $0.16/lb 

Biodiesel output (main product) 100 - 

Glycerin output (co-product) 12 $0.15/lb 

 Table 4.1-39 shows the production cost allocation for the soy oil-to-biodiesel facility as 

modeled in the 2022 primary control case. Production cost for biodiesel is primarily a function of 

feedstock price, with other process inputs, facility, labor, and energy comprising much smaller 

fractions. 

Table 4.1-39. Production cost allocation for soy biodiesel derived from this analysis for the 

primary control case in 2022 

Cost Category Share of Per-Gallon Cost 

Soy Oil 85% 

Other Materials a 6% 

Capital & Facility 6% 

Labor 2% 

Utilities 2% a Includes acids, bases, methanol, catalyst 
4.1.3 Renewable Diesel Production Costs

The renewable diesel process converts rendered fats (or plant oils) into diesel fuel using 

thermal depolymerization, which is similar to refinery hydrotreating used to remove sulfur. The 

process uses hydrogen and catalyst to remove oxygen from the triglyceride molecules in the 

feedstocks oils via a decarboxylation and hydro-oxygenation reaction, yielding some light 

petroleum products and water as byproducts. The reactions also saturate the olefin bonds in the 

feedstock oils, converting them to paraffins, and may also isomerize some paraffins. Depending 

on process operating conditions, the yield to diesel-range material is typically between 90-99% 

volume, with the rest being naphtha and light fuel gases (primarily propane). 

As described in the industry characterization discussion (see RIA Section 1.5.4), we have 

chosen to focus on stand-alone renewable diesel production, as we believe this will be the 

primary pathway given tax incentives and the definition of the biomass-based diesel fuel 

category. We assume a total project cost of $150MM for a standalone facility based on materials 

made publically available by Syntroleum Corp. related to their Geismar, LA, project.lxxi 

Our operating cost and yield estimates were derived from material presented by UOP and 

Eni at a 2007 industry conference, which describes producing renewable diesel in a grass roots 

standalone production process inside a refinery.lxxii In addition to feedstock and facility costs, 

another significant cost input is hydrogen. For hydrogen operating costs, we used the UOP 

analysis and guidance from Conoco Philips to derive our estimate to make renewable diesel. lxxiii

The UOP paper presents a range of 1000 to 2000 standard cubic feed (scf) per barrel for 

converting the various feedstock to renewable diesel. Based on characteristics of rendered fats, 

we estimated a hydrogen demand of 1,590 SCF/bbl of feedstock processed. 

Accounting for this quantity of hydrogen, along with a value taken from our refinery 

modeling work, we derived a figure of 6.9 cents/gallon of diesel product to cover utilities, labor, 

and other costs. Finally, total cost per gallon was estimated at $2.42 for the 2022 primary control 

case (2007 dollars). Table 4.1-40 gives more details for the process assumed in this analysis. 

Co-product values were also taken from refinery modeling work done for this rulemaking. Table 

4.1-41 shows the cost allocation we arrived at for renewable diesel production. 

Table 4.1-40. 

Parameters used in renewable diesel production cost estimates. 

Stream By volume Estimated value (2007$) 

Fat input 100 gal $0.23/lb 

Hydrogen input 505 scf $0.0044/scf 

Renewable diesel output (main product) 93.5 gal - 

Naphtha output (co-product) 5 gal $0.55/lb 

Light fuel gas output (co-product) 9 gal $0.13/lb 
61 

Table 4.1-41. 

Production Cost Allocation for Renewable Diesel for Primary Control Case in 2022 

Cost Category Contribution to Cost 

Feedstock 78% 

Capital & Facility 11% 

Hydrogen 7% 

Other variable costs 3% 

4.1.4. Biodiesel and Renewable Diesel Cost Summary 

 Table 4.1-42 summarizes the feedstock prices and fuel production cost for biodiesel. 

Table 4.1-43 gives the same information for renewable diesel. Combined with information from 

Table 4.1-36, a weighted average production cost could be estimated (our overall economic 

impacts take into account this information). 

Table 4.1-42 

Summary of Costs for Biodiesel for the Primary Control Case in 2022 

Fuel / Feedstock Feedstock Price 

($/lb) 

Fuel Production Cost 

($/gal) 

Biodiesel / soy oil 0.33 a 2.73 

Biodiesel / corn oil extraction at ethanol 

plants 

0.17 a 1.90 

Biodiesel / yellow grease or other rendered 

fats 

0.23 b 2.43 

Biodiesel / algae or other advanced virgin oil 

feedstock 

0.58 c 4.52 d

a Taken from outputs of FASOM model. 

b

 Derived from outputs of FASOM model, assuming 70% value of soy oil. 

c

 Derived from figures in a Technical Memo by Ryan Davis of NREL entitled “Techno-economic analysis of 

microalgae-derived biofuel production” (available in docket). 

d

 This production cost assumes this advanced feedstock has very low free fatty acid content. 

Table 4.1-43 

Summary of Cost for Renewable Diesel for the Primary Control Case in 2022 

Fuel / Feedstock Feedstock Price 

($/lb) 

Fuel Production Cost 

($/gal) 

Renewable diesel / yellow grease or other 

rendered fats 

0.23 a 2.42 

a

 Derived from outputs of FASOM model, assuming 70% value of soy oil. 
4.1.5 BTL Diesel Production Costs 

 Biofuels-to-Liquids (BTL) processes, which are also thermochemical processes, convert 

biomass to liquid fuels via a syngas route. If cellulose is converted to syngas, rather than 

converting the syngas to mixed alcohols, a Fischer Tropsch reactor can be added to convert the 

syngas to diesel fuel and naphtha. The primary product produced by this process is diesel fuel. 

This technology is commonly termed biomass-to-liquids (BTL) because of its similarity to gasto-liquids and coal-to-liquids technology. Diesel fuel’s higher energy density per gallon than 

ethanol and even biodiesel provides it an inherent advantage over these other fuels. In addition, 

BTL diesel fuel can be more easily distributed from production to retail outlets and used by 

motor vehicles. The diesel fuel produced by the Fischer Tropsch process tends to be comprised 

of paraffins which provide a much higher cetane number than petroleum diesel fuel, with a 

downside of poorer cloud point which reduces its widespread use in cold temperatures. 

 There are many steps involved in a BTL process which makes this a capital-intensive 

process. The first step, like all the cellulosic processes, requires that the feedstocks be processed 

to be dried and ground to a fine size. The second step is the syngas step, which 

thermochemically reacts the biomass to carbon monoxide and hydrogen. Since carbon monoxide 

production exceeds the stoichiometric ideal fraction of the mixture, a water shift reaction must be 

carried out to increase the relative balance of hydrogen. The syngas products must then be 

cleaned to facilitate the following Fischer-Tropsch (FT) reaction. The Fischer-Tropsch reaction 

reacts the syngas to a range of hydrocarbon compounds – a type of synthetic crude oil. This 

hydrocarbon mixture is then hydrocracked to maximize the production of high cetane diesel fuel, 

although some low octane naphtha and small amounts of wax are also produced. The many steps 

of the BTL process contribute to its high capital cost. 

Although there were several studies available which provided costs estimates for BTL 

diesel fuel, they did not provide sufficient detail to understand all the cost elements of BTL 

diesel fuel and naphtha. EPA therefore contracted with NREL to estimate the production costs 

for BTL diesel fuel and naphtha. Like the other technologies, we asked for cost estimates for the 

same years assessed above for cellulosic ethanol which was for 2010, 2015 and 2022, however, 

NREL did not believe that the costs would change that much over this time span. So NREL only 

provided the costs for 2022, advising us that the costs would only be slightly less for earlier 

years, and most of that difference would because of the poorer economies of scale if the initial 

plants are sized smaller. Table 4.1-44 summarizes the cost information provide by NREL to 

EPA for a year 2022 cellulosic BTL plant. 
63 

Table 4.1-44 

Year 2022 Production Costs for Thermochemcal (BTL) Cellulosic 

Fischer Tropsch Diesel Fuel Provided by NREL 

(2007 dollars and 10% after tax rate of return)

Plant Size MMgal/yr 33.2 Diesel Fuel 

49.4 All Liquid 

Capital Cost $MM 346 

Capital Cost 10% ROI after taxes ($MM/yr) 61.7 

Fixed Costs ($MM/yr) 18.3 

Feedstock Cost ($MM/yr) 39.1 

Coproduct Credit ($MM/yr)a -53.5 

Other raw material Costs ($MM/yr) 0.9 

Waste Disposal and Catalyst Costs ($MM/yr) 1.1 

Total Costs ($MM/yr) 79 

Total Costs (cents/gallon of diesel fuel) 206 

a Based on a naphtha coproduct value of 327 cents per gallon. 

NREL estimated that diesel fuel made by a 33 million gallon per year FT plant in 2022 

could be produced at $2.06 per gallon estimated (in year 2007 dollars).lxxiv Three adjustments 

however are needed to make the NREL production cost compatible with the rest of our analysis: 

1) increase the feedstock costs, 2) reduce the capital charge costs and 3) adjust the co-product 

prices for naphtha and wax. 

For capital charges, the NREL costs were based on amortizing capital assuming a 10 

percent rate of return after taxes, using an annual capital charge factor of 0.178. The report’s 

estimate for capital costs was $346 million for the plant, resulting in annual capital cost of $61.6 

million or $1.85 per gallon of diesel fuel produced. We adjusted the capital cost by amortizing 

the capital cost assuming a 7 percent rate of return before taxes, using an annual capital charge 

factor of 0.11 which resulted in yearly cost of $38 million or $1.14 per gallon of diesel fuel 

produced. 

In the NREL study, the total operating cost due to feedstock is $1.17 per gallon, using 

wood at $50.7 per dry ton. We adjusted the feedstock cost to $67.4 per dry ton, see subsection

4.1.1.2.1, which increased the feedstock costs to $1.56 per gallon of diesel fuel. 

 In the NREL analysis, the co-products produced have a credit value of $1.60 per gallon 

of diesel fuel, assuming a price for naphtha of $3.27 per gallon and wax at $0.49 per pound. The 

price of naphtha was set by NREL at 40 cents per gallon below the price of gasoline to account 

for its low octane value. The naphtha produced by the BTL process is also largely comprised of 

paraffins, however, as a gasoline blendstock it is poor because its octane could potentially be as 

low as 50. This material could be processed by refinery isomerization units raising its octane to 

perhaps 70 octane, but it cannot be processed by refinery reformers since it does not contain the 

napthenic compounds that are necessary for octane improvement by those units. Because of the 

large amount of octane rich ethanol which is expected to be made available from both corn and 

cellulose, it could be that BTL naphtha could be blended along with the ethanol into the gasoline 

pool. Rather than prejudge how this naphtha may be utilized in the future, for our cost analysis 
we simply assigned it a coproduct credit. So we set the BTL naphtha cost to be 83% as much of 

the cost of BTL diesel fuel based on its relative energy density. This results in a naphtha price of 

$1.98 per gallon. We adjusted the price of wax, by ratio-ing the NREL price by the change in 

price for naphtha. The price adjustment for naphtha and wax, results in a co-product value of 

$0.97 per gallon of FT diesel produced. The result is a diesel fuel production cost of $2.37 per 

gallon from the FT process. 

Table 4.1-45 summarizes NREL’s estimated and projected production costs for a 

thermochemical Fischer Tropsch biochemical cellulosic ethanol plant technology for their 

projected year 2022 technology in 2007 dollars reflecting a 7 percent before tax rate of return on 

investment. The costs are based on a cellulosic feedstock cost of $67.4 per dry ton. 

Table 4.1-45 

Year 2022 Production Costs for Thermochemcal (BTL) Cellulosic 

Fischer Tropsch Diesel Fuel Provided by NREL 

(2007 dollars and 7% before tax rate of return)

Plant Size MMgal/yr 33.2 Diesel Fuel 

49.4 All Liquid 

Capital Cost $MM 346 

Capital Cost 7% ROI before taxes ($MM/yr) 38 

Fixed Costs ($MM/yr) 18 

Feedstock Cost ($MM/yr) 52 

Coproduct Credit ($MM/yr)a -32 

Other raw matl. Costs ($MM/yr) 1.5 

Waste Disposal and Catalyst Costs ($MM/yr) 1.5 

Total Costs ($MM/yr) 79 

Total Costs (cents/gallon of diesel fuel) 237 

 a Based on a naphtha coproduct value of 198 cents per gallon. 

Initially, the estimated cost of $2.37 per gallon seems high relative to the projected cost 

for a year 2022 biochemical cellulosic ethanol plant, which is 126 cents per gallon of ethanol 

(see subsection 4.1.1.2.4). However, ethanol provides about half the energy content on a per 

gallon basis as Fischer Tropsch diesel fuel. So, if we double the biochemical cellulosic ethanol 

costs to $2.52 to be consistent with the energy per diesel fuel-equivalent gallon, the estimated 

costs are very consistent between the two. The cellulosic biofuel tax subsidy currently favors the 

biochemical ethanol plant, though, because it is a per-gallon subsidy regardless of the energy 

content, and it therefore offsets twice as much cost as the BTL plant producing diesel fuel. 

However, the cellulosic diesel fuel may still be more valuable in the marketplace than cellulosic 

ethanol. In 2008 and for much of 2009 diesel fuel was priced higher than gasoline, and if this 

trend continues in the future, it may provide a better market for selling the BTL diesel fuel than 

for selling biochemical ethanol into the E85 market. 

 It was necessary to estimate cellulosic diesel fuel costs for previous years for the year-byyear cost analysis (see Section 4.4). However, NREL did not provide costs for previous years, 

although NREL did say that the primary difference in costs for the previous years would be 
65 

economies of scale impacts for the capital costs due to smaller sized plants. Thus, to derive a 

cost for 2010, we estimated that the cellulosic diesel fuel plants that would be installed in 2010 

would be half the size of the plant estimated for 2022. While the total capital costs decrease, the 

capital costs increase relative to the volume of cellulosic diesel fuel produced. We increased the 

naphtha credit from 198 cents per gallon to 216 cents per gallon to maintain an 83% cost 

percentage relative to the cellulosic diesel fuel. For this smaller plant size, we estimate the cost 

for cellulosic diesel fuel to be 258 cents per gallon. 

Other Cellulosic Diesel Fuel Costs 

 

For our volumes analysis, we assumed early on for our final rule analysis that there 

would likely be one or more other cellulosic diesel fuel technologies, other than BTL, producing 

cellulosic diesel fuel. However, we were either not able to obtain cost information from them, or 

we were uncertain enough about their future that we felt that we should not base the cost of the 

program on them. For example, Cello Energy has already built a cellulosic diesel fuel facility in 

Alabama here in the US with projected costs of about one dollar per gallon of diesel fuel. 

However, the facility has had difficulty operating as designed. As a result, perhaps very 

conservatively, we assumed that the other cellulosic diesel fuel costs would be the same as the 

BTL diesel fuel costs, and used the 237 cents per gallon cost for BTL diesel fuel for the entire 

cost for cellulosic diesel fuel. 

4.2 Renewable Fuel Distribution Costs 

 Our analysis of the costs associated with distributing the volumes of biofuels that we 

project will be used under RFS2 focuses on: 1) the capital cost of making the necessary 

upgrades to the fuel distribution infrastructure system directly related to handling these fuels, and 

2) the ongoing additional freight costs associated with shipping renewable fuels to the point 

where they are blended with petroleum-based fuels. Our analysis considers distribution costs 

within the U.S. only. The costs associated with bringing ethanol imports to the U.S. are 

considered in the context of the cost of the imports themselves. We chose to evaluate the 

distribution costs for cellulosic distillate and renewable diesel together because the same 

considerations apply to their handling in the fuel distribution system and because the projected 

volume of renewable diesel fuel is relatively small. The following sections outline our estimates 

of the distribution costs for the additional volumes of ethanol, cellulosic distillate fuel/renewable 

diesel fuel, and biodiesel that we project will be used to meet the RFS2 standards. There will be 

ancillary costs associated with upgrading the basic rail, marine, and road transportation nets to 

handle the increase in freight volume due to the RFS2. We have not sought to quantify these 

ancillary costs because 1) the growth in freight traffic that is attributable to RFS2 represents a 

minimal fraction of the total anticipated increase in freight tonnage (approximately 0.4% by 

2022, see Section 1.6.3 of this RIA), and 2) we do not believe there is an adequate way to 

estimate such non-direct costs.

 The biofuels used in response to the RFS2 standards will displace petroleum-based fuels 

that would otherwise be used. Thus, it would be appropriate to subtract the distribution costs for 

the displaced petroleum-based fuels from the distribution costs attributed to the biofuels that 
replace these petroleum-based fuels. However, we chose not to do so as it is difficult to project 

exactly what changes would result in cost savings. As a result, our analysis should provide a 

conservatively high estimate of biofuel distribution costs given the uncertainties in our analysis. 

A discussion of the changes that will be needed in the biofuels distribution system to 

accommodate the increased volumes of biofuels that we project will be used to meet the RFS2 

standards is contained in Section 1.6 of this RIA. In this Section, we further detail the nature of 

these projected changes and estimate the associated costs. Distribution capital costs associated 

with the additional volume of ethanol, cellulosic distillate fuel/renewable diesel, and biodiesel 

that we project will be used by 2022 to meet the RFS2 standards under the primary mid-ethanol 

scenario relative to the AEO 2007 reference case totals $8.4 billion, of which 68% is attributed to 

ethanol, 17% to cellulosic distillate/renewable diesel fuel, and 14% to biodiesel. 

4.2.1 Ethanol Distribution Costs 

As discussed in the following sections, we estimate that the total capital costs in the U.S 

to support distribution of the additional volume of ethanol that will be used to meet the RFS2 

standards under the primary mid-ethanol scenario will be $5.5 billion by 2022 relative to the 

AEO 2007 reference case. When amortized, this translates to 7 cents per gallon of additional 

ethanol used to meet the RFS2 standards. Amortization of capital costs was done over 15 years 

at a 7% annual cost of capital except in the case of the cost of tank trucks where a 10 year 

amortization schedule was used. These costs were calculated relative to the AEO 2007 baseline 

which projects that 13.2 BGY of ethanol would be used in 2022 absent the RFS2 standards. 

Under the mid-ethanol primary scenario, we project that 22.2 BGY of ethanol will be used by 

2022. Ethanol freight costs are estimated to be 13 cents per gallon on a national average basis. 

Thus, we estimate that total ethanol distribution costs will be 20 cents per gallon of ethanol that 

we project will be used to meet the RFS2 standards.19

The ethanol distribution capital and freight costs for all the control scenarios relative to 

the 2 reference cases that we evaluated in this FRM is summarized in Table 4.2-1. The itemized 

ethanol capital costs are presented in Table 4.2-2 relative to the AEO 2007 reference case, and in 

Table 4.2-3 relative to the RFS1 reference case. These costs do not include the potential costs to 

supply butane to terminals for E85 blending, which are presented in Table 4.2-4. The way in 

which we estimated these costs is detailed in the following sections. 

 

19 As noted previously, we chose not to subtract the distribution costs for the petroleum-based fuels that would be 

displaced by the use of biofuels from our estimated biofuel distribution costs. We believe that the freight costs to 

ship petroleum-based fuels to the terminal are approximately 4 cents per gallon. If we were to subtract these costs 

from the estimated ethanol distribution costs under the mid-ethanol scenario relative to the AEO 2007 reference 

case, the result would be 16 cents per gallon. 
67 

Table 4.2-1. 

Summary of Estimated Ethanol Distribution Capital and Freight Costs for the RFS2 

Control Scenarios Relative to the Reference Cases 

Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

RFS1 

Reference 

AEO 

Reference

RFS1 

Reference 

AEO 

Reference 

RFS1 

Reference 

AEO 

Reference

Billion $ 

Capital 

5.5 3.0 7.9 5.5 11.9 9.9 

Capital 

Costs (cpg) 

6 8 6 7 5 6 

Freight 

Costs 

(cpg) 

13 13 13 13 12 12 

Total 

Distribution 

Costs 

(cpg) 

19 21 19 20 17 18 

Table 4.2-2. 

Summary of Estimated Ethanol Distribution Capital Costs 

for the RFS2 Control Scenarios Relative to the AEO 2007 Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Rail Cars 365 760 1,699 

Barges 22 45 102 

Tank Trucks 42 87 194 

Storage Tanks at Petroleum Terminals 355 739 1,568 

Blending and other Miscellaneous 

Equipment at Petroleum Terminals 

345 411 503 

Unit Train Receipt Facilities 238 434 748 

Manifest Rail Receipt Facilities 7 12 21 

Marine Receipt Facilities for Inta-U.S. 

Transport 

76 100 144 

Import Receipt Facilities 49 53 63 

E85 Retail Facilities 1,526 2,863 4,893 

Total (Million $) 3,025 5,505 9,935 

Total (cpg) 8 7 6 
Table 4.2-3. 

Summary of Estimated Ethanol Distribution Capital Costs 

for the RFS2 Control Scenarios Relative to the RFS1 Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Rail Cars 884 1,279 2,218 

Barges 53 77 133 

Tank Trucks 107 154 268 

Storage Tanks at Petroleum Terminals 859 1,243 2,073 

Blending and other Miscellaneous 

Equipment at Petroleum Terminals 

1,006 1,064 1,144 

Unit Train Receipt Facilities 444 586 838 

Manifest Rail Receipt Facilities 15 20 28 

Marine Receipt Facilities for Inta-U.S. 

Transport 

98 130 186 

Import Receipt Facilities 49 53 63 

E85 Retail Facilities 1,957 3,293 4,973 

Total (Million $) 5,471 7,898 11,922 

Total (cpg) 6 6 5 

Table 4.2-4. 

Potential Costs to Provide Butane to Terminals for E85 Blending 

for the RFS2 Control Scenarios 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Butane Blending, Storage, Receipt and 

Other Miscellaneous Terminal Costs 

235 536 1,249 

Tank Trucks 325 830 837 

Rail Cars 32 81 89 

Total Capital Costs 592 942 2,175 

Freight Cost (Annual cost in 2022) 16 24 40 

Total Butane Distribution Costs 

Relative to the RFS1 Reference Case 

(cpg ethanol) 

1 1 1 

Total Butane Distribution Costs 

Relative to the AEO Reference Case 

(cpg ethanol) 

2 2 2 
69 

4.2.1.1 Capital Costs to Upgrade the Ethanol Distribution System 

4.2.1.1.1 Petroleum Terminal Ethanol Distribution Capital Costs 

 The terminal facility modifications needed to support the use of the volume of ethanol 

that we project will be used to meet the RFS2 standards are discussed in Section 1.6.7. A 

summary of the costs associated with these modifications is detailed in Tables 4.2-5 and 4.2-6. 

Table 4.2-5. 

Ethanol Associated Petroleum Terminal Costs 

for the RFS2 Control Scenarios Relative to the AEO Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Costs 858 1,150 1,913 

Total Storage Tank Costs 355 739 1,568 

New Storage Tank Construction Costs 291 606 1,287 

Cost to Retrofit Existing Storage Tanks 64 133 282 

Costs to Prepare Terminals to Handle 

Ethanol for the First Time 

167 167 167 

Tank Truck Unloading Facilities 277 186 123 

Ethanol Blending and Miscellaneous 

Ethanol Handling Costs 

59 57 55 

Table 4.2-6. 

Ethanol Associated Petroleum Terminal Costs 

for the RFS2 Control Scenarios Relative to the RFS1 Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Costs 2,003 2,307 3,078 

Total Storage Tank Costs 859 1,243 2,073 

New Storage Tank Construction Costs 705 1,020 1,701 

Cost to Retrofit Existing Storage Tanks 154 223 372 

Costs to Prepare Terminals to Handle 

Ethanol for the First Time 

594 594 594 

Tank Truck Unloading Facilities 366 286 231 

Ethanol Blending and Ancillary 

Ethanol Handling Costs 

184 183 180 

 The above cost estimates are bases on the following. Input from terminal operators 

indicates that the primary modifications needed to prepare a terminal to handle ethanol for the 
first time are associated with the modification of vapor recovery equipment to handle ethanolcontaining gasoline at a cost of $1,000,000 per terminal. We added another $20,000 to account 

for related ancillary costs. Input from terminal operators indicates that the cost of ethanol 

blending equipment is $300 thousand for E10-capable equipment, $310 thousand for E85-

capable equipment, and $10,000 to upgrade E10-capable equipment to handle E85. Input from 

companies that are familiar with the installation of ethanol truck unloading equipment at 

terminals indicates that the cost averages $500 thousand per facility. Input from terminal 

operators indicates that the cost of new ethanol storage tank construction is $40 per barrel of 

capacity, and that the cost of retrofitting existing gasoline storage tanks for ethanol service is $5 

per barrel of capacity for the size of tanks that are likely to be used. 

 

4.2.1.1.2 Capital Cost of Unit Train Receipt Facilities for Ethanol 

Our estimation of the number of unit train receipt facilities that will be need to support 

the transport of the volumes of ethanol and cellulosic distillate fuel that we project will be used 

to meet the RFS2 standards is discussed in Section 1.6.4 of this RIA. Input from industry 

indicates that the cost of unit train receipt facility capable of handling 229 million gallons of 

biofuels per year is $10 million and the cost of a facility capable of handling 613 million gallons 

is $25 million. We interpolated between these two estimates to derive a cost estimate for each 

unit train receipt facility that we projected will be constructed based on its anticipated annual 

throughput volume. The total cost of unit train receipt facilities was divided between ethanol and 

cellulosic distillate fuel/renewable diesel fuel in proportion to the fraction of the total ethanol + 

cellulosic distillate fuel/renewable diesel fuel volume under the respective control scenario. 

Our projections of the total cost of unit train receipt facilities and the portion that we 

attributed to the volume of ethanol that we project will be used to meet the RFS2 standards is 

presented in Tables 4.2.7 and 4.2.8. 

Table 4.2-7. 

Cost of Unit Train Facilities to Facilitate the Transport of Ethanol 

for the RFS2 Control Scenarios Relative to the AEO Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Cost of Unit Train Facilities 

Needed for the Transport of Ethanol 

and Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

748 748 748 

Cost of Unit Train Facilities 

Attributed to Ethanol Transport 

238 434 738 
71 

Table 4.2-8. 

Cost of Unit Train Facilities to Facilitate the Transport of Ethanol 

for the RFS2 Control Scenarios Relative to the RFS1 Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Cost of Unit Train Facilities 

Needed for the Transport of Ethanol 

and Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

838 838 838 

Cost of Unit Train Facilities 

Attributed to Ethanol Transport 

444 586 838 

4.2.1.1.3 Capital Cost of Manifest Rail Receipt Facilities for Ethanol 

Our estimation of the number of manifest rail receipt facilities that will be needed to 

support the transport of the volumes of ethanol and cellulosic distillate fuel that we project will 

be used to meet the RFS2 standards is discussed in Section 1.6.4 of this RIA. The cost of these 

facilities was divided between ethanol and cellulosic distillate fuel/renewable diesel fuel in 

proportion to the fraction of the total ethanol + cellulosic distillate fuel/renewable diesel fuel 

volume. Based on input from companies familiar with the installation of manifest rail receipt 

facilities, we estimate that the total cost per facility will be $500 thousand. 

Our projections of the total cost of the manifest rail receipt facilities and the portion that 

we attributed to the volume of ethanol that we project will be used to meet the RFS2 standards is 

presented in Tables 4.2.9 and 4.2.10. 

Table 4.2-9. 

Cost of Manifest Rail Receipt Facilities 

for the RFS2 Control Scenarios Relative to the AEO Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Cost of Manifest Rail Receipt 

Facilities Needed for the Transport 

of Ethanol and Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

21 21 21 

Cost of Unit Train Facilities 

Attributed to Ethanol Transport 14 9 21 
Table 4.2-10. 

Cost of Manifest Rail Receipt Facilities 

for the RFS2 Control Scenarios Relative to the RFS1 Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Cost of Manifest Rail Receipt 

Facilities Needed for the Transport 

of Ethanol and Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

28 28 28 

Cost of Unit Train Facilities 

Attributed to Ethanol Transport 13 8 28 

4.2.1.1.4 Ethanol Import Facility Capital Costs 

Our estimation of the number of marine facilities that will be needed to support the 

receipt of the volume of imported ethanol that we project will be used to meet the RFS2 

standards is discussed in Section 1.6.5 of this RIA. We estimate that a total of 30 port facilities 

will receive imported ethanol by 2022. Of these ports, 14 will need to accommodate ethanol 

receipts for the first time under the low-ethanol scenario, 15 under the mid-ethanol scenario, and 

18 under the high ethanol scenario. 

 We believe that all such port facilities also serve as petroleum terminals. Thus, the cost 

of additional ethanol storage, ethanol blending equipment, and other miscellaneous equipment 

related to handling ethanol from the standpoint of terminal operations at such facilities is 

accounted for in the context of the costs at petroleum terminals (see Section 4.2.1.1.1 of this 

RIA). However, there will be additional costs at the port facilities which had not received 

ethanol in the past. Input from industry indicates that offloading large marine transport 

containers of ethanol requires significantly upgraded vapory recovery equipment. Based on this 

input, we estimated the cost of making the needed upgrades to vapor recovery equipment at 2.5 

million dollars per facility. We further estimated miscellaneous costs associated with delivery of 

ethanol into storage tanks from marine vessels at 1 million dollars per facility. This is meant to 

include new piping, pumps, various other fittings, and a contingency cost. The actual cost could 

be significantly lower. Thus, we estimate that the total cost to prepare for delivery of ethanol at a 

port that had not received ethanol before at 3.5 million dollars per facility. 

Based on the above, we estimate that the ethanol import port costs due to the importation 

of the additional volume of ethanol used to meet the RFS2 standards will be $49 million under 

the low-ethanol scenario, $52 million under the mid-ethanol scenario, and $63 million under the 

high-ethanol scenario. We assumed the same costs relative to both the RFS1 and AEO reference 

cases because we believe that the use of the incremental volume of ethanol imports attributed to 

meeting the RFS2 standards will take place after the RFS1 and AEO ethanol use volumes are 

met. 

4.2.1.1.5 Capital Costs of Barge Receipt Facilities for Intra-U.S Ethanol Transport 
73 

Our estimation of the number of barge receipt facilities for intra-U.S. biofuel shipment 

that will be need to support the transport of the volumes of ethanol and cellulosic distillate fuel 

that we project will be used to meet the RFS2 standards is discussed in Section 1.6.5 of this RIA. 

We estimate that 41 additional barge receipt facilities will receive shipments of ethanol and 

cellulosic distillate fuel/renewable diesel fuel relative to the AEO reference case and 53 relative 

to the RFS1 reference case. We used the same $3.5 million per facility cost that we estimated for 

the ethanol import facilities (see Section 4.2.1.1.4). The cost of these facilities was divided 

between ethanol and cellulosic distillate fuel/renewable diesel fuel in proportion to the fraction 

of the total ethanol + cellulosic distillate fuel/renewable diesel fuel volume. 

Our projections of the total cost of the barge receipt facilities and the portion that we 

attributed to the volume of ethanol that we project will be used to meet the RFS2 standards is 

presented in Tables 4.2.11 and 4.2.12. 

Table 4.2-11. 

Cost of Barge Receipt Facilities 

for the RFS2 Control Scenarios Relative to the AEO Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Cost of Barge Receipt 

Facilities Needed for the Transport 

of Ethanol and Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

143 143 143 

Cost of Barge Receipt Facilities 

Attributed to Ethanol Transport 

76 100 143 

Table 4.2-12. 

Cost of Barge Receipt Facilities 

for the RFS2 Control Scenarios Relative to the RFS1 Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Cost of Barge Receipt 

Facilities Needed for the Transport 

of Ethanol and Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

185 185 185 

Cost of Barge Receipt Facilities 

Attributed to Ethanol Transport 

98 129 185 
4.2.1.1.6 Ethanol Rail Car Capital Costs 

 Our estimation of the number of rail cars needed to transport the additional volume of 

ethanol that we project will be used to meet the RFS2 standards is discussed in Section 1.6.4 of 

this RIA. Based on input from rail car manufactures, we estimate that the cost of a new 30,000 

gallon rail car suitable for ethanol service is $90 thousand. The cost of the additional ethanol rail 

cars needed under the 3 control scenarios relative to the 2 reference cases is presented in Tables 

4.2-13 and 4.2-14. 

Table 4.2-13. 

Cost of Additional Ethanol Rail Cars 

for the RFS2 Control Scenarios Relative to the AEO Reference Case 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Number of Additional Rail Cars 4,050 8,450 18,870 

Rail Car Cost ($Million) $365 $760 $1,699 

Table 4.2-14. 

Cost of Additional Ethanol Rail Cars 

for the RFS2 Control Scenarios Relative to the RFS1 Reference Case 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Number of Additional Rail Cars 9,820 14,210 24,639 

Rail Car Cost ($Million) $884 $1,279 $2,218 

4.2.1.1.7 Ethanol Barge Capital Costs 

 Our estimation of the number of barges needed for intra-U.S. transport of the additional 

volume of ethanol that we project will be used to meet the RFS2 standards is discussed in 

Section 1.6.5 of this RIA. Based on input from fuel barge manufactures, we estimate that the 

cost of a new 10,000 barrel barge suitable for ethanol service is $1.4 million. The cost of the 

additional ethanol barges needed under the 3 control scenarios relative to the 2 reference cases is 

presented in Tables 4.2-15 and 4.2-16. 
75 

Table 4.2-15. 

Cost of Additional Ethanol Barges 

for the RFS2 Control Scenarios Relative to the AEO Reference Case 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Number of Additional Barges 16 32 73 

Cost of Barges ($Million) $22 $45 $101 

Table 4.2-16. 

Cost of Additional Ethanol Barges 

for the RFS2 Control Scenarios Relative to the RFS1 Reference Case 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Number of Additional Barges 38 55 95 

Cost of Barges ($Million) $53 $76 $133 

4.2.1.1.8 Ethanol Tank Truck Capital Costs 

 Our estimation of the number of tank trucks needed to transport the additional volume of 

ethanol that we project will be used to meet the RFS2 standards is discussed in Section 1.6.6 of 

this RIA. Based on input from ethanol tank truck manufactures, we estimate that the cost of a 

new 8,000 gallon tank truck suitable for ethanol service is $180 thousand. The cost of the 

additional ethanol tank trucks needed under the 3 control scenarios relative to the 2 reference 

cases is presented in Tables 4.2-17 and 4.2-18. 

Table 4.2-17. 

Cost of Additional Ethanol Tank Trucks 

for the RFS2 Control Scenarios Relative to the AEO Reference Case 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Number of Additional Tank Trucks 230 480 1,080 

Cost of Tank Trucks ($Million) $42 $87 $194 

Table 4.2-18. 

Cost of Additional Ethanol Tank Trucks 

for the RFS2 Control Scenarios Relative to the RFS1 Reference Case 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Number of Additional Tank Trucks 590 860 1,490 

Cost of Tank Trucks ($Million) $107 $154 $268 
4.2.1.1.9 E85 Retail Facility Costs 

 Our estimates of the number of additional E85 retail facilities and the number of E85 

refueling positions needed at such facilities to enable the use of the volumes of E85 that we 

project will be used to meet the RFS2 standards under the 3 control scenarios is contained in 

Section 1.6.9 of this RIA. Our estimates of the additional E85 refueling infrastructure that will 

be needed relative to the 2 reference cases are presented in Table 4.2-19 and 4.2-20. 

Table 4.2.19. 

Additional E85 Retail Facilities Needed by 2022 to Support the Projected Increase in E85 

use under the RFS2 Control Scenarios Relative to the RFS1 Reference Case 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

New E85 Installation with 1 Dispenser 14,967 10,923 0 

New E85 Installation with 2 Dispensers 0 12,133 0 

New E85 Installation with 3 Dispensers 0 0 27,099 

Addition of 2 Dispensers to Retail 

Facility that had 1 Dispenser 

0 0 1,210 

Table 4.2.20. 

Additional E85 Retail Facilities Needed by 2022 to Support the Projected Increase in E85 

use under the RFS2 Control Scenarios Relative to the AEO Reference Case 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

New E85 Installation with 1 Dispenser 11,677 7,633 0 

New E85 Installation with 2 Dispensers 0 12,133 0 

New E85 Installation with 3 Dispensers 0 0 23,809 

Addition of 2 Dispensers to Retail 

Facility that had 1 Dispenser 

0 0 4,500 

 The following estimates regarding the cost of E85 compatible retail equipment are based 

on input from gasoline retailers and other parties with experience in the requirements and costs 

associated with installing E85 retail equipment. The total cost of installing a two nozzle E85 

dispenser is estimated at $23,000. This is composed of $17,000 for the dispenser itself, $750 for 

hanging hardware, $950 for refueling island hardware, $3,000 for installation, and a $1,300 

contingency cost. Hanging hardware costs are composed of $310 for 2 nozzles, $135 for 2 

breakaway connections, $135 for 2 swivel connections, and $170 for 2 hoses. Refueling island 

hardware costs are composed of $450 for the dispenser island, $250 for an island sump pump, 

and $250 for bumper posts. Installation costs are composed of $1,500 for concrete removal and 

replacement, and $1,500 for wiring and piping. 

The cost of automatic tank level gauging equipment is estimated at $6,500. It is 

estimated that 65% of retailers will install automatic tank gauging (ATG) equipment and the 

remainder will rely on manual means of determining the amount of fuel remaining in their 
77 

underground storage tank. Thus, the average cost per facility will be $4,225 for ATG equipment. 

We estimate the cost of installing a canopy addition to provide cover for an additional dispenser 

at $15,000. We estimated that only 10% of facilities will need to install additional canopy 

coverage in order to accommodate the new E85 retail dispenser. Thus, the average canopy cost 

per facility is estimated at $1,500. The cost of installing a new 15,000 underground E85 storage 

tank is estimated at $102,000. The cost of connecting the tank to the dispenser(s) is included in 

this cost along with other miscellaneous storage tank related costs. In the NPRM, we estimated 

that an 8,000 gallon storage tank would be used at E85 retail facilities. We increased the size to 

15,000 based on industry comments that the added storage volume will be needed to keep pace 

with fuel throughput without necessitating an overly-frequent fuel delivery schedule. The use of 

a 15,000 gallon storage tank will also allow the delivery of a full 8,000 gallon tank truck at a 

single retail facility. Input from fuel retailers indicates that there typically is at least 15,000 

gallons of gasoline storage at current retail facilities. 

 Our E85 retail facility cost estimates are presented in Table 4.2-21 are based on the above 

E85 equipment cost estimates and the estimated facility requirements detailed in Tables 4.2-19 

and 4.2-20. 

Table 4.2-21. 

Cost of the Additional E85 Retail Facilities Needed by 2022 

to Support the Projected Increase in E85 use under the RFS2 Control Scenarios 

 E85 Capital Costs ($Billion) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Relative to the AEO 2007 Reference 

Case 

1.526 2.863 4.893 

Relative to the RFS1 Reference Case 1.956 3.293 4.973 

4.2.1.1.10 Potential Costs of Supplying Special Blendstocks at Petroleum Terminals 

for E85 

As discussed in Section 1.6.8 of this RIA, special blendstocks may need to be supplied to 

terminals to facilitate the manufacture of E85 which meets ASTM International minimum 

volatility specifications. To evaluate the potential impacts to the fuel distribution system if this 

is the case, we assumed that butane would be used as the special blendstock and that it would be 

blended into gasoline before being blended with denatured ethanol to produce E85. As such, we 

estimated the potential costs associated with automated inline butane blending systems, butane 

storage tanks, tank trucks, railcars, transloading facilities, and other facility changes needed for 

butane blending into E85. These costs are based upon discussions with industry representatives.

We assume that butane would be transported by tank truck and/or railcar from petroleum 

refineries to E85-producing petroleum terminals and stored until blended into a final product. Of 

the 1,063 terminals identified in our analysis, two-thirds (709) are assumed to blend E85. All of 

these terminals are assumed to require butane blending equipment. Our cost estimates assumed 

that twenty-five percent (177) of these terminals will receive butane via 31,500 gallon railcar and 
the remaining seventy-five percent (532) will receive butane via 8,200 gallon tank truck. Of the 

177 terminals that receive butane via railcar, fifty-percent are assumed to directly off-load butane 

to tank storage for eventual blending into E85. The other fifty-percent of the terminals which 

received butane via railcar are assumed to transload the butane from railcars to tank trucks for 

final delivery to terminals which store butane for eventual blending into E85. 

The blending of butane into E85 requires petroleum terminals to have on-site butane 

blending equipment. In developing our cost estimates, we assume that each terminal which 

blends E85 uses an automated, in-line butane blending system and two 60,000 gallon butane 

storage tanks. The cost of an in-line butane blending systems is assumed to be $1.5 million per 

unit. The cost each 60,000 gallon butane storage tank is assumed to be $150,000. Transloading 

equipment is assumed to cost $500,000 per unit.

 Transport cost estimates were based upon the ORNL transport analysis discussed in 

Section 1.6.3. In that analysis, the cost of freight rail transport was assumed to average $0.12 per 

ton-mile. The cost of truck transport was assumed to average $0.14 per ton-mile. Average 

round trip distance is assumed to be 1,200 miles for railcars and 300 miles for tank trucks. 

Travel speed estimates are truck 35 mph and railcar 10 mph with roundtrip times being 

approximately 8 hours for trucks and 5 days for railcars. Each tank truck is assumed to cost 

$150,000 and each railcar is assumed to cost $135,000. 

Estimates of the number of tank trucks and railcars required to deliver butane appears by 

low, medium, and high volume cases in Table 4.2-22 and a summary of cost estimates for the 

three volume cases appears in Table 4.2-23. 

Table 4.2-22. 

Estimated Number of Tank Trucks and Rail Cars Needed for Shipment of Butane under 

the RFS2 Control Scenarios 

Number of Tank Trucks and Rail Cars Needed to 

Transport Butane 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario

High-Ethanol 

Scenario 

Tank Truck (8,200 gallons) 2,165 3,280 5,530 

Railcar (31,500 gallons) 236 358 602 

Table 4.2-23. 

Summary of Potential Costs to Provide Butane for E85 Blending 

under the RFS2 Control Scenarios 

 Freight Costs Capital Costs 

Low-Ethanol Scenario $16 million $357 million 

Mid-Ethanol Scenario $24 million $911 million 

High-Ethanol Scenario $40 million $927 million 
79 

4.2.1.2 Ethanol Freight Costs 

 Our estimates of ethanol freight costs are based on a study conducted by Oakridge 

National Laboratories (ORNL).lxxv The ORNL analysis contains detailed projections of which 

transportation modes and combination of modes (e.g. unit train to barge) are best suited for 

delivery of ethanol to specific markets considering ethanol source and end use locations, the 

current configuration and projected evolution of the distribution system, and cost considerations 

for the different transportation modes. The NPRM analysis assumed that all biofuel volumes 

other than biodiesel would be ethanol. For this FRM, we analyzed three scenarios under which 

varying volumes of cellulosic distillate fuel take the place of ethanol production volumes to meet 

the RFS2 standards. However, due to the timing of the various analyses for the FRM, the NPRM 

projections of the location of ethanol production facilities and end use areas contained in the 

NPRM had to be used as the inputs into the ORNL analysis.20 Therefore, our use of the ORNL 

analysis to evaluate the freight costs for the final rule assumes that cellulosic distillate production 

plants will take the place of some of the ethanol production plants projected in the NPRM. It 

further assumes that cellulosic distillate fuel use will coincide with the ethanol end-use areas 

projected in the NPRM and that both fuels will be transported by the same means. 

We estimated the freight costs under the FRM control scenarios by totaling the cellulosic 

distillate/renewable diesel fuel and ethanol volume under each scenario and interpolating 

between the freight costs projected by ORNL for 2 NPRM ethanol volume scenarios. This 

approach provides for the economy of scale in biofuel freight costs with increased volume. 

Based on this approach, we estimate that ethanol freight costs will be 12 cents per gallon (cpg) 

under the high-ethanol scenario and 13 cpg under the low-ethanol and mid-ethanol scenarios. 

Our use of the ORNL freight cost estimates to derive the freight FRM freight cost estimates is 

illustrated in Table 4.2-24. 

 

20 The ORNL final report contains maps of projected ethanol production locations and end use areas. 
Table 4.2-24. 

Interpolation of FRM Ethanol and Cellulosic Distillate Fuel/Renewable Diesel Fuel Freight 

Costs from ORNL Freight Cost Estimates 

for NPRM Ethanol Volume Scenarios 

 Volume of Ethanol, Cellulosic 

Distillate Fuel, and Renewable 

Diesel Fuel (BGal/yr in 2022) 

Freight Cost 

(cpg) 

NPRM Control Scenario 34.14 12.2 

(ORNL estimate)

FRM High-Ethanol Scenario 33.24 12 

(Interpolation) 

FRM Mid-Ethanol Scenario 28.68 13 

(Interpolation) 

FRM Low Ethanol Scenario 26.75 13 

(Interpolation) 

AEO 2007 Reference Case 13.18 15.3 

(ORNL estimate)

4.2.2 Cellulosic Distillate Fuel Distribution Costs 

As discussed in the following sections, we estimate that the total capital costs in the U.S 

to support distribution of the additional volume of cellulosic distillate fuel/renewable diesel fuel 

that will be used in to meet the RFS2 standards under the primary mid-ethanol scenario will be 

1,392 billion dollars by 2022 relative to the AEO 2007 reference case. When amortized, this 

translates to 2 cents per gallon of additional cellulosic distillate fuel/renewable fuel attributed to 

the RFS2 standards. Amortization of capital costs was done over 15 years at a 7% annual cost of 

capital except in the case of the cost of tank trucks where a 10 year amortization schedule was 

used. Under the mid-ethanol primary scenario, we project that 6.7 BGY of cellulosic distillate 

fuel/renewable diesel fuel will be used by 2022. Cellulosic distillate fuel/renewable diesel fuel 

freight costs are estimated to be 13 cents per gallon on a national average basis. Thus, we 

estimate that total cellulosic distillate fuel/renewable diesel fuel distribution costs will be 15 

cents per gallon of cellulosic distillate fuel/renewable diesel fuel that we project will be used to 

meet the RFS2 standards.21

The cellulosic distillate fuel/renewable diesel fuel distribution capital and freight costs for 

all the control scenarios relative to the 2 reference cases that we evaluated in this FRM is 

summarized in Table 4.2-25. The itemized cellulosic distillate fuel/renewable diesel fuel capital 

costs are presented in Table 4.2-26 relative to the AEO 2007 reference case, and in Table 4.2-27 

relative to the RFS1 reference case. The way in which we estimated these costs is detailed in the 

following sections. As discussed in the following sections, some biofuel infrastructure assets 

 

21 As noted previously, we chose not to subtract the distribution costs for the petroleum-based fuels that will be 

displaced by the use of biofuels from our estimated biofuel distribution costs. We believe that the freight costs to 

ship petroleum-based fuels to the terminal are approximately 4 cents per gallon. If we were to subtract these costs 

from the estimated cellulosic distillate fuel/renewable diesel fuel distribution costs under the mid-ethanol scenario 

relative to the AEO 2007 reference case, the result would be 11 cents per gallon. 
81 

such as unit train receipt facilities are used to distribute both cellulosic distillate fuel/renewable 

diesel fuel and ethanol. We attributed a fraction of the capital costs for such facilities to either 

cellulosic distillate fuel/renewable diesel fuel or ethanol in proportion to the fraction of the total 

additional volume of these fuels that we project will be used to meet the RFS2 standards relative 

to the reference case. This approach results in a slight difference in the capital costs under the 2 

reference case despite the fact that the incremental volume of cellulosic distillate/renewable 

diesel fuel used to meet the RFS2 standards is the same under both reference cases. 

Table 4.2-25. 

Summary of Estimated Cellulosic Distillate Fuel/Renewable Diesel Fuel 

Distribution Capital and Freight Costs 

under the RFS2 Control Scenarios Relative to the Reference Cases 

Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol Scenario

RFS1 

Reference 

AEO 

Reference

RFS1 

Reference 

AEO 

Reference 

RFS1 

Reference 

AEO 

Reference

Billion $ 

Capital 

1,999 2,036 1,375 1,392 NA NA 

Capital 

Costs (cpg) 

2 2 2 2 NA NA 

Freight 

Costs 

(cpg) 

13 13 13 13 NA NA 

Total 

Distribution 

Costs 

(cpg) 

16 16 15 15 NA NA 
Table 4.2-26. 

Summary of Estimated Cellulosic Distillate Fuel/Renewable Diesel Fuel Distribution 

Capital Costs under the RFS2 Control Scenarios 

Relative to the AEO 2007 Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Rail Cars 784 552 NA 

Barges 47 33 NA 

Tank Trucks 90 63 NA 

Storage Tanks at Petroleum Terminals 218 154 NA 

Blending and other Miscellaneous 

Equipment at Petroleum Terminals 

304 223 NA 

Unit Train Receipt Facilities 511 315 NA 

Manifest Rail Receipt Facilities 15 9 NA 

Marine Receipt Facilities for Inta-U.S. 

Transport 

67 43 NA 

Total (Million $) 2,036 1,392 NA 

Total (cpg) 2 2 NA 

Table 4.2-27. 

Summary of Estimated Cellulosic Distillate Fuel/Renewable Diesel Fuel Distribution 

Capital Costs under the RFS1 Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Rail Cars 784 552 NA 

Barges 47 33 NA 

Tank Trucks 95 67 NA 

Storage Tanks at Petroleum Terminals 218 154 NA 

Blending and other Miscellaneous 

Equipment at Petroleum Terminals 

361 252 NA 

Unit Train Receipt Facilities 394 253 NA 

Manifest Rail Receipt Facilities 13 8 NA 

Marine Receipt Facilities for Inta-U.S. 

Transport 

87 56 NA 

Total (Million $) 1,999 1,375 NA 

Total (cpg) 2 2 NA 

4.2.2.1 Cellulosic Distillate Fuel Distribution Capital Costs 

4.2.2.1.2 Petroleum Terminal Cellulosic Distillate Fuel/Renewable Diesel Fuel 

Distribution Capital Costs 
83 

 The terminal facility modifications needed to support the use of the volume of cellulosic 

diesel fuel/renewable diesel fuel that we project will be used to meet the RFS2 standards are 

discussed in Section 1.6.7. A summary of the costs associated with these modifications is 

detailed in Tables 4.2-28 and 4.2-29. The estimated costs 

vary depending on the reference case considered because of the way we attributed the cost of 

tank truck unloading facilities (which are used to handle both ethanol and cellulosic distillate 

fuel/renewable diesel fuel) to either ethanol or cellulosic distillate fuel/renewable diesel fuel. 

The cost of such facilities was divided between ethanol and cellulosic distillate fuel/renewable 

diesel fuel in proportion to the fraction of the total ethanol + cellulosic distillate fuel/renewable 

diesel fuel volume. 

Table 4.2-28. 

Cellulosic Distillate Fuel/Renewable Diesel Fuel Associated Petroleum Terminal Costs 

under the RFS2 Control Scenarios Relative to the AEO Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Costs 522 377 NA 

New Storage Tank Construction Costs 218 154 NA 

Tank Truck Unloading Facilities 65 55 NA 

Blending and Miscellaneous Fuel 

Handling Costs 

239 168 NA 

Table 4.2-29. 

Cellulosic Distillate Fuel/Renewable Diesel Fuel Associated Petroleum Terminal Costs 

under the RFS2 Control Scenarios Relative to the RFS1 Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Costs 579 406 NA 

New Storage Tank Construction Costs 218 154 NA 

Tank Truck Unloading Facilities 122 84 NA 

Blending and Miscellaneous Fuel 

Handling Costs 

239 168 NA 

 The above cost estimates are based on the following. Input from terminal operators 

indicates that the cost of ethanol blending equipment is $310 thousand for E85-capable 

equipment. Input from companies that are familiar with the installation of ethanol truck 

unloading equipment at terminals indicates that the cost averages $500 thousand per facility. 

Input from terminal operators indicates that the cost of new diesel fuel storage tank construction 

is $35 per barrel for the size of tanks that are likely to be used. We used the above estimates 
regarding the costs of installing similar equipment for cellulosic distillate fuel/renewable diesel 

fuels. 

4.2.2.1.3 Capital Cost of Unit Train Receipt Facilities for Cellulosic Distillate 

Fuel/Renewable Diesel fuel 

Our estimation of the number of unit train receipt facilities that will be needed to support 

the transport of the volumes of ethanol and cellulosic distillate fuel/renewable diesel fuel that we 

project will be used to meet the RFS2 standards is discussed in Section 1.6.4 of this RIA. The 

cost of these facilities was divided between ethanol and cellulosic distillate fuel/renewable diesel 

fuel in proportion to the fraction of the total ethanol plus cellulosic distillate fuel/renewable 

diesel fuel volume. See Section 4.2.1.1.2 for additional discussion regarding the derivation of 

the total cost of unit train receipt facilities. 

Our projections of the total cost of unit train receipt facilities and the portion that we 

attributed to the volume of cellulosic distillate fuel/renewable diesel fuel that we project will be 

used to meet the RFS2 standards is presented in Tables 4.2-30 and 4.2-31. 

Table 4.2-30. 

Cost of Unit Train Facilities to Facilitate the Transport of Cellulosic Distillate 

Fuel/Renewable Diesel Fuel under the RFS2 Control Scenarios 

Relative to the AEO Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Cost of Unit Train Facilities 

Needed for the Transport of Ethanol 

and Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

748 748 748 

Cost of Unit Train Facilities 

Attributed to Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

Transport 

394 253 NA 
85 

Table 4.2-31. 

Cost of Unit Train Facilities to Facilitate the Transport of Cellulosic Distillate 

Fuel/Renewable Diesel Fuel under the RFS2 Control Scenarios 

Relative to the RFS1 Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Cost of Unit Train Facilities 

Needed for the Transport of Ethanol 

and Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

838 838 838 

Cost of Unit Train Facilities 

Attributed to Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

Transport 

511 315 NA 

4.2.2.1.4 Capital Cost of Manifest Rail Receipt Facilities for Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

Our estimation of the number of manifest rail receipt facilities that will be needed to 

support the transport of the volumes of ethanol and cellulosic distillate fuel that we project will 

be used to meet the RFS2 standards is discussed in Section 1.6.4 of this RIA. The cost of these 

facilities was divided between ethanol and cellulosic distillate fuel/renewable diesel fuel in 

proportion to the fraction of the total ethanol plus cellulosic distillate fuel/renewable diesel fuel 

volume. See Section 4.2.1.1.2 for additional discussion regarding the derivation of the total cost 

of manifest rail receipt facilities. 

Our projections of the total cost of the manifest rail receipt facilities and the portion that 

we attributed to the volume of cellulosic distillate fuel/renewable diesel fuel that we project will 

be used to meet the RFS2 standards is presented in Tables 4.2-32 and 4.2-33. 
Table 4.2-32. 

Cost of Manifest Rail Receipt Facilities under the RFS2 Control Scenarios 

Relative to the AEO Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Cost of Manifest Rail Receipt 

Facilities Needed for the Transport 

of Ethanol and Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

21 21 21 

Cost of Unit Train Facilities 

Attributed to Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

Transport 

14 9 NA 

Table 4.2-33. 

Cost of Manifest Rail Receipt Facilities under the RFS2 Control Scenarios 

Relative to the RFS1 Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Cost of Manifest Rail Receipt 

Facilities Needed for the Transport 

of Ethanol and Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

28 28 28 

Cost of Unit Train Facilities 

Attributed to Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

Transport 

13 8 NA 

4.2.2.1.5 Barge Receipt Facility Costs for Cellulosic Distillate Fuel/Renewable 

Diesel Fuel 

Our estimation of the number of barge receipt facilities for intra-U.S. biofuel shipments 

that will be needed to support the transport of the volumes of ethanol and cellulosic distillate 

fuel/renewable diesel fuel that we project will be used to meet the RFS2 standards is discussed in 

Section 1.6.5 of this RIA. The cost of these facilities was divided between ethanol and cellulosic 

distillate fuel/renewable diesel fuel in proportion to the fraction of the total ethanol plus 

cellulosic distillate fuel/renewable diesel fuel volume. 

Our projections of the total cost of the barge receipt facilities and the portion that we 

attributed to the volume of cellulosic distillate fuel/renewable diesel fuel that we project will be 

used to meet the RFS2 standards is presented in Tables 4.2-34 and 4.2-35. See Section 4.2.1.1.5 

of this RIA for additional discussion of the derivation of these estimates. 
87 

Table 4.2-34. 

Cost of Barge Receipt Facilities under the RFS2 Control Scenarios 

Relative to the AEO Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Cost of Barge Receipt 

Facilities Needed for the Transport 

of Ethanol and Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

143 143 143 

Cost of Barge Receipt Facilities 

Attributed to Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

Transport 

87 56 NA 
Table 4.2-35. 

Cost of Barge Receipt Facilities under the RFS2 Control Scenarios 

Relative to the RFS1 Reference Case 

 Capital Cost (Million $) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Total Cost of Barge Receipt 

Facilities Needed for the Transport 

of Ethanol and Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

185 185 185 

Cost of Barge Receipt Facilities 

Attributed to Cellulosic Distillate 

Fuel/Renewable Diesel Fuel 

Transport 

67 46 NA 

4.2.2.1.6 Cellulosic Distillate Fuel/Renewable Diesel Fuel Rail Car Capital Costs 

 Our estimation of the number of rail cars needed to transport the additional volume of 

cellulosic distillate fuel/renewable diesel fuel that we project will be used to meet the RFS2 

standards is discussed in Section 1.6.4 of this RIA. Based on input from rail car manufactures, 

we estimate that the cost of a new 30,000 gallon rail car suitable for ethanol service is $90 

thousand. We used this estimate as the cost of a rail car suitable for cellulosic distillate 

fuel/renewable diesel fuel service. This may tend to overstate the cost of such rail cars given that 

ethanol rail cars need to be constructed of ethanol tolerant materials. The cost of the additional 

cellulosic distillate fuel/renewable diesel fuel rail cars needed under the 3 control scenarios is 

presented in Table 4.2-36. Our estimate of the additional number of cellulosic distillate 

fuel/renewable diesel fuel rail cars needed to support meeting the RFS2 standards is the same 

relative to both reference cases. 

Table 4.2-36. 

Cost of Additional Cellulosic Distillate Fuel/Renewable Diesel Fuel Rail Cars 

under the RFS2 Control Scenarios 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Number of Additional Rail Cars 8,710 6,130 NA 

Rail Car Cost ($Million) $784 $552 NA 
89 

4.2.2.1.7 Cellulosic Distillate Fuel/Renewable Diesel Fuel Barge Capital Costs 

 Our estimation of the number of barges needed for intra-U.S. transport of the additional 

volume of cellulosic distillate fuel/renewable diesel fuel that we project will be used to meet the 

RFS2 standards is discussed in Section 1.6.5 of this RIA. Based on input from fuel barge 

manufactures, we estimate that the cost of a new 10,000 barrel barge suitable for ethanol service 

is $1.4 million. We used this estimate as the cost of a barge suitable for cellulosic distillate 

fuel/renewable diesel fuel service. This may tend to overstate the cost of such barges given that 

ethanol barges need to be constructed of ethanol tolerant materials. The cost of the additional 

cellulosic distillate fuel/renewable diesel fuel barges needed under the 3 control scenarios is 

presented in Table 4.2-37. Our estimate of the additional number of cellulosic distillate 

fuel/renewable diesel fuel barges needed to support meeting the RFS2 standards is the same 

relative to both reference cases. 

Table 4.2-37. 

Cost of Additional Cellulosic Distillate Fuel/Renewable Diesel Fuel Barges 

under the RFS2 Control Scenarios 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Number of Additional Barges 33 24 NA 

Cost of Barges ($Million) $47 $33 NA 

4.2.2.1.8 Cellulosic Distillate Fuel/Renewable Diesel Fuel Tank Truck Capital 

Costs 

 Our estimation of the number of tank trucks needed to transport the additional volume of 

cellulosic distillate fuel/renewable diesel fuel that we project will be used to meet the RFS2 

standards is discussed in Section 1.6.6 of this RIA. Based on input from ethanol tank truck 

manufactures, we estimate that the cost of a new 8,000 gallon tank truck suitable for ethanol 

service is $180 thousand. We used this estimate as the cost of a tank truck suitable for cellulosic 

distillate fuel/renewable diesel fuel service. This may tend to overstate the cost of such tank 

trucks given that ethanol tank trucks need to be constructed of ethanol tolerant materials. The 

cost of the additional cellulosic distillate fuel/renewable diesel fuel tank trucks needed under the 

3 control scenarios is presented in Table 4.2-38. Our estimate of the additional number of 

cellulosic distillate fuel/renewable diesel fuel tank trucks needed to support meeting the RFS2 

standards is the same relative to both reference cases. 
Table 4.2-38. 

Cost of Additional Cellulosic Distillate Fuel/Renewable Diesel Fuel Tank Trucks under the 

RFS2 Control Scenarios 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Number of Additional Tank Trucks 500 350 NA 

Cost of Tank Trucks ($Million) $90 $63 NA 

4.2.2.2 Cellulosic Distillate Fuel Freight Costs 

 We used a study conducted by Oakridge National Laboratories (ORNL) to estimate 

ethanol and cellulosic distillate fuel/renewable diesel fuel freight costs. Refer to Section 4.2.1.2 

of this RIA for a discussion of how these costs were derived. We estimate that cellulosic 

distillate fuel/renewable diesel fuel freight costs will be 13 cents per gallon under both the lowethanol and mid-ethanol scenarios. 

4.2.3 Biodiesel Distribution Costs

As discussed in the following sections, we estimate that the total capital costs in the U.S 

to support distribution of the additional volume of biodiesel that we project will be used to meet 

the RFS2 standards will be 1,141 billion dollars relative to the AEO 2007 reference case and 

1,212 billion dollars relative to the RFS1 reference case.22 When amortized, this translates to 10 

cents per gallon of additional biodiesel volume that we project will be used to meet the RFS2 

standards relative to both reference cases. Amortization of capital costs was done over 15 years 

at a 7% annual cost of capital except in the case of the cost of tank trucks where a 10 year 

amortization schedule was used. We project that 1.67 BGY of biodiesel will be used by 2022 to 

meet the RFS2 standard volumes. Under the AEO reference case 380 BG/yr of biodiesel will be 

used by 2022. Under the RFS1 reference case, 300 BG/yr of biodiesel will be used by 2022. 

Thus, the additional amount of biodiesel that will be used by 2022 to meet the RFS2 standard 

volumes is 1,290 BG/yr relative to the AEO reference case and 1,370 BG/yr relative to the RFS1 

reference case. Biodiesel freight costs are estimated to be 10 cents per gallon on a national 

average basis. Thus, we estimate that biodiesel distribution costs will be 20 cents per gallon of 

biodiesel that we project will be used to meet the RFS2 standards.23

The biodiesel distribution capital and freight costs relative to the 2 reference cases that 

we evaluated in this FRM are summarized in Table 4.2-39. The itemized biodiesel capital costs 

are presented in Table 4.2-40. The way in which we estimated these costs is detailed in the 

following sections. 

 

22 Biodiesel distribution costs do not vary under the three control scenarios evaluated in this final rule. 23 As noted previously, we chose not to subtract the distribution costs for the petroleum-based fuels that will be 

displaced by the use of biofuels from our estimated biofuel distribution costs. We believe that the freight costs to 

ship petroleum-based fuels to the terminal are approximately 4 cents per gallon. If we were to subtract these costs 

from the estimated biodiesel distribution, the result would be 16 cents per gallon. 
91 

Table 4.2-39. 

Summary of Estimated Biodiesel Capital and Freight Costs 

for the RFS2 Control Scenario Relative to the Reference Cases 

RFS1 

Reference 

AEO 

Reference

Billion $ 

Capital 

1,212 1,141 

Capital 

Costs (cpg) 

10 10 

Freight 

Costs 

(cpg) 

10 10 

Total 

Distribution 

Costs 

(cpg) 

20 20 

Table 4.2-40. 

Summary of Estimated Biodiesel Distribution Capital Costs 

for the RFS2 Control Scenario Relative to the Reference Cases 

 Capital Costs (Million$) 

 RFS1 

Reference 

AEO 

Reference 

Rail Cars 111 105 

Barges 53 50 

Tank Trucks 25 24 

Storage Tanks at Petroleum Terminals 411 387 

Blending and other Miscellaneous 

Equipment at Petroleum Terminals 

612 576 

Total (Million $) 1,212 1,141 

Total (cpg) 10 10 
4.2.3.1 Capital Costs to Upgrade the Biodiesel Distribution System 

4.2.3.1.1 Petroleum Terminal Biodiesel Distribution Capital Costs 

 The terminal facility modifications needed to support the use of the volume of biodiesel 

that we project will be used to meet the RFS2 standards are discussed in Section 1.6.7. Total 

capital costs at terminals by 2022 are estimated at $963 million relative to the AEO reference 

case and $1,023 million relative to the RFS1 reference case. 

We estimate that a total of 5.5 million barrels of new biodiesel storage will be needed at 

petroleum terminals to facilitate meeting the projected RFS2 biodiesel volume relative to the 

AEO reference case, and 5.9 million barrels relative to the RFS1 reference case. We assumed 

that all of the additional biodiesel storage will be satisfied by new construction. Based on 

information from industry, we estimate that the cost of constructing new biodiesel storage tanks 

would be 70 dollars per barrel of capacity. This is considerably higher than the 40 per barrel cost 

we estimated for construction of new ethanol tanks for two reasons. Biodiesel tanks need to be 

heated/insulated in colder climes and they tend to be of considerably smaller size compared to 

ethanol tanks. Both of these factors contribute significantly to the cost per barrel of constructing 

a new storage tank. We estimate that the total cost at petroleum terminals of new biodiesel 

storage tanks would be $387 million dollars relative to the AEO reference case and $411 million 

relative to the RFS1 reference case. 

 We projected that 600 additional petroleum terminals will need to install biodiesel 

blending equipment by 2022 to facilitate meeting the RFS2 biodiesel volume relative to the AEO 

reference case and 637 relative to the RFS1 reference case. Based on input from industry, we 

estimated that the cost of biodiesel blending equipment will be 400 thousand dollars per 

terminal. The cost of additional piping is estimated at 60,000 per terminal. Ancillary costs 

associated with receiving/blending/storing biodiesel are estimated at 500 thousand dollars per 

terminal.24 Based on the above, the cost of additional biodiesel blending and other miscellaneous 

biodiesel handling equipment at terminals is estimated at $576 million relative to the AEO 

reference case, and $612 million relative to the RFS1 reference case. Estimated equipment costs 

for handling biodiesel are higher than those for similar equipment designed to handle ethanol due 

to the need for insulated/heated equipment in colder climes. 

4.2.3.1.2 Biodiesel Rail Car Capital Costs 

 As discussed in Section 1.64 of this RIA, we estimate that an additional 1,060 rail cars 

will be needed by 2022 to facilitate transport of the volume of biodiesel that we project will be 

used to meet the RFS2 standards relative to the AEO reference case, and 1,120 relative to the 

RFS1 reference case. Based on input from industry, we estimate that the cost of a new biodiesel 

tank car of 25,600 gallon capacity is $99,000. The estimated cost for a biodiesel rail car is 10% 

higher than that of an ethanol rail car to accommodate the need for insulated/heated tanks in 

colder climes. Thus, we estimate that the cost of the biodiesel rail tanks cars needed by 2022 to 

facilitate transport of the volume of biodiesel that we project will be used to meet the RFS2 

 

24 This includes the installation of biodiesel truck receipt facilities, quality control testing equipment, and other 

ancillary equipment at terminals. 
93 

standards would be $105 million relative to the AEO reference case, and $111 million relative to 

the RFS1 reference case. 

4.2.3.1.3 Biodiesel Barge Capital Costs 

 As discussed in Section 1.65 of this RIA, we estimate that an additional 32 barges will be 

needed by 2022 to facilitate transport of the volume of biodiesel that we project will be used to 

meet the RFS2 standards relative to the AEO reference case, and 34 relative to the RFS1 

reference case. Based on input from industry, we estimate that the cost of a new biodiesel barge 

of 10,000 bbl capacity is $1.54 million. The estimated cost for a biodiesel barge is 10% higher 

than that of an ethanol rail car to accommodate the need for insulated/heated storage 

compartments in colder climes. Thus, we estimate that the cost of the biodiesel barges needed by 

2022 to facilitate transport of the volume of biodiesel that we project will be used to meet the 

RFS2 standards would be $49 million relative to the AEO reference case, and $52 million 

relative to the RFS1 reference case. 

4.2.3.1.4 Biodiesel Tank Truck Capital Costs 

 As discussed in Section 1.66 of this RIA, we estimate that an additional 120 tank trucks 

will be needed by 2022 to facilitate transport of the volume of biodiesel that we project will be 

used to meet the RFS2 standards relative to the AEO reference case, and 130 relative to the 

RFS1 reference case. Based on input from industry, we estimate that the cost of a new biodiesel 

tank truck of 8,000 gallon capacity is $198,000. This is based on an 110,000 dollar cost for the 

tractor and an 88,000 thousand dollar cost for the tank trailer. This estimate is 25% higher than 

the cost of a tank trailer designed to transport ethanol due to the need for an insulated/heated tank 

in colder climes. Based on the above, we estimate that the cost of the biodiesel tank trucks 

needed by 2022 to facilitate transport of the volume of biodiesel that we project will be used to 

meet the RFS2 standards would be $23 million relative to the AEO reference case, and $25 

million relative to the RFS1 reference case. 

4.2.3.2 Biodiesel Freight Costs 

Our analysis of biodiesel freight costs for this FRM draws upon the analysis conducted 

for the NPRM. The NPRM analysis was based on a total biodiesel production volume of 810 

million gallons by 2022 and was conducted relative to the AEO reference case under which 380 

million gallons of biodiesel would be used. For the FRM, we are assuming that 1,670 million 

gallons of biodiesel would be used by 2022. The biodiesel capital cost analysis was conducted 

relative both the AEO and RFS1 reference cases. Under the RFS1 reference case 300 million 

gallons of biodiesel would be used by 2022 compared to the 380 million gallons under the AEO 

reference case. We believe that the difference between to the two reference cases is sufficiently 

small (80 million gallons per year by 2022) so that a single analysis of biodiesel freight costs 

conducted relative to the AEO reference case provides a reasonable estimate relative to both 

reference case. Hence, we used the results of our biodiesel freight cost analysis under the AEO 

reference case for the RFS1 reference case as well. 
Our estimation of biodiesel freight costs for the NPRM was based on our evaluation of 

where biodiesel would be produced and the potential biodiesel demand centers. Our projections 

of where biodiesel would be produced and used under the NPRM analysis is contained in Section 

1.8.2 of this RIA. Our projections of where biodiesel will be produced under the final rule 

(FRM) analysis are contained in Section 1.5.4 of this RIA. The NPRM estimate of where 

biodiesel would be used was used in our final rule analysis. Due to time constraints, we used a 

modified NPRM biodiesel freight cost analysis (which assumes the same production and demand 

centers used in the NPRM) to estimate biodiesel freight costs for this final rule. This analysis is 

described below. Our comparison of projected biodiesel production centers under the NPRM 

and FRM analyses relative to the projected demand centers indicates that the biodiesel 

transportation modes and distances are substantially similar. As a result, the freight cost 

estimates should be similar. 

The distribution of biodiesel from production plants to petroleum terminals where it 

would be blended with diesel fuel is discussed in Section 1.6.2 of this RIA. Tank truck was the 

assumed method of shipment for distances of less than 300 miles. Where distances are longer 

than 300 miles, shipment by manifest rail was assumed to be the preferred option other than in 

cases on the East coast where there were apparent barge routes from production to demand 

centers. Biodiesel that could not be consumed in the state where it was produced to meet State 

level biodiesel mandates, demand for biodiesel use in heating oil, or other projected biodiesel use 

in diesel fuel was assumed to be shipped to market by manifest rail.25 A 1,000 mile shipping 

distance was selected to ensure that all biodiesel not used to satisfy a state mandate, otherwise 

used in state, or used for bio-heat could find a market. 

Our estimates of the freight costs for shipping biodiesel by tank truck are based on the 

ethanol tank truck freight costs that we developed for the RFS1 final rule. These ethanol 

transport costs were increased by 10% to account for the increased cost associated with 

preventing fuel gelling during cold conditions. The cost of shipping biodiesel by truck when the 

trip (or multiple trips) could be completed in a day was estimated to range from 7 to 8 cents per 

gallon. Some long truck transports were assumed to be necessary (up to 300 miles), where a 

round trip could not be completed in a single day. In such cases, the need for an overnight 

layover was assumed to add 120 dollars to shipping costs, resulting in an estimated 9.5 cents per 

gallon freight cost. 

Our estimate of the cost of shipping biodiesel by manifest rail cars is based on publicly 

available biodiesel freight tariff information from BNSF railway from February 2008.lxxvi 

Specific tariff information was not available for source/destinations needed for our analysis. A 

minimum cost of 9 cents per gallon was assumed to accommodate loading, unloading, and rail 

car lease costs. Based on the BNSF tariff information, we estimated that every 100 miles of 

additional shipment by manifest rail car beyond 600 miles adds 1.4 cents per gallon to shipping 

cost. Thus, for the assumed 1,000 mile shipping distance for biodiesel used to meet 

miscellaneous demand (i.e. not used to meet state mandates or for bioheat) the cost to ship by 

manifest rail car was estimated at 15 cents per gallon. Barge shipping costs were assumed to be 

comparable to the cost of shipping by manifest rail. This will tend to overstate barge shipping 

 

25 Biodiesel is projected to be blended into most heating oil used in the Northeast by 2022. The blended product is 

commonly referred to as bioheat. 
95 

costs, since we understand that barge freight costs tend to be significantly less than rail freight 

costs. However, given the small fraction of biodiesel is projected to me moved by barge, this 

will have only a minimal effect on our overall estimation of biodiesel freight costs. Shipping 

distances were estimated based on a review of biodiesel production plant locations, demand 

centers, and the rail/barge transportation net.26

Considering the location of biodiesel plants and biodiesel demand centers, 86% of 

biodiesel was projected to be shipped by truck, 13% was estimated to be shipped by manifest rail 

car, and 1% was estimated to be shipped by barge. We project that approximately 44% of the 

biodiesel production volume in 2022 would be used in the state where it was produced to meet 

state mandates, satisfy the demand for bioheat, or to meet other in-state miscellaneous demand. 

The average cost of shipping this volume by tank truck is estimated to average 8 cents per gallon. 

Approximately 3% of biodiesel production volume is estimated to be shipped out-of-state by 

manifest rail car to meet miscellaneous biodiesel demand at an average freight cost of 16 cents 

per gallon. Approximately 54% of biodiesel production is projected to be shipped out of state to 

satisfy state mandates or bioheat demand which could not be satisfied with in-state production. 

We assigned portions of the production volumes from states that had already satisfied this 

demand to meet this demand in other states based on minimizing overall shipping distances (and 

costs). 

A freight cost estimate was derived based on the fraction of the volumes that would be 

shipped by each mode and the freight cost for each mode used given the shipping distance. On 

average the cost of shipping biodiesel from out-of-state to satisfy state biodiesel mandates or the 

demand for bioheat is estimated at 10 cents per gallon. By weighting the biodiesel volumes used 

to satisfy the three demand categories by the respective freight cost to ship that volume we 

arrived at a national average biodiesel freight cost estimate of 10 cents per gallon. Biodiesel 

freight costs are summarized in Table 4.2-41. 

Table 4.2-41. 

Estimated Biodiesel Freight Costs for the RFS2 Control Case 

 

Biodiesel Demand Category 

Fraction of 

Biodiesel Production 

Freight Cost 

(cpg) 

Shipped In-State to Satisfy In-State Demand 43% 8 

Shipped Out-of-State to Satisfy State Mandates 

and Demand for Bioheat 

54% 11 

Shipped Out-of-State to Satisfy 

Miscellaneous Demand 

3% 16 

Total (National Average) 100% 10 

 

26 See Section 1.8.2 of this RIA. 
4.2.4 Potential Fuel Retail Costs to Facilitate the Use of Mid-Level Ethanol 

Blends 

As discussed in Section 1.6.10 of this RIA, our preliminary projections regarding the 

potential costs to the fuel distribution system are based on the premise that the facility changes 

needed would be limited to retail facilities. There may be additional costs upstream of retail 

facilities if separate gasoline blendstocks are needed to blend E10 and E15. 

 Testing is still underway regarding what changes might be needed to retail fuel storage 

and dispensing equipment originally designed to handle E10 to ensure its compatibility for an 

E15 blend. Thus there is considerable uncertainty regarding the potential costs. Ideally, E15 

could be dispensed and stored in existing retail equipment with no physical modifications. 

However, it seems most prudent to assume that the potential changes might range from the 

replacement of hanging hardware (hoses attached to the dispenser and the nozzles), to the 

replacement of dispensers with E85 compatible equipment, and/or to the modification to 

underground piping which connects the dispenser to the underground storage tanks. There may 

also be the need to replace the underground storage tanks themselves at some facilities. Some 

newer facilities might need to make fewer changes, while older facilities may require more 

extensive modifications. 

 We evaluated 3 cost scenarios regarding the potential modifications needed to ensure the 

compatibility of current retail fuel storage and dispensing facilities to handle E15. Under the 

first scenario, each retail facility would need to replace only the hanging hardware on the pumps 

which dispense gasoline. The National Association of Convenience Stores (NACS) estimates 

that there are 3.9 gasoline refueling dispensers on average at retail facilities.lxxvii The National 

Petroleum News (NPN) estimates that there were 161,768 retail facilities in the U.S. in 

2008.lxxviii Thus, we estimate that there are approximately 631,000 gasoline dispensers at retail 

facilities. Information from fuel retailers indicates that the cost of hanging hardware that is 

compatible with E85 is $750 for the 2 hoses and nozzles needed for a single dispenser. We 

choose to use the cost for E85-compatible hardware because there is no information on whether 

there may be lower costs for E15-compatible equipment.27 We assumed a $25 installation cost 

per dispenser. Assuming that the hanging hardware on all gasoline dispensers would need to 

replaced, the resulting cost would be $127 million. However, a significant fraction of this cost 

might be deferred to the extent that hanging hardware could be replaced on a timetable that is 

consistent with the normal maintenance schedule as the number of E15 facilities ramps up. 

Information from fuel retailers indicates that hanging hardware is typically replaced every 3 to 5 

years. 

 Under the second scenario, the wetted components inside fuel dispensers would need to 

be replaced in addition to the hanging hardware.28 Information from fuel dispenser manufactures 

indicates that the cost of the wetted fuel dispenser components is approximately $10,000. We 

assumed a $1,000 installation cost per dispenser. Fuel dispenser equipment installers indicated 

 

27 Underwriters Laboratories has separate certification for E10, E25, and E85 retail dispensing equipment. No 

equipment has currently been certified for E25 or E85 use. However, there is considerable experience regarding the 

equipment suitable for E85 service. 

28 The wetted components refers to the components inside the fuel dispenser which come into contact with the fuel. 
97 

that the replacement of the wetted components in a fuel dispenser is not standard practice, and 

there may be logistical and administrative difficulties that would need to be overcome. The cost 

would be $6.940 billion, if assume that the wetted components in all fuel dispensers would need 

to replaced. Adding the cost of replacing the wetted dispenser components to the cost of 

replacing the hanging hardware, results in a total cost estimate of $7.067 billion. 

 Under the third scenario, a fraction of retail facilities would need to break concrete to 

modify underground components such as the piping between dispensers and storage tanks and 

the joints between piping and other underground components. This is the most speculative 

scenario given that the costs of modifying underground components could vary greatly 

depending on the extent of the modifications that might be needed. We assumed an average cost 

of $25,000 per facility to make the changes needed to underground facilities. We believe that 

this is a low-end estimate given that the cost of modifications to underground retail fuel storage 

facilities can escalate quickly. We assumed that 50% of all retail facilities would need to make 

such changes for a total cost of $2.022 billion. Adding in the cost of replacing the wetted 

dispenser components and cost of replacing the hanging hardware, results in a total cost estimate 

of $9.089 billion. 

 These cost estimates could be altered significantly as a result of the findings of the test 

programs currently underway regarding the compatibility of existing fuel retail equipment with 

E15. As discussed in Section 1.6.10 of this RIA, there may be difficulties in identifying what 

changes are needed at some retail facilities due to a lack of records on the type of equipment 

currently installed. This may limit the ability to make such retail facilities E15 compatible. 

4.3 Reduced U.S. Refining Demand 

 As renewable and alternative fuel use increases, the volume of petroleum-based products, 

such has gasoline and diesel fuel produced by U.S. refineries, would decrease. This reduction in 

finished refinery petroleum products results in reduced refinery industry costs. The reduced 

costs would essentially be the volume of fuel displaced multiplied by the cost for producing the 

fuel. There is also a reduction in capital costs as investment in new refinery capacity is displaced 

by investments in renewable and alternative fuels capacity. 

 Although we conducted refinery modeling for estimating the cost of blending ethanol 

(see Section 4.4), we did not rely on the refinery model results for estimating the volume of 

displaced petroleum as other economic factors also come into play. Instead we conducted an 

energy balance around the increased use of renewable fuels, estimating the energy-equivalent 

volume of gasoline or diesel fuel displaced. This allowed us to more easily apply our best 

estimates for how much of the petroleum would displace imports of finished products versus 

crude oil for our energy security analysis which is discussed in Section 5.2 of the RIA. 

 As part of this petroleum displacement analysis, we accounted for the change in 

petroleum demanded by upstream processes related to additional production of the renewable 

fuels as well as reduced production of petroleum fuels. For example, growing corn used for 

ethanol production requires the use of diesel fuel in tractors, which reduces the volume of 
petroleum displaced by the ethanol. Similarly, the refining of crude oil uses by-product 

hydrocarbons for heating within the refinery, therefore the overall effect of reduced gasoline and 

diesel fuel consumption is actually greater because of the additional upstream effect. We used 

the lifecycle petroleum demand estimates provided for in the GREET model to account for the 

upstream consumption of petroleum for each of the renewable and alternative fuels, as well as 

for gasoline and diesel fuel. Although there may be some renewable fuel used for upstream 

energy, we assumed that this entire volume is petroleum because the volume of renewable and 

alternative fuels is fixed by the RFS2 standard. 

 We assumed that a portion of the gasoline displaced by ethanol would have been 

produced from domestic refineries causing reduced demand from US refineries, while the rest of 

the additional ethanol displaces imported gasoline or gasoline blendstocks which does not affect 

domestic refining sector costs. To estimate the portion of new ethanol which displaces US 

refinery production we relied on some Markal refinery modeling conducted for us by DOE. The 

Markal refinery model models all the refinery sectors of the world and thus can do a fair job 

estimating how renewable fuels would impact imports of finished gasoline and gasoline 

blendstocks. The Markal refinery model estimated that 2/3rds of a reduction in petroleum 

gasoline demand would be met by a reduction in imported gasoline or gasoline blendstocks, 

while the other 1/3rd would be met by reduced refining production by the US refining sector. In 

the case of biodiesel and renewable diesel, all of it is presumed to offset domestic diesel fuel 

production. For ethanol, biodiesel and renewable diesel, the amount of petroleum fuel displaced 

is estimated based on the relative energy contents of the renewable fuels to the fuels which they 

are displacing. The savings due to lower imported gasoline and diesel fuel is accounted for in 

the energy security analysis contained in Section 5.2. 

 For estimating the U.S. refinery industry cost reductions, we multiplied the estimated 

volume of domestic gasoline and diesel fuel displaced by the projected wholesale price for each 

of these fuels in 2022, which are $3.42 per gallon for gasoline, and $3.83 per gallon for diesel 

fuel (see Section 4.4). For the volume of petroleum displaced upstream, we valued it using the 

wholesale diesel fuel price. Table 4.3-1 shows the net volumetric impact on the petroleum 

portion of gasoline and diesel fuel demand, as well as the reduced refining industry costs for 

2022. 
99 

Table 4.3-1 

Changes in U.S. Refinery Industry Volumes and Costs for the RFS2 Program in 2022 

Relative to the AEO 2007 Reference Case 

(2007 dollars) 

Low Ethanol 

Case

Primary Case 

(mid-ethanol case)

High Ethanol Case

 Bil 

Gals 

Bil $ Bil 

Gals 

Bil $ Bil 

Gals 

Bil $ 

Upstream Petroleum 0.34 1.3 0.34 1.3 0.33 1.3 

End Use Gasoline -0.9 -3.1 -2.0 -6.8 -4.4 -15.0 

Diesel 

Fuel 

-10.1 -38.7 -7.5 -28.7 -1.3 -5.0 

 Total -10.7 -40.5 -9.2 -34.2 -5.4 -18.7 

 For the primary control case, this analysis estimates that the RFS2 program would reduce 

the gasoline and diesel fuel production volume of US refineries by 9.2 billion gallons in 2022, 

which would reduce their production costs by $34 billion dollars. Accounting for all the 

petroleum displaced (domestic and foreign), the RFS2 program is estimated to reduce gasoline 

and diesel fuel demand by 13.6 billion gallons. 

4.4 Overall Costs to Gasoline and Diesel Fuel 

The previous sections of this chapter have presented estimates of the cost of producing 

and distributing ethanol, biodiesel and renewable and cellulosic diesel fuel. In this section, we 

summarize the overall cost of the RFS 2 program by assessing the costs of using more renewable 

fuels in the transportation fuel supply. The analysis was conducted in two steps. One step 

involved running a refinery model for estimating the costs of blending and using more ethanol.79 

We used the Haverly Linear Programming (LP) model to conduct the refinery analysis. This 

model is widely used by the refining industry, consultants, engineering firms and government 

agencies to analyze refinery economics, refinery operations, fuel quality changes, refinery capital 

investments, environmental changes and demand changes. This Haverly model uses Jacobs’s 

Refining Process Technology Database to represent refining operations. 

While the change in volumetric demand for petroleum-based diesel fuel was modeled 

with the Haverly refinery model, the modeling of the cost of blending and using cellulosic and 

renewable diesel fuel and biodiesel on the overall cost of diesel fuel was estimated as a second 

step post-refinery modelling. Assessing the costs of blending of renewable diesel fuels postrefinery modeling inherently assumes that the renewable diesel fuels will be drop in 

replacements for petroleum-based diesel fuel. However, if the higher cetane values for cellulosic 

and renewable diesel fuel and biodiesel can be taken advantage of by refiners in blending up 

diesel fuel, then our cost estimates are likely to be conservative. We provide a more detailed 

description about how we estimated the costs of using cellulosic and renewable diesel fuel and 

biodiesel at the end of subsection 4.4.1. 

4.4.1 Description of Cases Modeled and Methodology 
 100

The fuels cost analysis was set up to analyze the volumes required by the RFS 2 as 

described in Section 1.2. Because of the uncertainty in how cellulosic biofuel industry will 

develop over time, we assessed three different renewable fuels scenarios each of which totaled 

36 billion gallons based on the energy equivalency of ethanol. The three cases represent a high 

quantity of cellulosic ethanol and a low amount of cellulosic diesel fuel, a low amount of 

cellulosic ethanol and a high amount of cellulosic diesel, and a midpoint between these two cases 

which served as our primary control case. We also considered a small amount of biodiesel and 

renewable diesel as required under EISA. 

 The refinery modeling analysis analyzed the extent to which ethanol will be used in 

conventional gasoline and reformulated gasoline by region and the resulting effects on gasoline 

composition. The refining industry was modeled based on five aggregate complex refining 

regions, representing Petroleum Administration for Defense Districts (PADD) 1, 2, 3, 4 & 5 

together minus California, and California separately. All of the PADDS were modeled 

simultaneously together in the LP model which allowed the refinery model to most efficiently 

rebalance the regional gasoline production volumes in response to the addition of the renewable 

fuels. We conducted the refinery modeling analysis assuming that crude oil would be priced at 

about $51 per barrel and product prices were set based on this crude oil price. We adjusted the 

costs to reflect a crude oil price of $116 per barrel which is the reference crude oil price 

estimated by the Energy Information Administration (EIA) for its 2009 Annual Energy Outlook 

(AEO).80

 

The fuels cost analysis was conducted in three distinct steps which involved a base case, 

two reference cases and the three control cases. 

4.4.1.1 Base Case 

 The first step involved the establishment of a 2004 base case which calibrated the 

refinery model against 2004 volumes, gasoline quality, and refinery capital in place. We chose 

2004 because the following year, 2005, as well as the beginning of 2006, were affected by 

hurricanes and would not be representative of a typical year, and 2007 and 2008 were years of 

extreme crude oil price volatility which skews the price relationships between crude oil and 

gasoline and diesel fuel. Refinery unit capacities from the Oil and Gas Journal and Energy 

Information Administration (EIA), as well as refinery feedstock and product volumes from EIA 

data were entered into the refinery model. The refinery model was then run and the resulting 

gasoline quality compared and calibrated to actual gasoline quality data information from EPA’s 

Reformulated Gasoline data base. 

 

4.4.1.2 Reference Cases 

 The reference cases are benchmark cases that serve as references to the control cases. 

Thus, the only difference between the control cases and the reference cases is that the control 

cases model the RFS 2 volumes of renewable fuels versus lesser volumes in the reference cases. 

We established two reference cases. One represented the volumes of renewable fuels assumed 

for the RFS1 program. The second reference case represented the growth of renewable fuels by 
101

EIA’s 2007 Annual Energy Outlook (AEO). The volumes for both these cases are summarized 

in Section 1.2 above. Because the RFS2 fuel standard becomes fully implemented in 2022, we 

established our reference cases using the projected volumes of finished products in 2022. These 

projected volumes were based on the energy demand for gasoline and diesel fuel from the EIA’s 

AEO 2009. The projected volumes were used for establishing total finished product production 

which then led to refinery production levels for each PADD. 

 

 The refinery modeling was conducted using a projection of crude oil and product prices 

in 2022 that Jacobs made for the proposed rulemaking. The average price of crude oil was 

projected to be about $51 per barrel, although crude oil prices varied by PADD. Jacobs based 

the prices for refined products based on the historical price spreads of fuels between the PADDs, 

using information from EIA’s 2004 price information tables, Platts, and AEO 2006. For the 

reference case as well as for the control cases, we assumed the same crude oil and product prices 

when conducting the refinery modeling work. The crude oil prices and summertime and 

wintertime prices for gasoline, diesel fuel and jet fuel used in the refinery modeling are 

summarized in Table 4.4-1. 

Table 4.4-1. Crude Oil and Finished Product Prices used in Refinery Modeling 

 PADD 1 PADD 2 PADD 3 PADD 4/5 

CA excl. 

California

Crude Oil 

($/bbl) 

Year-round 

Average 

53.6 53.0 50.6 51.8 50.2 

Reformulated Summer 175.2 173.5 170.8 - 186.7 

Gasoline 

(c/gal) 

Winter 161.4 158.7 155.3 - 173.7 

Conventional Summer 167.6 165.1 161.4 173.6 - 

Gasoline 

(c/gal) 

Winter 154.0 151.8 148.5 160.4 - 

Diesel Fuel Summer 156.6 157.6 154.6 166.6 164.6 

(c/gal) Winter 162.6 163.6 160.6 172.6 170.6 

Jet Fuel Summer 158.6 158.6 156.6 164.6 164.6 

(c/gal) Winter 156.6 156.6 154.6 162.6 162.6 

However, AEO 2009 projected crude oil prices to be $116 bbl in 2022, which is much 

higher than those that Jacobs had estimated. After completing the refinery modeling, we 

adjusted the costs of using the renewable fuels post-refinery modeling using a methodology 

described below in Subsection 4.4.1.6. 

 We also modeled the implementation of several environmental programs that will have 

required changes in fuel quality by 2022, including the 30 ppm average gasoline sulfur standard, 

the 15 ppm cap standards on highway and nonroad diesel fuel and the Mobile Source Air Toxics 

(MSAT) benzene standard. Although there may still be a small amount high sulfur diesel fuel, 

we assumed that all distillate fuel would be ultra low sulfur in compliance with the 15 ppm cap 

standard required by the highway and nonroad diesel fuel sulfur standards. We modeled the 

implementation of the 2005 Energy bill, which by rescinding the RFG oxygenate standard, 
 102

resulted in the discontinued use of MTBE, and a large increase in the amount of ethanol blended 

into reformulated gasoline.81 By using the AEO 2009 energy demand we also included the EISA 

Corporate Average Fuel Economy (CAFE) standards that were mandated in EISA and modeled 

in AEO 2009. .82 The assumed EISA vehicle CAFE standard as projected by EIA in AEO 

phases-in less aggressively than the EPA and NHTSA proposed greenhouse gas and CAFE 

standards. However, because both programs would be fully phased in by 2022, their net effects 

in 2022 would not be that different. So basing our refinery modeling analysis on the EISA 

CAFE standard versus the EPA/NHTSA proposed standard would not make a significant 

difference in our costs. 

4.4.1.3 Control Cases 

 The third step in the refinery modeling analysis was to model the control cases. As stated 

above, we modeled three different control cases to capture the impacts of a range of different 

levels of cellulosic ethanol versus cellulosic diesel fuel. All three cases model increased 

volumes of corn ethanol, biodiesel and renewable diesel fuel. Tables 1.2-1 through 1.2-3 in 

Section 1.2 of the RIA summarize the volumes modeled for the control cases. For the additional 

ethanol blended into the gasoline pool, a substantial portion of the additional ethanol was 

blended as E85. The cost and other implications of the control cases are compared to the 

reference cases to assess the costs of the program. We ran these multiple cases to understand 

how costs change based on different levels of cellulosic ethanol versus cellulosic diesel fuel. 

 

 The gasoline and diesel fuel product energy output for each control case modeled was 

maintained the same as that for the reference cases which modeled the energy demand of the 

AEO 2009. Thus, as the volumes of lower energy dense renewable fuels increased, the total 

volume of combined renewable and conventional fuels was increased to maintain the same level 

of energy demand. Maintaining constant energy output assumes that vehicle miles traveled 

would remain the same between the various cases despite any change in gasoline and diesel fuel 

prices caused by the use of renewable fuels. In reality the increased use of renewable fuels may 

result in changes to fuel prices to consumers, either directly as estimated in this section, or 

indirectly by affecting world oil prices as discussed in Chapter 5, and changes in fuel prices 

would be expected to affect demand. However, our analysis was conducted in parallel without 

the ability to input the results of the other analysis. Furthermore, it is difficult to predict the 

impacts on fuel prices to consumers, especially in light of the federal tax subsidies which we 

attempted to account for in our analysis, and the many and diverse state tax subsidies which we 

did not attempt to account for. Maintaining constant fuel product energy output captures the 

capital cost differences between the cases. Table 4.4-3 below summarizes the volumes of 

gasoline and diesel fuel used for the two reference cases, the primary control case and the two 

other control cases. The gasoline volumes include the volumes of renewable fuels, while the 

diesel fuel volumes do not since diesel fuel costs were estimated post refinery modelling. 

 
103

Table 4.4-2. 

Volumes of Gasoline and Diesel Fuel Used in Refinery Modeling 

(Billion Gallons/yr) 

 RFS 1 

Reference 

Case 

AEO 2007 

Reference 

Case 

Low 

Ethanol 

Control 

Case 

Mid-Ethanol 

Control 

Case 

Primary 

Case 

High Ethanol 

Control Case 

Gasoline 

Volume 

(Gasoline and 

Ethanol) 

136.3 138.2 139.6 141.1 144.7 

Diesel Fuel 

Volume 

(Diesel Only) 

70.7 70.6 60.7 63.3 69.4 

 All the other fuel standards and ASTM fuel quality constraints modeled in the reference 

case described above are assumed to apply to the control case as well. The reference and control 

cases where modeled assuming that ethanol conventional gasoline blends are entitled to the 

current 1.0 psi RVP waiver during the summer (i.e., for all 9.0 RVP and many low RVP control 

programs) so as to correctly assess the use of butanes in summertime conventional gasoline. 

Reformulated gasoline (RFG), however, must meet the same volatility standard with or without 

ethanol, so the addition of ethanol into RFG forced the refinery model to remove the last of the 

butane and some pentanes to rebalance RVP. Wintertime conventional and reformulated 

gasoline are normally blended up to either the RVP or vapor/liquid ASTM limits so the addition 

of ethanol into the wintertime gasoline pools resulted in the removal of light hydrocarbon 

compounds – normally butane. The crude oil and product prices for the control cases were the 

same as the reference cases. The capital investments made for the reference cases are not 

assumed to be sunk when the refinery model is assessing the economics for capital investments 

for the various control cases. Thus, the refinery model is free to optimize the capital investments 

made for each control case incremental to the base case. The control cases are run with capital 

costs evaluated at a 15 percent rate of return on investment (ROI) after taxes, but are then 

adjusted post-modeling to a 7 percent ROI before taxes.

4.4.1.4 Ethanol Blending and Prices 

 A special procedure was set up in the refinery model to capture the costs of blending 

ethanol. Because ethanol is primarily produced in the Midwest, but distributed to the final 

terminals where it is blended with the gasoline (or gasoline blendstock for blending with 

ethanol), hypothetical terminals were set up in each PADD within the refinery model which 

would receive the shipped ethanol as well as the gasoline blendstock for blending with ethanol 

(also referred to as conventional blendstock for oxygenate blending (CBOB) for conventional 

gasoline and reformulated blendstock for oxygenate blending (RBOB) for RFG and for 

California RFG (CARBOB). The gasoline blendstock either comes from the same PADD where 

the terminal is located, or transferred from a different PADD. This refinery modeling technique 

helps to more correctly estimate the distribution costs for both the ethanol and the gasoline. The 
 104

refinery model assessed ethanol’s use in each PADD based on its price relative to CG and RFG, 

which is based on its production cost and distribution costs, and its blending economics. For the 

base case we assumed that ethanol would be splash blended into gasoline. But for both the 

reference and control cases modeled in the year 2022 we expect that most, if not all, of the 

ethanol will be octane match-blended for blending up E10. 

The price of ethanol used in the reference case and the primary control cases were based 

on the 2004 yearly average price spread between regular conventional gasoline sold into the spot 

market in Houston and ethanol sold on the spot market on Chicago Board of Trade (CBOT). 

This price spread was 12.3 cents per gallon lower than gasoline in the summer, and 7.7 cents per 

gallon lower than gasoline in the winter. This worked out to an average ethanol price of 146.8 

c/gal in the summer, and 139.4 in the summer. To derive ethanol prices for all the PADDs, the 

Midwest ethanol production price was then adjusted for transportation costs to deliver ethanol 

from the Midwest to end use terminals (see Section 4.2 for additional details about the 

distribution costs). This assumes that the Midwest ethanol market will continue to set the price 

for ethanol – a reasonable assumption considering the significant amount of corn and other 

biomass available in the Midwest. The sales prices assigned to ethanol are summarized in Table 

4.4-4. 

Table 4.4-3. Ethanol Prices used in Refinery Modeling (c/gal) 

 PADD 1 PADD 2 PADD 3 PADD 

4/5 CA 

excl. 

California 

Summer 166.2 158.9 164.3 170.4 170.2 

Winter 158.8 151.5 156.9 163.0 162.8 

 After the refinery modeling was completed, the ethanol prices and the costs for each case 

were adjusted to reflect the ethanol production and distribution costs described above in Sections 

4.1 and 4.2. The ethanol production cost is the volume-weighted average for ethanol sourced 

from corn, cellulose and imports. The ethanol production and distribution cost and cellulosic and 

renewable diesel and biodiesel costs for 2022 are shown in Table 4.4-4 
105

Table 4.4-4. 

Average 2022 Production and Distribution Costs 

for Ethanol, Biodiesel and Cellulosic and Renewable Diesel Fuels 

 Production 

Cost (c/gal) 

Low Ethanol Case Primary Case Mid 

Ethanol Case 

High Ethanol Case 

 Distribution 

Cost 

Total 

Cost 

Distribution 

Cost 

Total 

Cost 

Distribution 

Cost 

Total 

Cost 

Corn Ethanol 150 23.2 173.2 21.6 171.6 18.8 168.8 

Cellulosic 

Ethanol 

127 23.2 150.2 21.6 148.6 18.8 145.8 

Imported 

Ethanol 

150 23.2 173.2 21.6 171.6 18.8 168.8 

Biodiesel from 

virgin oils 

273 20.0 293 20.0 293 20.0 293 

Biodiesel from 

waste oil 

243 20.0 263 20.0 263 20.0 263 

Biodiesel from 

corn oil 

190 20.0 210 20.0 210 20.0 210 

Biodiesel from 

algae oil 

452 20.0 472 20.0 472 20.0 472 

Renewable 

Diesel Fuel 

from waste oil 

242 15.7 257.7 15.4 257.4 14 256 

Cellulosic 

diesel from 

BTL 

237 15.7 252.7 15.4 252.4 14 251 

 The ethanol production and distribution costs summarized in Table 4.4-4 are different in 

value compared to the ethanol prices used in the refinery modeling summarized above in Table 

4.4-3. To capture the costs of the RFS 2 program renewable fuel volumes, we adjusted the initial 

costs of the refinery modeling cost analysis using the ethanol production and distribution costs. 

This cost adjustment was made by multiplying the difference in ethanol cost or price between 

Tables 4.4-4 and 4.4-3 by the difference in ethanol volume modeled between the control case 

and the reference case. 

 We also estimated the costs of the RFS 2 program renewable fuel volumes taking into 

account the consumption subsidies for corn ethanol, cellulosic ethanol, biodiesel and renewable 

diesel fuel. While these subsidies conceal large portions of the costs of renewable fuels, their 

economic effects deserve to be understood. 

4.4.1.5 E85 Blending and Prices 

 Today E85 is blended at 85 percent by volume in the summer and at 70 percent by 

volume in the winter. Ethanol must be blended at less than 85 percent in the winter because of 

ethanol’s low blending Reid Vapor Pressure (RVP). Unlike when ethanol is blended at 10 

percent and causes a large vapor pressure increase, when ethanol is blended at 85 percent it 

blends much closer to its very low neat blending RVP of 2.2. The denaturant provides a small 
 106

RVP increase to the neat ethanol, however, the amount of denaturant which may be blended into 

neat ethanol was recently limited to 2 percent. The lower denaturant volume limits the RVP 

increase that the denaturant will have on neat ethanol. 

 When ethanol is blended with gasoline at the terminal to make E85, the available 

gasoline blendstock must be used. Today this blendstock is either a conventional blendstock for 

oxygenate blending (CBOB) or reformulated blendstock for oxygenate blending (RBOB) used 

for blending E10 to the local gasoline specifications. For example, reformulated gasoline (RFG) 

must comply with the hydrocarbon standard of the RFG program and therefore RFG tends to 

have an RVP of 6.8, and the RBOB that is blended with ethanol has an RVP of about 5.8. When 

this 5.8 RVP RBOB is blended with ethanol to make E85, its final RVP is estimated to be 4.72. 

However, the RVP minimum specified in the E85 ASTM standard shows the summertime lower 

limit of E85 is 5.5, thus, blending RBOB with 85 percent ethanol would not comply with the 

ASTM lower RVP standard. Table 4.4-7 summarizes ethanol’s blending RVP, gasoline’s RVP 

and the final blend RVP for summertime RFG and CG gasoline, and compares the blends RVP 

values to that of the E85 ASTM RVP standards.83 

Table 4.4-5. Comparison of E85 RVP levels to the ASTM RVP Standard 

 Summer E85 Winter E70 

Gasoline 

RVPa

CG 10.0 RFG & low 

RVP 6.8 

ASTM Std CG/RFG 

14 

ASTM Std 

Gasoline 

Blendstock 

RVP 

9.0 5.8 13 

Ethanol 

Blending 

RVP 

4.37 4.37 - 6.1 

Blend 

RVP 

5.20 4.72 5.5 

minimum 

5.85 9.5 

minimum a Summertime CG is allowed a 1 psi waiver for blending with ethanol, however, RFG and some 

low RVP areas and wintertime CG/RFG do not normally receive 1 psi waivers. 

 Table 4.4-7 shows that summertime RFG and CG and wintertime gasoline cannot meet 

the ASTM RVP minimum standards based on blending ethanol with the locally available 

gasoline blendstock for blending up E10. For this reason, we ran the refinery model assuming 

that E85 will be blended differently in the future than it is today if it is to be used in large 

volumes. We assumed in the refinery modeling that all E85 will be blended at 85 percent 

ethanol year-round by being blended with some butanes or pentanes (whichever is available from 

the nearest refineries) to bring E85 up to the maximum ASTM RVP standard for E85, in addition 

to the CBOB or RBOB being supplied to the local area. The maximum ASTM E85 RVP 

standard is 8.5 in the summertime and 12.0 in the wintertime. 

 E85 is expected to be priced much lower in the marketplace than E10 and even less 

relative to gasoline (E0) because of E85’s lower energy density. E85 contains about 77,900 

BTUs per gallon compared to E10 which contains about 111,300 BTUs per gallon. Thus, when 

consumers consider refueling their vehicle using E85, they will bypass using it unless it is priced 
107

at parity with gasoline on an energy basis. Parity pricing means that E85 would have to be 

priced about 25 percent lower than E10. Assuming that E85 is priced 25 percent lower than E10 

at retail to account for the energy content differences, the pricing disparity between ethanol and 

gasoline is even greater at the terminal. Table 4.4-6 summarizes the pricing of E85 at retail and 

at the terminal where ethanol is usually blended with gasoline blendstock to create the E85. 

Retail markup averages about 10 cents per gallon.84 Federal and state taxes average 46 cents per 

gallon (although this varies significantly by state), and transportation from the terminal to retail 

averages 3 cents per gallon.85 Thus, if E10 gasoline is priced at 163 cents per gallon at the 

terminal,CC it would be priced at 222 cents per gallon at retail when the costs for transporting the 

fuel to the retail market and taxes and retail markup are added on. Based on E85’s 25 percent 

lower energy density, E85 would have to be priced at 167 cents per gallon at retail to reflect its 

lower energy density. Using the same terminal to retail costs/taxes, E85 would be priced at 108 

cents per gallon at the terminal. All this is shown in Table 4.4-6. The bottom row of the table 

shows what ethanol (E100 plus denaturant) would have to be priced at for terminals to breakeven 

using ethanol in E85 (this assumes that E85’s gasoline blendstock is priced the same as E10 at 

the terminal). Thus, unlike with E10 where the lower energy content of ethanl is largely 

transparent to the consumer, based on ethanol’s energy content alone, ethanol used in E85 would 

have to be discounted significantly compared to gasoline for refiners to find it cost-effective to 

use. 

Table 4.4-6. E85 Pricing at Retail and at Terminals (cents per gallon) 

 Price at 

Retail 

Retail 

Markup 

Average 

Federal and 

State Taxes 

Transportation 

terminal to 

retail 

Terminal 

Price 

Gasoline E10 222 10 46 3 163 

E85 167 10 46 3 108 

Ethanol 

Breakeven 

Price 

- - - - 97 

 In addition to this effect of energy equivalency, Section 1.7 above outlines the difficulty 

of using all this E85 because of the relatively low number of fuel flexible vehicles (FFVs) that 

will be available to consume the fuel. The relatively low number of FFVs means that the 

refueling rate of these vehicles will have to be very high. In the year 2022, we estimate that 

FFVs will have to refuel 74 percent of the time to use the volume of ethanol required by the 

RFS2 standard.DD This means that E85 may have to be priced significantly lower than gasoline 

for FFV owners to choose to fuel on it instead of gasoline. In addition, it is unlikely that every 

service station would make the capital investments to make E85 available for sale. In Section 

4.2, we estimate that one out of very four service stations will carry E85. Thus, E85 may have to 

be priced even lower than its fuel economy-adjusted price to entice FFV owners to refuel at a 

station carrying E85. To estimate the marginal lower price at which FFV owners would refuel at 

this high rate, we referenced an analysis based on a willingness to pay survey conducted by 

 

CC The terminal price of 163 c/gal is the wholesale gasoline priced used in the refinery modeling analysis. DD The FFV refueling percentage was estimated at 74% for the proposed rulemaking. Because the refinery 

modeling analysis was started before the FFV refueling percentage was reasessed for the final rulemaking, we 

continued to base our analysis on the 74% refueling figure. 
 108

David Greene of the Oak Ridge National Laboratory.86 The summary of this analysis is depicted 

in the Figure 4.4-1. 

Figure 4.4-1

Alternative Fuel Market Share as a Function of Fuel Availability and 

Price Advantage (David L. Greene, 1997, Figure 6)

Refueling frequency given 

“reasonable access”

Percent of stations offering E85 in areas of the 

country with “reasonable access”, i.e., 25%

X $0.21/gal Price Advantage (1997$)

Alternative Fuel Market Share as a Function of Fuel Availability and 

Price Advantage (David L. Greene, 1997, Figure 6)

Refueling frequency given 

“reasonable access”

Percent of stations offering E85 in areas of the 

country with “reasonable access”, i.e., 25%

X $0.21/gal Price Advantage (1997$)

 Based on our estimates that E85 would have to be purchased 74 percent of the time and 

that one out of every four service stations would carry E85, then Figure 4.4-1 estimates that E85 

would have to be priced 21 cents per gallon lower than gasoline to match this availability and 

refueling scenario in addition to the adjustment for energy content. This cost estimate is based in 

1997 dollars. Adjusting this cost estimate to 2006 dollars increases this estimate to 26 cents per 

gallon in addition to the adjustment for energy content. 

 There is one more factor which we believe could affect the price of E85. FFV owners 

who refuel on E85 will drive fewer miles before having to refuel compared to operating their 

vehicle on gasoline. The FFV drivers will therefore spend more time refueling their vehicle. As 

described above, FFV owners will drive 25 percent fewer miles per gallon and thus, will have to 

spend 25 percent more time refueling. We estimate that each refueling event requires 6 minutes 

of time, and that a person’s time is worth an average of 30 dollars per hour.87,88,89,90 Finally we 

assumed that a typical refueling volume for a refueling event is 15 gallons. Using these 

assumptions, the increased refueling frequency is costing the average FFV owner 5 cents per 

gallon more to use E85. To account for this additional cost, E85 would have to be priced 5 cents 

per gallon lower to make refueling FFVs a breakeven proposition. For our refinery modeling 

work, we reduced the refiner purchase price of E85 used in our refinery modeling analysis by 

this additional 5 cents per gallon. 
109

 Table 4.4-7 summarizes the E85 refinery purchase prices at terminals by PADD used in 

our refinery modeling work. These prices represent the total of the energy content, the price 

adjustment for reduced fuel availability and the cost for increased refueling events. The E85 

prices should be compared to regular grade gasoline because the FFVs generally only require 

regular grade gasoline when operated on gasoline. 

Table 4.4-7. Wholesale E85 Prices used within the Refinery Model 

 E85 used in Conventional 

Gasoline Areas (c/gal) 

E85 used in Reformulated 

Gasoline Areas (c/gal) 

PADD 1 Summer 76 81 

 Winter 67 72 

PADD 2 Summer 75 80 

 Winter 66 71 

PADD 3 Summer 74 79 

 Winter 65 70 

PADDs 4/5 Summer 84 80 

 Winter 75 81 

CA Summer - 86 

 Winter - 77 

 While we used these E85 prices within the refinery model, they don’t necessarily 

represent the societal costs for using E85. The pricing to reflect reduced fuel availability, in 

particular, contains a significant amount of transfer payments from the refining industry to 

consumers and other entities, and these transfer payments do not represent the true cost for using 

E85.EE 

 For estimating the program costs for using E85 (shown in Tables 4.4-12 and 4.4-13 and 

other similar tables), we adjusted E85 price back up to 5 cents per gallon less than the gasoline 

price for each case (the additional time spent refueling is a true cost). We then used the relative 

energy density of the E85 to that of gasoline as reported by the refinery model (see energy 

content values in Table 4.4-19 and other similar tables) to account for the energy density costs 

for using E85. We preferred the energy content price cost made by the refinery model to our 

preliminary E85 energy content price adjustments because the refinery model accounts for other 

changes in gasoline energy content made when accommodating the blending of ethanol . We are 

not assuming that the price adjustment that we made account for lower E85 availability accounts 

for any additional social cost. If the FFV driver would have to drive out of his way from time-totime to find the E85, then there would be some extra cost associated with the lower availability. 

But most of the time FFV drivers would likely learn where to find E85 along the routes that they 

normally frequent, thus, no additional effort and cost would be incurred for refueling on E85. 

Thus, we assume that the lower E85 price to account for reduced E85 availability is purely a 

transfer payment from the refiner to the FFV owner. Despite assessing the costs on a different 

basis, estimating E85 prices for the refinery modeling is important so that the refinery model can 

 

EE The possibility for this potentially large transfer payment associated with using ethanol in E85 would encourage 

obligated partners to pursue the development of nonethanol renewable fuels. 
 110

correctly choose which gasoline type and which part of the country to blend the ethanol in the 

refinery model. 

The assumption used here and throughout this proposed rulemaking is that ethanol’s fuel 

economy is directly proportional to its energy density and its concentration in the fuel. Since the 

volumetric energy content of ethanol is approximately 33 percent less than conventional 

gasoline, we assumed this loss in fuel economy proportional to its concentration in the fuel. 

Some studies have suggested, however, that ethanol’s decrease in fuel economy may be less than 

its relative decrease in volumetric energy content of the fuel. In other words, there is less of a 

fuel consumption decrease than what the lower energy density of ethanol would suggest. 

However, the results may more be a function of how the testng was conducted than the true 

effect of ethanol on fuel economy. We therefore intend to investigate this issue more as more 

data becomes available. 

 As discussed above, we needed to adjust the estimated program costs from costs based on 

$51/barrel crude oil, the crude oil price at which the refinery model was run, to $116/bbl which 

is the crude oil costs that served as the basis for our cost analysis. To make these adjustments we 

estimated the wholesale gasoline and diesel fuel prices (which are the surrogate for the gasoline 

and diesel fuel production costs) at the adjusted crude oil price and compared these adjusted 

wholesale gasoline and diesel fuel adjusted prices to the baseline wholesale gasoline and diesel 

fuel prices. The baseline wholesale gasoline and diesel fuel prices, based on an average $51/bbl 

crude oil price, are summarized in Table 4.4-1. To adjust these wholesale prices, we estimated 

how the price of crude oil will affect them. We conducted a regression between the annual 

average spot price of price of Western Texas Intermediate crude oil and the annual average retail 

gasoline and diesel fuel prices for the years 2002 through 2008.91,92 This regression is reflected 

in Table 4.4-8 as Gasoline Retail Price = Crude Oil Price multiplied times 2.65 plus 79.0, or 

Gasoline Retail Price = Crude Oil Price x “X” + “Y.” The slope “X” and intercept “Y” for this 

equation are summarized in Table 4.4-8. The X and Y factors for diesel fuel are also 

summarized in Table 4.4-8 as well. However, we needed to estimate the wholesale prices 

instead of the retail prices, so we adjusted the equations to estimate the wholesale price using the 

Jacob’s wholesale prices as the calibrating values. The regression, including the adjustment 

values to derive the wholesale prices equations are summarized in Table 4.4-8. 

Table 4.4-8. 

Equations Used for Estimating Wholesale Average Gasoline and Diesel Fuel Prices* 

 Equation for Retail Prices Equation for Wholesale Prices 

 X Y X Adjusted Y 

Gasoline 2.65 79.0 2.65 +27.0 

Diesel Fuel 3.38 44.8 3.38 -11.7 

* The equation is used by multiplying the crude oil price ($/bbl) times the X and then adding Y to that 

product resulting in a gasoline or diesel fuel cost expressed in cents per gallon. 

 

 The equations were used to estimate the average wholesale gasoline and diesel fuel 

prices. These average wholesale gasoline and diesel fuel prices are summarized in Table 4.4-9. 
111

Table 4.4-9 

Average Gasoline and Diesel Fuel Wholesale Prices by Crude Oil Price 

Crude Oil Price Gasoline Diesel Fuel 

$/bbl c/gal c/gal 

51 163 160 

116 342 383 

 Table 4.4-9 shows the nationwide average costs, but our cost analysis was conducted on a 

PADD basis, thus, it was necessary to estimate revised gasoline and diesel fuel wholesale prices 

in each PADD. This was accomplished by generating a ratio of the average wholesale gasoline 

and diesel fuel prices at the higher crude oil price relative to the average gasoline and diesel fuel 

wholesale prices at the lower crude oil price, and applying this ratio to the gasoline price in each 

PADD. It is important to point out one aspect of the gasoline and diesel fuel pricing changes 

captured by our crude oil/gasoline and diesel fuel price relationship price model. Prior to 2005, 

diesel fuel was priced about the same as gasoline (+/- 5 cents per gallon on a yearly average). In 

2005 and 2006, when crude oil was priced higher, diesel fuel was priced 13 cents per gallon 

higher than gasoline. In 2007 gasoline and diesel fuel were priced about the same, but then in 

2008, diesel fuel was priced much higher than gasoline. Thus, the equation picks up this 

relatively higher diesel fuel price at the higher crude oil prices in 2005, 2006 and 2008 and 

projects a greater relative higher price for diesel fuel at our high crude oil price of $116/bbl. A 

higher relative diesel fuel price at higher crude oil prices in the future may be appropriate for a 

couple reasons. The first reason is that from January to mid-October 2008, when crude oil prices 

were very high, diesel fuel averaged 51 cents per gallon higher than gasoline. While we cannot 

say for certain that this association would always hold true at higher crude oil prices, we do have 

a possible explanation for a possible relationship here. Higher crude oil prices are likely to affect 

gasoline demand more than diesel fuel as more of the trips made by gasoline powered light-duty 

vehicles are discretionary. For example, people may readily change their vacations plans at 

higher crude oil prices, while diesel fuel used to power trucks that bring food to markets would 

be expected to continue. Thus, as crude oil prices increase, gasoline consumption is likely more 

elastic resulting in greater reductions in gasoline demand compared to diesel fuel. We therefore 

believe that higher crude oil prices will tend towards relatively higher diesel fuel prices 

compared to gasoline. 

 For other reasons, diesel fuel prices may trend higher in the future relative to gasoline 

prices. Because EISA required that corporate average fuel economy (CAFE) standards be 

increased for light duty motor vehicles, over time light duty vehicles, which are almost 

exclusively gasoline powered, will become more fuel efficient. This will cause gasoline demand 

to decrease, while diesel demand is projected to continue to increase with GDP to transport 

goods and services. A second reason why refinery gasoline production will decrease is that most 

of the renewable fuel volume being produced to comply with the RFS will displace gasoline. 

This will contribute to the over supply of gasoline and the relative undersupply of diesel fuel, 

thus causing gasoline prices to be soft relative to diesel fuel prices. 
 112

 

Another adjustment we made to the costs directly estimated by the LP refinery cost 

model was to add additional cost for distributing gasoline from the refinery to the terminal. The 

refinery cost model assigned a low distribution costs to gasoline for moving the gasoline from 

the refinery to the terminal. We estimate that this distribution cost should be about 4 cents per 

gallon, but the refinery model only assigned 2.5 cents per gallon for this. Thus, we credited 

ethanol 1.5 cents per gallon for each gasoline-equivalent gallon of ethanol blended into each 

PADD’s gasoline, since this roughly corresponded to the volume of gasoline displaced by the 

ethanol. 

 The diesel fuel costs are estimated based on two calculations conducted post-refinery 

modeling. The first calculation estimates costs based on the difference in the renewable fuels 

production costs compared to the production costs for petroleum-based diesel fuel multiplied 

times the increased volume of renewable fuels in the control case compared to the reference case. 

For example, producing and distributing cellulosic diesel fuel for the primary control case is 

estimated to cost 252 cents per gallon (see Table 4.4-4). The cost of producing diesel fuel is 

estimated to be 383 cents per gallon when crude oil is priced at $116 per barrel (see Table 4.4-9), 

which is 131 cents per gallon higher than the cellulosic diesel fuel costs. From the volume tables 

in Section 1.2, the incremental volume of cellulosic diesel fuel is 6.52 billion gallons for the 

primary reference relative to the AEO 2007 reference case. Therefore, the net production cost 

for cellulosic diesel fuel is -131 cents per gallon times 6.52 billion gallons for a cost of -8540 

million dollars in 2022. 

 The second calculation for estimating the cellulosic diesel fuel costs is an estimate of 

the fuel economy cost. This is calculated by multiplying the percent loss in fuel economy for 

cellulosic diesel fuel compared to petroleum-based diesel fuel times the production cost for 

petroleum-based diesel fuel. Continuing with the cellulosic diesel fuel example, we assume that 

cellulosic diesel fuel is from the biomass-to-liquids (BTL) process and contains 123,000 BTUs 

per gallon versus petroleum diesel fuel which is estimated to contain 130,000 BTUs per gallon. 

Thus, cellulosic diesel fuel contains about 95% of the energy content of petroleum-based diesel 

fuel. The 5% shortfall in energy content is multiplied times the production cost of petroleumbased diesel fuel, which is 383 cents per gallon, and multiplied times 6.52 billion gallons - the 

volume of cellulosic diesel fuel. This results in a cost of 1250 million dollars in 2022. 

 The total cost for cellulosic diesel fuel is the sum of the production cost and the fuel 

economy cost which is -7290 million dollars in 2022. The total annual cost is converted to a 

per-gallon cost by dividing the total annual cost by the total volume of petroleum-based and 

renewable diesel fuel. 

4.4.1.6 Other Adjustments to the Costs 

 The assumed volumes of E85 in our control cases will require increased numbers of 

flexible fuel vehicles (FFVs) be available to use the fuel. In Section 1.7 above, we estimate the 

number of FFVs that would be produced to enable the consumption of the volume of E85 that we 

project would have to be consumed for each control case. As the number of FFVs increases it 

results in higher costs due to the production of FFVs. In the following tables, we resummarize 
113

the number of FFVs that we projected would be available for the AEO 2007 reference case and 

each control case that we described above in Section 1.7. However, to estimate the cost impacts, 

we attribute a cost for every FFV produced. For the low ethanol case, we assume that each FFV 

would cost $100 per vehicle, which is an estimate for producing an FFV today. For the higher 

ethanol cases, as FFV production volumes increase, because of economies of scale, we expect 

that the per-vehicle costs would decrease. Furthermore, overhead costs associated with 

producing FFVs would be amortized over a larger number of vehicles further lowering the pervehicle costs. For the primary case we project that FFV costs would decrease to $75 per vehicle. 

For the high ethanol case we assume that FFV costs would decrease to $50 per vehicle. Tables 

4.4-10 and 4.4-11 provide estimates of the FFV costs above the business-as-usual FFV costs in 

the AEO 2007 and RFS 1 reference cases. 

Table 4.4-10 

Numbers of FFVs and Total FFV Costs for the Control Cases 

Relative to the AEO 2007 Reference Case 

AEO 2007 

Reference 

Case

Number of 

FFVs 

(millions)

Number of 

FFVs 

(millions)

Incremental 

FFV Cost 

(millon dollars) 

($100/FFV)

Number of 

FFVs 

(millions)

Incremental 

FFV Cost 

(millon dollars) 

($75/FFV)

Number of 

FFVs 

(millions)

Incremental 

FFV Cost 

(millon dollars) 

($50/FFV)

2010 1.67 1.25 -$41.7 1.85 $13.4 3.62 $97.4

2011 1.75 1.60 -$14.8 2.66 $68.6 5.44 $184.6

2012 1.77 1.90 $13.6 3.52 $131.6 7.39 $281.2

2013 1.80 2.25 $45.6 3.74 $145.9 9.42 $381.1

2014 1.83 2.52 $69.7 3.88 $154.1 11.40 $478.8

2015 1.82 2.69 $87.6 3.96 $160.5 13.29 $573.4

2016 1.82 2.76 $94.4 3.97 $161.3 13.32 $575.3

2017 1.83 2.80 $97.8 4.00 $163.3 13.44 $580.8

2018 1.83 2.93 $109.4 4.04 $165.6 13.57 $586.9

2019 1.86 2.83 $97.0 4.08 $167.2 13.71 $592.8

2020 1.90 2.77 $87.1 4.12 $166.3 13.82 $596.2

2021 1.91 2.67 $75.6 4.10 $163.9 13.76 $592.4

2022 1.91 2.61 $69.4 4.10 $163.7 13.75 $591.9

Totals 23.7 31.6 $791 48.0 $1,826 145.9 $6,113

Low Ethanol Control Case High Ethanol Control Case Primary Control Case 

(mid ethanol case)

Year

 Table 4.4-10 summarizes our estimated costs for the increased numbers of FFVs that 

would be produced to use the projected increased volume of E85. For the primary control case 

we estimate that increased FFV production would cost $1.8 billion. For the low and high ethanol 

control cases we estimate that increased FFV production would cost $0.8 and $6.1 billion, 

respectively. 
 114

Table 4.4-11 

Numbers of FFVs and Total FFV Costs for the Control Cases 

Relative to the RFS 1 Reference Case

RFS 1 

Reference 

Case

Number 

of FFVs 

(millions)

Number 

of FFVs 

(millions)

Incremental 

FFV Cost 

(millon dollars) 

($100/FFV)

Number 

of FFVs 

(millions)

Incremental 

FFV Cost 

(millon dollars) 

($75/FFV)

Number 

of FFVs 

(millions)

Incremental 

FFV Cost 

(millon dollars) 

($50/FFV)

2010 0.98 1.25 $27.0 1.85 $64.9 3.62 $131.7

2011 1.08 1.60 $51.5 2.66 $118.3 5.44 $217.8

2012 1.16 1.90 $74.1 3.52 $177.1 7.39 $311.5

2013 1.23 2.25 $101.7 3.74 $188.0 9.42 $409.2

2014 1.28 2.52 $124.2 3.88 $195.1 11.40 $506.1

2015 1.31 2.69 $138.7 3.96 $198.9 13.29 $599.0

2016 1.31 2.76 $145.2 3.97 $199.4 13.32 $600.7

2017 1.32 2.80 $148.3 4.00 $201.2 13.44 $606.0

2018 1.33 2.93 $159.5 4.04 $203.2 13.57 $612.0

2019 1.35 2.83 $147.8 4.08 $205.2 13.71 $618.2

2020 1.36 2.77 $141.2 4.12 $206.9 13.82 $623.2

2021 1.35 2.67 $131.7 4.10 $206.0 13.76 $620.5

2022 1.35 2.61 $125.6 4.10 $205.8 13.75 $620.0

Totals 16.4 31.6 $1,516 48.0 $2,370 145.9 $6,476

High Ethanol Control Case Low Ethanol Control 

Case

Primary Control Case 

(mid ethanol case)

Year

Table 4.4-11 summarizes our estimated costs for the increased numbers of FFVs that 

would be produced to use the projected increased volume of E85. For the primary control case 

we estimate that increased FFV production would cost $2.4 billion. For the low and high ethanol 

control cases, we estimate that increased FFV production would cost $1.5 and $6.5 billion, 

respectively. 

4.4.2 Refinery Modeling Results 

 In this subsection, we summarize the results of the three control cases that we modeled 

and compare them to the two different reference cases. 

 Table 4.4-12 summarizes the costs for the primary control case relative to the AEO 2007 

reference case excluding federal ethanol, biodiesel and renewable diesel tax subsidies. By 

excluding the federal ethanol, biodiesel and renewable diesel fuel consumption subsidies, we 

avoid the transfer payments caused by these subsidies that would hide a portion of the program’s 

costs. The costs are reported by different cost components and adjustments described above, as 

well as aggregated to show the total annual and per-gallon costs. The costs are reported 

separately for gasoline and diesel fuel. The estimate of gasoline costs are based on the refinery 

model and reflect the changes in gasoline that are estimated to occur by the refinery model 

accommodating the expanded use of ethanol. The refinery model variable operating costs 

include the labor, utility and other operating costs and are a direct output from the refinery 

model. These costs reflect ethanol’s and E85’s prices used in the refinery model and reflect 
115

crude oil priced at about $51 per barrel. The reduced refinery capital costs are shown in the table 

amortized annually and over the gasoline pool (the nonamortized refinery and biofuel capital 

costs are summarized in Table 4.4-18). The fixed costs shown in the table include the 

maintenance and insurance costs and are calculated to be 3 percent of the reduced capital costs. 

Next in the table we show the adjustment to remove the costs associated with low E85 prices, 

except for the 5 cent per gallon refueling cost, and then we show the costs for using lower energy 

density E10 gasoline and E85. The energy density costs changes rely on the fractional change in 

energy density shown in Table 4.4-19, multiplied by the wholesale price of gasoline. The cost 

adjustment is shown for basing the gasoline costs on $116 per barrel crude oil price versus the 

$51 per barrel price that was the basis for the refinery model runs. At $116 per barrel crude oil 

costs, ethanol’s production and distribution costs are lower than the wholesale cost of gasoline 

which results in the cost savings. Finally for the gasoline costs, the table summarizes our 

estimated costs for producing an appropriate number of fuel flexible vehicles (FFVs) for using 

E85. With respect to the cellulosic and renewable diesel fuel and biodiesel costs, the production 

costs and for the fuel economy effects are both presented in Table 4.4-12. 

Table 4.4-12. 

Primary Control Case Costs without Tax Subsidies 

Relative to the AEO 2007 Reference Case 

(2007 dollars, 7% ROI before taxes) 

Gasoline Diesel Fuel

Refinery Model Variable Operating Cost $MM/yr 11,077 -

Amortized Refinery Capital Costs $MM/yr -997 -

Fixed Operating Costs $MM/yr -275 -

Added Gasoline Transportation Cost $MM/yr -88 -

E85 Pricing Effect $MM/yr -8,338 -

Crude Oil Cost $51 to $116/bbl $MM/yr -15,302 -

Lower Energy Density $MM/yr 8,745 1,722

Adjustment from Ethanol Price to Cost $MM/yr 83 -

FFV Costs $MM/yr 1,826

Renewable Diesel Cost vs Petroleum Diesel $MM/yr - -10,268

Total Costs $MM/yr -3,349 -8,546

Refinery Model Variable Operating Cost c/gal 7.85 -

Amortized Refinery Capital Costs c/gal -0.71 -

Fixed Operating Costs c/gal -0.19 -

Added Gasoline Transportation Cost c/gal -0.06 -

E85 Pricing Effect c/gal -5.91 -

Crude Oil Cost $51 to $116/bbl c/gal -10.84 -

Lower Energy Density c/gal 6.20 2.42

Adjustment from Ethanol Price to Cost c/gal 0.06 -

FFV Costs c/gal 1.29

Renewable Diesel Cost vs Petroleum Diesel c/gal - -14.41

Total Costs c/gal -2.37 -11.99
 116

Our analysis shows that when considering all the costs associated with the expanded use 

of ethanol for the primary control case relative to the AEO 2007 reference case that the cost of 

gasoline will decrease by $3.3 billion in the year 2022. Expressed as per-gallon costs, these fuel 

changes will save the U.S. 2.4 cents per gallon of gasoline. The addition of biodiesel, renewable 

and cellulosic diesel fuel is estimated to reduce the cost of diesel fuel by $8.5 billion in the year 

2022, or save 12.0 cents per gallon. 

Table 4.4-13 expresses the total and per-gallon gasoline costs for the primary control case 

with the federal ethanol, biodiesel and renewable diesel subsidies included. The federal tax 

subsidy is 45 cents per gallon for each gallon of ethanol blended into gasoline and 101 cents per 

gallon for each gallon of cellulosic biofuel. Imported ethanol is also assumed to receive the 45 

cents per gallon ethanol subsidy, although we assume that a greater volume of imported ethanol 

would be used than that which can flow through the Caribbean Basin, tariff free. Thus the 51 

cents per gallon tariff would apply to that incremental volume of imported ethanol above the 

allowable Caribbean Basin initiative volume. We estimate that imported ethanol would earn 23 

cents per gallon net subsidy. The biodiesel subsidy is 100 cents per gallon, and the renewable 

diesel fuel subsidy is 50 cents per gallon. The cost adjustment is estimated by multiplying the 

subsidy times the volume of new ethanol, biodiesel and renewable diesel estimated to be used. 

Table 4.4-13. 

Primary Control Case Costs Reflecting Tax Subsidies 

Relative to the AEO 2007 Reference Case 

(2007 dollars, 7% ROI before taxes) 

Gasoline Diesel Fuel

Total Costs $MM/yr -3,349 -8,546

Federal Subsidies $MM/yr -6,313 -7,944

Revised Total Cost $MM/yr -9663 -16,490

Total Costs c/gal -2.37 -11.99

Federal Subsidies c/gal -4.47 -11.15

Total Costs c/gal -6.85 -23.14

 The cost including subsidies would represent gasoline and diesel fuel’s apparent cost as 

reflected to the fuel industry as a whole because the federal tax subsidies tends to transfer a 

portion of the actual costs to consumers through non-fuel taxes. Our analysis estimates that 

relative to the AEO 2007 reference case, the primary control case would cause a 6.9 cent per 

gallon decrease in the apparent cost of producing gasoline, and a 23.1 cent decrease in the 

apparent cost of producing diesel fuel. These costs would also represent the apparent cost to 

consumers “at the pump” if the full tax credit were passed along to the consumers. However, it 

is possible that only a portion of the tax subsidy will be passed along to the consumer 

(historically, this has been the case). Thus, the price impact at the pump may be somewhere 

between the values in Tables 4.4-12 and 4.4-13. However, consumers would also pay the full tax 

subsidy through higher taxes in addition to the values in Tables 4.4-13. 

 Table 4.4-14 summarizes the volumetric inputs to refineries in each PADD for the 

primary control case and provides the incremental difference relative to the AEO 2007 reference 

case. Because of the increased use of biofuels, petroleum inputs would be expected to decrease, 

and this is confirmed. 
117

Table 4.4-14. 

Summary of the Total and Incremental Volumetric Refinery Inputs by PADD 

for the Primary Control Case Relative to the AEO 2007 Reference Case 

(barrels/day) 

Control Difference Control Difference Control Difference Control Difference Control Difference

Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case

PADD Crude 1,246,981 -281,399 3,117,973 -340,516 7,056,501 -194,917 1,460,255 -73,349 1,865,224 -24,171

GTL Naphtha 0 0 0 0 0 0 0 0 0 0

GTL Diesel 0 0 0 0 0 0 0 0 0 0

VGO HS 0 0 0 0 0 -43,785 0 0 0 0

VGO LS 0 0 38,063 0 0 0 0 0 0 0

HS AR (A960) 0 0 0 0 0 0 0 0 0 0

LS AR (Alg) 290,427 60,773 0 0 732,497 26,283 0 0 0 0

Normal Butane 26,527 4,042 65,106 13,451 111,678 25,512 40,206 490 39,573 0

Isobutane 9,412 8,868 17,236 -6,556 25 25 19,001 12,735 0 0

Other 0 0 0 0 0 0 0 0 0 0

MTBE 0 0 0 0 0 0 0 0 0 0

Ethanol - E10 300,677 27,590 188,968 -8,932 155,813 -19,904 69,817 -573 145,656 2,998

Ethanol - E20 0 0 0 0 0 0 0 0 0 0

Ethanol - E85 243,490 243,490 111,243 111,243 212,446 212,446 17,420 17,420 0 0

Reformer Feed 0 0 0 0 0 0 0 0 0 0

Methanol 0 0 0 0 0 0 0 0 0 0

Natural Gas (FOE) 68,419 -12,688 135,263 -9,379 490,908 -13,379 87,228 -6,669 154,101 -1,567

Hydrogen (MSCF) 0 0 0 0 0 0 0 0 0 0

Pentanes Plus 0 0 32,124 0 52,055 0 18,580 0 0 0

Import CBOB 10% 148,371 142,085 0 0 0 0 0 0 0 0

Import CBOB 20% 0 0 0 0 0 0 0 0 0 0

Import RBOB 10% 65,943 -79,650 0 0 0 0 0 0 0 0

Import RBOB 20% 0 0 0 0 0 0 0 0 0 0

Import Alkylate 19,134 16,901 0 0 0 0 0 0 0 0

Import Raffinate 38,375 -15,151 0 0 0 0 0 0 45,808 0

Import Reformate 7,080 -1,749 0 0 0 0 0 0 0 0

Import FCC Naphtha 0 0 0 0 17,503 17,503 0 0 0 0

Import Lt Naphtha 0 0 0 0 0 0 0 0 584 0

Import Hvy Naph 0 0 0 0 41,644 0 0 0 0 0

Transfer Lt Naphtha 23,342 19,010 0 0 0 0 0 0 23,053 4,669

Transfer Reformate 17,226 569 0 0 0 0 0 0 0 0

Transfer Alkylate 59,431 -569 9,795 9,795 0 0 0 0 60,000 0

Transfer FCC Naphtha 0 0 20,822 0 0 0 0 0 0 0

Transfer Raffinate 0 0 784 -10,853 0 0 0 0 60,000 12,556

Transfer RBOB 10% 242,605 0 37,596 37,596 0 0 0 0 0 0

Transfer RBOB 20% 0 0 0 0 0 0 0 0 0 0

Transfer CBOB 10% 1,355,660 219,387 81,092 27,037 0 0 9,099 2,747 0 0

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0

Isooctane 3,278 3,178 100 0 100 0 100 0 13,287 -1,975

Isooctene 17,071 16,971 100 0 100 0 100 0 2,461 1,861

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA

 Table 4.4-14 shows that inputs of crude oil decreases substantially in most of the PADDs. 

In all the PADDs the input of crude oil to refineries decreases, which is expected since 

renewable fuels will supplant the need for petroleum feedstocks. Imports of gasoline 

blendstocks into PADD 1 also decreases. Butane inputs increase due to its blending into E85. 

 Table 4.4-15 below summarizes the refinery output volumes and changes in refinery 

output volumes relative to the reference case by PADD. 
 118

Table 4.4-15. 

Summary of Total and Incremental Refinery Outputs by PADD 

for the Primary Control Case Relative to the AEO 2007 Reference Case 

(barrels/day) 

Control Difference Control Difference Control Difference Control Difference Control Difference

Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case

Propane 30,305 -1,816 50,863 -6,424 100,460 -17,092 21,022 -1,481 52,834 1,242

Propylene 18,685 0 42,525 0 245,407 0 2,041 0 11,774 0

Normal Butane 0 -4,967 1,698 733 23,031 -10,632 0 0 0 0

Isobutane 0 0 0 0 0 -411 0 0 39,318 -2,172

PC Naphtha 15,830 0 40,290 0 432,937 0 0 0 0 0

PC Gasoil 0 0 502,059 -58,642 157,500 0 0 0 0 0

CG Reg 0 0 0 0 0 0 0 0 0 0

CG Prem 0 0 0 0 0 -182,001 0 0 0 0

CG E10 Reg 1,654,618 397,669 1,277,077 -100,639 850,572 -224,891 577,355 -8,008 96,902 1,992

CG E10 Prem 214,377 144,044 267,934 5,512 209,149 4,299 113,837 2,340 18,457 379

RFG E10 Reg 885,097 -271,021 273,652 5,624 405,579 19,731 0 0 1,114,370 22,903

RFG E10 Prem 222,613 2,400 52,124 1,071 77,253 3,758 0 0 212,261 4,363

CG E20 Reg 0 0 0 0 0 0 0 0 0 0

RFG E20 Reg 0 0 0 0 0 0 0 0 0 0

E85 to CG 0 0 129,577 129,577 247,459 247,459 20,291 20,291 0 0

E85 to RFG 283,619 283,619 0 0 0 0 0 0 0 0

Transfer RBOB 10% 0 0 0 0 280,201 37,596 0 0 0 0

Transfer RBOB 20% 0 0 0 0 0 0 0 0 0 0

Transfer CBOB 10% 0 0 0 0 1,445,851 249,171 0 0 0 0

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0

Jet/Kero A (450ppm) 70,000 0 143,275 3,194 936,227 0 274,537 0 229,653 0

X-Fer Diesel Rundown 0 0 0 0 0 0 0 0 0 0

HSD Gr 76 (0.2%) 0 0 0 0 0 0 0 0 0 0

LSD Gr 74 (.05%) 0 0 0 0 0 0 0 0 0 0

ULSD (15 ppm) 505,645 -128,972 562,879 -109,292 2,011,680 -124,623 470,858 -62,441 0 0

CARB Diesel 0 0 0 0 0 0 0 0 326,650 -37,699

X-Fer C5's to Storage 0 0 0 0 0 0 0 0 0 0

1% Residual Fuel 0 0 0 0 0 0 0 0 0 0

Residual Fuel 50,000 -41,643 57,026 -7,562 262,834 0 126,642 4,352 49,880 0

Slurry 31,083 3,675 76,076 -10,192 108,692 -5,256 18,513 5,031 28,829 -178

Asphalt & Wax 91,682 0 198,329 -9,357 157,500 0 5,250 0 41,774 0

Gasoil 0 0 4,895 0 0 0 0 0 9,814 0

Lubes 18,706 0 17,313 0 157,500 0 0 0 20,149 0

Benzene 11,003 0 11,003 0 51,347 0 0 0 0 0

Toluene 0 0 0 0 34,910 0 0 0 0 0

Xylenes 0 0 0 0 7,777 0 0 0 0 0

Cumene 0 0 0 0 0 0 0 0 0 0

Other 0 0 0 0 0 0 0 0 0 0

Cyclohexane 0 0 0 0 0 0 0 0 0 0

Transfer Raffinate 0 0 0 0 60,784 1,703 0 0 0 0

Transfer Alkylate 0 0 0 0 129,226 9,226 0 0 0 0

Transfer Reformate 0 0 0 0 17,226 569 0 0 0 0

Transfer FCC naphtha 0 0 0 0 20,822 0 0 0 0 0

Transfer Lt Naphtha 0 0 0 0 23,342 19,010 0 0 23,053 4,669

Transfer Blendstock 0 0 0 0 0 0 0 0 0 0

Sulfur (STons) 1,008 -146 3,676 -438 11,971 -427 1,925 -162 3,504 -42

Coke (STon) 2,913 -1,037 10,524 -2,203 47,524 -2,276 7,111 -1,368 17,012 -282

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA

What stands out in Table 4.4-15 is that E85 volumes increase while 10 percent ethanol 

gasoline blends decrease in response to the increased ethanol blended into the gasoline pool. 

Similarly, ultra low sulfur diesel fuel output decreases in response to the new volume of 

cellulosic and renewable diesel fuel and biodiesel. 

 Table 4.4-16 summarizes the change in refinery unit capacities by PADD comparing the 

primary control case to the AEO 2007 reference case. 
119

Table 4.4-16. 

Change in Refinery Unit Capacities by PADD 

for the Primary Control Case Relative to the AEO 2007 Reference Case 

(thousand barrels/day) 

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA California US Total

Crude Tower 0 -414 0 0 0 -414

Vacuum Tower 0 -185 0 0 0 -185

Sats Gas Plant -12 0 -2 0 8 -6

Unsats Gas Plant 0 0 0 0 0 0

FCC DeC5 Tower 0 0 0 0 0 0

FCC 0 0 0 0 0 0

FCC Splitter 4 -6 0 0 0 -2

Hydrocracker -16 0 0 -21 0 -37

H-Oil Unit 0 0 0 0 0 0

Delayed Coker 0 0 0 -24 0 -24

Visbreaker 0 0 0 0 0 0

Thermal Naphtha Splitter -1 -6 0 -1 0 -8

CRU Reformer 0 0 0 0 0 0

SRU Reformer 0 0 0 0 -5 -5

BTX Reformer 0 0 -10 0 0 -10

C4 Isomerization 0 0 0 0 1 1

C5/C6 Isomerization 21 0 0 0 0 21

HF Alkylation 0 0 0 0 0 0

H2SO4 Alkylation -14 0 0 13 0 -2

Dimersol 0 0 0 0 0 0

Cat Poly 6 0 0 0 0 6

Isooctane 0 0 0 0 0 0

DHT - Total -132 0 -75 -49 0 -256

DHT 2nd RCT - Total -117 -116 -146 -51 -4 -435

DHT Arom Saturation 0 0 0 0 0 0

NHT - Total Fd 0 0 0 0 0 0

CGH - Generic -16 -23 -6 -2 0 -48

CGH - Olefin Sat'n 0 0 0 0 0 0

FCCU Fd HDT 55 0 0 0 0 55

LSR Splitter 0 0 0 0 0 0

LSR Bz Saturator 0 0 0 0 0 0

Reformate Saturator -14 -4 1 0 0 -16

Reformate Splitter -41 -12 4 0 0 -49

SDA 0 0 0 0 0 0

MTBE 0 0 0 0 0 0

TAME 0 0 0 0 0 0

Hydrogen Plant - Total MSCF -88 -72 -84 -71 0 -316

Lube Unit 0 0 0 0 0 0

Sulfur Plant -95 0 0 -204 -69 -368

Merox Jet 0 0 0 0 0 0

Merox Diesel 0 0 0 0 0 0

BTX Reformer - Tower feed 0 0 0 0 0 0

BTX Reformer - Extract feed 0 0 0 0 0 0

 

 Most of the capacity throughput changes are negative, reflecting the decreased processing 

of crude oil and vacuum gas oil and decreased downstream refining units as projected by the 

refinery model. Another important decrease in refinery unit throughput is the distillate 
 120

hydrotreater and hydrocracker units which reflect the displacement of petroleum distillate by 

cellulosic and renewable diesel and biodiesel. 

 These changes in refinery unit throughputs are associated with changes in capital 

investments. Table 4.4-17 summarizes the projected change in capital investments between the 

primary control case and the AEO 2007 reference case. 
121

Table 4.4-17. 

Change in Refinery Unit Investments by PADD 

for the Primary Control Case Relative to the AEO 2007 Reference Case 

(million dollars/year)

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA California US Total

Crude Tower 0 -960 0 0 0 -960

Vacuum Tower 0 -572 0 0 0 -572

Sats Gas Plant -67 0 -4 0 53 -18

Unsats Gas Plant -2 0 0 0 0 -2

FCC DeC5 Tower 0 0 0 0 0 0

FCC 0 0 0 0 0 0

FCC Splitter 2 -7 0 0 0 -5

Hydrocracker -584 0 0 -641 0 -1,225

H-Oil Unit 0 0 0 0 0 0

Delayed Coker 0 0 0 -534 0 -534

Visbreaker 0 0 0 0 0 0

Thermal Naphtha Splitter -3 -7 0 -2 0 -12

CRU Reformer 0 0 0 0 0 0

SRU Reformer 0 0 0 0 -30 -30

BTX Reformer 0 0 -63 0 0 -63

C4 Isomerization 0 0 0 0 6 6

C5/C6 Isomerization 187 0 0 0 0 187

HF Alkylation 0 0 0 0 0 0

H2SO4 Alkylation -246 0 0 246 0 1

Dimersol 0 0 0 0 0 0

Cat Poly 48 0 0 0 0 48

Isooctane 0 0 0 0 0 0

DHT - Total -1,364 0 -496 -531 0 -2,391

DHT 2nd RCT - Total -905 -771 -694 -308 -21 -2,699

DHT Arom Saturation 0 0 0 0 0 0

NHT - Total Fd 0 0 0 0 0 0

CGH - Generic -75 -131 -60 -7 0 -274

CGH - Olefin Sat'n 0 0 0 0 0 0

FCCU Fd HDT 695 0 0 0 0 695

LSR Splitter 0 0 0 0 0 0

LSR Bz Saturator 0 0 0 0 0 0

Reformate Saturator -92 -19 5 0 0 -105

Reformate Splitter -53 -16 2 0 0 -68

SDA 000 000

MTBE 0 0 0 0 0 0

TAME 0 0 0 0 0 0

Hydrogen Plant - Total MSCF -352 -221 -227 -237 0 -1,038

Lube Unit 0 0 0 0 0 0

Sulfur Plant -3 0 0 -2 -2 -6

Merox Jet 0 0 0 0 0 0

Merox Diesel 0 0 0 0 0 0

BTX Reformer - Tower feed 0 0 -1 0 0 -1

BTX Reformer - Extract feed 0 0 0 0 0 0

Total -2,814 -2,704 -1,539 -2,016 6 -9,067

 Table 4.4-17 shows that incremental to the AEO 2007 reference case, refiners are 

expected to reduce their capital investments by $9.1 billion under the primary control case. The 

reduction in capital investments occurs in PADDs 1 through 4 and PADD 5 outside of 

California. Table 4.4-17 essentially expresses the change in refinery capacity input shown in 
 122

Table 4.4-16, but expresses the changes in terms of dollars instead of thousands of barrels per 

day. 

 The capital cost decrease in refineries is countered by the capital costs incurred to build 

new renewable fuels plants and to put into place the distribution system that the new renewable 

fuels require. The increased use of renewable and alternative fuels would require capital 

investments in corn and cellulosic ethanol plants, and renewable diesel fuel plants. In addition to 

producing the fuels, storage and distribution facilities along the whole distribution chain, 

including at retail, will have to be constructed for these new fuels. In Table 4.4-18, we list the 

total incremental capital investments that we project would be made for the primary control case 

incremental to the AEO 2007 reference case. All these capital costs are represented in the 

summary of costs in Table 4.4-12 either in the per-gallon biofuel production costs, or the pergallon distribution costs. 

Table 4.4-18. 

Projected Total U.S. Capital Investments for the Primary Control Case 

Relative to the AEO 2007 Reference Case 

(billion dollars) 

 Cost Type Plant Type Capital 

Investments 

Corn Ethanol 3.9 

Cellulosic Ethanol 14.3 

Cellulosic Diesel a 68.0 

Production 

Costs 

Renewable Diesel and 

Algae 

1.1 

All Ethanol 8.2 

Cellulosic and 

Renewable Diesel Fuel 

1.4 

Distribution 

Costs 

Biodiesel 1.2 

 FFV Costs 1.8 

 Refining -9.4 

Total Capital Investments 90.5 

a The cellulosic diesel fuel capital costs are based on the biomass-toliquids (BTL) technology which is a very capital intensive 

technology. If other cellulosic biofuel technologies are used which 

are less capital intensive than BTL technologies, these capital costs 

would be lower. 

 Table 4.4-18 shows that the total U.S. incremental capital investments to achieve the RFS 

2 volumes under the primary control case in 2022 is $90.5 billion. One contributing reason why 

the capital investments made for renewable fuels technologies is so much more than the decrease 

in refining industry capital investments is that a part of the decrease in petroleum gasoline supply 

was from reduced imports. In addition, renewable fuels technologies are more capital intensive 

per gallon of fuel produced than incremental increases in gasoline and diesel fuel production at 

refineries. 
123

 Table 4.4-19 summarizes the gasoline volume and qualities by different gasoline types 

for the primary control case, and also, for comparison, lists the same for the AEO 2007 reference 

case. 

Table 4.4-19. 

Ethanol and Gasoline Volume, Quality and Energy Density by Gasoline Type at the PADD 

Terminal for the Primary Control Case Relative to the AEO 2007 Reference Case 

Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control

RFG

Total ('000 BPD) 1,376,331 1,107,710 319,080 325,776 459,343 482,832 0 0 1,299,365 1,326,631 3,454,120 3,242,949

Ethanol ('000 BPD) 139,023 111,890 32,230 32,907 46,397 48,771 0 0 131,244 134,003 348,895 327,571

RVP (psi) 10.8 10.8 10.6 10.6 9.7 9.8 0.0 0.0 9.5 9.5 10.1 10.1

Sulfur (ppm) 24.4 24.6 20.0 20.5 23.2 23.4 0.0 0.0 8.8 8.5 18.0 17.4

Density 258.9 258.9 258.2 258.3 259.5 259.4 0.0 0.0 258.5 258.7 258.8 258.8

Octane (R+M/2) 88.1 88.3 88.0 88.0 88.0 88.0 0.0 0.0 87.6 87.6 87.9 87.9

Aromatics (vol%) 19.9 19.9 19.9 19.9 19.6 19.7 0.0 0.0 22.2 22.1 20.7 20.8

Benzene (vol%) 0.57 0.57 0.57 0.57 0.56 0.56 0.00 0.00 0.53 0.54 0.55 0.56

Olefins (vol%) 13.6 14.7 9.4 9.3 11.5 11.1 0.0 0.0 5.7 5.7 10.0 9.9

Oxygen (wt%) 3.7 3.7 3.7 3.7 3.7 3.7 0.0 0.0 3.7 3.7 3.7 3.7

E200 (vol%) 55.6 55.1 58.3 57.4 53.3 52.7 0.0 0.0 58.2 58.2 56.5 56.2

E300 (vol%) 93.9 95.3 93.9 93.8 93.9 93.4 0.0 0.0 86.2 86.2 91.0 91.2

Energy (MMBtu/Bbl 4.947 4.961 4.924 4.935 4.981 4.990 0.000 0.000 4.994 5.002 4.967 4.979

CG

Total ('000 BPD) 1,830,582 1,868,996 1,640,138 1,545,011 1,280,314 1,059,721 696,861 691,193 112,988 115,359 5,560,884 5,280,279

Ethanol ('000 BPD) 134,064 188,787 165,671 156,062 129,320 107,043 70,390 69,817 11,413 11,652 510,857 533,362

RVP (psi) 11.4 11.8 11.6 11.5 10.7 10.4 11.4 11.4 10.6 10.6 11.3 11.3

Sulfur (ppm) 22.9 24.5 23.6 23.3 23.1 23.1 28.0 28.0 26.6 26.3 23.9 24.4

Density 258.9 259.5 259.1 259.1 260.5 260.1 258.1 257.9 262.7 264.1 259.3 259.4

Octane (R+M/2) 87.8 87.8 88.0 88.0 88.0 88.2 86.9 86.9 89.3 89.5 87.8 87.9

Aromatics (vol%) 23.1 22.4 22.5 22.5 22.4 21.8 15.9 15.6 26.5 28.3 21.9 21.6

Benzene (vol%) 0.53 0.53 0.53 0.52 0.51 0.51 1.05 1.01 0.59 0.61 0.59 0.59

Olefins (vol%) 13.2 14.0 11.0 11.0 13.1 12.3 8.5 7.6 17.8 18.4 12.0 12.0

Oxygen (wt%) 2.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.4 3.7

E200 (vol%) 52.5 53.1 58.8 58.0 53.0 52.5 63.0 62.7 58.0 56.4 55.9 55.8

E300 (vol%) 93.9 95.3 93.9 83.8 93.9 79.5 93.9 90.6 86.2 86.2 93.7 88.0

Energy (MMBtu/Bbl 4.995 4.980 4.925 4.937 4.988 5.005 0.000 4.912 4.942 4.964 4.961 4.963

E85

Total ('000 BPD) 0 283,619 0 129,577 0 247,459 0 20,291 0 0 0 680,947

Ethanol ('000 BPD) 0 243,490 0 111,243 0 212,446 0 17,420 0 0 0 584,599

RVP (psi) 0.0 11.1 0.0 12.2 0.0 12.1 0.0 11.9 0.0 0.0 0.0 11.7

Sulfur (ppm) 0.0 9.5 0.0 8.8 0.0 8.8 0.0 8.8 0.0 0.0 0.0 9.1

Density 0.0 267.7 0.0 266.3 0.0 266.2 0.0 266.1 0.0 0.0 0.0 266.8

Octane (R+M/2) 0.0 107.9 0.0 108.0 0.0 108.0 0.0 107.9 0.0 0.0 0.0 107.9

Aromatics (vol%) 0.0 0.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.3

Benzene (vol%) 0.00 0.02 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.01

Olefins (vol%) 0.0 2.4 0.0 3.0 0.0 1.8 0.0 0.0 0.0 0.0 0.0 2.2

Oxygen (wt%) 0.0 30.6 0.0 30.8 0.0 30.8 0.0 30.8 0.0 0.0 0.0 30.7

E200 (vol%) 0.0 128.1 0.0 130.1 0.0 129.8 0.0 129.3 0.0 0.0 0.0 129.1

E300 (vol%) 0.0 96.1 0.0 96.6 0.0 96.6 0.0 96.6 0.0 0.0 0.0 96.4

Energy (MMBtu/Bbl 0.000 3.628 0.000 3.599 0.000 3.597 0.000 3.594 0.000 0.000 0.000 3.610

All Mogas

Total BPD 3,206,913 3,260,324 1,959,219 2,000,364 1,739,657 1,790,012 696,861 711,484 1,412,353 1,441,990 9,015,003 9,204,175

Ethanol BPD 273086.9 544,167 197900.9 300,212 175717.0 368,259 70390.0 87,238 142657.3 145,656 859752.1 1,445,532

RVP 11.1 11.4 11.4 11.4 10.4 10.5 11.4 11.4 9.6 9.6 10.8 10.9

Sulfur ppm 24 23 23 22 23 21 28 27 10 10 22 21

Density 258.9 260 259.0 259 260.2 261 258.1 258 258.9 259 259.1 260

R+M/2 87.9 89.7 88.0 89.3 88.0 90.9 86.9 87.5 87.8 87.8 87.8 89.4

Aromatics 21.7 19.7 22.1 20.6 21.7 18.2 15.9 15.2 22.5 22.6 21.5 19.7

Benzene 0.55 0.50 0.53 0.50 0.53 0.45 1.05 0.98 0.54 0.55 0.58 0.53

Olefins 13.4 13.2 10.7 10.2 12.7 10.6 8.5 7.4 6.7 6.7 11.2 10.6

Oxygen (wt%) 3.1 6.1 3.7 5.5 3.7 7.5 3.7 4.5 3.7 3.7 3.5 5.8

E200 53.8 60.3 58.7 62.6 53.1 63.2 63.0 64.6 58.2 58.1 56.1 61.4

E300 93.9 95.4 93.9 86.3 93.9 85.6 93.9 90.8 86.2 86.2 92.7 89.7

Energy (MMBtu/Bbl 4.974 4.856 4.925 4.850 4.986 4.806 4.913 4.874 4.990 4.999 4.963 4.869

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA US

 Several very important differences are evident when comparing the U.S. gasoline 

(mogas) qualities of the primary control case to the AEO 2007 reference case in Table 4.4-19. 
 124

First, the energy content of the control case gasoline is lower than that of the reference case. 

Other obvious changes include decreases in aromatics, benzene, olefins and sulfur. Another 

important change is the increase in the gasoline pool octane. Since the reference case gasoline 

pool was compliant in octane, the increased octane of the control case represents octane 

giveaway. After further review, it is evident that virtually all these changes are caused by the 

blending of E85 which significantly dilutes these properties in the gasoline blendstock in E85. 

Year-by-Year Costs 

 To understand entire costs of the increase in renewable fuel use mandated by EISA, their 

impacts on the U.S. economy, and to compare those costs to the benefits, we estimated the yearby-year costs from 2010, the first year of the RFS 2 program, to 2030. We first estimated 

renewable fuels volumes for each renewable fuels type based on the RFS2 volume standards and 

based on our projections of which renewable fuels would be used to comply with the standard 

(see Section 1.2). These volumes represent the increment between the AEO 2007 reference case 

and the primary control case. Based on AEO 2009, we also estimated the overall gasoline and 

diesel fuel volumes. Table 4.4-20 below summarizes the projected year-by-year incremental 

renewable fuel, and total gasoline and diesel fuel volumes. 

Table 4.4-20. 

Summary of Year-by-Year Volumes 

for the Primary Control Case Relative to the AEO 2007 Reference Case 

(Billion Gallons/year) 

Year

Diesel 

Fuel 

Volume

Cellulosic 

Diesel 

Fuel

Renewable 

Diesel Fuel

Biodiesel 

(all types)

Gasoline 

Volume

Corn 

Ethanol

Imported 

Ethanol

Cellulosic 

Ethanol

2010 62.93 0.04 0.04 0.51 158.65 0.75 0.00 -0.09

2011 63.98 0.10 0.08 0.56 162.54 1.38 0.00 -0.11

2012 65.47 0.20 0.08 0.71 162.15 2.01 0.00 -0.10

2013 66.42 0.41 0.08 0.87 161.03 2.49 0.00 0.06

2014 66.50 0.71 0.15 1.01 159.48 3.08 0.00 0.29

2015 66.65 1.22 0.15 1.13 157.14 3.69 0.00 0.67

2016 67.21 1.73 0.15 1.06 154.50 3.84 0.12 1.06

2017 67.85 2.24 0.15 1.09 152.44 3.70 0.54 1.44

2018 68.57 2.85 0.15 1.13 149.84 3.51 0.97 1.90

2019 69.23 3.46 0.15 1.16 148.08 3.31 1.38 2.36

2020 69.98 4.28 0.15 1.20 145.78 3.17 1.29 2.98

2021 70.59 5.50 0.15 1.24 144.14 2.93 1.19 3.90

2022 71.25 6.52 0.15 1.28 141.10 2.71 1.60 4.67

2023 72.16 6.52 0.15 1.28 141.18 2.71 1.60 4.67

2024 73.17 6.52 0.15 1.28 141.80 2.71 1.60 4.67

2025 74.21 6.52 0.15 1.28 141.66 2.71 1.60 4.67

2026 75.16 6.52 0.15 1.28 141.70 2.71 1.60 4.67

2027 76.07 6.52 0.15 1.28 139.74 2.71 1.60 4.67

2028 76.99 6.52 0.15 1.28 139.65 2.71 1.60 4.67

2029 77.87 6.52 0.15 1.28 138.14 2.71 1.60 4.67

2030 78.97 6.52 0.15 1.28 138.59 2.71 1.60 4.67
125

 

Also for our year-by-year cost analysis, we needed year-by-year estimates of the 

production and distribution cost for each renewable fuel type. The feedstock costs were 

available for the years 2012, 2017 and 2022 from FASOM for corn ethanol and soy oil, used for 

producing biodiesel, with crude oil priced at $116 per barrel. We entered those feedstock costs 

into the respective cost models and interpolated and extrapolated the production costs for the 

years provided to develop production costs for the in-between years. For cellulosic ethanol, we 

assumed the same feedstock costs for all years, but we adjusted the production costs based on 

our adjusted NREL production costs, interpolating between the years for which we have specific 

cost data. Imported ethanol costs by year are from Section 4.1 above. Tables 4.4-21 summarize 

the renewable fuels production costs by year along with the projected crude oil, gasoline and 

diesel fuel wholesale costs. 

Table 4.4-21. 

Renewable Fuel Production Costs Used in the Year-by-Year Analysis 

for the Primary Control Case Relative to the AEO 2007 Reference Case 

Year

Crude Oil 

Price 

($/bbl)

Wholesale 

Diesel Fuel 

Cost 

(c/gal)

Cellulosic 

Diesel 

Fuel Cost 

(c/gal)

Renewable 

Diesel Fuel 

Cost 

(c/gal)

Biodiesel 

Fuel Cost 

(c/gal)

Wholesale 

Gasoline 

Cost 

(c/gal)

Corn 

Ethanol 

Cost 

(c/gal)

Imported 

Ethanol 

Cost 

(c/gal)

Cellulosic 

Ethanol 

Cost 

(c/gal)

2010 49.0 154 258 236 261 157 160 158 220

2011 62.0 198 256 236 264 191 160 157 203

2012 72.1 232 255 236 227 218 160 156 186

2013 81.0 262 253 238 227 241 159 155 168

2014 88.6 288 251 240 225 262 158 154 151

2015 96.8 315 249 243 226 283 158 153 134

2016 101.9 333 248 245 228 297 157 153 133

2017 106.2 347 246 247 232 308 156 152 132

2018 110.5 362 244 246 234 320 155 152 131

2019 112.8 369 242 245 235 326 154 152 130

2020 114.5 375 241 244 238 330 152 151 129

2021 115.8 380 239 243 241 334 151 151 128

2022 116.5 383 237 242 244 335 150 150 127

2023 117.7 386 237 242 244 339 150 150 127

2024 118.3 388 237 242 244 340 150 149 127

2025 116.1 380 237 242 244 334 150 149 127

2026 117.5 385 237 242 244 338 150 149 127

2027 119.2 391 237 242 244 343 150 149 127

2028 121.2 398 237 242 244 348 150 149 127

2029 121.9 400 237 242 244 350 150 149 127

2030 124.4 409 237 242 244 356 150 149 127

 Based on the volumes and renewable fuels production and distribution costs, we 

estimated the net cost for the increased volumes of renewable fuels in years other than 2022 and 

summarized them in Table 4.4-22. We started with the year 2022 costs as our basis. We then 

adjusted those costs using the volume and price relationship between ethanol and gasoline to 

estimate the costs in other years. We also calculated the total dollar amount of the subsidies 

based on the volumes of renewable fuels and the subsidy that applies to each renewable fuel, and 

what the subsidized cost would be when the subsidies are applied. 
 126

Table 4.4-22. 

Year-by-Year Annual Average and Per-Gallon Costs for Gasoline 

for the Primary Control Case Relative to the AEO 20007 Reference Case 

Total 

Annual 

Cost 

($MM/yr)

PerGallon 

Cost 

(c/gal)

Subsidy 

($MM/yr)

Subsidized 

Per-Gallon 

Cost 

(c/gal)

Total 

Annual 

Cost 

($MM/yr)

PerGallon 

Cost 

(c/gal)

Subsidy 

($MM/yr)

Subsidized 

Per-Gallon 

Cost 

(c/gal)

2010 456 0.3 242 0.1 815 1.3 602 0.3

2011 703 0.4 511 0.1 719 1.1 693 0.0

2012 835 0.5 808 0.0 377 0.6 940 -0.9

2013 831 0.5 1181 -0.2 152 0.2 1312 -1.7

2014 758 0.5 1678 -0.6 -251 -0.4 1771 -3.0

2015 198 0.1 2339 -1.4 -963 -1.4 2405 -5.1

2016 -229 -0.1 2839 -2.0 -1601 -2.4 2797 -6.5

2017 -1110 -0.7 3275 -2.9 -2351 -3.5 3343 -8.4

2018 -2076 -1.4 3726 -3.9 -3400 -5.0 3992 -10.8

2019 -2825 -1.9 4150 -4.7 -4333 -6.3 4640 -13.0

2020 -2922 -2.0 4721 -5.2 -5479 -7.8 5504 -15.7

2021 -2936 -2.0 5554 -5.9 -7099 -10.1 6779 -19.7

2022 -3349 -2.4 6308 -6.8 -8546 -12.0 7849 -23.0

2023 -3545 -2.5 6308 -7.0 -8787 -12.2 7849 -23.1

2024 -3640 -2.6 6308 -7.0 -8933 -12.2 7849 -22.9

2025 -3285 -2.3 6308 -6.8 -8369 -11.3 7849 -21.9

2026 -3512 -2.5 6308 -6.9 -8728 -11.6 7849 -22.1

2027 -3769 -2.7 6308 -7.2 -9157 -12.0 7849 -22.4

2028 -4097 -2.9 6308 -7.5 -9679 -12.6 7849 -22.8

2029 -4199 -3.0 6308 -7.6 -9857 -12.7 7849 -22.7

2030 -4589 -3.3 6308 -7.9 -10473 -13.3 7849 -23.2

Gasoline Costs Diesel Fuel Costs

Year 

 The projected costs in Table 4.4-22 show that in the initial years of 2010 to 2013 for 

diesel fuel and 2010 to 2015 for gasoline, the per-gallon costs are positive reflecting the 

generally higher projected production costs for renewable fuels and the lower crude oil prices. 

After those initial years, the program would accrue a cost savings assuming that the crude oil 

prices projected by EIA hold true. 

4.4.2.1.2 Primary (Mid-Ethanol) Control Case Incremental to the RFS 1 Reference Case 

We also assessed the gasoline and diesel fuel costs and other impacts of the primary 

control case relative to the RFS1 reference case. The costs contained in Table 4.4-23 are 

reported by different cost components as well as aggregated total and per-gallon costs. 
127

Table 4.4-23. 

Primary Control Case Costs without Tax Subsidies 

Relative to the RFS 1 Reference Case 

(2007 dollars, 7% ROI before taxes) 

Gasoline Diesel Fuel

Refinery Model Variable Operating Cost $MM/yr 11,252 -

Amortized Refinery Capital Costs $MM/yr -1,031 -

Fixed Operating Costs $MM/yr -284 -

Added Gasoline Transportation Cost $MM/yr -148 -

E85 Pricing Effect $MM/yr -8,338 -

Crude Oil Cost $51 to $116/bbl $MM/yr -25,884 -

Lower Energy Density $MM/yr 15,928 1,750

Adjustment from Ethanol Price to Cost $MM/yr 507 -

FFV Costs $MM/yr 2,370

Renewable Diesel Cost vs Petroleum Diesel $MM/yr - -10,382

Total Costs $MM/yr -5,628 -8,632

Refinery Model Variable Operating Cost c/gal 7.97 -

Amortized Refinery Capital Costs c/gal -0.73 -

Fixed Operating Costs c/gal -0.20 -

Added Gasoline Transportation Cost c/gal -0.10 -

E85 Pricing Effect c/gal -5.91 -

Crude Oil Cost $51 to $116/bbl c/gal -18.34 -

Lower Energy Density c/gal 11.29 2.45

Adjustment from Ethanol Price to Cost c/gal 0.36 -

FFV Costs c/gal 1.68

Renewable Diesel Cost vs Petroleum Diesel c/gal - -14.56

Total Costs c/gal -3.99 -12.10

Our analysis shows that when considering all the costs associated with the expanded use 

of ethanol for the primary control case relative to the RFS 1 reference case that the cost of 

gasoline will decrease by $5.6 billion in the year 2022. Expressed as per-gallon costs, these fuel 

changes will reduce the cost of producing gasoline in the U.S. by 4.0 cents per gallon. The 

addition of biodiesel, renewable and cellulosic diesel fuel is estimated to reduce the cost of diesel 

fuel by $8.6 billion in the year 2022, or save 12.1 cents per gallon. 

Table 4.4-24. 

Primary Control Case Costs Reflecting Tax Subsidies 

Relative to the RFS 1 Reference Case 

(2007 dollars, 7% ROI before taxes)

Gasoline Diesel Fuel

Total Costs $MM/yr -5,628 -8,632

Federal Subsidies $MM/yr -9,075 -8,026

Revised Total Cost $MM/yr -14,703 -16,659

Total Costs c/gal -3.99 -12.10

Federal Subsidies c/gal -6.43 -11.25

Total Costs c/gal -10.42 -23.35

 Our analysis of the primary control case costs relative to the RFS 1 reference case 
 128

reflecting the federal tax subsidies would cause a 10.4 cent per gallon decrease in the apparent 

cost of producing gasoline, and a 23.4 cent decrease in the apparent cost of producing diesel fuel. 

While this could represent the cost of the renewable fuel use to consumers at retail, it is possible 

that only a portion of the tax subsidy will be passed along to the consumer. Thus, the price 

impact at the pump may be somewhere between the values in Tables 4.4-23 and 4.4-24. 

However, consumers would also pay the full tax subsidy through higher taxes which would 

offset the cost savings caused by the subsidies. 

 Table 4.4-25 summarizes the volumetric inputs to refineries in each PADD for this 

control case and shows the relative changes of the primary control case compared to the RFS 1 

reference case. Because of the increased use of biofuels, petroleum inputs would be expected to 

decrease, and this is confirmed. 

Table 4.4-25. 

Summary of the Total and Incremental Volumetric Refinery Inputs by PADD for the 

Primary Control Case Relative to the RFS 1 Reference Case 

(barrels/day) 

Control Difference Control Difference Control Difference Control Difference Control Difference

Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case

PADD Crude 1,347,342 -151,714 3,058,241 -475,740 7,117,305 -241,263 1,534,859 -4,119 1,886,357 -1,136

GTL Naphtha 0 0 0 0 0 0 0 0 0 0

GTL Diesel 0 0 0 0 0 0 0 0 0 0

VGO HS 0 0 0 0 0 -33,772 0 0 0 0

VGO LS 0 0 7,920 -23,914 0 0 0 0 0 0

HS AR (A960) 0 0 0 0 0 0 0 0 0 0

LS AR (Alg) 279,819 39,889 0 0 738,057 21,829 0 0 0 0

Normal Butane 30,814 8,329 78,293 19,185 69,363 -14,040 25,526 -13,917 39,573 0

Isobutane 12,582 12,582 16,476 -8,390 8,234 8,234 1,178 -22,245 0 0

Other 0 0 0 0 0 0 0 0 0 0

MTBE 0 0 0 0 0 0 0 0 0 0

Ethanol - E10 270,313 130,437 168,062 63,684 142,590 88,811 66,626 40,273 143,845 8,610

Ethanol - E20 0 0 0 0 0 0 0 0 0 0

Ethanol - E85 575,048 575,048 332,715 332,715 361,999 361,999 60,129 60,129 46,969 46,969

Reformer Feed 0 0 0 0 0 0 0 0 0 0

Methanol 0 0 0 0 0 0 0 0 0 0

Natural Gas (FOE) 74,115 -6,201 136,509 -5,559 493,553 6,876 86,015 -3,625 154,032 -2,444

Hydrogen (MSCF) 0 0 0 0 0 0 0 0 0 0

Pentanes Plus 0 0 58 -32,066 52,055 0 0 -17,467 0 0

Import CBOB 10% 0 0 0 0 0 0 0 0 0 0

Import CBOB 20% 0 0 0 0 0 0 0 0 0 0

Import RBOB 10% 0 -200,000 0 0 0 0 0 0 0 0

Import RBOB 20% 0 0 0 0 0 0 0 0 0 0

Import Alkylate 45,167 45,167 0 0 0 0 0 0 0 0

Import Raffinate 3,442 -61,147 0 0 0 0 0 0 45,808 0

Import Reformate 0 0 0 0 0 0 0 0 0 0

Import FCC Naphtha 15,980 15,980 0 0 11,943 11,943 18,580 18,580 0 0

Import Lt Naphtha 0 0 17,575 17,575 0 0 0 0 584 0

Import Hvy Naph 0 0 0 0 41,644 0 0 0 0 0

Transfer Lt Naphtha 0 -23,342 0 -20,822 0 0 0 0 11,387 -9,842

Transfer Reformate 16,658 0 0 -14,074 0 0 0 0 0 0

Transfer Alkylate 60,000 17,381 0 0 0 0 0 0 60,000 16,933

Transfer FCC Naphtha 0 0 20,822 20,822 0 0 0 0 0 0

Transfer Raffinate 0 0 11,353 -5,888 0 0 0 0 60,000 11,077

Transfer RBOB 10% 242,605 0 0 0 0 0 0 0 0 0

Transfer RBOB 20% 0 0 8,720 8,720 0 0 0 0 0 0

Transfer CBOB 10% 1,398,409 1,381,833 80,262 77,306 0 0 6,493 -19,539 0 0

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0

Isooctane 100 0 100 0 100 0 100 0 16,462 2,029

Isooctene 100 0 100 0 100 0 100 0 600 0

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA

 The changes in 4.4-25 are similar to those in 4.4-14 except because the new volume of 

ethanol is larger, some of the differences are larger. 

Table 4.4-26 below summarizes the refinery output volumes and changes in refinery 

output volumes for the primary control case relative to the RFS 1 reference case by PADD. 
129

Table 4.4-26. 

Summary of Total and Incremental Refinery Outputs by PADD 

for the Primary Control Case Relative to the RFS 1 Reference Case 

(barrels/day) 

Control Difference Control Difference Control Difference Control Difference Control Difference

Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case

Propane 34,143 1,539 50,843 -12,263 103,144 -32,064 23,369 -1,541 52,782 1,461

Propylene 18,685 0 42,525 0 245,407 0 2,041 0 11,774 0

Normal Butane 0 -7,832 0 -2,370 0 -45,506 0 0 0 0

Isobutane 0 0 0 0 0 -345 0 0 40,012 5,009

PC Naphtha 15,830 0 40,290 0 432,937 0 0 0 0 0

PC Gasoil 0 0 455,618 -108,658 157,500 0 0 0 0 0

CG Reg 0 -118,066 0 -852,131 0 -2,020,447 0 -374,129 0 -53,481

CG Prem 0 0 0 0 0 -416,926 0 -51,984 0 0

CG E10 Reg 1,535,198 1,516,962 1,172,450 704,964 872,274 872,274 542,856 325,693 99,374 59,284

CG E10 Prem 306,669 306,669 274,765 23,409 214,485 134,887 116,742 72,990 18,928 1,105

RFG E10 Reg 605,554 -542,443 163,150 -101,096 246,042 -134,362 0 0 1,088,091 12,026

RFG E10 Prem 228,678 10,012 53,454 3,122 78,844 6,386 0 0 217,676 12,712

CG E20 Reg 0 0 0 0 0 0 0 0 0 0

RFG E20 Reg 0 0 0 0 0 0 0 0 0 0

E85 to CG 74,814 74,814 270,064 270,064 253,773 253,773 70,039 70,039 0 0

E85 to RFG 595,006 595,006 117,484 117,484 167,888 167,888 0 0 54,710 54,710

Transfer RBOB 10% 0 0 0 0 251,325 8,720 0 0 0 0

Transfer RBOB 20% 0 0 0 0 0 0 0 0 0 0

Transfer CBOB 10% 0 0 0 0 1,485,164 1,439,600 0 0 0 0

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0

Jet/Kero A (450ppm) 70,000 0 138,523 -3,108 936,227 0 274,537 0 229,653 0

X-Fer Diesel Rundown t 0 0 0 00 0 0 0 0 0

HSD Gr 76 (0.2%) 0 0 0 0 0 0 0 0 0 0

LSD Gr 74 (.05%) 0 0 0 0 0 0 0 0 0 0

ULSD (15 ppm) 587,042 -39,165 643,331 -30,227 2,150,901 2,423 523,035 -11,120 0 0

CARB Diesel 0 0 0 0 0 0 0 0 358,152 -6,714

X-Fer C5's to Storage 0 0 0 0 0 0 0 0 0 0

1% Residual Fuel 0 0 0 0 0 0 0 0 0 0

Residual Fuel 68,283 -21,481 67,826 8 262,834 0 138,312 22,862 45,680 -4,199

Slurry 30,026 3,876 67,363 -19,645 112,554 -4,041 12,295 -4,210 29,893 1,191

Asphalt & Wax 86,013 -5,669 198,329 -11,671 157,500 0 5,250 0 41,774 0

Gasoil 0 0 4,895 0 0 0 0 0 9,814 0

Lubes 18,706 0 17,313 0 157,500 0 0 0 20,149 0

Benzene 11,003 0 11,003 0 51,347 0 0 0 0 0

Toluene 0 0 0 0 34,910 0 0 0 0 0

Xylenes 0 0 0 0 7,777 0 0 0 0 0

Cumene 0 0 0 0 0 0 0 0 0 0

Other 0 0 0 00 0 0 0 0 0

Cyclohexane 0 0 0 0 0 0 0 0 0 0

Transfer Raffinate 0 0 0 0 71,353 5,190 0 0 0 0

Transfer Alkylate 0 0 0 0 120,000 34,314 0 0 0 0

Transfer Reformate 0 0 0 0 16,658 16,658 0 0 0 0

Transfer FCC naphtha 0 0 0 0 20,822 20,822 0 0 0 0

Transfer Lt Naphtha 0 0 0 0 0 -23,342 0 0 11,387 -9,842

Transfer Blendstock 0 0 0 0 0 0 0 0 0 0

Sulfur (STons) 1,076 -74 3,571 -630 12,042 -533 2,038 -59 3,559 -10

Coke (STon) 3,495 -227 10,154 -3,068 48,646 -2,278 7,899 -790 17,358 86

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA

 Table 4.4-27 summarizes the change in refinery unit capacities by PADD comparing the 

primary control case to the RFS 1 reference case. 
 130

Table 4.4-27. 

Change in Refinery Unit Capacities by PADD 

for the Primary Control Case Relative to the RFS 1 Reference Case 

(thousand barrels/day) 

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA California US Total

Crude Tower 0 -439 0 0 0 -439

Vacuum Tower 0 -196 0 -2 0 -198

Sats Gas Plant 3 0 -30 0 9 -18

Unsats Gas Plant -2 0 0 0 0 -2

FCC DeC5 Tower 0 0 0 0 0 0

FCC 0 0 0 -8 0 -8

FCC Splitter 2 -6 0 0 0 -5

Hydrocracker -18 0 0 -14 0 -33

H-Oil Unit 0 0 0 0 0 0

Delayed Coker 0 0 0 -28 0 -28

Visbreaker 0 0 0 0 0 0

Thermal Naphtha Splitter -1 -6 0 -1 0 -8

CRU Reformer 0 0 0 0 0 0

SRU Reformer 0 0 0 0 -1 -1

BTX Reformer 0 -10 -18 0 0 -27

C4 Isomerization 0 0 0 0 1 1

C5/C6 Isomerization 26 0 0 0 0 26

HF Alkylation 0 0 0 0 0 0

H2SO4 Alkylation 1 0 0 -5 0 -4

Dimersol 0 0 0 0 0 0

Cat Poly 000 0 00

Isooctane 0 0 0 0 0 0

DHT - Total -132 0 -103 -50 -4 -290

DHT 2nd RCT - Total -117 -153 -174 -52 -4 -501

DHT Arom Saturation 0 0 0 0 0 0

NHT - Total Fd 0 0 0 -4 0 -4

CGH - Generic -12 -19 -19 -6 0 -57

CGH - Olefin Sat'n 0 0 0 0 0 0

FCCU Fd HDT 37 0 0 0 0 37

LSR Splitter 0 41 38 0 0 80

LSR Bz Saturator 0 0 0 0 0 0

Reformate Saturator -4 -4 1 0 0 -7

Reformate Splitter -12 -12 3 0 0 -21

SDA 0 0 0 0 0 0

MTBE 0 0 0 0 0 0

TAME 0 0 0 0 0 0

Hydrogen Plant - Total MSC -72 11 109 -47 0 1

Lube Unit 0 0 0 0 0 0

Sulfur Plant -128 0 0 -204 -71 -402

Merox Jet 0 0 0 0 0 0

Merox Diesel 0 0 0 0 0 0

BTX Reformer - Tower feed 0 -1 -1 0 0 -2

BTX Reformer - Extract feed -1 0 0 0 0 -1

These changes in refinery unit throughputs are associated with changes in capital 

investments. Table 4.4-28 summarizes the projected change in capital investments between the 

primary control case and the RFS 1 reference case. 
131

Table 4.4-28. 

Change in Refinery Unit Investments by PADD 

for the Primary Control Case Relative to the RFS 1 Reference Case 

(million dollars/year)

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA California US Total

Crude Tower 0 -997 0 0 0 -997

Vacuum Tower 0 -591 0 0 0 -591

Sats Gas Plant 12 0 -101 0 55 -34

Unsats Gas Plant -10 0 0 0 0 -10

FCC DeC5 Tower 0 0 0 0 0 0

FCC 0 0 0 -193 0 -193

FCC Splitter 1 -7 0 0 0 -6

Hydrocracker -631 0 0 -505 0 -1,137

H-Oil Unit 0 0 0 0 0 0

Delayed Coker 0 0 0 -592 0 -592

Visbreaker 0 0 0 0 0 0

Thermal Naphtha Splitter -3 -7 0 -3 0 -13

CRU Reformer 0 0 0 0 0 0

SRU Reformer 0 0 0 0 -4 -4

BTX Reformer 0 -93 -231 0 0 -324

C4 Isomerization 0 0 0 0 8 8

C5/C6 Isomerization 227 0 0 0 0 227

HF Alkylation 0 0 0 0 0 0

H2SO4 Alkylation 16 0 0 -70 0 -54

Dimersol 0 0 0 0 0 0

Cat Poly -1 0 0 0 0 -1

Isooctane 0 0 0 0 0 0

DHT - Total -1,367 0 -702 -539 -96 -2,703

DHT 2nd RCT - Total -904 -998 -840 -312 -21 -3,076

DHT Arom Saturation 0 0 0 0 0 0

NHT - Total Fd 0 0 0 -46 0 -46

CGH - Generic -58 -63 -92 -25 0 -238

CGH - Olefin Sat'n 0 0 0 0 0 0

FCCU Fd HDT 555 0 0 0 0 555

LSR Splitter 0 29 18 0 0 47

LSR Bz Saturator 0 0 0 0 0 0

Reformate Saturator -46 -19 4 0 0 -60

Reformate Splitter -20 -16 2 0 0 -34

SDA 0 0 0 0 0 0

MTBE 0 0 0 0 0 0

TAME 0 0 0 0 0 0

Hydrogen Plant - Total MSC -255 69 274 -171 0 -84

Lube Unit 0 0 0 0 0 0

Sulfur Plant -3 0 0 -2 -2 -7

Merox Jet 0 0 0 0 0 0

Merox Diesel 0 0 0 0 0 0

BTX Reformer - Tower feed 0 -2 -1 0 0 -3

BTX Reformer - Extract feed -3 0 0 0 0 -3

Total -2,491 -2,694 -1,669 -2,459 -59 -9,373

 Table 4.4-28 shows that incremental to the RFS 1 reference case, refiners under the 

primary control case are expected to reduce their capital investments by $9.4 billion compared to 
 132

business as usual. The reduction in capital investments occurs in PADDs 1 through 4 and PADD 

5 outside of California. Table 4.4-17 essentially expresses the change in refinery capacity input 

shown in Table 4.4-16, but expresses the changes in terms of dollars instead of thousands of 

barrels per day. 

Table 4.4-29 summarizes the gasoline volume and qualities by different gasoline types 

for the primary control case, and also, for comparison, lists the same for the RFS 1 reference 

case. 
133

Table 4.4-29. 

Ethanol and Gasoline Volume, Quality and Energy Density by Gasoline Type at the PADD 

Terminal for the Primary Control Case Relative to the RFS 1 Reference Case 

Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control

RFG

Total ('000 BPD) 1,366,663 1,107,710 314,578 325,776 452,862 482,832 0 0 1,281,031 1,326,631 3,415,134 3,242,949

Ethanol ('000 BPD) 138,034 111,890 31,773 32,907 45,739 48,771 0 0 129,386 134,003 344,932 327,571

RVP (psi) 10.7 10.8 10.3 10.6 9.6 9.8 0.0 0.0 9.5 9.5 10.1 10.1

Sulfur (ppm) 23.8 24.6 20.1 20.5 23.5 23.4 0.0 0.0 8.7 8.5 17.8 17.4

Density 258.5 258.9 256.2 258.3 259.1 259.4 0.0 0.0 258.5 258.7 258.4 258.8

Octane (R+M/2) 88.1 88.3 88.0 88.0 88.0 88.0 0.0 0.0 87.6 87.6 87.9 87.9

Aromatics (vol%) 19.9 19.9 18.2 19.9 19.5 19.7 0.0 0.0 22.2 22.1 20.5 20.8

Benzene (vol%) 0.57 0.57 0.57 0.57 0.57 0.56 0.00 0.00 0.54 0.54 0.56 0.56

Olefins (vol%) 13.1 14.7 8.0 9.3 9.3 11.1 0.0 0.0 5.7 5.7 9.3 9.9

Oxygen (wt%) 3.7 3.7 3.8 3.7 3.7 3.7 0.0 0.0 3.7 3.7 3.7 3.7

E200 (vol%) 55.7 55.1 62.5 57.4 54.5 52.7 0.0 0.0 58.5 58.2 57.2 56.2

E300 (vol%) 93.9 95.3 91.5 93.8 93.9 93.4 0.0 0.0 86.2 86.2 90.8 91.2

Energy (MMBtu/Bbl) 4.963 4.961 4.864 4.935 5.027 4.990 0.000 0.000 4.988 5.002 4.971 4.979

CG

Total ('000 BPD) 1,841,024 1,868,996 1,570,973 1,545,011 1,262,249 1,059,721 687,028 691,193 111,394 115,359 5,472,668 5,280,279

Ethanol ('000 BPD) 1,842 188,787 72,606 156,062 8,040 107,043 26,352 69,817 5,849 11,652 114,689 533,362

RVP (psi) 10.5 11.8 11.8 11.5 10.7 10.4 11.3 11.4 10.8 10.6 11.0 11.3

Sulfur (ppm) 27.8 24.5 25.3 23.3 27.3 23.1 24.6 28.0 26.4 26.3 26.6 24.4

Density 259.3 259.5 258.8 259.1 259.4 260.1 256.8 257.9 260.8 264.1 258.9 259.4

Octane (R+M/2) 88.0 87.8 88.0 88.0 88.0 88.2 86.8 86.9 88.0 89.5 87.8 87.9

Aromatics (vol%) 28.7 22.4 26.3 22.5 28.4 21.8 19.3 15.6 26.8 28.3 26.7 21.6

Benzene (vol%) 0.65 0.53 0.64 0.52 0.65 0.51 0.80 1.01 0.62 0.61 0.67 0.59

Olefins (vol%) 15.2 14.0 11.2 11.0 16.0 12.3 8.0 7.6 18.6 18.4 13.4 12.0

Oxygen (wt%) 0.0 3.7 1.7 3.7 0.2 3.7 1.4 3.7 1.9 3.7 0.8 3.7

E200 (vol%) 45.2 53.1 52.9 58.0 45.9 52.5 58.9 62.7 54.5 56.4 49.5 55.8

E300 (vol%) 93.9 95.3 91.5 83.8 93.9 79.5 93.9 90.6 86.2 86.2 93.0 88.0

Energy (MMBtu/Bbl) 5.133 4.980 5.007 4.937 5.127 5.005 5.004 4.912 4.998 4.964 5.077 4.963

E85

Total ('000 BPD) 0 283,619 0 129,577 0 247,459 0 20,291 0 0 0 680,947

Ethanol ('000 BPD) 0 243,490 0 111,243 0 212,446 0 17,420 0 0 0 584,599

RVP (psi) 0.0 11.1 0.0 12.2 0.0 12.1 0.0 11.9 0.0 0.0 0.0 11.7

Sulfur (ppm) 0.0 9.5 0.0 8.8 0.0 8.8 0.0 8.8 0.0 0.0 0.0 9.1

Density 0.0 267.7 0.0 266.3 0.0 266.2 0.0 266.1 0.0 0.0 0.0 266.8

Octane (R+M/2) 0.0 107.9 0.0 108.0 0.0 108.0 0.0 107.9 0.0 0.0 0.0 107.9

Aromatics (vol%) 0.0 0.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.3

Benzene (vol%) 0.00 0.02 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.01

Olefins (vol%) 0.0 2.4 0.0 3.0 0.0 1.8 0.0 0.0 0.0 0.0 0.0 2.2

Oxygen (wt%) 0.0 30.6 0.0 30.8 0.0 30.8 0.0 30.8 0.0 0.0 0.0 30.7

E200 (vol%) 0.0 128.1 0.0 130.1 0.0 129.8 0.0 129.3 0.0 0.0 0.0 129.1

E300 (vol%) 0.0 96.1 0.0 96.6 0.0 96.6 0.0 96.6 0.0 0.0 0.0 96.4

Energy (MMBtu/Bbl) 0.000 3.628 0.000 3.599 0.000 3.597 0.000 3.594 0.000 0.000 0.000 3.610

All Mogas

Total BPD 3,207,687 3,260,324 1,885,551 2,000,364 1,715,111 1,790,012 687,028 711,484 1,392,425 1,441,990 8,887,802 9,204,175

Ethanol BPD 139875.7 544,167 104378.5 300,212 53779.6 368,259 26352.4 87,238 135235.5 145,656 459621.7 1,445,532

RVP 10.6 11.4 11.5 11.4 10.4 10.5 11.3 11.4 9.6 9.6 10.6 10.9

Sulfur ppm 26.1 23.2 24.5 21.9 26.3 21.2 24.6 27.4 10.1 9.9 23.2 20.8

Density 258.9 260.0 258.4 259.5 259.3 260.8 256.8 258.1 258.7 259.2 258.7 259.8

R+M/2 88.0 89.7 88.0 89.3 88.0 90.9 86.8 87.5 87.7 87.8 87.8 89.4

Aromatics 24.9 19.7 24.9 20.6 26.0 18.2 19.3 15.2 22.6 22.6 24.3 19.7

Benzene 0.62 0.50 0.63 0.50 0.63 0.45 0.80 0.98 0.55 0.55 0.63 0.53

Olefins 14.3 13.2 10.7 10.2 14.2 10.6 8.0 7.4 6.7 6.7 11.8 10.6

Oxygen (wt%) 1.6 6.1 2.0 5.5 1.2 7.5 1.4 4.5 3.6 3.7 1.9 5.8

E200 49.7 60.3 54.5 62.6 48.1 63.2 58.9 64.6 58.1 58.1 52.5 61.4

E300 93.9 95.4 91.5 86.3 93.9 85.6 93.9 90.8 86.2 86.2 92.2 89.7

Energy (MMBtu/Bbl) 5.061 4.856 4.983 4.850 5.101 4.806 5.004 4.874 4.988 4.999 5.036 4.869

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA US

4.4.2.2 Low Ethanol Control Case 

 This section contains the tables which summarizes the costs and other impacts of the low 

ethanol control case relative to the AEO 2007 and RFS 1 reference cases. 

4.4.2.2.1 Low Ethanol Control Case Incremental to the AEO 2007 Reference Case 
 134

 This subsection summarizes the costs and other impacts of the low ethanol control case 

relative to the AEO 2007 reference case. 

Table 4.4-30 

Low Ethanol Control Case Costs without Tax Subsidies 

Relative to the AEO 2007 Reference Case 

(2007 dollars, 7% ROI before taxes) 

Gasoline Diesel Fuel

Refinery Model Variable Operating Cost $MM/yr 6,113 -

Amortized Refinery Capital Costs $MM/yr -1,138 -

Fixed Operating Costs $MM/yr -314 -

Added Gasoline Transportation Cost $MM/yr -42 -

E85 Pricing Effect $MM/yr -3,549 -

Crude Oil Cost $51 to $116/bbl $MM/yr -7,232 -

Lower Energy Density $MM/yr 4,098 2,254

Adjustment from Ethanol Price to Cost $MM/yr 648 -

FFV Costs $MM/yr 791

Renewable Diesel Cost vs Petroleum Diesel $MM/yr - -13,962

Total Costs $MM/yr -672 -11,707

Refinery Model Variable Operating Cost c/gal 4.38 -

Amortized Refinery Capital Costs c/gal -0.82 -

Fixed Operating Costs c/gal -0.22 -

Added Gasoline Transportation Cost c/gal -0.03 -

E85 Pricing Effect c/gal -2.54 -

Crude Oil Cost $51 to $116/bbl c/gal -5.18 -

Lower Energy Density c/gal 2.94 3.16

Adjustment from Ethanol Price to Cost c/gal 0.46 -

FFV Costs c/gal 0.57

Renewable Diesel Cost vs Petroleum Diesel c/gal - -19.56

Total Costs c/gal -0.48 -16.40

Table 4.4-31. 

Low Ethanol Control Case Costs Reflecting Tax Subsidies 

Relative to the AEO 2007 Reference Case 

(2007 dollars, 7% ROI before taxes)

Gasoline Diesel Fuel

Total Costs $MM/yr -672 -11,707

Federal Subsidies $MM/yr -1,597 -10,712

Revised Total Cost $MM/yr -2,269 -22,419

Total Costs c/gal -0.48 -16.40

Federal Subsidies c/gal -1.14 -15.00

Total Costs c/gal -1.63 -31.40
135

Table 4.4-32. 

Summary of the Total and Incremental Volumetric Refinery Inputs by PADD 

for the Low Ethanol Control Case Relative to the AEO 2007 Reference Case 

(barrels/day) 

Control Difference Control Difference Control Difference Control Difference Control Difference

Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case

PADD Crude 1,279,888 -248,492 3,227,551 -230,937 6,947,777 -303,641 1,418,700 -114,904 1,842,788 -46,607

GTL Naphtha 0 0 0 0 0 0 0 0 0 0

GTL Diesel 0 0 0 0 0 0 0 0 0 0

VGO HS 0 0 0 0 11,581 -32,204 0 0 0 0

VGO LS 0 0 38,063 0 0 0 0 0 0 0

HS AR (A960) 0 0 0 0 0 0 0 0 0 0

LS AR (Alg) 296,982 67,329 0 0 738,419 32,205 0 0 0 0

Normal Butane 22,485 0 55,234 3,579 111,678 25,512 39,858 142 39,573 0

Isobutane 9,412 8,868 15,826 -7,966 617 617 20,399 14,133 0 0

Other 0 0 0 0 0 0 0 0 0 0

MTBE 0 0 0 0 0 0 0 0 0 0

Ethanol - E10 319,378 46,291 200,104 2,203 157,892 -17,825 68,870 -1,520 144,107 1,450

Ethanol - E20 0 0 0 0 0 0 0 0 0 0

Ethanol - E85 25,821 25,821 27,311 27,311 178,439 178,439 18,976 18,976 0 0

Reformer Feed 0 0 0 0 0 0 0 0 0 0

Methanol 0 0 0 0 0 0 0 0 0 0

Natural Gas (FOE) 71,943 -9,163 135,126 -9,516 486,804 -17,483 84,312 -9,585 150,902 -4,765

Hydrogen (MSCF) 0 0 0 0 0 0 0 0 0 0

Pentanes Plus 0 0 32,124 0 52,055 0 18,580 0 0 0

Import CBOB 10% 241,570 235,283 0 0 0 0 0 0 0 0

Import CBOB 20% 0 0 0 0 0 0 0 0 0 0

Import RBOB 10% 107,364 -38,229 0 0 0 0 0 0 0 0

Import RBOB 20% 0 0 0 0 0 0 0 0 0 0

Import Alkylate 19,290 17,057 0 0 0 0 0 0 0 0

Import Raffinate 45,299 -8,228 0 0 0 0 0 0 45,808 0

Import Reformate 0 -8,829 0 0 0 0 0 0 0 0

Import FCC Naphtha 0 0 0 0 0 0 0 0 0 0

Import Lt Naphtha 0 0 0 0 0 0 0 0 584 0

Import Hvy Naph 7,291 7,291 0 0 41,644 0 0 0 0 0

Transfer Lt Naphtha 39,298 34,965 0 0 0 0 0 0 22,233 3,849

Transfer Reformate 9,504 -7,154 0 0 0 0 0 0 0 0

Transfer Alkylate 48,790 -11,210 1,609 1,609 0 0 0 0 60,000 0

Transfer FCC Naphtha 2,408 2,408 20,822 0 0 0 0 0 0 0

Transfer Raffinate 0 0 1,066 -10,571 0 0 0 0 59,963 12,519

Transfer RBOB 10% 242,605 0 37,596 37,596 0 0 0 0 0 0

Transfer RBOB 20% 0 0 0 0 0 0 0 0 0 0

Transfer CBOB 10% 1,289,975 153,702 114,969 60,914 0 0 9,099 2,747 0 0

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0

Isooctane 6,030 5,930 100 0 100 0 100 0 13,445 -1,817

Isooctene 24,113 24,013 100 0 100 0 100 0 804 204

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA
 136

Table 4.4-33. 

Summary of Total and Incremental Refinery Outputs by PADD 

for the Low Ethanol Control Case Relative to the AEO 2007 Control Case 

(barrels/day) 

Control Difference Control Difference Control Difference Control Difference Control Difference

Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case

Propane 30,661 -1,460 54,531 -2,756 101,580 -15,973 20,156 -2,347 52,426 834

Propylene 18,685 0 42,525 0 245,407 0 2,041 0 11,774 0

Normal Butane 6,350 1,383 2,614 1,650 22,377 -11,285 0 0 0 0

Isobutane 0 0 0 0 0 -411 0 0 41,656 167

PC Naphtha 15,830 0 40,290 0 432,937 0 0 0 0 0

PC Gasoil 0 0 535,896 -24,805 157,500 0 0 0 0 0

CG Reg 0 0 0 0 0 0 0 0 0 0

CG Prem 0 0 0 0 0 -182,001 0 0 0 0

CG E10 Reg 1,684,887 427,937 1,388,234 10,518 878,511 -196,953 569,190 -16,174 95,872 961

CG E10 Prem 168,009 97,675 270,485 8,063 206,925 2,075 112,627 1,129 18,261 183

RFG E10 Reg 1,094,702 -61,416 270,743 2,715 401,267 15,419 0 0 1,102,523 11,057

RFG E10 Prem 214,244 -5,969 51,570 517 76,432 2,937 0 0 210,004 2,106

CG E20 Reg 0 0 0 0 0 0 0 0 0 0

RFG E20 Reg 0 0 0 0 0 0 0 0 0 0

E85 to CG 0 0 31,813 31,813 207,848 207,848 22,103 22,103 0 0

E85 to RFG 30,077 30,077 0 0 0 0 0 0 0 0

Transfer RBOB 10% 0 0 0 0 280,201 37,596 0 0 0 0

Transfer RBOB 20% 0 0 0 0 0 0 0 0 0 0

Transfer CBOB 10% 0 0 0 0 1,414,043 217,363 0 0 0 0

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0

Jet/Kero A (450ppm) 70,000 0 143,275 3,194 936,227 0 274,537 0 229,653 0

X-Fer Diesel Rundown to Storage 0 0 0 0 0 0 0 0 0 0

HSD Gr 76 (0.2%) 0 0 0 0 0 0 0 0 0 0

LSD Gr 74 (.05%) 0 0 0 0 0 0 0 0 0 0

ULSD (15 ppm) 487,798 -146,819 552,466 -119,705 1,937,875 -198,428 448,555 -84,744 0 0

CARB Diesel 0 0 0 0 0 0 0 0 313,223 -51,127

X-Fer C5's to Storage 0 0 0 0 0 0 0 0 0 0

1% Residual Fuel 0 0 0 0 0 0 0 0 0 0

Residual Fuel 50,000 -41,643 56,903 -7,686 262,834 0 115,134 -7,157 49,880 0

Slurry 32,981 5,572 76,116 -10,151 106,272 -7,675 20,000 6,518 28,956 -51

Asphalt & Wax 91,682 0 210,000 2,314 157,500 0 5,250 0 41,774 0

Gasoil 0 0 4,895 0 0 0 0 0 9,814 0

Lubes 18,706 0 17,313 0 157,500 0 0 0 20,149 0

Benzene 11,003 0 11,003 0 51,347 0 0 0 0 0

Toluene 0 0 0 0 34,910 0 0 0 0 0

Xylenes 0 0 0 0 7,777 0 0 0 0 0

Cumene 0 0 0 0 0 0 0 0 0 0

Other 0 0 0 0 0 0 0 0 0 0

Cyclohexane 0 0 0 0 0 0 0 0 0 0

Transfer Raffinate 0 0 0 0 61,029 1,948 0 0 0 0

Transfer Alkylate 0 0 0 0 110,399 -9,601 0 0 0 0

Transfer Reformate 0 0 0 0 9,504 -7,154 0 0 0 0

Transfer FCC naphtha 0 0 0 0 34,440 13,618 0 0 0 0

Transfer Lt Naphtha 0 0 0 0 28,088 23,755 0 0 22,233 3,849

Transfer Blendstock 0 0 0 0 0 0 0 0 0 0

Sulfur (STons) 1,034 -120 3,768 -345 11,741 -657 1,880 -207 3,459 -86

Coke (STon) 3,201 -749 10,908 -1,818 46,210 -3,591 7,111 -1,368 16,750 -544

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA

 
137

Table 4.4-34. 

Change in Refinery Unit Capacities by PADD 

for the Low Ethanol Control Case Relative to the AEO 2007 Control Case 

(thousand barrels/day) 

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA California US Total

Crude Tower 0 -175 0 0 0 -175

Vacuum Tower 0 -78 0 0 0 -78

Sats Gas Plant -12 0 -13 0 6 -18

Unsats Gas Plant 1 0 0 0 0 1

FCC DeC5 Tower 0 0 0 0 0 0

FCC 0 0 0 0 0 0

FCC Splitter 4 -6 0 0 0 -2

Hydrocracker -16 0 0 -33 0 -49

H-Oil Unit 0 0 0 0 0 0

Delayed Coker 0 0 0 -24 0 -24

Visbreaker 0 0 0 0 0 0

Thermal Naphtha Splitter -1 -4 0 -1 0 -6

CRU Reformer 0 0 0 0 0 0

SRU Reformer 0 0 0 0 -9 -9

BTX Reformer 0 7 -6 0 0 1

C4 Isomerization 0 0 0 0 1 1

C5/C6 Isomerization 21 0 0 0 0 21

HF Alkylation 0 0 0 0 0 0

H2SO4 Alkylation -14 0 0 15 0 0

Dimersol 0 0 0 0 0 0

Cat Poly 600 006

Isooctane 0 0 0 0 0 0

DHT - Total -136 0 -213 -61 0 -410

DHT 2nd RCT - Total -127 -150 -220 -63 -10 -571

DHT Arom Saturation 0 0 0 0 0 0

NHT - Total Fd 0 0 0 0 0 0

CGH - Generic 24 -10 -17 -3 0 -6

CGH - Olefin Sat'n 0 0 0 0 0 0

FCCU Fd HDT 57 0 0 0 0 57

LSR Splitter 0 0 0 0 0 0

LSR Bz Saturator 0 0 0 0 0 0

Reformate Saturator -14 -9 1 0 0 -22

Reformate Splitter -43 -27 3 0 0 -66

SDA 0 0 0 0 0 0

MTBE 0 0 0 0 0 0

TAME 0 0 0 0 0 0

Hydrogen Plant - Total MSC -79 -52 -149 -101 0 -381

Lube Unit 0 0 0 0 0 0

Sulfur Plant -95 0 0 -264 -73 -432

Merox Jet 0 0 0 0 0 0

Merox Diesel 0 0 0 0 0 0

BTX Reformer - Tower feed 0 0 0 0 0 0

BTX Reformer - Extract feed 000 000
 138

Table 4.4-35. 

Change in Refinery Unit Investments by PADD 

for the Low Ethanol Control Case Relative to the AEO 2007 Control Case 

(million dollars/year)

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA California US Total

Crude Tower 0 -372 0 0 0 -372

Vacuum Tower 0 -297 0 0 0 -297

Sats Gas Plant -65 0 -24 0 48 -41

Unsats Gas Plant 6 0 0 0 0 6

FCC DeC5 Tower 0 0 0 0 0 0

FCC 0 0 0 0 0 0

FCC Splitter 2 -7 0 0 0 -5

Hydrocracker -584 0 0 -891 0 -1,475

H-Oil Unit 0 0 0 0 0 0

Delayed Coker 0 0 0 -534 0 -534

Visbreaker 0 0 0 0 0 0

Thermal Naphtha Splitter -3 -3 0 -2 0 -9

CRU Reformer 0 0 0 0 0 0

SRU Reformer 0 0 0 0 -66 -66

BTX Reformer 0 70 -38 0 0 32

C4 Isomerization 0 0 0 0 5 5

C5/C6 Isomerization 184 0 0 0 0 184

HF Alkylation 0 0 0 0 0 0

H2SO4 Alkylation -245 0 0 274 0 29

Dimersol 0 0 0 0 0 0

Cat Poly 48 0 0 0 0 48

Isooctane 0 0 0 0 0 0

DHT - Total -1,394 0 -1,511 -606 0 -3,510

DHT 2nd RCT - Total -949 -985 -1,103 -443 -57 -3,536

DHT Arom Saturation 0 0 0 0 0 0

NHT - Total Fd 0 0 0 0 0 0

CGH - Generic 157 -88 -87 -12 0 -29

CGH - Olefin Sat'n 0 0 0 0 0 0

FCCU Fd HDT 709 0 0 0 0 709

LSR Splitter 0 0 0 0 0 0

LSR Bz Saturator 0 0 0 0 0 0

Reformate Saturator -94 -60 5 0 0 -149

Reformate Splitter -55 -36 2 0 0 -88

SDA 0 0 0 0 0 0

MTBE 0 0 0 0 0 0

TAME 0 0 0 0 0 0

Hydrogen Plant - Total MSC -324 -172 -385 -363 0 -1,244

Lube Unit 0 0 0 0 0 0

Sulfur Plant -3 0 0 -2 -2 -7

Merox Jet 0 0 0 0 0 0

Merox Diesel 0 0 0 0 0 0

BTX Reformer - Tower feed 0 1 0 0 0 1

BTX Reformer - Extract feed 000 000

Total -2,609 -1,948 -3,141 -2,578 -72 -10,349

 
139

Table 4.4-36. 

Projected Total U.S. Capital Investments 

for the Low Ethanol Control Case Relative to the AEO 2007 Reference Case 

(billion dollars) 

Cost Type Plant Type Capital 

Investments 

Corn Ethanol 3.9 

Cellulosic Ethanol 0 

Cellulosic Diesel a 96.5 

Production 

Costs 

Renewable Diesel and 

Algae 

1.1 

All Ethanol 5.6 

Cellulosic and 

Renewable Diesel Fuel 

2.0 

Distribution 

Costs 

Biodiesel 1.2 

 FFV Costs 0.8 

 Refining -10.3 

Total Capital Investments 110.0 
 140

Table 4.4-37. 

Ethanol and Gasoline Volume, Quality and Energy Density by Gasoline Type at the PADD 

Terminal for the Low Ethanol Control Case Relative to the AEO 2007 Control Case 

Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control

RFG

Total ('000 BPD) 1,376,331 1,308,946 319,080 322,313 459,343 477,699 0 0 1,299,365 1,312,528 3,454,120 3,421,486

Ethanol ('000 BPD) 139,023 132,217 32,230 32,557 46,397 48,252 0 0 131,244 132,579 348,895 345,605

RVP (psi) 10.8 10.7 10.6 10.6 9.7 9.7 0.0 0.0 9.5 9.5 10.1 10.1

Sulfur (ppm) 24.4 24.5 20.0 20.7 23.2 24.1 0.0 0.0 8.8 8.8 18.0 18.0

Density 258.9 258.6 258.2 258.2 259.5 258.5 0.0 0.0 258.5 258.7 258.8 258.6

Octane (R+M/2) 88.1 88.1 88.0 88.0 88.0 88.0 0.0 0.0 87.6 87.6 87.9 87.9

Aromatics (vol%) 19.9 19.8 19.9 19.9 19.6 18.5 0.0 0.0 22.2 22.1 20.7 20.5

Benzene (vol%) 0.57 0.56 0.57 0.57 0.56 0.56 0.00 0.00 0.53 0.54 0.55 0.55

Olefins (vol%) 13.6 14.8 9.4 9.1 11.5 11.2 0.0 0.0 5.7 5.7 10.0 10.2

Oxygen (wt%) 3.7 3.7 3.7 3.7 3.7 3.7 0.0 0.0 3.7 3.7 3.7 3.7

E200 (vol%) 55.6 54.8 58.3 57.6 53.3 53.7 0.0 0.0 58.2 58.3 56.5 56.3

E300 (vol%) 93.9 82.3 93.9 91.1 93.9 93.9 0.0 0.0 86.2 86.2 91.0 86.2

Energy (MMBtu/Bbl) 4.947 4.953 4.924 4.939 4.981 4.973 0.000 0.000 4.994 5.000 4.967 4.972

CG

Total ('000 BPD) 1,830,582 1,852,896 1,640,138 1,658,720 1,280,314 1,085,436 696,861 681,817 112,988 114,133 5,560,884 5,393,001

Ethanol ('000 BPD) 134,064 187,161 165,671 167,547 129,320 109,640 70,390 68,870 11,413 11,529 510,857 544,748

RVP (psi) 11.4 11.8 11.6 11.5 10.7 10.5 11.4 11.4 10.6 10.6 11.3 11.4

Sulfur (ppm) 22.9 24.2 23.6 23.6 23.1 23.0 28.0 28.0 26.6 26.0 23.9 24.3

Density 258.9 258.9 259.1 258.9 260.5 259.6 258.1 257.6 262.7 263.4 259.3 259.0

Octane (R+M/2) 87.8 87.7 88.0 88.0 88.0 88.1 86.9 86.9 89.3 89.4 87.8 87.8

Aromatics (vol%) 23.1 22.4 22.5 22.5 22.4 21.8 15.9 15.2 26.5 27.6 21.9 21.5

Benzene (vol%) 0.53 0.52 0.53 0.53 0.51 0.51 1.05 1.03 0.59 0.63 0.59 0.59

Olefins (vol%) 13.2 13.9 11.0 10.8 13.1 11.9 8.5 7.6 17.8 17.5 12.0 11.8

Oxygen (wt%) 2.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.4 3.7

E200 (vol%) 52.5 52.9 58.8 58.5 53.0 52.5 63.0 63.1 58.0 57.2 55.9 55.9

E300 (vol%) 93.9 79.3 93.9 84.0 93.9 79.3 93.9 91.0 86.2 86.2 93.7 82.4

Energy (MMBtu/Bbl) 4.995 4.966 4.925 4.939 4.988 4.990 4.907 4.942 4.946 4.961 4.955

E85

Total ('000 BPD) 0 30,077 0 31,813 0 207,848 0 22,103 0 0 0 291,840

Ethanol ('000 BPD) 0 25,821 0 27,311 0 178,439 0 18,976 0 0 0 250,548

RVP (psi) 0.0 12.9 0.0 12.2 0.0 12.1 0.0 11.9 0.0 0.0 0.0 12.1

Sulfur (ppm) 0.0 8.9 0.0 8.8 0.0 8.8 0.0 8.8 0.0 0.0 0.0 8.8

Density 0.0 266.0 0.0 266.3 0.0 266.2 0.0 266.1 0.0 0.0 0.0 266.2

Octane (R+M/2) 0.0 108.1 0.0 108.0 0.0 107.9 0.0 107.9 0.0 0.0 0.0 108.0

Aromatics (vol%) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Benzene (vol%) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Olefins (vol%) 0.0 3.0 0.0 3.0 0.0 1.3 0.0 0.0 0.0 0.0 0.0 1.5

Oxygen (wt%) 0.0 30.8 0.0 30.8 0.0 30.8 0.0 30.8 0.0 0.0 0.0 30.8

E200 (vol%) 0.0 130.1 0.0 130.1 0.0 129.7 0.0 129.3 0.0 0.0 0.0 129.7

E300 (vol%) 0.0 96.6 0.0 96.6 0.0 96.6 0.0 96.6 0.0 0.0 0.0 96.6

Energy (MMBtu/Bbl) 0.000 3.591 0.000 3.599 0.000 3.596 0.000 3.594 0.000 0.000 0.000 3.596

All Mogas

Total BPD 3,206,913 3,191,919 1,959,219 2,012,845 1,739,657 1,770,983 696,861 703,921 1,412,353 1,426,660 9,015,003 9,106,327

Ethanol BPD 273,087 345,199 197,901 227,416 175,717 336,332 70,390 87,846 142,657 144,107 859,752 1,140,900

RVP 11.1 11.4 11.4 11.4 10.4 10.5 11.4 11.4 9.6 9.6 10.8 10.9

Sulfur ppm 24 24 23 23 23 22 28 27 10 10 22 21

Density 259 259 259 259 260 260 258 258 259 259 259 259

R+M/2 87.9 88.0 88.0 88.3 88.0 90.4 86.9 87.6 87.8 87.8 87.8 88.5

Aromatics 21.7 21.1 22.1 21.7 21.7 18.3 15.9 14.8 22.5 22.6 21.5 20.4

Benzene 0.55 0.53 0.53 0.52 0.53 0.46 1.05 1.00 0.54 0.55 0.58 0.56

Olefins 13.4 14.1 10.7 10.4 12.7 10.5 8.5 7.4 6.7 6.6 11.2 10.9

Oxygen (wt%) 3.1 4.0 3.7 4.2 3.7 7.0 3.7 4.6 3.7 3.7 3.5 4.6

E200 53.8 54.4 58.7 59.5 53.1 61.9 63.0 65.2 58.2 58.2 56.1 58.4

E300 93.9 80.7 93.9 85.3 93.9 85.3 93.9 91.2 86.2 86.2 92.7 84.3

Energy (MMBtu/Bbl) 4.974 4.948 4.925 4.918 4.986 4.822 4.913 4.866 4.990 4.995 4.963 4.918

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA US

4.4.2.2.2 Low Ethanol Control Case Incremental to the RFS 1 Reference Case 

This subsection summarizes the gasoline and diesel fuel costs and other impacts of the 

low ethanol control case relative to the RFS1 reference case. 
141

Table 4.4-38. 

Low Ethanol Control Case Costs without Tax Subsidies 

Relative to the RFS 1 Reference Case 

(2007 dollars, 7% ROI before taxes) 

Gasoline Diesel Fuel

Refinery Model Variable Operating Cost $MM/yr 6,289 -

Amortized Refinery Capital Costs $MM/yr -1,172 -

Fixed Operating Costs $MM/yr -323 -

Added Gasoline Transportation Cost $MM/yr -102 -

E85 Pricing Effect $MM/yr -3,549 -

Crude Oil Cost $51 to $116/bbl $MM/yr -17,805 -

Lower Energy Density $MM/yr 10,917 2,283

Adjustment from Ethanol Price to Cost $MM/yr 1,108 -

FFV Costs $MM/yr 1,516

Renewable Diesel Cost vs Petroleum Diesel $MM/yr - -14,071

Total Costs $MM/yr -3,121 -11,788

Refinery Model Variable Operating Cost c/gal 4.50 -

Amortized Refinery Capital Costs c/gal -0.84 -

Fixed Operating Costs c/gal -0.23 -

Added Gasoline Transportation Cost c/gal -0.07 -

E85 Pricing Effect c/gal -2.54 -

Crude Oil Cost $51 to $116/bbl c/gal -12.75 -

Lower Energy Density c/gal 7.82 3.19

Adjustment from Ethanol Price to Cost c/gal 0.79 -

FFV Costs c/gal 1.09

Renewable Diesel Cost vs Petroleum Diesel c/gal - -19.69

Total Costs c/gal -2.24 -16.49

Table 4.4-39. 

Low Ethanol Control Case Costs Reflecting Tax Subsidies 

Relative to the RFS 1 Reference Case 

(2007 dollars, 7% ROI before taxes)

Gasoline Diesel Fuel

Total Costs $MM/yr -3,121 -11,788

Federal Subsidies $MM/yr -4,358 -10,794

Revised Total Cost $MM/yr -7479 -22,582

Total Costs c/gal -2.24 -16.49

Federal Subsidies c/gal -3.12 -15.10

Total Costs c/gal -5.36 -31.60

 
 142

Table 4.4-40. 

Summary of the Total and Incremental Volumetric Refinery Inputs by PADD 

(barrels/day) 

Control Difference Control Difference Control Difference Control Difference Control Difference

Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case

PADD Crude 1,279,888 -219,169 3,227,551 -306,429 6,947,777 -410,791 1,418,700 -120,278 1,842,788 -44,705

GTL Naphtha 0 0 0 0 0 0 0 0 0 0

GTL Diesel 0 0 0 0 0 0 0 0 0 0

VGO HS 0 0 0 0 11,581 -22,191 0 0 0 0

VGO LS 0 0 38,063 6,229 0 0 0 0 0 0

HS AR (A960) 0 0 0 0 0 0 0 0 0 0

LS AR (Alg) 296,982 57,053 0 0 738,419 22,191 0 0 0 0

Normal Butane 22,485 0 55,234 -3,874 111,678 28,274 39,858 415 39,573 0

Isobutane 9,412 9,412 15,826 -9,041 617 617 20,399 -3,024 0 0

Other 0 0 0 0 0 0 0 0 0 0

MTBE 0 0 0 0 0 0 0 0 0 0

Ethanol - E10 319,378 179,502 200,104 95,726 157,892 104,113 68,870 42,518 144,107 8,872

Ethanol - E20 0 0 0 0 0 0 0 0 0 0

Ethanol - E85 25,821 25,821 27,311 27,311 178,439 178,439 18,976 18,976 0 0

Reformer Feed 0 0 0 0 0 0 0 0 0 0

Methanol 0 0 0 0 0 0 0 0 0 0

Natural Gas (FOE) 71,943 -8,373 135,126 -6,941 486,804 126 84,312 -5,329 150,902 -5,574

Hydrogen (MSCF) 0 0 0 0 0 0 0 0 0 0

Pentanes Plus 0 0 32,124 0 52,055 0 18,580 1,113 0 0

Import CBOB 10% 241,570 241,570 0 0 0 0 0 0 0 0

Import CBOB 20% 0 0 0 0 0 0 0 0 0 0

Import RBOB 10% 107,364 -92,636 0 0 0 0 0 0 0 0

Import RBOB 20% 0 0 0 0 0 0 0 0 0 0

Import Alkylate 19,290 19,290 0 0 0 0 0 0 0 0

Import Raffinate 45,299 -19,291 0 0 0 0 0 0 45,808 0

Import Reformate 0 0 0 0 0 0 0 0 0 0

Import FCC Naphtha 0 0 0 0 0 0 0 0 0 0

Import Lt Naphtha 0 0 0 0 0 0 0 0 584 0

Import Hvy Naph 7,291 7,291 0 0 41,644 0 0 0 0 0

Transfer Lt Naphtha 39,298 15,956 0 -20,822 0 0 0 0 22,233 1,004

Transfer Reformate 9,504 -7,154 0 -14,074 0 0 0 0 0 0

Transfer Alkylate 48,790 6,171 1,609 1,609 0 0 0 0 60,000 16,933

Transfer FCC Naphtha 2,408 2,408 20,822 20,822 0 0 0 0 0 0

Transfer Raffinate 0 0 1,066 -16,175 0 0 0 0 59,963 11,040

Transfer RBOB 10% 242,605 0 37,596 37,596 0 0 0 0 0 0

Transfer RBOB 20% 0 0 0 0 0 0 0 0 0 0

Transfer CBOB 10% 1,289,975 1,273,399 114,969 112,012 0 0 9,099 -16,933 0 0

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0

Isooctane 6,030 5,930 100 0 100 0 100 0 13,445 -988

Isooctene 24,113 24,013 100 0 100 0 100 0 804 204

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA
143

Table 4.4-41. 

Summary of Total and Incremental Refinery Outputs by PADD 

for the Low Ethanol Control Case Relative to the RFS 1 Control Case 

(barrels/day) 

Control Difference Control Difference Control Difference Control Difference Control Difference

Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case

Propane 30,661 -1,943 54,531 -8,575 101,580 -33,628 20,156 -4,754 52,426 1,106

Propylene 18,685 0 42,525 0 245,407 0 2,041 0 11,774 0

Normal Butane 6,350 -1,482 2,614 244 22,377 -23,129 0 0 0 0

Isobutane 0 0 0 0 0 -345 0 0 41,656 6,653

PC Naphtha 15,830 0 40,290 0 432,937 0 0 0 0 0

PC Gasoil 0 0 535,896 -28,380 157,500 0 0 0 0 0

CG Reg 0 -118,066 0 -852,131 0 -2,020,447 0 -374,129 0 -53,481

CG Prem 0 0 0 0 0 -416,926 0 -51,984 0 0

CG E10 Reg 1,684,887 1,666,651 1,388,234 920,748 878,511 878,511 569,190 352,027 95,872 55,782

CG E10 Prem 168,009 168,009 270,485 19,129 206,925 127,328 112,627 68,875 18,261 438

RFG E10 Reg 1,094,702 -53,295 270,743 6,497 401,267 20,863 0 0 1,102,523 26,457

RFG E10 Prem 214,244 -4,422 51,570 1,238 76,432 3,974 0 0 210,004 5,040

CG E20 Reg 0 0 0 0 0 0 0 0 0 0

RFG E20 Reg 0 0 0 0 0 0 0 0 0 0

E85 to CG 0 0 31,813 31,813 207,848 207,848 22,103 22,103 0 0

E85 to RFG 30,077 30,077 0 0 0 0 0 0 0 0

Transfer RBOB 10% 0 0 0 0 280,201 37,596 0 0 0 0

Transfer RBOB 20% 0 0 0 0 0 0 0 0 0 0

Transfer CBOB 10% 0 0 0 0 1,414,043 1,368,478 0 0 0 0

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0

Jet/Kero A (450ppm) 70,000 0 143,275 1,643 936,227 0 274,537 0 229,653 0

X-Fer Diesel Rundown t 0 00 0 0 0 0 0 0 0

HSD Gr 76 (0.2%) 0 0 0 0 0 0 0 0 0 0

LSD Gr 74 (.05%) 0 0 0 0 0 0 0 0 0 0

ULSD (15 ppm) 487,798 -138,408 552,466 -121,092 1,937,875 -210,603 448,555 -85,599 0 0

CARB Diesel 0 0 0 0 0 0 0 0 313,223 -51,643

X-Fer C5's to Storage 0 0 0 0 0 0 0 0 0 0

1% Residual Fuel 0 0 0 0 0 0 0 0 0 0

Residual Fuel 50,000 -39,764 56,903 -10,915 262,834 0 115,134 -316 49,880 0

Slurry 32,981 6,831 76,116 -10,892 106,272 -10,322 20,000 3,494 28,956 254

Asphalt & Wax 91,682 0 210,000 0 157,500 0 5,250 0 41,774 0

Gasoil 0 0 4,895 0 0 0 0 0 9,814 0

Lubes 18,706 0 17,313 0 157,500 0 0 0 20,149 0

Benzene 11,003 0 11,003 0 51,347 0 0 0 0 0

Toluene 0 0 0 0 34,910 0 0 0 0 0

Xylenes 0 0 0 0 7,777 0 0 0 0 0

Cumene 0 0 0 0 0 0 0 0 0 0

Other 0 0 0 0 0 0 0 0 0 0

Cyclohexane 0 0 0 0 0 0 0 0 0 0

Transfer Raffinate 0 0 0 0 61,029 -5,135 0 0 0 0

Transfer Alkylate 0 0 0 0 110,399 24,713 0 0 0 0

Transfer Reformate 0 0 0 0 9,504 9,504 0 0 0 0

Transfer FCC naphtha 0 0 0 0 34,440 34,440 0 0 0 0

Transfer Lt Naphtha 0 0 0 0 28,088 4,746 0 0 22,233 1,004

Transfer Blendstock 0 0 0 0 0 0 0 0 0 0

Sulfur (STons) 1,034 -115 3,768 -433 11,741 -834 1,880 -216 3,459 -110

Coke (STon) 3,201 -520 10,908 -2,313 46,210 -4,714 7,111 -1,577 16,750 -523

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA

 
 144

Table 4.4-42. 

Change in Refinery Unit Capacities by PADD 

for the Low Ethanol Control Case Relative to the RFS 1 Control Case 

(thousand barrels/day) 

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA California US Total

Crude Tower 0 -200 0 0 0 -200

Vacuum Tower 0 -89 0 -2 0 -92

Sats Gas Plant 4 0 -40 0 7 -29

Unsats Gas Plant 0 0 0 0 0 0

FCC DeC5 Tower 0 0 0 0 0 0

FCC 0 0 0 -8 0 -8

FCC Splitter 2 -6 0 0 0 -5

Hydrocracker -18 0 0 -26 0 -45

H-Oil Unit 0 0 0 0 0 0

Delayed Coker 0 0 0 -28 0 -28

Visbreaker 00 0 0 00

Thermal Naphtha Splitter -1 -4 0 -1 0 -6

CRU Reformer 00 0 0 00

SRU Reformer 0 0 0 0 -5 -5

BTX Reformer 0 -3 -14 0 0 -16

C4 Isomerization 0 0 0 0 1 1

C5/C6 Isomerization 25 0 0 0 0 25

HF Alkylation 0 0 0 0 0 0

H2SO4 Alkylation 1 0 0 -3 0 -2

Dimersol 0 0 0 0 0 0

Cat Poly 0 0 0 0 0 0

Isooctane 0 0 0 0 0 0

DHT - Total -137 0 -241 -62 -4 -444

DHT 2nd RCT - Total -126 -187 -248 -64 -10 -637

DHT Arom Saturation 0 0 0 0 0 0

NHT - Total Fd 0 0 0 -4 0 -4

CGH - Generic 28 -6 -30 -7 0 -15

CGH - Olefin Sat'n 0 0 0 0 0 0

FCCU Fd HDT 39 0 0 0 0 39

LSR Splitter 0 41 38 0 0 80

LSR Bz Saturator 0 0 0 0 0 0

Reformate Saturator -4 -9 1 0 0 -13

Reformate Splitter -13 -27 3 0 0 -38

SDA 0 0 0 0 0 0

MTBE 0 0 0 0 0 0

TAME 0 0 0 0 0 0

Hydrogen Plant - Total MSCF -62 31 44 -77 0 -64

Lube Unit 0 0 0 0 0 0

Sulfur Plant -128 0 0 -264 -75 -467

Merox Jet 0 0 0 0 0 0

Merox Diesel 0 0 0 0 0 0

BTX Reformer - Tower feed 0 -1 0 0 0 -1

BTX Reformer - Extract feed -1 0 0 0 0 -1
145

Table 4.4-43. 

Change in Refinery Unit Investments by PADD 

for the Low Ethanol Control Case Relative to the RFS 1 Control Case 

(million dollars/year)

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA California US Total

Crude Tower 0 -408 0 0 0 -408

Vacuum Tower 0 -317 0 0 0 -317

Sats Gas Plant 14 0 -120 0 50 -57

Unsats Gas Plant -1 0 0 0 0 -1

FCC DeC5 Tower 0 0 0 0 0 0

FCC 0 0 0 -193 0 -193

FCC Splitter 1 -7 0 0 0 -6

Hydrocracker -631 0 0 -755 0 -1,386

H-Oil Unit 0 0 0 0 0 0

Delayed Coker 0 0 0 -592 0 -592

Visbreaker 0 0 0 0 0 0

Thermal Naphtha Splitter -3 -3 0 -3 0 -10

CRU Reformer 00 0 0 00

SRU Reformer 0 0 0 0 -40 -40

BTX Reformer 0 -22 -206 0 0 -229

C4 Isomerization 0 0 0 0 7 7

C5/C6 Isomerization 224 0 0 0 0 224

HF Alkylation 0 0 0 0 0 0

H2SO4 Alkylation 17 0 0 -42 0 -25

Dimersol 0 0 0 0 0 0

Cat Poly -1 0 0 0 0 -1

Isooctane 0 0 0 0 0 0

DHT - Total -1,397 0 -1,716 -614 -96 -3,822

DHT 2nd RCT - Total -948 -1,212 -1,249 -447 -57 -3,913

DHT Arom Saturation 0 0 0 0 0 0

NHT - Total Fd 0 0 0 -46 0 -46

CGH - Generic 175 -20 -119 -29 0 7

CGH - Olefin Sat'n 0 0 0 0 0 0

FCCU Fd HDT 569 0 0 0 0 569

LSR Splitter 0 29 18 0 0 47

LSR Bz Saturator 0 0 0 0 0 0

Reformate Saturator -48 -60 4 0 0 -104

Reformate Splitter -21 -36 2 0 0 -55

SDA 0 0 0 0 0 0

MTBE 0 0 0 0 0 0

TAME 0 0 0 0 0 0

Hydrogen Plant - Total MSCF -227 118 117 -298 0 -290

Lube Unit 0 0 0 0 0 0

Sulfur Plant -3 0 0 -2 -2 -7

Merox Jet 0 0 0 0 0 0

Merox Diesel 0 0 0 0 0 0

BTX Reformer - Tower feed 0 -1 -1 0 0 -2

BTX Reformer - Extract feed -3 0 0 0 0 -3

Total -2,285 -1,938 -3,272 -3,021 -138 -10,654

 

 
 146

Table 4.4-44. 

Ethanol and Gasoline Volume, Quality and Energy Density by Gasoline Type at the PADD 

Terminal for the Low Ethanol Control Case Relative to the RFS 1 Control Case 

Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control

RFG

Total ('000 BPD) 1,366,663 1,308,946 314,578 322,313 452,862 477,699 0 0 1,281,031 1,312,528 3,415,134 3,421,486

Ethanol ('000 BPD) 138,034 132,217 31,773 32,557 45,739 48,252 0 0 129,386 132,579 344,932 345,605

RVP (psi) 10.7 10.7 10.3 10.6 9.6 9.7 0.0 0.0 9.5 9.5 10.1 10.1

Sulfur (ppm) 23.8 24.5 20.1 20.7 23.5 24.1 0.0 0.0 8.7 8.8 17.8 18.0

Density 258.5 258.6 256.2 258.2 259.1 258.5 0.0 0.0 258.5 258.7 258.4 258.6

Octane (R+M/2) 88.1 88.1 88.0 88.0 88.0 88.0 0.0 0.0 87.6 87.6 87.9 87.9

Aromatics (vol%) 19.9 19.8 18.2 19.9 19.5 18.5 0.0 0.0 22.2 22.1 20.5 20.5

Benzene (vol%) 0.57 0.56 0.57 0.57 0.57 0.56 0.00 0.00 0.54 0.54 0.56 0.55

Olefins (vol%) 13.1 14.8 8.0 9.1 9.3 11.2 0.0 0.0 5.7 5.7 9.3 10.2

Oxygen (wt%) 3.7 3.7 3.8 3.7 3.7 3.7 0.0 0.0 3.7 3.7 3.7 3.7

E200 (vol%) 55.7 54.8 62.5 57.6 54.5 53.7 0.0 0.0 58.5 58.3 57.2 56.3

E300 (vol%) 93.9 82.3 91.5 91.1 93.9 93.9 0.0 0.0 86.2 86.2 90.8 86.2

Energy (MMBtu/Bbl) 4.963 4.953 4.864 4.939 5.027 4.973 0.000 0.000 4.988 5.000 4.971 4.972

CG

Total ('000 BPD) 1,841,024 1,852,896 1,570,973 1,658,720 1,262,249 1,085,436 687,028 681,817 111,394 114,133 5,472,668 5,393,001

Ethanol ('000 BPD) 1,842 187,161 72,606 167,547 8,040 109,640 26,352 68,870 5,849 11,529 114,689 544,748

RVP (psi) 10.5 11.8 11.8 11.5 10.7 10.5 11.3 11.4 10.8 10.6 11.0 11.4

Sulfur (ppm) 27.8 24.2 25.3 23.6 27.3 23.0 24.6 28.0 26.4 26.0 26.6 24.3

Density 259.3 258.9 258.8 258.9 259.4 259.6 256.8 257.6 260.8 263.4 258.9 259.0

Octane (R+M/2) 88.0 87.7 88.0 88.0 88.0 88.1 86.8 86.9 88.0 89.4 87.8 87.8

Aromatics (vol%) 28.7 22.4 26.3 22.5 28.4 21.8 19.3 15.2 26.8 27.6 26.7 21.5

Benzene (vol%) 0.65 0.52 0.64 0.53 0.65 0.51 0.80 1.03 0.62 0.63 0.67 0.59

Olefins (vol%) 15.2 13.9 11.2 10.8 16.0 11.9 8.0 7.6 18.6 17.5 13.4 11.8

Oxygen (wt%) 0.0 3.7 1.7 3.7 0.2 3.7 1.4 3.7 1.9 3.7 0.8 3.7

E200 (vol%) 45.2 52.9 52.9 58.5 45.9 52.5 58.9 63.1 54.5 57.2 49.5 55.9

E300 (vol%) 93.9 79.3 91.5 84.0 93.9 79.3 93.9 91.0 86.2 86.2 93.0 82.4

Energy (MMBtu/Bbl) 5.133 4.966 5.007 4.939 5.127 4.990 5.004 4.907 4.998 4.946 5.077 4.955

E85

Total ('000 BPD) 0 30,077 0 31,813 0 207,848 0 22,103 0 0 0 291,840

Ethanol ('000 BPD) 0 25,821 0 27,311 0 178,439 0 18,976 0 0 0 250,548

RVP (psi) 0.0 12.9 0.0 12.2 0.0 12.1 0.0 11.9 0.0 0.0 0.0 12.1

Sulfur (ppm) 0.0 8.9 0.0 8.8 0.0 8.8 0.0 8.8 0.0 0.0 0.0 8.8

Density 0.0 266.0 0.0 266.3 0.0 266.2 0.0 266.1 0.0 0.0 0.0 266.2

Octane (R+M/2) 0.0 108.1 0.0 108.0 0.0 107.9 0.0 107.9 0.0 0.0 0.0 108.0

Aromatics (vol%) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Benzene (vol%) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Olefins (vol%) 0.0 3.0 0.0 3.0 0.0 1.3 0.0 0.0 0.0 0.0 0.0 1.5

Oxygen (wt%) 0.0 30.8 0.0 30.8 0.0 30.8 0.0 30.8 0.0 0.0 0.0 30.8

E200 (vol%) 0.0 130.1 0.0 130.1 0.0 129.7 0.0 129.3 0.0 0.0 0.0 129.7

E300 (vol%) 0.0 96.6 0.0 96.6 0.0 96.6 0.0 96.6 0.0 0.0 0.0 96.6

Energy (MMBtu/Bbl) 0.000 3.591 0.000 3.599 0.000 3.596 0.000 3.594 0.000 0.000 0.000 3.596

All Mogas

Total BPD 3,207,687 3,191,919 1,885,551 2,012,845 1,715,111 1,770,983 687,028 703,921 1,392,425 1,426,660 8,887,802 9,106,327

Ethanol BPD 139,876 345,199 104,378 227,416 53,780 336,332 26,352 87,846 135,236 144,107 459,622 1,140,900

RVP 10.6 11.4 11.5 11.4 10.4 10.5 11.3 11.4 9.6 9.6 10.6 10.9

Sulfur ppm 26.1 24.2 24.5 22.9 26.3 21.6 24.6 27.4 10.1 10.2 23.2 21.4

Density 258.9 258.9 258.4 258.9 259.3 260.1 256.8 257.9 258.7 259.1 258.7 259.1

R+M/2 88.0 88.0 88.0 88.3 88.0 90.4 86.8 87.6 87.7 87.8 87.8 88.5

Aromatics 24.9 21.1 24.9 21.7 26.0 18.3 19.3 14.8 22.6 22.6 24.3 20.4

Benzene 0.62 0.53 0.63 0.52 0.63 0.46 0.80 1.00 0.55 0.55 0.63 0.56

Olefins 14.3 14.1 10.7 10.4 14.2 10.5 8.0 7.4 6.7 6.6 11.8 10.9

Oxygen (wt%) 1.6 4.0 2.0 4.2 1.2 7.0 1.4 4.6 3.6 3.7 1.9 4.6

E200 49.7 54.4 54.5 59.5 48.1 61.9 58.9 65.2 58.1 58.2 52.5 58.4

E300 93.9 80.7 91.5 85.3 93.9 85.3 93.9 91.2 86.2 86.2 92.2 84.3

Energy (MMBtu/Bbl) 5.061 4.948 4.983 4.918 5.101 4.822 5.004 4.866 4.988 4.995 5.036 4.918

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA US

4.4.2.3 High Ethanol Control Case 

 This section summarizes the costs and other impacts of the high ethanol control case 

relative to the AEO 2007 and RFS 1 reference cases. This case assumes that the cellulosic 

biofuel standard would be met solely through the production and use of cellulosic ethanol. 
147

4.4.2.3.1 High Ethanol Control Case Relative to the AEO 2007 Reference Case 

This subsection summarizes the gasoline and diesel fuel costs and other impacts of the 

high ethanol control case relative to the AEO 2007 reference case. 

Table 4.4-45. 

High Ethanol Control Case Costs without Tax Subsidies 

Relative to the AEO 2007 Reference Case 

(2007 dollars, 7% ROI before taxes) 

Gasoline Diesel Fuel

Refinery Model Variable Operating Cost $MM/yr 23,718 -

Amortized Refinery Capital Costs $MM/yr -426 -

Fixed Operating Costs $MM/yr -117 -

Added Gasoline Transportation Cost $MM/yr -197 -

E85 Pricing Effect $MM/yr -19,854 -

Crude Oil Cost $51 to $116/bbl $MM/yr -34,958 -

Lower Energy Density $MM/yr 21,728 473

Adjustment from Ethanol Price to Cost $MM/yr -1,866 -

FFV Costs $MM/yr 6,113 -

Renewable Diesel Cost vs Petroleum Diesel $MM/yr - -1,744

Total Costs $MM/yr -5,961 -1,271

Refinery Model Variable Operating Cost c/gal 16.39 -

Amortized Refinery Capital Costs c/gal -0.29 -

Fixed Operating Costs c/gal -0.08 -

Added Gasoline Transportation Cost c/gal -0.14 -

E85 Pricing Effect c/gal -13.72 -

Crude Oil Cost $51 to $116/bbl c/gal -24.16 -

Lower Energy Density c/gal 15.02 0.67

Adjustment from Ethanol Price to Cost c/gal -1.29 -

FFV Costs c/gal 4.22 -

Renewable Diesel Cost vs Petroleum Diesel c/gal - -2.46

Total Costs c/gal -4.12 -1.79 

Table 4.4-46. 

High Ethanol Control Case Costs Reflecting Tax Subsidies 

Relative to the AEO 2007 Reference Case 

(2007 dollars, 7% ROI before taxes)

Gasoline Diesel Fuel

Total Costs $MM/yr -5,961 -1,271

Federal Subsidies $MM/yr -17,504 -1,359

Revised Total Cost $MM/yr -23,465 -2,630

Total Costs c/gal -4.12 -1.79

Federal Subsidies c/gal -12.10 -1.92

Total Costs c/gal -16.22 -3.71

 
 148

Table 4.4-47. 

Summary of the Total and Incremental Volumetric Refinery Inputs by PADD for the High 

Ethanol Control Case Relative to the AEO 2007 Reference Case 

(barrels/day) 

Control Difference Control Difference Control Difference Control Difference Control Difference

Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case

PADD Crude 1,347,342 -181,037 3,058,241 -400,248 7,117,305 -134,113 1,534,859 1,256 1,886,357 -3,037

GTL Naphtha 0 0 0 0 0 0 0 0 0 0

GTL Diesel 0 0 0 0 0 0 0 0 0 0

VGO HS 0 0 0 0 0 -43,785 0 0 0 0

VGO LS 0 0 7,920 -30,143 0 0 0 0 0 0

HS AR (A960) 0 0 0 0 0 0 0 0 0 0

LS AR (Alg) 279,819 50,165 0 0 738,057 31,843 0 0 0 0

Normal Butane 30,814 8,329 78,293 26,638 69,363 -16,802 25,526 -14,190 39,573 0

Isobutane 12,582 12,038 16,476 -7,315 8,234 8,234 1,178 -5,088 0 0

Other 0 0 0 0 0 0 0 0 0 0

MTBE 0 0 0 0 0 0 0 0 0 0

Ethanol - E10 270,313 -2,774 168,062 -29,838 142,590 -33,127 66,626 -3,764 143,845 1,188

Ethanol - E20 0 0 0 0 0 0 0 0 0 0

Ethanol - E85 575,048 575,048 332,715 332,715 361,999 361,999 60,129 60,129 46,969 46,969

Reformer Feed 0 0 0 0 0 0 0 0 0 0

Methanol 0 0 0 0 0 0 0 0 0 0

Natural Gas (FOE) 74,115 -6,992 136,509 -8,134 493,553 -10,734 86,015 -7,881 154,032 -1,636

Hydrogen (MSCF) 0 0 0 0 0 0 0 0 0 0

Pentanes Plus 0 0 58 -32,066 52,055 0 0 -18,580 0 0

Import CBOB 10% 0 -6,286 0 0 0 0 0 0 0 0

Import CBOB 20% 0 0 0 0 0 0 0 0 0 0

Import RBOB 10% 0 -145,593 0 0 0 0 0 0 0 0

Import RBOB 20% 0 0 0 0 0 0 0 0 0 0

Import Alkylate 45,167 42,933 0 0 0 0 0 0 0 0

Import Raffinate 3,442 -50,084 0 0 0 0 0 0 45,808 0

Import Reformate 0 -8,829 0 0 0 0 0 0 0 0

Import FCC Naphtha 15,980 15,980 0 0 11,943 11,943 18,580 18,580 0 0

Import Lt Naphtha 0 0 17,575 17,575 0 0 0 0 584 0

Import Hvy Naph 0 0 0 0 41,644 0 0 0 0 0

Transfer Lt Naphtha 0 -4,333 0 0 0 0 0 0 11,387 -6,997

Transfer Reformate 16,658 0 0 0 0 0 0 0 0 0

Transfer Alkylate 60,000 0 0 0 0 0 0 0 60,000 0

Transfer FCC Naphtha 0 0 20,822 0 0 0 0 0 0 0

Transfer Raffinate 0 0 11,353 -284 0 0 0 0 60,000 12,556

Transfer RBOB 10% 242,605 0 0 0 0 0 0 0 0 0

Transfer RBOB 20% 0 0 8,720 8,720 0 0 0 0 0 0

Transfer CBOB 10% 1,398,409 262,136 80,262 26,208 0 0 6,493 142 0 0

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0

Isooctane 100 0 100 0 100 0 100 0 16,462 1,200

Isooctene 100 0 100 0 100 0 100 0 600 0

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA
149

Table 4.4-48. 

Summary of Total and Incremental Refinery Outputs by PADD 

for the High Ethanol Control Case Relative to the AEO 2007 Reference Case 

(barrels/day) 

Control Difference Control Difference Control Difference Control Difference Control Difference

Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case

Propane 34,143 2,023 50,843 -6,445 103,144 -14,409 23,369 866 52,782 1,190

Propylene 18,685 0 42,525 0 245,407 0 2,041 0 11,774 0

Normal Butane 0 -4,967 0 -965 0 -33,663 0 0 0 0

Isobutane 0 0 0 0 0 -411 0 0 40,012 -1,478

PC Naphtha 15,830 0 40,290 0 432,937 0 0 0 0 0

PC Gasoil 0 0 455,618 -105,083 157,500 0 0 0 0 0

CG Reg 0 0 0 0 0 0 0 0 0 0

CG Prem 0 0 0 0 0 -182,001 0 0 0 0

CG E10 Reg 1,535,198 278,248 1,172,450 -205,266 872,274 -203,190 542,856 -42,507 99,374 4,464

CG E10 Prem 306,669 236,335 274,765 12,343 214,485 9,635 116,742 5,244 18,928 850

RFG E10 Reg 605,554 -550,564 163,150 -104,878 246,042 -139,806 0 0 1,088,091 -3,375

RFG E10 Prem 228,678 8,465 53,454 2,401 78,844 5,349 0 0 217,676 9,778

CG E20 Reg 0 0 0 0 0 0 0 0 0 0

RFG E20 Reg 0 0 0 0 0 0 0 0 0 0

E85 to CG 74,814 74,814 270,064 270,064 253,773 253,773 70,039 70,039 0 0

E85 to RFG 595,006 595,006 117,484 117,484 167,888 167,888 0 0 54,710 54,710

Transfer RBOB 10% 0 0 0 0 251,325 8,720 0 0 0 0

Transfer RBOB 20% 0 0 0 0 0 0 0 0 0 0

Transfer CBOB 10% 0 0 0 0 1,485,164 288,485 0 0 0 0

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0

Jet/Kero A (450ppm) 70,000 0 138,523 -1,557 936,227 0 274,537 0 229,653 0

X-Fer Diesel Rundown 0 00 00 00 00 0

HSD Gr 76 (0.2%) 0 0 0 0 0 0 0 0 0 0

LSD Gr 74 (.05%) 0 0 0 0 0 0 0 0 0 0

ULSD (15 ppm) 587,042 -47,575 643,331 -28,840 2,150,901 14,598 523,035 -10,264 0 0

CARB Diesel 0 0 0 0 0 0 0 0 358,152 -6,197

X-Fer C5's to Storage 0 0 0 0 0 0 0 0 0 0

1% Residual Fuel 0 0 0 0 0 0 0 0 0 0

Residual Fuel 68,283 -23,360 67,826 3,237 262,834 0 138,312 16,021 45,680 -4,199

Slurry 30,026 2,617 67,363 -18,904 112,554 -1,394 12,295 -1,187 29,893 886

Asphalt & Wax 86,013 -5,669 198,329 -9,357 157,500 0 5,250 0 41,774 0

Gasoil 0 0 4,895 0 0 0 0 0 9,814 0

Lubes 18,706 0 17,313 0 157,500 0 0 0 20,149 0

Benzene 11,003 0 11,003 0 51,347 0 0 0 0 0

Toluene 0 0 0 0 34,910 0 0 0 0 0

Xylenes 0 0 0 0 7,777 0 0 0 0 0

Cumene 0 0 0 0 0 0 0 0 0 0

Other 0 0 0 0 0 0 0 0 0 0

Cyclohexane 0 0 0 0 0 0 0 0 0 0

Transfer Raffinate 0 0 0 0 71,353 12,273 0 0 0 0

Transfer Alkylate 0 0 0 0 120,000 0 0 0 0 0

Transfer Reformate 0 0 0 0 16,658 0 0 0 0 0

Transfer FCC naphtha 0 0 0 0 20,822 0 0 0 0 0

Transfer Lt Naphtha 0 0 0 0 0 -4,333 0 0 11,387 -6,997

Transfer Blendstock 0 0 0 0 0 0 0 0 0 0

Sulfur (STons) 1,076 -78 3,571 -542 12,042 -356 2,038 -49 3,559 14

Coke (STon) 3,495 -455 10,154 -2,572 48,646 -1,154 7,899 -580 17,358 64

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA

 
 150

Table 4.4-49. 

Change in Refinery Unit Capacities by PADD 

for the High Ethanol Control Case Relative to the AEO 2007 Reference Case 

(thousand barrels/day) 

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA California US Total

Crude Tower 0 -459 0 0 0 -459

Vacuum Tower 0 -205 0 8 0 -197

Sats Gas Plant -21 0 -45 0 10 -56

Unsats Gas Plant 1 0 0 0 0 1

FCC DeC5 Tower 000 000

FCC 0 0 0 0 0 0

FCC Splitter 1 -6 0 0 0 -4

Hydrocracker 14 0 0 -6 0 7

H-Oil Unit 0 0 0 0 0 0

Delayed Coker 0 0 0 -1 0 -1

Visbreaker 0 0 0 0 0 0

Thermal Naphtha Splitter 0 -6 0 0 0 -6

CRU Reformer 0 0 0 0 0 0

SRU Reformer 000 099

BTX Reformer 0 7 -9 0 0 -1

C4 Isomerization 0 0 0 0 3 3

C5/C6 Isomerization 16 0 0 0 0 16

HF Alkylation 0 0 0 0 0 0

H2SO4 Alkylation -27 0 0 0 0 -27

Dimersol 0 0 0 0 0 0

Cat Poly 100 001

Isooctane 0 0 0 0 0 0

DHT - Total -40 0 -19 -10 0 -69

DHT 2nd RCT - Total -38 -52 -20 -10 0 -120

DHT Arom Saturation 0 0 0 0 0 0

NHT - Total Fd 0 0 0 2 0 2

CGH - Generic 13 -30 -6 1 0 -23

CGH - Olefin Sat'n 0 0 0 0 0 0

FCCU Fd HDT 24 0 0 0 0 24

LSR Splitter 0 -25 0 0 0 -25

LSR Bz Saturator 000 000

Reformate Saturator -18 0 -2 0 0 -20

Reformate Splitter -54 0 -6 0 0 -59

SDA 0 0 0 0 0 0

MTBE 0 0 0 0 0 0

TAME 0 0 0 0 0 0

Hydrogen Plant - Total MSCF -2 -43 -80 -31 0 -156

Lube Unit 0 0 0 0 0 0

Sulfur Plant -24 0 0 -30 -22 -76

Merox Jet 0 0 0 0 0 0

Merox Diesel 0 0 0 0 0 0

BTX Reformer - Tower feed 0 0 0 0 0 0

BTX Reformer - Extract feed 0 0 0 0 0 0
151

Table 4.4-50. 

Change in Refinery Unit Investments by PADD 

for the High Ethanol Control Case Relative to the AEO 2007 Reference Case 

(million dollars/year)

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA California US Total

Crude Tower 0 -1,121 0 0 0 -1,121

Vacuum Tower 0 -676 0 70 0 -606

Sats Gas Plant -107 0 -129 0 60 -176

Unsats Gas Plant 8 0 0 0 0 8

FCC DeC5 Tower 000 000

FCC 0 0 0 0 0 0

FCC Splitter 1 -7 0 0 0 -6

Hydrocracker 305 0 0 -129 0 176

H-Oil Unit 0 0 0 0 0 0

Delayed Coker 0 0 0 -22 0 -22

Visbreaker 0 0 0 0 0 0

Thermal Naphtha Splitter 0 -7 0 0 0 -7

CRU Reformer 000 000

SRU Reformer 0 0 0 0 45 45

BTX Reformer 0 70 -55 0 0 16

C4 Isomerization 0 0 0 0 20 20

C5/C6 Isomerization 156 0 0 0 0 156

HF Alkylation 0 0 0 0 0 0

H2SO4 Alkylation -470 0 0 0 0 -470

Dimersol 0 0 0 0 0 0

Cat Poly 8 0 0 0 0 8

Isooctane 0 0 0 0 0 0

DHT - Total -390 0 -82 -174 0 -646

DHT 2nd RCT - Total -355 -361 -64 -43 0 -822

DHT Arom Saturation 0 0 0 0 0 0

NHT - Total Fd 0 0 0 31 0 31

CGH - Generic 109 -157 -59 4 0 -102

CGH - Olefin Sat'n 0 0 0 0 0 0

FCCU Fd HDT 319 0 0 0 0 319

LSR Splitter 0 -17 0 0 0 -17

LSR Bz Saturator 000 000

Reformate Saturator -110 0 -9 0 0 -119

Reformate Splitter -64 0 -4 0 0 -68

SDA 0 0 0 0 0 0

MTBE 0 0 0 0 0 0

TAME 0 0 0 0 0 0

Hydrogen Plant - Total MSCF -7 -148 -186 -129 0 -469

Lube Unit 0 0 0 0 0 0

Sulfur Plant 0 0 0 0 0 -1

Merox Jet 0 0 0 0 0 0

Merox Diesel 0 0 0 0 0 0

BTX Reformer - Tower feed 0 1 0 0 0 1

BTX Reformer - Extract feed 0 0 0 0 0 0

Total -597 -2,422 -587 -391 124 -3,874

 
 152

Table 4.4-51. 

Projected Total U.S. Capital Investments 

for the High Ethanol Control Case Relative to the AEO 2007 Reference Case 

 (billion dollars) 

Cost Type Plant Type Capital 

Investments 

Corn Ethanol 3.9 

Cellulosic Ethanol 48.3 

Cellulosic Diesel a 0 

Production 

Costs 

Renewable Diesel and 

Algae 

1.1 

All Ethanol 11.9 

Cellulosic and 

Renewable Diesel Fuel 

- 

Distribution 

Costs 

Biodiesel 1.2 

 FFV Costs 6.1 

 Refining -4.1 

Total Capital Investments 68.4 
153

Table 4.4-52. 

Ethanol and Gasoline Volume, Quality and Energy Density by Gasoline Type at the PADD 

Terminal for the High Ethanol Control Case Relative to the AEO 2007 Reference Case 

Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control

RFG

Total ('000 BPD) 1,376,331 834,232 319,080 216,604 459,343 324,886 0 0 1,299,365 1,305,768 3,454,120 2,681,490

Ethanol ('000 BPD) 139,023 84,266 32,230 21,879 46,397 32,817 0 0 131,244 131,896 348,895 270,858

RVP (psi) 10.8 10.3 10.6 12.5 9.7 11.3 0.0 0.0 9.5 9.4 10.1 10.1

Sulfur (ppm) 24.4 23.4 20.0 24.5 23.2 22.4 0.0 0.0 8.8 8.9 18.0 16.3

Density 258.9 259.4 258.2 257.1 259.5 258.7 0.0 0.0 258.5 258.9 258.8 258.9

Octane (R+M/2) 88.1 88.6 88.0 88.5 88.0 88.5 0.0 0.0 87.6 87.7 87.9 88.1

Aromatics (vol%) 19.9 20.0 19.9 20.0 19.6 19.8 0.0 0.0 22.2 22.2 20.7 21.1

Benzene (vol%) 0.57 0.58 0.57 0.57 0.56 0.54 0.00 0.00 0.53 0.55 0.55 0.56

Olefins (vol%) 13.6 14.0 9.4 11.4 11.5 13.7 0.0 0.0 5.7 5.7 10.0 9.7

Oxygen (wt%) 3.7 3.7 3.7 3.8 3.7 3.7 0.0 0.0 3.7 3.7 3.7 3.7

E200 (vol%) 55.6 56.7 58.3 60.7 53.3 54.2 0.0 0.0 58.2 58.2 56.5 57.4

E300 (vol%) 93.9 95.1 93.9 95.1 93.9 95.1 0.0 0.0 86.2 86.2 91.0 90.7

Energy (MMBtu/Bbl) 4.947 4.956 4.924 4.895 4.981 4.951 0.000 0.000 4.994 4.997 4.967 4.970

CG

Total ('000 BPD) 1,830,582 1,841,867 1,640,138 1,447,215 1,280,314 1,086,759 696,861 659,598 112,988 118,302 5,560,884 5,153,740

Ethanol ('000 BPD) 134,064 186,047 165,671 146,183 129,320 109,774 70,390 66,626 11,413 11,950 510,857 520,580

RVP (psi) 11.4 11.7 11.6 11.4 10.7 10.4 11.4 11.2 10.6 10.6 11.3 11.3

Sulfur (ppm) 22.9 24.1 23.6 24.7 23.1 22.6 28.0 28.0 26.6 25.6 23.9 24.5

Density 258.9 260.0 259.1 259.3 260.5 260.8 258.1 259.1 262.7 262.5 259.3 259.9

Octane (R+M/2) 87.8 88.0 88.0 88.1 88.0 88.2 86.9 87.0 89.3 89.2 87.8 88.0

Aromatics (vol%) 23.1 22.5 22.5 22.5 22.4 22.4 15.9 17.7 26.5 26.7 21.9 22.0

Benzene (vol%) 0.53 0.53 0.53 0.53 0.51 0.51 1.05 1.03 0.59 0.57 0.59 0.59

Olefins (vol%) 13.2 13.9 11.0 10.9 13.1 12.6 8.5 9.5 17.8 16.1 12.0 12.3

Oxygen (wt%) 2.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.4 3.7

E200 (vol%) 52.5 53.5 58.8 58.9 53.0 51.4 63.0 63.5 58.0 58.5 55.9 56.0

E300 (vol%) 93.9 80.4 93.9 95.0 93.9 79.2 93.9 95.8 86.2 86.2 93.7 86.3

Energy (MMBtu/Bbl) 4.995 4.974 4.925 4.938 4.988 4.998 0.000 4.930 4.942 4.929 4.961 4.962

E85

Total ('000 BPD) 0 669,821 0 387,549 0 421,660 0 70,039 0 54,710 0 1,603,779

Ethanol ('000 BPD) 0 575,048 0 332,715 0 361,999 0 60,129 0 46,969 0 1,376,860

RVP (psi) 0.0 9.9 0.0 10.3 0.0 10.7 0.0 11.9 0.0 12.0 0.0 10.4

Sulfur (ppm) 0.0 10.1 0.0 9.7 0.0 9.6 0.0 9.0 0.0 8.8 0.0 9.8

Density 0.0 268.9 0.0 268.1 0.0 267.8 0.0 266.6 0.0 266.2 0.0 268.2

Octane (R+M/2) 0.0 107.7 0.0 107.7 0.0 107.8 0.0 107.9 0.0 107.9 0.0 107.7

Aromatics (vol%) 0.0 1.2 0.0 0.8 0.0 0.7 0.0 0.1 0.0 0.0 0.0 0.9

Benzene (vol%) 0.00 0.03 0.00 0.02 0.00 0.02 0.00 0.00 0.00 0.00 0.00 0.03

Olefins (vol%) 0.0 2.4 0.0 2.0 0.0 2.1 0.0 2.8 0.0 1.2 0.0 2.2

Oxygen (wt%) 0.0 30.5 0.0 25.7 0.0 30.6 0.0 28.6 0.0 30.8 0.0 29.3

E200 (vol%) 0.0 126.8 0.0 127.7 0.0 128.0 0.0 129.8 0.0 129.6 0.0 127.6

E300 (vol%) 0.0 95.6 0.0 95.9 0.0 96.0 0.0 96.6 0.0 96.6 0.0 95.8

Energy (MMBtu/Bbl) 0.000 3.656 0.000 3.642 0.000 3.633 0.000 3.605 0.000 3.596 0.000 3.642

All Mogas

Total BPD 3,206,913 3,345,919 1,959,219 2,051,367 1,739,657 1,833,305 696,861 729,637 1,412,353 1,478,780 9,015,003 9,439,008

Ethanol BPD 273,087 845,361 197,901 500,777 175,717 504,590 70,390 126,755 142,657 190,815 859,752 2,168,297

RVP 11.1 11.0 11.4 11.3 10.4 10.6 11.4 11.3 9.6 9.6 10.8 10.8

Sulfur ppm 24 21 23 22 23 19 28 26 10 10 22 20

Density 259 262 259 261 260 262 258 260 259 259 259 261

R+M/2 87.9 92.1 88.0 91.9 88.0 92.7 86.9 89.0 87.8 88.5 87.8 91.4

Aromatics 21.7 17.6 22.1 18.1 21.7 16.9 15.9 16.0 22.5 21.8 21.5 18.1

Benzene 0.55 0.44 0.53 0.44 0.53 0.40 1.05 0.93 0.54 0.53 0.58 0.49

Olefins 13.4 11.6 10.7 9.3 12.7 10.3 8.5 8.9 6.7 6.4 11.2 9.8

Oxygen (wt%) 3.1 9.2 3.7 8.0 3.7 10.0 3.7 6.2 3.7 4.7 3.5 8.2

E200 53.8 69.0 58.7 72.1 53.1 69.5 63.0 69.9 58.2 60.9 56.1 68.6

E300 93.9 87.1 93.9 95.1 93.9 85.9 93.9 95.9 86.2 86.6 92.7 89.2

Energy (MMBtu/Bbl) 4.974 4.706 4.925 4.689 4.986 4.676 4.913 4.803 4.990 4.939 4.963 4.740

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA US

4.4.2.3.2 High Ethanol Control Case Relative to the RFS 1 Reference Case 

This subsection summarizes the gasoline and diesel fuel costs and other impacts of the 

high ethanol control case relative to the RFS1 reference case. 
 154

Table 4.4-53. 

High Ethanol Control Case Costs without Tax Subsidies 

Relative to the RFS 1 Reference Case 

(2007 dollars, 7% ROI before taxes) 

Gasoline Diesel Fuel

Refinery Model Variable Operating Cost $MM/yr 23,894 -

Amortized Refinery Capital Costs $MM/yr -460 -

Fixed Operating Costs $MM/yr -127 -

Added Gasoline Transportation Cost $MM/yr -257 -

E85 Pricing Effect $MM/yr -19,854 -

Crude Oil Cost $51 to $116/bbl $MM/yr -45,548 -

Lower Energy Density $MM/yr 29,609 502

Adjustment from Ethanol Price to Cost $MM/yr -1,524 -

FFV Costs $MM/yr 6,476

Renewable Diesel Cost vs Petroleum Diesel $MM/yr - -1,851

Total Costs $MM/yr -7,790 -1,350

Refinery Model Variable Operating Cost c/gal 16.51 -

Amortized Refinery Capital Costs c/gal -0.32 -

Fixed Operating Costs c/gal -0.09 -

Added Gasoline Transportation Cost c/gal -0.18 -

E85 Pricing Effect c/gal -13.72 -

Crude Oil Cost $51 to $116/bbl c/gal -31.48 -

Lower Energy Density c/gal 20.46 0.71

Adjustment from Ethanol Price to Cost c/gal -1.05 -

FFV Costs c/gal 4.48

Renewable Diesel Cost vs Petroleum Diesel c/gal - -2.61

Total Costs c/gal -5.38 -1.90 

Table 4.4-54. 

High Ethanol Control Case Costs Reflecting Tax Subsidies 

Relative to the RFS 1 Control Case 

(2007 dollars, 7% ROI before taxes)

Gasoline Diesel Fuel

Total Costs $MM/yr -7,790 -1,350

Federal Subsidies $MM/yr -20,266 -1,441

Revised Total Cost $MM/yr -28,055 -2,791

Total Costs c/gal -5.38 -1.90

Federal Subsidies c/gal -14.01 -2.03

Total Costs c/gal -19.39 -3.94

 
155

Table 4.4-55. 

Summary of the Total and Incremental Volumetric Refinery Inputs by PADD 

for the High Ethanol Control Case Relative to the RFS 1 Reference Case 

(barrels/day) 

Control Difference Control Difference Control Difference Control Difference Control Difference

Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case

PADD Crude 1,347,342 -151,714 3,058,241 -475,740 7,117,305 -241,263 1,534,859 -4,119 1,886,357 -1,136

GTL Naphtha 0 0 0 0 0 0 0 0 0 0

GTL Diesel 0 0 0 0 0 0 0 0 0 0

VGO HS 0 0 0 0 0 -33,772 0 0 0 0

VGO LS 0 0 7,920 -23,914 0 0 0 0 0 0

HS AR (A960) 0 0 0 0 0 0 0 0 0 0

LS AR (Alg) 279,819 39,889 0 0 738,057 21,829 0 0 0 0

Normal Butane 30,814 8,329 78,293 19,185 69,363 -14,040 25,526 -13,917 39,573 0

Isobutane 12,582 12,582 16,476 -8,390 8,234 8,234 1,178 -22,245 0 0

Other 0 0 0 0 0 0 0 0 0 0

MTBE 0 0 0 0 0 0 0 0 0 0

Ethanol - E10 270,313 130,437 168,062 63,684 142,590 88,811 66,626 40,273 143,845 8,610

Ethanol - E20 0 0 0 0 0 0 0 0 0 0

Ethanol - E85 575,048 575,048 332,715 332,715 361,999 361,999 60,129 60,129 46,969 46,969

Reformer Feed 0 0 0 0 0 0 0 0 0 0

Methanol 0 0 0 0 0 0 0 0 0 0

Natural Gas (FOE) 74,115 -6,201 136,509 -5,559 493,553 6,876 86,015 -3,625 154,032 -2,444

Hydrogen (MSCF) 0 0 0 0 0 0 0 0 0 0

Pentanes Plus 0 0 58 -32,066 52,055 0 0 -17,467 0 0

Import CBOB 10% 0 0 0 0 0 0 0 0 0 0

Import CBOB 20% 0 0 0 0 0 0 0 0 0 0

Import RBOB 10% 0 -200,000 0 0 0 0 0 0 0 0

Import RBOB 20% 0 0 0 0 0 0 0 0 0 0

Import Alkylate 45,167 45,167 0 0 0 0 0 0 0 0

Import Raffinate 3,442 -61,147 0 0 0 0 0 0 45,808 0

Import Reformate 0 0 0 0 0 0 0 0 0 0

Import FCC Naphtha 15,980 15,980 0 0 11,943 11,943 18,580 18,580 0 0

Import Lt Naphtha 0 0 17,575 17,575 0 0 0 0 584 0

Import Hvy Naph 0 0 0 0 41,644 0 0 0 0 0

Transfer Lt Naphtha 0 -23,342 0 -20,822 0 0 0 0 11,387 -9,842

Transfer Reformate 16,658 0 0 -14,074 0 0 0 0 0 0

Transfer Alkylate 60,000 17,381 0 0 0 0 0 0 60,000 16,933

Transfer FCC Naphtha 0 0 20,822 20,822 0 0 0 0 0 0

Transfer Raffinate 0 0 11,353 -5,888 0 0 0 0 60,000 11,077

Transfer RBOB 10% 242,605 0 0 0 0 0 0 0 0 0

Transfer RBOB 20% 0 0 8,720 8,720 0 0 0 0 0 0

Transfer CBOB 10% 1,398,409 1,381,833 80,262 77,306 0 0 6,493 -19,539 0 0

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0

Isooctane 100 0 100 0 100 0 100 0 16,462 2,029

Isooctene 100 0 100 0 100 0 100 0 600 0

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA
 156

Table 4.4-56. 

Summary of Total and Incremental Refinery Outputs by PADD 

for the High Ethanol Control Case Relative to the RFS 1 Reference Case 

(barrels/day) 

Control Difference Control Difference Control Difference Control Difference Control Difference

Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case Case from Ref Case

Propane 34,143 1,539 50,843 -12,263 103,144 -32,064 23,369 -1,541 52,782 1,461

Propylene 18,685 0 42,525 0 245,407 0 2,041 0 11,774 0

Normal Butane 0 -7,832 0 -2,370 0 -45,506 0 0 0 0

Isobutane 0 0 0 0 0 -345 0 0 40,012 5,009

PC Naphtha 15,830 0 40,290 0 432,937 0 0 0 0 0

PC Gasoil 0 0 455,618 -108,658 157,500 0 0 0 0 0

CG Reg 0 -118,066 0 -852,131 0 -2,020,447 0 -374,129 0 -53,481

CG Prem 0 0 0 0 0 -416,926 0 -51,984 0 0

CG E10 Reg 1,535,198 1,516,962 1,172,450 704,964 872,274 872,274 542,856 325,693 99,374 59,284

CG E10 Prem 306,669 306,669 274,765 23,409 214,485 134,887 116,742 72,990 18,928 1,105

RFG E10 Reg 605,554 -542,443 163,150 -101,096 246,042 -134,362 0 0 1,088,091 12,026

RFG E10 Prem 228,678 10,012 53,454 3,122 78,844 6,386 0 0 217,676 12,712

CG E20 Reg 0 0 0 0 0 0 0 0 0 0

RFG E20 Reg 0 0 0 0 0 0 0 0 0 0

E85 to CG 74,814 74,814 270,064 270,064 253,773 253,773 70,039 70,039 0 0

E85 to RFG 595,006 595,006 117,484 117,484 167,888 167,888 0 0 54,710 54,710

Transfer RBOB 10% 0 0 0 0 251,325 8,720 0 0 0 0

Transfer RBOB 20% 0 0 0 0 0 0 0 0 0 0

Transfer CBOB 10% 0 0 0 0 1,485,164 1,439,600 0 0 0 0

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0

Jet/Kero A (450ppm) 70,000 0 138,523 -3,108 936,227 0 274,537 0 229,653 0

X-Fer Diesel Rundown t 0 0 0 00 0 0 0 0 0

HSD Gr 76 (0.2%) 0 0 0 0 0 0 0 0 0 0

LSD Gr 74 (.05%) 0 0 0 0 0 0 0 0 0 0

ULSD (15 ppm) 587,042 -39,165 643,331 -30,227 2,150,901 2,423 523,035 -11,120 0 0

CARB Diesel 0 0 0 0 0 0 0 0 358,152 -6,714

X-Fer C5's to Storage 0 0 0 0 0 0 0 0 0 0

1% Residual Fuel 0 0 0 0 0 0 0 0 0 0

Residual Fuel 68,283 -21,481 67,826 8 262,834 0 138,312 22,862 45,680 -4,199

Slurry 30,026 3,876 67,363 -19,645 112,554 -4,041 12,295 -4,210 29,893 1,191

Asphalt & Wax 86,013 -5,669 198,329 -11,671 157,500 0 5,250 0 41,774 0

Gasoil 0 0 4,895 0 0 0 0 0 9,814 0

Lubes 18,706 0 17,313 0 157,500 0 0 0 20,149 0

Benzene 11,003 0 11,003 0 51,347 0 0 0 0 0

Toluene 0 0 0 0 34,910 0 0 0 0 0

Xylenes 0 0 0 0 7,777 0 0 0 0 0

Cumene 0 0 0 0 0 0 0 0 0 0

Other 0 0 0 00 0 0 0 0 0

Cyclohexane 0 0 0 0 0 0 0 0 0 0

Transfer Raffinate 0 0 0 0 71,353 5,190 0 0 0 0

Transfer Alkylate 0 0 0 0 120,000 34,314 0 0 0 0

Transfer Reformate 0 0 0 0 16,658 16,658 0 0 0 0

Transfer FCC naphtha 0 0 0 0 20,822 20,822 0 0 0 0

Transfer Lt Naphtha 0 0 0 0 0 -23,342 0 0 11,387 -9,842

Transfer Blendstock 0 0 0 0 0 0 0 0 0 0

Sulfur (STons) 1,076 -74 3,571 -630 12,042 -533 2,038 -59 3,559 -10

Coke (STon) 3,495 -227 10,154 -3,068 48,646 -2,278 7,899 -790 17,358 86

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA

 
157

Table 4.4-57. 

Change in Refinery Unit Capacities by PADD 

for the High Ethanol Control Case Relative to the RFS 1 Reference Case 

(thousand barrels/day) 

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA California US Total

Crude Tower 0 -439 0 0 0 -439

Vacuum Tower 0 -196 0 -2 0 -198

Sats Gas Plant 3 0 -30 0 9 -18

Unsats Gas Plant -2 0 0 0 0 -2

FCC DeC5 Tower 0 0 0 0 0 0

FCC 0 0 0 -8 0 -8

FCC Splitter 2 -6 0 0 0 -5

Hydrocracker -18 0 0 -14 0 -33

H-Oil Unit 0 0 0 0 0 0

Delayed Coker 0 0 0 -28 0 -28

Visbreaker 0 0 0 0 0 0

Thermal Naphtha Splitter -1 -6 0 -1 0 -8

CRU Reformer 0 0 0 0 0 0

SRU Reformer 0 0 0 0 -1 -1

BTX Reformer 0 -10 -18 0 0 -27

C4 Isomerization 0 0 0 0 1 1

C5/C6 Isomerization 26 0 0 0 0 26

HF Alkylation 0 0 0 0 0 0

H2SO4 Alkylation 1 0 0 -5 0 -4

Dimersol 0 0 0 0 0 0

Cat Poly 000 0 00

Isooctane 0 0 0 0 0 0

DHT - Total -132 0 -103 -50 -4 -290

DHT 2nd RCT - Total -117 -153 -174 -52 -4 -501

DHT Arom Saturation 0 0 0 0 0 0

NHT - Total Fd 0 0 0 -4 0 -4

CGH - Generic -12 -19 -19 -6 0 -57

CGH - Olefin Sat'n 0 0 0 0 0 0

FCCU Fd HDT 37 0 0 0 0 37

LSR Splitter 0 41 38 0 0 80

LSR Bz Saturator 0 0 0 0 0 0

Reformate Saturator -4 -4 1 0 0 -7

Reformate Splitter -12 -12 3 0 0 -21

SDA 0 0 0 0 0 0

MTBE 0 0 0 0 0 0

TAME 0 0 0 0 0 0

Hydrogen Plant - Total MSC -72 11 109 -47 0 1

Lube Unit 0 0 0 0 0 0

Sulfur Plant -128 0 0 -204 -71 -402

Merox Jet 0 0 0 0 0 0

Merox Diesel 0 0 0 0 0 0

BTX Reformer - Tower feed 0 -1 -1 0 0 -2

BTX Reformer - Extract feed -1 0 0 0 0 -1
 158

Table 4.4-58. 

Change in Refinery Unit Investments by PADD 

for the High Ethanol Control Case Relative to the RFS 1 Reference Case 

(million dollars/year)

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA California US Total

Crude Tower 0 -997 0 0 0 -997

Vacuum Tower 0 -591 0 0 0 -591

Sats Gas Plant 12 0 -101 0 55 -34

Unsats Gas Plant -10 0 0 0 0 -10

FCC DeC5 Tower 0 0 0 0 0 0

FCC 0 0 0 -193 0 -193

FCC Splitter 1 -7 0 0 0 -6

Hydrocracker -631 0 0 -505 0 -1,137

H-Oil Unit 0 0 0 0 0 0

Delayed Coker 0 0 0 -592 0 -592

Visbreaker 0 0 0 0 0 0

Thermal Naphtha Splitter -3 -7 0 -3 0 -13

CRU Reformer 0 0 0 0 0 0

SRU Reformer 0 0 0 0 -4 -4

BTX Reformer 0 -93 -231 0 0 -324

C4 Isomerization 0 0 0 0 8 8

C5/C6 Isomerization 227 0 0 0 0 227

HF Alkylation 0 0 0 0 0 0

H2SO4 Alkylation 16 0 0 -70 0 -54

Dimersol 0 0 0 0 0 0

Cat Poly -1 0 0 0 0 -1

Isooctane 0 0 0 0 0 0

DHT - Total -1,367 0 -702 -539 -96 -2,703

DHT 2nd RCT - Total -904 -998 -840 -312 -21 -3,076

DHT Arom Saturation 0 0 0 0 0 0

NHT - Total Fd 0 0 0 -46 0 -46

CGH - Generic -58 -63 -92 -25 0 -238

CGH - Olefin Sat'n 0 0 0 0 0 0

FCCU Fd HDT 555 0 0 0 0 555

LSR Splitter 0 29 18 0 0 47

LSR Bz Saturator 0 0 0 0 0 0

Reformate Saturator -46 -19 4 0 0 -60

Reformate Splitter -20 -16 2 0 0 -34

SDA 0 0 0 0 0 0

MTBE 0 0 0 0 0 0

TAME 0 0 0 0 0 0

Hydrogen Plant - Total MSC -255 69 274 -171 0 -84

Lube Unit 0 0 0 0 0 0

Sulfur Plant -3 0 0 -2 -2 -7

Merox Jet 0 0 0 0 0 0

Merox Diesel 0 0 0 0 0 0

BTX Reformer - Tower feed 0 -2 -1 0 0 -3

BTX Reformer - Extract feed -3 0 0 0 0 -3

Total -2,491 -2,694 -1,669 -2,459 -59 -9,373

 
159

Table 4.4-59. 

Ethanol and Gasoline Volume, Quality and Energy Density by Gasoline Type at the PADD 

Terminal for the High Ethanol Control Case Relative to the RFS 1 Reference Case 

Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control

RFG

Total ('000 BPD) 1,366,663 834,232 314,578 216,604 452,862 324,886 0 0 1,281,031 1,305,768 3,415,134 2,681,490

Ethanol ('000 BPD) 138,034 84,266 31,773 21,879 45,739 32,817 0 0 129,386 131,896 344,932 270,858

RVP (psi) 10.7 10.3 10.3 12.5 9.6 11.3 0.0 0.0 9.5 9.4 10.1 10.1

Sulfur (ppm) 23.8 23.4 20.1 24.5 23.5 22.4 0.0 0.0 8.7 8.9 17.8 16.3

Density 258.5 259.4 256.2 257.1 259.1 258.7 0.0 0.0 258.5 258.9 258.4 258.9

Octane (R+M/2) 88.1 88.6 88.0 88.5 88.0 88.5 0.0 0.0 87.6 87.7 87.9 88.1

Aromatics (vol%) 19.9 20.0 18.2 20.0 19.5 19.8 0.0 0.0 22.2 22.2 20.5 21.1

Benzene (vol%) 0.57 0.58 0.57 0.57 0.57 0.54 0.00 0.00 0.54 0.55 0.56 0.56

Olefins (vol%) 13.1 14.0 8.0 11.4 9.3 13.7 0.0 0.0 5.7 5.7 9.3 9.7

Oxygen (wt%) 3.7 3.7 3.8 3.8 3.7 3.7 0.0 0.0 3.7 3.7 3.7 3.7

E200 (vol%) 55.7 56.7 62.5 60.7 54.5 54.2 0.0 0.0 58.5 58.2 57.2 57.4

E300 (vol%) 93.9 95.1 91.5 95.1 93.9 95.1 0.0 0.0 86.2 86.2 90.8 90.7

Energy (MMBtu/Bbl) 4.963 4.956 4.864 4.895 5.027 4.951 0.000 0.000 4.988 4.997 4.971 4.970

CG

Total ('000 BPD) 1,841,024 1,841,867 1,570,973 1,447,215 1,262,249 1,086,759 687,028 659,598 111,394 118,302 5,472,668 5,153,740

Ethanol ('000 BPD) 1,842 186,047 72,606 146,183 8,040 109,774 26,352 66,626 5,849 11,950 114,689 520,580

RVP (psi) 10.5 11.7 11.8 11.4 10.7 10.4 11.3 11.2 10.8 10.6 11.0 11.3

Sulfur (ppm) 27.8 24.1 25.3 24.7 27.3 22.6 24.6 28.0 26.4 25.6 26.6 24.5

Density 259.3 260.0 258.8 259.3 259.4 260.8 256.8 259.1 260.8 262.5 258.9 259.9

Octane (R+M/2) 88.0 88.0 88.0 88.1 88.0 88.2 86.8 87.0 88.0 89.2 87.8 88.0

Aromatics (vol%) 28.7 22.5 26.3 22.5 28.4 22.4 19.3 17.7 26.8 26.7 26.7 22.0

Benzene (vol%) 0.65 0.53 0.64 0.53 0.65 0.51 0.80 1.03 0.62 0.57 0.67 0.59

Olefins (vol%) 15.2 13.9 11.2 10.9 16.0 12.6 8.0 9.5 18.6 16.1 13.4 12.3

Oxygen (wt%) 0.0 3.7 1.7 3.7 0.2 3.7 1.4 3.7 1.9 3.7 0.8 3.7

E200 (vol%) 45.2 53.5 52.9 58.9 45.9 51.4 58.9 63.5 54.5 58.5 49.5 56.0

E300 (vol%) 93.9 80.4 91.5 95.0 93.9 79.2 93.9 95.8 86.2 86.2 93.0 86.3

Energy (MMBtu/Bbl) 5.133 4.974 5.007 4.938 5.127 4.998 5.004 4.930 4.998 4.929 5.077 4.962

E85

Total ('000 BPD) 0 669,821 0 387,549 0 421,660 0 70,039 0 54,710 0 1,603,779

Ethanol ('000 BPD) 0 575,048 0 332,715 0 361,999 0 60,129 0 46,969 0 1,376,860

RVP (psi) 0.0 9.9 0.0 10.3 0.0 10.7 0.0 11.9 0.0 12.0 0.0 10.4

Sulfur (ppm) 0.0 10.1 0.0 9.7 0.0 9.6 0.0 9.0 0.0 8.8 0.0 9.8

Density 0.0 268.9 0.0 268.1 0.0 267.8 0.0 266.6 0.0 266.2 0.0 268.2

Octane (R+M/2) 0.0 107.7 0.0 107.7 0.0 107.8 0.0 107.9 0.0 107.9 0.0 107.7

Aromatics (vol%) 0.0 1.2 0.0 0.8 0.0 0.7 0.0 0.1 0.0 0.0 0.0 0.9

Benzene (vol%) 0.00 0.03 0.00 0.02 0.00 0.02 0.00 0.00 0.00 0.00 0.00 0.03

Olefins (vol%) 0.0 2.4 0.0 2.0 0.0 2.1 0.0 2.8 0.0 1.2 0.0 2.2

Oxygen (wt%) 0.0 30.5 0.0 25.7 0.0 30.6 0.0 28.6 0.0 30.8 0.0 29.3

E200 (vol%) 0.0 126.8 0.0 127.7 0.0 128.0 0.0 129.8 0.0 129.6 0.0 127.6

E300 (vol%) 0.0 95.6 0.0 95.9 0.0 96.0 0.0 96.6 0.0 96.6 0.0 95.8

Energy (MMBtu/Bbl) 0.000 3.656 0.000 3.642 0.000 3.633 0.000 3.605 0.000 3.596 0.000 3.642

All Mogas

Total BPD 3,207,687 3,345,919 1,885,551 2,051,367 1,715,111 1,833,305 687,028 729,637 1,392,425 1,478,780 8,887,802 9,439,008

Ethanol BPD 139,876 845,361 104,378 500,777 53,780 504,590 26,352 126,755 135,236 190,815 459,622 2,168,297

RVP 10.6 11.0 11.5 11.3 10.4 10.6 11.3 11.3 9.6 9.6 10.6 10.8

Sulfur ppm 26.1 21.0 24.5 21.8 26.3 19.5 24.6 26.1 10.1 10.3 23.2 19.6

Density 258.9 261.7 258.4 260.8 259.3 262.1 256.8 259.8 258.7 259.4 258.7 261.1

R+M/2 88.0 92.1 88.0 91.9 88.0 92.7 86.8 89.0 87.7 88.5 87.8 91.4

Aromatics 24.9 17.6 24.9 18.1 26.0 16.9 19.3 16.0 22.6 21.8 24.3 18.1

Benzene 0.62 0.44 0.63 0.44 0.63 0.40 0.80 0.93 0.55 0.53 0.63 0.49

Olefins 14.3 11.6 10.7 9.3 14.2 10.3 8.0 8.9 6.7 6.4 11.8 9.8

Oxygen (wt%) 1.6 9.2 2.0 8.0 1.2 10.0 1.4 6.2 3.6 4.7 1.9 8.2

E200 49.7 69.0 54.5 72.1 48.1 69.5 58.9 69.9 58.1 60.9 52.5 68.6

E300 93.9 87.1 91.5 95.1 93.9 85.9 93.9 95.9 86.2 86.6 92.2 89.2

Energy (MMBtu/Bbl) 5.061 4.706 4.983 4.689 5.101 4.676 5.004 4.803 4.988 4.939 5.036 4.740

PADD 1 PADD 2 PADD 3 PADD 4/5 ex CA CA US
 160

 

i

 Kwaitkowski, J.R., McAloon, A., Taylor, F., Johnston, D.B., Modeling the process and costs of fuel ethanol 

production by the corn dry-grind process. Industrial Crops and Products 23 (2006) 288-296. A copy of the 

current USDA model can be obtained by contacting the corresponding author. 

ii See Tables 4.1-21 and 4.1-22 of this section for biomass costs. Coal costs taken from EIA Annual Energy 

Outlook 2008 Table 15. 

iii Bioenergy Feedstock Characteristics from Jonathan Scurlock, Oak Ridge National Laboratories, available at 

http://bioenergy.ornl.gov/papers/misc/biochar_factsheet.html (accessed October 1, 2008) 

iv Gallagher, P.W., Brubaker, H., and Shapouri, H. “Plant Size: Capital Cost Relationships in the Dry Mill 

Ethanol Industry,” Biomass and Bioenergy Vol. 28. 2005. Pp. 565-7. v

 Corn Stover Collection Project, David A. Glassner, National Renewable Energy Laboratory, 1617 Cole Blvd., 

Golden, CO 80401, James R. Hettenhaus, Chief Executive Assistance, 3211 Trefoil Ave, Charlotte, NC 28226, 

and Thomas M. Schechinger, Iron Horse Custom Farming, 816 Iron Horse Rd, Harlan, IA 51537; in BioEnergy 

’98: Expanding BioEnergy Partnerships 

vi Abhijith Mukunda, Graduate Student School of Industrial Engineering, Purdue University, West Lafayette IN 

47907, Klein E Ileleji, Assistant Professor, School of Agricultural & Biological Engineering, Purdue University, 

West Lafayette IN 47907, Hong Wan, Assistant Professor, School of Industrial Engineering, Purdue University, 

West Lafayette IN47906, Simulation of Corn Stover Logistics from On-farm Storage to an Ethanol Plant, Paper 

Number: 0661772006, ASABE Annual International Meeting, Portland Convention Center, Portland, Oregon, 9 

- 12 July 2006 

vii Shahab Sokhansanj, , Anthony Turhollow, Oak Ridge National Laboratory, North Logan, UT 84341-8804, 

Janet Cushman, Oak Ridge National Laboratory, Oak Ridge, TN 37831-6422, John Cundiff, Biological Systems 

Engineering, Virginia Technical University, Blacksburg, VA 24061-0303, Engineering aspects of collecting 

corn stover for bioenergy, Biomass and Bioenergy 23 (2002) 347 – 355; Received 15 October 2001; received in 

revised form 15 April 2002; accepted 3 May 2002; 2002 Published by Elsevier Science Ltd. 

viii David A. Glassner, National Renewable Energy Laboratory, Golden, CO 80401, James R. Hettenhaus, Chief 

Executive Assistance, Charlotte, NC 28226, and Thomas M. Schechinger, Iron Horse Custom Farming, Harlan, 

IA 51537; Corn Stover Collection Project, in BioEnergy ’98: Expanding BioEnergy Partnerships 

ix J.E. Atchison, Atchison Consultants, Inc., J. R. Hettenhaus, Chief Executive Assistance, Inc. Charlotte, North 

Carolina, National Renewable Energy Laboratory Golden, Colorado, .Innovative Methods for Corn Stover 

Collecting, Handling, Storing and Transporting, March 2003. x

 Daniel R. Petrolia, Department of Applied Economics, College of Food, Agriculture, and Natural Resources 

Sciences, University of Minnesota, The Economics of Harvesting and Transporting Corn Stover for Conversion 

to Fuel Ethanol: A Case Study for Minnesota, 

Staff Paper P06-12 August 2006 

xi Renee Sayler & Kenneth Von Bargen, Principal Investigators, Feasibility of Corn Residue Collection in 

Kearney, Nebraska Area, for Western Regional Biomass Energy Program, Report of findings, by University of 

Nebraska-Lincoln, Industrial Agricultural Products Center, Lincoln, NE 68583, September 1993. 

xii John S. Cundiff, Professor, Robert D. Grisso, Professor, Biological Systems Engineering Dept(MS 0303), 

Virginia Tech, Blacksburg, VA 24061, Hosein Shapouri, Senior Agricultural Economist, U.S.D.A., Office of 

Energy Policy and New Uses, Washington DC 20250-3815, Economic Analysis of two Receiving Facility 

Designs for a Bioenergy Plant, Paper Number: 076051,2007 ASABE Annual International Meeting, Sponsored 

by ASABE, Minneapolis Convention Center, Minneapolis, Minnesota, 17 - 20 June 2007 
161

 xiii Kevin J. Shinners – Professor of Agricultural Engineering, Ben N. Binversie – Graduate Research Assistant, 

Department of Biological Systems Engineering, University of Wisconsin, Madison, WI, Philippe Savoie – 

Research Scientist, Agriculture and Agri-Food Canada, Quebec, Canada, Whole-Plant Corn Harvesting for 

Biomass: Comparison of Single-Pass and Multiple-Pass Harvest Systems, Paper Number: 036089 2003 ASAE 

Annual International Meeting, Sponsored by ASAE, Riviera Hotel and Convention Center, Las Vegas, Nevada, 

USA, 27- 30 July 2003. 

xiv S. Sokhansanj1, A. Turhollow, and R. Perlack, Oak Ridge National Laboratory, Tennessee, USA 37830, 

Stochastic Modeling of Costs of Corn Stover Costs Delivered to an Intermediate Storage Facility, Paper 

Number: 024190, Presented at: 2002 ASAE Annual International Meeting / CIGR XVth World Congress, 

Sponsored by ASAE and CIGR, Hyatt Regency Chicago, Chicago, Illinois, USA, July 28-July 31, 2002 

xv D. Montross, Associate Professor, Scott A. Shearer, Professor, Timothy S. Stombaugh, Associate Extension 

Professor, Stephen F. Higgins, Research Specialist, and Samuel G. McNeill, Associate Extension Professor, 

Department of Biosystems and Agricultural Engineering, University of Kentucky, Lexington, Kentucky; and 

Shahab Sokhansanj, Professor, Oak Ridge National Laboratory, Environmental Sciences Division, Oak Ridge, 

Tennessee, Corn Stover Availability and Collection Efficiency Using Typical Hay Equipment, This article is 

published with the approval of the Director of the Kentucky Agricultural Experiment Station and designated 

Paper No. 04-05-066. Transactions of the ASABE, Vol. 50(3): 705−711 – 2007 American Society of 

Agricultural and Biological Engineers, ISSN 0001−2351. 

xvi American Society of Agricultural and Biological Engineers (ASABE), ASABE Standards, 2007, 54th

Edition, Standards, Engineering Practices, Data, 2950 Niles Road, St. Joseph, MI 49085-9659. 

xvii William Edwards, extension economist, Machinery Management: Estimating Farm Machinery Costs, PM 

710 Paper version, Revised November 2001; Electronic version Revised August 2005, University Extension, 

Iowa State University. 

xviii Mark Hanna, Extension Engineer, University Extension, Iowa State University, Ames Iowa, Estimating the 

Field Capacity of Farm Machines, File A3-24, April 2002. 

xix Terry Kastens, Extension Agricultural Economist, Kansas State University Agricultural Experiment Station 

and Cooperative Extension Service, Farm Machinery Operation Cost Calculations, MF-2244 May 1997 xx Machinery Cost Estimates: Forage Field Operations, University of Illinois Farm Business Management 

Handbook, University of Illinois Extension FBM 0203 Department of Agricultural and Consumer Economics • 

College of Agricultural, Consumer and Environmental Sciences, University of Illinois at Urbana-Champaign 

xxi Tim Cross, Agricultural Economics, Agriculture Machinery Cost Calculation Methods, E12-2015-00-032-98, 

Agricultural Extension Service, The University of Tennessee Institute of Agriculture. 

xxii Agricultural Prices 2006 Summary, July 2007 United States, Department of Agriculture 

National Agricultural Statistics Service, Pr 1-3 (07) 

xxiii National Agricultural Statistics Service, Quick Stats (Agricultural Statistics Data Base, State and County 

Data), USDA, http://www.nass.usda.gov/ 

xxiv L. O. Pordesimo, W. C. Edens, The University of Tennessee, Dept. of Biosystems Engineering and 

Environmental Science, Knoxville, TN, U.S.A., S. Sokhansanj Oak Ridge National Laboratory, Environmental 

Sciences Division, Oak Ridge, TN, U.S.A., Distribution of Above Ground Biomass in Corn , Stover, Paper 

Number: 02-6059; 2002 ASAE Annual International Meeting/CIGR XVth World Congress, Hyatt Regency 

Chicago, Chicago, Illinois, USA,; July 29-31, 2002. 

xxv Kevin J. Shinners, Professor of Agricultural Engineering, Ben N. Binversie, Graduate Research Assistant, 

Department of Biological Systems Engineering, University of Wisconsin, Madison, WI, Philippe Savoie, 

Research Scientist, Agriculture and Agri-Food Canada, Quebec, Canada; Harvest and Storage Of Wet and Dry 

Corn Stover As A Biomass Feedstock, Paper Number: 036088, 2003 ASAE Annual International Meeting 

Riviera Hotel and Convention Center, Las Vegas, Nevada, USA, 27- 30 July 2003 

xxvi R.L. Graham, R.D. Perlack, and L.L. Wright, Environ. Sci. Div., Oak Ridge National Lab., Oak Ridge, TN 

37831-6407; R. Nelson, Engineering Extension Programs, Kansas State Univ., Manhattan, KS 66506, and J. 

Sheehan, National Renewable Energy Lab., Golden, CO 80401. Current and Potential U.S. Corn Stover 

Supplies, Agronomy Journal 99:1–11, American Society of Agronomy, Madison, WI 53711 USA; 

doi:10.2134/agronj2005.0222 prepared 2005; published online 1 January 2007 
162

 xxvii Ron Kotrba, Ethanol Producer Magazine staff writer, The Great Biomass Inquisition, 

Ethanol Producer Magazine, January 2007. 

http://ethanolproducer.com/article.jsp?article_id=2621&q=&page=all 

xxviii Kevin J. Shinners, Professor of Agricultural Engineering, Ben N. Binversie, Graduate Research Assistant, 

Department of Biological Systems Engineering, University of Wisconsin, Madison, WI, Philippe Savoie, 

Research Scientist, Agriculture and Agri-Food Canada, Quebec, Canada; Harvest and Storage Of Wet and Dry 

Corn Stover As A Biomass Feedstock, Paper Number: 036088, 2003 ASAE Annual International Meeting 

Riviera Hotel and Convention Center, Las Vegas, Nevada, USA, 27- 30 July 2003. 

xxix William Edwards, Extension Economist, Estimating Farm Machinery Costs, PM710, Machinery 

Management, University Extension, Iowa State University, revised November 2001 xxx Renee Sayler & Kenneth Von Bargen, Principal Investigators, Feasibility of Corn Residue Collection in 

Kearney, Nebraska Area, for Western Regional Biomass Energy Program, Report of findings, by University of 

Nebraska-Lincoln, Industrial Agricultural Products Center, Lincoln, NE 68583, September 1993. 

xxxi Robert D. Grisso , Professor, Virginia Tech, Department of Biological Systems Engineering, Blacksburg, 

Virginia; Paul J. Jasa , Extension Engineer, Biological Systems Engineering Department, University of 

Nebraska, Lincoln, Nebraska; and Dale E. Rolofson , Farm Manager, Agri-Cross Farms, Inc. Greenwood, 

Nebraska. Corresponding author : Paul J. Jasa, Biological Systems Engineering Dept., University of Nebraska, 

Lincoln, Analysis of Traffic Patterns and Yield Monitor Data for Field Efficiency Determination, Paper No. 

011013, Presented at the 2000 ASAE Annual Meeting, Applied Engineering in Agriculture Vol. 18(2): 171-

178 ( © 2002 American Society of Agricultural Engineers ). A contribution of the University of Nebraska 

Agricultural Research Division, Lincoln, Nebraska. Journal Series No. 13335. Mention of trade and company 

names are for the reader and do not infer endorsement or preferential treatment of the products by the 

University of Nebraska, Lincoln. 

xxxii Robert “Bobby” Grisso, Professor, and John C. Cundiff, Professor; and David H. Vaughan, Professor, 

Department of Biological Systems Engineering, Virginia Tech, Blacksburg, VA., Investigating Machinery 

Management Parameters with Computer Tools, Paper Number: 071030, Presented at 2007 ASABE Annual 

International Meeting, Minneapolis Convention Center, Minneapolis, Minnesota, 17 - 20 June 2007. Mention 

of trade and company names are for the reader and do not infer endorsement or preferential treatment of the 

products by Virginia Tech. 

xxxiii Poorna P. Ravula, Robert D. Grisso and John S. Cundiff, Biological Systems Engineering Department, 

Virginia Tech, Blacksburg, VA 24061-0303, Comparison between Two Policy Strategies for Scheduling in a 

Biomass Logistic System, Paper Number: 071095, Presented at the 2007 ASABE Annual International Meeting, 

Sponsored by ASABE, Minneapolis Convention Center 

xxxiv International Fire Code 2903.4: Agricultural Products. Hay, straw or similar agricultural products shall not 

be stored adjacent to structures of combustible materials. Storage shall be limited to stacks of 100 tons (91 

metric tons) each. Stacks shall be separated by a minimum of 20 feet (6096 mm) of clear space. Quantities of 

hay, straw and other agricultural products shall not be limited where stored in or near farm structures located 

outside closely built areas. A permit shall not be required for agricultural storage. 

xxxv Daniel R. Petrolia, Department of Applied Economics, College of Food, Agriculture, and Natural Resources 

Sciences, University of Minnesota, The Economics of Harvesting and Transporting Corn Stover for Conversion 

to Fuel Ethanol: A Case Study for Minnesota, 

Staff Paper P06-12 August 2006 

xxxvi Ron Kotrba, staff writer, The Great Biomass Inquisition, Ethanol Producer Magazine. January 2007 Issue. 

Reach him at rkotrba@bbibiofuels.com, © 2007 BBI International 

http://ethanolproducer.com/article.jsp?article_id=2621&q=&page=all 

xxxvii Ron Kotrba, staff writer, The Great Biomass Inquisition, Ethanol Producer Magazine. January 2007 Issue. 

Reach him at rkotrba@bbibiofuels.com, © 2007 BBI International 

http://ethanolproducer.com/article.jsp?article_id=2621&q=&page=all 
163

 xxxviii Graeme R Quick, Single-pass Corn and Stover Harvesters: Development and Performance. Proceedings of 

the International Conference on Crop Harvesting and Processing, 9-11 February 2003, Louisville, Kentucky 

USA, ASABE, St. Joseph, Mich.; ASAE Publication Number 701P1103e 

xxxix A. Aden, M. Ruth, K. Ibsen, J. Jechura, K. Neeves, J. Sheehan, and B. Wallace 

National Renewable Energy Laboratory (NREL); L. Montague, A. Slayton, and J. Lukas Harris Group, Seattle, 

Washington, Ethanol Process Design and Economics Utilizing Co-Current Dilute Acid Prehydrolysis and 

Enzymatic Hydrolysis for Corn Stover; June 2002;NREL is a U.S. Department of Energy Laboratory Operated 

by Midwest Research Institute • Battelle • Bechtel; Contract No. DE-AC36-99-GO10337 

xl Robert M. Prewitt, Graduate Research Assistant, Michael D. Montross, Associate Professor, Scott A. Shearer, 

Professor, Timothy S. Stombaugh, Associate Extension Professor, Stephen F. Higgins, Research Specialist, 

Samuel G. McNeill, Associate Extension Professor, Department of Biosystems and Agricultural Engineering, 

University of Kentucky, Lexington, KY; Shahab Sokhansanj, Professor, Oak Ridge National Laboratory, 

Environmental Sciences Division, Oak Ridge, TN, Corn Stover Availability and Collection Efficiency Using 

Typical Hay Equipment, Transactions of the American Society of Agricultural and Biological Engineers 

(ASABE), Vol. 50(3): 705−711, 2007, ISSN 0001−2351; Publication of this article approved by the Director of 

the Kentucky Agricultural Experiment Station and designated Paper No. 04-05-066. 

xli Graeme R Quick, Single-pass Corn and Stover Harvesters: Development and Performance. Proceedings of 

the International Conference on Crop Harvesting and Processing, 9-11 February 2003, Louisville, Kentucky 

USA, ASABE, St. Joseph, Mich.; ASAE Publication Number 701P1103e 

xlii Kevin J. Shinners, Professor of Agricultural Engineering, Graham S. Adsit, Graduate Research Assistant, 

Benjamin N. Binversie, Graduate Research Assistant, Matthew F. Digman, Graduate Research Assistant, 

Department of Biological Systems Engineering, University of Wisconsin, Richard E. Muck, Research Scientist, 

Paul. J. Weimer, Research Scientist, US Dairy Forage Research Center – USDA-ARS, Madison, WI, 

Characteristic Performance and Yields using a Single-Pass, Split- Stream Maize Grain and Stover Harvester, 

Paper Number: 056051, presented at the 2004 ASAE/CSAE Annual International and the 2005 ASAE Annual 

International Meeting, Sponsored by ASAE, Tampa Convention Center, Tampa, Florida 17 - 20 July 2005 

xliii Shahab Sokhansanj, , Anthony Turhollow, Oak Ridge National Laboratory, North Logan, UT 84341-8804, 

Janet Cushman, Oak Ridge National Laboratory, Oak Ridge, TN 37831-6422, John Cundiff, Biological Systems 

Engineering, Virginia Technical University, Blacksburg, VA 24061-0303, Engineering aspects of collecting 

corn stover for bioenergy, Biomass and Bioenergy 23 (2002) 347 – 355; Received 15 October 2001; received in 

revised form 15 April 2002; accepted 3 May 2002; 2002 Published by Elsevier Science Ltd. 

xliv Kevin J. Shinners, Professor of Agricultural Engineering, Garrit C. Boettcher, Graduate Research Assistant, 

Jesse T. Munk, Graduate Research Assistant, Matthew F. Digman, Graduate Research Assistant, Department of 

Biological Systems Engineering, University of Wisconsin; Richard E. Muck, Research Engineer, Paul. J. 

Weimer, Research Scientist, US Dairy Forage Research Center, USDA-ARS, Madison, WI, Single-Pass, SplitStream of Corn Grain and Stover: Characteristic Performance of Three Harvester Configurations, Presented at: 

ASABE Annual International Meeting, 2006; Oregon Convention Center, Portland, Oregon, 9 – 12 July 2006. 

xlv W. C. Edens, L. O. Pordesimo, The University of Tennessee, Dept. of Biosystems Engineering and 

Environmental Science, Knoxville, TN, S. Sokhansanj, Oak Ridge National Laboratory, Environmental 

Sciences Division, Oak Ridge, TN, Field Drying Characteristics and Mass Relationships of Corn Stover 

Fractions, Presented at the ASAE Annual International Meeting/ CIGR XVth World Congress, 2002, Hyatt 

Regency Chicago, Chicago, Illinois, USA, July 28-31, 2002. 

xlvi Richard Hess, Idaho National Laboratory, Uniform Format Feedstock Supply System Design for 

Lignocellulosic Biomass, Western Region Biomass Workshop August 27, 2007 

http://sungrant.oregonstate.edu/workshop/HESS_Western_RP_workshop.pdf 

xlvii Kevin J. Shinners, Professor of Agricultural Engineering, Ben N. Binversie, Graduate Research Assistant, 

Department of Biological Systems Engineering, University of Wisconsin, Madison, WI, Philippe Savoie, 

Research Scientist, Agriculture and Agri-Food Canada, Quebec, Canada; Harvest and Storage Of Wet and Dry 

Corn Stover As A Biomass Feedstock, Paper Number: 036088, 2003 ASAE Annual International Meeting 

Riviera Hotel and Convention Center, Las Vegas, Nevada, USA, 27- 30 July 2003. 

xlviii Shahab Sokhansanj and Janet Cushman, Bioenergy Feedstock Development Program 
164

 

Oak Ridge National Laboratory (ORNL), Feedstock Engineering, Presentation, Lincoln, NB, December 12, 

2001 ORNL, Energy Efficiency and Renewable Energy, US DOE, USA 

xlix Sudhagar Mani, Ph.D. Candidate, Shahab Sokhansanj, Adjunct Professor, Xiaotao Bi, Associate Professor, 

Department of Chemical & Biological Engineering, University of British Columbia, Vancouver, BC CANADA 

V6T 1Z4, Modeling of Forage Drying in Single and Triple Pass Rotary Drum Dryers, Paper Number: 056082, 

2005 ASAE Annual International Meeting, Tampa Convention Center, Tampa, Florida, 17 - 20 July 2005 

l

 Xianzhe Zheng, Professor, Yiyuan Jiang, Professor, College of Engineering, North East Agricultural 

University, Harbin, China; Yubin Lan, Associate Professor, Agricultural Engineering Technology, Fort Valley 

State University, University Systems of Georgia, Fort Valley, GA 31030, Determination of Parameters for an 

Alfalfa Rotary Dryer, Paper Number: 056186, 2005 ASAE Annual International Meeting, Tampa Convention 

Center, Tampa, Florida, 17 - 20 July 2005 

li This information came in a confidential, personal communication. 

lii Christopher T. Wright , Peter A. Pryfogle, Nathan A. Stevens , J. Richard Hess , 

Corey W. Radtke , Idaho National Laboratory , Idaho Falls, ID, Value of Distributed Preprocessing of Biomass 

Feedstocks to a Bioenergy Industry, Paper No: 066151 

Presented at the ASABE Annual International Meeting, 2006, Oregon Convention Center Portland, Oregon, 9 - 

12 July 2006 

liii Roger G. Ginder, Professor of Economics, Department of Economics, Iowa State University, Ames, Iowa 

50011, Potential Infrastructure Constraints on Current Corn Based and Future Biomass Based U.S. Ethanol 

Production, Working Paper # 07018 , July 2007 

liv E-mailed file from Robert Perlack, U.S. Department of Agriculture, May 2008. 

lv Phillips, S, Thermochemical Ethanol via Indirect Gasification and Mixed Alcohol Synthesis of 

Lignocellulosic Biomass; NREL, April, 2007. 

lvi Aden, Andy, Mixed Alcohols from Woody Biomass – 2010, 2015, 2022, National Renewable Energy 

Laboratory (NREL), September, 23 2009. 

lvii OECD, “Biofuels: Linking Support to Performance,” ITF Round Tables No. 138, March 2008. 

lviii International Energy Agency (IEA), “Biofuels for Transport: An International Perspective,” 2004. 

lix Goldemberg, J. as sited in Rothkopf, Garten, “A Blueprint for Green Energy in the Americas,” 2006. 

lx Unicamp, “A Expansāo do Proalcool como Programa de Desenvolvimento Nacional,” Powerpoint 

presentation at Ethanol Seminar in BNDES, 2006. As quoted in OECD, “Biofuels: Linking Support to 

Performance,” ITF Round Tables No. 138, March 2008. 

lxi Ibid. 

lxii Ibid.

lxiii Ibid. 

lxiv Macedo. I.C., “Green house gases emissions in the production and use of ethanol from sugarcane in Brazil: 

The 2005/2006 Averages and a Prediction for 2020,” Biomass and Bioenergy, 2008. 

lxv Ibid.

lxvi Smeets E, Junginger M, Faaij A, Walter A, Dolzan P, Turkenburg W, “The sustainability of Brazilian 

ethanol-An Assessment of the possibilities of certified production,” Biomass and Bioenergy, 2008. 

lxvii Official Statistics of the U.S. Department of Commerce, USITC 

lxviii Davis, Ryan. November 2009. Techno-economic analysis of microalgae-derived biofuel production. 

National Renewable Energy Laboratory. Technical Memorandum to EPA. 

lxix Sun, A. et al., “Techno-Economic Analysis of Algae Biofuel Deployment.” Presented at the 2009 Algae 

Biomass Summit, San Diego, CA (October 2009) as noted in report by Davis, Ryan, op. sit. 

lxx Haas, M.J, A process model to estimate biodiesel production costs, Bioresource Technology 97 (2006) 671-

678. 

lxxi Capital cost and other details taken from Syntroleum Corp Investor Presentation materials dated November 2009, available in the 

docket or at http://www.syntroleum.com/Presentations/SyntroleumInvestorPresentation.November%205.2009.FINAL.pdf 

lxxii A New Development in Renewable Fuels: Green Diesel, AM-07-10 Annual Meeting NPRA, March 18-20, 2007. lxxiii Per EPA phone discussion July 23, 2007. 

lxxiv Ryan Davis, National Renewable Energy Laboratory, Golden Colorado 80401-3392, Technical Memo to 

EPA “ Techno-economic Analysis of Current Technology for Fischer Tropsch Fuels Production. August 2009. 
165

 

lxxv “Analysis of Fuel Ethanol Transportation Activity and Potential Distribution Constraints”, prepared for EPA 

by Oak Ridge National Laboratory, March 2009.

lxxvi BNSF railway biodiesel freight cost information can be found at 

http://www.bnsf.com/markets/agricultural/bnsf4024/cur/itm31001.txt

lxxvii 2007 National Association of Convenience Stores State of the Industry survey data www.nacsonline.com as 

reported in the National Petroleum News MarketFacts 2007, October 2007. 

lxxviii National Petroleum News, “2008 marketfacts”, www.npnweb.com 79 Modeling the Effect of Renewable Fuels Standards 2, Prepared for the Environmental Protection Agency by Jacobs Consultancy 

under contract with Southwest Research Associates, August 2008. 

80 Table 12, Reference and High Price Cases, Annual Energy Outlook 2008; Energy Information Administration, Department of 

Energy, June 2008. 

81 Table 2, Reference Case, Annual Energy Outlook 2007; Energy Information Administration, Department of Energy, February 

2007. 

82 Table 2, Reference Case, Annual Energy Outlook 2008; Energy Information Administration, Department of Energy, June 2008. 

83 D5798-99 (Reapproved 2004), ASTM International. 

84 National Association of Convenience Stores (NACS) online annual price resource kit, NACS, February 2, 2006. 

85 Combined local, state and federal gasoline taxes, American Petroleum Institute, January 2008. 

86 Greene, David L.; Alternative Fuel Market Share as a Function of Fuel Availability and Price Advantage, 1997. 

87 Brownstone, D., Small, K., 2005. Valuing time and reliability: assessing the evidence from road pricing demonstrations. Trans. 

Res. Part A 39, 279-293. 

88 Brownstone, D., Ghose, D., Golob, T., Kazimi, C., Van Amelsfort, D., 2003. Driver's willingness-to-pay to reduce travel time:

evidence from the San Diego I-15 Congestion Pricing Project. Trans. Res. Part A 37, 373-387. 

89 Lam, T., Small, K., 2001. The value of time and reliability: measurement from a value pricing experiment. Trans. Res. Part E 37 (2-

3), 231-251. 

90 Steimetz, S., Brownstone, D., 2005. Estimating consumers' 'Value of time' with noisy data: a multiple imputation approach. Trans. 

Res. Part B 39, 865-889. 

91 Spot Annual Crude Oil Prices for Western Texas Intermediate (WTI), Cushing Oklahoma; 

http://tonto.eia.doe.gov/dnav/pet/hist/rwtca.htm; Energy Information Adminstration, 2008. 92 National Annual Average Gasoline and Diesel Fuel Prices (all grades); 

http://tonto.eia.doe.gov/dnav/pet/pet_pri_gnd_dcus_nus_a.htm; Energy Information Adminstration, 2008.