U.S. Department of 

Transportation

Federal Railroad 

Administration

Cost-Benefit Analysis of Alternative Fuels 

and Motive Designs

Office of Research

and Development

Washington, DC 20590

DOT/FRA/ORD-13/21 Final Report

April 2013
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Cost-Benefit Analysis of Alternative Fuels and Motive Designs

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Chris Pinney and Brian Smith

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13. ABSTRACT (Maximum 200 words)

This project was funded by the Federal Railroad Administration to better understand the potential cost and benefits of using 

alternative fuels for U.S. freight and passenger locomotive operations. The framework for a decision model was developed by 

Transportation Technology Center, Inc., to evaluate the feasibility of these newly emerging technologies. Because these 

alternatives (fuels and engine designs) are at early stages of development, the objective is to identify the most feasible alternatives 

and support their future development. Various government agencies, U.S. railroads, and the original equipment manufacturers of 

locomotives are considered the primary stakeholders in this study.

The biodiesel blend of B20 is compared with the baseline technology (petroleum diesel) using an operating scenario for Class I 

railroad line-haul operations in 2010 to demonstrate the decision model approach in this study from a volumetric standpoint. This 

is not a recommendation for using B20 in railroad operations, but it is a good case with which to illustrate the decision framework 

developed to analyze alternative fuels for future research and development initiatives. The main drivers for the decision model 

identified in this research effort are cost, energy security, emissions, safety, and efficiency. Under each decision driver, there are 

multiple criteria that may be used for comparison between proposed alternatives. The goal is to understand if the criteria under the 

decision drivers are independently a cost or a benefit to industry stakeholders compared with the baseline.

14. SUBJECT TERMS

Cost-benefit analysis, alternative fuels, biodiesel, motive designs

15. NUMBER OF PAGES

125

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ii

METRIC/ENGLISH CONVERSION FACTORS

ENGLISH TO METRIC METRIC TO ENGLISH

LENGTH (APPROXIMATE) LENGTH (APPROXIMATE)

1 inch (in) = 2.5 centimeters (cm) 1 millimeter (mm) = 0.04 inch (in)

1 foot (ft) = 30 centimeters (cm) 1 centimeter (cm) = 0.4 inch (in)

1 yard (yd) = 0.9 meter (m) 1 meter (m) = 3.3 feet (ft)

1 mile (mi) = 1.6 kilometers (km) 1 meter (m) = 1.1 yards (yd)

1 kilometer (km) = 0.6 mile (mi)

AREA (APPROXIMATE) AREA (APPROXIMATE)

1 square inch (sq in, in2) = 6.5 square centimeters (cm2) 1 square centimeter (cm2) = 0.16 square inch (sq in, in2)

1 square foot (sq ft, ft2) = 0.09 square meter (m2) 1 square meter (m2) = 1.2 square yards (sq yd, yd2)

1 square yard (sq yd, yd2) = 0.8 square meter (m2) 1 square kilometer (km2) = 0.4 square mile (sq mi, mi2)

1 square mile (sq mi, mi2) = 2.6 square kilometers (km2) 10,000 square meters (m2) = 1 hectare (ha) = 2.5 acres

1 acre = 0.4 hectare (he) = 4,000 square meters (m2)

MASS - WEIGHT (APPROXIMATE) MASS - WEIGHT (APPROXIMATE)

1 ounce (oz) = 28 grams (gm) 1 gram (gm) = 0.036 ounce (oz)

1 pound (lb) = 0.45 kilogram (kg) 1 kilogram (kg) = 2.2 pounds (lb)

1 short ton = 2,000 pounds 

(lb)

= 0.9 tonne (t) 1 tonne (t) =

=

1,000 kilograms (kg)

1.1 short tons

VOLUME (APPROXIMATE) VOLUME (APPROXIMATE)

1 teaspoon (tsp) = 5 milliliters (ml) 1 milliliter (ml) = 0.03 fluid ounce (fl oz)

1 tablespoon (tbsp) = 15 milliliters (ml) 1 liter (l) = 2.1 pints (pt)

1 fluid ounce (fl oz) = 30 milliliters (ml) 1 liter (l) = 1.06 quarts (qt)

1 cup (c) = 0.24 liter (l) 1 liter (l) = 0.26 gallon (gal)

1 pint (pt) = 0.47 liter (l)

1 quart (qt) = 0.96 liter (l)

1 gallon (gal) = 3.8 liters (l)

1 cubic foot (cu ft, ft3) = 0.03 cubic meter (m3) 1 cubic meter (m3) = 36 cubic feet (cu ft, ft3)

1 cubic yard (cu yd, yd3) = 0.76 cubic meter (m3) 1 cubic meter (m3) = 1.3 cubic yards (cu yd, yd3)

TEMPERATURE (EXACT) TEMPERATURE (EXACT)

[(x-32)(5/9)] °F = y °C [(9/5) y + 32] °C = x °F

QUICK INCH - CENTIMETER LENGTH CONVERSION

0 1 2 3 4 5

Inches

Centimeters 0 1 2 3 4 5 6 7 8 9 10 11 12 13

QUICK FAHRENHEIT - CELSIUS TEMPERATURE CONVERSIO

 -40° -22° -4° 14° 32° 50° 68° 86° 104° 122° 140° 158° 176° 194° 212°

 

°F

 °C -40° -30° -20° -10° 0° 10° 20° 30° 40° 50° 60° 70° 80° 90° 100°

For more exact and/or other conversion factors, see NIST Miscellaneous Publication 286, Units of Weights and 

Measures. Price $2.50 SD Catalog No. C13 10286 Updated 6/17/98
iii

Contents

Executive Summary...........................................................................................1

1. Introduction.................................................................................................................. 4

1.1 Background ................................................................................................................. 5

1.2 Objectives.................................................................................................................... 6

1.3 Overall Approach ........................................................................................................ 6

1.4 Scope ........................................................................................................................... 7

2. Stakeholder Overview ................................................................................................. 8

2.1 Class I Railroad ........................................................................................................... 8

2.1.1 Locomotive Designs...................................................................................... 9

2.1.2 Railroad Operations..................................................................................... 11

2.2 Passenger (Amtrak)................................................................................................... 15

2.3 Original Equipment Manufacturers........................................................................... 19

3. Decision Model Framework with a CBA Component .............................................. 21

3.1 Decision Drivers and Decision Model Development................................................ 21

3.1.1 Cost.............................................................................................................. 22

3.1.2 Energy Security........................................................................................... 23

3.1.3 Safety (Risk Aassessment).......................................................................... 24

3.1.4 Emissions .................................................................................................... 25

3.1.5 Efficiency .................................................................................................... 27

3.2 Alternative Fuel Comparison Case (Biodiesel, B20)................................................ 28

3.2.1 Cost.............................................................................................................. 31

3.2.2 Energy Security........................................................................................... 32

3.2.3 Emissions .................................................................................................... 33

3.2.4 Safety........................................................................................................... 33

3.2.5 Efficiency .................................................................................................... 33

3.3 B20 Comparison with No. 2 Diesel........................................................................... 36

3.3.1 Cost.............................................................................................................. 38

3.3.2 Energy Security........................................................................................... 38

3.3.3 Emissions .................................................................................................... 39

3.3.4 Safety........................................................................................................... 39
iv

3.3.5 Efficiency .................................................................................................... 39

3.3.6 Cost and Benefit Results............................................................................. 40

3.3.7 Decision Matrix Approach .......................................................................... 41

4. Conclusions................................................................................................................ 44

5. References.................................................................................................................. 46

Appendix A. Overview of Alternative Fuels and Motive Power Technologies........................ 49

Appendix B. International – Europe ........................................................................................ 108

Appendix C. U.S. National Fire Protection Association Diamond 

Placard Designations........................................................................................ 113

Abbreviations and Acronyms ..................................................................................................... 114
v

Illustrations

Figure 1. Transportation Sector Petroleum Consumption .......................................................... 5

Figure 2. Age Distribution of Locomotive Fleet December 31, 2009........................................ 9

Figure 3. Class I Railroad Locomotive and Fuel Spending Account Asset Base for 

Locomotives and Fuel Stations (Book Value) .......................................................... 12

Figure 4. Class I Railroad Locomotive Fuel Stations Compared with 

Locomotive Assets.................................................................................................... 12

Figure 5. Comparison of Line Haul and Yard Fuel Expenses.................................................. 13

Figure 6. Class I Railroad Efficiency Measures 1965-2010..................................................... 15

Figure 7. Amtrak’s Heartland Flyer Powered by a Biodiesel Fuel Blend................................ 18

Figure 8. (a) NFPA Diamond Placard; (b) Hazard Class 3 Flammable and 

(c) Combustible Placards .......................................................................................... 25

Figure 9. U.S. Biodiesel Production ......................................................................................... 35

Figure 10. Gallons of Biodiesel Required by Blend (Bx) .......................................................... 36
vi

Tables

Table 1. U. S. Class I Freight Rail System Age Distribution of 

Locomotive Fleet......................................................................................................... 9

Table 2. Class I Railroad Locomotive Purchasing Data ......................................................... 14

Table 3. Amtrak Road Locomotive Fleet Age ........................................................................ 16

Table 4. Amtrak Switching Locomotive Fleet Age ................................................................ 17

Table 5. Line-Haul Locomotive Operations Baseline............................................................. 22

Table 6. Measured Consumption of Petroleum Products........................................................ 24

Table 7. NFPA 704 Baseline Measures for No. 2 Diesel........................................................ 25

Table 8. New Line-Haul Locomotives Standards................................................................... 26

Table 9. Energy Content of Selected Fuels............................................................................. 27

Table 10. B20 Biodiesel Alternative Comparison with Baseline No. 2 Diesel......................... 30

Table 11. Potential Reduction in Petroleum Products B20....................................................... 32

Table 12. Comparison of Low Temperature Values for Cloud Point and 

Pour Point.................................................................................................................. 34

Table 13. Decision Model Comparing B20 with No. 2 Diesel ................................................. 37

Table 14. Matrix to Rank Decision Drivers with Weights........................................................ 42

Table 15. Matrix to Rank Proposed Alternatives by Decision Driver Scores........................... 42

Table 16. Matrix to Calculate the Weighted Scores for Each Alternative ................................ 43
1

Executive Summary

This project was funded by the Federal Railroad Administration (FRA) to better understand the 

potential cost and benefits of using alternative fuels for U.S. freight and passenger locomotive 

operations. The framework for a decision model was developed by Transportation Technology 

Center, Inc. (TTCI), to evaluate the feasibility of these newly emerging technologies. Because 

these alternatives (fuels and engine designs) are at early stages of development, the objective is 

to identify the most feasible alternatives and to support their future development. Various 

government agencies, U.S. railroads, and the original equipment manufacturers (OEMs) of 

locomotives are considered the primary stakeholders in this study.

Energy security policies developed by the U.S. Department of Energy (DOE) and emission 

standards set forth by the U.S. Environmental Protection Agency (EPA) are driving most of the 

technology initiatives related to alternative fuels today. Identifying alternatives that may provide 

benefits in the areas of emissions and energy security in relation to their potential cost, safety, 

and operating efficiencies are the main analysis objectives of this study.

Energy security deals with many issues related to national security and energy policies. For the 

purpose of this study, the consumption of petroleum diesel fuel (fossil energy) by U.S. railroads 

is the key measure. Current and future issues related to petroleum products (crude oil and 

equivalents) used by railroads include U.S. imports (which are used in part for railroad

operations) and essentially the sole energy reliance by railroads. In 2009, approximately 1.6 

percent of U.S. transportation petroleum was used by railroads (1). 

U.S. railroads have just recently had emission standards regulated by EPA. In 2000, the EPA 

mandated a set of tier emission levels for existing locomotives by the OEM build date and for 

new locomotives put into service. Freight and passenger locomotives are designed to meet these 

tier-level emission standards by using petroleum diesel. Freight railroads account for a small 

portion of U.S. greenhouse gas (GHG) emissions. According to EPA data, in 2009, total U.S. 

GHG emissions for railroads were 2.1 percent of total transportation-related emissions (2). 

Some of the alternative energy sources being studied and that may be in limited use are biomass, 

natural gas, and coal. These energy sources have the potential to replace diesel fuel and provide 

power for locomotive operations. However, most are considered experimental by the railroad

industry. In most cases, engine modifications or complete motive power design changes are 

required. As a result, the use of alternative fuels or locomotive designs that are different from 

current diesel engine designs represents only a small percentage of the total fleet. 

Current fuel standards allow an alternative fuel blend of up to 5-percent biodiesel (B5) with the 

remaining 95 percent made up of conventional diesel. Biodiesel refers to the fuel produced from 

renewable sources (biomass). This mixture will meet the American Standard for Testing and 

Materials (ASTM) D975 diesel fuel specification and can be used in any application as if it were 

pure petroleum diesel (3). These concentrations are being used in locomotive operations in small 

amounts today. 

By the mid-1960s, essentially all freight locomotives owned and operated by U.S. railroads were 

dieselized. Passenger locomotives represent a small percentage of the locomotive fleet with a 

mix of electric and diesel electric; the latter providing the dominate power. Therefore, the 

baseline case for comparison to proposed alternatives is diesel-electric locomotive technology 
2

and its fueling infrastructure. In 2010, just over 28,000 diesel-electric locomotives were in the 

U.S. fleet for freight and passenger service. This includes both switching (yard) and line-haul 

(mainline) units. 

As an assessment of the cost structure for the railroad industry using a Class I railroad example, 

expenditures related to locomotives (acquisitions and repair and maintenance) and fueling (fuel 

and fueling stations) averaged over $12 billion annually from 2008 to 2010. This represents over 

25 percent of total Class I railroad spending annually. In addition, the locomotive fleet ranked 

second in total railroad assets at just over $4.7 billion in 2010. Therefore, alternatives may have 

significant financial impacts on railroad cost structure and future investments strategies.

On the basis of the literature search and interview process for this study, biodiesel was the 

alternative selected as a comparison case to the baseline (diesel locomotive technology).

Specifically, the blend of 20-percent biodiesel and 80-percent petroleum diesel (B20) was 

studied. B20 is the most commonly used biodiesel blend for all transportation modes in the 

United States (4). Resources used to refine biomass into fuel (biodiesel) are a renewable energy 

source and is typically produced domestically.

The biodiesel blend of B20 is compared with the baseline technology (petroleum diesel) using an 

operating scenario for Class I railroad line-haul operations in 2010 to demonstrate the decision 

model approach in this study from a volumetric standpoint. This is not a recommendation for 

using B20 in railroad operations but a good comparison case to illustrate the decision framework 

developed to analyze alternative fuels for future research and development initiatives. 

The main drivers for the decision model identified in this research effort are cost, energy 

security, emissions, safety, and efficiency. Under each decision driver, there are multiple criteria 

that may be used for comparison between proposed alternatives. The goal is to understand 

whether the criteria under the decision drivers are independently a cost or a benefit to industry 

stakeholders as compared with the baseline. Only the fuel production ($/diesel gallon equivalent) 

(DGE) criterion under the cost decision driver and petroleum products (diesel fuel displaced) 

criterion under the energy security decision driver are independently quantified and compared 

with the baseline in this B20 comparison case based on available data.

For the B20 scenario, the fuel production criterion under the cost decision driver would require 

railroads (Class I) to pay a premium of 3.5 percent in fuel costs or just over $250 million dollars 

for line-haul operations in 2010 by using a biodiesel blend of B20. The price of biodiesel is 

consistently higher than No. 2 diesel. By normalizing the B20 price by DGE (energy content),

there is a further separation in cost between diesel and B20. The price of biodiesel is also 

affected by the Federal Excise Tax Credit (5); without this subsidy, the retail price to consumers 

would be even higher than current prices.

The petroleum products criterion under the energy security decision driver using B20 would 

provide a benefit by displacing approximately 667.5 million gallons of diesel, which is 

equivalent to approximately 15.7 million barrels of petroleum. This can be normalized into 

million barrels per day (MMbd), which equals approximately 0.04 (MMbd) of petroleum. The 
3

0.04 MMbd estimate represents approximately 0.23 percent of U.S. consumption (19.1 MMbd) 

or 0.37 percent of U.S. imports (11.8 MMbd) in 2010.

1

There is considerable interest in the highest U.S. policy circles to improve energy security (6). 

Therefore, significant resources have been put into assessing the energy security benefits of 

reduced U.S. oil imports. With U.S. Federal-proposed rulemaking data for the on-highway 

vehicle sector, an estimate of the oil import premium is $13.13 per barrel (2009 dollars) (7). 

Because the proposed rulemaking is evaluating the reduction of petroleum imports through fuel 

efficiency, it provides an equitable approach for this study. Calculating the 15.7 million barrels 

of petroleum by the $13.13 per barrel premium yields an estimated societal benefit of just over 

$200 million.

To populate the remaining inputs for the other decision driver criteria for the B20 comparison 

case, recommended research and testing for cost (locomotive durability testing and a fueling 

infrastructure study), energy security (availability and sustainability study), emissions 

(laboratory tier level emissions testing), and efficiency (fuel consumption and cold temperature 

testing operations) are recommended to develop a more robust decision model. FRA, railroads, 

and OEMs are currently addressing some of these important issues. 

As an example, FRA sponsored a 1-year test trial in 2010 using a biodiesel fuel blend of B20 to 

power the Heartland Flyer passenger locomotive, putting this innovation on Time’s list of “The 

50 Best Inventions of 2010” (8). The primary objective of the test trial was to evaluate the 

feasibility and effectiveness of utilizing biodiesel as an alternative fuel. Information from this 

test trial will be supported with more detailed laboratory testing at Southwest Research Institute 

(SwRI). Information from these initiatives will help develop criteria under the emissions (tier 

level emissions) and efficiency (fuel consumption) decision drivers.

Because of the mature nature of diesel locomotive technology for freight and passenger railway 

operations and its fueling infrastructure, no alternative fuels or motive power designs that 

differentiate from current diesel technology can be cost justified from the research conducted in 

this study. Diesel locomotive technology was essentially fully integrated into U.S. railroad 

operations by the mid-1960s. 

However, comparisons among selected alternative fuels and motive power designs are 

recommended under this framework approach to address future issues related to the rising cost 

and supply of petroleum diesel fuel and the emission standards required for U.S. railroads.

Cooperation among industry stakeholders is vital to the success of evaluating alternatives for 

future consideration.

 

1 If B20 replaces diesel fuel, 0.04 million barrels of diesel fuel would be saved per day. The consumption of diesel 

fuel in the United States is 19.1 million barrels per day, and the import is 11.8 million barrels per day. Therefore, by 

using B20, saving 0.04 million barrels per day would save approximately 0.23 percent in consumption and 0.37 

percent in import.
4

1. Introduction

This project was funded by FRA to better understand the potential cost and benefits of using 

alternative fuels for U.S. freight and passenger locomotive operations. The framework for a 

decision model was developed to support industry stakeholders as they evaluate the feasibility of 

these newly emerging technologies. The primary stakeholders considered in this study are 

government, railroads, and manufacturers of locomotives in the United States.

As the regulatory body of the railroad industry, safety, cost, and the efficiency of these new

alternatives (fuels and engine designs) and the locomotives and infrastructure that may be 

affected by them are important factors for FRA to monitor as other regulatory groups develop 

national energy and emissions policies. The emissions standards set forth by EPA in 2000 for 

locomotives and DOE policies related to energy security are driving some of these technology 

initiatives. Therefore, energy security and emissions are the main problems to understand in 

relation to the potential use of alternative fuels and motive power technologies. 

Energy security deals with many issues related to national security and energy policies; however 

for the purpose of this study, the amount of petroleum-based diesel fuel used in railroad

transportation and how proposed alternative fuels and motive power designs may affect current 

consumption levels are important issues to understand. The two specific areas of concern are the 

amount of imported oil the United States consumes and the future depletion of conventional 

petroleum resources. As conventional petroleum (crude oil) resources become depleted, 

alternative energy resources will increasingly replace them. Although emissions are an 

important problem, EPA emissions standards now regulate this problem.

Petroleum-based diesel powers the modern diesel-electric locomotive. It is derived from fossil 

energy resources. Some of the alternative energy sources being studied, and that may be in 

limited use, are biomass, natural gas, hydrogen, and coal. These energy sources have the 

potential to power the electric traction motors for locomotive operations. However, most are 

considered experimental by the railroad industry today. In most cases, engine modifications and 

complete motive power design changes are required. These changes may have a significant 

impact on railroad infrastructure and locomotive operations on a large scale. Resource 

availability and the environmental impact of some alternative energy sources are other important 

issues that must be addressed.

Alternative fuels and motive power designs that differentiate from the modern diesel-electric 

locomotives for freight and passenger operations are at an early stage of development and usage 

in the railroad industry today. The number of locomotive units in switching (yard operations) 

service that differentiate from current designs represents a very small percentage of the total 

fleet, and there are currently no line-haul (mainline) locomotive units in revenue service. Current 

fueling standards allow an alternative fuel blend of up to 5-percent biodiesel (B5) with the 

remaining part made up of conventional diesel. Therefore, small amounts of biodiesel blends are 

being consumed with some benefits on the emissions side and a small reduction in the 

consumption of fossil fuel-based petroleum (crude oil).
5

1.1 Background

Modern locomotive operations have been influenced significantly by the introduction of the 

diesel-electric locomotive design introduced in the 1940s. By the mid-1960s, essentially all 

locomotives owned and operated by Class I railroads were dieselized. The remaining fleet 

consisted of a few steam engines, several hundred electric, and around 30 gas turbine 

locomotives. Today, virtually all locomotives are diesel electric. There are approximately 

28,000 diesel electric locomotives in operation on the U.S. freight and passenger railroad system. 

Of this number, approximately 24,000 are Class I railroad owned or operated with the remaining 

4,000 owned or operated by shortline and passenger (9, 10, 11). (On average, 800–1,000 units 

are purchased, and around 125 are rebuilt annually (10) for Class I railroads.) With retirements 

of older locomotives, the entire fleet size has remained consistently at 28,000 since 1965 (11). 

However, the average horsepower (hp) per unit has increased significantly. The typical line-haul 

unit today would be over 4,000 hp. On the passenger side, the National Railroad Passenger 

Corporation (Amtrak) operates a mix of electric and diesel locomotives. Diesel is the 

predominate power source for the passenger fleet, which consists of approximately 500 

locomotives.

Locomotives operate over a vast network. The U.S. Class I railroad system covers nearly 

124,000 miles of track in the United States. It works as an interchange system; therefore 

locomotives and freight cars operate between railroad carriers and require consistent fueling 

infrastructure, repair, and maintenance facilities. Interchange operations extend into Canada and 

Mexico. Locomotive operations are designed almost exclusively for compression-ignition engine 

technology using ASTM fuel specifications. Amtrak, the largest passenger service railroad 

serves more than 500 destinations in 46 states and three Canadian provinces on more than 21,200 

miles of routes. Amtrak operates a mix of diesel and electric locomotives, and diesel is the 

predominate power for locomotive passenger operations. 

Figure 1 shows approximately 1.6 percent of the U.S. transportation sector (highway and 

nonhighway) petroleum is consumed by U.S. railroads (12). Because the consumption of diesel 

fuel requires fossil-based energy sources, the United States imports foreign oil to meet this 

demand. On a net basis, the United States imports nearly 50 percent of the oil it consumed (13).

U.S. policies suggest a link between oil imports and U.S. national security (14). One of the 

DOE’s main policy themes is developing programs to improve energy security for the United 

States. 

Figure 1. Transportation Sector Petroleum Consumption

Pipeline

0.0%

Highway

86.4%

Water

4.3%

Air

7.6%

Rail

1.6%
6

In 1965, the railroad industry reported consumption of just over 3.5 billion gallons of diesel fuel 

with the average price of $0.09 per gallon. An important point is that fuel costs represented 

approximately 3.5 percent of the industry’s total operating expenses. In 2008, Class I railroads 

reported the consumption of 3.9 billion gallons of diesel fuel with an average price of $3.12 per 

gallon. In 2009 with the recession looming, car loads declined, and the consumption of diesel 

declined to 3.2 billion gallons at a price point of $1.77 per gallon with less demand. In 2010,

consumption increased to 3.5 billion gallons at an average price per gallon of $2.25 with total 

fuel expenses of about $7.9 billion, representing nearly 19 percent of total operating expenses 

($42.7 billion). For 2008, 2009, and 2010, the percentage of total operating expenses for fuel was 

26, 15, and 19 percent, respectively. The number of gallons consumed between the mid-1960s 

and today has not changed significantly, but the efficiency with which the fuel is utilized and the 

financial landscape for railroad spending on fuel has changed.

On the emissions side, U.S. railroads have only recently had emission standards regulated by 

EPA. In 2000, EPA developed a set of tier-level emission standards for existing locomotives by 

OEM build date and for new locomotives put into service. Freight railroads account for only a 

small portion of U.S. GHG emissions. According to EPA data, total U.S. GHG emissions in 

2009 were 6,633 teragrams (trillion grams) of carbon dioxide equivalents. Nontransportation 

sources (power plants, industry, etc.) accounted for 73 percent of this total, and transportation 

accounted for the remaining 27 percent. The 37.2 teragrams accounted for by freight railroads 

was just 0.6 percent of total U.S. GHG emissions from all sources and just 2.1 percent of 

transportation-related GHG emissions (2).Therefore, the main goal on the emission side today is 

developing technology to meet EPA tier emission levels through retrofit programs or new 

designed locomotives.

1.2 Objectives

For this study, alternative fuels and motive power designs in use or under consideration for use 

around the world for freight and passenger railroad transportation were investigated. The current 

strategies and recommendations of industry stakeholders (railroads and OEMs) were reviewed. 

The most practical fuels that may be supported by the industry were analyzed. A decision model 

with a Cost Benefit Analysis (CBA) component that may be used to compare selected 

alternatives to current technology (conventional diesel locomotive engines) was developed.

1.3 Overall Approach

The approach of this study is to develop the framework for a decision model that may be used to 

compare and contrast potential alternative fuels and motive power designs to existing technology 

using fossil-based diesel fuel and modern locomotive compression-ignition engines. Key drivers 

included in the framework are safety, cost, and efficiency implications for selected alternatives. 

Identifying technology-based solutions to help reduce U.S. reliance on fossil fuel-based energy 

sources (energy security) and meeting emissions regulations is the main objective of this study. 

Therefore, the key decision drivers in the study are cost, energy security, emissions, safety and 

efficiency, with their associated criteria.

Input from four primary stakeholder groups helped formulate the framework of this study: FRA,

freight (Class I), passenger (Amtrak) railroads, and the OEMs that build, retrofit, and maintain 

diesel-electric locomotives in U.S. operations. In addition, an international perspective, primarily 

from Europe, was assessed.
7

1.4 Scope

Developing the framework for a decision model to support industry stakeholders as they evaluate 

the feasibility of alternatives to diesel fuel and diesel locomotive technology is the primary 

objective of this study. Stakeholders for this study are the U.S. Government (FRA), railroads

(freight and passenger), and manufacturers of locomotives.

The following are key deliverables:

• Overview of Class I railroad, passenger railroad (Amtrak), and OEM strategies as they 

relate to alternative fuels and motive power designs (Section 2).

• Selection and overview of potential alternative fuels and motive power designs for the 

North American railroad industry (Appendix A).

• Overview of initiatives and strategies for using alternatives to fossil fuel-based rail 

technology in Europe (Appendix B).

• Development of the framework for a decision model with a cost-benefit analysis (CBA)

component to support industry stakeholders as they evaluate the feasibility of alternatives 

to diesel fuel and diesel locomotive technology (Section 3).

• Selection of an alternative (fuels and or engine designs) to illustrate the proposed 

decision model framework for analyzing alternative fuels and motive power designs 

(Section 3.2)

• Development of a decision matrix to support the decision model analysis component. 

Under the framework for the decision model, this is a proposed component for the 

decisionmaking process between stakeholders (Section 3.3.7).
8

2. Stakeholder Overview

This section provides an overview of Class I railroad, passenger railroad (Amtrak), and OEM

strategies as they relate to alternative fuels and motive power designs. A series of interviews

were conducted with each stakeholder group. The primary goal was to better understand the 

perspective of the various stakeholders in regard to the potential of alternative fuels and motive 

power designs and to identify what factors impact their decisions when considering the various

technologies.

2.1 Class I Railroad

There are seven Class I railroads: BNSF Railway (BNSF), CSX Transportation, Grand Trunk 

Corporation (owned by Canadian National Railway Company), Kansas City Southern Railway 

Company, Norfolk Southern Corporation, Soo Line (owned by Canadian Pacific), and Union 

Pacific Railroad Company (UP). Together with their counterparts in Canada and Mexico, the 

U.S. freight railroads form the world’s most efficient, lowest-cost freight rail system. In addition 

to providing shippers with an affordable and an efficient way to move their products, freight 

railroads provide enormous public benefits, including fuel efficiency, low GHG emissions, and 

reduced highway congestion.

2.2 Locomotive Fleet

Modern U.S. locomotive operations have been influenced significantly by the introduction of the 

diesel-electric locomotive design introduced in the 1940s. By the mid-1960s, essentially all 

locomotives owned and operated by Class I railroads were dieselized. The remaining fleet 

consisted of a few steam engines, several hundred electric, and around 30 gas turbine 

locomotives. Today, virtually all Class I railroad locomotives are diesel electric. There are 

approximately 28,000 diesel-electric locomotives in operation on the U.S. freight railroad system

with about 24,000 owned or operated by Class I railroads (15). 

On average, 800–1,000 new locomotives are purchased and around 125 are rebuilt annually. 

With retirements of older locomotives, the fleet size has remained fairly consistent since 1965

(10). However, the average horsepower per unit has increased significantly. The typical line-haul 

unit today would be approximately 4,000 hp. Figure 2 and Table 1 show the age distribution of 

the fleet in 2009. New locomotives manufactured and purchased by railroads must meet EPA 

tier emissions standards. In addition, locomotives in service must continue to meet EPA tier 

emission standards by build date, including after rebuild (which in some cases is now more 

restrictive).
9

Figure 2. Age Distribution of Locomotive Fleet December 31, 2009

Table 1. U.S. Class I Freight Rail System Age Distribution of Locomotive Fleet

Locomotives in Age Bracket

Date Built* Number Percent

Jan. 1, 2009–Dec. 31, 2009 461 1.9

Jan. 1, 2008–Dec. 31, 2008 777 3.2

Jan. 1, 2007–Dec. 31, 2007 911 3.8

Jan. 1, 2006–Dec. 31, 2006 1,122 4.7

Jan. 1, 2005–Dec. 31, 2005 875 3.6

Jan. 1, 2000–Dec. 31, 2004 4,650 19.3

Jan. 1, 1995–Dec. 31, 1999 4,173 17.4

Jan. 1, 1990–Dec. 31, 1994 2,464 10.2

Jan. 1, 1985–Dec. 31, 1989 1,558 6.5

Before 1985 7,054 29.3

Total 24,045 100.0

*Disregards year of rebuilding. Represents 2009 Class I railroad statistics.

2.2.1 Locomotive Designs 

Excerpts from this section are developed from a report for FRA on “Rail Efficiency Study” (16). 

Locomotives in the United States typically use a large bore (500–750 cubic inches per cylinder), 

medium-speed (up to approximately 1150 rpm) design of diesel engine. Locomotive engines 

typically range from 8 to 20 cylinders, dependent on horsepower requirements. Both two-cycle 

and four-cycle diesel engine technologies are used.

4 yrs.

4%

3 yrs.

5%

2 yrs.

4%

20-24 yrs.

6% 1 yr.

3%

> 1 yr.

2%

25 > yrs.

30%

15-19 yrs.

10%

5-9 yrs.

19%

10-14 yrs.

17%
10

Historically, freight locomotives ranged from 1,500 to 3,600 hp. In the early 1990s, locomotive 

horsepower increased to over 4,000 hp. A limited number (~300) of locomotives of up to 6,000 

hp were developed and sold. 

Currently, there are no new four-axle medium hp locomotives being manufactured by ElectroMotive Diesel, Inc. (EMD), or General Electric Transportation Systems (GETS). Four-axle 

locomotives are important for yard operations because of their ability to safely negotiate sharp 

curves on industrial and branch lines, and bridges and trestles with limited weight capacities. 

Several small manufacturers offer four-axle locomotives that are essentially remanufactured 

EMD locomotives. Repowering a previously owned locomotive versus purchasing a 

remanufactured locomotive was another factor in selecting the repower alternative, because it 

avoids the cost of purchasing the locomotive platform.

2.3 Alternative Fuels – Locomotives 

Biodiesel fuel is an alternative to diesel fuel now being considered in multiple railroad 

demonstration projects. Mixtures of biodiesel and regular No. 2 diesel at mix levels from 2 

percent to approximately 20 percent are being considered.

Several alternatives to diesel powered locomotives have been demonstrated and tested over the 

last 20 plus years; e.g., UP has tested a line-haul locomotive powered by natural gas. For this 

case, a fuel tender was required to allow enough fuel storage capacity to traverse the given routes 

(usually requires liquefied natural gas (LNG) to have enough storage capability). Additionally, 

the BNSF continues to operate four natural gas locomotives in switcher service in California.

Another demonstration of alternative fuels usage was a cooperative program between the U.S. 

Department of Defense (DOD), BNSF, and a private company called Vehicle Projects from 

Golden, Colorado. The demonstration used the Green Goat concept hybrid locomotive where the 

small diesel engine was replaced by a pair of fuel cells that ran off of stored hydrogen. Green 

Goat locomotives work under the principal that smaller high efficiency four-cycle diesel engines 

can be run at a continuous high speed (efficient operating point) to charge a bank of storage 

batteries. Utilizing the existing traction motor system, the batteries are used as the main power 

source for “high power” switching operations. Because it is a switching operation, the traction 

system is not utilized as often for long periods of high power operations. The system does 

require sufficient diesel engine power and battery storage capability to last through the required 

duty cycles for typical line-haul operations. That concept completed its demonstration and is 

currently under phase II development to increase the duty cycle capability for the unit (i.e., larger 

battery storage, lighter weight battery technology, and increased hydrogen storage).

Several other possible fuels are available for consideration, which have a variety of hardware 

change requirements onboard the locomotive such as the potential for cryogenic fuel storage and,

in some cases, significant modifications of the existing diesel engine.

2.3.1 Repower Alternatives

Four-axle locomotives are important for switching operations because of their ability to safely 

negotiate light track, sharp curves on industrial and branch lines, and for bridges and trestles with 

limited weight capacities. Several small manufacturers offer four-axle locomotives that are 

essentially remanufactured EMD locomotives. 
11

Options are available to repower older four- and six-axle switcher size locomotives with newer,

efficient, medium-speed large bore, clean burning engines or to utilize multiple smaller output 

four-cycle high efficiency, clean burning engines. Each option provides the ability to improve 

the efficiency of older locomotive designs and is offered to allow older locomotives to be 

brought up to more current efficiency and emissions standards rather than to simply continue to 

rebuild them at former standards.

Wabtec’s website on a multi-engine (GenSet) low emission switcher suggests a fuel savings of 

up to 35 percent depending on duty cycle, with emissions benefits of 70–90 percent (an 

improvement from Tier 0 to Tier 2 EPA emissions levels).

EMD offers an eight-cylinder 710ECO engine technology repower kit. The locomotive is 

certified to Tier 0 because typically the built dates of the original locomotives fall into the Tier 0 

time span. According to EMD, the engines actually perform at Tier 2 levels. This 

environmentally friendly performance is achieved with up to 25-percent savings in fuel 

consumption and over 50-percent lube oil savings and is augmented by a fully integrated 

Automatic Engine Start Stop system that can reduce engine idle time by over 50 percent.

2.3.2 Railroad Operations

Railroad stakeholders recognized several primary cost centers that may be benchmarked to

current operations. These benchmarks may be used to compare how the potential implementation 

of alternative fuels and motive power designs affect locomotive and fueling infrastructure cost 

structures. Capital expenditures, operating expenses, and the investments in railroad assets that 

may be affected by these new technologies are all important issues.

The most important cost centers to railroad stakeholders are the following: (1) the annual costs of 

diesel fuel consumed in line haul and yard operations, (2) initial capital cost of newly purchased 

locomotives and average capital expenditures per year for the fleet, (3) repair and maintenance 

expenses of the locomotive fleet, and (4) the infrastructure cost of fueling stations, and current 

fuel efficiency of the locomotive fleet.

Figure 3 shows railroad spending by accounts that may be affected by alternative fuels and 

motive power designs. The Locomotive Bar shows a 3-year average (2008–2010) for capital 

expenditures of locomotive acquisitions and operating expenses for repair and maintenance of 

the fleet at $3.4 billion annually. The Fuel Bar also shows a 3-year average (2008–2010) for 

capital expenditures of fuel stations and operating expenses for fuel at $8.6 billion annually.

Total spending for the locomotive and fuel accounts was over $12 billion annually. Using a 3-

year average, these accounts represent over 25 percent of total Class I railroad spending 

annually. Therefore, major cost centers are associated with these potential new technologies (17).
12

OPEX = operating expenses; CAPEX = capital expenditures

Figure 3. Class I Railroad Locomotive and Fuel Spending Account Asset Base for

Locomotives and Fuel Stations (book value)

Assets that Class I railroads are invested in are important accounts to understand from a cost 

structure standpoint when considering technology changes to the system. In 2010, the locomotive 

fleet ranked second to rail in total railroad assets. Figure 4 shows fueling stations for locomotive 

fueling operations are small compared with locomotive assets. However, $547 million is a 

significant investment in any industry, and the combined asset base of $4.7 billion for both 

accounts is a major investment as it relates to current railroad operations (17).

Figure 4. Class I Railroad Locomotive Fuel Stations Compared with Locomotive Assets

2.3.3 Fuel Consumption

In 2010, Class I railroads consumed approximately 3.5 billion gallons of diesel at an average 

price per gallon of $2.25, making total fuel expenses about $7.9 billion. This represented nearly 

19 percent of total operating expenses ($42.7 billion). In 2009, total fuel expenses were nearly 

15 percent of total operating expenses, and in 2008, they were just over 26 percent. The 3-year 

average (2008–2010) for total fuel expenses was $8.6 billion annually. Note that fuel expenses

for yard and line-haul operations are significantly different, as Figure 5 shows. In 2008, just over 

92 percent of the fuel was consumed in line-haul service and about 8 percent was in yard 

operations. Railroad stakeholders use different strategies for locomotive acquisitions for lineMillions $

Locomotives 

$4,197

Fuel 

Stations, 

$547

CAPEX CAPEX

OPEX

OPEX

$0

$2,000

$4,000

$6,000

$8,000

$10,000

Locomotive Fuel

Millions $

$3.4B

$8.6B
13

haul service and for switching operations. Therefore, different strategies may be considered for 

alternative fuel and motive power designs. For example, repowered locomotives are exclusively 

being put into switching operating service (17).

Figure 5. Comparison of Line Haul and Yard Fuel Expenses

2.3.4 Fuel Stations

Railroad stakeholders were very interested in how alternative fuels may affect the fuelling

infrastructure for railroad operations. Railroad experts suggest that the potential use of 

alternative fuels on a wide scale will largely depend on the economics, fuel availability,

environmental, and infrastructure factors. The fuel station account includes the cost of structures, 

facilities other than track, appliances necessary to service equipment, and stations for supplying 

fuel to locomotives. In 2010, railroads had an asset base of just under $143 million2 in fuel 

station infrastructure and annual capital expenditures were $53.6 million for fuel stations. In 

2008, capital expenditures were nearly $57.5 million and in 2009 nearly $36.9 million, making a 

3-year average of $49.3 million annual capital expenditures (17).

The railroads handle large amounts of fuel and have numerous fuel facilities, including direct to 

locomotive suppliers. As such, issues of fuel mixing, fuel cleanliness, cloud point, and filters 

will likely come rapidly to the forefront for biofuels. Other potential energy sources such as 

natural gas and hydrogen would require significant infrastructure changes.

2.3.5 Locomotive Investments

The purchase of locomotives is an important capital expenditure for railroads. In 2010, railroads

spent nearly $892 million on the acquisition of switch and line-haul locomotive units. In 2009,

capital expenditures were significantly higher at $1.96 billion than in 2008 at $1.11 billion. A 3-

year average is about $1.33 billion annually for investments in locomotive power. On the balance 

sheet, locomotives rank second only to rail in terms of assets owned. In 2010, the locomotive 

asset base was just over $27 billion (17).

 

2 This $143 million is for fueling station assets and accompanying facilities, not total railroad assets. The asset does 

not last only 3 years; the values provided for capital expenditures is given over a 3-year period to show how the cost 

has increased over time.

Yard

7.7%

Line haul

92.3%
14

Key points made by industry stakeholders were that unit cost per horsepower should not change 

significantly from current designs. In Table 2, costs per unit are shown for newly purchased 

locomotives. Aggregate horsepower for the fleet was over 86 million in 2010. The fleet is driven 

completely by diesel-electric locomotive technology using conventional No. 2 diesel fuel. All 

newly purchased units must meet current EPA tier level emission standards.

Currently, there are no new medium horsepower locomotives being manufactured by EMD or 

GETS for switching service, but the industry is repowering locomotive units. The current 

alternatives are to rebuild or repower existing older switching units. Table 2 shows costs per unit 

for a repowered unit and some sample costs for line-haul units.

Table 2. Class I Railroad Locomotive Purchasing Data (17)

Service Type Cost Per Unit Method of Acquisition

Switching NRE 3GS21 CDB (repower) $1,634,000 Purchased-2008

Line haul SD70ACE $2,124,522 Purchased-2008

Line haul ES44DC, 4000 HP $2,440,958 Purchased-2008

Line haul C45ACCTE, 4500 $2,111,050 Purchased-2008

Line haul ES45AC, 4400 HP $2,279,472 Purchased-2009

Line haul ES44AC, 4400 HP $2,437,786 Purchased-2010

2.3.6 Maintenance (Repair and Maintenance)

The durability and life-cycle cost as it relates to locomotive repair and maintenance cost is a 

major operating expense. One of the primary areas of interest is how alternative fuels such as 

biodiesel blends will perform in existing engine designs. Railroads and manufacturers reported 

that they are in cooperative testing programs to understand some of these issues. Maintenance 

cost per hour and overall life-cycle cost is important information for fleet managers to quantify

and justify potential alternatives to the existing fleet operations. One of the benchmarks is the 

current repair and maintenance expense for the existing fleet. In 2010, Class I railroads spent 

over $2.1 billion on repair and maintenance. In 2008, expenses reached $2.1 billion, and in 

2009, expenses were $1.9 billion, making a 3-year average spending of just over $2 billion 

annually (17).

2.3.7 Emissions

On the emissions side, U.S. railroads have only recently had emission standards regulated by 

EPA. In 2000, EPA developed a set of tier emission levels for existing locomotives by OEM 

build date and for new locomotives put into service. Freight railroads account for only a small 

portion of U.S. GHG emissions. According to EPA data, total U.S. GHG emissions in 2009 were 

6,633 teragrams (trillion grams) of carbon dioxide equivalents. Nontransportation sources (power 

plants, industry, etc.) accounted for 73 percent of this total, and transportation accounted for the 

remaining 27 percent. The 37.2 teragrams accounted for by freight railroads was just 0.6 percent 

of total U.S. GHG emissions from all sources and just 2.1 percent of transportation-related GHG
15

emissions (2).Therefore, the main goal on the emission side today is developing technology to 

meet EPA tier emission levels through retrofit programs or new designed locomotive.

2.3.8 Efficiency

By the mid-1960s, essentially all locomotives owned and operated by U.S. Class I railroads were 

dieselized. Railroads have made great progress in efficiency gains as measured in revenue tonmiles per gallon of diesel consumed and the average length of haul, as Figure 6 shows. Since 

1965, efficiency has increased nearly 150 percent to 484 revenue ton miles per gallon of diesel,

while the average length of haul has increased over 80 percent to just over 900 miles (10).

Although many operational improvements have contributed to these efficiency gains, the 

locomotive engine is considered the core item for efficiency improvements. The diesel-electric 

locomotive represents the major fuel consumption component of rail operations. These

improvements have influenced the length of haul for railroads today. Increasing the length of 

haul affects logistical operations of fueling and cycle times for delivery to customers, reducing

transportation costs and improving customer service (10).

Figure 6. Class I Railroad Efficiency Measures 1965–2010

2.4 Passenger (Amtrak)

Amtrak is a passenger railroad. The U.S. Department of Transportation (DOT) owns all issued 

and outstanding preferred stock. Amtrak’s principal business is to provide rail passenger 

transportation service in the major intercity travel markets of the United States.

Amtrak operates a nationwide rail network, serving more than 500 destinations in 46 states and 3

Canadian provinces on more than 21,200 miles of routes. Amtrak-owned equipment includes 

Amfleet®, Superliner®, Viewliner®, and other railroad passenger cars totaling 1,518, plus 459 

locomotives, 80 Auto Train® vehicle carriers, and 101 baggage cars.

0

50

100

150

200

250

300

350

400

450

500

550

19651975198519951997199920012003

2005

20072009

Rev-Ton Miles per Gallon

0

100

200

300

400

500

600

700

800

900

1,000

Average length of Haul (Miles)

Rev-Ton Miles per gallon of Fuel Average Length of Haul
16

Amtrak’s fuel, power, and utilities expenses increased $26.9 million, or 9.9 percent, to $299.7 

million in 2010 compared with $272.8 million in 2009. Of this increase, $25.6 million is the 

result of a 21.1-percent increase in average diesel fuel costs to $2.24 per gallon in 2010 (from 

$1.85 per gallon in 2009). The remainder of the increase is to the result of an increase in diesel 

fuel usage.

With an average age of 25 years, many car types in Amtrak’s fleet have exceeded their 

commercial life. Replacement of the current fleet is one of Amtrak’s most pressing needs, given 

the fleet’s age, reliability issues, and the increase in demand for passenger rail. In Fiscal Year

2010, Amtrak released a comprehensive fleet strategy that outlined plans for completely 

replacing Amtrak’s fleet by 2040. For the purpose of the section, only locomotive-related 

information is referenced for both diesel-electric and electric locomotives (18).

2.4.1 Fleet Strategy

The fleet planning process is designed to shape the fleet so that it delivers the services customers 

want, meets the strategic requirements of the business regarding sustainability, helps develop a 

viable supplier base, enhances the product offered to customers, and identifies the funding 

requirements to meet these goals. The current locomotive fleet for road service and switching 

service is shown is in Table 3 and Table 4 (11).

Table 3. Amtrak Road Locomotive Fleet Age

Equipment Type Active Fleet 

12/1/2010

Year Started in 

Service

Age of Locomotive 

in 2010

Average 

Mileage

P32-8 18 1991 19 years 1,900,000

P32DM 18 1995–1998 12–15 years 1,500,000

P32DM 18 1995–1998 12–15 years 1,500,000

P40 12 1993 17 years 1,800,000

P42 200 1996–2001 9–14 years 2,000,000

F59PHI 21 1998 12 years 1,400,000

AEM7 49 1980–1988 22–30 years 3,700,000

HHP-8 15 1999–2001 9–11 years 960,000

Acela Express Power 

Cars 40 1999–2000 10–11 years 1,400,000

NPCU 22 1976–1981 29–34 years 3,700,000
17

Table 4. Amtrak Switching Locomotive Fleet Age

Equipment Type Active Fleet 12/1/2010 Year Started in 

Service

Age of Locomotive 

in 2010

SW1 1 1950 60

SW1000 7 1950 60

GP38H 7 1966 44

MP15 10 1970 40

SW 1500-SW1001 3 1973 37

GP38 5 1976 34

GP15D 10 2004 6

GenSet MP14/MP21 2 2010 -

Amtrak’s fleet strategy plan has been updated throughout to reflect the current state of the fleet, 

programs that are under way, and changes in the larger business environment. Some equipment 

has been returned to service. Funding provided under the American Recovery and Reinvestment 

Act allowed stored Amfleet I cars to be returned to service, providing much needed capacity on 

the Northeast Corridor. Fifteen P-40 diesel locomotives have been refurbished and returned to 

service, providing additional capacity on long-distance routes and State-supported services.

On the basis of demand, analysis, and defined life policies under the plan, Amtrak needs to buy 

70 electric locomotives and 280 diesel locomotives over the next 15 years. These electric 

locomotives will replace all of the existing ones on the Northeast Corridor, which should provide 

a significant improvement in reliability for the electric locomotive fleet, as well as increase 

capacity for future service expansion. Alternative uses for the HHP-8 locomotives remain under 

review, and their ultimate disposal will be addressed later. A reserve fleet will be required as the 

new locomotives enter service, and the HHP-8 fleet should be suitable for this work, because

their leases will run for a few years after the arrival of the new locomotives.

Amtrak is undertaking a progressive approach to switcher fleet replacement. The new switchers 

will replace traditional locomotive designs with GenSet technology. GenSets use two or three 

500-horsepower diesel engines that meet Tier 4 EPA truck emission standards, which are stricter 

than EPA locomotive emission standards. New switchers will use about 60 percent less fuel, with 

a corresponding emissions reduction. The emissions reductions will allow Amtrak to take 

advantage of diesel emission reduction grant programs in partnership with State and local 

agencies in the places where the switchers are operated.

Two new switchers have already been introduced in California—one in Oakland and one in Los 

Angeles. Two more GenSet switchers will be introduced in Chicago. In cooperation with the 

Brotherhood of Locomotive Engineers and Trainmen, Amtrak has applied for a grant to update a 

switcher in Washington, DC, which will be rebuilt to take a new GenSet configuration, extending

its service life and altering the replacement plan considerably.
18

Alternative Fuels Testing

A 1-year trial to use a renewable biodiesel fuel blend to power the Heartland Flyer, shown in 

Figure 7, put this innovation on Time’s list of “The 50 Best Inventions of 2010.” Initiated by the 

Oklahoma DOT, in collaboration with Amtrak, FRA, and the Texas DOT, the trial began April 

2010 and was designed to evaluate the use of B20, a blend of 20-percent biofuel and 80-percent 

regular ultra low sulfur diesel fuel. The test program was funded through an FRA grant. 

According to Amtrak, test details were made available in the last quarter of 2011 (18).

Figure 7. Amtrak’s Heartland Flyer Powered by a Biodiesel Fuel Blend

The primary objective of the test program was to evaluate the feasibility and effectiveness of 

utilizing biodiesel as an alternative fuel for passenger locomotives. The test program focused on 

the following elements:

Revenue Service Trial of B20 

Amtrak is operating the Heartland Flyer in normal passenger service while utilizing biodiesel 

blended (B20) fuel. Amtrak is measuring and recording the B20 fuel consumption of the engine 

on a daily basis. 
19

Power Assembly Inspection and Analysis 

Task 2 was completed prior to the commencement of revenue service testing. Amtrak performed

at a minimum pre- and post-revenue service test inspection and analysis of two power assemblies 

from the locomotive engine. The analyses identified any and all adverse effects of the B20 fuel 

on engine components expected to be directly or indirectly impacted by the utilization of B20 

fuel. 

Engine Exhaust Emissions Analysis 

Following the 12-month revenue service test period, Amtrak will collect locomotive exhaust 

emissions data. Exhaust emissions from the locomotive will be analyzed in accordance with EPA 

locomotive exhaust emissions Federal test protocol. GETS or another contract provider with 

equivalent capabilities will conduct the engine exhaust emissions testing and provide 

documentation of the results to be included in the final report. 

Miscellaneous Maintenance/Inspection/Test 

Amtrak will perform analysis of the engine oil every 10 days for degradation and/or dilution. 

Amtrak will have the pure biodiesel, B100 fuel samples analyzed to determine that the fuel meets 

ASTM D6751 standards (19). Amtrak will subject the diesel fuel to be blended with the pure 

biodiesel (B100) to be tested monthly to ensure it meets ASTM D975 specifications and 

similarly the B20 blend will be tested monthly to determine conformance with ASTM D7467 

specifications (3, 20).

2.3 Original Equipment Manufacturers

Locomotives used in the United States are primarily produced by two manufacturers: EMD and 

GETS. EMD manufactures its locomotives primarily in London, Ontario, Canada, and its 

engines in La Grange, IL. Both EMD and GETS were interviewed for this study. The GETS 

locomotive manufacturing facilities are located in Erie, PA, whereas its engine manufacturing 

facilities are located in Grove City, PA. These manufacturers produce both the locomotive 

chassis and propulsion engines. They also remanufacture engines. 

EMD and GETS were interviewed regarding the testing of biodiesels. It is important to note that 

competition between manufacturers limits the available testing information. Manufacturers of 

locomotives and locomotive engines issued their positions on the use of biodiesel (updated from 

reference 21):

• GETS—Biodiesel use up to B5 is acceptable in GETS engines because it fits within 

ASTM specifications. Values above that level are not acceptable. Under the express 

terms of GETS’ warranty, the failure of the railroad to use the prescribed fuel (i.e., No. 2 

diesel) voids the contractual warranty obligations. The use of alternative fuels may also 

be in violation of the EPA locomotive emission regulations, because the engines are 

emission certified by using petroleum diesel.

• EMD— Biodiesel use up to B5 is acceptable in EMD engines because it fits within 

ASTM specifications. EMD “does not approve or prohibit the use of biodiesel fuels or 

biodiesel blends with distillate diesel fuel” (22). However, if an engine failure arises as a 

result of using biodiesel, it will be not covered by the engine warranty. EMD also notes 

that fuel system components may require modification to accommodate the lower energy 
20

content of biodiesel fuels. Furthermore, the use of biodiesel may impact the regulatory 

emission compliance of the engines, and it is the responsibility of the user to obtain the 

proper regulatory exemptions to use biodiesel in any emission regulated EMD engine.

• MotivePower—allows the use of biodiesel blends up to B20, in consultation with 

Caterpillar, the manufacturer of the Head End Power engine. Caterpillar has agreed to the 

use of B20 biodiesel in their products if the lubrication properties of the fuel are equal to 

the No. 2 diesel, and if the energy content is equivalent.

• Because biodiesel is the main alternative fuel in locomotive operations today, it was the 

primarily emphasis of this section. With the increasing usage of biodiesel and with 

incidents of related engine problems, the major manufacturers of diesel fuel injection 

equipment (FIE) issued a common position statement on the use of biodiesel in 2000 

(23), which was updated in 2004 (24), 2007 (25), and 2009 (26).

• Until 2007, the FIE manufacturers stated that blends of up to 5 percent of biodiesel in 

mineral diesel fuel should not create any serious engine problems if the final blend meets 

the European diesel fuel specification EN 590 at the point of sale, provided the biodiesel 

fuel used in the blend meets EN 14214. In 2009, they changed their position to allow up 

to 7 percent provided the biodiesel component meets EN 14214:2009 and the final blend 

meets EN590:2009. The key biodiesel issue for the FIE manufacturers is resistance to 

oxidation. Aged or poor quality biodiesel fuel may contain organic acids, free water, 

peroxides, and products of polymerization, which can attack many components and 

reduce the service life of FIE.
21

3. Decision Model Framework with a CBA Component

This section provides the framework for a decision model with preliminary results. To illustrate 

the proposed framework, a baseline for diesel locomotive technology is developed and compared 

with a selected alternative fuel technology (biodiesel B20) by using the proposed decision 

drivers. Decision theory is a general approach to decisionmaking when the outcomes associated 

with alternatives are often in doubt. From the initial findings of this study, alternative fuels and

motive power designs are at an early stage of development in the railroad industry. Therefore,

the results of this study and proposed recommendations should only be used to develop further 

research and development initiatives for the most feasible alternatives.

Although the specifics of each situation vary, decisionmaking generally involves the same basic 

steps that are followed in this study: (1) recognize and clearly define the problem, (2) collect the 

information needed to analyze possible alternatives (for the purpose of this study the objective is 

to develop a framework to help select the alternatives that show the best potential for future 

implementation), and (3) choose and implement the most feasible alternatives (this step is 

outside the scope of this study).

The decision model framework provides a locomotive unit to unit comparison where applicable. 

Larger scale implementation scenarios are outside the scope of this project. In addition, this 

model represents a high level analysis tool that requires railroad industry review and 

recommendations. Some inputs suggested by stakeholders are undefined at this time because of

insufficient data discussed in this section. An important task under this project is to propose

additional work activities to build a more robust model and to recommend research initiatives to 

validate model inputs.

3.1 Decision Drivers and Decision Model Development

Key decision drivers for the decision model were selected, based on the literature search 

conducted for this project, stakeholder interviews, and the statement of work developed by FRA.

As the regulatory body of the railroad industry, safety, cost, and the efficiency of these new 

technologies and the locomotives and infrastructure that may be affected by them are areas FRA 

may monitor as other regulatory groups develop national energy and emissions policies. The 

EPA emission standards set forth in 2000 and DOE policies related to energy security are driving 

some of these technology initiatives. The key decision drivers are cost, energy security, safety 

(risk assessment), emissions, and efficiency. For the purpose of this study, line-haul Tier 2-

compliant locomotives and Class I railroad data is used as a representation of railroad operations.

From the decision drivers developed in the stakeholder interview process, Table 5 provides a 

synopsis of baseline measures that may be used to compare current technology to proposed 

alternative fuels and motive powers designs. Only line-haul locomotive units are evaluated in 

this preliminary model where applicable and some specific drivers can only be considered 

estimates at this time. One of the goals of the study is to identify research initiatives where data 

is lacking to provide a complete model to validate the model inputs. 
22

Table 5. Line-Haul Locomotive Operations Baseline

Line-Haul Locomotive (No. 2 Diesel)

Key Decision Drivers Drivers Baseline

Cost

Locomotive:

New Purchase $/unit $2,200,000

Life-Cycle Cost (durability) $/unit/year $280,000

Fuel:

Production Cost $/DGE $3.95

Infrastructure:

Fueling Stations $/unit $8,000

Energy Security

Petroleum Products (diesel fuel) gallons/DGE 1

Emissions (Tier 2 Line-Haul Levels)

Hydrocarbons (HC) g/hp-h 0.30

Carbon Monoxide (CO) g/hp-h 1.5

Oxides of Nitrogen (NOx) g/hp-h 5.5

Particulate Matter (PM) g/hp-h 0.20

Safety (Risks assessment)

Employee exposer [NFPA 704]†

Flammability NFPA 704 Rating 2

Health Hazard NFPA 704 Rating 1

Reactivity NFPA 704 Rating 0

Efficiency

Energy

Energy Content (fuel) Btu/gallon 129,500

Gross Engine Power hp/N8 Undefined

*BSFC lb/hp-h Undefined

Temperature (operations)

Cloud Point Degrees/C (F) –35 to 5 (–31 to 41)

Pour Point Degrees/C (F) –35 to –15 (–31 to 5) 

*Brake-specific fuel consumption.

†

NFPA, National Fire Protection Agency; h, hour.

3.1.1 Cost

The direct cost of locomotives and fueling were the primary cost centers of interest to 

stakeholders. Railroad experts suggest that the potential use of alternative fuels on a wide scale 

will largely depend on the economics, fuel availability, environmental, and infrastructure

development. From the stakeholder interviews, the initial capital expenditure of a new 

locomotive, its life cycle cost (durability), fuel cost (per equivalent gallon of energy), and fueling 

infrastructure were the primary cost centers that were recommended for comparison as shown in 

Table 5.

An estimate of $2.2 million for a newly purchased Tier 2-compliant locomotive is based on Class 

I railroad purchasing data from Table 2 of this report. These estimates were developed using 

samples from different OEMs, railroads, and year of purchase (2008–2010).
23

In the interview process, locomotive life-cycle cost referred to by stakeholders as durability of 

the equipment was an important issue. Although no data was provided by stakeholders during the 

interview process, a life-cycle cost estimate was developed for a typical line-haul locomotive 

based on the acquisition cost of $2.2 million, a 30-year useful life, salvage value of 10 percent,

and Class I railroad cost of capital. A 90-percent locomotive availability rate is also used in the 

calculation. These variables yielded an estimated life-cycle cost of approximately $280,000 per 

year (this driver requires further research to validate the input).

Fuel production for this analysis is measured by the price of energy produced per DGE. The 

content of 1 gallon of diesel produces approximately 129,500 British thermal units (Btu) of 

energy. For the purpose of this study, the average price for a gallon of diesel reported by DOE is 

used for the baseline case. The average retail price for diesel was $3.95 in July 2011 (27). 

Therefore, this input represents a means of comparing other energy sources in terms of price and 

energy content produced. 

For fueling infrastructure, the driver is the cost invested in fueling stations per locomotive in 

service. Railroad stakeholders were very interested in how alternative fuels may affect the 

fueling infrastructure for railroad operations. The fueling infrastructure account includes the cost 

of structures, facilities other than track, appliances necessary to equipment for service, and 

stations for supplying fuel to locomotives. 

In 2010, railroads had an asset base of just under $143 million in fuel station infrastructure and 

capital expenditures of $53.6 million, equaling $196 million total expenditures and assets. The 

fueling infrastructure decision driver is then developed by adding the asset base to capital 

spending and dividing it by the number of locomotives in service ($196 million/24,000 = 

~$8,000 per unit).

With the potential implementation of new technology, a per unit measure can be made based the 

additional investments made in fueling infrastructure. It should be noted that this is only a Class I 

railroad driven assumption; fueling infrastructure outside of railroad operations is not included.

3.1.2 Energy Security

Energy security deals with many issues related to national security and energy policies. For the 

purpose of this study, the amount of diesel fuel from petroleum products (barrels of oil or oil 

equivalent) used in railroad transportation and how proposed alternative fuels or motive power 

designs may affect current consumption levels are the key measures. United States total 

consumption, including imports, of petroleum products is the benchmark for comparison for the 

energy security decision driver. Resource availability and sustainability of proposed alternative 

fuels are also important issues to stakeholders. This subject is touched on briefly in Section 4.

The United States consumed 19.1 million barrels per day (MMbd) of petroleum products in

2010, for all sectors. Imports were 11.8 million barrels per day (MMbd) of petroleum products

(13). Gallons per DGE and liquid volumes between diesel and alternative fuels are the proposed

factor for this decision driver. The purpose of this calculation is to understand the current amount 

of diesel consumed in DGEs that may be compared to an alternative fuel or motive power design 

change. The final calculation converts diesel gallons consumed into barrels of petroleum 

products consumed.
24

The benchmark factor in Table 5 for the energy security driver is normalized to 1, which 

represents the number of DGEs for Btu/gallon of diesel (129,500). As the energy content of fuel 

or engine efficiency changes as a result of alternative fuels or motive power designs, there may 

be changes in the consumption of diesel and petroleum products.

In 2010, Class I railroads consumed 3.6 billion gallons of diesel for line-haul operations. On the 

basis of a calculation using refinery yield statistics for petroleum and other liquids, this 

represents approximately 85 million barrels of petroleum products annually or 234,000 barrels 

per day of consumption (0.2 MMbd). Therefore, as a comparative measure to U.S. consumption 

of petroleum and imports, it is estimated that Class I railroad line-haul operations represented

approximately 1.2 percent of U.S. consumption and 2.0 percent of U.S. imports, as Table 6

shows.

Table 6. Measured Consumption of Petroleum Products

U.S. Petroleum 

Consumption1

Petroleum 

(MMbd)1

Diesel Gallons 

(billions)

2

Petroleum 

(MMbd)3

Petroleum (MMbd)

U.S. Consumption 19.1

3.6 0.2

1.2%

U.S. Imports 11.8 2.0% 1

U.S. Energy Information Administration: June 24, 2011. 2

U.S. Class I railroads: Annual line-haul diesel gallons are 3.6 billion (freight), 2010. 3

Each gallon of petroleum diesel fuel was assumed to equal 1 gallon of petroleum products (crude oil and equivalents) with 42

gallons equaling one barrel.

3.1.3 Safety (risk assessment)

Achieving and maintaining the safe operation of commercial railroads in the United States falls 

under the jurisdiction of FRA. In addition, each railroad interviewed conveyed the importance of 

safety. Therefore, safety is an important decision driver for stakeholders when considering 

alternative fuels and motive power designs to current operations. Employee exposure, storage,

and transport were the main concerns. 

The U.S. National Fire Protection Association (NFPA) standard NFPA 704 was selected as the 

baseline measure for diesel (28). Table 7 shows the ratings for diesel used in locomotive 

operations NFPA 704 define the familiar red, blue, yellow, and white “fire diamond” used by 

emergency personnel to quickly and easily identify the risks posed by hazardous materials. 

Appendix C contains the details of the four NFPA diamond placard designations and describes 

the safety risks associated with fuels.

The NFPA fire diamond placard shown in Figure 8a correlates with the ratings in Table 7. For 

transport of diesel, the Hazard Class 3 flammable and combustible placards are required (Figure 

8b & c) (ANSI Z400.5-2004 Standard (United States) MSDS ULSD Fuel).
25

Table 7. NFPA 704 Baseline Measures for No. 2 Diesel

Description NFPA Rating Diamond Color

Flammability 2 Red

Health 1 Blue

Instability/Reactivity 0 Yellow

Special - White

Figure 8. (a) NFPA Diamond Placard; (b) Hazard Class 3 Flammable; and 

(c) Combustible Placards

3.1.4 Emissions

Emissions were selected as a decision driver by stakeholders because of EPA emission standards

mandated in 2000. Each stakeholder recommended that a comparison of proposed alternative 

fuels or motive power designs to existing technology be included in the decision model. For the 

purpose of this study Tier 2 emission levels are used as a benchmark for comparison as shown in 

Table 9 for line-haul locomotives. The specific emission driver that may be compared with

alternative fuels and motive power designs on a mass basis (grams per brake horse power hour

(g/bhp-h)) created by the locomotive engine under testing specifications. Table 5 under the 

emissions driver shows the baseline criteria for Tier 2 line-haul levels.

Test procedures used to compare the performance should be based on the Federal Test Procedure 

(FTP) as recommended. Table 8 shows the new line-haul locomotive standards (g/bhp-h) and 

dates of compliance for the U.S. line-haul fleet (29).

b c a
26

Table 8. New Line-Haul Locomotives Standards (29)

Locomotive 

Group

Date

PM NOx HC

Previous 

Standard

New 

Standard

Previous 

Standard

New 

Standard

Previous 

Standard

New 

Standard

Remanufactured Line-Haul Locomotive Standards

Remanufactured 

Tiers 0 & 1

2008 as 

available 

2010 required

0.60 0.22

9.5 (Tier 0)

7.4 (Tier 1)

7.4

(8.0 if no 

SLAC)

1.00 (Tier 0)

0.55 (Tier 1)

0.55

(1.00 if no 

SLAC)

Remanufactured 

Tier 2

2008 as 

available 

2013 required

0.20 0.10 5.5 5.5 0.30 0.30

Newly Built Line-Haul Locomotive Standards

Tier 3 2012 -- 0.10 -- 5.5 -- 0.30

Tier 4 2015 -- 0.03 -- 1.3 -- 0.14

SLAC = separate loop intake air cooling.

Additionally, in all locomotive groups:

Idle emissions control—must equip locomotive with automatic engine stop/start.

HC standards are Total HC, except Tier 4 (nonmethane hydrocarbon (NMHC)).

Part 92 smoke standards apply if particulate matter family emission limit (PM FEL) > 0.05 g/bhp-h but are generally waived 

from testing.

Part 92 CO standards continue to apply (at Tier 2 levels for Tiers 3&4); notch caps also apply.

Must also meet switch-cycle standards of the same tier (of Tier 2 for Tier 3 line-haul locomotive) except for Tier 4.

The FTP should be considered the standard test procedure when comparing alternative fuel and

motive power designs. However, as with EPA’s test procedures for other vehicles and engines, 

the locomotive test regulations also allow alternate test procedures to be used, provided that they 

have been demonstrated to yield results equivalent or superior to those obtained from the FTP. 

The FTP for locomotives is a nominally steady-state test procedure that measures gaseous (HC, 

CO, and NOx), PM, and smoke emissions from locomotives with the engine at a series of steadystate speed and load conditions. Measurement of emissions would actually be performed during 

both steady-state operations and during the limited periods of engine accelerations between 

notches. The reason for this is that in-use locomotive operation is not truly steady state. Rather, 

locomotive operation is a combination of long periods of largely steady-state operation at 

individual notches and short transient periods between notch changes. In developing the final test 

procedure, EPA sought to ensure that all measured emission rates are representative of actual inuse emissions. 

The test procedures, other than the test sequence, are based largely on those previously 

established for on-highway heavy-duty diesel engines in 40 CFR 86 Subparts D and N (U.S. 

Code of Federal Regulations) (30). Specifically, the raw sampling procedures and many of the 

instrument calibration procedures are based on Subpart D, and the dilute particulate sampling 

procedures and general test procedures are based on Subpart N.
27

3.1.5 Efficiency

Efficiency of locomotive operations is a key decision driver recommended by stakeholders as a

comparative measure to using alternative fuels or motive power designs. The energy content of 

fuel, gross engine power, and brake-specific fuel consumption (BSFC) of the engine and 

temperature-related fuel operations were of primary interest. 

The driver for energy content is Btu/gallon of fuel consumed. Diesel energy content is the 

benchmark for efficiency at 129,500. Table 9 shows examples of energy content of fuel

measured in Btu/gallon. The information illustrates significant ranges of various alternative fuels 

in Btu/gallon. The percent change column has many operational implications relating to cost, 

onboard fuel storage, and length of haul for railroads today.

Table 9. Energy Content of Selected Fuels

Fuel Btu/gallon Btu/gallon 

(percentage change)

Diesel No. 2 129,500 100.0

Biodiesel (B5) 128,940 99.6

Biodiesel (B20) 127,250 98.3

Biodiesel (B100) 118,300 91.4

Natural Gas (LNG) 75,000 57.9

Hydrogen 25,293 19.5

The other impacts on engine output capability using alternative fuels are gross engine power and 

BSFC. These measures are recommended for testing with a Tier 2 level line-haul locomotive. At 

this time, these measures are undefined for the baseline No. 2 diesel case on many of the more 

modern high horse-power engines in this study. FRA-funded testing on two higher horsepower 

line-haul locomotive engine families is being contracted currently with SwRI in San Antonio, 

TX, and through these proposed tests a baseline may be developed.

When conducting engine tests, one measure of engine health is to verify that an engine is able to 

produce its rated gross engine power output at its designed (usually highest) control setting (for a 

locomotive Notch 8). Emissions certifications are related to emissions, which constitute output 

levels for a given power output. When testing an engine with different fuels, it is common to 

determine the engine control system’s ability to use the fuel by verifying that the engine can 

produce full-rated horsepower. It should also be noted that the engine certification is conducted 

with a “certification fuel” (a pure fuel with normally no alternative fuel component) whose 

makeup is not only specified (40 CFR Section 1065.703) (31) but also is sampled, tested, and 

verified for use. If an engine is not capable of producing full-rated horsepower at the proper 

control setting with a certified fuel, the engine condition is usually reviewed.

The BSFC is the measure of fuel consumed at a given control setting with the output of the 

engine limited by a brake, or in this case, by resistance of the output device (generator or 

alternator) with the output of the device measured and dissipated by a set of electrical resistor 

grids. In this way, tightly controlled testing can be conducted and repeated with the output of 
28

each test condition compared with that of other test conditions. For BSFC, the fuel consumption 

is measured and normalized (divided) by the amount of horsepower produced at a particular 

engine control setting (lb/hp-h).

It is important to measure both gross engine power output and fuel consumption (BSFC),

because this can help to understand differences in engine performance, depending on the fuels 

tested and the engines used for test (and the ability of the control system to adapt as necessary).

Low temperature properties of fuels are measured by the cloud point and pour point as described 

below. 

Cloud point, [°C (°F) –35 to 5 (–31 to 41)]. The temperature at which small solid crystals are 

first visually observed as the fuel is cooled (ASTM D2500, D5771, D5772, or D5773). Below 

the cloud point, these crystals might plug filters or drop to the bottom of a storage tank. Cloud 

point is the most widely used and most conservative estimate of the low temperature operability 

limit. However, fuels can usually be pumped at temperatures below the cloud point. A related 

test is for the wax appearance point, ASTM D3117.

Pour point, [°C (°F) –35 to –15 (–31 to 5)]. The temperature at which the fuel contains so many 

agglomerated crystals that it is essentially a gel and will no longer flow (ASTM D97, D5949, or 

D5950). Distributors and blenders use the pour point as an indicator of whether the fuel can be 

pumped, even if it would not be suitable for use without heating or taking other steps (4).

3.2 Alternative Fuel Comparison Case (Biodiesel, B20) 

On the basis of the literature search, interview process, and information in Appendix A, biodiesel

was selected as the alternative fuel comparison case, specifically the blend of 20-percent 

biodiesel and 80-percent petroleum diesel (B20). This is not a recommendation for using B20 in 

railroad operation, but it is a good comparison case to illustrate the proposed decision framework 

for analyzing alternative fuels or motive power designs. This comparison is made to the baseline

(No. 2 diesel) and potentially to other selected alternatives for future analysis. The following are 

some of the potential benefits of biodiesel blend B20 for railroad operations:

• It is renewable and may be produced from domestic resources.

• It displaces petroleum-derived diesel fuel.

• It can be used as a 20-percent blend in most on-highway diesel equipment with minor or 

no modifications.

• It may reduce global warming GHG emissions.

• It is safe as compared to petroleum diesel and suitable for sensitive environments.

Other areas of interest for the use of biodiesel in railroad operations are the following:

• Further understanding of the effects on railroad fueling infrastructure and engine designs

are warranted.

• The lower energy content (Btu/gallon) as compared with conventional diesel may have 

significant operational issues for railroads.

• The full risks of temperature (cold weather) impacts have not been fully explored.
29

Biodiesel refers to the fuel produced from renewable sources that meets ASTM International 

D6751, the standard for biodiesel. Biodiesel is most commonly used as a blend with petroleum 

diesel. At concentrations of up to 5 (volume) percent (B5) in conventional diesel fuel, the 

mixture will meet the ASTM D975 diesel-fuel specification and can be used in any application 

as if it were pure petroleum diesel. These concentrations are likely being used in locomotive 

operations today, but the extent is not known.

At concentrations of 6–20 percent, biodiesel blends have been used in off-highway (farming)

equipment and in some on-highway equipment with minor or no modifications to the equipment, 

although certain manufacturers do not extend warranty coverage if equipment is damaged by 

these blends. The B6 to B20 blends are covered by the ASTM D7467 specification that was 

approved in June 2008. B100 is covered by ASTM 6751.

B20 is the most commonly used biodiesel blend in the United States, because it provides a good 

balance between material compatibility, cold weather operability, performance, emission 

benefits, and costs (4). B20 is also the minimum blend level allowed for compliance with the 

Energy Policy Act of 1992 (EPAct), which requires the use of renewable fuels or alternative fuel 

vehicles by certain covered fleets. Equipment that can use B20 includes compression-ignition 

engines, fuel oil and heating oil boilers, and turbines. However, the long-term effects on diesel 

locomotive engines in terms of durability and emissions are not fully understood at this time.

The following sections will compare information developed from the baseline case for diesel 

line-haul operation in Section 3.1 and in Table 5 to the B20 operating scenario results in Table 

10.
30

Table 10. B20 Biodiesel Alternative Comparison with Baseline No. 2 Diesel

Line-Haul Locomotive 

Key Decision Drivers Drivers Diesel (No. 2) Biodiesel (B20)

Cost

Locomotive:

New Purchase $/unit $2,200,000 Undefined

Life-Cycle Cost 

(durability)

$/unit/year $280,000 Undefined

Fuel:

Production Cost $/DGE $3.95 $4.09

Infrastructure:

Fueling Stations $/unit $8,000 Undefined

Energy Security

Petroleum Products (diesel fuel) gallons/DGE 1 0.814

Emissions (Tier 2 Line-Haul 

Levels)

Hydrocarbons (HC) g/hp-h 0.30 Undefined

Carbon Monoxide (CO) g/hp-h 1.5 Undefined

Oxides of Nitrogen (NOx) g/hp-h 5.5 Undefined

Particulate Matter (PM) g/hp-h 0.20 Undefined

Safety (Risks assessment)

Employee exposure (NFPA 704)

Flammability NFPA Rating 2 2

Health Hazard NFPA Rating 1 1

Reactivity NFPA Rating 0 0

Efficiency

Energy

Energy Content (fuel) Btu/gallon 129,500 127,250

Gross Engine Power hp/N8 Undefined Undefined

BSFC lb/hp-h Undefined Undefined

Temperature (operations)

Cloud Point Degrees/C (F) –35 to 5 (–31 to 41) –16 to –1 (3 to 30)

Pour Point Degrees/C (F) –35 to –15 (–31 to 5) –17 to –9 (1 to 16)
31

3.2.1 Cost

Locomotive

The potential new purchase or retrofit cost for locomotives that would operate using B20 is 

undefined for the purpose of this study. According to OEMs, no locomotives in service or newly 

built units have design modifications for use with biodiesel blends. Both OEMs and railroads 

were interested in the potential cost and design issues related to biodiesel use, especially onboard 

locomotive fuel systems and capacity design changes that may result from using B20. 

Elastomers (rubber components), metals, and plastics in locomotive fuel systems were potential

areas that may require component modifications, which may lead to warranty issues between 

railroads and OEMs. Pure biodiesel is not compatible with certain elastomers, metals, and 

plastics that are commonly used with petroleum diesel. Generally (but not always), biodiesel 

blends of 20 percent or lower have a much smaller effect on these materials; very small 

concentrations of biodiesel in B5 or B2 have no noticeable effect on materials compatibility.

The life-cycle cost (durability), as a result of using B20 or lower blends, is undefined for the

purpose of this study. Railroads and suppliers were concerned about the long-term potential 

impact on current engine designs relating to longevity as a result of changes in engine oil 

contaminants with biofuel consumption. Research and testing by OEMs, railroads, and suppliers 

are ongoing to understand the effects B20 will have on existing locomotives in service and newly 

purchased units. However, no data was found or provided during the interview process to 

quantify the potential change in life-cycle cost as the result of using B20 in railroad locomotives.

Fuel

Fuel production for this analysis is measured by the price of energy produced per DGE. The 

energy content of 1 gallon of diesel produces approximately 129,500 Btu. The average price for 

a gallon of diesel was $3.95 in 2010. The energy content of B20 is 127,250 Btu/gallon with an

average price per gallon of $4.09 in DGE in 2010. Therefore, $4.09 is used in this analysis as a 

comparison to the baseline of $3.95, which is an increase of about 3.5 percent over diesel. Even 

though this is a spot price comparison from 2010, biodiesel is historically a higher cost than

diesel with government subsidies, as reported by EIA (13).

Fuel expenses were close to $7.3 billion in 2010 for Class I railroad line-haul operations. 

Therefore, a 3.5-percent increase in fuel cost by using B20 would be a significant increase in 

operational costs to railroad operations using the decision framework for this study. It is 

important to note that the spot prices are only used to develop the fuel production factor of 3.5 

percent. At this time, a B20 price for railroads has not been established. Railroad and highway 

fuel prices differ because railroads are not subject to highway taxes. As a result, average prices 

for railroads are typically lower than average retail prices. Therefore, the fuel production factor 

can be applied only to the total expense of line-haul operation as an equitable comparison to 

B20.

The potential cost to the fueling infrastructure is undefined at this time. As referenced in the 

baseline case, in 2010, railroads had an asset base of just under $143 million in fuel station 

infrastructure and capital expenditures were $53.6 million; therefore, total investment and annual 

capital expenditures equaled $196 million. The effects of biodiesel blends on the fueling 

infrastructure are of great interest to railroads and fuel suppliers. Because of the investment in 

railroad infrastructure for dieselized operations, it is important to understand the logistical issues 
32

related to biodiesel blends. A knowledge base may be developed and benchmarked from onhighway operations for railroad fueling infrastructure. Onboard fueling and storage of biodiesel 

should be approached independently through approved testing.

3.2.2 Energy Security

Biodiesel (B20) reduces the amount of diesel fuel consumed; therefore, it is a benefit under the 

decision framework for this study. On the basis of the calculations in this section, 667.5 million 

gallons of petroleum diesel may be displaced annually by a scenario of using 100 percent B20 in 

line-haul operations. This represents approximately 0.23 percent of the U.S. petroleum product 

consumed and 0.37 percent of U.S. imports annually, as Table 11 shows. 

Table 11. Potential Reduction in Petroleum Products B20

U.S. Petroleum 

Consumption1

Petroleum 

(MMbd)1

Diesel Gallons 

(million)

2

Reduction 

(MMbd)3

Reduction 

(MMbd)

U.S. Consumption 19.1

667.5 0.04

0.23%

U.S. Imports 11.8 0.37%

1

U.S. Energy Information Administration: June 24, 2011.

2

U.S. Class I railroads: Annual line-haul diesel gallons (estimated reduction). 3

Each gallon of petroleum diesel fuel was assumed to equal 1 gallon of petroleum products (crude oil and 

equivalents) with 42 gallons equaling one barrel.

As stated, 1 is the normalized baseline factor for diesel fuel. Essentially, all locomotives in Class 

I railroad service are powered by diesel. Diesel energy content is 129,500 Btu/gallon. Therefore, 

the base case for diesel is a constant factor of 1 (gallons/DGE) that may be multiplied by the 

number of gallons consumed.

To determine the impact on the consumption of petroleum diesel by substituting biodiesel, a 

comparison case is made with a B20 blend. By using B20 as an example, the volume of diesel 

and biodiesel used in 2010 Class I railroad line-haul operations becomes (0.8 × 3.585 billion 

gallons diesel) = 2.868 billion gallons, and (0.20 × 3.585 billion gallons B100) = 717 million 

gallons, respectively, per year. 

However, with the simultaneous reduction in energy content of the fuel, an additional step is 

required to determine how much total B20 blend is needed for the same total energy content.

Table 9 shows the energy content of B20 per gallon is 127,250 Btu, resulting in an energy 

content reduction from pure diesel to B20 blend of 0.983 (which requires 1.7 percent more 

volume of B20 blend to be used to make up for lost energy).

The increase in total B20 fuel required compared with straight diesel is (1.017 × 3.585 billion 

gallons) = 3.648 billion gallons. The diesel component increase then becomes (2.868 billion ×

1.017) = 2.918 billion gallons with the B100 component becoming (717 million gallons × 1.017) 

= 730 million gallons. Actual diesel replaced then becomes (3.585 billion gallons – 2.918 billion 

gallons) = 667.5 million gallons (or 15.9 million barrels or 0.044 MMbd).

Therefore, the relative change for the line-haul operation scenario is a reduction in diesel-fuel 

consumption of approximately 667.5 million gallons, with a resulting energy security factor of 
33

0.814 (2.918 billion gallons/3.585 billion gallons). This assumes 100-percent use of domestically 

produced B20 fuel for line-haul operations. 

3.2.3 Emissions

The primary measure for this decision driver is how B20 will affect current engine designs under 

EPA’s tier emission levels, specifically, Tier 2 levels shown in Table 10. FRA-funded testing on 

two higher horsepower line-haul locomotive engine (one Tier 2) families is being contracted 

currently with SwRI in San Antonio, TX. This will help further investigate the potential 

emissions performance of biodiesel blends up to B20 on railroad scale engines. 

Although this enhances the knowledge base of the potential impact of biodiesel blends, it is 

noted that the data gathered will not represent the potential impact on the wide variety of other 

locomotive emissions tier levels. This effort represents a small component of the testing 

required to show performance across all engine families (limited by available funding) and is 

limited to emissions testing only (as extended durability testing represents a significant effort on 

a variety of engine families as well).

To date, data on single cylinder four-stroke and older two-stroke roots-blown engines tend to 

demonstrate either decreases or no change in HC, CO, and PM emissions but also have noted 

increases in NOx emissions—a 7- to 8-percent increase in NOx was noted on the four-stroke 

single cylinder engine, and a 5- to 6-percent increase in NOx was noted for the two-stroke 16-

cylinder engine (21).

3.2.4 Safety

In using the NFPA standards as a reference for relative safety consideration between various 

alternative fuels (Section 3.1.3), it is noted that there are no significant differences between the 

measured levels for flammability, health hazard, reactivity, and transport between standard diesel 

fuel and biodiesel blends (B20). 

NFPA will be used as a reference to evaluate other risk factors of other alternative fuel options. 

Needs for ancillary systems (changes to fire protection systems) should be included in not only 

the safety assessment but also the cost and required infrastructure change categories.

3.2.5 Efficiency

The energy content of B20 is approximately 1.7 percent lower than that of petroleum diesel fuel

as shown in Table 10. Although it may be possible to overcome this change in energy content 

mechanically by injecting more material into the cylinder to gain the same engine output power, 

it will have a related impact on decreasing the distance that a train can travel by that amount 

based on the built-in fuel storage capability. It may also have impacts on the refueling 

requirements (volumes handled on any given fueling) and locations of fueling infrastructure.

For the purpose of this study, baseline and comparison values for No. 2 diesel and B20 are 

undefined for gross engine power and BSFC. As mentioned previously, FRA-funded testing on 

two higher horsepower line-haul locomotive engine families is being contracted currently with 

SwRI. In addition to emissions results, both gross engine power and BSFC measure will be 

generated for B20 and No. 2 diesel.
34

Gross engine power is an important measure to determine if the engine can attain its rated 

horsepower at a maximum control setting with a biodiesel blend (B20). The horsepower can be 

limited if the fuel used contains less Btu/gallon. However, depending on the engine control 

system and the ability to control fuel consumption, the engine may be able to produce the rated, 

or near fully rated horsepower by consuming increased amounts of fuel. As a result, the BSFC 

value (measured in either volume or weight of fuel consumed to produce power, lb/hp-h) will 

increase or decrease with the amount of fuel consumed.

If a fuel provides 5 percent less energy per gallon of fuel, for example, with a basic engine 

control system, the engine might produce 5 percent less energy while consuming a “normal” 

amount of fuel, or it could produce up to full rated horsepower while consuming an increased 

amount of fuel. Depending on the control system and the capability of the fueling system, the 

engine could produce a power level somewhat less than the fully rated amount with a somewhat 

increased amount of fuel consumption. Therefore, when conducting fuel comparison testing, it is 

highly necessary to measure both energy output of the engine (horsepower) and simultaneous 

fuel consumption (BSFC) for all fuels tested.

Ultimately, it is recommended that results from a Tier 2-level line-haul locomotive be used in the 

decision model as a baseline for diesel and a comparison case using B20 (as those are most 

common and are sold today). As the emissions standards continue to tighten (i.e., Tier 3 and 

Tier 4), the baseline for these measurements should change accordingly.

The efficiency of low temperature properties is measured by the cloud point and pour point of 

diesel as compared with B20 (see Section 3.1.5). The lower temperature values are the 

benchmarks as they relate to these low-temperature properties for diesel locomotive operations 

shown in Table 10.

A comparison of low temperature values for cloud point and pour point are shown in Table 12. 

The difference in low temperature ranges for diesel and B20 suggest that operational issues may

exist for railroad operations, and further investigation is recommended for cold weather 

operations. Logistics for fueling and locomotive operations are designed exclusively for 

dieselized operations today. 

Table 12. Comparison of Low Temperature Values for Cloud Point and Pour Point

Temperature Degrees Diesel (No. 2) B20 Median

(Diesel/B20)

Cloud Point °C (°F) –35 to 5 (–31 to 41) –16 to –1 (3 to 30) –13/9 (5/17)

Pour Point °C (°F) –35 to –15 (–31 to 5) –17 to –9 (1 to 16) –25/–13 (–15/–9)

Differences in ambient operating conditions such as cold temperature performance of alternative 

fuels and power systems have to be accounted for appropriately for each operational 

environment. For diesel engines, cold temperature performance of the fuel (cloud point, pour 

point) is extremely important and has to be factored into daily operations. 

Negative changes in alternative fuel performance characteristics require changes to normal 

operations and may result in it being unusable in a revenue service environment. Several 

demonstration programs have been conducted that evaluate high-level usage issues related to 

engine wear and cold temperature operations; however, no program reports to date have allowed 

fuels, storage devices, locomotives, and related hardware to be shut down unexpectedly in severe 
35

ambient conditions (which does occur in daily operations). Therefore, the full risks of 

temperature impacts and requirement to get equipment back to operational condition have not 

been fully explored.

Production of Biodiesel

Since the adoption of the Renewable Fuel Standard (RFS2) by EPA in 2010 (32), Federal biofuel 

requirements (rather than state mandates) may be a driver in biodiesel demand. According to a 

statement issued by the National Biodiesel Board (NBB) in January 2008, annual production 

capacity for biodiesel in the United States was 2.24 billion gallons (5). By early to mid-2009, 

production capacity was expected to increase to 3.47 billion gallons. However, current biodiesel 

production capacity utilization in the United States is extremely low. Actual production in 2008 

was 678 million gallons or 30 percent of production capacity. A rapid rise in production occurred 

in 2007 and 2008 (Figure 9), followed by a decline in 2009 as the result of the economic 

recession and a further decline in 2010 to 311 million gallons because of the expiry of the 

blenders tax credit.

250

490

678

506

311

0

100

200

300

400

500

600

700

800

2006 2007 2008 2009 2010

Year

Million US Gallons (MMgal)

Figure 9. U.S. Biodiesel Production

 *(Source: Energy Information Administration)

In 2010, U.S. Class I railroads consumed 3.6 million gallons of diesel in line-haul operations. To 

illustrate the amount of biodiesel required at different blend levels for railroad operations, Figure 

10 was constructed. In 2010, total U.S. production was 311 million gallons, whereas

consumption was 222 or just over 70 percent of production. On the basis of line-haul 

consumption, it would require 701 million gallons of biodiesel by volume to meet the demand 

for B20 at 100-percent utilization of the B20 alternative fuel. Referencing current production 

levels in 2010, this is a difference of approximately 390 million gallons. 

As stated by NBB, by the early to mid-2009, production capacity was expected to increase to 

3.47 billion gallons (5). Therefore, production capacity far exceeds demand and production 

levels at this time. It is important to note that production capacity and availability of resources
36

for production are mutually exclusive production factors. The availability of resources for 

production is not discussed in detail in this report.

Figure 10. Gallons of Biodiesel Required by Blend (Bx)

3.3 B20 Comparison with No. 2 Diesel

Table 13 shows the biodiesel blend B20 compared with No. 2 diesel as an operating scenario to 

demonstrate the proposed decision model approach. The aim is to understand whether the 

proposed decision drivers in the decision model are independently a cost or a benefit to industry 

stakeholders as compared with petroleum diesel locomotive operations. Then, for each decision 

driver provide quantitative and qualitative results and recommendations for their validation. 

Because the use of biodiesel in railroad industry is at an early stage of development, additional 

research and testing for specific decision drivers are recommended.

3,505

1,752

350 175 70

701

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

B2 B5 B10 B20 B50 B100

Biodiesel Blends

US Gallons (Million)
37

Table 13. Decision Model Comparing B20 with No. 2 Diesel

Key Decision Drivers Drivers Diesel (No. 2) Biodiesel (B20) Change (+/-) Cost/Benefit

Cost

Locomotive:

New Purchase $/unit $2,200,000 Undefined Undefined Undefined

Life-Cycle Cost (annual) $/year/unit $280,000 Undefined Undefined Undefined

Fuel:

Production Cost $/DGE $3.95 $4.09 3.5% Cost

Infrastructure:

Fueling Stations $/unit $8,000 Undefined Undefined - Undefined -

Energy Security

Petroleum Products (diesel 

fuel)

gallons/DGE 1 0.814 -0.186% Benefit

Emissions (Tier 2 Linehaul)

Hydrocarbons (HC) g/hp-h 0.30 Undefined Undefined - Undefined

Carbon Monoxide (CO) g/hp-h 1.5 Undefined Undefined - Undefined

Oxides of Nitrogen (NOx) g/hp-h 5.5 Undefined Undefined Undefined

Particulate Matter (PM) g/hp-h 0.20 Undefined Undefined Undefined

Safety (Risks assessment)

Employee exposure [NFPA 

704] 

Flammability NFPA Rating 2 2 No change No change -

Health Hazard NFPA Rating 1 1 No change No change -

Reactivity NFPA Rating 0 0 No change No change -

Efficiency

Energy

Energy Content (fuel) Btu/gallon 129,500 127,250 -1.7% Cost

Gross Engine Horsepower hp/N8 Undefined Undefined Undefined - Undefined -

BSFC lb/hp-h Undefined Undefined Undefined - Undefined -

Temperature (operations) Median: 

Diesel/B20

Cloud Point C Degrees/C (F) –35 to 5 (–31 to 41) –16 to –1 (3 to 30) –13/9 (5/17) Cost

Pour Point Degrees/C (F) –35 to -15 (–31 to 5) –17 to –9 (1 to 16) –25/–13 (–15/–9) Cost
38

3.3.1 Cost

On the basis of the data collected in this study, only fuel production is quantifiable at this time 

and is considered a cost to U.S. railroads. Because of the higher production price and lower 

energy content of B20, it would be a significant cost to the railroad industry. The price of 

biodiesel is consistently higher than No. 2 diesel. By normalizing the B20 price by DGE, there is 

a further separation in cost between diesel and B20. As an illustration of the potential cost 

increase using average retail prices from July 2011 for B20 and fuel consumption (gallons) data 

from 2010, Class I railroads would have paid a premium of 3.5 percent or just over $250 million 

for line-haul operations.

The price of biodiesel is affected by the Federal Excise Tax Credit; without this subsidization,

the retail price to consumers would be even higher than current retail prices. Qualitative 

questions are related to whether biodiesel can be produced in large quantities at a cost that is 

competitive with petroleum diesel prices in the future. This is a direct cost to railroads; therefore,

little can be done by railroads to reduce the price of biodiesel. They must rely on producers and 

distributors of biodiesel to improve the production process to gain cost efficiencies.

Recommendations:

• To understand the potential capital cost (increase or decrease) of acquiring locomotives 

designed to run efficiently on biodiesel, information from durability testing and emission 

testing is required.

• Engine durability testing on Tier 2-compliant line-haul locomotives with blends up to 

B20 is needed to understand the effects on life cycle cost.

• A study is needed to identify the impact of biodiesel blends of up to B20 on current 

fueling infrastructure (capacity, maintenance, and storage).

3.3.2 Energy Security

The use of B20 is considered a benefit in terms of reducing the consumption of petroleum 

products by U.S. railroads. This benefit falls mainly in the area of energy security policies to 

reduce the transportation sector’s reliance on petroleum-based imports and replacement of 

petroleum products with alternative fuels. 

On the basis of the scenario of using B20 in Class I railroad line-haul operations, approximately 

667.5 million gallons of diesel or 0.04 MMbd of petroleum may have been displaced in 2010 

(Section 3.2.1.). This represents approximately 0.23 percent of U.S. consumption or 0.37 percent 

of U.S. imports.

Today, there are no commercial incentives for railroads to reduce diesel consumption as an 

energy source that would offset the potential inefficiencies that may be incurred by using 

replacement energy sources (alternative fuels). 

There is considerable interest in the highest U.S. policy circles to improve energy security (1). 

Therefore, significant resources have been put into assessing the energy security benefits of 

reduced U.S. oil imports. An estimate of the oil import premium based on U.S. Federal proposed 

rules for the on-highway vehicle sector is $13.13 per barrel (2009 dollars).Because the proposed 

rulemaking is evaluating the reduction of petroleum imports through fuel efficiency, it provides 
39

an equitable approach for this study. Calculating the 15.7 million barrels of petroleum by the 

$13.13 per barrel premium yields an estimated benefit of just over $200 million. 

Recommendations:

• A study is recommended to understand the potential sustainability and availability of 

biodiesel at various railroad consumption demand scenarios.

3.3.3 Emissions

This decision driver is undefined with no cost or benefit assessment at this time. It is 

recommended that emissions testing based on EPA-mandated testing protocol be conducted to 

understand and measure the changes that may result in using biodiesel blends (B20) for this 

decision driver. 

On the basis of the upcoming testing by SwRI, the benefits and/or cost will be related to 

emission changes in the four general criteria areas (HC, CO, NOx, and PM) for a selected linehaul engine family as compared with the diesel case.

If testing results yield reductions in any of the criteria areas as compared with the diesel case, 

benefits may be attributable to meeting future tier emission levels. Today, there are no 

commercial incentives for railroads to reduce emission levels below EPA regulatory limits. 

Potential costs may be related to increases in any of the four general criteria areas.

Recommendations:

• FTP emissions testing on a Tier 2 compliant line-haul locomotive. This testing is 

recommended to understand how the four general emissions criteria (HC, CO, NOx, or 

PM) under the Tier 2 emissions levels (g/hp-h) compare with the diesel (test fuel) and

biodiesel blends up to B20.

3.3.4 Safety

As noted in previous sections of this report, there are no significant differences between the 

measured levels for flammability, health hazard, reactivity, and transport between standard diesel 

fuel and biodiesel blends (B20). Therefore, no cost or benefits are assessed for the safety 

decision driver. However, for other alternative fuel and/or motive power design options that may 

be evaluated, NFPA will be used as a reference to the various risk factors but needs for ancillary 

systems (changes to fire protection systems) will need to be included in not only the safety 

assessment but also in the cost and required infrastructure change sections.

3.3.5 Efficiency

The efficiency measures proposed for comparison to B20 under the energy category are energy 

content, gross engine power, and BSFC. The energy content of B20 is approximately 1.7 percent 

lower than that of petroleum diesel fuel; therefore, it is a cost to railroad operations. However, 

gross engine power and BSFC are undefined at this time and are important variables along with 

the energy content variable to access fuel efficiency of locomotives tested with various fuel 

types.
40

Conclusions can be drawn from these variables to estimate changes in efficiency for freight and 

passenger railroads. A key fuel efficiency measure for freight is revenue ton-miles per gallon of 

diesel consumed, whereas passenger fuel efficiency can be measured by passenger ton-miles per 

gallon of diesel consumed. Since 1965, freight fuel efficiency has increased nearly 150 percent to 

484 revenue ton-miles per gallon of diesel for Class I railroads.

Recommendations:

• FTP emissions testing on Tier 2-compliant line-haul locomotives with biodiesel blends of 

up to B20. Under the recommended emissions testing for the emissions decision driver, 

both gross engine power and BSFC results should be measured as part of this test. The 

information from these variables may be used to evaluate fuel efficiency changes 

between diesel and biodiesel (B20).

The efficiency measures under the temperature category consist of the cloud point and pour 

point. These measures show significant differences in temperature ranges between diesel and 

biodiesel (B20). Therefore, it is considered a cost in terms of potential operational changes to 

railroad for fuel storage and distribution.

Several demonstration programs have been conducted that evaluate high-level issues related to 

engine wear and cold temperature operations. From November 2009 to March 2010, four GE 

AC4400CW diesel-electric locomotives were held in captive service on Canadian Pacific’s 

mainline between Calgary and Edmonton. The primary focus of the study was to assess the 

feasibility of using up to a maximum of 5-percent (B5) biodiesel blend in freight locomotives 

operating in cold weather service.

Although the test successfully demonstrated the viability of B5 biodiesel use in cold weather 

freight rail service, there are renewable fuel supply chain issues to address. These issues were 

identified in the test and include the availability of biodiesel and distribution infrastructure, the 

limited number of vendors, quality control, and the availability of appropriate blends.

Although demonstration programs have been conducted that evaluate high-level issues related to 

engine wear and cold temperature operations, no program reports to date have allowed 

fuels/storage devices/locomotives and related hardware to be shut down unexpectedly in severe 

ambient conditions (which does occur in daily operations). Therefore, the full risks of 

temperature impacts and requirements to get equipment back to operational condition have not 

been fully explored.

Recommendations:

• Low-temperature operations testing on Tier 2-compliant line-haul locomotives with 

blends of up to B20 to understand technical issues and potential cost

• Low-temperature testing on fuel storage infrastructure and distribution systems with 

blends of up to B20 to understand technical issues related to operational efficiencies and 

potential cost

3.3.6 Cost and Benefit Results

For the B20 scenario, only fuel production under the cost decision driver and petroleum products

under the energy security decision driver are independently quantified as shown in Table 13. 

Energy content under the efficiency decision driver is quantified but requires additional variables 
41

(gross engine power and BSFC) to draw conclusions related to fuel efficiency. The cloud point

and pour point under the efficiency decision driver are generally considered a cost but require 

additional research to quantify as a measured cost.

It is estimated that Class I railroads would have paid a premium of 3.5 percent or just over $250 

million for line-haul operations in 2010. As a measure of this relative purchasing power, over 

100 new line-haul locomotives could be acquired ($2.2 million per unit).

Class I railroad line-haul operations would have displaced approximately 667.5 million gallons 

of diesel, or 0.04 MMbd of petroleum based products in 2010, as shown in Section 3.2.1. This 

represents approximately 0.23 percent of U.S. consumption or 0.37 percent of U.S. imports in 

2010. 

An estimate of the oil import premium based on U.S. Federal proposed rules for the on-highway 

vehicle sector is $13.13 per barrel (2009 dollars) (2). Calculating the 15.7 million barrels of 

petroleum by the $13.13 per barrel premium yield an estimated benefit of just over $200 million. 

3.3.7 Decision Matrix Approach 

In the case of alternative fuels, a decision matrix is recommended to support the decision driver 

analysis component. This can be a powerful tool to help support the decisionmaking process for 

selecting the best technologies for further development. Under the framework for the decision 

model, this is a proposed component for the decisionmaking process.

Development of the decision matrix relies on the quantitative (CBA) and qualitative (interview 

process and literature search) information developed for each proposed alternative. This tool is 

designed to be used for making decisions between new alternatives being evaluated. For 

instance, if the new alternatives being considered for further research and testing are biofuels 

(biodiesel) and natural gas (LNG), this tool can help support the process of selecting the most 

valued alternative by stakeholder. 

3.3.8 Decision Matrix Attributes

This decision matrix relies on stakeholder inputs to draw conclusions on selecting the best 

alternatives. Therefore, U.S. railroads, OEMs, and FRA inputs are recommended for proposed 

alternative fuels and/or motive power technologies. Three steps are used to develop results: (1) 

rank the decision drivers with weights, (2) rank the proposed alternatives by decision driver 

score, and (3) calculate the weighted scores for each alternative (highest scores represent the 

higher valued alternatives). It can be used for multiple stakeholders or within stakeholders 

groups. To illustrate the functionality of the decision matrix, an example with two stakeholders 

and two alternatives are provided.

Step 1: Rank decision drivers (weights)

Generally (independent of any specific alternative), each decision driver must be ranked from 1

to 100 (with a maximum weight of 100) when considering the potential use of alternative fuels 

and/or motive power designs for railroad locomotive operations (Table 14). These weights will 

remain a constant variable independent of the alternatives being considered for evaluation.
42

Table 14. Matrix to Rank Decision Drivers with Weights

Decision Driver: Weights (1–100)

Decision Drivers Stakeholder 1 Stakeholder 2 Weights

Cost 20 20 40

Energy security 20 20 40

Emissions 20 20 40

Safety 20 20 40

Efficiency 20 20 40

100 100 200

Step 2: Rank decision driver alternatives (scores)

For each alternative being considered, determine what score (1 = worst, 10 = best) represents the 

importance or value of each decision driver in relation to the alternative proposed.

Table 15 illustrates two alternatives ranked by score (although multiple alternatives may be 

evaluated).

Table 15. Matrix to Rank Proposed Alternatives by Decision Driver Scores

Alternative 1

Decision Driver: Scores (1–10)

Decision Drivers Stakeholder 1 Stakeholder 2 Scores

Cost 5 5 10

Energy security 5 5 10

Emissions 5 5 10

Safety 5 5 10

Efficiency 5 5 10

Alternative 2

Decision Driver: Scores (1–10)

Decision Drivers Stakeholder 1 Stakeholder 2 Scores

Cost 5 5 10

Energy security 5 5 10

Emissions 5 5 10

Safety 5 5 10

Efficiency 5 5 10
43

Step 3: Calculating the weighted scores

The weights for each decision driver in step 1 are constant variables that are multiplied by the 

scores for each alternative in step 2. This calculation produces a weight score for each decision 

driver and a total weighted score (Table 16).

Table 16. Matrix to Calculate the Weighted Scores for Each Alternative

Decision Driver: Weighted Scores

Alternatives Cost

Energy 

security Emissions Safety Efficiency Total 

Alternative 1 400 400 400 400 400 2,000

Alternative 2 400 400 400 400 400 2,000
44

4. Conclusions

The framework for a decision model with a cost-benefit component was developed to guide

industry stakeholders as they evaluate the feasibility of alternatives to diesel fuel and diesel 

locomotive technology. The primary stakeholders proposed to further develop the decision 

model are government, railroads, and manufacturers of locomotives in the United States.

Because of the mature nature of diesel locomotive technology for freight and passenger railway 

operations and its fueling infrastructure, no alternative fuels or motive power designs that 

differentiate from current diesel technology can be cost justified from the research conducted in 

this study. However, comparisons among selected alternative fuels are suggested under this 

decision framework approach to evaluate potential alternatives. Cooperation between industry 

stakeholders is vital to the success of evaluating alternatives for future consideration.

Energy security policies developed by DOE and emission standards set forth by EPA are driving 

most of the technology initiatives related to alternative fuels today. The main objective of the 

decision model recommended in this study was to identify alternatives that may provide benefits 

in the areas of emissions and energy security in relation to their potential cost, safety, and 

operating efficiencies. 

For the B20 scenario illustrated in this study, it is estimated that Class I railroads would have 

paid a premium of 3.5 percent or just over $250 million for line-haul operations in 2010. Class I 

railroad line-haul operations would have displaced approximately 667.5 million gallons of diesel, 

or 0.04 MMbd of petroleum equivalents. The oil import premium (estimating the cost of U.S. 

imports) is $13.13 per barrel, which yields a societal benefit of just over $200 million. 

To populate the remaining inputs for the other decision driver criteria for the B20 comparison 

case in this study, recommended research and testing for cost (locomotive durability testing and 

a fueling infrastructure study), energy security (availability and sustainability study), emissions 

(laboratory tier level emissions testing), and efficiency (fuel consumption and cold temperature 

testing operations) are recommended to further develop the decision model case for B20. FRA, 

railroads, and OEMs are currently addressing some of these important issues. 

Future alternative fuels will be selected based on cost and applicability and will be balanced with 

the ability to meet efficiency and emissions requirements. Although the main alternative energy 

options include natural gas, coal, and biomass, the form of their utilization remains to a large 

degree uncertain for the railway industry. 

The fuel supply infrastructure will be an important factor in choosing future fuel options. The 

existing infrastructure is capable of handling liquid hydrocarbon fuels including diesel and 

gasoline. A number of important alternative fuel options include diesel-like liquids composed 

mostly of paraffinic hydrocarbons. Fuels in this category include Fischer-Tropsch (FT) synthetic 

diesel made of natural gas (gas-to-liquid (GTL)), coal (coal-to-liquid (CTL)), or renewable diesel 

made by hydrogenation of vegetable oils (used mainly in blends of diesel and biodiesel).

Although some of these blends will meet the ASTM D975 standard, engine issues are always 

possible when changes are introduced to the fuel composition. Some negative characteristics 

shared by paraffinic fuels often include poor lubricity and poor low temperature operability. At 

this time, there are no published studies on the operation of locomotive engines with synthetic 
45

diesel fuel. Research is necessary to determine the compatibility of locomotive engines with 

synthetic diesel, its impact on the fuel system, engine wear and durability, emission levels, as 

well as cold weather performance.

Other alternative fuel options exist, supported by government policies or by various groups of 

interests that are not compatible with the existing infrastructure, include hydrogen (as a longterm fuel option for light vehicles) and natural gas. Because the development of an additional 

fuel infrastructure would involve a substantial cost to society, it would have to be well justified. 

Because of the initiatives currently under investigation in Europe, as they relate to the uses of 

biofuels, and the conclusions from RSSB that improved diesel fuels were among the most 

suitable for rail from other potential fuel sources, an overview of information as it relates to 

biofuels were included in this report. According to the RSSB report, biofuels have the potential 

to reduce GHG emissions, which contribute to climate change. The use of biofuels can 

potentially increase energy security, reducing a country’s reliance on imported energy products.
46

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8.0.1.1.2;idno=40;cc=ecfr

31. U. S. Code of Federal Regulations. 2011. CFR Title 40: Protection of Environment, Part 

1065—Engine Testing Procedures. Washington, D.C. http://www.ecfr.gov/cgi-bin/textidx?sid=694d902c88ce2521aa19ca25a747a11a&c=ecfr&tpl=/ecfrbrowse/Title40/40cfrv33

_02.tpl

32. U. S. Environmental Protection Agency. 2010. Renewable Fuel Standard. Washington, 

D.C., http://www.epa.gov/otaq/fuels/renewablefuels/index.htm
49

Appendix A. Overview of Alternative Fuels and Motive Power 

Technologies

This section contains material from the Association of American Railroads Research Report R999, Alternative Fuels Availability, Make-up, and Potential Impact on Locomotive Engines

(Majewski et al., 2011). A number of important alternative fuel options include diesel-like 

liquids composed mostly of paraffinic HCs. Fuels in this category include FT synthetic diesel 

made of natural gas (GTL) or coal (CTL), or renewable diesel made by hydrogenation of 

vegetable oils. Although properties will vary depending on the particular production process, all 

of these fuels show similarities and have potentially attractive properties. They are unlikely to be 

used in the pure form, but they will be used as blending stock to improve properties of 

conventional No. 2 diesel.

Although the blends will meet the ASTM D975 standard, engine issues are always possible when 

changes are introduced to the fuel composition. Some negative characteristics shared by 

paraffinic fuels often include poor lubricity and poor low temperature operability. At this time, 

there are no published studies on the operation of locomotive engines with synthetic diesel fuel. 

Research is necessary to determine the compatibility of locomotive engines with synthetic diesel, 

its impact on the fuel system, engine wear/durability, emission levels, as well as cold weather 

performance.

The role of biodiesel has been increasing, currently driven by the Federal RFS (RFS2). Under the 

ASTM D975 standard, up to 5-percent biodiesel can be blended into No. 2 diesel without 

disclosing it to the customer. It is important that the railroad industry ensures that locomotives 

can be operated with at least B5 blends. To date, testing biodiesel blends in medium-speed diesel 

engines in North America has been limited to a small number of studies. The data available 

suggests that biodiesel impacts on medium-speed engines may not necessarily mirror those in 

high-speed diesel engines surveyed by EPA in 2002. The following additional work is needed to:

• Quantify the effect on emissions and performance on EPA-regulated Tiers 0, 1, and 2 

locomotives (The effects on NOx emissions of Tiers 1 and 2 locomotives are a real 

concern because even a small increase in NOx from these engines may cause emissions to 

exceed the certification limit.)

• Quantify the effects on combustion and FIE system behavior

• Characterize the cold weather performance

Manufacturers of high-speed diesel engines for on-road and off-road applications have expressed 

a number of concerns about the long-term impact of biodiesel on the FIE system, aftertreatment 

devices, and the lubricating oil. Some of the issues pertinent to the locomotive application are as 

follows:

• Impact on the long-term performance of the FIE system and the ability of the locomotive 

to maintain emission levels

• Effect on aftertreatment devices that may see use in Tier 4 locomotives

• Compatibility with the current lubricating oil specifications
50

Feedstock is another source of uncertainty with biodiesel fuels. Although most of U.S. biodiesel 

is made from soybeans, some of the larger scale biodiesel plants can process the more costeffective imported palm oil feedstock. Palm oil biodiesel has poorer low temperature operability 

properties than most other biodiesels. In the future, biodiesel can also be made from algae, with a 

yet unknown impact for its fuel properties.

Considering the need for a new fuel infrastructure, a wide-scale introduction of LNG as 

locomotive fuel remains unlikely. However, niche markets for LNG/compressed natural gas 

(CNG)/liquefied petroleum gas (LPG) locomotives, as well as political pressures to switch to 

gaseous fuels, will persist in areas with air quality problems such as California or Texas. These 

pressures will likely diminish after 2015 once EPA Tier 4 locomotives with exhaust 

aftertreatment technologies are launched.

DME can be manufactured from coal via gasification and synthetic gas. Although in North 

America the alternate route of coal utilization—FT synthetic diesel—seems to be gaining 

momentum, DME can still play a role. Significant interest in DME as automotive fuel exists in 

China, Japan, as well as in Europe.

DME, although compatible with diesel combustion, is a gaseous fuel that requires a dedicated 

FIE system. It also has insufficient lubricity and requires lubricity additives. A wide-scale 

research program with the participation of railroads, engine manufacturers, emission labs, DME 

fuel suppliers, and other stakeholders would be necessary to demonstrate the feasibility of DME 

as locomotive fuel.

Energy recovery technologies can provide considerable reductions in fuel consumption and GHG 

emissions. The most market-ready energy recovery technology is the hybrid locomotive. The 

most significant research issues in hybrid locomotives are related to the high energy storage 

requirements and an efficient and cost-effective battery technology.

Flywheel energy storage is another technology that appears to be compatible with the railroad 

application, but it requires further research to make it practical.

Some energy recovery technologies, for instance thermoelectric, may warrant interest from the 

railroad industry provided more progress is achieved in the highway diesel engine applications.

A.1 Regulations

With ultralow emission requirements adopted for nearly all categories of diesel engines, future 

environmental priorities are gradually shifting from exhaust emissions to GHG emissions and 

energy supply and security. One of the reasons for the shift in focus toward energy supply is the 

depletion of oil resources. There are indications that the production capacity of conventional oil 

resources is likely to decline already in the 2010–2020 timeframe. This will drive the use of 

unconventional oil resources, alternative fuels—notably natural gas, the worldwide resources of 

which increased significantly with the development of shale gas extraction technologies—as 

well as increased energy efficiency.

Following the changes in environmental priorities and energy supply and security, governments 

worldwide have been adopting new regulations that affect fuels and engine/vehicle technologies, 

including:
51

● Renewable fuels/biofuels regulations—These are designed to gradually increase the 

consumption of renewable fuels in the total fuel mix on the market. One of the 

approaches is to legislate a minimum volume or percentage of renewables that must be 

blended into petroleum fuels. The regulations include life-cycle GHG emissions/carbon 

intensity criteria that must be met by fuels to earn the “renewable” designation. 

Alternative approaches exist, such as “carbon taxes” designed to provide financial 

incentives for increased usage of renewable fuels and/or disincentives for petroleum 

fuels.

● GHG emission and fuel economy regulations—These require increased efficiency of the 

engine and the powertrain, as well as the efficiency of the entire vehicle. Future 

regulations may also seek fuel consumption reductions through changes in vehicle 

operation patterns.

United States. Under the 2005 EPAct, EPA adopted the RFS, which required blending certain 

volumes of ethanol into gasoline. Under the Energy Independence and Security Act of 2007 (14), 

the RFS program was expanded in several ways, including the addition of renewable diesel fuel 

requirements. The expanded legislation, finalized by the EPA in 2010, is often referred to as the 

RFS2 standard.

For the first time, some renewable fuels must achieve life-cycle GHG emission reductions—

compared with the gasoline and diesel fuels they displace—to be counted toward compliance 

with volume standards. The RFS2 volume requirements are set for the following four categories 

of fuels:

● Cellulosic biofuel—to be classified in this category, fuels must provide a 60-percent lifecycle GHG emission reduction.

● Biomass-based diesel—a 50-percent GHG emission reduction.

● Advanced biofuel—a 50-percent GHG emission reduction.

● Total renewable fuel—the remaining renewable fuel volumes must provide a 20-percent 

GHG emission reduction if produced at new facilities (initial construction after December 

19, 2007).

The GHG emissions are determined by EPA as the aggregate quantity of GHG emissions—

including direct emissions and significant indirect emissions such as emissions from land use 

changes. The emission reductions are relative to the 2005 petroleum fuel baseline. 

In the final rulemaking, EPA relaxed its GHG estimates for a number of conventional biofuels 

that are now meeting the RFS2 requirements but were to be disqualified under the RFS2 

proposal. In particular, EPA determined that biodiesel and renewable diesel from soy oil or waste 

oils, fats, and greases will meet the 50-percent GHG threshold for biomass-based diesel. 

Biodiesel and renewable diesel produced from algae oils will also comply with the 50-percent 

threshold should they reach commercial production.

The RFS2 requires biofuels production to grow from the 2009 level of 11.1 billion gallons to 36 

billion gallons in 2022, with 21 billion gallons to come from advanced biofuels. Table A1 lists 

the exact fuel volume requirements.
52

Table A1. RFS2 Renewable Fuel Volume Requirements, billion gallons

Year Cellulosic 

Biofuel

Biomass-Based 

Diesel

Advanced 

Biofuel

Total 

Renewable 

Fuel

2008 n/a n/a n/a 9.0

2009 n/a 0.5 0.6 11.1

2010 0.1 0.65 0.95 12.95

2011 0.25 0.80 1.35 13.95

2012 0.5 1.0 2.0 15.2

2013 1.0 A 2.75 16.55

2014 1.75 A 3.75 18.15

2015 3.0 A 5.5 20.5

2016 4.25 A 7.25 22.25

2017 5.5 A 9.0 24.0

2018 7.0 A 11.0 26.0

2019 8.5 A 13.0 28.0

2020 10.5 A 15.0 30.0

2021 13.5 A 18.0 33.0

2022 16.0 A 21.0 36.0

2023+ B B B B

A - To be determined by EPA through a future rulemaking, but no less than 1.0 

billion gallons.

B - To be determined by EPA through a future rulemaking. 

The minimum volumes of biomass-based diesel after 2012 must be 1 billion gallons or more, to 

be determined by EPA. NBB has called to increase the volume requirements to 1.3 billion 

gallons in 2013, 1.6 billion in 2014, and 1.9 billion in 2015 (5). EPA proposed the biomass-based 

diesel volume to 1.28 billion gallons in 2013.

Every year, EPA develops percentage-based standards for the particular renewable fuel 

categories to be met during the following year. Table A2 lists the 2011 requirements.
53

Table A2. 2011 RFS2 Fuel Volumes and Percentage Standards

Category Volume Percentage

Actual Ethanol Equivalent Standard†

Cellulosic biofuels 6.6 million gallons 6.0 million gallons 0.003%

Biomass-based diesel 0.80 billion gallons 1.20 billion gallons 0.69%

Advanced biofuels 1.35 billion gallons 1.35 billion gallons 0.77%

Total renewable fuels 13.95 billion gallons 13.95 billion gallons 8.01%

† Percentage standards are based on ethanol-equivalent volumes, not actual volumes. The ethanolequivalent volume is determined from the volumetric energy content of a biofuel in comparison to the 

volumetric energy content of denatured ethanol.

Fuel Economy/GHG Emission Regulations: EPA and U.S. DOT have been developing a number 

of fuel economy and GHG emission regulations for highway vehicles:

● Fuel economy (Corporate Average Fuel Economy (CAFE)) and GHG standards for 

model year 2012–2016 light-duty vehicles—the regulation is expected to result in an 

average MY 2016 vehicle emission level of 250 g CO2/mile and 34.1 mpg (6.9 liters/100 

kilometers (km)) CAFÉ fuel economy. Status: final rule.

● Fuel economy (CAFÉ) and GHG standards for model year 2017–2025 light-duty 

vehicles—four scenarios were suggested, with annual CO2 emission reductions from 3 to 

6 percent. The most extreme scenario (6 percent reduction per year) calls for an average 

CAFÉ fuel economy of 62 mpg by 2025. Status: Notice of Intent.

● Fuel economy and GHG emission standards for medium- and heavy-duty trucks—the 

regulation would be phased-in from 2014 to 2018, to bring fuel economy improvements 

between 7 and 20 percent, depending on vehicle category. Status: proposed rule.

Although off-road engines and vehicles could potentially become a subject of GHG emission 

regulations, the EPA is currently not developing such legislation.

Canada. In September 2010, Canada finalized its Federal Renewable Fuels Regulations, which 

require gasoline producers and importers to have an annual average renewable fuel content of at 

least 5 percent based on the volume of gasoline produced and imported. The 5-percent 

requirement became effective December 15, 2010.

For diesel fuels, Canada’s Renewable Fuels Regulations require an average 2-percent renewable 

fuel content in diesel fuel and heating distillate oil, effective July 1, 2011. The technical 

feasibility of the 2-percent requirement was assessed, based on the results of the National 

Renewable Diesel Demonstration Initiative (NRC, 2010).

The Renewable Fuels Regulations support Canada’s commitment to reduce its total GHG

emissions by 17 percent from 2005 levels by 2020. The Regulations are estimated to result in an 

incremental reduction of GHG emissions of about 1 MT carbon dioxide equivalent per year.

Current biodiesel production in Canada is about 200 million liters (52 million gallons) annually. 

To meet the 2-percent renewable fuel mandate, about 550 million liters (145 million gallons) of 

renewable diesel will be required.
54

GHG Regulations: Emission regulations for locomotives that are being developed by Transport 

Canada will include emission standards for criteria air pollutants as well as limits on GHG 

emissions. The final regulations are expected to be effective in 2011.

European Union (EU). Two EU directives were adopted that mandate the use of biofuels in the 

transportation sector:

● Directive 2003/30/EC of May 8, 2003, established the goal of reaching a 5.75 percent 

share of renewable energy in the transportation sector by 2010.

● Directive 2009/28/EC of April 23, 2009, referred to as the new directive on the 

promotion of renewable energy, increased this mandate to a minimum of 10 percent in 

every member state in 2020. 

The new renewable energy directive supports the European “20-20-20 goal,” driven by climate 

change and energy security, which aims to reduce consumption of primary energy by 20 percent 

by 2020. Under the directive, each member state has a target calculated according to the share of 

energy from renewable sources in its gross final consumption for 2020. Moreover, the share of 

energy from renewable sources in the transportation sector must amount to at least 10 percent of 

final energy consumption in the sector by 2020. The renewable energy targets apply to the total 

of all forms of energy used in transportation—this includes not only biofuels for internal 

combustion engines but also electrical energy used in the transportation sector, for example.

The directive encompasses energy from biofuels and bioliquids, which should contribute to a 

reduction of at least 35 percent of GHG emissions to be taken into account. From January 1, 

2017, their GHG emission savings should be increased to 50 percent. On June 10, 2010, the 

European Commission adopted a regulatory package to encourage industries, governments, and 

nongovernment organizations to set up certification schemes for all types of biofuels, including 

those imported into the EU. The package focuses on the sustainability criteria for biofuels and 

what is to be done to ensure that only sustainable biofuels are used. 

CO2 Emission Regulations: EU has adopted CO2 emission standards for light-duty vehicles. A 

fleet average CO2 emission target of 130 grams/kilometer (g/km) must be reached by each 

vehicle manufacturer by 2015 using vehicle technology. To meet the EU CO2 emission target of 

120 g/km, a further emission reduction of 10 g/km is to be provided by additional measures, such 

as the use of biofuels.

CO2 emission regulation for light commercial vehicles (such as vans) is in the final stages of 

development. The EU authorities also intend to develop CO2 emission requirements for heavyduty highway vehicles, but the development of the regulation is still at an early stage.

The EU has not been developing CO2/GHG emission regulations for off-road engines or 

vehicles, and it has not announced an intention to develop such legislation.
55

A.2 Alternative Diesel Fuels

As the conventional crude oil resources become depleted, alternative energy resources will 

increasingly replace them, which may include the following:

● Unconventional crude resources—Deep sea, oil sands, oil shale.

● Natural gas—From a resource perspective, natural gas remains the most abundant energy 

source. According to the International Energy Agency (IEA), global use of gas may rise 

by more than 50 percent from 2010 levels and account for more than 15 percent of global 

energy demand by 2035 (IEA 2011). In the early 2000s, worldwide reserves of natural 

gas were estimated at 140,000 billion cubic meters (bcm), whereas annual global 

consumption was only 2,100 bcm (Clark, 2002). In recent years, shale gas production 

methods have been commercialized, contributing to a rapid growth of natural gas 

production and causing an increase in gas resources. Adding identified shale gas 

resources to current estimates of other gas resources would increase the total world’s 

technically recoverable resources by over 40 percent (EIA, 2011). The most efficient 

utilization of natural gas remains an important open issue. Natural gas could be used 

directly or converted to liquid (FT diesel, methanol) or gaseous (DME, hydrogen) fuels.

● Coal—Although coal is not particularly usable as a transportation fuel in its solid form, 

transportation fuels that may be produced from coal include CTL synthetic diesel as well 

as DME.

● Biomass—Renewable biofuels are believed by many to be the ultimate solution to the 

problems of GHG emissions and the depleting fossil fuel resources. However, an 

uncertainty exists about the energy balance and the sustainability of the so-called first

generation biofuels (i.e., fuels made from agricultural feedstocks that compete with food 

resources (examples include corn ethanol and soy biodiesel)). Second-generation biofuels 

should be developed and commercialized, which could be produced in a sustainable 

manner. Examples of prospective future renewable fuels include biodiesel made of algae, 

cellulosic ethanol from wood, synthetic FT diesel, or DME made from synthesis gas 

obtained via biomass gasification.

Table A3 lists selected alternative fuel options for the transportation industry.
56

Table A3. Alternative Fuel Options

Alternative 

Fuels

Diesel Engine 

Compatibility Specifications Status

Biodiesel/

Renewable 

Diesel

May be used in existing 

engines, fuel stability, low 

temperature operability 

issues, increased filter 

replacement?

Fuel Storage issues?

Requires separate 

specifications for blends 

higher than 5% (B5) Existing 

ASTM standards cover 

blends up to B20

Meets ASTM D975

B2 – Canada 

B5 – Standard

B20 – Experimental

Synthetic Diesel 

Fuel Compatible Assume it meets ASTM D975 Experimental

Natural Gas

Not compatible: requires 

dedicated fuel and 

ignition/storage systems

Dedicated fuel specifications 

exist

Road –

demonstration 

Switcher – in-use

Propane

Not compatible: requires 

dedicated fuel and ignition 

systems

Dedicated fuel specifications 

exist

Not being 

considered 

Dimethyl Ether

Compatible with 

compression-ignition, but 

requires a dedicated fuel 

system, Engine 

modifications similar to 

LPG

Specifications as automotive 

fuel not yet adopted Experimental

Coal Slurry Fuels

Requires dedicated fuel 

system 

Major issues in engine wear

No specifications exist Experimental

Ethanol-Water 

Blends

Issues exist if used in 

existing engines No specifications exist Experimental

Hydrogen

Not compatible: envisioned 

for use in fuel cell or H2 

internal combustion engines

No specifications exist

Experimental 

Switcher –

Demonstration

A.3 Advanced Motive Power Technologies

As outlined in Table A3, many of the alternative fuel options are not fully compatible with 

existing engines and/or with the existing distribution infrastructure for liquid, HC-based engine 

fuels. Thus, the reduction of GHG emissions through the use of alternative fuels may require a 

significant investment not only in the production of the fuel but also in new engine technology 

and/or fuel infrastructure, which necessitates a long timeframe. In contrast, GHG reductions 

through increased engine efficiency may be realized in a shorter term while bringing a monetary 

benefit to the customer as the result of the reduced fuel consumption (Ryan, 2008).

New combustion modes are also being developed to reduce pollutant emissions. A significant 

amount of research is being conducted by highway engine manufacturers to develop various 

premixed diesel combustion modes, such as premixed charge compression ignition (PCCI) and 
57

low temperature combustion (LTC). These premixed combustion modes can provide ultralow 

NOx emissions as well as reduced PM, usually at the expense of increased carbon 

monoxide/hydrocarbons (CO/HC). One of the major issues is combustion control, especially at 

higher engine loads. “Mixed-mode” engines are envisioned (Stanton, 2008) that would operate in 

premixed combustion modes at low load and in the conventional diesel combustion mode at high 

load. 

Fuel economy presents another challenge in advanced combustion research. Although future 

NOx emission standards seem to be possible to meet through advanced combustion alone, 

without NOx aftertreatment, this approach may involve a fuel economy and GHG emission 

penalty. A division has formed between highway engine manufacturers, with some companies 

integrating urea selective catalytic reduction (SCR) aftertreatment into their engines, and others 

attempting to ultimately meet future emission standards without NOx aftertreatment. Section 

A.12 presents more discussion on the advanced combustion research pertaining to locomotive 

engines.

Another important direction of research is improved energy efficiency through energy recovery 

in the diesel engine or in the vehicle. Figure A1 illustrates the heat balance of a 1998 model year 

heavy-duty truck diesel engine operating at its most efficient operating point (Eckerle, 2007). 

Only 43.5 percent of the chemical energy contained in the fuel is converted into mechanical 

work.

Figure A1. Energy Balance in 1998 HD Truck Engine

As the chart shows, the largest source of thermal efficiency loss is the heat dissipated from the 

engine (20 percent) and the heat expelled with the exhaust (30 percent). A number of 

technologies are being developed that could capture that energy and increase the engine 

efficiency. U.S. DOE-sponsored research is targeting a 55-percent thermal efficiency in heavyduty diesel engines by 2015. 
58

In addition to increased engine efficiency, further energy and fuel savings are possible through 

vehicle technology. For example, hybrid powertrains commonly recover some of the energy 

normally lost during vehicle braking.

A.4 Biodiesel

Although a wide variety of materials could potentially carry the label “biodiesel” in that they are 

biologically derived fuels that can be used in diesel engines, the label is generally applied to a 

specific class of compounds. In the United States, the ASTM Biodiesel Task Force adopted a 

definition of biodiesel that limits it to “mono alkyl esters of long chain fatty acids derived from 

renewable lipid feedstocks, such as vegetable oils and animal fats, for use in compression 

ignition (diesel) engines” (Howell, 1997). The most common alcohol used in the production of 

mono alkyl esters is methanol, and the more specific label “methyl ester” is often attached to this 

type of esterified biodiesel. The mono alkyl ester definition eliminates pure vegetable oils as well 

as monoglycerides and diglycerides from consideration as biodiesel. This review will limit the 

term biodiesel to mono alkyl ester fuels.

Note that considerable variation in the definition of biodiesel exists both in North America and 

worldwide. The term biodiesel may occasionally refer to diesel-like fuels other than alkyl esters. 

For several years, the term biodiesel was used to describe HC-based fuels manufactured through 

hydrogenation of fats or vegetable oils—an increasingly more important type of biofuel. For 

various reasons, the use of the term biodiesel to describe HC fuels produced by hydrotreating oils 

at a refinery has fallen out of favor, and these fuels are commonly referred to as renewable diesel 

fuels. 

Biodiesel is rarely used in its neat form but is commonly blended with diesel fuel. The resulting 

blend is commonly referred to as Bx where x is a numerical value representing the volume 

percentage of biodiesel in the final fuel blend. For example, B2, B5, and B20 are common blend 

levels and denote a blend of 2-, 5-, and 20-percent biodiesel by volume, respectively, in 

petroleum diesel fuels. B5 is the highest blend level approved by almost all manufacturers of 

high-speed diesel engines. Under the ASTM D975 standard, up to 5-percent biodiesel content is 

allowed in commercial diesel fuel. Some engine manufacturers allow higher level blends. B20 is 

the minimum blend level eligible for EPAct credits. B100 refers to 100-percent (or “neat”) 

biodiesel.

A.4.1 Properties and Specifications

ASTM Specifications

In the United States, ASTM D6751 defines the properties of biodiesel blending stock to be used 

in blends with diesel fuel up to a blend level of B20. Table A4 shows the technical requirements 

of ASTM D6751-07b.
59

Table A4. Technical Requirements of ASTM D6751-07b

Property Test Method Limits Units Min. Max.

Alcohol control either:

Flash point or

Methanol

ASTM D93 130 °C

EN 14110 0.2 % vol.

Flash point ASTM D93 93 °C

Kinematic viscosity 

@40 °C ASTM D445 1.9 6.0 mm2

/s

Sulfated ash ASTM D874 0.02 % mass

Sulfur:

S15

S500

ASTM D5453 0.0015 % mass

ASTM D5453 0.05 % mass

Copper corrosion ASTM D130 No. 3

Cetane number ASTM D613 47

Cloud point ASTM D2500 Report °C

Carbon residue ASTM D4530 0.05 % mass

Acid number ASTM D664 0.50 mg KOH/g

Free glycerin ASTM D6854 0.020 % mass

Total glycerin ASTM D6854 0.240 % mass

Distillation, 90% ASTM D1160 360 °C

Water and sediment ASTM D2709 0.05 % vol.

P ASTM D4951 0.001 % mass

Ca + Mg EN 14538 5 μg/g

Na + K EN 14538 5 μg/g

Oxidation stability EN 14112 3 Hours

Visual appearance ASTM D4176 Free of undissolved water, 

sediment, and suspended matter

In 2008, the ASTM adopted standards for biodiesel blends. Blends of B5 or less were 

incorporated into the diesel fuel standard, ASTM D975. Up to 5-percent biodiesel can be blended 

into No. 1 or No. 2 diesel fuel so long as:

• the biodiesel component meets the requirements of ASTM D6751, and

• the final blend meets the requirements of D975.

Labeling of the finished blend is not required; therefore, it may not be possible for the purchaser 

to know whether the fuel contains biodiesel unless an analysis is carried out.

B6–B20 blends are covered by a stand-alone ASTM specification D7467, as Table A5 shows.
60

Table A5. ASTM D7467 Standard for B6–B20 Blends

Property Test Method Limits Units Min. Max.

Biodiesel content ASTM D7371 6 20 % vol.

Flash point ASTM D93 52 °C

Kinematic viscosity

@40 °C ASTM D445 1.9 4.1 mm2

/s

Ash ASTM D482 0.01 % mass

Sulfur:

S15

S500

S5000

ASTM D5453

ASTM D2622

15 μg/g 

0.05 % mass

0.5 % mass

Copper corrosion ASTM D130 No. 3

Cetane number ASTM D613 41

Cloud point ASTM D2500 Report °C

Carbon residue, 10% 

bottom ASTM D524 0.35 % mass

Acid number ASTM D664 0.3 mg KOH/g

Distillation, 90% ASTM D86 343 °C

Water and sediment ASTM D2709 0.05 % vol.

Lubricity, HFRR @ 60 °C ASTM D6079 520 μm

Cetane index or

Aromaticity

ASTM D976-80 40

ASTM D1319-03 35 % vol.

Oxidation stability EN 14112 6 Hours

Major Standards Development Issues

In the winter of 2005–2006, the first winter after Minnesota’s B2 mandate came into existence, 

there were widespread filter plugging problems across the State (Zeman, 2006). Although a large 

number of these problems occurred with fuel blends when the biodiesel component did not meet 

the requirements of ASTM D6751, this was not the case for all these problems. A number of 

problems were encountered with biodiesel that was entirely in compliance with the existing 

standard. In these cases, filter plugging problems occurred at temperatures above the cloud point 

of the fuel. Clearly, the existing parameters used to define the low temperature operability limit 

of fuels for diesel engines were not adequate even for low-level biodiesel/diesel fuel blends. 

An important aspect of these precipitates in many cases is that they did not redissolve after the 

fuel was warmed up. Contaminants such as sterol glucosides and/or soap in combination with 

water or saturated monoglycerides are thought to be at the root of such precipitates. 

To address the issue, a specific operational type test was developed for biodiesel to reproduce the 

conditions under which precipitates can form above the fuel’s cloud point. In this test, the Cold 

Soak Filtration Test (CSFT), a 300-milliliter sample of the biodiesel is cooled to 4.4 °C and 

soaked at this temperature for 16 hours. It is then gently heated to room temperature where the 
61

time taken to pass through a 0.7-μm filter is recorded. The CSFT and appropriate test limits are 

currently being determined for inclusion into ASTM D6751. 

Although the CSFT test appears to address many of the filter plugging concerns encountered in 

vehicle fuel systems, not everyone is in agreement that this is sufficient to entirely address 

precipitation issues with biodiesel/diesel blends above the cloud point of the fuel. Evidence 

suggests that saturated monoglycerides on their own can come out of a solution at low 

temperatures given sufficient time and collect in the bottom of fuel storage tanks (Brewer, 2007) 

and unheated distribution system filters (Selvidge, 2007). If other contaminants are not present, 

these saturated monoglycerides easily redissolve when the temperature of the fuel rises and 

would not be detected with the CSFT. Unlike vehicle fuel systems, the temperature of fuel 

storage and distribution system tanks and filters does not generally rise rapidly, and the presence 

of these insolubles could be a problem in some cases. 

Fuel Handling

The railroads handle large amounts of fuel and have numerous fuel facilities, including direct to 

locomotive suppliers. As such, issues of fuel mixing, fuel cleanliness, cloud point, and filters 

will likely come rapidly to the forefront.

Because biodiesel has different properties compared with petroleum diesel—including stability 

and low temperature operability—special fuel handling demands apply to biodiesel. Special 

handling procedures or completely new infrastructure and/or storage facilities may be required to 

address the following issues:

• General handling and storage guidelines (stability)

• Blending facilities

• Solvency effect of biodiesel

• Heated storage for B100

• Free water

Storage and fuel system issues have been seen in large-scale on-highway trial programs (e.g., the 

Las Vegas Clark County School District busing program). These issues are seen even in areas 

where temperatures are considered moderate by railroad standards. Biodiesel handling and use 

guidelines have been published by the U.S. DOE (2009).

Fuel Quality Issues

The U.S. DOE National Renewable Energy Laboratory (NREL) has conducted biodiesel fuel 

quality surveys since 2004 (McCormick, 2005; Alleman, 2007 and 2008). According to 

estimates for 2007, 10 percent of the volume of U.S. biodiesel may be out of specification 

(Alleman, 2008).

To address many of the quality issues, a voluntary BQ-9000 program has been started in the 

United States that allows biodiesel producers and marketers to certify that not only do their fuels

meet ASTM D6751 requirements but also that proper sampling, testing, storage, sample 

retention, shipping, and handling procedures are in place (BQ-9000 2008).
62

A.4.2 Commercial and Economic Factors

Figure A2 outlines the average U.S. retail prices for No. 2 diesel fuel and B100 for the dates 

indicated (DOE, 2011). The dashed line represents the price of B100 adjusted for energy content, 

expressed in dollars per DGE. Owing to the rapid rise in diesel prices and a lower rise in B100 

prices for April–July 2008, the price of B100 had matched (or was even lower at some 

geographical locations) that of diesel fuel. Because diesel prices rose in recent months, the price 

gap between B100 and diesel narrowed again. When the energy content is taken into account, 

biodiesel (B100, $/DGE in the chart) has been always more expensive than diesel fuel.

Figure A2. Average U.S. Retail Prices for Diesel and B100

The U.S. price of biodiesel is affected by the Federal Excise Tax Credit (so-called “blenders 

credit”), effective January 1, 2005. It provides blenders with $1 per gallon for B100 made from 

agricultural products and $0.50 per gallon for B100 made from other oils (e.g., cooking oils). 

The tax credit lapsed in December 2009—which resulted in a 42 percent drop in U.S. biodiesel 

production in 2010—but was reinstated from December 2010 (NBB, 2011).

Obligatory blending of biodiesel into the diesel fuel has been mandated by some States. 

Typically, the mandate requires that all diesel fuel sold in a State contain a minimum of a 2-

percent biodiesel (B2) blend. Some States are adding language that would increase the B2 blend 

to a B5 or an even higher level after a designated period. Some States tie their biodiesel 

requirements to the local feedstock or biodiesel fuel production (e.g., Pennsylvania bill HB1202 

of July 2008).

The first State that adopted biodiesel blending requirements was Minnesota, where a B2 mandate 

has been applied since 2005. A bill adopted in May 2008 increased the mandatory blend level as 

0

1

2

3

4

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6

Feb 2006Jun 2006

Oct 2006

Mar 2007

Jul 2007

Oct 2007

Jan 2008

Apr 2008

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Oct 2008

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Apr 2009

Jul 2009

Oct 2009

Jan 2010

Apr 2010

Jul 2010

Oct 2010

Jan 2011

Apr 2011

Retail Price, $/gallon

B100, $/DGE

B100, $/gal

Diesel, $/gal
63

follows: 5 percent from May 1, 2009; 10 percent from May 1, 2012; and 20 percent from May 1, 

2015. Other States that adopted or are considering the adoption of some form of biodiesel 

requirement include California, Florida, Louisiana, Kansas, Connecticut, Missouri, Oregon, 

Mississippi, Arkansas, Montana, and New Mexico as well as some Canadian provinces.

Since the adoption of the RFS2 by EPA in 2010, Federal biofuel requirements (rather than 

individual State mandates) are becoming the major driver in biodiesel demand.

According to a statement issued by NBB in January 2008, annual production capacity for 

biodiesel in the United States was 2.24 billion gallons. By early to mid-2009, production 

capacity was expected to increase to 3.47 billion gallons. However, current biodiesel production 

capacity utilization in the United States is extremely low. Actual production in 2008 was 678

million gallons or 30 percent of production capacity. A rapid rise in production occurred in 

2007–2008, followed by a 2009 decline as the result of the economic recession and a further 

decline in 2010 because the blenders’ tax credit expired. 

An increase in biodiesel production can be expected from 2011 because of the reinstatement of 

the blenders’ tax credit in 2011 and the increasing RFS2 mandates for biomass-based diesel, 

proposed at 1.0 billion gallons and 1.28 billion gallons for 2012 and 2013, respectively. 

Biodiesel remains the main option for fulfilling this mandate because the North American 

production capacity of the main alternative—the refinery-made renewable diesel—remains low.

Most feedstocks currently used in biodiesel production compete with food production. Although 

the estimates of the relative contribution of diverting feedstocks to biofuel production on food 

prices vary significantly, it is generally agreed that biofuel production is only one factor of many 

contributing to global food price increases. Although technology to produce biofuels from 

nonfood feedstocks is developing, it is unclear how long it will take for these technologies to be 

commercialized. 

The increase in food commodities also affects biodiesel feedstock costs. This may have the effect 

of shifting from high-cost feedstocks, such as virgin vegetable oils, to less costly feedstocks, 

such as imported palm oil or used cooking oil and animal fat. Depending on the operating 

environment and government policy, this may also affect existing producers by making their 

product less competitive with other fuels.

A dispute over U.S. exports of biodiesel to Europe is another possible risk factor. The European 

Biodiesel Board accused U.S. producers of dumping subsidized biodiesel on the European 

market at a cost lower than production costs in EU countries. U.S. blenders receive the blenders’

credit regardless of the country of origin of the biodiesel or whether it is sold on the domestic 

market or exported. The EU estimated that 300 million gallons of biodiesel was exported to the 

EU from the United States in 2007. Although this would appear to represent most of the U.S. 

production, a significant portion of it is likely imported to the United States, blended with a small 

quantity of petroleum diesel (e.g., into B99) to collect the tax credit, and then exported to 

Europe. In March 2009, EU trade authorities imposed antidumping and countervailing measures 

on imports of U.S. biodiesel, which are set for 5 years. These measures were further strengthened 

in May 2011 to prevent exports of U.S. biodiesel via third countries such as Canada.
64

A.4.3 Environmental Impacts

Life-Cycle Analysis: Energy and GHG Emissions

Energy. One of the main advantages claimed for biodiesel is its renewable character and the 

potential to reduce petroleum consumption. Biodiesel’s raw resources, such as soybeans or 

rapeseed, are entirely renewable. The U.S. DOE NREL conducted one of the first life-cycle 

analyses for biodiesel (Sheehan, 1998). In terms of energy, the NREL analysis found that 0.31 

megajoule of fossil energy is needed to produce 1 megajoule of biodiesel, thus representing a 69-

percent energy gain over the fossil energy input. Similar figures were reported by other authors. 

For example, IEA reviewed seven European rapeseed biodiesel studies, which were reporting 

that biodiesel production resulted in fossil energy savings from 30 to 80 percent (IEA, 2004).

According to newer studies, however, the issue of life-cycle energy efficiency of biodiesel 

remains largely uncertain. There are several fossil fuel energy inputs, such as those in the process 

of growing biodiesel crops that might have been underestimated or overlooked. Some authors 

estimated that growing and processing soybeans require 32 percent more fossil energy than the 

energy content in the produced biodiesel (Pimentel, 2005). The difference between this and the 

former estimates can be attributed to higher assumed energy inputs in soy agriculture such as 

machinery, fuels, fertilizers, lime, herbicides, and electricity.

GHG Emissions. Because of the renewable character of carbon in the fuel, biodiesel can also 

potentially provide reductions of life-cycle CO2 emissions. Carbon is biologically cycled when 

plants such as soybean crops convert atmospheric CO2 to carbon-based compounds through 

photosynthesis. Biomass-derived fuels participate in the relatively rapid biological cycling of 

carbon to the atmosphere (via engine tailpipe emissions) and from the atmosphere (via 

photosynthesis). Fossil fuel combustion, in contrast, releases carbon that was removed from the 

atmosphere millions of years ago. For this reason, shifting from fossil fuels to biomass-derived 

fuels can reduce the amount of CO2 in the atmosphere.

An early estimate of life-cycle CO2 emissions for biodiesel and petroleum diesel fuels conducted 

by the DOE (Sheehan, 1998) indicated that the use of biodiesel resulted in a 78-percent reduction 

in life-cycle CO2 emissions (this effect is entirely to the result of the biological recycling of CO2; 

the tailpipe emissions are actually higher for biodiesel than for petrodiesel). The analysis 

considered several life-cycle CO2 contributions, such as emissions from the refinery and other 

industrial emissions that occurred during the production and distribution of fuels.

However, newer studies include an increasing number of additional factors and assumptions that 

have an impact on the life-cycle GHG effect of biodiesel. These factors include indirect land use 

change effects from cultivation of soybeans or rapeseed, such as changes in carbon content in the 

soil—which decreases in cultivated land—as well as GHG emissions from fertilizers (NOx) or 

effects related to displaced products, such as glycerin (Delucchi, 2003).

Studies that take indirect land use changes into account have raised significant doubt about the 

net GHG emissions reduction potential of alkyl ester biodiesel. A technical analysis by the 

University of California related to California’s Low Carbon Fuel Standard (Arons, 2007) found 

that the net GHG emissions of biodiesel made from U.S. Midwest soybeans varied significantly 

depending on how the land use issues were treated. A life-cycle analysis methodology 

(Greenhouse gases, Regulated Emissions, and Energy use in Transportation (GREET)) that is 

known to have shortcomings when dealing with land use changes gave U.S. Midwest soybean 
65

fatty-acid methyl ester (FAME) biodiesel a net GHG intensity of 30 g CO2 equivalent/megajoule. 

This is about 42 percent of that for petroleum diesel (71 g CO2 equivalent/megajoule) with the 

same analysis. However, when an alternative life-cycle analysis (Life-cycle Emission Model 

(LEM)) that deals with land use changes in a more comprehensive manner was used, the soybased biodiesel gave an astounding 224 g CO2 equivalent/megajoule, which is over three times 

higher than that for petroleum diesel (73 g CO2 equivalent/megajoule) estimated with the same 

analysis.

Similar concerns have been raised over rapeseed-derived FAME. Some authors suggested that if 

rape is grown on dedicated farmland, the life cycle GHG emissions are almost equivalent to 

those for petroleum diesel (Johnson, 2007). Others, based on a detailed analysis of NOx release 

in agricultural production, have negated any climate benefit of rapeseed biodiesel (Crutzen 

2007). Studies showed that between 3 and 5 percent of the nitrogen fertilizer used for growing 

rape is emitted as NOx, twice the value used by the United Nations Intergovernmental Panel on 

Climate Change to calculate the impact of fertilizers on climate change, causing up to 70 percent 

more GHG emissions than using the equivalent amount of fossil-based diesel.

Even more uncertainty exists about the net GHG effect for tropical biodiesel crops, such as palm 

oil or soybeans grown over cleared Amazon rainforest. Clearing forests for plantations usually 

produces a significant GHG release, which may be compensated for only after a very long time

of biodiesel use. In the case of palm oil, significant GHG emissions are also generated in the 

production process (Reijnders 2008). Palm oil mills produce large amounts of organic waste, up 

to as much as 80 percent of the inputs, a part of which enters waste water. During effluent 

treatment, a large part of the carbon input in the waste water undergoes anaerobic decomposition 

to methane, a potent GHG, which makes the overall GHG benefit of palm oil derived biodiesel 

uncertain.

Potential Policy Impacts. The growing uncertainty over the life cycle GHG emission impacts 

associated with the production of biodiesel feedstocks may have a potential impact on biofuels 

policies and future regulations by governments worldwide, especially in countries that are 

committed to ambitious GHG emission reduction goals.

As mentioned earlier, under the RFS2 proposal by the EPA, conventional biodiesel such as that 

made from soy was assigned a life cycle GHG reduction effect of less than 50 percent, which 

would disqualify the fuel from being designated as biomass-based diesel. The GHG reduction 

effect of biodiesel was increased to above the 50 percent threshold later during the rulemaking 

process, allowing biodiesel to be designated as both biomass-based diesel and advanced biofuel. 

In the EU, a growing public concern has followed the adoption of the biofuels directives in 2003 

and 2009. The regulatory authorities have been criticized for acting hastily, without proper 

understanding of the life cycle GHG effects of biofuels. With mounting scientific evidence 

indicating that the overall GHG emissions might be actually increased through the use of 

rapeseed or palm oil biodiesel, there are opinions—shared by many environmental groups—that 

the EU biofuels directives might have a counterproductive effect and increase climate change 

emissions. In response, the European Commission has initiated the development of regulatory 

measures to ensure sustainability of biofuels.

According to recent reports by the European Commission obtained by Reuters, biodiesel from 

Asian palm oil, South American soybeans, and EU rapeseed all had a bigger overall climate 
66

impact than conventional diesel. “Europe’s biodiesel industry could be wiped out by EU plans to 

tackle the unwanted side effects of biofuel production” (Reuters 2011).

Emissions of Pollutants

Most testing with biodiesel has been carried out on high-speed diesel engines and only limited 

data is available for medium-speed diesels. Figure A3 shows some average trends on emissions 

for pre-1998 high-speed diesel engines from an EPA survey (2002) for different blend levels of 

biodiesel. On average, PM, CO, and total hydrocarbons (THC) emissions decrease, whereas NOx

emissions increase with increased proportion of biodiesel in the blend. 

Figure A3. Average Impact of Biodiesel on Emissions for High-Speed Diesel Engines

Work on on-highway engines since 2004 suggests that the PM reduction potential may be higher 

than with the older pre-1998 engines. Part of the PM reduction control strategy for these newer 

engines is reduced lubricating oil consumption. The relative contribution of combustion 

generated soot to total PM would be higher, and fuel effects on PM would be accentuated. On 

the downside, the NOx increase with the newer engines was higher than in the older engines used 

in the EPA survey (Figure A4). Change in Emissions, Percentage

Biodiesel Content in Blend, Percentage
67

Figure A4. Relative Increase in NOx for Pre-1998 and 2004 On-Highway Diesel Engines

The NOx increase with biodiesel has been fairly consistently noted. One characteristic of this 

NOx increase is that its magnitude is strongly dependent on engine load. Figure A5 shows the 

relative NOx increase for B20 and B50 blends from a 2006 Cummins ISB on-road engine 

measured for different test cycles having different average power demands (Sze, 2007).

0

10

20

30

0 50 100 150

Average cycle power, hp

% increase in NOx with biodiesel 

blend

B50

B20

Figure A5. Relative Increase in NOx Measured on Different Drive Cycles 

Having Different Average Power Requirements

Change in Emissions, Percentage

% Increase in NOx with Biodiesel Blend

Biodiesel Blend, Percentage
68

Some would argue that biodiesel can show a NOx decrease in some cases, and therefore, the 

claim that biodiesel always causes a NOx increase is unwarranted (McCormick, 2006a). 

However, examination of data used to support this argument shows that NOx decreases only 

occur on drive cycles with very low average power demands such as those used with some urban 

buses (Sze, 2007). The data also shows that in cases where a NOx decrease is noted, a

significantly higher fuel penalty is observed when compared to cases where NOx increases, 

suggesting that the NOx decrease at low loads is the result of degradation in engine efficiency 

(Majewski, 2008).

The increases in NOx with biodiesel can be attributed to numerous factors that depend on details 

of the engine being considered. Changes in controlled parameters such as fuel injection timing, 

injection pressure, and exhaust gas recirculation (EGR) rate can play a major role. However, 

even in cases where measures to hold these controlled parameters constant have been taken, NOx

increases have persisted because of changes in combustion phasing, peak temperatures, and 

mixture stoichiometry (Cheng, 2006; Majewski, 2008).

Results from Rail Applications

Although a significant body of work exists on the effect of biodiesel on emissions for high-speed 

engines, only limited data is available for medium-speed diesel engines such as those used in 

North American rail service. 

Tests with an unregulated two-stroke EMD GP38-2 locomotive with an EMD roots blown 16-

645E diesel engine using both EPA line haul and EPA switch duty cycles showed statistically 

significant increases in NOx of about 5–6 percent and decreases in CO with B20. No impact on 

PM or THC was detected (Fritz, 2004). This study suggested that the engine used is the most 

likely candidate for use of biodiesel by freight railroads because of its extensive use in switcher 

and road-switcher applications, and as such, it is likely to be centrally fuelled and operated in 

urban areas.

In another study using a four-stroke single cylinder medium-speed research engine having a 

similar power assembly to a GE 7FDL locomotive engine, B5 and B20 blends where tested using 

an Association of American Railroads’ three-mode test cycle. With the B20 blend, a 13- to 19-

percent decrease in CO, a 7- to 8-percent increase in NOx, and a 13- to 19-percent decrease in 

PM emissions were noted (Su, 2005).

Trials outside of North America have also been carried out. Tests with B20 by the French 

railway operator National Corporation of French Railways (Société Nationale des Chemins de 

fer français (SNCF)) showed some reduction in smoke number but increases in all other 

emissions (Skinner, 2007). In the United Kingdom (UK) (where many passenger rail applications 

use multiple small diesel power plants such as Cummins NT855, Cummins QSX-19, and MTU 

6R-183), tests with a Cummins NT855 engine, while showing trends consistent with Figure A3

up to B20, showed a poor response from the engine at blend levels above B20. Significant 

increases in PM and HC emissions were measured at B50 and B100 levels (Skinner, 2007). 

The study by Fritz suggests that there is no PM reduction benefit to using biodiesel in some 

common locomotives. It should be kept in mind, however, that these tests were carried out on an 

unregulated two-stroke locomotive with PM emissions of 0.62 g/kilowatt hour (kWh) (0.46 

g/bhp-h) on the EPA line-haul duty cycle. PM emissions from this two-stroke engine are 

dominated by lubricating oil components and the impact of fuel effects would be relatively 
69

insignificant. As these unregulated locomotives are replaced with EPA-certified locomotives, 

PM emissions will decrease to the level where fuel effects may become detectible. The work by 

Su suggests that this is indeed the case; PM decreases comparable to those in Figure A3 were 

measured using B20 from an engine with PM emissions of 0.16 g/kWh (0.12 g/bhp-h). 

The results from the European tests also point to the fact that assumptions about emission 

reductions, especially for higher level blends, should not be taken as a given. Some level of 

testing is required to verify that locomotive operation and emissions performance will not be 

adversely affected.

The increases in NOx with biodiesel blends, however, may be a concern. The studies by Fritz 

(2004) and Su (2005) measured NOx increases comparable to those shown in Figure A3. 

Depending on the particular engine and the operating environment, these NOx increases could 

pose a significant challenge to using higher level blends of biodiesel.

Concerns over NOx increases were a particular concern for Canadian Railroads that operated 

under a memorandum of understanding (MOU) that capped NOx emissions. Estimated NOx

emissions are near the capped limit, and increases cannot be tolerated (Dunn, 2003).

NOx emissions higher than those achieved with certification fuel may also be a concern for EPAcertified locomotives. Data from the 2007 EPA certification database shows that little increase in 

NOx levels can be tolerated from locomotives meeting 2000 Tier 1 and Tier 2 PM and NOx levels 

before NOx emissions exceed the line-haul certification limit (Figure A6). Line-haul operation is 

weighted to operate at high loads where the relative increase in NOx would be more pronounced 

(Figure A5).

0

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0.3

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0.7

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NOx, g/bhp-hr

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GE reman

EPA Line-Haul Duty Cycle EPA Switch Duty Cycle

Figure A6. EPA Certification Results for NOx and PM for Fresh and Remanufactured 

EMD and GETS Locomotives

In switch mode, however, there is a greater margin between the certification level and the 

certification limit for NOx. A larger increase in NOx could be tolerated before exceeding the 

certification limit. However, EPA certification rules state that locomotives must meet emissions 

for both line-haul and switch duty cycles.
70

A.4.4 Engine Performance Effects

Energy Content

The energy content of biodiesel is lower and its specific gravity is higher than No. 2 diesel. Table

A6 lists the volumetric energy contents. As a result of these differences, loss of engine power 

and increased fuel consumption can be expected.

Table A6. Energy Content of Biodiesel and No. 2 Diesel

Fuel Energy Content

MJ/l Btu/gal

Biodiesel (B100) 32.9 118,170

Biodiesel B20 – 127,250

No. 2 Diesel 36.0 129,500

A survey by EPA on pre-1998 high-speed engines found that the average fuel consumption 

increase by mass for a wide range of engines was about 9 percent for B100 and varied almost 

linearly with the proportion of biodiesel in the blend (EPA, 2002). For a B20 blend, the average 

increase expected would then be a little under 2 percent.

The fuel consumption penalty can, however, be highly dependent on the particular engine in 

question. In one study with three different on-road high-speed diesel engines (Sharp, 2000), the 

fuel consumption penalty ranged from 13 to 17 percent for B100 and 2 to 7 percent for B20 over 

the U.S. FTP Transient test cycle. The same study measured a power loss of about 7 percent with 

B100 and about 2 percent with B20.

Work with engines used in rail applications is relatively limited, but reflects the trends seen with 

high-speed engines.

In a study with an EMD GP38-2 locomotive equipped with a two-stroke EMD roots blown 16-

645-E diesel engine, no detectable differences were measured in fuel consumption between B20 

and diesel fuel on both the EPA line-haul and EPA switch duty cycles. Power losses ranged from 

0.9 to 2.4 percent depending on the base diesel fuel. The engine load control system on this 

particular engine sets a fixed volumetric fueling rate at each notch position (Fritz, 2004).

Tests with a four-stroke single cylinder medium-speed research engine having a similar power 

assembly to a GE 7FDL locomotive engine showed a power loss of 1–3 percent with B20. The 

impact on fuel consumption was minimal (Su, 2005).

Compatibility with Existing Engines

Several concerns exist regarding the use of biodiesel blends, especially higher level blends or 

B100, in existing diesel engines not designed for biodiesel fuels. The major potential issues are

as follows:

• Material Compatibility—Changes in fuel composition and the introduction of 

alternative fuels often create unforeseen problems in seals, gaskets, o-rings, as well as 

metallic components in the fuel system. An experimental laboratory study (Besee, 1997) 

concluded that the physical properties of nitrile rubber, nylon 6/6, and high-density 
71

polypropylene were affected by biodiesel and its blends; whereas Teflon, Viton 401-C,

and Viton GFLT appeared to have good resistance to biodiesel.

• Engine Oil Dilution—Engine oil can be diluted by fuel, such as by fuel exiting the fuel 

injectors that did not fully vaporize and impinge on the cylinder liner. The differences in 

fuel properties of biodiesel (decreased volatility, higher surface tension, and higher 

density) can lead to larger fuel droplets leaving the injector that travel farther and take 

longer to evaporate. These droplets are more likely to impinge on the cylinder wall and 

be scraped into the crankcase by the piston rings. Once in the crankcase, the higher 

boiling point biodiesel components are less likely to evaporate than the lower boiling 

point diesel fuel components.

• Fuel System Compatibility—In addition to the already mentioned fuel filter plugging, 

other potential compatibility issues with fuel systems have been investigated. Some fuel 

injection pumps lubricated by engine oil can introduce small amounts of lubricating oil 

into the fuel. Fang (2003) suggested that the polar nature of biodiesel may destabilize 

over-based detergents found in lubricating oil that enters the fuel system, leading to 

excessive deposits in the fuel filter and premature fuel filter plugging. Excessive deposit 

formation and wear in fuel injectors and pumps are also important considerations. 

According to some studies, biodiesel can have a negative impact on deposit formation in 

fuel injectors if insufficient detergent additives are used (Caprotti, 2007). Fuel system 

issues can also be caused by the presence of impurities (free methanol, water, glycerin, 

solid impurities) and aging products (organic acids, polymerization products).

• Aftertreatment Effects—Additional issues may exist with new engines fitted with 

catalytic exhaust after treatment, for instance, particulate filters. Potential problems may 

be caused by high ash levels in biodiesel PM and/or catalyst deactivation by metals (e.g., 

P, Na, K, Ca, Mg). The 10 milligram per kilogram level of phosphorus allowed in 

biodiesel by most standard specifications has been shown to cause catalyst deactivation 

with B100 (Krahl, 2006). Out-of-spec samples with even higher phosphorus content were 

reported by U.S. biodiesel quality surveys (McCormick, 2005). EU car manufacturers 

disallow the use of B100 in vehicles with particulate filters, presumably the result of oil 

dilution during filter regeneration (performed via in-cylinder postinjection). A recent 

study by the DOE NREL examined the impact of biodiesel impurities on catalytic 

emission controls, including diesel oxidation catalyst (DOC), diesel particulate filter 

(DPF), and SCR catalysts (Williams, 2011). It was found that B20 blends with metals at 

the maximum ASTM specification level would cause catalyst deactivation and metal 

migration into the cordierite catalyst substrates with detrimental effects to the substrate 

mechanical properties and would increase (double) the ash amount in the DPF. Thus, the 

ASTM biodiesel specification is not sufficiently protective for aftertreatment 

technologies when using B20 or higher biodiesel blends. 

Experience with high-speed diesel engines indicates that low-level blends up to B5 can be used 

in most existing engines with no engine modifications. Almost all heavy-duty highway and 

nonroad engine manufacturers allow blends up to B5 with no changes.

With blend levels higher than B5, compatibility depends on the manufacturer and specific engine 

model being considered. Some engines tolerate up to B20 with no changes. Other manufacturers 
72

have taken deliberate design steps to ensure their engines are compatible with higher level 

blends. Others offer OEM retrofit kits to make some engine models compatible.

Some tests have been conducted with biodiesel in locomotive engines. GETS completed 

performance testing on a single cylinder engine with B2-B20 blends and S15-S500 blends. 

Durability testing in a stationary engine is ongoing and operability testing in a locomotive 

application is planned (Lawson, 2008).

In B20 trials using Bombardier Class 220 and Class 221 locomotives equipped with Cummins 

QSK19-R engines by Virgin Cross Country in the UK, modifications were made to the fuel feed 

and return lines, fuel filter, and fuel fill adapter (Edwards, 2007).

A.5 Renewable Diesel

The term renewable diesel usually refers to hydrotreated vegetable oils (HVO) or animal fats. 

The feedstocks, identical to those used for ester-based biodiesel production, are treated with 

hydrogen in a refinery process that removes oxygen, resulting in a paraffin fuel similar to 

synthetic FT/GTL diesel. Renewable diesel fuels can meet the ASTM D975 standard. 

Considering their value for refiners, the fuels will likely be used as blending stock to improve 

properties of No. 2 diesel.

Terminology confusion exists around renewable diesel, in part because of one of the leading 

developers of that technology, the Finnish oil company Neste Oil. At the time Neste Oil 

introduced its NExBTL HVO diesel, it referred to it as second generation biodiesel. Later, the 

company dropped the term biodiesel and renamed the fuel NExBTL renewable diesel.

From the fuel quality point of view, renewable diesel presents an attractive method of vegetable 

oil feedstock utilization, producing HC fuel with no stability, low temperature operability, or 

engine compatibility problems, which have troubled ester-based biodiesel. The life-cycle GHG 

emission effect of renewable diesel depends mostly on the sustainability of the feedstock, as 

discussed in the section on biodiesel.

A.5.1 Commercial Status

From the commercial point of view, renewable diesel is currently the only alternative to 

biodiesel to satisfy the biomass-based diesel quotas of the EPA RFS2 program, as well as the EU 

biofuels mandates. 

Although there are no commercial renewable diesel plants in North America, Neste Oil invested 

into several NExBTL renewable diesel facilities intended to supply the EU and the North 

American biofuel markets. Neste commissioned its first two NExBTL facilities in Finland at the 

Porvoo refinery in 2007 and 2009, with a combined capacity of 380,000 metric tons per annum 

(t/a). In 2010, Neste opened the world’s largest renewable diesel plant in Singapore, with a 

capacity of 800,000 t/a. A similar-sized facility under construction in Rotterdam could be 

commissioned in 2011. Palm oil imported from Indonesia and Malaysia is the main feedstock 

used by these plants. Other feedstocks can be also processed, such as waste animal fats from 

Australia and New Zealand.

Under April 2008 decisions of the U.S. Internal Revenue Service and the U.S. EPA, renewable 

diesel produced in stand-alone plants (as opposed to coprocessing with petroleum diesel) was 
73

eligible for the EPAct $1/gallon tax credit. These decisions were fought by the biodiesel lobby 

that feared that refiners would produce renewable diesel from less expensive feedstocks, such as 

imported palm oil, rather than U.S.-grown soybeans.

A.5.2 Properties and Emissions

Properties of the renewable diesel fuel are very similar to GTL diesel. The Neste NExBTL 

contains no sulfur, oxygen, nitrogen, or aromatics (Kuronen, 2007). The cetane number can be 

very high, up to 90. Cloud point can be adjusted by severity of the process from –5 to –30 °C. 

Heating value is similar to diesel fuel, storage stability is good, and water solubility is low.

In a study by Neste Oil and VTT Technical Research Centre of Finland, emissions from two 

heavy-duty engines and two urban buses were compared using HVO and sulfur-free EN 590 

diesel fuel (Kuronen, 2007). The following emission reductions were measured with the HVO 

fuel, compared to EN 590 diesel: NOx: 7–14 percent; PM: 28–46 percent; CO: 5–78 percent; and 

HC: 0–48 percent.

A.6 Natural Gas

Contrary to crude oil, natural gas supplies are considered abundant and should be ample for even 

greatly expanded use of the fuel. Therefore, the share of natural gas in the total energy mix is 

believed to grow in the coming decades at the expense of the shrinking crude oil supply.

It remains uncertain what will be the dominant utilization method of the growing natural gas 

production. Natural gas could be used as a transportation fuel in several ways:

● It can be used directly to fuel internal combustion engines as LNG or CNG. This section 

deals with such direct use of CNG/LNG fuels.

● Natural gas can be also converted to liquid HC fuels, such as diesel fuel, via GTL 

technologies.

● Finally, natural gas can be used to produce gaseous fuels (e.g., DME or hydrogen). 

The recent increase in natural gas resources can be largely attributed to the commercialization of 

horizontal drilling combined with hydraulic fracturing (i.e., fracturing the rock using fluids under 

pressure)—a technique commonly referred to as fracking. Early experiments with commercial 

shale gas production were conducted in the 1980s and 1990s by Mitchell Energy in the Barnett 

Shale in Texas. Mitchell Energy succeeded and other companies aggressively began fracking so 

that by 2005, the Barnett Shale alone was producing almost half a trillion cubic feet per year of 

natural gas. The development of shale gas has become a game changer for the U.S. natural gas 

market—dry shale gas production in the United States increased from 0.39 trillion cubic feet in 

2000 to 4.80 trillion cubic feet in 2010, which was 23 percent of U.S. dry gas production (EIA,

2011).

Shale gas resources are not limited to the United States but are found in a number of other 

countries (Figure A7): China, Argentina, Mexico, South Africa, and Canada are the top players. 

When the identified, technically recoverable shale gas resources are added to current estimates of 

natural gas resources, the world’s total technically recoverable gas resources increase by over 40

percent (EIA, 2011).
74

Figure A7. Estimated Global Shale Gas Technically Recoverable Resources 

A number of potential environmental issues exist with shale gas production, which includes the 

following:

● GHG emissions

● Contamination of drinking water supplies

Because of its lowest carbon-to-hydrogen ratio, natural gas has the lowest carbon footprint 

among all fossil fuels. By increasing the natural gas share in their total energy volume, energy 

producers would be able to reduce their carbon footprint and, in some cases, even meet the 

applicable, legislated carbon emission reduction targets. However, shale gas is believed to have 

substantially higher life-cycle GHG emissions than conventionally produced natural gas, because 

of methane leaks in the production, which can be approximately 5 percent of the gas volume.

Some studies suggest that the GHG impact of shale gas is actually higher than that of coal 

(Howarth, 2011). According to these findings, the migration from coal to natural gas for 

electricity production would not produce GHG emission reductions if the natural gas is obtained 

from shale resources.

The water contamination issue is linked to the hydraulic fluids used in fracking. Concerns exist 

that fracking may cause adverse environmental impacts, including contamination of drinking 

water supplies and withdrawal of large volumes of water from creeks and streams. Some States 

are pushing for Federal control and regulation of natural gas drilling by EPA and/or other 

Federal agencies. For instance, the New York Attorney General announced a lawsuit against the 
75

Federal Government for its “failure to commit to a full environmental review of proposed 

regulations that would allow natural gas drilling—including the potentially harmful ‘fracking’

technique—in the Delaware River Basin” (NY, 2011). Natural gas drilling is currently not under 

Federal jurisdiction.

A.6.1 Railroad Experience

Natural gas is a mixture of gases typically consisting of at least 90-percent methane, along with 

small amounts of ethane, propane, nitrogen, CO2, and trace amounts of other gases. Natural gas 

is not a “natural” diesel fuel because it has high octane and a low cetane number. Several 

approaches allow the use of methane-based gaseous fuels in the diesel engine. Each of them, 

however, requires a conversion or a modification to the diesel engine. A conversion to Otto cycle 

has often been done in highway engines, but development work is also carried out to use the 

diesel cycle. In the latter case, which is more common in the rail application, diesel pilot ignition 

is often used for igniting the fuel mixture.

Since the mid-1980s, a number of projects were launched by the railroad industry in North 

America and worldwide to assess the viability of natural gas-fueled locomotives (Fritz, 1997; 

Xin, 1998; Payne, 1999). In 1984, a program to develop natural gas fueled locomotives was 

started in Russia. In 1993, four types of natural gas-fueled locomotives, including CNG diesel 

switching locomotives and LNG freight trains, were commissioned in the Russian railway 

industry (Xin, 1998). Germany has developed 165-kilowatt CNG locomotives and tested them in 

rail yard switching operation. Japan, Finland, and the Czech Republic have also designed

locomotives that operate on natural gas (Xin, 1998).

In the United States, experiments on LNG/diesel dual-fueled locomotives were conducted by 

BNSF until the mid-1990s. Morrison Knudsen Corporation (MK) introduced an MK1200G 

LNG-burning locomotive in 1994 (Fritz, 1997). BNSF in Los Angeles, CA, is still using four of 

these locomotives in revenue service. Perhaps the most comprehensive endeavor in the United 

States was the GasRail project, a multiyear cooperative industry research undertaking. Initiated 

in 1993 by the SwRI, it involved the development and integration of an LNG engine and its 

associated fuel storage and handling systems into an EMD-F59PHI passenger locomotive. The 

fueling system was of the late-cycle high-injection pressure technology (LaCHIP), similar to the 

high-pressure injection developed by Westport for natural gas bus application. The installation of 

the LaCHIP prototype engine into a locomotive was not completed because the program ended in 

1998, in part because EMD, the principal locomotive builder participating in the program, did not 

support it (BNSF, 2007).

In March 1992, EMD and the UP announced an agreement for modifying two EMD 3,000-

kilowatt model SD60M locomotives that would run either on diesel fuel alone or on dual-fuel 

with diesel and high-pressure natural gas. In May 1992, GETS announced that they would 

develop a dual-fuel 3,000-kilowatt model Dash-8 locomotive for the UP. At that time, delivery 

and testing of these prototype locomotives were scheduled for mid-1993. Work progressed on 

demonstration units at both companies until 1995, when technical difficulties with the highpressure fuel injection systems on both designs, combined with the introduction of many other 

technologies on diesel locomotives, resulted in both builders suspending their LNG freight 

locomotive programs.
76

In 2005, trials were conducted with GE C30-7 locomotives converted to dual-fuel CNG/diesel 

operation by the Ferrocarril Central Andino railroad in Peru (Roberson, 2006). India Railways 

reportedly tested a dual-fuel CNG/diesel locomotive on a line between Delhi and Rewari.

LNG has been evaluated as prospective fuel for future fuel cell power trains (Bourn, 2004). In a 

project funded by the U.S. DOD, LNG was evaluated as the base fuel for a fuel cell-powered 

GP-10 switcher operated by the U.S. Army. LNG, which would be reformed onboard into 

hydrogen, was found to be one of the feasible fuel options for this application.

Natural gas can be stored in two forms: CNG or LNG. LNG is usually favored for the 

locomotive fuel application, because it offers a higher storage density (Hofeldt, 1993). 

Approximately five times more LNG can be stored in the same size container than CNG, saving 

space and making refueling less frequent (Payne, 1999). In addition, the liquefaction process 

removes impurities that solidify at temperatures at or above the boiling point of methane (e.g., 

water, CO2, and heavy HCs), thereby reducing the problem of fuel weathering in storage 

(Owens, 1994).

There are certain applications, however, when CNG may be the preferred option. For example, 

switch locomotives usually remain close to stations and can be refilled more easily during long 

idle periods. Commuter rails may also favor CNG because of their frequent and routine stops and 

close proximity to available fuel supply.

To provide enough LNG for mainline rail operations between current fueling stations, it is 

necessary to provide a fuel tender car as part of the locomotive consist. To keep natural gas in a 

liquid state, it must be refrigerated to –259 °F (–162 °C). To maintain such low temperatures, the 

tender car is constructed of a double-walled stainless steel “thermos bottle” design, capable of 

keeping the LNG cold for as long as 14 days (Payne, 1999). A heat exchanger aboard the tender 

car converts the LNG to gas, which flows to the locomotive through a flexible hose connection 

between the tender and the locomotive engine. No cryogenic fuel is ever transferred onboard the 

engine. Safety features built in to the coupling inhibit the release of gas in the event of traintender disconnect.

One of the major factors that have limited the use of natural gas as a transportation fuel is the 

infrastructure requirement for its transport and storage. The physical characteristics of LNG (as 

well as CNG) make transport more difficult and expensive than diesel fuel.

LNG cannot be efficiently transported by pipeline for long distances because of pipeline costs 

and heat transfer. Thus, it must be produced at the site, near the point of consumption, or 

transported by truck or tank car. For example, the natural gas could be transported from the 

refinery to liquefaction plants, which are situated near the fueling sites. The fuel consumption 

rate will determine the plant and the main fuel storage tank size. In addition, mobile liquefaction 

units are also available that can be used to produce LNG at the fueling site if a low quantity of 

LNG is desired.

Natural gas is a well-established commercial fuel. LNG production and storage are well 

understood, and the technology is transferable to conditions likely to be encountered in railroad 

applications. Operational, storage, and safety guidelines are established and available through the 

LNG and general cryogenic industry. There appears to be no significant technical problems in 

setting up the equipment and facilities required to supply LNG in the quantities and delivery 

rates needed by the railroads.
77

A.6.2 Natural Gas Engines

Engine technology options for using natural gas can be grouped into the following three groups:

• Spark ignition natural gas (SING), Otto cycle

• Direct injection natural gas (DING), Diesel cycle

• Dual fuel natural gas (DFNG), Diesel cycle

SING engines could be of lean-burn or stoichiometric type. The latter can use the three-way 

catalyst (TWC) emission technology and, therefore, provides the greatest emission potential. 

Stoichiometric combustion is used in most light-duty SING engines. Problems with thermal 

stress and low-power density have favored the use of the lean-burn combustion system in heavyduty engines. The use of cooled EGR provides further potential to increase the engine output 

and, at the same time, decreases NOx emissions (Nellen, 2000).

A specific advantage of SING engines is low particulate emissions in comparison to diesel 

engines without particulate filters. The NOx emissions are generally lower (lean-burn type) or 

significantly lower (TWC type) than from conventional diesel engines.

DING and DFNG engines use late-cycle direct injection, and therefore, they are characterized as 

engines using the Diesel cycle. Both engine types need some kind of ignition source, because

methane has a very low cetane number. Furthermore, engine knock has to be avoided if 

premixing of air and methane is used.

The DING engine uses a small quantity of diesel fuel (pilot injection) or a glow plug as ignition 

sources. Because the injection system for the diesel fuel does not have the capability of greater 

injection quantities, this option has no dual-fuel properties. In contrast, an optimization of the 

pilot injection can be made to achieve lower emissions. An injection system combining the 

injection of both diesel fuel and natural gas has been developed by Westport (Ouellette, 1998,

2002). Another example is the so-called micropilot injection, which has been developed by 

FEV (Umierski, 2000). Using a glow plug for ignition of the fuel is another possibility. The 

German development company GVH, now part of Westport, pursued this idea (Bartunek, 2000).

In a DFNG engine, natural gas is mixed (fumigated) with intake air before induction to the 

cylinder, and diesel fuel is used as ignition source. Because conventional diesel injection is used 

in this case, this engine has dual-fuel properties. A kind of hybrid version of both systems, often 

referred to as PING, uses pilot injection of diesel fuel and premixing of natural gas. The diesel 

fuel injection for PING engines is typically optimized for low fuel flows to improve emissions 

with CNG. Therefore, contrary to DFNG, these engines cannot be run in diesel fuel-only mode. 

Because the combustion in DING and DFNG engines is not completely premixed combustion, 

soot formation can occur. Thus, stringent future PM emission standards may necessitate the use 

of a particulate filter.

An overview of the technology used in natural gas engines has been provided in two 

International Association for Natural Gas Vehicles (IANGV) reports (Nylund, 2000, 2002). The 

latter report is mostly focused on light-duty vehicles and advanced drivetrains such as fuel cells. 

An overview of the worldwide use of natural gas fueled buses is provided in another report by 

IANGV (Watt, 2001).
78

Natural gas engine technology for railroad locomotives was reviewed by Payne (1999), and a 

comprehensive review was performed by BNSF and UP (2007) as part of its technology survey 

for the 2005 California MOU.

A conversion kit to convert diesel line-haul locomotives to dual-fuel diesel/natural gas operation 

has been developed by Energy Conversions, Inc. (ECI), of Tacoma, WA (ECI 2008). The kit is 

applicable to the EMD 645 two-stroke diesel engine. With the ECI system, the LNG is vaporized 

and injected as a gaseous fuel; the fuel and air mix during compression. A small portion of diesel 

pilot fuel is then injected into the cylinder at the top of the stroke to facilitate combustion. The 

locomotive engine can also operate in a 100-percent diesel mode, if needed.

The ECI kit provides 90-percent natural gas fuel replacement rate at high loads. At low engine 

loads, including idle, the engine is operated in the diesel mode, which has an effect on emissions. 

The ECI kit has been recognized by the railroad industry as the only one “commercially 

available, proven, and tested natural gas-fueled line-haul locomotive product available for the 

North American locomotive market” (BNSF, 2007). However, this kit has not been EPA

emission certified.

A.6.3 Natural Gas Emissions

The trends in regulated emissions from diesel and natural gas engines can be summarized as 

follows (Ahlvik, 2003):

• NOx emissions are generally lower for natural gas than for diesel. However, a great 

variability was seen for natural gas in many tests, resulting in higher average NOx

emissions for the fleet. Using EGR and other advanced engine technologies, diesel NOx

emissions can be reduced, thus reducing the apparent advantage of natural gas. Test 

cycles could also have a significant impact on NOx emissions.

• HC and NMHC emissions are generally lower for diesel than for natural gas. This is 

usually also the case for CO emissions, but very low CO emissions could be achieved 

with an oxidation catalyst on natural gas as well.

• PM mass emissions from uncontrolled diesel engines are higher than from natural gas. If 

particulate filters are used, diesel PM emission can be reduced to the same or lower level 

than natural gas. Ultralow sulfur diesel fuel is essential for the use of some types of 

particulate filters.

Emissions with natural gas depend not only on the fuel but also on the engine technology. 

Therefore, direct comparisons with the diesel engine are not always straightforward.

Table A7 provides an emission comparison of the ECI LNG kit as applied to an approximately 

25-year-old, EMD 16-645-E3 3,000-horsepower diesel locomotive with two EPA Tier 2 diesel 

locomotives (BNSF, 2007). 
79

Table A7. Emissions from LNG and Diesel Locomotives, G/BHP-HR

Mode THC NMHC CO NOx PM

ECI Natural Gas Conversion 7.55 1.17 10.0 5.2 0.38

Diesel Tier 2 compliant EMD 0.22 0.22 1.0 5.1 0.07

Diesel Tier 2 compliant GETS 0.16 0.16 0.4 5.3 0.10

The data shows that the LNG locomotive has no emission advantage over the Tier 2 diesels. It 

may be possible to design a natural gas locomotive engine that would have cleaner emissions 

than a Tier 2 diesel.

Fuel consumption is generally lower for diesel fuel than for natural gas. However, because 

natural gas contains more hydrogen than diesel fuel, the CO2 emissions are sometimes lower for 

natural gas.

A.6.4 Future Trends

The authors believe that future emission standards can be met using both clean diesel and natural 

gas technology. Thus, the choice of fuel will largely depend on the economics and fuel 

availability and infrastructure factors. According to the experience of U.S. railroad operators, 

natural gas-fueled locomotives are more expensive to operate than diesel equipment (BNSF,

2007). The economics, however, may change in favor of natural gas, because the price ratio of 

crude oil to natural gas has been increasing and has already reached twice the historical level.

With the improving natural gas economics, manufacturers are evaluating natural gas large bore 

engine programs for a wider range of applications including rail. In 2011, development of natural 

gas fueling for large engines was announced by Westport Innovations of Vancouver, BC, 

Canada—a developer and manufacturer of natural gas fuel systems and natural gas engines 

including heavy-duty highway truck engines. In a project partially funded by Sustainable 

Development Technology Canada, Westport will design high-performance LNG technology for 

high-horsepower applications such as mining, rail, and marine. A prototype fuel system will be 

tested and demonstrated in service using a Canadian National Railways locomotive. In a separate 

project, Westport will cooperate with Caterpillar to evaluate direct injection, natural gas, fuel 

system technologies for use on Caterpillar’s large engines in various applications, potentially 

including rail. The evaluation is expected to be completed in 2012.

Support of natural gas-fueled locomotives would also require significant investments in new 

fueling infrastructure that are duplicative to establish diesel-based infrastructure. These 

infrastructure investments and their associated operating costs must be accounted for in any 

evaluation of cost-effectiveness.

A.7 Propane

LPG, most often referred to as propane, is typically a mixture containing at least 90-percent 

propane, approximately 2.5-percent butane, and higher HCs, and a balance of ethane and 

propylene. LPG is a byproduct of natural gas processing and petroleum refining. LPG is a well-
80

established commercial fuel with existing fuel quality specifications. Special requirements exist 

for storage and handling of LPG, but the technology is well understood.

Propane has been one of the earliest alternative fuel considered for locomotive use. Already in 

1936, the Plymouth Locomotive Company built a propane locomotive for the Joplin-Pittsburg 

Railroad in Missouri (BNSF, 2007). The fuel was stored in three cylinders under the carbody. A 

spark ignited engine, rated at 450 hp, was used. The locomotive was retired around 1980. 

Considerable interest in LPG locomotives existed among railroads during the late 1950s and 

early 1960s (SwRI, 1961). The interest was driven by the perceived cost savings from converting 

from diesel to propane.

Liquid propane is stored under moderate pressures in special tanks. The liquid propane is 

typically vaporized and supplied to the engine as a gaseous fuel. Compared with natural gas, the 

saturated vapor pressure of LPG is lower, which makes it possible to store LPG at lower 

pressures and at ambient temperatures (as opposed to the cryogenic temperatures of LNG). In 

many other respects, including the engine technology as well as emission issues, similarities 

exist between natural gas and LPG.

As in the case with natural gas, LPG engine technologies include dual-fuel, diesel pilot injection 

and 100-percent LPG spark-ignited combustion. In 1953, an LPG gas-turbine-electric locomotive 

was also tested by UP, but the idea was ultimately abandoned because of poor fuel economy 

(BNSF, 2007).

Some renewed interest in the possibility of using propane as locomotive fuel has been sparked by 

the availability of NOx emission credits and incentive programs in NOx emission sensitive areas, 

such as parts of Texas. A study by the SwRI evaluated the feasibility of using LPG-fueled 

switcher locomotives in the Port of Houston, TX—a nonattainment area in regards to ozone/NOx

(Bourn, 2003). The results of NOx emission modeling in the study showed that NOX emission 

savings of 5.3–14.9 tons of NOx per year per locomotive were possible with LPG compared to 

the current diesel equipment available at that time (NOx reductions varying from 55 to 85 percent 

for the LPG compared with diesel were assumed). The propane engines will generally have a 10-

to 15-percent disadvantage in thermal efficiency compared with the diesel counterparts,

depending on the combustion technology selected. On the basis of the fuel prices gathered in the 

study, the use of propane would increase the operational costs unless incentives are used.

A.8 DME

A.8.1 DME Properties

DME (CH3OCH3) is the simplest ether, consisting of two methyl groups bonded to a central 

oxygen atom. DME, most commonly produced from natural gas, provides a possible avenue for 

the utilization of natural gas reserves, especially those that are inaccessible by pipelines. Because 

DME can be produced from coal, via gasification and synthesis gas, it receives increasing 

attention as potential automotive fuel in countries with coal resources. Renewable DME could be 

produced via gasification of biomass.

DME has replaced freon as an environmentally friendly and safe aerosol propellant, which is one 

of its major current applications. In the 1990s, a worldwide quantity of 100,000–150,000 tons per 

annum DME was produced (Verbeek, 1997).
81

DME is a colorless gas at room temperature with an ethereal odor, a vapor pressure of 0.593 

megapascals (MPa) (4450 mm Hg) at 25 °C, and is highly flammable in air (3.4–18 percent) 

(DuPont, 2000). Because of its vapor pressure, it is handled and stored as liquefied gas, in the 

form of a colorless clear liquid, similar to LPG. DME has no corrosive effect on metals, but it is 

an excellent solvent that can dissolve a number of elastomers (including those used in 

conventional diesel fuel systems).

Because of its low autoignition temperature, DME can be used as a fuel for diesel (compression 

ignition) engines. DME is characterized by a relatively high cetane number of 55–60 but an 

inferior heating value compared with diesel fuel. Physical and chemical properties of DME are 

compared with those of other fuels in Table A8 (Basu, 1995; Ogawa, 2003; Ohno, 2003).

Table A8. Comparison of DME with Other Fuels

Property

Fuel

DME Diesel Methane Propane Methanol

Formula CH3OCH3 - CH4 C3H8 CH3OH

Boiling temperature, °C -25 ~150–380 -162 -42 65

Vapor pressure @293 K, kPa 618 - - 942 -

Explosion limit, % in air 3.4–17 0.6–6.5 5-15 2.1-9.4 5.5–36

Liquid density

 @20 °C, kg/m3 660 800–840 420 490 790

Liquid viscosity 

 @25 °C, kg/ms 0.12–0.15 2–4 - 0.2 -

Gas specific gravity (vs air) 1.59 - 0.55 1.52 -

Lower heating value, MJ/kg 28.4 42.5 49.4 46.3 19.5

Gas lower heating value, 

MJ/Nm3 59.3 - 35.9 91.0 -

Cetane number 55–60 40–55 0 ~5 ~5

Autoignition temperature*, °C 350 206a 632 504 470

* with air at 0.1 MPa.

a – n-Cetane.

kg, kilogram.

No standard specifications exist for DME as automotive fuel. Proposed DME fuel specifications 

have been suggested by IEA and Japan (RENEW, 2008).

A.8.2 DME Engines

Because of the different fuel handling and properties, the use of DME requires dedicated DME 

engines, with fuel systems resembling those for LPG fuel. DME engine developments have been 

taking place mostly in Japan and Europe. The world’s first DME vehicle was reportedly a 2-ton 

light-duty truck converted from diesel to DME by NKK Corporation in 1998 (Ohno, 2001).
82

In Europe, Volvo has developed DME engines and vehicles in cooperation with other partners. 

In 1999, the first-generation Volvo DME vehicle prototype was built. In 2005, a secondgeneration Volvo DME truck—the FM model powered by a 9-liter, 300-horsepower DME 

engine—was unveiled. The vehicle met Euro V emission standards through the use of EGR and 

an oxidation catalyst.

Figure A8 shows a prototype DME storage and injection system developed for a prototype 

DME-fueled bus (Hansen, 2001). The fuel system consists of the following main components:

• Fuel tanks with level indicators, integrated submerged fuel pumps for low-pressure 

supply of liquid DME

• Valves, connectors, and fuel lines, including safety enhancing devices (pressure relief 

valves)

• Purge tank for storage of gaseous DME

• Pneumatic control unit for the purge system

• Air-driven purge compressor

• Electrical control unit and driver interface

• Wiring harness

Because DME provides insufficient lubrication in the injection system, a lubrication additive 

must be added.
83

Figure A8. DME Fuel System Layout (Volvo)

The performance of engines converted to DME fuel was reported to be roughly equivalent to that 

of the diesel engine before conversion. This is illustrated in Figure A9, which shows similar

thermal efficiency (BSFC) of diesel and DME. (Ohno, 2001). An improvement in engine noise 

was also recorded with DME.
84

Figure A9. DME and Diesel Engine Performance Comparison (Constant Speed 2000 RPM)

A.8.3 Emissions with DME

DME is characterized by a low autoignition temperature and by an instantaneous evaporation 

when injected into the cylinder. Because of the fast fuel evaporation, DME engines can achieve 

low PM emissions without the need for diesel particulate filters.

NOx emissions can be controlled to a degree through the injection rate shaping. However,

controlling NOx emissions to Euro V levels (2 g/kWh) requires the additional use of EGR. 

Meeting the U.S. 2010 NOx limit (0.2 g/bhp-h) in DME engines may require the use of both 

EGR and NOx aftertreatment.

DME fuel may cause a significant increase of CO emissions. An increase of gas-phase HC is 

also possible. These emissions are easy to control with the use of a diesel oxidation catalyst.

Figure A10 illustrates NOx and smoke (PM) emission benefits from the use of DME (Ohno,

2001). As evident from the chart, the potential of DME for smoke (PM) reduction is higher than 

that for NOx reduction.

Figure A10. Smoke and NOx Emissions with DME (Constant speed 2000 rpm, 2-ton diesel 

truck converted to DME)
85

Although there are few published reports about the use of DME, engines using it may also 

produce negative emission effects. For instance, formation of methyl nitrite, CH3ONO, an 

asthma causing gas, has been suspected with ester-based fuels including DME (Joseph, 2007).

The CO2 efficiency of diesel and DME was reported to be very similar. In a heavy-duty engine 

application, if the well-to-wheel CO2 emissions of the diesel engine equal 1.00, the emissions of 

DME are 1.02 (Verbeek, 1997). According to other sources, CO2 emissions with DME, relative 

to diesel, would range between 0.96 and 1.14 (Basu, 1995).

A.8.3 Experience with Large Bore Engines

A 1.25-megawatt DME engine was developed (Masuda, 2007) on the basis of a Daihatsu DK 

series medium-speed diesel engine for power generation. The development of the engine was 

intended to promote earlier commercialization of decentralized DME power generation systems. 

The developed DME diesel engine of 1.25-megawatt class had a cylinder bore of 260 millimeters

(mm), a stroke of 380 mm, and an engine speed of 750 min–1

. A modified jerk fuel injection 

pump was installed in the FIE system to supply the increased (1.8 times) volumetric fueling rate. 

The feeding pressure in the fuel circulation line was set to a high level to ensure that the DME 

fuel remained liquid.

A trial test demonstrated that the DME engine had a thermal efficiency comparable to 

conventional diesel engines. No black smoke was observed from the stack when the engine was 

started or during low load operation. The authors confirmed that the engine could be operated 

with DME in a stable condition from low to high load. 

To control NOx emissions to very low levels, the same DME engine was operated with EGR as 

well as with SCR using DME as a reducing agent (Shimizu, 2007). With EGR ratios over 40 

percent, NOx was reduced to below 30 parts per million (ppm) (O2 = 13 percent). With a 

combination of EGR and DME-SCR, NOx was further reduced to 15 ppm, a 99-percent reduction 

from the original engine-out emissions.

In a more theoretical study, two laboratory engines (a one-cylinder engine of 102 mm bore, 105 

mm stroke, 12.5-kilowatt power, and a four cylinder engine) were operated using natural gas, 

with a small amount of DME as an ignition source (Ishida, 2007). The authors operated the 

engines in homogeneous charge compression ignition (HCCI) mode. The minimum DME 

amount to achieve stable ignition was determined depending on engine operating parameters.

A.9 Ethanol-Diesel Blends

Some suppliers offer blends of ethanol with diesel fuel, often referred to as “e-diesel,” for use in 

unmodified diesel engines. Typically, standard diesel fuel (such as No. 2) is blended with up to 

15 percent (by volume) of ethanol using an additive package that may comprise from 0.2 to 5.0 

percent of the blend. There is currently no specification for e-diesel in the United States, and the 

fuel must be considered experimental.

Relative to diesel, e-diesel blends without additives are typically characterized by poor stability, 

low flash point, high volatility, low cetane number, and low lubricity. Cold flow properties tend 

to improve even though cloud point can be significantly higher. E-diesel additive packages are 
86

designed to improve the blend stability, cetane number, and the lubricity in the final blended 

product. Low flash point and high volatility persist. The exact properties depend on the ethanol 

content and on the additive.

Ethanol has a flashpoint of approximately 17 °C, while that of diesel fuel, depending on grade 

and the jurisdiction, is 38 °C and higher. Blends of 10- to 20-percent ethanol with diesel have 

flashpoints almost identical to that of neat ethanol. Adding ethanol to diesel makes the resulting 

blend a Class I liquid (flashpoint < 37.8 °C) according to the U.S. NFPA ratings. Diesel fuel is a 

Class II liquid. Class I liquids have more stringent storage requirements including more distant 

location of storage tanks from property lines, buildings, other tanks, and vent terminals as well as 

the requirement of flame arrestors on all vents and in the fill necks (Waterland, 2003; Weyandt,

2003). This means that e-diesel must be stored and handled like gasoline.

E-diesel can produce reductions in some regulated emissions. Most studies find decreased PM 

emissions with e-diesel. PM emission reductions up to 30 percent and higher have been reported. 

Results with CO, HC, and NOx tend to be mixed, including increases and decreases (Corkwell,

2003).

A number of potential operational issues exist with e-diesel, mainly related to two properties: the 

high volatility and low viscosity of e-diesel blends. In some FIE systems, the high volatility of ediesel may lead to cavitation, resulting in damage to fuel injectors, the injection pump, and/or the 

transfer pump (Waterland, 2003). Cavitation may be especially significant in engines with fuel 

systems that produce increased fuel temperatures. Therefore, the effect of e-diesel on injection 

equipment must be tested before wider deployment on each type/model of the diesel engine.

The lower viscosity of e-diesel can increase pump and injector leakage, resulting in reduced 

maximum fuel delivery and lower peak power. Hot restart problems may be encountered as well

because of insufficient fuel being injected at cranking speed (Hansen, 2005).

As it is the case with fuel additive-based technologies, the e-diesel additive package may 

contribute to fuel injector fouling. Considering the high-additive content in e-diesel, up to 

approximately 5 percent, the quality of the additive package is of critical importance.

A.10 Coal Slurry Fuels

Coal slurry fuels are obtained typically by mixing finely dispersed coal particles with 

conventional diesel fuel or with water. The mixture is then combusted in the diesel engine. 

Stimulated by high oil prices, the technology of coal slurry fuel was developed in the 1980s 

(Nydick, 1987; Flynn, 1990; Caton, 1994). After the oil price returned to a low level, studies and 

commercial projects on coal slurry fuel were practically suspended for several years. The recent 

increase in oil prices caused a renewed interest in the technology, especially in countries with 

abundant coal resources such as China.

In a newer Chinese study (Cui, 2008), a new process was presented for the preparation of 

superfine coal–oil slurry intended as fuel for high-speed diesel engines. The process uses highpressure jet mills to reduce coal particle size and to mix the coal with diesel fuel. The coal 

content in the slurry was 50 percent, and the mean diameter of coal particles was 2.71 

micrometers.

There are no comprehensive literature reports on the effect of coal slurries on the performance 

and emissions in modern diesel engines, and the technology must be considered experimental. 
87

Several potential issues exist, including the effect on slurry properties (stability, heat value, and 

rheological behavior with potentially high viscosity), on combustion and emissions, and on fuel 

injection components and engine wear.

A.11 Hydrogen Technology for Locomotive Applications

A.11.1 Hydrogen Powertrains

Fuel Cells

Fuel cells are electrochemical devices that convert the energy of a chemical reaction directly into 

electricity, with heat and water as byproducts. They differ from batteries in that the fuel and 

oxidant are stored externally. This enables them to continue operating as long as fuel and oxidant 

are supplied. The main types of fuel cell being developed are the following (DOE, 2008):

• Polymer electrolyte or proton exchange membrane fuel cells (PEMFCs), also known 

as solid polymer fuel cells (SPFCs). PEMFCs/SPFCs operate at relatively low 

temperatures between 80 and 120 °C and are fueled by high-purity hydrogen. Because of

their fast startup time, low sensitivity to orientation, and favorable power-to-weight ratio, 

PEMFCs are particularly suitable for use in passenger vehicles such as cars and buses.

• Direct methanol fuel cells (DMFCs) are similar to PEMFCs except that DMFCs operate 

directly on methanol without the need to reform it to hydrogen first. 

• Molten carbonate fuel cells (MCFCs) operating at about 650 °C are being developed 

for combined heat and power (CHP) and distributed generation applications. They are 

typically fueled by natural gas. MCFCs take a long time to reach operating temperatures 

and are slow to respond to changes in power demand. This makes them unsuitable for 

transport applications.

• Solid oxide fuel cells (SOFCs) are also being developed for CHPs and distributed 

generation applications. Their high temperature of operation (800–1000 °C) provides the 

opportunity to combine them with gas turbines to give electrical efficiencies as high as 70 

percent. Lower temperature SOFCs operating at 650–750 °C are also being developed for 

vehicle auxiliary power units (APUs) and stationary power applications. As with MCFCs, 

SOFCs are slow to respond to changes in power demand and are unsuitable for many 

transport motive power applications. The high temperature of operation allows SOFCs to 

be fueled by HC fuels. This eliminates the fuel storage and distribution issues currently 

facing other fuel types (such as PEMFCs). 

• Phosphoric acid fuel cells (PAFCs) are one of the most mature types of fuel cell and 

were the first to be used commercially. They are typically used for stationary power 

generation, but some have been used in early fuel cell bus demonstration projects running 

on methanol. PAFCs have much lower power densities than PEMFCs, and they are also 

expensive.

• Alkaline fuel cells (AFCs) were one of the first fuel cell technologies developed and 

widely used in the early U.S. space program. AFCs have high efficiency but are very 

easily poisoned by CO2. They require high-purity hydrogen and oxygen. 
88

Fuel cells offer a number of benefits over internal combustion engines including higher 

efficiencies, quiet operation, much lower or no local emissions, and a modular construction that 

is scalable to meet higher power requirements. The different fuel cell technologies all face 

similar development challenges. Fuel cell performance depends fundamentally on the 

electrochemical reactions that occur within the core fuel cell stack itself. Fuel cell systems are 

complex and currently costly because of the expensive materials required for catalysts, 

electrodes, and membranes, and because of the additional peripheral equipment (e.g. cooling 

systems, complex fuel storage requirements, power conditioners, and fuel processor/reformer) 

required.

PEMFCs are the type of fuel cell predominantly being considered for transport applications and 

are closest to market commercialization.

Hydrogen Internal Combustion Engines

Although not as widely discussed as fuel cells, hydrogen internal combustion engines could 

allow rapid deployment of hydrogen-fueled vehicles and enable a hydrogen refueling 

infrastructure to become more economically viable. Hydrogen internal combustion engines are 

much closer to commercial deployment for transport applications than fuel cells. 

Hydrogen internal combustion engines can currently be manufactured more cheaply than fuel 

cell powertrains. They are only approximately 15 percent more expensive than conventional 

gasoline engines (DOE, 2008) used in road vehicles. They also have the additional advantage of 

running on pure hydrogen or a blend of hydrogen and CNG.

Hydrogen Storage

Main methods of hydrogen storage include the following (DOE, 2008):

• Compressed hydrogen. The storage of hydrogen in pressurized tanks is the most 

commonly used technology for large-scale storage. The limitations of compressed 

hydrogen storage relate to the tank materials’ permeability to hydrogen and to their 

mechanical stability under pressure. Storage at 5,000 pounds per square inch (psi) is 

common, but high-pressure storage tanks capable of up to 10,000 psi are being developed 

to improve storage density. 

• Liquid hydrogen. The storage of hydrogen as a cryogenic liquid offers higher storage 

densities than compressed gas. The low temperature, however, requires cryogenic cooling 

equipment capable of cooling the hydrogen to approximately 20 K (–253 °C) at 1 bar. 

Extremely effective insulation is required to maintain this low temperature. 

• Metal hydrides. Metal hydrides have the potential to provide reversible onboard 

hydrogen storage and release at low temperatures (25–120 °C) and pressures (1–10 

atmosphere) ideally suitable for the fuel temperature and pressure requirements of 

PEMFCs. The release of hydrogen from metal hydrides is an endothermic process (heat 

must be supplied) and, in some cases, could use waste heat from the fuel cell.

Research and development priorities are in the development of new materials and systems to 

enhance storage density and to reduce costs. Figure A11 summarizes volumetric and gravimetric 

storage densities and costs for some fuel storage options for mobile applications (DOE, 2008). 
89

Figure A11. Comparison of Gravimetric and Volumetric Storage Capacities of Some 

Hydrogen Storage Options

Figure A12 compares the storage capacity and storage cost (£) of several hydrogen storage 

options with diesel fuel (Butterworth, 2005). It is clear that none of the options compare very 

favorably with diesel fuel storage.

Figure A12. Comparison of Some Hydrogen Storage Options to Diesel Fuel Storage

A.11.2 Rail Applications

Scott (1993) and coworkers (Steinberg, 1984; Jones, 1985) carried out some of the earlier 

research work looking at fuel cell locomotives. An economic analysis of applying a 2,345-
90

kilowatt alkaline fuel cell by using liquid hydrogen to a commuter train suggested that fuel 

savings from the increased efficiency of the fuel cell locomotive could offset increased capital 

costs and make it cost-competitive with conventional diesel locomotives (Steinberg, 1984). 

An examination of conceptual designs of an alkaline fuel cell-powered locomotive for long-haul 

passenger and freight service was also carried out. An analysis based solely on fuel costs that 

assumed that electricity prices would remain static at approximately $7.30 GJ–1 (U.S. dollars in 

1984) and diesel fuel costs would rise to as high as $20 GJ–1 (U.S. dollars in 1984) predicted that 

by the year 2000, a fuel cell locomotive could be competitive with one using diesel (Jones,

1985). 

However, in a more comprehensive study that included an estimate of capital costs, Scott 

concluded that fuel cell locomotives miss feasibility by approximately 1 order of magnitude. 

Although, hydrogen fuel cell locomotives could break even with diesels if targets were met for 

fuel cell performance and cost and fuel production cost. If CO2 emissions were to be included 

into life-cycle costing, hydrogen fuel cell locomotives could show a significant advantage over 

diesel (Scott, 1993).

More recently, work has been presented on the development of a fuel cell switching locomotive 

(Miller, 2006, 2007a, 2007b; Barnes, 2007; Lustig, 2008). Led by Vehicle Projects LLC, an 

industry–government partnership is developing a prototype fuel cell-hybrid switcher locomotive 

for demonstration of rail yard applications in the Los Angeles basin and a power-to-grid 

application at Hill Air Force Base (Utah). 

Early work on the project was based on a preliminary design of 1.2 megawatts of gross fuel cell 

power coupled with 250 kg of metal-hydride hydrogen storage. The first fuel cell considered was 

a PEMFC type for stationary application. A number of problems were encountered early in the 

project. Testing of one of the eight fuel cell modules that would eventually make up the 1.2-

megawatt fuel cell stack resulted in multiple stack failures and significant anode flooding. The 

costs of the metal hydride storage system, at about $10,000/kg hydrogen, also proved to be 

excessive, and the absence of any previous experience with the feasibility of such a large scale 

metal hydride storage system proved to present too many uncertainties. Overall, the design was 

overweight, excessively large, and too costly (Barnes, 2007).

As a result of these problems, the preliminary design was re-evaluated, and a hybrid design that 

uses a smaller fuel cell pack coupled to a battery bank was selected. It had the potential to reduce 

the cost significantly, because it minimized the use of fuel cells, and it prolonged fuel cell life 

because its operation was closer to steady state. Although battery hybrids are not a good choice 

for line-haul operation, they can be well suited to a switcher locomotive. 

The final design used a commercially available RailPower Corporation Green Goat hybrid 

switcher locomotive. These locomotives used a 205-kilowatt diesel generator set and a bank of 

lead-acid batteries. In the fuel cell version, the diesel generator was replaced with 250 kW of 

Ballard Power Systems’ Mark 902 P5 fuel cells. Instead of the 250 kg of metal hybrid storage, 

70 kg of gaseous compressed hydrogen was stored in 14 Dynetek 350 bar (5,000 psi) composite 

cylinders mounted on the roof of the locomotive (Figure A13). The final drive train was able to 

provide over 1 megawatt of peak power. Final demonstration occurred in 2008. Additional 

design details are outlined by Miller (2007a).
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Figure A13. Final Design of Fuel Cell/Battery Hybrid Switching Locomotive

The Rail Safety and Standards Board (RSSB) in the UK carried out a feasibility study for 

hydrogen trains (Butterworth 2005). They concluded that the current state of development of fuel 

cell technology is not mature enough, and demonstration projects for mainstream rail 

applications are not justified at this time. Technical concerns related to current fuel cell 

technology included durability, heat dissipation, and maximum fuel cell power output.

Automotive PEMFC applications are being developed with a 5,000-hour lifetime in mind. For 

rail applications, much longer lifetimes would be required. Butterworth (2005) estimated that 

lifetimes of approximately 16,000–18,000 h would be needed for fuel cells to be competitive 

with diesel multiple unit (DMU) engines, and lifetimes of 30,000–40,000 h would be needed for 

fuel cells to be competitive with diesel locomotive engines.

Heat dissipation is a particularly important issue. Although fuel cell powertrains produce similar 

levels of waste heat as internal combustion engines, 80 percent of the heat generated must be 

dissipated via the radiator. For diesel engines, waste heat dissipation is split between the radiator 

and the exhaust stack.

Currently, the most powerful fuel cells for transport applications have an output of 

approximately 200 kW. Rail applications will need higher power outputs if traction power 

requirements are to be met. This is likely to be possible in future years, but there may still be 

issues regarding the ability to package such a fuel cell powertrain in a rail vehicle.

It was suggested, however, that SOFC APUs using diesel fuel could be used on diesel 

locomotives and DMUs and could provide some real air quality and noise benefits in the near 

term and such demonstrations should be pursued. Such APUs could also be used for maintenance 

vehicles for enclosed spaces, signaling applications, track circuits/point machines at semirural 

locations, and point heating.

One rail fuel cell application that may warrant consideration with the current state of fuel cell 

development is diesel fueled SOFCs for APUs.
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A.12 Diesel Combustion Technology

A.12.1 Advanced Combustion Concepts

Low-Temperature Combustion

The recent evolution of the diesel combustion process has been significant. Advanced 

combustion strategies currently under development attempt to decrease the combustion 

temperature to lower NOx emissions and, in some cases, PM emissions. These approaches carry 

numerous names such as HCCI and PCCI that may or may not accurately reflect the combustion 

process.

HCCI was one of the early diesel combustion concepts that differed from the conventional diesel 

process to attract attention. As the name implies, a homogeneous premixed mixture is formed 

much the same way as in a spark ignition engine. This can be achieved either by injecting fuel 

into the intake port or directly into the cylinder early enough to allow complete mixing of air and 

fuel. The charge then ignites as it is heated during the compression stroke.

To address many of the challenges, such as limited load range, controllability, and knocking 

posed by HCCI, several other concepts have evolved from this homogeneous charge approach, 

and in many cases, charge stratification was introduced. Although these concepts carry names 

such as Toyota’s UNIBUS and Nissan’s MK concepts, there has unfortunately been a tendency 

to refer to them generally as HCCI. This is slowly evolving, and LTC is slowly gaining 

acceptance as a general term for these advanced combustion concepts.

Early work with HCCI demonstrated that engine-out NOx and PM emissions could be lowered to 

approximately 1–10 percent of current diesel engine technology through changes to the 

combustion process, possibly eliminating the need for aftertreatment devices to meet regulated 

emission limits.

One characteristic that HCCI and other LTC concepts share is that either all or a significant 

amount of fuel is premixed with air before ignition occurs. The combustion rate of such 

premixed LTC concepts is controlled by the chemical kinetics of the mixture. This greatly 

complicates the control of the combustion process as well as making it sensitive to fuel 

properties. Many premixed LTC concepts benefit from low cetane number fuels.

Premixing of air and fuel can also be a major factor in conventional diesel combustion. However, 

in conventional diesel combustion, the rate of combustion is mainly determined by the rate of 

mixing of air and unburned/partially burned fuel. The conventional diesel combustion process is 

thus often referred to as mixing-controlled combustion. This mixing control characteristic greatly 

simplifies the control of the heat release process.

Although much of the work with LTC has focused on premixed LTC concepts, it has been 

demonstrated that mixing-controlled diesel combustion can also be adopted to produce NOx

emissions in the 0.2 g/kWh range—comparable to those achievable with premixed LTC concepts 

(Haugen, 2004; Gray, 2005; Eismark, 2006; EPA 2008). Although such mixing-controlled 

approaches could be considered to be conventional diesel combustion, they do require lower 

combustion temperatures to control NOx and unconventional hardware to manage PM emissions. 

These engines require such features as advanced fuel injection systems that provide injection 

pressures as high as 3,000 bar and air management systems producing levels of boost pressures 

that require multistage turbochargers. Such approaches could be referred to as mixing-controlled 
93

LTC concepts. Unlike premixed LTC approaches, it has been shown that mixing-controlled LTC 

can operate over the entire speed and load range of the engine (Haugen, 2004; Gray, 2005; EPA,

2008).

Although significant resources have been spent studying HCCI and other LTC concepts, 

successful commercial applications to date have been limited. Although Toyota’s UNIBUS 

(Hasegawa, 2003) and Nissan’s MK (Kimura, 1999) concepts have been introduced 

commercially in some markets, they are unable to operate over the entire engine speed and load 

range, conventional diesel combustion must still be used at high load conditions, and 

aftertreatment devices are still needed.

In the North American market, Navistar (2007) and Cummins (2007) both announced that they 

would be able to meet 2010 U.S. EPA on-road heavy-duty emission requirements with engines 

that use only PM aftertreatment and no NOx aftertreatment. Although the actual approach is not 

entirely clear, the 2010 engines by Navistar—currently certified to NOx levels of 0.5 g/bhp-h and 

below without NOx aftertreatment—do require reductions in combustion temperatures and are 

believed to use some form of premixed LTC approach. Fuel economy is one of the key issues in 

developing LTC engines. Cummins (2008) eventually decided to change its technology approach

for 2010 and introduced urea-SCR Nox aftertreatment in all engines to improve fuel efficiency.

Regardless of whether an LTC approach is mixing-controlled or premixed, large amounts of 

cooled EGR are almost always required to keep combustion temperatures low enough to achieve 

low NOx and/or to control heat release rates and combustion phasing.

Miller Cycle

The Miller cycle (or the Miller valve timing) involves an early closure of the inlet valve. It 

produces reduced compression temperatures, which in turn result in NOx emission reductions. 

This strategy also allows for increased engine efficiency, but careful optimization of the 

combustion process is required to control such issues as pumping losses, transient load 

acceptance, or increased engine noise.

The Miller cycle is believed to have been used in the Caterpillar ACERT truck engines 

introduced in 2003. It is also an NOx control option for four-stroke medium-speed diesel engines, 

including locomotive engines (Nerheim, 2007). 

The use of a highly efficient (often a two-stage) turbocharger is required with the Miller cycle to 

ensure that sufficient airflow is retained in spite of the reduced intake period. PM emissions tend 

to be increased with Miller timing, necessitating the use of injection equipment with significantly 

increased pressures as well as improved turbochargers. 

Because of engine performance issues, it may not be possible to use the Miller cycle throughout 

the entire engine map. If the use of the Miller cycle is limited to some engine operating

conditions, an intake valve actuator may be necessary to switch between the Miller and the 

conventional diesel cycle valve timing.

A.12.2 Medium-Speed Engine Trends

The application of advanced combustion strategies to medium-speed diesels requires the use of 

cooled EGR. Cooled EGR with a conventional diesel combustion system, such as used in most 
94

2007 and later North American heavy-duty trucks, has seen little or no commercial application in 

medium-speed diesel engines. Challenges to applying EGR to commercial medium-speed 

locomotive engines include the following:

• Cooling system demands. Substantial increase in the cooling system demands are 

difficult to accommodate in already crowded locomotives.

• Lube oil compatibility. A new lube oil formulation would likely be needed to 

accommodate increased soot levels.

• Possible fouling concerns. Locomotive test cycles have a high weighting for idle 

operation where application of EGR can be challenging.

• Fuel sulfur levels. Corrosion of engine components by sulfuric acid may be a concern.

Notwithstanding the above issues, in-cylinder NOx control (as opposed to urea-SCR 

aftertreatment) has been chosen by most locomotive engine manufacturers for meeting the Tier 

3/Stage IIIB emission standards.

The new MTU Series 4000 R44 engine, meeting EU Stage IIIB emissions, will cover a power 

range from 1,000 to 3,000 kW for the line-haul and switcher applications (Wintruff, 2010). In 

2012, 12V and 16V versions will be available, to be followed by 8V and 20V engines. The Stage 

IIIB NOx limit (NOx + HC = 4 g/kWh) is achieved without aftertreatment, whereas a DPF will be 

used to meet the 0.025 g/kWh PM limit. The engine features cooled EGR, Miller valve timing, 

the MTU two-stage turbocharger, and the LEAD common rail injection system by L’Orange. 

The DPF system—which includes an upstream oxidation catalyst (DOC) and a catalyzed DPF—

has been designed to rely on passive NO2-based regeneration starting from 260°C. At light loads, 

the exhaust temperature is increased through an active engine management strategy. The engine 

matches the fuel consumption of its R43 predecessor.

GETS presented a Tier 3 version of its Evolution locomotive engine (Blythe, 2010). The Tier 3 

(2012) PM standard of 0.10 g/bhp-h requires a nearly 50-percent PM emission reduction from 

the Tier 2 levels. This has been achieved by reduced lube oil consumption (by 50 percent), the 

use of reduced ash lube oil, and replacement of the legacy unit pump injection system by a 180-

megapascal Bosch common rail system with multiple injection capabilities. A moderate level of 

Miller valve timing was adopted to maintain the fuel consumption of Tier 2 engines.

Although no reports are published on emission systems in Tier 4 locomotives, both GETS and 

EMD are believed to favor in-cylinder NOx control, without the use of urea-SCR.

A growing number of medium-speed engines (both diesel and natural gas) in marine and power 

generation applications are also adopting the Miller cycle in conjunction with two-stage 

turbocharging. The first commercial application of two-stage turbocharging on a medium-speed 

diesel engine is the Wärtsilä W20V32 engine (Raikio, 2010), featuring a twin low-pressure/twin 

high-pressure turbo configuration that can provide a pressure ratio of approximately 8.

A.12.3 Existing Rail Engines

Emission reductions and efficiency improvements can be achieved in existing locomotive 

engines through repowering with more advanced combustion and control technologies. An 

example repower product is the 710ECOTM launched in 2007 by EMD.
95

The 710ECO repower engine is emission certified to the EPA Tier 2 locomotive standards. It is 

designed for use with 2,000- to 3,150-horsepower switching locomotives and features a 90-

percent parts commonality with existing EMD 710 engine equipped locomotives. The engine is 

electronically controlled and includes an integrated automatic engine start stop system for idle 

reduction.

According to the manufacturer, the 710ECO repower product provides a 25-percent reduction in 

fuel consumption and greater than 50-percent lube oil savings.

A.13 Energy Recovery Technologies

A.13.1 Hybrid Locomotives

Hybrid locomotives allow the recovery of some of the braking energy, which can be used to 

provide power resulting in improved fuel economy and reduced GHG emissions. Figure A14 is a 

schematic of a hybrid locomotive (GE, 2007).

Figure A14. Hybrid Locomotive

In a conventional locomotive, energy generated by the traction motors (A in Figure A14) during 

braking is dissipated entirely as heat through resistor grids (B). In contrast, in a hybrid 

locomotive, some of that energy is captured in a series of rechargeable batteries (C). The 

captured energy can then be used to provide power in one of three ways:

• Hybrid power mode—In combination with diesel-electric power (provided by the engine 

(D) and the electric system (E)) to consistently deliver the required horsepower

• Power boost—As an addition to full diesel-electric power for quick acceleration from a 

full stop

• Primary power—As the primary power source (full battery power)

One of the major challenges in the development of hybrid technologies is the high-energy 

storage requirement and the battery technology.
96

GETS is developing the 4,400-horsepower Evolution Hybrid diesel-electric locomotive, with a 

target fuel consumption reduction of 10 percent compared with conventional locomotives. GETS

unveiled a prototype unit during its Ecomagination Event in Los Angeles in 2007. The hybrid 

locomotive used a new sodium-based (lead-free) type of rechargeable batteries.

A.13.2 Waste Heat Recovery

Future powertrains will likely include exhaust gas energy recovery systems. In the diesel engine, 

the exhaust gas enthalpy represents a significant fraction of the chemical energy of the fuel—up 

to over 30 percent—which is one of the most significant sources of thermal efficiency loss. 

Exhaust heat recovery systems may range from simple heat exchangers to such technologies as 

turbocompounding, thermodynamic cycles converting heat into work (e.g., Rankine), or 

thermoelectrics. 

There are two major types of turbocompounding systems: (1) mechanical turbocompounding and 

(2) electric turbocompounding.

The mechanical turbocompounding system, schematically represented in Figure A15, is based on 

the premise that exhaust from the first turbine (T1) has enough energy left to turn a second 

turbine wheel (T2). This excess energy is high enough to give T2 power that is adequate to lend 

the crankshaft some assistance. This additional power provided to the crankshaft by T2 is 

considered part of the exhaust heat recovery and results in real fuel economy benefits. For the 

same power output, BSFC for a turbo-compounded engine is lower than a turbochargedintercooled engine.

Figure A15. Schematic Representation of Turbocompounding

Turbocompounding systems have been commercialized by Garrett. Sweden’s Scania claims the 

credit for the first truck engine with turbocompounding, which entered series production in 1991 

(turbocompounding was later dropped, then re-introduced in 2001, and also used in the first 

Scania Euro IV truck engine in 2004). Mechanical turbocompounding is generally more suitable 

for large engine installations such as power generation or bulk fluid pumping stations. The 
97

reason for this is the expense involved in gearing down from high turbine rotational speeds to 

crankshaft speeds.

Exhaust gas heat energy can be also recovered in the form of electrical power through the 

addition of an alternator/motor unit to the turbocharger, Figure A16 (Algrain, 2003). In this 

configuration, referred to as electric turbocompounding, the mechanical connection between the 

turbine and the crankshaft and the second turbine itself is eliminated.

Figure A16. Electric Turbocompounding

A high-speed electrical generator is incorporated directly into the turbocharger assembly and 

placed on a common shaft between the compressor and the turbine. The generated electricity can 

be used to run engine auxiliaries (starter, oil pump, water pump, air compressor, HVAC, etc.), 

thus providing a fuel economy benefit. Ongoing development projects for heavy-duty engines 

target a fuel economy improvement on the order of 5 percent (Algrain, 2003). Electric 

turbocompounding also provides high flexibility in turbocharger control, including the capability 

to operate the generator as a motor to provide assistance to the turbocharger at moments when 

increased boost is required (i.e., to operate the device as a supercharger).

Thermodynamic cycles are being developed where a number of waste heat streams can be 

recovered in the form of electricity. Engine thermal efficiency improvement of about 10 percent, 

from approximately 42 to 46 percent, is typically targeted. 

Figure A17 illustrates the waste heat recovery concept by Cummins (Nelson, 2007). A 10-

percent thermal efficiency improvement is targeted—6 percent from EGR energy, 2-percent 

exhaust energy, 2-percent electric accessories—through the implementation of the organic 

Rankine cycle. In this thermodynamic cycle, a working liquid is evaporated in a boiler using the 

heat being recovered to drive a turbine. The energy is ultimately recovered as electricity via a 

generator.
98

Figure A17. Cummins Waste Heat Recovery Concept

Thermoelectrics are solid-state devices capable of converting heat into electricity for such uses 

as cooling, heating, and power generation (Majumdar, 2004). Research aimed at using 

thermoelectric generators to produce electricity from waste exhaust heat in light- and heavy-duty 

diesel engines has been sponsored by the U.S. DOE (Fairbanks, 2007).

Thermoelectric modules can be operated as (1) refrigeration units and/or (2) power generation 

units, as Figure A18 illustrates. In the refrigeration mode, the thermoelectric unit consumes 

electricity to provide cooling. In the power generation mode, the unit generates electricity from 

heat energy.
99

Figure A18. Thermoelectric Modules

Significant progress in the efficiency of thermoelectrics has been achieved in the recent years. 

Although today’s materials still have insufficient efficiency for exhaust gas recovery, 

thermoelectrics have been commercially used since 2000 for climate control seat systems 

(heating/cooling) in high-end automobiles. The goal of the DOE-sponsored research is to 

introduce thermoelectric exhaust heat recovery systems in production personal vehicles in the 

2011–2014 timeframe to improve fuel economy by a nominal 10 percent. The technology may 

be nearing commercialization, because BMW intends to introduce thermoelectric generators in 

the 5 Series cars in 2010–2014 (Fairbanks, 2008). The system currently tested by BMW can 

generate 750 watts during highway driving, equivalent to an 8.3-percent improvement in fuel 

economy and about half of that amount in city driving.

Because of their ability to operate without moving parts and without a refrigerant gas or a 

heating medium, thermoelectrics are potentially attractive for a wide range of future applications. 

The U.S. Navy conducted thermoelectric air-conditioning tests on a submarine (USS Dolphin 

AGSS 555) for silent running. Assuming further technology progress, long-term applications 

could include thermoelectric generators replacing propulsion engines or a plug-in solid-state 

hybrid with multifuel capability.

A.13.3 Flywheel Energy Storage

The application of flywheel energy storage has been considered for a variety of rail applications. 

In one study examining the practicality and viability of a flywheel energy storage system to a 

switching locomotive, it was noted that the attractiveness of the system is very dependent on the 

operational scenario of the locomotive. On the basis of the operation of locomotives at different 

flat yards and a large amount of data on the operating environment of switching locomotives, it 

was concluded that a boxcar was required to carry the energy storage unit, because no room 

existed on the locomotive. No difference in locomotive energy consumption was apparent with 

the flywheel energy storage system for a typical flat-yard operation. The duty cycle of the 
100

switching operations did not provide enough energy recovery. Brake maintenance savings, 

although significant, were not sufficient to give an attractive return on investment (Cook, 1979).

The case of a Class I railroad operating over a major mountain pass with a long downhill, and 

thus a much better duty cycle for dynamic braking, has also been examined (Painter, 2006). On 

the basis of simulation results, despite the fuel savings and emission reductions, no economic 

incentive was sufficient to warrant implementation of dynamic brake energy recovery at 2005 

fuel prices. When environmental benefits were weighed, a likely return on investment of 

approximately 5 years was found.

Another application for which flywheel energy storage has been studied is for high-speed 

locomotives using gas turbines. Although gas turbines offer a significant weight savings for 

high-speed locomotives, these turbines have two important disadvantages compared with diesel 

engines: (1) gas turbines produce a greater number of thermal cycles than diesel engines, which 

negatively affects maintenance requirements and (2) the energy efficiency of gas turbines is 

lower. A flywheel energy storage system would provide some load leveling to potentially reduce 

the number of thermal cycles and recover braking energy to increase overall energy efficiency. 

Although work on this project seems to be continuing at the University of Texas Center for 

Electromechanics, a Transportation Review Board Committee Review of Federal Railroad 

Administration Research, Development, and Demonstration Programs recommended in 2003 

that Federal funding for this program be phased out, because of technical, schedule, and budget 

risks (Thompson, 2003).
101

A.14 Bibliography

Ahlvik, P. 2003. “Natural Gas,” Revision 2003.05, DieselNet.com.

Algrain, M., and Hopmann, U. August 2003. “Diesel Engine Waste Heat Recovery Utilizing 

Electric Turbocompound Technology,” U.S. DOE, 9th Diesel Engine Emissions 

Reduction Conference (DEER), Newport, RI.

Alleman, T. L., and McCormick, R. L. 2007. “2006 B100 Quality Survey Results Milestone 

Report,” National Renewable Energy Laboratory, Golden, CO, USA, NREL/TP-540-

41549.

Alleman, T. L., and McCormick, R. L. 2008. “Results of the 2007 B100 Quality Survey,” 

Technical Report NREL/TP-540-42787.

Arons, S. M., et al. 2007. “A Low-Carbon Fuel Standard for California, Part 1: Technical 

Analysis,” California Air Resources Board, Sacramento, CA, USA.

Association of American Railroads. 2011. Railroad Facts. Washington, DC.

Barnes, D. L. 2007. “Fuelcell Prototype Locomotive,” Final Technical Report, U.S. Department 

of Energy, Office of Energy Efficiency and Renewable Energy, Golden Field Office, 

Hydrogen, Fuel Cells, and Infrastructure Technologies Program, Grant Award No. DEFG36-05GO85049.

Bartunek, B., and Hilger, U. 2000. “Direct Induction Natural Gas (DING): A Diesel-Derived 

Combustion System for Low Emissions and High Fuel Economy,” SAE Technical Paper 

2000-01-2827.

Basu, A., et al. 1995 July. “Dimethyl Ether: Amoco’s New Clean Diesel Option,” U.S. DOE, 1st 

Diesel Engine Emissions Reduction Workshop (DEER), San Diego, CA.

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Appendix B. International — Europe 

Excerpts from this section are from the Rail Safety Standards Board (RSSB) research and 

development program report “RSSB Energy April 2011” ( and from a joint study by 

International Union of Railways (UIC) and Association of Train Operating Companies (ATOC) 

titled “First UIC Report on Railways and Biofuels.” An overview of initiatives and strategies for 

using alternatives to fossil-fuel-based rail technology in Europe is presented.

B.1 RSSB

RSSB facilitates the resolution of difficult cross-industry issues and builds consensus. This 

section provides a guide into energy research conducted by RSSB. The program is funded by the 

Department for Transport in the UK and aims to assist the industry and its stakeholder in 

achieving key objectives. The primary area of engineering research in Europe is on further 

electrification. However, the purpose of this FRA study is to research energy sources other than 

electrification. The following projects provide a synopsis of ongoing and some concluded RSSB 

research activities (RSSB Energy Report April 2011).

“Feasibility study into the use of hydrogen fuel (T515)—This project studied 

the viability of hydrogen as a fuel for the rail industry. It explored the technology, 

how it can be developed, and whether or not there is a business case for 

development. The research led to the formation of a Future Fuels Technology 

Group (FFTG) to consider the carious fuels and storage technologies that might 

be applied to the UK railway over a 30-year horizon. The findings of the research 

project indicated that hydrogen is a conceptually viable fuel and informed 

research project T711 Hydrogen fuel cell trial.

Hydrogen fuel cell trial (T722)—The purpose of this research was to develop 

the UK position with respect to hydrogen fuelled rail vehicles. The FFTG was 

keen to participate in the European project to develop a hydrogen powered train, 

however, the development funding priorities in Europe were focused on 

automotive applications and it was not practical for UK to develop a project 

alone.

Regenerative braking on AC and DC electrified lines (T580)—The project 

investigated the extent to which regenerative braking is used currently on the UK 

mainline railways. It examined the scope for further use and established the 

anticipated scale of energy efficiency and CO2 emissions benefits which might be 

realized over future years.

The research demonstrated the benefits of regenerative braking and is being used 

by the industry-wide Regenerative Braking Steering Group, which is actively 

championing the introduction of regenerative braking. On the AC railway, the 

majority of vehicles that can use regenerative braking are now doing so, and on 

the DC railway, steady progress is being made toward full implementation.

Investigation into the use of sulfur-free diesel fuel on UK railways (T536)—

This project investigated the impact of moving to the use of reduced sulphur 
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diesel by performing trials on representative train fleets. This research project has 

provide an insight into understanding the problems associated with introducing a 

new type of diesel fuel onto the UK railway and has also informed the train 

operating companies’ strategic decision regarding which new diesel fuels can be 

safely implemented. 

Further research has been undertaken in research project T697 Investigation into 

use the use of biodiesel fuel on the UK railway, which also looked at alternative 

diesel fuels, particular biodiesel, for use on the UK railway. 

Investigation into the use of biodiesel fuel on UK railways (T697)—This 

research project has assessed the impact of biodiesel in the diesel engines of 

railway locomotives and DMUs in the UK. From this research project, the Diesel 

Metering Group has concluded the following are two important barriers to 

biodiesel usage:

• The sustainability of the fuel source is a political/ environmental decision 

and requires verification of the source of the fuel.

• Economics, not engineering, is the concern for biodiesel blends up to B20.

ATOC and key members of the Diesel Metering Group will continue to promote 

the findings and results of the research to other industry members including 

presentations at sustainability conferences and engineering forums. Already the 

emerging findings have been used by ATOC in support of discussions with HM 

Treasury and more specifically by parties involved in franchise bidding as the 

tradeoff between cost of operating and other government targets. The Department 

for Transport has started consultation on the Renewable Transport Fuel 

Obligation.

Review of potential rail vehicle fuels and “energy carriers” (T721)—This 

project considered the potential of more radical and long-term solutions for 

energy such as biogas, methanol, ammonia, battery technology, and flywheels. 

This project was initiated by the FFTG to establish what potential there was for 

the application of novel fuels in the rail industry. The report did not find any 

further suitable fuels that had not been previously identified, and it concluded that 

improved diesel fuels, whether from mineral or bio sources, were among the most 

suitable for rail application. Of the novel fuels, only hydrogen could be 

considered to be a contender in the future.”

B.2 UIC and ATOC—Railway and Biofuels 

Because of the initiatives currently under investigation in Europe, as they relate to the uses of 

biofuels, and the conclusions from RSSB that improved diesel fuels were among the most 

suitable for rail from other potential fuel sources, an overview of information as it relates to 

biofuels are included in this section. According to the report, “First UIC Report on Railways and 

Biofuels” (July 2007),

“...biofuels have the potential to reduce emissions of GHG, gases that contribute 

to climate change. They can also increase energy security, reducing a country’s 

reliance on imported energy products. 
110

The principal forms of biofuel are biodiesel, which can be blended with, or 

replace diesel, and bioethanol, which can be blended with, or replace petrol. In the 

EU, an indicative target of 5.75 percent (by energy content), set in the Biofuels 

Directive (2003/30/EC), is stimulating the increased use of biofuels, in particular 

biodiesel, for EU road transport. There are also discussions on increasing the 

proportion beyond 5.75 percent to say 10-20 percent (Source: EC 8/9 March 

Presidency conclusions).

Many countries are responding to this directive by introducing tax incentives and 

obligations on manufacturers to produce biofuel and add it to conventional 

transport fuels. Outside of the EU, many countries are taking similar policy 

actions. There is also the possibility of using one of the so-called flexible 

mechanisms of the Kyoto Protocol, the Clean Development Mechanism, to 

stimulate the development of biofuel technology in developing countries.

Railways already have an environmental advantage over other forms of air and 

road transport as seen in various reports (Source: ATOC Baseline Statement,

April 2007). This is diminishing, due to rapid progress in the other transport 

sectors. Biofuels offer an opportunity to help rail to maintain or improve its green 

credentials and promote modal shift, as an environment conscious society may 

choose rail over other modes of transport. This should increase rail usage and 

indeed, transport market share. Biofuels can also provide an alternative source of 

transportable energy, which may help to increase the security of supply for the rail 

industry.

There is also scope for potential cost savings if sufficient tax exemptions and 

incentives could be applied by Member States to railways. Finally, these items all 

contribute to meeting the requirement of the EEA TERM paper: “a shift to more 

environmentally friendly modes should be sought where appropriate,” and the 

Kyoto Protocol which pledges to: “cut EU-15 GHG emissions by an 8 percent

reduction on 1990 levels by 2012.” Although there are significant advantages to 

be realized, there are important issues and risks that need to be considered and 

addressed such as the following:

Supply—The Biofuels Directive has resulted in an increased use of biofuel from

virtually nothing in the 1990s to an estimated 3500 million litres in 2005. Planned 

or recent increases in production capacity suggest that earlier predictions of 

biodiesel supply in 2012 of 14,000 million litres (Source: IEA 2004) might be an

underestimate.

Demand—Compliance with the EU target on increasing transport biofuel using

biodiesel alone will potentially require 16,000 million liters by 2012. However, 

given the likely increased demand resulting from the various policy initiatives 

around the world, the railway sector is likely to face global competition for 

biodiesel. Biomass to liquid or second generation biofuel will offer a higher yield 

and can help increase supply to help meet the rising demand. However, the 

processes and technologies for the production of second generation biodiesel are 

still being developed and are uncertain.
111

Costs—Currently, biodiesel costs significantly more than diesel and this is a

disincentive to using biodiesel. The costs and prices are volatile, being related to 

the biofuel source and supply and demand market forces.

• Governments could subsidize biodiesel production, but a complication is 

that currently it is difficult to guarantee that the fuel being subsidized is 

not coming from an unsustainable source, which may be worse in terms 

of GHG emissions than the substituted fossil fuels.

• A worldwide/EU (See Section A.3) certification scheme could give

governments the confidence to offer discounts to reduce costs to the end

user. A potential alternative is for governments to legislate and consumers

pick up the costs.

Technical—Initial engine results from desk top analysis and test bench work 

shows that biodiesel is feasible for use in railway traction unit engines in lower 

percentage blends. However, there are potential disadvantages such as increased 

fuel consumption and decreased power. Blends in excess of B30 (30 percent 

biodiesel content) may increase maintenance costs, although it is expected that

second generation biofuels will be of a higher specification and may prove to be 

better than fossil fuels.

• Biodiesel can influence the emissions from engines, and this needs to be 

considered in light of EU Directive on NonRoad Mobile Machinery stage 

IIIB or equal legislation. For example, using biodiesel is likely to increase 

NOx emissions, but lower PM emissions, even if tests results vary from 

railway to railway.

• In Germany and the UK, some road transport is currently using biodiesel 

blends of up to 50 percent. To meet the expected rail demand, MTU have 

already developed an engine that is capable of running on B100, (Source: 

MTU, section 6.2) and undoubtedly, others are under development.

Global Sustainability—Information in this report shows biofuels are able to 

reduce GHG emissions by up to 80 percent considering the whole life cycle of 

production, transport and combustion. But there are still some uncertainties about 

the sustainability of biofuels, and it is still difficult for customers to be sure of the 

environmental credentials of the biofuels they are buying and to be certain of the 

benefits they provide. With certification schemes in place that are supported by 

the nongovernment organizations, it would be possible for customers to be 

confident that their biodiesel was produced in a sustainable manner and know 

what GHG savings the fuel actually delivers.”

B.3 Emissions Standards in Europe

B.3.1 Background

Emission standards for railway locomotives have been established by the UIC, a Paris-based 

association of European railway companies. UIC issues technical leaflets on railway equipment 

and components, which are termed “standards” and are binding to member railways. Emission 
112

standards for rail locomotives are specified in UIC Leaflet 624, published in April 2002 and 

titled “Exhaust emission tests for diesel traction engines.”

The UIC emission standards apply to diesel engines for railway traction, with the exception of 

engines for special locomotives (e.g., refinery or mine locomotives) and traction engines with an 

output of less than 100 kW. The standards apply to all new engines used in new vehicles or for 

repowering of existing locomotives.

B.3.2 Emission Standards

Table B1 lists the UIC locomotive emission standards. The test method is ISO 8178, cycle F.

Table B1. UIC Locomotive Emission Standards

Stage Date

Power, P Speed, n CO HC NOx PM Smoke

kW rpm g/kWh BSN

UIC I up to 2002.12.31 3 0.8 12 - 1.6-2.5a

UIC II 2003.1.1

P ≤ 560 2.5 0.6 6.0 0.25

P > 560

n > 1000 3 0.8 9.5 0.25b

n ≤ 1000 3 0.8 9.9 0.25b

a - Bosch smoke number (BSN) = 1.6 for engines with an air throughput of above 1 kg/s; BSN = 2.5 for 

engines below 0.2 kg/s; linear BSN interpolation applies between these two values.

b - For engines above 2200 kW, a PM emission of 0.5 g/kWh is accepted on an exceptional basis until 

2004.12.31.

The UIC Stage III standards are harmonized with the EU Stage IIIA standards for nonroad 

engines [Directive 97/68/EC].

ISO 8178 International Standard (http://www.dieselnet.com/standards/cycles/iso8178.html)

The ISO 8178 is an international standard designed for a number of nonroad engine applications. 

It is used for emission certification and/or type approval in many countries worldwide, including 

the United States, EU, and Japan. Depending on the legislation, the cycle can be defined by 

reference to the ISO 8178 standard, or else by specifying a test cycle equivalent to ISO 8178 in 

the national legislation (as is the case with the U.S. EPA regulations). 

The ISO 8178 is actually a collection of many steady-state test cycles (types C1, C2, D1, etc.) 

designed for different classes of engines and equipment. Each of these cycles represents a 

sequence of several steady-state modes with different weighting factors.

The ISO 8178 test cycle—or its 8-mode schedule C1 in particular—can be also referred to as the 

“NonRoad Steady Cycle.”
113

Appendix C. U.S. National Fire Protection Association Diamond 

Placard Designations

Health (Blue) Flammability (Red)

0 Poses no health hazard, no precautions 

necessary (e.g., water) 0 Will not burn (e.g., argon)

1 Exposure would cause irritation with only 

minor residual injury (e.g., acetone) 1 Must be heated before ignition can occur (e.g., mineral oil). Flash point over 93°C (200°F)

2

Intense or continued but not chronic exposure 

could cause temporary incapacitation or 

possible residual injury (e.g., ethyl ether)

2

Must be moderately heated or exposed to 

relatively high ambient temperature before 

ignition can occur (e.g., diesel fuel). Flash point 

between 38°C (100°F) and 93°C (200°F)

3

Short exposure could cause serious 

temporary or moderate residual injury (e.g., 

chlorine gas)

3

Liquids and solids that can be ignited under 

almost all ambient temperature conditions 

(e.g., gasoline). Liquids having a Flash point 

below 23°C (73°F) and having a Boiling point at 

or above 38°C (100°F) or having a Flash point 

between 23°C (73°F) and 38°C (100°F)

4

Very short exposure could cause death or 

major residual injury (e.g., hydrogen cyanide, 

phosphine, carbon monoxide)

4

Will rapidly or completely vaporize at normal 

atmospheric pressure and temperature, or is 

readily dispersed in air and will burn readily 

(e.g., propane, hydrogen). Flash point below 

23°C (73°F) Instability/Reactivity (Yellow) 

Special (White)

Instability/Reactivity (Yellow) Special (White)

0

Normally stable, even under fire exposure 

conditions, and is not reactive with water (e.g., 

helium)

0

The white "special notice" area can contain 

several symbols. The following symbols are 

defined by the NFPA 704 standard.

1

Normally stable, but can become unstable at 

elevated temperatures and pressures (e.g., 

propane) 

2

Undergoes violent chemical change at 

elevated temperatures and pressures, reacts 

violently with water, or may form explosive 

mixtures with water (e.g., phosphorus, 

potassium, sodium) 

O

X

Oxidizer (e.g., potassium perchlorate, 

ammonium nitrate, hydrogen peroxide)

3

Capable of detonation or explosive 

decomposition but requires a strong initiating 

source, must be heated under confinement 

before initiation, reacts explosively with water, 

or will detonate if severely shocked (e.g., 

ammonium nitrate)

W Reacts with water in an unusual or dangerous 

manner (e.g., cesium, sodium, sulfuric acid)

4

Readily capable of detonation or explosive 

decomposition at normal temperatures and 

pressures (e.g., nitroglycerine, Trinitrotoluene) 
114

Abbreviations and Acronyms

AFC alkaline fuel cell

APU auxiliary power unit

ASTM American Society for Testing and Materials

ATOC Association of Train Operating Companies

bcm billion cubic meters

BNSF BNSF Railway

BSFC brake-specific fuel consumption

Btu British thermal unit

CAFE Corporate Average Fuel Economy

CBA Cost-benefit analysis

CFR U.S. Code of Federal Regulations

CHP combined heat and power

CNG compressed natural gas

CO2 carbon dioxide

CO carbon monoxide

CTL coal-to-liquid

CSFT cold soak filtration test

DDC Detroit Diesel Corporation

DFNG dual fuel natural gas

DGE diesel gallon equivalent

DING direct injection natural gas

DME dimethyl ether

DMFC direct methanol fuel cell

DMU diesel multiple unit

DOD U.S. Department of Defense

DOE U.S. Department of Energy

DOT Department of Transportation

DPF diesel particulate filter

ECI Energy Conversions, Inc.

EGR exhaust gas recirculation
115

EIA Energy Information Administration

EMD Electro-Motive Diesel, Inc.

EN European Committee for Standardization

EPA U.S. Environmental Protection Agency

EPAct Energy Policy Act of 1992

EU European Union

FAME fatty-acid methyl ester

FEL family emission limit

FFTG Future Fuels Technology Group

FIE fuel injection equipment 

FRA Federal Railroad Administration

FT Fischer-Tropsch

FTC U.S. Federal Trade Commission

FTP Federal Test Procedure

g/bhp-h grams per brake horsepower hour

GenSet generator set technology = sets of engines turning a generator

GETS General Electric Transportation Systems

GHG greenhouse gases

g/km grams per kilometer

GREET Greenhouse gases, Regulated Emissions, and Energy use in Transportation

GTL gas-to-liquid

H2 hydrogen

HC hydrocarbons

HCCI homogeneous charge compression ignition

HIRC Hydrogen Innovation Research Center

h hour

HVO hydrotreated vegetable oil

IANGV International Association for Natural Gas Vehicles

IEA International Energy Agency

IRS U.S. Internal Revenue Service

kg kilogram

kWh kilowatt hour

LaCHIP late-cycle high injection pressure technology
116

LEM Life-cyle Emission Model

LNG liquefied natural gas

LPG liquefied petroleum gas (propane)

LTC low temperature combustion

MCFC molten carbonate fuel cell

MJ megajoule

MK Morrison Knudsen Corporation

mm millimeter

MMbd million barrels per day

MOU memorandum of understanding

MPa megapascal

NBB National Biodiesel Board

NFPA National Fire Protection Association

NMHC nonmethane hydrocarbon

NOx oxides of nitrogen

NREL National Renewable Energy Laboratory

OEM original equipment manufacturer

PAFC phosphoric acid fuel cell

PCCI premixed charge compression ignition

PEMFC polymer electrolyte or proton exchange membrane fuel cell

PING pilot injection of diesel fuel and premixing natural gas

PM particulate matter

PM FEL particulate matter family emission limit

ppm part per million

psi pound per square inch

RFS Renewable Fuel Standard

RSSB Rail Safety Standards Board

SCR selective catalytic reduction 

SING spark ignited natural gas

SOFC solid oxide fuel cell

SPFC solid polymer fuel cells

SwRI Southwest Research Institute

t/a metric tons per annum
117

THC total hydrocarbons

TRB Transportation Research Board

TTCI Transportation Technology Center, Inc.

TWC Three way catalysts

UIC Union Internationale des Chemins de fer/International Union of Railways

UK United Kingdom

UP Union Pacific Railroad Company