Federal Technology Alert

Internet: www.eere.energy.gov/femp/

No portion of this publication may be altered in any form without

prior written consent from the U.S. Department of Energy, Energy

Efficiency and Renewable Energy, and the authoring national laboratory.

Leading by example,

saving energy and

taxpayer dollars

in federal facilities.

The boiler plant at the

Department of Energy’s

Savannah River Site

co-fires coal and biomass.

DOE/EE-0288

Biomass Cofiring in Coal-Fired Boilers

Using this time-tested fuel-switching technique in existing federal boilers helps to reduce operating 

costs, increase the use of renewable energy, and enhance our energy security

Executive Summary

To help the nation use more domestic fuels and renewable energy technologies—and 

increase our energy security—the Federal Energy Management Program (FEMP) in the 

U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, assists 

government agencies in developing biomass energy projects. As part of that assistance, 

FEMP has prepared this Federal Technology Alert on biomass cofiring technologies. This 

publication was prepared to help federal energy and facility managers 

make informed decisions about using biomass cofiring in existing coalfired boilers at their facilities. 

The term “biomass” refers to materials derived from plant matter such as 

trees, grasses, and agricultural crops. These materials, grown using energy 

from sunlight, can be renewable energy sources for fueling many of today’s 

energy needs. The most common types of biomass that are available at 

potentially attractive prices for energy use at federal facilities are waste 

wood and wastepaper. 

One of the most attractive and easily implemented biomass energy 

technologies is cofiring with coal in existing coal-fired boilers. In biomass cofiring, biomass 

can substitute for up to 20% of the coal used in the boiler. The biomass and coal are 

combusted simultaneously. When it is used as a supplemental fuel in an existing coal boiler, 

biomass can provide the following benefits: lower fuel costs, avoidance of landfills and 

their associated costs, and reductions in sulfur oxide, nitrogen oxide, and greenhouse-gas 

emissions. Other benefits, such as decreases in flue gas opacity, have also been documented.

Biomass cofiring is one of many energy- and cost-saving technologies to emerge as feasible 

for federal facilities in the past 20 years. Cofiring is a proven technology; it is also proving 

to be life-cycle cost-effective in terms of installation cost and net present value at several 

federal sites. 

Energy-Saving Mechanism

Biomass cofiring projects do not reduce a boiler’s total energy input requirement. In fact, in 

a properly implemented cofiring application, the efficiency of the boiler will be the same 

as it was in the coal-only operation. However, cofiring projects do replace a portion of the 

nonrenewable fuel—coal—with a renewable fuel—biomass.

Cost-Saving Mechanisms

Overall production cost savings can be achieved by replacing coal with inexpensive biomass 

fuel sources—e.g., clean wood waste and waste paper. Typically, biomass fuel supplies 

should cost at least 20% less, on a thermal basis, than coal supplies before a cofiring project 

can be economically attractive.

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Energy Efficiency

and Renewable Energy

Bringing you a prosperous future where energy

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Payback periods are typically 

between one and eight years, and 

annual cost savings could range 

from $60,000 to $110,000 for an 

average-size federal boiler. These 

savings depend on the availability 

of low-cost biomass feedstocks. 

However, at larger-than-average 

facilities, and at facilities that can 

avoid disposal costs by using selfgenerated biomass fuel sources, 

annual cost savings could be 

significantly higher.

Application

Biomass cofiring can be applied 

only at facilities with existing 

coal-fired boilers. The best 

opportunities for economically 

attractive cofiring are at coal-fired 

facilities where all or most of 

the following conditions apply: 

(1) coal prices are high; (2) annual 

coal usage is significant; (3) local 

or facility-generated supplies 

of biomass are abundant; (4) 

local landfill tipping fees are 

high, which means it is costly 

to dispose of biomass; and (5) 

plant staff and management are 

highly motivated to implement 

the project successfully. As a 

rule, boilers producing less than 

35,000 pounds per hour (lb/hr) 

of steam are too small to be used 

in an economically attractive 

cofiring project. 

Field Experiences

Cofiring biomass and coal is a 

time- tested fuel-switching strategy 

that is particularly well suited 

to a stoker boiler, the type most 

often found at coal-fired federal 

facilities. However, cofiring has 

been successfully demonstrated 

and practiced in all types of coal 

boilers, including pulverized-coal 

boilers, cyclones, stokers, and 

fluidized beds. 

To make economical use of captive 

wood waste materials—primarily 

bark and wood chips that are 

unsuitable for making paper—the 

U.S. pulp and paper industry 

has cofired wood with coal for 

decades. Cofiring is a standard 

mode of operation in that industry, 

where biomass fuels provide more 

than 50% of the total fuel input. 

Spurred by a need to reduce fuel 

and operating costs, and potential 

future needs to reduce greenhouse 

gas emissions, an increasing 

number of industrial- and utilityscale boilers outside the pulp and 

paper industry are being evaluated 

for use in cofiring applications.

Case Study Summary

The U.S. Department of Energy’s 

(DOE) Savannah River Site (SRS) 

in Aiken, South Carolina, has 

installed equipment to produce 

“alternate fuel,” or AF, cubes from 

shredded office paper and finely 

chipped wood waste. After a 

series of successful test burns have 

been completed to demonstrate 

acceptable combustion, emissions, 

and performance of the boiler 

and fuel processing and handling 

systems, cofiring was expected to 

begin in 2003 on a regular basis. 

The biomass cubes offset about 20% 

of the coal used in the facility’s two 

traveling-grate stoker boilers. The 

project should result in annual coal 

cost savings of about $112,000.

Cost savings associated with 

avoiding incineration or landfill 

disposal of office waste paper 

and scrap wood from on-site 

construction activities will total 

about $172,000 per year. Net 

annual savings from the project, 

after subtracting the $30,000 

per year needed to operate the 

AF cubing facility, will be about 

$254,000. An initial capital 

investment of $850,000 was 

required, resulting in a simple 

payback period for the project 

of less than four years. The net 

present value of the project, 

evaluated over a 10-year analysis 

period, is about $1.1 million.

Test burns at SRS have shown 

that the present stoker boiler fuel 

handling equipment required no 

modification to fire the biomass/ 

coal mixture successfully. No 

fuel-feeding problems were 

experienced, and no increases 

in maintenance are expected to 

be needed at the steam plant. 

Steam plant personnel have 

been supportive of the project. 

Emissions measurements made 

during initial testing showed 

level or reduced emissions for all 

eight measured pollutants, and 

sulfur emissions are expected to 

be reduced by 20%. Opacity levels 

also decreased significantly. The 

project will result in a reduction of 

about 2,240 tons per year in coal 

usage at the facility.

Implementation Barriers

For utility-scale power generation 

projects, acquiring steady, yearround supplies of large quantities of 

low-cost biomass can be difficult. 

But where supplies are available, 

there are several advantages 

to using biomass for cofiring 

operations at federal facilities. For 

example, federal coal-fired boilers 

are typically much smaller than 

utility-scale boilers, and they are 

most often used for space heating 

and process heat applications. 

Thus, they do not have utility-scale 

fuel requirements. 

In addition, federal boilers 

needed for space heating typically 

operate primarily during winter 

months. During summer months, 

waste wood is often sent to the 
Federal Technology Alert

mulch market, which makes the 

wood unavailable for use as fuel. 

Thus, federal coal-fired boilers 

could become an attractive 

winter market for local wood 

processors. This has been one 

of the driving factors behind a 

cofiring demonstration at the 

Iron City Brewery in Pittsburgh, 

Pennsylvania.

These are some of the major 

policy and economic issues 

and barriers associated with 

implementing biomass cofiring 

projects at federal sites:

• Permit modifications may be 

required. Permit requirements 

vary from site to site, but 

modifications to existing 

emissions permits, even for 

limited-term demonstration 

projects, may be required for 

cofiring projects.

• Economics is the driving factor.

Project economics largely 

determine whether a cofiring 

project will be implemented. 

Selecting sites where waste wood 

supplies have already been 

identified will reduce overall 

costs. Larger facilities with 

high capacity factors—those 

that operate at high loads 

year-round—can utilize more 

biomass and will realize greater 

annual cost savings, assuming 

that wood supplies are obtained 

at a discount in comparison 

to coal. This will also reduce 

payback periods.

Conclusion

DOE FEMP, with the support 

of staff at the DOE National 

Laboratories and Regional Offices, 

offers many services and resources 

to help federal agencies implement 

energy efficiency and renewable 

energy projects. Projects can be 

funded through Energy Savings 

Performance Contracts (ESPCs), 

Utility Energy Services Contracts, 

or appropriations. Among these 

resources is a Technology-Specific 

“Super ESPC” for Biomass and 

Alternative Methane Fuels (BAMF), 

which facilitates the use of biomass 

and alternative methane fuels to 

reduce federal energy consumption, 

energy costs, or both. 

Through the BAMF Super ESPC, 

FEMP enables federal facilities 

to obtain the energy- and costsavings benefits of biomass and 

alternative methane fuels at no 

up-front cost to the facility. More 

information about FEMP and 

BAMF Super ESPC contacts and 

contract awardees is provided in 

this Federal Technology Alert.

Disclaimer

This report was sponsored by the United States Department of Energy, Energy Efficiency and Renewable Energy, Federal 

Energy Management Program. Neither the United States Government nor any agency or contractor thereof, nor any of 

their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, 

completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would 

not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring 

by the United States Government or any agency or contractor thereof. The views and opinions of authors expressed herein do 

not necessarily state or reflect those of the United States Government or any agency or contractor thereof. 
Federal Technology Alert

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Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 1

Contents

 Abstract .......................................................................................................2

 About the Technology ................................................................................3

 Application Domain

 Cost-Saving Mechanisms

 Other Benefits

 Installation Requirements

 Federal-Sector Potential ..............................................................................9

 Estimated Savings and Market Potential

 Laboratory Perspective

 Application ............................................................................................... 11

 Application Prerequisites

 Cost-Effectiveness Factors

 Where to Apply

 What to Avoid

 Equipment Integration

 Maintenance

 Equipment Warranties

 Codes and Standards

 Costs

 Utility Incentives

 Project Financing and Technical Assistance

 Technology Performance .......................................................................... 17

 Field Experience

 Fuel Supply and Cost Savings Calculations ............................................. 17

 Case Study — Savannah River Cofiring Project ....................................... 18

 Facility Description

 Existing Technology Description

 New Technology Description

 Energy Savings

 Life-Cycle Cost

 Performance Test Results

 The Technology in Perspective ................................................................20

 Manufacturers .......................................................................................... 21

 Biomass Pelletizing Equipment

 Boiler Equipment/Cofiring Systems

 Biomass and Alternative Methane Fuels (BAMF) Super ESPC

 Competitively Awarded Contractors

 For Further Information ........................................................................... 21

 Bibliography .............................................................................................. 21

 Appendix A: Assumptions and Explanations for Screening Analysis .....23

 Appendix B: Blank Worksheets for Preliminary Evaluation of a 

 Cofiring Project ........................................................................................24 

 Appendix C: Completed Worksheets for Cofiring Operation at

 Savannah River Site ..................................................................................28 

 Appendix D: Federal Life-Cycle Costing Procedures and BLCC 

 Software Information ............................................................................... 31 

 Appendix E: Savannah River Site Biomass Cofiring Case Study: 

 NIST BLCC Comparative Economic Analysis ..........................................33
Federal Technology Alert

2 — FEDERAL ENERGY MANAGEMENT PROGRAM

Abstract

Biomass energy technologies 

convert renewable biomass fuels 

to heat or electricity. Next to 

hydro-power, more electricity 

is generated from biomass than 

from any other renewable energy 

resource in the United States. 

Biomass cofiring is attracting 

interest because it is the most 

economical near-term option for 

introducing new biomass resources 

into today’s energy mix.

Figure 1. The NIOSH boiler plant was 

modified to cofire biomass with coal.

Cofiring is the simultaneous 

combustion of different fuels 

in the same boiler. Cofiring 

inexpensive biomass with fossil 

fuels in existing boilers provides 

an opportunity for federal energy 

managers to use a greenhousegas-neutral renewable fuel while 

reducing energy and waste 

disposal costs and enhancing 

national energy security. Specific 

requirements will depend on 

the site. But in general, cofiring 

biomass in an existing coalfired boiler involves modifying 

or adding to the fuel handling, 

storage, and feed systems. Fuel 

sources and the type of boiler 

at the site will dictate fuel 

processing requirements. 

Biomass cofiring can be 

economical at federal facilities 

where most or all of these criteria 

are met: current use of a coalfired boiler, access to a steady 

supply of competitively priced 

biomass, high coal prices, and 

favorable regulatory and market 

conditions for renewable energy 

use and waste reduction. Boilers 

at several federal facilities were 

originally designed for cofiring 

biomass with coal. Others were 

modified after installation to allow 

cofiring. Some demonstrations—

e.g., at the National Institute of 

Occupational Safety and Health 

(NIOSH) Bruceton Boiler plant in 

Pittsburgh, Pennsylvania (Figure 

1)—show that, under certain 

circumstances, only a few boiler 

plant modifications are needed 

for cofiring.

This Federal Technology Alert

was produced as part of the 

New Technology Demonstration 

activities in the Department 

of Energy’s Federal Energy 

Management Program, which 

is part of the DOE Office of 

Energy Efficiency and Renewable 

Energy, to provide facility and 

energy managers with the 

information they need to decide 

whether to pursue biomass 

cofiring at their facilities. 

This publication describes 

biomass cofiring, cost-saving 

mechanisms, and factors that 

influence its performance. 

Worksheets allow the reader to 

perform preliminary calculations 

to determine whether a facility 

is suitable for biomass cofiring, 

and how much it would save 

annually. The worksheets also 

allow required biomass supplies 

to be estimated, so managers can 

work with biomass fuel brokers 

and evaluate their equipment 

needs. Also included is a case 

study describing the design, 

operation, and performance of 

a biomass cofiring project at 

the DOE Savannah River Site in 

Aiken, South Carolina. A list of 

contacts and a bibliography are 

also included.
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 3

About the Technology

Biomass is organic material from 

living things, including plant 

matter such as trees, grasses, 

and agricultural crops. These 

materials, grown using energy 

from sunlight, can be good 

sources of renewable energy and 

fuels for federal facilities. 

Wood is the most commonly used 

biomass fuel for heat and power. 

The most economical sources of 

wood fuels are wood residues from 

manufacturers and mill residues, 

such as sawdust and shavings; 

discarded wood products, such 

as crates and pallets; woody yard 

trimmings; right-of-way trimmings 

diverted from landfills; and 

clean, nonhazardous wood debris 

resulting from construction and 

demolition work. Using these 

materials as sources of energy 

recovers their energy value and 

avoids the need to dispose of 

them in landfills, as well as other 

disposal methods. 

Biomass energy technologies 

convert renewable biomass fuels to 

heat or electricity using equipment 

similar to that used for fossil 

fuels such as natural gas, oil, or 

coal. This includes fuel-handling 

equipment, boilers, steam turbines, 

and engine generator sets. Biomass 

can be used in solid form, or it 

can be converted into liquid or 

gaseous fuels. Next to hydropower, 

more electricity is generated from 

biomass than from any other 

renewable energy resource in the 

United States. 

Cofiring is a fuel-diversification 

strategy that has been practiced 

for decades in the wood products 

industries and more recently 

in utility-scale boilers. Several 

federal facilities have also cofired 

biomass and coal. Cofiring involves 

substituting biomass for a portion 

of the fossil fuel used in a boiler. 

Cofiring inexpensive biomass with 

fossil fuels in existing federal boilers 

provides an opportunity for federal 

energy managers to reduce their 

energy and waste disposal costs 

while making use of a renewable 

fuel that is considered greenhousegas-neutral. Cofiring biomass 

counts toward a federal agency’s 

goals for increasing the use of 

renewable energy or “green power” 

(environmentally benign electric 

power), and it results in a net cost 

savings to the agency. Cofiring 

biomass also increases our use of 

domestic fuels, thus enhancing the 

nation’s energy security.

This publication focuses on the 

most promising, near-term, proven 

option for cofiring—using solid 

biomass to replace a portion of 

the coal combusted in existing 

coal-fired boilers. This type of 

cofiring has been successfully 

demonstrated in nearly all 

coal-fired boiler types and 

configurations, including stokers, 

fluidized beds, pulverized coal 

boilers, and cyclones. The most 

likely opportunities at federal 

facilities will be found at those 

that have stokers and pulverized 

coal boilers. This is because the 

optimum operating range of 

cyclone boilers is much larger than 

that required at a federal facility, 

and few fluidized bed boilers have 

been installed at federal facilities 

for standard, non-research uses. 

One of the most important keys to 

a successful cofiring operation is 

to appropriately and consistently 

size the biomass according to 

the requirements of the type of 

boiler used. Biomass particles can 

usually be slightly larger than coal 

particles, because biomass is a more 

volatile fuel. Biomass that does not 

meet these specifications is likely to 

cause flow problems in the fuelhandling equipment or incomplete 

burnout in the boiler. General 

biomass sizing requirements for 

each boiler type mentioned here 

are shown in Table 1.

Table 1. Biomass sizing requirements.

Existing Type Size Required

of Boiler (inches)

Pulverized coal ≤ 1/4 

Stoker ≤ 3 

Cyclone ≤ 1/2

Fluidized bed ≤ 3

More detailed information follows 

about the cofiring options for stoker 

and pulverized-coal federal boilers.

Stoker boilers. Most coal-fired boilers 

at federal facilities are stokers, 

similar to the one shown in the 

schematic in Figure 2. Because 

these boilers are designed to 

fire fairly large fuel particles on 

traveling or vibrating grates, they 

are the most suitable federal boiler 

type for cofiring at significant 

biomass input levels. In these 

boilers, fuel is either fed onto the 

grate from below, as in underfeed 

stokers, or it is spread evenly across 

the grate from fuel spreaders above 

the grate, as in spreader stokers. 

In the more common spreaderfired traveling grate stoker boiler, 

solid fuel is mechanically or 

pneumatically spread from the 

front of the boiler onto the rear of 

the traveling grate. Smaller particles 

burn in suspension above the grate, 

while the larger particles burn on 

the grate as it moves the fuel from 

the back to the front of the boiler. 

The ash is discharged from the 

grate into a hopper at the front of 

the boiler.
Federal Technology Alert

4 — FEDERAL ENERGY MANAGEMENT PROGRAM

The retrofit requirements for 

cofiring in a stoker boiler will vary, 

depending on site-specific issues. If 

properly sized biomass fuel can be 

delivered to the facility premixed 

with coal supplies, on-site capital 

expenses could be negligible. 

Some facilities have multiple coal 

hoppers that discharge onto a 

common conveyor to feed fuel 

into the boiler. Using one of the 

existing coal hoppers and the 

associated conveying equipment 

for biomass could minimize new 

capital expenses for a cofiring 

project. Both methods have been 

successfully employed at federal 

stoker boilers for implementing 

a biomass cofiring project. If 

neither of these low-cost options is 

feasible, new handling and storage 

equipment will need to be added. 

The cost of these additions is 

discussed later. 

Pulverized coal boilers. There are 

two primary methods for cofiring 

biomass in a pulverized coal boiler. 

The first method, illustrated in 

Figure 3, involves blending the 

biomass with the coal before 

the fuel mix enters the existing 

pulverizers. This is the least 

expensive method, but it is limited 

in the amount of biomass that 

can be fired. With this blended 

feed method, only about 3% or 

less of the boiler’s heat input can 

be obtained from biomass at full 

boiler loads because of limitations 

in the capacity of the pulverizer. 

The second method, illustrated 

in Figure 4 on page 5, requires 

installing a separate processing, 

handling, and storage system 

for biomass, and injecting the 

biomass into the boiler through 

dedicated biomass ports. Although 

this method is more expensive, it 

allows greater amounts of biomass 

to be used—up to 15% more on a 

heat input basis. If the biomass is 

obtained at a significant discount to 

current coal supplies, the additional 

expense may be warranted to offset 

coal purchases to a greater degree.

Application Domain

The best opportunities for cofiring 

biomass with fossil fuels at federal 

facilities are at sites with regularly 

operating coal-fired boilers. Biomass 

cofiring has been successfully 

demonstrated in nearly all coal-fired 

boiler types and configurations, 

including stokers, fluidized beds, 

pulverized coal boilers, and 

cyclones. The least expensive 

opportunities are most likely to be 

for stoker boilers, but cofiring in 

pulverized coal boilers may also be 

economically attractive.

At least 10 facilities in the federal 

sector have had experience with 

biomass cofiring. Two facilities—

the NIOSH Bruceton boiler plant in 

Pennsylvania and DOE’s Savannah 

River Site in South Carolina—have 

been considering implementing 

commercial cofiring applications. 

Other federal sites with cofiring 

experience include KI Sawyer 

Air Force Base in Michigan, Fort 

Stewart in Georgia, Puget Sound 

Naval Shipyard in Washington, 

Wright-Patterson Air Force Base in 

Ohio, Brunswick Naval Air Station 

in Maine, and the Red River Army 

Depot in Texas.

More than 100 U.S. companies 

or organizations have experience 

in cofiring biomass with fossil 

fuels, and many cofiring boilers 

are in operation today. Most are 

found in industrial applications, 

in which the owner generates a 

significant amount of biomass 

residue material (such as sawdust, 

scrap wood, bark, waste paper, or 

cardboard or agricultural residues 

Figure 2. Schematic of a typical traveling-gate speader-stoker.

Figure 3. Schematic of a blended-feed cofiring arrangement for a pulverized 

coal boiler.
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 5

like orchard trimmings and coffee 

grounds) during manufacturing. 

Using these residues as fuel allows 

organizations to avoid landfill and 

other disposal costs and offsets 

some purchases of fossil fuel. 

Most ongoing cofiring operations 

are in stoker boilers in one of 

four industries: wood products, 

agriculture, textiles, and chemicals.

A screening analysis was done 

to determine which states have 

the most favorable conditions for 

a financially successful cofiring 

project. The primary factors 

considered were average delivered 

state coal prices, estimated low-cost 

biomass residue supply density 

(heat content in Btu of estimated 

available low-cost biomass residues 

per year per square mile of state 

land area), and average state 

landfill tipping fees. See Appendix 

A for a more detailed discussion.

The top 10 states in the analysis 

were classified as having high 

potential for a biomass cofiring 

project, and the next 10 states were 

classified as having good potential. 

See Table 2 and Figures 5 and 6 on 

page 6. 

Table 2. States with most attractive 

conditions for biomass cofiring.

Cofiring

Potential State

High Connecticut

Potential Delaware

Florida

Maryland

Massachusetts

New Hampshire

New Jersey

New York

Pennsylvania

Washington

Good Alabama

Potential Georgia

Indiana

Michigan

Minnesota

North Carolina

Ohio

South Carolina

Tennessee

Virginia

Within each group in Table 2, 

states are shown in alphabetical 

order, because slight variations 

in rankings result from selecting 

weighting-factor values. The 

analysis was intended simply to 

indicate which states have the most 

helpful conditions for economically 

successful cofiring projects. It found 

that the Northeast, Southeast, Great 

Lakes states, and Washington State 

are the most attractive locations for 

cofiring projects. 

Utility-scale cofiring projects are 

shown on the map in Figure 5. 

These sites are in or near states 

identified by the screening model 

as having good or high potential for 

cofiring. This increases confidence 

that the states selected by the 

screening process were reasonable 

choices. Figure 6 shows the locations 

of existing federal coal-fired boilers. 

There is good correspondence 

between the locations of these 

facilities and the states identified as 

promising for cofiring.

Figure 4. Schematic of a separate-feed cofiring arrangement for a pulverized coal boiler.
Federal Technology Alert

6 — FEDERAL ENERGY MANAGEMENT PROGRAM

Coal-fired federal boilers in the 20 

states indicated in the study would 

be promising for cofiring biomass 

if annual coal use is high enough 

to obtain significant annual cost 

savings—enough to pay off the 

initial investment—by switching 

part of the fuel supply to biomass. 

Federal facilities that operate coalfired boilers but are not in states 

on the list in Table 2 could still 

be good candidates for cofiring if 

specific conditions at their sites 

are favorable. 

“Wild card” factors, such as the 

impact of a motivated project 

manager or biomass resource 

supplier, the local availability of 

biomass, and the fact that a large 

federal facility or campus could 

act as its own source of biomass 

fuel, capitalizing on fuel cost 

reductions while avoiding landfill 

fees. These factors could easily tip 

the scales in favor of a particular 

site. The coal-fired boilers in 

Alaska could be examples of good 

candidates not located in highly 

rated states because of a long 

heating season, large size, and very 

high coal prices. 

The map in Figure 6 indicates 

average landfill tipping fees for 

each state. It also shows cities 

in which fairly recent local 

biomass resource supply and cost 

studies have been performed, as 

reported in Urban Wood Waste 

Resource Assessment (Wiltsee 

1998). Additional information 

on potential biomass resource 

supplies near federal facilities can 

be obtained from the DOE program 

manager for the TechnologySpecific Super ESPC for Biomass 

and Alternative Methane Fuels, or 

BAMF; contact information can be 

found later in this publication. To 

encourage new projects under the 

BAMF Super ESPC, the National 

Energy Technology Laboratory 

(NETL) has compiled a database 

that identifies federal facilities 

within 50 miles of 10 or more 

potential sources of wood waste.

Figure 5. States with most favorable conditions for biomass cofiring, based on 

high coal prices, availability of biomass residue, and high landfill tipping fees.

Figure 6. Average tipping fee and locations of local biomass supply studies 

(Chartwell 1997, Wiltsee 1998).
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 7

Cost-Saving Mechanisms

Cofiring operations are not 

implemented to save energy—they 

are implemented to reduce energy 

costs as well as the cost of other 

facility operations. In a typical 

cofiring operation, the boiler 

requires about the same heat 

input as it does when operating 

in a fossil-fuel-only mode. When 

cofiring, the boiler operates to 

meet the same steam loads for 

heating or power-generation 

operations as it would in fossilfuel-only mode; usually, no 

changes in boiler efficiency result 

from cofiring unless a very wet 

biomass is used. With no change 

in boiler loads, and no change in 

efficiency, boiler energy usage will 

be the same. The primary savings 

from cofiring are cost reductions 

resulting from (1) replacing a 

fraction of high-cost fossil fuel 

purchases with lower cost biomass 

fuel, and (2) avoiding landfill 

tipping fees or other costs that 

would otherwise be required to 

dispose of the biomass.

According to data obtained from 

the Defense Energy Support 

Center (DESC), the average 

delivered cost of coal for 18 

coal-fired boilers operated by the 

Department of Defense (DoD) was 

about $49 per ton in 1999, 

or about $2.10 per million Btu 

(the average coal heating value 

for those boilers is about 11,500 

Btu/lb). Coal costs for those 

facilities ranged from $1.60 to $3 

per million Btu, depending on the 

location, coal type, and annual 

quantity consumed. The average 

annual coal cost for these boilers 

was about $2 million and ranged 

from $28,000 to $8.9 million 

per year. According to three 

independently conducted studies 

that estimated the quantities and 

costs of unused and discarded 

wood residues in the United 

States, large quantities of biomass 

are available at delivered costs 

well below the $2.10 per million 

Btu average price of coal at the 

DoD facilities. Coal prices at 

other federal facilities are likely to 

be similar. 

For example, if 15% of the coal 

used at a boiler were replaced by 

biomass delivered to the plant for 

$1.25 per million Btu, annual fuel 

cost savings for the average DoD 

boiler described above would be 

more than $120,000. Neither the 

cofiring rate of 15% of the boiler’s 

total heat input, nor the delivered 

price of $1.25 per million Btu, is 

unrealistic, especially for stoker 

boilers. Higher cofiring rates and 

lower biomass prices are common 

in current cofiring projects. Note 

that the cost of most biomass 

residues will range from $2 to 

$3 per million Btu, so successful 

cofiring project operators must 

try to obtain the biomass fuel at 

a low price.

The average landfill tipping fee 

in the United States is about $36 

per ton of material dumped. 

Average tipping fees for each 

state are shown in Figure 6. If 

significant quantities of clean 

biomass residues—such as 

paper, cardboard, or wood—are 

generated at a federal site, and 

if some of that material can be 

diverted from landfill disposal 

and used as fuel in a boiler, 

the savings generated would be 

equivalent to about $66 per ton 

of biomass: $36/ton by avoiding 

the tipping fee, and $30/ton by 

replacing the coal with biomass. 

Since biomass has a lower heating 

value than coal, it takes more 

than one ton of biomass to offset 

the heat provided by one ton of 

coal. A ton of fairly dry biomass 

would have a heating value of 

about 7,000 Btu/lb, compared 

with an average of 11,500 Btu/lb 

for the coal used at DoD facilities. 

Each ton of biomass will thus 

offset 7,000/11,500 = 0.61 ton 

of coal. If the biomass is used to 

replace coal at $49/ton, each ton 

of biomass is worth $49/ton x 

0.61 = $30 in fuel cost savings. 

The typical cost of processing 

biomass waste material into a 

form suitable for use in a boiler 

is $10 per ton, so the net costs 

savings per ton of biomass 

residues could be about $56: 

$66/ton for the fuel and landfill 

cost savings minus $10/ton for 

the biomass processing cost. 

This assumes that the biomass 

is available at no additional 

transportation costs, as is the case 

at the Savannah River Site. 

If the average DoD facility using 

a coal-fired boiler could obtain 

biomass fuel by diverting its own 

residues from landfill disposal, 

the net annual cost savings would 

be about $560,000 per year. This 

would require about 10,000 tons 

of biomass residues per year, a 

quantity higher than most federal 

facilities generate internally. The 

savings generated by a real cofiring 

project would be expected to 

fall somewhere between the two 

examples given here—between 

$120,000 and $560,000 per year. 

They would probably depend on 

using some biomass materials 

generated on site and some 

supplied by a third party.

Other Benefits

When used as a supplemental 

fuel in an existing coal boiler, 

biomass can provide the following 

benefits, with modest capital 

outlays for plant modifications:
Federal Technology Alert

8 — FEDERAL ENERGY MANAGEMENT PROGRAM

• Reduced fuel costs. Savings in 

overall production costs can be 

achieved if inexpensive biomass 

fuel sources are available (e.g., 

clean wood waste). Biomass 

 fuel supplies at prices 20% or 

more below current coal prices 

will usually provide the cost 

savings needed.

• Reduced sulfur oxide and 

nitrogen oxide emissions.

Because of differences in the 

chemical composition of 

biomass and coal, emissions 

of acid rain precursor gases—

sulfur oxides (SOx) and 

nitrogen oxides (NOx)—can be 

reduced by replacing coal with 

biomass. Because most biomass 

has nearly zero sulfur content, 

SOx emissions reductions 

occur on a one-to-one basis 

with the amount of coal (heat 

input) offset by the biomass. 

Reducing the coal supply 

to the boiler by 10% will 

reduce SOx emissions by 10%. 

Mechanisms that lead to NOx 

savings are more complicated, 

and relative savings are 

typically less dramatic than 

the SOx reductions are, on a 

percentage basis.

• Landfill cost reductions. Using 

waste wood as a fuel diverts 

the material from landfills and 

avoids landfill disposal costs.

• Reduced greenhouse-gas emissions.

Sustainably grown biomass is 

considered a greenhouse-gasneutral fuel, since it results in 

no net carbon dioxide (CO2) in 

the atmosphere. Using biomass 

to replace 10% of the coal in an 

existing boiler will reduce the 

net greenhouse-gas emissions 

by approximately 10% if the 

biomass resource is grown 

sustainably.

• Renewable energy when needed.

Unlike other renewable energy 

technologies like those based 

on solar and wind resources, 

biomass-based systems are 

available whenever they are 

needed. This helps to accelerate 

the capital investment payoff 

rate by producing more heat 

or power per unit of installed 

capacity.

• Market-ready renewable energy 

option. Cofiring offers a fasttrack, low-cost opportunity 

 to add renewable energy 

capacity economically at 

federal facilities.

• Fuel diversification. The ability 

to operate using an additional 

fuel source provides a hedge 

against price increases and 

supply shortages for existing 

fuels such as stoker coals. In a 

cofiring operation, biomass can 

be viewed as an opportunity 

fuel, used only when the 

price is favorable. Note that 

administrative costs could 

increase because of the need to 

purchase multiple fuel supplies; 

this should be considered when 

evaluating this benefit.

• Locally based fuel supply. The 

most cost-effective biomass 

fuels are usually supplied from 

surrounding areas, so economic 

and environmental benefits will 

accrue to local communities.

Installation Requirements 

Specific requirements depend 

on the site that uses biomass in 

cofiring. In general, however, 

cofiring biomass in an existing 

coal boiler requires modifications 

or additions to fuel-handling, 

processing, storage, and feed 

systems. Slight modifications to 

existing operational procedures, 

such as increasing over-fire air, 

may also be necessary. Increased 

fuel feeder rates are also needed to 

compensate for the lower density 

and heating value of biomass. 

This does not usually present a 

problem at federal facilities, where 

boilers typically operate below 

their rated output. When full 

rated output is needed, the boiler 

can be operated in a coal-only 

mode to avoid derating. 

Expected fuel sources and boiler 

type dictate fuel processing 

requirements. For suspension 

firing in pulverized coal boilers, 

biomass should be reduced to a 

particle size of 0.25 in. or smaller, 

with moisture levels less than 25% 

when firing in the range of 5% 

to 15% biomass on a heat input 

basis. Equipment such as hoggers, 

hammer mills, spike rolls, and 

disc screens may be required to 

properly size the feedstock. Local 

wood processors are likely to own 

equipment that can adequately 

perform this sizing in return for a 

processing fee. Other boiler types 

(cyclones, stokers, and fluidized 

beds) are better suited to handle 

larger fuel particles. 

Two common forms of processed 

biomass are shown in Figure 

7, along with a typical stoker 

coal, shown in the center of 

the photo. Recent research 

and demonstration on several 

industrial stoker boilers in the 

Pittsburgh area has shown that 

wood chips (on the right) are 

preferable to mulch-like material 

(on the left) for cofiring with 

coal in stoker boilers that have 

not been designed or previously 

reconfigured for multifuel firing. 

The chips are similar to stoker 

coal in terms of size and flow 

characteristics; therefore, they 

cause minimal problems with 
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 9

existing coal-handling systems. 

Using a mulch-like material, or 

a biomass supply with a high 

fraction of fine particles (sawdust 

size or smaller) can cause periodic 

blockage of fuel flow openings in 

various areas of the conveying, 

storage, and feed systems. These 

blockages can cause significant 

maintenance increases and 

operational problems, so fuel 

should be processed to avoid 

those difficulties. With properly 

sized and processed biomass 

fuel, cofiring operations have 

been implemented successfully 

without extensive modifications 

to equipment or operating 

procedures at the boiler plant.

Federal-Sector 

Potential

A large percentage of federal 

facilities with coal-fired boilers 

have the potential to benefit from 

this technology. However, as 

noted, the potential is highest in 

areas with high coal prices, easyto-obtain biomass resources, and 

high landfill tipping fees. 

The potential savings resulting 

from using the technology at 

typical federal facilities with 

existing coal-fired boilers 

were estimated as part of the 

technology-screening process 

of FEMP’s New Technology 

Demonstration activities. Payback 

periods are usually between one 

and eight years, and annual fuel 

cost savings range from $60,000 

to $110,000 for a typical federal 

boiler. Savings depend on the 

availability of low-cost biomass 

feedstocks. The savings would be 

greater if the federal site can avoid 

landfill costs by using its own clean 

biomass waste materials as part of 

the biomass fuel supply.

Estimated Savings and 

Market Potential

The National Renewable Energy 

Laboratory (NREL) conducted a 

study for FEMP of the economic 

and environmental impacts of 

biomass cofiring in existing federal 

boilers, as well as associated 

savings. Results of the study are 

presented in Tables 3 through 6 

on pages 10 and 11. As shown in 

Table 6, cofiring 

biomass with coal 

at one typical 

coal-fired federal 

facility will 

replace almost 

3,000 tons of 

coal per year, 

could divert up to 

about 5,000 tons 

of biomass from 

landfills, and 

will reduce net 

carbon dioxide 

(CO2) emissions 

by more than 

8,000 tons per 

year and sulfur 

dioxide (SO2) 

emissions by 

about 136 tons per year. Reductions 

in NOx emissions could also occur. 

In terms of CO2 reductions, this 

would be equivalent to removing 

about 1,000 average-sized 

automobiles from U.S. highways.

Additional indirect benefits could 

also occur. If the biomass fuel 

would otherwise be sent to a 

landfill to decay over a period of 

time, methane (CH4) would be 

released to the atmosphere as a 

by-product of the decomposition 

process, assuming no landfill-gascapturing system is installed. Since 

CH4 is 21 times more powerful 

than CO2 in terms of its ability to 

trap heat in the atmosphere and 

increase the greenhouse effect, 

cofiring at one typical coalfired federal facility could avoid 

decomposition processes that 

would be equivalent to reducing 

an additional 29,000 tons of CO2

emissions per year.

Payback periods using cofiring 

at suitable federal facilities are 

between one and eight years. 

Annual cost savings range from 

about $60,000 to $110,000 for a 

typical federal boiler, if low-cost 

biomass feedstocks are available. 

There are more than 1500 

industrial-scale stoker boilers in 

operation in the United States. If 

federal technology transfer efforts 

result in cofiring projects at 50 

boilers (this is about 7% of existing 

U.S. stokers), the resulting CO2

reductions would be about 405,000 

tons/yr (the equivalent of removing 

about 50,000 average-size cars from 

U.S. highways), and SO2 reductions 

would be about 6,700 tons/yr. 

If all biomass materials used in 

these boilers were diverted from 

landfills with no gas capture, the 

greenhouse-gas equivalent of an 

additional 1.45 million tons of CO2

emissions would be avoided.

Figure 7. Comparison of two biomass residues with coal. 

Because they are similar in size and flow characteristics, 

wood chips (right) flow more like coal (center) in stoker 

boilers. Wood chips can thus be used in existing boilers 

with minimal modifications to fuel handling systems. 

Mulch-like processed wood (left) is more problematic.
Federal Technology Alert

10 — FEDERAL ENERGY MANAGEMENT PROGRAM

Table 3. Example economics of biomass cofiring in power generation applications (vs. 100 percent coal).

Table 4. Example environmental impacts of cofiring in power generation applications (vs. 100 percent coal).

Table 5. Example economic of biomass cofiring in heating applications (vs. 100 percent coal).

Boiler

Type

Example

Plant

Size

(MW)

Heat

from

Biomass

(%)

Biomass

Power

(MW)

Unit Cost

($/kW)1

Total

Cost for

Cofiring

Retrofit ($)

Net

Annual

Cost

Savings

($/yr)2

Payback

Period

(years)

Production

Cost, no 

Cofiring

(¢/kWh)3

Production

Cost, with

Cofiring

(¢/kWh)3

Stoker 

(low cost)

15 20 3.0 50 150,000 199,760 0.8 5.25 5.03

Stoker 

(high cost)

15 20 3.0 350 1,050,000 199,760 5.3 5.25 5.03

Fluidized bed 15 15 2.3 50 112,500 149,468 0.8 5.41 5.24

Pulverized coal 100 3 3.0 100 300,000 140,184 2.1 3.26 3.24

Pulverized coal 100 15 15.0 230 3,450,000 700,922 4.9 3.26 3.15

Notes: 

 1 Unit costs are on a per kW of biomass power basis (not per kW of total power).

 2 Net annual cost savings = fuel cost savings – increased O&M costs. 

 3 Based on data obtained from EPRI’s Technical Assessment Guide, 1993, EIA’s Costs of Producing Electricity, 1992, UDI’s Electric 

Power Database, EPRI/DOE’s Renewable Energy Technology Characterizations, 1997, coal cost of $2.10/MBtu, biomass cost of 

$1.25/MBtu, and capacity factor of 70%.

Boiler

Type

Example

Plant

Size

(MW)

Heat

from

Biomass

(%)

Reduced

Coal Use

(tons/yr)

Biomass

Used

(tons/yr)1

Annual

CO2

Savings

(tons/yr)2

Annual

SO2

Savings

(tons/yr)

Annual

NOx

Savings

(tons/yr)

Stoker 

(low cost)

15 20 10,125 16,453 27,843 466 N/A

Stoker 

(high cost)

15 20 10,125 16,453 27,843 466 N/A

Fluidized bed 15 15 7,578 12,314 20,839 349 N/A

Pulverized coal 100 3 7,429 12,072 20,430 342 N/A

Pulverized coal 100 15 37,146 60,362 102,151 1,709 N/A

Notes: 

 1 Depending on the source of biomass, “biomass used” could be avoided landfilled material.

 2 Carbon savings can easily be calculated from CO2 savings (i.e., carbon savings = 12/44 x CO2 savings).

Notes: 

 1 Unit costs are on a per unit of biomass capacity basis (not per unit of total capacity).

 2 Assumptions: coal cost of $2.10/MBtu and capacity factor of 25% (based on data from coal-fired federal boilers), biomass cost of 

$1.25/MBtu.

Example

Boiler Size

(steam lb/hr)

No. of

Boilers

at Site

Heat from

Biomass

(steam lb/hr)

Biomass

Capacity

(steam lb/hr)

Unit Cost

($/lb/hr)1

Total Cost

for Cofiring

Retrofit ($)

Net Annual

Cost Savings

($/yr)2

Payback

Period

(years)

120,000 2 15% 36,000 2.8 100,075 41,628 2.4
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 11

Laboratory Perspective

Since the 1970s, DOE and NETL 

have worked with alternative fuels 

such as solid waste and refusederived fuel. In 1995, NETL, 

Sandia National Laboratories, and 

NREL sponsored a workshop that 

led to several projects evaluating 

technical and commercial issues 

associated with biomass cofiring. 

These projects included research 

conducted or sponsored by NETL, 

NREL, Sandia, and Oak Ridge 

National Laboratory (ORNL) on 

char burnout; ash deposition; 

NOx behavior; cofiring 

demonstration projects using 

various boiler types, coal/biomass 

feedstock combinations, and fuel 

handling systems; reburning for 

enhanced NOx reduction; and 

the use of ash. These efforts have 

led to improved and documented 

knowledge about the impacts of 

cofiring biomass with coal in a 

wide range of circumstances.

Results from a joint Sandia/NETL/

NREL project found that in terms 

of slagging and fouling, wood was 

more benign than herbaceous 

crops. It has also been shown 

that, in general, NOx emissions 

decrease with cofiring as a result 

of the lower nitrogen content of 

most woody biomass in relation 

to coal, and the greater volatility 

of biomass in relation to coal. 

The greater volatility of biomass 

results in a natural staging of 

the combustion process that can 

reduce NOx emissions to levels 

below those expected on the basis 

of fuel nitrogen contents.

DOE, NETL, and the Electric 

Power Research Institute (EPRI) 

also collaborated on short-term 

demonstration projects. Several 

of the demonstrations took 

place at federal facilities in the 

Pittsburgh area. They found 

no significant impact on boiler 

efficiency at low levels of cofiring. 

Fuel procurement, handling, and 

preparation were found to require 

special attention.

In addition, DOE’s Idaho National 

Energy and Environmental 

Laboratory (INEEL) and DOE’s 

Savannah River Site have biomasscubing equipment that can 

convert paper and wood waste 

materials into a form that can be 

used more easily as fuel at existing 

coal-fired facilities. In a separate 

project with funding from NETL, 

the University of MissouriColumbia’s Capsule Pipeline 

Research Center examined the 

potential for compacting various 

forms of biomass into small 

briquettes or cubes for use as 

supplemental fuels at existing 

coal-fired boilers. The results 

indicated that biomass fuel cubes 

could be manufactured and 

delivered to a power plant for as 

little as $0.30 per million Btu, or 

less than $5 per ton. This price 

included all capital and operating 

costs for the manufacturing 

facility plus transportation costs 

within a 50-mile radius. The 

analysis assumed the facility 

would collect a $15-per-ton 

tipping fee for biomass delivered 

to the site. See the bibliography 

for more detailed information on 

biomass cofiring research activities 

and published results of research 

led by DOE and its laboratories. 

Application

This section addresses technical 

aspects of biomass cofiring in 

Table 6. Potential environmental impact of cofiring in heating applications (vs. 100 percent coal).

No. of

Cofiring

Projects1,2

Reduced

Coal Use

(tons/yr)

Biomass

Used

(tons/yr)3

Annual

CO2

Savings

(tons/yr)4

Annual

SO2

Savings

(tons/yr)

Annual

NOx

Savings

(tons/yr)

1 2,947 5,057 8,103 136 N/A

2 5,893 10,114 16,206 271 N/A

10 29,466 50,570 81,030 1,355 N/A

50 147,328 252,851 405,151 6,777 N/A

Notes: 

 1 There are approximately 1500 industrial stoker boilers operating today.

 2 Assumptions for the average project were: 120,000 lb/hr steam capacity per boiler, 2 boilers at site, 15% heat from biomass, and a 

25% capacity factor.

 3 Depending on the source of biomass, “biomass used” could be avoided landfilled material.

 4 Carbon savings can easily be calculated from CO2 savings (i.e., carbon savings = 12/44 x CO2 savings).
Federal Technology Alert

12 — FEDERAL ENERGY MANAGEMENT PROGRAM

coal-fired boilers, including the 

range of situations in which 

cofiring technology can be 

used best. First, prerequisites for 

a successful biomass cofiring 

application are discussed, as 

well as the factors that influence 

the cost-effectiveness of 

projects. Design and integration 

considerations are also discussed 

and include equipment and 

installation costs, installation 

details, maintenance, and 

permitting issues. 

Application Prerequisites

The best opportunities for cofiring 

occur at sites in which many of 

the following criteria apply:

• Existing, operational coal-fired 

boiler. It is possible to cofire 

biomass with fossil fuels 

other than coal; however, 

the similarities in the fuelhandling systems required 

for both coal and biomass 

(because they are both solid 

fuels) usually make cofiring 

less expensive at coal-fired 

facilities. An exception could 

be cofiring applications in 

which the biomass fuel is gas 

piped to the boiler from a 

nearby landfill. Cofiring with 

landfill gas has been done in 

both coal-fired and naturalgas-fueled boilers, but is less 

common than solid-fuel 

cofiring because of the need 

for a large boiler very close to 

the landfill. 

• Local expertise for collecting and 

processing biomass. Most boiler 

operators at federal facilities 

are not likely to be interested 

in purchasing and operating 

equipment to process biomass 

into a form that can be used 

as boiler fuel. Thus, it is 

advantageous for the facility to 

have access to local expertise 

in collecting and processing 

waste wood. This expertise 

can be found primarily among 

companies specializing in 

materials recycling, mulch, and 

wood products.

• Boiler plant equipped with a 

bag-house. Cofiring biomass 

with coal has been shown to 

increase particulate emissions 

in some applications in 

comparison to coal-only 

operation. If the existing 

facility is already equipped 

with a bag-house or cyclone 

separation devices, this should 

not be a significant problem; 

in other words, it should 

not cause noncompliance 

with particulate emissions 

standards. The existing 

baghouse or cyclone typically 

provides sufficient particulate 

filtration to allow stack gases 

to remain in compliance 

with air permits. However, 

some small coal-fired boilers 

are not equipped with these 

devices. Instead, they use 

methods such as natural gas 

overfiring to reduce particulate 

emissions. In such cases, a 

new baghouse may be required 

to permit cofiring biomass at 

significant input levels, and 

this would increase project 

costs significantly.

• Storage space available on 

site. Unless the biomass is 

immediately fed into a boiler’s 

fuel-handling system upon 

delivery, a temporary staging 

area at the boiler plant will 

be needed to store processed 

biomass supplies. An ideal 

storage facility would have at 

least a concrete pad and a roof 

to minimize the accumulation 

of moisture and dirt. It may 

also be possible to arrange 

storage through the biomass 

fuel provider.

• Receptive plant operators at 

the federal facility. At the 

very least, increases will be 

necessary in administrative 

activities associated with 

adding a new fuel to a boiler 

plant’s fuel mix. In addition, 

new or additional boiler 

control and maintenance 

procedures will be required 

to use biomass effectively. 

As opposed to a capital 

improvement project, which 

requires one-time installation 

and minimal attention 

afterwards (such as equipment 

upgrades), a cofiring operation 

requiresongoing changes 

in fuel procurement, fuelhandling, and boiler control 

operations. Receptive 

boiler plant operators and 

management are therefore 

instrumental in implementing 

and sustaining a successful 

cofiring project.

• Favorable regulatory climate 

for renewable energy. As of 

February 2003, 28 states had 

either enacted electricity 

restructuring legislation 

or issued orders to open 

their electricity markets to 

competition. Most of these 

states have established some 

type of incentive program to 

encourage more installations of 

renewable energy technologies. 

Since biomass is a renewable 

energy resource, some states 

may provide favorable 

conditions for implementing 

a cofiring project through 

incentiveprograms, technical 

assistance, or flexible 

permitting procedures.
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 13

Cost-Effectiveness Factors

The list below presents the major 

factors influencing the costeffectiveness of biomass cofiring 

applications. The worksheets in 

Appendix B provide procedures 

for estimating total project cost 

savings based on easy-to-obtain 

information for any federal facility 

with a coal-fired boiler.

• Coal supply price. The higher the 

coal supply price, the greater 

the potential cost savings 

from implementing a biomass 

cofiring project. Prices above 

$1.30 per million Btu are 

usually high enough to make 

cofiring worth considering, 

especially if some of the other 

factors mentioned in this 

section are also favorable. 

 Since the average delivered 

coal price for boilers operated 

by DoD was about $2.10 per 

million Btu in 1999, and ranged 

from $1.60 to $3.00 per million 

Btu, coal prices at nearly all 

federal facilities should be 

high enough to make biomass 

cofiring worth considering.

• Biomass supply price. Abundant 

local supplies of low-cost 

biomass are necessary for 

cost-effective biomass cofiring 

projects. This is most likely to 

occur near cities, wood-based 

industries, or landfills and 

material recycling facilities 

where wood waste is collected. 

NREL conducted a study that 

examined national waste 

 wood availability and costs 

based on detailed local data 

gathered from 30 cities 

throughout the United States. 

The study indicates that 

more than 60 million tons of 

wood waste per year could be 

available at a low enough cost 

to make cofiring economically 

viable at nearly any federal 

facility. This amount of wood 

contains 40 times the amount 

of energy supplied by coal to all 

DoD-operated federal facilities 

in 1999.

• Landfill tipping fees. High local 

landfill tipping fees increase 

the probability that low-cost 

biomass supplies could be 

available for a cofiring project. 

Average state landfill tipping 

fees are indicated in Figure 6. 

The average U.S. tipping fee is 

about $36 per ton, and the fee 

ranges from about $15 per ton 

in Nevada to about $74 per ton 

in New Jersey.

• Boiler size and usage patterns.

Boiler size and capacity factor 

were considered in the initial 

screening process (see Figure 

5). Larger, high-capacity-factor 

facilities (those that operate at 

high loads year-round) can use 

more biomass and will realize 

greater annual cost savings. This 

in turn reduces project payback 

periods. Because the amount 

of environmental paperwork 

needed is significantly less if 

less than 5,000 tons of coal 

are burned annually, smaller 

facilities might also want to 

consider cofiring.

• Boiler modifications and 

equipment additions required.

Start-up costs are a key 

consideration in evaluating any 

cofiring project. The cost of 

modifying an existing facility 

to use biomass or to purchase 

equipment to prepare biomass 

for cofiring can range from 

nearly nothing to as much 

as $6/lb per hour of boiler 

steaming capacity.

Where to Apply

The most common applications for 

biomass cofiring are at coal-fired 

boilers located in areas with an 

adequate, reliable supply of biomass 

fuel. For a list of states in which these 

conditions are most likely to occur, 

see Table 2 and Figures 5 and 6.

What to Avoid

Major technical issues and 

problems associated with 

implementing a biomass project 

at a federal site are listed below. 

Each problem can be addressed 

with technical assistance from 

experts with experience in 

cofiring projects.

• Slagging, fouling, and corrosion.

Some biomass fuels have high 

alkali (principally potassium) 

or chlorine content, or both. 

This can lead to unmanageable 

ash deposition problems 

on heat exchange and ashhandling surfaces. Chlorine in 

combustion gases, especially 

at high temperatures, can 

cause accelerated corrosion of 

combustion system and flue 

gas clean-up components. 

These problems can be 

minimized or avoided by 

screening fuel supplies for 

materials high in chlorine 

and alkalis, by limiting the 

biomass contribution to 

boiler heat input to 15% or 

less, by using fuel additives, 

or by increased sootblowing. 

Additional site-specific 

adjusments may be necessary. 

Annual crops and agricultural 

residues, including grasses 

and straws, tend to have high 

alkali and chlorine contents. 

In contrast, most woody 

materials and waste papers are 

low in alkali and chlorine. As 

a precaution, a sample of each 
Federal Technology Alert

14 — FEDERAL ENERGY MANAGEMENT PROGRAM

new type of fuel should be 

tested for both chlorine and 

alkali before use. For further 

details on the alkali deposits 

associated with biomass fuels, 

including recommendations 

for fuel testing methods and 

specifications, see Miles 

 et al. 1996. 

• Fuel-handling and processing 

problems. Certain equipment 

and processing methods are 

required to reduce biomass 

to a form compatible with 

coal-fired boilers and fluegas-handling systems. Most 

coal boiler operators are 

not familiar with biomass 

processing, so technical 

assistance may be needed 

to help make the transition 

to biomass cofiring. Some 

cofiring facilities have found 

it more convenient and costeffective to have biomass 

processed by a third-party fuel 

supplier; in some cases, this 

is their coal supplier. When 

wood is used, chips tend to 

work much better than mulchlike material. Large quantities 

of fine, sawdust-like material 

should also be avoided because 

they plug up the fuel supply 

and storage system.

• Underestimating fuel acquisition 

efforts. Securing dependable, 

clean, economical sources of 

biomass fuels can be timeconsuming, but this is one 

of the most important tasks 

in establishing a biomass 

project. Federal facilities 

that already have staff with 

experience in aggregating and 

processing biomass are ideal 

sites for projects. In most cases, 

however, technical assistance 

will probably be required in 

this area.

• Boiler efficiency losses. Some 

design and operational changes 

are needed to maximize boiler 

efficiency while maintaining 

acceptable opacity, baghouse 

performance, and so on. 

Without these djustments, 

boiler efficiency and 

performance can decrease. 

For example, boiler efficiency 

losses of 2% were measured 

during cofiring tests at a 

pulverized coal boiler at a heat 

input level from biomass of 

10% (Tillman 2000, p. 373). 

Numerous cofiring projects 

have demonstrated that 

efficiency and performance 

losses can be minimized with 

proper attention, however. 

These losses should be 

included in the final economic 

evaluation for a project. 

• Negative impacts on ash 

markets. Concrete admixtures 

represent an important market 

for some coal combustion 

ash by-products. Current 

ASTM standards for concrete 

admixtures require that the 

ash be 100% coal ash. Efforts 

are under way to demonstrate 

the suitability of commingled 

biomass and coal ash in 

concrete admixtures, but in the 

near term, cofired ash will not 

meet ASTM specifications. This 

is a serious problem for some 

utility-scale power plants that 

obtain a significant amount of 

revenue from selling ash. Since 

most federal facilities dispose 

of ash rather than sell it, this 

issue should not be a problem; 

however, ash disposal methods 

at each potential project site 

should be considered early in 

the evaluation process to avoid 

future problems.

Equipment Integration

A typical stoker boiler is shown in 

Figure 8. Recent demonstration 

projects of stoker boilers in Pittsburgh, Pennsylvania; Idaho Falls, 

Idaho; and Aiken, South Carolina, 

have shown that properly sizing 

the biomass fuel helps to avoid 

the need for modifications to the 

existing boiler. The Pittsburgh 

project used premixed coal and 

wood chips. As indicated in Figure 

8, no modifications were needed to 

deliver the mixed fuel to the dump 

grate after the switch from coalonly supplies. However, cofiring 

biomass in an existing coal boiler 

usually requires at least slight 

modifications or additions to fuelhandling, processing, storage, and 

feed systems. Specific requirements 

vary from site to site.

Fuel processing requirements are 

dictated by the fuel source and 

boiler type. For suspension firing 

in pulverized coal (PC) boilers, 

biomass should be reduced to a 

maximum particle size of 0.25 

in. at moisture levels of less than 

25%. When firing in the range 

of 5% to 15% biomass (on a heat 

input basis), a separate injection 

system is normally required. For 

firing small amounts of biomass in 

a PC boiler (less than 5% of total 

heat), the biomass can be blended 

with the coal before injection into 

the furnace.

Additional processing and 

handling equipment requirements 

make separate injection systems 

more expensive than blendedfeed systems, but they offer the 

advantage of higher biomass 

firing rates. Cyclone, stoker, and 

fluidized-bed boilers are better 

suited to handle larger fuel 

particles, and they are thus usually 

less expensive to modify than PC 
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 15

boilers. In general, each boiler and 

fuel combination must be carefully 

evaluated to maximize boiler 

efficiency, minimize costs, and 

avoid combustion-related problems 

in the furnace.

Maintenance 

Maintenance requirements for 

boilers cofiring biomass and coal are 

similar to those for coal-only boilers. 

However, slight changes to previous 

operational procedures, such as 

increasing over-fire air and fuel 

feeder speeds, may be needed. For a 

project to be successful, the biomass 

fuel must be processed before 

cofiring to avoid large increases in 

current maintenance levels.

Equipment Warranties 

If additional equipment is required 

to implement a cofiring project, it 

is most likely to be commercially 

available. Therefore, it will carry 

the standard manufacturer’s 

warranty, which is usually a 

minimum of one year for parts. 

Installation labor usually carries a 

one-year warranty, as well. 

Codes and Standards

Permit requirements vary 

from site to site, but a facility’s 

emissions permits—even for 

limited-term demonstration 

projects—usually have to be 

modified for cofiring projects. 

Results from earlier cofiring 

projects in which emissions 

were not negatively affected 

can be helpful during the 

permit modification process. 

Air permitting officials also may 

need detailed chemical analyses 

of biomass fuel supplies and 

a fuel supply plan to evaluate 

the permit requirements for a 

cofiring project. NETL and the 

University of Pittsburgh are 

already developing this type of 

information. Preliminary results 

can be found in several papers 

listed in the bibliography. 

Because of increases in regulations 

for particulate emissions and 

increases in the availability of 

natural gas, some federal boilers 

are being converted from coal to 

natural gas despite the higher cost. 

Fifteen projects in which natural 

gas (at about 10% of boiler heat 

input) is cofired with coal or wood 

have been implemented or are in 

progress. Eleven of these projects 

involve coal-fired boilers and four 

involve wood-fired units. They 

include the coal-fired Capital 

Heating Plant in Washington, D.C. 

Such projects do not eliminate 

the possibility of cofiring 

biomass with natural gas and 

coal, however. If biomass can be 

obtained more cheaply than coal 

and gas, using biomass could help 

offset the cost of the gas.

Costs

Cofiring system retrofits require 

relatively small capital investments 

per unit of capacity, in comparison 

to those required for most other 

renewable energy technologies 

and carbon sequestration 

alternatives. Costs as low as $50 

to $100/kW of biomass power can 

be achieved for stokers, fluidized 

beds, and low-percentage (less 

than 2% biomass on a heat basis) 

cofiring in cyclone and PC boilers. 

For heating applications, this is 

equivalent to about $3 to $6/lb per 

hour of steaming capacity. 

Retrofits for high-percentage 

cofiring (up to 15% of the total 

heat input) at a pulverized coal 

(PC) boiler are typically about 

$200/kW of biomass power 

capacity. Smaller applications 

such as those at federal facilities 

have higher per-unit costs because 

they cannot take advantage of 

economies of scale. For example, 

a small-scale stoker application 

that requires a completely new 

receiving, storage, and handling 

system for biomass could cost 

as much as $350/kW of biomass 

power capacity. 

When inexpensive biomass fuels 

are used, cofiring retrofits have 

Figure 8. A typical stoker boiler conveyor system receiving premixed coal and 

biomass (Adapted from J. Cobb et al., June 1999).
Federal Technology Alert

16 — FEDERAL ENERGY MANAGEMENT PROGRAM

payback periods ranging from one 

to eight years. A typical existing 

coal-fired power plant can produce 

power for about 2.3¢/kWh. 

However, cofiring inexpensive 

biomass fuels can reduce this cost 

to 2.1¢/kWh. For comparison, a 

new combined-cycle power plant 

using natural gas can generate 

electricity for about 4¢ to 5¢/kWh. 

These generation costs are based 

on large-scale power plants and 

would be higher for smaller federal 

power plants. 

Tables 3 and 5 provide examples 

of the economic impacts of 

biomass cofiring projects for 

power and heating, respectively. 

Federal boilers are most likely to 

be similar to the 15 MW stoker 

in Table 3 for power generation, 

and results shown in Table 5 for 

heating. The stoker unit and the 

two 120,000 lb/hr boilers in Table 

5 are similar in terms of rated 

steam generating capacity. At 

coal costs of $2.10/MBtu and a 

delivered biomass cost of $1.25/

MBtu, payback periods would be 

between one and three years for 

low-cost stoker installations. The 

payback period for a higher cost 

stoker installation, like the one 

shown in Table 4, row 2, would be 

about 5.3 years. 

All these examples of stoker 

boilers assume that 20% of the 

heat input to the boiler is obtained 

from biomass. Annual fuel cost 

savings thus range from about 

$60,000 to $110,000 for a typical 

federal boiler. Payback periods 

and annual savings for powergenerating boilers tend to be more 

favorable than similarly sized 

heating boilers, because they are 

usually used fairly consistently 

throughout the year, and thus 

they consume more fuel.

Utility Incentives

At present, there are no known 

utility incentives for biomass 

cofiring at federal facilities.

Project Financing and Technical 

Assistance

DOE FEMP, with support from 

staff at national laboratories and 

DOE Regional Offices, can provide 

many services and resources to 

help federal agencies implement 

energy efficiency and renewable 

energy projects. Projects can be 

funded through energy savings 

performance contracts (ESPCs), 

utility energy service contracts, 

or appropriations. Among these 

resources is a technology-specific 

“Super ESPC” for Biomass and 

Alternative Methane Fuels 

(BAMF), which facilitates the 

use of biomass and alternative 

methane fuels to reduce federal 

energy consumption and energyrelated costs. 

For this Super ESPC, biomass fuels 

include any organic matter that 

is available on a renewable or 

recurring basis (excluding oldgrowth timber). Examples include 

dedicated energy crops and trees, 

agricultural food and feed crop 

residues, aquatic plants, wood and 

wood residues, animal wastes, and 

other waste materials. Alternative 

methane fuels include landfill 

methane, wastewater treatment 

digester gas, and coal-bed methane.

Through a standard ESPC, an 

energy services company (ESCO) 

arranges financing to develop 

and carry out energy and water 

efficiency and renewable energy 

projects. This allows federal 

energy and facility managers to 

improve buildings and install new 

equipment at no up-front cost. 

As part of the project, the ESCO 

conducts a comprehensive energy 

audit and identifies improvements 

that will save energy and reduce 

utility bills at the facility. The 

ESCO guarantees that energy 

improvements will result in a 

specified level of annual cost 

savings to the federal customer 

and that these savings will be 

sufficient to repay the ESCO for 

initial and ongoing work over 

the term of the contract. In other 

words, agencies use a portion 

of their guaranteed energy 

cost savings to pay for facility 

improvements and specified 

maintenance over the life of the 

contract. After the contract ends, 

additional cost savings accrue to 

the agency. Contract terms can be 

up to 25 years, depending on the 

scope of the project. 

Recognizing that awarding a 

stand-alone energy savings 

performance contract (ESPC) can 

be complex and time-consuming, 

FEMP created streamlined 

Super ESPCs. These “umbrella” 

contracts are awarded to ESCOs 

selected through a competitive 

bidding process on a regional or 

technology-specific basis. Super 

ESPCs thus allow agencies to 

bypass the initial competitive 

bidding process and to undertake 

multiple energy projects under one 

contract. Each Super ESPC project 

is designed to meet the specific 

needs of a facility; it can include 

a wide range of energy- and 

cost-saving improvements, from 

energy-efficient lighting to heating 

and cooling systems.

Technology-Specific Super ESPCs 

focus on technologies that promise 

substantial energy savings. The 

technologies are well suited for 

application in federal facilities, but 

they are usually not well enough 

established in the marketplace 
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 17

to be readily available through 

routine acquisition processes. The 

ESCOs that have been awarded 

technology-specific Super ESPC 

contracts have demonstrated their 

expertise in the application of 

these technologies through 

past performance, such as 

proposing and carrying out 

specific projects defined in DOE’s 

requests for proposals. 

Through the BAMF Super ESPC, 

FEMP helps to make accessible to 

federal facilities the energy- and 

cost-savings benefits of biomass 

and alternative methane fuels. 

Projects carried out under the 

BAMF Super ESPC can reduce 

federal energy costs by utilizing 

biomass and alternative methane 

fuels in a variety of applications, 

such as steam boilers, hot-water 

heaters, engines, and vehicles. 

The federal facility, the ESCO, 

or a third party could own the 

biomass or alternative methane 

fuel resource. If the fuel requires 

transport to end-use equipment, 

that equipment must be located 

on federal property. 

As discussed earlier, some projects 

may modify or replace existing 

equipment so that the facility 

can supplant or supplement its 

conventional fuel supply with a 

biomass or alternative methane 

fuel. In other projects, ESCOs 

could install equipment that 

uses these fuels to accomplish 

something altogether new at a 

federal facility, such as on-site 

power generation. Although 

the primary component of any 

project under this Super ESPC 

must feature the use of a biomass 

or alternative methane fuel, all 

projects are also expected to 

employ a variety of traditional 

conservation measures, which 

include retrofits to lighting, 

motors, and heating, ventilation, 

and cooling systems in order to 

reduce energy costs.

For further information, see the 

FEMP and BAMF Super ESPC 

contacts listed on page 21. See also 

the list of manufacturers for BAMF 

Super ESPC contract awardees.

Technology 

Performance

In general, facility managers who 

have cofired biomass in coal-fueled 

boilers have been pleased with 

the technology’s operation, once 

initial testing and performance 

verification activities have been 

completed. They cite the ease of 

retrofitting their operations to 

accommodate biomass and the 

various cost savings and emissions 

benefits as factors that have made 

their projects worthwhile.

Field Experience 

Biomass cofiring has been 

successfully demonstrated and 

practiced in a full range of coal 

boiler types and sizes, including 

pulverized-coal boilers, cyclones, 

stokers, and fluidized beds. At 

least 182 separate boilers and 

organizations in the United States 

have cofired biomass with fossil 

fuels; although this number is not 

comprehensive, it is based on the 

most thorough and current list 

available. Much of this experience 

has been gained as a result of 

the energy crisis of the 1970s, 

when many boiler plant operators 

were seeking ways to reduce fuel 

costs. However, a steady number 

of organizations have continued 

cofiring operations to reduce 

their overall operating costs. 

Of the 182 cofiring operations 

mentioned above, 114 (or 63%) 

have been at industrial facilities, 

32 at utility-owned power plants, 

18 at municipal boilers, 10 at 

educational institutions, and 8 at 

federal facilities. The majority of 

cofiring projects have occurred in 

industrial applications. These are 

primarily in the wood products, 

agricultural, chemical, and textile 

industries, in which companies 

generate a biomass waste byproduct such as sawdust, scrap 

wood, or agricultural residues. By 

using the waste material as fuel, 

the companies avoid a certain 

amount of fossil-fuel purchases 

and disposal costs.

Several U.S. power generators are 

either considering or actually 

using economical forms of 

biomass as supplemental fuels in 

coal-fired boilers. These generators 

include the Tennessee Valley 

Authority (TVA), New York State 

Electric and Gas, Northern States 

Power, Tacoma City Light, and 

Southern Company. The TVA 

expects annual fuel cost savings 

of about $1.5 million as a result of 

cofiring at the Colbert pulverizedcoal power plant in Alabama.

Currently, federal facilities use 

very little biomass energy. Because 

of DOE FEMP’s commitment 

to reducing energy costs and 

environmental emissions at 

federal facilities, the program is 

working to add biomass cofiring 

to the portfolio of options for 

improving the economic and 

environmental performance of 

these facilities.

Fuel Supply and Cost 

Savings Calculations

Appendix B contains worksheets 

and supporting data for agencies 

to evaluate the feasibility of a 

biomass cofiring operation in 

a preliminary manner. These 

worksheets were designed to 

permit useful calculations based 
Federal Technology Alert

18 — FEDERAL ENERGY MANAGEMENT PROGRAM

on information that is readily 

available at any coal-fueled 

boiler plant.

The first worksheet in Appendix 

B is for estimating the amount 

of biomass fuel supply needed 

for a cofiring application. This 

can be used to determine the 

size of biomass processing 

equipment required and to 

evaluate local biomass supplies 

in relation to the biomass fuel 

requirements of the cofiring 

project. The second worksheet in 

Appendix B is for determining 

the annual cost savings resulting 

from cofiring with biomass at a 

coal-fired facility.

Appendix C provides examples 

of completed worksheets 

estimating annual cost savings 

and biomass fuel supplies for 

DOE’s Savannah River Site 

cofiring project. This project

is illustrated in the following 

case study.

Case Study

Savannah River Cofiring Project 

Facility Description

The primary function of the 

Department of Energy’s Savannah 

River Site (SRS)—constructed 

during the early 1950s in Aiken, 

South Carolina—is to handle, 

recycle, and process basic nuclear 

materials such as tritium and 

plutonium. The Site Utilities 

Department at SRS is implementing 

an innovative, cost-effective system 

for cofiring biomass with coal in 

the site’s existing coal-fired stoker 

boilers. The system converts paper 

and wood waste generated from 

the day-to-day operations of the 

site into “process engineered fuel” 

(PEF) cubes, which will replace 

about 20% of the coal used at the 

steam plant. 

Existing Technology 

Description

Savannah River Site uses two 

moving-grate spreader stoker 

boilers to produce steam. The 

boilers were manufactured by 

Combustion Engineering and have 

a capacity of 60,000 lb/hr at full 

load. Fuel is fed to the facility from 

two track hoppers of equal size, 

located next to the boiler plant. 

Steam from the boilers is required 

year-round for process heating 

applications. Steam demands peak 

during winter as a result of extra 

comfort-heating loads. Multiclones 

remove particulates from the stack 

gases. Before the PEF project, the 

boilers used only coal for fuel, 

and average annual coal use at the 

facility was about 11,145 tons. At a 

delivered price of $50 per ton, this 

coal cost the site just over $550,000 

per year.

Like many other facilities its 

size, SRS generates significant 

quantities of scrap paper and 

cardboard products—about 280 

tons per month. In the years before 

implementing the 

PEF cofiring project, 

SRS had been paying 

about $23 per ton 

to landfill these 

materials. Landfill 

costs for the paper 

waste amounted to 

about $77,280 per 

year. In addition, the 

site burned about 70 

tons per month of 

recently unclassified 

paper in an on-site 

burn pit. The annual 

cost of operating the 

burn pit was about 

$83,050.

These high wastedisposal costs, 

combined with 

directives in Executive Order 

13123 to increase the use of 

renewable energy and reduce 

emissions, compelled SRS to pursue 

the PEF project.

New Technology Description

The PEF Facility uses a shredder 

and a cubing machine (see Figure 

9) to convert waste paper into 

cubes that can be used as fuel 

in the SRS stoker boilers. The 

cuber greatly increases the bulk 

density of the waste materials and 

makes them compatible with fuel 

conveyors and handling equipment 

at the steam plant. 

The PEF Facility has two major 

handling sections: the tipping 

floor, where the PEF feedstock is 

delivered, and the processing line, 

which forms the feedstock into 

cubes. Waste paper is collected in 

plastic bags from facility offices. 

The plastic bags containing the 

waste paper products are then 

loaded into dumpsters marked 

“PAPER PRODUCTS ONLY.” These 

Figure 9. The PEF Facility has a shredder and a 

cubing machine to convert waste paper into cubes 

used for fuel in SRS stoker boilers
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 19

dumpsters are collected by trucks 

that bring this material directly 

to the PEF facility tipping floor. 

Because previous landfill disposal 

activities for paper required the 

same amount of collection and 

transportation, no new costs 

were incurred by diverting the 

waste material from the landfill 

to the PEF Facility.

After they are delivered to 

the tipping floor, the plastic 

bags containing waste paper 

are pushed into a hopper. The 

hopper drops the paper onto 

a conveyor that delivers it to 

a shredder. The waste paper 

is shredded in a 300-hp highspeed shredder that yields pieces 

no larger than 2 in. in length, 

width, or depth. Water sprays 

and/or dry granular material can 

easily be added to the shredded 

paper to incorporate emissionreducing agents into the cubes. 

A dust collection system filters 

air from the shredder, feedstock 

metering box, and cuber. Dust is 

removed from the airflow in 

a cyclone separator and a 

baghouse filter before being 

vented to the atmosphere. 

The combined feedstock material 

is processed through a machine 

that extrudes it into cubes 

approximately 1 in. square 

and 3 to 4 in. long. The cubing 

machine can be modified to 

produce cubes from 1/4 to 1 in. 

square. Sample cubes are shown 

in the inset of Figure 10. From 

left to right, the cubes shown 

in the inset are made of wood, 

cardboard, and office paper.

The initial bulk density of 

shredded paper is only about 2 

to 4 lb/ft3. The bulk density of 

the PEF cubes at SRS is from 35 

to 40 lb/ft2. The bulk density 

of the coal used in the SRS 

boilers is 80 lb/ft2. The PEF cubes 

have an average heating value 

of about 7,500 Btu/lb, compared 

with 13,000 Btu/lb for the coal. 

The cost of operating the PEF 

facility is about $7.61 per ton of 

cubes produced.

The PEF cubes are delivered to 

one of the two track hoppers at 

the SRS steam plant. Coal is fed 

from one hopper and PEF cubes 

are fed from the other. The two 

fuels are placed in equal volumes 

onto the conveyor that feeds 

the bucket elevator. The bucket 

elevator places the coal/PEF mix 

into the fuel bunkers, which 

supply fuel to the boilers.

Energy Savings

This project will 

not decrease 

the amount of 

energy input 

to the boilers 

at the steam 

plant; however, 

it will replace 

a significant 

amount of coal 

with a renewable 

fuel made from 

waste paper that 

previously had 

to be disposed of 

at great expense. 

The worksheets in 

Appendix C show 

the calculations 

needed to 

determine that, 

if the PEF cubes 

are 50% of the 

volume of fuel 

input to the 

boilers, the heat 

input obtained 

from PEF is about 

20% of the total. 

In other words, 

20% less coal will be required 

to produce the same amount 

of steam. Since the average 

annual coal use before the 

PEF project was about 11,145 

tons per year, the annual coal 

savings will be about 2,240 

tons (11,145 x 20% = 2,240). 

Since the heating value of 

the coal used at SRS is about 

13,000 Btu/lb, the coal-based 

energy input to the boilers will 

be reduced by about 58,240 

million Btu per year (2,240 

tons x 2,000 lb/ton x 13,000 

Btu/lb = 58,240 MBtu).

Figure 10. The combined feedstock material is 

processed through a machine that extrudes it into 

cubes approximately 1 in. square and 3 to 4 in. long. 

Sample cubes shown in the inset (left to right) are 

made of wood, cardboard, and office paper.
Federal Technology Alert

20 — FEDERAL ENERGY MANAGEMENT PROGRAM

Table 7. Savings from the Savannah 

River Site Cofiring Project.

Energy Savings

Coal supply reduced 2,240 tons/yr

58,240 MBtu/yr

Disposal Savings (paper & cardboard)

PEF cube supply 3,880 tons/yr

Savings Source Savings

Reduced coal costs $112,000/yr 

Reduced landfill costs $89,000/yr 

Burn pit closure $83,000/yr 

PEF processing costs ($30,000/yr)

Total Cost Savings $254,000/yr

Life-Cycle Cost

Design, construction, and 

equipment purchases for the PEF 

Facility totaled about $850,000. The 

net annual cost savings generated 

by the project are expected to be 

about $254,000. These savings are 

the result of reduced coal purchases, 

reduced landfill costs, and 

elimination of burn-pit operational 

costs. Operating the PEF Facility 

will cost about $30,000 per year. 

All expected costs and savings 

are summarized in Table 7, and 

associated calculations are shown in 

the annual cost savings worksheet 

in Appendix C. 

Based on a National Institute of 

Standards and Technology (NIST) 

Building Life-Cycle Costing (BLCC) 

comparative economic analysis (see 

Appendix E), the net present value 

of the project, based on a 10-year 

analysis period, will be more than 

$1.1 million. With a savings-toinvestment ratio of 2.3, the project 

is cost-effective according to federal 

criteria (W CFR 43G). The simple 

pay-back period for the project will 

be less than 4 years. (For details, 

see the federal life-cycle costing 

procedures in Appendix D and the 

NIST BLCC comparative analysis in 

Appendix E.) 

Performance Test Results 

As of February 2003, all equipment 

had been installed and tested 

at the SRS, and the facility is in 

preliminary startup mode. The 

equipment installed at the SRS 

PEF Facility was previously used 

in a similar coal-and-biomass 

cofiring demonstration project at 

INEEL in Idaho. The equipment 

operated well for more than a 

year at INEEL, but its use was 

discontinued when the steam 

plant was closed because of 

privatization of the utility. When 

the equipment was used at INEEL, 

PEF cubes provided about 25% (by 

volume) of the fuel at the steam 

plant, and no major operational 

problems were encountered. 

Test burns at the SRS have shown 

that no modifications were needed 

to current stoker boiler fuel-handling equipment to successfully 

fire the PEF/coal mixture. No 

fuel-feeding problems were 

experienced, and no increase in 

maintenance is expected to be 

necessary at the steam plant. 

Emissions measurements made 

during initial tests showed level 

or reduced emissions for all eight 

measured pollutants. Because 

of the low (nearly zero) sulfur 

content of wood and paper, sulfur 

emissions are expected to decrease. 

Sulfur emissions are reduced on a 

one-to-one basis with the fraction 

of heat input obtained from 

biomass; i.e., obtaining 20% of the 

plant’s total heat input from PEF 

cubes will reduce sulfur emissions 

by 20%. Opacity levels were also 

noticed to decrease significantly.

SRS steam plant personnel have 

supported the project. In 2003, 

permitting officials in South 

Carolina licensed SRS for one year 

of operation and evaluation, after a 

review of emissions test results and 

procedures for material collection 

and handling. The project manager 

hopes the facility will be licensed 

by South Carolina for long-term 

operation at high levels of biomass 

input by the end of 2004.

The Technology in 

Perspective

Biomass cofiring has good 

potential for use at federal 

facilities with existing coal-fired 

boilers. Advantages to federal 

facilities that accrue from using 

biomass cofiring technology 

can include reductions in fuel, 

operating, and landfill costs, as 

well as in emissions, and increases 

in their use of domestic renewable 

energy resources. Cofiring 

biomass with coal is expected 

to become more widespread as 

concerns for energy security and 

the environment become greater 

within agencies of the federal 

government. 

By replacing coal with less 

expensive biomass fuels, a federal 

facility can reduce air emissions 

such as NOx, SO2, and greenhouse 

gases. Cofiring with biomass also 

provides facility managers with 

a near-term renewable energy 

option, and it reduces their fuel 

price risk by diversifying the 

fuel supply. Cofiring also allows 

facilities to make use of local fuel 

supplies. Finally, only a minimum 

number of modifications 

to existing equipment and 

operational procedures (if any) 

are required, for the most part, 

to adapt a boiler to cofiring with 

biomass. When new equipment is 

needed, proven technologies are 

readily available.
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 21

Manufacturers

The following list includes companies identified as manufacturers 

of biomass cofiring equipment. 

We made every effort to identify 

current manufacturers; however, 

this listing is not purported to be 

complete or to reflect future market 

conditions. Please see the Thomas 

Register (www.thomasregister.com)

for more information.

Biomass Pelletizing Equipment

Bliss Industries

P.O. Box 910

Ponca City, OK 74602

Phone: 580-765-7787

www.bliss-industries.com

Cooper Equipment Inc.

227 South Knox Drive

Burley, ID 83318

Phone: 208-678-8015 

CPM Acquisitions Group

2975 Airline Circle

Waterloo, IA 50703

Phone: 319-232-8444

www.cpmroskamp.com 

Sprout Matador, 

Div. of Andritz

35 Sherman Street

Muncy, PA 17756-1202

Phone: 570-546-5811

www.sprout-matador.com

UMT (Universal Milling 

Technology) Inc.

8259 Melrose Drive

Lenexa, KS 66214

Phone: 913-541-1703

www.umt-group.com

Boiler Equipment/Cofiring 

Systems

ALSTOM Power Inc. 

(Formerly, ABB-Combustion 

Engineering Inc.)

2000 Day Hill Road

P.O. Box 500 

Windsor, CT 06095 

Phone: 860-285-3654

www.power.alstom.com 

The Babcock & Wilcox 

Company

20 South Van Buren Avenue

Barberton, OH 44203-0351

Phone: 800-BABCOCK

www.babcock.com

Babcock Borsig Power

(Formerly DB Riley, Inc.)

5 Neponset Street

Worcester, MA 01606

Phone: 508-852-7100

www.dbriley.com

Detroit Stoker Company

1510 East First Street

P.O. Box 732 

Monroe, MI 48161

Phone: 800-STOKER4

www.detroitstoker.com

Foster Wheeler Corporation

Perryville Corporate Park

P.O. Box 4000

Clinton, NJ 08809-4000

Phone: (908) 730-4000 

www.fwc.com

SNC-Lavalin Constructors 

Inc.

(Formerly Zurn/NEPCO)

P.O. Box 97008

Redmond, WA 98073-9708

Phone: 425-896-4000

www.nepco.com

Biomass and Alternative 

Methane Fuels (BAMF) Super 

ESPC Competitively Awarded 

Contractors

Constellation Energy Source

7133 Rutherford Rd.

Suite 401

Baltimore, MD 21244

Phone: 410-907-2002

DTE Biomass Energy, Inc.

54 Willow Field Drive

North Falmouth, MA 02556

Phone: 508-564-4197 

Energy Systems Group

101 Plaza East Boulevard

Suite 320

Evansville, IN 47715

Phone: 812-475-2550 x2541

Systems Engineering and 

Management Corp.

1820 Midpark Road, Suite C

Knoxville, TN 37921-5955

Phone: 865-558-9459

Trigen Development 

Corporation

One North Charles Street

Baltimore, MD 21201

Phone: 937-256-7378

For Further Information

For more information about the 

BAMF Super ESPC, contact:

Christopher Abbuehl

National BAMF Program

 Representative

U.S. Department of Energy 

Philadelphia Regional Office

100 Penn Square East, Suite 890

Philadelphia, PA 19107

Phone: 215-656-6995

E-mail:

 christopher.abbuehl@ee.doe.gov

See also the following U.S. 

Government Web sites:

www.eere.energy.gov/biopower/

main.html

www.eere.energy.gov/states 

Bibliography 

Antares Group Inc. (2000), The 

Cofiring Connection (CD-ROM 

compendium of technical papers 

on biomass cofiring), prepared for 

the U.S. Department of Energy 

Biomass Power Program.

Antares Group Inc. (May 1999), 

Strategic Plan and Analysis for 

Biomass Cofiring at Federal 

Facilities, prepared for the National 

Renewable Energy Laboratory, Task 

Order No. KAW-5-15061-01.
Federal Technology Alert

22 — FEDERAL ENERGY MANAGEMENT PROGRAM

Antares Group Inc. (June 1999), 

Biomass Residue Supply Curves for the 

United States, prepared for the U.S. 

Department of Energy’s Biomass 

Power Program and the National 

Renewable Energy Laboratory, Task 

Order No. ACG-7-17078-07.

Thompson, J. (updated annually), 

Directory and Atlas of Solid Waste 

Disposal Facilities, Chartwell 

Information Publishers, 

Alexandria, VA.

Cobb, J., et al. (Oct. 1999), 

“Demonstration of Wood/Coal 

Cofiring in a Spreader Stoker,” 

Sixteenth Annual Pittsburgh Coal 

Conference Proceedings, University 

of Pittsburgh, Pittsburgh, PA.

Cobb, J., et al. (June 1999), “Wood/ 

Coal Cofiring in Industrial Stoker 

Boilers,” Proceedings of the of the Air 

and Waste Management Association’s 

1999 Annual Meeting and Exhibition, 

St. Louis, MO.

Comer, K. (Dec. 1997), “Biomass 

Cofiring,” Renewable Energy 

Technology Characteristics, EPRI 

Topical Report No. TR-109496, 

Palo Alto, CA.

Electric Power Research Institute, 

et al. (1999), Biomass Cofiring: Field 

Test Results, EPRI Topical Report 

No. TR-113903, Palo Alto, CA.

Giaier, T., and Eleniewski, M. 

[Detroit Stoker Company] (Sept. 

1999), “Cofiring Biomass with 

Coal Utilizing Water-Cooled 

Vibrating Grate Technology,” 

Proceedings of the 4th Biomass 

Conference of the Americas, Elsevier 

Science Ltd., Oxford, UK.

Idaho National Engineering 

and Environmental Laboratory 

(1999), Waste-to-Energy Paper 

Cuber Project, Award Application 

to the American Academy of 

Environmental Engineers, U.S. 

Department of Energy, Idaho 

Operations Office, Idaho Falls, ID.

Liu, H. (Feb. 2000), Economic 

Analysis of Compacting and 

Transporting Biomass Logs for 

Cofiring with Coal in Power Plants, 

Capsule Pipeline Research Center, 

College of Engineering, University 

of Missouri-Columbia, CPRC 

Report No. 2000-1.

Makansi, J. (July 1987), “Cocombustion: Burning biomass, 

fossil fuels together simplifies 

waste disposal, cuts fuel cost,” 

Power, McGraw-Hill, New York, 

NY.

Miles, T. R.; Miles, T. R. Jr.; Baxter, 

L. L.; Bryers, R. W.; Jenkins, B. 

M.; Oden, L. L.; Dayton, D. C.; 

Milne, T. A. (1996), Alkali Deposits 

Found in Biomass Power Plants. A 

Preliminary Investigation of Their 

Extent and Nature (Vol. I); The 

Behavior of Inorganic Material in 

Biomass-Fired Power Boilers—Field 

and Laboratory Experiences (Vol. 

II), Vol. I: 133 pp.; Vol II: 496 

pp.; prepared for the National 

Renewable Energy Laboratory, 

NREL Report No. TP-433-8142; 

Golden, CO.

Mitchell, C.P., Overend, R.P., and 

Tillman, D.A. (2000), “Cofiring 

Benefits for Coal and Biomass,” 

Biomass & Bioenergy (special issue), 

Vol. 19, No. 6, Elsevier Science 

Ltd., Oxford, UK.

Muschick, R. (Oct. 1999), 

Alternate Fuel Facility Economic 

Study, Westinghouse Savannah 

River Company Site Utilities 

Department, Aiken, SC.

Tillman, D.A. (ed.) (2000), “Cofiring Benefits for Coal and 

Biomass,” Biomass & Bioenergy 

(special issue), Vol. 19, No. 6, 

Elsevier Science Ltd., Oxford, UK.

Tillman, D., Plasynski, S., and 

Hughes, E. (Sept. 1999), “Biomass 

Cofiring In Coal-Fired Boilers: 

Summary of Test Experiences,” 

Proceedings of the 4th Biomass 

Conference of the Americas, Elsevier 

Science Ltd., Oxford, UK.

Walsh, M., et al. (January 2000), 

Biomass Feedstock Availability in 

the United States: 1999 State Level 

Analysis, Oak Ridge National 

Laboratory, Oak Ridge, TN.

Wiltsee, G. (Nov. 1998), Urban 

Wood Waste Resource Assessment, 

prepared for the National 

Renewable Energy Laboratory, 

NREL/SR-570-25918, Golden, CO.
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 23

Appendix A

Assumptions and Explanation for Screening Analysis

Average delivered state coal prices were obtained from the Department of Energy’s Energy Information 

Administration. Estimated state-level low-cost biomass residue supplies were obtained from Biomass Residue 

Supply Curves for the United States (Antares Group Inc., June 1999). Average state landfill tipping fees were 

obtained from Chartwell Information Publishers. 

Data for coal costs, biomass supplies, and tipping fees were normalized on a 100-point scale for each of the 

50 states to capture the relative variation in each item from one state to the next. Weighting factors (ranging 

from one to three) were then applied to the normalized coal cost, biomass supply, and tipping fee data to 

account for the varying importance of these items in terms of the economics of a potential cofiring project. 

Typically, coal cost was weighted the highest, followed by biomass supply and then tipping fees. The weighted 

values for the normalized coal cost, biomass supply, and tipping fees were then summed together for each 

state, and the state rankings were based on these totals. A wide range of weighting-factor combinations were 

attempted to test the sensitivity of the screening tool, including a case in which coal costs, biomass supplies, 

and tipping fees were weighted equally.

This process showed that, although there were slight changes in the ordering of the states from one set of 

weighting factors to the next, the relative ranking of each state was very stable from trial to trial over a wide 

combination of weighting factors. In general, states with high coal costs, high biomass supplies, and high 

tipping fees ranked very high, while those with low coal costs, low biomass supplies, and low tipping fees 

ranked very low.
Federal Technology Alert

24 — FEDERAL ENERGY MANAGEMENT PROGRAM

Appendix B

Blank Worksheets for Preliminary Evaluation of a 

Cofiring Project

Biomass Fuel Supply Estimation Worksheet

The amount of biomass needed for a cofiring application depends on the size of the boiler, its loading, the 

cofiring rate (biomass/coal blend), and the type of biomass used. Biomass fuel supplies required for a cofiring 

operation can be estimated as follows, if the rate of coal use in the boiler, the heating value and density of the 

coal, the biomass/coal blend (or cofiring rate), and the heating value and density of the biomass are known.

DCFmax = daily coal feed rate at maximum rated load _________ tons/day

DCFave = daily coal feed rate at average operating load _________ tons/day

 (based on operating history)

ACU = annual coal use (based on operating history) _________ tons/year

HVc = average heating value of coal _________ Btu/lb

BDc = bulk density of coal _________ lb/ft3

HVb = average heating value of biomass fuel(s) _________ Btu/lb

BDb = bulk density of biomass _________ lb/ft3

If actual data are not available for HVc, BDc, HVb, and BDb, use the table below to estimate them.

Fuel Type Example Fuel

As-received 

Heating Value 

(Btu/lb) 

Bulk 

Density 

(lb/ft3)

Dry biomass (10% moisture) Chipped pallets 7,500 12.5

Moist biomass (30% moisture) Slightly air-dried wood chips or sawdust 6,000 15.0

Wet biomass (50% moisture) Fresh (“green”) wood chips or sawdust 4,500 17.5

Pelletized or cubed biomass Paper or sawdust cubes 7,500 to 8,500 40

Coal Stoker coal 13,000 80

Fill in one of the following three blanks and use the indicated equations to compute the other two values:

 Hb = % biomass, heat basis (% of total heat provided by biomass) _____%,

 use Eq. 1 and 2 to obtain Mb and Vb

 Mb = % biomass, mass basis (% of total fuel mass that is biomass) _____%, 

 use Eq. 2 and 3 to obtain Vb and Hb 

 Vb = % biomass, volume basis (% of total fuel volume that is biomass) _____%, 

 use Eq. 4 and 3 to obtain Mb and Hb 
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 25

To determine the cofiring rate (percent biomass) on a mass, heat, and volume basis:

After selecting a desired/target cofiring rate on either a mass (Mb), heat (Hb), or volume (Vb) basis, use two of the 

following equations to estimate the cofiring rate in the other units of measure:

The following equations allow you to estimate key biomass fuel supply rates in three units of measure: tons, 

cubic feet (ft3), and cubic yards (yd3). These numbers may be useful when sizing equipment, scheduling fuel 

deliveries, and obtaining biomass supply prices.

Maximum Daily Biomass Requirements:

 DBFmax = daily biomass feed rate at maximum rated load (multiple units)
Federal Technology Alert

26 — FEDERAL ENERGY MANAGEMENT PROGRAM

Average Daily Biomass Requirements:

 DBFavg = daily biomass feed rate at average rated load (multiple units)

Annual Biomass Requirements:

 ABU = annual biomass use (multiple units)
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 27

Annual Cost Savings Estimation Worksheet

ACU = annual coal use (based on operating history) ___________ tons/yr

Hb = % biomass, heat basis (% of total heat provided by biomass) ___________ %

UCcoal = unit cost of coal delivered to the boiler facility ___________ $/ton

ABU = annual biomass use proposed/estimated for boiler facility ___________ tons/yr 

UCbiomass = unit cost of biomass delivered to the boiler facility ___________ $/ton

TF = average tipping fee avoided by diverting biomass from landfill ___________ $/ton

Cother = other annual costs associated with using biomass ($/yr) ___________ $/yr

(not including the cost of delivered biomass; could include increased power consumption by material handling and processing 

equipment, additional labor costs associated with using biomass, etc.) 

CSother = other annual cost savings associated with using biomass ($/yr) ___________ $/yr 

(could include reduced biomass waste handling and transportation costs, recycling savings associated with the new method of 

handling biomass, etc.)

Annual Cost Savings

CScoal = annual cost savings from reduced coal consumption ($/yr)

Cbiomas = annual cost of biomass delivered to the boiler facility ($/yr)

CSlandfill = annual cost savings from avoided landfill fees ($/yr)

CStotal = total annual cost savings ($/yr)
Federal Technology Alert

28 — FEDERAL ENERGY MANAGEMENT PROGRAM

Appendix C

Completed Worksheets for Cofiring Operation

at Savannah River Site
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 29
Federal Technology Alert

30 — FEDERAL ENERGY MANAGEMENT PROGRAM
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 31

Appendix D

Federal Life-Cycle Costing Procedures

and the BLCC Software

Federal agencies are required to evaluate energy-related investments on the basis of minimum life-cycle costs 

(LCC) (10 CFR part 436). An LCC evaluation computes the total long-term costs of a number of potential 

actions, and selects the action that minimizes long-term costs. In considering retrofits, using existing equipment 

is one potential action; this is often called the baseline condition. The LCC of a potential investment is the 

present value of all of the costs associated with the investment over time.

The first step in calculating the LCC is to identify various costs: installed cost, energy cost, non-fuels operation 

and maintenance (O&M) costs, and replacement cost. Installed cost includes the cost of materials purchased 

and the cost of labor, for example, the price of an energy-efficient lighting fixture plus the cost of labor needed 

to install it. Energy cost includes annual expenditures on energy to operate equipment. For example, a lighting 

fixture that draws 100 watts (W) and operates 2,000 hours annually requires 200,000 watt-hours (2 kWh) 

annually. At an electricity price of $0.10/kWh, this fixture has an annuals energy cost of $20. Non-fuel O&M 

costs include annual expenditures on parts and activities required to operate the equipment, for example, 

checking light bulbs in the fixture to see if they are all operating. Replacement costs include expenditures for 

replacing equipment upon failure, for example, replacing a fixture when it can no longer be used or repaired.

Because LCC includes the cost of money, periodic and other O&M, and equipment replacement costs, energy 

escalation rates, and salvage value, it is usually expressed as a present value, which is evaluated by

LCC = PV (IC) + PV(EC) + PV (OM) + PV (REP)

 where 

 PV (x) denotes “present value of cost stream x,”

 IC is the installed cost,

 EC is the annual energy cost,

 OM is the annual non-energy cost, and

 REP is the future replacement cost.

Net present value (NPV) is the difference between the LCCs of two investment alternatives, e.g., between the 

LCC of an energy-saving or energy-cost-reducing alternative and the LCC of the baseline equipment. If the 

alternative’s LCC is less than the baseline’s LCC, the alternative is said to have NPV, i.e., it is cost-effective. NPV 

is thus given by

NPV = PV(EC0) - PV(EC1) + PV(OM0) – PV(OM1) + PV(REP0) – PV(REP1) – PV (IC)

 or

NPV = PV(ECS) + PV (OMS) + PV(REPS) – PV (IC)

 where

 subscript 0 denotes the baseline condition,

 subscript 1 denotes the energy cost-saving measure,

 IC is the installation cost of the alternative (the IC of the baseline is assumed to be zero),

 ECS is the annual energy cost savings,

 OMS is the annual non-energy O&M savings, and

 REPS is the future replacement savings.
Federal Technology Alert

32 — FEDERAL ENERGY MANAGEMENT PROGRAM

Levelized energy cost (LEC) is the break-even price (blended) at which a conservation, efficiency, renewable, or 

fuel-switching measure becomes cost effective (NPV ≥ 0). Thus, a project’s LEC is given by

PV(LEC*EUS) = PV(OMS) + PV(REPS) - PV(IC)

where EUS is the annual energy use savings (energy units/yr). Savings-to-investment ratio (SIR) is the total (PV) 

saving of a measure divided by its installation cost:

SIR = (PV(ECS) + PV(OMS) + PV(REPS))/PV(IC)

Some of the tedious effort of LCC calculations can be avoided by using the Building Life-Cycle Cost (BLCC) 

software developed by NIST. For copies of BLCC, call the EERE Information Center at 1-877-337-3463.
Federal Technology Alert

FEDERAL ENERGY MANAGEMENT PROGRAM — 33

Appendix E

NIST BLCC 5.0 Comparative Economic Analysis

10-Year Case Study Base Case: Coal Only

Alternative: Biomass and Coal Cofiring

General Information

Project name: Westinghouse Savannah River Company Fuel Facility Economic Study

Project location: South Carolina

Analysis type: Federal analysis, agency-funded project

Base date of study: January 1, 2001

Service date: January 1, 2002

Study period: 11 years 0 months (January 1, 2001, through December 31, 2011)

Discount rate: 3.4% (assumes initial system service date occurs one year after 

project evaluation begins)

Discounting convention: End-of-year

Comparison of Present-Value (PV) Costs: PV Life-Cycle Cost

Base Case Alternative Savings

Initial investment costs:

Capital requirements as of base date $0 $850,000 -$850,000

Future costs:

Energy consumption costs $4,220,115 $3,369,685 $850,430

Recurring and non-recurring OM&R costs: $1,333,451 $219,134 $1,114,316

Capital replacements $0 $0 $0

Total PV life-cycle cost $5,553,566 $4,438,819 $1,114,747

Net Savings from Alternative Compared with Base Case

PV of non-investment savings $1,864,747

– Increased total investment $850,000

Net savings $1,114,747

Savings-to-investment ratio (SIR): 2.31

Adjusted internal rate of return: 11.59%

Payback Period

Estimated years to payback (from beginning of service period): 

Simple payback occurs in year 4. 

Discounted payback occurs in year 4.

Energy Savings Summary 

Note: Total energy use would remain approximately the same. Figures below indicate reduced coal consumption. 

Displaced energy from coal will be replaced with energy from renewable biomass.

Energy Average Annual Consumption Life-Cycle

 Type Base Case (MBtu) Alternative (MBtu) Savings (MBtu) Savings (MBtu)

 Coal 289,800.0 231,400.0 58,400.0 583,760.2 

Emissions Reduction Summary

 Emission Average Annual Emission Life-Cycle

 Type Base Case (kg) Alternative (kg) Reduction (kg) Reduction (kg)

 CO2 27,478,053.40 21,940,723.11 5,537,330.29 55,350,562.35

 SO2 235,570.14 188,098.45 47,484.70 474,521.95 
Federal Technology Alert

34 — FEDERAL ENERGY MANAGEMENT PROGRAM

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Federal Technology Alert

About FEMP’s New Technology Demonstrations

Federal Energy Management Program

The federal government is the largest energy consumer in the nation. Annually, the total primary energy consumed by 

the federal government is 1.4 quadrillion British thermal units (quads), costing $9.6 billion. This represents 1.4% of the 

primary energy consumption in the United States. The Federal Energy Management Program was established in 1974 

to provide direction, guidance, and assistance to federal agencies in planning and implementing energy management 

programs that will improve the energy efficiency and fuel flexibility of the federal infrastructure.

Over the years, several federal laws and Executive Orders have shaped FEMP’s mission. These include the Energy Policy 

and Conservation Act of 1975; the National Energy Conservation and Policy Act of 1978; the Federal Energy Management 

Improvement Act of 1988; the National Energy Policy Act of 1992; Executive Order 13123, signed in 1999; and most 

recently, Executive Order 13221, signed in 2001, and the Presidential Directive of May 3, 2001.

FEMP is currently involved in a wide range of energy-assessment activities, including conducting new technology 

demonstrations, to hasten the penetration of energy-efficient technologies into the federal marketplace.

The Energy Policy Act of 1992 

and subsequent Executive Orders 

mandate that energy consumption 

in federal buildings be reduced by 

35% from 1985 levels by the year 

2010. To achieve this goal, the U.S. 

Department of Energy’s Federal 

Energy Management Program 

(FEMP) sponsors a series of activities 

to reduce energy consumption at 

federal installations nationwide. One 

of these activities, new technology 

demonstrations, is tasked to 

accelerate the introduction of energyefficient and renewable technologies 

into the federal sector and to improve 

the rate of technology transfer. 

As part of this effort, FEMP 

sponsors the following series of 

publications that are designed to 

disseminate information on new 

and emerging technologies:

Technology Focuses—brief 

information on new, energyefficient, environmentally friendly 

technologies of potential interest to 

the federal sector.

Federal Technology Alerts—

longer summary reports that 

provide details on energy-efficient, 

water-conserving, and renewableenergy technologies that have 

been selected for further study for 

possible implementation in the 

federal sector.

Technology Installation 

Reviews—concise reports describing 

a new technology and providing case 

study results, typically from another 

demonstration or pilot project.

Other Publications—we also issue 

other publications on energy-saving 

technologies with potential use in 

the federal sector.

More on Federal 

Technology Alerts

Federal Technology Alerts, our 

signature reports, provide summary 

information on candidate energysaving technologies developed 

and manufactured in the United 

States. The technologies featured in 

the FTAs have already entered the 

market and have some experience 

but are not in general use in the 

federal sector.

The goal of the FTAs is to improve 

the rate of technology transfer of new 

energy-saving technologies within 

the federal sector and to provide 

the right people in the field with 

accurate, up-to-date information on 

the new technologies so that they 

can make educated judgments on 

whether the technologies are suitable 

for their federal sites.

The information in the FTAs 

typically includes a description of 

the candidate technology; the results 

of its screening tests; a description 

of its performance, applications, 

and field experience to date; a list 

of manufacturers; and important 

contact information. Attached 

appendixes provide supplemental 

information and example worksheets 

on the technology.

FEMP sponsors publication of the 

FTAs to facilitate informationsharing between manufacturers 

and government staff. While the 

technology featured promises 

significant federal-sector savings, 

the FTAs do not constitute FEMP’s 

endorsement of a particular product, 

as FEMP has not independently 

verified performance data provided 

by manufacturers. Nor do the FTAs 

attempt to chart market activity 

vis-a-vis the technology featured. 

Readers should note the publication 

date on the back cover, and consider 

the FTAs as an accurate picture of 

the technology and its performance 

at the time of publication. Product 

innovations and the entrance of 

new manufacturers or suppliers 

should be anticipated since the date 

of publication. FEMP encourages 

interested federal energy and 

facility managers to contact the 

manufacturers and other federal 

sites directly, and to use the 

worksheets in the FTAs to aid in 

their purchasing decisions.
Federal Technology Alert

For More Information

EERE Information Center

1-877-EERE-INF or

1-877-337-3463

www.eere.energy/gov/femp/

General Program Contacts

Ted Collins

New Technology Demonstration

 Program Manager

Federal Energy Management Program

U.S. Department of Energy

1000 Independence Ave., S.W., EE-92

Washington, DC 20585

Phone: (202)-586-8017

Fax: (202)-586-3000

theodore.collins@ee.doe.gov

Steven A. Parker

Pacific Northwest National Laboratory

P.O. Box 999, MSIN: K5-08

Richland, WA 99352

Phone: (509)-375-6366

Fax: (509)-375-3614

steven.parker@pnl.gov

Technical Contacts and Authors

Sheila Hayter

National Renewable Energy Laboratory

1617 Cole Blvd.

Golden, CO 80401

Phone: (303) 384-7519

sheila_hayter@nrel.gov

Stephanie Tanner

National Renewable Energy Laboratory

901 D Street, S.W., Suite 930

Washington, DC 20024

Phone: (202) 646-5218

stephanie_tanner@nrel.gov

Kevin Comer and Christian Demeter

Antares Group Inc. 

4351 Garden City Drive, Suite 301 

Landover, MD 20785 

Phone: (301) 731-1900 

Produced for the U.S. Department 

of Energy, Energy Efficiency and 

Renewable Energy, by the National 

Renewable Energy Laboratory, 

a DOE national laboratory.

DOE/EE-0288

May 2004

A Strong Energy Portfolio for a Strong America

Energy efficiency and clean, renewable energy will mean a stronger 

economy, a cleaner environment, and greater energy independence for 

America. Working with a wide array of state, community, industry, and 

university partners, the U.S. Department of Energy’s Office of Energy 

Efficiency and Renewable Energy invests in a diverse portfolio of energy 

technologies.

Log on to FEMP’s Web site for information about

New Technology Demonstrations 

www.eere.energy.gov/femp/

You will find links to

• A New Technology Demonstration Overview

• Information on technology demonstrations

• Downloadable versions of publications in Adobe Portable 

 Document Format (pdf)

• A list of new technology projects under way

• Electronic access to a regular mailing list for new products 

 when they become available

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 new and emerging technologies

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