_______________________________________________ 

Sector-Based Pollution Prevention: Toxic Reductions 

through Energy Efficiency and Conservation Among 

Industrial Boilers 

A Report to the Great Lakes National Program Office (GL97514402) 

Submitted by The Delta Institute

July 2002 

__________________________________________ 

________________________________ 

The Delta Institute 

53 West Jackson Blvd., Suite 1604 

Chicago, Illinois 

(312) 554-0900 

http://www.delta-institute.org

_____________________________ 
Acknowledgements 

This work was funded by the U.S. EPA’s Great Lakes National Program Office and the 

Council of Industrial Boiler Owners. The Delta Institute would like to thank the facilities 

that participated in the audits, the Wisconsin Department of Natural Resources and the 

Wisconsin Focus on Energy for their involvement in this project. 
Contents 

Executive Summary 

Section 1: Introduction............................................................................1-1 

Section 2: Project Background...................................................................2-1 

 2.1 Overview 

 2.2 Industrial Boiler Background 

 2.3 Pollutants of Concern 

 2.4 Regulatory Framework 

Section 3: Energy Efficiency Assessments ...................................................3-1 

 3.1 Overview 

 3.2 Energy Efficiency Recommendation Trends 

 3.3 Discussion 

Section 4: Implementation........................................................................4-1 

 4.1 Overview 

 4.2 Discussion 

Section 5: Aggregation Analysis.................................................................5-1 

 5.1 Overview 

 5.2 Aggregation Analysis 

 5.3 Significance of Industrial Boiler Emissions 

 5.4 Efficiency Improvements 

 5.5 Summary 

Section 6: Conclusions and Recommendations................................................6-1 

References 

Tables 

2-1 U.S. Industrial Boiler Use by Sector 

3-1 Participating Facility Boiler Summary 

3-2 Recommendation Summary 

3-3 Average Recommendation Costs and Efficiency Improvements 

4-1 Factors Leading to Energy Efficiency Improvements 

5-1 Percent Total Number of Great Lakes States Industrial Boiler by Primary Fuel 

Source 
5-2 Summary of Aggregated Air Emissions of Specific Binational Toxic Strategy 

Compounds from Industrial Boilers in Great Lakes Region 

5-3 Comparison of Total Great Lakes States Industrial Boiler Emissions with Total 

U.S. Emissions from All Sources 

5-4 Comparison of U.S. Industrial Boiler Emissions with Total U.S. Emissions from 

All Sources 

5-5 Estimated Emissions Reduction from Great Lakes States Industrial Boilers 

Resulting from a 10% Energy Efficiency Improvement 

5-6 Comparison of Estimated Emissions Reductions from Great Lakes States 

Industrial Boilers to Total U.S. Emissions from All Sources 

5-7 Estimated Criteria Pollutant Emissions Reduction for Great Lakes States 

Industrial Boilers Resulting from a 10% Energy Efficiency Improvement 

Figures 

2-1 Industrial Boiler Schematic 

5-1 Great Lakes States Industrial Boiler Summary 

5-2 Great Lakes States Industrial Boiler Primary Fuel Summary 

5-3 Specific BTS Compound Emissions versus Primary Fuel 

Attachments 

A: Agreement Letter 

B: Sample Facility Survey 

C: Detailed Emissions Aggregation Tables 
Executive Summary 

In July of 1999, the Delta Institute launched a partnership with the Council of Industrial 

Boiler Owners to achieve emission reductions of Binational Toxics Strategy Level I and 

Level II pollutants from industrial boilers through the implementation of selected energy 

efficiency technologies and methods. The project hypothesized that energy efficiency 

measures offer significant opportunities to reduce both energy consumption and 

emissions of Binational Toxics Strategy substances from industrial boilers. 

To test this hypothesis, the Delta Institute, working with the Council of Industrial Boiler 

Owners and the Wisconsin Department of Natural Resources, performed energy 

efficiency assessments at nine Wisconsin facilities, with a total of 34 industrial boilers. 

Through these assessments, we found that optimizing energy needs (e.g., reducing the 

amount of fuel input) can result in reductions of toxics and greenhouse gas emissions 

because of reduced fuel use. 

This correlation was also confirmed through an aggregations analysis of emissions from 

over 20,000 industrial boilers located at facilities in eight Great Lakes states. This 

analysis showed that twelve percent, or 2,900, of industrial boilers located in the Great 

Lakes region that use coal and residual fuel oil as the primary fuel emit the majority of 

toxic emissions. For example, almost all of the 4.5 tons per year of mercury emitted by 

industrial boilers are from coal and residual fuel fired units. Our analysis of industrial 

boiler emissions shows that a conservative 10% efficiency improvement would reduce 

over 900 pounds of mercury emissions to the Great Lakes Basin. Furthermore, a 10% 

energy efficiency improvement would result in important reductions of criteria pollutants 

such as carbon monoxide, sulfur dioxide, nitrogen oxides, particulate matter, and carbon 

dioxide. 

Because of the significance of industrial boilers as a source of air toxics and the potential 

for reductions through energy efficiency measures, resources should be dedicated to 

designing a large-scale pollution prevention outreach initiative that links toxic reduction 

and energy efficiency. By doing so, the “natural” cost savings incentive of energy 

efficiency can be used to achieve quantifiable reductions of toxics as well as criteria 

pollutants. Given the relatively large number of facilities and ubiquitous nature of 

industrial boilers, achieving meaningful reductions from this “sector” will require new 

approaches to outreach and implementation incentives such as closer alliances between 

local pollution prevention and energy technical assistance resources and improved access 

to capital and other financial incentives. 

 

Current regulations will only go so far to attain the necessary reduction in air emissions. 

Even if all of the needed reductions from regulations could be achieved, the 

implementation timeframe would be too long. With respect to greenhouse gases, states 

are only just beginning to formulate policies and programs that reduce greenhouse gases. 

Pollution reduction opportunities that go beyond existing programs need to be sought out 

and implemented if permanent, ecosystem improvements in the Great Lakes region are 

ever to be realized. 
SECTION 1: Introduction 

In July of 1999, the Delta Institute launched a partnership with the Council of Industrial 

Boiler Owners (CIBO) to achieve emission reductions of Binational Toxics Strategy 

(BTS) Level I and Level II pollutants from industrial boilers through the implementation 

of selected energy efficiency technologies and methods.1

 The project hypothesized that 

energy efficiency measures offer significant opportunities to reduce both energy 

consumption and emissions of BTS substances from industrial boilers. The project 

focused on industrial boilers, as compared to larger utility boilers, because the local 

contribution of toxics deposited to the Great Lakes may be disproportionately higher 

from smaller facilities. 

To test this hypothesis, the Delta Institute, working with CIBO and the Wisconsin 

Department of Natural Resources (DNR), developed a program to provide technical 

assistance to industrial boiler owners in order to evaluate energy efficiency opportunities 

and emissions of BTS compounds. A series of boiler audits were subsequently 

performed at nine private and public sector facilities. Participants agreed to have a free 

assessment performed by a combustion expert hired by the Delta Institute. Each 

assessment included interviews with facility managers and power plant personnel, a site 

walk-through of the power plant facility, and a facility report documenting 

recommendations for energy efficiency improvements. In exchange, each facility agreed 

to consider implementing several recommendations for achieving greater energy 

efficiency and to explain why they would or would not implement the recommendations. 

A copy of a typical agreement letter is included in Attachment A. The Delta Institute 

identified potential facilities to audit by working in partnership with the Wisconsin DNR, 

Wisconsin Focus on Energy, and the Wisconsin Paper Council. 

The energy efficiency assessments were performed from May to July 2001. One 

additional assessment was completed in April 2002 to take advantage of an opportunity 

to work with the Wisconsin Focus on Energy project in order to understand the 

connections between energy efficiency opportunities associated with the manufacturing 

process and the power plant. 

This report presents the results of the energy efficiency assessments performed by the 

Delta Institute’s combustion expert and evaluates the opportunities associated with 

 

1

 Binational Strategy Level I substances include: mercury, PCBs, dioxin, 

benzo(a)pyrene/hexachlorobenzene, octachlorosytrene, pesticides, and alkyl lead. Level 

II substances include: cadmium and cadmium compounds, 1,4-dichlorobenzene, 3,3'-

dichlorobenzidine, dinitropyrene, endrin, heptachlor (and heptachlor epoxide), 

hexachlorobutadiene and hexachloro-1,3-butadiene, hexachlorocyclohexane, 4,4'-

methylenebis(2-chloroaniline), pentachlorobenzene, pentachlorophenol, 

tetrachlorobenzene (1,2,3,4- and 1,2,4,5-), tributyl tin, and PAHs as a group, including 

anthracene, benzo(a)anthracene, benzo(ghi)perylene, perylene, and phenanthrene. 
reducing both energy consumption and emissions of BTS substances from industrial 

boilers. The report is organized into the following sections: 

Section 2- Background. Provides an overview of industrial boiler units and the 

associated regulatory framework. 

Section 3- Energy Efficiency Assessment. Provides an overview of the energy 

efficiency assessments conducted by the Delta Institute’s consultant and presents 

the energy efficiency recommendations developed for each participating facility. 

Section 4- Implementation. Describes opportunities and barriers to implementing 

the energy efficiency recommendations. 

Section 5- Aggregation Analysis. Presents an analysis of the emissions reduction 

potential to the Great Lakes region from industrial boilers that implement energy 

efficiency measures. 

Section 6- Conclusions and Recommendations. Presents a proposal for “getting to 

scale” to achieve significant emissions reductions from industrial boilers. 

This work was funded by the U.S. EPA’s Great Lakes National Program Office and the 

CIBO. The Delta institute would like to thank the facilities that participated in the audits, 

the Wisconsin DNR and the Wisconsin Focus on Energy for their involvement in this 

project. 
SECTION 2: Project Background 

2.1 Overview 

Industrial boilers provide thermal energy in the form of hot water, saturated steam, or 

superheated steam needed to run processes or machinery or to produce electricity to 

power manufacturing operations. Each year, approximately 245 billion kilowatt hours of 

electrical energy or 6% of the total energy generated in the United States is produced by 

manufacturing industrial sources such as industrial boilers, kilns and furnaces (DOE 

2001). The 51,000 industrial boilers and process heaters located throughout the U.S. 

(20,000 of which are located in the Great Lakes region) produce a significant portion of 

that energy load. 

Industrial boilers are ubiquitous in industrial, commercial and institutional operations. It 

is estimated that over 800 industrial sectors use industrial boilers for generating 

electricity and steam (U.S. EPA 1998b). As shown on Table 2-1, approximately 50% of 

the total boilers in the U.S. are used by 17 industrial/institutional/commercial sectors to 

meet their energy needs. 

Table 2-1: U.S. Industrial Boiler Use by Sector (1)

SIC SIC Description 

No. 

facilities

No. 

boilers 

< 10 MM 

BTU 

10 to <50 

MM BTU

50 to 

<100MM 

BTU 

100 to <250 

MM BTU 

> or =250 

MM BTU

% of 

Total 

9711 

National Security And Intl. Affairs, National 

Security, National security 264 4,047 2,214 374 119 78 8 8% 

8062 

Health Services, Hospitals, General medical & 

surgical hospitals 849 2,283 517 901 102 35 8 5% 

1311 

Oil And Gas Extraction, Crude Petroleum and 

Natural Gas 371 2,011 318 113 81 25 9 4% 

8221 Educational Services, Colleges and Universities 393 1,868 513 391 176 119 19 4% 

8211 

Educational Services, Elementary and 

Secondary Schools, Elementary and secondary 

schools 1,208 1,832 1,258 295 18 1 4 4% 

2869 

Chemicals And Allied Products, Industrial 

Organic Chemicals, Industrial organic 

chemicals, nec 328 1,373 158 185 107 216 155 3% 

2911 

Petroleum And Coal Products, Petroleum 

Refining, Petroleum refining 237 1,143 41 127 98 140 137 2% 

2621 

Paper And Allied Products, Paper Mills, Paper 

mills 286 1,030 47 92 85 141 146 2% 

3312 

Primary Metal Industries, Blast Furnace and 

Basic Steel Products, Blast furnaces and steel 

mills 122 1,009 73 71 44 63 17 2% 

4961 

Electric, Gas, And Sanitary Services, Steam and 

Air-conditioning Supply, Steam and airconditioning supply 259 879 32 81 61 107 28 2% 

2821 

Chemicals And Allied Products, Plastics 

Materials and Synthetics, Plastics materials and 

resins 238 852 113 150 90 99 54 2% 

2421 

Lumber And Wood Products, Sawmills and 

Planing Mills, Sawmills & planing mills, 

general 462 829 83 158 45 21 5 2% 

3714 

Transportation Equipment, Motor Vehicles and 

Equipment, Motor vehicle parts and accessories 250 766 230 122 50 44 8 2% 

2819 

Chemicals And Allied Products, Industrial 

Inorganic Chemicals, Industrial inorganic 

chemicals, nec 222 704 139 125 52 49 31 1% 

2834 

Chemicals And Allied Products, Drugs, 

Pharmaceutical preparations 176 602 157 153 47 30 2 1% 
SIC SIC Description 

No. 

facilities

No. 

boilers 

< 10 MM 

BTU 

10 to <50 

MM BTU

50 to 

<100MM 

BTU 

100 to <250 

MM BTU 

> or =250 

MM BTU

% of 

Total 

2752 

Printing And Publishing, Commercial Printing, 

Commercial printing, lithographic 139 595 198 52 8 6 5 1% 

2511 

Furniture And Fixtures, Household Furniture, 

Wood household furniture 287 550 105 152 14 4 1 1% 

9223 

Justice, Public Order, And Safety, Public Order 

and Safety, Correctional Institutions 158 511 131 162 27 3 0 1% 

(1) U.S. EPA. 1998b. Distribution of boilers by SIC Table. Office of Air Quality Planning and Standards. 

http://www.epa.gov/ttn/atw/combust/iccrarch/bo.html. April. 

Many of the sectors shown on Table 2-1 are considered to be energy intensive industries. 

A comparison of these industrial sectors with industrial energy consumption data found 

in the Department of Energy 1998 Energy Consumption Survey shows the following 

sectors to be energy intensive and utilize industrial boilers to meet their energy needs: 

• Primary Metals 

• Petroleum Refining 

• Paper 

• Chemicals 

• Transportation Equipment 

2.2 Industrial Boiler Background 

Sizes of industrial boilers range from off-the-shelf package boilers of less than 10 MM 

Btu (million British thermal units) heat input to custom installed units of more than 250 

MM Btu heat input.2

 Even though some industrial boilers are as large as utility boilers 

(boilers owned and operated by electric generating utilities producing energy for sale), 

energy generated by industrial boilers is primarily for private consumption.3

Consequently, industrial boilers are regulated separately from utility boilers. This report 

solely considers energy efficiency options associated with industrial boiler units. 

A range of industrial boiler types and sizes were assessed during this project; however, 

the majority of the units assessed fall into the category of large capacity, water-tube type 

boilers. The predominate design configurations assessed as part of this project were: 

1. Stoker-fired boilers. Stoker-fired boilers are typically water-tube boilers with a 

mechanical system to feed solid fuel into the boiler. Water-tube boilers circulate 

hot combustion gas around water-filled tubes lining the walls of the boiler unit. 

2. Pulverized Coal (PC) fired boilers. PC-fired boilers are also water-tube type 

boilers. Instead of solid fuel, pulverized coal is injected with primary combustion 

air into the boiler unit from a series of coal injection points. Liquid and gaseous 

fossil fuels can be supplemented in PC-fired boilers. 

 

2

 A British thermal Unit (Btu) is a standard unit of heat measure approximately equivalent to 0.293 Watts. 

3

 An electric utility is defined in Section 112 (a) (8) of the Clean Air Act as “any fossil fuel fired 

combustion unt of more than 25 megawatts electric (MWe) that serves a generator that produces electricity 

for sale.” A unit that cogenerates steam and electricity and supplies more than one-third of its potential 

electric output capacity and more than 25 MWe output to any utility power distribution system for sale is 

also considered an electric utility steam generating unit. 
3. Fluidized bed combustion (FBC) boilers. Fuel is burned on a bed of hot particles 

suspended by an upward flow of combustion air. As compared to other watertube type boilers, FBCs can burn a variety of fuel types and generally achieve 

greater rates of efficiency. 

4. Cyclone-fired boilers. Cyclone-fired boilers are water-tube type boilers where 

high-temperature flames circulate in a cyclonic pattern. Cyclone-fired boilers are 

almost always coal-fired units. 

A more detailed description of these, and other types of industrial boiler units, can be 

found in the CIBO’s Industrial Boiler Guide. Figure 2-1 shows a simple schematic of a 

water-tube boiler. 

Schematic from the Coal Utilization Center 

For the purposes of this report, the primary distinction between boilers is fuel source. 

The type of fuel used together with the individual boiler efficiency characteristics defines 

the air emissions profile (e.g. type and quantity of controlled and uncontrolled emissions) 

for industrial boiler units. The three fuels most commonly used in industrial boilers are 

coal, liquid fossil fuel, and natural gas (CIBO 2002). Alternative fuel sources such as 

wood, tires and other solid waste, and process gases are utilized by less than 1% of 

industrial boilers in the Great Lakes region. 

Coal was the most common fuel used in the industrial boilers evaluated in this project. 

Fuel oil and natural gas were used in several of the smaller size units evaluated or as 

supplemental fuel for coal-fired units. Coal is a solid fossil fuel that varies in heat value 

based on the type of coal and source location. Classes of coal include lignite, subbituminous, bituminous, and anthracite. The type and quantity of criteria and toxic 

emissions depend on the class of coal. Fuel oils are liquid fossil fuels that also vary in 

heat value based on the type of fuel oil. For the purpose of this report, two types of fuel 

oil are considered- distillate fuel oil and residual fuel oil. Distillate fuel oils (e.g. Number 

2 fuel oil) are more refined than residual fuel oils and are generally considered to have 
fewer emissions of toxic pollutants as compared to residual fuel oil or coal. Distillate oils 

are commonly used for residential heating or as supplemental fuels in industrial boilers. 

Residual fuel oils (e.g. Number 6 fuel oil) are more viscous and have greater emissions of 

criteria and toxic compounds than the lighter, less viscous distillate oils. Natural gas is 

considered to be the cleanest burning fuel- lowest overall emissions of criteria and toxic 

pollutants- of the three fuels considered in this report. Natural gas is used as the primary 

fuel by some smaller industrial boiler units and as a supplemental fuel source by larger 

units. 

The efficiency of a boiler unit is the capacity of the unit to maximize the conversion of 

fuel energy to thermal energy with minimal heat losses. It is generally accepted that 

more efficient boilers utilize less fuel to produce a given quantity of steam or energy 

(CIBO 2002). Correspondingly, reduced fuel usage results in reduced emissions per a 

given quantity of energy produced. Two factors that affect operation at optimal 

efficiency are combustion efficiency and boiler efficiency (CIBO 2002). Combustion 

efficiency is the ability of the boiler through design and operational parameters to extract 

the maximum energy from the fuel sources or to achieve complete fuel combustion. 

Boiler efficiency is a function of non-combustion related losses such as radiant heat loss, 

blow-down loss, and other unaccounted losses (CIBO 2002). The industrial boiler 

assessments completed as part of this project identified efficiency improvements to 

improve both combustion efficiency and boiler efficiency with the overall result being 

reduced fuel usage. 

2.3 Pollutants of concern 

Emissions from industrial boilers are a function of the type and quantity of primary fuel 

burned in the boiler unit, the type of boiler, and emissions controls. Boilers emit a 

variety of pollutants including those pollutants associated with combustion processes, 

such as nitrogen oxides (NOx), sulfur dioxide (SO2), particulate matter (PM), and carbon 

monoxide (CO), as well as air toxics. The primary air toxics include: formaldehyde, 

polynuclear aromatic hydrocarbons (PAHs), lead, hydrogen chloride, cadmium, mercury, 

and dioxin/furans (US EPA 1998). Several of the air toxics emitted by industrial boiler 

units, such as mercury, dioxin/furans, cadmium, PAHs, and 1,4-dichlorobenzene are 

considered to be Level I and II pollutants of concern under the BTS program which are 

the primary focus of this project. 

2.4 Regulatory Framework 

Industrial boilers considered to be major sources are regulated for hazardous air 

pollutants and certain criteria pollutants.4

 Title V of the Clean Air Act contains 

provisions for issuing operating permits by the federal government or designated state 

agencies (40 CFR 70 and 71). For some units, the Acid Rain Program may also be 

applicable (40 CFR 72). Additionally, new boiler units over a certain size are required to 

comply with National Ambient Air Quality Standards (NAAQS) and New Source 

Performance Standards that regulate criteria pollutants including NOx, SO2, CO, PM, and 

ozone (O3). New large sources or modification of existing sources located in attainment 

 

4

 A major source is considered to emit more than 25 tons of total hazardous air pollutants per year or more 

than 10 tons of any one hazardous air pollutant per year. 
areas must comply with the Prevention of Significant Deterioration (PSD) requirements 

(40 CFR 52.21).5 Sources located in non-attainment areas must obtain a Non-attainment 

New Source Review Permit. 

A Maximum Achievable Control Technology (MACT) standard for industrial, 

commercial and institutional boilers and process heaters will be proposed by the U.S. 

EPA in summer 2002 (Eddinger 2002a). The MACT rules are technology driven 

requirements that require facilities to meet emissions limits of hazardous air pollutants 

(HAPs). Industrial/commercial/institutional boilers and process heaters situated at a 

major source facility will likely be required to comply with the MACT standards. 

Nationwide it is estimated that 57,000 units (42,000 boilers and 15,000 process heaters) 

will be required to comply. Fossil fuel-fired electric utility boilers, municipal waste 

boilers, hazardous waste boilers, medical waste boilers, black liquor recovery boilers, hot 

water heaters, and waste heat boilers will not be addressed by the upcoming MACT rules 

(Eddinger 2002a). 

The Industrial/Commercial/Institutional Boiler MACT is anticipated to include 

provisions for controlling the following compounds: metal and particulate matter, acid 

gases, and mercury. With respect to the BTS compounds, when fully implemented the 

MACT rules are expected to reduce cadmium by 10.3 tons per year and mercury by 1.9 

tons per year. MACT will not likely regulate organic HAPs, although some reductions 

may be realized based on the final emissions limitations promulgated, therefore projected 

reductions from MACT implementation for dioxin, PAHs, 1,4-dichlorobenzene are not 

available (Eddinger 2002a). The MACT emissions limits are based on the concentration 

of HAPs per unit of fuel input as compared with total HAPs in the fuel. Therefore, 

energy efficiency measures that depend on decreasing HAPs emissions by reducing fuel 

usage could not necessarily be used to meet the MACT emissions limits. However, 

reductions through energy efficiency opportunities will become increasingly important in 

those states, such as Wisconsin, that are in the process of promulgating state rules to 

control combustion and industrial sources of certain compounds- specifically mercury. 

 

5

 An attainment area is a geographic area considered to meet the U.S. EPA National Ambient Air Quality 

Standards for six criteria pollutants: carbon monoxide, nitrogen dioxide, ozone, lead, particulate matter, and 

sulfur dioxide. Additional information can be found at the U.S. EPA websitewww.epa.gov/airs/criteria.html. 
SECTION 3- Energy Efficiency Assessments 

3.1 Overview 

The combustion expert, hired by the Delta Institute, performed boiler energy efficiency 

assessments at nine facilities with a total of thirty-four operating boilers. Primary 

operations at the participating facilities included: 

• Four pulp and paper producers (designated in this report as PVT-1 through 4); 

• One manufacturing facility (designated PVT-5); and, 

• Four institutional facilities (designated PUB-1 through 4). 

Except for the manufacturing facility, coal was the primary fuel source used in each 

industrial boiler. The manufacturing facility used natural gas because of the relatively 

small size of its boilers. Table 3-1, found at the end of this section, summarizes the boiler 

types, sizes, and fuel sources at each participating facility. 

Each assessment included: a one to two day site walkthrough of readily accessible areas 

of the power plant; a visual inspection of each boiler, control room, and associated 

equipment; and visual inspections of fuel storage areas. The consultant also interviewed 

on-site personnel responsible for maintenance and operation of each power plant. When 

available, each facility provided data for operating parameters (e.g. oxygen, inlet air 

temperature, flue gas temperature) for each boiler as well as stack emissions 

measurements. Plant-specific energy efficiency recommendations were developed based 

on the site visit. In general, the consultant used the following assessment methodology: 

1. Consultation with facility managers. The consultant interviewed facility 

managers and power plant operators and collected general background facility 

information such as: type and configuration of combustion devices and steam 

systems and fuel use records. The consultant also reviewed pertinent technical 

documentation including: previous audit or testing reports, stack testing, and 

permits. In some cases, the facility provided this information prior to the on-site 

assessment. 

2. Inspection and audit of facility. The consultant assessed the feasibility and 

effectiveness of implementing the following specific combustion and steam 

efficiency measures: 

• Combustion Evaluation and Optimization Methods 

• Combustion Monitoring and System Controls 

• General Operations and Training of Staff 

• Steam Load and Efficiency Measures 

• Combined Heat and Power (CHP) potential. 

3. Facility report. Recommendations on the feasibility of implementing specific 

combustion and steam efficiency measures and combined heat and power were 

provided. This included estimates of costs to implement, fuel and cost savings, 

and specific emission reductions, including persistent bioaccumulative 

compounds. 
The recommendations were discussed with each facility immediately following the site 

visit and a follow-up letter report documenting the recommendations and, in some cases, 

capital costs and estimated payback periods. 

The scope of the April 2002 assessment performed at a small manufacturing facility was 

different from the previous assessments. The manufacturing facility had previously 

undergone a process side energy efficiency assessment by the Wisconsin Focus on 

Energy process experts. Based on that assessment, it was determined that greater energy 

efficiency savings could potentially be realized throughout the plant if the boiler and 

steam generating systems also operated more efficiently. The Wisconsin Focus on 

Energy group contacted the Delta Institute to participate in the project. At the time of 

this report, the Wisconsin Focus on Energy group is continuing to coordinate with the 

facility to implement the recommendations. 

3.2 Energy Efficiency Recommendation Trends 

The energy efficiency opportunities recommended to a participating facility can be 

divided into nine categories based on industrial boiler operations, as follows: 

• Start-up procedures 

• Fuel management 

• Water treatment 

• Combustion air pre-heating 

• Controls 

• Flue gas treatment 

• Associated equipment 

• Steam systems 

• Heat recovery. 

In general, the recommendations have been grouped to correspond to typical power plant 

operational areas and could, therefore, be implemented at other industrial boiler facilities. 

Even though boiler systems have many of the same operational components, it should be 

acknowledged that most large boiler systems are custom designed and installed to meet 

specific facility power needs. The final category- Facility-specific recommendationsrepresents those recommendations that are particular to a facility and not likely to be 

broadly implemented at other facilities. A description of each of the categories follows. 

Start-up/shut-down procedures- Boiler start-ups typically require one to six hours 

to achieve optimal operating temperatures. Until the operating temperature is 

reached, the start-up fuel is not completely combusted causing increased 

emissions of toxic compounds. Frequently, boiler owners will use a relatively 

low emission fuel, such as natural gas, during start-up to alleviate this problem. 

This, however, is not the case with all boilers. Start-up procedures typically do 

not improve boiler efficiency; however, managed start-up and fuel choice can 

minimize regulatory compliance issues as well as significantly reduce toxics. In 

one instance, shut-down procedures provided energy savings. If the boiler units 
are relatively small, shutting the units down in the evening would provide energy 

savings. 

Fuel management- Fuel is typically the most costly item associated with boiler 

operation; therefore, the maximum BTUs should be extracted from each load of 

fuel introduced into the boiler. Improving management of fuel storage areas to 

reduce excess water and debris and enhancing fuel input mechanisms are methods 

that can easily be implemented to improve the combustion potential of fuels. 

Water treatment- Water is the most common medium for boiler heat exchange 

and steam generation. Proper conditioning of water used in boiler systems, in 

order to prevent scaling and fouling, is integral to maintaining efficient boiler 

operations. 

Combustion air preheating- Preheating inlet combustion air with otherwise 

wasted heat is one method to improve combustion and increase the efficiency of 

the boiler unit. 

Controls- Implementing control strategies that take advantage of improved 

measurement techniques such as computer based distributed control systems for 

air flow, pressure, and temperature can be utilized by boiler operators to improve 

overall system efficiency. 

Flue gas treatment- Flue gas controls are necessary to minimize criteria and toxic 

pollutants into the atmosphere. Improved pollution reduction techniques and 

control measures do not necessarily provide energy efficiency opportunities; 

however, these measures can improve regulatory compliance. 

Associated equipment- Auxiliary equipment includes fans, pumps, motors, 

turbines, and material handling equipment. Proper control, operation, and 

maintenance of this equipment, as a whole, will result in significant energy 

efficiency improvements. Replacing equipment with high efficiency models or 

installing variable speed drives will more significantly improve energy efficiency. 

Steam systems- Operation and maintenance of steam system components such as 

steam generating equipment, steam traps, and steam lines have been found to be 

one of the best energy and cost saving techniques. 

Heat recovery- Utilizing excess heat from boiler operations to fuel other plant 

processes or to create energy that can be sold to a local utility is one method of 

efficiently using all of the BTUs generated from the boiler fuel. Economic gains 

from combined heat and power systems will vary, however, based on the local 

utility pricing structure and the power needs of the plant. 

Table 3-2, found at the end of this section, summarizes the recommendations presented to 

each facility. Estimated capital costs were based on typical purchase and installation 
requirements and yearly cost savings and payback periods were based on yearly fuel 

usage and estimated yearly primary fuel savings that would result from implementing the 

recommended energy efficiency improvement. 

Taken together, these eight categories represent some of the best opportunities for cost 

savings from energy efficiency. Table 3-3 presents the average energy efficiency 

savings, costs, and payback period for each category. 

Table 3-3: Average Recommendation Costs and Efficiency Improvements 

Category (1) No. of 

Recommendations 

Average Capital 

Cost to 

Implement 

Average 

Yearly 

Cost Savings 

Average 

Efficiency 

Improvement 

Start-up/Shutdown procedures 4 (2) $0 $1,500 <1% 

Fuel management 9 $77,000 $133,800 0.8 

Water treatment 4 $93,200 $24,300 2 

Combustion air 

pre-heating 3 (2) $12,000 to $75,000 $146.700 2 

Controls 8 $53,100 $46,000 1.4 

Associated 

equipment 2 $65,000 $109,800 3 

Steam systems 6 $21,350 $313,900 9 

Heat Recovery 4 Further assessment required. 

(1) Recommendations pertaining to flue-gas treatment were not included in Table 3-3 because no 

efficiency improvements would be realized for those recommendations although reductions in 

toxics would likely occur. Only one start-up/shut-down procedure would provide efficiency 

improvements. These recommendations, as shown on Table 3-2, generally address permit issues 

and stack emission controls. 

(2) Cost information provided for one recommendation only. 

3.3 Discussion 

A comparison with other energy efficiency studies shows that the energy efficiency 

savings developed by this project are less than those projected by CIBO in their Energy 

Efficiency Handbook or DOE/Industrial Assessment Centers (IAC) database for similar 

recommendations (CIBO 1997; U.S. EPA 1999). Energy efficiency improvement 

estimates developed for this project are considered to be conservative (low) due to the 

small sample size (9 facilities). 

Average capital costs and payback periods for the project recommendations are 

representative for the paper and allied products industry (SIC 26) when compared to the 

DOE/IAC database of 226 paper and allied product companies summary of energy 

efficiency measures. (U.S. EPA 1998c). For example, the average implementation cost 

for the pulp and paper facilities assessed by the Delta Institute is $76,000 while the 

DOE/IAC database average is $65,000. Alternately, payback costs for recommendations 

developed as part of this project are generally higher than the DOE/IAC database. The 

capital costs and payback periods developed for the manufacturing facility were higher 

than the averages found in the DOE/IAC database of efficiency measures (U.S. EPA 

1998c). The primary reason for these differences is that the costs developed for the 
participating facilities did not fully integrate operation and maintenance costs and used 

using maximum operating parameters to calculate the fuel load. 
Table 3.1 - Facility Boiler Summary

Facility 

(1, 2) Description

Boiler 

Unit 

Number

Boiler Type (3) Installation 

Date Primary Fuel (4) Start-Up Fuel (3) Maximum Capacity (MMBtu/hr)

PVT-1 Pulp & Paper 7 Stoker 1955 Coal/20% bark Wood/Coal 122

8 Cyclone 1956 Coal Natural Gas 190.9

9 Package 1969 Natural Gas Natural Gas 140

10 Stoker 1977 Coal/20% bark Wood/Coal 357

11 Package 1995 Natural Gas Natural Gas 249

PVT-2 Pulp & Paper 3 Not Operating

4 Underfeed Stoker 1944 Coal Coal 200

5 Underfeed Stoker 1950 Coal Coal 200

6 Spreader Stoker 1962 Coal Coal 350

7 Cyclone 1968 Coal Coal/Fuel Oil/Natural Gas 615

8 Rotograte Stoker 1975 Coal Coal 235

9 Fluidized Bed 1989 Petroleum Coke Coal/Fuel Oil 486

PVT-3 Pulp & Paper 1 Pulverized coal 1947 Coal Natural Gas 208

2 Pulverized coal 1952 Coal Natural Gas 208

7 Not Operating

8 Not Operating

10 Stoker 1965 Coal/Bark Natural Gas 300

PVT-4 Pulp & Paper 3 Water Tube NA Residual Oil/Natural Gas Natural Gas 66

4 Water Tube NA #6 Oil/Natural Gas Natural Gas 77

9 Water Tube 1962 Residual Oil/Natural Gas Natural Gas 182

Package Fuel Oil NA 38

PVT-5 Manufacturing Plant 1 

Unit 1 Pacakage 1960 Natural Gas Natural Gas 8.3

Plant 1 

Unit 2 Steam Generator Unk. Natural Gas Natural Gas > 90 psi

Plant 2 

Unit 1 Steam Generator Unk. Natural Gas Natural Gas > 90 psi

Plant 2 

Unit 2 Steam Generator Unk. Natural Gas Natural Gas > 90 psi

PUB-1 Institutional 1 Water Tube 1971 Natural Gas/#2 Fuel Oil Natural Gas/#2 Fuel Oil 80

2 Water Tube 1971 Natural Gas/#2 Fuel Oil Natural Gas/#2 Fuel Oil 80

3 Water Tube 1971 Natural Gas/#2 Fuel Oil Natural Gas/#2 Fuel Oil 40

4 Water Tube 1991 Natural Gas/#2 Fuel Oil Natural Gas/#2 Fuel Oil 10.4

PUB-2 Institutional 1 Stoker 1949 Coal/Paper pellets Natural Gas 47.5

2 Stoker 1949 Coal/Paper pellets Natural Gas 47.5

3 Stoker 1949 Coal/Paper pellets Natural Gas 47.5

PUB-3 Institutional 1 Water Tube 1955 Coal Natural Gas 59.5

2 Water Tube 1955 Coal/Natural Gas/Oil Natural Gas 59.5

3 Water Tube 1960 Coal/Natural Gas/Oil Natural Gas 71.8

PUB-4 Institutional 1 Water Tube 1968 Natural Gas/#2 Oil Natural Gas/#2 Oil 150

2 Water Tube 1968 Natural Gas/#2 Oil Natural Gas/#2 Oil 150

Notes:

(1) PVT- Private Industry

(2) PUB- Public Facility

(3) See Section 2 of the Sector-Based Pollution Prevention: Toxic Reductions through Energy Efficiency and Conservation Among Industrial Boilers

Page 1 of 1
Facility Boiler Unit Recommendation Estimated 

Capital Cost

Estimated 

Yearly Cost 

Savings

Estimated 

Efficiency 

Improvement

PVT-1 Boiler 5

Boiler 9

Reduce start-up times on all boilers. Utilize natural 

gas as a start-up fuel to reduce levels or organic 

toxics. 

$50,000 NA 0

PVT-2 General Revise SO2 limit in existing air permit to reduce the 

need for multiple start-ups caused by SO2 limitations. 

$10,000 to 

$15,000 NA 0

PVT-5 General Improve shut down procedures for unneeded boilers $0 $1,500 <1%

PUB-3 General Reduce start-up times to reduce levels of toxics 

emitted during start-up procedures. NA NA 0

PVT-1 General Fuel dry bark to improve combustion of bark fuel 

source. 

$100,000 fuel 

dryer capable of 

treating bark at a 

rate of 6 tons 

per hour .

Up to $300,000 

per year savings 

in coal use by 

increasing Btu 

value of wood 

fuel.

1 to 2%

PVT-1 General Cover bark fuel storage area to reduce moisture and 

improve combustion of bark. 

$50,000 to 

$100,000

Up to $300,000 

per year savings 

in coal use by 

increasing Btu 

value of wood 

fuel.

0.50%

PVT-2 Boiler 9

Reinject ash to reduce the amount of ash (and cost) 

for disposal. Operators stated that reworking the ash 

removal system on this unit would greatly reduce 

maintenance requirements. 

$75,000 $13,300 to 

$26,600 1 to 2%

PVT-2 Boiler 9 Install sootblowers to improved heat transfer and 

reduce back-end temperatures. $100,000 NA

Additional 

assessment 

needed by vendor.

Fuel Management

Table 3-2: Recommendation Summary

Start-up/Shut-down Procedures

Page 1 of 6
Facility Boiler Unit Recommendation Estimated 

Capital Cost

Estimated 

Yearly Cost 

Savings

Estimated 

Efficiency 

Improvement

Table 3-2: Recommendation Summary

PVT-2 General

Re-use bottom boiler ash to take advantage of Btu 

value. Bottom boiler ash has been analyzed and 

contains up to 8000 BTU/lb (better than dry wood). 

$75,000 

Fuel cost saving: 

$8,200 to 

$27,900. 

Disposal Cost 

saving: $48,000

1 to 2%

PVT-2 General

Modify limestone conveying system to improve delivery 

of correctly sized limestone and minimize quantity of 

limestone used.

$100,000 

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

PVT-3 General Tarp rail cars to reduce excess moisture to coal and 

bark fuel sources to improve combustion process. 

10 tarps at $500 

per tarp: $5,000 $5,800 

0.2% overall 

improvement for 

three boiler system

PUB-2 General

Replacing fuel feeders with newer, more modern 

design to improve opacity and decrease toxic 

emissions.

$123,000 per 

boiler $128,000 0.25%

PUB-3 General Co-fire (or over-fire) up to 20% natural gas to reduce 

criteria and toxic pollutant emissions. 

$35,000 to 

$45,000 to install 

one gas burner

Dependent on 

the price of 

natural gas.

0

PVT-2 General Automated boiler conductivity blowdown and feedwater 

monitoring instrument systems. 

$50,000 to 

$100,000

$29,000 to 

$58,000 1-2%

PVT-2 General Upgrade water clarifier to minimize the amount of 

blowdown required and reduce boiler fouling.

$100,000 to 

$200,000 $29,000 1%

PVT-3

Boiler 1

Boiler 2

Boiler 10

Upgrade water cleaning system to reduce tube fouling. <$100,000 $14,400 

0.5% overall 

improvement for 

three boiler system

PVT-5 Plant 1 Return condensate to boiler units for reuse. $48,000 $10,480 4%

PVT-1 General Preheating inlet combustion air to reduce the amount 

of heat needed for combustion process. 

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

0.5 to 2%

Water Treatment

Combustion air pre-heating

Page 2 of 6
Facility Boiler Unit Recommendation Estimated 

Capital Cost

Estimated 

Yearly Cost 

Savings

Estimated 

Efficiency 

Improvement

Table 3-2: Recommendation Summary

PUB-1 General

Preheat inlet combustion air using heat exhaust and/or 

air preheaters to reduce the amount of heat needed for 

the combustion process. 

$12,000 to 

$75,000 $146,700 2%

PUB-4 General

Increase temperature in the condensate (feed water) 

using boiler exhaust heat and/or to preheat the inlet air 

with the spent condensate. 

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

0.5 to 1%

PVT-2 Boiler 6

Boiler 8

Retrofitting two boilers with underthrow feeders and 

variable frequency drive (VFD) grate drives. $150,000 $45,400 (2 boilers) 1% per boiler

PVT-2 Boiler 7 Convert boiler control to computer based distributed 

control system to improve overall combustion process. $50,000 $114,700 2%

PVT-2 General

Improved monitoring/metering of the specific paper mill 

steam and electrical usage to refine power plant 

operation.

$30,000 

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

PVT-3 Boiler 10 Updgrade O2 controls to maintain outlet 

temperatures. 

$50,000 to 

$100,000

$33,300 to 

$83,200 1% to 2.5%

PVT-4

Boiler 3

Boiler 4

Boiler 9

Improve burner tip workmanship to improve 

combustion of fuel oil. 

$5,000 to 

$10,000 per year

$36,200 to 

$72,500

1% to 2% overall 

improvement for 

three boiler system

PVT-5 General Setting combustion on all boilers $5,780 $3,145 1%

PUB-2 General

Conduct a “NOx vs. % overfire air” study to assess 

potential NOx reductions. 

$20,000 for 

study

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

PUB-3 General

 Conduct a “NOx vs. % overfire air” study to assess 

potential NOx reductions. 

$20,000 for 

study

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

PUB-1 General Install CO/VOC catalyst unit to reduce toxics. $150,000 NA 0

PUB-3

Boiler 1

Boiler 2

Boiler 3

Replace old baghouses for three boiler units. This 

would reduce the metals portion of the toxic pollutants 

by, conservatively, 98%. 

$250,000 per 

boiler NA 0

Controls

Flue gas treatment

Page 3 of 6
Facility Boiler Unit Recommendation Estimated 

Capital Cost

Estimated 

Yearly Cost 

Savings

Estimated 

Efficiency 

Improvement

Table 3-2: Recommendation Summary

PVT-2 Boiler 6 Install new forced draft fan and improve overfire air 

flow measurement. <$100,000 $49,000 2%

PVT-2

Boiler 6

Boiler 7

Boiler 8

Chemically clean three boilers to remove scale and 

improve heat exchange. $30,000 

$170,600 for 

three boiler 

system

5%

PVT-2 General Conduct regular maintenance of 300 to 400 steam 

traps. 

$50,000 to 

$60,000 per year $1,200,000 10% to 20% (1)

PVT-5 General Conduct steam pressure profiling on 2 boilers $11,900 

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

PVT-5 General Insulate steam and condensate lines. $42,300 $21,100 8%

PVT-5 Plant 1 Conduct flash steam loss study to reduce utilizable 

steam lost to the atmosphere $2,900 

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

PVT-5 Plant 2 Reduce utilizable flash steam currently vented to the 

atmosphere $13,000 $29,400 11%

PVT-5 Plant 1 Reduce operational steam pressure $3,000 $5,200 2%

PVT-3 Boiler 10

Relatively high outlet temperature (489oF to the 

precipitator) indicate that some excess heat still 

available. No immediate potential process uses were 

apparent. 

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

PUB-1

Boiler 1

Boiler 2

Boiler 3

Relatively high outlet temperatures for three boilers 

(530oF) indicate some excess heat is available. No 

immediate process uses for the excess heat were 

identified; however, a study should be completed to 

assess potential. 

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

Steam systems

Heat Recovery

Associated equipment

Page 4 of 6
Facility Boiler Unit Recommendation Estimated 

Capital Cost

Estimated 

Yearly Cost 

Savings

Estimated 

Efficiency 

Improvement

Table 3-2: Recommendation Summary

PUB-2

Boiler 1

Boiler 2

Boiler 3

Relatively high outlet temperatures for three boilers 

(450oF) indicate some excess heat is available. No 

immediate process uses for the excess heat were 

identified; however, a study should be completed to 

assess potential since ductwork combines the exit 

gases into one plant stack.

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

PUB-3

Boiler 1

Boiler 2

Boiler 3

The boilers are all designed to produce 425 psi steam. 

In reality they generate steam at only 175 psi. No 

immediate uses were identified. Consideration should 

be given to purchasing a larger steam turbine that can 

accept the higher pressure steam and, in turn, 

generate (20% to 30%) more megawatts using the 

same amount of fuel.

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

PVT-1 General

Install activated carbon filters to collect vapors from the 

paper rolling/process rooms. Organic vapors are 

generated from the steam injection process.

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

PVT-2 General

Redesign the turbines for efficiency improvements. 

Turbines with less extracting ability and more 

condensing ability would result in more efficient units, 

but not without significant cost. 

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

PVT-2 General

Consider installing a new boiler and removing two old 

boilers from service. This would prolong the life of the 

existing baghouse and eliminate the need for costly 

installation of additional additional modules while 

upgrade to new, higher efficiency boiler units.

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

Further 

assessment by 

vendor needed.

PVT-5 General

Connect boilers in Plants 1 and 2. Two boilers would 

be sufficient to meet the steam needs of the facility. 

Connecting the systems would remove redundency 

and excess energy use.

$64,700 $23,600 9%

Facility specific Recommendations

Page 5 of 6
Facility Boiler Unit Recommendation Estimated 

Capital Cost

Estimated 

Yearly Cost 

Savings

Estimated 

Efficiency 

Improvement

Table 3-2: Recommendation Summary

(1) SIP Energy Efficiency Renewables Catalog 9Draft), Jaunary 5, 1999, Table C-1.

Page 6 of 6
SECTION 4- Implementation 

4.1 Overview 

Several months after the site visits, the Delta Institute requested each participating facility 

to complete a short survey. The purpose of the survey was threefold. First, each facility 

was asked to assess progress toward implementation of energy efficiency opportunities. 

Second, each facility was asked to identify incentives and barriers affecting 

implementation of the recommendations. Third, feedback regarding incentives that 

would lead to energy efficiency changes was requested. A sample survey is included in 

Appendix B. The following presents a summary of the survey feedback from each the 

participating facilities. The small manufacturing facility had not completed a survey at 

the time of this report. The section headers correspond with each section of the survey. 

Assessment 

Each facility reported that previous boiler efficiency studies had been completed at the 

plant. Generally, the facilities considered the assessment to be helpful although a greater 

level of detail could have been provided with the recommendations. All of the 

responding facilities, however, felt that on-site screening of certain operational 

parameters such as O2 or CO would have been helpful. Providing the additional 

screening data as part of the assessment report may have enabled some of the facilities to 

justify expenditures for additional studies or analysis to follow-up the recommendations. 

For instance, PVT-3 noted during the site visit that there was some uncertainty with the 

reliability of existing O2 control measurements- an operational parameter needed to 

control the air-heat ratios and maximize fuel combustion. Routine screening as part of 

the assessment could have been used to confirm the internal controls. One facility noted 

that a permit and regulatory review would have been helpful. 

Assessment Recommendations and Implementation 

At each facility, the operators and power plant supervisors were very familiar with the 

operational issues of each boiler unit. Therefore, energy efficiency opportunities 

presented to the facilities were, for the most part, already known. In general, the 

recommendations provided to each facility can be categorized into three areas: 

1. New findings 

2. Known issues being considered for implementation 

3. Known issues not being considered for implementation. 

Two recommendations provided by the Delta Institute’s consultant had not been 

considered by the facilities prior to the assessment. PVT-1 noted that the facility-specific 

recommendation to install activated carbon filters to collect and filter vapors emitted 

from the steam injections process into the paper rolling/process units had not been 

considered by the facility even though odors were detected in the facility. This 

recommendation would not improve boiler efficiency but the carbon filters would likely 

reduce emissions of certain toxics as well as improving the workplace environment; 

however, it is unlikely that PVT-1 will implement this recommendation. PUB-1 

acknowledged that they were not aware if the high exhaust exit temperatures on the three 
existing boilers. High exhaust temperatures indicate the presence of waste heat that could 

be recirculated or reused; however, additional research is needed to assess the energy 

potential and identify possible uses. The facility plans to investigate the exhaust gas 

temperatures from the boiler units and assess the potential for waste heat recovery. 

Five recommendations by the Delta Institute’s consultant were already being considered 

for implementation based on previous assessments and/or internal reviews. Three 

recommendations presented to PVT-1 were already under consideration at the time of the 

Delta Institute’s audit including: 1) preheating inlet combustion air; 2) fuel drying; and, 

3) installing a protective rain cover for bark fuel storage area. To date, PVT-1 has not 

implemented these recommendations since the capital costs for each are relatively high 

($50,000 to $100,000) with efficiency savings of approximately 2%. PVT-3 noted that 

they were already addressing excess air to the Boiler Unit 10 through an extensive boiler 

overfire control testing program underway as part of a regulatory process. Once PVT-3 

corrects this problem, efficiency savings of up to 2.5% could be realized. Lastly, PUB-2 

noted that they were considering replacement of the coal stokers prior to the Delta 

Institute’s assessment in order to improve opacity and remain within permitted limits. 

Potential energy efficiency improvements for this recommendation were only 0.25% 

while capital costs are relatively high (greater than $100,000 per boiler). 

The remainder of the recommendations were known to the power plant operators 

interviewed at each facility but were not being considered for implementation due to high 

capital costs, long payback periods, and/or other operational considerations. Two 

opportunities- steam trap maintenance and chemical cleaning- presented to PVT-2 had 

high efficiency savings and short payback periods yet were not being considered by plant 

personnel as viable energy efficiency projects even though energy and cost savings 

potentials were known to the plant operators. According to plant personnel, internal 

budget constraints prevented even those recommendations with low capital costs, short 

payback periods, and high efficiency savings from being implemented. However, plant 

representatives felt that a report from a third-party audit may be helpful to obtain buy-in 

of upper management for implementation of some efficiency measures. 

Factors leading to efficiency improvements 

Each facility provided feedback about factors that contribute in making efficiency 

improvement decisions. According to the facilities surveyed and as shown on Table 4-1, 

the dominant factors that lead to implementing energy efficiency improvements are 

payback periods of less than two years and regulatory relief- particularly from New 

Source Review requirements. 

Table 4-1: Factors Leading to Energy Efficiency Improvements 

 PVT-1 PVT-2 PVT-3 PVT-4 PUB 1 to 3 

Payback period less than two years 

Better economy 

Management support Increasing priority of energy efficiency 

alternatives in management plan 



Proven technology 

Streamlined permitting 

New source review relief 

Relief from certain regulatory 

requirements 



Access to low interest loans 

Other Emission 

credits 

Note: PVT-5 did not complete a survey at the time of this report. 

4.2 Discussion 

Feedback from the participating facilities identified specific technical assistance and 

outreach strategies that should be considered to increase the likelihood that industrial 

boiler owners would implement energy efficiency measures. First, capital expenditures 

for power plant upgrades are often limited because power plants are traditional cost 

centers in a manufacturing operation. Rather than focus on traditional payback periods, 

one consultant advised analyzing the costs of maintaining an old boiler, such down time, 

maintenance repairs and labor, chemical treatment (water) and energy usage, versus 

capital and operational costs associated with a newer, more efficient boiler. Also, 

providing technical implementation assistance and other incentives are necessary to help 

implement certain recommendations. Second, limited operational parameter testing and 

data collection, such as hand-held oxygen analyzers, is warranted to justify further 

consideration of recommendations. Lastly, assistance providers need to avoid “free audit 

syndrome.” Boiler operators are knowledgeable about their units and, more often than 

not, use free assessments to justify their own ideas or recommendations from prior 

assessments. Many facilities will say yes to a free assessment, even if they have had 

independent consultants or government agencies already perform similar audits. 
SECTION 5: BTS Compound Emission Aggregation Analysis 

5.1 Overview 

The objective of the emissions aggregation analysis was to evaluate the potential for 

Great Lakes region-wide reductions of five BTS compounds that would result from 

extensive implementation of energy efficiency improvements. The Delta Institute 

completed an analysis that evaluated the potential emissions from industrial boilers in 

eight Great Lakes states. The industrial boiler source data used for this analysis was 

obtained from the U.S. EPA Emissions Test Database, Population Database, and 

Materials Analysis Database, dated December 14, 1999, developed by the U.S. EPA for 

the Industrial/Commercial/Institutional Boiler National Emissions Standards for 

Hazardous Air Pollutants (NESHAP). The NESHAP database was based on state input. 

As part of the Industrial/Commercial/Institutional Boiler MACT rulemaking, the U.S. 

EPA developed a range of emission factors for 31 chemical compounds emitted from 

industrial and commercial boilers based on boiler type, fuel source, and control 

technology.6

 The U.S. EPA provided the NESHAP database and emission factors to the 

Delta Institute. This section presents the results of the emissions aggregation as well as 

an analysis of those results. 

The emissions factors used in the analysis were developed and provided to the Delta 

Institute by the U.S. EPA. The U.S. EPA developed these emissions factors for the 

Industrial/Commercial/Institutional MACT rulemaking. Only Level I and II BTS 

compounds and certain criteria pollutants with calculated emissions factors were included 

in the aggregation analysis. 

The Delta Institute chose to utilize the U.S. EPA NESHAP database and emissions 

factors, as opposed to the U.S. EPA National Toxics Inventory (NTI) or the Great Lakes 

Inventory, based on the age of the data- the most current data available from NTI at the 

time of this report was 1996. The NTI database was used as a comparative measure of 

the aggregated industrial boiler emissions when more recent data was unavailable. 

5.2 Aggregation Analysis 

Boilers were segregated by state, fuel type, and fuel input rate in order to complete the 

aggregation analysis. Figure 5-1 shows the breakdown of industrial boiler units by state. 

 

6

 Emission factors developed by the Industrial/Commercial/Institutional MACT program for the following 

compounds: 1,4-dichlorobenzene, 16-PAHs, acetaldehyde, acrolein, arsenic, benzene, beryllium, cadmium, 

chlorine, chromium, dibenzofuran, dibutylphthalate, dioxin, ethylbenzene, formaldehyde, hydrochloric 

acid, hydrofluoric acid, lead, manganese, mercury, methyl chloroform, methyl ethyl ketone, methylene 

chloride, nickel, o-xylene, phosphorus, toluene, xylenes, particulate matter, carbon monoxide, and sulfur 

dioxide. 
Figure 5-1: Great Lakes States Industrial Boiler Summary

Total Number of Industrial Boilers: 24,522

Illinois

24%

Indiana

6%

Michigan

31%

Pennsylvania

13%

Wisconsin

14%

Minnesota

5%

Ohio

3%

New York

4%

The following table further segregates the number of boilers in each state by fuel type 

and size in order to analyze the emissions from each fuel source. 

Table 5-1: Percent Total Number of Great Lakes States Industrial Boilers 

per Primary Fuel Source

State 

Total 

Boilers 

Coal 

(% Total) 

Residual 

Fossil Fuel 

(% Total) 

Distillate 

Fossil Fuel 

(% Total) 

Natural 

Gas 

(% Total) 

Other 

(% 

Total) 

Illinois 5,769 3 5 7 84 ~1 

Indiana 1,561 11 6 13 68 2 

Michigan 7,570 5 2 5 88 <1 

Minnesota 1,348 5 6 16 70 3 

New York 900 4 27 22 39 8 

Ohio 802 36 8 16 37 3 

Pennsylvania 3,150 10 13 18 56 3 

Wisconsin 3,422 3 4 13 78 2 

Based on Figure 5-1 and Table 5-1, the predominate fuel type used in industrial boilers in 

the Great Lakes region is natural gas which is also the fuel considered to have the lowest 

emissions of toxic compounds. Natural gas, however, is primarily used in the smaller 

size boiler units (less than 10 MM Btu fuel input per hour) because of the higher cost of 

natural gas as compared to coal and oil. Ohio is an anomaly with an equal or greater 

percentage of coal boilers as compared to other fuels. 

The average air emissions of five Level I and II BTS compounds were calculated 

utilizing the U.S. EPA emissions factors developed for the 

Industrial/Commercial/Institution Boiler MACT. The average emissions, by fuel type, 

were then developed for each size category of boiler. Average emissions were used to 

compensate for the emissions profile differences between boiler types and control 
technologies. Attachment C presents the total air toxic emissions on a state by state and 

fuel type basis. 

Table 5-2 summarizes the detailed emissions breakdowns in Attachment C. This analysis 

shows that the majority of emissions to the eight Great Lakes states are from industrial 

boilers using coal fuel, other fuel (wood, tires, other solid materials), and residual fossil 

fuel. 

Table 5-2: Summary of Aggregated Air Emissions of Specific BTS 

Compounds from Industrial Boilers in the Great Lakes Region

Compound 

Total 

Emissions 

(Lbs/Year) 

Coal 

(% Total) 

Residual Fossil 

Fuel 

(% Total) 

Distillate Fossil 

Fuel (1) 

(% Total) 

Natural 

Gas 

(% Total) 

Other 

(% Total) 

Hg 9,050 49 43 <1 NA 8 

Dioxin 3 57 3 3 5 30 

Cd 11,400 72 3 <1 15 9 

1,4- 

Dichlorobenzene 1,220 83 NA NA NA 17 

16-PAHs 360,970 3 3 7 84 4 

(1) Emission factors develop for mercury in residual fossil fuel are considered conservation since the 

emission factors developed for the Industrial/Commercial/Institutional MACT were based on 

utility boiler emissions (Eddinger 2002b). 

Comparing the results from Table 5-1 and Table 5-2 shows that approximately 1,500 coal 

boilers and approximately 1,400 residual fuel boilers are the primary sources of certain 

toxic air compounds from industrial boilers in the Great Lakes region. As shown on 

Figures 5-2 and 5-3, 12% (6% coal fired and 6% residual fossil fuel fired) of the boilers 

are responsible for the majority of toxic air emissions of certain BTS compounds from 

industrial boilers in the eight state region. 

Figure 5-2: Great Lakes States Industrial Boiler Primary 

Fuel Summary

Total Number of Industrial Boilers: 24,522

Coal

6%

Natural Gas

76%

Other

2%

Distillate Fossil Fuel

10%

Residual Fossil Fuel

6%
Hg

Dioxin

Cd

1,4- Dichlorobenzene

16-PAHs

Coal

Residual Fossil Fuel

Distillate Fossil Fuel

Natural Gas

Other

0

10

20

30

40

50

60

70

80

90

Percent

Figure 5-3: Specific Binational Toxic Compound Emissions 

versus Primary Fuel Type

5.3 Significance of Industrial Boiler Emissions 

Industrial boilers are used in many industrial sectors; therefore, obtaining accurate 

emissions estimates is challenging. For instance, some facilities aggregate boiler 

emissions with the total plant emissions making it difficult to ascertain the contribution to 

total emissions from the boiler units. In order to put the emissions profile developed 

from this aggregation effort into perspective, a comparison between emissions of select 

compounds from boilers with total nationwide emissions from all sources has been 

completed. Tables 5-3 and 5-4 compare the industrial boiler emissions of Level I and II 

BTS compounds aggregated for this project with publicly available emissions databases. 

Table 5-3: Comparison of Total Great Lakes States. Industrial Boiler 

Emissions with Total U.S. Emissions from All Sources 

Compound 

Binational 

Toxics 

Strategy 

Level 

Aggregated 

Emissions for 

Eight Great 

Lakes States 

(tons/year) 

1996 U.S. 

Emissions from 

All Sources 

 EPA National 

Toxics Inventory 

(tons/year) 

U.S. Emissions 

from All 

Sources 

Other Data 

Source 

(tons/year) 

Percent of 

National 

Total 

Mercury Level I 4.5 125 (1) 3.6 

Dioxin Level I 3.0 lbs/year 2.2 to 90 

lbs/year (2) 

0 to 3.3 

Cadmium Level II 5.7 157 3.6 

1,4-Dichlorobenzene Level II 0.6 10,984 <1 

16-PAHs Level II 180 20,873 <1 

(1) Cain 2002. 

(2) U.S. EPA 2000. 
Industrial boiler emissions for the Great Lakes region comprise up to 3% of the estimated 

national emissions for mercury, dioxin, and cadmium. Nationwide, emissions of the 

aforementioned five compounds from industrial boilers are estimated as follows: 

Table 5-4: Comparison of Total U.S. Industrial Boiler Emissions with Total 

U.S. Emissions from All Sources 

Compound 

U.S. Emissions from 

All Sources 

(tons/year) 

U.S. Aggregated 

Industrial Boiler 

Emissions 

(tons/year) 

Percent Total of U.S. 

Emissions from All 

Sources 

Mercury 125 (1) 14 10 

Dioxin 2.2 to 90 lbs/year (2) 10.7 lbs/year 0 to 12 

Cadmium 157 (3) 19.8 13 

1,4-Dichlorobenzene 10,984 (3) 3.6 <1 

16-PAHs 20,873 (3) 375 2 

(1) Cain 2002. 

(2) U.S. EPA 2000. 

(3) U.S. EPA 2002. 

 

5.4 Efficiency Improvement Potential 

The estimated emissions reductions for five BTS compounds shown in Table 5-5 are 

based on reduced fuel usage associated with implementing energy efficiency 

recommendations. Since energy improvements result in less fuel usage, it is not 

surprising that the most significant emissions reductions would result from improvements 

to coal, residual, and other fuel (e.g. wood, tires, other solid materials) boilers. 

Table 5-5: Estimated Emissions Reductions from Great Lake States 

Industrial Boilers Resulting from a 10% Energy Efficiency Improvement (1) 

Compound 

Coal 

(lbs/yr) 

Residual 

Fuel Oil 

(lbs/yr) 

Distillate 

Fuel Oil 

(lbs/yr) 

Natural 

Gas 

(lbs/yr) 

Other 

Fuel 

(lbs/yr) 

Total 

(lbs/yr) 

No. Boilers 1,531 1,436 2,564 18,591 387 24,509 

Mercury 443 389 <0.01 NA 73 905 

Dioxin 0.17 ~0.01 ~0.01 ~0.02 ~0.09 0.3 

Cadmium 826 32 6 175 101 1,140 

1,4 Dichlorobenzene 101 NA NA NA 21 122 

16-PAHs 1,043 927 2,353 30,453 1,293 36,069 

(1) The potential emissions reductions, according to fuel type, from implementing energy efficiency 

improvements are shown in Attachment C. Each table in Attachment C presents the aggregated potential 

reductions associated with a 1%, 2%, 5%, or 10% fuel savings possible from energy efficiency 

improvements. 

For example, 905 pounds of mercury emissions could be avoided if industrial boiler units 

implemented some form of energy saving measures and reduced fuel use by 10%. This 

represents approximately 1% of mercury from all emissions sources in the Great Lakes 

region and 0.4% of mercury of all U.S. emissions sources (U.S. EPA 1998d; Cain 2002). 

On a national level, industrial boilers emit approximately 14 tons, or 28,000 pounds, of 

mercury per year (Eddinger 2002a) representing approximately 10% of the total 

estimated U.S. mercury emissions from all sources. Achieving a 10% energy efficiency 
reduction for all boilers represents 1% of total U.S. mercury emissions. Table 5-6 

presents a similar analysis for the five BTS compounds analyzed above. 

Table 5-6: Comparison of Estimated Emissions Reductions from Great 

Lakes States Industrial Boilers Compared to Total U.S. Emissions from All 

Sources

Compound 

U.S. Emissions 

from All 

Sources 

(tons/yr) 

Estimated U.S. 

Industrial Boiler 

Emissions Reductions 

from a 10% Efficiency 

Improvement (tons/yr) 

% Total of Estimated 

10% Reduction 

Compared to U.S. 

Emissions from All 

Sources 

Mercury 125 (1) 1.1 ~1% 

Dioxin 2.2 to 90 

lbs/year (2) 

1.07 lbs/year 0 to 1% 

Cadmium 157 (3) 2 1% 

1,4-Dichlorobenzene 10,984 (3) ~0.4 <<1% 

16-PAHs 20,873 (3) 37 <1% 

(1) Cain 2002. 

(2) U.S. EPA 2000. 

(3) U.S. EPA 2002. 

Furthermore, a 10% energy efficiency with coal and residual fuel boilers would result in 

important reductions of criteria pollutants. 

Table 5-7: Estimated Criteria Pollutant Emissions Reductions from Great 

Lake States Industrial Boilers Resulting from a 10% Energy Efficiency 

Improvement 

Compound 

Coal 

(tons/yr) 

Residual 

Fuel Oil 

(tons/yr) 

Distillate 

Fuel Oil 

(tons/yr) 

Natural 

Gas 

(tons/yr) 

Other 

Fuel 

(tons/yr) 

Total 

(tons/yr) 

No. Boilers 1,531 1,436 2,564 18,591 387 24,509 

Particulate Matter 189,334 24,143 1,795 1,623 64,298 281,193 

Carbon Monoxide 11,532 1,663 6,698 6,669,094 98,961 6,787,948 

Sulfur Dioxide 1,093,946 (1) (1) (1) 194,065 1,288,011 

Carbon Dioxide 1,104 635 898 2,988 (1) 5,625 

Nitrogen Oxide (2) (2) (2) (2) (2) (2) 

(1) Emissions factors were not readily available. 

(2) CO2 and NOx reductions will occur; however emission factors were not developed as part of 

the Industrial Boiler MACT program. Where provided, emissions for CO2 are based on 

emissions factors provided in the U.S. EPA Climate Wise: Wise Rules for Industrial 

Efficiency (U.S. EPA 1998c) 

5.5 Summary 

Industrial boilers represent a significant source of air toxics to the Great Lakes region and 

the U.S. Comparison of industrial boiler emissions with national emissions estimates for 

all sources show that emissions from boilers comprise a significant portion of the national 

inventory- 10% or greater- for certain toxic compounds. Energy efficiency 

improvements that result in reduced fuel use are one way to achieve nationally significant 

emissions from industrial boilers. For example, achieving a 10% fuel use improvement 
for all industrial boilers represents 1% of the total mercury emitted in the U.S. The same 

10% reduction achieved by industrial boilers using coal as the primary fuel, representing 

5.7% of the total U.S. industrial boilers, would result in a reduction of 1,320 pounds of 

mercury or 0.5% of total emissions from all U.S. sources of mercury. Similarly, a 10% 

efficiency reduction in the Great Lakes region would result in approximately 1% 

reductions of total cadmium emitted in the U.S. 

Comparatively, the Industrial/Commercial/Institution Boiler MACT rules are expected to 

achieve reductions of certain BTS compounds- mercury and cadmium- through emissions 

limits (Eddinger 2002b). Reductions of other toxic compounds, such as organic 

hazardous air pollutions, are likely but have not been calculated by the U.S. EPA. While 

the total reductions of these compounds from MACT implementation are greater than for 

energy efficiency measures, the benefits from implementing energy efficiency measuressuch as reduced fuel usage and cost savings- will not necessarily be realized through 

MACT implementation. 
SECTION 6- Conclusions and Recommendations 

6.1 Conclusions 

This section summarizes the results of the Delta Institute’s outreach to industrial boiler 

owners and emissions aggregation analysis. 

Overall, based on our work at nine Wisconsin facilities, with a total of 34 industrial 

boilers, we found that optimizing energy needs (e.g., reducing the amount of fuel input) 

can result in reductions of toxics, in addition to lowering greenhouse gas emissions 

because of reduced fuel use. Our aggregation analysis showed that industrial boilers are 

a substantial source of toxic compounds. Even though emissions of toxic compounds 

from industrial boilers are significant, they are not well inventoried since industrial boiler 

emissions are often grouped together with the total facility emissions. 

The aggregation analysis showed that over 20,000 industrial boilers are located at 

facilities in Great Lakes. Twelve percent, or 2,900, of industrial boilers that use coal and 

residual fuel oil as the primary fuel, emit the majority of toxic emissions. For example, 

almost all of the 4.5 tons per year of mercury emitted by industrial boilers are from coal 

and residual fuel fired units. Our analysis of industrial boiler emissions shows that a 

conservative 10% efficiency improvement by coal and residual fuel fired boilers alone 

would result in reduced mercury emissions of over 900 pounds to the Great Lakes Basin. 

Furthermore, a 10% energy efficiency with coal and residual fuel boilers would result in 

important reductions of criteria pollutants. 

6.2 Recommendations 

Because of the significance of industrial boilers as a source of air toxics and the potential 

for reductions through energy efficiency measures, we recommend that resources be 

dedicated to designing a large-scale pollution prevention outreach initiative that links 

toxic reduction and energy efficiency. By doing so, the “natural” cost savings incentive 

of energy efficiency can be used to achieve quantifiable reductions of toxics as well as 

criteria pollutants such as carbon monoxide, sulfur dioxide, nitrogen oxides, particulate 

matter, and carbon dioxide. 

Such an effort would focus on coal and residual oil fired boilers in energy intensive 

industries in order to take advantage of the reduction potential from this “sector.” 

Focusing on coal and residual-fired units would reduce the target pool of industrial 

boilers from over 20,000 to 2,900 located in approximately 1,100 facilities in the Great 

Lakes region. The greatest potential to achieve significant reductions through energy 

efficiency lies with the following sectors: 

• Federal facilities • Petroleum refining 

• Health service facilities • Paper 

• Institutions (e.g. schools and universities) • Chemicals 

• Primary metals • Transportation equipment 
Given the relatively large number of facilities and ubiquitous nature of industrial boilers. 

In order to achieve meaningful reductions from this “sector” new approaches to outreach 

and implementation incentives need to be considered. This would require appropriately 

linking public and private technical assistance and financing tools in such a way so to 

encourage adoption of energy efficiency measures. For example, closer alliances 

between local pollution prevention and energy technical assistance resources and state 

and federal agencies, as well as industry representatives and trade associations need to be 

established. Simultaneously, access to capital and other financial incentives, a necessary 

component of any energy efficiency or pollution prevention program, need to be more 

fully developed to promote diffusion of energy efficiency opportunities. 

Current regulations will only go so far to attain the necessary reduction in air emissions. 

Even if all of the needed reductions from regulations could be achieved, the 

implementation timeframe would be too long. With respect to greenhouse gases, states 

are only just beginning to formulate policies and programs that reduce greenhouse gases. 

Pollution reduction opportunities that go beyond existing programs need to be sought out 

and implemented if permanent, ecosystem improvements in the Great Lakes region are 

ever to be realized. 
REFERENCES 

Cain. Alexis. 2002. Personal communication. March 27. 

CIBO. 1997. Energy Efficiency Handbook. November. 

CIBO. 2002. Industrial Boiler Guide. Council of Industrial Boiler Owners. Draft. 

DOE. 1998. Manufacturing Energy Consumption Survey. 

http://www.eia.doe.gov/emeu/mecs/mecs98/datatables/contents.html

DOE. 2001. Electric Power Annual 2000. Energy Information Administration Office of 

Coal, Nuclear, Electricity and Alternative Fuels. August. 

Eddinger. James. 2002a. Personal communication. April. 

Eddinger. James. 2002b. Personal communication. June. 

U.S. EPA. 1998a. Study of Hazardous Air Pollutant Emissions from Electric Utility 

Steam Generating Units- Final Report to Congress. Volume 1. Office of Air Quality and 

Planning Standards. February. 

U.S. EPA. 1998b. Distribution of boilers by SIC Table. Office of Air Quality Planning 

and Standards. http://www.epa.gov/ttn/atw/combust/iccrarch/bo.html. April. 

U.S. EPA. 1998c. Climate Wise- Wise Rules for Industrial Efficiency. Office of Policy, 

Planning, and Evaluation. EPA 231-R-98-014. July. 

U.S. EPA 1998d. Regional Air Pollutant Inventory Development System (RAPIDS) 

Database. www.epa.gov/ARD-R5/glakes/einven.htm; 

www.glc.org/air/rapids/rapids.html. 1998. 

U.S. EPA. 1999. SIP Energy Efficiency and Renewables Catalog. ICF Resources. Draft 

January 5, 1999. 

U.S. EPA. 2000. Binational Toxics Strategy Dioxin and Furan Sources and Regulations

Great Lakes National Program Office. Draft Report. May 26, 2000. 

U.S. EPA, 2002. 1996 National Toxics Inventory Website. www.epa.gov/nti. March. 
Attachment A 

Facility Agreement Letter 
Letter of Agreement 

Between the Delta Institute 

And 

Facility 

Background

In July of 1999, the Delta Institute launched a partnership with the Council of Industrial 

Boiler Owners to achieve emission reductions of Bi-National Strategy (BNS) Level I and 

Level II pollutants from industrial and public sector boilers through the implementation of 

selected energy efficiency technologies and methods. All BNS pollutants are also 

considered to be persistent bioaccumulative toxics (PBTs). Non-utility boilers and other 

energy generating devices constitute a significant percentage of the emission inventories 

for several BNS pollutants. Boilers, internal combustion engines and gas-fired turbines 

producing thermal and/or electric energy are the second largest source of mercury (EPA, 

1997), second largest source of cadmium, fifth largest source of PCBs, and seventh 

largest source of dioxins and furans (NTI). These facilities are also significant sources of 

PAHs. They are important to the Great Lakes industrial economy and are expected to 

play a greater role in meeting the demands of a deregulated energy marketplace. 

Although the quantity of emissions of air toxics from electric utility boilers is greater, the 

local contribution of toxics deposited to the Great Lakes may be disproportionately 

higher from smaller facilities. These facilities are also significant sources of ozone 

precursors, acid aerosols, particulate matter and fine particulate precursors, as well as 

greenhouse gases. 

The project is being implemented in two phases. Phase I focused on assessing options 

for achieving reductions, barriers to achieving widespread reductions and developing 

strategies for overcoming any identified barriers. In summary, Phase I resulted in 

agreement on which efficiency measures were most practical, estimations of likely 

emission reductions and identification of several barriers to widespread implementation 

of emission reduction strategies. 

Phase II began in November 2000 and will continue through October 2001. Based upon 

the findings of Phase I, the Delta Institute has agreed to offer free combustion/steam 

system audits to interested public sector and industrial facilities. Participants will review 

– and as appropriate – implement recommended energy efficiency methods and 

technologies. Further, the Delta Institute and participants will develop a method for 

reporting the results of the implemented energy efficiency strategies, including actual 

and potential PBT emission reductions. 

Services Offered by the Delta Institute

The Delta Institute (Delta) will retain an independent combustion/steam system 

consultant, Ted Guth, PhD, to inspect participating facilities. The consultant will 

interview facility staff, conduct a on-site inspection, and issue both a draft and 

final report recommending options for improving combustion and steam system 

operations. 

4. Delta will pay all professional fees and travel expenses incurred by the 

consultant. 

5. Delta will provide all participating facilities with a draft final report. Delta will 

accept editorial suggestions before issuing a final project report. 
6. Delta will treat all as confidential facility information that the participant wants 

treated as confidential. Facility specific findings of the project will be aggregated 

within final project reports. 

Responsibilities of the Participating Facilities

By accepting these services, the participating facility agrees to: 

1. Agree to work with undersigned consultant. 

2. Provide consultant with access to key facility staff and technical data prior to an 

on-site inspection. This could include interviews and review of reports from 

combustion system analyses, stack testing and/or energy audits. Any technical 

information will be treated by the consultant as confidential. 

3. Assist the consultant with the on-site inspection. This will include allowing 

reasonable access to areas of the facility for both the consultant and Delta staff 

over an agreed upon period. 

4. Review and comment on consultant’s draft facility report. The participating 

facility is expected to provide feedback on the draft report within three weeks of 

receiving the draft report. 

5. Accept and review final facility report. Although under no obligation to implement 

any of the recommendations in the final facility report, the participating facility 

agrees to discuss with the Delta Institute staff any changes in facility operations 

and reductions in emissions resulting from acting upon the report. 

6. Review and comment upon the draft project report. The Delta Institute will 

provide each participating facility with a draft project report that summarizes the 

generic findings of the project based on the results of audits of all participating 

facilities. The Delta Institute will incorporate comments received prior to 

releasing a final project report. 

7. Within six months to a year after receiving the final report, will report on which 

recommendations the facility implemented and the results as well as on what 

was not implemented and why. 

Signed: 

__________________________________ 

Facility Manager 

Participating Facility 

__________________________________ 

Delta Institute 
Attachment B 

Sample Facility Survey
Attachment B- Sample Facility Survey

Facility Information

We have the following industrial boiler information for your facility. Please update and 

or note any corrections to this information. 

Boiler 

Unit 

Installation 

Date 

Boiler 

Type 

Manufacturer Fuel Input Fuel Start-up 

Fuel 

 

 

 

 

Boiler 

Unit 

Installation 

Date 

Boiler 

Type 

Manufacturer Fuel Input Fuel Start-up 

Fuel 

 

 

Assessment

Was this the first boiler energy efficiency assessment performed at your facility? Yes/No 

If no, were recommendations from other, recent assessments implemented? 

If no, how did this assessment compare to previous assessments? Please explain. 

Would the assessment have been more valuable to you if the assessment included: 

__ emission or operational parameter testing 

__ permit/regulatory review 

__ more involvement by plant personnel 
__ less involvement by plant personnel 

__ other________________________________________________________________ 

Assessment Recommendations

Please refer to the recommendation numbers on the attached report. 

Did the consultant identify any issues that you were not aware of? Yes/No 

If yes, please indicate the recommendation number from the attached report. 

Was the level of detail provided for each recommendation sufficient? Yes/No 

If no, please explain. 

What additional information would have made the recommendation more useful? 
Implementation

Was the information provided in the assessment report satisfactory (i.e. could the 

information be used to justify additional follow-up activities and expenses)? Yes/No 

If no, please explain. 

Is your facility considering follow-up activities associated with any of the 

recommendations presented in the assessment report? Yes/No 

If yes, please indicate which recommendation, anticipated follow-up actions, timeframe, 

and why. 

If no, please explain why. 

Was your facility considering actions associated with any of the issues identified as a 

recommendation prior to the Delta Institute assessment? Yes/No 

If yes, please indicate which recommendation, anticipated action, and status 

What factors would lead your facility to make efficiency improvements? 
__ payback period less than 2 years 

__ better economy 

__ management support 

__ increasing priority of energy efficiency alternatives in management plan 

__ proven technology 

__ streamlined permitting 

__ no New Source Review (NSR) 

__ relief from certain regulatory requirements 

__ access to low interest loans 

__ other___________________________________________________ 

Please use the space below to provide any additional comments on the project. 
Attachment C 

Detailed Emissions Aggregation Tables 
Table C-1: Total Emissions & Potential Emissions Reductions from Energy Efficiency Improvements to All Fuel Types

State

Estimated 

Number of 

Boilers

Cd Dioxin Hg

1,4-

Dichloro 

benzene

16-PAHs As Benzene Cr HCl 

Total Air Emissions (lbs/year)

IL 5,769 1,955 0.3 1,373 162 60,042 10,262 110,369 13,302 4,253,05

IN 1,561 720 0.2 570 77 16,088 4,234 88,804 6,746 1,791,80

MI 7,570 3,021 0.7 1,690 297 154,103 15,618 122,382 19,783 6,426,36

MN 1,348 906 0.3 758 88 20,168 5,372 140,171 8,607 2,330,10

NY 900 230 0.1 423 18 8,519 1,259 83,606 3,428 810,026 

OH 802 956 0.2 647 85 13,616 5,913 40,060 8,820 2,495,92

PA 3,150 3,010 0.8 3,202 423 59,181 19,367 119,684 25,675 9,131,44

WI 3,422 607 0.4 383 71 28,980 3,095 231,476 4,766 1,513,50

Total 24,522 11,404 3.0 9,047 1,222 360,697 65,121 936,552 91,127 28,752,22

Potential Emission Reduction for Energy Efficiency Improvements (lbs/year)

1% 114 0.03 90 12 3,607 651 9,366 911 287,522 2% 228 0.06 181 24 7,214 1,302 18,731 1,823 575,044 5% 570 0.15 452 61 18,035 3,256 46,828 4,556 1,437,61

10% 1,140 0.30 905 122 36,070 6,512 93,655 9,113 2,875,22

Notes:

1. Estimated number of boilers based on US EPA Emissions Test Database, Population Database, and Materials Analysis Data Development of the Industrial/Commercial Boiler NESHAP (12-14-99)2. Average total emissions are calculated from emission factors developed by the U.S. EPA for a range of boiler types using all 
Table C-2: Total Emissions & Potential Emissions Reductions from Energy Efficiency Improvements for Coal Fired Industrial Boi

State

Estimated 

Number of 

Boilers

Cd Dioxin Hg

1,4-

Dichloro 

benzene

16-PAHs As Benzene Cr HCl 

Total Air Emissions (lbs/year)

IL 172 1,318 0.3 667 153 1,574 9,125 1,452 10,024 3,895,82

IN 176 518 0.1 274 63 645 3,586 595 3,939 1,567,45

MI 357 1,998 0.4 1,045 239 2,463 13,833 2,272 15,195 6,045,73

MN 71 648 0.1 327 75 771 4,486 711 4,927 1,917,89

NY 34 102 0.0 47 11 112 708 103 778 297,943 

OH 293 793 0.1 355 82 842 5,491 777 6,032 2,219,56

PA 329 2,605 0.6 1,577 359 3,694 18,038 3,408 19,814 8,492,36

WI 99 276 0.1 139 32 328 1,914 303 2,103 846,456 

Total 1,531 8,258 1.7 4,430 1,014 10,429 57,182 9,621 62,811 25,283,22

Potential Emission Reduction for Energy Efficiency Improvements (lbs/year)

1% 114 0.03 90 12 3,607 651 9,366 911 287,522 2% 228 0.06 181 24 7,214 1,302 18,731 1,823 575,044 5% 570 0.15 452 61 18,035 3,256 46,828 4,556 1,437,61

10% 1,140 0.30 905 122 36,070 6,512 93,655 9,113 2,875,22

Notes:

1. Estimated number of boilers based on US EPA Emissions Test Database, Population Database, and Materials Analysis Data Development of the Industrial/Commercial Boiler NESHAP (12-14-99)2. Average total emissions are calculated from emission factors developed by the U.S. EPA for a range of boiler types using co
Table C-3: Total Emissions & Potential Emissions Reductions from Energy Efficiency Improvements to Distillate Liquid Fossil Fu

State

Estimated 

Number of 

Boilers

Cd Dioxin Hg

1,4-

Dichloro 

benzene 

(3)

16-PAHs As Benzene Cr HCl 

Total Air Emissions (lbs/year)

IL 429 7 0.01 0 0 2,653 20 792 24 3,201 

IN 204 3 0.00 0 0 1,152 8 344 10 1,447 

MI 374 13 0.02 1 0 5,011 35 1,496 43 6,444 

MN 208 5 0.01 0 0 1,824 13 545 16 2,270 

NY 198 4 0.01 0 0 1,815 12 542 15 2,409 

OH 126 5 0.01 0 0 1,673 12 499 15 2,077 

PA 571 16 0.03 1 0 6,397 44 1,910 53 8,196 

WI 454 8 0.01 1 0 3,009 21 899 26 3,781 

Total 2,564 61 0.10 4 0 23,535 166 7,028 201 29,825 

Potential Emission Reduction for Energy Efficiency Improvements (lbs/year)

1% 114 0.03 90 12 3,607 651 9,366 911 287,522 2% 228 0.06 181 24 7,214 1,302 18,731 1,823 575,044 5% 570 0.15 452 61 18,035 3,256 46,828 4,556 1,437,61

10% 1,140 0.30 905 122 36,070 6,512 93,655 9,113 2,875,22

Notes:

1. Estimated number of boilers based on US EPA Emissions Test Database, Population Database, and Materials Analysis Data Development of the Industrial/Commercial Boiler NESHAP (12-14-99)2. Average total emissions are calculated from emission factors developed by the U.S. EPA for a range of boiler types using dis3. No Emission Factor
Table C-4: Total Emissions & Potential Emissions Reductions from Energy Efficiency Improvements to Residual Liquid Fossil Fu

State

Estimated 

Number of 

Boilers

Cd Dioxin Hg

1,4-

Dichloro 

benzene 

(3)

16-PAHs As Benzene Cr HCl 

Total Air Emissions (lbs/year)

IL 290 267 0.02 626 0 1,490 234 640 1,366 4,539 

IN 84 3 0.01 248 0 601 100 258 582 1,966 

MI 133 13 0.01 565 0 1,330 203 571 1,185 3,748 

MN 82 5 0.01 342 0 801 121 344 704 2,208 

NY 246 4 0.01 262 0 628 102 270 598 1,993 

OH 64 5 0.01 230 0 541 83 232 484 1,536 

PA 396 16 0.04 1,491 0 3,595 586 1,544 3,422 11,507 

WI 141 8 0.00 121 0 282 42 121 245 802 

Total 1,436 320 0.09 3,885 0 9,268 1,469 3,981 8,586 28,299 

Potential Emission Reduction for Energy Efficiency Improvements (lbs/year)

1% 114 0.03 90 12 3,607 651 9,366 911 287,522 2% 228 0.06 181 24 7,214 1,302 18,731 1,823 575,044 5% 570 0.15 452 61 18,035 3,256 46,828 4,556 1,437,61

10% 1,140 0.30 905 122 36,070 6,512 93,655 9,113 2,875,22

Notes:

1. Estimated number of boilers based on US EPA Emissions Test Database, Population Database, and Materials Analysis Data Development of the Industrial/Commercial Boiler NESHAP (12-14-99)2. Average total emissions are calculated from emission factors developed by the U.S. EPA for a range of boiler types using re3. No Emission Factor
Table C-5: Total Emissions & Potential Emissions Reductions from Energy Efficiency Improvements to Natural Gas Fuel Fired In

State

Estimated 

Number of 

Boilers

Cd Dioxin Hg (3)

1,4-

Dichloro 

benzene 

(3)

16-PAHs As Benzene Cr HCl 

Total Air Emissions (lbs/year)

IL 4,838 280 0.03 0 0 52,998 380 634 321 4,101 

IN 1,064 72 0.01 0 0 12,530 98 150 82 982 

MI 6,677 857 0.07 0 0 143,598 1,166 1,718 985 11,456 

MN 944 77 0.01 0 0 14,900 105 178 88 1,157 

NY 351 28 0.00 0 0 4,681 38 56 32 371 

OH 297 50 0.01 0 0 9,850 69 118 58 770 

PA 1,763 264 0.02 0 0 43,678 359 522 303 3,498 

WI 2,657 122 0.01 0 0 22,296 166 267 140 1,722 

Total 18,591 1,749 0.16 0 0 304,531 2,380 3,643 2,012 24,058 

Potential Emission Reduction for Energy Efficiency Improvements (lbs/year)

1% 114 0.03 90 12 3,607 651 9,366 911 287,522 2% 228 0.06 181 24 7,214 1,302 18,731 1,823 575,044 5% 570 0.15 452 61 18,035 3,256 46,828 4,556 1,437,61

10% 1,140 0.30 905 122 36,070 6,512 93,655 9,113 2,875,22

Notes:

1. Estimated number of boilers based on US EPA Emissions Test Database, Population Database, and Materials Analysis Data Development of the Industrial/Commercial Boiler NESHAP (12-14-99)2. Average total emissions are calculated from emission factors developed by the U.S. EPA for a range of boiler types using na3. No Emission Factor
Table C-6: Total Emissions & Potential Emissions Reductions from Energy Efficiency Improvements to Other Fuel Type Fired Ind

State

Estimated 

Number of 

Boilers

Cd Dioxin Hg

1,4-

Dichloro 

benzene

16-PAHs As Benzene Cr HCl 

Total Air Emissions (lbs/year)

IL 40 83 0.0 79 9 1,327 503 106,851 1,567 345,392 

IN 33 124 0.1 48 14 1,160 442 87,457 2,132 219,954 

MI 26 141 0.1 79 58 1,701 381 116,324 2,375 358,988 

MN 41 171 0.2 89 13 1,872 648 138,393 2,871 406,572 

NY 68 91 0.0 114 7 1,282 398 82,634 2,005 507,310 

OH 21 104 0.1 63 3 710 258 38,433 2,232 271,982 

PA 91 109 0.1 133 64 1,817 341 112,300 2,083 615,878 

WI 67 192 0.3 123 39 3,065 952 229,887 2,251 660,742 

Total 387 1,015 0.9 728 208 12,934 3,923 912,279 17,517 3,386,81

Potential Emission Reduction for Energy Efficiency Improvements (lbs/year)

1% 114 0.03 90 12 3,607 651 9,366 911 287,522 2% 228 0.06 181 24 7,214 1,302 18,731 1,823 575,044 5% 570 0.15 452 61 18,035 3,256 46,828 4,556 1,437,61

10% 1,140 0.30 905 122 36,070 6,512 93,655 9,113 2,875,22

Notes:

1. Estimated number of boilers based on US EPA Emissions Test Database, Population Database, and Materials Analysis Data Development of the Industrial/Commercial Boiler NESHAP (12-14-99)2. Average total emissions are calculated from emission factors developed by the U.S. EPA for a range of boiler types using pr3. Other fuel types include bagasse, wood, non-fossil fuel liquids & solids, biomass, & others.