1

Economics of Lime and Limestone for 

Control of Sulfur Dioxide 

William DePriest 

Sargent & Lundy LLC 

55 East Monroe Street 

Chicago, Illinois 60603 

Rajendra P. Gaikwad 

Sargent & Lundy LLC 

55 East Monroe Street 

Chicago, Illinois 60603 

Paper # 169 

ABSTRACT 

Over 90% of U.S. flue gas desulfurization system capacity uses lime or limestone. This trend 

will likely continue into the next phase of federally mandated SO2 reduction from coal burning 

power plants. The paper will present results of life-cycle cost analyses of major FGD processes 

that use lime and limestone including wet limestone with forced-oxidation (LSFO), wet 

magnesium-enhanced lime, and dry/semi-dry lime. 

This paper will show the relative competitive position of limestone and lime-based processes 

relative to reagent cost, auxiliary power cost, coal sulfur content, dispatch, capital cost, and byproduct production. The information presented here is based on a study performed by Sargent & 

Lundy and sponsored by the National Lime Association. The full report is available on the 

National Lime Association web site:

http://www.lime.org/NLADryFGD.pdf

http://www.lime.org/Wet_FGD.pdf

INTRODUCTION 

Sargent & Lundy LLC performed a study to compare costs of leading lime and limestone-based 

flue gas desulfurization (FGD) processes utilized by power generating plants in the United 

States. The study included developing conceptual designs with capital and O&M cost 

requirements using up-to-date performance criteria for the processes. This paper provides a 

summary of results of the study. 

Four FGD processes were evaluated: wet limestone scrubbing with forced oxidation (LSFO), wet 

lime scrubbing using magnesium-enhanced lime (MEL) with forced oxidation, dry lime 

scrubbing using a conventional spray-dryer absorber, and dry lime scrubbing using a circulating 

fluid bed (CFB) absorber. Each process was evaluated for a 500 MW coal-fired generating unit. 

The first three processes account for over 85% of FGD capacity in the United States. The fourth 

process, dry lime CFB, uses a newer type of absorber which has been more widely used in 
2

Europe. There was interest in evaluating dry scrubbing using this absorber because of its claims 

of increased SO2 removal efficiency and reduced cost and complexity compared with a 

conventional spray dryer absorber. 

A specific purpose of the study was to provide a cost comparison between wet lime and wet 

limestone technology that takes into account recent improvements in these technologies. Wet 

limestone systems have been substantially improved in the last decade resulting in improved 

performance and reliability and reduced capital and operating costs. Examples of such 

improvements include use of a single absorber module for power generating units with capacity 

of 500 MW and greater and increased sulfur dioxide removal efficiency to greater than 95%. 

Wet magnesium-enhanced lime systems have also been substantially improved. The MEL 

process now includes production of wallboard-quality gypsum via ex-situ forced oxidation, 

which results in a large reduction in operating cost compared with the predecessor MEL 

throwaway process. Since 1997, 4300 MW of MEL capacity have been retrofitted to produce 

gypsum. Single absorber modules have been utilized for power generating units of 500 MW and 

greater. New absorber installations have taken advantage of the lower L/G requirements 

inherent in the MEL process to substantially reduce absorber size and cost. 

SO2 removal efficiencies evaluated in the study reflect improvements in SO2 removal capability 

of both wet and dry FGD processes. Design removal efficiency of 98% was chosen for wet FGD 

evaluation, and 93 to 95% removal was chosen for dry FGD depending on process and coal type. 

For new coal-fired plants operating on high-sulfur coal with wet FGD, a 98% removal design 

may be required to meet Best Available Control Technology emission limits. For new coal-fired 

plants operating on low-sulfur coal with dry FGD, 93-95% removal may likewise be required. 

For retrofit application of wet FGD where removal requirements have traditionally depended on 

the value of SO2 allowances, an increasing value of allowances would be expected to increase 

desired removal efficiency above 95%..For this reason, a removal efficiency of 98% was chosen 

for this study. Also, 98% reduction was chosen to be the same for retrofit as for new unit 

application of wet FGD to allow better comparison between these cases. 

Additional aspects of the study included: development of design criteria; determination of 

application limits (absorber module size, coal sulfur content vs. SO2 removal efficiency); 

performance expectations for SO2 removal, reagent utilization, byproduct quality, parasitic 

power consumption; design considerations and costs for FGD application in new power 

generating units versus retrofit to existing units; and advantages and disadvantages of wet and 

dry technologies. 

Capital costs were developed primarily from Sargent & Lundy’s cost database, which is 

continuously updated from ongoing work in the area of FGD. 

Coal types used in the evaluations included high-sulfur Appalachian, low-sulfur Appalachian, 

and low-sulfur Powder River Basin (PRB). The wet FGD systems were evaluated on both 

Appalachian coals, while the dry FGD systems were evaluated on the low-sulfur coals. Table 1 

shows composition of these coals. 
3

Table 1. Compositions of Coals Used in Study of FGD Processes

Coal Type High-sulfur 

Appalachian 

Low-sulfur 

Appalachian 

Low-sulfur 

PRB 

FGD process type evaluated Wet Wet, Dry Dry 

Fuel analysis, % wt.: 

 Sulfur 3.0 1.3 0.6 

 Chlorine 0.12 0.1 0.03 

High heating value, Btu/lb 12,720 13,100 8,335 

SO2 generation*, lb/Mbtu 4.72 2.0 1.44 

* All sulfur in coal is assumed to be converted to SO2, and that no sulfur is removed in the either 

the bottom ash or electrostatic precipitator ash. 

EVALUATION OF FGD PROCESSES 

The following sections include description of the wet and dry processes, lime and limestone 

types utilized, byproducts, and commercial status of each. 

FGD Process Description 

Wet FGD 

Wet FGD technology using limestone or lime as a reagent has been the FGD technology most 

frequently selected for sulfur dioxide (SO2) reduction from coal-fired utility boilers. A wet FGD 

flue gas treatment system is usually located after removal of particulate matter from flue gas by an 

electrostatic precipitator or baghouse. Cleaned gas is discharged to a stack. Both LSFO and MEL 

are considered commercially mature technology and are offered by a number of suppliers. 

LSFO and MEL processes are well known and described in detail in the study and elsewhere. 

Compositions of limestone and magnesium-enhanced lime required are well known. Both processes 

produce gypsum byproduct utilized in wallboard production and other uses. Unlike the recycle tank 

oxidation common in the LSFO process, in the MEL process, forced oxidation to produce gypsum is 

accomplished in a reactor separate from the absorber recycle tanks . This “ex-situ” oxidation is 

desirable in the MEL process to maintain a high concentration in absorber slurry of soluble 

magnesium sulfites which buffer pH during SO2 absorption. Presence of this buffer allows reduced 

liquid-to-gas ratio and depresses scaling tendency. A second MEL process by-product, magnesium 

hydroxide, can be produced by treating FGD wastewater with additional lime. Use of this byproduct 

for control of sulfur trioxide emissions via furnace injection has been demonstrated in 800 MW and 

1300 MW units. 

Besides reagent, a significant difference between LSFO and MEL is the required absorber liquid-togas ratio to achieve the required SO2 removal efficiency which results in a significantly different 

parasitic power consumption for each of the technologies. An important goal of this study was to 

quantify the impact that selection of reagent (limestone or lime) would have on capital cost, 

operations & maintenance costs and combined life cycle costs for the LSFO and MEL processes. 
4

The LSFO system evaluated in the study did not include use of organic acids. LSFO systems are 

usually designed without depending on use of organic acids such as DBA. Advantages of organic 

acid addition are ability to reduce L/G and reduced power consumption. Provision is sometimes 

included to allow future organic acid addition in case SO2 collection efficiency is inadequate. 

Disadvantages include additional operating cost, uncertainty in long-term supply and pricing of 

DBA by-products, possible contamination of gypsum by-product, biological oxygen demand in 

wastewater, and potential increased wastewater treatment cost. 

Dry FGD 

The dry FGD process using a spray dryer absorber is well known and described elsewhere. 

The CFB absorber is relatively new to the U.S. market. In a typical CFB absorber flue gas is treated 

in the absorber by mixing flue gas with dry hydrated lime [calcium hydroxide, Ca(OH)2] and 

recycled FGD product containing unreacted lime. Velocity is maintained to develop a fluidized 

bed in the columnar absorber. Water is injected into the scrubber in the throat of a venturi section 

at the bottom, cooling the gas at the inlet from 300°F or higher to approximately 160°F, 

depending on the relationship between approach to saturation and removal efficiency. The 

hydrated lime absorbs SO2 from the gas and forms the reaction products calcium sulfite and 

calcium sulfate. A portion of hydrated lime reacts with CO2 in the flue gas. The desulfurized 

flue gas flows out of the CFB, along with the reaction products, unreacted hydrated lime, 

calcium carbonate and the fly ash, to an ESP or baghouse. 

Most CFB designs include equipment for on-site hydration of lime (calcium oxide, CaO), which 

reduces reagent cost compared with purchase of hydrated lime. Some developers claim 

improved performance with freshly prepared hydrated lime. 

CFB differs from a spray-dryer in several ways. No moving parts or dual-fluid nozzles are 

required to mix lime with the flue gas. The CFB relies on dispersion of lime in a large mass of 

recycle solids from the particulate collector. When a large amount of recycle ash is used there is 

a reduced risk of wetting absorber walls compared with a typical spray-dryer due to the added 

drying surface provided by the recycle ash. This may allow a closer approach to saturation, 

which can improve SO2 removal and lime utilization. SO2 removal can be increased by 

increasing addition rate of dry hydrated lime without the lower temperature limit imposed on a 

spray-dryer absorber. However, lime utilization for the CFB generally decreases with increasing 

SO2 removal. 

A number of variations on the CFB-FGD technology are offered by various process developers . 
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SO2 Removal Performance and Reagent Utilization 

Wet FGD 

Based on the coal compositions used in the wet FGD evaluations, liquid-to-gas ratios necessary 

to achieve 98% SO2 removal were determined as shown in Table 2. The values for LSFO are 

based on demonstrations and testing by various FGD process developers and are further verified 

by recent guarantees offered by FGD vendors for new unit applications. For the Appalachian 

high- and low-sulfur coals, Sargent & Lundy estimated that L/G ratios of 130 and 80, respectively, 

will be required to achieve 98% SO2 removal efficiency without the use of organic acid in a typical 

LSFO spray-tower absorber design. Limestone reagent utilization of at least 97% is required due to 

gypsum byproduct purity requirements. 

Table 2. L/G to Achieve 98% Removal in Wet FGD vs. Coal Sulfur Content

Wet process LSFO LSFO MEL MEL 

Coal type Appalachian

High Sulfur 

Appalachian

Low Sulfur 

Appalachian

High Sulfur 

Appalachian

Low Sulfur 

L/G ratio, gpm per 1000 acfm at 

absorber outlet 

130 80 40 30 

Because of higher SO2 absorption capacity available in the MEL system compared with the 

LSFO system, estimated L/G ratios of 40 and 30 are required to achieve 98% removal for the 

Appalachian high- and low-sulfur coals respectively. Lime utilization is near 100% due to high 

reactivity of lime and small particle size of slaked lime. 

The difference in the L/G ratio requirements and the reagent between the LSFO and MEL processes 

has a major impact both on capital and O&M cost differences between the two competing 

technologies. 

Dry FGD 

Lime spray-dryer (LSD) and CFB based dry FGD systems have been demonstrated to 

economically achieve as high as 90-95% SO2 removal efficiency. Dry FGD systems are applied 

mainly to low-sulfur coal, including PRB and western coals with inlet SO2 less than 2.0 lb/Mbtu 

and low-sulfur eastern bituminous coal with inlet SO2 concentrations as high as 3.0 lb/MBtu. 

However, the higher efficiency also typically results in lower lime utilization for both processes. 

 

SO2 removals chosen for the dry systems in this study are given in Table 3. SO2 removals 

include removal that occurs in a subsequent ESP or baghouse. SO2 removals for the spray-dryertype absorber are based on likely outlet SO2 emission limit guarantees available for the coal 

types used in the study. SO2 removals for the CFB-type is higher but is assumed to be 

accompanied by lower lime utilization. 
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Some suppliers of FGD systems will utilize unreacted alkalinity in the ash collected in the 

particulate collector by recycling the ash back to the reactor. Of particular interest is the inherent 

alkalinity in Powder River Basin ash which has been exploited by systems designers and resulted 

in good reagent utilization compared to acidic fly ashes from eastern bituminous coal, resulting 

in a lower lime reagent ratio as shown in Table 3. 

Table 3. SO2 Removal and Lime Reagent Ratio vs. Coal Type for Dry FGD 

Absorber type LSD LSD CFB CFB 

Coal type Appalachian 

Low sulfur 

PRB 

Low sulfur 

Appalachian 

Low sulfur 

PRB 

Low sulfur 

SO2 removal, % 94 93 95 95 

SO2 emission, lb/Mbtu 0.12 0.10 0.10 .072 

Reagent ratio, moles of Ca/mole of 

inlet SO2

1.4 1.1 1.5 (retrofit) 

1.35 (new) 

1.2 (retrofit) 

1.1 (new) 

Commercial Status 

Wet FGD 

Wet FGD is a well-established technology with proven reliability operating in plants burning a 

variety of coals. Reagents used by the process are plentiful and readily available. The FGD 

system is not sensitive to boiler operational upsets and typical operating modes, such as cycling 

duty. However, due to the potential for acid pH in parts of the process and the presence of 

chlorine in the fuel, a high potential for corrosion is created in some of the system components 

which, in turn, require extensive use of costly corrosion-resistant alloys or nonmetallic liners as 

materials of construction. Alloy 317 LMN was used as a basis for this study and chloride level 

was limited to 8,000 ppm. 

Both the LSFO and the MEL FGD systems are operating successfully at many coal-fired power 

facilities, ranging in size from less than 100 MW to 1000 MW. Many competing designs are 

available in the marketplace from a number of viable suppliers. 

Large, single absorber modules have been demonstrated for application to a single unit up to 1000 

MW. 

Wet FGD systems also have the capability to efficiently remove oxidized forms of mercury from 

flue gas. 

Dry FGD 

Lime spray-dryer FGD systems are in operation at many facilities, ranging in size from less than 

10 MW to 600 MW. However, currently the largest single absorber module is approximately 
7

300 MW, so two absorbers were used in this study. Spray-dryer systems with rotary or dual 

fluid atomizers are available from a number of vendors. 

 CFB systems are in operation at many facilities ranging in size from less than 10 MW to 

300 MW. A CFB unit, in Austria, is on a 275 MW size oil-fired boiler burning 1.0-2.0% sulfur 

oil. The CFB-based FGD system is commercially available from several vendors. Accordingly, 

for CFB application, two absorber modules were used for the 500 MW unit employed in this 

study. 

Unlike wet FGD absorbers which must be constructed of expensive corrosion-resistant metals or 

other material, dry FGD absorbers can be constructed of less expensive carbon steel due to 

absence of a water-saturated gas. Because dry FGD systems operate without saturating the flue 

gas, they may not produce a visible moisture plume and, when used in conjunction with a fabric 

filter, are able to efficiently capture sulfur trioxide. Dry FGD systems are also capable of 

efficiently removing oxidized forms of mercury from flue gas. 

By-Product Quality 

Wet FGD 

The by-product from either the wet LSFO process or the MEL process can be fashioned for use 

in the cement industry, for wallboard manufacturing, or for agricultural use. By-product quality 

requirements are much more stringent for wallboard manufacturing compared to the other uses. 

While opportunities currently exist to contract to sell gypsum for a nominal $1-3 per ton, the 

future gypsum market holds many uncertainties and, therefore, it was assumed that the gypsum 

could be “sold” for $0 per ton in this study. 

Dry FGD 

The waste product contains CaSO3, CaSO4, CaCO3, unreacted calcium hydroxide, and fly ash. 

Normally this material must be disposed in a landfill. There is potential for use as agricultural 

soil conditioning and for preparation of bricks or lightweight aggregates. If there is currently a 

significant market for fly ash, it may be prudent to install the dry FGD/baghouse combination 

after the fly ash particulate collector such that the fly ash is segregated from the LSD waste and 

can be “sold”. 

For disposal in a landfill, a disposal cost of $12 per dry ton was applied to the non-fly ash 

portion of the FGD byproduct. 

Energy Consumption 

Wet FGD 

The process energy consumption results primarily from booster ID fan power required to 

overcome the draft loss across the absorber, power requirement for recirculation pumps, power 
8

required for oxidation air compressors, power for ball mills/slakers, power for gypsum 

dewatering system, and various electrical and control users typically needed for FGD operations. 

 Table 4 shows L/G pumping requirements, absorber draft loss and the resultant overall energy 

consumption versus wet FGD process and coal type. These values were used in the evaluation to 

calculate power cost. 

Table 4. L/G, Draft Loss and Power Consumption (% of MW net) for Wet FGD vs. Coal Sulfur 

and Process

Process LSFO LSFO MEL MEL 

Coal Appalachian

High Sulfur 

Appalachian

Low Sulfur 

Appalachian

High Sulfur 

Appalachian

Low Sulfur 

L/G ratio, gpm per 1000 acfm at 

absorber outlet 

130 80 40 30 

Absorber draft loss, inches water 9 8 7 7 

Power consumption, % of MWnet 2.0 1.3 1.4 1.0 

The MEL process has a significant advantage over the LSFO process in power consumption. In 

the high-sulfur case, power requirement for slurry recirculation is 71% lower than for the LSFO 

process and the power requirement for the booster ID fan is 22% lower than for the LSFO 

process. Overall, the MEL process will require approximately 0.6% less auxiliary power for 

high-sulfur coal and approximately 0.3% less auxiliary power for low-sulfur coal compared to 

the LSFO process. 

Dry FGD 

A major component of the energy consumption in dry FGD is from draft loss across the 

absorber. In the study, the reactor draft loss for the LSD is 6-8 inches of water and for the CFB 

the loss is 8-10 inches. These values are used to compute parasitic power consumption, shown 

in Table 5. Power consumptions due to draft loss were not included in these values. These 

values were used in the evaluation to calculate power cost. 

Table 5. Power Consumption for Dry FGD vs. Coal Sulfur and Process 

Process LSD LSD CFB CFB 

Coal type Appalachian 

Low sulfur 

PRB 

Low sulfur 

Appalachian 

Low sulfur 

PRB 

Low sulfur 

Power consumption, % of MWnet: 

 New Unit 0.65 0.70 0.80 0.90 

 Retrofit 1.1 1.2 0.80 0.90 
9

New Units Versus Retrofit 

Wet FGD 

In new unit and retrofit applications, wet FGD technology is typically installed between the 

electrostatic precipitator/baghouse outlet and the stack. Retrofit units will usually have booster 

fans to overcome the pressure drop across the FGD absorber, which will be located after the 

existing ID fans. New units will be installed with ID fans large enough to overcome the pressure 

drop across the FGD absorber. This feature will result in lower capital cost for the draft system 

on a new unit application compared with a retrofit. 

Retrofit units will usually not use existing stacks, as these stacks are designed for hot flue gas 

approximately at a 100 ft/sec exit velocity. To accommodate saturated flue gas from wet FGD, 

wet stacks are designed for a highly corrosion-resistant material with a gas velocity of between 

55 to 70 ft/sec. Lower gas velocity is required to prevent condensed moisture from being carried 

out the top of the stack. 

The capital cost estimates in this study for wet FGD retrofit includes cost for a new wet stack. 

Dry FGD

A dry FGD system is installed between the air heater outlet and particulate collector. Most 

existing units have very short ductwork between the air heater outlet and electrostatic 

precipitator inlet. This makes it very difficult to take the gas from the air heater outlet to the dry 

FGD equipment and return it to the electrostatic precipitator inlet. Also, most existing 

electrostatic precipitators are not designed to handle increased particulate loading resulting from 

the dry FGD waste products. This will require modifications to the existing electrostatic 

precipitator to accommodate collection of the additional particulate from the dry FGD. In 

addition, an electrostatic precipitator will capture only a small percentage of the SO2 (5% to 

10%), placing a high burden on the dry FGD for SO2 removal. 

New units are expected to be installed with a baghouse rather than an ESP. Reagent utilization is 

expected to be better on units installed with a baghouse compared to retrofit units installed with 

modifications to an ESP. A baghouse can achieve 15% to 20% SO2 capture lessening the burden 

on the dry FGD. 

For both new units and retrofit with dry FGD and where fly ash sales are essential, a preferred 

arrangement may be to use an ESP for fly ash collection followed by a dry FGD or CFB and a 

baghouse for SO2 collection. 

In this study, for both new unit and retrofit, the spray-dryer is assumed be followed by a new 

pulse-jet baghouse. For retrofit of a CFB absorber, it is assumed that an existing ESP can be 

modified to follow it. Costs to modify the ESP to accommodate increased particulate loading are 

included in the capital cost. For a new unit application, the CFB is followed by a pulse-jet 

baghouse. 

FGD DESIGN CRITERIA 
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The following additional design criteria were used in the evaluation. Table 6 shows flue gas 

flows and temperatures used for sizing absorber equipment for the various processes and coal 

types. 

Table 6. Flue Gas Flows and Temperatures

FGD Processes LSFO, 

MEL 

LSFO, 

MEL 

LSD, 

CFB 

LSD, 

CFB 

Heat input to boiler, MBtu/hr 5000 5000 5000 5186 

Coal type Appalachian 

High-sulfur 

Appalachian

Low-sulfur 

Appalachian 

Low-sulfur 

PRB 

Low-sulfur 

Flue gas flow at FGD inlet*, macfm 1.75 1.70 1.79 1.97 

Flue gas temperature at FGD inlet, 

°F 

300 280 280 280 

Flue gas flow at FGD outlet, macfm 1.52 1.50 1.60 1.75 

Flue gas temperature at FGD outlet, 

°F 

130 130 160 165 

* includes air in-leakage, assumed same for new and retrofit 

Table 7 shows additional design parameters for the wet FGD system designs. Lime and limestone 

costs are for reagent delivered to the power plant site by truck. For LSFO, a reagent ratio of 1.03 or 

less is required in order for gypsum byproduct to meet wallboard quality standards. Table 8 shows 

additional design parameters for the dry FGD systems. 

 

Table 7. Additional Design Parameters Used for Wet FGD Comparison

 LSFO MEL 

SO2 removal, % 98% 98% 

By product Gypsum Gypsum 

Reagent Limestone Lime 

Reagent cost, $/ton 15 50 

Reagent purity, % 95 94 

Reagent ratio, moles of 

reagent/mole of sulfur removal 

1.03 1.02 

SO2 oxidation stoichiometry 

(moles O fed/mole SO2 removed) 

3.0 3.0 
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Table 8. Additional Design Parameters Used for Dry FGD Comparison

Process LSD LSD CFB CFB 

Coal type Appalachian 

Low sulfur 

PRB 

Low sulfur 

Appalachian 

Low sulfur 

PRB 

Low sulfur 

 

SO2 removal, % 94 93 95 95 

Byproduct Dry Waste Dry Waste Dry Waste Dry Waste 

Lime cost, $/ton 60 60 60 60 

Reagent purity, % 93 93 93 93 

Reagent ratio, moles of CaO/mole 

of inlet sulfur 

1.4 1.1 1.5 (retrofit) 

1.35 new) 

1.2 (retrofit) 

1.1 (new) 

EVALUATION OF FGD COSTS 

Capital Costs 

The costs were developed primarily from Sargent & Lundy’s cost database, which is 

continuously updated from ongoing work in the area of FGD. 

The capital costs represent the “total plant cost,” and include the following: equipment and 

material (FGD system and balance-of-plant); direct field labor; indirect field costs and engineering; 

contingency; owner's cost; allowance for funds during construction (AFUDC); and initial inventory 

and spare parts (1% of the process capital); and startup and commissioning. Owner’s cost includes 

owner’s project management, engineering, accounting, billing, etc., as well as an estimate for 

any “corporate” charges that may apply to capital projects. In many cases, owners will also 

place capital financing charges in this category. We have assumed in our analysis that the 

capital cost estimate is an “overnight” cost and therefore no financing charges or escalation are 

included. Contracting arrangement for implementation of an FGD project is assumed based on 

multiple lump sum specialty work packages. Relative accuracy of the capital costs is estimated 

at plus-or-minus 20%. 

Table 9 presents results of capital cost estimates as total capital requirements for the wet FGD 

system for both new units and retrofit. Table 10 presents capital costs for the dry FGD systems 

for both new units and retrofit. 

 
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Table 9. Total Capital Requirements for 500 MW Wet FGD Systems: New Unit and Retrofit 

Wet FGD process LSFO MEL 

Coal type Appalachian

High Sulfur 

Appalachian 

Low Sulfur 

Appalachian 

High Sulfur 

Appalachian 

Low Sulfur 

New unit: 

 $ 64,451,000 53,344,000 54,665,000 48,214,000 

 $/kW 125 107 109 96 

Retrofit: 

 $ 85,958,000 76,106,000 76,256,000 69,659,000 

 $/kW 172 152 153 139 

Table 10. Total Capital Requirements for 500 MW Dry FGD Systems: New Unit and Retrofit 

Dry FGD process LSD CFB 

Coal type Appalachian 

Low Sulfur 

PRB Low 

Sulfur 

Appalachian 

Low Sulfur 

PRB Low 

Sulfur 

New unit: 

 $ 61,291,000 62,581,000 66,914,000 68,551,000 

 $/kW 122 126 134 137 

Retrofit: 

 $ 77,322,000 81,434,000 74,235,000 75,819,000 

 $/kW 155 163 149 152 

Capital Cost Comparisons 

The following comparisons can be made regarding capital costs for the LSFO, MEL and SDA 

technologies: 

 LSFO vs. MEL on High “S” Bit. Coal 

 Mel ~11% Lower (or $9.8 million) 

 LSFO vs. MEL on Low “S” Bit. Coal 

 Mel ~9% Lower (or $6.7 million) 

 MEL vs. SDA w/o baghouse on Low “S” Bit. Coal 

 Mel ~30% higher (or $16 million) 

 MEL vs. SDA w/baghouse on Low “S” Bit. Coal 

 MEL ~10% Lower (or $7.8 million) 

 SDA Comparison on Eastern and Western Low “S” Coal 

 ~5% higher on Western sub. Bit. Coal (or $4.0 million) 
13

Operations and Maintenance Costs 

Tables 11, 12, 13, and 14 present results of determination of first-year O&M costs associated 

with the wet and dry FGD systems for new units and retrofit. Fixed operating costs include 

operating and maintenance labor, supervisory labor, and maintenance materials. Operating labor 

cost includes addition of 8 operators to the labor pool for a new unit and addition of 12 operators 

for a retrofit. Variable operating costs consist of mainly reagent, waste disposal or byproduct 

credit (gypsum is assumed “sold” for $0 per ton), and parasitic power. Power cost is assumed to 

be $30/MW-hr, which includes both energy and capacity charges. Variable operating costs were 

calculated assuming a 80% annual average load factor. 

Table 11. First-Year Fixed and Variable Operating Costs for Wet FGD Processes and Coal 

Sulfur - New Unit 

Wet FGD process LSFO ($/year) MEL ($/year) 

Coal type Appalachian 

High Sulfur 

Appalachian 

Low Sulfur 

Appalachian 

High Sulfur 

Appalachian 

Low Sulfur 

 

Fixed Operating Costs 3,929,000 3,514,000 3,574,000 3,280,000

Variable Operating 

Costs: 

 Reagent Costs 2,059,000 873,000 3,847,000 1,630,000

 Waste Disposal Cost 0 0 0 0

 Byproduct Credit 0 0 0 0

 Water 208,000 208,000 208,000 208,000

 Power 2,102,000 1,367,000 1,472,000 1,051,000

Total Variable Cost 4,369,000 2,448,000 5,527,000 2,889,000

Total O&M 8,298,000 5,962,000 9,101,000 6,169,000
14

Table 12. First-Year Fixed and Variable Operating Costs for Wet FGD Processes and Coal 

Sulfur - Retrofit 

Wet FGD process LSFO ($/year) MEL ($/year) 

Coal type Appalachian 

High Sulfur 

Appalachian 

Low Sulfur 

Appalachian 

High Sulfur 

Appalachian 

Low Sulfur 

 

Fixed Operating Costs 4,470,000 4,055,000 4,114,000 3,821,000

Variable Operating 

Costs: 

 Reagent Costs 2,059,000 873,000 3,847,000 1,630,000

 Waste Disposal Cost 0 0 0 0

 Byproduct Credit 0 0 0 0

 Water 208,000 208,000 208,000 208,000

 Power 2,102,000 1,367,000 1,472,000 1,051,000

Total Variable Cost 4,369,000 2,448,000 5,527,000 2,889,000

Total O&M 8,839,000 6,503,000 9,641,000 6,710,000

Table 13. First-Year Fixed and Variable Operating Costs for Dry FGD Processes and Coal 

Sulfur - New Unit 

Wet FGD process LSD ($/year) CFB ($/year) 

Coal type Appalachian 

Low Sulfur 

PRB 

Low Sulfur 

Appalachian 

Low Sulfur 

PRB 

Low Sulfur 

 

Fixed Operating Costs 2,539,000 2,578,000 2,710,000 2,759,000

Variable Operating 

Costs: 

 Reagent Costs 2,769,000 1,354,000 2,670,000 1,354,000

 Waste Disposal Cost 1,071,000 589,000 1,057,000 596,000

 Byproduct Credit 0 0 0 0

 Bag Replacement 341,000 375,000 341,000 375,000

 Cage Replacement 21,000 23,000 21,000 23,000

 Water 102,000 127,000 102,000 127,000

 Power 1,156,000 1,261,000 841,000 946,000

Total Variable Cost 5,460,000 3,729,000 5,032,000 3,421,000

Total O&M 7,999,000 6,307,000 7,742,000 6,180,000

 
15

Table 14. First-Year Fixed and Variable Operating Costs for Dry FGD Processes and Coal 

Sulfur - Retrofit

Wet FGD process LSD ($/year) CFB ($/year) 

Coal type Appalachian 

Low Sulfur 

PRB 

Low Sulfur 

Appalachian 

Low Sulfur 

PRB 

Low Sulfur 

 

Fixed Operating Costs 2,944,000 2,983,000 2,710,000 2,759,000

Variable Operating 

Costs: 

 Reagent Costs 2,769,000 1,354,000 2,967,000 1,477,000

 Waste Disposal Cost 1,071,000 589,000 1,116,000 621,000

 Byproduct Credit 0 0 0 0

 Bag Replacement 341,000 375,000 341,000 375,000

 Cage Replacement 21,000 23,000 21,000 23,000

 Water 102,000 127,000 102,000 127,000

 Power 1,156,000 1,261,000 841,000 946,000

Total Variable Cost 5,460,000 3,729,000 5,026,000 3,171,000

Total O&M 8,404,000 6,712,000 8,141,000 6,336,000

Table 14 shows calculated parasitic power consumption for the wet FGD processes as a function 

of coal sulfur content. Power consumption is lower for the MEL system due to lower recycle 

pump flow and lower spray header elevation and lower absorber draft loss, all due to lower L/G. 

 

O&M Cost Comparisons 

The following comparisons can be made regarding O&M costs for the LSFO, MEL, and SDA 

technologies: 

 LSFO vs. Mel on High “S” Bit. Coal 

 MEL ~9% Higher (or $0.98 million/year) 

 LSFO vs. MEL on Low “S” Bit. Coal 

 MEL ~3.3% Higher (or $0.26 million/year) 

 MEL vs. SDA w/o Baghouse on Low “S” Bit. Coal 

 MEL ~10% Higher (or $0.61 million/year) 

 MEL vs. SDA w/Baghouse on Low “S” Bit. Coal 

 MEL is equivalent 

 SDA Comparison on Eastern and Western Low “S” Coal 

 SDA ~25% lower on Western Sub. Bitu. Coal

Levelized Costs 

Levelized costs, also referred to as “life cycle costs,” take into account impacts of capital costs 

and O&M cost during the operation of a plant over the period of analysis. Table 15 includes 
16

factors used in this study to levelize capital and operating costs. The levelized fixed charge rate 

(impact due to capital cost) was calculated based on an assumption that a typical customer is a 

regulated utility. The levelized fixed charge rate includes depreciation of the property, return on 

capital (50% debt and 50% equity), income tax, property tax, and insurance. Based on an 8.75% 

discount rate and 30-year or 20-year life expectancy for new or retrofit facilities, respectively, 

the levelized fixed charge rates are 14.50% (30-year life) and 15.43% (20-years life). The 

levelized cost analysis was performed based on current dollars, as most regulated utilities base 

their analysis on current dollars. 

The levelized O&M cost factor takes into account plant life, discount rate, and inflation rate. 

The levelized O&M cost factors were 1.30 for the 30-year period and 1.22 for the 20-year 

analysis. 

Table 15. Capital and Operating Cost Levelizing Factors for New Unit and Retrofit 

 New Unit Retrofit 

Plant Life, years 30 20 

Capital cost levelizing factor, %/year 14.5 15.43 

Discount rate, % 8.75 8.75 

Inflation rate, % 2.5 2.5 

Operating cost levelization factor 1.30 1.22 

Tables 16 through 19 shows levelized costs for wet and dry FGD. 

Table 16. Levelized Costs for Wet FGD for New Unit

Process LSFO MEL 

Coal type 

Appalachian

High sulfur

Appalachian

Low sulfur 

Appalachian

High sulfur 

Appalachian 

Low sulfur 

Total capital cost $MM 62.5 53.3 54.7 48.2 

Levelized capital Cost, MM$/yr 9.06 7.73 7.93 6.99 

Levelized O&M Cost, MM$/yr 10.79 7.75 11.83 8.02 

Total Levelized Cost, MM$/yr 19.84 15.49 19.76 15.01 

 

Total cents/kW-hr 0.57 0.44 0.57 0.43 
17

Table 17. Levelized Costs for Wet FGD for Retrofit

Process LSFO MEL 

Coal type 

Appalachian

High sulfur

Appalachian

Low sulfur 

Appalachian

High sulfur 

Appalachian 

Low sulfur 

Total capital cost $MM 86.0 76.1 76.3 69.7 

Levelized capital Cost, MM$/yr 13.26 11.74 11.77 10.75 

Levelized O&M Cost, MM$/yr 10.78 7.93 11.76 8.19 

Total Levelized Cost, MM$/yr 24.05 19.68 23.53 18.93 

 

Total cents/kW-hr 0.69 0.56 0.67 0.54 

Table 18. Levelized Operating Cost for Dry FGD for New Unit 

Process LSD CFB 

Coal type 

PRB 

Low sulfur

Appalachian 

Low sulfur 

PRB 

Low sulfur 

Appalachian 

Low sulfur 

Total capital cost $MM 62.6 61.3 68.6 66.9 

Levelized capital Cost, MM$/yr 9.07 8.89 9.07 8.89 

Levelized O&M Cost, MM$/yr 8.20 10.40 8.03 10.06 

Total Levelized Cost, MM$/yr 17.27 19.29 17.52 19.36 

 

Total cents/kW-hr 0.49 0.55 .49 .54 

Table 19. Levelized Operating Cost for Dry FGD for Retrofit

Process LSD CFB 

Coal type 

PRB 

Low sulfur

Appalachian 

Low sulfur 

PRB 

Low sulfur 

Appalachian 

Low sulfur 

Total capital cost $MM 81.4 77.3 75.6 74.1 

Levelized capital Cost, MM$/yr 12.57 11.93 12.57 11.93 

Levelized O&M Cost, MM$/yr 8.19 10.25 7.73 9.93 

Total Levelized Cost, MM$/yr 20.75 22.18 20.30 21.86 

 

Total cents/kW-hr 0.59 0.63 .58 0.62 
18

Life Cycle Comparisons 

Considering only the wet FGD technologies (LSFO and MEL), the following life cycle 

comparisons were made to quantify the relative economics of using limestone or lime as the 

FGD reagent. 

1. Reagent Cost Sensitivity (High “S”): 

Reagent Cost Sensitivity (Low “S”) 

0

5

10

15

20

45 50 55 60 65 70 75

Lime Cost, $/ton

Limestone cost, $/ton

Wet lime process favored

Wet limestone process favored

Basis:

1.3% sulfur

Retrofit

80% CF

$ 30/Mwhr

0

5

10

15

20

25

30

40 45 50 55 60 65 70 75

Lime Cost, $/ton

Limestone cost, $/ton

Wet lime process favored

Wet limestone process favored

Basis:

3% sulfur

Retrofit

80% CF

$ 30/Mwhr
19

2. New Unit Vs. Retrofit Unit 

3. Auxiliary Power Cost 

Using high sulfur coal, the following three graphs show the affect that auxiliary power costs have on 

the choice of reagent (limestone vs. lime) for three different limestone costs and three different lime 

costs: 

Aux. Power Sensitivity (Lime @ $45/ton) 

0

5

10

15

20

25

30

35

40 45 50 55 60 65 70 75

Lime Cost, $/ton

Limestone cost, $/ton

Wet lime process favored

Wet limestone process favored

Retrofit Units

 New Units

Basis:

3% sulfur

80% CF

$ 30/Mwhr

0.6

0.62

0.64

0.66

0.68

0.7

0.72

0.74

15 20 25 30 35 40 45 50

Aux. Power Cost, $/MWH

Increase in Cost of Electricity, Cents/kWH

MEL at $45/ton 

LSFO @ $15/ton

LSFO @ $10/ton

LSFO @ $5/ton

Basis:

3% sulfur

Retrofit

80% CF

$ 30/Mwhr
20

Aux. Power Sensitivity (Lime @ $50/ton) 

Aux. Power Sensitivity (Lime @ $60/ton) 

0.6

0.62

0.64

0.66

0.68

0.7

0.72

0.74

15 20 25 30 35 40 45 50

A ux. P ow er C ost, $/M W H

Increase in Cost of Electricity, Cents/kWH

M E L at $50/ton 

LS FO @ $15/to n

L S F O @ $10/to n

L S F O @ $5/to n

Basis:

3% sulfur

Retrofit

80% CF

$ 30/Mwhr

0.6

0.62

0.64

0.66

0.68

0.7

0.72

0.74

15 20 25 30 35 40 45 50

A u x. P o w er C o st, $/M W H

Increase in Cost of Electricity, Cents/kWH

M E L at $60/to n 

L S F O @ $15/to n

L S F O @ $10/to n

L S F O @ $5/to n

Basis:

3% sulfur

Retrofit

80% CF

$ 30/Mwhr
21

Similarly, for low sulfur coal applications the following graphs represent the affect of auxiliary 

power costs on reagent choice: 

Aux. Power Sensitivity (Low “S”, Lime @ $45/ton) 

Aux. Power Sensitivity (Low “S”, Lime @ $50/ton) 

Basis:

1.3% sulfur

Retrofit

80% CF

$ 30/Mwhr

0.52

0.53

0.54

0.55

0.56

0.57

0.58

0.59

0.6

15 20 25 30 35 40 45 50

A ux. P ow er C ost, $/M W H

Increase in Cost of Electricity, Cents/kWH

M E L @ $50/ton

LSFO @ $/5 ton

LS FO @ $15/ton

0.51

0.52

0.53

0.54

0.55

0.56

0.57

0.58

0.59

0.6

15 20 25 30 35 40 45 50

A ux. P ow er C ost, $/M W H

Increase in Cost of Electricity, Cents/kWH

LS FO @ $/15/ton

LSFO @ $/5 ton

M E L @ $45/ton

Basis:

1.3% sulfur

Retrofit

80% CF

$ 30/Mwhr
22

Aux. Power Sensitivity (Low “S”, Lime @ $70/ton) 

4. Capital Cost 

The following graph shows an example of the sensitivity of reagent choice to the accuracy 

in the capital cost estimate for each of technologies: 

High “S” Appalachian Coal – Capital Cost Sensitivity 

0.52

0.53

0.54

0.55

0.56

0.57

0.58

0.59

0.6

15 20 25 30 35 40 45 50

Aux. Pow er Cost, $/M W H

Increase in Cost of Electricity, Cents/kWH

LSFO @ $/15/ton

LSFO @ $/5 ton

M EL @ $70/ton

Basis:

1.3% sulfur

Retrofit

80% CF

$ 30/Mwhr

0.6

0.62

0.64

0.66

0.68

0.7

0.72

0.74

-10 -5 0 5 10

Variation in Absolute Capital C ost, %

Increase in Cost of Electricity, cents/kWh

M EL @ $50/ton

LSFO @ $10/ton

LSFO @ $15/ton

Basis:

3% sulfur

Retrofit

80% CF

$ 30/Mwhr
23

Similarly, the following graph shows an example of the sensitivity of reagent choice to the size of 

the difference between the capital costs for the LSFO technology vs. the MEL technology. 

High “S” Appalachian Coal – Capital Cost Sensitivity (Assume Constant LSFO Cost) 

4. Plant Capacity Factor 

The following three graphs show the affect that the plant capacity factor has on reagent choice for a 

high sulfur application for various reagent costs. 

High “S” Appalachian Coal – Load Factor Sensitivity (Lime @ $45/ton) 

0 .6

0 .6 1

0 .6 2

0 .6 3

0 .6 4

0 .6 5

0 .6 6

0 .6 7

0 .6 8

0 .6 9

0 .7

-1 0 -5 0 5 1 0

V a ria tio n in D iffe re n tia l C a p ita l C o s t, %

Increase in Cost of Electricity, cents/kWh

M EL @ 

$ 5 0 /t

LSFO @ $ 1 0 /to n

L S F O @ $ 1 5 /to n

LSFO @ $ 5 /to n

Basis:

3% sulfur

Retrofit

80% CF

$ 30/Mwhr

0.6

0.62

0.64

0.66

0.68

0.7

0.72

0.74

0.76

0.78

0.8

65 70 75 80 85 90

Load Factor, %

Increase in Cost of Electricity, cents/kWh

M EL @ $45/ton

LSFO @ $15/ton

LSFO @ $10/ton

Basis:

3% sulfur

Retrofit

80% CF

$ 30/Mwhr
24

High “S” Appalachian Coal – Load Factor Sensitivity (Lime @ $50/ton) 

High “S” Appalachian Coal – Load Factor Sensitivity (Lime @ $60/ton) 

0.6

0.62

0.64

0.66

0.68

0.7

0.72

0.74

0.76

0.78

0.8

65 70 75 80 85 90

Load Factor, %

Increase in Cost of Electricity, cents/kWh

MEL @ $50/ton

LSFO @ $10/ton

LSFO @ $15/ton

Basis:

3% sulfur

Retrofit

80% CF

$ 30/Mwhr

0.6

0.62

0.64

0.66

0.68

0.7

0.72

0.74

0.76

0.78

0.8

65 70 75 80 85 90

Load Factor, %

Increase in Cost of Electricity, cents/kWh

MEL @ $60/ton

LSFO @ $15/ton

LSFO @ $10/ton

Basis:

3% sulfur

Retrofit

80% CF

$ 30/Mwhr
25

Conclusions

1. Lime’s position as a candidate FGD reagent improves as the sulfur content of the fuel decreases. 

2. Because of a generally higher capital cost for retrofit applications versus new unit applications, 

Lime’s position will be marginally better in retrofit applications of FGD technology. 

3. Because the “cost” of auxiliary power on new units is generally higher than on existing units, the 

relative competitive position of lime will look better when the MEL process is applied on new units. 

 This phenomenon becomes less important as the fuel sulfur content is reduced. 

4. The absolute value of the capital cost is not nearly as important as the differential cost between 

LSFO and MEL technologies.