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 SO 2 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 processesrelative 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 limest one 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 in2 Europe. There was interest in evaluating dry scr ubbing using this absorber because of its claims of increased SO 2 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 ta ken advantage of the lower L/G requirements inherent in the MEL process to substantially reduce absorber size and cost.

SO 2 removal efficiencies evaluated in the study reflect improvements in SO 2 removal capability of both wet and dry FGD processes. Design rem oval efficiency of 98% was chosen for wet FGD evaluation, and 93 to 95% removal was chosen fo r 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 SO 2 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. SO 2 removal efficiency); performance expectations for SO 2 removal, reagent utilization, byproduct quality, parasitic power consumption; design considerations a nd 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 hi gh-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 SO 2 generation*, lb/Mbtu 4.72 2.0 1.44 * All sulfur in coal is assumed to be converted to SO 2 , 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 (SO 2 ) 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 SO 2 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 furn ace injection has been demonstrated in 800 MW and 1300 MW units.

Besides reagent, a significant difference between L SFO and MEL is the required absorber liquid-togas ratio to achieve the required SO 2 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 SO 2 collection efficiency is inadequate. Disadvantages include additional operating cost, un certainty 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. Ve locity 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 SO 2 from the gas and forms the reaction products calcium sulfite and calcium sulfate. A portion of hydrated lime reacts with CO 2 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 SO 2 removal and lime utilization. SO 2 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 SO 2 removal.

A number of variations on the CFB-FGD technology are offered by various process developers .5 

### SO 2 

### 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% SO 2 removal were determined as shown in Table 2. The values for LSFO are based on demonstrations and testing by various F GD 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% SO 2 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 SO 2 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 respectiv ely. 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% SO 2 removal efficiency. Dry FGD systems are applied mainly to low-sulfur coal, including PRB and western coals with inlet SO 2 less than 2.0 lb/Mbtu and low-sulfur eastern bituminous coal with inlet SO 2 concentrations as high as 3.0 lb/MBtu. However, the higher efficiency also typically results in lower lime utilization for both processes.

SO 2 removals chosen for the dry systems in this study are given in Table 3. SO 2 removals include removal that occurs in a subsequent ESP or baghouse. SO 2 removals for the spray-dryertype absorber are based on likely outlet SO 2 emission limit guarantees available for the coal types used in the study. SO 2 removals for the CFB-type is higher but is assumed to be accompanied by lower lime utilization.6 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. SO 2 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 SO 2 removal, % 94 93 95 95 SO 2 emission, lb/Mbtu 0.12 0.10 0.10 .072 Reagent ratio, moles of Ca/mole of inlet SO 2 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 approximately7 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 CaSO 3 , CaSO 4 , CaCO 3 , 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 li ghtweight 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, power8 required for oxidation air compressors, power for ball mills/slakers, power for gypsum dewatering system, and various electrical and cont rol 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 MW net

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 MW net : New Unit 0.65 0.70 0.80 0.90 Retrofit 1.1 1.2 0.80 0.909 

### 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 SO 2 (5% to 10%), placing a high burden on the dry FGD for SO 2 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% SO 2 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 SO 2 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 CRITERIA10 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 SO 2 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

SO 2 oxidation stoichiometry (moles O fed/mole SO 2 removed) 3.0 3.011 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

SO 2 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 implementa tion 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.12 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 rega rding 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 Opera ting 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 6,169,00014 Table 12. First-Year Fixed and Variable Operati ng 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 Opera ting 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 6,180,00015 Table 14. First-Year Fixed and Variable Operati ng 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 includes16 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 Leveliz ing 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 0.4317 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 0.6218 

### 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, $/tonLimestone 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, $/tonLimestone cost, $/ton Wet lime process favored

Wet limestone process favored Basis: 3% sulfur Retrofit 80% CF $ 30/Mwhr19 2. New Unit Vs. Retrofit Unit

3. Auxiliary Power Cost

Using high sulfur coal, the following three graphs s how the affect that auxiliary power costs have on the choice of reagent (limestone vs. lime) for thr ee 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, $/tonLimestone 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, $/MWHIncrease 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/Mwhr20 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 HIncrease 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 HIncrease 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/Mwhr21 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 HIncrease 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 HIncrease 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/Mwhr22 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 HIncrease 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/Mwhr23 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 th e 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/Mwhr24 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/Mwhr25 

### Conclusions

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

2. Because of a generally higher capital cost for re trofit 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 un its 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 n early as important as the differential cost between LSFO and MEL technologies.