Tetra Tech, Inc.

10306 Eaton Place, Suite 340

Fairfax, VA 22030

phone 703-385-6000

fax 703-385-6007

DATE: March 9, 2011

TO: Paul Shriner, EPA

FROM: John Sunda, SAIC a

SUBJECT: Repowering and 316(b)

Power plant repowering is simply the “r

the combustion technology with a new combustion technology, usually resulting in better 

performance and greater capacity” (DOE 2009). As power plants age, the ge

become less efficient and prone to higher 

additional maintenance requirements of older combustion equipment may also result in more 

frequent maintenance outages, reducing the equipment reliability

operation less economically attractive

equipment. In addition, new restrictions on environmental emissions create requirements that 

older technologies may not be capable of m

installation of expensive abatement 

restrictions may result in the need to derate (reduce power output)

power demand or high source-water temperatures. 

adding capacity or using other, often 

As aging plants become less cost

less frequently, resulting in progressively 

retired. At the same time, the demand 

US is constantly increasing. Power companies generally have two a

these problems: 1) construct new g

existing facility to replace the capacity of older generating systems that are eventually retired

2) refurbish (repower) existing generating facilities. 

companies often involve a mix of both options

considerations. 

MEMORANDUM

Paul Shriner, EPA

John Sunda, SAIC and Kelly Meadows, Tetra Tech

and 316(b)

epowering is simply the “refurbishment of a plant by replacement (or upgrade) 

the combustion technology with a new combustion technology, usually resulting in better 

performance and greater capacity” (DOE 2009). As power plants age, the generating units 

and prone to higher operations and maintenance (O&M) costs

dditional maintenance requirements of older combustion equipment may also result in more 

frequent maintenance outages, reducing the equipment reliability. These factors

operation less economically attractive when compared to newer, more efficient processes and 

estrictions on environmental emissions create requirements that 

older technologies may not be capable of meeting without equipment modifications or 

abatement technologies. In some cases, the environmental emission 

in the need to derate (reduce power output), especially at times of pe

water temperatures. The derated capacity must be made up by 

often less cost-efficient generating systems. 

become less cost-efficient than the newer systems, over time they are 

progressively lower capacity utilization rates, and may eventually be 

the demand for increased power generating capacity throughout the 

Power companies generally have two alternatives for 

construct new greenfield generating plants or add new generating units at an 

the capacity of older generating systems that are eventually retired

existing generating facilities. The strategies employed by power 

companies often involve a mix of both options and are driven mostly by economic 

(or upgrade) of 

the combustion technology with a new combustion technology, usually resulting in better 

nerating units 

costs. The 

dditional maintenance requirements of older combustion equipment may also result in more 

make their 

more efficient processes and 

estrictions on environmental emissions create requirements that 

equipment modifications or 

nvironmental emission 

especially at times of peak 

The derated capacity must be made up by 

over time they are operated

and may eventually be 

increased power generating capacity throughout the 

lternatives for dealing with 

or add new generating units at an 

the capacity of older generating systems that are eventually retired or 

The strategies employed by power 

and are driven mostly by economic 
- 2 -

This memo discusses repowering of existing combustion-based generating plants using 

combustion-based systems1and does not address the addition of new capacity.

Repowering is an attractive alternative because it can simultaneously address issues regarding 

load growth, environmental compliance and technological obsolescence. Improvements that can 

be achieved through repowering include some or all of the following possibilities (Stenzel et al

2009):

 It may be the least-cost option for increasing generation capacity

 It can minimize capital cost expenditures 

 It can reduce overall system fuel usage and/or costs

 It can reduce O&M costs

 It can reduce emissions and other discharges

 It can reduce water usage per KW generated

At any given facility, repowering projects can involve existing units still in operation or 

generating units that have been retired and inactive for a number of years. Repowering projects 

often help meet increasing load demand by increasing the power output of an existing plant. The 

increased output may result from both the use of more efficient equipment and combustion 

processes, as well as the addition of combustion capacity and generating equipment. In some 

cases, repowering does not result in an increase in the generating capacity. The goals of such 

projects often include reducing costs, reducing emissions, improving reliability, or changing the

fuel used or allowing for more flexibility in the type of fuel used.

Repowering an existing facility has numerous advantages over building a greenfield facility to 

meet electricity demand or replace the capacity of inefficient or retired existing generating units.

Repowering projects avoid some of the problems associated with greenfield projects and may

offer the following advantages:

 Avoid the difficulty and public resistance to the siting of new transmission lines

associated with new facilities

 Avoid the difficulties and public resistance to the siting of new plant facilities

 Avoid the difficulties of obtaining environmental permits for new facilities

 Can reduce investment costs by utilizing existing equipment, structures, and land

 Can utilize existing transmission and steam distribution equipment

 Can utilize existing utility connections and fuel delivery systems

 Can utilize existing highway and rail access

 Can utilize existing trained staff

 Can utilize existing cooling water intake and discharge equipment, structures, and 

permitted water withdrawal capacity

 

1 Note that such efforts do not necessarily run counter to goals of reducing the proportion of power generated using 

fossil fuels and increasing the use of renewable resources. Combustion-based repowering can help meet these goals 

by increasing the efficiency of combustion-based processes (resulting in reduced fossil fuel use) and, in some cases,

by replacing the use of fossil fuels with use of renewable fuels such as biomass or waste materials.
- 3 -

Fuel efficiency is of the utmost importance at power plants. Even small increases in plant 

efficiency of 1% to 2% can result in substantial financial benefits. For example, a 1,000 MW

coal-fired plant with an initial thermal efficiency of 36% LHV (lower heating value) and a fuel 

cost of $2 per Million BTU will expend over $150 million annually in fuel costs alone. If the 

plant efficiency were increased by just 1% to 37%, the annual fuel savings would be 

approximately $4 million. Thus, historically, power plants have been willing to invest 

substantial quantities of money for even small increases in plant efficiency. Repowering can 

provide for substantially larger increases in efficiency as shown in Table 1.

 

Repowering Options

Many existing facilities have multiple generating units of various ages and many of these units 

may be infrequently used or retired. Increasingly, facilities are evaluating the possibility of 

repowering existing generating units. These generating units may have different designs, ages, 

equipment conditions, and fuel types. Repowering may involve the replacement of the entire 

system, the replacement of a portion of the system, or the addition of new combustion/generating

equipment that is incorporated into the existing system. In many cases, especially if the steam 

turbines are in relatively good condition, the existing steam turbine equipment remains in use 

and additional non-steam generation capacity is added. In such a case, the cooling water design 

flow requirement would remain the same. As noted above, there is generally a greater incentive 

to repower or replace the older steam units that tend to cost more and generate more 

environmental emissions per KWh generated.

Many of the repowering technologies involve the use of combustion turbines either alone or,

more often, in conjunction with steam cycle power generation. The combination of combustion 

turbines with steam cycle power generation, also known as combined cycle, generally results in a 

much more efficient system than the use of either alone. Combined cycle generating systems 

offer greater flexibility in their application because they can be started up and shut down more 

rapidly than steam generation systems and thus can function more efficiently as intermediate 

load and peaking load facilities in addition to base load applications.

In order to operate reliably, the high pressure combusted gas stream that powers the combustion 

turbines must be relatively free of ash and particulates to prevent problems associated with 

deposition and erosion from affecting the turbine blades. Liquid and gaseous fuels typically

generate fewer quantities of ash or particulates and thus are the preferred fuels used to power 

combustion turbines. The exceptions are solid fuel systems that either convert the solid fuel to a 

combustible gas that can then be used as fuel in combustion turbines, or that combust the solid 

fuel under pressure and then remove the ash and particulates prior to passing the pressurized 

combustion gases through the gas turbines. Some turbines are designed to be more compatible 

with slightly elevated ash and particulate levels.

Some repowering projects may involve the replacement of existing generating equipment that 

utilizes steam as a prime mover with generating equipment that does not use steam (e.g., 

combustion turbines). Generating units that use combustion turbines alone are most often used 

to provide peaking power because they can be rapidly started up and shut down, but are 

generally not as efficient as new steam power and combined cycle systems. Wherever existing 
- 4 -

steam generating capacity is replaced with combustion generating capacity, the cooling water 

requirement will be reduced. This option, however, is not discussed in detail here.

The various types of repowering options that can be applied at existing steam cycle generating 

systems are described below. These are divided into two main groups: combustion turbine-based 

systems which generally involve the use of gas or liquid fuel to power the combustion turbines; 

and solid fuel-based systems which use coal or other solid fuels to power the system.

Combustion Turbine-Based Repowering Options

The following repowering options use combustion turbines and combined cycle technologies that 

may replace the existing generating system, provide supplemental energy to an existing system, 

or be integrated into an existing system with replacement of portions of the existing equipment. 

Each option results in a system that is more efficient and often has a higher total power output 

than the existing system. All of these systems use gas or liquid fuels to power the added 

combustion turbine technology. In systems where the existing boiler remains in operation, the 

existing boiler may continue to use the same fuel type as before. Otherwise, if the existing 

system does not use natural gas or oil, then the repowering may involve a complete conversion 

of the type of fuel used.

Site Repowering or Full Repowering involves the demolition of the existing generating units

(except for possibly the cooling water system, switchyard, and other ancillary systems and 

building structures), followed by the construction of a new combined-cycle or other type of plant

in its place. In some cases, if space allows, the old system may be kept in operation while a 

portion or all of the new system is constructed nearby. Site repowering is commonly used at 

very old plants where the boilers and steam turbines are at the end of their useful lives. It is 

considered one of the simplest ways of repowering an existing plant.

Combined Cycle Repowering (CCR) involves the replacement of the existing boiler by a 

combustion turbine and a heat recovery steam generator (HRSG). The HRSG generates steam 

using heat from the combustion turbine exhaust gases. Steam from the HRSG then powers the 

existing steam turbines. The old boiler and furnace may be demolished first or the new 

combustion turbine and HRSG power block may be constructed on an adjacent location with the 

HRSG steam replacing the existing boiler as the steam source only after construction is 

completed. Combined cycle repowering is the most common type of repowering currently being 

implemented in the U.S. 

Hot Windbox Repowering (HWBR), also known as Topping, involves the conversion of a steam 

cycle unit to combined-cycle where the existing boiler remains intact and a gas turbine is added 

to the system such that exhaust hot gases from the gas turbine replace all or a portion of the 

combustion air entering the existing conventional steam boiler-turbine unit. The hot exhaust 

from the gas turbine is used as preheated combustion air in the existing boiler. Thus, the 

additional fuel used in the gas turbine will offset some of the fuel requirement for the existing 

boiler, providing an increase in system efficiency associated with a combined cycle system while 

maintaining the existing boiler steam output conditions at which the existing steam turbines are 

designed to operate most efficiently. Partly because the combustion now has a lower oxygen 
- 5 -

content, this type of conversion involves the highest degree of technical complexity of all the 

combustion turbine-based repowering options. The added combustion turbine contributes a 

relatively small amount of the total power to this configuration. Therefore, the final efficiency of 

a HWBR unit will be dominated by the efficiency of the larger steam cycle. For this reason, 

existing units that already have the capability of being more efficient will be preferred candidates 

for HWBR.

Feedwater Heater Repowering (FWHR), also known as Boosting, involves the addition of a 

combustion turbine with the exhaust gas from the combustion turbine being used to heat the 

boiler feedwater in the existing steam-cycle power plant. In a conventional steam turbine unit,

some of the boiler steam is diverted to heat the boiler feedwater which starts out at the relatively 

low temperature of the condensed steam in the condensers. By replacing this diverted steam 

with another heat source, additional power can be produced by the additional steam sent to the 

steam turbine-generator. Also, power generation is augmented by the combustion turbine. The 

benefit of additional steam turbine generation occurs only if the design limits of the steam 

turbine are not exceeded. The existing feedwater heaters can be retained to allow for 

conventional operation when the combustion turbine is not needed or out of service.

Supplemental Boiler Repowering (SBLR) involves adding combustion turbines with the exhaust 

gases being used in an HRSG that provides additional steam to directly supplement the steam

supplied by the existing boiler used to power the existing steam turbines. The economics of this 

configuration depend greatly on the ability to use the additional steam efficiently in the turbine 

generator and/or whether the existing boiler has steam generation limitations that result in the 

steam turbines not being able to operate at their full power capability.

Parallel Repowering (PR) involves adding a combustion turbine and an HRSG that supplies

steam to the existing steam turbines. This application is similar to SBLR except that in SBLR 

the existing boiler remains in operation continuously, while in PR the existing boiler only 

operates for peak and intermediate loads. The steam from the existing boiler is added to the 

steam from the HRSGs at several pressure levels, depending on the condition and capability of 

the existing steam turbines.

Solid Fuel-Based Repowering Options

Most solid fuels tend have a lower cost than natural gas or liquid fuels such as fuel oil. Where 

low cost solid fuels are already in use or are available, repowering with solid fuel-based 

technology may be selected for the cost advantages. Solid fuel options tend to have higher upfront capital costs and therefore are more suited to systems requiring a higher capacity factor in 

order to recover the investment. Systems that use the newer fluidized bed combustion 

technology are capable of switching between a variety of solid fuels. Being able to alternate 

between different solid fuel types provides the opportunity to utilize lower-cost fuels such as 

high ash coals and waste materials (e.g., petroleum coke) or to use fuel blends, and allows the 

flexibility to take advantage of variations in fuel availability and costs over time. The use of 

lower-cost solid fuels can offset the higher capital costs and generally lower efficiencies of these 

solid fuel systems. The following repowering options are available for use with solid fuels.
- 6 -

Atmospheric Fluidized Bed Combustion Repowering (AFBC) involves replacing the existing 

boiler with a fluidized bed combustion process. The new boiler is either designed to match the 

existing steam turbine or the turbine system is upgraded to a more efficient system. Fluidized 

bed systems have the benefit of reducing air pollution emissions exiting the boiler by burning 

fuel at temperatures low enough to minimize NOX and by reducing SOX through use of sulfur

absorbents such as limestone inside the combustion chamber mixed with the fuel as a bed 

material.

Pressurized Fluidized Bed Combustor Repowering (PFBC) involves replacing an existing boiler 

with a pressurized fluidized bed combustor to produce steam to drive the existing steam turbinegenerator and to generate pressurized hot gases that drive combustion turbines. Hot gases from 

combustion turbines are used to generate steam in an HRSG to power existing steam turbines.

This technology, also referred to as first-generation PFBC, uses a “relatively stationary fluidized 

(bubbling) bed” using relatively low air velocities to fluidize the material. A boiler tube bundle 

is immersed in the bed to generate additional steam to power the steam turbines. Particulate 

matter is removed from the flue gas using cyclone separators prior to the flue gas entering a gas 

turbine. The gas turbines are designed to accept a moderate amounts of particulate matter.

PFBC technology introduces some significant operating complications to the fluidized bed 

combustion process in that solid fuel, sorbent, and air must be transferred into a pressurized 

process vessel and ash transferred out.

Pressurized Circulating Fluidized Bed Combustor Repowering (PCFBC) is similar to PFBC and 

is referred to as the second-generation pressurized fluidized bed combustion process. PCFBC 

uses a “circulating fluidized bed” that uses higher air flow volumes to circulate fuel and sorbent 

in the fluidized bed combustor. This technology uses a number of efficiency enhancement 

measures, including the integration of a coal gasifier or carbonizer to produce a fuel gas that is 

combusted in a separate topping combustor that adds to the flue gas energy from the fluidized 

bed combustor that powers the gas turbine (DOE 2009). This technology is still in the 

development stage.

Gasification Combined Cycle Repowering (GCC), also known as IGCC, involves addition of a 

solid fuel gasification system, a gas processing system, a combustion turbine, and an HRSG. 

This system replaces the existing boiler. The gasification system converts a solid fuel to a 

gaseous fuel (syngas) used in the combustion turbine, with the hot exhaust gases generating 

steam in the HRSG. Steam is also generated in a heat exchanger in the solid fuel gasification 

process. Steam from both the solid fuel gasification process and the HRSG powers the existing 

steam turbine. In the gasifier, solid fuel is typically exposed to steam and carefully controlled 

amounts of air or oxygen under high temperatures and pressures. Under these conditions, the 

solid fuel breaks down into a mixture of carbon monoxide, hydrogen and other gaseous 

compounds. The gasification process can also produce other products that have commercial 

value, such as sulfur and an inert slag.

The primary benefit of this technology is that air emissions are substantially reduced. Also, CO2

removal for sequestration (if required in the future) can be done at lower costs than at 

conventional coal power plants because the CO2 can be removed under pressure during the 

syngas processing step. In addition, combustion turbines which run on syngas can generate more 
- 7 -

power. The syngas is a low heat-content gas and gas turbines that are run on low heat-content 

fuel (BTU/gm) must have more fuel injected in order to reach their operating limits, such as 

combustion temperature. The resulting higher power output is due to the fact that there is more 

mass impinging on the turbine blades, which results in greater energy output from the turbines. 

For example, a GE Model 6FA turbine has a power rating of 70 MW using natural gas and a 

power rating of 90 MW using syngas (GE 2009).

Table 1 presents a summary of some of the attributes of each of the repowering options listed 

above. It shows the relative capital investment costs when compared to a full repowering option 

for a combined cycle system of comparable generating capacity. It also shows potential 

increases in capacity and system efficiency and construction outage times where available.

Other Modifications

Repowering can also include replacement and modernization of various components of the 

power plant.2This can include replacement or upgrade of the existing steam turbines and other 

options described below:

Steam Turbine Upgrade — Replacement or upgrade of existing steam turbines may be necessary

to optimize system efficiency and capacity, and to match new design specifications. In one 

example, upgrading the turbines alone increased output by 7% (Hong Kong Electric Co. 2000).

Instrumentation and Controls — Instrumentation and control systems at older plants can be 

upgraded and “tuned,” such that plant efficiency could be increased by 4% to 7% by allowing the 

boiler and turbine generator to work at their optimum operational control points (Ferrer and 

Kishinevsky 2008).

Electrical Systems — The use of variable frequency drives for boiler feed and condensate 

pumps, induced draft fans and forced draft fans can provide precise speed and load control with 

the potential for increased efficiency of up to 2% at reduced loads (Ferrer and Kishinevsky

2008). Also, modest increases in plant efficiency can be achieved by conducting a study of plant 

power use and minimizing power use by making improvements such as upgrading HVAC 

systems.

Other Improvements — Other improvements could be made to the power cycle to increase the 

overall cycle efficiency by as much as 4% to 6% (Ferrer and Kishinevsky 2008). Such 

improvements include:

 Minimizing excess air and improving combustion control

 Improving cooling tower performance

 Improving condenser performance by installing on-line condenser cleaning

The individual percent increases in efficiency listed above are not necessarily cumulative. 

Opportunities for each will be dependent on the design and condition of each system.

 

2 Also see DCN 10-6633 for a discussion of uprates at nuclear plants; uprating involves a similar process to improve 

generating capacity.
Table 1. Summary of Repowering Technology Options

Type Brief Description Comments Performance and Costs Increased 

Capacity

Change in 

Efficiency *

Relative 

Investment**

Outage 

Time 

Months

Site 

Repowering or 

Full 

Repowering

Entire existing unit is 

demolished and replaced

Simplest method Performance same as new greenfield facility. 

Can save approximately $106 to $300 per KW

compared to Greenfield, excluding land costs.

150% to 

200%

Up to 20% 100%

Combined 

Cycle 

Repowering

(CCR)

Replace boiler with 

combustion turbine and 

heat recovery generator

Most common type of 

Repowering in US

Reduces heat rate by 30% to 40%. 150% to 

200%

12% to 17% 70% to 85% 12 to 18

Hot Windbox 

Repowering 

(HWBR)

Add combustion turbine 

with exhaust gases 

replacing all or portion of 

combustion air source for 

existing boiler

High degree of technical 

complexity. Competitive 

for larger, newer efficient 

oil/gas-fired units.

Increase capacity 0% to 25%. Increase 

efficiency by 10% to 20%. Costs $150 to $250

per KW total repowered capacity.

0% to 25% 3% to 6% 20% to 30% 8

Feedwater 

Heater 

Repowering 

(FWHR)

Add combustion turbine 

with exhaust gasses used 

to heat boiler feedwater

Useful when additional 

peaking capacity is 

needed.

Costs $90 to$110 per KW for smaller fossil 

steam units to $75 to $80 per KW for larger 

units.

10% to 30% 2% to 6% 15% to 20% 2

Supplemental 

Boiler 

Repowering 

(SBLR)

Add combustion turbine 

and HRSG which provides 

supplemental steam to 

existing turbines

Useful where existing 

steam turbines can handle 

more steam than boilers 

produce. 

Benefit dependent on ability to use additional 

steam efficiently.

2

Atmospheric 

Fluidized Bed 

Combustion 

Repowering 

(AFBC)

Replace existing boiler 

with a fluidized bed 

combustion process

Benefits are ability to use 

a variety of solid fuels and 

reduced emission of air 

pollutants 

Plant performance is essentially unchanged 

except for reduction in air emissions. 

Reduced operating costs when using low cost 

fuels. 

0% 0%

Pressurized 

Fluidized Bed 

Combustor 

Repowering 

(PFBC)

Replace boiler with a 

pressurized fluidized bed 

combustor to drive 

combustion turbines and 

produce steam for existing 

turbines

Benefits are ability to use 

a variety of solid fuels, 

reduced emission of air 

pollutants, and increased 

plant efficiency. Available 

for units ranging from 80

to 350 MW. 

Has the benefit of increased efficiency of 40% 

to 45% and potential for up to 50% for 

advanced 2

nd generation systems. The 

proportion of power coming from the 

steam:gas turbines is approximately 80%:20%

Up to 100% Up to 12% 150% to 200%

Gasification 

Combined 

Cycle 

Repowering 

(GCC)

Add gasification system, 

combustion turbine and 

HRSG to provide steam to 

existing steam turbines

Only one repowering 

demonstration has been 

performed in US.

Expected efficiencies are in the 40% to 45% 

range. Gasification process results in 

relatively high capital costs, in the range of 

$1,200 to $2,000 per KW. 

165% Up to 7% 200% to 300%

* Numerical difference in efficiency.

** Relative to investment for new combined cycle of same capacity.

Sources: Stenzel et al; Shahnazari et al 2003. 
9

Repowering Decision Making

The decision of whether to repower and the selection of a system from the many options 

available requires an in-depth evaluation of many financial and technical considerations and how 

these relate to the available repowering options. Such an evaluation could take the following 

steps:

1. Determine the generating system goals, including consideration of the following items 

and/or other requirements and goals:

 Projected generating load schedules and requirements

 Value of needed power and forecasted market price

 Air emissions and discharge reductions

2. Identify site restrictions to help determine if the existing plant can be repowered to meet 

the generation goals. This could include consideration of:

 Air emissions and discharge limits

 Transmission requirements and limitations

 Equipment age and condition

 Site access

 Technology option limitations

 Permitting requirements

3. Identify candidate repowering technologies, including those identified earlier in this 

document, and perform an initial analysis to help narrow the list down to the most 

competitive technologies.

4. Develop preliminary technology design and costs for each candidate technology, 

including operation parameters, and conduct a financial analysis, including consideration 

of:

 Projected fuel availability and costs

 Anticipated regulatory changes

 Investment capital costs

 System O&M costs

 Schedules

 Future revenue and return on investment

5. Select the best option based on the results of the analysis.

The analysis of each repowering option must take into consideration many factors, some of 

which may be based on uncertain projections and assumptions. As such, general rules-of-thumb 

and simple engineering analyses generally will not suffice in performing such a complex

analysis. To assist in this decision making process, the Electric Power Research Institute (EPRI)

has made available a suite of software tools entitled State-of-the-Art Power Plant (SOAPP®). 
10

SOAPP® includes numerous software modules, with the two most relevant to repowering being 

the “SOAPP® Repowering Screening Module” and the “SOAPP® REPO CC WorkStation.”

These software tools are available from EPRI for a fee.

The SOAPP® Repowering Screening Module conducts a screening analysis that provides a 

preliminary assessment of the viability of repowering an existing unit and location considering 

use of different technologies (including CCR, HWBR, SBLR, FWHR, CFBC, PFBC, and GCC). 

The Screening Module will identify major site-specific limitations and estimate technology

performance and costs, enabling the user to identify which technology options are worth 

evaluating further in a more detailed analysis.

Once the technology options have been narrowed down using the Screening Module, another 

software tool, the SOAPP® REPO CC WorkStation can then be used to provide a more in-depth 

analysis for repowering options that involve combined-cycle repowering of existing fossil steam 

plants. The WorkStation allows for input of detailed site-specific data and can generate any or 

all of the following conceptual design deliverables:

 Design criteria 

 Equipment reuse plan 

 Heat balance 

 Performance and emissions summaries 

 Equipment list (includes sizing) 

 Process flow and piping diagrams 

 General arrangement drawings 

 Capital cost estimates 

 O&M cost estimates 

 Financial analysis

The WorkStation allows evaluation of numerous equipment options and configurations, allowing 

the user to change input variables and option selections in order to conduct sensitivity analyses 

and select the optimum system design from multiple options and scenarios. SOAPP® can 

replace the need to employ a team of engineering staff or outside consultants that would be 

necessary to conduct a similar analysis.

Fuel Selection

Factors that influence fuel selection include fuel availability, fuel costs, system efficiency, 

technology costs, technology reliability, air pollution limits, and waste disposal costs. Table 2 

presents electricity generation fuel costs (in dollars per million BTU heat content) projected by 

the DOE Energy Information Administration (EIA) for coal, natural gas, and two types of oil for 

2007 through 2010. As can be seen, based on energy content, the cost of natural gas and oil 

ranges from about three to ten times higher than the cost of coal. These costs, however, do not 

necessarily reflect power generation costs because they do not take into consideration the 

different efficiencies of different types of combustion systems.
11

Table 2. Projected Fuel Costs Based on Heat Content

Fuel Type Unit 2007 2008 2009 2010

Coal Dollars/Million BTU $1.77 $1.94 $1.92 $1.88

Natural Gas Dollars/Million BTU $7.02 $9.18 $6.32 $6.47

Distillate Fuel Oil (#2) Dollars/Million BTU $14.77 $19.05 $14.61 $14.61

Residual Fuel Oil (#6) Dollars/Million BTU $8.38 $13.77 $8.01 $12.32

Source: DOE EIA 2008 (Table 3).

Table 3 shows the effects that different combustion system efficiencies have on fuel costs for 

generating electricity. Table 3 presents the calculated fuel costs per MWh for conventional 

steam boilers and combined cycle systems, based on the assumed heat rates shown in the table 

using the projected year 2010 fuel costs from Table 2. The fuel costs for combined cycle are

shown for both a low efficiency system (heat rate = 7,000 BTU/KWh) that might be expected for 

a repowered or older system and for a newer high efficiency system (heat rate = 6,000 Btu/KWh) 

that represents the upper end of possible combined cycle system efficiencies As can be seen, 

even when the highest efficiency combined cycle technology is factored in, the fuel cost in 

dollars per MWh for combined cycle using natural gas is still several times higher than the fuel

cost for a conventional coal-fired steam plant. 

Table 3. Fuel Costs per MWh Power Generated for Different Types of Generating Systems 

Using 2010 Projected Fuel Costs

From the mid-1990s until about 2002, the cost of natural gas was in the $2-$3/MMBTU range 

and as a result construction of natural gas-fired combined cycle power plants dominated new 

capacity additions in the US. Since fuel costs account for about 70% of operating expenses, the 

recent run-up and volatility in natural gas prices have put natural gas-fired combined cycle plants 

at a competitive disadvantage economically compared to conventional coal-fired plants, and as a 

result many combined cycle generating units have reduced their capacity utilization rates 

(Donaldson and Mukherjee 2006). This has increased the economic viability of the 

consideration for repowering using solid fuel-based systems, including replacing all or a portion 

of the natural gas at existing combined cycle generating units with syngas derived from coal 

using GCC technology. For facilities that are currently fueled by oil or natural gas, repowering 

using combined cycle technology is still an attractive option due to the higher generating 

efficiencies. 

Units

Conventional 

Steam Boiler at 

38% Efficiency

Combined 

Cycle at 49% 

Efficiency

Combined 

Cycle at 57% 

Efficiency

Assumed Heat Rate BTU/Kwh 9000 7000 6000

Coal Dollars/MWh $16.9 NA NA

Natural Gas Dollars/MWh $58.2 $45.3 $38.8

Distillate Fuel Oil Dollars/MWh $131.5 $102.3 $87.7

Residual Fuel Oil Dollars/MWh $110.9 $86.2 $73.9
12

Despite the higher fuel price, natural gas as a fuel source is still attractive because it produces 

lower air emissions. The need for construction and operation of additional air pollution control 

equipment and for waste disposal add to the cost of using solid fuels. The prospect of future 

limits on carbon dioxide emissions from climate legislation will add another important economic 

factor to be considered in the fuel selection decision, and will favor fuels and generating systems 

with low specific CO2 emissions (gm/KWh). Table 4 presents the range of specific CO2

emission rates for different fuel types and different combustion system generating efficiencies. 

The table shows the typical range of efficiency for gas turbines (GT), steam power plants (SPP), 

and combined cycle power plants (CCPP). 

Table 4. Specific CO2 Emissions Rates for Different Fuels 

and Different Combustion Technologies

Source: Fränkle 2006.

While natural gas has the best performance with respect to reducing CO2 emissions, as discussed 

above it is a more expensive fuel and is more prone to price fluctuations and concerns about 

ability to meet future demand. Solutions for reducing high CO2 emission rates (especially for 

coal-fired power plants), such as CO2 sequestration technology (which is still in the development 

stage), will add to the capital and operating costs of power plants fueled by coal. However, the 

proven coal reserves in the US, the expectations that the price of coal will remain low relative to 

other fuels, and the availability of transportation infrastructure at many existing facilities makes 

coal an attractive fuel source for future repowering options. 
13

The current uncertainty about the future costs of climate legislation, along with public 

opposition, has slowed the pace of construction of new coal-fired power plants. This, combined 

with the uncertainty of future fuel prices, has injected a great deal of uncertainty into the 

reliability of current projections regarding repowering and new capacity additions. Once the 

specific requirements of climate legislation are established and the magnitude of the cost of CO2

emissions becomes clear, power companies will be better able to predict the costs of each fuel 

option.

The availability and cost of transporting different fuel types will also play a role in fuel selection. 

It will affect the cost of the fuel, as well as the cost of constructing the necessary transportation 

infrastructure for fuels not currently available at the site. Proximity to natural gas mainlines is an 

important factor in determining the costs of repowering with natural gas. Because of these 

differences in availability and costs, the mix of repowering options selected will vary in different 

regions of the US. Also, in areas where existing air pollution levels are high, the selected fuels 

and repowering options will tend to be limited to those that minimize air emissions.

Projecting Future Repowering for former Phase II Facilities3

EPA’s economic impact analysis includes future projections of changes in available generating 

capacity. The analysis, which uses the IPM model, provides projections for generating capacity

changes during the years 2013, 2015, 2017, and 2020. These projections distinguish between

existing capacity that is retained, capacity of units that are repowered, and new capacity 

additions. The existing capacity retained and the capacity of units repowered is estimated for 

each facility on an individual unit level. Thus, the IPM model can provide a spreadsheet 

identifying specific predictions as to which facilities and units will be repowered. New capacity

additions are only projected on a NERC regional basis, and do not identify whether these 

capacity additions will be at greenfield sites or new unit construction at existing power plants

(e.g., a full repowering at a retired facility). It is probably reasonable to assume that, in most 

cases, the new capacity would be required to meet more stringent 316(b) limits commensurate 

with the 316(b) Phase I Rule. 

Repowering as defined in the in the IPM model typically consists of the conversion of existing 

oil/gas or coal capacity to new natural gas-fired combined-cycle capacity. The baseline IPM 

model unit-level projection for the period through 2020 lists only one coal plant as being

repowered using combined cycle and one unit at another coal facility as being repowered from a 

coal plant to coal using IGCC. Total repowered capacity for both was less than 200MW. The 

remainder of the repowering was projected to be oil/gas-fired plants converted to combined 

cycle. A comparison of the new capacity of the repowered units to the capacity before 

repowering for all those units projected to be repowered in the US through 2020 shows that the 

projected increase in capacity for each unit ranges from a factor of 1.05 to 2.78, with most being 

assigned a factor of 2.78. The weighted average increase in capacity for generating units

repowered through 2020 is approximately 2.5. 

 

3 The scope of this analysis was limited to only large power plants that would have been regulated under the 2004 

Phase II rule. The electric generating facilities in Phase II reflect 91% of total cooling water withdrawals and 87% of 

steam capacity (based on 2007 EIA data).
14

Table 5 provides a summary of the IPM model projections for generating capacity for new 

generating units and existing generating units repowered using combined cycle repowering for 

the years 2013, 2015, 2017, and 2020. Capacity data for NERC regions and total US are 

included. These projections are for the baseline regulatory condition (i.e., they do not include 

consideration of 316(b) requirements). The baseline unit generation data is the 2003 EIA 

generating unit data with some modifications that include more recent plant changes. The total 

baseline generating capacity for in-scope facilities that served as input for the IPM model was 

453,820 MW. 

Table 5 shows the expected magnitude of repowering activities compared to new capacity 

additions by presenting the totals as a percent of this baseline capacity. The values shown for 

each year are cumulative totals. Note that the repowered capacity projections represent the total 

capacity of the repowered generating units (including existing capacity), and that the added 

generating capacity for repowering is approximately 60% (1 - 1/2.5) of the total repowered 

capacity shown. 

Table 5. Estimated Generating Capacity for New Generating Units and

Existing Generating Units Repowered Using Combined Cycle Repowering

Source: Example IPM Model Output, Abt Associates 2009.

Table 5 shows that the IPM model predicts that initially the majority of added generating 

capacity will be from repowering and that the addition of new capacity from construction of new 

units will accelerate over the period. By 2020, roughly two thirds of added capacity will be from 

new additions. Thus, the existing facility rule, which generally applies to repowered facilities,

could apply to a substantial portion of new generating capacity over the period. Of course, this 

data represents the IPM model baseline conditions and does not include the projected effects of 

promulgation of the proposed rule. 

While the IPM model provides a fairly rigorous projection, it is based mostly on the dynamics of 

the electricity market and the projections regarding which facilities will be repowered may not be 

very accurate due to limitations of the model inputs. Potentially more accurate information on 

NERC Region 2013 2015 2017 2020 2013 2015 2017 2020

ERCOT 12 12 64 3,051 6,429 9,806 14,403 14,403

FRCC 40 40 40 4,687 13,215 15,946 19,914 19,914

MRO 0 43 1,244 2,828 25 25 25 25

NPCC 1,417 4,330 4,354 8,450 2,489 2,489 3,710 3,710

RFC 1,444 3,337 7,783 14,355 2,661 2,661 5,785 5,785

SERC 894 3,264 8,748 20,446 0 0 1,533 1,533

SPP 5 986 2,763 4,689 0 0 738 738

WECC 995 5,723 7,815 16,752 9,084 9,084 12,445 15,661

Total 4,808 17,735 32,811 75,258 33,904 40,012 58,554 61,770

Percent of Total 

Generating Capacity 1.0% 3.7% 6.7% 15.4% 7.2% 8.4% 12.0% 12.6%

Total Generating 

Capacity 472,206 476,619 487,038 489,478 472,206 476,619 487,038 489,478

Capacity - New Additions (MW) Capacity - Repowered Units (MW)
15

future capacity additions and repowering activities is also available from RDI Consulting for a 

fee. However, given the current uncertainty with respect to the costs of climate legislation, fuel 

costs, and technology development, even this potentially more accurate projection may still

include a great deal of uncertainty.

Effect of Repowering on Cooling Water Flow Requirements

Changes in cooling water requirements for repowered facilities will be dependent on the changes 

that occur in the capacity and utilization of the steam cycle component of each repowered 

generating unit. With the exception of full repowering, most of the repowering options involve 

the addition of combustion turbine-based technology to provide for an increase in the system 

generating capacity, while making at most only modest changes in the capacity of the steam 

cycle component. Thus, for most repowering options, the cooling water design flow or 

maximum flow requirement at full power for each repowered generating unit will not increase,

while at the same time the generating capacity may increase up to 200% depending on the 

technology selected. Repowering options that result in an increase in the amount of steam 

supplied to the steam turbines may result in a slight increase in the heat load processed through 

the condensers and thus result in an increase in the cooling water flow or an increase in the 

temperature rise across the condenser. However, for most repowering projects, the design 

cooling water flow requirement is not expected to change significantly.

The same is not true for the average intake flow or total flow over a given period. As noted 

earlier, units selected for repowering will tend to be those that are less efficient and more costly 

to operate. As a result, they will tend to be operated at lower capacity utilization rates, meaning 

they will be operated less often and at lower power and will tend to use less cooling water. Since 

repowering often results in an increase in efficiency and a decrease in the cost of generating

electricity, the repowered units will likely be operated more frequently, resulting in a higher 

capacity utilization rate after repowering which will likely result in an increase in both the 

average intake flow and the total flow over time. This is particularly true for plants where 

existing gas- or oil-powered units are repowered with combined cycle. Thus, repowering has the 

potential for resulting in an increase in average intake flow and thus an increase in impingement 

mortality and entrainment.

Plants that repower only a portion of their steam generating units using combined cycle 

technology while retiring other units can still substantially increase their generating capacity

while reducing their maximum intake flow requirements. For example, a facility with two steam 

units of equal size could repower one of them with combined cycle (CCR) and retire the other 

and still increase the generating capacity by 25% to 50% (assuming 150% to 200% increase in

unit capacity). In such a case, the cooling water flow requirement when operating would be 

reduced by 50%. The change in average intake flow may be higher or lower depending on the 

combination of the reduced maximum flow versus increased capacity utilization.

In the case of full repowering, the capacity of the steam cycle component is no longer 

constrained by the existing plant design. The use of combined cycle or other more efficient 

technology should allow for an increase in generating capacity without an increase in the cooling 

water flow rate. And even when steam capacity is increased, it is likely that other cooling 
16

options will be employed for this added capacity and thus the maximum intake flow rate will not 

be increased. However, it is also likely that new generating technology will be more economical 

and result in an increase in the capacity utilization rate. Therefore, an increase in the average 

intake flow rate compared to that of the existing system before it was retired can be expected.

Example Facilities

A brief description of some example facilities that were repowered using combined cycle and 

solid fuel repowering options are provided below.

Full Repowering - Pulverized Coal-Fired to Natural Gas Combined Cycle

Port Washington Generating Station, Port Washington, WI – Wisconsin Energy

(Sources: Peltier 2008; Wicker 2005; WI DNR 2002.)

A 1935-era power plant was demolished and replaced by two 545 MW high-efficiency natural 

gas-fired combined cycle generating units. The project was done in two phases with units

coming online in 2005 and 2006. Each new unit consisted of two combustion turbines, two 

HSRGs, and one steam turbine generator. The original pulverized coal steam plant had five 80 

MW generating units (four were operating at 320 MW total capacity in 2000) and held the record 

as the highest efficiency plant at 32% from 1935 to 1948 (heat rate = 10,800 BTU/KWh). A 16-

mile lateral natural gas pipe from Jackson, Wisconsin was constructed to provide fuel. The 52-

acre plant located on the south end of Port Washington, Wisconsin was typical in size for this

type of plant. The new generating units cover about 10 acres. Construction was hampered by 

access being limited to only one direction, and the design of the HSRGs was modified to fit into

the old building footprint. Some of the older buildings and the west wall of the existing power 

house were retained. The 450 ft by approximately 1,000 ft coal dock and coal storage area is no 

longer in use and it appears that this area would have provided sufficient space for installation of 

closed loop cooling towers.

The new plant operates as an intermediate load facility operating 16 hours per day, 5-7 days per 

week and withdraws 565,000 gpm of cooling water from Lake Michigan. The design intake 

flow reported in the 2000 survey was 550,000 gpm. However, it appears that no new pumping 

capacity was added and that the survey DIF may not have included total service pump capacity 

of 15,000 gpm. Thus, while the design intake flow rate appears to have remained the same or 

increased by about 3%, the generating capacity has increased by a factor of 3.2 (220%). The cost 

of the entire new plant was approximately $669 million (or $614/KW).

Combined Cycle Repowering – Coal-Fired to Natural Gas Combined Cycle

Grand Tower Power Plant, Grand Tower, Illinois – Ameren Energy

(Sources: Burns & McDonnell 2009; Ameren Energy 2009.)

In 2001, two 1950s-vintage pulverized coal-fired steam electric units were repowered with 

natural gas-fired combined cycle using the existing steam turbine generators. Units 3 and 4,

previously rated at 82 and 104 MW, are now rated at 90 and 112 MW. The units were modified 
17

by adding one 176 MW combustion turbine generator and one HRSG to each unit. The new 

combustion turbines and HRSGs provide steam to the existing steam turbines, and total system 

capacity is 550 MW. The result is a generating capacity increase by a factor of 2.98. The 

existing coal-fueled boilers and all associated systems will be retired in-place (Ameren 2009). 

The plant withdraws once-through cooling water from the Mississippi River. No information is 

available concerning changes in cooling water withdrawal rates, but it is likely that the design 

capacity remained unchanged.

Combined Cycle Repowering – Oil to Natural Gas

Sanford Plant, Sanford, Florida – Florida Power & Light

(Source: Peltier 2004.)

The original plan was to repower Unit 3 (a 1950s-vintage 150 MW oil-fired generating unit) and 

Unit 4 (one of two 1970s-era 400 MW oil-fired generating units). The older Unit 3 was cooled 

using once-through cooling water from the St. Johns River and the two 400 MW Units 4 and 5 

are cooled using a cooling pond. Capacity utilization for Unit 3 was expected to increase from 

30% to 98%. The public was concerned that manatees might be attracted to the increased flow 

of heated cooling water during the winter, making them more susceptible to injury by watercraft. 

As a result, FPL decided to repower both of the 400 MW Units 4 and 5 instead. The repowered 

Units 4 and 5 are cooled by recirculating cooling water through the existing cooling pond. 

Another benefit of repowering Unit 5 instead of Unit 3 was that less oil would be used and thus 

there would be less oil barge traffic on the St. Johns River. Total oil barge traffic was reduced 

by 90%.

Each unit was repowered by adding a power block consisting of four combustion turbines 

feeding a single HSRG that provided steam to the 400 MW existing steam turbines. Each 

repowered unit produces 938 MW for a total new capacity of 1,876 MW, increasing the capacity

of the two units by a factor of 2.35. The existing steam turbines remained in operation until after 

the combustion turbine HSRG power blocks were completed. The existing 400 ft stacks and 

boilers were not demolished until after the new power blocks were commissioned.

Unit 5 construction began January 2000 and was completed June 2002. Unit 4 construction 

started March 2000 and was completed May 2003. Total cost was approximately $600 million 

dollars (or $320/KW).

Atmospheric Fluidized Bed Combustion Repowering –Oil/Gas to Solid Fuel (Coal and 

Petroleum Coke)

Northside Generating Station, Jacksonville, Florida - JEA

(Sources: Peltier 2002; DOE NETL 2003.)

Installed two advanced fluidized bed combustors to provide steam to the Units 1 and 2 (297 MW 

each) steam turbines which were originally powered by oil/gas. Units 1 and 3 have been in 

operation since 1966 and 1977, respectively, at an annual capacity factor of 40%. Unit 2 has not 
18

been in operation since 1983. Unit 3 will continue to operate as a conventional 564-MW oil/gasfired steam unit. The generating capacity of the existing Units 1 and 2 turbines will remain 

nearly the same with a heat rate of 9950 BTU/ KWh for an overall efficiency of 34%. With Unit 

2 coming back online and an increase of the capacity factor to 90%, power generation will 

increase by 250%. Despite this increase in power generation, the total air emissions will be 

reduced by 10% which includes the continued contributions of the Unit 3 fueled by oil/gas.

Construction includes installation of two large 400 ft diameter aluminum fuel domes, primarily

intended to keep the fuel dry and also to control fugitive dust and storm runoff. Open storage of 

coal in coastal areas increases moisture content, which reduces combustion efficiency. 

Construction also includes the first continuous ship fuel unloader in the US. The continuous 

loader will eliminate the possibility of fuel spills into the St. Johns River by transferring fuel 

through an enclosed conveyor system from dock to boiler.

Unit 2 was completed first in 2001 as part of DOE’s Clean Coal Technology (CCT) 

Demonstration Program and Unit 1 was completed in 2002. Total cost for Unit 2 was $309

million (or $1,039/KW).

Gasification Combined Cycle Repowering – Coal to Coal/Coke

Wabash River Power Station, West Terre Haute, IN - Wabash Valley Power Association

(Source: DOE NETL 2002.)

The Wabash River plant has six generating units that prior to the project had a total nameplate 

capacity of 973 MW. Unit 1 (the oldest), having a nominal capacity of 99 MW, was repowered 

by adding a coal gasification process integrated with a new 192 MW combustion turbine and an 

HRSG. The repowered unit has a total generating capacity of 262 MW net. Thus, generating 

capacity was increased by a factor of 2.75. Power used to operate process equipment was 36 

MW. The system was tested on high sulfur coal and petroleum coke which had a sulfur content 

of 5%.

In the process, fuel is ground and fed in a water slurry to the gasifier in which the coal is partially

combusted using 95% oxygen gas at high temperature and pressure. The oxygen is generated 

onsite. The fuel is converted almost completely to syngas consisting of hydrogen, carbon 

monoxide and carbon dioxide, water vapor, and a small amount of carbonyl sulfide (COS). 

Steam is generated when the hot syngas is cooled in order to allow for gas processing. Gas 

processing includes particulate removal, wet scrubbing to remove chlorides and volatile metals, 

conversion of COS to hydrogen sulfide (H2S). H2S and some CO2 are removed in an acid gas 

removal system. H2S is then processed into a pure sulfur product with overall sulfur recovery of 

98%. The syngas is then moisturized, superheated and sent to the combustion turbine. While in 

a conventional combined cycle system most of the steam is generated by the HSRG from the 

combustion turbine exhaust gases, in this system about two-thirds of the high pressure steam 

available to power the existing steam turbine is generated from the process used to cool the hot 

syngas. The system heat rate was 8,900 BTU/KWh, which was equivalent to an efficiency of 

38.3%. Air emission levels were well within all Clean Air Act requirements.
19

Being a demonstration project, the plant experienced operating problems typical of an evolving 

technology. These problems were resolved over time, with plant availability being only 22% the 

first year, increasing to 44% the second year and 60% by the third year. Total cost was $416.6 

million (or $1,590/KW). The process was designed to produce very low SOX emissions, which 

added about $100/KW to the costs. It was estimated that, if a greenfield project was constructed 

using knowledge learned from this project, its capital cost would be $1,275/KW and heat rate 

would be 8,250 BTU/KWh (41.4% efficiency). 

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