Tetra Tech, Inc.

10306 Eaton Place, Suite 340 Fairfax, VA 22030 phone 703 - 385 - 6000 fax 703 - 385 - 6007 DATE: March 9 , 20 11 TO : Paul Shriner, EPA FROM : John Sunda, SAIC a SUBJECT: Repowering and 316(b) Power plant r epowering 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 a dditional maintenance requirements of older combustion equipment may also result in more frequent maintenance outages, reducing the equipment reliability operation less economically attractive equipment
. Inaddition , n ew r estrictions 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. add ing capacity or using other , often As aging plants become less cost less frequentl y , resulting in progressivel y retired. At the same time , the demand US is constantly

increasing. Power companies generall y have two a these problems: 1) construct new g existing facility

to replac e the capacity of older generating s ys tems that are eventuall y retired 2) refurbish ( repower ) existing generating facilities. companies often involve a mix of both options considerations
. 

### MEMORANDUM

Paul Shriner, EPA John Sunda, SAIC a nd Kelly Meadows, Tetra Tech and 316(b) epowering is simply

the “r efurbishment 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 ge nerating 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 m eeting without equipment modifications or abatement technologies
. In some cases, the e nvironmental emission in the need to derate (reduce power output) , especially at times of pe water temperatures. The derated capacity must be made up b y often less cost
- efficient generating s ys tems. become less cost
- efficient than the newer s ys tems , over time they are progressivel y lower capacity utilization rates , and may eventuall y be the demand for increased power generating capacity throughout the Power companies generall y have two a lternatives for construct new g reenfield generating plants or add new generating units at an the capacity of older generating s ys tems that are eventuall y retired existing generating facilities. The strategies emplo yed by power companies often involve a mix of both options and are driven mostly b y 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 mak e their more efficient processes and estrictions on environmental emissions create requirements that equipment modifications or

nvironmental emission especially at times of pe ak The derated capacity must be made up b y

over time they

are operated and may eventuall y be increased power generating capacity throughout the lternatives for dealing with or add new generating units at an the capacity of older generating s ys tems that are eventuall y retired or The strategies emplo yed by power and are driven mostly b y economic- 2 -

This memo discusses repowering of existing combustion
- based generating plants using combus tion
- based s ys tems 1 and 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 r epowering include some or all of the following possibilities (Stenzel et al 2009 ):

 It may

be the l east - cost option for increasing generation capacity  It can m inimiz e capital cost expenditures  It can r educ e overall s ys tem fuel usage and/or costs  It can r educ e O&M costs  It can r educ e emissions and other discharges  It can reduce wat er 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. R epowering projects often help me et increasing load demand by increasing the power output of an existing plant
. The i ncreased 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
. Insome cases , repowering does not result in an increase in the generating capacity
. The goals of such projects often include reducing cost s , reducing emissions , improving reliability , or changing the fuel used or allowing for more flexibility in the ty pe of fuel used
. Repowering an existing facility has numerous advantages over building a greenfield facility to meet electricity

demand or replace the ca pacity 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 transmi ssion 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 s ys tems  Can utilize existing highway and rail access  Can utilize exis ting trained staff  Can utilize ex isting cooling water intake and discharge equipment , structures, and permitted water withdrawal capaci ty

1 Note that s uch efforts do not necessarily run counter to goal s of reducing the proportion of power generated using fossil fuels and increasing the use of renewable resources. Combustion
- base d 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 (lowe r 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 b y 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 . R epowering can provide for substantiall y 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. Increasingl y, facilities are evaluating the possibility of repowering existing generating units. These generating units may have different designs, ages, e quipment conditions , and fuel ty pes . Repowering may

involve the replacement of the entire sy stem , the replacement of a portion of the s ys tem , or the addition of new combustion/ generating equipment that is incorporated into the existing sy stem. Inman y cases, especially if the steam turbines are in relativel y 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 w ould 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 generati on . The combination of combustion turbines with steam cycle power generation, also known as combined cycle , generall y results in a much more efficient s ys tem than the use of either alone
. Combined cycle generating s ys tems offer greater flexibility

in the ir application because they can be started up and shut down more rapidly than steam generation sy stems and thus can function more efficiently as intermediate load and peaking load facilities in addition to base load applications. In order to operate relia

bly , 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 . L iquid and gaseous fuels ty picall y generate fewer quantities of ash or particulates and thus are the preferred fuel s used to power combustion turbines. The exception s are solid fuel sy stems 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 do es not use steam (e.g., combustion turbines). Generating units that u se combustion turbines alone are most often used to provide peaking power because they can be rapidly

started up and shut down , but are generall y not as efficient as new steam power and combined cycle s ys tems. Wherever existing- 4 -

steam generating capacity i s replaced with combustion generating capacity , the cooling water requirement will be reduced. This option , however, is not discussed in detail here. The v arious types of repowering options that can be applied at existing steam cycle generating sy stems are described below
. These are divided into two main groups: combustion turbine
- based sy stems which generally

involve the use of gas or liquid fuel to power the combu stion turbines; and solid fuel
- based s ys tems which use coal or other solid fuels to power the sy stem. C ombustion Turbine
- B ased Repowering Options The following repowering options use combustion turbines and combined cycle technologies that may replace th e existing generating sy stem, provide supplemental energy to an existing sy stem, or be int egrated into an existing sy stem with replacement of portions of the existing equipment
. Each option result s in a sy stem that is more efficient and often has a higher total power output than the existing sy stem. All of these s ys tems use gas or liquid fuels to power the added combustion turbine technology
. In s ys tems where the existing boiler remains in operation, the existing boiler may continue to use the same fuel type as before. Otherwise , if the existing sy s tem does not use natural gas or oil , then the repowering may involve a complete conversion of the ty pe of fuel used. Site Repowering or Full Repowering i nvolves the demolition of the existing generating unit s ( except for possibly

the cooling water s ys tem , switchyard, and other ancillary sy stems and building structures ), followed b y the construction of a new combined
- cycle or other type of plant in its place
. In some cases, if space allows, the old sy stem may be kept in operation while a portion or all of the new sy stem is constructed nearby
. Site repowering is commonly used at very old plants where the boilers and steam turbines are at the en d of their useful lives
. Itis considered one of the simplest way s o f repowering an existing plant. Combined Cycle Repowering (CCR) i nvolves the replacement of the existing boiler b y 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 onl y after construction is completed. Combined cycle repowering is the m ost common ty pe of repowering currentl y being implemented in the U.S. H ot W indbox Repowering (HWBR) , also known as Topping , i nvolves the conversion of a steam cycle unit to combined
- cycle where the existing boiler remains intact and a gas turbine is added to the sy stem 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 addition al fuel used in the gas turbine will offset some of the fuel requirement for the existing boiler , providing an increase in sy s tem efficiency associated with a combined cycle s ys tem while maintaining the existing boiler steam output conditions at which the existing steam turbines are designed to operate most efficientl y. Partl y because the combustion now has a lower ox ygen- 5 -

content, this ty

pe of conversion involves the highest degree of technical c omplexity of all the combustion turbine
- based repowering op tions
. The added combustion turbine contributes a relativel y 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 Bo osting , 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. Ina conventional steam turbine unit , some of the boiler steam is diverted to heat the boiler feedwater which starts out at the relativel y 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 b y the combustion turbine. The benefit of additional steam turbine generation occurs only if the des ign limits of the steam turbine are not exceeded. The e xis ting 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 directl y 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 tur bine 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 R epowering (P

R) 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 onl y operates for peak and intermediate load s . The steam from th e existing boiler is added to the steam from the HRSGs at several pressure levels, depending on the condition and capability of the existing steam turbine s . Solid Fuel
- B ased Repowering Options Most solid fuels tend have a lower cost th an 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 up
front capital co sts and therefore are more suited to sy stems re quiring 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 ty pes provide s the opportunity to utilize lowe r - cost fuels such as high ash coals and waste materials (e.g., petroleum coke) or to use fuel blends, and allow s the flexibility to take advantage of variati ons in fuel availability and costs over time
. The use of low er - cost solid fuels can offset the higher capital costs and generally lower efficiencies of these solid fuel sy stems. The following repowering options are available for use with solid fuels.- 6 -

At mospheric Fluidized Bed Combustion Repowe ring (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 sy stem is upgraded to a more efficient sy stem . Fluidized bed sy stems have the benefit of reducing air pollution emissions exiting the boiler by burning fuel at temperatures low enough to m inimize 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 turbine
generator 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
. P articulate matter is removed from the flu e gas using cyclone separators p rior to the flue gas entering a gas turbine. The gas turbines are designed to accept a moderate amount s of particulate matter
. PFBC technology

introduces some significant operating complications to the fluidized bed combus tion 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 (P C FBC) is similar to PFBC and is referred to as the second
- generat ion pre ssurized 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 power s the gas turbine (DOE 2009)
. This technology i s still in the development stage. Gasification Combined Cycle Repow ering (GCC) , also known as IGCC , involves addition of a s olid fuel gasification sy stem , a gas processing s ys tem, a combustion turbine , and an HRSG . This sy stem replaces the existing boiler
. The gasification sy stem converts a solid fuel to a gaseous fuel (s yn gas) 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 ty pically exposed to steam and carefull y controlled amounts of air or ox ygen under high temperatures and pressures. Under these conditions, the solid fuel break s 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

benef it of this technology

is that air emissions are substantially reduced. Also, CO 2 removal for sequestration (if required in the future) can be done at lower costs than at conventional coal power plants beca use the CO 2 can be remov ed under pressure d uring the sy ngas processing step. In addition, combustion turbines which run on s yn gas can generate more- 7 -

power. T he s yn gas 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 ha s a power rating of 70 MW using natural gas and a power rating of 90 MW using s yn gas (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 wh en compared to a full repowering option for a combined cycle s ys tem of comparable generating capacity. It also shows potential increase s in capacity

and sy stem efficiency and construction outage times where available. Other Modifications Repowering can also include replacement and modernization of various components of the power plant. 2 This can include replacement or upgrade of the existing steam turbine s and other options described below: Steam Turbine Upgrade

— R eplacement or upgrade of existing steam turbines may be necessary to optimize sy stem efficiency and capacity , and to match new design specifications. Inone example, u

pgrading the turbines alone increase d output by 7% (Hong Kong Electric Co. 2000 ). Instrumentation and Controls

— Instrume ntation and control s ys tems at older plants can be upgraded and “tuned , ” such that plant efficiency could be increased b y 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 c an be achieved b y conducting a study of plant power use and minimizing power use b y making improvements such as upgrading HVAC sy stems. 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  Improvin g condenser performance b y i nstalling 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 sy stem.
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 E ntire existing unit is

demolished and replaced Simplest method Performance same as new greenfield facility. Can sav e approximately $106 to $300 per KW compared to Greenfield, excluding l and 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 com bustion turbine with exhaust ga ses 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 capac ity 0% to 25%. Increase effic iency 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 smalle r 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 supp lemental 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 Pla nt 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 tur

bines 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 s ys tem from the many options available requires an in
- depth evaluation of man y financial and technical considerations and how these relate to the available r epowering 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 d etermine if the existing plant can be repowered to meet the generation goals
. This could include consideration of :
 Air emissions and discharge limits  Transmissi on requirements and limitations  Equipment age and conditi on  Site a ccess  Technology option limitations  Permitting requirements 3. Identify candidate repowering technologies , including those identified earlier in this document , and perform an initial analy sis to help narrow the list down to the most competitive technologies. 4. Develop preliminary technology desi gn and costs f or each candidate technology , including operation parameters, and conduct a financial analy sis , including consideration of:

 Projec ted fuel availability and costs  Anticipated regulatory changes  Investment capital costs  S ys tem O&M costs  Schedules  Future revenue and return on investment 5. Select the best option based on the results of the analy sis
. The anal ys is of each repowering option must take into consideration many factors, some of which may

be based on uncertain project ions and assumptions
. As such, general rules
- of
- thumb and simple engineering analy ses generally will not suffice in performing such a complex anal ys is. 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 “ SO APP ® R epowering Screening Module ” and the “ SOAPP ® REPO CC WorkStation
. ” These software tools are available from EPRIfor a fee
. T he SOAPP ® Repowering Screening Module conducts a screening anal ys is that provides a preliminary assessment of the viability of repowering an existing unit and location conside ring us e of different technologies (including CCR, HWBR, SBLR, FWHR, CFBC, PFBC, and GCC)
. The Screening Module will identify major site
- specific limitation s and estimate technology performance and costs , enabling the user to identify which technology opti ons are worth evaluating further in a more detail ed anal ys is. 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 pro vide a more in
- depth anal ys is for re powering options that involve combined
- cycle repowering of existing fossil steam plants
. The WorkS tation 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 anal ys is The W ork S tation allow s evaluation of numerous equipment options and configurations , allowing the user to change input variables and option selection s in order to conduct sensitivity anal ys es and select the optimum sy stem design from multiple options and scenarios
. SOAPP ® can repla ce the need to employ a team of engineering staff or outside consultants that would be necessary to conduct a similar anal ys is. Fuel Selection Factors that influence fuel selection include fuel availability , fuel costs, s ys tem efficiency , technology costs, technology reliability , air pollution limits, and waste disposal costs. Table 2 presents e lectricity generation fuel costs (in dollars per million BTU heat content) projected b y the DOE Energy

Information Administration (EIA) for coal, natural gas , and two ty pes 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 co sts because they do not take into consideration the different efficiencies of different types of combustion sy stems.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 sy stem efficiencies have o n fuel cost s for generating electricity. Table 3 presents the calculated fuel costs per MWh for conventional steam boilers and combined cycle s ys tems , based on the assumed heat rates shown in the table using the projected ye ar 2010 fuel costs from Table 2. The fuel costs for combined cycle are shown for both a low efficiency sy stem (heat rate = 7,000 BTU/KWh) that might be expected for a repowered or older sy stem and for a newe r high efficiency sy stem (heat rate = 6,000 Btu/KWh) that represent s the upper end of possible combined cycle sy stem 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
- 1990 s 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 ab o ut 70% of ope rating 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 sy stems , including repl acing all or a portion of the natural gas at existing combined cycle generating units with sy ngas 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 $73.912

Despite the higher fuel price, n atural 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 c limate l egislation will add another important economic factor to be considered in the fuel selection decision , and will favor fuels and generating s ys tems with l ow specific CO 2 emissions (gm/KWh). Table 4 presents the range of specific CO 2 emission rates for different fuel ty pes and different combustion sys tem generating efficiencies
. The table shows the ty

pical range of efficiency

for gas turbines (GT), steam power plants (SPP), and combined cycle power plants (CCPP).

Table 4. Specific CO 2 Emissions Rates for Different Fuels and Different Combustion Technologies

Source: Fränkle 2006. While natural gas ha s the best performance with respect to reducing CO 2 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 CO 2 emission rates ( especially for coal
- fired power plants ) , such as CO 2 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 c limate l egislation , along with public opposition , has slowed the pace of construction of new coal
- fired power plants. This, c ombined with the uncertainty of future fuel prices , has injected a great deal of uncertainty into th e 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 CO 2 emissions becomes clear, power companies will be better able t o predict the costs of each fuel option. The availability

and cost of transport ing different fuel ty pes 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 current ly 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 option s 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 emission s . Projecting Future Repowering for for mer P hase II Facilities 3 EPA’s economic impact anal ys is includes future projections of changes in available generating capacity
. The anal ys is , which us es the IPM model , provide s projections for generating capacity changes during the ye ars 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 prediction s as to which facilities and units will be repowered. New capacity additions are onl y projected on a N ERC 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 ty pically 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 o nly one coal plant as be ing repowered using combined cycle and one unit at another coal facility as being repowered from a coal plant to coal using IG CC. Total repowered capacity for both was less than 200MW. The remainder of the repowering was projected to be o il/ gas - fired plants converted to combined cycle. A comparison of the new capacity of the repowered units to the capacity before repowering fo r all those units projected to be repowered in the US through 2020 show s 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 increa se 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 Phas e 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 N ERC regions and t otal 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 includ e 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

prese nting the totals as a percent of this baseline capacity . The values shown for each ye ar are cumulative totals. Note that the repowered capacity projections represent the total capacity of the repowered generating units (including existing capacity) , and th at the added generating capacity for repowering is a pproximately 60% (1
- 1/2.5) of the total rep ower ed capacity shown.

Table 5. Estimated Generating Capacity for New Generating Units and Existing Generating Units Repowered Using Combined Cycle Repow ering

Source: Example IPM Model Output, Abt Associates 2009. Table 5 shows that the IPM model predicts that initial ly the majority of added generating capacity will be from repowering and that the addition of new cap acity from construction of new units will accelerate over the period. By 2020, roughl y two thirds of added capacity will be from new additions. Thus, the existing facility r ule , which generally applies to repowered facilities , could apply

to a substantial portion of new generat ing 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 r ule
. While the IPM model provides a fairl y rigorous projection , it is based mostl y 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 i nformation 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 A dditions (MW) Capacity- Repowered Units (MW)15

future capacity additions and repowering activities is also available from RDIConsulting 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 stil l 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 s ys tem generating capacity , while making at most only mo dest 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 f or each repowered generating unit will not increase , while at the same time the generati ng capacity may increase u p to 200% depending on the technology

selected . Repowering options that result in an increase in the amount o f 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 n ot 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 costl y 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 t e nd to use less cooling water. S ince repowering often result s in an increase in efficiency and a decrease in the cost of generating electricity, the repow ered units w ill likely be operated more frequentl y , 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 p lants 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. P lants that repower onl y 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 e qual 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 operatin g would be reduced b y 50%. The change in average intake flow may be higher or lower depending on the combination of the reduced maximum flow versus increase d capacity utilization. In the case of full repowering , the capacity of the steam cycle component is no longer constrained b y the existing plant design. T he 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 cooling16

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 mo re 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 sy stem 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
- F ired to Natural Gas Combined Cycle Port W ashington Generating S

tation , Port W

ashington, W

I

– Wiscons in Energy ( Sources: Peltier 2008; Wicker 2005; WIDNR 2002.) A 1935 - era power plant was demolished and r eplaced b y two 545 MW high
- efficiency natural gas - fired combined cycle generating units
. The project was done in two phases with unit s 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 8 0 MW generating units ( four were operating at 32 0 MW total capacity in 200 0) 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 W ashington , Wisconsin was ty pical in size for this ty pe of plant
. The new generating units cover about 10 acres. Con struction was hampered b y 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 b y approximately 1,000 ft coal dock and coal storage area is no longer in use and it appears that this area would have provid ed sufficient space for installation of closed loop cooling towers. The new plant operates as an intermediate load faci lity operating 16 hours per day , 5 - 7 day s per week and withdraws 565,000 gpm of c ooling water from Lake Michigan. The d esign intake flo w 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 rem ained the same or increased b y about 3%, the generating capacity has increased b y a factor of 3.2 (220%). The cost of the entire new plant was approximately $669 million (or $614/KW )
. Combined Cycle Repowering

– Coal
- F ired to Natura l G as Combined Cycle Grand Tower Power Plant , Grand Tower

, Illinois

– Ameren Energy ( Sources: Burns & McD onnell 2009; Ameren Energy 2009 . ) In 2001, two 1950s - vintage pulverized coal
- fired steam electric units were repow e red with natural gas
- fired combine d 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 modified17

by adding one 176 MW combustion turbine generator and one HRSG to each unit
. The new combustion turbines and HRS Gs provide steam to the existing steam turbines , and total sy stem 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 sy stems 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 remain ed 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 unit s )
. T he 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 concern ed that m anatees 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. Ano ther 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 fee ding 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 existin g steam turbines remained in op eratio n 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 (Source s : Peltier 2002; DOE NETL 2003
. ) Installed two advanced fluidized bed combustor s to provide steam to the Units 1 and 2 ( 297 MW each) steam turbines which were originall y p owered by oil/g as . Units 1 and 3 have been in operation since 1966 and 1977 , respectivel y , at an annual capacity factor of 40%. Unit 2 has not18

been in operation si nce 1983. Unit 3 will continue to operate as a conventional 564
- MW oil/gas
fired steam unit. The generating capacity of the existing Units 1 and 2 turbines will remain nearl y the s ame with a heat rate of 9950 BTU/ KWh for an o verall efficiency of 34%. W ith Unit 2 coming back online and an increas e of the capacity factor to 90% , power generation will increase b y 25 0%. Despite this increase in power generation , the total air emissions will be reduced b y 10% which in clud es the c ontinued contributions of th e Unit 3 fueled b y oil/gas. Construction includes installation of two large 400 ft diameter aluminum f uel 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 sy stem from d ock 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 m illion (or $1,039/KW )
. Gasification Combined Cycle Repo wering

– Coal to Coal/Coke Wabash River Power Station, W est Terre Haute, IN
- Wa bash 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 cap acity 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 sy stem was tested on high sulfur coal and petroleum coke which had a sulfur content of 5%. In the process , fu el 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 sy ngas consisting of h ydrogen, carbon monoxide and carbon dioxide, water vapor, and a small amount of carbonyl sulfide (COS). Steam is generated when the hot sy ngas is cooled in order to allow for gas processing. Gas processing includes particulate removal, wet scrubbing to remove chlorides and volatile metal s , conve rsion of COS to hydrogen sulfide (H 2 S). H 2 S and some CO 2 are removed in an acid gas removal s ys tem. H 2 S is then processed into a pure sulfur product with overall sulfur recovery of 98%. The s yn gas is then moisturized , superheated and sent t o the combustion turbine. While in a conventional combined cycle sy stem most of the steam is generated by the HSRG from the c ombustion 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 sy ngas. The s ys tem heat rate was 8,900 BTU/KWh , which was equivalent to an efficiency of 38.3%. Air emission levels were well within all C lean Air Act requirements.19

Being a demonstration project , the plant experienced operating problems ty pical of an evolving technology
. These problems were resolved over time , with plant availability being onl y 22% the first year, increasing to 44% the second ye ar and 60% by the third year. Total cost was $ 416. 6 m illion (or $1,5 90 /KW )
. The process was designed to produce very low SOX emi ssions , which added about $100/KW to the costs. Itwas estimated that , if a greenfield project was constructed using know ledge learned from this project, its capital cost would be $1,275/KW and heat rate would be 8,250 BTU/KWh (41.4% efficiency). References Ameren Energy . Grand Tower Power Station
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– P lant Description. Accessed on March 2009 at website: http://www.ameren.com/AEG/adc_au_grandtower.asp
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— Grand Tower, I L . Project D escription. 2009. Accessed on March 16, 2009 at website: http ://www.burnsmcd.com/portal/page/portal/Internet/L ocations/St.%20L ouis/StL ouis%20PD% 20Repository

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— Overview. Accessed on March 8, 2009 at website: http://www.fossil.energy .gov/programs/powers ys tems/combustion/fluidizedbed_overview.html
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.21

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