Page 2 of 65 

Table of Contents 

1. Narrative Summary of Credentials 

2. Executive Summary 

3. Issues with Accelerating Tennessee Valley Authority’s Clean Air Strategy for 

Emission Controls at Fossil Power Plants - Introduction 

3.1. Schedule Issues 

3.1.1. FGD Installations 

3.1.2. SCR Installations 

3.1.3. SNCR Installations 

3.1.4. SO3 Mitigation Installations 

3.2. Manpower Issues 

3.3. Material Issues 

3.4. Equipment Issues 

3.5. Permitting Issues 

3.6. Other Issues 

3.7. Program Cost Forecasts 

4. Program Cost Forecasts 

5. Conclusions 

6. Attachments 

6.1. CV 

6.2. Specification of Compensation 

6.3. List of all Publications Authored in the Preceding Ten Years 

6.4. List of Other Cases - - Testimony as an Expert at Trial or by Deposition 

6.5. List of Data or other Information Considered in Forming the Opinions 

6.5.1. References 

6.5.2. Manpower Backup Data 

6.5.3. Cost Backup Data 

6.6. Exhibits not Included in the Body of the Report 

6.6.1. FGD Construction Photos 

6.6.2. SCR Construction Photos 
Page 3 of 65 

1.0 Narrative Summary of Credentials 

I am currently the Program Manager for the Tennessee Valley Authority (TVA) directing 

the design, procurement, installation and commissioning of Flue Gas Desulfurization 

(FGD) projects at TVA’s coal-fired power plants. For over thirty five years, I have been 

involved in the construction and management of major capital projects. I have worked at 

TVA since 1993 in various management assignments with responsibilities including: 1) 

Oversight of TVA’s Fossil Power Maintenance and Modification Partners, 2) Director of 

TVA’s External Business for Domestic and International Power Related Projects, and 3) 

Design, procurement, installation and commissioning of numerous emission reduction 

projects for TVA’s Fossil Power Group. 

Prior to my current assignment, I was the Program Manager responsible for TVA’s 

NOx Reduction Program from 1999 though 2006, which included projects for the 

installation of Selective Catalytic Reactors (SCRs) on 21 coal-fired units and Selective 

Non-Catalytic Reactors (SNCRs) on 4 coal-fired units. Currently, the FGD program has 

four projects in progress to install wet limestone-forced oxidation scrubbers on 15 coalfired units. 

 

Prior to 1993, I worked for the Blount Construction Group headquartered in 

Montgomery, Alabama for nearly eighteen years. While there, I progressed from Project 

Engineer to Project Manager to Director of Projects on various utility and heavy 

industrial related projects that included four new coal-fired generating units. Three of 

those new coal-fired generating units included wet limestone-forced oxidation scrubbers. 

I received a B.S. in Civil Engineering with a major in Construction Management from 

The Ohio State University in 1971. I was a commissioned officer in the Corps of 

Engineers (U.S. Army Reserves) from 1971 to 1979. 
Page 4 of 65 

2.0 Executive Summary 

The Tennessee Valley Authority’s (TVA) current plan to meet the emission requirements 

of the Environmental Protection Agency’s (EPA) Clean Air Interstate Rule (CAIR) 

includes the installation of Flue Gas Desulfurization (FGD) wet scrubbers on ■■

additional units, Selective Catalytic Reactors (SCRs) on ■■ additional units and Selective 

Non-Catalytic Reactors (SNCRs) on ■■ additional units by 2018. This is in addition to 

the 7 units with FGD scrubbers, the 21 units with SCRs and the 3 units with SNCRs 

currently installed on the TVA Fossil Generation Fleet. 

According to the Expert Report from James E. Staudt, to meet what Staudt conceives to 

be the equivalent emission requirements of North Carolina’s Clean Smokestack Act 

(CSA), TVA would have to install FGDs on 51 additional units, SCRs on 22 additional 

units and SNCRs on 14 additional units. Of equal significance to the additional emission 

controls that Mr. Staudt contends are required, is the requirement to have all of these 

emission controls installed by 2013. My report is to address the requirement to install 

Mr. Staudt’s proposed emission controls by 2013 and associated cost issues. To 

complete the proposed emission control projects by 2013 would require the installation of 

FGDs on ■■ additional units, SCRs on ■■ additional units and SNCRs on ■■ additional 

units beyond the current TVA Clean Air Plan. This schedule requirement is unrealistic, 

impractical and would outstrip many key resources that are already proving to be 

incapable of meeting the current demands created by the utility industry trying to meet 

the emission requirements imposed by EPA’s CAIR. Mr. Staudt's assumption of TVA’s 

ability to install these proposed emission controls by 2013 is clearly theoretical and lacks 

the proper analysis of the market capability. For one example, Mr. Staudt’s proposed 

plan would require a recycle pump demand from TVA alone that would be equal to the 

total capacity of the two proven vendors (Weir and GIW) for three years with no 

availability for any other utilities11. 

Mr. Staudt’s Expert Report also significantly underestimates the total capital cost of the 

retrofit program for TVA to meet what Staudt conceives to be the CSA equivalent 

emissions rate for NOx and SO2 at just under $3 billion (provided in his report in 2006 

dollars). Mr. Staudt acknowledges in his report that actual costs will differ from his 

estimate based upon site-specific factors that determine the difficulty of retrofits, market 

pricing of material and labor and other factors. TVA’s estimate of the capital cost 

required is approximately $5.0 billion (in 2006 dollars), which is 69% higher than the 

estimate provided by Mr. Staudt. This estimate is based on historical TVA costs incurred 

for completed projects to install FGDs, SCRs and SNCRs as well as detailed cost 

estimates and updated forecasts for ongoing and future projects. 

An example of the underestimates in Mr. Staudt’s report is his prediction that it will cost 

$172,003,000 to install a scrubber on the unit at TVA’s Bull Run Fossil Plant. TVA’s 

current forecast for the FGD at Bull Run, with the project approximately 50% complete 

and engineering approximately 85% complete, is $313,355,000. This is over an 82% 

increase above Mr. Staudt’s estimate. Mr. Staudt also estimates that the cost to install a 

FGD on Colbert Unit 5 would be $137,631,000. TVA’s current forecast is $264,574,000, 
Page 5 of 65 

which is based upon a detailed target cost estimate that was completed in 2004. This is a 

92% increase to Mr. Staudt’s estimate. For comparison to another utility, Duke Energy’s 

cost to install a FGD on a similar sized unit at Cliffside 5 is projected to cost 

$252,176,300 (not converted to 2006 dollars)4

. 

Mr. Staudt’s report doesn’t address schedule implications of the proposed accelerated 

plan. A typical FGD project installation duration from conceptual design to commercial 

operation averages 5 years. A typical SCR project installation duration from conceptual 

design to commercial operation averages 3 to 4 years depending on the size of the unit 

and complexity with the retrofit installation. There are also schedule implications of the 

SNCR and SO3 mitigation projects that must be worked in conjunction with the new 

installation of FGDs and SCRs. TVA is confident in our projections for the time needed 

to complete FGD and SCR projects, which are based on TVA’s actual experience to 

install FGDs and SCRs on several units, input from Advatech (TVA’s FGD Partner), 

benchmarking with other utilities and an extensive program review on cost and schedule 

conducted by Bechtel Power Corporation. In addition to the heavy demand for emission 

control installations for the next several years, TVA and the other utilities must carry out 

their normal outage work and are also looking to build new generation to meet the ever 

increasing demand for electric power. The schedule placed on the utility companies to 

meet CAIR has exceeded the market capacity for many critical resources. For this reason 

and others discussed in this report, accelerating TVA’s Clean Air Plan from the current 

schedule is not achievable.
Page 6 of 65 

3.0 Issues with Accelerating Tennessee Valley Authority’s Environmental Control 

Program at Fossil Power Plants - Introduction 

With the current high demand for Flue Gas Desulfurization (FGD), Selective Catalytic 

Reactor (SCR) and Selective Non Catalytic Reactor (SNCR) installations across the 

country, all phases of engineering, procurement, construction and commissioning are 

being pushed to the limit. TVA alone will be constructing FGDs on 10 units with 3 

FGDs in commercial operation by the Spring of 2010 at the Bull Run and Kingston Fossil 

Plants. Another ■■ Fossil Plant Units will be equipped with approximately ■■ additional 

FGDs after 2010 within TVA’s Fossil Generation Fleet. Just one of the major utilities 

that borders TVA’s territory will be installing ■■ FGDs by 2010 and ■■ FGDs in total by 

2015. There is a shortage of professional and craft personnel available to accomplish the 

presently planned work. Materials and equipment are getting harder to procure with 

delivery times that meet the present construction schedules. As each week passes, the 

delivery times for both materials and engineered equipment continue to move out. The 

expert report written by James E. Staudt clearly does not address these implications on 

the schedule that he proposes, which accelerates the TVA Clean Air Plan for the 

installation of emission controls in TVA’s Fossil Generation Fleet. 

Assumptions provided in Mr. Staudt’s report and stressed in Paragraph 60 A, pg. 30 of S. 

Tierney’s Expert Report, that the development, equipment ordering and purchase, and the 

construction of the proposed accelerated TVA program could be completed with money 

evenly spent over a five year period from 2008-2012 are both unrealistic and impractical 

to accomplish. The following information is provided to enumerate some of the major 

constraints to compressing the schedule for TVA’s Clean Air Plan. TVA has developed a 

comprehensive emission control strategy (TVA’s current air strategy is shown in Figure 

1 - Table A) that was developed from past experiences in completing FGD, SCR and 

SNCR installations. 

Page 8 of 65 

The Environmental Protection Agency (EPA) studied the capital investments and the 

critical resources required to achieve the emission limits from the Clean Air Interstate 

Rule (CAIR). TVA’s Clean Air Plan, shown above in Figure 1 - Table A, is based on an 

aggressive schedule to meet the CAIR. The EPA, in response to public comment in 

2005, declared the CAIR would “require the most extensive capital investment and 

engineering retrofit program ever undertaken in the U.S. for pollution control”1

. The 

EPA response goes on to say about the CAIR, “The proposed program’s objective was to 

eliminate upwind states’ significant contribution to downwind nonattainment, providing 

air quality as soon as feasible”1

. According to the “Report of Proceedings of Public 

Hearing on Proposed Adoption of Rule 15A NCAC 02D Section .2400 Clean Air 

Interstate Rules” from proceedings held in January of 2006, the North Carolina 

Department of Environment and Natural Resources, Division of Air Quality, answered a 

comment on why it is taking so long to effect reduction on emissions from large utility 

sources by stating “The primary reason for the length of the schedule in CAIR is that it 

takes a significant amount of time to get scrubbers and other appropriate control and 

monitoring equipment in place for the large population of sources impacted by CAIR”2

. 

TVA’s Clean Air Plan is structured to install emission controls on our Fossil Generation 

Fleet to comply with the CAIR. TVA is already concerned with meeting the current 

schedule based on the CAIR requirements because of the issues discussed in this 

document. 

The EPA report also discusses the increased difficulty with retrofitting emission controls 

on smaller fossil units as opposed to larger units. Hence, a two-phased approach is used 

in the CAIR regulations so that utilities would have time to properly study and complete 

activities necessary to retrofit smaller units with FGDs, SCRs and SNCRs. Phase I places 

permanent caps on NOx emissions in 2009 and SO2 emissions in 2010. Phase II places 

more stringent permanent caps on NOx and SO2 emissions in 2015. After the Bull Run 

FGD Project, only eight of the 39 remaining fossil units within the TVA fleet are over 

200 MWs and several of the remaining Plants have significant space limitations that have 

not been studied by TVA nor addressed in Mr. Staudt’s report. Of the FGDs to be added 

to the Progress Energy Fleet, only four units of the 10 planned for FGDs are below 200 

MWs. FGD installations are not even planned for 8 fossil units (1 unit being over 200 

MWs) in the Progress Energy Fleet totaling 786 MWs (or 15%) of generation not being 

scrubbed. Of the FGDs to be added to the Duke Power fleet, only two units of the 14 

planned for FGDs are below 200 MWs. FGD installations are not even planned for 15 of 

the 27 fossil units in the Duke Energy Fleet totaling 1336 MWs (or 19%) of generation 

not being scrubbed. This information is available in the “Implementation of the ‘Clean 

Smokestacks Act’” reports from 20053 and 20064 with some supporting information on 

the size of the Duke Power units coming from the Energy Information Administration 

Website5

. Mr. Staudt’s proposed plan also has TVA installing SCRs (the most expensive 

NOx control technology yielding the highest removal) on 43 of the 59 fossil units. SCR 

installations are not even planned for 7 of the 18 fossil units on the Progress energy fleet 

totaling 1512 MWs (or 30%) of generation without an SCR4

. SCR installations are not 

even planned for 24 of the 27 fossil units on the Duke Energy fleet totaling 4487 MWs 

(or 62%) of generation without an SCR4. 
Page 9 of 65 

TVA is working diligently to meet the requirements of the CAIR and has serious 

concerns whether the current clean air strategy is achievable due to the limited resources 

currently available in today’s market. Figure 1 - Table B depicts Mr. Staudt’s 

accelerated emission control plan on the TVA Fossil Generation Fleet for FGD and SCR 

projects. The assumptions made in the expert report written by Mr. Staudt create 

impractical schedules and unrealistic capital cost estimates for accelerating TVA’s Clean 

Air Plan. The proposed accelerated installation schedule for emission controls by Mr. 

Staudt is not achievable by 2013 because of several critical limited resources. TVA 

contends, through actual construction experience and benchmarking experience from 

other major utilities, that Mr. Staudt’s proposed schedule is not practical -- indeed, not 

even achievable -- and his estimated cost is significantly understated. 

3.1 Schedule Issues 

In addition to the heavy demand for FGD installations for the next several years, TVA 

and the other utilities must carry out their normal outage work and the new installation of 

SCRs and SNCRs. TVA and other utilities are also looking to build new generation to 

meet the ever increasing demand for electric power. It is extremely unlikely that all work 

that is presently planned by utilities can be accomplished between now and 2010. 

Accelerating the FGD projects from the current schedule, which has already exceeded 

market capacity, is not achievable for the reasons that are discussed in this report. 

3.1.1 FGD Installations 

There are a variety of emission control technologies available to reduce SO2 emissions 

from the flue gas of coal fired power plants. TVA is presently installing FGDs described 

as Limestone-Forced Oxidation (LSFO) wet scrubbers. Figure 2A is a simplified 

schematic for the FGD and Limestone Handling systems for Paradise Fossil Plant Unit 3 

and how they are interfaced with the existing Plant. All equipment shown to the right of 

the “Existing Stack” and “ID Fan” has been constructed to complete the FGD installation 

for Paradise Unit 3. 

TVA completed the first Advatech FGD installation on the 1062 Megawatt (MW) 

Paradise Unit 3 in the Fall of 2006. This marked the first Advatech engineered, 

constructed, and commissioned FGD system on the TVA fleet and in the United States. 

Advatech, LLC is comprised of two major companies (URS and Mitsubishi Heavy 

Industries or MHI). TVA has a program contract with Advatech for all of the ongoing 

and future FGDs on the TVA fleet. In late 2003, TVA requested a Scrubber Program 

Evaluation from Bechtel Power Corporation. TVA wanted a third party evaluation of the 

FGD Program because: 1) TVA had no construction experience with the MHI new 

generation FGDs, 2) the partnership with Advatech, LLC for the FGD Program was new, 

3) TVA wanted a third party evaluation of our budgetary estimates, and 4) TVA wanted 

to ensure the proposed schedule for engineering, construction and commissioning was 

feasible. Bechtel used the Paradise Unit 3 Target Cost Estimate and Schedule to evaluate 

its use as a basis for the overall program cost and schedule. Overall, the Paradise Unit 3 

Target Cost Estimate and schedule was found to be sound and reasonable. According to 
Page 10 of 65 

the Bechtel report issued on February 4, 2004, “The current overall program schedule 

[Note: The Program Schedule at that time was only for the installation of FGDs at the 

Paradise, Bull Run, Colbert and Kingston Fossil Plants] is feasible, but is very aggressive 

and will significantly tax the resources of both TVA and Advatech. We recommend a 

schedule that limits the number of sites under active construction to two. This schedule 

approach allows better incorporation of lessons learned and utilization of the 

management team, and will significantly reduce the risk of cost overruns”6. The Paradise 

Unit 3 FGD met the schedule date when it was placed into commercial operation on 

October 17, 2006. The project will also be at or below budget at completion. These facts 

verify that the original target cost estimate and schedule were, indeed, sound and 

reasonable. 

To understand the complexity and size of FGD installations, one must first have a basic 

understanding of the wet scrubbing process and the equipment that is required to operate 

the system. Wet limestone technology uses finely crushed limestone to react with the 

SO2 in the flue gas. The limestone composition must contain a high percentage of 

calcium carbonate (CaCO3) for the reaction to achieve the high SO2 removal required. 

The limestone comes from local quarries and is transported to the plant by truck. There 

the limestone is unloaded onto a conveyor system that feeds a silo and eventually into 

one or more surge bins. These, in turn, feed ball mills that pulverize the limestone 

aggregate for use in the FGD absorber. The slurry is circulated in the absorber to ensure 

the efficient contact with the flue gas needed for removal of SO2. Figure 2-B and Figure 

2-C illustrates what occurs in the MHI absorber. 

The SO2 in the flue gas is slightly soluble in water. The transfer of SO2 to the water 

phase occurs at the vapor/liquid interface in the absorber. In solution, the SO2 ionizes and 

transfers to the interior of the liquid. The increased acidity of the water increases the 

solubility and ionization of the CaCO3 content of the limestone. In solution, the reaction 

of SO2 with CaCO3 will form calcium sulfite (CaSO3) if sufficient quantities of oxygen 

are not present. 

CaSO3 is undesirable as a reaction product so oxygen is introduced into the liquid to 

ensure that the reaction produces calcium sulfate. Calcium sulfate has limited solubility 

in water and precipitates as gypsum (CaSO4

.

2H2O). To control the slurry density in the 

reaction zone, a portion of the reaction product is bled from the reactor and makeup water 

is added. Likewise, to maintain the concentration of dissolved CaCO3, limestone slurry is 

continuously supplied to the reaction. Figure 2-D is a hierarchy of major limestone 

preparation and absorber area engineered equipment that is required to operate a FGD 

system. 
Page 11 of 65 

Figure 2-A.

Figure 2-B. 

Fuel

Boiler

ESP

Fly Ash Removal

Existing Stack

ID Fan

Booster Fan

Oxidation Air

Blower

Treated Water

Storage Tank

Treated Water

Pump

ARS

Recycle Pump

LS Slurry

Feed Pump

Air

Ball Mill

Limestone

Surge Bin

Limestone

LS Slurry

Storage Tank

Effluent Pond

Absorber Bleed

Pump

Absorber Sump

Absorber Trench

Wet Stack
Page 12 of 65 

Figure 2-C. 

Figure 2-D. 
Page 13 of 65 

The Paradise Unit 3 FGD system has several areas unique in function and operation. 

These areas include limestone handling and preparation, absorber, water supply and 

balance of plant. All equipment and processes from the limestone receiving area to 

the limestone slurry pumps are included in the limestone receiving and handling 

area. For Paradise Unit 3, the limestone receiving and handling area consists of a 

limestone truck unloader, storage silo with 4000 tons capacity for limestone, 

approximately 1600 ft of conveyors, two-8 hours storage bins with 400 tons capacity 

of limestone each, two-120,720 gallon each slurry storage tanks, two-5000 gallon 

mill sump tanks, two 50 ton per hour (tph) weigh feeders, two hydrocyclones and 

two 50 ton per hour ball mills (with other supporting mechanical and electrical 

equipment). This equipment is required to crush the 3/4”x 0” limestone rock from 

local quarries and produce 30 wt. % limestone slurry with a fineness of 90% passing 

a 325 mesh screen, a size suitable for the wet scrubbing process. The limestone 

preparation system for the Paradise Unit 3 Project alone cost over $35 million to 

construct. 

The absorber area includes the twin tower absorber, slurry recirculation system, 

forced oxidation air, as well as all flue gas ducting associated with the FGD system. 

The water supply system includes all water handling facilities associated with raw 

and treated water. Slurry transfer systems for both limestone and gypsum are 

included. The balance of plant includes such services as cranes and hoists, HVAC, 

fire protection, plant air, and building services. The absorber consists of one cocurrent tower and one counter-current tower. These are vertical towers above an 

integrated reaction tank. One bank of spray headers, located at either side of each 

tower, introduces absorber slurry to the flue gas stream. Three air rotary spargers 

(ARS) maximize the oxidation of bisulfite to sulfate-

 in the absorber tank. The 

oxidized sulfate is then mixed with limestone slurry to form gypsum slurry. After 

leaving the absorber, the desulfurized flue gas passes through a mist eliminator to 

remove entrained mist droplets. The mist eliminator is located horizontally in the 

outlet tower after the spray headers. 

Advatech began engineering work on the Paradise Unit 3 FGD in Fall of 2002. Advatech 

expended over 450,000 man hours of engineering on the Paradise Unit 3 FGD Project. 

The engineering effort spanned from Fall of 2002 to Summer of 2006 (Preliminary - 4 

months, Conceptual - 7 months, Detailed - 19 months, Construction Support - 15 

months). Construction began on the Paradise Unit 3 FGD in the late Spring of 2003. The 

Paradise Unit 3 FGD construction took approximately 3.5 years to complete running 

from the late Spring of 2003 to the Winter of 2007 (estimated completion of all punch list 

items). The project required over 1,400,000 craft man hours to complete the 

construction. The installation required three Unit outages. The first outage was needed 

to install dampers and connecting ductwork, which took approximately 34 days and was 

during a planned plant outage. The second outage was needed to install DCS equipment, 

which took approximately 12 days and was again during a planned plant outage. The 

third outage was needed for the FGD DCS tie-in and fan verification, which took 

approximately 10 days. 
Page 14 of 65 

The amount of materials that is required to construct FGDs on large coal fired power 

plants is massive. The Paradise Unit 3 FGD Project installed over 150,000 linear feet of 

conduit with over 10,000 ft of cable tray. The Paradise Project also installed over 

780,000 linear feet of electrical and control wiring at the Absorber Area and over 385,000 

linear feet of electrical and control wiring at the limestone area. The Bull Run FGD 

Project estimates to install over 184,000 linear feet of conduit with over 6000 linear ft of 

cable tray. The Paradise FGD Project poured over 7,300 CY of concrete for the FGD 

area and over 3,500 CY of concrete for the limestone area. The Bull Run FGD Project 

estimates to require over 5,000 CY of concrete (the FGD and Limestone Areas are 

designed together at Bull Run). The Absorber Area construction at Paradise Unit 3 

required installation of over 4,400 tons of steel for structures and buildings (mix of 

carbon and alloys). The Absorber Area construction at Bull Run estimates to install over 

3,400 tons of steel for structures and buildings (mix of carbon and alloys). For large bore 

piping, the Paradise Unit 3 FGD Project installed greater than: 8,000 linear feet of carbon 

steel, 13,000 linear feet of stainless steel, 28,000 linear feet of Heavy Duty Polyethylene 

(HDPE) and 3,500 linear feet of Fiberglass Reinforced Plastic (FRP). For large bore 

piping, the Bull Run FGD Project estimates to install greater than: 25,000 linear feet of 

carbon steel, 6,500 linear feet of stainless steel, 1000 linear feet of Heavy Duty 

Polyethylene (HDPE) and 2,000 linear feet of Fiberglass Reinforced Plastic (FRP). For 

ductwork, over 1500 tons were installed during the Paradise Unit 3 FGD construction and 

greater than 1100 tons are estimated for the Bull Run FGD construction. These are only 

a few examples of the massive amounts of material required on projects of this 

magnitude. 

The construction of retrofit emission control projects, as opposed to building controls 

as part of a new unit, usually adds unique challenges because of limited space around 

the coal fired units to add the large structures required. Many FGD retrofit projects 

require high capacity, long reach cranes. The greater than 1,500 tons of new 

ductwork that was installed on the Paradise Unit 3 FGD Project required a 1000 ton 

crane to make two of the primary duct lifts. There are very few 1000 ton cranes 

available in the U.S., which require 70-80 tractor loads to deliver and 4 weeks to 

assemble onsite. There are several construction photos provided in Exhibit 6.6.1 to 

show the enormity of the construction scope for FGD projects. The Paradise Unit 3 

FGD construction also required a helicopter for an aerial lift to remove construction 

equipment from the top of the new stack. Coordination of these and like efforts are 

massive and time consuming to major project schedules. 

To summarize the information provided above on FGD installations, a typical FGD 

project installation duration from conceptual design to commercial operation averages 5 

years. For comparison, ■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■

■■■■7

 and the Duke Energy FGD Projects range between 5 and 8 years3&4 (Marshall - 5 

years, Belews Creek - 6 years, Allen - 7 years and Cliffside - 8 years). TVA completed 

installation of the Paradise Fossil Plant Unit 3 FGD in late 2006, which took 

approximately 5 years to complete, as shown in Figure 3, from conceptual design to 

commercial operation. Construction began on the FGD for Paradise Unit 3 prior to the 

current high demand on the market for manpower, materials and equipment. TVA is 
Page 15 of 65 

confident in the projections for the time and manpower needed to complete the FGD 

projects, which are based on TVA’s actual experience to install FGDs on several units 

(Cumberland Units 1&2 and Paradise Unit 3 being the most recent), input from 

Advatech, benchmarking with other utilities and an extensive program review on cost and 

schedule conducted by Bechtel Power Corporation. 
Figure 3. 
Page 17 of 65 

3.1.2 SCR Installations 

To understand the complexity and size of SCR installations, one must first have a basic 

understanding of the NOx removal process and the equipment that is required to operate 

the system. A SCR is a control technology where (NOx) formed in the coal combustion 

process is removed by the injection of ammonia (NH3) into the flue gas. This process 

consists of injecting ammonia (NH3) into boiler flue gas and passing the flue gas through 

a stationary catalyst bed where the NOx and NH3 react to form nitrogen and water vapor. 

The SCR catalyst is made of a ceramic material that is a mixture of carrier (i.e., titanium 

oxide) and active components (i.e., oxides of vanadium and, in some cases, tungsten). 

For the SCRs recently provided by Alstom on TVA’s fleet, the catalyst modules are of a 

honeycomb shape (Cormetech’s design for the TVA SCRs). For example, there were 

540 catalyst modules (~1 m3 in size) installed in the Unit 2 SCR at the Paradise Plant, 

each weighing approximately 3,300 lb. Figure 4-A shows an SCR with a depiction of 

the catalyst beds inside of the SCR. 

The process chemistry consists of the following primary reactions: 

4NO + 4NH3 + O2 Æ 4N2 + 6H2O 

and 

2NO2 + 4NH3 + O2 Æ 3N2 + 6H2O 

The SCR process reaction is most effective within a temperature range of 600o

F to 750oF. 

Figure 4-B shows the process reaction that occurs inside of SCRs. Above 750o

F, the 

effect of catalytic sintering becomes prominent in lowering NOx reduction performance. 

Below 600o

F, the susceptibility of ammonium bisulfate (NH4HSO4) formation on catalyst 

surfaces increases resulting in lower NOx reduction performance. The required 

temperature range of flue gas on coal fired units is typically found between the 

economizer and air heater equipment. Figure 4-C shows the typical location of an SCR 

retrofit on a coal fired unit. Older coal fired units were not designed for this type of 

environmental controls and generally there is limited space available to install the reactor 

for the technology, which are very large structures (see the SCR photos provided in 

Exhibit 6.6.2). 
Page 18 of 65 

Figure 4-A.

Figure 4-B. 
Page 19 of 65 

Figure 4-C. 

FD Fan 

NH3

Injection 

SCR

Reactor

Boiler 

SCR 

Bypass 

Dampers 

Economizer 

ID Fan 

Air Heater

Coal 

Air 

Flue Gas to Scrubbers 

SCR System Schematic 

Overview of SCR Unit 

Outlet 

Dampers 

Inlet 

Dampers 

Possible 

Future 

Layer 
Page 20 of 65 

There is really not a typical SCR construction because each SCR project is unique based 

on the size of the unit and complexity with the retrofit installation. The SCR on Paradise 

Unit 3 was put into commercial operation in April of 2003. ABB Alstom Power, a 

leading international engineering firm in power generation and emission controls, was 

contracted by TVA to design and supply the SCRs and related equipment on Paradise 

Units 1-3, Allen Units 1-3, Cumberland Units 1-2, Bull Run Unit 1, Colbert Unit 5, 

Widows Creek Units 7-8 and Kingston Units 1-9. Alstom began engineering work on 

the Paradise Unit 3 SCR in October of 2000. Alstom expended over 135,000 man hours 

of engineering on the Paradise Unit 3 SCR Project alone. The initial engineering effort 

spanned from October of 2000 to early Summer of 2001 when construction on the new 

SCR began. The SCR construction was performed by TVA’s maintenance partners. The 

construction sequence for SCRs generally began by installing flue gas by-pass ducts to 

provide the necessary space to install the foundations, structural steel and the reactor 

vessel. This was usually accomplished during a planned Unit outage. Once that by-pass 

was complete, the SCR was constructed with the Unit in operation. After the flue gas 

ducts were re-routed, there were usually structures (i.e., old electrostatic precipitators) 

that had to be demolished to make room for the reactor vessel. Once the SCR was ready 

for commercial operation, another Unit outage was required for final duct tie-in. The 

Paradise Unit 3 SCR construction took approximately 2.5 years to complete spanning 

from the Summer of 2001 to the Spring of 2003. The project required over 1,038,797 

man hours to complete the construction. 

Though generally not as great as required for FGD installations, the amount of materials 

that is required to construct SCRs on large coal fired power plants is still massive. The 

Paradise Unit 3 SCR required nearly 2000 CY of concrete for foundations. Greater than 

2500 tons of new ductwork, greater than 3500 tons of structural steel and another 1274 

tons of reactor steel were installed for the Paradise Unit 3 SCR. Nearly 300,000 linear ft 

of electrical and control cable was also installed during the construction. These are only 

a few examples of the massive amounts of material required on projects this large. 

As noted earlier, the construction of retrofit emission control projects usually 

encompasses unique challenges because of limited space around the coal fired units to 

add the large structures required. Many SCR retrofit projects require high capacity, long 

reach cranes. The SCR Projects at Allen Units 1-3 required a 1000 ton crane to make 

several of the equipment lifts. As stated earlier, there are very few 1000 ton cranes 

available in the U.S., which require 70-80 tractor loads to deliver and 4 weeks to 

assemble onsite. The Paradise Unit 3 SCR Project had to actually stage cranes on 

pedestals approximately one hundred feet off of the ground in order to gain access to the 

work area. Also, significantly adding to the complexity of the SCR installation at 

Paradise Unit 3 was the requirement to install ash hoppers and SCR ductwork between 

the economizer outlet and the air heater inlet. This installation required the removal and 

installation of steel support beams and ductwork through specially designed monorails 

(crane access was not available) as well as the enhancement of the entire boiler 

suspension system. To accomplish this work required a 77 day unit outage. Several 

construction photos are provided in Exhibit 6.6.2 to show the enormity of the 

construction scope for SCR projects. 
Page 21 of 65 

To summarize the information provided above on SCR installations, a typical SCR 

project installation duration from conceptual design to commercial operation averages 3 

to 4 years depending on the size of the unit and complexity with the retrofit installation. 

For comparison, ■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■■7

 and 

the Duke Energy SCR Projects range between 3 and 5 years3&4. TVA completed 

installation of the Kingston SCR Projects on Units 5-8 in late 2005, which took 3 years to 

complete, as shown in Figure 5, from conceptual design to commercial operation. The 

Kingston 5-8 SCR Project is shown because this particular project is similar in scope to 

the projects that would be conducted in the future on the remaining smaller units within 

TVA’s Fossil Generation Fleet. Not shown in the summary schedule for the Kingston 5-

8 SCR Projects are the required activities of TVA Pre-Contract Investigations and the 

Technical Evaluations for the SCR vendors prior to contract award. These two activities 

could take up to 6 months to complete. Also, the SCRs on the Kingston Units were under 

construction prior to the current strain on the market for manpower, materials and 

equipment. TVA is confident in the projections for the time and manpower needed to 

complete the SCR projects, which are based on TVA’s actual experience to install SCRs 

on similar sized units at Kingston. 

The last photograph provided in Exhibit 6.6.2, Paradise Unit 3 FGD, SCR and Fossil 

Unit Photograph 2007, shows the complete FGD and SCR at Paradise Unit 3 with the 

existing Fossil Unit. The structure to the left is the FGD, the structure in the middle is the 

SCR with the structure to the right being the existing Fossil Unit. The purpose of this 

photograph is the show the enormity of the emission control structures with their size 

being nearly that of the fossil unit itself. 
Figure 5. 
Page 23 of 65 

3.1.3 SNCR Installations

SNCRs are generally installed on smaller units and involve considerable less scope than 

SCR projects but also provide less NOx removal efficiency. SNCR is a post-combustion 

process involving injection of ammonia or urea directly into the furnace. The 

temperature of the boiler flue gas serves as the catalyst for converting the urea to 

ammonia and for converting ammonia and NOx to water vapor and nitrogen. The correct 

location for injection and number of injectors are determined by field testing and 

Computational Fluid Dynamics (CFD) modeling. Injection may occur at different boiler 

elevations at different unit loads because of the variation in the temperature profile. 

Injection may also be combined with over-fired air (OFA) to achieve better distribution 

of the reagent resulting in better NOx reduction. TVA has SNCRs operational on 3 units. 

SNCRs will be added to two more units by May 1, 2007 and to an additional five units by 

January 1, 2009. The timeframe from preliminary engineering to commercial operation 

can range from 9 to 18 months. 

3.1.4 SO3 Mitigation Installations 

Mr. Staudt’s report fails to mention that the combination of fuel switch with installation 

of the FGD and SCR catalyst results in increased oxidation of SO2 to SO3 and thus 

increased emissions of sulfur trioxide (SO3), a precursor of sulfuric acid emissions. This 

results in additional requirements for mitigation of SO3. 

TVA, EPRI and other utilities have been testing injections of various sorbents into the 

gas stream for SO3 mitigation with varying degrees of success8&9. TVA has also been 

participating in an EPRI sponsored interest group, called the Aerosol Emissions Control 

Interest Group (AECIG), to share experience with other utilities related to SO3 mitigation 

technologies. TVA’s own testing experience along with other utility experience has 

shown that, in most cases, hydrated lime is the most successful sorbent (of those tested) 

for removing SO3. However, the lime material coats the precipitator collector plates and 

acts as an insulator thereby reducing the current flow and causing strong sparking, which 

reduces operating current and thus efficiency of the precipitator. The ESP outlet mass 

emissions increase accordingly. Any degradation of the efficiency of particulate control 

equipment (precipitator) will require modifications of that equipment to restore 

performance to the required particulate removal level. The determination of an effective 

SO3 mitigation technology is unit specific and adds to the complexity, cost and 

potentially duration of FGD and SCR projects. TVA has installed lime injection on 3 

units with near term plans to install on 1 to 4 additional units and a possible 25 additional 

units in the future. Future testing will determine what units require SO3 mitigation and 

what units will not require mitigation. 

Recent testing at TVA has confirmed that lime injection is unacceptable at Paradise Unit 

3 without modification to existing particulate control equipment. Future testing is 

planned for the fossil unit at Bull Run but, with the uncertainty of defining a technology 

prior to testing, TVA is not in a position at this time to forecast the requirements. While 

not currently fully defined, TVA estimates that the cost of SO3 mitigation will be as 
Page 24 of 65 

much, or more than, the cost of the SNCR installations being proposed. In summary, SO3

mitigation must be provided on most plants with retrofitted FGD and SCR emission 

control systems and, while excluded from the expert report of Mr. Staudt, must be 

considered in any proper analysis of requirements, cost and durations for emissions 

reduction projects involving the installation of SCR and FGD equipment. 

3.2 Manpower Issues

Craft and Technical manpower requirements are causing a major concern throughout the 

utility industry because of the high demand for environmental controls and new power 

generation. Over the past several years, TVA has seen a steady reduction in the 

availability of craft personnel and technical/engineering expertise. Primary reasons for 

the decline in the labor workforce are attributable to an aging workforce that is retiring 

and a new generation that is not interested in the labor trades. Labor trades, though 

prospering now, generally offer only seasonal employment requiring significant travel 

and sometimes odd/extensive work hours. The EPA discusses manpower concerns in 

“Corrected Response to Significant Public Comments on the Proposed Clean Air 

Interstate Rule”1

. EPA’s response states that shortages and bottlenecks in all resources 

(manpower - specifically boilermakers, construction equipment, engineering and 

construction staffs belonging to different trades, construction materials and equipment 

manufacturers) caused increase project times and costs during the NOx SIP Call. These 

concerns led to the EPA’s two-phase approach for the CAIR to keep utilities from having 

near-term shortages of critical resources. Phase I places permanent caps on NOx

emissions in 2009 and SO2 emissions in 2010. Phase II places more stringent permanent 

caps on NOx and SO2 emissions in 2015. 

There are a limited number of personnel with FGD or SCR experience available to meet 

the present demand for the design of these projects. Equipment suppliers are also limited 

in the support staffs they have to support the commissioning and troubleshooting of their 

equipment in the field. To support Mr. Staudt’s proposed plan, Advatech would require 

over 1000 full time equivalent technical and management personnel with experience in 

FGD design10. The Advatech projected manpower for the current TVA Clean Air Plan 

and the NC Lawsuit Plant is shown in Figure 6. Stretched manpower resources will also 

have other ramifications such as wage wars that cannot be avoided. 
Figure 6. 
Page 26 of 65 

Craft resources are also a major concern. For the past several years, in various locations 

within the Tennessee Valley Region, TVA has experienced difficulty obtaining the 

necessary number of craft (boilermakers, pipe fitters, electricians, etc...) needed to 

support our current work load. This workload includes our routine maintenance projects, 

as well as the current FGD, SCR and SNCR Projects, annual planned outages at our 

generation facilities and new generation projects in the near future. Mr. Staudt’s plan 

will require an unrealistic amount of craft manpower to expect to be available in the 

Tennessee Valley Region as shown in Figure 7. Based on information provided by 

■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■

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■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ 7

. Because of the lack of qualified craft personnel, it is 

unlikely that all of the utilities will be able to maintain the present schedules for their SO2

and NOx reduction projects. 

In 1995 there were over 20,000 unionized Boilermakers in the U.S. but by 1999 there 

were less than 16,000. Aggressive apprentice recruitment for Boilermakers in recent 

years is not keeping pace with attrition. Approximately 1,000 Boilermakers have been 

historically available in the Tennessee Valley Region. Shortages have occurred in recent 

outage seasons when Boilermaker totals exceeded 850 because of the high demand on 

Boilermakers for SCR, FGD and new power generation projects. The situation could 

easily progress to craft bidding wars between utilities and drive the costs of construction 

craft significantly higher. Another challenge is that craft are commonly pulled from 

capital project work when planned or forced outages are occurring on the power 

generating units. The power generating units will always take priority to the capital 

projects for the demand for craft. 

■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■

■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■

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■ ■ ■ ■ ■ ■ ■ ■10. New power generation will place even more of a strain on the 

available technical, construction management and craft manpower. TVA is nearing a 

decision to complete construction on the previously delayed Watts Bar Unit 2 nuclear 

generating unit. The TVA Watts Bar Unit 2 nuclear construction project alone would 

require approximately 2500 manual and non-manual staff (by 2009) for several years and 

is located in the same local union region of the ongoing Bull Run, Kingston and John 

Sevier FGD Projects. The Watts Bar Unit 2 Project, which is currently in the study 

phase, could begin construction within the next couple of years.

Page 28 of 65 

3.3 Material Issues 

With the great demand for material worldwide, alloy materials, steel, and other building 

materials are becoming more difficult to obtain in the time period needed to meet the 

current FGD construction schedules. Carbon steel plate delivery times have increased 

significantly from 8-10 weeks in 2004 to 20-22 weeks in 2006. For shapes and alloy 

plate, fabricators are being limited to reduced allocations from the mills of both of these 

materials, which is pushing out the delivery times as well as requiring modifications to 

the design so that available materials and shapes can be used. Deliveries of metal shapes 

are running 16-18 weeks with jumbo shapes running 20-24 weeks. Depending on the 

alloy, TVA is seeing deliveries range from 20-30 weeks from the time of order. For duct 

and plate fabricators, shops are committed through the first quarter of calendar year 2008. 

To make matters worse, fabricators have indicated to TVA and Advatech that they cannot 

put on additional shifts because of the lack of qualified labor. To follow the proposed 

plan by Mr. Staudt, absorber and structural steel shop space just for the TVA FGD 

Projects alone would be equal to the combined full capacity of TVA’s two main vendors 

(PSP and Cives) for three solid years with no availability for any other utilities11

 or 

TVA’s other work including SCRs. Raw steel and alloy prices would surely escalate to 

include a significant premium over current pricing as well. 

The strain on the carbon steel plate and metal shape markets for FGD installations does 

not take into consideration an accelerated schedule for SCR installations. Mr. Staudt’s 

proposed plan would also require a significant amount of these materials for the SCR 

installations that would further increase delivery times and cost. 

3.4 Equipment Issues 

Because of the demand for FGD installations by utilities to comply with CAIR, there is a 

considerable demand for equipment that is specific to FGDs as well as equipment that is 

used in FGDs and other industries in limited amounts. When vendors are contacted, 

TVA and Advatech are being told that shops are committed through the first quarter of 

calendar year 2008. Therefore, even if TVA orders additional equipment in the near term 

for more FGD projects, it is very unlikely that we would be able to receive all needed 

equipment in time to meet the proposed 2013 deadline. As a consequence of this large 

demand, TVA has already experienced a considerable number of equipment quality 

issues, which were identified during the startup and commissioning phase at Paradise. 

These equipment issues add delays to the construction schedule. Because of this heavy 

demand, TVA and other utilities are seeing delivery times moving out. Not all utilities 

have placed orders for their presently planned FGD projects, which make some current 

proposed installation schedules unrealistic. 

There are two major concrete stack suppliers in the US. All of the TVA FGD Projects 

will require the construction of new stacks to handle the wet flue gas emitted by the 

FGDs. In an effort to try and mitigate this resource issue, TVA has developed a preferred 

vendor arrangement with one of these two suppliers to erect all of the stacks required to 

support the FGD installations. Construction of the Kingston FGD stack was pushed out 
Page 29 of 65 

several months because of the high demand on TVA’s stack supplier. TVA has been told 

by the concrete stack vendors that they are booked through 2008. TVA was only able to 

get a slot because of our program commitment with our preferred vendor. Once a stack 

contract is awarded, construction then takes several months to erect the shell of the stack, 

which for safety reasons, prevents other work on the majority of the FGD process island 

from progressing until the shell is completed. Following the completion of the shell, 

construction of the Fiberglass Reinforced Plastic (FRP) liner takes several more months 

to install. There are only three FRP vendors, which are all presently in great demand as 

well. 

There are two major manufacturers of recycle pumps. These pumps circulate the 

water/slurry in the absorber tanks and are the hearts to the operation of conventional and 

dual spray tower FGDs (See Exhibit 6.6.1, FGD Construction Photo D). The Paradise 

FGD has 11 recycle pumps rated at 48,400 gpm driven with 1100 hp motors. Delivery 

times for these pumps have gone from 36-38 weeks in 2003 to 65-70 weeks in 2006 

because of the high demand. To follow the proposed plan by Mr. Staudt, the recycle 

pump demand for the TVA FGD Projects alone would be equal to the total capacity of 

the two proven vendors (Weir and GIW) for three years with no availability for any other 

utilities11. 

There are three major suppliers for ball mills. Delivery of ball mills for the Paradise 

FGD Project took 40 weeks and TVA is now seeing deliveries on the order of 80 weeks, 

which likely will increase due to the number of FGDs being constructed and the need for 

mills in the cement and other industries. 

For electrical equipment, delivery times for large motors (> 1500 H.P.) have increase 

significantly from 40-42 weeks in 2003 to 60 weeks in 2006. Transformer delivery times 

are on the order of 40 weeks after an initial 12 weeks of engineering work and 

approximately 28 weeks for manufacturing following drawing approval. 

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■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■.

10 

3.5 Permitting Issues 

Most of the TVA sites will require solid waste permits for the disposal of the solid waste 

resulting from the FGD process. The EPA discusses solid waste landfill permitting 

issues in “Corrected Response to Significant Public Comments on the Proposed Clean 

Air Interstate Rule”1

. According to the EPA, “the time required to obtain these permits 

could range from 1 to 3-1/2 years”. TVA has typically found that an average of 3 years is 

required to obtain new solid waste landfill permits for FGD byproduct storage and 

disposal. There are site specific factors that can increase the amount of time required to 
Page 30 of 65 

obtain permits (i.e., karst at Colbert Fossil Plant, needing land at John Sevier Fossil 

Plant). For the FGD Project at John Sevier Fossil Plant, TVA is looking at a four year 

cycle to obtain a solid waste permit because of the land purchase requirement. 

TVA is also subject to the requirement of the National Environmental Policy Act 

(NEPA). Each Environmental Assessment (EA) required by NEPA takes approximately 

one year to generate and each EA, when one is needed, must be completed before 

construction of the permanent facility can begin on any given project. Another potential 

hurdle on the horizon is New Source Review (NSR). In New York v. United States 

Environmental Protection Agency, 413 F.3d3 (D.C. Cir. 2005), the Court of Appeals 

invalidated EPA’s regulation creating a pollution control exclusion from New Source 

Review12. NSR permitting requirements could also increase the length of the permitting 

process for new emission control installations according to the pending decision in the 

DC circuit court of appeals. 

Mr. Staudt’s report does not take into consideration the extent of work nor the amount of 

time required to obtain the proper permitting for FGD, SCR and SNCR installations. 

3.6 Other Issues 

There are other issues that are affecting TVA’s ability to design, procure, install, and 

commission FGD Projects. For Paradise, TVA was able to get a number of acceptable 

bids for drilled shafts, absorber erection, relocation of utilities and non-outage ductwork 

(to name a few). TVA attributes this to starting the project early and being ahead of most 

of the other utilities. Now that most utilities are well into their FGD Programs, most of 

the qualified contracts are getting booked up. TVA is now getting few acceptable bids 

for the Bull Run Project and TVA has serious reservations that enough acceptable bids 

will be received for all the material, equipment and constructors for the Kingston and 

John Sevier Projects. This may force TVA to change its contracting model and adversely 

affect our ability to negotiate fixed price contracts, which will drive the costs of these 

projects even higher. 

Out year projects have not been assessed and site relocations may be required to retrofit 

new FGDs on the TVA sites. In addition to the known challenges, unknown challenges 

have and will continue to affect FGD installations. For example, Hurricane Katrina in 

August 2005 affected the engineering team based in New Orleans working on TVA’s 

FGD Program and delayed engineering on the Bull Run Project several months. 

Hurricane Katrina also adversely affected the schedule for Paradise Unit 3 because of 

delays in responding to construction issues and delayed the design of the Kingston FGD 

project approximately 4 months. Also, the recent Falk warehouse fire in Milwaukee 

destroyed all of the Bull Run recycle pump gear boxes. TVA is currently working with 

the recycle pump vendor to assess the effects of the Falk fire on the equipment delivery 

and installation schedule. With the stretched resources in manpower, materials and 

equipment there is no margin for error. Unavoidable events, such as Katrina, can have 

major impacts on the schedules of these projects. 
Page 31 of 65 

4. 0 Program Cost Forecasts 

TVA’s clean air program is seeing significant cost increases resulting from the market 

demand on materials, equipment and craft. The EPA discusses cost increases that were 

seen during the NOX SIP Call in “Corrected Response to Significant Public Comments on 

the Proposed Clean Air Interstate Rule”1. The EPA acknowledged that cost increases 

were “most likely due to increase in construction costs (resulting from increased demand 

for boilermaker labor) and steel prices”. These concerns were a contributing factor that 

led to the EPA two-phase approach for the CAIR to keep utilities from having near-term 

shortages of critical resources. 

Mr. Staudt’s Expert Report also significantly underestimates the total capital cost of the 

retrofit program for TVA to meet the CSA equivalent emissions rate for NOx and SO2 at 

just under $3 billion (provided in his report in 2006 dollars). Mr. Staudt acknowledges in 

his report that actual costs will differ from his estimate based upon site-specific factors 

that determine the difficulty of retrofits, market pricing of material and labor and other 

factors. TVA’s estimate of the capital cost required is approximately $5.0 billion (in 

2006 dollars), which is 69% higher than the estimate provided by Mr. Staudt. This 

estimate is based on TVA’s actual costs incurred for completed projects to install FGDs, 

SCRs and SNCRs as well as detailed cost estimates and updated forecasts for ongoing 

and future projects. A summary of the estimated costs to install emissions controls per 

Mr. Staudt’s proposed plan is shown in Table 1. 

An example of the underestimates in Mr. Staudt’s report is his prediction that it will cost 

$172,003,000 to install a scrubber on the unit at TVA’s Bull Run Fossil Plant. TVA’s 

current forecast for the FGD at Bull Run, with the project approximately 50% complete 

and engineering approximately 85% complete, is $313,355,000. This is over an 82% 

increase above Mr. Staudt’s estimate. Mr. Staudt also estimates that the cost to install a 

FGD on Colbert Unit 5 would be $137,631,000. TVA’s current forecast is $264,574,000, 

which is based upon a detailed target cost estimate that was completed in 2004. This is a 

92% increase to Mr. Staudt’s estimate. For comparison to another utility, Duke Energy’s 

cost to install a FGD on a similar sized unit at Cliffside 5 is projected to cost 

$252,176,300 (not provided in 2006 dollars)4

. TVA is confident in our projections for 

the costs required to complete the FGD projects, which are based on TVA’s actual 

experience to install FGDs on several units (Cumberland Units 1&2 and Paradise Unit 3 

being the most recent), input from Advatech, benchmarking with other utilities and an 

extensive program review on cost and schedule conducted by Bechtel. 

Detailed schedule, manpower and cost charts for FGD, SCR and SNCR installations are 

provided in the attachments located at the back of this document. 
Page 32 of 65 

Table 1. 
Page 33 of 65 

5.0 Conclusions 

According to the Expert Report from James E. Staudt, to meet the equivalent emission 

requirements of North Carolina’s Clean Smokestack Act (CSA), TVA would have to 

install FGDs on 51 additional units, SCRs on 22 additional units and SNCRs on 14 

additional units. Of equal significance to the additional emission controls that Mr. Staudt 

contends are required, is the requirement to have all of these emission controls installed 

by 2013. To complete the proposed emission control projects by 2013 would require the 

installation of FGDs on ■■ additional units, SCRs on ■■ additional units and SNCRs on 

■■ additional units beyond the current TVA Clean Air Plan.. This schedule requirement 

is unrealistic, impractical and would outstrip many key resources that are already proving 

to be incapable of meeting the current demands created by the utility industry trying to 

meet the emission requirements imposed by EPA’s CAIR. 

TVA’s Clean Air Plan to meet the emission requirements of the EPA CAIR includes the 

installation of FGDs on ■■ additional units, SCRs on ■■ additional units and SNCRs on 

■■ additional units by 2018. This is in addition to the 7 units currently equipped with 

FGD scrubbers, the 21 units currently equipped with SCRs and the 3 units currently 

equipped with SNCRs on the TVA Fossil Generation Fleet. Other utilities are 

experiencing the same issues as TVA and accelerating the implementation of emission 

control projects cannot be handled with the present infrastructure for the personnel, 

material, environmental permitting and equipment. TVA is already concerned with 

meeting the current TVA Clean Air Plan based on the CAIR because of the issues 

discussed in this document. 

The EPA has reported increased difficulty with retrofitting emission controls on smaller 

fossil units as opposed to larger units, and acknowledges that high demand for craft and 

professional personnel would be caused by accelerating the CAIR1

. There is already a 

need for several thousand craft personnel in TVA’s territory and surrounding areas, 

which exceeds what has been available historically. Because of the lack of qualified 

technical, project management, construction management and craft personnel, it is 

unlikely that all of the utilities will be able to maintain their present FGD installation 

schedules. There is not sufficient manpower available in the Tennessee Valley Region to 

support Mr. Staudt’s proposed plan. 

Materials and equipment are getting harder to procure with delivery times that can meet 

the current TVA Clean Air Plan. The accelerated emission control schedule proposed by 

Mr. Staudt is not practical given the two facts that: 1) Mr. Staudt’s proposed plan would 

require a recycle pump demand for TVA that is equal to the total capacity of the two 

main vendors (Weir and GIW) for three years with no availability for other customers11, 

and 2) Mr. Staudt’s proposed plan would require absorber and structural steel shop space 

equal to the combined full capacity of two main vendors (PSP and Cives) for three years 

with no other customers11. 

Mr. Staudt significantly underestimates FGD and SCR project durations in his expert 

report. A typical FGD project installation requires 5 years from conceptual design to 
Page 34 of 65 

commercial operation. A typical SCR project installation requires 3 to 4 years from 

conceptual design to commercial operation. Mr. Staudt’s expert report also significantly 

underestimates the total capital cost of the retrofit program for TVA to meet what Mr. 

Staudt conceives to be the CSA equivalent emissions rate for NOx and SO2 at just under 

$3 billion (provided in his report in 2006 dollars). TVA’s estimate of the capital cost 

required is approximately $5.0 billion (in 2006 dollars), which is 69% higher than the 

estimate provided by Mr. Staudt. 

TVA has developed a comprehensive emission control strategy from past experience on 

FGD, SCR and SNCR installations and is working diligently to meet the requirements of 

the CAIR. TVA is confident in our projections for the time needed and cost required to 

complete the emission control projects, which are based on TVA’s actual experience to 

install FGDs, SCRs and SNCRs, input from Advatech, benchmarking with other utilities 

and a FGD program cost and schedule review conducted by Bechtel. The assumptions 

made in the expert report written by Mr. Staudt create impractical schedules and 

unrealistic capital costs for accelerating TVA’s Clean Air Plan. Simply stated, the 

accelerated emission control installation schedule proposed by Mr. Staudt cannot be 

achieved by 2013 because of the enormous amount of work required and the limiting 

critical resources available.
Page 35 of 65 

6.1 CV 

Ronald D. Nash 

34 Cool Springs Rd., Signal Mountain, Tennessee 37377 

rdnash2@tva.gov 

(423) 751-3876 | (423) 751-9149 (fax) 

EDUCATION 

June 1998 OWENS GRADUATE SCHOOL OF MANAGEMENT AT VANDERBILT Nashville, TN

Executive Development Program 

February 1987 TEXAS A&MUNIVERSITY College Station, TX

 Construction Executive Program

March 1971 THE OHIO STATE UNIVERSITY Columbus, OH 

 Bachelor of Science in Civil Engineering 

 Construction Management Major 

Chi Epsilon - Civil Engineering Honorary Fraternity 

EXPERIENCE 

2006-Present TENNESSEE VALLEY AUTHORITY Chattanooga, TN

Manager of Environmental Projects-FGD Program Fossil Power Group 

Total Project Responsibility including engineering, procurement, construction, start-up and 

testing, for TVA’s Scrubber Program for the installation of Flue Gas Desulfurization (FGD) 

retrofits for 36 coal fired units with a capital cost forecast of over $4 billion

1999-2006 Manager of Environmental Projects-NOx Reduction Program Fossil Power Group 

Total Project Responsibility including engineering, procurement, construction, startup and testing for the installation of Selective Catalytic Reduction retrofit projects on 

21 coal fired units two different Selective Non-Catalytic Reduction technologies on 4 

coal fired units with a total capital cost of over $1.4 billion. 

1997-1999 Manager of Generation Services-Synterprise Group

Responsible for coordinating and managing all external business opportunities for Fossil 

and Hydro Power. Responsible for distributed generation project for TVA, including 

implementation of projects within the Valley and total accountability for projects outside 

the Valley. Responsible for managing TVA’s business opportunities in India with the Tata 

Electric Companies. 

1993-1997 Manager of Modification Services-Fossil and Hydro Power 

Responsible for managing Fossil & Hydro Power’s supplemental maintenance and 

modifications work through long-term agreements with NPS Energy Services, G.UB.MK 

(Gilbert Commonwealth, Union Boiler, Morrison-Knudsen), and Williams Power. 

Duties and responsibilities include: Principle interface and advocate for modifications 

partnering and management of the partnering relationship; manages the performance and 

incentive process, including overall analysis and recommend improvements for consistency 

in TVA/partner business practices and procedures management; oversight and contract 

management for work sampling; multi-site issue resolution, including inconsistency, 

conflict and disputes; regional overhead issues and resolution, establishing and managing 

the baseline process including benchmarking and targets for improvement; system-wide 

processes to manage indirect costs, such as OCIP (owner-controlled insurance program), 

ADP, facilities, staff, etc. Served as Fossil and Hydro Power’s representative on the Joint 

Administrative Council to resolve Trades and Labor grievances with TVA’s contractors. 
Page 36 of 65 

1979-1993 BLOUNT, INC Montgomery, AL 

1992-1993 Senior Project Manager Cross, SC 

Project management responsibility for the piping, equipment installation, and insulation 

contract for a 450-MW coal-fired unit at Santee Cooper’s Cross Generating Station. The 

scope of responsibilities included the installation of all piping and mechanical equipment, 

furnishing and installation of all piping insulation, and design furnishing and installation of 

all heat tracing. 

1986-1992 Project Director Montgomery, AL

Responsible for managing multiple projects. Responsible for staffing, monitoring schedule 

progress, cost forecast, contract changes, and change orders and estimating. Projects 

supervised as Project Director: A contract with Public Service of Indiana (PSI) to provide 

maintenance services to all the fossil power plants in PSI’s System. An $18 million 

contract to provide all labor and construction equipment to install the foundations, support 

steel, duct work, electrical equipment, power and control wiring, conduit and cable trays. 

This work was performed on a precipitator replacement project for two 650-MW units at 

PSI’s Gibson Station. A $10 million lump-sum contract for the installation of a new 

processing facility for Burroughs Welcome Company to manufacture the drug AZT. A 

cost-reimbursable contract with Louisville Gas and Electric to provide maintenance 

services for their fossil generating stations. A $25 million contract for a pharmaceutical 

plant expansion for Bausch & Lomb. A $65 million contract to rebuild the number one 

paper machine at Union Camp’s Prattville, Alabama mill which included a new waste 

paper processing facility, a new extended nip press, a new winder, and a new vacuum 

system. A $43 million contract to engineer, procure and construct a 64-MW combined 

cycle co-generation plant for Energy Factors in Greeley, Colorado. 

1983-1986 Project Director Counce, TN 

Project management responsibility for engineering, procurement, and construction of paper 

machine modifications (including an extended nip press) and for increasing the capacity of 

the waste paper processing facility. In addition, had responsibility for engineering, 

procurement, and construction of a 550,000-pound per hour multi-fueled boiler and turbine 

generator and associated fuel handing facilities. Managed a staff of 24 salary personnel and 

550 craftsmen at peak. Approximate contract value was $72 million. 

1979-1983 Project Engineer Lakeland, FL 

Responsible for all estimating, cost-engineering, contract administration, planning, 

scheduling, and field engineering for the construction of a 365-MW coal-fired power plant 

for the City of Lakeland, Florida. 

1978-1979 ALPHA LAVAL PROCESS GROUP Keokuk, IA 

Construction Manager 

Responsible for managing the design and construction of a wheat processing facility for 

General Mills Chemical Corporation. 

1975-1978 BLOUNT BROTHERS CORPORATION Conesville, OH 

Subcontract Supervisor 

Responsible for coordinating contracts for erection of the boiler and turbine generator for 

two 400MW coal-fired units for the Columbus and Southern Ohio Electric Company. 

1971-1975 COLUMBIA GAS TRANSMISSION CORPORATION Columbus, OH 

Compressor Engineer 

Responsible for budget preparation and cost forecasting for compressor station modification 

and for resolving contractor interferences and engineering discrepancies. 
Page 37 of 65 

6.2 Specification of Compensation 

I prepared this report as part of my job duties and received only my normal compensation 

from TVA for this work. None of my compensation is linked to the outcome of this case. 
Page 38 of 65 

6.3 List of all Publications Authored in the Preceding Ten Years 

None 
Page 39 of 65 

6.4 List of Other Cases - - Testimony as an Expert at Trial or by Deposition within the 

Preceding Four Years 

None
Page 40 of 65 

6.5 List of Data or other Information Considered in Forming the Opinions 

6.5.1 References 

1. “Corrected Response to Significant Public Comments on the Proposed Clean Air 

Interstate Rules”, Docket No. OAR-2003-0053, by the Environmental Protection 

Agency, dated April 2005. 

2. “Report of Proceedings of Public Hearing on Proposed Adoption of Rule 15A 

NCAC 02D Section .2400 Clean Air Interstate Rules”, Department of Environment 

and Natural Resources, Division of Air Quality, Environmental Management 

Commission; Charlotte, North Carolina, January 5, 2006; Raleigh, North Carolina, 

January 11, 2006. 

3. “Implementation of the “Clean Smokestacks Act””, Information provided by 

Progress Energy Carolinas, LLC and Duke Energy Carolinas, LLC, dated June 01, 

2005. 

4. “Implementation of the “Clean Smokestacks Act””, Information provided by 

Progress Energy Carolinas, LLC and Duke Energy Carolinas, LLC, dated June 01, 

2006. 

5. http://www.eia.doe.gov/cneaf/electricity/epa/epat2p4.html, Energy Information 

Administration, Official Energy Statistics from the US Government, Existing 

Electric Generating Units in the United States, 2004. 

6. “Tennessee Valley Authority Scrubber Program Evaluation Study”, submitted by 

Bechtel Power Corporation, February 4, 2004 (Confidential Information). 

7. ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■

■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■. 

8. “The Effect of SO3 Sorbents on ESP Performance: A State-of-the-Art Review”, 

EPRI, Palo Alto, CA: 2006. 1013348. 

9. “SO3 Mitigation Guide Update”, EPRI Technical Report No. 1004168 dated March 

2004. 

10. ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■

■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■

■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■. 

11. Assessments made by Timothy E. Thomas, the Program Director for Tennessee 

Valley Authority FGD Installations, of Advatech, LLC, A Company of URS and 

Mitsubishi Heavy Industries America. 

12. New York v. United Stated Environmental Protection Agency, 413 F.3d 3 (D.C. Cir. 

2005). 
Page 41 of 65 

6.5.2 Manpower Backup Data (Page 1) 
Page 42 of 65 

6.5.2 Manpower Backup Data (Page 2) 
6.5.3 Cost Backup Data (Page 1) 
6.5.3 Cost Backup Data (Page 2) 
Page 45 of 65 

6.6 Exhibits not Included in the Body of the Report 

6.6.1 FGD Construction Photos 

Paradise Unit 3 FGD Project Absorber Area 3-D Model A. 

Paradise Unit 3 FGD Project Absorber Area 3-D Model B. 
Page 46 of 65 

6.6.1 FGD Construction Photos 

Paradise Unit 3 FGD Project Absorber Area 3-D Model C. 
Page 47 of 65 

6.6.1 FGD Construction Photos 

Paradise Unit 3 FGD Project Absorber Area Construction Photo A. 

Paradise Unit 3 FGD Project Absorber Area Construction Photo B. 
Page 48 of 65 

6.6.1 FGD Construction Photos 

Paradise Unit 3 FGD Project Absorber Area Construction Photo C. 

Paradise Unit 3 FGD Project Absorber Area Construction Photo D. 
Page 49 of 65 

6.6.1 FGD Construction Photos 

Paradise Unit 3 FGD Project Absorber Area Construction Photo E. 

Paradise Unit 3 FGD Project Absorber Area Construction Photo F. 

 
Page 50 of 65 

6.6.1 FGD Construction Photos 

Paradise Unit 3 FGD Project Absorber Area Construction Photo G.
Page 51 of 65 

6.6.1 FGD Construction Photos 

Paradise Unit 3 FGD Project Absorber Area Construction Photo H. 
Page 52 of 65 

6.6.1 FGD Construction Photos 

Paradise Unit 3 FGD Project Ball Mill Area 3-D Model A. 

Paradise Unit 3 FGD Project Ball Mill Area 3-D Model B. 
Page 53 of 65 

6.6.1 FGD Construction Photos 

Paradise Unit 3 FGD Project Ball Mill Construction Photo A.

Paradise Unit 3 FGD Project Ball Mill Construction Photo B. 
Page 54 of 65 

6.6.1 FGD Construction Photos

Paradise Unit 3 FGD Project Ball Mill Construction Photo C. 

Paradise Unit 3 FGD Project Ball Mill Construction Photo D. 
Page 55 of 65 

6.6.1 FGD Construction Photos 

Bull Run Unit 1 FGD Project 3-D Model A.

Bull Run Unit 1 FGD Project 3-D Model B. 
Page 56 of 65 

6.6.1 FGD Construction Photos 

Bull Run Unit 1 FGD Project 3-D Model C. 

Bull Run Unit 1 FGD Project 3-D Model D. 
Page 57 of 65 

6.6.1 FGD Construction Photos

Bull Run FGD Project Construction Photo A. 

Bull Run FGD Project Construction Photo B. 
Page 58 of 65 

6.6.1 FGD Construction Photos 

Bull Run FGD Project Construction Photo C.

Bull Run FGD Project Construction Photo D. 
Page 59 of 65 

6.6.2 SCR Construction Photos 

Paradise Unit 1 SCR Project Construction Photo A.

Paradise Unit 3 SCR Project Construction Photo A.
Page 60 of 65 

6.6.2 SCR Construction Photos 

Allen SCR Project Construction Photo A.

Allen SCR Project Construction Photo B. 
Page 61 of 65 

6.6.2 SCR Construction Photos 

Bull Run SCR Project Construction Photo A.

Bull Run SCR Project Construction Photo B. 
Page 62 of 65 

6.6.2 SCR Construction Photos 

Bull Run SCR Project Construction Photo C. 

Bull Run SCR Project Construction Photo D. 
Page 63 of 65 

6.6.2 SCR Construction Photos 

Bull Run SCR Project Construction Photo E. 

Bull Run SCR Project Construction Photo F. 
Page 64 of 65 

6.6.2 SCR Construction Photos 

Cumberland SCR Project Construction Photo A. 

Cumberland SCR Project Construction Photo B. 
Page 65 of 65 

6.6.2 SCR Construction Photos 

Paradise Unit 3 FGD, SCR and Fossil Unit Photograph 2007.