Page 2 of 65 Table of Contents

1. Narrative Summary of Credentials

2. Executive Summary

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

Emission Controls at Fossil Po wer Plants - Introduction

3.1. Schedule Issues

3.1.1. FGD Installations

3.1.2. SCR Installations

3.1.3. SNCR Installations

3.1.4. SO 3 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 Author ed 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 PhotosPage 3 of 65 1.0 Narrative Summary of Credentials

I am currently the Program Manager for the Tennessee Valley Aut hority (TVA) directing the design, procurement, installation and co mmissioning 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 assignmen ts with responsibilit ies including: 1) Oversight of TVA’s Fossil Power Maintenance and Modification Partne rs, 2) Director of

TVA’s External Business for Domestic and In ternational Power Rela ted Projects, and 3) Design, procurement, installation and comm issioning of numerous emission reduction projects for TVA’s Fossil Power Group.

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

NO

x Reduction Program from 1999 though 2006, wh ich 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 pr ogress to install wet limestone-for ced 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 cont ends 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 projec ts 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 requi rement is unrealistic, impractical and would outstrip many key res ources that are alr eady proving to be incapable of meeting the current demands cr eated 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 cont rols by 2013 is clearly theoretical and lacks the proper analysis of the market capabilit y. 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 pr oven vendors (Weir and GIW) for three years with no availability for a ny other utilities 11

.

Mr. Staudt’s Expert Report also significantl y underestimates the total capital cost of the retrofit program for TVA to meet what St audt conceives to be the CSA equivalent

emissions rate for NO

x and SO 2 at just under $3 billion (pro vided in his report in 2006 dollars). Mr. Staudt acknowledges in his repo rt that actual costs will differ from his estimate based upon site-specific factors that de termine 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 estima te is based on historical TVA costs incurred for completed projects to install FGDs, S CRs 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% comp lete, is $313,355,000. This is over an 82%

increase above Mr. Staudt’s estimate. Mr. Sta udt 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 es timate 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 un it at Cliffside 5 is projected to cost $252,176,300 (not converted to 2006 dollars) 4

.

Mr. Staudt’s report doesn’t address schedul e implications of the proposed accelerated plan. A typical FGD project installation duration from con ceptual design to commercial operation averages 5 years. A typical SCR pr oject 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 schedul e implications of the

SNCR and SO 3 mitigation projects that must be worked in conjunction with the new

installation of FGDs and SCRs. TVA is conf ident in our projections for the time needed to complete FGD and SCR projects, whic h 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 utili ties 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 ne xt 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 sche dule placed on the utility companies to meet CAIR has exceeded the market capacity fo r many critical resources. For this reason and others discussed in this report, acceler ating TVA’s Clean Air Plan from the current

schedule is not achievable.Page 6 of 65 3.0 Issues with Accelerating Tennessee Valle y 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, procur ement, 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 a nd craft personnel available to accomplish the presently planned work. Materials and equi pment are getting harder to procure with delivery times that meet the present constr uction schedules. As each week passes, the delivery times for both materials and engineer ed 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 accel erates the TVA Clean Air Plan for the

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

Assumptions provided in Mr. Sta udt’s report and stressed in Paragraph 60 A, pg. 30 of S. Tierney’s Expert Report, that the developmen t, 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 pr ovided 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 (T VA’s current air strategy is shown in Figure

1 - Table A ) that was developed from past expe riences 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 em ission 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 undert aken 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’ signi ficant contribution to downw ind 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 Res ources, 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 sc rubbers and other appr opriate control and monitoring equipment in place for the large population of sources impacted by CAIR” 2

. TVA’s Clean Air Plan is structured to inst all 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 di fficulty with retrofitting emission controls on smaller fossil units as opposed to larger uni ts. Hence, a two-phased approach is used in the CAIR regulations so that utilities w ould have time to properly study and complete activities necessary to retrofit smaller units with FGDs, SCRs and SNCRs. Phase I places permanent caps on NO

x emissions in 2009 and SO 2 emissions in 2010. Phase II places more stringent permanent caps on NO

x and SO 2 emissions in 2015. After the Bull Run FGD Project, only eight of the 39 remaining fo ssil 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. St audt’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 pla nned for 8 fossil units (1 unit being over 200 MWs) in the Progress Energy Fleet totali ng 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 inst allations are not even planned for 15 of the 27 fossil units in the Duke Energy Fl eet totaling 1336 MWs (o r 19%) of generation not being scrubbed. This information is ava ilable in the “Implement ation of the ‘Clean

Smokestacks Act’ ” reports from 2005 3 and 2006 4 with some supporting information on the size of the Duke Power units coming fr om the Energy Information Administration

Website 5 . Mr. Staudt’s proposed plan also has TVA installing SCRs (the most expensive

NO

x control technology yielding th e highest removal) on 43 of the 59 fossil units. SCR installations are not even pla nned for 7 of the 18 fossil units on the Progress energy fleet totaling 1512 MWs (or 30%) of generation without an SCR 4 . 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 SCR 4

.Page 9 of 65 TVA is working diligently to meet the requirements of the CAIR and has serious

concerns whether the current clean air strate gy 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 T VA Fossil Generation Fl eet for FGD and SCR projects. The assumptions made in the e xpert report written by Mr. Staudt create impractical schedules and unrealistic capital cost estimates for accelerating TVA’s Clean Air Plan. The proposed accelerated installa tion schedule for emission controls by Mr. Staudt is not achievable by 2013 because of several critical limited resources. TVA contends, through actual construction experi ence and benchmarking experience from other major utilities, that Mr. Staudt’s proposed schedule is not practical -- indeed, not

even achievable -- and his estimate d cost is significantly understated.

3.1 Schedule Issues

In addition to the heavy demand for FGD inst allations for the next several years, TVA and the other utilities must carry out their normal outage work and th e 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 pow er. 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 curr ent schedule, which has already exceeded market capacity, is not achievable for the r easons that are discu ssed in this report.

3.1.1 FGD Installations

There are a variety of emission contro l technologies available to reduce SO 2 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 majo r companies (URS and Mitsubishi Heavy Industries or MHI). TVA has a program cont ract with Advatech for all of the ongoing

and future FGDs on the TVA fleet. In la te 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 cons truction experience with the MHI new generation FGDs, 2) the partnership with A dvatech, LLC for the FGD Program was new, 3) TVA wanted a third party evaluation of our budgetary es timates, and 4) TVA wanted to ensure the proposed schedule for engi neering, 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 toPage 10 of 65 the Bechtel report issued on February 4, 2004, “The current over all program schedule [Note: The Program Schedule at that time wa s only for the installation of FGDs at the Paradise, Bull Run, Colbert and Ki ngston Fossil Plants] is feasib le, 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 sc hedule 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 th e equipment that is required to operate the system. Wet limestone technology uses fi nely crushed limestone to react with the

SO 2 in the flue gas. The limestone composition must contain a high percentage of calcium carbonate (CaCO 3 ) for the reaction to achieve the high SO 2 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 slu rry is circulated in the absorber to ensure

the efficient contact with the fl ue gas needed for removal of SO 2

. Figure 2-B and Figure

2-C illustrates what occurs in the MHI absorber.

The SO 2 in the flue gas is slightly soluble in water. The transfer of SO 2 to the water phase occurs at the vapor/liquid interf ace in the absorber. In solution, the SO 2 ionizes and transfers to the interior of the liquid. The increased acidity of the water increases the solubility and ionization of the CaCO 3 content of the limestone. In solution, the reaction

of SO 2 with CaCO 3 will form calcium sulfite (CaSO 3 ) if sufficient quan tities of oxygen

are not present.

CaSO 3 is undesirable as a reaction product so oxygen is introduced into the liquid to ensure that the reaction produces calcium sulf ate. Calcium sulfate has limited solubility in water and precipitates as gypsum (CaSO 4 . 2H 2 O). 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 CaCO 3, limestone slurry is continuously supplied to the reaction. Figure 2-D is a hierarchy of major limestone preparation and absorber area engineered eq uipment 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 StackPage 12 of 65 Figure 2-C.

Figure 2-D.Page 13 of 65 The Paradise Unit 3 FGD system has severa l areas unique in f unction and operation. These areas include limestone handling a nd preparation, absorber, water supply and balance of plant. All equipment and pro cesses 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 hour s 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 th e wet scrubbing process. The limestone preparation system for the Paradise Un it 3 Project alone cost over $35 million to

construct.

The absorber area includes the twin towe r absorber, slurry recirculation system, forced oxidation air, as well as all flue ga s ducting associated with the FGD system. The water supply system includes all water handling facilities associated with raw and treated water. Slurry transfer sy stems for both limestone and gypsum are included. The balance of plant includes su ch services as cranes and hoists, HVAC, fire protection, plant air, a nd building services. The abso rber 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 fl ue 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 limest one slurry to form gypsum slurry. After leaving the absorber, the desu lfurized flue gas passes th rough 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, Detaile d - 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 appr oximately 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 out age was needed to install DCS equipment, which took approximately 12 days and was ag ain during a planned plant outage. The third outage was needed for the FGD DC S tie-in and fan verification, which took approximately 10 days.Page 14 of 65 The amount of materials that is required to construct F GDs on large coal fired power plants is massive. The Paradise Unit 3 F GD 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 electr ical and control wiri ng 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 conc rete (the FGD and Limestone Areas are designed together at Bull Run). The Abso rber Area construction at Paradise Unit 3 required installation of over 4,400 tons of st eel for structures a nd buildings (mix of carbon and alloys). The Absorber Area construc tion at Bull Run estimat es to install over 3,400 tons of steel for structures and buildings (mix of carbon a nd alloys). For large bore piping, the Paradise Unit 3 FGD Project instal led greater than: 8,000 lin ear feet of carbon steel, 13,000 linear feet of st ainless steel, 28,000 linear feet of Heavy Duty Polyethylene (HDPE) and 3,500 linear feet of Fiberglass Re inforced 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 st eel, 1000 linear feet of Heavy Duty Polyethylene (HDPE) and 2,000 linear feet of Fi berglass Reinforced Plastic (FRP). For ductwork, over 1500 tons were installed duri ng the Paradise Unit 3 FGD construction and greater than 1100 tons are estimated for the Bull Run FGD construc tion. These are only a few examples of the massive amounts of ma terial required on projects of this magnitude.

The construction of retrofit em ission control projects, as op posed to building controls as part of a new unit, usually adds uni que challenges because of limited space around the coal fired units to add the large struct ures 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 Paradi se 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 severa l 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. C oordination of these a nd like efforts are massive and time consuming to major project schedules.

To summarize the information provided a bove 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 Projec ts range between 5 and 8 years 3&4 (Marshall - 5 years, Belews Creek - 6 years, Allen - 7 y ears and Cliffside - 8 years). TVA completed

installation of the Paradi se 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. Construc tion began on the FGD for Paradise Unit 3 prior to the current high demand on the market for manpow er, materials and equipment. TVA isPage 15 of 65 confident in the projections for the time a nd manpower needed to complete the FGD projects, which are based on TVA’s actual e xperience to install FGDs on several units (Cumberland Units 1&2 and Paradise Unit 3 being the most recent), input from Advatech, benchmarking with ot her utilities and an extensiv e program review on cost and schedule conducted by Bechtel Power Corporation.Page 16 of 65Figure 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 NO

x removal process and the equipmen t that is required to operate the system. A SCR is a control technology where (NO

x ) formed in the coal combustion process is removed by the injection of ammonia (NH 3 ) into the flue gas. This process consists of injecting ammonia (NH 3 ) into boiler flue gas and passing the flue gas through a stationary catalyst bed where the NO

x and NH 3 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 m 3 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 + 4NH 3 + O 2 Æ 4N 2 + 6H 2 O

and

2NO 2 + 4NH 3 + O2 Æ 3N 2 + 6H 2 O

The SCR process reaction is most effec tive within a temperature range of 600 o F to 750 o F. Figure 4-B shows the process reaction that oc curs inside of SCRs. Above 750 o F, the effect of catalytic sintering becomes prominent in lowering NO

x reduction performance.

Below 600 o F, the susceptibility of ammonium bisulfate (NH 4 HSO 4 ) formation on catalyst surfaces increases resulting in lower NO

x 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 gene rally there is limited space av ailable to install the reactor for the technology, which are very large st ructures (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 NH 3 Injection

S C R

R

e a c t o r 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 LayerPage 20 of 65 There is really not a typical SCR constructi on because each SCR project is unique based on the size of the unit and complexity with th e 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 th e 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 Proj ect alone. The initial engineering effort spanned from October of 2000 to early Su mmer of 2001 when construction on the new SCR began. The SCR construction was perfor med by TVA’s maintenance partners. The construction sequence for SCRs generally bega n by installing flue gas by-pass ducts to provide the necessary space to install the f oundations, 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 stru ctures (i.e., old electro static precipitators)

that had to be demolished to make room fo r the reactor vessel. Once the SCR was ready for commercial operation, another Unit outag e was required for final duct tie-in. The Paradise Unit 3 SCR construction took appr oximately 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 to ns 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 materi al required on projects this large.

As noted earlier, the construction of retr ofit emission control projects usually encompasses unique challenges because of lim ited 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 S CR 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 in stall ash hoppers and SCR ductwork between

the economizer outlet and the air heater inlet. This installa tion required the removal and installation of steel suppor t 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 a bove 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 years 3&4 . TVA completed installation of the Kingston SCR Projects on Un its 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 fu ture 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-Contra ct Investigations and the Technical Evaluations for the SCR vendors prio r to contract award. These two activities could take up to 6 months to complete. Al so, 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 proj ections for the time a nd 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 ri ght being the existing Fossil Unit. The purpose of this photograph is the show the enormity of the em ission control structures with their size being nearly that of th e fossil unit itself.Page 22 of 65Figure 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 NO

x 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 NO

x to water vapor and nitrogen. The correct location for injection and number of inje ctors are determined by field testing and Computational Fluid Dynamics (CFD) modeling. Injection may occur at different boiler

elevations at different unit lo ads 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 NO

x 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 prelim inary engineering to commercial operation can range from 9 to 18 months.

3.1.4 SO 3 Mitigation Installations

Mr. Staudt’s report fails to mention that the combination of fuel switch with installation of the FGD and SCR catalyst resu lts in increased oxidation of SO 2 to SO 3 and thus increased emissions of sulfur trioxide (SO 3 ), a precursor of sulfuric acid emissions. This results in additional requirements for mitigation of SO 3

.

TVA, EPRI and other utilities have been tes ting injections of vari ous sorbents into the gas stream for SO 3 mitigation with varying degrees of success 8&9 . TVA has also been participating in an EPRI sponsored interest group, called the Aerosol Emissions Control Interest Group (AECIG), to share experi ence with other utilities related to SO 3 mitigation technologies. TVA’s own testing experience along with other util ity experience has shown that, in most cases, hydrated lime is the most successful sorbent (of those tested) for removing SO 3 . However, the lime material coats th e 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

SO 3 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 SO 3 mitigation and what units will not require mitigation.

Recent testing at TVA has confirmed that lim e injection is unacceptable at Paradise Unit 3 without modification to existing particulat e control equipment. Future testing is planned for the fossil unit at Bull Run but, w ith the uncertainty of defining a technology prior to testing, TVA is not in a position at this time to fo recast the requirements. While not currently fully defined, TVA estimates that the cost of SO 3 mitigation will be asPage 24 of 65 much, or more than, the cost of the SNCR installations being pr oposed. In summary, SO 3 mitigation must be provided on most plan ts with retrofitted FGD and SCR emission control systems and, while excluded from th e expert report of Mr. Staudt, must be considered in any proper analysis of requi rements, cost and durations for emissions reduction projects involving th e installation of SCR and FGD equipment.

3.2 Manpower Issues

Craft and Technical manpower requirement s 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 personne l and technical/engineering expe rtise. Primary reasons for

the decline in the labor workfor ce are attributable to an agin g workforce that is retiring and a new generation that is not interested in the labor trades. Labor trades, though prospering now, generally offer only seas onal employment requiring significant travel

and sometimes odd/extensive work hours. The EPA discusses manpower concerns in “Corrected Response to Significant Pub lic Comments on the Proposed Clean Air

Interstate Rule” 1 . EPA’s response states that shor tages and bottlenecks in all resources (manpower - specifically boilermakers, c onstruction equipment, engineering and construction staffs belonging to different trades, construc tion materials and equipment manufacturers) caused increase proj ect times and costs during the NO

x 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 NO

x emissions in 2009 and SO 2 emissions in 2010. Phase II places more stringent permanent caps on NO

x and SO 2 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 proj ects. Equipment suppliers are also limited in the support staffs they have to suppor t the commissioning and troubleshooting of their equipment in the field. To support Mr. Sta udt’s proposed plan, Advatech would require over 1000 full time equivalent technical and management personnel with experience in FGD design 10 . 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 wa ge wars that cannot be avoided.Page 25 of 65Figure 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, pi pe 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 ge neration 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 qua lified craft pe rsonnel, it is unlikely that all of the utilities will be able to maintain the present schedules for their SO 2 and NO

x 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 apprenti ce recruitment for Bo ilermakers 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 ge neration projects. The situation could easily progress to craft bidding wars between ut ilities and drive the costs of construction craft significantly higher. Another challenge is that cr aft are commonly pulled from capital project work when planned or forced outages are occurring on the power generating units. The power generating units wi ll 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 pr eviously 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-manua l staff (by 2009) for several years and is located in the same local union regi on 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 w ithin the next couple of years.Page 28 of 65 3.3 Material Issues

With the great demand for material worldwide, alloy materials, st eel, and other building materials are becoming more difficult to obtain in the time period needed to meet the

current FGD construction schedules. Carbon st eel 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 shap es can be used. Deliv eries 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, fabri cators have indicated to TVA a nd 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 structur al steel shop space just for the TVA FGD Projects alone would be equal to the comb ined full capacity of TVA’s two main vendors (PSP and Cives) for three solid years with no availability for any other utilities 11 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 stee l 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 signifi cant amount of these materials for the SCR

installations that would further increa se delivery times and cost.

3.4 Equipment Issues

Because of the demand for FGD installations by utilities to comply w ith CAIR, there is a considerable demand for equipment that is speci fic to FGDs as well as equipment that is

used in FGDs and other industries in lim ited 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 or ders additional equipment in the near term for more FGD projects, it is very unlikely th at we would be able to receive all needed equipment in time to meet the proposed 2013 de adline. As a consequence of this large demand, TVA has already experienced a cons iderable number of equipment quality issues, which were identified during the st artup and commissioning phase at Paradise. These equipment issues add delays to the c onstruction schedule. Because of this heavy demand, TVA and other utilities are seeing de livery times moving out. Not all utilities have placed orders for thei r presently planned FGD project s, 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 supp liers to erect all of the stacks required to support the FGD installations. Construction of the Kingston FGD stack was pushed outPage 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 ar e booked through 2008. TVA was only able to get a slot because of our program commitmen t with our preferred vendor. Once a stack contract is awarded, construction then takes se veral 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 complete d. Following the completion of the shell, construction of the Fiberglass Reinforced Plas tic (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 manufact urers of recycle pumps. These pumps circulate the water/slurry in the absorber tanks and are the hearts to th e 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 pr oposed 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 a nd GIW) for three years with no availability for any other

utilities 11

.

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 manufactu ring 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 Signifi cant 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 y ears”. TVA has typically found th at 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 toPage 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 Fo ssil Plant, TVA is looki ng 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 (E A) 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 be gin on any given project. Another potential

hurdle on the horizon is New S ource 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 po llution control exclusion from New Source

Review 12 . NSR permitting requirements could also increase the length of the permitting process for new emission control installati ons according to the pending decision in the DC circuit court of appeals.

Mr. Staudt’s report does not ta ke into consideration the exte nt of work nor the amount of time required to obtain the proper permitting for FGD, SCR and SN CR installations.

3.6 Other Issues

There are other issues that ar e affecting TVA’s ability to design, procure, install, and commission FGD Projects. For Paradise, T VA 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 star ting the project early and being ahead of most

of the other utilities. Now that most utilit ies 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 seriou s reservations that enough acceptable bids will be received for all the material, equi pment 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 c ontracts, which will driv e 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 challenge s, unknown challenges

have and will continue to a ffect 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 adversel y affected the schedule for Paradise Unit 3 because of delays in responding to constr uction issues and delayed th e 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. T VA 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 stre tched 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 s eeing significant cost increases resulting from the market demand on materials, equipment and craft. Th e EPA discusses cost increases that were seen during the NO X 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 constr uction costs (resulting from increased demand for boilermaker labor) and steel prices”. Thes e concerns were a cont ributing factor that led to the EPA two-phase approach for the CA IR to keep utilities from having near-term shortages of critical resources.

Mr. Staudt’s Expert Report also significantl y underestimates the total capital cost of the retrofit program for TVA to meet the CSA equivale nt emissions rate for NO

x and SO 2 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, mark et 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 incurre d 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 estima ted 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% comp lete, is $313,355,000. This is over an 82%

increase above Mr. Staudt’s estimate. Mr. Sta udt 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 es timate 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 un it 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 Advat ech, benchmarking with other utilities and an extensive program review on cost and schedule conducte d by Bechtel.

Detailed schedule, manpower and cost charts for FGD, SCR and SN CR 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 Sm okestack 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 ha ve all of these emission controls installed by 2013. To complete the proposed emission c ontrol 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 dema nds 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 addi tion to the 7 units cu rrently equipped with FGD scrubbers, the 21 units currently equippe d with SCRs and the 3 units currently equipped with SNCRs on the TVA Fossil Ge neration Fleet. Ot her utilities are experiencing the same issues as TVA a nd 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, a nd acknowledges that high demand for craft and professional personnel would be caused by accelerating the CAIR 1 . There is already a need for several thousand craft personne l in TVA’s territory and surrounding areas,

which exceeds what has been available histor ically. 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 pr oposed plan.

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

the current TVA Clean Air Plan. The accele rated emission control schedule proposed by Mr. Staudt is not practical gi ven 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 customers 11

, and 2) Mr. Staudt’s proposed plan would re quire absorber and structural steel shop space equal to the combined full cap acity of two main vendors (PSP and Cives) for three years

with no other customers 11

.

Mr. Staudt significantly undere stimates FGD and SCR project durations in his expert report. A typical FGD project installation requires 5 years from conceptual design toPage 34 of 65 commercial operation. A typical SCR project installation re quires 3 to 4 years from conceptual design to commercial operation. Mr. Staudt’s expe rt 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 NO

x and SO 2 at just under $3 billion (provided in his repor t in 2006 dollars). TVA’s es timate 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 c ontrol strategy from past experience on FGD, SCR and SNCR inst allations 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, wh ich are based on TVA’s actual experience to install FGDs, SCRs and SNCRs, input from Ad vatech, benchmarking with other utilities and a FGD program cost and schedule revi ew 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 sc hedule proposed by Mr. Staudt cannot be achieved by 2013 because of the enormous am ount 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 O WENS G RADUATE S CHOOL OF MANAGEMENT A T V ANDERBILT Nashville, TN Executive Development Program

February 1987 T EXAS A&M U NIVERSITY College Station, TX Construction Executive Program

March 1971 T HE O HIO S TATE U NIVERSITY Columbus, OH Bachelor of Science in Civil Engineering Construction Management Major Chi Epsilon - Civil Engineering Honorary Fraternity

EXPERIENCE

2006-Present T ENNESSEE V ALLEY A UTHORITY 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 in stallation 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 GroupTotal 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 Selectiv e 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 l ong-term agreements with N PS Energy Services, G.UB.MK (Gilbert Commonwealth, Union Boiler, Morr ison-Knudsen), and Williams Power. Duties and responsibilities include: Principl e 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 Foss il 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 B LOUNT , 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 w ith 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 equi pment, 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 Ener gy 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 incr easing the capacity of the waste paper processing facility. In a ddition, 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 A LPHA L AVAL P ROCESS G ROUP Keokuk, IA Construction Manager Responsible for managing the design and construction of a wheat processing facility for General Mills Chemical Corporation.

1975-1978 B LOUNT B ROTHERS C ORPORATION Conesville, OH Subcontract Supervisor Responsible for coordinating contracts for erec tion of the boiler and turbine generator for two 400MW coal-fired units for the Columbus and Southern Ohio Electric Company.

1971-1975 C OLUMBIA G AS T RANSMISSION C ORPORATION Columbus, OH Compressor Engineer Responsible for budget preparation and cost forecasting fo r 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 compensa tion is linked to the outcome of this case.Page 38 of 65 6.3 List of all Publications Auth ored in the Preceding Ten Years

NonePage 39 of 65 6.4 List of Other Cases - - Testimony as an E xpert at Trial or by Deposition within the Preceding Four Years

NonePage 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 Pub lic 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 Hear ing on Proposed Adoption of Rule 15A

NCAC 02D Section .2400 Cle an Air Interstate Rules ”, Department of Environment and Natural Resources, Division of Ai r 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/e lectricity/epa/epat2p4.html , Energy Information Administration, Official En ergy Statistics from the US Government, Existing Electric Generating Units in the United States, 2004.

6. “ Tennessee Valley Authority Scr ubber Program Evaluation Study ”, submitted by Bechtel Power Corporation, February 4, 2004 (Confidential Information).

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

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

. 8. “The Effect of SO 3 Sorbents on ESP Performance: A State-of-the-Art Review”

, EPRI, Palo Alto, CA: 2006. 1013348.

9. “ SO 3 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)Page 43 of 656.5.3 Cost Backup Data (Page 1)Page 44 of 656.5.3 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 Abso rber Area Construction Photo A.

Paradise Unit 3 FGD Project Abso rber Area Construction Photo B.Page 48 of 65 6.6.1 FGD Construction Photos

Paradise Unit 3 FGD Project Abso rber Area Construction Photo C.

Paradise Unit 3 FGD Project Abso rber Area Construction Photo D.Page 49 of 65 6.6.1 FGD Construction Photos

Paradise Unit 3 FGD Project Abso rber Area Construction Photo E.

Paradise Unit 3 FGD Project Abso rber Area Construction Photo F.Page 50 of 65 6.6.1 FGD Construction Photos

Paradise Unit 3 FGD Project Abso rber Area Construction Photo G.Page 51 of 65 6.6.1 FGD Construction Photos

Paradise Unit 3 FGD Project Abso rber 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 Ba ll Mill Construction Photo A.

Paradise Unit 3 FGD Project Ba ll Mill Construction Photo B.Page 54 of 65 6.6.1 FGD Construction Photos

Paradise Unit 3 FGD Project Ba ll Mill Construction Photo C.

Paradise Unit 3 FGD Project Ba ll 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 Co nstruction Photo A.

Allen SCR Project Cons truction 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.