IMPLEMENTATION SCHEDULES FOR 

SELECTIVE CATALYTIC REDUCTION (SCR) AND 

FLUE GAS DESULFURIZATION (FGD) 

PROCESS EQUIPMENT

October 1, 2010 

Prepared by 

J. Edward Cichanowicz 

Prepared for 

Utility Air Regulatory Group 

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TABLE OF CONTENTS 

SECTION 1 EXECUTIVE SUMMARY.................................................................. 1-1

SECTION 2 BACKGROUND................................................................................... 2-1

2.1 PROCESS EQUIPMENT REQUIRED 2-1

2.1.1 FLUE GAS DESULFURIZATION (FGD) 2-1

2.1.2 SELECTIVE CATALYTIC REDUCTION (SCR) 2-3

2.2 ELEMENTS OF A COMMERCIAL PROCUREMENT SPECIFICATION 2-4

2.2.1 CONCEPTUAL DESIGN/PREPARATION OF SPECIFICATION 2-4

2.2.2 IDENTIFICATION OF QUALIFIED CANDIDATE BIDDERS 2-6

2.2.3 SOLICITATION AND REVIEW OF BIDS/SELECTION OF CONTRACTOR 2-6

2.2.4 NEGOTIATION OF CONTRACT TERMS/CONTRACT ISSUANCE 2-7

2.2.5 SECURING PERMITS TO CONSTRUCT AND OPERATE THE RETROFITTED CONTROL 

EQUIPMENT 2-7

2.2.6 FINALIZATION OF DESIGN AND PREPARATION OF FABRICATION DRAWINGS 2-10

2.2.7 MOBILIZATION OF THE WORKFORCE TO SITE 2-11

2.2.8 ACTUAL CONSTRUCTION 2-11

2.2.9 PROCESS EQUIPMENT TIE-IN 2-12

2.2.10 PROCESS STARTUP 2-12

SECTION 3 FLUE GAS DESULFURIZATION (FGD) SCHEDULES............... 3-1

3.1 INSTALLATION OF A SINGLE FGD SYSTEM AT A SITE 3-2

3.2 INSTALLATION OF TWO FGD PROCESSES 3-3

3.3 INSTALLATION OF THREE OR MORE FGD PROCESS UNITS AT ONE SITE 3-4

3.3.1 ALABAMA POWER GORGAS UNITS 8-10 (61 MONTHS). 3-5

3.3.2 ALLEGHENY ENERGY HATFIELD S FERRY UNITS 1-3 (45 MONTHS) 3-5

3.3.3 DUKE ENERGY ALLEN UNITS 1-5 (49 MONTHS FOR THE FIRST RETROFIT; 1

EXTRA MONTH FOR THE OTHER). 3-6

3.3.4 DUKE MARSHALL UNITS 1-4 (46 MONTHS FOR THE FIRST RETROFIT; 6 MORE 

MONTHS FOR THE OTHER THREE RETROFITS). 3-6

3.3.5 FIRST ENERGY SAMMIS UNITS 1-7 (56 MONTHS). 3-6

SECTION 4 SELECTIVE CATALYTIC REDUCTION (SCR) AND LOW NOx

BURNER SCHEDULES ............................................................................................... 4-1

4.1 SELECTIVE CATALYTIC REDUCTION (SCR) 4-2

4.1.1 INSTALLATION OF A SINGLE SCR UNIT AT A SITE 4-3

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4.1.2 MULTIPLE SCR PROCESSES AT ONE SITE 4-4

4.2 LOW NOx BURNERS 4-5

SECTION 5 CRITIQUE OF EXAMPLES CITED BY EPA ................................. - 

5.1 FGD INSTALLATIONS OVERVIEW 5-1

5.2 EPA EXAMPLES OF FGD INSTALLATIONS BEING COMPLETED IN A TOTAL 

OF LESS THAN 30 MONTHS 5-2

5.2.1 CENTRALIA WET FGD 5-2

5.2.2 TAMPA ELECTRIC BIG BEND 5-3

5.3 EPA EXAMPLES OF SCR INSTALLATIONS BEING COMPLETED IN A TOTAL 

OF LESS THAN 30 MONTHS 5-4

5.4 OTHER FACTORS 5-4

SECTION 6 SUMMARY/CONCLUSIONS ............................................................ 6-1

6.1 DEMAND 6-2

6.2 LABOR PRODUCTIVITY 6-2

6.3 ENGINEERING 6-2

6.4 PERMITTING 6-2

SECTION 7 REFERENCES ..................................................................................... 7-1

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LIST OF FIGURES 

Figure 2-1. Typical Wet FGD Absorber Tower .......................................................................2-2

Figure 2-2. Perspective View of SCR Reactor for Coal-Firing (Babcock & Wilcox 

product information: 

www.babcock.com/products/environmental_equipment/scr.html)............................2-3

Figure 3-1. Timeline of FGD Activities.......................................................................................3-1

Figure 3-2. Sammis Site Layout....................................................................................................3-7

Figure 4-1. Timeline of NOx Control Projects SCR .............................................................4-1

Figure 4-2. Timeline of NOx Control Projects LNB .............................................................4-2

Figure 5-1: Timeline Showing Recent Installed FGD Capacity by Startup Date ........5-2

LIST OF TABLES 

Table 2-1. Lead Time (Weeks) for Key FGD Components 

(after Katzberger, 2007)..................................................................................................................2-2

Table 6-1. Summary of Design, Fabrication, Installation Period.....................................6-1

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SECTION 1 

EXECUTIVE SUMMARY 

This report evaluates the different factors that can affect how long it takes to design, 

permit and construct lue gas emissions control technologies that power plant 

owners may have to install on their electric generating units (EGUs) in order to meet 

the emission reduction requirements that will be included in the United States 

scheduled to be published in mid 2011. The control technologies considered by this 

report as candidates to be used to meet the emission reduction requirements of the 

 inal Transport Rule are lue gas desulfurization (FGD) systems for the control of 

sulfur dioxide (SO2) emissions; and Low NOx Burners (LNB) and selective catalytic 

reduction (SCR) reactors for the control of nitrogen oxide (NOx) emissions. 

In the preamble to its Proposed Transport Rule (published in the Federal Register 

on August 2, 2010) and in earlier studies upon which EPA now relies (EPA, 2005; 

EPA, 2002), EPA says that the Agency expects it will take 27 months of total effort 

for an electric generating company to plan, engineer, install, and start up one FGD 

system at one unit at a plant site; and that the total effort to retro it three FGD 

systems at one plant site might take 36 months. In addition, EPA says that it expects 

it will take 21 months of total effort for an electric generating company to plan, 

engineer, install and start up one SCR system at one unit at a plant site; and that it 

might take about 35 months of total effort for a company to complete the retro it of 

7 SCR systems at a plant site. Also, in the preamble to its Proposed Transport Rule, 

EPA indicates that it believes it will take less than 6 months of total effort for a 

utility company to plan, engineer, install and start up a low NOx burner system at a 

plant site. 

This report includes a broad review of numerous FGD, SCR, and LNB retro its that 

have been accomplished during the past ten years, describing each of the key steps 

that power plant owners must follow in order to be able to install and operate these 

control technology systems. In addition, this report presents more detailed 

information about the speci ic obstacles faced by the plant owners that have 

recently had to retro it FGD and SCR systems on their plants, including some 

obstacles that were not faced by companies having to make such retro its 5 to 10 

years ago. 

Following the presentation of background information in Section 1 of this report, 

Section 2 describes the steps affected power plant owners must take in order to 

design, permit, and implement one or more SCR or FGD installation projects. 

Section 3 then presents information on speci ic FGD retro its that have recently 

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been undertaken or are now in the process of being undertaken by electric 

generating companies. Section 4 then contains information about recent or ongoing 

projects for the installation of NOx controls: SCR and low NOx burners. The projects 

discussed in Sections 3 and 4 provide examples of the obstacles that companies now 

face in undertaking such retro its, including obstacles they (and others in the 

industry) may not have faced 10 years ago. Next, Section 5 addresses some of the 

retro it cases that EPA cites in its much earlier reports (EPA, 2005; EPA, 2002). 

Finally, Section 6 summarizes observations and offers alternative, realistic 

schedules for equipment installation. 

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SECTION 2 

BACKGROUND 

This section presents background information, describing the type of equipment 

retro it and the key activities involved in undertaking such equipment installations. 

2.1 PROCESS EQUIPMENT REQUIRED 

The type of process equipment required for a commercial FGD and SCR process is 

described, highlighting those aspects that affect fabrication and installation. 

2.1.1 FLUE GAS DESULFURIZATION (FGD) 

The lue gas desulfurization (FGD) system is comprised of four key elements: 

(a) reagent receiving and preparation equipment, (b) SO2 absorber tower, 

(c) byproduct dewatering and management equipment, and (d) a wet stack 

(optional). The latter wet stack is considered optional particularly if an existing wet 

FGD process operates at the station, but is usually required for stations without FGD 

The most visible element of the FGD process is the absorber tower, where lue gas 

SO2 contacts inely prepared and dispersed alkali reagent. Figure 2-1 depicts a 

commercial absorber tower. Most absorber towers can be located near the stack, 

pending routing of ductwork. Installing or erecting absorber towers requires cranes 

to relocate material, boilermakers for special-purpose welding, and other special 

trades and craft workers. 

Absorber towers are physically large and their installation has triggered 

construction delays, particularly where special exotic corrosion-resistant alloys 

were required for liners. These delays, however, were generally not the project ratedetermining step for the FGD equipment installed in 2008-2010. 

Rather, what typically caused project schedules to be prolonged in the 2008 to 2010 

timeframe was the lack of availability of heavy-duty process equipment: reagent 

mills (pulverizers) and lue gas fans. In addition, projects were delayed by the 

limited number of stack erectors: reportedly only 4-6 in the world with what some 

observers judge to be adequate experience. Katzberger (2007) describes the role of 

prepare limestone. The order-to-delivery time for this category of equipment 

escalated from 32 weeks in 2003, to 65 weeks (fall of 2005), 68 weeks (August 

2006), 70 weeks (December 2006), and 75 weeks (April 2007). 

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Figure 2-1. Typical Wet FGD Absorber Tower 

http://www.babcockpower.com/index.php?option=products&task=viewproduct&coid=17&proid=11) 

AEP reports that its most recent (August 2010) attempt to purchase a ball mill 

resulted in a 90 week delivery schedule from the vendor. Table 2-1 summarizes the 

escalation in delivery time of ball mills and other key process components. 

Table 2-1. Lead Time (Weeks) for Key FGD Components (after Katzberger, 2007) 

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Transformers and switchgear can also be long-lead items, with some companies 

reporting that it took more than 100 weeks to get delivery of such items. 

In addition, companies have reported extensive delays in the overall installation 

process caused by the need to get a broad array of permits and authorizations for 

SCR and FGD installations. As discussed more below, plant owners must have some 

of the needed permits and authorizations in hand before they can begin most of the 

site work for FGD and SCR installations. 

2.1.2 SELECTIVE CATALYTIC REDUCTION (SCR) 

plant layout extracting gas from the economizer exit and returning it to the air 

heater inlet. This location is necessarily constrained, as plant design did not envision 

access for such large equipment. Figure 2-2 depicts a typical SCR reactor. Finding 

space for and retro itting such equipment is challenging at all sites. 

Figure 2-2. Perspective View of SCR Reactor for Coal-Firing (Babcock & Wilcox 

product information: 

www.babcock.com/products/environmental_equipment/scr.html)

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2.2 ELEMENTS OF A COMMERCIAL PROCUREMENT SPECIFICATION 

This section addresses the steps in a project to design, procure, and install process 

control equipment such as SCR and FGD. 

It is convenient to consider the required activities as ten separate steps. Many of 

these steps can be conducted in parallel but some must be sequential. 

Each of these steps is described in the following text: 

Conceptual process design and preparation of speci ication

Identi ication of quali ied candidate bidders

Solicitation and review of bids; selection of contractor 

Negotiation of contractual terms and conditions, and contract issuance 

Securing environmental permits and other needed authorizations and 

approvals 

Finalization of the process design and preparation of fabrication drawings 

Mobilization of the workforce to site 

Actual construction 

Process Equipment Tie-in 

Process Startup 

Each of these key steps is further described in this section. 

2.2.1 CONCEPTUAL DESIGN/PREPARATION OF SPECIFICATION

As part of developing a conceptual design for FGD or SCR systems, it is necessary for 

the power plant owner to select the speci ic type of equipment to be applied, 

determine the feasible range of control ef iciency, identify potential byproducts 

from operation of the new control equipment, and project the capital and operating 

cost range. Also, as part of conceptual design, a power plant owner must identify any 

site characteristics or requirements that could make it more dif icult or more 

expensive than is typical to install and operate the proposed new equipment. This 

step will require at least several months but typically takes 6-12 months, depending 

on site complexity. The owner of a large, multi-state system reports that taking 9-12 

months to complete this process is a prudent way to minimize risk and avoid cost 

overruns. 

Numerous other items can prolong this activity. These include the need to (a) 

undertake a thorough review and solicitation of available fuel suppliers, perhaps 

qualifying new fuel sources particularly for conventional wet limestone FGD, 

which may allow the iring of coals with higher sulfur content not historically used 

at a station; (b) make a detailed characterization of site conditions, including soil 

characteristics, the presence of underground utilities, and available water for 

process make-up; and (c) develop a detailed description of how the unit will operate 

over the future decades (which is not necessarily the same as historical operations). 

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This and other preconstruction steps typically take over 12 months to complete. 

Some companies particularly those operating multiple EGUs at multiple sites 

may be able to take actions to reduce the time needed for engineering and for the 

procurement process (which is discussed below). Speci ically, it may be possible for 

a plant owner to reduce engineering and procurement timelines to a year, or just 

under one year, by establishing a common-design absorber and other process 

equipment. 

The best example of this is Duke Energy, which has used a common-design absorber 

and auxiliary equipment in the retro its of FGD systems at 12 individual units at 4 

generating stations in North Carolina 4 units at Marshall, 2 at Belews Creek, 5 at 

Allen, and 1 at Cliffside (McCarthy, 2004). When Duke engaged Alstom to evaluate 

such an approach in 2003, it was at a point when none of the Duke units in North 

Carolina had yet deployed FGD. Because Alstom was working on such a relatively 

clean slate and because the fuel sources were relatively consistent, Alstom was able 

a system-wide design for FGD absorbers 

and support equipment. A combination of these components was used in all 

applications in North Carolina, which reduced engineering and procurement 

actions.1 As a result of this effort, completion of the engineering and procurement 

steps for FGD installations at each affected Duke plant in North Carolina generally 

took a year or just under one year. 

(Notably, McCarthy (2004) reports that each station underwent a two-phase 

engineering analysis in order to ensure that the work to be done was properly 

described. The irst phase established the design basis (gas low rate, gas 

composition, available reagent composition), optimized a standard absorber design, 

established balance-of-plant needs, and developed a layout and preliminary cost. 

The second phase addressed details of balance-of-plant and auxiliary equipment, 

and developed detailed contracts for fabrication and construction schedules by 

which to manage the work and hold subcontractors accountable. Each phase 

reportedly required 6 months. Such attention to detailed design is necessary, for 

either approach that emphasizes a system versus an optimized individual unit 

design. Before awarding contracts valued at several hundred million dollars, any 

less effort in the present activist climate could invite prudency challenges.) 

Similarly, Southern Company employed common process designs developed by two 

suppliers Chyoda Corporation and AdvaTech LLC in assembling an FGD strategy 

for 12,000 MW of capacity (Wall, 2010). 

 

After the system design strategy was conceived for Duke Duke Energy 

merged with Cinergy in May of 2005. former 

Cinergy plants, but Duke was able to use alternative design approaches for the former Cinergy plants, 

based on considerable experience with higher sulfur fuels.

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The use of a system-wide engineering approach may not be applicable, or provide 

high payoff, to all owners. This approach may not be bene icial to small systems

those with 1 or perhaps 2 units. Also, owners of large multi-state systems that 

have in-plac

signi icant expertise and experience with coals native to their systems may not 

fully bene it from common design approaches. 

2.2.2 IDENTIFICATION OF QUALIFIED CANDIDATE BIDDERS

Once the scope of the project is de ined, owners can start to identify the candidate 

bidders for the project, i.e., vendors that are quali ied to satisfactorily deliver and 

install the components of the project. To take advantage of competitive forces that 

can reduce the price of a project (and to avoid prudency challenges that can arise 

from seeking bids from only one provider), power plant owners typically want to 

receive bids from a broad list of candidates. Because of the high cost involved to 

prepare a bid in response to a request for proposal (RFP), and to review the bids, 

good business practice leads most power plant owners to solicit bids only from 

suppliers believed to be quali ied. 

This step in the procurement process is also, however, intended to eliminate the 

possibility of limited or no bids, which can force plant owners to start the whole 

process over again. The possibility of this happening is very real. Katzberger (2007) 

noted that in 2007 some RFPs received one or in some cases no qualifying bids. 

This step typically requires at least 1 month. The most common delays are those 

data, which is important particularly in constrained (i.e., sellers) markets. 

2.2.3 SOLICITATION AND REVIEW OF BIDS/SELECTION OF CONTRACTOR

The process of deciding which suppliers to use is not based solely on cost. Many 

other factors must be taken into account in order to assure that the best long-term 

solution is found, one which will assure approval by both management and, in the 

case of regulated companies, by PUC staff. 

This goal is factored into the process of soliciting and reviewing competitive bids. In 

particular, the bid solicitation process requires issuing a detailed process 

speci ication, hosting a bidder meeting and site inspection, reviewing the submitted 

bids, and selecting the successful contractor. Generally, bidder meetings and site 

-3 weeks of issuing the speci ication, although this 

part of the process can often take 4-6 weeks in the case of large, multi-unit projects. 

A minimum of 30 days following the site inspection is required to prepare a bid. 

Review of bids will be conducted by power company staff or designated engineering 

 irms. The successful supplier is selected based on numerous factors, including 

relevant experience, ability to meet projected schedule, experience in containing 

cost, and historical performance on similar projects. 

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This entire step typically requires 3-5 months but can take longer, depending on the 

need for follow-up to clarify issues and proposed responses. For example, the 

development of an adequate bid in response to an engineering speci ication can take 

longer when demand on equipment and suppliers is high.2 Also, the time for 

completing this part of the process can be extended when plant owners receive 

inadequate or partially responsive bids, need addendum or additional submittals 

from bidders, or must seek clari ications of the responses they get. 

2.2.4 NEGOTIATION OF CONTRACT TERMS/CONTRACT ISSUANCE

Once the preferred contractor is selected, that contractor and the plant owner must 

agree to acceptable terms and conditions. The framework of acceptable terms and 

conditions is de ined in the speci ication, and bidders in their proposals can take 

exceptions to the proposed conditions. All these details cannot be resolved in the 

proposal process. 

After the preferred contractor has been selected, the time it will take to inalize 

contract terms will depend on several factors, including whether the plant owner 

and contractor have previously worked together and the nature of the contract 

terms. For example, it may take 1-2 months to negotiate standard terms and 

conditions where the plant owner is familiar with and has previously worked with 

the contractor. For larger projects where the plant owner and selected party have 

not previously worked together, it can take longer sometimes as long as 3-5 

months. Also, the negotiation of non-standard terms and conditions can add time to 

the overall process. One example is the inancial surety details how much, if any, of 

a inancial bond must be posted, or the damage provisions of a contract in the event 

of non-performance. For projects that are conducted as an open book alliance, the 

rate structure of relevant personnel and the inancial incentives and penalties to 

reward or penalize performance can require lengthy inancial and legal analysis. 

2.2.5 SECURING PERMITS TO CONSTRUCT AND OPERATE THE RETROFITTED CONTROL 

EQUIPMENT

Securing all pre-construction permits needed for the design and installation of 

pollution control projects can be a time-consuming process but companies can 

incur legal liabilities and run other risks if they start installation before they have 

key permits in hand. Thus, the typical approach is for companies to inalize the 

conceptual design of equipment and to have in place the major contracts and then 

armed with detailed information they are in the best position to start the process 

of getting all needed permits and other regulatory authorizations. 

 

2 Not surprisingly, almost without exception, it has been possible to accelerate project schedules only 

during times when demand on equipment and suppliers was low.

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As part of this step, plant owners will not only need to get permits governing the 

treatment of lue gas emitted from the retro itted control equipment, but also to get 

other environmental permits (to cover other emissions of air pollutants, water 

discharges, and the treatment of waste water and the management of solids 

byproduct) and a broad array of other authorizations (for example, from zoning 

boards and public utility commissions). As just noted, although parts of the 

installation process can go forward in parallel with the permitting/authorization 

process, some permitting programs prohibit a company from going too far in the 

construction process without irst getting speci ic pre-construction authorizations. 

And getting all those authorizations has become much more time-consuming and 

complicated during the past ive years, thus making it a possible major bottleneck 

for the installation of FGD and SCR systems. This is especially the case for power 

plant stations at which FGD and SCR control systems have not previously been 

installed. There are many reasons that permitting has recently become more 

complicated and time-consuming, including but not limited to the following. 

Increased Dif iculties in Getting Preconstruction Permits Under the Clean Air Act. The 

operation of SCR and FGD units will signi icantly reduce emissions of NOx and SO2, 

byproduct species other than NOx or SO2. For example, 

the operation of wet FGD and SCR while reducing SO2 and NOx emissions may 

increase sulfuric acid mist by more than insigni icant amounts. Also, operating low 

NOx burners will reduce NOx emissions but under some conditions have been 

thought to increase carbon monoxide (CO) emissions. Concern for a possible 

increase in CO emissions may delay permit approval by some agencies. (Recent 

installations of LNBs, in conjunction with improved combustion controls, have not 

increased carbon monoxide emission rates.) 

The new source review preconstruction permitting program can be triggered by 

projects that will result in a signi icant net emissions increase of one or more 

regulated pollutants. Prior to late 2005, projects that installed environmental 

control equipment did not trigger the time-consuming new source review 

preconstruction permitting process because such projects were subject to the 

urce review 

(NSR) rules. In December 2005, a court decision vacated the PCP exclusion. As a 

result, the NSR permitting process may be triggered by a project to install an FGD, 

SCR or LNB system, if the operation of that control system may result in the increase 

of a pollutant other than the pollutant being controlled by the FGD, SCR or LNB unit. 

Having to obtain a new source review permit could delay installation of the new 

control system because of the elaborate procedures associated with NSR permitting. 

For example, the process of obtaining a new source review permit prior to the 

beginning of construction for FGD or SCR units, even if consisting of no more than a 

paper exercise, can add many months to the overall process. And if a full-blown 

review is needed (perhaps to evaluate emissions of greenhouse gases once the NSR 

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process is scheduled to start applying to greenhouse gas emissions in early 2011), 

that could add a year or more to the entire process. 

NSR provisions were not a problem faced by companies installing pollution control 

projects in the irst part of the last decade.3 Thus, the two key SCR examples cited by 

EPA those at the Kintigh and Keystone stations were retro its that did not 

address the NSR implications of enhanced SO3 emissions. 

Permits Governing Byproduct Management. In addition to securing permits 

authorizing the release of air pollution associated with the operation of pollution 

control systems, power plant owners also must secure permits to address other 

environmental consequences of operating such equipment, including permits for the 

treatment and/or storage of the byproducts of both wet and semi-dry FGD systems. 

For a variety of reasons including public concerns over coal ash management that 

have prompted examination of the benign byproducts of both wet and semi-dry 

FGD, such as gypsum addressing this issue can now take 4 to 5 years. 

Some of the speci ic examples presented in Sections 3 and 4 of this report 

demonstrate that securing a land use management permit for FGD byproducts can 

take longer than four years and can itself be an absolute impediment to the 

installation of a complete system in under 30 months. For example, AEP reports 

instances in which the time from preparing the permit application for a land ill to 

the irst storage was 40-42 months. (As discussed in separate comments being iled 

by AEP, this was the case for the Cardinal and Mountaineer FGD projects). Also, 

Georgia Power Company reports that it took over 48 months to obtain a 

preconstruction permit for a byproduct management site and an additional 14 

months to complete construction of that installation, a total of over 60 months. 

It can also take time to secure the necessary permits to authorize use of a separate 

byproduct management site not located on plant property. AEP reports that the 

permitting process for a separate byproduct management site located remote from 

an existing site can add 10 to 20 months to a project schedule. 

Examples from Duke Energy in North Carolina also demonstrate this point. Duke 

staff report the timeline to secure a workable land ill on plant property in their 

possession has been 42-48 months (Hallman, 2010). This timeline includes locating 

and assessing the suitability of the site (18-22 months), securing the permit to 

construct (10-12 months), construction (12 months), and securing the operating 

permit (2 months). 

 

3 Although a company may be able to avoid triggering the NSR permitting process by adding other 

controls to reduce emissions of collateral pollutants, that will not necessarily shorten the overall 

permitting process. Speci ically, adding pollution control equipment to reduce emissions of collateral 

pollutants means going through the above-listed steps including engineering design, solicitation of 

bids, permitting, etc. before those additional pollution control systems can be constructed.

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Public Utility Commission (PUC) Approvals to Install Pollution Control Equipment. 

Where PUC approvals are needed, the length of time it can take to seek and receive 

such approvals can vary widely, from 6 months to more than one year. For example, 

AEP reports that in one state in which it owns generating units (Kentucky), the 

PUC after receiving an application typically takes 9 months to act on that 

application. Another example comes from Minnesota: the Minnesota PUC required 

subsidiary, for a series of environmental upgrades (Hansen, undated). These 

upgrades included applying SCR an

Station, in addition to repowering smaller units with natural gas combustion 

turbines. 

Other Authorizations. Individual companies point to other, more site-speci ic 

permitting issues that have arisen or are likely to arise when they seek permits to 

install FGD or SCR systems. For example, some companies report that the operation 

of pollution control equipment will result in discharges that will trigger the need for 

revisions to source Clean Water Act permits. For discharges into some water bodies 

(e.g., those that have stringent restrictions on discharges of any additional 

nutrients), that permitting process could be extremely dif icult and time-consuming. 

Other companies point to the increasing regulatory uncertainty surrounding 

ef luent guideline regulations, noting that such uncertainty can hinder the decisionmaking process and make the process iterative if regulations require additional 

changes or alterations to the plant not anticipated in the original permit 

applications. Yet other companies note the regulatory complications involved in 

locating, constructing, and operating pollution control equipment in urban areas, 

where they may face zoning challenges, restrictions on the truck traf ic related to 

such operations, and even height restrictions if equipment is to be located near an 

airport. 

In summary, completion of this step will routinely take two years and can often take 

up to 4 years, making it a major impediment to the completion of FGD and SCR 

installations in less than 30 months. 

2.2.6 FINALIZATION OF DESIGN AND PREPARATION OF FABRICATION DRAWINGS

The engineering contractor will inalize design and fabrication drawings. These 

detailed drawings provide speci ic instructions as to what type of equipment to 

procure and install. 

Final design begins almost immediately after the engineering or supplier contractor 

is selected and will last for 15 to 45 months. Most delays in preparing the inal 

design are due to identifying site limitations or constraints that are not obvious at 

preliminary design such as the presence (or lack of ) underground utilities or 

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other structures, or soil properties. Much of this process can be conducted in 

parallel with other equipment installation activities. 

2.2.7 MOBILIZATION OF THE WORKFORCE TO SITE

Securing the construction services of key trades and crafts staff must be executed 

promptly upon execution of construction contracts. When there are not a signi icant 

number of competing projects going on simultaneously, this can be accomplished in 

1 to 3 months. It can take longer, however, when there are a signi icant number of 

similar projects underway and competing for the same skilled workforce. 

Signi icant regional differences in workforce availability or mobility can affect this 

element of construction. 

2.2.8 ACTUAL CONSTRUCTION

Construction activities are initiated immediately following mobilization of the 

workforce to the site. Typically, progress is accomplished according to a rapidly 

accelerating rate, starting with preparation of the site for laydown area, assembling 

necessary equipment, and initiating concrete and foundations work. 

Of course, construction cannot start until the necessary fabricated and raw 

materials can be delivered to the site. The extensive delays in delivery of the key 

components de ined in Table 2-1, as well as electrical and switchgear components, 

had a signi icant impact on FGD construction schedules in the 2008-2010 

timeframe. The lack of availability of key components could also adversely affect 

FGD and SCR installation schedules in a future 2012 to 2014 time frame. 

Although some fabrication work can take place off-site, restrictions on the size of 

process equipment that can be transported limit the amount of off-site fabrication. 

The physical size of the SO2 absorber tower in Figure 2-1 and of the SCR reactor in 

Figure 2-2 indicates that most construction must occur on-site. 

The length of time it will take to complete the construction process will vary from 

site to site depending upon several key factors: the complexity of the site and the 

presence of other in-plant equipment, access to the site and limits on where the 

cranes required to install heavy equipment can be placed, the amount of existing 

equipment demolition or relocation, and site remediation. For example, as will be 

facility could not be installed until contractors irst removed from the site the 

-p

particulate control equipment was installed. Also, the highly publicized retro it of 

wet FGD to PSNH Merrimack required two years of site preparation, and one year of 

major construction (PSNH, 2010). 

Also, the productivity of construction labor is key, and there can be signi icant 

differences in regional workforce productivity, which can affect installation 

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schedule. Experience with the equipment retro its in 2008-2010 showed a strong 

demand for the most experienced and productive staff. Consequently, the skilled 

trade craft assigned to later-in-the-pipeline projects often projects being 

undertaken by smaller companies, seeking to complete only 1 or 2 retro its tended 

to be the less experienced and less productive staff. Finally, timely access to 

equipment avoiding delays in delivery of equipment must be minimal. 

Construction timelines under the best conditions have been about 25-30 months, 

with more complex sites requiring more than 40 months. For multiple units, the 

construction timeline can extend for several years. 

2.2.9 PROCESS EQUIPMENT TIE-IN

Following actual construction of the control equipment, a unit outage is necessary to 

tie in process ductwork to an existing unit. Companies usually try to conduct tie-in 

activities during or near planned outages, but such outages are typically not 

scheduled solely for the purpose of equipment tie-in, and such outages are never 

scheduled during peak load periods. Also, in cases involving more complicated 

installations, the tie-in process will likely extend beyond the time usually set aside 

for outages. 

In some cases, the equipment tie-in process can be accomplished in as little as 3-4 

weeks, but this process will require up to 3 months at sites where conditions are 

more challenging. For -week outage was 

required for tie-in of the FGD process. This 10-week period was due to the complex 

ductwork arrangement that prevented the use of conventional modular 

construction methods; also, the FGD retro it required the company to make changes 

to the air heater and forced draft fans. Another example would be the retro it of SCR 

at Georgia Power Scherer Unit 3. That effort required a 3 month outage due to the 

complexity of ductwork. Similarly, the tie-in period required to install SCR at Unit 4 

of Plant Hammond was 7 weeks simply due to the inability to get cranes close to 

the ductwork to be penetrated. 

2.2.10 PROCESS STARTUP

Once the equipment is installed and tied in, it generally takes at least 30 days and 

can take up to 90 days of shakedown operations, testing, and process tuning before 

the power plant owner will take over unit operations. In some instances a process 

shutdown and re-start is required to mitigate a performance issue. 

In summary, there are numerous steps involved in the design permitting and 

construction of SCR or FGD process equipment, only a few of which can be 

conducted in parallel. And the overall period of time that it will take to complete the 

entire installation and design process will depend upon many factors including, for 

example, the size and con iguration of the site at which equipment is being installed, 

whether (for FGD installations) the process equipment is located at a site where 

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FGD already exists, and whether the site has in place a permitted facility for 

byproduct management. As discussed in the following sections of this report, factors 

like this will lead to FGD and SCR installation schedules far in excess of the 30 

months that EPA has cited. 

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SECTION 3 

FLUE GAS DESULFURIZATION (FGD) SCHEDULES 

This section of the report discusses the installation schedules of several recent (or 

ongoing) FGD projects. The projects discussed demonstrate that the timetable for 

completing such installations can vary signi icantly, depending upon many factors, 

including the nature of the site and whether the host is a single unit or one of 

multiple FGD processes to be installed at a station. 

Figure 3-1 presents a summary timeline for representative FGD projects, depicting 

when engineering and procurement start, and construction begins. The stations 

represented in Figure 3-1 are from those FGD owners who could expeditiously 

provide the requested schedule information within the abbreviated time required 

for preparation of this report. Despite attempts to authentically re lect the 

distribution of the 1,500 generating stations in the U.S., it is not known if the 

stations in Figure 3-1 re lect a true statistically representative sample. 

Consequently, the trends between different categories of units will be approximate. 

Figure 3-1 shows a wide variety of project duration schedules. 

Figure 3-1. Timeline of FGD Activities 

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The following is a more detailed discussion of many of these FGD installation 

projects. 

installations of a single FGD process at one site. There are also examples of more 

challenging installations, including multiple FGD installations at a generating station 

with multiple units. These examples also include stations that are 

contemporaneously retro itting SCR and FGD systems. 

3.1 INSTALLATION OF A SINGLE FGD SYSTEM AT A SITE 

How long it will take to add a single FGD process at a site will depend on the speci ic 

details of the site. For example, retro itting an FGD process to a site already 

equipped with one or more FGD units and where there is already a licensed 

byproduct management system at the site is likely to present a more straightforward engineering and installation situation than will be faced when a company 

installs FGD at a site that is not already equipped with one or more FGD units.4

However, other site-speci ic factors can override any such advantage. Consequently, 

for the purposes of this discussion, stations with and without FGD are placed in the 

same category for discussion. 

As shown in Figure 3-1, examples in this category include the installation of the FGD 

system at G

FGD retro it at Alabama Power Gaston Unit 5 (which took 64 months); and the 

even though the plant owner was willing to pay additional local agency fees and 

assign contactors to expedite the permitting process and accelerate review). 

-toaverage-time installation schedule. The single FGD module for four boilers at 

Hammond was implemented in the shortest schedule incurred by this owner. 

Several factors enabled this abbreviated schedule. First, the process and absorber 

design developed for other sites was applied, shortening the period for procuring 

contracts. Second, certain design tasks were accelerated as they were leveraged on 

previous, similar applications. Third, as described in greater detail in comments 

being iled separately by Southern Company, ample and accessible space was 

available to allow simultaneous construction of equipment such as the absorber and 

reagent preparation facilities. 

 

4 As will be noted in Section 5, one of the four reference units selected by EPA (Tampa Electric Big 

Bend) represents this case. There, the existence of reagent receiving, processing and handling 

systems for two other, FGD-equipped units at the site supported expedited design and construction 

for Units 1 and 2.

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In contrast, there was a 64-month schedule for installation of FGD at Alabama 

pose for a source owner trying to install control equipment. 

Another factor that should be considered is whether the plant owner operates a 

large leet of plants or only a few units. Owners in the latter category without the 

market power of large, multi-state operators will have less leverage over suppliers 

and can expect longer installation times. The relatively small market presence of 

Dairyland Power Cooperative is believed to contribute to the 50 month installation 

schedule for retro it of semi-dry FGD. As described by Katzberger (2007), it is not 

uncommon for small operators to not receive the same degree of response as larger 

owners. 

In summary, during the past ive years, the average time incurred to retro it FGD on 

a single unit at a site has been 48 months, but it has recently taken some companies 

less time to complete such a single retro it (as little as 40 months) and it has taken 

other companies more than 60 months to complete a single retro it. The dif iculties 

faced by large companies are magni ied for smaller companies. 

3.2 INSTALLATION OF TWO FGD PROCESSES 

Implementing two FGD units at a site can affect an overall FGD installation schedule. 

For example, by undertaking multiple installations, the per-unit design timelines 

may be shorter, but the overall construction schedule may have to be extended due 

to the number and complexity of site activities. Usually the additional time is due to 

the availability or unavailability of space during construction. For example, in the 

adjacent to the inal location, where inal preparation can take place. The distance 

between the laydown area and installation site ideally is minimal, and a single 

installation can usually be supported. However, in many cases, an adequate laydown 

area for two units cannot be found adjacent to the site. As a result, there are longer 

transport distances and there may be a delay in the inal preparation preceding 

installation. 

There are numerous examples of FGD retro its that fall into this category. These 

12 months of project work and 37 months of construction for the irst unit to be 

operable) and Cayuga Units 1 and 2 (54 months: 9 months of project work and 45 

m

plus an additional 9 months to relocate existing byproduct settling lagoons); and 

Also being included in this category are the FGD projects at WE Energies Pleasant 

Prairie Units 1 and 2 and Progress Energy Crystal River Units 4 and 5, where plant 

owners contemporaneously constructed FGD SO2 control systems and SCR NOx

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control systems. This type of project can take 

retro its due to size of the entire project a greater amount of concrete to be poured 

for foundations, electrical cable installed located for power and instrumentation and 

controls, fabricated steel vessels to be stored and prepared for erection in limited 

space for hundreds of boilermaker and other skilled trades. Completion of the FGD 

installation at and 

months. 

installations may, on average, have taken less time than those steps took at some of 

the other above-listed installations is that Duke by adopting a system-wide FGD 

design was able to initiate construction sooner. Not all owners can adopt this 

approach, based on the variety of generating units and the presence of FGD on 

existing units. 

Site differences can also elongate a construction schedule. The case of Allegheny 

Fort Martin is instructive on this point. The cited installation schedule of 40 months 

does not include an additional 9 months to relocate existing byproduct settling 

lagoons to accommodate the reagent storage and preparation, gypsum dewatering, 

and waste water treatment facilities. In addition, the subsurface area beneath the 

former lagoons required caissons for support. This site was very congested and 

required a step-by-step erection process instead of erecting multiple facilities 

simultaneously. For example, the stack shell was irst erected, followed in sequence 

by the Unit 2 and Unit 1 absorber island. Site constraints forced the absorber shell to 

end of the plant, and welded section by section. The shared facilities such as reagent 

unloading, storage and processing, gypsum dewatering and storage, and waste 

water treatment were all separated from the absorber island. Consequently, 

signi icant pipe and electrical racks were necessary to connect all facilities. In 

addition, inally, labor productivity was not optimal construction craft had to be 

bussed to the work site each day from a parking area that consumed valuable work 

time. 

In summary, the average retro it time for these installations was 47 months but as 

was the case with the previous category there was great variation, with some 

installations taking less time and others taking much more. 

3.3 INSTALLATION OF THREE OR MORE FGD PROCESS UNITS AT ONE SITE 

Implementing three or more FGD processes at a site can lead to even greater 

dif iculties as the challenges for two units are extended. The limits of space and 

access for manpower are greater. 

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The following examples of this category of FGD retro its are discussed below: 

Alabama Power Miller Units 1- -3; Duke Energy 

Allen Units 1-5; Duke Energy Marshall Units 1-4; First Energy Sammis Units 1-7; and 

Alabama Power Gorgas 8-10. TVA Kingston Units 6-9 are also re lected in Figure 

3-1. 

As demonstrated by the following discussion, it took an average of 49 months for 

owners of these units to install three or more FGD systems at one site. The least 

required time was 45 months; in two instances it took 56 months or more to 

complete installation of FGD at the irst unit at the site, with subsequent units 

requiring additional time. 

The reasons why FGD installations at each of these took more than the 27 months 

that EPA suggests is standard is that there is nothing standard about most power 

plant sites. 

3.3.1 ALABAMA POWER GORGAS UNITS 8-10 (61 MONTHS). 

The 61 month schedule for Gorgas was the longest incurred by this owner. There 

were several key reasons for this extended schedule. First, as the initial FGD project 

for this owner, the engineering required signi icant time as did negotiating 

contracts. Second, the site required extensive modi ications literally moving a 

small mountain to create the adequate space. The limit on space forced the new 

stack to be constructed sequentially, and not in parallel with other equipment. 

Further, signi icant improvements to the lue gas handling system including 

upgrade of fans were required. 

3.3.2 ALLEGHENY ENERGY HATFIELD S FERRY UNITS 1-3 (45 MONTHS) 

process and material handling equipment. Each of these areas is located over an 

abandoned coal mine that required stabilization by injecting a lyash/concrete 

mixture. A caisson structure was also required to further provide structural support. 

Prior to construction, transmission lines (500 KV) from the generating unit to the 

switchyard had to be relocated to provide clearance for cranes to erect the induced 

draft fan and absorber facilities. Due to lack of laydown space near the unit, the 

absorber vessel shells were built off site, shipped to the site and erected ring by ring. 

Finally, the shared facilities such as reagent unloading, storage and processing, 

gypsum dewatering and storage, and waste water treatment were all separated 

from the absorber island. Consequently, signi icant pipe and electrical racks were 

necessary to connect all facilities. 

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3.3.3 DUKE ENERGY ALLEN UNITS 1-5 (49 MONTHS FOR THE FIRST RETROFIT; 1 EXTRA MONTH 

FOR THE OTHER). 

Two FGD units were installed to serve the ive units at 

Plant, where the units are relatively small and several boilers feed one of two FGD 

absorbers. It took a total of 49 months to bring on-line the irst FGD unit and an 

additional month to bring the other FGD unit on line. 

3.3.4 DUKE MARSHALL UNITS 1-4 (46 MONTHS FOR THE FIRST RETROFIT; 6 MORE MONTHS FOR 

THE OTHER THREE RETROFITS). 

Duke Energy installed 4 FGD units at its Marshall Power Plant. The irst FGD 

installation to be completed was at Marshall Unit 4, which took 46 months. It took 

an additional 4 months to complete work on the second retro it and another two 

months to complete work on the remaining two retro its.

3.3.5 FIRST ENERGY SAMMIS UNITS 1-7 (56 MONTHS).

A notable case is that of Sammis Units 1-7. Figure 3-2 depicts the Sammis site layout, 

adjacent to the Ohio River, with Ohio State Route 7 located below the ESPs and 

fabric ilters built in the 1980s for these units, and three 800 MW FGD absorber 

towers. Flue gas from the entire station all 7 units is treated by these three 

absorber towers. (SCR process equipment is located on Units 6 and 7.) Figure 3-2 

shows the Sammis site is bounded by the Ohio River and a rail line which, among 

other factors, constrained construction activities and contributed to the extended 

installation time of 56 months. 

Figure 3-2 also indicates where that two 600 MW SCR reactors were installed within 

the boilerhouse building. 

In summary, owners of major generating stations have required a total of between 

45 and 66 months to retro it 3 or more FGD systems at one site. The length of time it 

took to complete FGD installations at the different sites varied depending upon sitebecame operational 46 month after start of engineering and permitting, with the 

three remaining units coming onMiller station, three FGD units are on line and one is scheduled to come on-line in 

2011; the total installation time for each of the four retro its ranges from 54 months 

to 66 months. 

The common theme in these retro its is the extensive number of activities to be 

conducted within a limited, con ined space, which requires many activities to be 

conducted sequentially and not in parallel. 

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Figure 3-2. Sammis Site Layout 

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SECTION 4 

SELECTIVE CATALYTIC REDUCTION (SCR) 

AND LOW NOX BURNER SCHEDULES 

This section of the report reviews the schedule to retro it SCR reactors and/or low 

NOx burners at 13 generating stations. A summary of the results for SCR is 

presented in Figure 4-1, and for low NOx burners in Figure 4-2. 

The stations represented in Figures 4-1 and 4-2 are those of plant owners that 

retro it SCR and low NOx burners and that could expeditiously provide the 

requested information within the time required for this report. As with the case for 

FGD experience summarized in Figure 3-1, it is not known if the stations in Figure 

4-1 re lect a statistically representative sample. Consequently, the trends between 

different categories of units will be approximate. 

Figure 4-1. Timeline of NOx Control Projects SCR 

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Figure 4-2. Timeline of NOx Control Projects LNB 

4.1 SELECTIVE CATALYTIC REDUCTION (SCR) 

The design and installation of SCR is considered for single unit retro it and multiple 

projects at one site. This section of the report also treats SCR installation projects 

conducted contemporaneously with FGD. Unlike the case for FGD, the use of a single, 

modular process design is not a widespread practice. This is because the location of 

the SCR process between the economizer outlet and air heater inlet requires a 

tailored, site-speci ic treatment.

Figure 4-1 presents a summary timeline for representative SCR projects, depicting 

the start of engineering and procurement, and construction. Figure 4-1 shows a 

variety of project durations. The data show that there is only a minor effect as to 

whether an SCR process has been previously installed at a given station. This is 

because there is no central, shared facility of the magnitude of a reagent receiving 

and preparation system that can be expanded, or a byproduct management system, 

where an existing system can be exploited. There may in some cases be a bene it of 

exploiting the existing ammonia-based reagent preparation system, depending upon 

 

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4.1.1 INSTALLATION OF A SINGLE SCR UNIT AT A SITE

Several owners retro itted a single SCR reactor to a site. Examples of such retro its 

tion 

described as follows. 

Georgia Power Plant Hammond (28 months) ammond 

Unit 4 represented the shortest schedule of any unit retro it by this owner. Several 

reasons contributed to an installation schedule that was markedly shorter than 

others undertaken recently. First, Unit 4 is an end unit thus construction could 

proceed during routine operation, as access to the reactor was adequate. Also, the 

unit required minimal modi ications to the gas handling system. These bene its to 

schedule did come at a price two cranes (rather than one) were required, and the 

tie-in time due to extended ductwork was closer to 7 weeks and not the typical 

4 weeks. 

Alabama Power Gaston Unit 5 (40 months). Alabama Gaston Unit 5 required 40 

months, one of the longest project durations experienced by this owner. Most 

notably, major modi ications to the gas handling system were necessary to 

accommodate the change in gas pressure drop; in addition to new fans both 

structural and electrical infrastructure had to be improved. The extremely 

congested site, adjacent to a river, minimized site access for construction, requiring 

mostly costly crane and protracted erection procedures. Ductwork location was 

complicated by coal conveyors, and the need for foundations in limited space. 

Finally, the altered ductwork arrangement required a new breach to the stack, 

imposing complexity. 

Duke Energy Marshall Unit 3 (46 months). It took approximately 12 months of 

upfront work at this site before the contractor was given authorization to proceed 

with detailed engineering. When the time for these efforts is added to the time 

needed for actual construction, the total time for this installation is 46 months. 

In summary, for cases involving the retro it of a single SCR reactor at a site, the 

construction schedule will depend on the speci ic characteristics of the site, 

including technical details of the application, and the engineering prep work. Recent 

examples of the installation of a single SCR unit indicate that it takes between a total 

of 28 months and 50 months (an average of about 40 months) to complete such 

projects. 

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4.1.2 MULTIPLE SCR PROCESSES AT ONE SITE

There are several examples of plant owners retro itting multiple processes for the 

control of NOx at one site. Sites at which multiple SCR units have been installed 

retro its on Units 6 and 7 required a total of 

60-

each took a total of 42 months and retro its on Units 3 and 4 each took a total of 34 

re was a retro it of 5 SCR units, with 

the irst operable within 31 months); Progress Energy Crystal River Station (where 

project (which includes work on SCR for Units 1 through 4, and where the SCR 

system closest to completion is that for Unit 3, which is scheduled to be completed 

work to control NOx at its Thomas Hill Station (including the addition of an SCR 

system and low NOx burners on Unit 3 and work on the Unit 2 SCR). 

The collective experience for this class of project suggests that it takes between 31 

and 50 months (an average of approximately 44 months) to install the irst of 

multiple SCR systems at a site and subsequent units come on after varying intervals, 

depending upon site-speci ic factors. It can, however, take much longer than the 

the Sammis site. Further details of selected stations are described as follows: 

First Energy Sammis Units 6 and 7. Sammis 6 and 7 required approximately 60-62 

months from the start of engineering to process startup. Section 3 discussed the 

dif iculties encountered for FGD, and Figure 3-2 presented a pictorial view of the 

station. The SCR units were installed in an extremely congested environment. The 

retro it of SCR to Units 6 and 7 required signi icant equipment demolition; the 

original equipment ESPs that had been decommissioned and abandoned in place (as 

new, upgraded particulate control equipment was installed) had to be removed. The 

ESPs occupied the space that was the only option for locating the SCR reactors. 

The constrained site as shown in Figure 3-2 illustrates that the signi icant 

demolition and equipment relocation are primary reasons why 60-62 months was 

incurred. 

Kyger Creek. AEP retro it ive SCR reactors to the Kyger Creek Station in a period of 

approximately 31 months. The number of identical units and the generating 

capacity were key to achieving this abbreviated time: all ive units are identical so 

engineering could be expedited, and the modest generating capacity (220 MW per 

unit) did not require large quantities of material to be installed or relocated. The use 

of cranes within the compact site, and small distances over which to transfer 

materials also contributed to expeditious installation. Although the plant site is 

constrained, the units are small and construction can be staged to address these in 

a serial manner. Consequently the 31 month period is not considered typical. 

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Georgia Power Scherer Unit 3. Unit 3 the irst unit to be operational at this site - is 

planned to be completed within about 50 months, with engineering and permitting 

commencing 19 months prior to any startup activities. Other units at Scherer that 

will receive SCR Units 1, 2, and 4 are scheduled for start up after Unit 3. The 

complexities of the site, and general congestion of executing these projects 

contemporaneously, extends the implementation schedule for these units. For 

example, Unit 4 is scheduled to be operable in early 2012, incurring a more than 60 

month project schedule, about 10 months following Unit 3. Units 1 and 2 will be 

implemented after Unit 4 by a similar amount of time. 

4.2 LOW NOX BURNERS 

The reduced complexity of an LNB system, compared to an SCR or FGD process, 

does not necessarily translate into abbreviated permitting procedures. As with SCR, 

construction schedules for LNB installations will depend on conditions at the 

speci ic site, including details of the application, the engineering and unit 

preparation work, and the availability of an outage. Most notably, a key factor in 

determining the installation schedule is the availability of LNB equipment. The 

limited number of quali ied suppliers, and the special-purpose fabrication 

techniques required, can extend fabrication and delivery times. Also, there can be 

complications in the permitting process. At least one multi-state owner is 

anticipating a lengthier schedule for installing LNB equipment, due to concerns that 

have arisen in the permitting of the installations, where local regulatory agencies 

are questioning whether lower NOx emissions are inextricability linked to higher CO 

emissions. Regardless of whether or not there is any validity to the claim, that 

permitting process is anticipated to be time consuming. 

Figure 4-2 presents schedule information provided for low NOx burners at Salt River 

 3. Also included in Figure 4-2 is a 

schedule typical of LNB retro its in the Southern Company System (based on recent 

LNB retro its to generating units at Plants Daniel and Watson). This experience 

suggests project installations typically take a total of about 18 months. 

Not included in Figure 4-2 is information on LNB installations for two 760 MW units 

The LNB installations 

were part of a larger project that took many years to complete and that included 

installation of an SCR unit, an FGD system, and an acid mist mitigation system 

(ammonia injection) and signi icant upgrades to the precipitator. If the low NOx

burners had been installed on their own, company representatives estimate that 

permitting and construction would have taken 18 to 24 months. 

The Crystal River installations are addressed here, though, because they are an 

example of a relatively straight-forward LNB installation project. LNB retro its can 

take less time than on average if (as Progress could do at Crystal River) companies 

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can use - -part changes. In many 

cases, though, more signi icant modi ications are required 

have to be expanded, to lower gas velocities and control mixing of fuel and air. 

Increasing the size of the penetration in the furnace wall to accommodate an 

enlarged burner throat will require high pressure part modi ications. Further, the 

d to promote burner 

performance these ports will also require pressure-part modi ications, and 

increase installation times. For these latter conditions, 18-month project schedules 

are typical. 

 

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SECTION 5 

CRITIQUE OF EXAMPLES CITED BY EPA 

This section of the report responds to and offers additional information on 

retro it examples that EPA has cited in support of its idea that it is reasonable to 

expect a single FGD installation to be completed in a total of 27 months and a single 

SCR installation to be completed in a total of 21 months. As noted in the following 

sections of this report, the installations cited by EPA (EPA, 2005; EPA, 2002) in 

support of those shorter installation schedules occurred at the beginning of the last 

decade and are not representative of recently completed FGD and SCR installations, 

or of FGD and SCR retro its that are likely to be undertaken in the near future. There 

are many reasons for this, including the fact that irst generation installations took 

place before owners and contractors knew all the pitfalls presented by these kinds 

of projects; now that the pitfalls are better known, plant owners typically require 

more upon faith that contractors will know how to address 

the unique factors presented by each installation. 

expect to ind at all the sites now being evaluated for control equipment retro its. 

The wide distribution of implementation schedules displayed in Figures 3-1 and 4-1 

bears witness to the fact that each site is unique and each presents its own retro it 

challenges. 

Finally, as discussed below, previous descriptions of the projects cited by EPA in 

support of its short installation deadlines may be incomplete. Additional 

information suggests that, in fact, some of the projects cited by EPA took longer to 

complete than suggested by EPA. 

5.1 FGD INSTALLATIONS OVERVIEW 

Figure 5-1 is a timeline showing the amount of FGD capacity that has been installed 

over the past decade and that is anticipated to be installed in the next two years. The 

 igure shows that the demand for FGD equipment and although not shown, SCR 

equipment was low around the year 2000, the time when all four key references 

cited by EPA were implemented. This igure suggests the experiences of those 

undertaking FGD retro its at the beginning of the past decade may not be 

representative of the experiences of those contemplating and conducting FGD 

retro it at present. Further details concerning the EPA-cited retro its that were 

undertaken approximately 10 years ago are described in the following sections. 

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Figure 5-1: Timeline Showing Recent Installed FGD Capacity by Startup Date 

5.2 EPA EXAMPLES OF FGD INSTALLATIONS BEING COMPLETED IN A 

TOTAL OF LESS THAN 30 MONTHS 

EPA cites two examples of FGD installations being completed in a total of less than 

30 months: t

Further information on those installations is provided below. 

5.2.1 CENTRALIA WET FGD

The Centralia FGD project was completed in November 2001. EPA claims that it was 

completed in less than 30 months. In fact, the complete installation process appears 

to have taken longer than 30 months. Based on information in the public domain 

(Miller, 2004), it appears that Centralia owners irst initiated engineering for wet 

FGD for their units in January of 1999, not in May 1999 (as was previously 

reported), that FGD performance tests for the irst unit were conducted in 

November of 2001, and that the unit was declared commercial in December of 2001. 

Given that the installation of process equipment is not 

this information indicates that it took a total of almost three years to do all the work 

to install the FGD system for Unit 1 at Centralia. In addition, the reported on-line 

date for Unit 2 (December 2002), indicates that 48 months were required for 

completion of work on the second Centralia unit. 

In addition to the fact that the Centralia installation appears to have taken more 

than a total of 27 months to complete, there are reasons to believe that the Centralia 

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installation is atypical. As noted in comments being separately submitted by 

Southern Company, the contract for the engineering and construction work at 

Centralia was part of a unique 

Centralia and the contractor. This type of relationship can speed subcontracting and 

procurement activities, but it can also require signi icant upfront negotiations and 

arrangements. As noted above, however, there can be pitfalls to any approach that 

does not set aside adequate time prior to the start of construction to ensure that the 

project design and engineering are done right. 

Also, because Centralia was an early generation installation, the plant owners may 

have had access to a larger number of experienced craftsmen to work on the project 

than would be available today, when so many retro its are being implemented in the 

same time period. Moreover, as an early generation retro it, Centralia may have 

faced fewer permitting obstacles than are faced by those now seeking to retro it 

FGD units (see Section 2.2.5 of this report). 

Finally, it appears that the Centralia site was not as challenging a candidate for 

retro its as some of the sites described in Section 3 of this report.5 

5.2.2 TAMPA ELECTRIC BIG BEND

was also an early generation project. Starting with time to prepare a detailed FGD 

bid speci ication, it irst appears (based on reports in the technical literature) that 

this project was operational in about 28 months. (Smolenski, 1999.) However, 

further investigation reveals that the reported schedule does not take into account 

that Tampa Electric conducted preliminary cost assessments and prepared the FGD 

procurement speci ication 8 months earlier. Also, a further review of records shows 

that the permit application for the project was submitted in July of 1996. This all 

indicates that the total amount of time needed to design, permit, and construct the 

FGD system was closer to a 42 month schedule than a 27- or 28-month schedule. 

In addition, there are several reasons for believing this project is not representative 

of the situations faced by many of the companies that will have to retro it FGD units 

in the next ive years. For example, it was possible for TECO to truncate the 

installation schedule at Big Bend by building upon the FGD installations that were 

already located at the site and in use at Big Bend Units 3 and 4. The reagent 

receiving and processing equipment and dewatering apparatus for the FGD 

equipment on Units 3 and 4 could with some limited modi ication be used in the 

new FGD installations at Units 1 and 2. Also, the land use permit for solid byproduct 

management already existed at Big Bend and likely received less scrutiny, which is 

 

5 An indication of the fact that the Centralia retro it may not have been a challenging one is that the 

reported FGD retro it cost of the project (approximately $100/kW on a 2001 dollar basis and 

$150/kW on a 2010 dollar basis) are a factor of 2-3 less than more recent projects.

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very different from the situation faced today by those seeking permits for new, 

6 

5.3 EPA EXAMPLES OF SCR INSTALLATIONS BEING COMPLETED IN A 

TOTAL OF LESS THAN 30 MONTHS 

EPA cites two examples of SCR installations being completed in a total of less than 

24 months: those early 2000 installations at the AES Kintigh station in New York 

ennsylvania. 

No information is available in the literature concerning the SCR project for 

Keystone, and very little information is available concerning the SCR project at the 

AES Kintigh station in New York. The available data do suggest, though, that the 

Kintigh project from start to inish 9 months in duration, and one of the irst SCR 

retro it installations in the country is atypical in several respects. For example, the 

procurement process for the Kintigh project does not re lect what most plant 

owners would have to follow today: there is no evidence this work was 

competitively bid; indeed, it is possible that B&W was the contractor selected 

-

g a contractor perhaps not unreasonable for the 

time period bypassed the open, competitive bid process generally mandated for an 

investor-owned utility or public agency. This procedure may not be available to 

investor owned or public agencies without prudency challenges. 

Also, the non-traditional Kintigh facility approach generally does not make sense for 

the much more complicated installations that companies now face. More complex 

projects require more effort to be taken up-front in the planning process before 

actual construction begins in order to minimize problems on the back end. 

Further, as noted in Section 2, those involved in the Kintigh project faced far fewer 

regulatory obstacles 10 years ago than plant owners face today. For example, a 

decade ago, companies did not have to deal with current requirements to predict 

and mitigate SO3 emissions from SCR units. 

5.4 OTHER FACTORS 

EPA also acknowledges (EPA, 2005; EPA, 2002) that the installation of multiple FGD 

and/or SCR units at one site will require more time than suggested in the proposed 

transport rule proceeding. While the overall conclusion is correct installing 

multiple control units at one site will take longer than installing just one control unit 

at the site EPA underestimates the complications in undertaking multiple 

installations simultaneously at a site. EPA assumes that many of the basic activities 

required conceptual system design, selecting the precise technology to be 

installed, developing technical speci ications for the project, identifying bidders, 

 

6 As was the case with the Centralia retro it, a further indication that the Big Bend Unit 1 and 2 FGD 

retro it may not have been a challenging one is that the reported FGD retro it cost of the project was 

low: approximately $100/kW on a 2001 dollar basis.

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procuring their bids, evaluating those bids, and awarding contracts are executed 

for not one but multiple units7. However, the rate-limiting step in a multi-project 

FGD or SCR retro it is usually construction, and the impediments that retro it 

activities for one unit can impose upon another. It is optimistic for EPA to assume 

that the incremental required time period for each additional retro it would be just 

4 months. 

In summary, there is not suf icient information to be able to determine the actual 

time it took to design, permit, and construct the projects upon which EPA relies in 

concluding that FGD and SCR retro its can routinely be completed in a total of less 

than 30 months. There is, though, a long list of reasons why the FGD and SCR 

retro its undertaken a decade ago may have taken less time to complete than those 

now being undertaken. It is generally believed the irst generation of retro its 

provided fewer challenges to those presently undertaking the work. For example, 

the simpler sites were logically chosen irst. Also, in the present timeframe, there 

are dif iculties in getting necessary preconstruction permits now that did not exist 

(or did not exist to the current extent) a decade ago. And inally, even EPA 

acknowledges that multiple installations of FGD and SCR installations at a single site 

will take longer sometimes much longer than single retro its. (Speci ically, EPA 

concluded ive years ago that it would then take 30 to 40 months to install multiple 

SCR and FGD equipment, respectively (EPA, 2005).) All of these factors undercut 

that FGD and SCR retro it installations can typically be completed in a total of less 

than 30 months. 

 

See Figures 1 and 2 of EPA, 2005.

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SECTION 6 

SUMMARY/CONCLUSIONS 

Signi icant evidence exists to show that the installation schedule proposed by EPA 

for SCR and FGD process equipment 21 and 27 months, respectively is 

unrealistic. Actual installation schedules that are reported in Sections 3 and 4 

Table 6-1 summarizes the observed total schedules for design and installation of 

 lue gas desulfurization, selective catalytic reduction, and combustion controls (e.g., 

low NOx burners). 

Table 6-1. Summary of Design, Fabrication, Installation Period 

Control 

Technology 

Site and Application Category 

Design, Fabrication, 

Installation (Months)

Flue Gas 

Desulfurization

Single Unit to Station: Large Owner 48 

Single Unit to Small (e.g., 

Cooperative) Owner 

50 

Two Units to Site 51 

Three or More Units to Site 54 

Selective 

Catalytic 

Reduction 

Single Unit to Site 40 

Multiple Units to Site 44 

Combustion 

Controls 

Both single and multiple 

installations 

12-18 months, 

depending on the 

speci ic conditions

As noted in both Sections 3 and 4, despite attempts to solicit schedule information 

from a representative sample of owners, it is not known if the results described in 

this report re lect a true statistically representative sample. As a consequence, 

although the estimates presented in Table 6-1 are believed valid, the trends 

between different categories should be viewed as approximate. However, it should 

also be noted that the number of example cases cited for FGD (23 projects at 21 

stations), and for SCR (15 projects at 13 stations) well exceed the much smaller 

number of references cited by the EPA. 

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The few cases cites by EPA provide no legitimate basis for challenging the 

reasonableness of the schedules cited in Table 6-1. As noted in Section 5, the cases 

upon which EPA relies were done almost a decade ago and represent less than 5% 

of the present FGD and SCR inventory which has been installed. The evolution of the 

degree of sophistication of technology, permitting requirements, and market forces 

since that time has evolved as follows: 

6.1 DEMAND 

The demand for competent process design and equipment suppliers will lengthen 

schedules. The reference cases were selected from a period when less than 5% of 

the existing inventory was installed. Having such an abundant talent pool may have 

allowed construction schedules to be compressed during that timeframe. That is not 

possible now, when there is much greater demand for competent process design 

and equipment suppliers. 

6.2 LABOR PRODUCTIVITY 

Demand affects labor productivity: with scores of projects underway 

simultaneously, there will be much more demand for the limited pool of skilled 

workers. As discussed in Section 2, this can have a disproportionately adverse effect 

on later-in-the-pipeline projects, which can frequently be projects for smaller utility 

systems. Construction schedules can be protracted as work schedules cannot be 

accomplished quickly with less experienced staff. 

6.3 ENGINEERING 

McCarthy (2004) describes a typical effort required a two-phase engineering 

approach, independent of whether a company adopts a system design or an 

individual optimized design. The irst phase established the design basis (gas low 

rate, gas composition, available reagent composition), optimized a standard 

absorber design, established balance-of-plant needs, and developed a layout and 

preliminary cost. The second phase addressed details of balance-of-plant and 

auxiliary equipment, and developed detailed contracts for fabrication and 

construction schedules by which to manage the work and hold subcontractors 

accountable. Each phase reportedly required 6 months. Such attention to detailed 

design is necessary, for either approach that emphasizes a system versus an 

optimized individual unit design. Before awarding contracts valued at several 

hundred million dollars, any less effort in the present activist climate could invite 

prudency challenges. 

6.4 PERMITTING 

As discussed in Section 2.2.5 of this report, those retro itting SCR and FGD 

installations today face far more regulatory hurdles today than plant owners faced 

R and FGD units 

can be subject to the rigors of the new source review preconstruction permitting 

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program. Also, those retro itting SCR units will need to conduct a detailed 

estimation and accounting of byproduct sulfuric acid emissions, with remedial 

means included in the design. These permitting issues were assuredly not part of 

the 9-month SCR retro it at the Kintigh facility. In addition, as also discussed in 

Section 2.2.5, those undertaking FGD retro its will face myriad other requirements 

to get environmental permits (some of which could take 4 or more years to get) and 

other authorizations . 

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SECTION 7 

REFERENCES 

Name, Date Citation 

EPA, 2005

cument for the Final Clean Air 

Interstate Rule, EPA Docket Number OAR-2003-0053, March 2005. 

EPA, 2002

Affecting the Installation of Control Technologies for Multipollutant 

PA-600/R-02/073, October 2002. 

Hallman, 

2010 

Hallman, C., Personal communication with M. Stroben, August 20, 2010. 

Hansen, 

undated Issue 6. 

http://www.pennenergy.com/index/power/display/297417/articles/powerengineering/volume-111/issue-6/features/clearing-the-air-in-the-twincities.html

Katzberger, 

2007 Coal Power Magazine, September 1, 2007. 

http://www.coalpowermag.com/plant_design/Plant-Economics-The-Impactof-Shortages-on-FGD-Prices_73.html

McCarthy, 

2004 Lowest System- edings of the 2004 Combined 

- 30-

September 2, 2004, Washington, D.C. 

Miller, 

2004 

-of-Art SO2

Proceedings of the Combined Power Plant Air Pollutant Control Mega-

-September 2, 2004, Washington, D.C. 

PSNH, 

2010 Utilities Commission, March 31, 2010, Docket 08-103 Informational Session.

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Smolenski, 

1999 Station Units 1 & 2 Advanced Design -

DOE-EPA Combined Utility Air Pollution Control Symposium: The MegaSymposium, August 16-20, 1999, Atlanta, GA. 

Wall, 2010

-Symposium, August 30-September 2, 

2010, Baltimore, MD. 

31531.420001 EMF_US 32738079v1 

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