BART Analysis i March 2008

Gerald Gentleman Station Units 1 & 2

REVISED

Best Available Retrofit

Technology (BART) Analysis

for

Units 1 & 2

Gerald Gentleman Station

Sutherland, Nebraska

For submittal to:

Nebraska Department of Environmental Quality

Air Quality Permitting Section

Suite 400, The Atrium

1200 N Street

P.O. Box 98922

Lincoln, Nebraska 69509-8922

Prepared by:

701 Xenia Avenue South, Suite 600

Minneapolis, MN 55416

Attention: Ed Liebsch

Ed.Liebsch@hdrinc.com

(763) 591-5452

With control technology costs provided by:

February 2008
BART Analysis ii March 2008

Gerald Gentleman Station Units 1 & 2

EXECUTIVE SUMMARY

This report and the accompanying air emission (PSD) construction permit application

were prepared for Nebraska Public Power District (NPPD), Gerald Gentleman Station, Units 1

and 2 (GGS1&2), according to the Environmental Protection Agency’s (EPA’s) regional haze

regulations under 40 CFR 51, Appendix Y. These regulations provide guidance on determining

whether facilities need to install Best Available Retrofit Technology (BART) emissions controls

to improve existing visibility impairment in certain areas of the nation. This report is being

submitted to the Nebraska Department of Environmental Quality (NDEQ), in accordance with

BART requirements.

The analysis provided by this report is required because dispersion modeling of visibility

impacts in certain National Parks, Wilderness Areas, and/or Wildlife Refuges, designated as

Class I areas, indicates that the visibility impacts of GGS1&2 would potentially exceed the

established exemption threshold of 0.5 deciviews (dV) on a 98

th

-percentile basis at one or more

Class I areas (HDR 2006). In light of this analysis, NPPD prepared for GGS1&2 a BART

analysis to determine whether BART emissions controls should be installed, and if so, what

emissions levels should be met after installation of emissions controls.

NPPD submitted a BART analysis for GGS1&2 to NDEQ in August 2007. The BART

analysis was based on EPA’s five-part process, and included: (1) identification of available

retrofit control technologies; (2) an evaluation of the technical feasibility of the available control

technologies; (3) ranking the technically feasible control technologies by order of effectiveness;

(4) evaluating the control technologies for economic impacts, energy impacts, and non-air quality

environmental impacts; and (5) an evaluation of the incremental visibility improvement

potentially achievable under each of the identified BART control alternatives.

This document updates the August 2007 BART analysis. Since August 2007, NPPD has

initiated a comprehensive multi-pollutant control technology study for the Gerald Gentleman

Station. The purpose of the study was to review the technical feasibility of potentially available

controls taking into consideration site-specific retrofit challenges, and to review and update the

cost of the retrofit technologies. Costs included in this document are based on site-specific

conceptual design layouts for each of the potential retrofit technologies. Major equipment costs

were based on vendor budgetary quotes. Material costs were developed based on project-specific

quantities and recent commodity costs. Costs in this document more accurately reflect the costs

that NPPD would incur to install the various retrofit technologies on GGS1&2.
BART Analysis iii March 2008

Gerald Gentleman Station Units 1 & 2

This report concludes that BART for GGS1&2 should be the installation and

optimization of modern Low Nitrogen Oxide (Low-NOx) combustion control technology as

necessary to meet a NOx emission limit of 0.23 lb/MMBtu, on a 30-day rolling average basis.

The 0.23 lb/MMBtu emission limit would be based on an average across both units, as allowed

under EPA regional haze guidelines (EPA 2005). Economic impacts associated with postcombustion NOx control using selective catalytic reduction (SCR) were determined to be

excessive compared to modeled visibility impact improvement. The incremental costeffectiveness of SCR was estimated to be approximately $100 million/yr/deciview of

improvement if it were added to a Low-NOx combustion control system. This cost is

approximately an order of magnitude greater than the cost of NOx controls required for other

BART eligible sources, and is excessive for a facility that will meet the BART presumptive level

for NOx.

This report also contains a detailed BART analysis of installing sulfur dioxide (SO2)

emission controls (specifically, available flue gas desulfurization (FGD) technologies) on

GGS1&2. This analysis includes an evaluation of the economic impacts and visibility benefits of

installing such SO2 emission controls to meet the EPA’s presumptive BART limit of 0.15

lb/MMBtu. Under EPA’s BART guidelines, the NDEQ retains discretion not to adopt the

presumptive limits if these control levels are determined not to be appropriate under the BART

five-part analysis, on a case-by-case basis for a given facility. The BART analysis supports

NDEQ making such a determination for no additional SO2 control at GGS1&2, given the very

high estimated expenditure per unit of modeled visibility improvement ($/deciview, or $/dV). In

the case of GGS1&2, the cost/benefit ratio for meeting the presumptive SO2 limit is estimated to

be approximately $169 million/year/dV for either a dry or wet FGD system, if added to the

baseline (no-control) scenario. If added to the plant after implementation of Low-NOx

combustion control, the cost effectiveness is still extremely high at approximately $123

million/year/dV. These costs are approximately an order of magnitude greater per year per dV

compared to what other facilities are spending for BART controls. Thus, this analysis

demonstrates that SO2 controls are not justified for GGS1&2.

For particulate matter (PM), NPPD proposes to retain the current opacity and particulate

matter limits applicable to GGS1&2. Modeling at current tested actual emission rates showed

negligible impacts of direct PM emissions on Class I areas, and the existing baghouses already

provide the best PM control possible.

Upon EPA approval of the NDEQ’s proposed State Implementation Plan (SIP)

submission for BART purposes, currently due to EPA, NPPD would have five years after the date
BART Analysis iv March 2008

Gerald Gentleman Station Units 1 & 2

of EPA SIP approval to complete the installation and operation of emission controls to meet the

established BART emissions levels.
BART Analysis v March 2008

Gerald Gentleman Station Units 1 & 2

Table of Contents

CHAPTER 1.0 - INTRODUCTION ............................................................................................... 1

1.1 Overview .............................................................................................................................1

1.2 Source Description ..............................................................................................................2

1.3 BART Analysis Methodology.............................................................................................2

1.4 Analysis Organization .........................................................................................................5

CHAPTER 2.0 – BART ANALYSIS ............................................................................................. 6

2.1 Overview .............................................................................................................................6

2.1.1 GGS1&2 Power Generation Process......................................................................... 6

2.1.2 Applicable Pollutants................................................................................................. 7

2.1.3 Project Economic Evaluation Criteria ....................................................................... 8

2.2 BART for Sulfur Dioxide (SO2)........................................................................................10

2.2.1 Identification of SO2 Control Technologies ............................................................ 10

2.2.2 SO2 Control Technology Effectiveness................................................................... 15

2.2.3 Evaluation of Impacts.............................................................................................. 16

2.3 BART for Nitrogen Oxides (NOx) ....................................................................................26

2.3.1 Identification of NOx Control Technologies........................................................... 26

2.3.3 Evaluation of Impacts.............................................................................................. 32

2.4 BART for Particulate Matter (PM)....................................................................................39

2.5 Visibility Impacts Analysis...............................................................................................40

CHAPTER 3.0 – PROPOSED BART SELECTION .................................................................... 44

3.1 Incremental Visibility Improvement Comparison.............................................................44

3.2 Proposed BART ................................................................................................................47

CHAPTER 4.0 – PSD Permit Application.................................................................................... 52

4.1 Overview ...........................................................................................................................52

4.2 Best Available Control Technology ..................................................................................53

4.3 Air Quality Impact (Dispersion Modeling) Analysis........................................................54

4.4 Additional Impacts Analysis.............................................................................................57

4.5 Summary ...........................................................................................................................58
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List of Tables

Table 1 Economic Criteria*............................................................................................................. 8

Table 2 SO2 Control Technologies Considered in Steps 1 & 2 of BART Analysis Process......... 14

Table 3 SO2 Control Technology Effectiveness............................................................................ 15

Table 4 SO2 Cost of Compliance................................................................................................... 20

Table 5 NOx Control Technologies Considered in Steps 1 & 2 of BART Analysis Process........ 31

Table 6 NOx Control Technology Effectiveness........................................................................... 31

Table 7 NOx Cost of Compliance.................................................................................................. 35

Table 8 Analyzed Emission Scenarios for GGS1&2..................................................................... 42

Table 9 Modeled Stack Parameters for GGS1&2 ......................................................................... 42

Table 10 Visibility Modeling Results for GGS1&2...................................................................... 43

Table 11 Incremental Visibility Cost Comparison – Multipollutant Control................................ 45

Table 12 Incremental Visibility Cost Comparison – NOx Control............................................... 46

Table 13 Incremental Visibility Cost Comparison – SO2 Control................................................ 47

Table 14 BART Proposals............................................................................................................. 48

Table 15 Recent CO BACT Limits for Similar Unit Retrofits...................................................... 53

Table 16 Maximum Modeled CO Concentrations in Comparison to Regulatory Thresholds ...... 57

List of Figures

Figure 1 Furnace Temperatures..................................................................................................... 29

Figure 2 Least Cost Curve............................................................................................................. 36

List of Appendices

Appendix A ............................... Dry FGD and ID Fan & Auxiliary Power Conceptual Design

Costs

Appendix B................................ Wet FGD and ID Fan & Auxiliary Power Conceptual Design

Costs

Appendix C................................ SCR and ID Fan & Auxiliary Power Conceptual Design Costs

Appendix D ............................... NDDH Permit Forms
BART Analysis 1 March 2008

Gerald Gentleman Station Units 1 & 2

CHAPTER 1.0 - INTRODUCTION

1.1 Overview

On July 6, 2005, the EPA published final amendments to its 1999 regional haze rules in

the Federal Register, including 40 CFR 51, Appendix Y, thus finalizing guidance for BART

determinations (70 FR 39104-39172). The regional haze rules establish guidelines that States

may follow in setting BART emissions limits on emission sources that are:

1) BART-eligible based on their having begun operation after August 8, 1962, and being “in

existence” before August 8, 1977, which includes sources that had received a

construction permit by the latter date; and,

2) which “may reasonably be anticipated to cause or contribute” to visibility impairment in

any Class I area.

Under the EPA’s BART guidelines, air quality modeling is used to determine whether a

given source is potentially causing or contributing to visibility impairment in any Class I area.

The CALMET/CALPUFF modeling system is a system of air quality modeling software,

recommended by EPA,

1

which is used to make the assessments of visibility impacts for BARTsubject facilities. This modeling system was applied to GGS1&2 using a protocol approved by

the NDEQ. The results of the CALMET/CALPUFF modeling assessment indicate that the

visibility impacts of GGS1&2 would potentially exceed the established threshold of 0.5 dV on a

98

th

-percentile basis at one or more Class I areas (HDR 2006). In light of this analysis, NPPD has

prepared for GGS1&2 the following BART analysis to determine whether emission controls

should be installed to improve visibility in Class I areas, and if so, what levels of control should

be applied to each unit. The BART emissions levels selected for GGS1&2 are based on EPA’s

five-part analysis that includes an evaluation of the incremental visibility improvement

potentially achievable under each of the identified BART control alternatives.

1 Notably, the final BART Guidelines expressly identify and endorse CALPUFF as an appropriate

modeling application. See 70 Fed. Reg. at 39,122 (stating that “CALPUFF is an appropriate application for

states to use for the particular purpose of this rule ... [and that the EPA Guidelines] encourage states to use

it for these purposes”).
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The following sections of the report comprise the BART determination analysis for

GGS1&2 following the applicable EPA regulatory guidance found in Appendix Y of 40 CFR 51.

1.2 Source Description

Owned and operated by Nebraska Public Power District (NPPD), Gerald Gentleman

Station (GGS) is located on Highway 25 South, approximately 5 miles to the south of the City of

Sutherland, Lincoln County, Nebraska. GGS currently consists of one existing 665 megawatt

(MW, net) unit (GGS1) and one 700 MW (net) coal-fired electric generating unit (GGS2).

Ancillary equipment at GGS consists of coal unloading from rail cars, coal storage and handling,

and coal preparation equipment.

GGS1&2 utilize reverse gas baghouses as their emissions control device for particulate

matter. For control of nitrogen oxide (NOx) emissions, GGS1 has recently installed (in 2006)

modern low-NOx combustion technology in conjunction with over-fire air (OFA) combustion

controls. Although the GGS1 low-NOx burners are already installed, the GGS1 low-NOx

combustion technology is being evaluated in this analysis as a candidate BART emission control

system, because the baseline emission rate period for BART-subject modeling in Nebraska was

2001-2003. NPPD is currently optimizing the NOx performance of the GGS1 low-NOx

combustion system, as it gains experience in operation of this system at various load conditions.

GGS2 currently utilizes its originally-installed burners. Various existing coal and ash handling

processes at the facility are controlled using a combination of bag filters and dust suppression.

1.3 BART Analysis Methodology

Federal regulations (codified at 40 CFR Part 51.301) define BART as:

“...an emission limitation based on the degree of reduction achievable through the

application of the best system of continuous emission reduction for each pollutant which

is emitted by an existing stationary facility. The emission limitation must be established,

on a case-by-case basis, taking into consideration the technology available, the costs of

compliance, the energy and nonair quality environmental impacts of compliance, any

pollution control equipment in use or in existence at the source, the remaining useful life

of the source, and the degree of improvement in visibility which may reasonably be

anticipated to result from the use of such technology.”

In summary, BART is defined as an emission limitation based on the maximum degree of

pollutant reduction, determined on a case-by-case basis, considering technical, economic, energy,
BART Analysis 3 March 2008

Gerald Gentleman Station Units 1 & 2

and environmental factors, the remaining useful life, and a degree of visibility improvement

resulting from the emissions reductions.

On July 6, 2005 the EPA issued guidelines for conducting a BART determination, which

are contained in Appendix Y to 40 CFR Part 51. The first step in determining the appropriate

level of control is to identify all available retrofit technologies for each pollutant in question.

Technologies required as Best Available Control Technology (BACT) or Lowest Achievable

Emissions Rate (LAER) must be considered as control options in the BART determination. The

control options that are technically infeasible are eliminated and the remaining options are

evaluated to determine their control effectiveness and economic, energy, environmental, and

visibility impacts.

The five basic steps of a case-by-case BART analysis are:

1. Identify All Available Retrofit Control Technologies. Control technologies should include

pollution prevention, use of add-on controls and combinations of the two.

2. Eliminate Technically Infeasible Options. Technologies demonstrated to be infeasible based

on chemical, physical, and engineering principles are excluded from further consideration.

3. Evaluate Control Effectiveness of Remaining Control Technologies. Technically feasible

control technologies are ranked in the order of highest expected emission reduction to lowest

expected emission reduction and are evaluated following a “top-down” approach similar to

BACT analyses.

4. Evaluate Impacts and Document Results. Impacts that should be considered for each control

technology include: cost of compliance, energy impacts, non-air quality environmental

impacts, and the remaining useful life of the unit to be controlled.

5. Evaluate Visibility Impacts. Modeling should be preformed on the pre- and post-control

emissions to determine the actual impact on visibility and assess the visibility improvement

achieved and at what cost. This step does not need to be performed if the most stringent

control technology is chosen.

The BART analysis focuses on the following regulated air pollutants: SO2, NOx, and PM

(both fine and coarse fractions). Although both GGS units have an individual stack, they were

modeled as a single stack. This was done to help prevent an overestimation of impacts due to
BART Analysis 4 March 2008

Gerald Gentleman Station Units 1 & 2

availablility of ambient background compounds (e.g. ammonia) that contribute to secondary fine

particulate formation. The model individually evaluates each plume with respect to total

available background compounds with no consideration to simultaneous plumes consuming and

reducing available background compounds.

In accordance with EPA guidelines set forth in 40 CFR 51, Appendix Y, Part III,

emission estimates used in the modeling analysis to determine visibility impairment impacts are

intended to reflect steady-state operating conditions during periods of high capacity utilization.

Because the visibility impairment modeling methodology evaluates the potential impact

of the entire facility (GGS1&2) on given Class I areas, NPPD proposes to address the BART

requirements on a facility-wide basis. Using a facility average emission rate to meet target

emission levels will allow more operational flexibility while providing a more cost effective and

environmentally beneficial approach.

This approach is supported by EPA’s BART guidelines as detailed in the July 6, 2005

Federal Register, page 39172:

“You should consider allowing sources to ‘average’ emissions across any set of BARTeligible emission units within a fence line, so long as the emission reductions from each

pollutant being controlled for BART would be equal to those reductions that would be

obtained by simply controlling each of the BART-eligible units that constitute [the]

BART-eligible source”.

Averaging is also consistent with the BART-eligibility dispersion modeling, which

modeled the emissions from both units as if they were coming from one stack.

Finally, the BART analysis gave consideration to the presumptive limits that EPA has

provisionally suggested for SO2 and NOx control. With respect to NOx, NPPD is proposing to

meet the presumptive limit using low-NOx combustion technology. Further control beyond the

NOx presumptive limit of 0.23 lb/MMBtu is not justified based on the very high cost, relative to

visibility improvement, of adding further control in the form of Selective Catalytic Reduction

(SCR) as shown in Chapter 3 of this document. In accordance with EPA’s Appendix Y

guidelines, NPPD is recommending that the presumptive SO2 limit not be adopted for GGS1&2

based on a careful consideration of the statutory factors.

2

Instead, NPPD is proposing that the

2 EPA acknowledges that the presumptive limits “may not be appropriate for all sources” and that “States

have the ability to consider the specific characteristics of the source at issue and to find that the

presumptive limits would not be appropriate for that source.” 70 Fed. Reg. at 39,134 column 3. In addition,

EPA’s Appendix Y guidelines specifically state that an alternative SO2 control level, in lieu of the
BART Analysis 5 March 2008

Gerald Gentleman Station Units 1 & 2

existing SO2 limits be retained given the extremely high costs of installing available flue gas

desulfurization technologies and low levels of visibility improvement that are estimated to be

achieved from the prospective SO2 controls, and the very high cost/benefit ratio (cost per dV of

improvement). A detailed analysis of the control costs and incremental air quality improvements

of each identified emissions control option is presented in Chapter 3 of this report.

1.4 Analysis Organization

Chapter 2 provides a pollutant-by-pollutant BART analysis and addresses

proposed control effectiveness and visibility impacts. Chapter 3 provides recommended BART

levels based on EPA’s five-part analysis that includes an evaluation of the incremental visibility

improvement potentially achievable under each of the identified BART control alternatives.

presumptive SO2 limit, may be adopted if that “alternative control level is justified based on a careful

consideration of statutory factors.” Appendix Y to Part 51, Section IV.E.4
BART Analysis 6 March 2008

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CHAPTER 2.0 – BART ANALYSIS

2.1 Overview

To better understand the interaction of control technologies and the retrofit application of

control technologies to a coal-fired boiler, the following sections provide a discussion of

equipment and formation of the BART-applicable pollutants for the GGS1&2 units.

Additionally, some fundamental economic information used in the BART analysis is

summarized.

2.1.1 GGS1&2 Power Generation Process

GGS1&2 consist of several components, which include the fuel preparation system, air

supply system, burners, furnace, heat transfer system, and existing pollution control equipment in

the form of reverse gas baghouses. After the coal is pulverized, it is transported from the fuel

preparation system using a portion of the primary combustion air. The transported fuel is then

mixed with additional combustion air (oxygen) in a controlled fashion and subsequently injected

through burners into the furnace.

Thermal energy released by the combustion process is captured by both radiant and

convective heat transfer systems that use the thermal energy to create superheated steam. In

general, radiant heat transfer is accomplished through multiple water filled tubes that line the

furnace walls. Water enters the tubes at the bottom of the boiler and rises to a steam drum at the

top of the boiler as it is heated. Heated water in the tubes exceeds the normal boiling temperature

of water at the furnace exit; however, high pressures within the tubes maintain the water in a

liquid state until it is collected as steam in the steam drum. The convective heat transfer system

generally consists of superheater, reheater, and economizer, which are used to extract the balance

of thermal energy contained by the exhaust gases before they exit the boiler. Superheated steam

is routed to a steam turbine, which drives an electrical generator.

The type and quantity of exhaust gases that result from the combustion process are

dependent on the specific design of the air supply, burner, and furnace system. Fly ash exits the

boilers with exhaust gases and is captured by the baghouse system. Bottom ash drops into a

water trough at the bottom of the boiler and is removed from the water by a drag conveyor system

and deposited in trucks for transfer to the on-site ash disposal area.

Currently, GGS1&2 use western subbituminous coal from the Powder River Basin

(PRB). Fuel for day-to-day operation of the units is delivered by railcar. An on-site coal storage

area is used for periods of delivery interruption.
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Gerald Gentleman Station Units 1 & 2

2.1.2 Applicable Pollutants

The BART analysis for GGS1&2 addresses criteria pollutant emissions of SO2, NOx and

PM.

SO2 Formation. SO2 emissions are formed from the oxidation of organic and pyritic

sulfur in the coal during the combustion process. The majority of sulfur is oxidized to SO2,

however, a small quantity is further oxidized to form sulfur trioxide (SO3). Approximately 90

percent of the sulfur present in the subbituminous coal will be emitted as SOx compounds.

Alkaline ash from some coals (including PRB coals) may cause some of the sulfur to react in the

furnace to form various sulfate salts that are then retained in the fly ash. Sulfuric acid mist

(H2SO4) forms when SO2 emissions react with moisture and oxygen in the environment.

NOx Formation. There are two primary mechanisms of NOx formation in coal-fired

utility boilers: thermal production of NOx from atmospheric nitrogen and oxygen, and oxidation

of nitrogen bound in the fuel. High combustion temperatures cause the nitrogen (N2) and oxygen

(O2) molecules in the combustion air to react and form NOx. Because the thermal NOx

production is primarily a function of combustion temperature, NOx emission rates vary greatly

with burner design. Experimental measurements of thermal NOx formation have shown that the

NOx concentration is exponentially dependent on temperature and is proportional to nitrogen

concentration in the flame, the square root of oxygen concentration in the flame, and the gas

residence time

3

. The formation of fuel NOx from reactions of fuel-bound nitrogen and air, can

account for up to 80 percent of total NOx from coal combustion. Subbituminous coals contain

from 0.5 to 2 percent by weight fuel-bound nitrogen.

PM Formation. PM emissions from utility boilers are a function of the boiler burner

configuration, operation practices, coal properties, and pollution control equipment. Uncontrolled

PM emissions include ash from the non-combustibles in coal as well as unburned carbon resulting

from incomplete combustion. When combusting pulverized coal, PM emissions are primarily

composed of inorganic ash residue because combustion is nearly complete, resulting in minimal

unburned carbon.

PM emissions are classified as filterable and condensable. Filterable PM is the portion of

total PM present in the exhaust stream as a solid or liquid, and which is typically measured on an

EPA Method 5 filter (Appendix A of 40 CFR 60). Condensable PM is the portion of PM that is

initially present as a gas in the exhaust stream, but condenses to a liquid or solid state at cooler

ambient temperatures.

3 EPA Publication AP42, Chapter 1, Bituminous and Subbituminous Coal Combustion, (9/98).
BART Analysis 8 March 2008

Gerald Gentleman Station Units 1 & 2

For purposes of BART, only certain components of total PM emissions are analyzed in

the visibility impact modeling: coarse particulate matter (PMC) and fine particulate matter

(PMF). PMF is defined as having an aerodynamic diameter of less than or equal to 2.5 microns.

PMC has an aerodynamic diameter greater than PM2.5, but less than or equal to 10 microns.

2.1.3 Project Economic Evaluation Criteria

Table 1 lists the general economic criteria used in the BART analysis to support capital

and annual cost calculations for various emission control technologies.

Table 1

Economic Criteria*

Economic Parameters Value

Amortization Life, years 20

Real Interest Rate, percent 5.25

O&M Cost Escalation, percent 2.5

Auxiliary Electric Power Cost, $/kW/yr 46.00

Auxiliary Electric Demand Cost, $/MWh 45.65

Outage Cost, $/MWh 31.90

Ash Disposal Costs, $/ton 5

Operating Labor Rate, $/hr 40.60

Lime Cost, $/ton delivered 95

Urea Cost, $/ton delivered 400

Water, $/1000 gallon 1.00

Limestone, $/ton delivered 26.00

SCR Catalyst Cost, $/cubic meter 7000.00

Fabric Filter Bag Cost, $/bag 157.00

Bag Change Out labor, $/bag 15.00

Bag Change Out Frequency – Wet FGD, years

between

7.00

Bag Change Out Frequency – Dry FGD, years

between

5.00

* Cost estimates for SO2 control technologies also included the cost of, or income

generated from, SO2 allowances required by the Acid Rain Program.

Cost estimates included in the BART analysis were compiled from a number of data

sources, based on 2007 dollars. In general, the cost estimates followed guidance provided in the

EPA Air Pollution Control Cost Manual, January 2002 (EPA 2002). Costs were developed based

on site-specific conceptual layouts for each control technology. Major equipment costs were
BART Analysis 9 March 2008

Gerald Gentleman Station Units 1 & 2

based on vendor budgetary quotes. Material costs were developed based on project-specific

quantities for each conceptual layout and recent commodity costs. Labor costs were developed

using the Union Craft rates and fringe benefits from the Omaha, Nebraska area, including costs

related to F.I.C.A., workers compensation, applicable taxes, incidentals, construction equipment

and contractor’s overhead. Labor crews were based on the types of construction crews and skills

required for the specific projects. The cost estimates also include indirect expenses such as

engineering costs, construction management, sales/use taxes, contingency, General Owner’s

Costs, and Owner’s Bond Fees. Detailed cost estimates and support data are provided in

Appendices A, B, and C, for dry flue gas desulfurization (FGD) or dry scrubbing, wet flue gas

desulfurization (FGD) or wet scrubbing, and for selective catalytic reduction (SCR),

respectively.

Over the past several years, prices on air pollution control equipment have increased

significantly. Several trends have contributed to the rapid escalation in costs, including the

greater demand for equipment and materials, significant increases in commodity prices, and

greater demand for skilled labor and construction contractors.

Over the past 4-year period the demand for electric utility steam generating emission

control equipment, including FGD and SCR control systems, increased significantly in response

to the Clean Air Interstate Rule (CAIR). CAIR, published May 12, 2005, mandates specific

emission caps on SO2 and NOx emissions from power plants located in 28 eastern and

Midwestern states. CAIR emission caps will be imposed in two phases, with the first phase

beginning in 2009 for NOx and 2010 for SO2. The second phase of emission reductions is

required in 2015 for both pollutants. CAIR is projected to result in the installation of an

additional 64 GW of flue gas desulfurization and an additional 34 GW of selective catalytic

reduction technology on existing coal-fired generation capacity.

4 This increase in demand for

retrofit emission control systems created a “sellers market” in the U.S. Pollution control

equipment vendors, their fabricators and material suppliers currently have significant backlogs

and are able to charge higher margins, contributing to the recent escalation in retrofit control

technology costs.

Construction contractors and construction labor are currently in high demand in the U.S.,

not only in the electric power generating industry but also in the petroleum refining, chemical

processing, and ethanol industries. All of these industries pull from the same labor force. Due to

4

“Regulatory Impact Analysis for the Final Clean Air Interstate Rule,” U.S. EPA Office of Air and

Radiation, EPA-452/R-05-002, March 2005.
BART Analysis 10 March 2008

Gerald Gentleman Station Units 1 & 2

increased demand, construction contractors are more selective with the projects that they bid, and

are able to demand higher margins. Similarly, the labor force is able to demand more lucrative

contracts in order to be attracted to an area that is short of labor. Per diems and mandatory

overtime are often needed to attract sufficient labor to support major construction projects.

During the same period, commodity prices have also increased significantly. Commodity

price data available from the U.S. Department of Labor’s Bureau of Labor Statistics show a sharp

upturn in metals prices since 2004. Pollution control projects require large quantities of basic

commodities, including steel, concrete, and copper. Increased commodity prices have a

significant impact on the cost of large emission control retrofit projects.

Because of the rapid escalation in equipment costs, commodity costs, construction and

labor, cost data from projects completed prior to 2005 were not included in the GGS BART cost

estimate. As described above, cost estimates were developed based on site-specific general

arrangements for each potential BART control technology using vendor budgetary quotes and

recently published costs for commodities, construction, and labor.

2.2 BART for Sulfur Dioxide (SO2)

The objective of this analysis is to determine BART for SO2 emissions from GGS1&2

units. The following subsections provide a review of the available SO2 control technologies and

their comparative effectiveness. Final BART determinations also take into account visibility

impacts, which are discussed commonly for all pollutants in Section 2.5. Final BART

determinations are detailed in Chapter 3.0.

2.2.1 Identification of SO2 Control Technologies

Generally, there are two approaches to controlling SO2 emissions: removal of elemental

sulfur from the fuel prior to combustion and flue gas desulfurization (FGD), which consists of

removal of SO2 from the flue gases after combustion.

Many oil refineries operate catalyst-based desulfurization units to remove organic sulfur

from crude oil and produce hydrogen sulfide (H2S). Sulfur recovery units are then used to

recover elemental sulfur from the H2S produced by desulfurization. Most sulfur recovery units

utilize a form of the Claus process, by which some H2S is combusted to form SO2 and the

remaining H2S and SO2 are combined over a catalyst to produce H2O and elemental sulfur.

In solid fuels, such as coal, a significant fraction of the sulfur is in the form of pyrite

(FeS2) or some other mineral sulfates. Mineral sulfates can be removed through washing or other

physical cleaning. However, organic sulfur cannot be removed by physical cleaning. Because

coal is solid, the use of chemical desulfurization processes can be very costly. Additionally, it is
BART Analysis 11 March 2008

Gerald Gentleman Station Units 1 & 2

unlikely that sufficient desulfurization of coal can be accomplished to meet current SO2 emission

requirements. Therefore, some form of FGD must be considered for solid fuels.

FGD technologies can be divided into two main categories, regenerative and throwaway

processes. Regenerative processes recover sulfur in a usable form that can be sold as a reusable

sulfur product. Throwaway processes remove sulfur from the flue gas and the scrubber

byproducts are discarded. All of the FGD technologies considered can achieve SO2 removal

efficiencies sufficient to meet the presumptive limit of 0.15 lb/mmBtu on lower sulfur coals (such

as Powder River Basin coal).,

Regenerative processes, by nature, contain a regeneration step in the FGD process that

results in higher costs than throwaway processes due to equipment and operational expenses.

However, in instances where disposal options are limited and markets for recovered sulfur

products are readily available, regenerative processes may be used. Potential regenerative

processes that are available include the Wellman-Lord (W-L) process, magnesium oxide process,

citrate scrubbing process, Flakt-Boliden process, aqueous carbonate process, Sulf-X process,

Conosox process, Westvaco process, and adsorption of SO2 by a bed of copper oxide.

A new regenerative process that was developed as an indirect result of collaborative

research with the former U.S. Bureau of Mines and the University of Minnesota is the Pahlman

process. The Pahlman process is a dry-removal technology that can remove multiple pollutants

(NOx and SO2). As a regenerative process, the Pahlman process purportedly reduces problems

associated with waste disposal and creates a commercially valuable byproduct. In the closed-loop

process, the Pahlmanite sorbent repeatedly captures NOx and SO2, which upon regeneration,

yields raw sulfates and nitrates. The Pahlman process is new technology that has been pilot

tested at several industrial sites, including smaller coal-fired electrical generating plants.

However, proven technical feasibility with application to large-scale coal-fired electrical

generating units, such as the GGS1&2 units, has yet to be demonstrated. Therefore, this new

regenerative technology will not be considered further in this BART analysis.

Throwaway processes, such as limestone scrubbing, have become widely accepted by the

coal-fired power industry for FGD because limestone scrubbers have lower overall costs and are

simpler to operate than regenerative processes. Because the throwaway processes can achieve the

same removal efficiencies as regenerative processes and cost less, this BART analysis for SO2

will focus on throwaway processes and further discussion of regenerative process will not be

considered.
BART Analysis 12 March 2008

Gerald Gentleman Station Units 1 & 2

Throwaway processes can be divided into two categories, wet or dry. Wet or dry refers

to the state of the waste by-products. Both wet and dry technologies have advantages and

disadvantages with respect to initial capital and operational expenses.

2.2.1.1 Wet FGD

Wet scrubbing (wet FGD) systems used for SO2 reduction typically consist of the

following operations: scrubbing or absorption, reagent handling and slurry preparation, sludge

processing, and flue gas handling.

Wet FGD technology is a well-established process for removing SO2 from flue gas. In

wet scrubbers, the flue gas enters the spray tower absorber where it contacts the water slurry

which is approximately 10 percent limestone. The calcium in the slurry reacts with the SO2 in the

flue gas to form calcium sulfite or calcium sulfate. The overall chemical reaction can be simply

expressed as:

SO2 + CaCO3 → CaSO3 + CO2

Spent slurry from the reaction tank is pumped into a thickener where solids settle before being

filtered for final dewatering to approximately 50 percent solids. Water removed during this

process is sent to a process water holding tank, which eventually will require wastewater

treatment. In a non-regenerative system, the waste sludge must also be disposed of properly.

Finally, scrubbed flue gases are directed through a stack gas reheater in order to minimize

corrosion downstream of the scrubber due to conversion of SO2 to SO3 and subsequently, sulfuric

acid (H2SO4). Reheating is sometimes needed for proper drafting and rise of exhaust gases out

the stack, as well as minimizing condensate. As an alternative, the stack can be constructed of

acid resistant material.

Most wet FGD systems have two stages, one for fly ash removal and one for SO2

removal. The flue gas normally passes first through a fly ash removal device, either an

electrostatic precipitator (ESP) or a bag filter, and then into the SO2 absorber. There are many

different types of absorbers that can be used in wet FGD systems, including: spray towers,

venturis, plate towers, and mobile packed beds. However, many of these systems can result in

scale buildup, plugging or erosion, which can affect the dependability and efficiency of the

absorber. Therefore, simple scrubbers such as spray towers are commonly used. The chief

drawback of the spray tower design is that it requires a higher liquid-to-gas ratio for equivalent

removal of SO2 compared to other absorber designs.
BART Analysis 13 March 2008

Gerald Gentleman Station Units 1 & 2

Finally, many utilities offset the operating costs of wet FGD by selling one of the

byproducts, calcium sulfate, also known as gypsum, to wallboard manufacturing facilities. This

is economically attractive only when there is sufficient local demand for wallboard such that a

manufacturing plant would be located in the area. Because there is little local wallboard demand

near GGS, NPPD would not be able to take advantage of the operating cost offset, thus incurring

higher operating costs for wet FGD than attained by utility plants in more populated areas, where

there is significant wallboard demand. The gypsum byproduct has also been used as a cement

filler or as a soil additive, but neither of these applications have achieved widespread use.

Without an opportunity to reuse this byproduct, NPPD would incur additional costs, compared to

many other plants, for land filling the gypsum.

Other reagents can be used to capture SO2 in a wet FGD. Lime rather than limestone can

be used, but an order-of-magnitude evaluation showed limestone was more cost effective than

lime at GGS. Sodium alkali solutions can also be used in FGD systems, however these processes

are considerably more expensive than lime. The preferred sorbents are limestone and lime,

respectively, due to the availability and relatively low cost of limestone.

2.2.1.2 Dry FGD

In contrast to wet scrubbing systems, dry FGD systems (spray-dryer absorber) systems

use much smaller amounts of liquid. With a spray dryer absorber (SDA) system, the flue gases

enter an absorbing tower (dryer) where the hot gases are contacted with a finely atomized slurry,

which is usually a calcium-based sorbent such as calcium hydroxide or calcium oxide (lime).

Acid gases and SO2 are absorbed by the slurry mixture and react to form solid salts. The

absorption process is temperature dependent and the cooler the flue gas, the more effectively the

acid gases will react with the sorbents. The overall chemical reactions can be simply expressed

as:

Ca(OH)2 + SO2 → CaSO3(s) + H2O

Ca(OH)2 + 2HCl → CaCl2 (s) + 2H2O

As can be seen above, one mole of calcium hydroxide will neutralize one mole of SO2,

whereas one mole of calcium hydroxide will neutralize two moles of hydrochloric acid (HCl). A

similar reaction occurs with the neutralization of hydrofluoric acid (HF). These reactions

demonstrate that when using a spray dryer the HCl and HF are removed more readily than SO2.
BART Analysis 14 March 2008

Gerald Gentleman Station Units 1 & 2

Reagent requirements should consider that the HCl and HF are removed first, followed by the

reagent quantity required to remove the SO2

5

.

The heat of the flue gas evaporates the water droplets in the sprayed slurry, and a nonsaturated flue gas exits the absorber tower. The exhaust stream exiting the absorber contains fly

ash, calcium salts, and un-reacted lime, which must be sent to a particulate control device such as

an electrostatic precipitator (ESP) or fabric filter (baghouse). The particulate control device not

only is necessary to control particulate matter, but also aids in acid-gas removal. Acid gases are

removed when the flue gas comes in contact with the lime-containing particles on the surface of

the ESP or baghouse. Fabric filters are considered to have slightly higher residual acid gas

removal levels than ESPs because the acid gases must pass through the lime-containing filter cake

in a fabric filter system. Modern dry FGD systems include a loop to recycle a portion of the

baghouse-collected material for re-use in the FGD module because this material contains a

relatively high amount of unreacted lime.

A summary of the identified SO2 control technologies and their technical feasibility for

GGS1&2 is provided in Table 2. This constitutes a summary of Steps 1 and 2 of the five-step

BART analysis process, as explained in Chapter 1. As shown in Table 2, the two technically

feasible processes, meaning those demonstrated to be effective on large coal-fired boilers, are

Wet FGD and Dry FGD. Therefore, these two technologies are carried through the remainder of

the BART analysis process in the following sections of this report.

Table 2

SO2 Control Technologies Considered in Steps 1 & 2 of BART Analysis Process

Coal Desulfurization Infeasible - not demonstrated for low-sulfur PRB coal

Pahlman Process Infeasible - not demonstrated on large coal-fired boilers

Other Regenerative

Processes

Infeasible – none have been demonstrated on large coal-fired boilers

Wet Scrubbing Feasible based on demonstrated performance on many similar units

Dry Scrubbing Feasible based on demonstrated performance on many similar units

5 Karl B. Schnelle, Jr. and Charles A. Brown, Air Pollution Control Technology Handbook, CRC Press,

2002.
BART Analysis 15 March 2008

Gerald Gentleman Station Units 1 & 2

2.2.2 SO2 Control Technology Effectiveness

Effectiveness is measured by the amount of SO2 removed by each control technology

based on a comparison of the controlled emission rates to the uncontrolled baseline emission rate

of the GGS1&2 units. Table 3 provides a summary of the SO2 control technology effectiveness.

Table 3

SO2 Control Technology Effectiveness

Identified

Control Technology

Emission Rate

(lb/MMBtu)

Potential

Emissions

(tons/yr)

A

Tons SO2

Removed

(tons/yr)

GGS1&2 Baseline 0.749 49,785 NA

Wet FGD 0.15 9,970 39,815

Dry FGD 0.15 9,970 39,815

A Based on maximum actual 24-hour emissions, maximum heat input of 15,175.5 MMBtu/hr and

100% capacity factor. Note that the potential tons/year value for the Baseline greatly overstates

emissions levels (and hence impacts on downwind Class I areas) since it is calculated by using the

maximum 24-hour emissions realized over the 3-year baseline period (2001-2003), at a 100%

capacity factor. Thus, the tons/yr removed values and improvements in downwind Class I areas

are also greatly overstated under this BART analysis.

As indicated in Table 3, it is anticipated that either the Dry or Wet FGD control systems

can achieve the presumptive BART emission level for SO2. This conclusion is based on

observations of FGD control in use on similar emission sources. The tons/year potential emission

levels in Table 3 are consistent with EPA guidance for using maximum actual 24-hour emissions

(over a three-year baseline period) for the BART dispersion modeling. However, actual SO2

emissions in a typical year with either FGD control system would be lower due to variable coal

sulfur and plant load.

In general terms, removal of high concentrations of SO2 in flue gas can be accomplished

using either Dry or Wet FGD. Lower concentrations become more difficult to control and require

greater amounts of reagent. Historically, Wet FGD systems have been used on higher-sulfur

eastern coals, leading to higher efficiencies cited for wet FGD systems, given there is much more

sulfur to control. However, on lower-sulfur western coals (such as the Powder River Basin coal

used at GGS1&2) modern Dry FGD systems, with improved atomizer systems in conjunction

with modern fabric filter technology, can perform as well as Wet FGD systems. Much of the

final SO2 control in a Dry FGD system takes place in the reagent-rich filter cake on the fabric

filter.
BART Analysis 16 March 2008

Gerald Gentleman Station Units 1 & 2

The equivalency in anticipated 24-hour SO2 emission rates using Dry or Wet FGD

technology makes economics the primary BART selection factor. Typically, Dry FGD

technology has lower capital costs while Wet FGD, which uses a lower cost reactant (limestone),

has lower operating costs. On the other hand, Wet FGD control systems have higher auxiliary

power requirements and generatea solid waste byproduct that requires dewatering and additional

handling. Wet FGD would also use more water than Dry FGD (although both systems use a

significant amount of water), which can be an important factor in technology selection in a semiarid location such as western Nebraska.

The cost effectiveness of a retrofit FGD control system is a function of several projectspecific design and operating parameters including flue characteristics, facility layout, existing

control technologies, equipment retrofit and tie-in challenges, as well as water and reactant

availability. Because retrofit FGD cost effectiveness is project-specific, detailed cost estimates

were prepared for both Wet and Dry FGD control systems. The cost effectiveness of each control

system is summarized in subsection 2.2.3.1. A visibility impact analysis, required by the BART

regulations to quantify potential visibility impact improvements associated with retrofit

technologies, is included in Section 2.5.

2.2.3 Evaluation of Impacts

The following sections present a detailed evaluation of the impacts of employing FGD to

control SO2 emissions from the GGS1&2 units. Associated impacts include: cost of compliance,

energy, non-air quality environmental impacts, and remaining useful life. An assessment of

incremental improvement in visibility is discussed separately under Section 2.5 and Section 3.0.

2.2.3.1 Cost of Compliance

Detailed cost estimates, including capital costs and annual operating and maintenance

(O&M) costs, were developed for Wet and Dry FGD control systems. Cost estimates were based

on a conceptual design layout and site general arrangement developed for retrofitting GGS Units

1 & 2 with either a Wet or Dry FGD control system. Capital costs were developed based on

burning 100% PRB coal, and include the equipment, material, labor, and all other direct costs

needed to retrofit GGS Units 1 & 2 with a FGD control system.

Fixed and variable O&M costs were also developed for each control system. Fixed

O&M costs include operating labor, maintenance labor, maintenance material, and administrative

labor. Variable O&M costs include the cost of consumables, including reagent (lime or

limestone), by-product management, bag replacement for the baghouse, water consumption, and

auxiliary power requirements. Auxiliary power costs reflect the additional power requirements

associated with operation of the new FGD control system, including operation of any new ID fans
BART Analysis 17 March 2008

Gerald Gentleman Station Units 1 & 2

as well as the power requirements for the absorber pumps, reagent handling, reagent preparation,

and by-product handling.

Retrofit projects can present significant design challenges with respect to fitting the

control technology into an existing facility layout. These retrofit challenges can add significantly

to the overall cost of the retrofit project. Some examples of retrofit costs include: (1) demolishing

and rebuilding existing equipment and structures in order to make room for the retrofit

technology; (2) replacing or supplementing existing fans to overcome additional pressure loss

associated with the retrofit technology; (3) rebuilding or reinforcing existing vessels and

ductwork to withstand increased operating pressures; and (4) lost revenue associated with

extended outages needed to construct and tie-in the retrofit technology.

2.2.3.1.1 Dry FGD Retrofit Costs

Several general arrangements of major equipment and structures were reviewed for the

GGS Dry FGD control option. Based on engineering judgment, the general arrangement shown

in Appendix A (Dry FGD and ID Fan & Auxiliary Power Conceptual Design Costs) was selected

as the preferred arrangement. This arrangement was determined to be the most appropriate for

GGS Units 1 & 2 primarily because it minimized the length of ductwork between the spray dryer

absorber (SDA) outlet and the baghouse inlet, and eliminated any turns or elevation changes in

the post-SDA duct. Other options considered had significant lengths of duct, multiple turns, and

elevation changes in the duct after the SDA. These characteristics do not allow an FGD design

engineer to design the duct to avoid ash dropout. Ash dropout has two negative results after a dry

FGD. First, the dropout is moist and can cause the floor of the duct to corrode and eventually

need replacement. The ash will also dry in place and form an encrusted deposit that is not

entrained. The buildup will grow until it needs to be removed during an outage before the duct

collapses.

The preferred Dry FGD arrangement positions the SDAs east of the existing baghouses,

and includes three absorber vessels per unit. The three absorber per unit arrangement better suits

the existing GGS baghouse arrangement. Each SDA would be between 50 and 60 feet in

diameter, which is considered a reasonably sized absorber vessel. Flue gas would be re-routed

from the existing air heater outlets to a long duct and to each of the SDA modules. Each SDA

outlet would be close coupled to one baghouse casing inlet.

Because flue gas must go through the SDA before the baghouse, the inlet plenum of the

baghouses would have to be reversed. Reversing the baghouse inlet plenum would require the

roof of the plenum be cut from the baghouse inlet plenum side walls and a new roof installed.
BART Analysis 18 March 2008

Gerald Gentleman Station Units 1 & 2

The bypass dampers between the inlet and outlet plenum would have to be modified and

reconnected after the inlet is reversed. Three new inlets would need to be cut into the back side

of the baghouse casing for the modified inlets. Reversing of the inlet plenum is expected to

require at least 7-weeks of outage which is one week longer than any currently planned outages.

The existing baghouses at GGS are designed to handle continuous operating pressure up

to –35 inches of water column (in. w.c.) and currently operate in the -23 to -27 in. w.c. range.

The addition of a Dry FGD could add up to 10-12 in. w.c. of additional negative pressure before

the flue gas enters the baghouse. In addition, an SCR would add another 7 to 9 in. w.c. of

additional negative pressure. The existing baghouses are not able to handle this additional

cumulative negative pressure and would therefore need to be reinforced. Reinforcement of the

outlet header duct from the baghouse to the existing ID fans may also be necessary. The

reinforcement could take 20-weeks of outage to complete, which is 14-weeks longer than any

currently planned outage.

With the potential installation of only a Dry FGD system, even without SCR, new booster

ID fans are needed to overcome the pressure drop of the of the new FDG equipment in the flue

gas path.

Although the existing Unit 1 and 2 baghouses can be reused with the proposed Dry FGD

arrangement, modifications to the baghouses and baghouse reinforcement would be needed.

However, reusing the existing baghouses still represents a significant cost savings for the Dry

FGD arrangement.

With the operation of a Dry FGD system, the baghouses will be required to collect more

solids and the bags will need to be cleaned more frequently. This will result in an increase in tube

sheet pressure drop of between 1 and 2 in. w.c., and the increased cleaning frequency will

probably lessen the bag life by 10 to 20%.

Operation of a Dry FGD system will require that more fly ash and collected solids will

need to be transported by the baghouse fly ash system to the fly ash storage silos. It has been

determined hat the existing GGS fly ash systems are not large enough to handle this increased

loading. New, larger fly ash conveying systems for the GGS baghouses will be needed. The

existing GGS fly ash storage silos will also have to be demolished to make room for the Unit 1

spray dryer absorbers and two new fly ash storage silos will be required at a new plant site

location, along with appurtenant ash transport piping, support structures, and ash unloading

equipment and facilities.

In addition to the SDA vessels and baghouse modifications, the Dry FGD system

includes lime unloading, bulk storage, lime preparation (slaking and grit removal), recycle ash
BART Analysis 19 March 2008

Gerald Gentleman Station Units 1 & 2

handling and storage, and fly ash handling. The preferred Dry DGF general arrangement requires

the existing GGS Warehouse #1 to be demolished, which would require a new warehouse to be

built directly north of the main GGS plant warehouse.

2.2.3.1.2 Wet FGD Retrofit Costs

A general arrangement of major equipment and structures was also developed for a wet

limestone forced oxidation (LSFO) FGD control system at GGS (see Appendix B - Wet FGD and

ID Fan and Auxiliary Power Conceptual Design Costs). The Wet FGD arrangement includes one

absorber vessel for each unit. The Wet FGD absorber vessels would be located to the north of

Unit 1 and south of Unit 2. The downstream flue gas ductwork positioned after the existing ID

fans would be the location of the tie-ins for the Wet FGD. A new short duct would be added to

divert flue gas flow to each absorber area.

The wet absorber vessels will be designed based on a vertical spray/tray tower concept.

Flue gas and limestone slurry will be in countercurrent contact within the absorber vessel, with

the flue gas moving upward and the slurry spraying downward. Each absorber would have

multiple spray levels to uniformly distribute the slurry to the absorber. Each absorber vessel

would be approximately 69 feet in diameter, and have two trays for mass transfer of SO2 gas with

the limestone slurry.

Because the Wet FGD control system is downstream of the baghouse, the existing

baghouses and fly ash handling systems would remain as is, and would not be affected by the Wet

FGD retrofit. However, the existing ID fans do not have the capability to overcome the 8 to 10

in. w.c. of additional pressure drop associated with the Wet FGD. With the potential installation

of only a Wet FGD system, and no SCR, new booster ID fans are needed to overcome the

pressure drop of the new FGD equipment in the gas path.

The Wet FGD requires an acid resistant chimney liner that is designed to minimize the

re-entrainment of water droplets. If water droplets are re-entrained in the chimney they will exit

the chimney and may fall to grade. Two new chimney arrangements were reviewed: (1) one

common chimney with two flues (one for each unit); and (2) a new fiberglass reinforced plastic

(FRP) lined concrete shell chimney for each unit. Adding a new chimney for each unit was

deemed more cost effective than adding a common chimney with dual flues. Part of the reason

for choosing one chimney for each unit is to minimize the expensive ductwork downstream of the

absorber that typically requires either FRP or C-276 alloy clad liners to avoid corrosion. The

existing chimneys could be demolished or capped and left in place.
BART Analysis 20 March 2008

Gerald Gentleman Station Units 1 & 2

In addition to the absorber vessels and new chimneys, Wet FGD control systems include

limestone delivery, limestone unloading and storage, reclaim to the day silo, limestone

preparation (ball mills, hydroclone classification and slurry storage), limestone slurry feed

system, forced oxidation system including aerators and agitators, gypsum dewatering systems

(hydroclones, belt filters, and conveyor system for stackout), and gypsum waste disposal. Wet

FGD control systems also generate a process wastewater stream that typically requires treatment

prior to discharge. Wet FGD system blowdown treatment would include a blowdown storage

tank, lime silo, clarifiers, and chemical feed skids.

2.2.3.1.3 Retrofit Cost Summaries

Table 4 summarizes the capital and annual operating costs associated with retrofitting a Dry

FGD (spray dryer absorber) or a Wet FGD (limestone forced oxidation) system to the GGS1&2

units. Detailed cost estimates indicating sources for each cost category have been included in

Appendix A – Dry FGD and ID Fan & Auxiliary Power Conceptual Design Costs, and Appendix B

– Wet FGD and ID Fan & Auxiliary Power Conceptual Design Costs. The costs presented in Table

4 include the total cost for controlling SO2 emissions from both units at GGS. The costs for each unit

were combined for comparison to the visibility impacts, which were modeled as one combined

emission point for the two units.

Table 4

SO2 Cost of Compliance

Technology Option

Description

Dry FGD Wet FGD

Emission Rate (lb/MMBtu) 0.15 0.15

Emission Reduction (tpy) 39,815 39,815

Capital Cost ($) $981,592,000 $1,029,819,000

Annualized Capital Cost ($) $80,013,000 $83,965,000

Annual Operating Cost ($) $27,806,000 $24,485,000

Annualized Outage Cost ($)* $698,000 -

Total Annualized Cost ($) $108,517,000 $108,450,000

Cost Effectiveness ($/ton) $2,726 $2,724
BART Analysis 21 March 2008

Gerald Gentleman Station Units 1 & 2

* The annualized outage cost accounts for costs associated with the additional outage

time needed to install the retrofit technology (i.e., outage time required beyond any

regularly planned outage). Installation of Dry FGD will take, at a minimum, one

additional week of outage per Unit. Actual costs for the additional one week of

outage per unit will be approximately $8.4 million. These costs would be annualized

over the expected equipment life.

2.2.3.2 Energy Impact

Use of Dry or Wet FGD to control SO2 emissions from the GGS1&2 units would result in

energy penalties to GGS facility operations in the form of the electricity demand required for

operation of ancillary equipment such as the reagent preparation and atomizer equipment as well

as additional backpressure on the exhaust system that results in a slight reduction in output. The

additional electrical demand will consume between 1.9 percent and 2.7 percent of the total

generating capacity of GGS1&2, or approximately 26 MW (Dry FGD) to 16 MW (Wet FGD).

This is a significant energy penalty and will require replacement generating capacity equivalent to

electricity that is necessary to meet the electrical needs of 26,000 to 37,000 homes. It takes

approximately one kilowatt of generation to satisfy the needs of an average household, based on

statistics compiled by the US Department of Energy, Energy Information Administration

(http://www.eia.doe.gov/emeu/reps/enduse/er01_us.html#Electricity). This loss in net base load

generation capacity would need to be made up by installation of additional base load generation

capacity in Nebraska or nearby states. This energy impact is included in the BART analysis

costs.

2.2.3.3 Non-Air Quality Environmental Impacts and Cost Uncertainties

The primary detrimental non-air quality environmental impacts of an FGD system

include water consumption and the creation of waste byproducts (either solid or liquid) from the

spent reagent. Potential non-air quality environmental impacts associated with installing and

operating an FGD control system on GGS Units 1 & 2 are discussed below.

2.2.3.3.1 Disposal of Liquid and Solid Wastes

Wet FGD

As discussed in Section 2.2.1.1, a portion of the solid waste from a wet FGD, in

the form of gypsum can be used by local wallboard manufacturers. However, there are

no such manufacturers or significant local gypsum demand near GGS. Therefore, all of

the wet FGD solid waste would need to be landfilled. The disposal of additional amounts

of gypsum from the wet FGD process will use up the remaining available life of the GGS
BART Analysis 22 March 2008

Gerald Gentleman Station Units 1 & 2

fly ash landfill at an increased rate or require the construction of additional landfill(s) for

this material. The cost to build additional landfill facilities at an increased rate to handle

the increased amounts of solid wet FGD waste products has not been included in the

capital cost estimate, but is included in the assumed $/ton solid waste disposal cost.

The wet FGD process also generates a liquid waste stream which must be treated

and disposed of via an evaporator system or in a disposal pond. The cost of waste water

treatment is included in the capital cost estimate. The use of evaporators or disposal

ponds for wet FGD liquid waste disposal either reduces overall plant efficiency or

requires the use of additional land for disposal and settling ponds. The cost to build

additional evaporator systems or disposal ponds for the handling and disposal of liquid

FGD waste products has not been included in the BART analysis.

Dry FGD

Solid waste in the form of fly ash generated from a dry FGD process can be

landfilled. However, due to the increased particulate loading in the baghouse from the

dry FGD process, the amount of fly ash waste that must be disposed of is significantly

increased. In addition, lime slurry added to the flue gas in the dry FGD process, which

in turn intermixes and is collected with the fly ash, results in the fly ash product being

unsuitable for third-party uses such as cement filler. Currently about half of the station’s

fly ash is sold for reuse. Once a dry FGD system is in operation, the fly ash will not be

salable so it will have to be landfilled. This will more than double the quantity of solid

waste (i.e., fly ash and FGD waste) required to be landfilled. The disposal of additional

amounts of fly ash (solids) from the dry FGD process would use up the remaining

available life of the GGS fly ash landfill at an increased rate, or require the construction

of additional landfill(s) for this material. The cost to build additional landfill facilities at

an increased rate to handle the increased amounts of dry FGD waste products has not

been included in the capital cost estimate, but has been accounted for in the assumed

$/ton solid waste disposal cost.

2.2.3.3.2 Water Consumption

Wet and Dry FGD processes consume a significant amount of water to properly

operate the process. The amount of water required to properly operate a wet FGD system

for each GGS unit has been calculated to be about 1,100 gpm. The amount of water
BART Analysis 23 March 2008

Gerald Gentleman Station Units 1 & 2

required to operate a dry FGD system for each GGS unit has been calculated to be about

850 gpm.

Due to the ongoing drought in the western part of Nebraska, the Twin Platte

Natural Resources District (NRD) has imposed new water regulations governing the

consumption of any additional water due to a new use. The new regulations in essence

require that any new consumptive use of water be “offset” with reductions in

consumption in the same area.

The addition of either wet or dry FGD control systems at GGS would be a new

consumptive water use. FGD systems on the GGS Units would use an estimated 1,700

(Dry FGD on both GGS units) to 2,200 gpm (Wet FGD on both GGS units) depending

upon the type of FGD process utilized. The required offset of this additional

consumption of water would be very costly to the NPPD customers. The cost associated

with the offsetting of increased water consumption due to a FGD process on the GGS

units has not been included in the BART analysis.

To offset the costs associated with water consumption the plant may be able to

install additional equipment and infrastructure to capture and reuse some of the plant

site’s wastewater flow steams. However, it is estimated that the potential capture and

reuse of these wastewater flow streams will still leave a significant amount of water that

will be required to be supplied to the FGD systems to properly operate them. The cost

associated with the implementation of GGS plant site wastewater recovery systems for

the capture and reuse of wastewater for a FGD system has not been included in the

BART analysis.

2.2.3.3.3 Reagent Delivery

Wet and dry FGD systems consume a significant amount of reagent material to

properly operate the desulfurization process. The amount of reagent material required to

properly operate wet FGD systems for both GGS units has been calculated to be

approximately 222,000 tons / year (i.e., 171 semi-truck loads/week). The amount of

reagent material required to operate dry FGD systems for both GGS units has been

calculated to be approximately 171,000 tons / year (i.e., 132 semi-truck loads/week).

The usage and required delivery of this much reagent material to the GGS plant

site necessitates the need to evaluate how this reagent material will be delivered.

Delivery by semi-truck is theoretically possible, however, the required amount of truck

traffic to supply the required amount of reagent material would result in increased traffic
BART Analysis 24 March 2008

Gerald Gentleman Station Units 1 & 2

loading and wear and tear on the nation’s and state’s highway system. Delivery by semitruck also limits the range of vendors who could cost effectively supply reagent to the

station.

Reagent material delivery by rail to GGS is a possibility and does provide the

advantage of increasing the number of vendors that could supply the reagent material for

the FGD process. However, due to the increased loading on the nation’s rail system, it is

imperative to make the use of rail for reagent material delivery as efficient as possible.

To do this requires the use of unit trains (i.e. trains with 128 – 150 cars/train set). The

use of unit trains requires site facilities that can handle this type of equipment. The use of

unit trains to deliver reagent material can not interfere with the normal delivery of fuel

supplies to the station. Due to the advantages of FGD reagent material delivery by rail,

the addition of wet or dry FGD systems at GGS would require the installation of

additional rail infra-structure and unloading facilities on the GGS plant site. These costs

have been included in the BART analysis.

To maximize the competitive advantages of reagent material rail delivery to GGS

modification of the existing rail delivery system into the GGS plant site off of the Union

Pacific’s main line would be required. Currently, the GGS plant site rail infrastructure is

set up to take rail deliveries of the plant’s fuel supply from the west only which is where

the Powder River Basin coal mines are located. There is no existing rail infra-structure

to allow direct rail delivery from the east, onto the plant site. Any rail delivery from the

east must be transported to the Morril, NE switchyard and then brought back to GGS

from the west. This process is inherently inefficient and an undesired operation to be

performed by the railroad.

Potential FGD reagent material supply vendors have been identified to the east

and west of GGS. However, due to the existing rail infrastructure into GGS, only

suppliers to the west of GGS are realistically potential suppliers of reagent. Therefore, to

maximize the competitive nature of the reagent material suppliers, and in turn to

minimize the potential cost to purchase reagent, additional rail infrastructure would be

required to allow efficient reagent material delivery from the east of the GGS plant site.

These costs associated with the construction of rail infra-structure to allow for direct

delivery of reagent material located east of GGS have not been included in the BART

analysis.
BART Analysis 25 March 2008

Gerald Gentleman Station Units 1 & 2

2.2.3.3.4 Black Start

Wet and dry FGD systems require many large pumps and motors to properly

operate the processes. One high risk scenario for the plant is the potential need to “black

start” the unit due to the occurrence of a major natural disaster or storm (e.g., the

2006/2007 ice storms), or similar which essentially isolates the GGS units from the

electrical power grid. Although not fully analyzed to date, to be capable of “black

starting” one or both of the GGS units, with additional FGD equipment installed, will

most likely require the installation of additional plant site infrastructure and equipment

The costs associated with assuring the station can be “black started” has not been

included in the BART analysis.

2.2.3.3.5 Outage Duration

Field installation of a dry FGD system on the GGS units has been evaluated in

detail. The potential complexities of installing a dry FGD system on each of the GGS

units and the potential impact on the required outage length to complete the dry FGD

retrofit has been estimated to be up to 20 weeks for each unit. The costs associated with

a 20 week installation outage for a dry FGD system on each GGS unit has not been

included in the BART analysis. Only the bare minimum outage duration of 7-weeks for

each GGS unit, meaning one week beyond a regularly scheduled outage, has been

assumed for the Dry FGD cost analysis.

2.2.3.4 Remaining Useful Life

The useful remaining life of GGS1&2 is greater than 20 years under the current NPPD

energy resource plan. Therefore, the remaining useful life has no impact on the annualized

estimated control technology cost at this time under the current regulatory framework. However,

future CO2 control requirements are possible in the near term and those control requirements

create considerable planning uncertainty that weigh against NPPD making a major capital

investment for pollution control equipment until further understanding is gained on the planning

implications of any future CO2 control requirements for GGS. If significant CO2 emissions

reductions are mandated nationally in the next few years, the remaining useful life of the facility

could be shortened to less than 20 years, making the annualized costs of prospective controls

substantially higher.
BART Analysis 26 March 2008

Gerald Gentleman Station Units 1 & 2

2.3 BART for Nitrogen Oxides (NOx)

The objective of this analysis is to determine BART for NOx emissions from the

GGS1&2 units. The following subsections provide a review of the available NOx control

technologies and their comparative effectiveness. Final BART determinations also take into

account visibility impacts, which are discussed commonly for all pollutants in Section 2.5. Final

BART determinations are detailed in Chapter 3.0.

2.3.1 Identification of NOx Control Technologies

Control of NOx emissions from boilers can be attained through either the application of

combustion controls or flue gas treatment (post-combustion) technologies. Combustion-control

processes can reduce the quantity of NOx formed during the combustion process. Postcombustion technologies reduce the NOx concentrations in the flue gas stream after the NOx has

been formed in the combustion process. These methods may be used alone or in combination to

achieve the various degrees of NOx emissions required.

Developing or experimental NOx control technologies such as SCONOx or the Pahlman

Process (see Section 2.2.1) are not addressed in detail in this analysis, since these technologies

have not been demonstrated on large coal-fired boilers like the GGS units.

2.3.1.1 Selective Catalytic Reduction

Selective Catalytic Reduction (SCR) systems are an add-on flue gas treatment (postcombustion control technology) to control NOx emissions. The SCR process involves the

injection of a nitrogen-based reducing agent (reagent) such as ammonia (NH3) or urea (CON2H4)

to reduce the NOx in the flue gas to N2 and H2O. The reagent is injected into the flue gas prior to

passage through a catalyst bed, which accelerates the NOx reduction reaction rate. Use of SCR

causes a small amount of NH3 emissions (NH3 slip). As the catalyst degrades, NH3 slip will

increase, ultimately requiring catalyst replacement.

Many types of catalysts, ranging from active metals to highly porous ceramics, are

available for different applications. The type of catalyst chosen depends on several operational

parameters, such as reaction temperature range, flue gas flow rate, fuel chemistry, catalyst

activity and selectivity, operating life, and cost. Catalyst materials include, platinum (Pt),

vanadium (V), titanium (Ti), tungsten (W), titanium oxide (TiO2), zirconium oxide (ZrO2),

vanadium pentoxide (V2O5), silicon oxide (SiO2), and zeolites (crystalline alumina silicates).

SCR systems can utilize aqueous NH3, anhydrous NH3, or a urea solution to produce NH3

on demand. Aqueous NH3 is generally transported and stored in concentrations ranging from 19

to 30 percent and therefore requires more storage capacity than anhydrous NH3. Anhydrous NH3
BART Analysis 27 March 2008

Gerald Gentleman Station Units 1 & 2

is nearly 100 percent pure in concentration and is a gas at normal atmospheric temperature and

pressure. Anhydrous NH3 must be stored and transported under pressure and when stored in

quantities greater than 10,000 pounds, is subject to Risk Management Planning (RMP)

requirements (40 CFR 68). The urea solution (urea and water at approximately 32 percent

concentration) is used to form NH3 on demand for injection into the flue gas. A specifically

designed duct and decomposition chamber with a small supplemental burner is used to provide an

appropriate temperature window and residence time to decompose urea to NH3 and isocyanic acid

(HNCO). Application of urea-based SCR systems to utility boilers is a relatively new practice

that is still under development.

SCR systems used on large utility boilers are typically designed as high-dust hot-side or

low-dust hot-side systems. In a high-dust hot-side SCR system, the reactor is located downstream

of the economizer and upstream of the air heater, FGD system, and particulate control device.

Low-dust hot-side SCR systems locate the reactor downstream of a particulate control device

(typically an electrostatic precipitator) where the flue gas is relatively dust-free. Tail-end SCR

systems, located downstream from the air heater and downstream from all air pollution control

equipment where most flue gas constituents detrimental to the SCR catalyst have been removed,

are not typically considered for application on large coal-fired boilers. The primary technical

problem with a tail-end SCR configuration is the exhaust gas temperature. The temperature of

the exhaust gas exiting the FGD control device will be in the range of 125 to 200

o

F (depending

on the emission control systems). The temperature range for an SCR system must be above

approximately 600

o

F to support the NOx reduction reaction and inhibit the formation of

ammonium sulfate. Therefore, the exhaust gas would have to be re-heated to approximately 600

o

F to support NOx reduction. Re-heating the flue gas would require a series of heat exchangers

and the combustion of additional fuel, most likely natural gas..

SCR is a technically feasible retrofit technology that has been in limited commercial use

on utility boilers since the late 1970s, but has become more common in recent years to meet

stringent Clean Air Act requirements. Therefore, SCR is considered a feasible NOx control

technology and will be considered further in this BART analysis.

2.3.1.2 Selective Non-Catalytic Reduction

Selective non-catalytic reduction (SNCR) is another method of post-combustion control.

Similar to SCR, the SNCR process involves the injection of a nitrogen-based reducing agent

(reagent) such as ammonia (NH3) or urea to reduce the NOx in the flue gas to N2 and H2O.

However, the SNCR process works without the use of a catalyst. Instead, the SNCR process
BART Analysis 28 March 2008

Gerald Gentleman Station Units 1 & 2

occurs within the boiler, which acts as the reaction chamber. The heat from the combustion

process provides the energy for the NOx reduction reaction. Flue gas temperatures in the range of

1,500 to 1,900 oF, along with adequate reaction time within this temperature range, are required

for this technology. SNCR is currently being used for NOx emission control on some industrial

and utility boilers, and can in some cases (with higher uncontrolled emissions) achieve NOx

reduction efficiencies of up to 75 percent. However, technically feasible applications of SNCR

on larger pulverized coal utility boilers may be expected to achieve significantly less NOx

reduction.

Within the past few years the Department of Energy sponsored a research program to

evaluate potential SNCR effectiveness on a Babcock & Wilcox (B&W) test boiler, rated at 100

MMBtu/hr. The boiler used B&W’s ultra low-NOx pulverized coal burner technology, and was

fitted with Fuel Tech’s NOxOUT SNCR system. At full load conditions, firing PRB coal, the

system demonstrated 27 percent NOx reductions from a baseline value of 0.26 lb/MMBtu. At 60

percent load, the system achieved a 23.5 percent NOx reduction. The DOE Fact Sheet (DOE,

2004) for this research project states “The full-load conditions of utility boilers are very

challenging environments for SNCR technology, since temperatures are high and residence time

is low for reaction.”

SNCR is a proven technology that has been in commercial use on utility boilers, and

therefore, is generally considered a feasible NOx control technology for these types of emissions

sources. However, there are situations where SNCR has limited applicability, and can even be

counterproductive. Normally, SNCR injection is accomplished in the upper portion of the

furnace, where temperatures are typically in the desired 1,500 to 1,900 oF temperature window.

Some boiler/furnace designs, in combination with certain coals, can create very high furnace exit

temperatures, which make SNCR implementation problematic. If ammonia is injected above the

appropriate temperature window, it can lead to additional NOx production, rather than reduction.

GGS1&2 experience high temperatures at the furnace exit as well as throughout the

convection sections of the boiler. Heat flux into the waterwall tubes in the furnace is reduced by

ash deposition on the tubes. In particular, Powder River Basin coal has high levels of calcium

oxide and magnesium oxide that result in a reflective ash on the waterwall surfaces. Because

most heat transfer in the furnace is radiant, this reflective ash results in less heat removal in the

furnace and high exit gas temperatures.

The Nebraska City Unit 1 (NC1) boiler is similar in design and size to GGS1&2 and is

expected to have similar temperature profiles in the upper portions of the furnace, although

information from GGS indicates that temperatures are even higher than for NC1. Data collected
BART Analysis 29 March 2008

Gerald Gentleman Station Units 1 & 2

for NC1 by the operator, shown in Figure 1, demonstrate that over the majority of the operating

loads experienced by the facility, temperatures at the furnace exit plane (upper cluster/line) are

much too high for SNCR implementation.

Figure 1

Furnace Temperatures

Nebraska City Station - Unit 1

Flue Gas Temperature vs Load

0

500

1000

1500

2000

2500

3000

200 300 400 500 600 700 800 900 1000

Gross Unit Output (MW)

Temperature (deg F)

Average Finishing SH Inlet Temp Average Finishing SH Outlet Temp

Obviously, SNCR ammonia injection would need to occur farther downstream in the

convection section when combustion gases have cooled more. The convective passages are

occupied by pendent heat exchangers that inhibit flue gas flow and thorough mixing of reagent

with combustion gases. In addition, the location of the appropriate temperature zone would

fluctuate with levels of fouling, unit load and other conditions, requiring multiple injection points

with a dynamic determination of the appropriate injection point. Such an unorthodox SNCR

implementation would mean significantly lower residence time in the appropriate temperature

window, and would be subject to significant spacing issues. This type of design would tend to

result in relatively high ammonia “slip” or unreacted ammonia. High ammonia concentrations at

lower temperature can lead to plugging of downstream equipment, and a visible plume.
BART Analysis 30 March 2008

Gerald Gentleman Station Units 1 & 2

An additional problem is that high ammonia slip results in ammonia accumulation in the

fly ash, making the ash unsuitable for use in cement and other types of beneficial uses. Because

NPPD currently sells most of its fly ash from GGS1&2, the installation of SNCR equipment

would likely cause cessation of most or all of its ash sales. Current users of the ash would need to

seek other sources, resulting in additional transportation and fuel costs, and perhaps additional

land would be required for aggregate mining. In addition, NPPD would need to secure additional

landfill capacity, taking more land away from other uses, and increasing ash disposal costs.

Installation of SNCR in the convective sections downstream of boilers the size of

GGS1&2 is unproven and problematic at best, as described above. SNCR effectiveness under

these circumstances would be marginal, if any, and because installation of SNCR in the

convective passages is not a proven implementation method on large PRB-fired boilers, SNCR is

considered to be technical infeasible for GGS1&2.

2.3.1.3 Combustion Controls

Combustion controls such as flue gas recirculation (FGR), reducing air preheat

temperature (RAP), oxygen trim (OT), low excess air (LEA), over-fire air (OFA), staged

combustion air (SCA), and low NOx burners (LNB), can be used to reduce NOx emissions

depending on the type of boiler, characteristics of fuel and method of firing. In practice,

combustion controls have not provided the same degree of NOx controls as provided by add-on

post combustion control technologies, but are generally used in conjunction with add-on controls,

such as SNCR, to increase the NOx removal efficiency. New developments in LNB technologies

have demonstrated substantial reductions in NOx formation, however, only limited data are

available that demonstrate control potential approaching that of SCR systems. Combustion

controls have been in commercial use on industrial and utility boilers and are considered a

feasible NOx control technology.

A summary of the identified SO2 control technologies and their technical feasibility for

GGS1&2 is provided in Table 5. This constitutes a summary of Steps 1 and 2 of the five-step

BART analysis process, as explained in Chapter 1. As shown in Table 5, the two technically

feasible processes, meaning those demonstrated effective on large coal-fired boilers, are

LNB/OFA and SCR. Therefore, these two technologies are carried through the remainder of the

BART analysis process in the following sections of this report.
BART Analysis 31 March 2008

Gerald Gentleman Station Units 1 & 2

Table 5

NOx Control Technologies Considered in Steps 1 & 2 of BART Analysis Process

LNB/OFA Feasible based on demonstrated performance on many similar units

SCR Feasible based on demonstrated performance on several similar units

SNCR Infeasible due to high furnace exit temperatures

SCONOx Infeasible - not demonstrated on large coal-fired boilers

Pahlman Process Infeasible - not demonstrated on large coal-fired boilers

2.3.2 NOx Control Technology Effectiveness

Effectiveness is measured by the amount of NOx removed by each control technology

based on a comparison of the controlled emission rates to the uncontrolled baseline emission rate

of the GGS1&2 units. Table 6 provides a summary of the NOx control technology effectiveness.

Table 6

NOx Control Technology Effectiveness

Identified

Control Technology

Emission Rate

(lb/MMBtu)

Potential

Emissions

(tpy)

A

Tons NOx

Removed

(tpy)

GGS1&2 Baseline 0.455 30,243 NA

LNB/OFA 0.23 15,287 14,956

LNB/OFA + SCR 0.08 5,317 24,926

A Based on a maximum actual 24-hour emissions, maximum heat input of 15,175.5 MMBtu/hr and

100% capacity factor. Note that the potential tons/year value for the Baseline greatly overstates

emissions levels (and hence impacts on downwind Class I areas) since it is calculated using the

maximum 24-hour emissions realized over the 3-year baseline period (2001-2003), at a 100%

capacity factor. Thus, the tons/yr removed values and improvements in downwind Class I areas

are also greatly overstated under this BART analysis.

It is generally not practical to install higher efficiency NOx control technologies without

first optimizing combustion controls. Reducing the baseline concentration of NOx to be

controlled provides the benefit of longer catalyst life and less reagent usage for add-on NOx

control technologies. Furthermore, low NOx combustion controls may provide the required target

level of control with out the need for add on control.

The baseline NOx emission rate for GGS1&2 presented in Table 6 is the maximum actual

24-hour combined emission rate from both units for the period 2001 to 2003, which was prior to

the recent installation of low-NOx burners on GGS1. Currently GGS1 utilizes modern low NOx

combustion technology in conjunction with OFA combustion controls. Because the low-NOx
BART Analysis 32 March 2008

Gerald Gentleman Station Units 1 & 2

burners on GGS1 were installed after the BART baseline period (2001-2003) these burners are

being treated as part of the prospective BART NOx controls for this study. GGS2 utilizes the

originally-installed combustion control technology. BART options for further control of NOx

emissions from the GGS1&2 units have been evaluated in a staged approach. The first option

would be the installation and optimization of modern low NOx combustion technology on both

boilers. The second option involves the application of add-on controls, specifically SCR, to the

low NOx combustion technology controlled sources.

2.3.3 Evaluation of Impacts

The following sections present a detailed evaluation of the impacts of employing the

feasible control technologies to control NOx emissions from the GGS1&2 units. Associated

impacts include: cost of compliance, energy, non-air quality environmental impacts, and

remaining useful life. Visibility impairment is discussed separately under Section 2.5.

2.3.3.1 Cost of Compliance

Detailed cost estimates, including capital costs and annual O&M costs, were developed

for the LNB/OFA control scenario as well as the LNB/OFA plus SCR control scenario. Cost

estimates for the LNB/OFA control scenario were based on actual retrofit costs associated with

the GGS1 low-NOx burner project. Cost estimates for the SCR control system were based on a

conceptual design layout and site general arrangement developed for retrofitting GGS Units 1 & 2

with SCR. Equipment costs were developed based on vendor budgetary quotes. Material costs

were developed based on project-specific quantities for the conceptual SCR layout and recent

commodity costs. Labor crews and costs were developed based on the types of construction

crews and skills required for an SCR retrofit project, using Union Craft rates and fringe benefits

for the Omaha, Nebraska area.

Fixed and variable O&M costs were also developed for the SCR control system. Fixed

O&M costs include operating labor, maintenance labor, maintenance material, and administrative

labor. Variable O&M costs include the cost of consumables, including reagent (urea or

ammonia), catalyst replacement costs, spent catalyst management, and auxiliary power

requirements. Auxiliary power costs reflect the additional power requirements associated with

operation of the new SCR control system, including operation of any new ID fans as well as the

power requirements for the urea/ammonia handling and injection systems.

2.3.3.1.1 SCR Retrofit Costs

Several SCR arrangements were evaluated for GGS, including high-dust hotside, low-dust hot-side, and low-dust cold-side arrangements. The preferred arrangement
BART Analysis 33 March 2008

Gerald Gentleman Station Units 1 & 2

is generally a function of the fuel burned, anticipated affects on the catalyst, and the

existing emission control equipment arrangement. Because of the GGS units’ fuel

characteristics and existing equipment arrangement, including the fabric filter baghouses,

high-dust hot-side SCR arrangements were determined to be the most suitable for GGS

Units 1 & 2. Low-dust hot-side SCRs are typically located after a hot-side electrostatic

precipitator, therefore this is not a viable arrangement for the GGS boilers. Low-dust

cold-side SCRs, located downstream of all other emission control technologies (tail end

SCR), have not been used on large coal-fired electric utility steam generating units. A

low-dust cold-side SCR system would also require flue gas reheating to reach the

temperatures needed for NOx reduction.

In a high-dust hot-side arrangement, the SCR is located after the economizer and

before the air heater. The general arrangements for GGS Units 1 & 2 are shown in

Appendix C – SCR and ID Fan and Auxiliary Power Conceptual Design Costs. The sizes

of the GGS units dictate that two SCR reactors would be required per unit. Based on the

conceptual design, the GGS SCR reactors would be designed with three layers of

operating catalyst, with space for an additional fourth layer.

For hot-side high-dust installations, it is preferable to locate the SCR reactors

relatively close to the boiler economizer outlet in order to minimize the extent of the new

high-temperature ductwork. However, these areas of the power block usually are

extremely congested with existing equipment, air heaters, ash handling equipment, sump

pumps, and other equipment, as well as with utilities installed both above and below

grade. All of this generally presents significant challenges in the design and installation

of a reliable structural support system. Major support columns and bracing towers have

to be located around the existing equipment and utilities, increasing the amount of

structural steel required to support the loads. Using existing steel for the primary support

system usually requires extensive reinforcement, and significant relocation of existing

utilities that are routed along that steel. In addition, existing foundations supporting the

existing steel typically would not be adequate to support significant additional load.

Therefore, the preferred approach to support the SCR reactors and new ductwork is to use

new steel framing for vertical and lateral support using an independent structure.

Each units’ SCR reactors would be located above the existing ESP bypass ducts.

The ESP bypass ducts would be modified, as necessary, to include a penetration for the

SCR inlet and outlet. The SCR vessels would be located where the existing ESPs are
BART Analysis 34 March 2008

Gerald Gentleman Station Units 1 & 2

located, so the ESPs would have to be demolished to make room for the SCR reactors

and support steel.

With the potential installation of only a Wet FGD system, and no SCR, new

booster ID fans are needed to overcome the pressure drop of the new FGD equipment in

the gas path.

The adequacy of the existing ducts between the new SCR outlet and the new ID

fans or booster would have to be assessed during the detailed design of the system.

Similarly, increased gas pressure may affect the adequacy of the existing baghouses. The

baghouses at GGS are designed to handle continuous operating pressure up to –35 in.

w.c., and will need to be reinforced in order to safely handle additional pressures

associated with the SCR and Dry FGD control system. Reinforcement of the outlet

header duct from the baghouse to the existing ID fans may also be necessary. The

reinforcement could take 20-weeks of outage to complete, which is 14-weeks longer than

any currently planned outage.

For the SCR catalyst to operate efficiently, flue gas temperatures at the catalyst

inlet face should be maintained between approximately 560 and 780

o

F for PRB coal.

Based on operating data from GGS Units 1 & 2, flue gas temperatures at the economizer

outlet at full load are typically above the desired average maximum temperature of

780°F. To lower economizer exit gas temperatures economizer surface can be added,

although the superheat or reheat surface could also be changed. Economizer surface may

be added in the economizer backpass if there is room, or external boiler economizer

surface area may be added (i.e. SCR inlet ductwork). A detailed study would need to be

performed to determine the best approach for each of the GGS units to lower the

economizer exit gas temperatures. At this time, the capital cost estimate includes an

allowance for additional economizer surface area.

In addition to the reactor vessels, SCR control systems include ammonia

handling and injection systems. The source of ammonia for an SCR control system can

be: (1) anhydrous ammonia; (2) aqueous ammonia; or (3) urea. Anhydrous is the least

cost form of ammonia, but is dangerous to transport and can be dangerous if an accidental

release occurs. Aqueous ammonia is safer to transport, however, transportation is more

expensive because only 19% of the volume is ammonia (the remainder being water).

Urea is a dry granular material that can be hydrolyzed or decomposed to form ammonia.

Urea can be safely transported, and can be dissolved into water and turned into ammonia

at the power plant. It was decided that a urea based system would be the most suitable
BART Analysis 35 March 2008

Gerald Gentleman Station Units 1 & 2

system for GGS due to the inherent safety issues associated with handling anhydrous

ammonia.

Urea handling systems include: (1) truck delivery and unloading; (2) urea

dissolution; (3) hydrolyzer (which uses station steam to heat the urea to form ammonia);

(4) hydrolyzer waste handling system; and (5) ammonia feed system. The ammonia feed

system typically uses a blower and dilution air to propel ammonia into the ammonia

injection grid. The ammonia injection grid, coupled with static mixers, would be

designed to distribute ammonia uniformly across the SCR inlet duct.

2.3.3.1.2 NOx Control Retrofit Cost Summaries

Table 7 summarizes the capital and annual operating costs associated with

retrofitting NOx control systems to the GGS1&2 units. Detailed SCR costs estimates

indicating sources for each cost category have been included in Appendix C – SCR and ID

Fan & Auxiliary Power Conceptual Design Costs.

Table 7

NOx Cost of Compliance

Technology Options

Description

LNB/OFA

A LNB/OFA +

SCR

B

Emission Rate (lb/mmBtu) 0.23 0.08

Emission Reduction (tpy) 14,956 24,926

Capital Cost ($) $36,930,000 $515,081,000

Annualized Capital Cost ($) $2,960,000 $41,715,000

Annual Operating Cost ($) $- $14,515,000

Annualized Outage Cost ($)

C

$- $1,021,000

Total Annualized Cost ($) $2,960,000 $57,251,000

Total Cost Effectiveness ($/ton) $198 $2,297

Incremental Cost Effectiveness ($/ton) $198

D

$5,445

A)

Costs for LNB/OFA controls were developed by HDR based on actual project costs for the GGS

Unit 1 LNB retrofit project.

B)

Costs for the SCR control system were developed by S&L based the conceptual design layout and

assumptions detailed in this report.

C) The annualized outage cost accounts for costs associated with the additional outage time needed to

install the retrofit technology (i.e., outage time required beyond any regularly planned outage).
BART Analysis 36 March 2008

Gerald Gentleman Station Units 1 & 2

Installation of SCR controls will take, at a minimum, three additional weeks of outage time over a

regularly scheduled five (5) week outage. Actual costs for the additional outage will be

approximately $12.5 million. These costs would be annualized over the expected equipment life.

D) Compared to existing controls for NOx.

The cost effectiveness of the multiple control option (i.e., LNB/OFA + SCR) includes the

total annualized cost for all required control equipment. The cost of LNB/OFA + SCR includes

the cost of both the LNB/OFA system, as well as the SCR system. Costs for both control

equipment systems are included because the controlled emissions of each control scenario are

compared to the baseline emissions of GGS1&2 to obtain “Total Cost Effectiveness.” In

addition, a separate calculation is made to estimate the “Incremental Cost Effectiveness.” For

that calculation, the added annual cost of the next most stringent option (SCR) is divided by just

the incremental tons/year removed compared to the prior option (LNB/OFA).

Figure 2 provides a least cost curve that compares the two evaluated control scenarios to

aid in evaluating the most cost-effective control technology option.

Figure 2

Least Cost Curve

2.3.3.2 Energy Impact

There is no significant energy penalty associated with the use of combustion controls.

Modern low NOx burners can provide equivalent efficiency as compared to older common

burners.

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

0 5,000 10,000 15,000 20,000 25,000 30,000

Expected NOx Reduction (tons)

LNB/OFA

LNB/OFA

+ SCR

Total Annualized Cost ($1,000)
BART Analysis 37 March 2008

Gerald Gentleman Station Units 1 & 2

The application of post-combustion control SCR systems would consume power and

reduce overall unit efficiency, thereby decreasing energy available to consumers. The additional

electrical demand will consume almost 1 percent of the total generating capacity of GGS1&2, or

approximately 10 MW. This is not a trivial amount of generating capacity, being enough energy

to supply the electrical needs of approximately 10,000 homes. It takes approximately one kilowatt

of generation to satisfy the needs of an average household, based on statistics compiled by the US

Department of Energy, Energy Information Administration

(http://www.eia.doe.gov/emeu/reps/enduse/er01_us.html#Electricity). This loss in net base load

generation capacity would need to be made up by installation of additional base load generation

capacity in Nebraska or nearby states. These energy impacts are included in the operational costs

as part of the economic impact analysis.

2.3.3.3 Non-Air Quality Environmental Impacts and Cost Uncertainties

There are no non-air quality related impacts associated with combustion controls.

However, post-combustion controls would result in the following non-air quality environmental

impacts:

Resource Usage

Production of either urea, as assumed here for costing purpose, or ammonia, as an alternative,

primarily uses a finite resource (natural gas), so use of these SCR reagent materials could

have long term consequences on fossil fuel supplies. The costs associated with the long term

consequences on fossil fuel supplies due to the use of urea or ammonia on site at GGS has not

been included in the BART analysis.

Disposal of Solid Wastes/Fly Ash Sales

SCR systems may cause enough ammonia accumulation in the fly ash to make the ash not

usable for cement or other beneficial uses. Currently the plant sells the majority of its fly ash

for such beneficial uses. If the ash is contaminated by ammonia, the necessary landfilling

would more quickly use up the remaining available life of the GGS fly ash landfill or require

the construction of additional landfill(s) for this material. The cost to build additional landfill

facilities at an increased rate to handle the increased amounts of fly ash needed to be disposed

due to ammonia contamination has not been included in the BART analysis.
BART Analysis 38 March 2008

Gerald Gentleman Station Units 1 & 2

Non-air quality environmental impacts are also a function of the control technologies. For

example, the impacts summarized above address only SCR control systems. If the SCR control

system is installed with FGD controls, some of the potential non-air quality impacts become

cumulative, as described below:

Lost Capacity

Installation of FGD and/or SCR systems at GGS will result in the increased energy penalties

to operate these systems. These increased energy penalties directly translate to lost output

capacity from the station. The amount of lost capacity from the GGS units due to the

potential installation of some or a combination of FGD and/or SCR systems has been

estimated to be the following:

o Wet FGD installed on both GGS Units – 37 MW total

o Dry FGD installed on both GGS Units – 26 MW total

o SCRs installed on both GGS Units – 10 MW total

The amount of generation capacity that will be lost to offsite usage due to the increased

energy penalty to operate a FGD and/or SCR system or a combination is not a trivial amount.

This is enough energy to supply the electrical needs of up to 47,000 homes (i.e. combined wet

FGD & SCR installation on both GGS units).

The costs necessary to design, permit, build, and operate new generation based

infrastructure to replace this lost capacity from the GGS units has not been included in

the BART analysis.

Plant Control Equipment

Further evaluation of the installation of dry or wet FGD and/or SCR systems on GGS

indicates that significant modification and expansion of each unit’s respective control systems

may be required. These control systems include the digital control systems (DCS), burner

management system (BMS), and integrated logic system (ILS). The following budgetary cost

estimates have been generated for the required modifications to these systems:

o DCS Replacement – $2.0 million for each unit

o BMS Replacement – $1.250 million for each unit

o ILS Replacement – $2.0 million for each unit

However, due to significant unknowns in this potential required scope of work, the costs

associated with the updating of this control equipment for use with FGD and / or SCR

systems have not been included in the BART analysis.
BART Analysis 39 March 2008

Gerald Gentleman Station Units 1 & 2

2.3.3.4 Remaining Useful Life

The useful remaining life of GGS1&2 is greater than 20 years under the current NPPD

energy resource plan. Therefore, the remaining useful life has no impact on the annualized

estimated control technology cost at this time under the current regulatory framework. However,

future CO2 control requirements are possible in the near term and those control requirements

create considerable planning uncertainty that weigh against NPPD making a major capital

investment for pollution control equipment until further understanding is gained on the planning

implications of any future CO2 control requirements for GGS. If significant CO2 emissions

reductions are mandated nationally in the next few years, the remaining useful life of the facility

could be shortened to less than 20 years, making the annualized costs of prospective controls

substantially higher.

2.4 BART for Particulate Matter (PM)

The objective of this analysis is to determine BART for particulate matter (PM)

emissions from GGS1&2 units. PM emissions are comprised of both a coarse and fine

component. PMF is defined as having an aerodynamic diameter of less than or equal to 2.5

microns. PMC has an aerodynamic diameter greater than PM2.5, but less than or equal to 10

microns. For non-condensable PM emissions, control technologies generally control both PMF

and PMC emissions. Therefore, for purposes of the technology effectiveness comparison, the use

of the term PM will refer to both PMC and PMF. The visibility impact analysis and associated

dispersion modeling will take into account both the PMF and PMC emissions.

This section provides a review of the available PM control technologies and their

comparative effectiveness. Proposed BART determinations, discussed in Chapter 3, take into

account modeled visibility impacts, which are provided commonly for all pollutants in

Section 2.5.

PM emissions from coal-fired combustion result from the combination of the boiler firing

configuration, boiler operation, and coal properties. Uncontrolled PM emissions from coal-fired

boilers typically include ash from the combustion of the fuel as well as unburned carbon resulting

from incomplete combustion. However, in pulverized coal systems, combustion is nearly

complete and PM emissions are composed primarily of inorganic ash residues and contaminants

in the fuel.

Beyond implementation of good combustion practices, control of PM emissions is

achieved through the addition of equipment downstream of the combustion device. The GGS1&2
BART Analysis 40 March 2008

Gerald Gentleman Station Units 1 & 2

units already utilize reverse gas baghouses to control PM emissions, making any additional PM

control redundant.

2.5 Visibility Impacts Analysis

This BART analysis utilized the EPA-approved CALPUFF dispersion model to estimate

the visibility impairment of each control alternative at several Class I areas in units of deciviews

(dV). To compare the visibility impacts of various alternative control options on a common

basis, the pre-BART impacts and the impacts of each alternative control option were evaluated

against the 98

th

percentile visibility impact measured in dV. Thus, visibility impacts of the

control alternatives are evaluated in the same manner as for the BART-subject modeling analysis

(HDR 2006).

Direct PM emissions were generally responsible for well under 1 percent of the total

predicted impact, and therefore, no scenarios were considered to further control PM emissions.

Also, because GGS1&2 already have baghouses, they are considered to have the best available

PM control at this time.

The change in dV impacts (98

th

percentile) for a given decrease in emissions is not a

fixed amount, but depends instead on the starting point in emissions of NOx and other pollutants.

For example, if one reduced NOx by 50 percent, without any other additional controls applied for

any pollutant, the change in dV would be different than if one first applied SO2 reductions

associated with a SDA retrofit, and then applied a NOx reduction of 50 percent. Therefore, to

estimate the dV incremental changes for each control technology alternative, it is necessary to

place the alternatives in some subjective order.

For a given pollutant, it makes sense to order the control alternatives or scenarios in terms

of increasing complexity of the controls, and more importantly, in terms of increasing cost per

amount of visibility improvement. Given that one needs to consider control for multiple

pollutants, it was initially decided to order the scenarios starting first with the LNB/OFA for NOx

control, followed by a FGD system for SO2 control in conjunction with LNB/OFA, and finally

the addition of SCR to the LNB/OFA & FGD combination to further control NOx emissions. The

LNB/OFA system was applied first, because it is the most cost-effective control measure. The

SO2 control scenario was applied second, because preliminary modeling results indicated that it

would be the next most effective alternative on a $/dV basis. The SCR system is expected to

have the highest $/dV cost effectiveness, so it is last in order of presentation of the initial analysis

results. For these reasons, the scenarios subjected to dispersion modeling were initially

developed and ordered as shown below in the first four rows of data in Table 8. Subsequent to
BART Analysis 41 March 2008

Gerald Gentleman Station Units 1 & 2

the initial BART analysis, the NDEQ requested that NPPD also present visibility impact

modeling to assess the benefits of full SO2 control (dry or wet FGD) without any NOx control,

and full NOx control (LNB/OFA plus SCR) without any SO2 control. Therefore, two additional

emission scenarios have been analyzed, as defined in the last two rows of Table 8.

The stack parameters used to model each scenario are presented in Table 9. As with

Table 8, the last two rows of data in Table 9 represent the parameters modeled for the “SO2

control only” and “NOx control only” scenarios. Note that the stack gas velocity and temperature

are not varied for due to the NOx control scenarios, as it is expected that the NOx control options

would have little effect on stack gas characteristics. However, there would be a significant

change in stack parameters with the implementation of a dry or wet FGD system. Either type of

FGD system would add substantial water to the flue gas stream, thereby cooling it and slightly

increasing the mass flow, but decreasing the total volume flow rate to the atmosphere. The

exhaust gas temperatures and flow rates for dry and wet FGD are not significantly different. For

a wet FGD system, the cost analysis developed by Sargent & Lundy assumes that new stacks

would be needed. These stacks are expected to be essentially the same height as the existing

stacks. Therefore, the CALPUFF model inputs were assumed to be identical for dry and wet

FGD plume dispersion and visibility impact analysis.

Except for the variations in stack parameters and emission rates listed in Tables 8 and 9,

the dispersion modeling procedures and inputs used for each prospective BART control scenario

were identical to those procedures and inputs used in HDR’s BART-subject modeling analysis

(HDR 2006).

The results of the modeling were used in conjunction with the control costs presented in

Section 2.3.3.1 to predict the incremental improvements in visibility for each successive control

scenario. The CALPUFF model results for these scenarios are presented in Table 10. The worstcase overall visibility impact at any Class I area occurred for 2003 meteorology at the Badlands

Wilderness Area in South Dakota for the Baseline scenario and for each modeled control

scenario.
BART Analysis 42 March 2008

Gerald Gentleman Station Units 1 & 2

Table 8

Analyzed Emission Scenarios for GGS1&2

NOx Max 24-hr

Actual Emissions

SO2 Max 24-hr

Actual Emissions

PMF Max 24-hr

Actual Emissions

PMC Max 24-hr

Actual Emissions

Control

Technology

Option (lb/day) (lb/MMBtu) (lb/day) (lb/MMBt

u)

(lb/day) (lb/MMBtu) (lb/day) (lb/MMBtu)

Existing

Pre-BART

Control

165,716 0.455 272,795 0.749 6,688 0.018 1,170 0.003

LNB/OFA 83,769 0.23 272,795 0.749 6,688 0.018 1,170 0.003

LNB/OFA

+ FGD

83,769 0.23 54,632 0.15 6,688 0.018 1,170 0.003

LNB/OFA

+FGD+SCR

29,137 0.08 54,632 0.15 6,688 0.018 1,170 0.003

LNB/OFA

+SCR

29,137 0.08 272,795 0.749 6,688 0.018 1,170 0.003

FGD 165,716 0.455 54,632 0.15 6,688 0.018 1,170 0.003

Table 9

Modeled Stack Parameters for GGS1&2

Control

Technology

Option

Location

Easting

(utm)

Location

Northing

(utm)

Height of

Exit From

Ground (ft)

Base Elevation

of Ground

(ft)

Stack

Diam.

(ft)

Velocity

At Exit

(m/sec)

Exit Gas

Temperature

(°K)

Existing PreBART Control320,200 4,549,900 550 3,118.5 28 22.3 417.0

LNB/OFA 320,200 4,549,900 550 3,118.5 28 22.3 417.0

LNB/OFA

+ FGD

320,200 4,549,900 550 3,118.5 28 20.5 352.0

LNB/OFA

+FGD+SCR

320,200 4,549,900 550 3,118.5 28 20.5 352.0

LNB/OFA+SCR 320,200 4,549,900 550 3,118.5 28 22.3 417.0

FGD 320,200 4,549,900 550 3,118.5 28 20.5 352.0
BART Analysis 43 March 2008

Gerald Gentleman Station Units 1 & 2

Table 10

Visibility Modeling Results for GGS1&2

Control 2001 2002 2003

Technology

Option

Class I

Area

With

Greatest

Impact

Modeled

98

th

Percentile

Value

(deciview)

No. Of

Days

Exceeding

0.5

deciview

Modeled

98

th

Percentile

Value

(deciview)

No. Of

Days

Exceeding

0.5

deciview

Modeled

98

th

Percentile

Value

(deciview)

No. Of

Days

Exceeding

0.5

deciview

Pre-BART

Baseline

Badlands

(SD)

2.845 54 2.828 55 3.121 60

LNB/OFA Badlands

(SD)

2.224 49 2.162 52 2.419 54

LNB/OFA

+ FGD

Badlands

(SD)

1.107 25 1.275 21 1.537 27

LNB/OFA

+FGD+SCR

Badlands

(SD)

0.596 8 0.591 11 0.660 14

LNB/OFA+

SCR

Badlands

(SD)

1.732 44 1.728 41 1.879 48

FGD Badlands

(SD)

1.836 36 2.125 35 2.478 39
BART Analysis 44 March 2008

Gerald Gentleman Station Units 1 & 2

CHAPTER 3.0 – PROPOSED BART SELECTION

3.1 Incremental Visibility Improvement Comparison

Based on the analysis of available retrofit technologies provided in Chapter 2, substantial

NOx reductions can be achieved by installing modern low-NOx combustion technology on both

GGS1 and GGS2. Once optimized for maximizing NOx control, this technology should be able

to meet the EPA’s presumptive limit of 0.23 lb/MMBtu on a two-unit average basis. Cost

information used in conjunction with visibility modeling results indicates the implementation of

modern low NOx combustion technologies to meet the presumptive NOx limit would result in an

overall annualized cost of $2,960,000 with an incremental visibility impairment improvement

cost of $4,229,000/yr/dV. This is based on a modeled improvement of visibility impairment of

0.700 dV from the baseline value of 3.119 dV for the worst-case year of meteorology, and at the

worst-base Class I area, which is the Badlands of South Dakota. The final modeled visibility

impairment of GGS1&2, incorporating modern low NOx combustion technology to meet the

EPA’s presumptive limit for NOx, would be 2.419 dV on a 98

th

percentile basis. Further controls

beyond the level of modern low NOx combustion technology would come at a substantially

higher incremental cost per deciview (dV) and would not be justified under the five statutory

BART factors, which are also listed in EPA’s BART guidelines. Table 11 shows a comparison of

the estimated incremental cost per amount of visibility improvement, in units of $/yr/dV, for the

initial set combined NOx and SO2 control scenarios. The incremental costs and visibility

improvement of each additional control option are based on the change from the cost increase and

visibility improvement over the prior listed control option. Note that the annualized costs for the

last two control scenarios listed (SDA for SO2 control and SCR for NOx control) also include the

costs for the Lo-NOx/OFA option.
BART Analysis 45 March 2008

Gerald Gentleman Station Units 1 & 2

Table 11

Incremental Visibility Cost Comparison – Multipollutant Control

Visibility Impairment

B

Control

Technology

Option

A

Total Annual

Cost

($/yr)

Incremental

Annualized

Cost

($/yr)

98

th %-tile

(dV)

Days > 0.5

dV

Incremental

Visibility

Impairment

Improvemen

t

(dV)

Incremental

Impairment

Improvement

Cost ($/yr/dV)

Baseline 0 0 3.121 60 0 0

LNB/OFA $2,960,000 $2,960,000 2.419 54 0.702 $4,229,000

LNB/OFA

+FGD

C $114,410,000 $108,450,000 1.537 27 0.882 $122,959,000

LNB/OFA +

FGD + SCR

$168,701,000 $54,291,000 0.660 14 0.877 $61,905,000

A All control technology options also incorporate the implementation of modern low NOx combustion

technologies to reduce baseline NOx emissions.

B

For worst-case year of meteorology with respect to baseline and controlled scenario impacts.

C

FGD cost is for wet FGD system, which is only slightly lower than estimated for a dry FGD system.

As indicated in Table 11, the addition of FGD control to GGS 1&2, on top of the LowNOx/OFA controls on both units to meet the presumptive NOx limit would result in an additional

annual cost of $108,517,000, and a total cost over the 20-year amortization period of over $2.1

billion. This is shown in Table 11 as the incremental annualized cost. The resulting visibility

impairment improvement would be 1.113 dV based on the difference between the presumptive

NOx control (LNB/OFA) scenario, 2.419 dV, and the impact for Low-NOx +FGA scenario, of

1.306 dV. Because of the relatively small improvement in visibility (1.113 dV) and the high

incremental cost of adding FGD to GGS Units 1 & 2, the incremental impairment improvement

cost would be $122,959,000 per year per dV improvement. The estimated incremental visibility

improvement for this scenario is less than the minimum perceptible dV change, based on a study

published in the Journal of the Air & Waste Management Association (Henry 2002). The cited

article shows that perceptibility of a change in deciviews varies with background conditions, and

under optimum (pristine) conditions, can be as low as 1.5 to 2 dV. Thus, the estimated

improvement in visibility to be gained by installing FGD technology on GGS1&2 would not be

expected to be discernable, even under optimum viewing conditions. Expending more than $2.1

billion over 20 years is not a justified for a predicted visibility improvement that is not

discernable to human perception. Also, because of the conservative emissions estimates input to

the BART modeling analysis, the predicted impact improvements are based on very conservative
BART Analysis 46 March 2008

Gerald Gentleman Station Units 1 & 2

assumptions and therefore greatly overstate the actual visibility improvements. To put this

another way, actual visibility improvements resulting from the FGD control option would most

likely be much less than the modeled 1.113 dV, and will not be discernable.

The addition of more stringent NOx controls on top of the modern low NOx combustion

technology and FGD controls was also evaluated in the same incremental fashion. The addition

of SCR controls would result in an incremental visibility improvement cost of $61,905,000 per

year per dV. This cost is also extremely high and thus not justified based on the small, nondiscernable level of visibility improvement.

Table 11 shows the incremental visibility improvement costs for an integrated multipollutant (NOx and SO2) emission control progression. Subsequent to the initial analysis of this

progression, the NDEQ also requested an analysis of controls of each pollutant individually.

Therefore, NPPD analyzed the two additional scenarios described in Tables 8, 9, and 10, and

calculated the incremental visibility improvement costs on a single-pollutant basis. The results of

this analysis are presented in Tables 12 and 13 for NOx and SO2, respectively. These results show

that if controlling just NOx, the incremental visibility improvement cost for adding an SCR

system to the LNB/OFA control is over $100,000,000/yr/dV. Likewise, if one controls only SO2,

the incremental visibility improvement cost for adding a FGD (wet scrubber) system to the plant

is also very high at over $169,000,000/yr/dV. Thus, visibility improvement effectiveness is even

worse when only one pollutant is controlled. As with the multi-pollutant progression of controls,

the very poor cost effectiveness for adding any controls beyond the LNB/OFA system for NOx,

demonstrates that such additional controls are not justified.

Table 12

Incremental Visibility Cost Comparison – NOx Control

Visibility Impairment

A

Control Technology

Option

Total

Annual Cost

($/yr)

Incremental

Annualized

Cost

($/yr)

98

th %-tile

(dV)

Days > 0.5

dV

Incremental

Visibility

Impairment

Improvement

(dV)

Incremental

Impairment

Improvement

Cost

($/yr/dV)

Baseline 0 0 3.119 60 0 0

LNB/OFA 2,960,000 2,960,000 2.419 54 0.700 $4,229,000

LNB/OFA+SCR $57,251,000 $54,291,000 1.879 48 0.54 $100,539,000

A

For worst-case year of meteorology based on 98

th

percentile dV impact.
BART Analysis 47 March 2008

Gerald Gentleman Station Units 1 & 2

Table 13

Incremental Visibility Cost Comparison – SO2 Control

Visibility Impairment

A

Control Technology

Option

Total

Annual Cost

($/yr)

Incremental

Annualized

Cost

($/yr)

98

th %-tile

(dV)

Days > 0.5

dV

Incremental

Visibility

Impairment

Improvement

(dV)

Incremental

Impairment

Improvement

Cost

($/yr/dV)

Baseline 0 0 3.119 60 0 0

FGD $108,450,000 $108,450,000 2.478 39 0.641 $169,189,000

A

For worst-case year of meteorology based on 98

th

percentile dV impact.

3.2 Proposed BART

A review of BART proposals for similar coal-fired units in other states, and industrial

facilities in northern Minnesota, shows proposed visibility impairment values, after

implementation of BART controls, ranging from 0.675 dV to 4.0 dV on a 98

th

percentile basis for

the individual facilities. The associated proposed visibility impairment improvement costs are

generally less than $10,000,000 per year per dV improvement. Table 14 provides a summary of

BART proposals for other facilities, along with NPPD’s BART proposal for comparison. Table

14 shows only those facilities submitting BART analysis for which comparable information was

provided in the BART analysis. A number of the other BART analyses obtained for other states

did not provide the pre- and post-BART impact values and/or costs, and such facilities are not

listed in Table 14.

The Gerald Gentlemen Station BART analysis demonstrates that the installation and

optimization of modern low NOx combustion technology emission controls to meet the EPA’s

presumptive emission limit for NOx would result in visibility impacts above the 0.5 dV de

minimis threshold applicable for BART-exemption modeling. However, the addition of further

controls would come at a substantially higher incremental cost per deciview. Furthermore, in

comparison to other BART proposals made by facilities in the central and western US, a final

visibility impairment target of 2.419 dV utilizing modern low NOx combustion technology is

considered reasonable and within the same range of cost effectiveness for controls proposed by

other facilities. Installing additional controls on GGS would put the incremental impairment

improvement cost ($/yr/dV) at roughly an order of magnitude above the values proposed by the

other facilities submitting BART proposals.
BART Analysis 48 March 2008

Gerald Gentleman Station Units 1 & 2

Table 14

BART Proposals

Post-BART

Visibility Impairment

A

Facility

Size

(MW)

Pre-BART

98

th Percentile

Visibility

Impairment

A

(dv/yr)

98

th %-tile

(dV/yr)

Days > 0.5

dV

Incremental

Impairment

Improvement

Cost ($/yr/dv)

Xcel (Sherco, MN) 1,379 2.93 2.36 72 $4,000,000

GRE (Stanton, ND) 188 1.68 0.67 13 $10,100,000

GRE (Coal Creek, ND) 1,100 4.48 2.15 32 $6,990,000

Northshore Mining (MN) 75 1.30 1.30 58 $1,250,000

United Taconite (MN) NA 4.70 4.00 115 NA

Trigen Energy Co. (CO) NA 0.746 0.566 NA $8,300,000

CEMEX Lyons (CO) NA 1.02 0.963 NA NA

Entergy- Firing NG (Lake

Catherine, AR)

552 1.56 0.56 NA $400,000

Entergy- Firing FO (Lake

Catherine, AR)

552 3.44 3.03 NA $1,420,000

White Bluff (AR) 1700 5.040 1.646 NA $13,170,000

NPPD (Gerald Gentleman) 1,365 3.12 2.42 54 $4,229,000

A

For worst-case year of meteorology.

As stated in EPA’s BART Guidelines (40 C.F.R. 51, Appendix Y) the BART

presumptive limit for SO2 is only a provisionally suggested control level. EPA acknowledges

that the presumptive limits “may not be appropriate for all sources” and that “States have the

ability to consider the specific characteristics of the source at issue and to find that the

presumptive limits would not be appropriate for that source.”

6

Furthermore, EPA’s Appendix Y

guidelines specifically authorizes that an alternative SO2 control level, in lieu of the presumptive

SO2 limit, may be adopted if that “alternative control level is justified based on a careful

consideration of statutory factors.”

7 The NDEQ thus retains discretion not to adopt the

6

70 Fed. Reg. at 39,134 column 3.

7 Appendix Y to 40 C.F.R. Part 51, Section IV.E.4
BART Analysis 49 March 2008

Gerald Gentleman Station Units 1 & 2

presumptive limits if these control levels are determined not to be appropriate under the BART

five-part analysis, on a case-by-case basis for a given facility.

The preceding BART analysis supports NDEQ making such a determination for no

additional SO2 control at GGS1&2, given the very high estimated expenditure per unit of

modeled visibility improvement ($/yr/deciview, or $/yr/dV). Depending on which progression of

controls is analyzed, adding control of SO2 emissions at GGS would yield an estimated

incremental visibility improvement cost effectiveness of approximately $122,959,000 to

$169,189,000 per year per dV in order to reach and/or exceed the EPA’s presumptive SO2 limit.

This is not warranted based on a reasonable economic cost-effectiveness analysis. It also is outof-line with comparable BART cost-effective evaluations that have been prepared for other

electric generating facilities. The application of further controls would result in controlled

visibility impact levels far lower than levels proposed for other facilities in the central and

western US, and at far higher cost effectiveness. Cost effectiveness to implement the SO2

controls, in terms of visibility improvement ($/dV), would be approximately an order of

magnitude higher than the cost effectiveness calculated for proposed BART controls by other

utility and industrial emission sources as summarized in Table 14.

Based on the above information, NPPD proposes to set for GGS a BART limit for

controlling NOx based on the performance levels achievable by modern low NOx combustion

technology. As demonstrated in the above BART analyses, the emission reduction levels

achievable by these control technologies justify setting the BART limit for NOx at the EPA’s

presumptive limit of 0.23 lb/MMBtu, or equivalent emissions on a lb/hour basis. Compliance

with the proposed NOx limit would be measured on a 30-day rolling average basis, which is

consistent with the EPA Guidelines for BART Determinations, as codified at Appendix Y to 40

CFR Part 51. This limit is proposed as an average across both units, as allowed by EPA guidance

cited earlier in this document. NPPD proposes no additional controls for SO2 emissions based on

the high cost of controls and control effectiveness, and diminishing returns on visibility

improvement.

For PM, EPA has not published any presumptive emission limits. NPPD proposes to

retain the current opacity and PM limits applicable to GGS1&2. Modeling at current tested actual

emission rates, based on continued use of the existing baghouses at GGS, showed negligible

impacts of direct PM emissions on all Class I areas.

The EPA has provisionally suggested a presumptive limit for SO2 of 0.15 lb/MMBtu.

However, NPPD is not proposing to install additional SO2 control to GGS1&2 to meet the EPA

presumptive limit due to the high estimated incremental visibility impairment improvement costs.
BART Analysis 50 March 2008

Gerald Gentleman Station Units 1 & 2

In order to meet the EPA’s presumptive SO2 limit, estimated visibility impairment improvement

costs are $122,959,000 to $169,000,000 per year per dV (for controlling both GGS1 and GGS2),

depending on which control progression is analyzed. These values are far in excess of any

incremental improvement costs proposed by other utility or industrial facilities, and would not

result in a perceptible improvement in visibility, with an incremental change estimated at just

over one dV. Installing SO2 controls to meet the presumptive limit would also be very expensive,

resulting in over $2.1 billion in capital and O&M costs over the 20-year amortization period.

BART guidelines generally require power plants over 750 MW to meet specific control

levels of either 95 percent control or controls of 0.15 lb/MMBtu for SO2. However, if a State

determines that an alternative control level is justified based on a careful consideration of the

statutory factors, a different level of control may be appropriate (FR 7/5/05, pgs. 39144, 39155

and 39171). The statutory factors for consideration include:

• Available retrofit control options;

• Pollution control equipment in use at the source (which affects

availability of options and associated impacts);

• Costs of compliance with control options;

• Remaining useful life of the facility;

• Energy and non-environmental impacts of control options; and,

• Visibility impacts analysis.

In the case of SO2 controls for GGS, the most pertinent factor arguing against the

presumptive limit being applied is the last factor listed, which is the visibility impact analysis,

together with the cost of controls. For GGS1&2, the visibility impact analysis shows that the

“incremental impairment improvement cost,” which is a measure of cost effectiveness in

improving visibility, is extremely high for SO2 controls at GGS, in comparison to cost

effectiveness for controls proposed by other BART-subject sources. It does not make sense to

invest such a large amount in capital and O&M for relatively little, and not discernable,

improvement in visibility. Therefore, meeting the presumptive SO2 limit of 0.15 lb/MMBtu at

GGS is not justified according to the statutory factors.

As discussed earlier in this document, the BART analysis demonstrates that installation

of additional NOx emission controls beyond low-NOx burners and overfire air is not justified, due

to very high cost/benefit in terms of annual dollars spent per amount of modeled visibility

improvement, calculated in $/yr/dV. For the addition of SCR to the proposed LNB/OFA system,

the “incremental impairment improvement cost” is estimated at over $100,000,000. This is

clearly not justified in comparison to the incremental impairment improvement costs of proposed
BART Analysis 51 March 2008

Gerald Gentleman Station Units 1 & 2

BART controls in other states. To complete the BART standard-setting process, the EPA

Guidelines require the establishment of enforceable emissions limits for each unit at GGS. When

setting such enforceable BART limits, the EPA Guidelines authorize “sources to ‘average’

emissions across any set of BART-eligible emissions units within a fence line, so long as the

emissions reductions of each pollutant being controlled for BART would be equal to those

reductions that would be obtained by simply controlling each of the BART-eligible units that

constitute the BART-eligible source.” The averaging of emissions across GGS1 and GGS2 is

therefore authorized under the EPA Guidelines as one alternative method for demonstrating

compliance with the applicable BART limits set for each air pollutant at GGS. Pursuant to this

authority, NPPD requests the adoption of a NOx emissions averaging protocol for GGS1&2 and

that such protocol be included in all appropriate construction and operating permits for GGS. The

protocol will establish an alternative method for demonstrating compliance with the applicable

BART limits for each air pollutant through emissions averaging between GGS1 and GGS2. As

authorized in Section V of the EPA Guidelines, such protocols must set forth a method of

demonstrating that the combined emissions reductions achieved at the two GGS units for a

particular air pollutant is equal to or greater than the reductions that would be achieved by each

GGS unit individually complying with the applicable BART limit for the same pollutant.

A two-unit average BART emission limit is further justified because the dispersion

modeling is based on the maximum emissions of each pollutant from both units combined,

actually measured/calculated over 24-hours, in a 3-year baseline emissions period (2001-2003).

Thus, the modeled emissions based on the proposed low-NOx control technology, at a limit of

0.23 lb/MMBtu, represent both units emitting at the maximum combined load attained over this

period.

8

NPPD will develop and provide a proposed NOx emissions averaging protocol to NDEQ

later, subsequent to its BART construction permit application.

8

In issuing all necessary construction and operation permits to implement the BART controls at the GGS

units, the NDEQ should also include permit conditions that preserve the option for achieving BART

compliance through emissions trading or other flexible alternative measures that Nebraska may adopt in the

future pursuant to 40 C.F.R. §51.308(e)(2).
BART Analysis 52 March 2008

Gerald Gentleman Station Units 1 & 2

CHAPTER 4.0 – PSD Permit Application

4.1 Overview

As part of the BART analysis process, a facility must account for emissions increases of

other pollutants that may be caused as part of the process of controlling BART-subject pollutants.

A LNB/OFA system was recently installed on GGS1, and this installation was subjected to PSD

review and was issued a PSD permit in 2006. Thus, this PSD permit application addresses

installation of a LNB/OFA system on GGS2. The proposed LNB/OFA system is projected to

cause a significant emissions increase, over 100 tons/year, in emissions of carbon monoxide (CO)

from the facility. Other pollutants are either not expected to be affected by the GGS2 LNB/OFA

system, or to be affected only in negligible amounts.

The NDEQ requested that NPPD submit a PSD permit application along with its BART analysis,

to address the increased CO that is expected with the proposed Lox-NOx burner retrofit on

GGS2. While such a permit may expire prior to beginning of the retrofit, NDEQ has indicated in

verbal communication the potential for a longer term or extension to keep such a permit valid for

longer than the 18 month window typically allowed to begin construction. In consideration of

this, and recognizing that GGS2 is a very similar unit to GGS1, NPPD is electing to submit a

permit application addressing PSD permitting requirements at this time. However, this

application is subject to amendment if new information becomes available prior to LNB/OFA

procurement and installation that changes the expectation that only CO would trigger PSD

review, and that no other pollutants would experience a PSD significant increase in emissions due

to the project.

This Chapter provides the PSD permit application requirements, including application forms, a

Best Available Control Technology (BACT) analysis, a Dispersion Modeling Analysis, and an

Additional Impacts Analysis for the proposed GGS2 LNB/OFA retrofit. Because of the nearly

identical design and size between GGS1 and GGS2, NPPD is assuming that the estimated CO

emissions increase for GGS2 is equivalent, on a lb/mmBtu basis, to the estimated increase for the

GGS1 LNB/OFA project as documented in NPPD’s November 2005 PSD permit application.
BART Analysis 53 March 2008

Gerald Gentleman Station Units 1 & 2

4.2 Best Available Control Technology

The BACT analysis for the GGS2 proposed LNB/OFA retrofit is based on providing an update to

the analysis submitted by NPPD for GGS Unit 1 in November 2005, with permit issuance for that

project in August 2006. Given that GGS2 is almost identical in size and design to GGS1, NPPD

is proposing that the same CO limitation used for GGS1 be determined as BACT for GGS2. This

BACT limitation is based on the analysis provided below.

While there are no new CO control technologies that have become available since the 2006 PSD

permit issuance for GGS1, NPPD has investigated the possibility that some additional PSD

permits have been issued for comparable facilities, which could provide a basis for changing the

presumed GGS2 BACT limitation from the GGS1 permit requirements.

NPPD has conducted a review of the EPA’s BACT/LAER permit database to find information on

any new projects since the preparation of the BACT analysis for the November 2005 permit

application for GGS1. The RBLC database search was specified to select all permits issued since

January 1, 2005. Table 15 provides a listing of those BACT determinations for CO for boilers

similar to GGS2. These include only BACT limits for existing boilers (those being retrofitted,

usually for NOx control), of similar design (dry-bottom, wall-fired), and coal type

(subbituminous coal). Included in Table 15 is the GGS Unit 1 CO BACT limit.

Table 15

Recent CO BACT Limits for Similar Unit Retrofits

Facility Unit Size RBLC No. Permit Date CO BACT Limit

Detroit Edison

Monroe Power Plant

Boiler #1 7624

MMBtu/hr

MI-0379 03/03/2006 None – good combustion

practices

MidAmerican Energy

Co., Neal - South

Unit 4 boiler 6900

MMBtu/hr

IA-0080 09/28/2005 0.42 lb/MMBtu, calendar

day average

MidAmerican Energy

Co., Neal - North

Unit 2 Boiler 3081

MMBtu/hr

IA-0090

(draft)*

09/05/2007 1.63 lb/MMBtu, 3-hour

rolling average

NPPD Gerald

Gentleman Station

Unit 1 Boiler 7538

MMBtu/hr

N.A. 08/18/2006 0.50 lb/MMBtu, 30-day

rolling average

* Final permit data not entered in RBLC database at time of database search, but the final permit was

downloaded from the Iowa DNR permit database.
BART Analysis 54 March 2008

Gerald Gentleman Station Units 1 & 2

The information summarized in Table 15 supports the proposed CO limitation of 0.50 lb/MMBtu,

30-day rolling average, for the GGS2 proposed LNB/OFA retrofit system. The proposed limit is

well within the range of other recent CO limits. The only limit in Table 15 that is lower than the

proposed GGS2 limit is for the MidAmerican Neal-South Unit 4 boiler, which has a sophisticated

“neural net” system to optimize combustion conditions. Because the GGS2 design is very similar

to GGS1, and both units utilize the same Powder River Basin coal, there is no basis for making

the GGS2 limit any more or any less stringent than the GGS1 limit.

4.3 Air Quality Impact (Dispersion Modeling) Analysis

The air quality impact analysis of CO emissions was performed using the EPA SCREEN3

dispersion model. Inputs to SCREEN3 included stack parameters based on the current GGS2

stack design and operation. The emission rate input to SCREEN3 was equivalent to 3769 lb/hr,

which is based on the maximum heat input rate of 7538 MMBtu/hr and an emission factor of 0.5

lb/MMBtu.

The SCREEN3 model was executed for a maximum (100%) load condition, because the GGS1

modeling analysis demonstrated that 100% load produced higher impacts than partial load

conditions. While there is no complex terrain (above stack height), in the area, there is rolling

terrain that reaches as much as 45 meters above stack base elevation within a few kilometers of

the facility. Therefore, the “simple terrain” option was used in SCREEN3, and the maximum

terrain elevation rise in the area at 45 meters was input to the model for the simple terrain

analysis. This is a very conservative procedure in that the model assumes that the terrain rise of

45 meters above stack base occurs at every receptor distance input to the model. Thus, impacts

would tend to be overestimated due to this simulation.

The SCREEN3 model output is provided below.
BART Analysis 55 March 2008

Gerald Gentleman Station Units 1 & 2

*** SCREEN3 MODEL RUN *** 11/05/07

*** VERSION DATED 96043 *** 08:25:53

NPPD GGS Unit 2 Boiler, CO Screening, 100% Load, 0.5 lb/MMBtu @ 7538 MMBtu/hr

SIMPLE TERRAIN INPUTS:

SOURCE TYPE = POINT

EMISSION RATE (G/S) = 474.894

STACK HEIGHT (M) = 167.6000

STK INSIDE DIAM (M) = 8.5345

STK EXIT VELOCITY (M/S)= 22.3000

STK GAS EXIT TEMP (K) = 417.0000

AMBIENT AIR TEMP (K) = 293.0000

RECEPTOR HEIGHT (M) = .0000

URBAN/RURAL OPTION = RURAL

BUILDING HEIGHT (M) = 81.6900

MIN HORIZ BLDG DIM (M) = 82.0300

MAX HORIZ BLDG DIM (M) = 180.2600

THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED.

THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED.

BUOY. FLUX = 1184.093 M**4/S**3; MOM. FLUX = 6362.642 M**4/S**2.

*** FULL METEOROLOGY ***

**********************************

*** SCREEN AUTOMATED DISTANCES ***

**********************************

*** TERRAIN HEIGHT OF 45. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES

***

DIST CONC U10M USTK MIX HT PLUME SIGMA SIGMA

(M) (UG/M**3) STAB (M/S) (M/S) (M) HT (M) Y (M) Z (M) DWASH

------- ---------- ---- ----- ----- ------ ------ ------ ------ -----

100. .1392E-12 5 1.0 2.7 10000.0 349.39 39.33 39.01 NO

200. .1823E-02 5 1.0 2.7 10000.0 349.39 62.75 61.98 NO

300. 312.6 6 4.0 18.9 10000.0 157.89 16.07 61.94 HS

400. 313.7 6 4.0 18.9 10000.0 166.39 20.20 68.98 HS

500. 315.6 6 4.0 18.9 10000.0 174.21 24.16 76.00 HS

600. 315.6 6 4.0 18.9 10000.0 181.52 28.00 82.99 HS

700. 313.2 6 4.0 18.9 10000.0 188.43 31.73 89.97 HS

800. 308.7 6 4.0 18.9 10000.0 195.02 35.39 96.92 HS

900. 278.6 6 4.0 18.9 10000.0 201.34 38.97 100.92 HS

1000. 229.3 6 4.0 18.9 10000.0 207.43 42.50 101.36 HS

1100. 190.8 6 4.0 18.9 10000.0 213.32 45.97 101.81 HS

1200. 172.1 6 4.0 18.9 10000.0 215.69 48.84 102.01 HS

1300. 174.2 1 2.5 3.0 1011.7 1010.67 323.91 813.14 NO

1400. 174.1 1 2.5 3.0 1011.7 1010.67 343.88 946.25 NO

1500. 168.0 1 2.5 3.0 1011.7 1010.67 363.59 1090.64 NO

1600. 160.3 1 2.5 3.0 1011.7 1010.67 383.08 1246.38 NO

1700. 152.8 1 2.5 3.0 1011.7 1010.67 402.35 1413.56 NO

1800. 145.9 1 2.5 3.0 1011.7 1010.67 421.43 1592.22 NO

1900. 139.7 1 2.5 3.0 1011.7 1010.67 440.32 1782.45 NO

2000. 134.0 1 2.5 3.0 1011.7 1010.67 459.03 1984.29 NO

2100. 129.8 1 2.5 3.0 1011.7 1010.67 473.90 2197.02 NO

2200. 126.0 1 2.5 3.0 1011.7 1010.67 488.01 2421.47 NO

2300. 122.5 1 2.5 3.0 1011.7 1010.67 502.18 2657.86 NO

2400. 119.1 1 2.5 3.0 1011.7 1010.67 516.40 2906.21 NO

2500. 115.9 1 2.5 3.0 1011.7 1010.67 530.67 3166.57 NO

2600. 112.8 1 2.5 3.0 1011.7 1010.67 544.97 3438.98 NO

2700. 109.9 1 2.5 3.0 1011.7 1010.67 559.29 3723.46 NO

2800. 107.2 1 2.5 3.0 1011.7 1010.67 573.63 4020.06 NO

2900. 104.6 1 2.5 3.0 1011.7 1010.67 587.99 4328.83 NO

3000. 102.1 1 2.5 3.0 1011.7 1010.67 602.35 4649.80 NO

3500. 91.21 1 2.5 3.0 1011.7 1010.67 674.18 5000.00 NO
BART Analysis 56 March 2008

Gerald Gentleman Station Units 1 & 2

4000. 82.46 1 2.5 3.0 1011.7 1010.67 745.77 5000.00 NO

4500. 75.27 1 2.5 3.0 1011.7 1010.67 816.93 5000.00 NO

5000. 70.90 2 2.5 3.0 1011.7 1010.67 689.78 687.43 NO

MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 100. M:

550. 315.9 6 4.0 18.9 10000.0 177.99 26.13 79.57 HS

DWASH= MEANS NO CALC MADE (CONC = 0.0)

DWASH=NO MEANS NO BUILDING DOWNWASH USED

DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED

DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED

DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB

********************************************

* SUMMARY OF TERRAIN HEIGHTS ENTERED FOR *

* SIMPLE ELEVATED TERRAIN PROCEDURE *

********************************************

TERRAIN DISTANCE RANGE (M)

HT (M) MINIMUM MAXIMUM

------- -------- --------

45. 100. 5000.

****************************************

*** REGULATORY (Default) ***

PERFORMING CAVITY CALCULATIONS

WITH ORIGINAL SCREEN CAVITY MODEL

(BRODE, 1988)

****************************************

*** CAVITY CALCULATION - 1 *** *** CAVITY CALCULATION - 2 ***

CONC (UG/M**3) = .0000 CONC (UG/M**3) = .0000

CRIT WS @10M (M/S) = 99.99 CRIT WS @10M (M/S) = 99.99

CRIT WS @ HS (M/S) = 99.99 CRIT WS @ HS (M/S) = 99.99

DILUTION WS (M/S) = 99.99 DILUTION WS (M/S) = 99.99

CAVITY HT (M) = 117.12 CAVITY HT (M) = 89.11

CAVITY LENGTH (M) = 227.81 CAVITY LENGTH (M) = 114.75

ALONGWIND DIM (M) = 82.03 ALONGWIND DIM (M) = 180.26

CAVITY CONC NOT CALCULATED FOR CRIT WS > 20.0 M/S. CONC SET = 0.0

****************************************

END OF CAVITY CALCULATIONS

****************************************

***************************************

*** SUMMARY OF SCREEN MODEL RESULTS ***

***************************************

CALCULATION MAX CONC DIST TO TERRAIN

PROCEDURE (UG/M**3) MAX (M) HT (M)

-------------- ----------- ------- -------

SIMPLE TERRAIN 315.9 550. 45.

***************************************************

** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS **

***************************************************

As shown in the SCREEN3 output above, the maximum modeled 1-hour impact was 315.9

μg/m3. To obtain an 8-hour maximum concentration estimate, this value was multiplied by the

1-hour to 8-hour averaging time adjustment factor of 0.7 provided in Screening Procedures for
BART Analysis 57 March 2008

Gerald Gentleman Station Units 1 & 2

Estimating the Air Quality Impact of Stationary Sources, Revised, EPA Publication No.

EPA-454/R-92-019.

The results of the screening dispersion modeling analysis are presented in Table 16 in comparison

to National Ambient Air Quality Standards (NAAQS), significant impact levels (SILs) and the

PSD preconstruction monitoring threshold. The maximum 1-hour impact predicted by SCREEN3

was at a distance of 550 meters downwind of the GGS2 stack, as shown above. The maximum 1-

hour and 8-hour impacts are below SILs, and therefore, a refined analysis of all sources at the

facility and in the region is not needed for this project. Also, the maximum 8-hour impact is

below the Preconstruction Monitoring Threshold found in 40 CFR 52.21, and therefore, the

project qualifies for an exemption from CO preconstruction ambient air monitoring.

Table 16

Maximum Modeled CO Concentrations in Comparison to Regulatory Thresholds

Averaging

Period

Maximum

Modeled

Concentration

(μg/m

3

)

Significant

Impact Level

(μg/m

3

)

Preconstruction

Monitoring

Threshold (μg/m

3

)

NAAQS

(μg/m

3

)

1-hour 315.9 2000 N.A. 40,000

8-hour 221.1 500 575 10,000

4.4 Additional Impacts Analysis

The additional impact analysis must be conducted in accordance with the requirements of 40 CFR

21.21(o) to evaluate a project’s air pollution impacts on soils, vegetation, and visibility. CO is the

only pollutant expected to trigger PSD requirements for this project. CO impacts as shown in

Table 2 are far below the NAAQS levels set to protect human health and welfare, which includes

the values of crops, soils or materials. Therefore, no adverse effects are anticipated with respect

to these values.

Compliance with NAAQS is not necessarily an indication of no adverse impact with respect to

visibility, because some pollutants such as SO2 and NOx can produce fine particulate matter that

may cause visible plumes, or which may contribute to regional haze. Because CO is an invisible

gas and has negligible effects on atmospheric chemistry of particulate matter formation, the

proposed project is not expected to have adverse impacts on visibility. In fact, because the
BART Analysis 58 March 2008

Gerald Gentleman Station Units 1 & 2

project will substantially reduce NOx emissions from the facility, it is expected to have a

beneficial effect in tending to reduce regional haze.

4.5 Summary

The PSD permit application information above, plus the forms in Appendix D of this report,

provide a complete PSD permit application for the proposed GGS2 LNB/OFA retrofit project.

This information demonstrates that the proposed project will maintain compliance with ambient

air quality standards and will meet BACT requirements for CO.
BART Analysis 59 March 2008

Gerald Gentleman Station Units 1 & 2

References

HDR, 2006. Clean Air Act Regional Haze Program for Best Available Retrofit Technology

(BART), Dispersion Modeling Analysis to Determine BART-Subject Facilities. Prepared for

Nebraska Public Power District, Omaha Public Power District, City of Grand Island, and

Hastings Utilities. Submitted to Nebraska Department of Environmental Quality, November

2006.

Henry, Ronald C., 2002. Just-Noticeable Differences in Atmospheric Haze, Journal of the Air &

Waste Management Association, Volume 52, pp. 1238-1243. October 2002.

Schnelle, Karl B., Jr. and Charles A. Brown, 2002. Air Pollution Control Technology Handbook,

CRC Press.

US Department of Energy (DOE), 2004. Project Facts – NOx Control for Utility Boiler OTR

Compliance. Office of Fossil Energy, National Energy Technology Laboratory. November 2004.

US Environmental Protection Agency (EPA), 1998. EPA Publication AP42, Chapter 1,

Bituminous and Subbituminous Coal Combustion, (9/98).

US Environmental Protection Agency (EPA), 2002. EPA Air Pollution Control Cost Manual,

Sixth Edition, Publication Number EPA 452/B-02-001. January 2002.

US Environmental Protection Agency (EPA), 2005. Regional Haze Regulations and Guidelines

for Best Available Retrofit Technology (BART) Determinations; Final Rule; published in the

Federal Register on July 6, 2005.

US Environmental Protection Agency (EPA), 2006. Regional Haze Regulations; Revisions to

Provisions Governing Alternative to Source-Specific Best Available Retrofit Technology

(BART) Determinations; Final Rule; published in the Federal Register on October 13, 2006.
Appendix A

Dry FGD and ID Fan & Auxiliary Power

Conceptual Design Costs
Appendix B

Wet FGD and ID Fan & Auxiliary Power

Conceptual Design Costs
Appendix C

SCR and ID Fan & Auxiliary Power

Conceptual Design Costs
Appendix D

NDEQ Permit Application Forms