Best Available Retrofit

Technology (BART) Analysis

for

Unit 1

Nebraska City Station

Nebraska City, 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

August 2007
BART Analysis i August 2007

Nebraska City Station Unit 1

EXECUTIVE SUMMARY

This report and the accompanying air emission construction permit application were

prepared for Omaha Public Power District (OPPD), Nebraska City Station, Unit 1 (NC1),

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 NC1 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, OPPD has prepared for NC1 the following 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. The BART emission levels selected

for NC1 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.

This report concludes that BART for NC1 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.

This study evaluated the economic impacts and visibility benefits of installing sulfur

dioxide (SO2) emission controls to meet the EPA’s presumptive BART limit of 0.15 lb/MMBtu.

The presumptive limits apply to plants with over 750 MW of affected capacity. While the

presumptive limits are therefore not applicable to NC1, EPA has stated that many units at

facilities below the presumptive limit threshold of 750 MW may be able to meet the presumptive

limits. OPPD could, from a technically feasibility standpoint, install retrofit technology on NC1

to meet an emission rate of 0.15 lb/MMBtu. However, given the very high estimated expenditure

per unit of modeled visibility improvement ($/year/deciview, or $/yr/dV), it is not reasonable to

install such controls. The cost/benefit ratio for meeting the presumptive SO2 limit for NC1 is

estimated at approximately $90 million/yr/dV, which is an order of magnitude greater

expenditure per dV than other facilities are proposing to spend for BART controls. Thus, this

analysis demonstrates that SO2 controls are not justified for NC1.
BART Analysis ii August 2007

Nebraska City Station Unit 1

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

matter limits applicable to NC1. Modeling at current tested actual emission rates showed

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

excellent PM control.

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

submission for BART purposes, currently due to EPA in December 2007, OPPD would have five

years after the date of EPA SIP approval to complete the installation and operation of emission

controls to meet the established BART emissions levels.
BART Analysis iii August 2007

Nebraska City Station Unit 1

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..............................................................................................4

CHAPTER 2.0 – BART ANALYSIS................................................................................. 5

2.1 Overview..................................................................................................................5

2.1.1 NC1 Power Generation Process.................................................................. 5

2.1.2 Applicable Pollutants.................................................................................. 6

2.1.3 Project Economic Evaluation Criteria ........................................................ 7

2.2 BART for Sulfur Dioxide (SO2) ..............................................................................8

2.2.1 Identification of SO2 Control Technologies............................................... 8

2.2.2 SO2 Control Technology Effectiveness.................................................... 12

2.2.3 Evaluation of Impacts............................................................................... 13

2.3 BART for Nitrogen Oxides (NOx) ........................................................................14

2.3.1 Identification of NOx Control Technologies............................................ 15

2.3.2 NOx Control Technology Effectiveness................................................... 19

2.3.3 Evaluation of Impacts............................................................................... 19

2.4 BART for Particulate Matter (PM)........................................................................22

2.5 Visibility Impacts Analysis....................................................................................23

CHAPTER 3.0 – PROPOSED BART SELECTION ....................................................... 26

3.1 Incremental Visibility Improvement Comparison .................................................26

3.2 Proposed BART.....................................................................................................27

List of Tables

Table 1 Economic Criteria .................................................................................................. 7

Table 2 SO2 Control Technology Effectiveness............................................................... 12

Table 3 SO2 Cost of Compliance ...................................................................................... 13

Table 4 NOx Control Technology Effectiveness .............................................................. 19

Table 5 NOx Cost of Compliance ..................................................................................... 20

Table 6 Analyzed Emission Scenarios for NC1 ............................................................... 24

Table 7 Modeled Stack Parameters for NC1 .................................................................... 24

Table 8 Visibility Modeling Results for NC1................................................................... 25

Table 9 Incremental Visibility Improvement Cost Comparison....................................... 26

Table 10 BART Proposals................................................................................................ 28

List of Figures

Figure 1 Furnace Temperatures........................................................................................ 18

Figure 2 Least Cost Curve ................................................................................................ 21

List of Appendices

Appendix A ............................... Control Equipment Cost Estimate Data

Appendix B............................NDEQ Permit Application Forms
BART Analysis 1 August 2007

Nebraska City Station Unit 1

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 NC1 using a protocol approved by the

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

impacts of NC1 would potentially exceed the established 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, OPPD has

prepared for NC1 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 NC1 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.

The following sections of the report comprise the BART determination analysis for NC1

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

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”).
BART Analysis 2 August 2007

Nebraska City Station Unit 1

1.2 Source Description

Owned and operated by Omaha Public Power District (OPPD), Nebraska City Station

(NCS) is located on Highway 75 approximately 5 miles to the southeast of the city of Nebraska

City, Otoe County. NCS currently consists of one existing nominal 650 megawatt (MW, net)

coal-fired electric generating unit (NC1) and one recently permitted nominal 660 MW (net) coalfired electric generating unit (NC2) that is currently under construction. Ancillary equipment at

NCS consists of coal unloading from rail cars, coal storage and handling, and coal preparation

equipment. The existing NC1 unit burns low-sulfur subbituminous coal from the Powder River

Basin (PRB) of Wyoming and PRB coal will also be used as fuel for the new NC2 unit.

The NC1 boiler utilizes an electrostatic precipitator (ESP) as its emissions control device

for PM and overfire air for nitrogen oxide (NOx) emissions control. Various existing coal and ash

handling processes are controlled using bag filters.

1.3 BART Analysis Methodology

Federal regulations at 40 CFR Part 51.301 define Best Available Retrofit Technology

(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 established based on the

maximum degree of pollutant reduction, determined on a case-by-case basis, considering

technical, economic, energy, and environmental factors, remaining useful life, and 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
BART Analysis 3 August 2007

Nebraska City Station Unit 1

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

Best Available Control Technology (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. 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). 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.

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

has established for SO2 and NOx, even though these limits do not apply to NC1. In

accordance with EPA’s Appendix Y guidelines, OPPD is recommending that the

presumptive SO2 limit not be adopted for NC1 based on a careful consideration of the

statutory factors. Instead, OPPD is proposing that the existing SO2 limits be retained

given the extremely high costs of installing available flue gas desulfurization
BART Analysis 4 August 2007

Nebraska City Station Unit 1

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). OPPD is proposing that the presumptive limit for NOx, which is 0.23

lb/MMBtu, be applied to NC1. 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.
BART Analysis 5 August 2007

Nebraska City Station Unit 1

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 NC1 unit. Additionally,

some fundamental economic information used in the BART analysis is summarized.

2.1.1 NC1 Power Generation Process

NC1 consists of several components: the fuel preparation system, the air supply system,

burners, a furnace, the heat transfer system, and existing pollution control equipment in the form

of an electrostatic precipitator (ESP). 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

mixture of a steam and liquid state. This mixture enters the drum at the top of the boiler where

the water is separated from the steam and returned to the bottom of the boiler again. The steam is

sent to the convective heat transfer portion of the boiler. This convective 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 ESP. Bottom ash drops into a water trough at

the bottom of the boiler, is removed from the water by a drag conveyor system, and deposited in

trucks for transfer to the on-site ash disposal area.
BART Analysis 6 August 2007

Nebraska City Station Unit 1

Currently, NC1 uses western subbituminous coal from the Powder River Basin (PRB).

Fuel for day-to-day operation of the unit is delivered by railcar. An on-site coal storage area is

used for periods of delivery interruption.

2.1.2 Applicable Pollutants

The BART analysis for NC1 addresses criteria pollutant emissions of NOx, SO2, and PM.

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

2

. 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.

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%

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.

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 (40 CFR 60, Appendix A). Condensable PM is the portion of PM that is

2 EPA Publication AP42, Chapter 1, Bituminous and Subbituminous Coal Combustion, (9/98).
BART Analysis 7 August 2007

Nebraska City Station Unit 1

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

ambient temperatures.

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 5.0

Capital Cost Recovery Factor, CCRF 0.0802

O&M Cost Escalation, percent 3.5

O&M Levelization Factor, OMLF 1.414

Auxiliary Electric Power Cost, $/kW-hr 0.03

Auxiliary Electric Demand Cost, $/kW 460

Outage Cost, $/MW-hr 30

Ash Disposal Costs, $/ton 9

Operating Labor Rate, $/hr 50

Lime Cost, $/ton delivered 125

Ammonia Cost, $/ton delivered 300

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

sources. At the present time, it is very difficult to get detailed cost information from vendors,

who are generally very busy working on actual retrofit projects, many in response to EPA’s Clean

Air Interstate Rule (CAIR) and other rules. Limited vendor data obtained from various vendors

in 2003 (see Appendix A) were scaled up based on escalated material and labor costs, which have

risen dramatically in the last few years due to extremely tight material and labor availability. In

general, the cost estimates were made following guidance provided in the EPA Air Pollution

Control Cost Manual, January 2002 (EPA 2002). The EPA control cost manual data was

supplemented with the 2003 vendor supplied quotations when available and with general
BART Analysis 8 August 2007

Nebraska City Station Unit 1

engineering estimates. However, because it is difficult to accurately predict future demand and

commodity related costs, the BART cost estimates are considered to be conservatively low. For

example, over the past several years prices on SO2 control equipment have increased significantly

due to both commodity prices and high demand for electric utility equipment. Detailed cost

estimates and support data are provided in Appendix A.

2.2 BART for Sulfur Dioxide (SO2)

The objective of this analysis is to determine BART for SO2 emissions from NC1. 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. 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 of 90 to 95%, depending on the amount of sulfur in the coal. For relatively high

sulfur coals, removal efficiencies can exceed 95%, while for lower sulfur coals (such as PRB), the

achievable removal efficiency is typically less than 95%.
BART Analysis 9 August 2007

Nebraska City Station Unit 1

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) at efficiencies greater than 99 percent. 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 technically feasibility with application to largescale coal-fired electrical generating units, such as the NC1 unit, 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.

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, lime 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 or absorber where it is sprayed with a water

slurry which is approximately 10 percent lime or limestone. Sodium alkali solutions can also be
BART Analysis 10 August 2007

Nebraska City Station Unit 1

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. 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% 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.

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 NCS, OPPD 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. In addition, without an opportunity to reuse this

byproduct, OPPD would incur additional costs, compared to many other plants, for land filling

the gypsum.
BART Analysis 11 August 2007

Nebraska City Station Unit 1

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.

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

reagent quantity required to remove the SO2

3

.

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.

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

2002.
BART Analysis 12 August 2007

Nebraska City Station Unit 1

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 NC1 unit. Table 2 provides a summary of the SO2 control technology effectiveness.

Table 2

SO2 Control Technology Effectiveness

Identified

Control Technology

Emission Rate

(lb/MMBtu)

Potential

Emissions

(tpy)

A

Tons SO2

Removed

(tpy)

NC1 Baseline 0.815 24,191 NA

Wet FGD 0.15 4,452 19,739

Dry FGD 0.15 4,452 19,739

A Based on maximum actual 24-hour emissions, maximum heat input of 6776.8 MMBtu/hr and a

100% capacity factor. Note that the potential tons/year value for the Baseline is an

overestimate, as it is calculated using the maximum 24-hour emissions realized over the 3-year

baseline period, and a 100% capacity factor. Thus, the tons/yr removed values are also

conservatively high.

As indicated in Table 2, it is anticipated that the same level of SO2 control can be

achieved by the use of either Dry or Wet FGD. This assumption is based on observations of FGD

control in use on similar emission sources. It must be emphasized that the tons/year potential

emission level in Table 2 is 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 would be far 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 NC1) 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.

Although both Dry and Wet FGD systems are technically feasible for SO2 control, the

BART analysis for NC1 focuses on the evaluation of Dry FGD. The equivalency in anticipated

SO2 emission rates using Dry or Wet FGD technology makes economics the primary selection

factor. Typically, Dry FGD technology has lower capital and operating costs than Wet FGD and

will result in a more cost-effective and conservative BART approach. Furthermore, use of Wet
BART Analysis 13 August 2007

Nebraska City Station Unit 1

FGD to control SO2 emissions from NC1 would result in both higher energy penalties to facility

operations and the generation of more waste byproducts than would Dry FGD.

Because of several uncertainties, such as final detailed design and vendor commitments

incorporating site-specific complexities related to equipment sizing, location, etc., it is possible

that detailed cost estimates for Dry FGD could be higher than those presented here, and could

exceed those of Wet FGD. However, for the time being, this BART analysis is based on Dry

FGD, assuming that the known spacing issues at the plant do not dramatically affect the total cost

for SO2 control. If the spacing issues drive Dry FGD cost up significantly, total costeffectiveness could be high enough that Wet FGD could be the least costly FGD alternative.

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 NC1 unit. 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

Table 3 summarizes the capital and annual operating costs associated with retrofitting a Dry

FGD (spray dryer absorber) system to the NC1 unit. Detailed cost estimates indicating sources for

each cost category have been included in Appendix A. Because a fabric filter would need to be

included as part of a FGD system, the cost of a fabric filter (baghouse) is included in this analysis.

Table 3

SO2 Cost of Compliance

Technology

Option

Description

Dry FGD

Emission Rate (lb/MMBtu) 0.15

Emission Reduction (tpy) 19,739

Capital Cost ($) 201,660,000

Annualized Capital Cost ($) 16,180,000

Annual Operating Cost ($) 18,540,000

Total Annualized Cost ($) 34,720,000

Cost Effectiveness $1,759/ton
BART Analysis 14 August 2007

Nebraska City Station Unit 1

2.2.3.2 Energy Impact

Use of FGD to control SO2 emissions from the NC1 unit would result in energy penalties

to 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 would consume approximately 1% (6 MW) of the generating capacity. This is

not a trivial amount of generating capacity, being enough energy to supply the electrical needs of

approximately 6,000 homes. 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

The primary detrimental non-air quality environmental impact of an FGD system is the

creation of a solid waste byproduct from the spent reagent (Wet FGD results in a wastewater

stream). The solid waste that is produced can be land filled or possibly used as an agricultural

soil supplement. As discussed in Section 2.2.1.1, a portion of the solid waste, in the form of

gypsum, can be used by local wallboard manufacturers. However, there are no such

manufacturers or significant local gypsum demand near NCS. Therefore, all of the wet FGD

solid waste would need to be land filled.

Another non-air environmental impact is the use of additional land for scrubber water

disposal and settling ponds.

2.2.3.4 Remaining Useful Life

The remaining useful life of NC1 is greater than 20 years under the current OPPD energy

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

control technology cost 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 OPPD 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 NCS. 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.

2.3 BART for Nitrogen Oxides (NOx)

The objective of this analysis is to determine BART for NOx emissions from NC1. 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,
BART Analysis 15 August 2007

Nebraska City Station Unit 1

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), which have not been demonstrated on large coal-fired boilers, are not

addressed in detail in this analysis.

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

results in small levels 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% and therefore requires more storage capacity than anhydrous NH3. Anhydrous NH3 is

nearly 100% 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% concentration) is used to form

NH3 on demand for injection into the flue gas. A specifically designed duct and decomposition
BART Analysis 16 August 2007

Nebraska City Station Unit 1

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 ureabased SCR systems to utility boilers is a relatively new practice that is still under development.

Several different SCR system configurations have been used on utility boilers. In a highdust SCR system, the reactor is located downstream of the economizer and upstream of the air

heater, FGD system, and particulate control device. Low-dust SCR systems locate the reactor

downstream of a particulate control device where the flue gas is relatively dust-free. Tail-end

SCR systems locate the reactor downstream from all air pollution control equipment where most

flue gas constituents detrimental to the SCR catalyst have been removed. However, tail-end SCR

systems can require reheating of the flue gas to minimize condensation, leading to corrosion

problems.

SCR is a proven 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

occurs within a combustion unit, 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 very high uncontrolled emissions)

achieve NOx reduction efficiencies of up to 75%. However, technically feasible applications of

SNCR on pulverized coal utility boilers may be expected to provide 20% to 50% 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% NOx reductions from a baseline value of 0.26 lb/MMBtu. At 60%

load, the system achieved a 23.5% NOx reduction. The DOE Fact Sheet (DOE, 2004) for this

research project states “The full-load conditions of utility boilers are very challenging
BART Analysis 17 August 2007

Nebraska City Station Unit 1

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.

NC1 experiences 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.

Data collected for NC1 by the OPPD, 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.

Obviously, for SNCR to work at all, 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.

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

OPPD currently sells much of its fly ash from NC1, the installation of SNCR would likely cause

cessation of most or all of its ash sales. Current users of the ash would need to seek other
BART Analysis 18 August 2007

Nebraska City Station Unit 1

sources, resulting in additional transportation and fuel costs, and perhaps additional land would

be required for aggregate mining. In addition, OPPD would need to utilize 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 NC1 is

unproven and problematic at best, as described above. SNCR effectiveness under these

circumstances would be marginal, if any, and because installation of SCNR in the convective

passages is not a proven implementation method on large PRB-fired boilers, SNCR is considered

to be technically infeasible for NC1.

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

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
BART Analysis 19 August 2007

Nebraska City Station Unit 1

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.

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 NC1. Table 4 provides a summary of the NOx control technology effectiveness.

Table 4

NOx Control Technology Effectiveness

Identified

Control Technology

Emission Rate

(lb/MMBtu)

Potential

Emissions

(tpy)

A

Tons NOx

Removed

(tpy)

NC1 Baseline 0.573 17,008 NA

LNB/OFA 0.23 6,827 10,181

LNB/OFA + SCR 0.08 2,375 14,633

A Based on 24-hour maximum actual emissions, a maximum heat input of 6776.8 MMBtu/hr and

100% capacity factor. Note that the potential tons/year value for the Baseline is an

overestimate, as it is calculated using the maximum 24-hour emissions realized over the 3-year

baseline period, and a 100% capacity factor. Thus, the tons/yr removed values are also

conservatively high.

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 without the need for add on control.

NC1 already has overfire air, which provides a modest level of NOx control. The BART

options for further control of NOx emissions from the NC1 have been evaluated in a staged

approach. The first option would be the installation and optimization of modern low NOx

combustion technology. The second option involves the application of add-on controls,

specifically SCR, in addition to the low NOx combustion controlled source.

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 NC1. 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.
BART Analysis 20 August 2007

Nebraska City Station Unit 1

2.3.3.1 Cost of Compliance

Table 5 summarizes the capital and annual operating costs associated with retrofitting

NOx control systems to NC1. Detailed costs estimates indicating sources for each cost category

have been included in Appendix A.

Table 5

NOx Cost of Compliance

Description Technology Options

LNB/OFA

+ SCR LNB/OFA

Emission Rate (lb/MMBtu) 0.08 0.23

Emission Reduction (tpy) 14,633 10,181

Capital Cost ($) 265,455,000 21,050,000

Annualized Capital Cost ($) 21,300,000 1,690,000

Annual Operating Cost ($) 16,910,000 0

Total Annualized Cost ($) 38,210,000 1,690,000

Total Cost Effectiveness $2,633/ton $166/ton

Incremental Cost Effectiveness $8,275/ton $166/ton

A

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 NC1 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.
BART Analysis 21 August 2007

Nebraska City Station Unit 1

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. The application of an SCR system would consume power and reduce efficiency, thereby

decreasing energy available to consumers. 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

There are no non-air quality related impacts associated with combustion controls.

However, SCR requires some form of ammonia (NH3) source for operation. This can be stored in

liquid, solid or gas, and processed on site for use. Depending on quantities stored, risk

management requirements may apply. Also, production of ammonia primarily uses a finite

resource (natural gas), so use of ammonia could have long term consequences on fossil fuel

supplies. In addition, SCR may cause enough ammonia accumulation in ash to make the ash not

usable for cement and other beneficial uses. Currently, the plant sells much of its ash for such

beneficial uses. If the ash is contaminated by ammonia, the necessary land filling would have

environmental impacts in the form of additional land use.

2.3.3.4 Remaining Useful Life

The remaining useful life of NC1 is greater than 20 years under the current OPPD energy

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

control technology cost under the current regulatory framework. However, future CO2 control

requirements are possible in the near term and those control requirements create considerable

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)

T

otal A

n

n

u

aliz

e

d

C

o

st ($1,0

0

0)

LNB/OFA

+ SCR

LNB/OFA
BART Analysis 22 August 2007

Nebraska City Station Unit 1

planning uncertainty that weigh against OPPD 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 NCS. 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 NC1. PM emissions are comprised of both a coarse and fine component. Fine

particulate matter (PMF) is defined as having an aerodynamic diameter of less than or equal to

2.5 microns. Coarse particulate matter (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 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. NC1 utilizes

an electrostatic precipitator to control PM emissions. Slightly greater control could be obtained

by installing a fabric filter, but because direct PM emissions have a negligible modeled impact on

Class I area visibility, a fabric filter for controlling PM alone is not considered in this analysis.

However, a fabric filter would be needed if FGD is installed for SO2 control, and thus, is included

in the evaluation of potential SO2 control.
BART Analysis 23 August 2007

Nebraska City Station Unit 1

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).

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%, 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/FF retrofit, and then applied a NOx reduction of 50%. 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 decided to order the scenarios starting first with the LNB/OFA for NOx control,

followed by an SDA system for SO2 control in conjunction with LNB/OFA, and finally the

addition of SCR to the LNB/OFA/SDA 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 would have the

highest $/dV value (least cost-effective), so it is last in order of presentation.

Direct PM emissions were generally responsible for well under 1% of the total predicted

impact, and therefore, no scenarios were considered to further control PM emissions. Based on

the above, the scenarios subjected to dispersion modeling for the BART technology comparison

were developed and ordered as shown below in Table 6.

The stack parameters used to model each scenario are presented in Table 7. Note that the

stack gas velocity and temperature are the same for all of the NOx control scenarios, as it is

expected that the NOx control options would have little effect on stack gas characteristics. The

one control option that would significantly change stack parameters is the implementation of the
BART Analysis 24 August 2007

Nebraska City Station Unit 1

SDA. The SDA system would add substantial water to the flue gas stream, thereby cooling it and

increasing the mass flow, but decreasing the total volume flow rate to the atmosphere.

Except for the variations in stack parameters and emission rates listed in Tables 6 and 7,

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 8. The worst-case overall visibility impact at any Class I area

occurred for 2001 meteorology at the Hercules Glades Wilderness Area in Missouri for

the Baseline scenario and for each modeled control scenario. For 2003 meteorology, the

worst-case 98

th

percentile impacts occurred at the Wichita Mountains National Wildlife

Refuge in Oklahoma for each control scenario. However, for each scenario, the 2001 98

th

percentile impacts at Hercules Glades were greater than the 2003 98

th

percentile impacts

at Wichita Mountains.

Table 6

Analyzed Emission Scenarios for NC1

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/MMBtu) (lb/day) (lb/MMBtu) (lb/day) (lb/MMBtu)

Existing

Pre-BART

Control

93,195 0.573 132,518 0.815 4,004 0.025 2,262 0.014

LNB/OFA 37,408 0.23 132,518 0.815 4,004 0.025 2,262 0.014

LNB/OFA

+ SDA

37,408 0.23 24,396 0.15 2,623 0.016 408 0.0025

LNB/OFA

+SDA+SCR

13,011 0.08 24,396 0.15 2,623 0.016 408 0.0025

Table 7

Modeled Stack Parameters for NC1

Control

Technology

Option

Location

Easting

Zone 15

(utm)

Location

Northing

Zone 15

(utm)

Height

Of Exit

From

Ground

(ft)

Base

Elevation

Of

Ground

(ft)

Stack

Diameter

(ft)

Velocity

At Exit

(m/sec)

Exit Gas

Temperature

(°K)

Existing

Pre-BART

265,400 4,500,200 696 925 23.7 18.47 467
BART Analysis 25 August 2007

Nebraska City Station Unit 1

Control

Technology

Option

Location

Easting

Zone 15

(utm)

Location

Northing

Zone 15

(utm)

Height

Of Exit

From

Ground

(ft)

Base

Elevation

Of

Ground

(ft)

Stack

Diameter

(ft)

Velocity

At Exit

(m/sec)

Exit Gas

Temperature

(°K)

Control

LNB/OFA 265,400 4,500,200 696 925 23.7 18.47 467

LNB/OFA

+ SDA

265,400 4,500,200 696 925 23.7 24.08 352

LNB/OFA

+SDA+SCR

265,400 4,500,200 696 925 23.7 24.08 352

Table 8

Visibility Modeling Results for NC1

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

Hercules

Glades

(MO)

0.933 14 0.556 9 0.686

(WMO)

A

10

(WMO)

A

LNB/OFA Hercules

Glades

(MO)

0.621 9 0.358 2 0.524

(WMO)

A

9

(WMO)

A

LNB/OFA

+ SDA

Hercules

Glades

(MO)

0.233 0 0.167 1 0.174

(WMO)

A

3

(WMO)

A

LNB/OFA

+SDA+SCR

Hercules

Glades

(MO)

0.147 0 0.089 0 0.117

(WMO)

A

0

A While overall maximum impacts are predicted at Hercules Glades, the maximum impacts for 2003

Meteorology were predicted at Wichita Mountains (WMO), Oklahoma.
BART Analysis 26 August 2007

Nebraska City Station Unit 1

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 NC1.

Once optimized for maximizing NOx control, this technology should be able to meet the EPA’s

presumptive limit of 0.23 lb/MMBtu. Cost information used in conjunction with visibility

modeling results indicates that the implementation of modern low NOx combustion technology to

meet the presumptive NOx limit would result in an overall annualized cost of $1,690,000 with an

incremental visibility impairment improvement cost of $5,434,000/dV. This is based on a

modeled improvement of visibility impairment of 0.311 dV from the baseline value of 0.933 dV.

The modeled visibility impairment of NC1, incorporating modern low NOx combustion

technology to meet the presumptive limit for NOx, would be 0.621 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 9

shows a comparison of the estimated incremental cost per amount of visibility improvement, in

units of $/dV. 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 LNB/OFA option.

Table 9

Incremental Visibility Improvement Cost Comparison

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 0.933 14 0 0

LNB/OFA 1,690,000 1,690,000 0.621 9 0.311 $5,434,000

LNB/OFA+SDA/FF 36,410,000 34,720,000 0.233 0 0.388 $89,485,000

LNB+SDA/FF+SCR 74,620,000 38,210,000 0.147 0 0.086 $444,302,000

A

For worst-case year of meteorology.
BART Analysis 27 August 2007

Nebraska City Station Unit 1

As indicated in Table 9, the addition of SDA/FF control to NC1, on top of the LowNOx/OFA controls to meet the presumptive NOx limit, would result in an additional annual cost

of $34,720,000, and a total cost over the 20-year amortization period of nearly $700 million. This

is shown in Table 9 as the incremental annualized cost. The resulting visibility impairment

improvement would be 0.388 dV based on the difference between the presumptive NOx control

(LNB/OFA) scenario, 0.621 dV, and the impact for LNB/OFA+SDA/FF scenario, of 0.233 dV.

Because of the relatively small improvement of visibility impairment (0.388) and the high

incremental cost of adding SDA/FF to NC1, the incremental impairment improvement cost would

be nearly $90,000,000 per year per dV of visibility improvement. The estimated incremental

visibility improvement for this scenario is well below 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 SDA/FF technology on NC1 would

not be expected to be discernable, even under optimum viewing conditions. Expending $700

million over 20 years is not a reasonable price to pay for a predicted improvement in visibility

that is far below the threshold of human perception. Also, because of the conservative emissions

estimates input to the BART modeling analysis, the predicted impact improvements are expected

to be conservatively high. Thus, actual visibility improvement for SDA/FF installation and

operation, on a 98

th

percentile basis, is expected to be much less than the modeled 0.388 dV.

The addition of more stringent NOx controls on top of the modern low NOx combustion

technology and SDA/FF controls was also evaluated in the same incremental fashion. The

addition of SCR controls would result in an extremely high incremental impairment improvement

cost of $444,302,000 per year per dV.

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 10 provides a summary of

BART proposals for other facilities, along with OPPD’s BART proposal for comparison.

The Nebraska City Unit 1 BART analysis demonstrates that the installation and

optimization of modern low NOx combustion technology emission controls to meet the EPA’s
BART Analysis 28 August 2007

Nebraska City Station Unit 1

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 0.621 dV utilizing modern low NOx combustion technology is

considered reasonable and within the same range of cost effectiveness for controls proposed by

other facilities. Also, the total of nine days per year over 0.5 dV is below all of the other BART

proposals that reported this value.

Table 10

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

OPPD (Nebraska City Unit 1) 650 0.933 0.621 9 $5,434,000

A

For worst-case year of meteorology.

Adding control of SO2 emissions at NCS would yield an estimated incremental

impairment improvement cost effectiveness of approximately $90,000,000 per year per dV in

order to reach and/or exceed the EPA’s presumptive SO2 limit. This is not warranted, based on a

comparison of data for other 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
BART Analysis 29 August 2007

Nebraska City Station Unit 1

controls, in terms of visibility improvement ($/dV), would be approximately an order of

magnitude higher than the cost effectiveness for proposed BART controls calculated by other

utility and industrial emission sources as summarized in Table 10.

Based on the above information, OPPD proposes to set for NCS 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. 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 in Appendix Y to 40 CFR Part 51. OPPD 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. OPPD proposes to

retain the current opacity and PM limits applicable to NC1. Modeling at current tested actual

emission rates, based on continued use of the existing ESP on NC1, showed negligible impacts of

direct PM emissions on all Class I areas.

Based on the above, it is clear that BART for NC1 should be established as installation

and optimization of low-NOx burners together with overfire air to minimize NOx formation in the

combustion process, to meet a NOx limitation of 0.23 lb/MMBtu. For BART purposes, OPPD

proposes to retain the current facility PM and SO2 emission limits. In accordance with EPA

regulatory guidelines, the 0.23 lb/MMBtu NOx limit would be applied on a 30-day rolling average

basis. OPPD proposes to exclude hours of startup, shutdown, or malfunction from computation

of the 30-day rolling average, and proposes to include in the 30-day average only those days

which have at least 12 hours of valid operational emissions data.
BART Analysis 30 August 2007

Nebraska City Station Unit 1

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.
BART Analysis 31 August 2007

Nebraska City Station Unit 1

Appendix A

Cost Information
Appendix B

NDEQ Permit Application Forms