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FACT SHEET

BART & PSD Analysis 

For the 

Omaha Public Power District 

Nebraska City Station Unit #1 

Located at 

7264 L Road 

Nebraska City, Otoe County, Nebraska 68410 

February 26, 2009
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Table of Contents 

Executive Summary.................................................................................................................................................................. 3

1.0 Introduction and Purpose ........................................................................................................................................... 3

1.1 Nebraska Regional Haze Program ............................................................................................................................. 3

1.2 Source Description and Permitting Background ........................................................................................................ 4

1.3 Nebraska City Station BART Eligibility Analysis ..................................................................................................... 5

1.4 BART Analysis Methodology.................................................................................................................................... 6

1.5 Consideration of Presumptive BART Limitations...................................................................................................... 7

2.0 BART Analysis for Particulate Matter (both fine and coarse fractions)..................................................................... 7

2.1 Particulate Matter (PM) Formation............................................................................................................................ 7

2.2 BART for PM ............................................................................................................................................................ 8

3.0 BART Analysis for SO2 ............................................................................................................................................. 9

3.1 SO2 Formation............................................................................................................................................................ 9

3.2 Identification of SO2 Control Technologies and Technical Feasibility ...................................................................... 9

3.2.1 Sulfur Removal from Fuel ................................................................................................................................ 9

3.2.2 Flue Gas Desulfurization (FGD)....................................................................................................................... 9

3.3 Ranking of Technologically Feasible SO2 Controls based on Effectiveness............................................................ 10

3.4 Evaluation of Effective SO2 Controls....................................................................................................................... 11

3.5 Visibility Impacts ..................................................................................................................................................... 11

4.0 BART Analysis for NOx........................................................................................................................................... 13

4.1 NOx Formation......................................................................................................................................................... 13

4.2 Identification of NOx Control Technologies and Technical Feasibility ................................................................... 13

4.2.1 Combustion Controls...................................................................................................................................... 13

4.2.2 Post Combustion Control Technologies ......................................................................................................... 13

4.3 Ranking of Technologically Feasible NOx Controls based on Effectiveness ........................................................... 14

4.4 Evaluation of Effective NOx Controls...................................................................................................................... 14

4.5 Visibility Impacts ..................................................................................................................................................... 15

4.6 BART Conclusion for SO2 and NOx ........................................................................................................................ 15

5.0 Prevention of Significant Deterioration (PSD)......................................................................................................... 16

5.1 Summary .................................................................................................................................................................. 16

5.2 Best Available Control Technology (BACT) Analysis Methodology...................................................................... 17

5.3 BACT Analysis for Carbon Monoxide (CO) ........................................................................................................... 17

5.4 Ranking of Technologically Feasible CO Controls based on Effectiveness............................................................. 19

5.5 BACT for CO........................................................................................................................................................... 19

6.0 Air Dispersion Modeling Analysis........................................................................................................................... 19

6.1 Model Information ................................................................................................................................................... 19

6.1.1 Facility Location and Site Description ........................................................................................................... 19

6.1.2 Model Selection.............................................................................................................................................. 20

6.1.3 Source Parameters .......................................................................................................................................... 20

6.2 Preliminary Modeling Analysis................................................................................................................................ 20

6.3 Additional Impacts Analysis .................................................................................................................................... 21

6.3.1 Pollutant Effects on Soil and Vegetation ........................................................................................................ 21

7.0 Type and Quantity of Air Contaminant Emissions Anticipated ............................................................................... 21

8.0 Applicable Requirements, Variances or Alternatives to Required Standards: ......................................................... 22

8.1 Nebraska State Construction Permit Requirements.................................................................................................. 22

8.2 New Source Performance Standards (NSPS) ........................................................................................................... 22

8.3 Particulate Matter Emissions.................................................................................................................................... 23

8.4 Sulfur Compound Emissions.................................................................................................................................... 23

8.5 Acid Rain ................................................................................................................................................................. 24

8.6 Hazardous Air Pollutants ......................................................................................................................................... 24

8.7 Visibility Protection ................................................................................................................................................. 24

9.0 Discussion of Specific Permit Conditions................................................................................................................ 24
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Executive Summary 

The Nebraska Department of Environmental Quality (NDEQ) identified the Omaha Public Power District 

(OPPD) Nebraska City Station Unit #1 as a Best Available Retrofit Technology (BART) eligible and subject 

source under the U.S. EPA Regional Haze Program. In August 2007, OPPD submitted a BART analysis and 

permit application to NDEQ. Furthermore, since controls were going to result in the increase in other 

pollutants above the Prevention of Significant Deterioration (PSD) thresholds, a PSD application was 

submitted. This fact sheet is a summary of the NDEQ’s evaluation and proposed decision on both BART and 

Best Available Control Technology (BACT). 

This analysis concludes that BART should be the installation and optimization of low-NOx burners with overfired air technology as necessary to meet a limit of 0.23 lb NOx/MMBtu on a 30-day rolling average. This 

analysis also concludes that BART is existing control equipment along with existing limits for particulates and 

that no additional SO2 controls are warranted due to the low benefit to cost ratio. 

1.0 Introduction and Purpose 

The Clean Air Act of 1990 (Title I, Sections 169A and 169B) declared it a national goal to prevent any future, 

and to remedy any existing, impairment of visibility in mandatory Class I Federal areas which impairment 

results from manmade air pollution. In 1999, the United States Environmental Protection Agency (EPA) issued 

regulations for the protection of visibility in Class I National Parks and Wilderness Areas. Revisions to the 

regional haze rules were promulgated on July 6, 2005 and October 13, 2006. These regulations require states to 

establish goals for improving visibility by developing long-term strategies for reducing emissions of air 

pollutants that cause visibility impairment. These pollutants include particulate matter (PM, both fine and 

coarse fractions), sulfur dioxide (SO2), nitrogen oxides (NOx), volatile organic compounds (VOC), and 

ammonia (NH3). The overall goal of the regional haze regulations is to achieve natural background visibility 

conditions in all Class I areas by the year 2064. 

1.1 Nebraska Regional Haze Program 

Nebraska does not have any Class I National Parks or Scenic areas. However, in accordance with the Regional 

Haze rule, Nebraska has an obligation to address visibility protection through the application of Best Available 

Retrofit Technology (BART) on BART subject sources and reasonable further progress if Nebraska source 

emissions are identified in another State’s Regional Haze State Implementation Plan (SIP). Additionally, 

Nebraska belongs to and participates in a regional planning organization, CENRAP. Nebraska participated in a 

central-states consultation process for Missouri and Oklahoma.1 No states have identified a need for reasonable 

further progress reductions from Nebraska sources at this time. Therefore, the application of BART is the 

primary element of the Nebraska Regional Haze program. In the future, additional requirements on sources 

through the application of reasonable further progress may be required for Class I areas to achieve natural 

background conditions by 2064. 

On February 16, 2008, Title 129-Nebraska Air Quality Regulations, of the Nebraska Administrative Code, were 

revised in order to incorporate numerous changes, including the establishment of Chapter 43: Visibility 

Protection. This chapter incorporated portions of the federal Regional Haze Rule, including 40 CFR 51.301 and 

40 CFR 51 Appendix Y by reference. It also requires owners or operators of stationary sources subject to 

BART to prepare and submit a BART determination in accordance with the Regional Haze Rule. The rules also 

require the issuance of a construction permit to the source in accordance with Title 129, Chapter 17. Since the 

 

1

 See Missouri’s regional haze plan at http://www.dnr.mo.gov/env/apcp/sips.htm. Missouri named Missouri, Arkansas, 

Kentucky, Illinois, Indiana, Ohio, Oklahoma, Tennessee and Texas as contributing to visibility impairment. Missouri’s 

analysis indicates that reductions from these states are sufficient to meet reasonable progress goals. Oklahoma’s plan is still 

under development, but their consultation plan which includes expected reductions may be found at 

http://www.deq.state.ok.us/aQDnew/RulesAndPlanning/Regional_Haze/index.htm. 
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application of BART is required, the BART decisions (i.e. the BART permits) will explicitly be included in 

Nebraska’s Regional Haze SIP. 

On August 8, 2007, the Department received a BART analysis for Omaha Public Power District (OPPD) 

Nebraska City Station (NCS), Unit 1. Additional information was received on December 4, 2007. The purpose 

of this permitting action is to require emission controls in accordance with NDEQ and BART regulations and to 

permit the increase in other pollutant emissions that are expected to result from the installation of the BART 

controls. To make the BART emission limitations enforceable, the NDEQ incorporated the BART 

requirements in a construction permit. The NDEQ will be evaluating the following visibility impairing 

pollutants for purposes of BART: PM (both fine and coarse fractions), SO2, and NOx. 

1.2 Source Description and Permitting Background 

In accordance with state law, Nebraska’s utility structure is currently 100% consumer-owned, also known as 

“public power.” OPPD is one of the largest publicly owned electric utilities in the United States, serving more 

than 340,000 customers in 13 southeast Nebraska counties. It was organized as a political subdivision of the 

State of Nebraska in 1946. Policies and rates are set by an eight-member Board of Directors elected by the 

people in the areas served. The map below shows OPPD’s service area: 

OPPD owns and operates Nebraska City Station (NCS) which is located approximately five (5) miles southeast 

of Nebraska City, Nebraska. The station currently consists of one existing nominal 650 megawatt (MW, net) 

pulverized coal-fired, dry-bottom boiler referred to as Unit 1. Unit 1 combusts sub-bituminous coal with a 

typical heat content of 8,400 British thermal units per pound (Btu/lb). Its Standard Industrial Classification 

(SIC) code is 4911 and North American Industry Classification System (NAICS) code is 221112 for fossil 

fueled electric generators. 

On February 23, 2004 the Department received a PSD construction permit application for “NCS Unit 2” which 

consisted of a new 6,478 million British thermal units per hour (MMBtu/hr)(660 MW, net) pulverized coalfired dry-bottom boiler, a new 125 MMBtu/hr auxiliary boiler (Aux Boiler 2), and other associated equipment. 

A PSD construction permit was issued for Unit 2 on March 9, 2005. 
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On October 26, 2006, the NDEQ issued a permit revision which superseded Condition XIV.(B)(1), Table 2 to 

increase the limit of the auxiliary boiler to the fuel equivalent of 876 hours per year until NCS Unit 2 comes online and becomes operational (expected to occur in spring 2009). 

On September 26, 2007 a permit revision request for the permits issued for NCS Unit 2 was received by the 

Department. A revised PSD construction permit that superseded the permits issued on March 9, 2005 and 

October 26, 2006 was issued for NCS Unit 2 on March 6, 2008. 

NCS is operating under a Class I operating permit (OP) issued on April 28, 2004 and a Phase II Acid Rain 

permit effective March 9, 2007. 

1.3 Nebraska City Station BART Eligibility Analysis 

Nebraska City Station Unit 1 was determined to be subject to BART using the criteria outlined in the Clean Air 

Act and the Regional Haze Rules. The applicability criteria for determining if a unit is eligible for being 

required to install BART controls are: 

1) The facility in which the unit is located contains emissions units in one or more of 26 source categories. 

One of the listed source categories is fossil-fuel fired steam electric plants of more than 250 million British 

thermal units per hour (MMBtu/hr) heat input. 

 Unit 1 is a fossil-fuel fired steam electric plant with a capacity of approximately 6,835 

MMBtu/hr. 

2) BART eligible units were in existence on August 7, 1977 and began operating after August 7, 1962. 

 OPPD began construction of Unit 1 in 1975 and brought it on-line in May 1979. 

3) The total potential emissions of visibility impairing pollutant(s) summed across all units that meet the date 

criteria in item 2 is greater than or equal to 250 tons/year. 

 Unit 1 has potential emissions of greater than 250 tons/year for: particulate matter (coarse 

and fine), SO2, and NOx (all visibility impairing pollutants). 

Since all of the three criteria presented above were met, the Unit 1 is considered to be BART eligible. In order to 

determine if Unit 1 is subject to BART requirements, it must be demonstrated that emissions are anticipated to 

cause or contribute to visibility impairment in one or more Class I areas. This was done by conducting long range 

transport air dispersion modeling using CALPUFF. If emissions from the BART eligible units at a source will 

impair visibility in any Class I area more than 0.5 deciviews (a measurement of visibility impairment based on 

extinction of light), then the unit becomes subject to BART. 

OPPD conducted air dispersion modeling in accordance with a modeling protocol approved by the Department. 

The modeling was based on maximum 24-hour emissions for each pollutant, as summarized in the table below. 

Note that the annual emissions listed are values equivalent to the 24-hour maximum emissions, and do not 

necessarily represent “potential to emit” values. 

Table 1: NCS Unit 1 Emissions Used for Modeling (Baseline Scenario) 

PM – Fine PM – Coarse SO2 NOx

Lb/day Tons/year Lb/day Tons/year Lb/day Tons/year Lb/day Tons/year

4,004 731.23 2,262 413.10 132,518 24,201.10 93,195 17,019.74 

The modeling protocol and the modeling results may be obtained from the Department’s website: 

www.deq.state.ne.us, under the “Regional Haze Program” under the “Focus on Air” link. The refined CALPUFF 

modeling analysis concluded that the emissions from NCS Unit 1, before requiring BART controls, cause or 

contribute to visibility impairment (NCS contributions exceed 0.5 deciview) on eight or more days (98th

percentile) in a year, at one or more Class I areas, in one or more of the three years (2001-2003) of meteorology 

evaluated. (See Table 2.) Therefore, NCS Unit 1 was determined to be subject to BART requirements. 
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Table 2: NCS Unit 1 Visibility Impact (Baseline Scenario) 

2001 2002 2003 

Days 

> 0.5 dV 

98th

Percentile 

dV 

Days 

> 0.5 dV 

98th

Percentile 

dV 

Days 

> 0.5 dV 

98th

Percentile 

dV 

Badlands (SD) 7 0.332 2 0.126 2 0.225 

Great Sand Dunes (CO) 0 0.009 0 0.019 0 0.036 

Hercules Glades (MO) 14 0.933 9 0.556 6 0.473 

Mingo (MO) 4 0.374 5 0.371 2 0.305 

Rocky Mountain (CO) 0 0.01 0 0.043 2 0.047 

Wichita Mountains (OK) 4 0.306 5 0.381 10 0.686 

Wind Cave (SD) 4 0.095 1 0.050 1 0.111 

1.4 BART Analysis Methodology 

BART is defined as “...an emissions limitation based on the degree of reduction achievable through the 

application of the best system of continuous emission reduction of each pollutant which is emitted by an 

existing stationary source. 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 non-air 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” (40 CFR Part 51.301). 

On July 6, 2005, the US EPA issued guidelines on conducting a BART determination, which are contained in 

Appendix Y of 40 CFR Part 51. States must follow these guidelines in making BART determinations on a 

source-by-source basis for 750 megawatt (MW) and larger power plants but are not required to use the process 

in the guidelines when making BART determinations for other types of BART sources, including those with a 

total plant capacity less than 750 MW. When an early draft of the BART proposal was shared with the Federal 

Land Managers, a question was raised as to the status of the total plant capacity at NCS. At issue was whether 

NCS Unit 2 should now be considered part of the total plant capacity at NCS for purposes of determining 

BART applicability. Since the CAA and the BART regulations did not speak to the specific issue of a source 

becoming a 750 MW facility after the BART rules were promulgated, the NDEQ raised the question with the 

US EPA and received a response on November 10, 2008. The response read “we believe that it is a reasonable 

interpretation to assume that if the plant is greater than 750 megawatts at the time the BART determination is 

made by the state (i.e. at the time the state places the BART determination on public notice) then any unit at the 

plant greater then [sic] 200 megawatts is subject to presumptive BART.” US EPA Region 7’s response is still 

vague in that it does not speak to whether it is sufficient to have commenced or begun actual construction on 

Unit 2, or whether Unit 2 must be operational. The NDEQ’s evaluation of the US EPA’s intent is that the 

plant’s commercial operational capacity must be 750 MW or more. Since Unit 2 is not yet commercially 

operational, NDEQ has determined that NCS, for purposes of BART has a plant capacity of less than 750 MW. 

Therefore, it is not mandatory for NDEQ to follow 40 CFR 51 Appendix Y for federal purposes. 

However, Nebraska Title 129, Chapter 43, Section 002 states that “the owner or operator [of the facility subject 

to BART] shall prepare the BART determination in accordance with Appendix Y of 40 CFR 51, as directed by 

the Director.” Therefore we have utilized 40 CFR 51 Appendix Y when making this BART determination. 

A BART analysis is comprised of the following basic steps: 

Step 1: Identify all retrofit control technologies: 

All control technologies for similar processes, as well as Best Available Control Technology (BACT) and 

Lowest Achievable Emission Rate (LAER) technologies must be considered. Control technologies should 

include pollution prevention, use of add-on controls, and combinations of the two. The owner/operator is not 
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expected to purchase or construct a process or control device that has not already been demonstrated in 

practice. 

Step 2: Eliminate technically infeasible options: 

Technologies demonstrated to be technically infeasible based on physical, chemical, and engineering principles 

are excluded from further consideration. Physical modifications needed to resolve technical obstacles do not, 

by themselves, provide justification to eliminate a technology. 

Step 3: Rank remaining technologies by control effectiveness: 

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

lowest expected emission reduction. The ranking also includes expected emission rate, control effectiveness, 

energy impacts, environmental impacts (including toxic and hazardous air emissions), economic impacts, and 

visibility impacts. 

Step 4: Evaluate most effective controls and document results: 

The technology ranking is evaluated and case-by-case consideration is given to costs of compliance, energy 

impacts, non-air quality and other environmental impacts, and remaining useful life of the unit. 

Step 5: Evaluate Visibility Impacts: 

Modeling analyses are performed on the pre- and post-control emissions to determine actual impact on 

visibility. The NDEQ has evaluated visibility improvement balanced with the cost of compliance in 

determining the best, most appropriate option for BART as allowed under Appendix Y. This was done through 

a cost per deciview of visibility improvement factor, which is similar to the cost per ton of pollutant removed 

from the atmosphere that is used in the BACT process. 

1.5 Consideration of Presumptive BART Limitations 

Appendix Y also gives consideration to presumptive limitations for SO2 and NOx established by EPA. When 

discussing the presumptive sulfur dioxide limits for utility boilers, Appendix Y states “You [the state] must 

require 750 MW power plants to meet specific control levels for SO2 of either 95 percent control or 0.15 

lbs/MMBtu, for each EGU [Electric Generating Unit] greater than 200 MW that is currently uncontrolled 

unless you determine that an alternative control level is justified based on a careful consideration of the 

statutory factors...For a currently uncontrolled EGU greater than 200 MW in size, but located at a power plant 

smaller than 750 MW in size, such controls are generally cost-effective and could be used in your BART 

determination considering the five factors...” EPA has provided guidance to NDEQ indicating that the five 

factors must be evaluated in all cases. 

It is clear in 40 CFR 51 Appendix Y that States are afforded the discretion to set limits different than the 

presumptive levels for NOx and SO2, if careful consideration is given to the statutory factors. The NDEQ has 

given careful consideration to the statutory factors and the presumptive levels, even though Unit 1 is not located 

at a 750 MW power plant. 

 

2.0 BART Analysis for Particulate Matter (both fine and coarse fractions) 

The objective of this analysis is to determine BART for PM emissions from the NCS Unit 1. 

2.1 Particulate Matter (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 noncombustibles in coal as well as unburned carbon resulting from incomplete combustion. When combusting 
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pulverized coal, PM emissions are primarily composed on 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, which is typically measured on an EPA Method 5 filter (40 CFR Part 60, 

Appendix A). 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 when cooled to ambient temperatures. 

For purposes of BART, coarse PM (PMC) and fine PM (PMF) are analyzed in the visibility impact modeling. 

PMF is defined as having an aerodynamic diameter of less than or equal to 2.5 microns (PM2.5). PMC has an 

aerodynamic diameter greater than PM2.5 but less than or equal to 10 microns. 

2.2 BART for PM 

Step 1: Identify all retrofit control technologies: 

Control of PM emissions can be achieved by application of good combustion practices (i.e. complete 

combustion) or by treatment of the flue gas after combustion. NCS Unit 1 currently utilizes an electrostatic 

precipitator to control PM emissions. Add-on control technology would include a fabric filter (baghouse). 

Step 2: Eliminate technically infeasible options: 

No technologies can be eliminated as being technically infeasible. 

Step 3 through 5: Rank remaining technologies by control effectiveness; Evaluate most effective controls and 

document results; and Evaluate Visibility Impacts: 

Step 5, Evaluate Visibility Impacts was done first to see at what level PM was contributing to visibility. If PM 

was found to be a significant portion of the contribution, then further ranking of technologies would be 

warranted. If PM was found to be a very small or insignificant portion of the overall visibility contribution 

from NCS Unit 1, then further evaluation of control technology would not be warranted at this time. 

The maximum 24-hour emission rates of PMF and PMC from NCS Unit 1 are presented below. These emission 

rates were utilized in the visibility modeling conducted. 

Table 3: Particulate Matter Emissions 

PM – Fine PM – Coarse 

Lb/day Tons/year Lb/day Tons/year 

4,004 731.2 2,262 413.1 

The baseline case model indicated that the direct particulate emissions were generally responsible for well 

under 1% of the total predicted change in deciview impact from NCS Unit 1 (See Table 4). In fact, PM only 

accounted for 0.32% of the greatest deciview impairment Unit 1 had (0.933 in 2001 at Hercules Glades in 

Missouri). This would indicate that the predicted deciview impact is from a pollutant or pollutants other than 

PM. The results for each year, by Class I area, are presented below. The 98% percentile value is presented for 

each year. The results below confirm that the direct particulate matter emissions from NCS Unit 1 do not 

significantly contribute to visibility impairment in the Class I areas analyzed. 
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Table 4: Particulate Matter Contribution of the NCS Unit 1 Predicted Visibility Impairment 

2001 2002 2003 

∆dV % PM ∆dV % PM ∆dV % PM 

Badlands (SD) 0.332 0.56% 0.126 0.23% 0.225 0.30% 

Great Sand Dunes (CO) 0.009 0.39% 0.019 0.15% 0.036 0.63% 

Hercules Glades (MO) 0.933 0.32% 0.556 0.42% 0.473 0.46% 

Mingo (MO) 0.374 0.63% 0.371 0.86% 0.305 0.81% 

Rocky Mountain (CO) 0.010 0.43% 0.043 0.51% 0.047 0.60% 

Wichita Mountains (OK) 0.306 0.43% 0.381 0.56% 0.686 0.51% 

Wind Cave (SD) 0.095 0.27% 0.050 0.27% 0.111 0.68% 

Based on the fact that NCS Unit 1 appears to be currently adequately controlled by an electrostatic precipitator 

(ESP), is subject to an emissions limitation of 0.1 lb/MMBtu (Title V OP), and the modeling results revealed 

that direct particulate emissions do not significantly contribute to visibility impairment in Class I areas, the 

NDEQ has determined that BART for PM shall be existing controls and requirements.

3.0 BART Analysis for SO2

The objective of this analysis is to determine BART for SO2 emissions from the NCS Unit 1. Generally there 

are two approaches to controlling SO2 emissions: removal of elemental sulfur from the fuel prior to combustion 

and flue gas desulfurization (FGD). FGD consists of removal of SO2 from the flue gases after combustion. 

3.1 SO2 Formation 

SO2 emissions are formed from the oxidation of organic and pyretic 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 Powder River Basin 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 SO3 emissions combine with combustion-related moisture, or when SO2 is oxidized to SO3

in the atmosphere. This SO3 will also combine with water in the atmosphere to form H2SO4, which typically 

reacts further with ammonia in the air to form fine particulate matter in the form of ammonium sulfates. 

3.2 Identification of SO2 Control Technologies and Technical Feasibility 

3.2.1 Sulfur Removal from Fuel 

A significant fraction of the sulfur in coal 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. Sulfur removal from low-sulfur Powder River Basin (PRB) coal has not been 

demonstrated. NCS uses PRB coal. Since this technology has not been demonstrated and it would not be cost 

effective to attempt a form of physical cleaning or chemical desulfurization, this technology is infeasible at this 

time. 

3.2.2 Flue Gas Desulfurization (FGD) 

FGD consists of removal of SO2 from the flue gases after combustion. 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 byproducts are discarded. The FGD technologies considered may be able to achieve SO2 removal 

efficiencies up to 90 to 95%, depending on the amount of sulfur in the coal. For relatively high sulfur coals 
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(such as eastern bituminous coal), removal efficiencies of 95% can be reached, while for lower sulfur coals 

(such as PRB), the achievable removal efficiency is typically less than 95%. 

3.2.2.1 Regenerative Processes

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 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%. 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. 

None of the regenerative processes identified above have been demonstrated on large coal-fired boilers and it 

would not be cost effective to attempt to utilize a regenerative process of FGD at this time. Therefore all 

regenerative technologies have been determined to be infeasible at this time.

3.2.2.2 Throwaway Processes-Wet and Dry FGD

Throwaway process have become widely accepted by the coal-fired power industry for FGD because they have 

lower overall costs and are simpler to operate than regenerative processes. Throwaway processes can achieve 

the same removal efficiencies as regenerative processes and cost less. 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. 

Wet FGD

Wet scrubbing 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. Many utilities can also offset 

operating costs of wet FGD by selling one of the by-products, calcium sulfate (gypsum), to wallboard 

manufacturing facilities. Although gypsum can be sold, there is little local demand for it near NCS, so OPPD 

could not take advantage of the cost offset. However, wet scrubbing is a feasible technology for SO2 control 

from NCS Unit 1. 

Dry FGD

Dry FGD is a well established process for removing SO2 from flue gas. Many 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. The exhaust from a dry FGD system contains 

very fine particulate, which would not be effectively controlled by the existing ESP. Therefore if OPPD would 

be required to install dry FGD, a baghouse would need to be installed also. However, dry scrubbing is a 

feasible technology for SO2 control from NCS Unit 1. 

3.3 Ranking of Technologically Feasible SO2 Controls based on Effectiveness 

Wet and dry scrubbing are feasible technologies for SO2 control. Effectiveness is measured by the amount of 

SO2 removed by each control technology based on a comparison of the controlled emission rates to the 
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uncontrolled baseline emission rate of NCS Unit 1. In this case, it is anticipated that the same level of SO2

control can be achieved by the use of either wet or dry FGD. The presumptive BART limit in 40 CFR 

Appendix Y for electrical generation units above 200 MW at plants greater than 750 MW in capacity is 0.15 

lb/MMBtu. However, the NDEQ estimated that both technologies could achieve a lower emissions rate of 0.1 

lb/MMBtu. 

Based on the maximum actual 24-hr SO2 emissions over a three year baseline period (2001-2003) of 0.815 

lb/MMBtu, together with assumed continuous operation, the maximum annual emissions would be equal to 

24,191 tons/year. At the presumptive BART level (0.15 lb/MMBtu) it is estimated that 19,739 tons/year would 

be removed from the flue gas and not emitted into the atmosphere if either dry or wet scrubbing was employed. 

At an emissions rate of 0.1 lb/MMBtu, it is estimated a total of 21,223 tons/year would be removed from the 

flue gas and not emitted into the atmosphere if wet or dry scrubbing was employed. 

3.4 Evaluation of Effective SO2 Controls 

The equivalency in anticipated SO2 emission rates using wet or dry 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, wet FGD to control 

SO2 emissions from NCS Unit 1 would result in higher energy penalties to facility operation and the generation 

of more waste byproducts than would dry FGD. Therefore dry FGD was selected for further evaluation. It is 

important to note that when final detailed design and vendor commitments incorporating site-specific 

complexities related to equipment sizing, location, etc. are known, it is possible that detailed cost estimates for 

dry FGD could vary from those used in this analysis. 

OPPD provided cost information associated with the installation of a dry FGD system. The capital cost 

estimate for the Spray Dryer Absorber (SDA) system included site work, demolition for the installation of the 

system, SDA lime preparation equipment and building, SDA/Fabric Filter (SDA/FF) system, ID Booster fan 

equipment, ash handling equipment, and electrical modifications. Operating costs were also considered, 

including labor, maintenance, lime costs, bag filter replacement, and additional electrical energy consumption. 

The total annualized cost associated with the installation of an SDA is $34,720,000. The cost effectiveness of 

this control technology is $1,635.96 per ton SO2 removed ($34,720,000 / 21,223 tons SO2 removed). 

Additional impacts to the source and the surrounding areas include the usage of 1% (6 MW) of the unit’s 

generating capacity to operate the SDA system, disposal of the solid waste byproduct from the spent reagent 

and ash mixture. The spent reagent and ash mixture must be landfilled, as it cannot be used for beneficial 

purposes based on its characteristics and current markets. If wet FGD is employed, use of additional land 

would be needed for scrubber water disposal and settling ponds. 

3.5 Visibility Impacts 

Air dispersion modeling using CALPUFF was conducted to determine the improvement in visibility at several 

Class I areas (those areas included in the modeling domain utilized) if an SDA system was installed on NCS 

Unit 1. The other visibility impairing pollutant levels remained unchanged. 

Table 5: Incremental Visibility Effectiveness (SO2 Controls) at Presumptive Level of 0.15 lb/MMBtu 

Control 

Option 

Class I 

Areas – 

Maximum 

Impacts 

(Year) 

Badlands 

(2001) 

Great Sand 

Dunes (2003) 

Hercules 

Glades 

(2001) 

Rocky Mtn 

(2007) 

Wichita Mtn 

(2003) 

Wind Cave 

(2003) Mingo (2001) 

line

(0.81

5 lb 

SO2/

MM

BTuModeled 98th

Percentile 

(∆dV) 

0.332 0.036 0.933 0.047 0.686 0.111 0.374 
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Control 

Option 

Class I 

Areas – 

Maximum 

Impacts 

(Year) 

Badlands 

(2001) 

Great Sand 

Dunes (2003) 

Hercules 

Glades 

(2001) 

Rocky Mtn 

(2007) 

Wichita Mtn 

(2003) 

Wind Cave 

(2003) Mingo (2001) 

Incremental 

Visibility 

Impairment 

Improvement 

- - - - - - - 

Modeled 98th

Percentile 

(∆dV) 

0.16 0.014 0.496 0.021 0.334 0.05 0.2 

Incremental 

Visibility 

Impairment 

Improvement 

(∆dV) 

0.172 0.022 0.437 0.026 0.352 0.061 0.174 

SDA/FF Control Added 

(0.15 lb SO2/MMBtu) 

Incremental 

Impairment 

Improvement 

Cost 

($/yr/∆dV)[1]

$201,860,465 $1,578,181,818 $79,450,801 $1,335,384,615 $98,636,364 $569,180,328 $199,540,230 

[1]Total annualized cost / Incremental visibility impairment improvement 

OPPD was asked to conduct further analysis at 0.1 lb/MMBtu for Hercules Glades and Wichita Mountains to 

determine whether there was a significant improvement in visibility and/or a significant change in the 

incremental visibility impairment improvement costs. This analysis was received on November 14, 2008. 

These two Class I areas were selected because of the greatest impact from NCS. Table 6 details the findings: 

Table 6: Incremental Visibility Effectiveness (SO2 Controls) at 0.1 lb/MMBtu 

 Class I Areas – 

Maximum Impacts (Year) 

Hercules Glades (2001) Wichita Mtn (2003) 

Modeled 98th Percentile (∆dV) 0.933 0.686 

Baseline 

(no control) 

(0.815 lb 

SO2/MMB

Tu) 

Incremental Visibility Impairment 

Improvement 

- - 

Modeled 98th Percentile (∆dV) 0.493 0.311 

Incremental Visibility Impairment 

Improvement (∆dV) 

0.44 0.375 

SDA/FF Control 

Added 

(0.1 lb 

SO2/MMBtu) 

Incremental Impairment Improvement 

Cost ($/yr/∆dV)[1]

$78,909,091 $92,586,667 

[1]Total annualized cost / Incremental visibility impairment improvement 

The baseline conditions for Hercules Glade and Wichita Mountains Class I areas, based on the 20% worst 

visibility days, and the goal of natural background conditions is found in Table 7. 

Table 7: Baseline Conditions (20% Worst Days) and Natural Background Goal 

Class I Area 

Hercules 

Glades 

dV 

Wichita Mtn 

dV 

Baseline 

20% Worst Days 26.75 23.81 

Natural Background 

By 2064 11.3 7.58 
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4.0 BART Analysis for NOx

The objective of this analysis is to determine BART for NOx emissions from the NCS Unit 1. Generally there 

are two approaches to controlling NOx emissions: combustion controls and/or flue gas treatment (postcombustion) technologies. Combustion control processes can reduce the quantity of NOx formed during the 

combustion process. Post-combustion 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 various degrees of NOx emission reductions. 

4.1 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 and residence time, 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. 

The formation of fuel NOx from reactions of fuel bound nitrogen and air, can account for up to 80% of the total 

NOx from coal combustion. Subbituminous coals contain from 0.5% -2% percent by weight fuel-bound 

nitrogen. 

4.2 Identification of NOx Control Technologies and Technical Feasibility 

4.2.1 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. New developments in LNB technologies have demonstrated substantial reductions in NOx formation. 

Combustion controls are able to be used on industrial and utility boilers and are considered to be feasible 

technologies for NOx control from NCS Unit 1. 

4.2.2 Post Combustion Control Technologies 

4.2.2.1 Selective Catalytic Reduction

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

SCR process involves the injection of a nitrogen-based reducing agent 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, and as the catalyst degrades, the NH3 emissions will increase. This phenomenon is 

known as the NH3 slip. SCR is a proven technology and is a feasible NOx control technology for NCS Unit 1. 

Although SCR is a feasible control technology, it would be most practical to install SCR in combination with 

combustion controls. This is because if NOx formation was not reduced upstream of the SCR system, the 

catalyst would degrade more rapidly, making it necessary to replace the catalyst more often. Therefore, the cost 

associated with installing LNB/OFA is linked to this control technology throughout the analysis. 

4.2.2.2 Selective Non-Catalytic Reduction

The selective non-catalytic reduction (SNCR) process involves the injection of a nitrogen-based reducing agent 

such as NH3 or urea to reduce the NOx in the flue gas; however a catalyst is not used. Instead the SNCR 

process occurs within the upper reaches of a combustion unit, which acts as the reaction chamber. Flue gas 

temperatures in the range of 1,500 to 1,900 degrees Fahrenheit, along with adequate reaction time within this 
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temperature range, are required for this technology. SNCR is a proven technology and is 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, such as in the case of 

NCS Unit 1. Due to the high temperatures experienced at the furnace exit, ammonia injection would have to 

occur far down stream in the convection section when combustion gases have cooled more. 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. 

This would mean significantly lower residence time in the appropriate temperature window, high ammonia 

“slip,” and non-sufficient NOx control by this method. Due to the reasons discussed above, SNCR has been 

determined to be infeasible at this time. 

4.3 Ranking of Technologically Feasible NOx Controls based on Effectiveness 

Combustion controls and SCR are feasible technologies for NOx control. 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 NCS Unit 1. It is generally not practical to install higher efficiency 

NOx control technologies without first optimizing combustion controls. Reducing the concentration of NOx to 

be controlled provides the benefit of longer catalyst life and less reagent usage for add-on NOx control 

technologies. NCS Unit 1 currently has overfire air (OFA), which might need to be modified, optimized, or 

replaced to work along with a new LNB system. Therefore LNB/OFA will be evaluated as the first level of 

NOx control, and then SCR with the LNB/OFA system as the second level of NOx control. 

Based on the maximum actual 24-hr NOx emissions over a three year baseline period (2001-2003), together 

with assumed continuous operation, the maximum annual emissions would be equal to 17,008 tons/year. If

LNB/OFA was employed, the NOx emissions limitation would be established at 0.23 lb/MMBtu which is the 

presumptive BART limitation in Appendix Y for this source type. If only LNB/OFA were required for BART, 

it is estimated that 10,181 tons/year would be removed from the flue gas and not emitted into the atmosphere. 

If SCR and LNB/OFA were installed, an emissions limitation of 0.08 lb/MMBtu would be established, equating 

to 14,633 tons/year of NOx reductions from Unit 1. By installing both an SCR system in conjunction with 

LNB/OFA, NOx would be controlled more efficiently than with a stand-alone SCR system. 

4.4 Evaluation of Effective NOx Controls 

The cost of compliance, energy impacts, non-air quality impacts, and remaining useful life of the unit were all 

evaluated for purposes of determining if either, both, or none of the feasible control options should be required 

for BART. 

OPPD provided cost information associated with the installation of LNB/OFA with and without the installation 

of an SCR system. The capital cost included the costs associated with the burner modification (installation of 

LNB/OFA and over fire air modification), SCR equipment, ID Booster fan equipment, air heaters, and electrical 

modifications. Operating costs were also considered. The total annualized cost associated with the installation 

of LNB/OFA is $1,380,000. The cost effectiveness of LNB/OFA is $135.55 per ton NOx removed ($1,380,000 

/ 10,181 tons NOx removed). The total annualized cost associated with the installation of LNB/OFA and SCR 

is $39,590,000. The cost effectiveness of LNB/OFA and SCR is $2,705.53 per ton NOx removed ($39,590,000 

/ 14,633 tons NOx removed). The incremental cost analysis of installing LNB/OFA and SCR as opposed to 

LNB/OFA alone is $8,583 ([$39,590,000 - $1,380,000] / [14,633 – 10,181]). Additional impacts to the source 

and the surrounding areas include 1) the usage of the unit’s generating capacity to operate the SCR system, 2) 

hazardous spill risk due to transport and storage of ammonia, and 3) ammonia used in the system would cause 

the ash to be contaminated, thereby jeopardizing the current beneficial reuse of a portion of the ash produced by 

NCS Unit 1.
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4.5 Visibility Impacts 

Air dispersion modeling using CALPUFF was conducted to determine the improvement in visibility at several 

Class I areas (those areas included in the modeling domain utilized) if either LNB/OFA or LNB/OFA with SCR 

was installed on NCS Unit 1. The other visibility impairing pollutant levels remained unchanged. 

Table 8: Incremental Visibility Effectiveness (NOx Controls) 

Control 

Option 

Class I 

Areas – 

Maximum 

Impacts 

(Year) 

Badlands 

(2001) 

Great Sand 

Dunes (2003) 

Hercules 

Glades 

(2001) 

Rocky Mtn 

(2003) 

Wichita Mtn 

(2003) 

Wind Cave 

(2003) Mingo (2001) 

Modeled 98th

Percentile 

(∆dV) 

0.332 0.036 0.933 0.047 0.686 0.111 0.374 

Baseline 

(0.573 

lb/MMBTU) 

(no NOx 

Control) 

Incremental 

Visibility 

Impairment 

Improvement 

- - - - - - - 

Modeled 98th

Percentile 

(∆dV) 

.258 0.03 0.633 0.036 0.531 0.105 0.269 

Incremental 

Visibility 

Impairment 

Improvement 

(∆dV) 

0.074 0.006 0.3 0.011 0.155 0.006 0.105 

LNB/OFA Control Added 

(0.23 lb/MMBtu) 

Incremental 

Impairment 

Improvement 

Cost 

($/yr/∆dV)[1]

$18,648,649 $230,000,000 $4,600,000 $125,454,545 $8,903,226 $230,000,000 $13,142,857 

Modeled 98th

Percentile 

(∆dV) 

0.16 0.014 0.453 0.013 0.447 0.05 0.2 

Incremental 

Visibility 

Impairment 

Improvement 

(∆dV) 

0.172 0.022 0.48 0.03 0.239 0.061 0.174 

LNB/OFA & SCR Control 

Added (0.08 lb/MMBtu) 

Incremental 

Impairment 

Improvement 

Cost 

($/yr/∆dV)[1]

$230,174,420 $1,799,545,455 $82,479,167 $1,319,666,667 $165,648,536 $649,016,393 $227,528,736 

[1]Total annualized cost / Incremental visibility impairment improvement 

4.6 BART Conclusion for SO2 and NOx

Dry scrubber technology is a technically feasible SO2 retrofit technology that could be implemented on NCS 

Unit 1. The cost effectiveness of this control technology is $1,636 per ton SO2 removed. Over the three years 

of meteorology modeled, the range of incremental visibility impairment improvement cost is $79,450,801 - 

$1,578,181,818 per year per change in deciview. As stated in Chapter 8 of the Regulatory Impact Analysis 

(RIA) the US EPA prepared for the Regional Haze rule, high cost control measures that have only minimal 

effect on visibility improvement can be avoided. Using scrubbing technology would be expected to result in the 

number of days where NCS’s impact contributed to more than 0.5 dV to decrease from 14 days to 7 days during 

the worst meteorological year for Hercules Glades and from 10 days to 6 days for Wichita Mountains. 

LNB/OFA technology is a feasible NOx retrofit technology that could be implemented on NCS Unit 1. The cost 

effectiveness of this control technology is $135.55 per ton NOx removed ($1,380,000 / 10,181 tons NOx

removed. The lowest incremental visibility impairment improvement cost is $4,600,000 per year per change in 

deciview. The NDEQ determined that at a minimum, LNB/OFA would be required for BART. Using 
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LNB/OFA technology would be expected to result in the number of days where NCS’s impact contributed to 

more than 0.5 dV to decrease from 14 days to 9 days during the worst meteorological year for Hercules Glades 

and from 10 days to 9 days for Wichita Mountains. 

Adding SCR to the LNB/OFA system would result in incremental visibility impairment improvement cost of 

approximately $82,479,167 - $1,799,545,455. As stated in Chapter 8 of the RIA EPA prepared for the Regional 

Haze rule, high cost control measures that have only minimal effect on visibility improvement can be avoided. 

Adding SCR to LNB/OFA technology would be expected to result in the number of days where NCS’s impact 

contributed to more than 0.5 dV to decrease from 14 days to 6 days during the worst meteorological year for 

Hercules Glades and from 10 days to 7 days for Wichita Mountains. Since the incremental visibility 

impairment improvement cost is so large for the LNB/OFA + SCR compared to LNB/OFA, that NCS 1 can cost 

effectively achieve presumptive levels using LNB/OFA, the Department has determined that it would not be 

appropriate to require the installation of SCR at this time. Furthermore, since the incremental visibility 

impairment improvement cost is so large compared to similar improvements in visibility using LNB/OFA 

technology and the states with the Class I areas that would benefit the most, Missouri and Oklahoma, have not 

identified a need for SO2 emission reductions from Nebraska at this point in time, the Department has 

determined that it is excessive to require the installation of SO2 scrubbing technology at this time. However, 

controls may be required in the future for purposes of “reasonable further progress.” 

Information provided by OPPD in the BART analysis showed that BART proposals in Minnesota and North 

Dakota would cost between $1,250,000 - $10,100,000 per year per deciview, have a post-BART impact 

between 0.67 – 2.36 dV, and have a greater than 0.5 dV impact on 13 – 72 days. The BART selected for NCS 

Unit 1 would achieve a post-BART impact level of 0.621 dV, has only 9 days of greater than 0.5 dV impact on 

a Class I area, and would still be well within the cost range in Minnesota and North Dakota. To reduce the 

impacts on a maximum of an additional 3 days, but add up to 20 times the cost per deciview is not cost

effective. 

Therefore BART for NCS Unit 1 shall be the installation of LNB/OFA with an emission limitation of 0.23 lb 

NOx/MMBtu. 

5.0 Prevention of Significant Deterioration (PSD) 

5.1 Summary 

BART for NCS Unit 1 has been determined to be the installation of low NOx burners supported by an existing, 

modified, or replacement overfire air port system as needed to meet a NOx limit of 0.23 lb/MMBtu. Although 

NOx emissions would decrease, carbon monoxide (CO) emissions are expected to increase in emissions above 

PSD significance thresholds (100 tons/year for CO). Title 129, Chapter 1, Section 076 defines a “major 

modification” as any physical change in or change in the method of operation of a major stationary source that 

would result in a significant emissions increase of a regulated New Source Review (NSR) pollutant and a 

significant net emissions increase of that pollutant from the major stationary source. Therefore, the installation 

of LNB/OFA is a major modification and NSR regulations are applicable. Otoe County is in attainment for all 

National Ambient Air Quality Standards (NAAQS) so the Prevention of Significant Deterioration (PSD) 

regulations apply to this source. The PSD regulations state that the application of best available control 

technology (BACT) is required for each new or modified emission unit and each regulated air pollutant for 

which the project emissions exceed the established PSD significance thresholds. Since Unit 1 is the only unit 

required to install BART (i.e. installation of LNB/OFA), Unit 1 is the only unit which needs to apply BACT for 

the increase in CO. BACT is defined as an emissions limitation established based on the maximum degree of 

pollutant reduction for each pollutant subject to regulation under the Clean Air Act which would be emitted 

from any proposed major stationary source or major modification which the Administrator, on a case-by-case 

basis, taking into account energy, environmental, and economic impacts and other costs, determines in 

achievable. However, BACT cannot be less stringent than emission limits established by an applicable NSPS. 
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Since it would not be appropriate to require NCS to install LNB/OFA without addressing the increase in CO 

emissions expected, the Department has decided to address the BART requirements and PSD requirements in a 

single permitting action. As documented below, it has been determined that BACT for this unit should be a 

specific 30-day rolling average CO emissions limitation of 0.50 lb/MMBtu, with the control being good 

combustion practices. 

5.2 Best Available Control Technology (BACT) Analysis Methodology 

In a memorandum dated December 1, 1987, the EPA stated its preference for a “top-down” analysis regarding 

BACT determinations. The first step in a top-down BACT analysis is to determine, for the emissions unit and 

pollutant in question, the most stringent control technology and emissions limit available for a similar or 

identical source or source category. If it can be shown that this level of control is infeasible on the basis of 

technical, economic, energy, and environmental impacts for the source in question, then the next most stringent 

level of control is identified and similarly evaluated. This process continues until the BACT level under 

consideration cannot be eliminated by any technical, economic, energy or environmental consideration. 

A “Top-Down” BACT analysis is comprised of the following five basic steps: 

5.2.1 Step 1: Identify all potentially applicable control technologies: 

All control technologies for similar processes, as well as Lowest Achievable Emission Rate (LAER) 

technologies are included. 

 

5.2.2 Step 2: Eliminate technically infeasible options: 

Technologies demonstrated to be infeasible based on physical, chemical, and engineering principles are 

excluded from further consideration. 

5.2.3 Step 3: Rank remaining technologies by control effectiveness: 

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

lowest expected emission reduction. The ranking also includes expected emission rate, control effectiveness, 

energy impacts, environmental impacts (including toxic and hazardous air emissions), and economic impacts. 

5.2.4 Step 4: Evaluate most effective controls and document results: 

The technology ranking is evaluated and case-by-case consideration is given to energy, environmental, and 

economic impacts. The most effective option not rejected is chosen as BACT and is used to express an 

enforceable emission limitation for the affected emission unit. 

5.2.5 Step 5: Propose BACT

5.3 BACT Analysis for Carbon Monoxide (CO) 

The objective of this analysis is to determine BACT for CO emissions from the NCS Unit 1 LNB/OFA system. 

Generally there are two approaches to controlling CO emissions: combustion controls and/or flue gas treatment 

(post-combustion) technologies. The rate of CO emissions from combustion sources is dependent upon the 

combustion efficiency of the source. Combustion control processes can reduce the quantity of CO formed 

during the combustion process. Post-combustion technologies reduce the CO concentrations in the flue gas 

stream after the CO has been formed in the combustion process. These methods may be used alone or in 

combination to achieve various degrees of CO emission reductions. High combustion temperatures, adequate 

excess air, and good air/fuel mixing during combustion can minimize CO emissions. 

5.3.1 CO Formation

CO formation occurs primarily through incomplete combustion. The oxidation of CO to carbon dioxide (CO2) 

is dependent on temperature, residence time during the combustion process, and the amount of excess O2
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present. Since temperature and residence time are critical factors in formation of CO, smaller boilers often emit 

more CO than larger combustion units, because these units have less high-temperature residence time to achieve 

complete combustion. Often, measures used to minimize or control emissions of NOx can result in incomplete 

combustion and increased CO emissions. Therefore, an acceptable compromise is necessary to achieve the 

lowest NOx emission rate possible while still keeping CO emissions as low as possible. 

5.3.2 Identification of CO Control Technologies and Technical Feasibility

Combustion Controls 

Combustion controls generally include staged combustion to minimize NOx formation, high temperatures and 

low oxygen levels in the primary combustion zone, sufficient excess air to complete combustion, sufficient 

residence times, and good air/fuel mixing. Combustion efficiency is often related to the three “T’s” of 

combustion: time, temperature, and turbulence. These components of combustion efficiency are designed into 

pulverized coal (PC) boilers in order to maximize fuel efficiency and reduce operating costs in terms of fuel 

consumption. Therefore, combustion control is accomplished primarily through burner/furnace design and 

operation. The primary combustion control methods used, once the burner/furnace design is set, are 

adjustments in the amount of air and the ratio of primary air to secondary air. These adjustments significantly 

affect combustion efficiency and CO levels in the combustion flue gases.

LNB/OFA systems for PC boilers are designed to burn the coal in a slow, controlled manner, which results in 

the minimum possible quantity of combustion air in the primary combustion zone. This initial combustion zone 

helps reduce NOx formation; however it increases the amount of incomplete combustion that increases CO 

emissions. CO emissions can be minimized by injecting air through over-fire air ports located in the upper 

furnace section. The injected air brings the total amount of combustion air up to the level needed to achieve 

complete combustion, thereby minimizing CO emissions. It is technically feasible and economically desirable 

to minimize CO emissions; therefore, good combustion practices are considered to be feasible technologies for 

CO control from NCS Unit 1. 

5.3.3 Post Combustion Control Technologies

Oxidation Catalysts 

There are a variety of manufacturers who offer oxidation catalysts to control CO emissions. The catalysts are a 

flue gas treatment technology with a typically honeycomb type of arrangement to allow the maximum surface 

area exposure to a given gas flow. The typical oxidation catalyst for CO is a rhodium or platinum (noble metal) 

catalyst on an alumina support material. Acceptable catalyst operating temperatures range from 400 – 1250 oF, 

with optimum temperature range being 850 – 1,100 oF. Below 600 oF, a greater catalyst volume would be 

required to achieve the same reduction. 

Catalytic oxidation has never been applied to a coal-fired unit due to several problems due to the solid fuel use, 

temperature requirements, and sulfur dioxide present in the flue gas. Catalyst plugging, fouling and poisoning 

by fuel sulfur and fly ash cause the catalyst to be ineffective. In order for the ideal temperature to be applied to 

the catalyst, the catalyst would need to be installed before the boiler economizer, which is ahead of the unit’s 

particulate controls (fabric filters). Installation of the catalyst in this section of the boiler would result in rapid 

poisoning and deactivation of the catalyst by sulfur and metal compounds, and plugging and fouling of the 

active catalyst sites with particulates due to the high dust loading. Additionally, significant cost would be 

incurred for retrofitting this technology to an existing boiler. In addition, because the catalyst would oxidize a 

high percentage of the flue-gas sulfur dioxide (SO2) to sulfur trioxide (SO3), the oxidation catalyst would result 

in significantly increased sulfuric acid mist formation and condensable particulate. High levels of sulfuric acid 

would lead to rapid and destructive corrosion of ducts and equipment downstream of the catalyst and higher 

fine particulate and opacity levels, which would result in a visible plume from the stack. Current oxidation 
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catalyst technology has not been designed for the higher particulate and sulfur dioxide levels found in coal-fired 

applications. Therefore, catalytic oxidation is not considered technically feasible for PC boilers like NCS 

Unit 1. 

5.4 Ranking of Technologically Feasible CO Controls based on Effectiveness 

Based on the CO control technologies presented above, the only feasible BACT technology for this source is 

good combustion practices (GCP). Catalytic oxidizers have not been proposed or demonstrated for use on a 

pulverized coal-fired boiler and therefore are technically infeasible for NCS Unit 1. 

5.5 BACT for CO 

At the time this permit was issued, the highest CO BACT emission limit that has been permitted on a retrofitted 

unit in US EPA Region 7, is 1.63 lb/MMBtu (3-hr average) for the Mid American Energy Company, Neal – 

North, Unit 2 Boiler (2007). A search of the RACT/BACT/LAER Clearinghouse (RBLC) database revealed 

that the lowest such limit for a retrofitted unit was in 2005 at the Mid-American Energy, Neal – South, Unit 4 

Boiler (0.42 lb/MMBtu, calendar day average.) OPPD proposed an emissions limit of 0.50 lb/MMBtu (30-day 

rolling average) for BACT, which is below the most recent permitted emission limit. A longer averaging period 

is necessary because NCS Unit 1 does not have a neural net system installed. This computer automated system 

measures certain operating parameters associated with combustion, and based on the parameters, automatically 

adjusts the system to achieve an optimal operating scenario. Since NCS Unit 1 does not have a neural net 

system, any “tweaks” in operation must be made by the operators manually. The NDEQ agrees that the 0.5 

lb/MMBtu (30-day rolling average) is an acceptable CO BACT limit for NCS Unit 1. 

The CO permit limit (30-day rolling average of 0.50 lb/MMBtu) is comparable with other recently issued 

permits issued in Nebraska and throughout US EPA Region 7. In 2006, Nebraska Public Power District 

(NPPD) Gerald Gentleman Station (GGS) was issued a PSD construction permit for a LNB replacement 

project. The CO emissions limits being established in this permitting action for NCS Unit 1 is identical to the 

emissions limitation established for NPPD GGS Unit1. This is appropriate since NCS Unit1 is almost identical 

in size and design to GGS Unit 1 and there have been no breakthroughs in CO control technology or GCP since 

the permit for GGS Unit 1 was issued. 

6.0 Air Dispersion Modeling Analysis 

All projects that are subject to NSR review are required to be accompanied by an air quality analysis of the 

ambient impacts associated with the project. This analysis includes an assessment of existing air quality, an air 

dispersion modeling analysis, an additional impact analysis, and an evaluation of any adverse impacts to Class I 

areas. The air dispersion modeling analysis is required to demonstrate that new emissions from the source or 

due to the major modification, in conjunction with applicable emissions from other existing sources, will not 

cause or contribute to a violation of any applicable National Ambient Air Quality Standards (NAAQS) or PSD 

increment. Depending on the modeling results, pre-application monitoring or more thorough analyses may be 

required. Although a significant modeling analysis was conducted in conjunction with the BART analysis, CO 

is not a visibility impairing pollutant and therefore was not addressed. Below is a summary of the modeling 

analysis conducted. More information can be obtained in the materials submitted by the source. 

6.1 Model Information 

6.1.1 Facility Location and Site Description

The OPPD Nebraska City Station is located approximately five (5) miles southeast of Nebraska City, Nebraska 

in Otoe County. While there is no complex terrain (above the stack height), there is rolling terrain at the edges 
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of the Missouri River Valley in which the facility is located. Otoe County is currently classified as in 

attainment or unclassifiable for all NAAQS pollutants. 

6.1.2 Model Selection 

The air quality impact analysis of CO emissions was performed using the EPA SCREEN3 dispersion model. 

Inputs to SCREEN3 included stack parameters based on calculated Good Engineering Practice (GEP) height of 

667.5 feet (the stack of NCS Unit 1 is actually taller, but only the GEP height can be used for modeling 

demonstrations of compliance when using SCREEN3). Because the GEP stack height was used, no building 

downwash dimensions were input to the SCREEN3 analysis. The emission rate input into SCREEN3 was 

equivalent to 3417 lb/hr, which is based on the maximum heat input rate of 6834.3 MMBtu/hr of Unit 1 and the 

BACT emissions limit of 0.5 lb/MMBtu. 

The model was executed for a maximum (100%) load condition, because this load produces higher impacts than 

when the unit operates at partial loads. The “simple terrain” option was used and the maximum terrain 

elevation difference of 98.66 meters was input into the model. This is a very conservative procedure in that the 

model assumes that the terrain rise of 98.66 meters above the stack base occurs at every receptor distance input 

to the model. 

6.1.3 Source Parameters

One emission source, NCS Unit 1, was evaluated for purposes of PSD screening modeling. It is the only unit at 

the OPPD facility for which a change is proposed. The results of the screening modeling indicated that impacts 

from the potential emission increases resulting from the changes to NCS are insignificant. The following table 

presents the source parameters. 

Table 9: Modeled Source Parameters 

Source 

Type 

Emission 

Rate 

(g/sec) 

Stack 

Height 

(m) 

Inside 

Diameter 

(m) 

Exit 

Velocity 

(m/s) 

Exit 

Temperature 

(K) 

Ambient 

Air Temp. 

(K) 

Point 430.56 

(3,417 

lb/hr) 

203.46 7.193 30.0 415.0 293.0 

 

6.2 Preliminary Modeling Analysis 

The preliminary modeling analysis evaluates potential emissions from the PSD project alone. The results of the 

preliminary analysis determine whether or not a full impact analysis is required. For this project the 

preliminary modeling analysis was also used to determine whether or not pre-application monitoring needed to 

be required from the source. 

The following table shows the results of the modeling analysis conducted. The results indicate that the 

modification of Unit 1 will not cause a significant impact in the surrounding area for the 1-hour or 8-hour 

averaging periods for CO. Therefore no refined modeling analysis needs to be completed and no preapplication monitoring was necessary. 
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Table 10: Maximum Modeled NCS Unit 1 Concentrations, Significant Impact Levels (SIL), 

and Pre-application Monitoring Thresholds

Pollutant Averaging 

Period 

Modeled 

Concentration 

(ug/m3) 

SIL 

(ug/m3) 

Pre-application Monitoring 

Threshold (ug/m3) 

1-hr 172.3 2,000 N/A CO 8-hr 120.6 500 575 

6.3 Additional Impacts Analysis 

An Additional Impacts Analysis, as required by Title 129, Chapter 19, Section 022, and the PSD regulations 40 

CFR 52.21(o), describes air quality and related impacts due to associated growth and construction, as well as 

potential impacts of atmospheric emissions on soils, vegetation, and visibility impairment. This analysis was 

provided in the materials submitted by the source. 

Visibility analyses were not conducted since the burner modification will not result in an increase of emissions of 

any visibility impairing pollutant. 

6.3.1 Pollutant Effects on Soil and Vegetation

Current literature contains little information on air pollutant effects on soil and no specific studies could be 

identified where potential pollutant effects on the soils specific to the project area were evaluated. One study was 

found concerning CO effects on vegetation. The study indicated that natural background concentration of CO has 

no detrimental effects on green plants, and adverse effects are only seen at extremely high CO concentrations that 

occur primarily in urban areas due to high traffic density. Since the project is taking place in a rural area, CO 

emissions are not expected to negatively impact vegetation. NAAQS are not expected to be exceeded as a result of 

this project. Since NAAQS were designed to protect the public health and welfare from known or anticipated 

adverse pollutant impacts, it can be assumed that there will not be any adverse effects on the soil or vegetation. 

7.0 Type and Quantity of Air Contaminant Emissions Anticipated 

As a result of the LNB installation supported by an Overfire Air Port System on NCS Unit 1, NOx and CO are 

the only pollutants expected to change. NOx emissions should decrease, while CO emissions may increase. 

Since CO is the only pollutant that may increase; it is the only pollutant subject to PSD review. 

CO PTE after LNB/OFA Project Emission Calculation 

6,834 MMBtu/hr x 0.50 lb CO/MMBtu = 3417.15 lb CO/hr x 8,760 hr/yr / 2,000 lb/ton = 14,967 ton CO/yr

The current potential emissions of Unit 1 were calculated by using a CO emission factor of 0.5 lb/ton of coal 

from AP-42, Chapter 1, Table 1.1-3 (9/1998) and the maximum amount of coal that could be combusted in Unit 

1 assuming a Btu content of coal of 8,400 Btu/lb. 

CO PTE prior to LNB/OFA Project Emission Calculation 

6,834 MMBtu/hr / 0.0084 MMBtu/lb x 8,760 hr/yr / 2,000 lb/ton = 3,563,443 ton coal/year 

 3,563,443 ton coal/year x 0.5 lb CO/ton coal = 1,781,722 lb CO/yr / 2,000 lb/ton = 891 ton CO/yr

Change in PTE Emission Calculation: 

(Future Potential minus Current Potential) 

14,967 ton CO/yr – 891 ton CO/yr = 14,076 ton CO/yr 
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This project is also expected to reduce the amount of NOx emissions currently being emitted by NCS Unit 1. 

Currently, NCS Unit 1 must comply with a NOx emissions limit of 0.2 lbs/MMBtu derived from gaseous fuel, 

0.3 lbs/MMBtu derived from liquid fuel, 0.7 lbs/MMBtu derived from solid fossil fuel, or the prorated equation 

contained in 40 CFR 60.44(b) when a combination of fuels is burned, based on an arithmetic average of three 

contiguous one-hour periods (40 CFR 60.44(a) and (b), and 60.45(g)) in order to be in compliance with the 

applicable New Source Performance Standard (NSPS), Subpart D, for Fossil-Fuel-Fired Steam Generators. In 

addition, NCS Unit 1 must comply with a NOx emission limit of 0.46 lb/MMBtu on an annual basis. The NOx

limit of 0.46 lb/MMBtu for dry bottom wall-fired boilers is found in 40 CFR 76.7(a)(2) and became effective 

1/1/2008. NCS Unit 1 has a heat input rating of 6,834 MMBtu/hr and by using the highest possible emission 

factor of 0.46 lbs/MMBtu, maximum potential NOx emissions are currently 13,769 tons/year. 

6,834 MMBtu/hr x 0.46 lb NOx/MMBtu = 3,144 lb NOx /hr x 8,760 hr/yr / 2,000 lb/ton = 13,769 ton NOx /yr

By establishing a NOx emissions limitation of 0.23 lb/MMBtu for BART, the new potential emissions of NOx

from NCS Unit #1 will be approximately 6,885 tons/year once the LNB/OFA project has been completed. 

6,834 MMBtu/hr x 0.23 lb NOx/MMBtu = 1,572 lb NOx /hr x 8,760 hr/yr / 2,000 lb/ton = 6,885 ton NOx /yr

Change in PTE Emission Calculation: 

 (Future Potential minus Current Potential) 

6,885 ton NOx/yr – 13,769 ton NOx/yr = - 6,884 tons NOx/yr 

Therefore, once the LNB/OFA project has been completed, maximum potential CO emissions would increase 

by 14,076 tons/year while maximum potential NOx emissions would decrease by 6,884 tons/year. 

8.0 Applicable Requirements, Variances or Alternatives to Required Standards: 

8.1 Nebraska State Construction Permit Requirements 

A state construction permit is required for this facility because this construction project has a net increase in 

emissions at the site greater than one or more of the threshold levels identified in Title 129, Chapter 17, Section 

001.01 for PM10, SOx (SO2 and/or SO3), NOx, CO, VOC and HAPs. Specifically, CO emissions are expected to 

increase greater than 50 tons/year. 

The facility-wide potential emissions from the facility after the issuance of this permit falls into the following 

category: 

 100 tons or more per year of any air pollutant; or 

 10 tons or more per year of any single HAP; or 

 25 tons or more per year of any combination of HAPs 

Therefore, the facility submitted a $3,000.00 fee in order to obtain this Air Quality Construction Permit, in 

accordance with Title 129, Chapter 17, Section 003.01. 

Section 014.04 of this chapter states that a source may request a state construction permit when establishing a 

Best Available Retrofit Technology (BART) permit or other permit required to reduce visibility impairment in a 

Class I Federal area pursuant to the provisions of Chapter 43. 

8.2 New Source Performance Standards (NSPS) 

The proposed project will not trigger the applicability of any new NSPS requirements to NCS Unit 1. 
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Subpart A – General Provisions: NSPS Subpart A, adopted by reference in Title 129, Chapter 18, Section 

001.01, applies to those units covered by the specific NSPS as discussed below. The permittee is required to 

submit notification of the date construction commenced postmarked no later than 30 days after such date (40 

CFR 60.7(a)(1)), notification of the anticipated date of initial startup of the equipment postmarked not more 

than 60 days nor less than 30 days prior to such date (40 CFR 60.7(a)(2)), and notification of the actual date of 

initial start up of the equipment postmarked within 15 days after such date (40 CFR 60.7(a)(3)). Unit 1 at NCS 

is currently subject to this subpart and the proposed project does not affect the applicability of this regulation or 

the compliance status of the unit. 

Subpart D – Standards of Performance for Fossil-Fuel-Fired Steam Generators: This subpart, adopted by 

reference in Title 129, Chapter 18, Section 001.17, is for steam generating units with a design rate greater than 

250 MMBtu/hr, installed after August 17, 1971. NCS Unit 1 is currently subject to this subpart and the 

proposed project does not affect the applicability of this regulation or the compliance status of the unit. 

Subpart Da – Standards of Performance for Electric Utility Steam Generating Units: This subpart, adopted by 

reference in Title 129, Chapter 18, Section 001.11, is for steam generating units with a design rate greater than 

250 MMBtu/hr, installed after September 18, 1978. The installation of LNB will not constitute a modification 

or reconstruction of the existing facility as specified in provisions under 40 CFR 60.14 and 40 CFR 60.15. 

Therefore, Unit 1 will continue to be an existing unit under NSPS Subpart D and will not be subject to any 

requirements under NSPS Subpart Da.

Subpart HHHH - Emission Guidelines and Compliance Times for Coal-Fired Electric Steam Generating Units: 

This subpart established a model cap and trade program as a means of reducing national Hg emissions from 

coal fired electric utilities. NCS Unit 1 would have been subject to Subpart HHHH, however the subpart was 

vacated in its entirety by the Court of Appeals for the District of Columbia Circuit on February 8, 2008 (State 

of New Jersey, ET AL.v. EPA). 

8.3 Particulate Matter Emissions 

Title 129, Chapter 20, Section 002 -Particulate Emissions from Combustion Sources 

NCS Unit 1 will continue to comply with the emission limits for fuel combustion located in this chapter. For 

units with heat input capacities between 10 MMBtu/hr and 10,000 MMBtu/hr, the following formula is used to 

determine the Maximum Allowable Emissions of Particulate Matter in lb/MMBtu: 

Lb/MMBtu = 1.026/I0.233 where I is the total heat input in MMBtu/hr. 

1.026/(6834.3 MMBtu/hr) 0.233 = 0.131 lb/MMBtu 

Title 129, Chapter 20, Section 004 - Opacity 

All of the equipment at the facility is subject to the opacity standard (20% opacity limit) specified in Title 129, 

Chapter 20, Section 004. Although coal is combusted at the facility, control equipment has been installed in the 

past to control particulate emissions that contribute to opacity. 

8.4 Sulfur Compound Emissions 

No fossil fuel burning equipment at the facility may emit sulfur oxides greater than two and one half (2.5) 

pounds per million BTU input. NCS Unit 1 will comply with this emission limit by complying with 

requirements that are contained within NSPS Subpart D for SO2 emissions. This limit is currently specified and 

contained within the facility’s Class I Operating Permit issued April 28, 2004. 
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8.5 Acid Rain 

The federal acid rain program requirements (40 CFR Part 72) have been incorporated by reference in this 

chapter. Unit 1 will continue to be considered an affected unit for purposes of the Acid Rain Rule because it is 

a utility unit that will generate more than 25 MW of electricity. The Acid Rain Rule requires a facility to 

monitor opacity, and all sulfur dioxide, nitrogen oxides, and carbon dioxide emissions for each affected unit. 

The proposed project does not affect any requirements of this rule. NCS is currently operating under an Acid 

Rain Permit that was issued on March 9, 2007. 

8.6 Hazardous Air Pollutants 

Title 129, Chapter 27, Section 002 - Best Available Control Technology (BACT) 

Title 129, Chapter 27, Section 002 requires a BACT determination for any source with net emissions increase 

of HAP in excess of 2.5 tons/year of any single HAP, or combined emissions of 10 tons/year of any group of 

HAPs. The proposed project will not result in net increases in potential emissions of HAPs that equals or 

exceeds the BACT thresholds. Therefore, requirements of this section do not apply to the proposed project. 

Title 129, Chapter 27, Section 003 - Maximum Achievable Control Technology (MACT) 

This section requires that MACT be installed on any source with a net emissions increase of HAP in excess of 

10 tons/year of any single HAP, or combined emissions of 25 tons/year of any group of HAPs. The proposed 

project will not result in net increases in potential emissions of HAPs that equal or exceed the MACT 

thresholds. Therefore, requirements of this section do not apply to the proposed project. 

Subpart A – General Provision: This subpart, adopted by reference in Title 129, Chapter 28, Section 001.01, 

applies to the owner or operator of any stationary source that emits or has the potential to emit any hazardous 

air pollutant listed in or pursuant to section 112(b) of the Act; and is subject to any standard, limitation, 

prohibition, or federally enforceable requirement established pursuant to Part 63. 

Subpart DDDDD – Industrial, Commercial, and Institutional Boilers and Process Heaters: This subpart, 

adopted by reference in Title 129, Chapter 28, Section 001.90, applies to certain boilers and process heaters that 

are located at major HAP sources (≥10 tons/year of individual HAP or ≥ 25 tons/year of combined HAPs). 

8.7 Visibility Protection 

Title 129, Chapter 43 incorporates 40 CFR 51.301 and Appendix Y of 40 CFR 51 by reference. It requires that 

BART analyses be submitted by sources determined to be subject to the requirement and establishes the 

construction permit as the mechanism for making the BART requirements federally enforceable. OPPD 

submitted a BART analysis for NCS Unit 1 on August 7, 2007. 

9.0 Discussion of Specific Permit Conditions 

General Condition V. 

General condition V. requires the low NOx Burners supported by an overfire air port system on Unit 1 to be 

operational and demonstrate compliance with the BART and BACT limitations as expeditiously as practicable, 

but no later than five years after the approval by EPA of the Regional Haze State Implementation Plan (SIP). 

Forty CFR Part 51, Section 51.302(c)(4)(iv) states: 
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“The plan [State Implementation Plan] must require that each existing stationary facility 

required to install and operate BART do so as expeditiously as practicable but in no case 

later than five years after plan approval.” 

Although the completion of the LNB/OFA project need not be completed until five years after the SIP approval, 

construction must commence on the project within 18 months of SIP approval in order for the Department to 

ensure that the project has undergone some progress in a reasonable timeframe. OPPD submitted additional 

timeline information regarding the time necessary to install the LNB/OFA to the Department on April 22, 2008. 

The Department will notify OPPD within 15 days of SIP approval that the approval has occurred. 

The requirements for EPA for approving SIP submissions are contained in the Clean Air Act, Section 110(k). 

Section 110(k)(1)(B) states that within 60 days of receipt of a State's plan or plan revision submission, but no 

later than 6 months after the date by which a State is required to submit the plan or revision, the Administrator 

must determine whether the minimum criteria for the plan have been met. If the Administrator does not inform 

the State of the determination within 6 months of receipt of the submission, the plan or revision is deemed to 

meet the minimum criteria. 

Section 110(k)(2) also states that within 12 months of a determination that a plan submission meets the 

minimum criteria, the Administrator must act on the plan, making a determination of full and partial 

approval/disapproval or conditional approval. 

No other general conditions have been altered for this permitting action. 

Specific Conditions

(A) Establishes a NOx emissions limit and Department determined BART control, low NOx Burners 

supported by an overfire air port system, for NCS Unit 1. The 30-day rolling emissions limit of 0.23 

lb/MMBtu must be complied with at all times including times of startup, shutdown, or malfunction. All 

malfunctions shall be addressed in accordance with Nebraska Title 129, Chapter 35. A discussion of 

how this limit was chosen can be found under the BART discussion located in this document. The NOx

emissions data is required to be collected in accordance with 40 CFR Part 75 for Acid Rain, which 

incorporates requirements the source is currently subject to. 

(B) Establishes a CO emissions limit and Department determined BACT control, combustion controls, for 

NCS Unit 1. The 30-day rolling emissions limit of 0.50 lb/MMBtu must be complied with at all times 

excluding startups and shutdowns. All malfunctions shall be addressed in accordance with Nebraska 

Title 129, Chapter 35. A discussion of how this limit was chosen can be found under the PSD 

discussion located in this document. 

(C) Requires that records be kept documenting all notifications, reports, test results, and plans submitted to 

the Department. The owner or operator is also required to maintain appropriate CEMS information, 

which is required in Conditions XIV.(A)(2)(d) and XIV.(B)(1)(c). These records must be maintained 

on-site for a minimum period of five (5) years and be clear and readily accessible to Department 

representatives. 

STATUTORY OR REGULATORY PROVISIONS ON WHICH PERMIT REQUIREMENTS ARE 

BASED:

Applicable regulations: Title 129 - Nebraska Air Quality Regulations as amended August 18, 2008. 
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PROCEDURES FOR FINAL DETERMINATION WITH RESPECT TO THE PROPOSED 

CONSTRUCTION PERMIT:

The public notice, as required under Title 129, NAQR Chapter 14, shall be published on December 12, 2008, in 

the Nebraska City News-Press newspaper. Persons or groups shall have 30 days from that issuance of public 

notice (January 10, 2009) to provide the NDEQ with any written comments concerning the proposed permit 

action and/or to request a public hearing, in accordance with NAQR Chapter 14. If a public hearing is granted 

by the Director, there will be a notice of that meeting published at least 30 days prior to the hearing. Persons 

having comments or requesting a public hearing may contact: 

W. Clark Smith-Permitting Section Supervisor 

Air Quality Division 

Nebraska Department of Environmental Quality 

PO Box 98922 

Lincoln, Nebraska 68509-8922 

If no public hearing is requested, the permit may be granted at the close of the 30-day comment period. If a 

public hearing is requested, the Director of the NDEQ may choose to extend the date on which the permit is to 

be granted until after that public hearing has been held. Additional public information is available on the 

agency’s website and by request at ndeq_records@nebraska.gov. During the 30-day comment period, persons 

requiring further information should contact: 

Beverly Kellison-Program Planning & Development Unit Supervisor 

Air Quality Division 

Nebraska Department of Environmental Quality 

PO Box 98922 

Lincoln, Nebraska 68509-8922 

Telephone inquiries may be made at:

 (402) 471-2189 

TDD users please call 711 and ask the relay operator to call us at (402) 471-2186.