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FACT SHEET

BART & PSD Analysis 

For the 

Nebraska Public Power District 

Gerald Gentleman Station 

6089 South Highway 25 

Sutherland, Nebraska 69165

May 11, 2010
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Table of Contents

Executive Summary.................................................................................................................................................................. 4

1.0 Introduction and Purpose ............................................................................................................................................ 4

1.1 Nebraska Regional Haze Program .......................................................................................................................... 4

1.2 Source Description and Permitting Background ..................................................................................................... 5

1.3 Gerald Gentleman Station BART Eligibility Analysis............................................................................................ 6

1.4 BART Analysis Methodology................................................................................................................................. 7

1.5 Consideration of Presumptive BART Limitations .................................................................................................. 8

1.6 Averaging Emission Limitations............................................................................................................................. 9

2.0 BART Analysis for Particulate Matter (both fine and coarse fractions)...................................................................... 9

2.1 Particulate Matter (PM) Formation......................................................................................................................... 9

2.2 BART for PM ....................................................................................................................................................... 10

3.0 BART Analysis for SO2 ............................................................................................................................................ 11

3.1 SO2 Formation ...................................................................................................................................................... 11

3.2 Identification of SO2 Control Technologies and Technical Feasibility................................................................. 11

3.2.1 Sulfur Removal from Fuel ................................................................................................................................ 11

3.2.2 Flue Gas Desulfurization (FGD)....................................................................................................................... 11

3.3 Ranking of Technologically Feasible SO2 Controls based on Effectiveness......................................................... 12

3.4 Evaluation of Effective SO2 Controls ................................................................................................................... 13

3.4.1 Cost of Compliance .......................................................................................................................................... 13

3.4.2 Energy Impacts ................................................................................................................................................. 14

3.4.3 Other (Non-Air Quality) Environmental Impacts ............................................................................................. 14

3.4.4 Remaining Useful Life...................................................................................................................................... 19

3.5 Visibility Impacts.................................................................................................................................................. 19

4.0 BART Analysis for NOx............................................................................................................................................ 20

4.1 NOx Formation...................................................................................................................................................... 20

4.2 Identification of NOx Control Technologies and Technical Feasibility ................................................................ 21

4.2.1 Combustion Controls........................................................................................................................................ 21

4.2.2 Post Combustion Control Technologies ........................................................................................................... 21

4.3 Ranking of Technologically Feasible NOx Controls based on Effectiveness........................................................ 22

4.4 Evaluation of Effective NOx Controls................................................................................................................... 22

4.4.1 Cost of Compliance .......................................................................................................................................... 22

4.4.2 Energy Impacts ................................................................................................................................................. 22

4.4.3 Non-Air Quality Environmental Impacts.......................................................................................................... 23

4.4.4 Remaining Useful Life...................................................................................................................................... 23

4.5 Visibility Impacts.................................................................................................................................................. 23

5.0 BART Determination for SO2 and NOx..................................................................................................................... 24

5.1 Comments & Response to Comments Received regarding BART............................................................................ 26

6.0 Prevention of Significant Deterioration (PSD).......................................................................................................... 43

6.1 Summary............................................................................................................................................................... 43

6.2 Best Available Control Technology (BACT) Analysis Methodology................................................................... 44

6.3 BACT Analysis for Carbon Monoxide (CO) ........................................................................................................ 44

6.4 Ranking of Technologically Feasible CO Controls based on Effectiveness ......................................................... 46

6.5 BACT for CO........................................................................................................................................................ 46

7.0 Air Dispersion Modeling Analysis ............................................................................................................................ 46

7.1 Model Information................................................................................................................................................ 47

7.1.1 Facility Location and Site Description ............................................................................................................. 47

7.1.2 Model Selection................................................................................................................................................ 47

7.1.3 Source Parameters ............................................................................................................................................ 47

7.2 Preliminary Modeling Analysis............................................................................................................................. 47

7.3 Additional Impacts Analysis ................................................................................................................................. 48

7.3.1 Pollutant Effects on Soil and Vegetation .......................................................................................................... 48

8.0 Type and Quantity of Air Contaminant Emissions Anticipated................................................................................. 48

9.0 Applicable Requirements, Variances or Alternatives to Required Standards............................................................ 49
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9.1 Nebraska State Construction Permit Requirements............................................................................................... 49

9.2 New Source Performance Standards (NSPS)........................................................................................................ 50

9.3 Particulate Matter Emissions................................................................................................................................. 50

9.4 Sulfur Compound Emissions................................................................................................................................. 51

9.5 Acid Rain .............................................................................................................................................................. 51

9.6 Hazardous Air Pollutants ...................................................................................................................................... 51

9.7 Visibility Protection.............................................................................................................................................. 52

10.0 Discussion of Specific Permit Conditions ................................................................................................................. 52
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Executive Summary 

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

(NPPD) Gerald Gentleman Station Units 1 and 2 as Best Available Retrofit Technology (BART) eligible and 

subject sources under the U.S. EPA Regional Haze Program. The Units at Gerald Gentleman Station were 

identified as either contributing or causing visibility impairment to Class I areas in South Dakota (Badlands and 

Wind Cave National Parks), Colorado (Rocky Mountain National Park), Oklahoma (Wichita Mountains 

National Wildlife Refuge), and Missouri (Mingo National Wildlife Refuge and Hercules Glades Wilderness 

Area). In August 2007, NPPD submitted a BART analysis and permit application to NDEQ. A new, revised 

analysis, was submitted in March 2008. Since the application of controls was 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 provides 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 overfire air technology as necessary to meet a limit of 0.23 lb/MMBtu. This analysis also concludes that BART is 

existing control equipment along with existing limits for particulates (0.1 lb/MMBtu) and that no additional SO2

controls are warranted due to other environmental impacts and the low benefit to cost ratio. 

1.0 Introduction and Purpose 

The Clean Air Act (CAA) Amendments 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 in 

which impairment results from manmade air pollution. In 1999, the United States Environmental Protection 

Agency (EPA) issued rules 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 rules 

require states to establish goals for improving visibility by developing long-term strategies for reducing 

emissions of air pollutants that cause or contribute to 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 program 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 rules, Nebraska has an obligation to address visibility protection through the application of Best Available 

Retrofit Technology (BART) on BART subject sources; and promote 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 the Central Regional Air Planning Association 

(CENRAP). Nebraska was asked, and participated in a central-states consultation process for Missouri and 

Oklahoma.1 No other states have asked Nebraska to participate in a collaborative consultation process. No 

states have yet 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 

 

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 at Class I areas 

in Missouri. 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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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 

application of BART is required, the BART decisions (i.e. the BART permits) will be explicitly included in 

Nebraska’s Regional Haze SIP. 

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

Gerald Gentleman Station (GGS), Units 1 and 2. This analysis indicated that Units 1 and 2 would be capable of 

attaining presumptive BART emissions limitations with the operation of the recently-installed low NOx burners 

and over-fire air on Unit 1 and with the proposed addition of low NOx burners and over-fire air on Unit 2. A 

revised BART analysis was provided to NDEQ by NPPD on March 3, 2008. 

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 result from the installation of the BART 

controls. To make the BART limitations enforceable, the NDEQ incorporated the BART requirements in a 

construction permit. The NDEQ has evaluated the following visibility impairing pollutants for purposes of 

BART: PM (both fine and coarse fractions), SO2, and NOx. 

This fact sheet provides a summary of information submitted by NPPD and provides the basis for the 

Department’s permit decision based on such information and applicable law and regulations. Detailed 

information can be found in the revised BART analysis received by the Department on March 3, 2008, and 

subsequent submittals. 

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.” NPPD is Nebraska’s largest electric utility, serving part or all of 91 of Nebraska’s 93 counties. 

It was organized as a political subdivision of the State of Nebraska in 1970. Policies and rates are set by an 

eleven-member Board of Directors elected by the people in the areas served. NPPD provides wholesale power 

to 52 towns and 25 public power districts, as well as providing retail power to about 80 communities. In all, 

about 1 million Nebraskans rely on NPPD to supply electricity. 

NPPD owns and operates Gerald Gentleman Station (GGS) which is located near Sutherland, Lincoln County, 

Nebraska, approximately thirty (30) kilometers west of North Platte, Nebraska. The station consists of two 

pulverized coal-fired boilers that are referred to as Unit 1 and Unit 2. Both units combust sub-bituminous coal 

with a typical heat content of 8,400 Btu/lb. Construction of the station began in 1973. Unit 1 went into 

commercial service in 1979 and Unit 2 went into service in 1982. GGS is currently a major source of air 

emissions under both the Prevention of Significant Deterioration (PSD) program and the Title V operating 

permits program. Its Standard Industrial Classification (SIC) code is 4911 and North American Industry 

Classification System (NAICS) code is 221112 for fossil fueled electric generators. 

On September 16, 1974 the Department issued an Order (case # 24) to NPPD allowing the construction of 

Unit 1. Because this boiler pre-dated the PSD program, a PSD construction permit was not issued. On 

February 9, 1977 the United States Environmental Protection Agency issued a PSD permit to NPPD for 

construction of Unit 2. As stated in the PSD permit, Best Available Control Technology (BACT) was 
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determined to be those limits established in New Source Performance Standard (NSPS) Subpart D. The 

Department issued an Order (case # 201) to NPPD on March 22, 1977 allowing the construction of Unit 2. The 

orders issued to NPPD (case # 24 and 201) were modified on February 28, 1979, February 20, 1981, March 12, 

1981, March 18, 1985, and April 1, 1985. These Orders and Modified Orders dealt mainly with the 

construction of the two units. 

GGS is currently operating under a Class I operating permit issued on August 26, 2002, and a Phase II Acid 

Rain permit effective January 26, 2005. An operating permit renewal application was received by the 

Department on February 26, 2007. 

On January 4, 2006, the Department received a PSD Construction Permit application for the replacement of 

Unit 1’s burner equipment system including an overfire air port system. NPPD installed new Low NOx Burners 

(LNB) on Unit 1 because the existing burners were near the end of their useful life and to be pro-active in 

installing expected Best Available Retrofit Technology (BART) controls. A PSD construction permit was 

issued to GGS for the installation of the LNB on Unit 1 on August 18, 2006. A PSD permit was required for 

the modification due to the expected increase in carbon monoxide emissions as a result of the LNB installation. 

The August 18, 2006, permit will be superseded as a result of this permitting action once Unit 2 BART controls 

are operational and Units 1 and 2 demonstrate compliance with the NOx limits. Condition V of the permit 

establishes a timeframe for achieving this demonstration. Until such time, the CO BACT limits and other 

conditions of the August 18, 2006 permit remain in effect. Additionally, both Units 1 and 2 will be required to 

have CO CEMs installed to demonstrate compliance with BACT. 

1.3 Gerald Gentleman Station BART Eligibility Analysis 

Gerald Gentleman Station Units 1 and 2 were 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. 

 GGS is a fossil-fuel fired steam electric plant of more than 250 MMBtu/hr. Both Units 1 and 

2 are each rated at approximately 7,538 MMBtu/hr. Therefore the total heat input capacity at 

the facility is 15,076 MMBtu/hr. 

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

 In existence means “the owner or operator obtained all necessary approvals/permits and has 

either begun, or caused to begin on-site construction of the facility, or executed binding 

agreements/contracts for construction.” 

 Unit 1 was approved in 1974 and began construction in 1973. Commercial operation began in 

1979. 

 Unit 2 was permitted/approved by March 1977 and began construction in June 1977.2 

Commercial operation began in 1982. 

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. 

 Table 1 presents the baseline actual 24-hour maximum emissions and equivalent maximum 

annual (365 days of operation at the maximum actual 24-hour rate) emissions from the 

source prior to requiring BART controls. This shows that the potential emissions from 

 

2

 Per Brochure on Gerald Gentleman Station found on NPPD’s GGS website at: 

http://www.nppd.com/About_Us/Energy_Facilities/facilities/ggs.asp
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both units (based on maximum 24-hour actual emissions) of particulate matter (coarse and 

fine), nitrogen oxides (NOx), and sulfur dioxide (SO2), all visibility impairing pollutants, 

are greater than 250 tons/year for each pollutant. 

Since all of the three criteria presented above were met, GGS Units 1 and 2 were considered to be BART eligible. 

In order to determine if GGS Units 1 and 2 are 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 deciview (a measurement of 

visibility impairment based on extinction of light), then the unit becomes subject to BART. 

NPPD 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: GGS Units 1 and 2 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 

6,688 1,221.4 1,170 213.7 272,795 49,785 165,716 30,263.9 

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” link under the “Focus on Air” link. The refined 

CALPUFF modeling analysis concluded that the Pre-BART emissions from GGS Units 1 and 2, before 

requiring BART controls, cause or contribute to visibility impairment (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, GGS Units 1 and 2 were determined to be 

subject to BART requirements. 

Table 2: GGS 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) 54 2.845 55 2.828 60 3.121 

Great Sand Dunes (CO) 3 0.295 6 0.48 6 0.42 

Hercules Glades (MO) 24 0.826 10 0.616 11 0.594 

Mingo (MO) 10 0.615 5 0.432 5 0.438 

Rocky Mountain (CO) 13 1.136 16 1.246 13 1.053 

Wichita Mountains (OK) 28 1.032 27 1.206 29 1.392 

Wind Cave (SD) 34 2.452 33 2.591 41 2.217 

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 
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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. Therefore Appendix Y has been followed when making the BART 

determination for GGS in accordance with federal and state regulations. 

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 

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 impact on visibility for 

each control alternative. Appendix Y states that the visibility improvement for the source as part of the BART 

determination “must be weighed among the five factors, and you [the state] are free to determine the weight and 

the significance assigned to each factor.” 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 
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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. 

The preamble to the final rule also states {70 FR pg. 39131} “Although we believe that these requirements 

[presumptive BART levels] are extremely likely to be appropriate for all greater than 750 MW power plants 

subject to BART, a State may establish different requirements based on a consideration of the five statutory 

factors.” 

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. Based on the 

controlling Appendix Y language and preamble guidance, the State of Nebraska will consider the five statutory 

factors when establishing BART controls and may not require the presumptive BART limitations if an 

alternative level of control is justified. 

1.6 Averaging Emission Limitations 

Appendix Y allows averaging of emissions across any set of BART emission units within a fence line. 

Appendix Y states, “You [the state] should consider allowing sources to ‘‘average’’ emissions across any set of 

BART-eligible emission units within a fence line, so long as the emission reductions from each pollutant being 

controlled for BART would be equal to those reductions that would be obtained by simply controlling each of 

the BART-eligible units that constitute BART-eligible source” {40 CFR Appendix Y, V. Enforceable 

Limits/Compliance Date} 

 

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 GGS Units 1 and 2. 

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 

pulverized coal, PM emissions are primarily composed of inorganic ash residue because combustion is nearly 

complete, resulting in minimal unburned carbon. 

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

the exhaust stream as a solid or liquid, 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. 
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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. GGS Units 1 and 2 currently utilize fabric filters 

(baghouses) to control PM emissions. 

Step 2: Eliminate technically infeasible options: 

Additional baghouses could be added, but would be redundant. 

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 GGS, then further evaluation of control technology would not be warranted at this time. 

The maximum 24-hour emission rates of PMF and PMC from GGS Units 1 and 2 are presented below. These 

baseline 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 

6,688 1,221.4 1,170 213.7 

The baseline case model indicated that the direct particulate emissions (PMF + PMC) were responsible for well 

under 1% of the total predicted change in deciview impact from GGS Units 1 and 2 (See Table 4). A deciview 

is a haze index derived from calculated light extinction, such that uniform changes in haziness correspond to 

uniform incremental changes in perception across the entire range of conditions, from pristine to impaired. 

This would indicate that the predicted deciview impact is from a pollutant or pollutants other than PM, 

specifically NOx and/or SO2. 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 GGS Units 1 and 2 are subject to 

BART due to their deciview impact, but the direct particulate matter emissions do not significantly contribute 

to visibility impairment in the Class I areas analyzed. 

Table 4: Particulate Matter Contribution of GGS Predicted Visibility Impairment 

2001 2002 2003 

dV % PM 

PM 

dV 

impact 

dV % PM 

PM 

dV 

impact 

dV % PM 

PM 

dV 

impact 

Badlands (SD) 2.845 0.66% 0.0188 2.828 0.47% 0.0133 3.121 0.69% 0.0215 

Great Sand Dunes 

(CO) 0.295 0.56% 0.0017 0.480 0.26% 0.0012 0.420 0.27% 0.0011 

Hercules Glades 

(MO) 0.826 0.33% 0.0027 0.616 0.43% 0.0026 0.594 0.40% 0.0024 

Mingo (MO) 0.615 0.19% 0.0012 0.432 0.22% 0.0095 0.438 0.36% 0.0016 

Rocky Mtn (CO) 1.136 0.48% 0.0055 1.246 0.42% 0.0052 1.053 0.22% 0.0023 

Wichita Mtns (OK) 1.032 0.58% 0.0060 1.206 0.48% 0.0058 1.392 0.43% 0.0060 

Wind Cave (SD) 2.452 0.67% 0.0164 2.591 0.68% 0.0176 2.127 0.41% 0.0087 
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Based on the fact that GGS Units 1 & 2 are currently adequately controlled by baghouses, are subject to an 

emissions limitation of 0.1 lb/MMBtu (Title V OP), and the modeling results indicate 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 GGS Units 1 and 2. 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 pyritic sulfur in the coal during the combustion 

process. The majority of sulfur is oxidized to SO2; however a small quantity is further oxidized to form sulfur 

trioxide (SO3). Approximately 90% of the sulfur present in the subbituminous coal will be emitted as SOx

compounds. Alkaline ash from some coals (including 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 or bottom 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. NPPD uses PRB coal at GGS. Since this technology has not been demonstrated and it would not 

be cost effective to attempt a form of physical cleaning or chemical desulfurization, coal sulfur removal is 

considered to be 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 

(such as eastern bituminous coal), removal efficiencies of over 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 

might be cost effective. Potential regenerative processes include the Wellman-Lord (W-L) process, magnesium 
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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 for 

long enough periods to allow estimates of annualized costs. Therefore, it is not possible to demonstrate cost 

effectiveness for a regenerative process on GGS 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, due to the rural and remote location of GGS, there is 

little local demand for it near GGS, so NPPD could not take advantage of the cost offset. However, wet 

scrubbing is a feasible technology for SO2 control from GGS Units 1 and 2. 

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. If NPPD would be required to install dry FGD, 

the existing baghouses would require significant augmentation. However, dry scrubbing is a feasible 

technology for SO2 control from GGS Units 1 and 2. 

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 

uncontrolled baseline emission rate of GGS Units 1 and 2. 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 on a consistent basis. 
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Based on the maximum actual 24-hr SO2 emissions over a three year baseline period (2001-2003) of 0.749 

lb/MMBtu, together with assumed continuous, maximum operation at 15,175.5 MMBtu/hr, the potential 

maximum annual emissions would be equal to 49,785 tons/year. At the presumptive BART level (0.15 

lb/MMBtu) it is estimated that up to 39,815 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 up to 43,138 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 

In order to evaluate the effectiveness of the SO2 control options, NDEQ considered: cost of compliance, energy 

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

3.4.1 Cost of Compliance 

NPPD provided detailed cost information associated with the installation of both a wet FGD and a dry FGD 

system. The costs utilized in the analyses were based on a site-specific engineering analysis of how much it 

would cost to retrofit GGS. NPPD used vendor quotes for the majority of the analysis. This approach is 

allowed by Appendix Y and supplements the guidance contained in the EPA’s OAQPS Control Cost Manual. 

Appendix Y states that in evaluating cost effectiveness, both the average cost effectiveness (total annualized 

costs of control divided by annual emissions reductions) and incremental cost effectiveness (dollars per 

incremental ton) should be evaluated. 

The evaluated costs associated with wet FGD installation included, but are not limited to, installing a wet 

limestone forced oxidation FGD system on both Units 1 & 2, Units 1 & 2 common equipment (reagent 

preparation and handling, solids dewatering and handling), auxiliary power system, ID Booster fan equipment, 

and operating costs. Detailed information may be found in the supporting materials provided by NPPD. 

The total annualized cost associated with the installation of Wet FGD at GGS is $108,450,000. The average 

cost effectiveness of this control technology is $2,724 per ton SO2 removed ($108,450,000 / 39,815 tons SO2

removed) based on an emissions rate of 0.15 lb/MMBtu. The average cost effectiveness of this control 

technology at an emissions rate of 0.1 lb/MMBtu is approximately $2,514 per ton SO2 removed 

($108,450,000/43,138 tons SO2 removed). The annualized cost for this alternative may be slightly higher than 

stated here, due to slightly more reagent usage as compared to the 0.15 lb/MMBtu control level. 

The costs evaluated associated with dry FGD installation included, but are not limited to, installing a spray 

dryer absorber FGD system on both Units 1 & 2, Units 1 & 2 common equipment (reagent preparation and 

handling, solids dewatering and handling), auxiliary power system, ID Booster fan equipment, and operating 

costs. The total annualized cost associated with the installation of Dry FGD is $108,517,000. The cost 

effectiveness of this control technology is $2,726 per ton SO2 removed ($108,517,000 / 39,815 tons SO2

removed) based on an emissions rate of 0.15 lb/MMBtu. The average cost effectiveness of this control 

technology at an emissions rate of 0.1 lb/MMBtu is approximately $2,516 per ton SO2 removed 

($108,517,000/43,138 tons SO2 removed). As with wet FGD, meeting the lower emission rate may cost slightly 

more than stated here due to higher reagent usage. 

The cost per ton removal estimated is in line with what EPA estimated for GGS. Since additional control 

options are not feasible, analyzing the incremental cost effectiveness for SO2 controls is not necessary. 
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3.4.2 Energy Impacts 

If Wet FDG was employed, 2.7% (36 MW) of the units’ generating capacity would be utilized to operate the 

control equipment. Thirty-six megawatts is equivalent to the power utilized by approximately 36,000 homes. 

If Dry FDG was employed, 1.9% (26 MW) of the units’ generating capacity would be utilized to operate the 

control equipment. Twenty-six megawatts is equivalent to the power utilized by approximately 26,000 homes. 

The energy costs were included in the BART analysis costs above. 

3.4.3 Other (Non-Air Quality) Environmental Impacts 

Non-air quality environmental impacts associated with the installation of a Wet FGD include disposal of a solid 

waste in the form of gypsum and a liquid waste stream which must be disposed of via an evaporator system or 

in a disposal pond. O&M costs for wet FGD waste disposal were included in the cost analysis, but given 

uncertainties in costs, capital costs for permitting, possible land acquisition, and construction of pond and 

landfill disposal units were not included in the BART cost analysis at this time, making the cost estimates 

conservatively low. 

Non-air quality environmental impacts associated with the installation of a Dry FGD include disposal of solid 

waste in the form of fly ash. The fly ash will be intermixed with lime and be unsuitable for third party use and 

will have to be landfilled, or otherwise appropriately disposed. In 2008, NPPD marketed over 75,000 tons of 

fly ash from GGS. O&M costs for dry FGD waste disposal were included in the cost analysis, but given 

uncertainties in costs; capital costs for permitting, possible land acquisition, and construction of a separate 

landfill disposal unit were not included in the BART cost analysis at this time, making the cost estimates 

conservatively low. 

A significant non-air quality environmental impact for NPPD, if either control technology is required, regards 

water use and impacts on the habitats of endangered species. 

3.4.3.1 Potential Impacts on Water 

In 2004, the Nebraska Legislature enacted LB 962, which went into effect in July 2004. This law required the 

Department of Natural Resources (DNR) to identify geographic areas where surface water and ground water are 

hydrologically connected. The law was designed to manage water resources through the identification of river 

basins where water resources were already fully-appropriated and other areas where the basins were overappropriated. Once a river basin has been designated, each Natural Resource District (NRD) must work in 

conjunction with the Nebraska DNR to develop an Integrated Management Plan (IMP) to either make certain 

the basin does not become over-appropriated or recharge the water resources in a manner such that the basin is 

no longer over-appropriated. The concept is analogous to the air quality state implementation planning process 

for non-attainment or attainment areas. The development of the basin IMP may take three to five years. The 

GGS Station is located within the Twin Platte NRD area. Below are maps detailing the relationship between 

the surface water and ground water in the area, the areas that have been identified as being fully-appropriated or 

over-appropriated, and the areas within the Twin Platte NRD that are currently under a stay for the construction 

of new high capacity (> 50 gallons/min) water wells and increasing irrigated acres (effective June 18, 2007). 
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It is clear from these maps that GGS is located in the affected areas. Both scrubbing technologies require a 

significant amount of consumptive water use in order to operate. A wet FGD would require approximately 

1,200 gallons/min and a dry FGD would require 1,000 gallons/min for each unit to operate. Being that GGS is 

located in an area currently designated as over-appropriated for water usage by the Twin Platte NRD, it would 

be difficult to acquire the water rights necessary to operate either type of control and the costs would be 

substantial. The cost estimates below are provided in 2009 actual dollars. 

Wet FGD

If wet FGD systems were installed on both units, the estimated consumption of 2,400 gallons/min would require 

approximately 3,881 acre feet of water per year. Retiring irrigated corn ground would offset about 12 inches of 

water per acre, or 1 acre foot/acre, resulting in the need to acquire 3,881 acres. In order to obtain the acres 

needed, rights would have to be acquired for parcels of land somewhat larger than the actual irrigated acres, so 

it is assumed that 4,000 acres would be needed. Cost estimates to purchase irrigated crop ground in the North 

Platte area are based on recent purchases and appraisals. For this analysis, $3,000 per acre is the price assumed 

for purchasing irrigated land. The total cost for acquiring 4,000 acres of land at $3,000 per acre would be $12 

million. 

An impact to the local area would be the lost crop production from the land. Based on a 200 bushel/acre loss in 

corn production and assuming a price of $4 per bushel, the impact would be about $3.2 million per year, or $64 

million over 20 years. This is assuming no escalation in corn prices over the next 20 years. 

Loss of property tax revenue would also impact the county. If NPPD were to purchase 3,881 acres, taxes would 

be reduced by an estimated $100,000 per year or $2 million over 20 years. This is assuming no escalation in 

taxes over the next 20 years. 

Dry FGD

If dry FGD systems were installed on both units, the estimated consumption of 2,000 gallons/min would require 

approximately 3,226 acre feet of water or offset from 3,226 acres per year. In order to obtain the acres needed, 

rights would have to be acquired for parcels of land somewhat larger than the actual irrigated acres. Assuming 

that 3,300 irrigated acres would need to be purchased at $3,000 per acre, the total cost would be $9.9 million. 

Lost crop production from the land would be about $2.6 million per year, or $52.8 million over 20 years, 

assuming a price of $4 per bushel. This is assuming no escalation in corn prices over the next 20 years. 

Loss of property tax revenue would also impact the county. If NPPD were to purchase 3,300 acres, taxes would 

be reduced by an estimated $82,500 per year or $1.7 million over 20 years. This is assuming no escalation in 

taxes over the next 20 years. 

3.4.3.2 Potential Impacts to Endangered Species: 

In July 1997, the State of Nebraska entered into an agreement with neighboring states, Colorado and Wyoming, 

and the Department of Interior to conduct research and other efforts related to the habitats of threatened and 

endangered species within the Platte Rivers area. This agreement was recently succeeded with another 

cooperative agreement in October 2006 called “The Platte River Recovery Implementation Program.”3 The 

purpose of this second cooperative agreement is to implement certain aspects of the U.S. Fish and Wildlife 

Service’s (FWS’) recovery plans for the target species, including the Piping Plover, Whooping Crane, Least 

Tern, and Pallid Sturgeon. The program involves basin-wide cooperative approaches including, but not limited 

 

3 More information about the Platte River Recovery Implementation Program may be found at: 

http://platteriverprogram.org/default.aspx. 
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to mitigating adverse impacts of new water related activities. New water related activities are those new 

surface water or hydrologically connected groundwater activities, implemented after July 1, 1997, which may 

affect the quantity or timing of water reaching the associated habitats. Drilling of new water wells for purposes 

of consumptive use, such as those needed for FGD, appear to be a new water related activity. The NDEQ has 

considered the potential non-air quality environmental impacts and the importance of protecting the habitats of 

endangered and threatened species along the Platte River Basin in its decision whether to require FGD. Any 

costs associated with mitigating or offsetting additional GGS water use to protect threatened and endangered 

species are unknown at this time, and therefore have not been factored into the BART analysis. 

3.4.4 Remaining Useful Life 

The useful remaining life of GGS Units 1 and 2 is greater than 20 years under the current NPPD energy 

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

technology cost at this time. 

3.5 Visibility Impacts 

Air dispersion modeling using CALPUFF was conducted to determine the impact on visibility from GGS Units 

1 and 2 at several Class I areas. The highest impacts were observed at Badlands in South Dakota. The second 

highest were in Wind Cave in South Dakota, which is just west of the Badlands. Badlands is the Class I area 

closest to GGS at approximately 300 km. Improvements seen at the Badlands are expected to be seen at Wind 

Cave as well. 40 CFR Appendix Y says that if the highest modeled effects are at the nearest Class I area, states 

may choose not to analyze the other Class I areas any further. Additional analyses beyond the Badlands are 

unwarranted because controls on the GGS Units 1 and 2 will not likely exhibit greater visibility improvement 

than what is predicted in the Badlands. Furthermore, model accuracy is highly uncertain at distances greater 

than 200 km. Table 5 shows the modeled incremental visibility effectiveness of SO2 control options, based on 

the estimated impacts at the Badlands. 

Included in the analysis is an evaluation of putting the control cost into perspective as they relate to visibility 

impairment. Two metrics were used, cost per deciview of improvement ($/yr/dV) and cost per days of deciview 

improvement. 
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Table 5: Incremental Visibility Effectiveness (SO2 Controls) 

 2001 2002 2003 

Control 

Option Class I Area with Greatest Impact from GGS Badlands Badlands Badlands 

SO2 Modeled Emission Rate (lb/MMBtu) 0.749 0.749 0.749 

Modeled 98th Percentile Value (dV) 2.845 2.828 3.121 

Baseline 

(no SO2

Control) 

Number of Days Exceeding 0.5 dV 54 55 60 

Modeled 98th Percentile Value (dV) 1.836 2.125 2.478 

Incremental Visibility Impairment Improvement (∆dV) 1.009 0.703 0.643 

Number of Days Exceeding 0.5 dV 36 35 39 

Incremental Impairment Improvement Cost ($/yr/∆dV)[1] $107,482,656 $154,267,425 $168,662,519

FGD Control Added 

(0.15 lb/MMBtu) 

Incremental Cost per Day of Improvement $6,025,000 $5,422,500 $5,164,286 

Modeled 98th Percentile Value (dV) 1.790 2.026 2.443 

Incremental Visibility Impairment Improvement (∆dV) 1.055 0.802 0.678 

Number of Days Exceeding 0.5 dV 33 33 36 

Incremental Impairment Improvement Cost ($/yr/∆dV)[1] $102,796,208 $135,224,439 $160,428,994

FGD Control Added 

(0.10 lb/MMBtu) 

Incremental Cost per Day of Improvement $5,164,286 $4,929,545 $4,518,750 

[1]Total annualized cost / Incremental visibility impairment improvement 

4.0 BART Analysis for NOx

The objective of this analysis is to determine BART for NOx emissions from GGS Units 1 and 2. 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
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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. GGS Unit 1 was recently permitted to install LNB/OFA. This project has been completed; 

however a lower NOx limit was not required by that permitting action. Combustion controls are able to be used 

on industrial and utility boilers and are considered to be feasible technologies for NOx control from GGS Units 

1 and 2. 

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 GGS Units 1 

and 2. 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 

amount of catalyst required would be higher, subjecting more catalyst to degradation. The amount of ammonia 

required would also be higher, increasing the capital and O&M costs of SCR significantly. Also, reagent costs 

would be significantly higher if LNB/OFA were not used to minimize NOx emissions before treatment with the 

SCR system. 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 

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 

GGS Units 1 and 2. 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. 
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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 GGS Units 1 and 2. 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. 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 30,243 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 reduction of 14,956 tons/year of NOx emissions would be realized. If SCR and LNB/OFA 

was installed, an emissions limitation of 0.08 lb/MMBtu would be established, equating to 24,926 tons/year of 

NOx reductions from GGS Units 1 and 2. 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. 

4.4.1 Cost of Compliance 

NPPD provided detailed site-specific cost information associated with the installation of LNB/OFA with and 

without the installation of an SCR system. The costs utilized in the analyses were based on site-specific 

engineering analysis (based mainly upon data supplied by equipment vendors) of how much it would cost to 

retrofit GGS. This approach is allowed by 40 CFR Appendix Y and supplements the guidance contained in the 

EPA’s OAQPS Control Cost Manual. Appendix Y states that in evaluating cost effectiveness, both the average 

cost effectiveness and incremental cost effectiveness should be evaluated. 

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 $2,960,000. The cost effectiveness of 

LNB/OFA is $198 per ton NOx removed ($2,960,000 / 14,956 tons NOx removed). 

The total annualized cost associated with the installation of LNB/OFA and SCR is $57,251,000. The cost 

effectiveness of LNB/OFA and SCR is $2,297 per ton NOx removed ($57,251,000 / 24,926 tons NOx removed). 

The incremental cost effectiveness calculation compares the costs and performance level of a control option to 

those of the next most stringent option. The incremental cost analysis of installing LNB/OFA and SCR as 

opposed to LNB/OFA alone is $5,445 ([$57,251,000 - $2,960,000] / [24,926 – 14,956]). 

4.4.2 Energy Impacts 

There is no significant energy penalty associated with the use of modern LNB/OFA. 
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If SCR was employed, 0.7% (10 MW) of the units’ generating capacity would be utilized to operate the control 

equipment. Ten megawatts is equivalent to the power utilized by approximately 10,000 homes. The energy 

impacts have been included in the BART analysis costs. 

4.4.3 Non-Air Quality Environmental Impacts 

There are no non-air quality related impacts associated with the use of modern LNB/OFA. 

Non-air quality environmental impacts associated with the installation of an SCR include disposal of solid 

waste in the form of fly ash. The fly ash will be intermixed with ammonia and be unsuitable for third party use 

and would have to be landfilled. The potential risk of a hazardous spill due to transport and storage of ammonia 

would also be created if an SCR was installed. 

4.4.4 Remaining Useful Life 

The useful remaining lives of GGS Units 1 and 2 are greater than 20 years under the current NPPD energy 

resource plan. Therefore the remaining useful life has no impact of the annualized estimated control technology 

cost at this time. 

4.5 Visibility Impacts 

Air dispersion modeling using CALPUFF was conducted to determine the impact on visibility from GGS Units 

1 and 2 at several Class I areas (See Table 6). The highest impacts were observed at Badlands in South Dakota. 

The second highest were in Wind Cave in South Dakota, which is adjacent to the Badlands. Badlands is the 

Class I area closest to GGS at approximately 300 km. Improvements seen at the Badlands are expected to be 

seen at Wind Cave as well. 40 CFR Appendix Y says that if the highest modeled effects are at the nearest Class 

I area, states may choose not to analyze the other Class I areas any further. Additional analyses beyond the 

Badlands are unwarranted because controls on the GGS Units 1 and 2 will most likely not exhibit greater 

visibility improvement than what is predicted in the Badlands. Furthermore, model performance is highly 

uncertain at distances greater than 200 km. 
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Table 6: Incremental Visibility Effectiveness (NOx Controls) 

 2001 2002 2003 

Control 

Option Class I Area with Greatest Impact from GGS Badlands Badlands Badlands 

Modeled 98th Percentile Value (dV) 2.845 2.828 3.121 

Baseline 

0.458 lb 

/MMBtu 

Number of Days Exceeding 0.5 dV 54 55 60 

Modeled 98th Percentile Value (dV) 2.224 2.162 2.419 

Incremental Visibility Impairment Improvement (∆dV) 0.621 0.666 0.702 

Number of Days Exceeding 0.5 dV 49 52 54 

Incremental Impairment Improvement Cost ($/yr/∆dV)[1] $4,766,506 $4,444,444 $4,216,524 

LNB/OFA Control Added 

(0.23 lb/MMBtu) 

Incremental Cost per Day of Improvement $592,000 $986,667 $493,333 

Modeled 98th Percentile Value (dV) 1.732 1.728 1.879 

Incremental Visibility Impairment Improvement (∆dV) 0.492 0.434 0.540 

Number of Days Exceeding 0.5 dV 44 41 48 

Incremental Impairment Improvement Cost ($/yr/∆dV)[1] $110,347,561 $125,094,470 $100,538,889

LNB/OFA and SCR 

Controls Added (0.08 

lb/MMBtu) 

Incremental Cost per Day of Improvement $10,858,200 $4,935,545 $9,048,500 

[1]Total annualized cost / Incremental visibility impairment improvement 

5.0 BART Determination for SO2 and NOx

Scrubber technology is a technically feasible SO2 retrofit technology that could be implemented on GGS Units 

1 and 2. Not taking the other environmental effects, except energy, into account, the average cost effectiveness 

of using scrubbing control technology is approximately $2,500 – $2,700 per ton SO2 removed. The cost per ton 

removed seems reasonable. When evaluating the cost effectiveness in terms of the visibility benefit derived 

from scrubbing, the NDEQ assessed the average incremental visibility impairment improvement. The NDEQ 

also calculated the incremental cost per day of visibility improvement. 

Over the three years of meteorology modeled, at 0.10 lb SO2/MMBtu, the average incremental visibility 

impairment improvement cost is $132,816,547 per year per change in deciview impact. The average number of 

days the Badlands would expect to experience a contribution from GGS of greater than 0.5 dV would be 22 per 

year. This is a 39% reduction in the 56 days per year that the units contribute more than 0.5 dV. The average 

incremental cost per day of visibility improvement calculates to be $4,870,860 per day ($2,435,430 per unit). 

Again, these values do not account for the added costs that would be incurred from other environmental 

impacts, except energy. These values are of the same magnitude as the OPPD Nebraska City Unit #1 BART 
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evaluation. There, NDEQ determined that additional SO2 controls were not reasonable, in part due to the 

excessive cost per benefit in terms of visibility improvement (i.e., $/yr/dV). 

Here in the case of NPPD GGS Units #1 and #2, NDEQ has serious concerns over the current availability of 

water to supply the scrubber and the potential affects the depletion of water on threatened and endangered 

species in the Platte River Valley area. Since the incremental visibility impairment improvement cost is so 

large compared to similar improvements in visibility using LNB/OFA technology and most importantly, the 

potential for other serious environmental impacts, the NDEQ has determined that it is inappropriate to require 

the installation of SO2 scrubbing technology as BART at this time. NPPD shall instead continue to utilize low 

sulfur coal. However, additional SO2 controls may be required in the future for purposes of “reasonable further 

progress.” At that time, available control technologies would be evaluated, as well as water availability, 

whether water availability can reasonably be resolved, and the ability to mitigate potential threats to endangered 

species in the Platte River Valley area. 

LNB/OFA technology is a feasible NOx retrofit technology that could be implemented on GGS Units 1 and 2. 

The average cost effectiveness of this control technology is $198 per ton NOx removed. Over the three years of 

meteorology modeled, the average incremental visibility impairment improvement cost is $4,475,825 per year 

per change in deciview impact. 

Utilizing SCR technology is also feasible only if LNB/OFA is utilized. The incremental cost effectiveness 

(incremental cost SCR) is $5,445 per ton NOx removed, over 25 times the amount of LNB/OFA alone. Over the 

three years of meteorology modeled, the incremental visibility impairment improvement cost of adding SCR is 

$111,993,640 per year per change in deciview impact. The average incremental improvement in visibility for 

the addition of SCR is less than 0.5 dV and improvement would be seen on an average of 7.3 days per year. 

The NDEQ determined that the incremental cost for the addition of SCR is excessive and that LNB/OFA would 

be required for BART. 

Therefore BART for GGS Units #1 and #2 shall be the installation of LNB/OFA with an emission limitation of 

0.23 lb NOx/MMBtu. 
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Table 7: BART Determination Comparison Summary 

BART Proposal EPA Presumptive 

NOx Control Technology LNB/OFA LNB/OFA 

NOx Emission Limitation 0.23 lb/MMBtu 0.23 lb/MMBtu 

SO2 Control Technology Low sulfur coal FGD 

SO2 Emission Limitation Acid Rain limits 0.15 lb/MMBtu 

Ave # of Days/Yr of 

Improvement to below 

0.5 dV 

5 20 

Annualized Cost $2,960,000 $111,410,000 

 Ave. Incremental 

Visibility Impairment 

Improvement (∆dV) 

0.663 1.775 

Ave. Incremental 

Impairment Improvement 

Cost ($/yr/∆dV) 

$4,475,825 $62,766,197 

Ave. Increment Cost per 

Day of Improvement $592,000 $5,570,500 

5.1 Comments & Response to Comments Received regarding BART 

The draft permit and materials were made available on the NDEQ website. Nearby states with Class I areas, 

federal land managers, EPA Region 7 and other interested parties were notified of the availability of the draft 

permit. 

 

The following individuals submitted written comments: 

• Paul Tourangeau, Director of the Air Pollution Control Division for the Colorado Department of Public 

Health and Environment (CDPHE) submitted comments on June 23, 2009. 

• John Bunyak Chief of the Policy, Planning and Permit Review Branch for the National Park Service in 

Denver, CO submitted comments in his capacity as a Federal Land Manager (FLM) on June 24, 2009. 

• Becky Weber, Division Director of the Air & Waste Management Division of the U.S. Environmental 

Protection Agency Region VII (EPA R7) Office in Kansas City, KS submitted comments on June 26, 

2009. 

No other comments were received. A summary of the comments as well as the NDEQ responses are provided 

below and in a separate Responsiveness Summary document. Where appropriate, similar comments from 

different persons were consolidated and summarized. The responses to the comments serve to complete the 

public record on the decision to issue the permit. Only where noted were changes made to the permit. 
NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

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COMMENT #1: 

The Colorado Department of Public Health and Environment (CDPHE) suggested that NDEQ closely evaluate the 

costs for dry flue gas desulfurization (FGD) to determine whether economies of scale were taken into account and 

whether EPA may have any recent information on the actual versus projected costs of retrofitting units like those at 

GGS with dry FGD. CDPHE still recognized that the costs identified in the public notice materials were 

considered to be sensible. 

RESPONSE AND RATIONALE: 

NDEQ has closely evaluated the cost estimates provided by NPPD and discussed the on-site modifications that 

would be necessary in order to physically accommodate the retrofits described. Much of the information used 

to develop the cost estimates was based upon vendor information. NPPD does not benefit from economies of 

scale that some companies across the country can, because NPPD has just the two units in western NE subject 

to BART evaluation. Wherever appropriate, costs and benefits for controlling both units were considered. 

NDEQ could not locate any actual cost information on retrofitting a system similar to GGS.

COMMENT #2: 

The CDPHE expressed concern over their ability to meet visibility improvement goals for Rocky Mountain 

National Park. They pointed NDEQ to a website where baseline, modeling projections and source 

apportionment information could be found. The CDPHE noted that the modeling conducted shows the Central 

Regional Air Partnership (CENRAP) states predicted to be contributing 7.2% of sulfates in 2018 on the 20% 

worst days. They conclude because of proximity to Colorado, that since Nebraska is one of nine CENRAP 

states, and that GGS is among the largest sources of sulfur dioxide (SO2) in the CENRAP region, it is 

reasonable to attribute some portion of the CENRAP contribution to GGS. Therefore, CDPHE requests that 

NDEQ reconsider SO2 controls at GGS under the Regional Haze rule. 

RESPONSE AND RATIONALE: 

NDEQ reviewed the website information provided by CDPHE. There, NDEQ found a “Causes of Haze 

Assessment” (COHA) that maybe found at http://www.coha.dri.edu/ as well as information on contribution for 

Rocky Mountain National Park, CO. The COHA included information regarding meteorological conditions. 

Below is an annualized wind rose for the Rocky Mountain National Park using the data collected from the 

station at the Class I area. As NDEQ expected, the patterns indicate the wind rarely comes from the east or 

northeast, directions that would have indicated a potential for impacts from sources in the state of Nebraska. 
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Filename: 34385f02.doc Page 28 of 53 

The contribution assessment did not distinguish Nebraska from the other eight CENRAP states. CENRAP 

includes Minnesota, Iowa, Kansas, Missouri, Oklahoma, Arkansas, Louisiana, and Texas. Overall, CENRAP’s 

contribution was significantly smaller than that of Colorado as shown in the graphs below. Taking into 

consideration the wind patterns it is most likely that contributions from the CENRAP region are not from 

Nebraska, but are from sources in states located southeast of Rocky Mountain National Park. 

Bec

ause 

othe

r 

Clas

s I 

area

s 

coul

d be 

imp

acte

d by emissions from Nebraska, NDEQ reviewed the COHA for other nearby Class I areas, specifically the 

Badlands Wilderness Area. The wind patterns (wind roses) for the Badlands indicate a high frequency of flow 

from the north-northwest year round, with an additional high frequency component of southeasterly flow during 

the warm months (June – August). 
NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

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August 2002 Wind Rose for Rapid City (station #24090- Rapid City, SD Regional Airport) 

The contribution analysis for the Badlands Wilderness Area did indicate a relatively high contribution from 

CENRAP. Given the wind pattern, location of GGS, it is possible that a portion of this contribution is 

attributable to GGS. However, the information did not distinguish Nebraska and its sources from the other 

CENRAP states. NDEQ provided a draft of the BART permit to the State of South Dakota Department of 

Environment and Natural Resources (DENR) to seek their input and feedback on the proposed BART package. 

Although in section 10.2 of the South Dakota Regional Haze State Implementation Plan, the South Dakota 

DENR states “...emissions from Nebraska are reasonably anticipated to contribute to visibility impairment in 

South Dakota’s two Class I areas. South Dakota and Nebraska consulted each other outside of WRAP as 

Nebraska developed BART requirements for sources in Nebraska that are impacting our Class I areas,” 

however, no comments were received from the State of South Dakota. 
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COMMENT #3: 

Like many parts of Nebraska, parts of Colorado are experiencing shortages of water. The CDPHE stated 

despite this obstacle, they have required dry or wet FGD on all electric generation units (EGUs) greater than 

250 MW in capacity. The majority of the units have installed dry FGDs, commonly referred to as lime spray 

dryers. The CDPHE claimed that dry FGD units have lower water demands, better waste stream characteristics 

and similar control efficiencies to wet FGD systems. 

EPA Region 7 also expressed concerns regarding the discussion on water shortages. EPA believes the crop 

revenue and property tax losses may be overstated. They further question whether the cost of lost crops plays 

any role in the BART analysis. EPA states that unless water is unobtainable as a result of a moratorium, water 

is not a significant factor in the BART analysis. 

EPA also believes the portion of the water discussion related to endangered species evaluation is inconclusive. 

EPA suggests that the reduction of SO2 and mercury could have a positive effect on endangered species. EPA 

suggests that US Fish & Wildlife and other Federal agencies with oversight responsibility for endangered 

species be consulted. 

RESPONSE AND RATIONALE: 

BART is defined as: an emission limitation based on the degree of reduction achievable through the 

application of the best system of continuous emission reduction for each pollutant which is emitted by a BART 

eligible 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 be reasonably be anticipated to result from the 

use of such technology. 

Appendix Y to Part 51 – Guidelines for BART Determinations under the Regional Haze Rule provides 

guidance on evaluation of the “costs of compliance” and “non-air quality environmental impacts.” One of the 

factors is taking into consideration the extent of the short term environmental gains at the expense of long term 

environmental losses and the extent to which there may be an irreversible or irretrievable commitment of 

resources. The water demands of scrubber systems (wet or dry) relate to a commitment of scarce water 

resources, costs of compliance, and non-air quality environmental impacts. NDEQ conducted further analysis 

into the available water resources in Nebraska and discussed the impact with the agencies and persons 

responsible for the management of water quantity in the state. The results of that analysis are summarized in 

the paragraphs below. 
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NDEQ searched for information on the water demands of dry FGDs to determine whether the estimates 

provided by NPPD were reasonable. Actual water usage information for comparable operating existing 

facilities that had been retrofitted was difficult to locate, but information on proposed units was found, and is 

summarized in the table below: 

Facility Name State MW GPM/MW 

(dry) 

GPM/MW 

(wet) 

Round Up Montana 780 0.743 1.03

Dave Johnston (existing) Wyoming 360 0.689 0.917

Noborne Missouri 680 0.912 1.22

Dry Fork Montana 590 0.578 0.723

Dry Fork Texas 920 0.707 0.891

Paradise (existing) Kentucky 1150 1.47 1.92

NPPD Nebraska 1365 1.47 1.76

Average 0.938 1.21

NPPD projected water usage at 1.47 GPM/MW of generation for dry FGD and 1.76 GPM/MW for wet FGD. 

While, it would appear that the water usage estimates submitted by NPPD are higher than the average, NPPD 

stated during a meeting that their estimates were for total water consumption for the project, not just for the 

scrubbers. Information relating to water quality, additives, pH, and other parameters, was not available to the 

NDEQ for analysis. Quality of water available to a source could have an impact on the efficiency of the device, 

how it is designed and ultimately how much water must be used to achieve the desired level of control. The 

water values provided by NPPD are within the range of other facilities currently in operation, particularly the 

one of a similar size in Kentucky as noted in the table above. Based on the information available, NDEQ 

concluded that NPPD’s water consumption estimates for wet and dry scrubbers were not unreasonable. To be 

conservative, NDEQ used both the average and NPPD’s values for analyzing NPPD’s water demands against 

water availability in Nebraska. 

Potential Scrubber water requirements for NPPD - GGS 

 GPM/MW 

(dry) 

GPM/MW 

(wet) 

MW GPM 

(dry) 

GPM 

(wet) 

Acre-Feet per 

Year (dry) 

Acre-Feet per 

Year (wet) 

NPPD 1.47 1.76 1365 2007 2402 3238 3877 

Average 0.938 1.21 1365 1280 1652 2065 2666 

1 million gallons = 3.07 acre-feet 

525,600 minutes per year 

Given that relatively large amounts of water needed for either a wet or dry scrubbing system, NDEQ consulted 

with the Nebraska Department of Natural Resources (NDNR) about the availability of water for future uses in 

the Sutherland, Nebraska area and to determine the feasibility of requiring a control technology based on what 

may be an unreliable water supply. If a reliable water supply cannot be ensured, scrubbing may not be a 

practical technology for GGS. 

GGS is located in an over-appropriated river basin

GGS is located in a semi-arid region of Nebraska in a portion of the Twin Platte NRD that has been designated 

by the Department of Natural Resources Director as over-appropriated. Nearby river basins from which water 

might be transferred have also been designated as either over-appropriated or fully-appropriated. The 

significance of these river basin designations is explained below. 
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In 2004, the Nebraska Legislature enacted a law that mandated the NDNR make a determination of which river 

basins, sub-basins or reaches are considered to be fully-appropriated or over-appropriated . The decision that a 

basin was fully-appropriated or over-appropriated would trigger a moratorium on new surface water and ground 

water uses and initiates a process with the affected natural resources districts (NRDs) to develop an integrated 

management plan (IMP) to govern the apportionment of water resources in these basins. On September 15, 

2004, the Director of NDNR issued an order designating portions of the North Platte NRD, South Platte NRD, 

Twin Platte NRD, Central Platte NRD and Tri-Basin NRD as over-appropriated. The GGS facility is located in 

the Twin Platte NRD within the area designated as over-appropriated. Most of these areas had already been 

determined to be fully-appropriated for surface water under the Nebraska system of prior appropriation of 

surface water rights and not available for new surface water appropriations. The new law mandated 

moratoriums on new water uses to remain in effect unless removed as a result of implementation of an approved 

integrated management plan. 

A basin is considered fully-appropriated if the current uses of hydrologically connected surface water and 

groundwater in a basin cause, or will cause in the reasonably foreseeable future, (a) the surface water to be 

insufficient to sustain over the long term the beneficial purposes for which the existing surface water 

appropriations were granted, (b) the stream flow to be insufficient to sustain over the long term the beneficial 

uses from wells constructed in aquifers dependent on recharge from the basin’s river or stream, or (c) reduction 

in stream flow sufficient to cause Nebraska to be in noncompliance with an interstate compact or decree, formal 

state contract, or state or federal laws. Therefore, in fully-appropriated and over-appropriated basins, a plan for 

future water use must be put in place. The statutory definition of an over-appropriated basin is very precise and 

related to conditions at a single point in time, July 16, 2004. Areas that were designated as over-appropriated 

were required to develop a plan to reduce water use to the 1997 level of use within the next 10 years. In overappropriated areas, the water demand already exceeds the current availability of water and the law requires 

steps be taken to mitigate the situation. 

The NDNR and the local NRDs involved are required to jointly develop and implement an integrated 

management plan within three to five years of a fully or over-appropriated designation. An Integrated 

Management Plan (IMP) for the Twin Platte NRD has been approved and took effect September 15, 2009. The 

purpose of the IMP is to manage all hydrologically connected groundwater and surface water for the purpose of 

sustaining a balance between demand and availability so that the economic viability, social and environmental 

health, safety, and welfare of the basin can be achieved and maintained for both the near and long-term. 

The IMP contains specific depletion rates that must be offset in the area in order to begin to return the basin to a 

fully-appropriated status. The current information indicates that 7,700 acre-feet on average per year must be 

offset. The plan contains both non-regulatory and regulatory actions. Some of the non-regulatory programs 

include incentive programs and education programs. Regulatory actions are those measures the NDNR and the 

Twin Platte NRD would put into place should the non-regulatory programs and retirement of irrigated acres not 

meet the specific annual reduction in depletion targets. Such actions could include: requiring alternative crop 

mixes for certified irrigated land, reducing a set percentage of irrigated farmland and allocating water to 

irrigators uniformly and likely in declining quantities. 

While the total reduction in consumptive use that will be required to reach a fully-appropriated status is not 

currently known, initial estimates indicate it may be several hundred thousand acre-feet per year. 

When a basin is determined to be fully-appropriated or over-appropriated, moratoriums on new or expanded 

consumptive uses of groundwater and surface water are automatically imposed. A moratorium on new water use 

exists in the basins surrounding GGS. The basin in which GGS is located remains in an over-appropriated 

status and the prospects for any less restrictive designation, even to fully-appropriated status, are extremely 

unlikely in the foreseeable future. Since there is no “new” water available, GGS would have to find and retire 
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existing water uses to meet scrubber needs and accomplish this at a time when the NDNR and local NRDs must 

seek to reduce water uses overall. 

The following moratoriums and restrictions on new water uses exist in Nebraska: 

Platte River Recovery and Implementation Program

As is evident with the over-appropriated status designation, the demand for beneficial uses of water in the area 

where GGS is located is considerable. In 1997, the Governors of Nebraska, Colorado, and Wyoming, and the 

U.S. Secretary of the Interior signed a cooperative agreement outlining a proposed basin-wide recovery 

implementation program for endangered species in the Central and Lower Platte river basins. In 2007, the 

Department of Interior, Colorado, Wyoming and Nebraska entered into an agreement called the Platte River 

Recovery and Implementation Program (PRRIP) to restore shortages to U.S. Fish and Wildlife Service 

(USFWS) target flows in the Platte River, thereby protecting endangered and/or threatened species whose 

habitat is the Platte River. The species identified for protection include the threatened piping plover and the 

endangered pallid sturgeon, least tern, and whooping crane. Substantial offsets to current water use are 

required in order to meet the PRRIP needs as well as the required IMP reductions. While the total potential 

water needs for both the PRRIP and IMP may not necessarily be mutually exclusive, they are substantial over 

the near and long term. 

 

PRRIP is also set up to restore the shortages to USFWS target flows in an incremental fashion. During the first 

increment, the goal is to restore between 130,000 and 150,000 acre-feet per year. Of this, 80,000 acre-feet per 

year has already been obtained through project commitments from the three states, for a remaining requirement 
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of 50,000 to 70,000 acre-feet per year. While additional increments have not yet been agreed to by the PRRIP 

states, the ultimate requirements of PRRIP may be as much as 417,000 acre-feet per year. For more information 

about the PRRIP see http://platteriverprogram.org/default.aspx. 

The outstanding existing commitments and obligations will total up approximately 100,000 acre-feet per year 

and the ultimate requirements may be several times greater than that. The expected demands of scrubbing at 

the NPPD GGS facility is 2,000 to 3,900 acre-feet per year, or 2 to 4 percent of the initial increment required 

for the basin. The NDNR has informed the NDEQ that this additional demand represents a significant amount 

of the overall initial increment required for the basin, and that placing this additional demand on the basin 

jeopardizes Nebraska’s ability to meet commitments made to other states and the federal government, as well as 

the requirements of State Law relating to over-appropriated basins described above. 

 

Acquisition of Allocations and Offsets (Costs of Water)

In order for NPPD to obtain sufficient water for the scrubbers, they would need to acquire water from 

somewhere or someone else. There are two options for this: 1) transport the water from a location that has a 

suitable water supply, or 2) purchase existing water rights owned by someone else, retire the wells to ensure the 

offset is permanent. 

Costs of Transporting Water

In a study conducted by the State of Nebraska Water Management Board, the Report on Water Rights Transfer 

Study (1988), the writers found that since water rights were not traded routinely in a market situation, there was 

no demand curve for determining a cost schedule. Instead, economics rely on willingness or ability to pay and 

the least cost alternatives. For industries, water is relatively hard to transfer compared to other inputs, so 

typically a site is chosen where there is an adequate supply of water. Over the years, many transfers have been 

under consideration in Nebraska. Several factors go into the costs of transferring water: well construction, 

pipeline construction, pumping plants, land, energy, operation and maintenance. Pipeline costs are the most 

significant fixed cost. Energy is the largest part of operations. 

In a study conducted by the High Plains Study Council, “A Summary of Results of the Ogallala Aquifer 

Regional Study, With Recommendations to the Secretary of Commerce and Congress” (1982), an evaluation of 

transferring water within the High Plains area was conducted. Four routes were evaluated, including one that 

started at Fort Randall, South Dakota, moved southwesterly across Nebraska (nearing the Sutherland, Nebraska 

area) to storage near Bonny Reservoir in Eastern Colorado. In 1977 dollars the average costs for this project 

were: 

Water 

Studied for 

Transfer 

Route 

Length 

Elevation 

Change 

# 

Pumping 

Stations 

Total Energy 

Requirements 

(Million 

KWHr/yr) 

Total 

Construction 

Costs (1977 $) 

Average 

Annual 

Cost 

($/acre-ft) 

1.91 – 3.4 

million 

acre-ft 

813 

miles 

0 ft 18 6,600 – 14,300 5.4 – 8.9 

billion 

291 

Colorado is planning to build a pipeline to comply with the Republican River Basin Compact. The costs 

associated with that are: $5,263 an acre for the water rights ($50 million); $1,400 per acre-foot to build pipeline 

($21 million). 
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Costs of Obtaining Water Rights and Retiring Wells

According to the 1988 Water Management Board report, the cost of obtaining water will be different for every 

situation. It would be most likely that NPPD would need to seek out water rights from irrigators and retire 

irrigation wells. For agricultural uses of water, the decision to sell a water right would be made only when/if 

the irrigator felt it would be advantageous to sell than continue to operate. If the irrigator were willing to 

forego the use of this resource, the price for that water right must sufficiently compensate for decreased net 

returns over a period of years. The irrigator relies on that well for livelihood in times when sufficient rain is 

unavailable. The long-term value of irrigation water to a farmer is based on the expected return over a number 

of years discounted into present values, i.e. the opportunity cost. If one thought that it would be to their 

advantage, the irrigator may be willing to trade water for potential farm income and related risks for less water, 

a smaller yield or operation, and secure dollars in the bank. 

In 2008, 30 square miles of a Lincoln County irrigated farm near North Platte sold for about $3,000 per acre. In 

2009, Lincoln County irrigated farmland sold for about $3,200 - $3,500 per acre. NPPD assumed that 

approximately 3,000 acres of land would be needed to be purchased. Costs for obtaining water rights could be 

between $9,600,000 and $10,500,000 or more, depending upon the willingness of potential sellers. 

Any offsets would be subject to approval from the local NRD through issuance of a variance. 

In conclusion, as indicated in the discussion above, the water resources in the river basin in which GGS is 

located and in surrounding river basins are scarce. A moratorium has been placed on new consumptive uses. 

Offsets of existing uses are difficult to find and economically prohibitive given the distances and infrastructure 

needed to transport water from a reliable supply location. The unusual circumstances related to the scarce 

water resources in this region of the state and the State of Nebraska’s commitments to other states and the 

federal government under the PRRIP when compared to the very limited visibility improvement that might 

result from the additional control justifies not requiring GGS to install scrubbing technology at this time. 

 

Agricultural Taxes and Crop Income

Agriculture is the main economy of Nebraska. Whenever cropland is taken out of service, it is appropriate to 

evaluate that impact to the state. Lincoln County was ranked in the top five counties for agriculture sales in 

2007. Nebraska’s leading commodities accounting for 98% of the state’s total cash receipts are: cattle, corn, 

soybeans, hogs, wheat, chicken eggs, dairy products, hay, dry beans, and sorghum. Nebraska has been 1st in red 

meat production, cattle slaughter, great northern beans production, irrigated land and popcorn production. 

When cropland is permanently taken out of service, wealth is being removed from the state. The effect of this 

is direct on the farmer, the employees, and their families, but there is also an indirect effect that trickles out 

from reductions in crop income. Reduced crops in an agricultural state result in fewer grains for livestock and 

for export out of the state. This reduction impacts more people and their jobs, including grain elevators and 

slaughter houses. According to the USDA, for every $1 in agricultural exports another $1.40 is generated in 

transportation, financing, warehousing and production. It follows that for every $1 reduced in agricultural 

exports, another $1.40 is reduced in those areas as well. When the foundational industries to our economic 

structure begin to weaken, the service sectors start to suffer as well. 

COMMENT #4:

The FLM resubmitted comments previously provided on August 29, 2008. The letter, at the time, dealt with 

both OPPD and NPPD facilities, however, only the comments regarding the NPPD action are germane to this 

action and are summarized below. 

The FLM states that the draft permit requires the presumptive NOx limit for Unit 1 and slightly above 

presumptive for Unit 2. In the attachment to the August 29, 2008 letter, the FLM outlines several other 
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concerns regarding the BART analysis for NOx. The FLM contends that selective non-catalytic reduction 

(SNCR) was eliminated from consideration without sufficient technical justification. They question whether, 

based upon the NOx emissions from the two boilers at GGS, make the boilers similar enough to be evaluated in 

combination instead of individually. They also question the logic of whether temperature is a factor for the 

boilers, making SNCR technically infeasible. 

The FLM believes that the ability of SCR systems to control NOx has been underestimated in the BART 

analysis. To support their presumption, the FLM provided information from EGUs with SCR systems that are 

used during the ozone season. 

Lastly, the FLM believes that NPPD has overestimated the costs associated with SCRs. They conclude and 

recommend that the SCR analysis be redone and that the modeled effects should be conducted at all Class I 

areas at a level no greater than 0.07 lb/MMBtu. 

RESPONSE AND RATIONALE: 

The draft permit package that was public noticed did not contain limits above the presumptive levels as 

indicated in the comment. The presumptive level is 0.23 lb/MMBtu. The limits in Condition XIV.(A)(1)(a) 

states: “Emissions from both units shall be averaged together and shall meet a NOx emissions limitation of 0.23 

lb/MMBtu (30-day rolling average).” 

The temperature issue was discussed with NPPD. The two units are different and could not be evaluated in 

combination. 

SCR controls were evaluated down to a level of 0.08 lb/MMBtu, a level deemed appropriate by NDEQ and 

supported by the record. This analysis was contained the application materials and in the proposed permit 

package that was public noticed on May 28, 2009. 

Please also refer to the response and rationale to comments #6 and #8. 

COMMENT #5:

The FLM made several comments concerning the SO2 BART analysis. First, they believe that SO2 controls 

can do better than the presumptive level established in the rule. The FLM stated that SO2 controls could be 

added and would act as if they were at a newly constructed facility. The FLM supported their claim that SO2 

controls could achieve better than the 0.15 lb/MMBtu level by providing a table summarizing systems that are 

either achieving or proposed to achieve levels between 0.04 and – 0.09 lb/MMBtu. They propose that GGS 

should be able to achieve 0.04 lb/MMBtu (wet) or 0.06 lb/MMBtu (semi-dry) on a 30-day rolling average. 

The FLM expressed concern that the cost figures were overestimated compared to other similar retrofits. They 

also expressed a lack of sufficient detail in the operating costs figures developed by NPPD to understand the 

annualized costs and the cost-per-ton figures. 

EPA also made comments about Flue Gas Desulfurization (FGD) control technology being able to operate at 

emission levels lower than the presumptive levels (0.15 lb of SO2/MMBtu) in the Regional Haze Rule. EPA 

suggested levels as low as 0.02 lb of SO2/MMBtu could be achieved. They suggest that it is important to 

consider the maximum efficiency a technology could achieve in order to avoid over-inflating cost effectiveness 

figures. EPA did concur with the NDEQ that, at the presumptive level, $2,700 per ton of SO2 removed is a 

reasonable cost. 

Please also refer to the response and rationale to comment #8. 
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RESPONSE AND RATIONALE: 

It is difficult to ascertain the maximum efficiency the technology could achieve at the source until it is installed 

and optimized. However, the point is to have the State consider other possible efficiencies the technology could 

achieve when determining whether something is cost effective. NDEQ did consider a lower lb/MMBtu than the 

presumptive level. 

NDEQ did a data pull of EPA’s database to determine how existing FGD systems performed at existing 

subbituminous coal fired EGUs. While units were found that performed below 0.1 lb/MMBtu, NDEQ did not 

find where levels as low as 0.02 lb/MMBtu, and several did not meet the 0.15 lb/MMBtu presumptive level. 

This is a summary of the results: 

State Plant Name MMBtu/Yr SO2 Tons/Yr lb/MMbtu Controls 

MN Sherburne 54,081,049 7,863.09 0.290 DL FGD 

WY Wyodak 32,852,075 7,732.07 0.470 DL FGD 

AZ Springerville 32,800,868 5,331.17 0.325 DL FGD 

AZ Springerville 27,474,762 4,548.64 0.331 DL FGD 

OK GRDA 41,980,796 4,113.71 0.196 DL FGD 

MO Hawthorn 41,523,208 2,140.86 0.103 DL FGD 

CO Craig 31,899,039 2,010.18 0.126 DL FGD 

KS Holcomb 27,332,412 1,772.24 0.130 DL FGD 

CO Rawhide 22,783,530 875.5 0.077 DL FGD 

WY Wygen 1 10,142,973 538.38 0.106 DL FGD 

WY Neil Simpson II 8,119,461 498.4 0.123 DL FGD 

MI Shiras 3,500,784 225.9 0.129 DL FGD 

ND Stanton 5,344,399 139.15 0.052 DL FGD 

NE NPPD GGS 110,115,509 28,171.44 0.512 

Note: The lbs/MMBTU was figured by dividing the annual SO2 tons values by the annual MMBTU values. NDEQ recognizes that short 

term periods (30 day) may show lower or high values. 

COMMENT #6:

The FLM believes that it is appropriate to consider cumulative, not average effects of improving visibility 

across all of the Class I areas affected. They believe that if emissions from GGS are reduced, the benefits will 

be wide-spread, well beyond one Class I area. The FLM referenced work that the Oregon Department of 

Environmental Quality conducted on the Boardman power plant where the cumulative impact across 14 Class I 

areas was 29.7 dV with a total of 2,367 impaired visibility days across the 14 Class I areas. It is the FLM 

opinion that the other Class I areas where GGS caused or contributed to visibility impairment were ignored. 

RESPONSE AND RATIONALE: 

Other areas where NPPD GGS affected visibility were not ignored. NDEQ summarized the greatest impacts 

because that is where the most benefit from control would be seen. The law of diminishing returns is 

experienced when one looks at all the potential Class I areas. NPPD GGS is located approximately 300 km 

from it’s nearest Class I area (Badlands). Models that are used as tools to help make decisions on control 

strategies and determine the perceived benefits become less reliable when the receptor (Class I area) is more 

than 200 km away from the BART source. 

Appendix Y to Part 51 – Guidelines for BART Determinations under the Regional Haze Rule provides under 

STEP 5: Determining Visibility Impacts: “If the highest modeled effects are observed at the nearest Class I 
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area, you may choose not to analyze the other Class I areas any further...” Given the guidance in Appendix Y 

and the uncertainties of the model beyond 200km, the analysis conducted is appropriate. However, there is 

another Class I area close to Badlands Wilderness Area, Wind Cave National Park. The next highest impacts 

were seen there. 

The total baseline impact from NPPD GGS is shown in Table 2 of the Fact Sheet. The number of days above 

0.5 dV for the 7 Class I areas analyzed ranged from 10 – 60 days. The area with the greatest impact was 

Badlands in all 3 years analyzed. There were 54 days above 0.5 dV in 2001, 55 in 2002 and 60 in 2003. Since 

Wind Cave is close to the Badlands, we will assume that improvements seen at the Badlands will be seen at 

Wind Cave as well. 

The following table shows what the cumulative improvements in visibility from SO2 and NOx controls would 

be, roughly, assuming that SO2 controls could be implemented, and the corresponding cost effectiveness: 

Badlands – 

2001 

Badlands – 

2002 

Badlands - 

2003 

Average 

Baseline – dV 2.845 2.828 3.121 2.931 

LNB/OFA- ∆dV 0.621 0.666 0.702 0.663 

Cost/ ∆dV $4,766,506 $4,444,444 $4,216,524 $4,464,555 

Cost/ ∆dV/days 

improvement 

$953,301 $1,481,481 $702,754 $1,045,845 

LNB/OFA + SCR -

∆dV 

0.492 0.434 0.540 0.489 

Cost/ ∆dV $110,347,561 $125,094,470 $100,538,889 $111,993,640 

Cost/ ∆dV/days 

improvement 

$10,858,200 $4,935,545 $9,048,500 $8,280,748 

FGD (0.1 

lb/MMbtu) - ∆dV 

1.055 0.802 0.678 0.845 

Cost/ ∆dV $102,796,208 $135,224,439 $160,428,994 $132,816,547 

Cost/ ∆dV/days 

improvement 

$5,164,286 $4,929,545 $4,518,750 $4,870,860 

LNB + FGD- ∆dV 1.676 1.468 1.380 1.508 

Cost/ ∆dV $107,562,714 $139,668,883 $164,645,518 $137,281,102 

Cost/ ∆dV/days 

improvement 

$6,117,587 $6,411,026 $5,221,504 $4,870,860 

Costs do not include costs of obtaining water 

Even assuming that Wind Cave would have the same level of benefit, the incremental cost effectiveness would 

be half of what is shown above: LNB + FGD = $137,281,102/ ∆dV / 2 = $68,640,551/ ∆dV. This is still 

significantly higher than the incremental cost effectiveness value under consideration in Wyoming at the 

Wyodak facility ($16.3 million/dV). In Wyoming, an additional metric was used to put the visibility 

improvement into perspective. The incremental reduction in days above 0.5 dV in each Class I area was 

evaluated. Using that metric for NPPD, assuming Wind Cave has the same level of benefit as Badlands, and 

using an average of days over 0.5 dV during 2001 – 2003 annually: 

NOx BART Controls Alone: $522,922/day 

Incremental Cost of adding SO2 Controls with NOx Controls: $2,435,430/day 

Cumulative Cost of NOx and SO2 Controls: $2,958,352/day 

The rule does not provide a level to which individual sources must reduce their visibility impact, leaving it up 

to the state’s judgment. All things considered, the moratorium on new consumptive uses of water, wind 

patterns, costs of compliance, visibility improvement that is expected from the additional NOx controls versus 
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NOx and SO2 controls, the irreversible or irretrievable commitment of water resources requiring scrubbers 

would cause on an already water-stressed area and the excessive costs for the amount of visibility improvement 

due to additional SO2 controls even if water were available, NDEQ has concluded it is most appropriate to 

implement only additional NOx controls as BART for NPPD GGS. 

COMMENT #7:

EPA raised concerns regarding whether Nebraska was fulfilling its obligations under the Regional Haze Rule. 

EPA noted that 40 CFR 51.308(d)(3) requires all states to submit a long-term strategy for addressing visibility 

impairment for each Class I area located outside the state that may be affected by emissions from within the 

state. EPA also referenced the regional planning process that NDEQ participated in which was facilitated by 

the Central Regional Air Planning Association (CENRAP). EPA held that work done by the CENRAP formed 

the basis for regional haze SIPs submitted by states such as Missouri, Oklahoma and Louisiana. EPA believes 

that the modeling was based on emissions reduction information for installations that were ‘on the books’ and 

‘on the way’ and that presumptive BART was an ‘on the way’ assumption for GGS in the modeling analysis. 

EPA notes that under 40 CFR 51.308(d)(3)(ii), the State must ensure that it has included all measures needed to 

achieve its apportionment of emissions reduction obligations agreed upon through the regional planning 

process. Furthermore, EPA believes Missouri, Oklahoma, and Colorado relied upon IPM modeling conducted 

by EPA, which included presumptive levels for BART on GGS.

RESPONSE AND RATIONALE: 

The regional haze process has been a difficult one. It is problematic to set a presumptive level, assume that all 

facilities will be able to comply with it regardless of the situation, but also allow for a case-by-case analysis in 

the rule. 

Areas of influence and apportionment of Nebraska’s SO2 emissions were evaluated in the August 31, 2005, 

Causes of Haze Study conducted by Sonoma Technology, Inc. This study may be found on CENRAP’s website 

(www.cenrap.org). Sonoma concluded that because the emission impact potentials (EIPs) of potentially BARTeligible sources are relatively small, the enforcement of BART requirements will produce limited improvement 

in visibility conditions and require the need for additional emission reduction strategies. Emission impact 

potentials relate the probability of transport of SO2 and NOx pollution from an area such as a state to a Class I 

area and the scale of emissions in that given area (State). In Figures 4-8 and 4-9 of the study, Nebraska BART 

sources have an insignificant EIP, specifically for the Hercules Glades Class I area. 

In a paper written by Sonoma Technology and Brett Anderson (EPA) (see Appendix D of the paper), the 

composition of particles were studied in an effort to better understand how to improve the visibility for the 

Hercules Glades Class I area. The results showed that sulfate accounted for 65% of the mass at Hercules 

Glades and most of the sulfate was in the form of ammonium sulfate. The paper reported that it “was highest 

on days with transport from the Ohio River area, where many coal-fired power plants are located and which has 

been identified as a significant area for the origin of sulfate transport.” Nebraska does not lie within the Ohio 

River Area. Sonoma and Anderson went on to say that the EIP analysis corroborated this, showing that more 

than half of the SO2 came from that particular area, and that when looking at the county-level, it was clear that 

a handful of sources in a few counties were responsible for most of the SO2 emissions impacting Hercules 

Glades. However, the study revealed that ammonium nitrate showed strong seasonal tendencies. It was highest 

during the winter, and was highest under conditions of slow moving cool air masses from northwest Missouri, 

Iowa, Nebraska, and Kansas. 

Nebraska participated in the CENRAP regional planning process. However, it is important to note that 

CENRAP recognizes the authority and jurisdiction of each state and tribal member. Nebraska also was invited 

to participate in a limited capacity in a consultation process with Missouri and Oklahoma, which is a part of the 

regional planning process. Please refer to the response to Comment #3 for information about Class I areas in 
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Colorado and South Dakota. We did not receive any comments from any states. We have concluded that by 

controlling NOx emissions, Nebraska is ensuring that it is including all measures needed to achieve its 

apportionment of emissions reduction obligations identified through the regional planning process. 

Additionally, we have concluded that controlling SO2 is not reasonable given, among the other reasons stated in 

this response, the unique circumstances regarding water availability in that area of the state. 

COMMENT #8: 

EPA expressed concern that NDEQ is using solely dollars per deciview ($/dV) as a decision-making metric for 

BART. They list four concerns: 1) they believe that although the EPA BART guidelines allow for its use, there 

are significant difficulties in developing a meaningful method for calculating $/dV; 2) they believe it should 

only be used as a supplement to $/ton, in evaluating cost effectiveness; 3) they believe cost estimates must be 

reasonable, and recommends that cost estimates be based upon the OAQPS Cost Manual; and 4) they believe 

that even when used as a supplement to $/ton, the $/dV analysis would be meaningless if it does not take into 

account visibility impacts at multiple Class I areas or ignores the total improvement (frequency, magnitude, and 

duration of the modeled changes in visibility). 

RESPONSE AND RATIONALE: 

NDEQ would like to clearly state that it did not rely solely on one factor in making its SO2 BART 

determination for GGS, but rather, considered all factors. Furthermore, the EPA’s citation of the $/dV metric 

as only one factor is mistaken, since by definition, this calculated ratio includes both the cost and the benefit 

(degree of visibility improvement). The other three factors (the energy and non-air quality environmental 

impacts of compliance, any existing pollution control technology in use at the source, the remaining useful life 

of the source) were also considered in the five-factor analysis. Therefore, Nebraska has indeed considered all 

five factors and has not relied on a single factor in its SO2 BART determination. 

The Clean Air Act, Section 169A (g) (2) states: 

“in determining best available retrofit technology the State (or the Administrator in determining 

emission limitations which reflect such technology) shall take into consideration the costs of 

compliance, the energy and non-air quality environmental impacts of compliance, any existing pollution 

control technology in use 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” 

EPA’s initial Regional Haze rules had directed states to set BART emissions limits based on only the first four 

factors listed in the above statutory language, after determining that a given source was “subject” to BART. 

Thus, EPA had initially left the visibility improvement factor out the BART determination step. In the case of 

American Corn Growers Assn v. EPA (291 F.3d 1; D.C. Cir., 2002), the court sided with the American Corn 

Growers Association, and ruled that all five factors, including the “degree of visibility improvement” needed to 

be considered in the BART determination. EPA subsequently revised the Regional Haze rules accordingly, on 

July 6, 2005. 

The cost analysis for the GGS BART analysis was prepared by Sargent and Lundy, LLC (S&L), a well 

recognized and experienced design engineering firm in the power industry, under contract with NPPD in 2008 

(referred to as the “2008 S&L NPPD Study”). When S&L prepared the 2008 cost analysis, the January 2002 

OAQPS Control Cost Manual was generally followed. In addition, S&L also provided certain cost information 

supplied to S&L by vendors. NDEQ met with NPPD, S&L and EPA Region 7 and discussed the cost analysis, 

and supporting vendor information, used by S&L in the 2008 S&L NPPD Study. 
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Costs to retrofit are unique to the specific unit, its current design, and site layout, making retrofit costs exceed 

those of building a new unit. There may be significant mechanical, structural, and electrical changes and 

upgrades needed to accommodate a retrofit. S&L also evaluated FGD technology and costs on electric 

generating units as part of a study for the National Lime Association in March 2007. The study is titled “Flue 

Gas Desulfurization Technology Evaluation: Dry Lime vs. Wet Limestone FGD” (and is referred to as the 

“2007 S&L Industry Study”). In the 2007 S&L Industry Study, S&L evaluated 36 cases, including retrofits. 

While the authors caution against using the information for planning the cost of an FGD project, NDEQ used 

this information for comparison purposes. Overall, the capital costs provided in the 2008 S&L NPPD Study for 

GGS were higher than those in the industry-generic 2007 S&L Industry Study. There appear to be several 

reasonable explanations for why this is the case: 1) the 2008 S&L NPPD Study provided costs for control of a 

2 units (1365 MW) whereas the 2007 S&L Industry Study only provided retrofit information on 400MW and 

500MW units; 2) the 2008 S&L NPPD Study added 10% for “turnkey services” for purposes of engineering, 

procurement, and construction management services; and 3) as stated in both S&L studies, FGD equipment, 

material and installation labor prices have been subject to significant inflation since 2006. Some recent 

contracts have been signed at prices over 300% higher than the market of 5 years ago. Therefore, the 

statements made by EPA that the costs of FGD have gone down are not supported by recent market trends. 

Also, while the 2008 S&L Study costs for GGS are higher than those contained in the industry-generic 2007 

S&L Industry Study, the $/ton SO2 removed was about the same as in both studies. 

All of the above considered, the NDEQ determined that the costs presented by NPPD were reasonable. 

The Appendix Y BART Guidelines provide for in the “Costs of Compliance” provide for several cost 

effectiveness measures including incremental cost effectiveness in $/ton and other measures like $/dV. In the 

BART program, Appendix Y is putting the cost of the control into perspective by allowing for consideration of 

the goal of the program, which is visibility improvement. Sources with a significant baseline impact to a Class I 

area will likely have much lower cost per deciview of visibility improvement when controls are employed 

provided significant improvements are realized. Using a $/dV metric also indirectly takes into consideration 

the distance a source is from the Class I area. Assuming a source is upwind from a class I area, similar size 

emission sources located different distances away from a given Class I area would be expected to have different 

impacts on that Class I area. 

COMMENT #9: 

EPA commented that GGS was not compared to other facilities within the same power pool, but instead 

facilities that were not similar to GGS. 

RESPONSE AND RATIONALE: 

Prior to public notice and again before issuance of the permit, NDEQ conducted a review of the BACT/LAER 

Clearinghouse for retrofit projects to compare to NPPD GGS, and to determine whether NPPD had adequately 

supplied all information about such projects in its submittal. Mid-Continent Area Power Pool (MAPP) 

includes the states of Nebraska, Iowa, North and South Dakota, Minnesota, and portions of Wisconsin and 

Montana. Information from the states of Minnesota and North Dakota were reflected in the Fact Sheet. 

Information was listed on the WRAP’s website in the MAPP; however, the facilities listed utilize lignite and 

not subbituminous coal similar to NPPD. 

EPA pointed to two facilities in Kansas. They said the visibility impacts from GGS were greater than Kansas 

City Power and Light (KCP&L) La Cygne and Westar Jeffery facilities. NDEQ does not agree with this 

statement. Looking at Table 9.2 of the Kansas draft SIP reveals these facilities have many more days of impact 

on many more Class I areas than NPPD GGS does. 
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COMMENT #10: 

EPA commented that while the use of a construction permit may provide for adequate enforceability of the 

BART emission limits, it is recognized that minor changes to permits often occur during construction and 

operation of the units. EPA stated that if changes were made to the construction permit which effects, in any 

manner, the permit requirements related to the BART emission limits, the source could not rely on such 

changes until NDEQ requested and EPA approved them into the SIP. They also state that this restriction 

applies even if the primary purpose of the permit revision is not to change BART obligations. Since there is no 

discretion to change the limits without a corresponding SIP change, EPA suggests that NDEQ may wish to 

consider utilizing a rulemaking or state enforceable agreement, incorporated into and approved as part of the 

SIP, to ensure the BART emission limits are enforceable. 

RESPONSE AND RATIONALE: 

NDEQ appreciates the suggestion made by EPA; however, as EPA Region 7 is aware, the NDEQ has already 

adopted into Title 129 NAQR Chapter 43 the construction permit program as the mechanism for making the 

BART requirements enforceable. At the time this was done, R7 had an opportunity to participate in the rulemaking. As with the current construction permit program, the provisions of Chapter 43 will be submitted as a 

part of the State Implementation Plan. The current construction permit program (Chapter 17) is a part of the 

State Implementation Plan; therefore any permits that are issued in accordance with it should be enforceable. 

Nebraska will include in its SIP submittal, information about the BART permits issued. 

COMMENT #11: 

EPA expressed concern about the differences in the timing between the BART rule provisions and the PSD 

permit requirements for purposes of commencing construction. EPA is concerned that NPPD may choose to 

delay construction and suggests that NDEQ require commencing construction within 18 months of the issuance 

of the PSD construction permit. 
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RESPONSE AND RATIONALE: 

NDEQ understands EPA’s concern. There is the unique situation where the control technology determined to 

be BART requires a PSD permit due to the projected increase in carbon monoxide emissions. The BART 

provisions promulgated by EPA allow sources up to 5 years after SIP approval to make BART controls 

operational and in compliance. While NPPD assures NDEQ their intent is to commence construction as soon as 

practicable after the Nebraska Regional Haze SIP has been approved by the EPA, however, unforeseen 

circumstances could change those plans. The PSD rules (52.21(r)(3)) and Title 129 NAQR Chapter 17, Section 

012, allow the NDEQ to grant extensions of the 18 months timeframe under certain circumstances. 

COMMENT #12: 

EPA noted that Condition XIV.(B)(1)(a)(i) on page 6 has sampling and recordkeeping conditions for Unit 1 that 

need to be duplicated for Unit 2. 

 

RESPONSE AND RATIONALE: 

NDEQ agrees with the comment. 

CHANGES: 

The language was revised to read: 

“The average CO emissions for each GGS unit, for each hour, shall be recorded by sampling the lb/MMBtu 

value by completing a minimum of one cycle of operation (sampling, analyzing, and data recording) for each 

successive 15-minute period Unit 1is for Unit 1 anytime it is combusting fuel and its monitor is in service and is 

not malfunctioning or being calibrated, and for Unit 2 anytime it is combusting fuel and its monitor is in service 

and is not malfunctioning or being calibrated. Data for startup and shutdown shall not be used to calculate the 

average CO emissions. All data shall be reduced as specified in 40 CFR 60.13(h).” 

6.0 Prevention of Significant Deterioration (PSD) 

6.1 Summary 

BART for GGS Units 1 and 2 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 the PSD significance threshold (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. Lincoln 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. Unit 1 previously 

received a PSD permit and a BACT analysis was done for CO when the LNB/OFA were permitted in August 

2006, therefore, Unit 2 is the only unit which needs to apply BACT for the increase in CO with this permitting 

action. However, in order for the requirements for both units to be contained in a single permitting document, 

the permit issued for Unit 1 on 8/18/2006 will be superseded by the PSD portion of this permit. 

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 is achievable. However, 
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BACT cannot be less stringent than emission limits established by an applicable NSPS. Since it would not be 

appropriate to require GGS 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. 

6.2 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: 

6.2.1 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. 

 

6.2.2 Step 2: Eliminate technically infeasible options: 

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

excluded from further consideration. 

6.2.3 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. 

6.2.4 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. 

6.2.5 Step 5: Propose BACT

6.3 BACT Analysis for Carbon Monoxide (CO) 

The objective of this analysis is to determine BACT for CO emissions from the GGS Unit 2 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. 
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6.3.1 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

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. 

6.3.2 Identification of CO Control Technologies and Technical Feasibility

6.3.2.1 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 GGS Unit 2. 

6.3.3 Post Combustion Control Technologies

6.3.3.1 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 because of 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 
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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 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 

GGS Unit 2. 

6.4 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 GGS Unit 2. 

6.5 BACT for CO 

At the time this permit was issued, the highest CO BACT emission limit that had 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’s Nebraska City Unit 1 was recently permitted with an 

emissions limit of 0.50 lb/MMBtu (30-day rolling average) for BACT, which is consistent with the proposed 

NPPD emission limit. A 30-day rolling average is appropriate because GGS Unit 2 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 combustion system to achieve an optimal 

operating scenario. Since GGS Unit 2 does not have a neural net system, any “tweaks” in operation must be 

made by the operators manually. Furthermore, even if GGS had a neural net system, if such a system 

automatically adjusted the combustion system to minimize CO emissions, this would tend to increase NOx

emissions, as there is a tradeoff between CO and NOx emissions. Because NOx emissions control is deemed 

much more important than minimizing CO emissions, the NDEQ agrees that the 0.5 lb/MMBtu (30-day rolling 

average) is an acceptable CO BACT limit for GGS Unit 2. NPPD’s Unit 1 went through BACT in August 2006 

and CO BACT was set at 0.5, which isn’t changing in this permit even though it supersedes the Unit 1 permit. 

7.0 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 for CO as part of the PSD permitting process. More information can be obtained in the 

materials submitted by the source. 
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7.1 Model Information 

7.1.1 Facility Location and Site Description

The NPPD Gerald Gentleman Station is located approximately 30 kilometers (km) west of North Platte and 12 

km south of Sutherland in Lincoln County. The terrain in the vicinity of the NPPD facility is essentially flat to 

gently rolling terrain, with no terrain elevation in excess of 50% of the NPPD boiler stack heights. Lincoln 

County is currently classified as in attainment or unclassifiable for all NAAQS pollutants. 

7.1.2 Model Selection 

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

The emission rate input into SCREEN3 was equivalent to 3,769 lb/hr, which is based on the maximum heat 

input rate of 7,538 MMBtu/hr of Unit 2 and the BACT emissions limit of 0.5 lb/MMBtu. 

The SCREEN3 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. 

7.1.3 Source Parameters

One emission source, GGS Unit 2, was evaluated for purposes of PSD screening modeling. It is the only unit at 

the NPPD 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 GGS are insignificant. The following table 

presents the source stack parameters. In addition to these parameters, building downwash dimensions were 

input to SCREEN3 as follows: building height= 81.69 meters, minimum building width = 82.03 meters, 

maximum building width (both boiler buildings combined) = 180.26 meters. 

Table 7: 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 474.89 167.6 8.53 22.3 417.0 293.0 

7.2 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 2 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 8: Maximum Modeled GGS Unit 2 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 315.9 2,000 N/A CO 8-hr 221.1 500 575 

7.3 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. 

7.3.1 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. Because the modeled CO impacts are insignificant 

compared to the NAAQS, the 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 concluded that there will not be any adverse 

effects on the soil or vegetation. 

8.0 Type and Quantity of Air Contaminant Emissions Anticipated 

As a result of the LNB installation supported by an Overfire Air Port System on GGS Unit 2, 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: 

7,538 MMBtu/hr x 0.50 lb CO/MMBtu = 3,769 lb CO/hr x 8,760 hr/yr / 2,000 lb/ton = 16,508 ton CO/yr

The current potential emissions of Unit 2 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 

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

CO PTE prior to LNB/OFA Project Emission Calculation: 

7,538 MMBtu/hr / 0.0084 MMBtu/lb x 8,760 hr/yr/ 2,000 lb/ton = 3,930,529 ton coal/year 

 3,930,529 ton coal/year x 0.5 lb CO/ton coal = 1,965,264 lb CO/yr / 2,000 lb/ton = 983 ton CO/yr
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Change in PTE Emission Calculation: 

(Future Potential minus Current Potential) 

16,508 ton CO/yr – 983 ton CO/yr = 15,525 ton CO/yr 

This project is also expected to reduce the amount of permitted and actual NOx emissions for GGS Units 1 and 

2. Currently, GGS Units 1 and 2 must comply with NOx emissions limits 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, GGS 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. Although GGS Unit 1 was retrofitted with a LNB/OFA system in 2006, the 

allowable (permitted) emissions did not change. GGS Units 1 and 2 have a heat input rating of 15,076 

MMBtu/hr and by using the highest possible emission factor of 0.46 lbs/MMBtu, maximum potential NOx

emissions are currently 30,375 tons/year. 

15,076 MMBtu/hr x 0.46 lb NOx/MMBtu = 6,935 lb NOx /hr x 8,760 hr/yr / 2,000 lb/ton = 30,375 ton NOx /yr

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

from GGS Units 1 and 2 will be approximately 15,188 tons/year once the LNB/OFA project has been 

completed for Unit 2. 

15,076 MMBtu/hr x 0.23 lb NOx/MMBtu = 3,467 lb NOx /hr x 8,760 hr/yr / 2,000 lb/ton = 15,188 ton NOx /yr

Change in PTE Emission Calculation: 

 (Future Potential minus Current Potential) 

15,188 ton NOx/yr – 30,375 ton NOx/yr = - 15,187 tons NOx/yr 

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

by 15,525 tons/year while maximum potential NOx emissions would decrease by 15,188 tons/year. 

9.0 Applicable Requirements, Variances or Alternatives to Required Standards 

9.1 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. 
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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. 

9.2 New Source Performance Standards (NSPS) 

The proposed project will not trigger the applicability of any new NSPS requirements to GGS Unit 2. 

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 2 at GGS 

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. GGS Unit 2 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 2 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. GGS Unit 2 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). 

9.3 Particulate Matter Emissions 

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

GGS Unit 2 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/(7,538 MMBtu/hr) 0.233 = 0.128 lb/MMBtu 
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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. 

9.4 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. GGS Unit 2 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. 

9.5 Acid Rain 

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

chapter. Unit 2 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. GGS is currently operating under an Acid 

Rain Permit that was issued on January 26, 2005.

9.6 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). 
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9.7 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. NPPD 

submitted a BART analysis for GGS Units 1 and 2 on August 7, 2007. 

10.0 Discussion of Specific Permit Conditions 

General Condition V. 

General Condition V. requires the low NOx Burners supported by an over-fire air port system on Unit 2 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: 

“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. NPPD submitted additional 

timeline information regarding the time necessary to install the LNB/OFA to the Department on April 30, 2008. 

The Department will notify NPPD 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 adjusted 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 GGS Units 1 and 2. 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. 
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(B) Establishes a CO emissions limit and Department determined BACT control, combustion controls, for 

GGS Units 1 and 2. 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. NPPD is required to install a CO CEMs on each unit. 

(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 XIII.(A)(2)(d) and XIII.(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 May 17, 2009. 

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 May 28, 2009, in the 

North Platte Telegraph newspaper. Persons or groups shall have 30 days from that issuance of public notice 

(June 26, 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.