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Nebraska Department of Environmental Quality 

State Implementation Plan

For

Regional Haze 

And

Best Available Retrofit Technology (BART)

Mike Linder, Director

Dave Heineman, Governor

June 30, 2011
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Table of Contents

1 Executive Summary..............................................................................................................................5

2 Background and Overview of the Federal Regional Haze Regulation.............................................7

2.1 General Background / History of Federal Regional Haze Rule.....................................................7

3 General Planning Provisions................................................................................................................9

4 Regional Planning ...............................................................................................................................10

5 State/Tribe and Federal Land Manager Coordination ...................................................................12

6 Assessment of Baseline and Current Conditions and Estimate of Natural Conditions in Class I 

Areas ..........................................................................................................................................................13

7 Monitoring Strategy............................................................................................................................15

7.1 Current Monitoring Strategy..........................................................................................................15

7.1.1 Measuring Visibility Data...............................................................................................................15

7.1.1.1 Nebraska National Forest.............................................................................................................15

7.1.1.2 Crescent Lake Wild Life National Refuge...................................................................................16

7.1.1.3 Omaha Tribe ................................................................................................................................17

7.1.2 Characterizing Visibility Data ........................................................................................................18

7.1.3 Data Validation and Reporting .......................................................................................................18

7.2 Special Monitoring Studies .............................................................................................................18

7.3 Future Monitoring Strategy............................................................................................................19

8 Emissions Inventory............................................................................................................................20

8.1 2002 Emissions Inventory Summary..............................................................................................20

8.1.1 Point Source Emissions...................................................................................................................21

8.1.1.1 Electric Generating Units.............................................................................................................21

8.1.1.2 Fuel Ethanol Manufacturing Facilities.........................................................................................22

8.1.2 Area Source Emissions ...................................................................................................................22

8.1.3 On-road Source Emissions..............................................................................................................24

8.1.4 Non-road Source Emissions............................................................................................................24

8.1.5 Biogenic Source Emissions.............................................................................................................25

8.2 2005 Emissions Inventory and Periodic Updates..........................................................................25

8.3 2018 Predicted Emissions Inventory ..............................................................................................26

8.3.1 Discussion of 2018 Predicted Emissions Inventory........................................................................28

8.3.1.1 Volatile Organic Compounds.......................................................................................................28

8.3.1.2 Nitrogen Oxides...........................................................................................................................28

8.3.1.3 Sulfur Dioxide..............................................................................................................................30

8.3.1.4 Particulate Matter.........................................................................................................................30

8.3.1.5 Ammonia......................................................................................................................................31
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9 Modeling Assessment..........................................................................................................................32

9.1 Modeling Protocol............................................................................................................................32

9.2 Quality Assurance Project Plan......................................................................................................33

9.3 Model Inputs.....................................................................................................................................33

9.3.1 Year Selection.................................................................................................................................33

9.3.2 Domain............................................................................................................................................34

9.3.3 Emissions Inputs.............................................................................................................................34

9.3.4 Meteorological Input Preparation ...................................................................................................34

9.4 Model Performance Evaluation......................................................................................................34

10 Best Available Retrofit Technology (BART)..................................................................................36

10.1 Identification of BART – Eligible Sources in Nebraska .............................................................36

10.2 Determination of Units Subject to BART....................................................................................38

10.3 Determination of BART Requirements for Subject-to-BART Sources....................................40

10.4 BART Determination Process.......................................................................................................41

10.5 Summary of BART Determination- OPPD .................................................................................42

10.5.1 Nebraska City Station Unit #1 – Not a Presumptive Unit ............................................................42

10.5.2 BART Determination Summary for PM.......................................................................................44

10.5.3 BART Determination Summary for SO2 ......................................................................................45

10.5.4 BART Determination Summary for NOx......................................................................................46

10.6 Summary of BART Determination- NPPD..................................................................................47

10.6.1 BART Determination Summary for PM.......................................................................................47

10.6.2 BART Determination Summary for NOx......................................................................................48

10.6.3 BART Determination Summary for SO2 ......................................................................................49

10.6.3.1 Unique Water Impacts in the Twin Platte Basin........................................................................50

10.6.3.2 Platte River Recovery and Implementation Program.................................................................55

10.6.3.3 Acquisition of Allocations and Offsets (Costs of Water) ..........................................................56

10.6.3.4 Economic Impacts from Irrigated Agriculture...........................................................................61

10.6.3.5 Visibility Impacts.......................................................................................................................62

10.6.4 Dry Sorbent Injection (DSI) Evaluation .......................................................................................64

10.6.4.1 Updated BART Analysis for SO2..............................................................................................64

10.6.4.2 Technical Feasibility..................................................................................................................64

10.6.4.3 Eliminate technically infeasible options....................................................................................65

10.6.4.4 Evaluate control effectiveness ...................................................................................................65

10.6.4.5 Evaluate impacts and document the results ...............................................................................65

10.6.4.6 Cost of Compliance....................................................................................................................65

10.6.4.7 Energy Impacts ..........................................................................................................................66

10.6.4.8 Other (Non-Air Quality) Environmental Impacts......................................................................66

10.6.4.9 Remaining Useful Life...............................................................................................................67

10.6.4.10 Visibility Impacts.....................................................................................................................67

10.6.4.11 SO2 BART Determination for GGS.........................................................................................70

11 Reasonable Further Progress/Long Term Strategy.......................................................................71

11.1 Determining Visibility Impact ......................................................................................................71

11.2 State Consultation Process............................................................................................................82

11.2.1 Minnesota (Northern Midwest).....................................................................................................82
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11.2.2 Central States (Missouri, Arkansas)..............................................................................................83

11.2.3 Wichita Mountains (Oklahoma)....................................................................................................85

11.2.4 Badlands National Park and Wind Cave National Park (South Dakota) ......................................86

11.2.5 Rocky Mountain National Park (Colorado)..................................................................................87

11.3 Long Term Strategy.......................................................................................................................89

11.3.1 Federal Measures..........................................................................................................................89

11.3.1.1 Clean Air Interstate Rule/ Clean Air Transport Rule.................................................................89

11.3.1.2 Mobile Source Related Emissions and Standards......................................................................90

11.3.1.3 Tier 2 Vehicle and Gasoline Sulfur Program.............................................................................90

11.3.1.4 Locomotives and Marine Engines..............................................................................................91

11.3.1.5 Small Engines (Personal Watercraft; Lawn and Garden Equipment)........................................91

11.3.1.6 NESHAP MACT Standards.......................................................................................................91

11.3.2 Visibility Requirements under the New Source Review and Prevention of Significant 

Deterioration Program ................................................................................................................................92

11.3.3 Measures to Mitigate the Impacts of Construction Activities.......................................................92

11.3.3.1 Water Regulations on Construction Activities...........................................................................93

11.3.3.2 Fugitive Dust Regulations..........................................................................................................93

11.3.4 Agricultural and Forestry Smoke Management ............................................................................93

11.3.5 Enforceability of Emission Limitations and Control Measures....................................................94

11.3.6 Source Retirement and Replacement Schedules...........................................................................94

11.3.7 Anticipated Net Effect on Visibility Resulting from Projected Changes to Emissions................94

11.4 Reasonable Further Progress Conclusion....................................................................................95

12 Plan Revisions and Progress Reports..............................................................................................96
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1 Executive Summary

In amendments to the Clean Air Act (CAA) in 1977, Congress set a national goal to restore 

national parks and wilderness areas to pristine conditions by preventing any future, and 

remedying any existing man-made visibility impairment. In 1999, the U.S. Environmental 

Protection Agency (EPA) finalized the federal Regional Haze Rule, which aims to fulfill the 

goals set forth in the CAA by the year 2064. The Regional Haze Rule addresses the combined 

effects of several pollution sources over large geographic areas. It was therefore necessary to use 

a regional planning approach.

EPA designated five regional planning organizations (RPOs); the Central Regional Air Planning 

Association (CENRAP) was designated as the RPO representing the central portion of the United 

States. Since its inception, the State of Nebraska has been actively involved in CENRAP. The 

Nebraska Regional Haze Plan incorporates data analyses, modeling results, and technical support 

documents prepared for CENRAP members by various contractors. In addition, CENRAP has 

served as a platform for consultation between states, tribes, federal land managers (FLMs), and 

stakeholders.

The federal Regional Haze Rule requires states to submit revisions to their State Implementation 

Plans by December 17, 2007. The Regional Haze Rule applies to all states that contribute to 

visibility impairment, even those states that do not have Class I areas. 

States are required by 40 CFR 51.308 to set reasonable progress goals for achieving natural 

visibility conditions, develop a long-term emissions reduction strategy, and maintain a 

monitoring network and emissions inventory to support regional haze programs. In addition, 

Section 51.308(e) outlines the requirements for applying Best Available Retrofit Technology 

(BART) to certain older emission sources that were not previously regulated by the CAA.

In July of 2005, EPA published a revised final rule, including Appendix Y to 40 CFR Part 51 

―Guidelines for BART Determinations under the Regional Haze Rule.‖ Nebraska followed these 

guidelines in its selection of sources that are subject to BART requirements. We further 

followed these rules when making determinations on control technology requirements. Appendix 

Y of the guidelines outlines a presumptive emission rate or percent of control for SO2 and NOx,

for certain types of facilities, unless the state can demonstrate, based on careful consideration of 

the statutory five factors. The five factors are: cost effectiveness, energy and non-air 

environmental impacts, existing controls at source, remaining useful life of source, and the 

degree of visibility improvement which may be reasonably anticipated from the technology.

Nebraska has three subject-to-BART emission units at two facilities. One facility, OPPD 

Nebraska City was not subject to presumptive levels of control; however, NDEQ used the 

statutory factors as a guide for making the BART determination. For the other facility which has 

two BART units, NPPD Gerald Gentleman Station, due to unique non-air environmental impacts 

and cost effectiveness and relative degree of visibility improvement, NDEQ determined 

presumptive levels of sulfate control were not appropriate and that presumptive levels of nitrate 

control were appropriate. The BART requirements are outlined in Chapter 10 of this document.

In addition to requiring BART controls at subject facilities, the state also evaluated whether other 

sources need to be addressed at this time to reach reasonable progress goals. This analysis is 

referred to as the statutory factor analysis, or four-factor analysis. 
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Nebraska has no mandatory Class I areas, but in an effort to support the planning process, 

Nebraska worked through CENRAP to coordinate regional efforts to reduce visibility at Class I 

areas within the CENRAP states. For areas outside the region, Nebraska consulted with other 

states that may have required reductions to improve visibility from emissions from Nebraska 

sources. Nebraska will continue to participate and cooperate in regional efforts to reduce 

visibility impairment at Class I areas outside its borders by maintaining an IMPROVE visibility 

monitoring network and emissions inventory, and providing periodic progress reports and SIP 

revisions as required by the Regional Haze Rule. 
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2 Background and Overview of the Federal Regional Haze Regulation

2.1 General Background / History of Federal Regional Haze Rule

In amendments to the Clean Air Act (CAA) in 1977, Congress added Section 169 (42 U.S.C. 

7491) setting forth the following national visibility goal of restoring pristine conditions in certain 

national parks and wilderness areas, which it named Class I areas:

“Congress hereby declares as a national goal the prevention of any future, and the remedying of 

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

results from man-made air pollution.”

Over the following years, modest steps were taken to address the visibility problems in Class I 

areas. The control measures taken mainly addressed ―plume blight‖ from specific pollution 

sources, and did little to address regional haze issues in the Eastern United States. Plume blight 

is the visual impairment of air quality that manifests itself as a coherent plume. This is a result 

from specific sources, such as a power plant smoke stack, emitting pollutants into a stable 

atmosphere. The pollutants are then transported in some direction with little or no vertical 

mixing. 

When the CAA was amended in 1990, Congress added Section 169B (42 U.S.C. 7492) 

authorizing further research and regular assessments of progress. In 1993, the National Academy 

of Sciences concluded: “current scientific knowledge is adequate and control technologies are 

available for taking regulatory action to improve and protect visibility.”

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In addition to authorizing creation of visibility transport commissions and setting forth their 

duties, Section 169B(f) of the CAA specifically mandated creation of the Grand Canyon 

Visibility Transport Commission (Commission) to make recommendations to the U.S. 

Environmental Protection Agency (EPA) for the region affecting the visibility of the Grand 

Canyon National Park. Following four years of research and policy development the 

Commission submitted its report to EPA in June of 1996. This report, as well as the many 

research reports prepared by the Commission, contributed invaluable information to EPA in its 

development of the federal Regional Haze Rule.

EPA‘s Final Regional Haze Rule was adopted July 1, 1999, and went into effect on August 30, 

1999. The Regional Haze Rule aims at achieving national visibility goals by 2064. This 

rulemaking addressed the combined visibility effects of various pollution sources over a wide 

geographic region. This wide-reaching pollution net meant that many states, even those without 

Class I Areas, would be required to participate in haze reduction efforts. EPA designated five 

regional planning organizations (RPOs) to assist with the coordination and cooperation needed to 

address the visibility issue. The Central Regional Air Planning Association (CENRAP) was 

designated as the RPO to represent those states that make up the midsection of the contiguous 

United States.

On May 24, 2002 the US Court of Appeals, DC District Court ruled on the challenge brought by 

the American Corn Growers Association against EPA‘s Regional Haze Rule of 1999. The Court 

remanded to EPA the Best Available Retrofit Technology (BART) provisions of the rule, and 

denied industry‘s challenge to the haze rule goals of natural visibility and no degradation

 

1 Protecting Visibility in National Parks and Wilderness Areas. National Research Council. Washington, DC: 1993.
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requirements. EPA adopted revisions to the Regional Haze rule pursuant to the remand. To 

facilitate the review of this State Implementation Plan (SIP) by the Environmental Protection 

Agency (EPA), Federal Land Managers (FLM), stakeholders and the public, a guide is provided 

to identify where the Section 308 Requirements may be found in this document. (See Appendix 

2.1)

Appendix 2.1 Section 308 Requirements Crosswalk
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3 General Planning Provisions

Pursuant to the requirements of 51.308(a) and (b), Nebraska submits this SIP submission as

adopted to meet the requirements of EPA‘s Regional Haze rules that were adopted to comply 

with requirements set forth in the Clean Air Act. Elements of this Plan address the Core 

Requirements pursuant to 40 CFR 51.308(d) and the Best Available Retrofit Technology 

(BART) components of 40 CFR 50.308(e). In addition, this SIP addresses Regional Planning, 

State/Tribe and Federal Land Manager coordination, and contains a commitment to provide Plan 

revisions and adequacy determinations.

Nebraska has adopted this SIP in accordance with Title 115 the Nebraska Administrative 

Procedures Act and 40 CFR 51.100 - 105. The Nebraska Department of Environmental Quality 

(NDEQ) provided public notice of the opportunity to comment on the SIP on December 6, 2010. 

NDEQ provided notice of public hearing on December 6, 2010. NDEQ held a public hearing 

regarding the SIP on January 21, 2011. All public comments on this proposed SIP, inclusive of 

those made by the Federal Land Manager (FLM), affected States, and Tribes were addressed and 

are summarized in Appendix 3.1. A complete copy of the public proceedings, including the 

affidavit of publication and the hearing transcript may be found in Appendix 3.2. 

A copy of this report is available at the NDEQ Offices, 1200 N Street Suite 400; Lincoln, NE 

68509-8922 and on-line at www.ndeq.state.ne.us. A notice of this report‘s availability for 

review and comment was submitted to the Omaha World Herald for general state-wide 

publication on or before December 6, 2010, and on the Department‘s website. In addition, 

Nebraska specifically made the States of Colorado, South Dakota, Missouri, Minnesota, and 

Oklahoma aware of its availability. 

Appendix 3.1 Public Comments & Responsiveness Summary

Appendix 3.2 Affidavit of Publication
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4 Regional Planning

In 1999, EPA and affected States/Tribes agreed to create five Regional Planning Organizations 

(RPOs) to facilitate interstate coordination on Regional Haze SIP/TIPs. The State of Nebraska is 

a member of the Central Regional Air Planning Association (CENRAP) RPO. Members of 

CENRAP are in the geographical areas listed in Table 4.1. Figure 4.1 shows a map of all five 

regional planning organizations.

Table 4.1 CENRAP Geographical Area*

Arkansas Iowa

Kansas Louisiana

Minnesota Missouri 

Nebraska Oklahoma 

Texas

*Includes both state and tribal areas 

Figure 4.1 Geographical Areas of Regional Planning Organizations

The governing body of CENRAP is the Policy Oversight Group (POG). The POG is made up of 

18 voting members representing the 9 States and 3 Tribes from each EPA Region within the 

CENRAP region and non-voting members representing local agencies, the EPA, the Fish and 

Wildlife Service, Forest Service and National Park Service. The Policy Oversight Group (POG) 

facilitates communication with Federal Land Managers, stakeholders, the public, and with 

CENRAP staff. 
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Since its inception, CENRAP has established an active committee structure to address both 

technical and non-technical issues related to regional haze. The work of CENRAP is 

accomplished through five standing workgroups: Monitoring; Emission Inventory; Modeling; 

Communications; and Implementation and Control Strategies. Participation in workgroups is 

open to all interested parties, including stakeholders and the public. Ad hoc workgroups may be 

formed by the POG to address specific issues. Ultimately, policy decisions are made by the 

CENRAP POG. However, SIP decisions are left to the individual State. 

CENRAP has adopted the approach that the Regional Haze Rule requires the ―States to 

establish goals and emission reduction strategies for improving visibility in all 156 mandatory 

Class I parks and wilderness areas.‖ The rule also encouraged states and tribes to work together 

in regional partnerships. 

This SIP utilizes and refers to data analysis, modeling results and other technical support 

documents prepared for CENRAP members by contractors and provided through the CENRAP 

website or file transfer protocol (FTP) site. 

By coordinating with CENRAP and other RPOs as well as through direct consultation with other 

states, Nebraska has worked to ensure that its long term strategy and BART determinations 

provide sufficient reductions to mitigate impacts of sources from Nebraska on affected Class I 

areas. 
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5 State/Tribe and Federal Land Manager Coordination

40 CFR Section 51.308(i) require coordination between States and the Federal Land Managers 

(FLMs). FLMs are an integral part of CENRAP‘s POG and the membership on standing 

committees. FLMs have contributed to the development of technical and non technical work as a 

result of that participation. In addition, opportunities have been provided by CENRAP for FLMs 

to review and comment on each of the technical documents developed by CENRAP and included 

in this SIP. NDEQ provided FLMs an early opportunity to comment on the draft BART permits 

for NPPD and OPPD prior to finalization of the SIP. Nebraska provided agency contacts to the 

FLMs as required. In development of this plan, the FLMs were consulted in accordance with the 

provisions of 51.308(i)(2). 

The State of Nebraska provided FLMs an opportunity for consultation, in person and at least 60 

days prior to holding any public hearing on the essential elements of the control strategies of the 

implementation plan or plan revision.

During the consultation process, the FLMs were given the opportunity to address their:

Assessment of the impairment of visibility in any Class I areas

Recommendations on the development of reasonable progress goals

Recommendations on the development and implementation of strategies to 

address visibility impairment.

Nebraska sent the draft Best Available Retrofit Technology permits to the FLMs in mid-2008 

and again prior to public notice. The FLM comments on the BART permits were addressed. No 

public hearings were requested on the BART permits. For the proposed Regional Haze SIP 

hearing, Nebraska notified all interested parties, including the FLMs, affected and nearby states, 

and Tribes on November 16, 2010, via email. Copies of all appendices were made available upon 

request via CD. This proposed SIP and appendices were also made available on our website.

Comments received from the Federal Land Managers on the proposed SIP were addressed.

Copies of the letters received from the FLMs are attached. A summary of responses to their 

comments are included in Appendix 3.1 and in the BART response to comments found in 

Appendix 10.8 to this plan. 

Nebraska will continue to coordinate and consult with the Federal Land Managers during the 

development of future progress reports and plan revisions, as well as during the implementation 

of programs having the potential to contribute to visibility impairment in the mandatory Class I 

areas. The FLMs must be consulted in the following instances:

Development and review of implementation plan revisions

Review of 5-year progress reports

Development and implementation of other programs that may contribute to impairment 

of visibility in Class I areas.
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6 Assessment of Baseline and Current Conditions and Estimate of Natural Conditions in

Class I Areas

The goal of the Regional Haze Rule is to restore natural visibility conditions to the 156 Class I

areas identified in the 1977 Clean Air Act Amendments. Section 51.301(q) defines natural

conditions: ―Natural conditions include naturally occurring phenomena that reduce visibility as

measured in terms of light extinction, visual range, contrast, or coloration.‖ Regional Haze SIPs

must contain measures that make ―reasonable progress‖ toward this goal by reducing

anthropogenic emissions that cause haze. Nebraska does not have any Class I areas. 

This chapter is provided as background information to support the technical analyses presented 

throughout this document.

For each Class I area, there are three metrics of visibility that are part of the determination of

reasonable progress:

1) Baseline conditions,

2) Natural conditions, and

3) Current conditions.

Each of the three metrics includes the concentration data of the visibility pollutants as different

terms in the light extinction algorithm, with respective extinction coefficients and relative

humidity factors. Total light extinction when converted to deciviews (dv) is calculated for the

average of the 20 percent best and 20 percent worst visibility days.

―Baseline‖ visibility is the starting point for the improvement of visibility conditions. It is the

average of the IMPROVE monitoring data for 2000 through 2004 and can be thought of as

―current‖ visibility conditions for this initial planning period. The comparison of initial baseline

conditions to natural visibility conditions indicates the amount of improvement necessary to

attain natural visibility by 2064.

Each state must estimate natural visibility levels for Class I areas within its borders in

consultation with federal land managers and other states [40 CFR 51.308(d)(2)]. ―Current

conditions‖ are assessed every five years as part of the SIP review where actual progress in

reducing visibility impairment is compared to the reductions committed to in the SIP. EPA‘s 

Guidance for Estimating Natural Visibility Conditions under the Regional Haze Program (2) 

provides states a ―default‖ estimate of natural visibility. The default values of concentrations of 

visibility pollutants are based on a 1990 National Acid Precipitation Assessment Program report 

(3). In the guidance, the United States is divided into ―East‖ and ―West‖ along the western 

boundary of the states one tier west of the Mississippi River. This division divides the CENRAP 

states into ―East‖ (MN, IA, MO, AR, LA) with seven Class I areas, and ―West‖ (NE, KS, OK, 

TX) with three Class I areas. In the two equations, only sulfate and organic carbon have different 

values, but the calculated deciview difference is significant.

In the guidance, EPA also provides that states may use a ―refined approach‖ to estimate the

values that characterize the natural visibility conditions of the Class I areas. The purpose of such

a refinement would be to provide more accurate estimates with changes to the extinction

algorithm that may include the concentration values, factors to calculate extinction from a

measured particulate species and particle size, the extinction coefficients for certain compounds,
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geographical variation (by altitude) of a fixed value, and the addition of visibility pollutants.

States can choose between the default and refined equations. One equation is used to calculate

baseline and current conditions of visibility due to haze-causing pollutants and, with natural

concentrations of the same pollutants; the same equation is used to calculate natural visibility.

The old (default) algorithm:

bext = 3 f (RH) [Sulfate]

+ 3 f (RH) [Nitrate]

+ 4 [Organic Carbon]

+ 10 [Elemental Carbon]

+ 1 [Fine Soil]

+ 0.6 [Coarse Mass]

+ 10

The new (refined) algorithm:

(Differences from the default are in bold)

bext = 2.2 fS (RH) [Small Sulfate] + 4.8 fL(RH) [Large Sulfate]

+ 2.4 fS (RH) [Small Nitrate] + 5.1 fL(RH) [Large Nitrate]

+ 2.8 fS (RH) [Small Organic Carbon] + 6.1 fL(RH) [Large Organic Carbon]

+ 10 [Elemental Carbon]

+ 1 [Fine Soil]

+ 1.7 fSS(RH) [Sea Salt]

+ 0.6 [Coarse Mass]

+ Rayleigh Scattering (Site Specific)

+ 0.33 [NO2 (ppb)]

The choice between use of the default or the refined equation for calculating the visibility

metrics for each Class I area is made by the state in which the Class I area is located [40 CFR

51.308(d)(2)]. Nebraska consulted with other CENRAP states as those states assessed baseline 

and natural visibility conditions in their respective Class I areas.
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7 Monitoring Strategy

Section 51.308(d)(4) of the federal Regional Haze Rule requires a monitoring strategy for 

measuring, characterizing, and reporting regional haze visibility impairment that is representative 

of all mandatory Class I areas. The monitoring strategy relies, in large part, upon participation in 

the Interagency Monitoring of Protected Visual Environments (IMPROVE) network. The 

IMPROVE website is located at http://vista.cira.colostate.edu/improve/ .

7.1 Current Monitoring Strategy

7.1.1 Measuring Visibility Data

Shortly after creation of the Central Regional Air Planning Association (CENRAP), the 

organization‘s Monitoring Workgroup identified large visibility data voids in southern Arkansas, 

Iowa, Kansas, southern Minnesota, Nebraska, and Oklahoma. Only five IMPROVE sites were 

located in the entire 9 state CENRAP region. Between 2000 and 2003, five more IMPROVE 

sites and 15 IMPROVE Protocol sites (i.e., sites not managed by IMPROVE directly, but by 

individual government or tribal organizations) were established in the CENRAP region.

In conjunction with CENRAP and EPA Region 7, Nebraska installed one IMPROVE protocol

sampler at Nebraska National Forest County near Halsey, NE in the central part of the State, and 

another at Crescent Lake National Wild Life Refuge in the Panhandle of the state. A third

IMPROVE Protocol sampler in Nebraska is operated independently in Thurston County, by the 

Omaha Tribe of Nebraska.

7.1.1.1 Nebraska National Forest

The IMPROVE Protocol site at Nebraska National Forest near Halsey, NE is located in the 

Sandhills of central Nebraska. The 90,000 acre forest area was first established in 1902 by 

Charles Bessey, a University of Nebraska Botanist, and is known to be the world‘s largest manmade forest. In addition to forest land, the area is characterized by rolling sand dunes covered 

with native grasses. The area is known for wildlife, including white tailed and mule deer, 

antelope, turkey, sharp-tailed grouse and the greater prairie chicken.

The primary purposes of the site are to evaluate regional haze and the contributions that may 

impact Federal Class I areas in National Parks and Wilderness Areas. The Nebraska National 

Forest site is regional in scale and the purpose is designed to understand background and 

transport of pollution into and out of the state. The monitor measures on a continuous basis for 

fine particulate matter (PM2.5) and speciates the particles to understand the composition.
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Figure 7.1 Nebraska National Forest IMPROVE Protocol Site

County: Thomas County (pop. 851)

Latitude: 41.8888

Longitude: -100.3387

Elevation: 883m above MSL

Region: Central Great Plains

Dates: 7/2002 – Present

7.1.1.2 Crescent Lake Wild Life National Refuge

The site at Crescent Lake Wild Life National Refuge in the panhandle of Nebraska serves as 

another background and transport site for evaluating background levels in rural Nebraska as well 

as understanding regional transport patterns. Like the Nebraska National Forest site, the monitor 

measures on a continuous basis for fine particulate matter (PM2.5) and speciates the particles to 

understand the composition.

This isolated refuge consists of 45,818 acres of rolling sandhills, the largest continuous sand 

dune area in America. The grass covered dunes were created from the windblown sands of an 

ancient sea.

The twenty-one lakes and numerous ponds are supported by an aquifer lying below the hills. The 

grasslands range from the densely vegetated meadows to the sparsely covered areas and support 

a wide variety of wildlife.
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Figure 7.2 Crescent Lake Wild Life National Refuge IMPROVE Protocol Site

County: Garden County (pop. 2460)

Latitude: 41.7627

Longitude: -102.4336

Elevation: 1207m above MSL

Region: Central Great Plains

Dates: 7/2002 - Present

7.1.1.3 Omaha Tribe

The Omaha Tribe also operated an IMPROVE Protocol sampler in Thurston County in northeast 

Nebraska. The monitor operated on a continuous basis and measured the same constituents as 

the other two monitors. For a period of time the Omaha Tribe also operated a nephelometer.

Figure 7.3 Omaha Tribe IMROVE Protocol Monitor 

County: Thurston County (pop. 6936)

Latitude: 42.1487

Longitude: -96.4318

Elevation: 429m above MSL

Sponsor: TRIBE

Region: Central Great Plains

Dates: 8/2003 - uknown
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7.1.2 Characterizing Visibility Data

The State of Nebraska does not have any mandatory Class I Federal areas. In accordance with 40 

CFR 51.308(d)(4)(iii), Nebraska, along with other states that do not have Class I areas, must 

establish procedures by which monitoring data and other information are used in determining the 

contribution of emissions from within the state to regional haze visibility impairment at affected 

mandatory Class I areas in other states. The procedures Nebraska used were established through 

the work completed by contractors retained by CENRAP, and are only briefly described here. 

IMPROVE monitoring data for the 2000-2004 period was used to define baseline, natural, and

2018 conditions for each of the Class I areas. PM10 was speciated into six components (sulfate, 

particulate nitrate, organic carbon, elemental carbon, soil, and coarse mass) which were used to 

develop relative response factors (RRFs) between current and predicted concentrations for each 

component. The RRFs were multiplied by current baseline values to estimate future 

concentrations. The visibility improvements for 2018 were then calculated using the original or 

new IMPROVE equation. Additional information about these analyses can be found in Chapter

4 of the Technical Support Document (TSD) prepared by ENVIRON and the Causes of Haze

Assessment work performed by Sonoma Technology for CENRAP (Appendix 9.1 and Appendix 

10.10).

Nebraska also relied upon source apportionment modeling (CAMx PSAT) in determining the

State‘s contribution to other Class I areas. This type of modeling provides the best available 

estimate of the potential visibility impacts Nebraska may have on various surrounding Class I 

areas in 2018. Source apportionment modeling for the CENRAP region is outlined in Chapter 11 

of this document.

7.1.3 Data Validation and Reporting

The filter samples from all IMPROVE modules from the three IMPROVE-protocol sites in

Nebraska are sent for analysis to the University of California in Davis (UC-D), and the resultant 

data are subjected to preliminary review and quality assurance/quality control (QA/QC) 

procedures. 

After validation, data from the three IMPROVE-protocol sites in Nebraska are sent by UC-D for 

posting to the IMPROVE website and the Visibility Information Exchange Web System 

(VIEWS) website [http://vista.cira.colostate.edu/views/]. 

7.2 Special Monitoring Studies

CENRAP, in cooperation with member states and tribes, studied the impacts of ammonia on

visibility impairment in the CENRAP region. Preliminary monitoring studies and monitoring

data analysis suggest that ammonia could contribute to visibility impairment in the CENRAP

geographical area. CENRAP conducted studies to provide more information on ammonia 

emission inventories. Given the extent of estimated ammonia emissions from natural and manmade sources such as fertilizer application, CENRAP determined that there was enough excess 

ammonia in the air such that it would not be feasible to control fine particle formation by 

controlling ammonia emissions. Rather, control of the other chemicals that combine with 

ammonia, such as nitrates or sulfates, is more conducive to reducing fine particle formation and 

consequent visibility impairment. 
19

During two measurement periods in 2002 (August 24–October 23 and November 18–December

31), an intensive study was conducted to characterize ambient fine particulate matter (PM2.5) at

the Sac and Fox Nation IMPROVE Protocol site in Reserve, Kansas. The sampling station was

configured in the same manner as the St. Louis, Missouri Supersite. Selected semi-continuous

monitors remained in operation during the six-week interim period. This special study was

funded by CENRAP and EPA Region 7. Daily 24-hour mass reconstructions demonstrated the

episodic nature and seasonal variations of sulfate (summer/fall) and nitrate (fall/winter). Ion

balances for 24-hour sampling periods were consistent with conditions favorable for formation of

ammonium nitrate. A sulfate transport episode was captured as well as elevated local ammonia

levels possibly associated with seasonal application of anhydrous ammonia to corn and soybean

fields.

From November 1, 2003 through June 28, 2006, the Sac and Fox Nation also operated a passive

ammonia monitoring station for a CENRAP ammonia monitoring project. Denuder-based gas

phase ammonia, nitric acid, and sulfur dioxide were monitored at the Reserve, Kansas site and

six other sites within the CENRAP region. Twenty-four hour samples were collected on a one insix day schedule. The denuder-based samples were analyzed by the Illinois State Water Survey 

Laboratory. IMPROVE Protocol samplers were in operation at all but one of the CENRAP 

ammonia study sites. This special ammonia study was conducted to collect data for evaluation of 

the role of ammonia in regional haze formation in the CENRAP region.

7.3 Future Monitoring Strategy

In order to assess progress in reducing visibility impairment in Class I areas, the existing

IMPROVE and IMPROVE Protocol sites will be maintained contingent upon continued federal 

103 grant funding. Data from the IMPROVE Protocol sites in Nebraska will be used to 

characterize and model conditions within the State of Nebraska. Data from IMPROVE monitors 

will be used to compare visibility conditions in Nebraska to regional haze visibility impairment 

at Class I areas affected by emissions from Nebraska to satisfy requirements of 40 CFR 

51.308(d)(4)(i). The State of Nebraska will evaluate the monitoring network periodically, 

including an evaluation of changes in technology and the need for new monitors. With 

continuation of adequate funding, the network will be reconfigured as necessary to enable 

assessment of reasonable progress toward goals for each of mandatory Class I area potentially 

affected by emissions from within the State of Nebraska. This assessment will be done as part 

of the monitoring network assessment required by federal regulation 40 CFR Part 58.
20

8 Emissions Inventory

Nebraska is required by 40 CFR 51.308(d)(4)(v) to provide a statewide emissions inventory of

pollutants that are reasonably anticipated to cause or contribute to visibility impairment in any

mandatory Class I area(s). Nebraska worked with CENRAP on the compilation of a statewide 

inventory using EPA guidance on inventorying all sources of anthropogenic and biogenic 

emissions. Nebraska‘s emissions inventory for 2002 may be found in Appendix 8.1.

8.1 2002 Emissions Inventory Summary

As specified in the applicable EPA guidance, the pollutants inventoried for Nebraska include

volatile organic compounds (VOCs), nitrogen oxides (NOx), fine particulates (PM2.5), coarse

particulates (PM10), ammonia (NH3), and sulfur dioxide (SO2). An inventory was developed for

the baseline year 2002; a summary of those inventory results is presented in Tables 8.1 and 8.2. 

Table 8.1 2002 Nebraska Emissions Summary, by Pollutant and Source Category

Source Category VOC NOx SO2 PM10 PM2.5

Tons per Year

Point 2

7,274 58,619 73,487 13,105 4,638

Area 3

66,769 15,023 7,748 447,703 83,852

On-Road4

43,113 61,850 1,822 1,277 930

Non-Road5

24,882 119,568 11,011 7,491 6,785

Fires6(Ag & Prescribed) 3,204 679 268 5,057 3,956

Nebraska Total 145,242 255,739 94,336 474,633 100,161

Table 8.2 2002 Nebraska Ammonia (NH3) Emissions Summary, by Source Category7

Source Category NH3 (TPY)

Livestock 96,983

Fertilizer Application 64,443

Biogenics (Soil) 7,829

Point 800

On-Road 1,521

Non-Road 320

Miscellaneous 7,912

Nebraska Total 179,808

 

2

Point Source Information taken from Table 2c Summary of Point Source Emissions by State and Pollutant Pechan, 

Refinement of CENRAP’s 2002 Emissions Inventories (August 31, 2005)

3 Area Source Information taken from Table 2b Summary of Area Source Emissions by State and Pollutant Pechan, 

Refinement of CENRAP’s 2002 Emissions Inventories (August 31, 2005)

4 On Road Information taken from Table 2e Summary of On Road Source Emissions by State and Pollutant Pechan, 

Refinement of CENRAP’s 2002 Emissions Inventories (August 31, 2005)

5 Non Road Information taken from Table 2d Summary of Non Road Source Emissions by State and Pollutant 

Pechan, Refinement of CENRAP’s 2002 Emissions Inventories (August 31, 2005)

6

Fire information taken from Table 2-1 and Table 2-2 of Research and Development of Planned Burning and 

Emission Inventories for the Central States Regional Air Planning Association (July 2004)

7 Ammonia information taken from Table B-1 Appendix B of Research and Development of Ammonia Emission 

Inventories for the Central States Regional Air Planning Association (October 2003)
21

Methodologies for the 2002 emissions inventory are documented in the Appendix 8.3. 

Nebraska, along with the other members of CENRAP agencies submits emission inventory 

information to EPA for purposes of building the National Emissions Inventory Report. This 

information formed the basis for the CENRAP 2002 emissions inventory. Sonoma Technology 

supplemented the National Emissions Inventory (NEI) data with area (non-point) source 

inventories specifically developed for CENRAP. These inventories addressed agricultural and 

prescribed burning, on-road and non-road mobile sources, agricultural and livestock dust, and 

agricultural ammonia. Information on fires was obtained from the Research and Development of 

Planned Burning and Emission Inventories for the Central States Regional Air Planning 

Association (July 2004) found in Appendix 8.3. 

8.1.1 Point Source Emissions

NDEQ conducts an annual emissions inventory of all Class I major sources. Synthetic minor 

sources are required to submit emissions inventories at least once every three years or as 

otherwise specified in their permit in accordance with Title 129 Chapter 6. This cycling of 

synthetic minor sources is to ensure a complete inventory once at least every three years. NDEQ 

followed internal quality assurance procedures and submitted the data to EPA for the 2002 

national emissions inventory. Following submission to the national emissions inventory, 

CENRAP provided additional quality assurance and revision opportunities for data 

improvement. E.H. Pechan & Associates, (Pechan) through a contract with CENRAP, obtained 

the Nebraska point-source inventory and worked with NDEQ and the Nebraska local agencies to 

make corrections and to fill gaps where necessary. 

8.1.1.1 Electric Generating Units 

The majority of visibility-impairing point source emissions in Nebraska currently come from the

electric utility sector. This sector represented 92% of the reported point source SO2 emissions 

and 82% of the point source NOx emissions for the 2002 inventory year. Nebraska‘s utility 

system is structured in a manner where power is provided to businesses and citizens through 

public (municipal or rural) utility districts. The largest units are found in the eastern part of 

Nebraska and in the panhandle of the state. Mid-size units servicing moderate sized 

communities are located throughout the state. In 2002, the continuous emission monitors

(CEMs) from the 13 units reporting to the EPA Clean Air Markets Division averaged between 

5,000-6,000 tons of SO2 per month and about 4,000 tons of NOx per month. 

Figure 8.1 Monthly CEM Profiles for Nebraska’s 13 EGUs
22

8.1.1.2 Fuel Ethanol Manufacturing Facilities

In 2002, there were six ethanol plants in operation in Nebraska. From 2002-2008 , due to a 

number of factors, production capacity expanded to where 24 plants are currently operating, with 

a production capacity of over 2 billion gallons per year.8 A map of the locations is shown in 

Figure 8.2. 9Since 2008, expansion of the fuel ethanol industry in Nebraska has slowed 

dramatically. The actual emission rate of NOx for these plants is relatively low compared to 

EGUs. The majority of ethanol plants are fueled with natural gas and report NOx emissions well 

below 100 tons per year. Four plants have the capability to be fueled by coal. The largest coal 

fired ethanol plant reported NOx emissions around 200 tons per year. One facility is partially 

fueled by landfill gas. One plant that is currently idle has the capacity to be fueled by methane 

that is generated from waste collected from a co-located feedlot. Many are exploring alternatives 

fuel scenarios to maximize efficiency of operations. Nebraska does not anticipate visibility 

impacts due to the operation of additional facilities as those facilities will likely be subject to the 

Prevention of Significant Deterioration (PSD) program. 

Figure 8.2 Locations of Operating Ethanol Plants

In Operation Under Construction Idle

8.1.2 Area Source Emissions

EPA treats each class of stationary area sources collectively by county. Neither EPA nor NDEQ

can feasibly collect specific information from each area source emission point; therefore EPA 

provides estimates over larger regions based upon factors such as population. Residential 

heating is an example of a stationary area source. The area-source inventory for 2002 builds on 

EPA-provided estimates for area-source emissions. It includes emissions estimates that NDEQ 

and CENRAP prepared and data from the national emissions inventory to fill gaps. 

 

8

From Nebraska Ethanol Board http://www.ne-ethanol.org/industry/ethplants.htm. 

9

From Nebraska Ethanol Board http://www.ne-ethanol.org/industry/ethplants.htm. 
23

Sonoma Technology prepared the following reports which are referenced in the Technical 

Support Document (Appendix 9.1) for CENRAP and found in Appendix 8.3: 

Research and Development of Planned Burning Emission Inventories for the Central 

States Regional Air Planning Association (July 30, 2004), 

Emission Inventory Development for Mobile Sources and Agricultural Dust Sources for 

the Central States (October 28, 2004), and 

Research and Development of Ammonia Emission Inventories for the Central States 

Regional Air Planning Association (October 30, 2003). 

The Sonoma reports were used to inform the bases of the prescribed burning, agricultural dust, 

and ammonia emissions inventories for CENRAP. 

Under contract with CENRAP, Pechan consolidated the area-source inventories from these 

various inventory sources, conducted additional quality assurance, and worked with states to 

revise this consolidated inventory. Two documents referenced in Appendix 9.1 describe the 

work of Pechan in detail: The Consolidation of Emissions Inventories (April 28, 2005) and

Refinement of CENRAP’s 2002 Emissions Inventories (August 31, 2005), both may also be found 

in Appendix 8.3. University of California at Riverside (UCR), under contract with CENRAP, 

removed selected sources from the consolidated area inventories to process them as separate 

subcategories. UCR created these subcategories to allow specialized processing within the 

Sparse Matrix Operator Kernel Emissions (SMOKE) model in anticipation of particulate source 

apportionment within the Comprehensive Air Quality Model with extensions (CAMx). 

Area sources account for the majority of the Nebraska PM10 emission inventory at 94%. As 

Figure 8.3 shows, unpaved roads comprise 52% of the PM10 emissions, 34% come from crop 

production.10 These values are based on the 2002 National Emissions Inventory. 

Figure 8.3 Compositions of PM10 Emissions

 

10 Nebraska Air Quality Report 2005-2006. 
24

Area sources account for approximately 46% of the total anthropogenic VOCs emitted in the 

state of Nebraska. The top VOC area source sectors include: solvent utilization, storage and 

transport, residential fuel combustion, and waste disposal and recycling. 

Area Source NOx and SO2 emissions are relatively small portions of the overall NOx and SO2

emissions from the state. Less than 6% of the total NOx emissions and approximately 8% of the 

total SO2 emissions come from area sources. The top sectors include residential, industrial, 

commercial/institutional combustion, and storage and transport.

8.1.3 On-road Source Emissions

CENRAP developed the on-road mobile source emissions inventory for 2002 with contractor 

support. For all counties in Nebraska and elsewhere throughout the CENRAP region, Sonoma 

Technology provided vehicle miles traveled data for all months of 2002 and MOBILE6 input 

files only for the months of January and July 2002, using the methods and data described in the 

report Emissions Inventory Development for Mobile Sources and Agricultural Dust Sources for

the Central States (October 28, 2004), referenced in Appendix 8.3. CENRAP contractors then 

prepared MOBILE6 input files for the remaining months of 2002 and processed the mobile 

emissions using the MOBILE6 model within the SMOKE framework. The two sets of results 

from the SMOKE process were then merged together to obtain an on-road mobile source 

emissions file for the entire CENRAP region.

8.1.4 Non-road Source Emissions

The non-road source emissions category includes aircraft operations, marine vessels, recreational

boats, railroad locomotives, and a broad category of other equipment ranging from large 

construction equipment to lawn equipment. Calculation methods for emissions from non-road 

engine sources are based on information about equipment population, engine horsepower, load 

factor, emission factor, and annual usage. 

Sonoma Technology, under contract to CENRAP, used the NONROAD model to prepare and 

develop broad emissions estimates for the non-road mobile source 2002 emission inventory. 

Sonoma Technology documented the methods and data used to generate the 2002 emissions

inventory in the report Emissions Inventory Development for Mobile Sources and Agricultural 

Dust Sources for the Central States (October 28, 2004) referenced in Appendix 8.3.

Pechan consolidated the estimates of Sonoma Technology with those of EPA to generate the full 

non-road emissions inventory. In the process of consolidating the emissions estimates, Pechan 

assured quality of the data and worked with NDEQ to make necessary corrections before 

creating SMOKE model formatted files. The local air agency, Lancaster County Health 

Department (LLHD) provided its own non-road inventory for Source Classification Code (SCC)

2260000000 (Off-highway Vehicle Gasoline, 2-Stroke: 2-Stroke Gasoline except Rail and 

Marine: All). Pechan removed inventories for SCCs starting with 226 in Lancaster County to 

correct double-counting of emissions. This adjustment was made by Pechan for Base02b 

modeling. Pechan made specific corrections to the fuel oxygenate content used in the 

NONROAD model. Two documents referenced in Appendix 8.3 describe Pechan‘s work: The 

Consolidation of Emissions Inventories (April 28, 2005) and Refinement of CENRAP’s 2002 

Emissions Inventories (August 31, 2005).
25

Of all non-road categories, non-road diesel engines made up the majority of the SO2 and NOx

emissions for the nonroad sector. Non-road sources are the second highest source of SO2

emissions in Nebraska, yet comprise only about 11.6% of the total SO2 inventory. However, nonroad NOx emissions are 47% of the statewide total for non-biogenic sources and are the largest 

sector for this pollutant, at more than double the total from all point sources combined.

8.1.5 Biogenic Source Emissions

EPA calculates biogenic emissions based on land use data that characterize types of vegetation as 

county-total or grid-cell values. 

NDEQ‘s biogenic source emissions were estimated through the use of CENRAP‘s contractor 

who ran the Biogenic Emissions Inventory System 3 (BEIS3) model within the SMOKE 

framework to generate a biogenic emissions inventory. The BEIS3 system derives estimates of 

biogenic gas-phase emissions from land-use information, emissions factors for different plant 

species, and hourly meteorological data on a coordinate grid. The technical support document 

found in 9.1 describes the development of the biogenic emissions inventory.

Nebraska‘s Biogenic Emissions are found in Table 8.3:

Table 8.3 Nebraska 2002 Biogenic Emissions Inventory

Source 

Category

VOC NOx SO2 PM10 PM2.5 NH3

Tons per Year

Biogenic 533,705 39,446 0 0 0 7,829

8.2 2005 Emissions Inventory and Periodic Updates

States are required by 40 CFR 51.308(d)(4)(v) to include in their SIPs a commitment to update 

their statewide emissions inventories periodically. Nebraska‘s Emissions Inventory for 2005 is 

the most recent state-wide emissions inventory available. This inventory is available on EPA‘s 

website at http://www.epa.gov/ttn/chief/eiinformation.html.

Nebraska tracks air emissions over time as required by current EPA regulations and the Air 

Emissions Reporting Rule (AERR). This federal rule, proposed in December 2005 and finalized 

in December 2008, consolidates the current emission inventory reporting requirements, and will 

require that emissions be reported every three years from the following source categories in all 

parts of the State, excluding sources located on tribal lands:

• Point

• Area

• On-road mobile

• Nonroad mobile

In addition, all visibility-impairing pollutants are required to be included for the reportable

categories listed above. These pollutants will include NOx, SO2, PM10, PM2.5, VOCs, and NH3. 

The rule requires that starting in 2009, emissions reports will be due 12 months after the end of

the year. The rule can be found at: http://www.epa.gov/ttn/chief/aerr/.
26

Nebraska intends to follow the reporting requirements of the AERR where funding and staffing

allow. We commit to updating its point source emissions inventory annually and to analyze 

sectors identified in the regional haze planning process that need improvement on a periodic 

basis.

In the past, due to available resources, Nebraska chose to utilize the EPA-generated nonpoint, 

on-road, and nonroad inventories when available. It is anticipated that practice will continue 

unless an error is noted in the EPA generated inventory that requires correction or there is 

another reason for NDEQ to generate the information. Nebraska will work with EPA to correct 

any errors in the aforementioned inventories. 

8.3 2018 Predicted Emissions Inventory

The 2002 emissions were grown to year 2018, primarily using the Economic Growth Analysis

System (EGAS6), MOBILE 6.2 vehicle emission modeling software, and the Integrated Planning

Model (IPM) version 2.93 for electric generating units (EGUs). Again, this work was done 

through CENRAP contractor support. Table 8.4 is a summary of those inventory results. The 

complete 2018 emissions inventory is submitted as Appendix 8.2. The 2018 emissions for most 

source categories were based on projections of the 2002 inventory assuming growth and ―on the 

books‖ control. The 2018 emissions for Electrical Generating Units (EGUs) were based on

simulations of the IPM that took into the account the effects of the Clean Air Interstate Rule 

(CAIR) on emissions from EGUs in CAIR states using an IPM realization of a CAIR cap-andtrade program. 

At the time modeling was conducted, Best Available Retrofit Technology (BART) decisions had 

not been made. Regardless, reductions anticipated from BART controls for electric generating 

units (EGU) in Oklahoma, Arkansas, Kansas, and Nebraska were included in projections of 2018 

emissions before the BART decisions were complete. These anticipated reductions were based 

on actual operating conditions and estimated control efficiencies from utilities.

Newly permitted coal-fired utilities were also included in 2018 projections. Therefore, two 

newly permitted units in Nebraska have been factored into the projections. The permitted 

allowable emissions were included into the projections. Conservatively, none of new units the 

IPM model projected to be installed, but not currently planned or permitted, were removed from 

the simulation. This is likely to project higher than needed allowable emissions, because the 

majority of the additional power that is projected to be needed is already factored in with the 

cleaner, newly permitted facilities. It is expected that with the new, cleaner units coming online, 

older units will be relied upon less. 

To correct the 2018 projections to account for the BART decisions, Table 8.5 has been updated. 

NDEQ also noted that other states in the MANE-VU region used a 2018 projection of 73,629 

tons SO2 per year. That value was obtained from IPM v 2.1.9.

Some source categories were held constant between 2002 and 2018 because either stagnant 

growth was deemed appropriate or insufficient data was available to adequately project future 

growth or controls. These categories include: biogenic VOC and NOx emissions, windblown 

dust, and emissions from fires.
27

Table 8.4 Actual SO2 Emissions from EGUs (Tons per Year)

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Gerald 

Gentleman 

Station

 

31,297 

 

32,152 

 

31,089 

 

32,035 

 

28,171 

 

31,135 

 

28,815 

 

31,362 

 

31,931 

 

29,741 

Whelan 

Energy 

Center

 

2,008 

 

2,007 

 

2,152 

 

2,352 

 

2,563 

 

2,330 

 

2,207 

 

2,229 

 

2,001 

 

2,301 

Lon D Wright 

Power Plant

 

1,088 

 

978 

 

1,017 

 

1,183 

 

1,332 

 

1,401 

 

1,708 

 

1,958 

 

1,250 

 

1,206 

Nebraska

City Station

 

16,205 

 

12,820 

 

15,052 

 

15,593 

 

17,550 

 

14,994 

 

14,173 

 

17,498 

 

19,074 

 

14,296 

North Omaha 

Station

 

11,799 

 

11,509 

 

11,730 

 

16,125 

 

16,705 

 

14,315 

 

14,749 

 

15,012 

 

13,159 

 

10,515 

Platte 

2,436 

 

2,250 

 

2,194 

 

2,158 

 

2,476 

 

2,637 

 

2,641 

 

3,086 

 

2,679 

 

2,365 

Sheldon 

5,410 

 

5,624 

 

4,478 

 

4,768 

 

4,878 

 

4,403 

 

4,627 

 

4,552 

 

5,395 

 

3,758 

70,243 67,340 67,712 74,214 73,675 71,215 68,920 75,697 75,489 64,182 70,869

The average SO2 emissions for the last 10 years from the coal fired power plants have been 

70,869 tons per year. Emissions have been within 7-10 % of that tonnage since 2001, with the 

low being in 2010. According to the US Census the population in Nebraska grew 6.7% from 

2000 – 2010. Assuming that the population grows another 6.7% from 2010 to 2018, and that 

there is a commensurate growth in EGU emissions, it is reasonable to anticipate the EGU point 

source SO2 contribution to be 75,617 tons per year in 2018. If EGU emissions contribute 92% 

overall, SO2 point source emissions would be anticipated to be 82,193 tons per year in 2018.

Table 8.5 2018 Nebraska Projected Emissions Summary, by Pollutant and Source Category

Source 

Category

VOC NOx SO2 PM10 PM2.5

Tons per Year

Point 13,344 56,190 82,193 18,654 8,596

Area 78,417 17,737 9,793 303,578 56,193

On-Road 18,862 19,702 236 432 432

Non-Road 14,611 50,972 226 3,269 2,974

Fires 3,204 679 268 5,057 3,956

Biogenic 533,705 39,446 0 0 0

Totals 660,868 185,040 92,716 335,012 76,610

Methodologies used to develop the non-SO2 2018 emissions inventory are documented in the 

CENRAP Technical Support Document found in Appendix 9.1. 

Table 8.6 presents percent changes in the inventory between 2002 and 2018.
28

Table 8.6 2018 Percent Changes in Nebraska Emissions 2002 to 2018, 

By Pollutant and Source Category

VOC NOx SO2 PM10 PM2.5

Tons per Year

83% -4% 12% 42% 85%

17% 18% 26% -32% -33%

-56% -68% -87% -66% -54%

-41% -57% -98% -56% -56%

0% 0% 0% 0% 0%

0% 0% N/A N/A N/A

-12% -43% -1.7% -30% -28%

8.3.1 Discussion of 2018 Predicted Emissions Inventory

8.3.1.1 Volatile Organic Compounds

Although VOC emissions from area and point sources are projected to grow by 2018, the onroad and non-road sectors are expected to decrease due to fleet turnover and improvement in 

efficiency of engines. Therefore, overall VOCs are expected to decrease state-wide by 12% by 

2018. Furthermore, as evidenced in the zero-out modeling done by ENVIRON and UCR for 

CENRAP to measure the impact of VOCs from BART-eligible facilities to Class I areas, VOC is 

not anticipated to be a large contributor to visibility impairment from point sources in the Class I 

areas surrounding Nebraska. When VOCs were zeroed out, the maximum improvement was less 

than 0.25 Δdv at any Class I area. Nebraska‘s VOC emissions inventory is the smallest of all 9 

states in the CENRAP region in both 2002 and 2018, so it follows that Nebraska‘s VOCs would 

likely have less impact than other states. Therefore, VOCs were not considered for reductions. 

8.3.1.2 Nitrogen Oxides

For the point source sector, reductions in NOx by 2018 were predicted, primarily through BART 

controls. Even with the projected growth predicted by the models for 2018, NDEQ expects that 

the point source sector will achieve at least an overall reduction of 4% for NOx emissions. 

However, it is anticipated that the NOx reductions achieved in practice may be more than what is 

predicted through the model. Table 8.7 details the NOx reductions anticipated from installation 

of BART controls at the three BART subject units in Nebraska. 
29

Table 8.7 Potential NOx Emission Reductions in BART-Subject Units

Subject to 

Bart Unit

Baseline 

Emissions

(BART 

assumption)

2002 

Actual

Emissions11

(CENRAP 

baseline)

Permitted 

BART 

Emissions

Maximum 

Expected 

Reduction 

Max

Percent 

Reduction

Reduction 

from 

CENRAP 

baseline

Percent 

Reduction

Tons per Year of NOx

OPPD 

Nebraska 

City #1

17,020 8,132 6,827 10,193 59.9% 1,305 16.0%

NPPD 

Gerald 

Gentleman 

Station #1 

& 2

30,243 21,878 15,287 14,956 49.5% 6,591 30.1%

Total 47,263 30,010 22,114 25,149 53.2% 7,896 26.3%

The baseline emissions (BART assumption) were established using the maximum 24-hr 

emissions over a three year period (2001-2003), assuming continuous maximum operation to 

establish the maximum potential emissions. The units were then assumed to be able to meet at 

least BART presumptive levels for NOx which are 0.23 lb/MMBtu. The CENRAP baseline is 

based on actual emissions from emission year 2002. 

These three units represent 51.1% of the total actual NOx emissions from 2002 (30,010 tons of 

58,619 tons) for the entire point source sector. Reducing emissions from this sector by over 25% 

represents a significant reduction in the overall emissions for the point source sector. 

NOx makes up a relatively small proportion of the non-biogenic (less than 6%) 2002 area source 

emissions inventory for Nebraska, at 15,023 tons/yr. By 2018, area source NOx emissions are 

projected to increase by 18% respectively. Despite the increase, the area source contribution is 

about 9.6% of the overall NOx inventory in 2018. 

Models predict reductions for NOx from the combined on-road and non-road sector of about 61%

between 2002 and 2018. These reductions are anticipated due to vehicle turnover and full 

implementation of current federal regulations, including the federal emission standards for lightduty vehicles and light-duty trucks and the Tier 2 Program. Reductions are also attributed to the 

use of newer equipment subject to more stringent emissions requirements, including the Clean 

Air Nonroad Diesel Rule, locomotive emission standards, the Large-Spark Ignition and 

Recreational Vehicle Rule, and Emissions Standards for New Nonroad Small Spark-Ignition 

Engines, Equipment, and Vessels. These rules are discussed in more detail in Chapter 11. 

 

11 As reported and used in the CENRAP emissions inventory. This value was used for the modeling into the 2018 

projections. 
30

8.3.1.3 Sulfur Dioxide

For the point source sector, the IPM procedure predicts reductions in SO2 by 2018. Reductions 

were presumed primarily from the installation of BART controls. However, as discussed in 

Chapter 10, additional controls for SO2 were not required by NDEQ during the BART 

determination. Despite the lack of additional controls on the BART subject sources, and 

assuming utility SO2 emissions were to remain constant, SO2 would still be reduced overall by 

1.7% due to the other sector categories. As discussed later, these reductions are presumed to 

result from the use of lower sulfur fuels for on-road and non-road equipment. Additionally, it is 

expected that due to other federal measures, SO2 emissions are expected to be reduced. 

SO2 makes up a relatively small proportion of the Nebraska‘s 2002 area emissions inventory at 

7,748 tons/yr. By 2018, area source SO2 emissions are projected to increase by 26%. The major 

contributing source categories for SO2 are associated with fuel combustion and storage and 

transport. However, in reality, due to the lack of availability of higher sulfur fuels, the distillate 

and residual oil combustion in the area source sector are likely to remain unchanged or decrease 

between 2002 and 2018. Therefore, NDEQ believes the 2018 projections for area source 

emissions are overstated. At worst, if the 2018 projections are correct, the nonpoint emissions 

for SO2 are still only about 15% of the total SO2 inventory. 

Models predict significant reductions for SO2 from the combined on-road and non-road sectors

of about 96% between 2002 and 2018. These reductions are anticipated due to vehicle turnover 

and full implementation of current federal regulations, including the federal emission standards

for light-duty vehicles and light-duty trucks and the Tier 2 Program. This large reduction is also 

due to the requirement to use low sulfur diesel fuel by 2010. Nebraska also participates in the 

Diesel Emissions Reduction Act program which provides financial incentives to reduce 

emissions from diesel engines. These rules are discussed in more detail in Chapter 11.

The models did not take into account the Clean Air Transport Rule which is currently proposed 

by EPA. Nebraska is named under the rule and expects that when the final rule comes out, if 

SO2 emissions are deemed to be a significant contributor to downwind ozone or PM2.5 

nonattainment, reductions will be required.

8.3.1.4 Particulate Matter

Area sources account for the majority of the Nebraska PM. As shown earlier in Figure 8.3, 

unpaved roads comprise 52% of the PM10 emissions, whereas 34% come from crop production.12

These values are based on the 2002 National Emissions Inventory. Since CENRAP held 

windblown dust from nonagricultural land-use categories and fire emissions constant from 2002 

to 2018, reductions in the PM were most likely from other sectors such as the implementation of 

area MACT standards and reduction in dust from crops through alternative land practices. While 

the point source sector is predicted to increase, the overall contribution of point source PM 

emissions to the total inventory is relatively low. The on-road and non-road sector reductions are 

anticipated due to fleet turnover and full implementation of current federal regulations, including 

the federal emission standards for light-duty vehicles and light-duty trucks and the Tier 2 

Program. The low sulfur fuel requirements are expected to result in reduced PM levels as well. 

 

12 Nebraska Air Quality Report 2005-2006. 
31

Nebraska also participates in the Diesel Emissions Reduction Act program which provides 

financial incentives to reduce diesel particulates emissions from engines. 

For BART, all units subject to BART were determined to be adequately controlled through either 

an electrostatic precipitator (ESP) or through baghouses. Furthermore, BART subject facilities 

provided information supporting a conclusion that, as currently controlled, PM had a small 

impact on visibility. OPPD NCS Unit #1 greatest impact was 0.933 dV at Hercules Glades 

(MO), of which only 0.32% could be attributed to PM, or 0.00299 ΔdV. For NPPD Units #1 and 

#2, the greatest impact was in the Badlands (SD). Their total impact was predicted to be 3.121 

dV, but only 0.69% of that could be attributed to PM for a 0.0215 ΔdV potential contribution. 

Therefore, eliminating all PM from these BART subject sources would have an insignificant 

impact on visibility improvement. 

8.3.1.5 Ammonia

Livestock production and fertilizer application contribute collectively about 90% of the ammonia 

emissions in Nebraska. These sources mostly lie beyond the currently active regulatory purview 

of the air quality program at NDEQ. Furthermore, EPA currently does not consider ammonia for 

regulation as a precursor of PM2.5, but does allow states to make case by case decisions. With 

regard to this, NDEQ has followed the lead of EPA. But most significantly, because NOx and 

SO2 are considered limiting pollutants with regard to PM2.5 formation and the significant 

uncertainties in the ammonia inventories as well as in assessing the effect of ammonia emissions 

reductions on visibility, Nebraska does not consider ammonia among visibility-impairing 

pollutants. For these reasons, the 2018 projections are not included here, but may be found in the 

Appendix 8.2.

Appendix 8.1 2002 Emissions Inventory

Appendix 8.2 2018 Emissions Inventory

Appendix 8.3 Consolidation of Emissions Inventories (April 28, 2005),

Refinement of CENRAP‘s 2002 Emissions Inventories (August 31, 2005),

Research and Development of Planned Burning and Emission Inventories for the 

Central States Regional Air Planning Association (July 2004),

Emission Inventory Development for Mobile Sources and Agricultural Dust 

Sources for the Central States (October 28, 2004), and 

Research and Development of Ammonia Emission Inventories for the Central 

States Regional Air Planning Association (October 30, 2003)
32

9 Modeling Assessment

40 CFR Part 51, Appendix W provides modeling guidelines for conducting regional-scale 

modeling for particulate matter and visibility. The U.S. EPA recommends the use of one of the 

three following models to simulate pollutants impairing visibility: CMAQ, CAMx, and 

REMSAD. CENRAP contractors performed regional modeling using CMAQ and CAMx.

Community Multi-scale Air Quality (CMAQ) Model is an Eulerian model that simulates the 

atmospheric and surface processes affecting the transport, transformation and deposition of air 

pollutants and their precursors. An Eulerian model computes the numerical solution of partial 

differential equations of plumes on a fixed grid, while other models may lose accuracy or need 

re-gridding as the plumes expand. 

The Comprehensive Air quality Model with extensions (CAMx) is a computer modeling system 

for the integrated assessment of photochemical and particulate air pollution. CAMx 

incorporates all of the technical attributes demanded of state-of-the-art photochemical grid 

models, including two-way grid nesting, a sub grid-scale Plume-in-Grid module to treat the early 

dispersion and chemistry of point source NOx plumes, and a fast chemistry solver. 

Particulate Matter (PM) Modeling: CAMx Mechanism 4 (M4) provides "1-atmosphere" 

modeling for fine and coarse PM and ozone. Aqueous phase chemistry is modeled using the 

RADM mechanism. Inorganic sulfate/nitrate/ammonium chemistry is modeled with 

ISORROPIA. Secondary organic aerosols are modeled using a semi-volatile scheme called 

SOAP. Wet and dry deposition processes are included for gasses and particles. Gridded 

deposition information is output along with the concentrations. 

In the July 1, 1999 publication of the Regional Haze Rule in the Federal Register, EPA defined 

the uses of regional modeling as follows:

Analyses and determination of the extent of emissions reductions needed from individual 

States

Analyses and determination of emissions needed to meet the progress goal for the Class I 

area

Analyses to support conclusion that the Long-Term Strategy provides for reasonable 

progress

Analyses to calculate the resulting degree of visibility improvement that would be 

achieved at each Class I area

Analyses to compare visibility improvement between proposed control strategies

9.1 Modeling Protocol

CENRAP‘s contractor, Environ, prepared a modeling protocol to serve as a road map for 

performing the CENRAP emissions and air quality modeling and to communicate the modeling 

plans to the CENRAP participants. The Modeling Protocol was prepared in accordance with the 

EPA guidance available at the time. This Modeling Protocol can be found on the CENRAP 

modeling Website at:

http://pah.cert.ucr.edu/aqm/cenrap/docs/CENRAP_Draft2.0_Modeling_Protocol_120804.pdf
33

9.2 Quality Assurance Project Plan

The CENRAP contractor prepared a Quality Assurance Project Plan (QAPP) for the CENRAP

emissions and air quality modeling study that described the quality management functions 

performed by the modeling team. The QAPP was prepared and was based on the national 

consensus standards for quality assurance and followed EPA‘s guidelines for quality assurance 

project plans for modeling and took into account recommendations from the North American 

Research Strategy for Tropospheric Ozone (NARSTO) Quality Handbook for modeling projects. 

The EPA and NARSTO guidance documents were developed specifically for modeling projects, 

which have different quality assurance concerns than environmental monitoring data collection 

projects. The work performed in this project involves modeling at the basic research level and for 

regulatory/planning applications. In order to use model outputs for these purposes, it must be

established that each model is scientifically sound, robust, and defensible. This is accomplished 

by following a project planning process that incorporates the following elements:

• A systematic planning process including identification of assessments and related

performance criteria;

• Peer reviewed theory and equations;

• A carefully designed life-cycle development process that minimizes errors;

• Documentation of any changes from original plans;

• Clear documentation of assumptions, theory, and parameterization that is detailed 

enough so others can understand the model output;

• Input data and parameters that are accurate and appropriate for the analysis; and

• Output data that can be used to help inform decision makers.

The CENRAP QAPP can be found at:

http://pah.cert.ucr.edu/aqm/cenrap/docs/CENRAP_QAPP_Nov_24_2004.pdf.

A key component of the CENRAP emissions and air quality modeling QAPP was the graphical 

display of model inputs and outputs and multiple peer-review of each step of the modeling 

process. This was accomplished through use of the CENRAP modeling website where modelers 

posted displays of work products (e.g., emissions plots, model outputs, etc.) for review by the 

CENRAP modeling team, modeling workgroup and others. This website can be found at:

http://pah.cert.ucr.edu/aqm/cenrap/index.shtml.

9.3 Model Inputs

9.3.1 Year Selection

For regional haze, the full 2002 modeling year was chosen as the episode period to evaluate. The 

2002 calendar year, which lies in the middle of the 2000-2004 baseline period in the regional 

haze rule, was selected for the following reasons:

Based on available information, 2002 appears to be a fairly typical year in terms of 

meteorology for the 5-year baseline period of 2000-2004;

2003 and 2004 appeared to be colder and wetter than typical in the eastern US;

The enhanced IMPROVE and IMPROVE Protocol and Supersites PM monitoring 

data were fully operational by 2002. Much less IMPROVE monitoring data was 

available during 2000-2001, especially in the CENRAP region;

IMPROVE data for 2003 and 2004 were not yet available at the time that the 

CENRAP modeling was initiated; and

2002 was being used by the other RPOs.
34

9.3.2 Domain

As one of the five national regional planning organizations (RPOs), CENRAP chose to use the 

unified grid domain developed by all of the other RPOs. This domain covers all RPO areas and 

was chosen to enable sharing of data and results between RPOs in a consistent manner. The grid 

consists of 36km grid cells and is 148 x 112 in size. Sensitivity simulations were also performed 

for episodes on a 12 km modeling domain covering the central states, however the results were 

very similar to the 36 km results so CENRAP elected to proceed with the 2002 annual modeling 

using the 36 km domain for computational efficiency.

9.3.3 Emissions Inputs

Generating the source inventory for modeling is intertwined with the creation of the pollutant 

inventory. Each emission source and the type of pollutants it emits must be specifically 

identified. For dispersion modeling, each source must be classified as a point source, area 

source, mobile source (on-road and off-road), and biogenic sources. The CENRAP Technical 

Support Document (TSD) provides the methodologies for this process and is found at Appendix 

9.1. Emission inventory information can be found in Chapter 8.

9.3.4 Meteorological Input Preparation

The Fifth-Generation NCAR / Penn State Mesoscale Model (MM5) is the latest in a series that 

developed from a mesoscale model used by Anthes at Penn State in the early 70's that was later 

documented by Anthes and Warner (1978). Since that time, it has undergone many changes 

designed to broaden its usage. These include (i) a multiple-nest capability, (ii) non-hydrostatic 

dynamics, which allows the model to be used at a few-kilometer scale, (iii) multitasking 

capability on shared- and distributed-memory machines, (iv) a four-dimensional dataassimilation capability, and (v) more physics options. The model (known as MM5) is supported 

by several auxiliary programs, which are referred to collectively as the MM5 modeling system. 

Since MM5 is a regional model, it requires an initial condition as well as a lateral boundary 

condition to run. To produce a lateral boundary condition for a model run, one needs gridded 

data to cover the entire time period that the model is integrated. The TSD in Appendix 9.1 refers 

to the methodologies and process used to collectively support the MM5 system for CENRAP. 

9.4 Model Performance Evaluation

Model evaluations compared concentrations of various pollutants simulated by CMAQ and 

CAMx with observations from:

Interagency Monitoring of PROtected Visual Environments (IMPROVE)

Clean Air Status and Trends Network (CAST Net)

Speciated Trends Network (STN)

Aerometric Information Retrieval Systems (AIRS)

South Eastern Aerosol Research and Characterization (SEARCH)

Environ evaluated the CMAQ and CAMx models against ambient measurements of PM species,

gas-phase species and wet deposition. Numerous iterations of CMAQ and CAMx 2002 base 

case simulations and model performance evaluations were conducted during the course of the 

CENRAP modeling study, most of which have been posted on the CENRAP modeling website

(http://pah.cert.ucr.edu/aqm/cenrap/cmaq.shtml). Details on the final 2002 Base F
35

36 km CMAQ base case modeling performance evaluations are provided in the TSD. Due to 

resource constraints and the similarity between 2002 Base F and 2002 Base G, the model 

evaluation was not re-conducted for Base G. In general, the model performance of the CMAQ 

and CAMx models for sulfate (SO4) and elemental carbon (EC) was good. Model performance 

for nitrate (NO3) was variable, with a summer underestimation and winter overestimation bias. 

Performance for organic mass carbon (OMC) was also variable, with the inclusion of the 

enhancement in CMAQ Version 4.5 greatly improving the CMAQ summer OMC model 

performance (Morris et al., 2006c). Model performance for Soil and coarse mass (CM) was 

generally poor. Environ concluded that the poor performance for Soil and CM was due, in part, 

to IMPROVE measured values for local fugitive dust sources that are not captured in the model‘s 

emission inputs and the 36 km grid resolution which is not conducive to modeling localized 

events. 

The CENRAP TSD contains a detailed model performance, including performance evaluations at 

each Class I area in CENRAP. (Appendix 9.1)

Appendix 9.1 CENRAP Technical Support Document

Appendix 9.2 CENRAP Modeling Protocol
36

10 Best Available Retrofit Technology (BART)

The U.S. EPA‘s 1999 Regional Haze Rule singles out certain older emission sources that have 

not been regulated under other provisions of the Clean Air Act for additional controls. The State

of Nebraska is to require that those older sources that contribute to visibility impairment in a 

mandatory Class I area to install Best Available Retrofit Technology (BART) unless an 

alternative level of control is warranted. On July 6, 2005, U.S. EPA published a revised final 

rule, including Appendix Y to 40 CFR part 51 ―Guidelines for BART Determinations Under the 

Regional Haze Rule‖ that provides guidance to states on determining which of these older 

sources may need to install BART and how to determine BART.

The rule states that in the case of any fossil-fuel fired power generation plant (EGU) having a 

total generating capacity in excess of 750 megawatts, the BART determination must be made 

pursuant to the guidelines in Appendix Y. Appendix Y of the guidelines outlines a presumptive 

emission rate or percent of control for SO2 and NOx, dependent of the fuel type (i.e. coal, oil) and 

unit type (i.e. dry-bottom wall fired, tangentially fired). These presumptive emission rates 

should be determined as BART for an EGU having a total generating capacity of 750 megawatt 

or greater unless the state can demonstrate, based on careful consideration of the statutory five 

factors. The five factors are: cost effectiveness, energy and non-air environmental impacts, 

existing controls at source, remaining useful life of source, and the degree of visibility 

improvement which may be reasonably anticipated from the technology. 

10.1 Identification of BART – Eligible Sources in Nebraska

The BART-eligible sources were identified using the methodology in the Guidelines for BART 

Determinations under the Regional Haze Rules or ―Guidelines‖. [40 CFR Part 51, Appendix Y.] 

For an emission unit source to be identified as BART-eligible, Nebraska used these criteria from 

the Guidelines:

One or more emissions units at the facility fit within one of the 26 categories listed in the 

Guidelines;

The emission unit(s) were in existence on August 7, 1977 and began operation at some 

point on or after August 7, 1962; and 

The limited potential emissions from all emission units identified in the previous two 

bullets emission units were greater than 250 tons or more per year of any of these 

visibility-impairing pollutants: SO2, NOx, and PM10.

NDEQ utilized its Integrated Information System (IIS) database to identify potential BARTeligible units and major facilities with emission units in one or more of the BART categories. 

Only those facilities with emission units in one or more of the 26 source categories below are 

eligible for BART, regardless of emissions potential. 
37

26 BART Source Categories

(1) Fossil-fuel fired steam electric plants of 

more than 250 million British thermal units 

(BTU) per hour heat input, 

(2) Coal cleaning plants (thermal dryers), 

(3) Kraft pulp mills, 

(4) Portland cement plants, 

(5) Primary zinc smelters, 

(6) Iron and steel mill plants, 

(7) Primary aluminum ore reduction plants, 

(8) Primary copper smelters, 

(9) Municipal incinerators capable of 

charging more than 250 tons of refuse per 

day, 

(10) Hydrofluoric, sulfuric, and nitric acid 

plants, 

(11) Petroleum refineries, 

(12) Lime plants, 

(13) Phosphate rock processing plants,

(14) Coke oven batteries, 

(15) Sulfur recovery plants, 

(16) Carbon black plants (furnace process), 

(17) Primary lead smelters, 

(18) Fuel conversion plants, 

(19) Sintering plants, 

(20) Secondary metal production facilities, 

(21) Chemical process plants, 

(22) Fossil-fuel boilers of more than 250 

million BTUs per hour heat input, 

(23) Petroleum storage and transfer 

facilities with a capacity exceeding 

300,000 barrels, 

(24) Taconite ore processing facilities, 

(25) Glass fiber processing plants, and 

(26) Charcoal production facilities. 

A survey of facilities was conducted to solicit information concerning potential emissions, age of 

units, and other relevant factors. The information was compared to known records and the list 

was narrowed to the one found in Table 10.1.

The facilities with BART-eligible units in the State of Nebraska are shown in Table 10.1. More 

detailed information regarding each facility‘s BART-eligible units may be found in Appendix 

10.2. 

Table 10.1 Facilities with BART-eligible Units in Nebraska

Facility Name City Location Facility ID SIC 

Code

Beatrice Nitrogen Plant Beatrice 3106700001 2873

Ash Grove Cement Louisville 3102500002 3241

Don Henry Power Center Hastings 3100100061 4911

NPPD Gerald Gentlemen Station Sutherland 3111100019 4911

Lon D. Wright Power Plant Fremont 3105300001 4911

CW Burdick Generating Station Grand Island 3107900001 4911

North Denver Station Hastings 3100100040 4911

OPPD Nebraska City Nebraska City 3113100036 4911

NPPD Sheldon Station Hallam 311090005 4911

OPPD North Omaha Station Omaha 310550002 4911

The Guidelines recommend addressing these visibility-impairing pollutants: sulfur dioxide 

(SO2), nitrogen oxides (NOx), and Particulate Matter. Nebraska addressed these three pollutants 

and used particulate matter less than 10 microns in diameter (PM10) as an indicator for 
38

particulate matter to identify BART-eligible units, as the Guidelines suggests. Consistent with 

the Guidelines, Nebraska did not evaluate emissions of Volatile Organic Compounds (VOCs)

and ammonia in BART determinations because:

The majority of VOC emissions in Nebraska are biogenic, rather than anthropogenic, in 

nature. Table 8.2 shows that biogenic VOC emissions are 533,705 tpy. Comparatively, 

anthropogenic VOCs as shown in Table 8.1 are 145,242, or just 21.4% of the total. 

The largest areas of anthropogenic VOC emissions in Nebraska exist in the eastern part 

of the state, in particular the largest metropolitan area of Omaha where VOC emission 

control is being undertaken as part of an innovative Community Based Planning process 

where the community is taking proactive steps to control emissions of VOC and NOx to 

mitigate ozone levels. The program is called Clean Air Performance Agreement. 

As explained in section 8.3.1.5 above, because NOx and SO2 are considered limiting 

pollutants with regard to PM2.5 formation and the significant uncertainties in the ammonia 

inventories as well as in assessing the effect of ammonia emissions reductions on 

visibility, NDEQ does not consider ammonia among visibility-impairing pollutants. 

NDEQ did not identify additional sources with greater than 250 tpy ammonia that 

required a subsequent BART analysis.

10.2 Determination of Units Subject to BART

Under the Guidelines, Nebraska has these options regarding its BART-eligible units: a) make 

BART determinations for all units or b) consider exempting some from BART because they do 

not cause or contribute to visibility impairment in a Class I area. Nebraska chose option  ̳b.‘ 

Under option  ̳b‘, the Guidelines suggest three sub-options for determining that certain sources 

need not be subject to BART: 

(1) Individual source attribution approach (dispersion modeling). 

(2) Use of model plants to exempt sources with common characteristics. 

(3) Cumulative modeling to show that no sources in a state are subject to BART. 

Nebraska chose the first option and with one exception, required the owner/operator of each 

BART-eligible source to conduct the dispersion modeling using the CALPUFF model. NDEQ 

conducted modeling for one source (Lon D. Wright). NDEQ reviewed source-specific analyses 

conducted by the sources to determine which ones cause or contribute to visibility impairment.

The CALPUFF modeling protocol used for determining which facilities are subject to BART is 

included in Appendix 10.3. In accordance with the Guidelines, a contribution threshold of 0.5

deciviews, based on the 98th percentile of daily modeled visibility impact over an annual period, 

was used for determining which sources were subject to BART. The Guidelines provide States 

the discretion to set a lower deciview threshold than 0.5 deciviews if ―the location of a large 

number of BART-eligible sources within the State and in proximity to a Class I area justifies this 

approach.‖ The 0.5 deciview threshold was selected because it is consistent with the guidelines, 

the nearest Class I area from any BART-eligible source is over 300 km away, stretching the 

reliability of the model, and Nebraska did not have any significant clusters of BART-eligible 

sources. 

 
39

During the time that NDEQ was reviewing the modeling provided by sources, NDEQ requested 

the assistance of an EPA Region 7 modeler. Although, Appendix Y states that CALPUFF is ―the 

best regulatory modeling application currently available for predicting a single source‘s 

contribution to visibility impairment and is currently the only EPA-approved model for use in 

estimating single source pollutant concentrations resulting from the long-range transport of 

primary pollutants‖, the person providing assistance utilized a different model (CAMx) to 

compare the results provided by one of the facilities, OPPD-North Omaha Station, and included 

additional Class I areas in the analysis. The CAMx results were not comparable to the 

CALPUFF results; however, the conclusions were the same. 

Table 10.2 summaries the conclusions for each of the BART-eligible units. In order for the 

NDEQ to consider the source to be contributing to visibility impairment, and thus subject to 

BART, the 98th percentile change in deciview (dV) must have been equal to or greater than 0.5 

dV for the source. Table 10.3 details the facilities with BART-eligible units found to be subject 

to BART by the State of Nebraska. Appendix 10.4 contains copies of the letters sent to sources 

deemed to be not BART-subject. Appendix 10.5 contains more detailed results of the modeling 

analyses for each BART-eligible source. 

Table 10.2 BART-Eligible CALPUFF Modeling Conclusions

Facility Name Modeling Conclusion

Beatrice Nitrogen Plant (Koch 

Nitrogen)

Visibility impacts < 0.5 dV. Not BART-subject.

Ash Grove Cement Visibility impacts < 0.5 dV. Not BART-subject.

Don Henry Power Center Visibility impacts < 0.5 dV. Not BART-subject.

NPPD Gerald Gentlemen Station Visibility impacts > 0.5 dV. BART-subject. 

See Table 10.3

Lon D. Wright Power Plant Visibility impacts < 0.5 dV. Not BART-subject.

CW Burdick Generating Station Visibility impacts < 0.5 dV. Not BART-subject.

North Denver Station Visibility impacts < 0.5 dV. Not BART-subject.

OPPD Nebraska City Visibility impacts > 0.5 dV. BART-subject. 

See Table 10.3

NPPD Sheldon Station Visibility impacts < 0.5 dV. Not BART-subject.

OPPD North Omaha Station Visibility impacts < 0.5 dV. Not BART-subject.
40

Table 10.3 Facilities with Units Subject to BART in the Nebraska

Facility Name Emission 

Units 

Subject to 

BART

Pollutants 

Evaluated in 

BART 

Determination

98th

Percentile

Contribution 

(dV)

Class I area 

& Year of 

Impact

OPPD Nebraska City Unit #1 PM, NOx, SO2 0.933 Hercules 

Glades, MO 

(2001)

0.556 Hercules 

Glades, MO 

(2002)

0.686 Wichita 

Mtns, OK 

(2003)

NPPD Gerald Gentleman 

Station

Units #1 & 

#2

PM, NOx, SO2 2.845 Badlands, SD 

(2001)

2.828 Badlands, SD 

(2002)

3.121 Badlands, SD 

(2003)

10.3 Determination of BART Requirements for Subject-to-BART Sources

As part of the BART determination, NDEQ considered EPA‘s BART Guidelines (Appendix Y to 

40 CFR Part 51) for those sources that were required to complete a five factor BART analysis.

NDEQ also considered the State‘s authority to implement the regional haze rule under Title 129 

Chapter 43 (Appendix 10.9). 

One of the more important decisions in the BART Guidelines relates to EGUs and facilities that 

met the presumptive threshold. NDEQ expected these presumptive levels of control to be cost 

effective in most cases. If a facility proposed controls or emission limits less stringent than these

presumptive levels, justification incorporating the statutory factors was required.

BART determinations for the three subject-to-BART units in Nebraska were carried out by thirdparty contractors on behalf of the sources‘ two owners and submitted to the State for evaluation.

All three of the BART units are EGUs, but only two are located at a 750 MW facility (NPPD) 

and are considered by the state to be ―presumptive‖ units. 

The third unit, located at OPPD – Nebraska City Unit #2 (NCS), is not considered by the state to 

be a presumptive BART unit.

A summary of the BART determinations for the BART-subject sources in Nebraska is shown in 

Table 10.4 for each visibility impairing pollutant. BART is the emission limit for each pollutant 

based on the degree of reduction achievable through the application of the best system of 

continuous emission reduction, taking into consideration the technology available, the costs of 

compliance, the energy and the non-air quality environmental impacts of compliance, any 
41

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

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

result from the use of such technology. BART-subject sources provide an estimated emission 

reduction from the 2002 baseline year of 25,137 tons per year of nitrogen oxides.

Table 10.4 BART Determinations for BART-subject units in Nebraska

Facility Name BART subject 

Unit

Pollutant Standard/Determination

OPPD Nebraska City Unit #1 PM Existing controls and 

requirements.

Electrostatic precipitator is 

subject to an existing permit 

limit of 0.1 lb/MMBtu.

NOx Install Low NOx Burners

with over fired air. 

Meet presumptive level of 

0.23 lb/MMBtu.

SO2 No additional controls. 

Source currently uses low 

sulfur coal. 

NPPD Gerald Gentleman 

Station

Units #1 & #2 PM Existing controls and 

requirements.

Baghouses subject to an 

existing permit limit of 0.1 

lb/MMBtu.

NOx Install Low NOx Burners

with over fired air. 

Meet presumptive level of 

0.23 lb/MMBtu.

SO2 No additional controls. 

Continue to use low sulfur 

coal.

10.4 BART Determination Process

The BART determination process 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.
42

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 (non-air quality impacts) 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. NDEQ used an incremental cost effectiveness threshold of $5,000 per ton.

Step 5: Evaluate Visibility Impacts:

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

impact on visibility. The NDEQ has evaluated visibility improvement balanced with the cost of 

compliance in determining the best, most appropriate option for BART as allowed under 

Appendix Y. This was done through a cost per deciview of visibility improvement factor, which 

is similar to the cost per ton of pollutant removed from the atmosphere that is used in the BACT 

process.

The Regional Haze Rules provide that States may conduct the analysis in the order they choose 

and that they may weigh each factor as they deem appropriate. 

There were a few factors that informed Nebraska‘s decision as to how to evaluate visibility 

improvement. First, the purpose of this program is to drive visibility improvement; therefore, 

any control technology would need to have a benefit on visibility improvement in order to 

warrant further evaluation. Nebraska does not have Class I areas. The closest Class I areas are 

located in the states of Missouri, South Dakota, Oklahoma, and Colorado. For the two BARTsubject sources, the nearest Class I areas are over 300 km away. The CALPUFF model has 

limited reliability at distances beyond 200 km, therefore, NDEQ took into account, the 

magnitude and frequency of predicted improvement, whether additional control provided 

significant, measureable average benefit (>0.5 dV) at the closest Class I areas and whether such 

control would improve this average level of visibility for less than $40,000,000 per deciview and 

$400,000 per day of improvement. NDEQ used the cost per deciview and cost per day of 

improvement as indices of the frequency of improvement as well as the cost effectiveness. 

The NDEQ also weighed the non-air quality impacts very carefully, in particular whether the 

amount of visibility improvement would result in other environmental issues. For example, if 

there was information indicating that investing in controls for haze purposes would result in 

another significant environmental (non-air quality) burden, such as impacts to water or land, 

NDEQ weighed that information heavily against the level of visibility benefit. NDEQ believed it 

was important to weigh all of these factors carefully because of the distance to Class I areas, the 

limited number of BART sources and the limitations of the model.

10.5 Summary of BART Determination- OPPD

10.5.1 Nebraska City Station Unit #1 – Not a Presumptive Unit

Prior to embarking on a BART determination, NDEQ first needed to determine whether the 

OPPD NCS Unit #1 should be included as a presumptive unit. 
43

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 guidelines when making BART determinations for other 

types of BART sources, including those with a total plant capacity less than 750 MW. 

When an early draft of the BART proposal was shared with the Federal Land Managers, a 

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

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

determining BART applicability. Since the CAA and the BART regulations did not speak to the 

specific issue of a source becoming a 750 MW facility after the BART rules were promulgated, 

the NDEQ raised the question with the US EPA and received a response on November 10, 2008. 

The response read ―we believe that it is a reasonable interpretation to assume that if the plant is 

greater than 750 megawatts at the time the BART determination is made by the state (i.e. at the 

time the state places the BART determination on public notice) then any unit at the plant greater 

then [sic] 200 megawatts is subject to presumptive BART.‖ US EPA Region 7‘s response did not 

address whether it is sufficient to have commenced or begun actual construction on Unit 2, or 

whether Unit 2 must be operational. The NDEQ‘s conclusion is that the plant‘s commercial 

operational capacity must be 750 MW or more. Since Unit 2 was not yet commercially

operational at the time of the BART determination, NDEQ determined that NCS, for purposes of 

BART had a plant capacity of less than 750 MW. Therefore, it is not mandatory for NDEQ to 

follow 40 CFR 51 Appendix Y for federal purposes.

To further substantiate NDEQ‘s conclusion, NDEQ conducted a careful review of the June 2005 

―Regulatory Impact Analysis for the Final Clean Air Visibility Rule or the Guidelines for Best 

Available Retrofit Technology (BART) Determinations under the Regional Haze Regulations‖ 

(RIA), the Federal Register July 2005 final preamble, and the rule. NDEQ believes that these 

documents provide clarification as to how the US EPA intended for states to aggregate multiple 

units at a power plant in order to determine whether the 750 MW threshold is crossed.

First, in the preamble to the July 6, 2005, Regional Haze/BART rule, on page 39112, middle 

column, EPA states: 

“Finally, the approach to identifying a “BART-eligible source” in the guidelines is based 

on the definitions in the regional haze rule of the relevant terms. For 750 MW power 

plants, States are required to apply the definitions as set forth in the guidelines; for other 

sources, States may adopt a different approach to the task of identifying BART eligible 

sources, so long as that approach is consistent with the ACT and the implementing 

regulations. In other words, while the guidelines adopt an approach for large power 

plants which involves the aggregation of all emission units put into place between 1962 

and 1977 (emphasis added), States have the flexibility to consider other reasonable 

approaches to the question of identifying BART-eligible sources for other source 

categories.”

Therefore, NDEQ determined that individual EGUs that were put into place between 1962 and 

1977 be aggregated for purposes of determining whether a power plant meets the 750 MW 

capacity threshold for applying presumptive-level BART. 
44

Further support of the NDEQ determination is found in Appendix B of the RIA includes a memo 

from Perrin Quarles Associates, Inc (PQA) dated July 19, 2004. The memo provides a summary 

of the analysis PQA conducted for EPA to develop supporting materials for the Regional 

Haze/BART rule. The memo states that “Based on EPA guidance, the original analysis also 

assumed that BART-eligible units are only those that are located at a plant where the total 

capacity of all units within the BART timeframe exceeds 750MW.” Attached to the memo are 

two tables which include NCS #1 with the listed capacity at around 616 MW. The first table also 

lists much smaller units located in Nebraska that were potentially put into place during the 

BART timeframe (1962 – 1977). The second table includes NCS #1 as a potentially BARTsubject source, but no-where does the table indicate that the sources on the table are subject to 

the presumptive levels in the guidelines. The reasonable conclusion NDEQ draws from the 

inclusion of NCS #1 in the second table is that NCS #1 could potentially have a contribution to a 

Class I area above the 0.5 deciview threshold on more than one day, triggering the need for 

further analysis and the potential need for BART to be applied to one or more visibility 

impairing pollutants. 

Therefore, NDEQ concluded that EPA‘s record supported a decision that OPPD Nebraska City 

Station is not a presumptive BART source. 

Nevertheless, given the size of the unit at OPPD, NDEQ concluded it was still appropriate to 

evaluate the necessity of BART controls at NCS Unit #1, and used the five-factor analysis as a 

guideline. 

The BART analysis conducted for OPPD NCS is included in Appendix 10.6. Appendix 10.7 

contains any additional supporting information that was provided by the OPPD. 

BART for each subject-to-BART source was determined by the State using the methodology in 

the Guidelines. These BART emission standards summarized above have been included in 

BART permits for each source and are in Appendix 10.8. Included in Appendix 10.8 is the 

State‘s rationale, including its evaluation of the full five-factor analysis for the BART 

determinations, and responses to comments received during the public processing of each of the 

BART permits.

10.5.2 BART Determination Summary for PM

Prior to evaluating BART, NDEQ evaluated whether PM control would be necessary for 

purposes of visibility improvement. 

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

responsible for well under 1% of the total predicted change in deciview impact from NCS. In 

fact, PM only accounted for 0.32% of the greatest deciview impairment Unit 1 estimated for 

(0.933 in 2001 at Hercules Glades in Missouri). This would indicate that the predicted deciview 

impact is from a pollutant or pollutants other than PM. The results confirmed that the direct 

particulate matter emissions from NCS do not significantly contribute to visibility impairment.

NDEQ concluded that based on the fact that NCS Unit 1 appears to be currently adequately 

controlled by an electrostatic precipitator (ESP), is subject to an emissions limitation of 0.1 
45

lb/MMBtu (Title V OP), and the modeling results revealed that direct particulate emissions do 

not significantly contribute to visibility impairment in Class I areas, BART for PM is existing 

controls and requirements.

10.5.3 BART Determination Summary for SO2

For a full summary of the SO2 control technologies evaluated and eliminated during the BART 

process, please see Appendices 10.6 – 10.8. 

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

on Nebraska City Station (NCS) Unit 1. NDEQ evaluated the effectiveness of this technology at 

the 0.15 lb/MMBtu and at 0.1 lb/MMBtu levels for SO2. Table 10.5 provides a summary of the 

cost effectiveness at 0.10 lb/MMBtu. 

Table 10.5 SO2 Controls (0.10 lb/MMBtu level)

2001

(Hercules Glades)

2003

(Wichita Mtns)

Average

Baseline 0.933 0.686

98th Percentile Impact 0.493 0.311

dV improvement 0.440 0.375 0.0.408

Baseline Days 14 10 12

Days over 0.5 dV 7 6 7

Total Days improved 7 4 5

Cost per dV $78,909,091 $92,586,667 $85,747,879

Cost per ton $1,636

Cost per ton per dV $3,718 $4,362 $4,040

Cost per day of 

Improvement

$4,960,000 $8,680,000 $6,820,000

As stated in Chapter 8 of the Regulatory Impact Analysis (RIA) the US EPA prepared for the 

Regional Haze rule, high cost control measures that have only minimal effect on visibility 

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

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

to 7 days during the worst meteorological year for Hercules Glades and from 10 days to 6 days 

for Wichita Mountains. The BART guidelines do not provide a level to which individual sources 

must reduce their visibility impact, leaving it up to the state‘s judgment. As further discussed 

and substantiated in Chapter 11, the PSAT apportionment modeling and the Causes of Haze 

study show that SO2 emissions contributing to visibility in the Class I areas in Missouri are

coming from the Ohio River Valley area. 

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 BART-eligible 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 
46

study, Nebraska BART sources have an insignificant EIP, specifically for the Hercules Glades 

Class I area.

Therefore, due to the costs for the amount of visibility improvement being high, meaning that the 

amount of visibility improvement would be small compared to the amount of investment, the 

lack of certainty of contribution of sulfate from Nebraska sources, given the distance, and the 

lack of Missouri needing controls from Nebraska at this time, NDEQ concluded NCS did not 

require additional SO2 controls.

10.5.4 BART Determination Summary for NOx

For a full summary of the NOx control technologies evaluated and eliminated during the BART 

process, please see Appendices 10.6 – 10.8. 

Low NOx burner with over-fire air (LNB/OFA) technology is a feasible NOx retrofit technology 

that could be implemented on NCS Unit 1. The cost effectiveness of this control technology is 

$135.55 per ton NOx removed ($1,380,000 / 10,181 tons NOx removed). The lowest incremental 

visibility impairment improvement cost is $4,600,000 per year per change in deciview at 

Hercules Glades in Missouri. The NDEQ determined that at a minimum, LNB/OFA would be 

required for BART. Using LNB/OFA technology would be expected to result in the number of 

days where NCS‘s impact contributing to more than 0.5 dV to decrease from 14 days to 9 days 

during the worst meteorological year for Hercules Glades and from 10 days to 9 days for Wichita 

Mountains in Oklahoma.

The incremental costs of adding select catalytic reduction (SCR) to the LNB/OFA system would 

be $8,583 per ton of NOx. NDEQ estimated that the incremental visibility impairment 

improvement cost of approximately ranged $82,479,167 - $1,799,545,455 for a SCR+LNB/OFA 

system. The incremental visibility improvement of adding SCR to the LNB/OFA system ranged 

0.022 – 0.48 dV with an average of 0.17 dV. 

Table 10.6 Low NOx Burner with Over-Fired Air Evaluation – OPPD NCS 1

2001

(Hercules Glades)

2003

(Wichita Mtns) Average

Baseline 0.933 0.686

98th Percentile 

Impact 0.633 0.531

dV improvement 0.300 0.155 0.228 dV 

Baseline Days 14 10 12

Days over 0.5 dV 9 9 9

Days improved 5 1 3

Cost per dV $4,600,000 $8,903,226 $6,751,613

Cost per ton $136

Cost per day of 

improvement $276,000 $1,380,000 $828,000
47

Table 10.7 Low NOx Burner with Over-Fired Air Evaluation with SCR – OPPD NCS 1

2001

(Hercules Glades)

2003

(Wichita Mtns) Average

Baseline 0.933 0.686

98th Percentile Impact 0.453 0.447

Incremental dV 

improvement over 

LNB/OFA

0.180 0.084 0.132 dV

Total

dV improvement 0.480 0.239 0.360 dV

Baseline Days 14 10 12

Days over 0.5 dV 7 6 6

Incremental days 

improved over LNB/OFA 2 3

Total Days improved 7 4 6

Cost per dV $82,479,167 $165,648,536 $124,063,851

Incremental Cost per dV $212,277,778 $454,880,952 $333,579,365

Cost per ton $2,706

Incremental cost per ton $8,583

Cost per day improvement $5,655,714 $9,897,500 $6,598,333

Incremental cost per total 

days improvement $5,458,571 $9,552,500 $6,368,333

As stated in Chapter 8 of the RIA EPA prepared for the Regional Haze rule, high cost control 

measures that have only minimal effect on visibility improvement can be avoided. Adding SCR 

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

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

Hercules Glades and to 7 days for Wichita Mountains. As indicated in the Causes of Haze 

assessment for Glades (see http://www.coha.dri.edu/doc/conceptualmodels/ConceptualModelHEGL1.pdf), sulfates comprise more than 50% of the components contributing to light 

extinction. Nitrates make up an average of 13.5%, of which Nebraska contributes less than 

4.4%. Using incremental cost effectiveness per ton of $5,000, the addition of SCR was deemed 

not cost effective. For the above reasons, LNB/OFA control was deemed appropriate for OPPD 

NCS. Therefore BART for OPPD NCS Unit 1 was determined to be the installation of 

LNB/OFA with an emission limitation of 0.23 lb NOx /MMBtu.

For more details on the BART determination for OPPD, see Appendices 10.6 – 10.8

10.6 Summary of BART Determination- NPPD

10.6.1 BART Determination Summary for PM

Prior to evaluating BART, NDEQ evaluated whether PM control would be necessary for 

purposes of visibility improvement. 

The baseline case model results indicated that the direct particulate emissions were generally

responsible for less than 1% of the total predicted change in deciview impact from NPPD GGS 
48

Units 1 and 2 at any Class I areas. These results demonstrate that the direct particulate matter 

emissions from GGS Units 1 and 2 do not significantly contribute to visibility impairment. 

Furthermore, GGS Units 1 and 2 are controlled by the baghouses, the best technology available 

for PM. NDEQ concluded that based on the fact that GGS Units 1 and 2 are currently controlled 

by the best technology available for direct PM emissions, and are subject to an emissions 

limitation of 0.1 lb/MMBtu (Title V OP), and the modeling results revealed that direct particulate 

emissions do not significantly contribute to visibility impairment in Class I areas, BART for PM 

is existing controls and requirements.

10.6.2 BART Determination Summary for NOx

For a full summary of the NOx control technologies evaluated and eliminated during the BART 

process, please see Appendices 10.6 – 10.8. 

LNB/OFA technology is a feasible NOx retrofit technology that could be implemented on GGS 

Units 1 and 2. The total annualized cost associated with the installation of LNB/OFA is 

$2,960,000. The average cost effectiveness of this control technology is $198 per ton NOx

removed ($2,960,000 / 14,956 tons NOx removed). 

Utilizing SCR technology is also feasible, however in order to install SCR, LNB/OFA must also 

be utilized. The incremental cost effectiveness (incremental cost SCR) is $5,445 per ton NOx

removed, over 25 times the amount of LNB/OFA alone. The average incremental improvement 

in visibility for the addition of SCR to LNB/OFA is less than 0.5 dV and improvement would be 

seen on an average of 7.3 days per year. Refer to Tables 10.8 & 10.9 for a comparison of the 

control options and the effectiveness. 

Table 10.8 Low NOx Burner with Over-Fired Air Evaluation - NPPD

2001

Badlands

2002

Badlands

2003

Badlands Average

Baseline 2.845 2.828 3.121

98th Percentile Impact 2.224 2.162 2.419

dV improvement 0.621 0.666 0.702 0.663

Baseline Days 54 55 60 56

Days over 0.5 dV 49 52 54 51

Days improved 5 3 6 5

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

Cost per ton $198

Cost per day of 

improvement $953,301 1481481 $702,754 $592,000

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]).
49

Table 10.9 Low NOx Burner with Over-Fired Air Evaluation with SCR - NPPD

2001

Badlands

2002

Badlands

2003

Badlands

Average

Baseline 2.845 2.828 3.121

98th Percentile Impact 1.732 1.728 1.879

Incremental dV 

improvement over 

LNB/OFA

0.492 0.434 0.540 0.489

Total

dV improvement 1.113 1.10 1.242 1.118

Baseline Days 54 55 60 56

Days over 0.5 dV 44 41 48 44

Incremental days 

improved over LNB/OFA 5 11 6 7

Total Days improved 10 14 12 12

Cost per dV $51,438,454 $52,046,363 $46,095,813 $51,208,408

Incremental Cost per dV $110,347,560 $125,094,470 $100,538,889 $111,024,540

Cost per ton $2,297

Incremental cost per ton $5,445

Cost per day of 

Improvement $5,725,100 $4,089,357 $4,770,917 $4,770,917

Incremental Cost per total 

days improvement $5,429,100 $3,877,929 $4,524,250 $4,524,250

NDEQ determined that the incremental cost for the addition of SCR is excessive (>$5,000 per 

ton) and that LNB/OFA would be required for BART.

For more details on the BART determination for NPPD, see Appendices 10.6 – 10.8.

10.6.3 BART Determination Summary for SO2

The BART Determination for SO2 for NPPD was different from OPPD in that impacts to water 

were raised during NDEQ‘s review that required consideration. 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. NDEQ solicited the assistance of the State 

Department of Natural Resources, the Twin Platte‘s Natural Resource‘s District Manager, and 

the Nebraska Association of Natural Resource Districts in its review as well as answering initial 

questions raised by EPA Region VII.
50

The BART Determination Process is summarized here, more details may be found in Appendices 

10.6 - 10.8. The information on the DSI evaluation may be found in Appendix 10.13.

Upon completion of Steps 1 – 2 of the BART Determination Process, scrubbing technology was 

identified as a technically feasible SO2 retrofit technology for NPPD Gerald Gentleman Station 

(GGS) Units 1 and 2. 

Prior to taking into account the other environmental effects, the average cost effectiveness of

using scrubbing control technology is approximately $2,500 – $2,700 per ton SO2 for both units,

combined. NDEQ believes this cost per ton removed seems reasonable. However, as discussed 

further below, NDEQ has determined that additional SO2 controls are not reasonable, due, in part 

to the excessive cost effectiveness in terms of cost per benefit in terms of visibility improvement. 

10.6.3.1 Unique Water Impacts in the Twin Platte Basin

Surface water and groundwater are both used for irrigation for purposes of crop production in the 

state. Irrigated crops have higher yields and irrigated lands are of higher value than non-irrigated 

cropland. (Lamphear October 2005) (See Appendix 10.7.) Water resources are also critical to 

conservation of endangered and threatened species and their habitats. The State of Nebraska has 

several unique laws in place to not only protect, but also increase, stabilize and allocate its water 

resources.

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. This innovative law requires the 

integrated management of water resources through the identification of river basins where water 

resources were already fully-appropriated and other areas where the basins were overappropriated. 

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 established. 

The statutory definition of an over-appropriated basin is very precise and relates to conditions at 

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

required to develop an integrated management plan to reduce water use to the 1997 level of use 

within the next 10 years. In over-appropriated areas, the water demand already exceeds the 

current availability of water and the law requires steps be taken to mitigate the situation. An 

over-appropriated area is causing depletion to occur not only in the immediate area, but 

potentially downstream as well. For both fully and over-appropriated areas, moratoriums are 

presently in place on the construction of new large capacity water wells (greater than 50 gallons 

per minute) and surface water rights. 
51

Once a basin has been designated as fully or over-appropriated, each local Natural Resource 

District (NRD) must work in conjunction with the State NDNR to develop an Integrated 

Management Plan (IMP) to either make certain the basin does not become over-appropriated or 

to find ways to recharge or augment the water resources in a manner such that the basin is no 

longer over-appropriated. The 23 local NRDs are distinctive to Nebraska and have been in 

existence since 1972. They are charged with water shed management and are equipped to best 

respond to the local needs of their district. 

The concept of developing an integrated management plan for watershed management is 

analogous to the air quality state implementation planning process for non-attainment or 

attainment areas. While the development of the basin IMP may take three to five years, 

recharging the system to a sustainable level is expected to take many more years. 

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. 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 moratorium prohibiting the construction of 

new water wells greater than 50 gallons per minute or increasing irrigated acres (effective June 

18, 2007).

As previously noted, 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 overappropriated designation. An Integrated Management Plan (IMP) for the Twin Platte NRD has 

been approved and took effect September 15, 2009 (Appendix 10.11). 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 Twin Platte NRD estimates that in order to return to 1997 levels, the NRD will need to 

return 7,700 acre-feet of already difficult to find offset water to the river that is hydrologically 

connected within the region and another 33,750 -67,450 acre-feet in order to return to fully 

appropriated status. 
52

Figure 1: Areas with Hydrologically Connected Surface Water to Ground Water

Approximate Location of GGSFigure 2: Over Appropriated Surface Water of Nebraska
53

Figure 3: Current Moratoriums on New Water Uses

Approximate Location of GGSFigure 4: Well Drilling Suspensions and Stays on Irrigation within Twin Platte NRD
54

NDEQ searched for information on the water demands of dry scrubbers 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 Table 10.10 below:

Table 10.10 Scrubber Water Usage

Gallons Per Minute/Megawatt (GPM/MW)

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 scrubbing and 1.76 

GPM/MW for wet scrubbing. While, it would appear that the water usage estimates submitted 

by NPPD are higher than the average, NPPD stated during a meeting with NDEQ 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, were 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. Although on the high side, 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 in its analysis, NDEQ used 

both the average and NPPD‘s values for analyzing NPPD‘s water demands against water 

availability in Nebraska.

Table 10.11 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
55

10.6.3.2 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. These agreements were the result of settlement negotiations in the Grayrocks Dam 

litigation and the FERC relicensing of Lake McConaughy. The threatened and endangered 

species identified for protection include the piping plover, 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. 

The requirements of the PRRIP are in addition to the requirements of LB962. The 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 of 50,000 to 70,000 acre-feet per year. For more information about 

the PRRIP see http://platteriverprogram.org/default.aspx. Should the requirements of the PRRIP 

not be met, Lake McConaughy‘s FERC license would be reopened. 

The outstanding existing commitments and obligations of both LB962 and the PRRIP are 

estimated below: 

1

ST Increment of PRRIP

3 State Projects 80,000AF

Remainder 50,000 – 70,000AF

Return to 1997 Levels (LB962) 26,200 AF (Current Estimate- Basin)

Twin Platte NRD only 7,700 AF

Potential 2ND Increment – PRRIP 137,500 AF (Current Estimate)

Return to “Fully Appropriated – LB 962 114,750 – 229,500 AF (Current Estimates-Basin)

Twin Platte NRD only 33,750- 67,450 AF

Potential 3rd Increment – PRRIP 137,500 AF (Current Estimate)

TOTALS 545,950 – 680,700 AF

The expected demands of scrubbing at the NPPD GGS facility is 2,000 to 3,900 acre-feet per 

year, or 26% - 51% of Twin Platte‘s estimate for their requirements for meeting initial 

obligations under LB962, and 7.6 – 29% for the entire basin‘s initial obligations to return to 1997 
56

levels. 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 overappropriated basins described above.

10.6.3.3 Acquisition of Allocations and Offsets (Costs of Water)

In order for NPPD to obtain sufficient water for the scrubbers, it 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 and retire the wells to ensure the offset is permanent.

Costs of Transporting Water

A study conducted by the State of Nebraska Water Management Board, the Report on Water 

Rights Transfer Study (1988), found that since water rights were not traded routinely in a market 

situation, there was no demand curve for determining a cost schedule. The report concluded that

economics in these situations will rely on willingness or ability to pay and the least cost 

alternatives. For industries, water is relatively hard to transfer compared to other inputs because 

transfers of water for industrial purposes are subject to additional statutory requirements, so 

typically a site is chosen where there is an adequate supply of water. Several other factors 

impact 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 cost of operation. 

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), evaluated the potential for transferring water within the High Plains area. 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:

Table 10.12 Summary of Costs to Transfer Water

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

The acre-ft involved in the above study is significantly larger than that which would be required 

for NPPD. Looking at the construction costs alone, the costs equate to $ 6.6 – 10.9 million per 

mile in 1977 dollars ($5.4-8.9 billion/813 miles). Converting to 2007 dollars would increase the 

costs to $16.46-27.1 billion/813 miles, or $20.2 – 33.3 million/mile. Sutherland, NE is 

approximately 300 miles from Fort Randall, SD. Using the above study as a guide, it would cost 

NPPD, and thus the citizens of Nebraska, nearly $6 billion to construct a water pipeline (2007 

dollars) from Fort Randall, SD. If water could be found closer, in an area that was not fully or 
57

over appropriated, where a moratorium does not currently exist, the closest area would be 

approximately 50 miles from NPPD, making it just over $1 billion to transport water. 

Annualizing costs at a rate of 7% over 20 years resulted in the costs associated with water 

transport to be estimated at $94,392,925 – $566,357,554.

The costs to transport water increased the annualized cost associated with FGD at GGS from 

$108,450,000 to $202,842,925 - $674,807,554. The cost per ton for this control technology is 

$4,702 – $15,643 per ton SO2 removed ($202,842,925 - $674,807,554/ 43,138 tons SO2

removed) based on an emissions rate of 0.10 lb/MMBtu. The mean (average) cost per ton 

removal rate would be $10,172 per ton. The NDEQ determined that the costs to transport water 

were costs prohibitive for NPPD as a BART SO2 measure. 

Costs of Obtaining Water Rights and Retiring Wells

There are two sources of water in the state: surface water and groundwater. 

Surface water is subject to prior appropriation and governed by water rights under the 

jurisdiction of the NDNR which are prioritized by the legal concept of ―first in time, first in 

right.‖ (Neb. Rev. Stat. §46-203 through 46-205) See Appendix 10.12. Therefore, were NPPD 

to find a surface water right that was available, retiring that right would only mean that the next

existing priority in line would receive that water. NPPD could not obtain a new water right 

given that the basin in which it is located or near are all fully-appropriated or over-appropriated. 

Even if a new surface water appropriation could be obtained, NPPD would be the newest and 

lowest priority water right in the chain. Therefore, surface water rights are not considered to be 

available to NPPD for purchase or transfer.

Groundwater is managed by the regional Natural Resources Districts, which are political 

subdivisions created by statute. Historically, groundwater has not been subject to an 

appropriation system similar to that applied to surface water. The owner of the overlying land 

could use groundwater for reasonable uses subject to the correlative rights of other landowners. 

Groundwater in and of itself is publicly owned in the State of Nebraska. Consequently, the value 

of groundwater to a landowner is often inextricably linked to the value of the land itself, i.e. 

irrigated cropland versus non-irrigated cropland. 

Management of groundwater use is becoming increasingly integrated with surface water after the 

passage of LB 962 discussed above. Due to the moratorium on new wells described above,

NPPD would have to find existing groundwater wells, such as irrigation wells and retire those 

wells, before NPPD could drill a new groundwater well. 

The cost of retiring a groundwater well will vary depending upon the situation largely based on 

the existence of a willing seller. For agricultural uses of water, the decision to retire a well

would be made only when/if the irrigator felt it would be more advantageous to sell than 

continue to irrigate—the seller could convert to dry land agriculture but could not resume 

irrigation after the well has been retired. If the irrigator were willing to forego the use of this 

resource, the price for that water right would presumably have to be sufficient to compensate for 

decreased net returns over a period of years and a decrease in overall land value from irrigated to 

non-irrigated. Decreased land value impacts a variety of other entities, including taxing 

authorities, which have not been evaluated here. The long-term economic value of irrigation 
58

water to a farmer is based on the expected return over a number of years discounted into present 

values, i.e. the opportunity cost. Furthermore, offset credits would be dependent upon how the 

retired well is hydrologically connected to the river, therefore, not all irrigation wells would 

necessarily given the same offset credit. 

Figure 10.5 is an aerial view of GGS station and the surrounding area. The circles are pivotirrigation, clearly showing the irrigated cropland in the area surrounding GGS. The star 

identifies the location of the NPPD GGS station. The black numbers in each box represent the 

Section within the Township and Range. The green numbers represent the percent stream 

depletion factors (SDF) for that section. This SDF value represents how wells in that section are 

hydrologically connected to the river. The higher the value, the more connected the well is to the 

river. Wells that would be retired with higher SDFs would receive more offset credit than those 

with lower SDF values. The Twin Platte NRD provided NDEQ with example offset calculations 

for NPPD near their GGS station. The calculations are found in Table 10.13 and coincide with 

Figure 10.5:

Table 10.13 Offset Water Calculations

Section Township Range Stream Depletion 

Factor (SDF) %

Offset H2O Calculation to 

South Platte River IF 100 

Acres of Irrigated Corn w/i 

Section no longer irrigated

Acre-Feet

35 14 34 81 37.03

2 13 34 96 39.37

11 13 34 74 25.39

14 13 34 59 20.57

23 13 34 48 16.66

26 13 34 39 13.62

35 13 34 33 11.59

3 12 34 28 9.88

10 12 34 15 5.33

NDEQ estimated that NPPD would need up to 3877 acre-feet per year to scrub SO2. In order to 

determine how much irrigated land NPPD would need to acquire and retire sufficient offsets, 

NDEQ used the information provided by the Twin Platte NRD. NDEQ visually estimated the 

amount of irrigated land based upon pivot coverage. NDEQ assumed all irrigated land was corn. 

Given that a section has 640 acres, the estimates in Table 10.14 were derived.
59

Table 10.14 Estimates Acres and Acre-Feet

Section Township Stream 

Depletion 

Factor 

(SDF) %

Offset H2O 

Calculation to 

South Platte River 

IF 100 Acres of 

Irrigated Corn w/i 

Section no longer 

irrigated

Acre-Feet

Estimated 

Irrigated Acres

Estimated 

Offset 

Acre-Feet

35 14 81 37.03 320 119

2 13 96 39.37 160 63

11 13 74 25.39 480 122

14 13 59 20.57 320 66

23 13 48 16.66 384 64

26 13 39 13.62 480 65

35 13 33 11.59 480 56

3 12 28 9.88 480 47

10 12 15 5.33 384 20

Total 3488 622

NPPD would require more than 6 times more acre-feet to offset their need. This would mean 

over 21,500 acres of irrigated crop land. This is about 6 times more acreage than was originally 

estimated in the NPPD fact sheet because stream depletion factors were not factored in.

Center pivot irrigated crop land sells for a higher price than non-irrigated crop land. In the 

Lincoln County area, prices went up 3.5% over last year. The average price as of February 2010 

was $2,475 per acre, not including the value of the pivot 

(http://www.agecon.unl.edu/Cornhuskereconomics/3-10-10.pdf). However, in 2008, according 

to newspaper reports, 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. Also, according to a prospective buyer in the area, when an offer of $2,500 per 

acre was made for irrigated land, the offer was not accepted. Given the amount of land that 

would be needed to be acquired and the fact that prices went up 3.5% in 2009, it is expected that 

if NPPD were in demand for irrigated land, the price per acre would be driven up. Furthermore, 

price for the irrigated land would likely be influenced by the fact that several farmers would no 

longer being able to farm their land. For this reason, NDEQ assumed NPPD would require

approximately 22,000 acres of land at $4,000 per acre. NDEQ determined the cost of irrigated 

land for purposes of offsets is estimated to be $88,000,000. Any offsets would be calculated and 

subject to approval from the local NRD through issuance of a variance.

The annualized costs to install scrubber alone are $108,450,000. The annualized costs of 

obtaining the water offsets at 7% over 20 years is $8,306,590, increasing the total annualized 

cost with the installation of scrubbers at GGS to $116,756,590. Over 14% of the costs would be 

for obtaining water. 
60

Figure 10.5 Aerial View of GGS & Surrounding Area
61

10.6.3.4 Economic Impacts from Irrigated Agriculture

Agriculture is the mainstay of Nebraska‘s economy. Irrigated cropland has a significant direct 

economic impact to the state, as well as indirect and consumptive effects within the state. 

Whenever irrigated 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 first in red meat production, cattle slaughter, great northern beans production, 

irrigated land and popcorn production. Nebraska is ranked third in corn and grain sorghum 

production. 

In 2008, net farm income was just over $4 billion and cash receipts from all crops just under $9 

billion. The 2008 farm marketing cash receipts contributed $17 billion to Nebraska‘s economy 

and 5% of the United States total. When cropland is permanently taken out of production or 

irrigated cropland is converted to dry land farming, 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. Nebraska‘s $5.9 billion in agricultural 

exports translate into $8.3 billion in additional economic activity. When the foundational 

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

NPPD GGS Station is located in Lincoln County. Within Lincoln County, there are 322,916 

irrigated acres of farmland. Should NPPD take 22,000 acres of irrigated farmland out of service 

that would be 6.8% of the total irrigated cropland in service as of the 2007 USDA Census.

(http://www.agcensus.usda.gov/Publications/2007/Full_Report/Volume_1,_Chapter_2_County_

Level/Nebraska/index.asp ). 

According to http://www.fedstats.gov/qf/states/31/31111.html, the current unemployment rate is 

lower in Lincoln County than in the rest of Nebraska; however, the percentage of people living 

in poverty is greater in Lincoln County. Were NPPD to be required to take about 6.8% of 

irrigated acres out of service, there could be an adverse ripple effect to the economy of Lincoln 

County. As indicated above, agriculture is the primary economic industry for Lincoln County. 

Irrigated land corn yields are about 74% higher than dry land farming. The approximate yield 

for 22,000 acres of irrigated corn cropland is 4,081,000 bushels. For dry land farming, the 

approximate yield for 22,000 acres is 2,347,400 bushels. While the corn market has experienced 

great volatility the last couple years, the average price in 2007 was $4.20 per bushel nationally, 

and $4.14 per bushel in Nebraska. Table 10.15 details the economic differences as a result of 

reduced corn yield at various price points since 2004. 

http://usda.mannlib.cornell.edu/MannUsda/viewDocumentInfo.do?documentID=1050 .
62

Table 10.15 Differences Value of Yields

Year Average Price 

per Bushel of 

Corn in 

Nebraska

Estimated Value 

Irrigated Yield

(4,081,000 

bushels)

Estimated Value 

Dry land Yield 

(2,347,400 

bushels)

Difference

2004 $ 2.02 $ 8,243,620 $ 4,741,748 $ (3,501,872)

2005 $ 1.92 $ 7,835,520 $ 4,507,008 $ (3,328,512)

2006 $ 3.00 $12,243,000 $ 7,042,200 $ (5,200,800)

2007 $ 4.14 $16,895,340 $ 9,718,236 $ (7,177,104)

2008 $ 4.05 $16,528,050 $ 9,506,970 $ (7,021,080)

2009 $ 3.70 $ 15,099,700 $ 8,685,380 $ (6,414,320)

According to the USDA (http://www.agcensus.usda.gov/Publications/2007/Online_ 

Highlights/County_Profiles/Nebraska/cp31111.pdf), the value of grains, oilseeds, dry beans and 

dry peas in Lincoln County totaled $185,812,000. The loss of the 1,733,600 bushels of corn 

yield would have equated to loss of 3.9% of the total value in grain, oilseeds, dry beans, and dry 

peas in Lincoln County for 2007 had the 22,000 acres been converted to dry land farm land. 

To illustrate an example: Livestock producers rely on grains from nearby farmers to supply feed. 

Reduced yields mean livestock producers must pay more to find feed trucked in from further 

away. Reduced yields could also affect the corn markets. Increased costs to livestock producers 

reduce their margins which could drive up prices to the meat packing facilities, which in turn 

could cause the prices of meat to increase in grocery stores. The farmer, livestock producer, 

meat packing facility, and grocery store owner all are operating with tight budgets and profit 

margins; therefore, when there is an upset to the market system, they make resource adjustments, 

find efficiencies, and may ask employees to do more work with less people. The ripple 

economic impacts to the livestock producer, the meat packing facility, grocer, and the general 

consumer are difficult to quantify. The ripple effects from the potential loss of jobs are 

impossible to predict. Usually businesses know how to manage through temporary, short-term 

fluctuations, however, in this case, the change is permanent, and therefore any affects as a result, 

permanent. Furthermore, as public power district, NPPD does not pay property taxes, resulting 

in lost tax revenue to Nebraska. Losses in tax revenue impact the local and state government 

services such as the NRD, the school district, the rural fire department, and the county health 

department. However, for purposes of the cost effectiveness analysis, only the loss of revenue 

(2007 figures) was added to the annualized costs, which increased the total annualized costs to 

$123,933,694. Approximately 5.7% of the costs are associated with the loss of crop value. 

Overall, the impact as a result due to water-related issues increased the annualized costs from 

$108,450,000 to $123,933,694, a 14.3% increase. The NDEQ concluded this is a significant 

economic impact.

10.6.3.5 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. 
63

Improvements seen at the Badlands are expected to be seen at Wind Cave as well. 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 area, you may choose not to analyze the other Class I areas any further...‖ Given 

the direction provided by Appendix Y and the uncertainties of the model beyond 200km, NDEQ 

concluded that the analysis of the Badlands was appropriate. 

The total baseline impact from NPPD GGS is shown in Table 2 of the May 11, 2010 NPPD 

BART Permit 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. Additional benefits 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. However, given the comment received by the federal land managers 

and the relative proximity of Wind Cave National Park, NDEQ assumed similar benefits would 

be expected there. Furthermore, model accuracy is highly uncertain at distances greater than 200 

km. Table 10.16 shows the modeled 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. 

Table 10.16: Visibility Effectiveness (SO2 Controls) 

2001 2002 2003 Average

Control 

Option

Class I Area with Greatest 

Impact from GGS Badlands Badlands Badlands

Baseline

(no SO2

Control)

SO2 Modeled Emission Rate 

(lb/MMBtu) 0.749 0.749 0.749

Modeled 98th Percentile Value 

(dV) 2.845 2.828 3.121 2.931

Number of Days Exceeding 

0.5 dV 54 55 60 56

FGD Control Added

(0.10 lb/MMBtu) 

Modeled 98th Percentile Value 

(dV) 1.790 2.026 2.443 2.086

Visibility Impairment 

Improvement ( dV) 1.055 0.802 0.678 0.845

Number of Days Exceeding 

0.5 dV 33 33 36 34

Days of Improvement 21 22 24 22

Impairment Improvement Cost 

($/yr/ dV) $117,472,696 $154,530,791 $182,793,059 $146,667,093

Cost per Day of Improvement $5,901,604 $5,633,350 $5,163,904 $5,633,350

If we assume similar benefits are achieved at Wind Cave National Park, and consider the benefits 

as cumulative: 

Average impairment improvement cost = $73,333,547 $/yr/ dV

Cost per Day of Improvement = $2,816,675
64

The cost per day of improvement index is an indicator of the frequency of impact (and benefit) a 

source has on a Class I area. The impairment improvement cost is an indicator of how much 

benefit is derived from the investment in the control. Nebraska used a $40,000,000/yr/ dV and 

$500,000 per day as thresholds for determining what would be considered reasonable investment 

for visibility improvement. In conclusion, as indicated in the discussion above, the water 

resources within the river basin in which GGS is located and in surrounding river basins are 

scarce. A moratorium has been placed on new consumptive uses of water. 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 and unique 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 

limited visibility improvement that might result from the additional control justifies not requiring 

GGS to install scrubbing technology as a BART control measure for SO2. 

10.6.4 Dry Sorbent Injection (DSI) Evaluation

On December 14, 2010, the federal land managers commented on Nebraska‘s proposed Regional 

Haze (RH) State Implementation Plan (SIP), while it was on public notice, concerning the extent 

to which dry sorbent injection (DSI) should be considered as a sulfur dioxide (SO2) control 

option for Nebraska Public Power District‘s (NPPD‘s) Gerald Gentleman Station (GGS) Units 1 

and 2. 

NDEQ had eliminated scrubbing as BART as document in Sections 10.6.3 above, but had failed 

to evaluate DSI, a control option uses very little water. The NDEQ cited the water requirements 

of Wet Flue Gas Desulfurization (FGD) and Dry FGD as one contributing factors for eliminating 

them as BART for GGS Units 1 and 2. 

The purpose of the following sections is to supplement the analyses on the other SO2 controls 

previously analyzed. 

10.6.4.1 Updated BART Analysis for SO2

The objective of this analysis is to complete a five-factor analysis for DSI, as it pertains to SO2

removal. The five basic steps for BART analysis are:

Step 1- Identify all available retrofit control technologies

Step 2- Eliminate technically infeasible options

Step 3- Evaluate control effectiveness of remaining control technologies 

Step 4- Evaluate impacts and document the results

Step 5- Evaluate visibility impacts

10.6.4.2 Technical Feasibility

DSI

DSI involves the injection of a sorbent into the ductwork upstream of the unit‘s particulate 

control system. The sorbent for SO2 removal is typically either mineral trona (sodium 

sesquicarbonate) or refined sodium bicarbonate. This BART analysis only considers trona as the 
65

sorbent since it has a wider active flue gas temperature range and is less expensive than refined 

sodium bicarbonate.13

10.6.4.3 Eliminate technically infeasible options

Utilities have installed DSI on several smaller boilers (88 megawatts (MW) to 200 MW) since 

2006. Midwest Generation, LLC recently conducted pilot scale testing at their Powerton and 

Joliet facilities on boilers ranging in size from 700 MW to 900 MW that demonstrated the 

technology is transferable to larger boilers. 

In addition, the Illinois Environmental Protection Agency14 and the Oregon Department of 

Environmental Quality15 are requiring DSI on large utility boilers in their states in order to 

satisfy BART requirements. However, NPPD continues to refute the claim that DSI is a proven 

technology for coal-fired power plants with the size of the GGS Units 1 and 2.

16

10.6.4.4 Evaluate control effectiveness 

Since DSI is considered a feasible technology, its effectiveness was measured by the amount of 

SO2 removed based on a comparison of the controlled emission rate of 0.15 pounds per million 

British thermal units (lb/MMBtu) to the uncontrolled baseline emission rate of 0.749 lb/MMBtu. 

The 0.15 lb/MMBtu is the presumptive BART limit in 40 CFR Appendix Y for electrical 

generation units above 200 megawatts (MW) at plants greater than 750 MW. NPPD used the 

baseline emission rate of 0.749 lb/MMBtu in the original BART analysis, which is based on the 

maximum actual 24-hr SO2 emissions over a three-year baseline period (2001-2003). 

10.6.4.5 Evaluate impacts and document the results

In order to be consistent with the last BART analysis for GGS, the NDEQ has considered DSI‘s 

cost of compliance, energy impacts, non-air quality environmental impacts, and the remaining 

useful life of the units.

10.6.4.6 Cost of Compliance

NPPD‘s analysis was conducted by Sargent & Lundy, LLC. They also provided the 

supplemental information for the previous BART analysis. Sargent & Lundy is a full-service 

firm, providing consulting, design, procurement, construction management, and turnkey services. 

As such, the analysis provided is considered to include vendor quotes as allowed by Appendix Y 

and supplements guidance contained the Environmental Protection Agency‘s (EPA‘s) Office of 

Air Quality Planning and Standards‘ Control Cost Manual. 

The cost associated with DSI installation include, but are not limited to: storage silos for the 

trona, construction of rail upgrades to allow for the receiving of trona, and expanding the ash 

storage system due to increased quantity of solid waste generated by the facility. Detailed 

information can be found in the supporting materials provided by NPPD. The table below 

 

13 Information provided by Solvay Chemicals, Inc. 

14 Faggert, Pamela F. of Dominion Resources Services, Inc., Concerning the Memorandum of Understanding on SO2

and NOx Reductions Reflective of BART for Kincaid Units 1 and 2, to James R. Ross of the Illinois Environmental 

Protection Agency, February 3, 2009. 

15 Addendum to the Oregon DEQ BART Report for the Boardman Power Plant, November 30, 2010. 

16 Information can be found in NPPD‘s letter dated April 29, 2011 to the NDEQ. 
66

provides a cost comparison of DSI versus the control technology analyzed in the previous BART 

Permit. Costs were adjusted to 2016 because that is the likely time when installation would 

occur.

Table 10.17: Comparison Costs for SO2 Controls Adjusted to 2016 Dollars

Cost Element Dry FGD17 Wet FGD17 DSI

Total Capital Cost $1,057,068,000 $1,109,003,000 $208,330,000

Annualized Capital Cost $86,166,000 $90,422,000 $17,500,000

Annualized O&M Cost $30,697,000 $26,368,000 $64,458,000

Total Annualized Cost $116,863,000 $116,790,000 $81,958,000

Annual Tons SO2 Removed 39,815 39,815 39,815

Cost Per Ton Removed $2,935 $2,933 $2,058

The total annualized cost associated with the installation of DSI at GGS is $81,958,000. The 

average cost effectiveness of this control technology is $2,058 per ton SO2 removed 

($81,958,000 / 39,815 tons SO2 removed) based on an emissions rate of 0.15 lb/MMBtu. This is 

assuming a very high removal rate at nearly 80%. The cost per ton removal estimated for GGS 

is similar to the values provided in the DSI BART analysis by the Illinois Environmental 

Protection Agency14 and the Oregon Department of Environmental Quality.

15

 However, the 

capital costs are higher when compared to other BART determinations requiring DSI. Even 

though Illinois and Oregon have required the use of DSI on comparable size boilers, there are 

many uncertainties involved with the installation of this control equipment since it is a relatively 

new technology for boilers the size of GGS Units 1 and 2. In addition, the majority of the dollars 

per ton of SO2 removed result from high ongoing operating cost due to the use of a sorbent. 

10.6.4.7 Energy Impacts

If DSI was employed, 0.6% (7.6 MW)16 of the units‘ generating capacity would be utilized to 

operate the control equipment. Seven and six-tenths megawatts is equivalent to the power 

utilized by approximately 7,600 homes. The original BART analysis reported a power usage rate 

36 MW and 26 MW for Wet FGD and Dry FGD, respectively. 

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

10.6.4.8 Other (Non-Air Quality) Environmental Impacts

Disposal of Solid Waste

Non-air quality environmental impacts associated with the installation of DSI include disposal of 

solid waste generated from the spent trona and fly ash. The cost to dispose of the waste was 

included in the cost analysis. The fly ash will be intermixed with trona which will cause it to be 

unsuitable for third party use requiring it to be land-filled.13 From 2004 to 2008, NPPD sold an 

average of approximately 107,000 tons of fly ash from GGS.188 The revenue lost from fly-ash 

sales was not included in the cost analysis.18

 

17 Appendix A of NPPD‘s letter dated March 15, 2011 to the NDEQ. Does not account for the costs of water with 

dry or wet scrubbing. 

18 GGS‘s Landfill Permit, pp. 2-3, September 2009.
67

The use of DSI would require GGS to landfill approximately 400,000 tons of waste per year16

which is four times more than GGS currently landfills.18 Therefore, the life of their current 

landfill would be vastly shortened, requiring additional landfill capabilities much sooner than 

previously anticipated. 

The NDEQ is also concerned with the possibility that the land-filled waste may have a hazardous 

waste classification. The EPA is still pending their determination on the classification of fly ash 

as a solid waste or hazardous waste. Also, a study by the Department of Energy found arsenic 

and methylene chloride in the ash when DSI was used; however, it is not currently known if the 

levels of arsenic and methylene chloride discovered would classify the ash as hazardous waste. 

This was an issue raised by the National Park Service in their comments on Martin Drake. 

Disposal of Liquid

The DSI application does not use water to improve the mass transfer of SO2 as is the case with 

Dry and Wet FGD technologies. However, some water is used in DSI application to wash the 

trona mills as part of required daily maintenance. The trona mills are filled with water to 

dissolve the deposits of sodium that accumulate on the mill internals. Based on information 

provided by NPPD18and a scaling factor, GGS will averages less than 5 gallons per minute on an 

annual basis to wash the trona mill. The resulting liquid waste is high in sodium and, therefore, 

must be disposed of properly. 

10.6.4.9 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. 

10.6.4.10 Visibility Impacts

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

from GGS Units 1 and 2 at the Badlands in South Dakota. The highest impacts were observed at 

the Badlands in the original BART analysis and it is the closest to GGS, at distance of 

approximately 300 km. 40 CFR Part 51 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. 

The CALPUFF results of the deciview improvement using DSI are compared to GGS‘s previous 

BART analysis in the table below. 
68

Table 10.18: Visibility Effectiveness

2001 2002 2003 Average

Control 

Option

Class I Area with Greatest 

Impact from GGS 

Badlands Badlands Badlands

Baseline 

(no SO2 Control)

SO2 Modeled Emission Rate 

(lb/MMBtu) 0.749 0.749 0.749

Modeled 98th Percentile 

Value (dV) 2.845 2.828 3.121 2.931

# of Days Exceeding 0.5 dV 54 55 60 56

FGD Control Added

(0.10 lb/MMBtu)

1

Modeled 98th Percentile 

Value (dV) 1.79 2.02 2.44 2.08

Visibility Impairment 

Improvement (ΔdV) 1.055 0.802 0.678 0.845

# of Days Exceeding 0.5 dV 33 33 36 34

Impairment Improvement 

Cost ($/yr/ΔdV)2 $117,472,696 $154,530,791 $182,793,059 $146,667,093

Cost per Day of 

Improvement3 $5,901,604 $5,633,350 $5,163,904 $5,633,350

Dry Sorbent Injection 

(0.15 lb/MMBtu)

4

Modeled 98th Percentile 

Value (dV) 1.755 2.147 2.31 2.07

Visibility Impairment 

Improvement (ΔdV) 1.09 0.681 0.811 0.861

# of Days Exceeding 0.5 dV 35 37 39 37

Impairment Improvement 

Cost ($/yr/ΔdV)2 $75,190,826 $120,349,486 $101,057,953 $95,189,314

Cost per Day of 

Improvement3 $4,313,579 $4,553,222 $3,902,762 $4,256,521

1 Results from GGS‘s previous BART analysis

2Total annualized cost / Incremental visibility impairment improvement 

3

Incremental Cost per day = Total annualized cost/no. of days improvement (<0.5 dV)

4 Provided in NPPD‘s letter to the NDEQ dated April 29, 2011.

The results for DSI and FGD (both at 0.15 lb/MMBtu) had different deciview impacts because 

the use of FGD results in a substantial drop in stack temperature and velocity, compared to when 

DSI is used.

If we assume similar benefits are achieved at Wind Cave National Park, and consider the benefits 

as cumulative: 

Average impairment improvement cost = $47,594,657$/yr/ dV

Cost per Day of Improvement = $2,156,789
69

The cost per day of improvement index is an indicator of the frequency of impact (and benefit) a 

source has on a Class I area. The impairment improvement cost is an indicator of how much 

benefit is derived from the investment in the control. Nebraska used a $40,000,000/yr/ dV and 

$500,000 per day as thresholds for determining what would be considered reasonable for 

visibility improvement. EPA Region 7 provided NDEQ with a table comparing the dollars per 

deciview ($/dV) impact of several BART SO2 determinations by other states in their comments 

on the NDEQ‘s proposed SIP. The NDEQ has confirmed that EPA Region 7 used the visibility 

improvement at a single class one area in order to compare the $/dV improvement. The table, 

with DSI incorporated as BART for GGS Units 1 and 2 can be found below.

Table 10.19: SO2 BART Cost Comparisons to other Facilities 1

Operating 

Company State Facility Proposed Control

Reductions 

(tons/year)

Capital 

Cost 

($1000)

Annual 

Cost 

($1000)

$/ton dv $/dv2

PGE 3 OR Boardman LSD/FF 11,988 $247,300 $36,600 $3,053 1.04 $35,192,308

Colorado 

Springs 

Utility 4

CO Martin 

Drake LSD/FF 3,610 $44,166 $8,216 $2,276 0.2 $4,192,276

PacifiCorp 5 WY Dave 

Johnston

Dry 

FGD/FF 11,589 $169,500 $21,419 $1,848 1.39 $16,703,531

PacifiCorp 6 WY Dave 

Johnston

Dry 

FGD/FF 5,657 $222,776 $26,833 $4,743 1.15 $25,421,181

PacifiCorp 7 WY Naughton Wet FGD 7,657 $89,400 $13,068 $1,707 1.03 $13,947,954

PacifiCorp 8 WY Naughton Wet FGD 9,934 $117,440 $16,889 $1,700 1.14 $15,889,802

Basin 

Electric 

Power 9,13

ND Leland Olds FGD 32,949 $107,220 $19,310 $586 1.75 $11,065,903

Great River 

Energy 10,13 ND Stanton LSD/FF 8,438 $79,514 $11,200 $1,330 0.77 $14,533,679

Minnkota 

Power 11,13 ND Milton R. Young FGD 20,443 $111,776 $22,584 $1,105 1.46 $15,426,230

Otter Tail 

Power 12 SD Big Stone Generation SD/FF 16,120 $141,300 $23,750 $1,462 0.16 $51,350,763

Nebraska 

Public Power 

District

NE Gerald 

Gentleman DSI/FF 39,815 $208,330 $64,458 $2,058 0.86 $95,189,314

Omaha 

Public Power 

District14

NE Nebraska 

City Station FGD 21,223 $201,660 $34,720 $1,636 0.49 $79,450,801

1 The costs were based on EPA Region 7's letter dated January 21, 2011. 

2 All were confirmed to use a single Class I Area in their $/dv comparison

3 Table 23 on page D-26 of "Appendix D: Supplement BART information for Boardman Power Plant BART Report", June 19, 2009 

4

Page 79 of "Colorado Visibility and Regional Haze State Implementation Plan for 12 Mandatory Class I Federal Areas", January 7, 2011

5 Tables 16 and 17 on page 22 and Table 28 on page 39 of "BART Application Analysis (AP-6041) for Dave Johnston Power Plant", May 28, 2009

6 Tables 18 and 19 on pages 22 and 23 and Table 29 on page 40 of "BART Application Analysis (AP-6041) for Dave Johnston Power Plant", May 

28, 2009

7 Tables 19 and 20 on page 26 of "BART Application Analysis (AP-6042) for Naughton Power Plant", May 28, 2009

8 Tables 21 and 22 on pages 26 and 27 of "BART Application Analysis (AP-6042) for Naughton Power Plant", May 28, 2009

9

Pages 6 and 8 of "BART Determination for Leland Olds Station Units 1 and 2" in Appendix B of Department BART Determination.

10 Page 5 of "BART Determination for Stanton Station Unit 1" in Appendix B of Department BART Determination.

11 Page 6 of "BART Determination for Milton R. Young Station Units 1 and 2" in Appendix B of Department BART Determination.

12 Table 3-8 on page 18 and Table 6-7 on page 87 of "South Dakota‘s Regional Haze State Implementation Plan" 

13 Primarily use Dakota Lignite Coal.

14 Omaha Public Power District BART determination was not to install control equipment for SO2 due to the high cost for the little benefit
70

10.6.4.11 SO2 BART Determination for GGS

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

1 and 2. Not considering all outstanding issues, the average cost effectiveness of using DSI control 

technology is approximately $2,000 per ton of SO2 removed; this cost per ton removed is reasonable. 

However, when comparing the dV improvement that would be gained and compared to the $/dV 

improvement to those provided by EPA Region 7, GGS Units 1 and 2 are substantially higher than any 

other facility included in Table 19. Furthermore, visibility benefit gained does not outweigh the added 

burden of the added waste that would be generated through the control of SO2. Even though one facility 

has a $/dV impact higher than that of the threshold NDEQ used, the rules allow for states to use different 

approaches and threshold. A distinguishing factor between Nebraska and South Dakota is that Nebraska 

does not contain any Class I areas. 

NDEQ does reserve the ability to revisit additional SO2 controls at NPPD GGS in the future for purposes 

of ―reasonable further progress‖. However, at this time the NDEQ has determined that it is inappropriate 

to require the installation of DSI at GGS Units 1 and 2 due to the excessive cost per benefit in terms of 

visibility improvement (i.e. $/yr/dV) and the significant solid waste impact, and the uncertainty with 

regard to whether the waste would be considered a hazardous waste. 

Appendix 10.1 Detailed Information on BART Eligible Units 

Appendix 10.2 Information about Identification of BART Eligible Units

Appendix 10.3 CALPUFF Modeling Protocols

Appendix 10.4 Letters sent to non-BART subject Sources

Appendix 10.5 Modeling Results

Appendix 10.6 BART analysis submitted by BART subject Sources

Appendix 10.7 Additional supporting information 

Appendix 10.8 BART permit determinations and supporting information 

Appendix 10.9 Title 129 Chapter 43- Visibility Protection

Appendix 10.10 Causes of Haze Study, Sonoma

Appendix 10.11 Twin Platte NRD Integrated Management Plan

Appendix 10.12 Nebraska Statutes 

Appendix 10.13 Supplemental BART information related to DSI Analysis
71

11 Reasonable Further Progress/Long Term Strategy

The Regional Haze Rule calls for each state to ―address regional haze in each mandatory Class I 

Federal area located within the state and in each mandatory Class I Federal area located outside 

the state which may be affected by emissions from within the state‖ [40 CFR 51.308(d)].

Although there are no Class I areas located within Nebraska, the State is still required to address 

regional haze by mitigating the emissions that may be significantly be impacting a mandatory 

Class I area. As part of the CENRAP regional planning process, regional modeling was

performed to show the impact on several surrounding Class I areas from Nebraska emissions. 

The impact from Nebraska emissions is discussed further below. 

Despite the minimal impact from Nebraska, the State still anticipated the surrounding states 

would request that we consult with them to address the requirements to meet reasonable progress 

at their Class I areas. As discussed in the consultation section, because of the minimal impact the 

State of Nebraska was not asked by any state, beyond the BART determinations, for any 

additional specific reductions from any State during their consultation process. The consultation 

process is described in Chapter 11.4.

11.1 Determining Visibility Impact

Nebraska is required by 40 CFR 51.308(d)(3)(iii) to document the technical basis for the State‘s

apportionment of emission reductions necessary to meet reasonable progress goals in each Class

I area affected by the State‘s emissions. In order to address the issue of source attribution and 

apportionment of regional haze for its member states, CENRAP contracted with ENVIRON to 

carry out PM Source Apportionment Technology (PSAT) modeling, a well known ―probing 

tool‖ for the CAMx photochemical model. ENVIRON delivered its results in the form of a 

customized Microsoft Access database query tool, hereinafter the PSAT tool, which allows users 

to select among various inputs to produce charts and tables. The PSAT information is available 

through the CENRAP website http://www.cenrap.org/html/projects.php and on the University of 

California Riverside website at http://pah.cert.ucr.edu/aqm/cenrap/camx.shtml. 

Visibility impact can be represented in terms of absolute light extinction (Bext),inverse 

megameters (Mm-1), and percent total light extinction. Visibility impact can be further evaluated 

in terms of the percent contribution by pollutant species. The relationship between deciviews 

(dv) and inverse megameters (Mm-1) is described in detail by Malm, (1999). The following 

equation defines the Haze Index (HI): 

HI = 10 ln(bext/10)

Thus, one deciview is approximately equal to 11.05 Mm-1 and a change of one dv represents a 

change of approximately ten percent in bext, ―which is a small but perceptible scenic change 

under many circumstances‖.

Figures 11.1-11.13 are taken from Appendix E of the Cenrap Technical Support Document and 

the PSAT modeling tool which show the ranked results by source category contributions to the 

average 2018 extinction (Mm-1) for the worst 20% visibility days. 
72

Figure 11.1 Caney Creek Wilderness Area, AR (CACR)

Figure 11.2 Upper Buffalo Wilderness Area, AR 

(UPBU)
73

Figure 11.3 Breton Island Wilderness Area, LA (BRET)

Figure 11.4 Boundary Waters Canoe Area Wilderness Area, MN 

(BOWA)
74

Figure 11.5 Voyagers National Park, MN (VOYA)

Figure 11.6 Hercules-Glades Wilderness Area, MO (HEGL)
75

Figure 11.7 Mingo Wilderness Area, MO (MING)

Figure 11.8 Wichita Mountains Wilderness Area, OK (WIMO)
76

Figure 11.9 Big Bend National Park (BIBE), TX

Figure 11.10 Guadalupe Mountains National Park (GUMO), TX
77

Figure 11.11 Badlands National Park (BADL), SD

Figure 11.12 Wind Cave National Park (WICA), SD
78

Figure 11.13 Rocky Mountain National Park (ROMO), CO

Figure 11.14 Modeled W20% 2002 Extinction from Nebraska (SO4 & NO3)
79

The nearest Class I areas to OPPD NCS is Hercules Glades, located in Missouri. Hercules 

Glades is just approximately 580km from OPPD NCS. OPPD NCS is located in the southeastern 

corner of the state. Using the PSAT tool, previously discussed, the source apportionment of light 

extinction causing pollutants can be determined. 

Figure 11.15 shows that at Hercules Glades the most significant pollutant to light extinction is 

sulfates from elevated point sources. 

Figure 11.15 Worst 20% visibility days at Hercules Glade (HEGL), MO Future Year 2018
80

Figure 11.16 Source Category contributions to the average 2018 SO4 extinction (Mm-1) for the 

Worst 20% visibility days at Hercules Glade (HEGL), MO.

Figure 11.17 Source Category Contributions to the Average 2018 NO3 extinction (Mm-1) for 

the Worst 20% visibility days at Hercules Glade (HEGL), MO
81

Figure 11.18: Worst 20% Sulfate Residence time from 500m

Finally, according to the analysis conducted by Sonoma for CENRAP in the Causes of Haze 

Assessment (Appendix 10.10), sulfates are coming from the east, south and south east of 

Hercules Glades, which further substantiates that reducing sulfates on Nebraska sources will 

have insignificant impact on visibility improvement in the Hercules Glades Class I area.

Of the 13 Class I areas, Nebraska did not show in the top 30 source category contributors of 

extinction on the worst 20% projected in 2018 for 7 of the Class I areas. Nebraska did not show 

up in the top 10 for any of the Class I areas. The extinction Nebraska contributed most to was 

the Class I areas in South Dakota, the Badlands National Park and Wind Cave National Park, 

approximately 300km away from NPPD GGS. Nitrates comprised a slightly larger percentage 

than sulfates at these parks in the baseline year 2002, as shown in Figure 11.14. Therefore, it 

would seem that mitigating nitrates, as has been done in the BART permits is appropriate.

The Federal Land Managers commented during the comment period of the proposed SIP that 

since the SO2 emissions were not being reduced from the EGUs (essentially elevated point 

sources) that the conclusions from the graphs above would be flawed. That said, using the 

revised 2018 emission inventory for SO2 and comparing it to the inventory for that of the 

neighboring Region 7 states: 
82

Table 11.1

State 2018 Predicted 

SO2 Emissions 

(TPY) 

Nebraska 92,716 

(previous 62,878)

Iowa 198,264

Kansas 97,070

Missouri 280,887

It would be expected that the predicted impacts would be greater in 2018 than previously 

predicted. However, even for the Badlands, where Nebraska‘s impact was the greatest, it is

highly unlikely that Nebraska would reach the impact level that elevated Iowa point sources have 

on the Badlands, considering that the SO2 emissions from Iowa are expected to contribute 

151,354 tons per year compared to 82,193 (approximately 55%) in Nebraska. The impact on 

Wind Cave, SD would likely be higher than previously predicted. Previous models expected 

elevated point sources to be #24 out of 30 as far as priority. An increase in SO2 emissions would 

increase this ranking, but is not expected to raise it to the top 10. For the other areas, 8 do not 

have Nebraska elevated point sources on the top 30 list. It is unlikely that would change. If it 

were, the most would be commensurate with where Kansas elevated point sources are, which is 

typically in the bottom 10. For the areas in Minnesota, Missouri, and Oklahoma, Nebraska 

elevated point sources may have a potential impact slightly higher than that predicted previously. 

11.2 State Consultation Process

11.2.1 Minnesota (Northern Midwest)

As identified in the document Reasonable Progress for Class I Areas in the Northern Midwest –

Factor Analysis (Appendix 11.1), the Lake Michigan Air Directors Consortium (LADCO) 

identified the following states contributing to Class I area visibility impairment in the LADCO 

region: Michigan, Minnesota, and Wisconsin, as well as surrounding states, such as the Dakotas, 

Iowa, Missouri, Illinois, and Indiana. Figure 11.19 presents the results of composite back 

trajectories for light extinction on the 20% worst visibility days. The darkest orange areas are 

where the air is most likely to come from on poor air quality days, and the darkest green areas 

are where the air is least likely to come from on poor air quality days. As can be seen, poor 

visibility days are generally associated with transport from regions located to the south of these 

class I areas. While Nebraska is in the lightest shade of orange, indicating some impact on poor 

visibility days, after further evaluation by Minnesota and consultation through the regional 

planning process, no additional emissions reductions from these Nebraska sources were required 

to meet Class I area visibility improvement goals at this point in time. 
83

Figure 11.19 Composite Back Trajectories Worst 20% Visibility Days

11.2.2 Central States (Missouri, Arkansas)

As identified in the document Central Class I Areas Consultation Plan (Appendix 11.2),

CENRAP identified early on in its process that Nebraska was in its area of influence for nitrogen 

oxides. Figure 11.20 presents the AOIs for NOx and SO4.

Figure 11.20 Initial AOI‘s for Central Class I Areas

The central states determined whether a state was a contributor based on a combined analysis of 

four approaches, i.e., PMF/Trajectories, Area of Influence (AOI), PSAT, and Q/D. If a state was 
84

found to be a major contributor in at least 3 of the 4 approaches, the central states concluded it 

was appropriate to include that state as a major contributor. 

To be included as a contributor under the PMF/Trajectories (positive matrix factorization) 

approach, depended on the level of probability that an air mass originated from the state during 

the days of high contribution by sulfate or nitrate sources where the emission impact potential 

was significant. A state with a high potential of emission impact would be considered a 

significant contributor.

States were included in the AOI listing if they were part of the level 1 group as determined by

Alpine Geophysics. This AOI was based primarily on residence time of air masses, along with 

evaluation of source emissions of, in this case, nitrate and sulfate.

PSAT analysis was determined based on the 2018 Modeled sulfate and nitrate contribution to 

average extinction for the 20% worst days. Any state with the contribution of 2.0 deciview or 

higher was identified as a candidate.

Lastly, Q/D was determined by dividing total SO2 and NO2 precursor emissions for the state by 

distance from a state geographic centroid. If totals were less than 200, the state was not 

indicated as a significant contributor under Q/D.

Nebraska was found to only be a contributor based upon the AOI and therefore it did not meet 

the criteria of meeting at least 3 of the 4 methodologies. Nebraska was excluded as a major 

contributing state to visibility impairment in Class I areas in Missouri and Arkansas. (See 

Appendix 11.2). Figure 11.21 below shows the results of each analysis. Red indicates the state 

has been identified as being a contributor based upon that analytical methodology.
85

Figure 11.21 States Contributing to Hercules Glade Class I Area

Sulfate Nitrate

11.2.3 Wichita Mountains (Oklahoma)

As identified in the document titled Oklahoma‘s Wichita Mountains Wilderness Area Regional 

Haze Planning (Appendix 11.3), Oklahoma identified early on in its process that Nebraska was 

in its area of influence for nitrogen oxides. Figures 11.22 & 11.23 present the AOIs for the 

Wichita Mountains.

Figure 11.22 AOI for Wichita Mountains – Nitrogen Oxides
86

Figure 11.23 AOI for Wichita Mountains – Sulfur Dioxide Sources

Nebraska was initially invited to participate in the Oklahoma consultation process. Only BART 

controls for NOx on the NPPD and OPPD were ultimately identified as requiring control. 

Nebraska provided copies of the draft BART permits packages to the State of Oklahoma while 

on public notice. Oklahoma did not provide any comment, nor did the State request additional 

controls for the initial planning period.

11.2.4 Badlands National Park and Wind Cave National Park (South Dakota)

Nebraska is part of the CENRAP region. South Dakota is part of the WRAP region. 

Information on emission inventories and modeling was shared between the two regional planning 

organizations to assist in the planning process and in the consultation process. 

As identified above, Nebraska‘s contribution to visibility impairment is limited. To examine 

Nebraska‘s potential impact closer, during the BART review, reviewed the Causes of Haze 

Study carefully. We noted that 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). Nebraska‘s primary 

sources emitting visibility impairing pollutants would be south of the Class I areas in South

Dakota. Figure 11.24 is a wind rose from August 2002 showing an equal distribution from the 

north-northwest and south-southeast.
87

Figure 11.24 August 2002 Wind Rose for Rapid City 

(Station #24090- Rapid City, SD Regional Airport)

Nebraska consulted directly with the State of South Dakota several times through phone and 

email correspondence. Nebraska provided copies of the draft BART package for NPPD

Gerald Gentleman Station because of the potential the units have on visibility impairment in 

Class I areas in South Dakota. Nebraska wanted to make sure South Dakota had an opportunity 

to comment on our plans to control emissions the Gerald Gentlemen Power Plant. As noted in 

their proposed SIP (http://denr.sd.gov/des/aq/publicnotices/RegionalHazeSIPDraft.pdf), South 

Dakota included Nebraska‘s BART plans in their SIP submittal.

11.2.5 Rocky Mountain National Park (Colorado)

Nebraska is part of the CENRAP region. Colorado is part of the WRAP region. Information on 

emission inventories and modeling was shared between the two regional planning organizations 

to assist in the planning process and in the consultation process. Additionally, during the BART 

permit development process, Nebraska provided copies of the draft BART package for NPPD

Gerald Gentleman Station because of the potential the units have on visibility impairment in 

Class I areas in Colorado. Nebraska wanted to make sure Colorado had an opportunity to 

comment on our plans to control emissions the Gerald Gentlemen Power Plant. The State of 

Colorado provided comments on the BART permit, as well as on the proposed SIP. 

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 
88

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

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

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. 

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.
89

11.3 Long Term Strategy 

11.3.1 Federal Measures

11.3.1.1 Clean Air Interstate Rule/ Clean Air Transport Rule

At the onset of the regional haze consultation process, many states relied heavily on the Clean 

Air Interstate Rule (CAIR), a rule that was to address the interstate transport of air pollution to 

downwind states. CAIR covered 28 eastern states plus the District of Columbia, and would have 

reduced SO2 emissions by an estimated 5.4 million tons and NOx emissions by an estimated 2 

million tons by 2015. Affected states had the choice of either meeting the state‘s emission budget 

by requiring power plants to participate in a cap and trade system, or by means of a measure of 

the state‘s choosing.

Although Nebraska was not included in the final CAIR rulemaking, the rule was a major 

component in the underlying assumptions used to determine source apportionment because of the 

reductions expected in neighboring states with Class I areas.

In July 2008, the D.C. District Court of Appeals vacated the CAIR rule in its entirety. On 

September 24, 2008 EPA filed a petition for rehearing or for a remand of the case without 

vacatur. On December 23, 2008, the D.C. District Court of Appeals remanded the case to EPA 

without vacatur so that EPA could remedy CAIR‘s flaws as were discussed in their July ruling.

On July 6, 2010, EPA announced a proposed rule to replace CAIR, the Clean Air Transport Rule. 

In this proposed rulemaking, Nebraska was a named state for purposes of PM2.5, and if finalized 

as proposed, would be required to control annual SO2 and NOx emissions from power plants. It 

is expected that this rule will still include Nebraska when finalized.
90

Figure 11.25 Clean Air Transport Rule Proposed States

Emissions reductions are to begin to take effect in 2012. EPA estimates that by 2014, the rule 

would reduce power plant SO2 emissions by 71 percent over 2005 levels and NOx emissions by 

52 percent. Certainly, should Nebraska be included in the final rule and be required to reduce 

emissions of SO2 and NOx, the impact on visibility is expected to be positive. A 71% reduction 

in SO2 emissions and 52% in NOx over 2005 levels would mean Nebraska EGU emissions 

would be: 52,309 tons of SO2 and 26,659 tons of NOx. 

Nebraska will continue to engage with states in the CENRAP region and will participate in 

future consultation processes as necessary to address reasonable progress goals at Class I areas.

11.3.1.2 Mobile Source Related Emissions and Standards

Mobile sources, both on-road and non-road, comprise a significant portion of Nebraska‘s 

emissions inventory. In 2002, non-road sources were the second largest emitter of SO2 in the 

state. On-road and non-road sources make up over 60% of Nebraska‘s total NOx emissions. 

Reducing emissions from these mobile sources could have a positive impact on visibility impacts 

from Nebraska sources. Over the last several years, EPA has promulgated mobile source rules 

that are under implementation. 

11.3.1.3 Tier 2 Vehicle and Gasoline Sulfur Program

In December 1999, the U.S. Environmental Protection Agency (EPA) is announced two 

significant mobile source rulemakings. The first was tailpipe emissions standards for all 

passenger vehicles, including sport utility vehicles (SUVs), minivans, vans and pick-up trucks. 

This regulation marked the first time that SUVs and other light-duty trucks were to be subject to 

the same national pollution standards as cars. The second rule that was announced at the same 

time was for lower sulfur standards in gasoline. The lower sulfur standards were put in place to 

ensure the effectiveness of low emission-control technologies in vehicles and reduce harmful air 
91

pollution. These new standards require passenger vehicles to be 77 to 95 percent cleaner than 

those on the previously on the road and reduce the sulfur content of gasoline by up to 90 percent.

The phase-in of new standards began with model year (MY) 2004, and was completed in MY 

2007 for cars and light-duty trucks, and in 2008 for medium-duty vehicles. By 2007, the 

emission limit for NOx was 0.07 grams per mile (g/mi). The sulfur levels in gasoline were 

capped at 300 parts per million (ppm) and limited to an average of 120 ppm in 2004, and by 

2006 the cap was lowered to 80 ppm with a limit on average sulfur levels of 30 ppm.

11.3.1.4 Locomotives and Marine Engines 

Like on-road vehicles, EPA addressed marine engines in two ways, through their fuels and 

through their emission limits. In May 2004, as part of the Clean Air Nonroad Diesel Rule, EPA 

finalized new requirements for nonroad diesel fuel that decrease the allowable levels of sulfur in 

fuel used in marine vessels by 99 percent. These fuel improvements, which began to take effect 

in 2007, are creating significant environmental and public health benefits by reducing PM from 

new and existing engines. In March 2008, EPA finalized a three part program that will 

dramatically reduce emissions from marine diesel engines below 30 liters per cylinder 

displacement. These include marine propulsion engines used on vessels from recreational and 

small fishing boats to towboats, tugboats and marine auxiliary. The rule is expected to cut PM 

emissions from these engines by as much as 90 percent and NOx emissions by as much as 80 

percent when fully implemented. Also in March 2008, EPA finalized a three part program that 

dramatically reduces emissions from diesel locomotives of all types -- line-haul, switch, and 

passenger rail. Just as with the marine engines, the rule will cut PM emissions from these engines 

by as much as 90 percent and NOx emissions by as much as 80 percent when fully implemented.

11.3.1.5 Small Engines (Personal Watercraft; Lawn and Garden Equipment)

EPA has established a new emission control program to reduce VOC and NOx emissions from 

small spark-ignition engines by about 35 percent. The new regulations put in place a set of more 

stringent exhaust standards and establish new evaporative emission standards for the fuel tanks 

and fuel lines used in this equipment. The rules apply starting in the 2011 model year for Class II 

engines (above 225 cc) and in the 2012 model year for Class I engines (less than 225 cc, used in 

non-handheld applications). 

11.3.1.6 NESHAP MACT Standards

National Emission Standards for Hazardous Air Pollutants (NESHAP) have been promulgated

by EPA and incorporated into Title 129-Nebraska Air Quality Regulations in recent years that 

will not only achieve reductions in hazardous air pollutants (HAPs), but will also reduce 

visibility impairing pollutants such as SO2, NOx, and PM. Some of the most notable NESHAPS 

include:

Commercial, Industrial & Institutional Boilers & Process Heaters - Subpart 

DDDDD

Industrial, Commercial, & Institutional Boilers - Area Sources - Subpart JJJJJJ

Reciprocating Internal Combustion Engines - Subpart ZZZZ

Stationary Combustion Turbines - Subpart YYYY
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EPA has also proposed a NESHAP for Coal- and Oil-Fired Electric Utility Steam Generating 

Units- Subpart UUUUU. This rule, when finalized, is expected to reduce emissions from power 

plants and have resulting benefits on visibility impairment. 

Nebraska has units subject to each of these standards, and the State has or intends to incorporate 

these rules into Title 129 as they are updated by EPA.

11.3.2 Visibility Requirements under the New Source Review and Prevention of Significant

Deterioration Program

The New Source Review Program is broken down into two parts: nonattainment new source 

review and prevention of significant deterioration (PSD) program. In Nebraska, since the whole 

state is currently in attainment with the National Ambient Air Quality Standards, the provisions 

of the PSD program apply. The visibility provisions of PSD are found under section 40 CFR 

52.21(o) which requires owners or operators of new major sources or modifications to provide an 

analysis of visibility impairment as part of the prevention of significant deterioration process. 

Section 40 CFR 52.21(p) requires notification and consultation with federal land managers 

(FLMs) of Class I areas which may be affected. Section 40 CFR 52.21(o) requirements have 

been incorporated into Title 129-Nebraska Air Quality Regulations at Chapter 19 Section 022 

―Additional impact analysis.‖ Notification and consultation requirements under 40CFR 52.21(p) 

have been incorporated by reference into Title 129 at Chapter 19 Section 001.

11.3.3 Measures to Mitigate the Impacts of Construction Activities

Nebraska is required by 40 CFR 51.308(d)(3)(v)(B) to consider measures to mitigate the impacts 

of construction activities. When EPA first promulgated the Regional Haze Rule in 1999, 

emissions related to construction activities such as windblown dust and nonroad diesel engines 

were a major concern. This was especially a problem in rapidly growing metropolitan areas such 

as Los Angeles and Phoenix. Construction activities are directly related to population growth. 

Nebraska has not experienced rapid growth and is not forecasted to in the future. Figure 11.26

comes from the 2009 Ambient Monitoring Network Plan. It shows the top ten counties 

population and their respective growth over the last few years. 
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Figure 11.26 Population Growth in Nebraska

Population growth is projected to remain at a steady pace and construction activities are not

expected to cause a significant impact to visibility. 

11.3.3.1 Water Regulations on Construction Activities

Construction projects in Nebraska that disturb one acre or more are required to obtain a general

permit for storm water discharges under the National Pollutant Discharge Elimination System 

(NPDES). The permitting program was implemented to protect the waters of the State from 

sediment and other contaminants, and may also reduce the amount of particulate matter 

emissions from these activities. The NPDES permits require permitted entities to develop storm

water pollution prevention plan containing best management practices to control erosion and 

runoff. Many of the best management practices employed to prevent erosion and runoff are also 

effective at preventing windblown dust. 

11.3.3.2 Fugitive Dust Regulations 

Nebraska Title 129- Chapter 32 – Dust; Duty to Prevent Escape (Appendix 11.4) of includes a 

provision applicable to construction activities in section 002. This section requires the use of 

reasonable measures such as paving, cleaning, application of water, planting and maintenance of 

ground cover, and/or application of dust-free surfactants to be taken to prevent dust from 

becoming airborne such that it remains visible beyond the property boundary. 

11.3.4 Agricultural and Forestry Smoke Management

Nebraska is required by 40 CFR 51.308(d)(3)(v)(E) to consider smoke management techniques 

for the purposes of agricultural and forestry management in developing reasonable progress 

goals. 
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As evidenced in the emissions inventory in Chapter 8, Nebraska‘s emissions from fires is 

insignificant. 

Nebraska Title 129- Chapter 30 – Open Fires (Appendix 11.5) is a ban on burning with some 

exceptions. Exceptions are limited in scope and most exceptions require permits from the 

NDEQ and the local fire authority. For purposes of agricultural burning, such burning is allowed 

under the following circumstances:

Must be in an agricultural setting

No nuisance or traffic hazard can be created

Only includes trees or vegetation indigenous to the property

Burning is recommended for disposal because of the hazardous nature of the materials. 

Such materials can only be those that have been used on the property.

For purposes of forestry or land management, such burning is allowed under section 002.06 

provided it is conducted by the Nebraska Game and Parks Commission, the US Forest Service, 

the University of Nebraska, or other entities determined to be acceptable by the Department. 

The University of Nebraska Extension service provides information on how to properly do a 

prescribed burn. These resources are available through their website at: 

http://www.ianrpubs.unl.edu. Because of the minimal impacts from burning, Nebraska has not 

further developed a smoke management plan. Existing measures seem to be working to manage 

smoke from prescribed fires. However, NDEQ will continue to evaluate the need for additional 

measures during the periodic SIP reviews. 

11.3.5 Enforceability of Emission Limitations and Control Measures

Nebraska is required by 40 CFR 51.308(d)(3)(v)(F) to ensure that emission limitations and 

control measures used to meet reasonable progress goals are enforceable. Nebraska has ensured 

that all emission limitations and control measures are enforceable by including adopting the 

appropriate rules into Title 129. Additionally, the other measures needed include the BART 

limits. These BART permits contain the applicable emission limits and compliance schedules, 

which will be federally enforceable upon EPA‘s approval of this SIP. The emissions limits and 

compliance verification requirements are already incorporated into an enforceable construction 

permit and will be incorporated into each facility‘s Title V operating permit when the appropriate 

operating permits are reopened or renewed.

11.3.6 Source Retirement and Replacement Schedules

At this time, Nebraska has not identified any source retirement or replacement obligations.

11.3.7 Anticipated Net Effect on Visibility Resulting from Projected Changes to Emissions

Nebraska is required by 40 CFR 51.308(d)(3)(v)(G) to address the net effect on visibility 

resulting from changes projected in point, area, and mobile source emissions by 2018. The 2002 

to 2018 projected visibility improvement at the Class I areas selected for analysis and discussed 

previously will, for the State of Nebraska, result chiefly from the implementation of NOx

controls on the 3 electric generating units (EGUs) at 2 facilities subject to BART. Additional 

improvements are expected from the other federal measures that are currently under 
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implementation described earlier in Chapter 11. NDEQ expects additional federal measures to 

be forthcoming which will have additional visibility improvement. 

These projected visibility improvements as a result of implementation of this plan are shown in 

Table 11.1, based on the ENVIRON PSAT tool, and shown in terms of light extinction. About 

36 to 40% improvement is expected in the South Dakota Class I areas. 

Table 11.2 Net Improvement in Light Extinction

Class I Area 2002 Extinction

(Mm-1)

2018 Extinction

(Mm-1)

Net 

Improvement

(Mm-1)

Badlands National Park 2.356 1.495 0.861

Caney Creek Wilderness Area 0.772 0.485 0.287

Great Sand Dunes Wilderness Area 0.183 0.115 0.068

Hercules-Glades Wilderness Area 1.249 0.860 0.389

Mingo Wilderness Area 1.093 0.731 0.362

Rocky Mountain National Park 0.254 0.158 0.096

Upper Buffalo Wilderness Area 0.353 0.226 0.127

Voyagers National Park 0.931 0.699 0.232

Wichita Mountains Wilderness Area 1.831 1.129 0.732

Wind Cave National Park 0.668 0.505 0.163

11.4 Reasonable Further Progress Conclusion

In summary, during this first planning period, Nebraska has not been asked by any other state to 

reduce emissions beyond those under BART during the consultation processes. Given that 

Nebraska was identified as a potential contributor, or a lower-tier contributor, in some Class I 

areas, additional emission reductions from Nebraska sources may be the subject of consultation 

discussions in the future. However, the implementation of federal measures such as the Clean 

Air Transport Rule, National Emission Standards for Hazardous Air Pollutants for various source 

categories, the lower standards for sulfur on motor vehicles, and other such measures are 

expected to have a significant effect on visibility improvement. 

At this time, consistent with the RPG guidance, given the emissions reductions that we anticipate 

to result from BART and the implementation of other federal CAA programs, and the resultant 

improvement in light extinction, we find that there are no additional measures necessary to 

achieve reasonable progress in the first planning period for Nebraska.

Appendix 11.1 Northern Midwest – Factor Analysis (LADCO)

Appendix 11.2 Central Class I Areas Consultation Plan 

Appendix 11.3 Oklahoma‘s Wichita Mountains Wilderness Area Regional Haze Planning 

Appendix 11.4 Nebraska Title 129- Chapter 32 – Dust; Duty to Prevent Escape 

Appendix 11.5 Nebraska Title 129- Chapter 30 – Open Fires 
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12 Plan Revisions and Progress Reports

Nebraska is required by 40 CFR 51.308(f) to revise its regional haze implementation plan and

submit a plan revision to EPA by July 31, 2018, and every ten years thereafter. In accordance 

with the requirements listed in 40 CFR 51.308(f) of the federal rule for regional haze, Nebraska 

commits to revising and submitting this regional haze implementation plan by July 31, 2018 and 

every ten years thereafter. 

In addition, 40 CFR 51.308(g) requires periodic reports evaluating progress towards the

reasonable progress goals established for each mandatory Class I area. In accordance with the

requirements listed in 40 CFR 51.308(g) of the federal rule for regional haze, Nebraska commits 

to submitting a report on reasonable progress to EPA every five years following the initial 

submittal of the SIP. The report will be in the form of a SIP revision. The reasonable progress 

report will evaluate the progress made towards the reasonable progress goal for each mandatory 

Class I area located outside Nebraska, which may be affected by emissions from within 

Nebraska. All requirements listed in 40 CFR 51.308(g) shall be addressed in the SIP revision for 

reasonable progress. The first five-year progress report will be completed by December 31, 2016. 

Using the findings of this first report, Nebraska will determine whether the adequacy of the plan 

is sufficient and will take appropriate action. Nebraska intends to consult and coordinate with 

other states, the FLMs, and EPA as required and appropriate.

The 2014 National Emissions Inventory will likely be the most current available inventory at that 

time and will be used as part of the progress report. However, given the need to consult with 

other states, an earlier inventory may be required to be used. It is expected that Nebraska will 

also have access to a later point source inventory and continuous emissions monitoring systems 

(CEMS) data for EGUs. Where this more up-to-date information is available, it may be used to 

supplement the National Emissions Inventory.

Nebraska will use the latest available inventory for the five-year progress report, and compare 

that with the projected 2018 inventories. The status of BART controls will be addressed 

individually in that review. For the remaining sectors, EGAS growth rates will be used, where 

applicable, and projected growth will be compared with actual emissions. If this comparison 

indicates overall emissions are growing at a rate significantly (i.e., more than 10%) higher, on an 

individual species basis than previously projected, Nebraska will evaluate the need to reassess 

the visibility impacts on potentially affected Class I areas through consultation with the 

appropriate federal land manager (FLM) and EPA. If additional controls are required, this could 

potentially include a SIP revision to address the visibility goal for the affected Class I area(s).