Technical Support Document

Nebraska Regional Haze Submittal

Prepared by:

Chrissy Wolfersberger

Environmental Protection Specialist

U. S. Environmental Protection Agency Region 7

February 2012

Table of Contents

I. Summary of Environmental Protection Agency (EPA) action Page 3

II. State regional haze rulemaking Page 3

III. EPA’s evaluation of Nebraska’s State Implementation Plan (SIP) Page 3

a. Identification of areas Page 3

b. Baseline and natural visibility conditions Page 6

c. Reasonable progress goals (RPG) Page 7

d. Long-term strategy (LTS) Page 7

i. Consultation with other States Page 8

1. South Dakota – Badlands and Wind Cave

2. Colorado – Rocky Mountain and Great Sand Dunes

3. Minnesota – Voyageurs and Boundary Waters

4. Oklahoma – Wichita Mountains

5. Missouri – Mingo and Hercules Glades

e. Best Available Retrofit Technology (BART) Page 11

i. BART-eligible sources Page 11

ii. BART-subject sources Page 13

iii. Particulate Matter (PM) evaluation Page 14

iv. BART determinations Page 14

1. Omaha Public Power District (OPPD) – Nebraska City Station

2. Nebraska Public Power District (NPPD) – Gerald Gentleman Station

v. BART summary and enforceability Page 28

f. Monitoring strategy Page 28

g. Emissions inventory Page 29

h. Federal Land Manager (FLM) consultation Page 30

i. SIP revisions and five year progress reports Page 32
2

Tables

Table 1 State of Nebraska’s contributions to visibility impairment at Class I areas

Table 2 South Dakota Uniform Rate of Progress (URP) and RPGs

Table 3 Facilities with BART-eligible units in Nebraska

Table 4 BART-eligible facilities determined not to be subject to BART

Table 5 BART-subject facilities in Nebraska

Table 6 NOx control technology effectiveness, NCS Unit 1

Table 7 Cost of NOx control options, NCS Unit 1

Table 8 Visibility improvement analysis, NCS Unit 1

Table 9 Costs for visibility improvement, NCS Unit 1

Table 10 SO2 control technology effectiveness, NCS Unit 1

Table 11 Cost of SO2 control options, NCS Unit 1

Table 12 NOx control technology effectiveness, GGS Units 1 and 2

Table 13 Cost of NOx control options, GGS Units 1 and 2

Table 14 Visibility analysis, NPPD GGS Units 1 and 2

Table 15 Costs for visibility improvement, GGS Units 1 and 2

Table 16 SO2 control technology effectiveness, GGS Units 1 and 2

Table 17 Cost of SO2 control options, GGS Units 1 and 2

Table 18 Cost of SO2 control and visibility benefit, GGS Units 1 and 2

Table 19 Range of GGS dry scrubber cost effectiveness

Table 20 Summary of BART determinations

Table 21 2002 Nebraska emissions

Table 22 2018 Nebraska projected emissions

Figures

Figure 1 Map of the 156 mandatory Class I Federal areas

Figure 2 Geographic area of Regional Planning Organizations

Appendices

Appendix A EPA’s analysis of cost estimates for flue gas desulfurization (FGD) at GGS 

Appendix B GGS emissions 

Appendix C GGS FGD cost analysis spreadsheet
3

I. Summary of EPA’s action

EPA is proposing a partial approval and a partial disapproval of Nebraska’s State Implementation 

Plan (SIP) for Regional Haze, received by EPA on July 13, 2011. Specifically, we are proposing to 

disapprove the sulfur dioxide (SO2) best available retrofit technology (BART) determination for 

Nebraska Public Power Station (NPPD), Gerald Gentleman Station (GGS), Units 1 and 2. We are 

proposing to disapprove this BART determination because it does not comply with our regional 

haze regulations and guidance. We are also proposing to disapprove the long term strategy (LTS), 

insofar as it relies on this deficient BART determination. To correct the deficiencies identified in 

these proposed disapprovals, we are also proposing a partial Federal Implementation Plan (FIP), 

relying on the Transport Rule as an alternative to BART for SO2 emissions from the GGS units. 

This limited FIP would satisfy the SO2 BART requirement for these units and remedy the 

deficiency in Nebraska’s LTS. 

EPA is proposing a partial approval on the remaining elements of Nebraska’ regional haze plan, 

including the BART determinations for Omaha Public Power District (OPPD), the NOx BART 

determination for Gerald Gentleman Station Units 1 and 2, emissions inventory, and monitoring 

strategy, as described below.

II. State regional haze rulemaking

The Nebraska Department of Environmental Quality (NDEQ) provided public notice of the 

opportunity to comment on the regional haze SIP on December 6, 2010, via notice in the Omaha 

World Herald and on NDEQ’s website. Nebraska also notified the FLMs, and the States of 

Colorado, South Dakota, Missouri, Minnesota, and Oklahoma of the opportunity for comment on 

the draft SIP.

Nebraska held a public hearing regarding the SIP on January 21, 2011. Comments were received 

from the State of Colorado, the National Parks Conservation Association (NPCA), EPA Region 7, 

the FLMs (National Park Service, Fish and Wildlife Service, Forest Service), and the Twin Platte 

Natural Resource District. These comments and Nebraska’s responses are available in Appendix 3 

of the SIP. Specific comments are mentioned throughout this technical support document (TSD). 

III. EPA’s evaluation of Nebraska’s State Implementation Plan 

a. Identification of affected Class I areas

States are required to identify each Class I area located within the State and each Class I area 

located outside the State which is affected by emissions from within the State. 

Although there are no Class I areas hosted by the State of Nebraska, the State is still required to 

identify those Class I areas which may be affected by emissions from Nebraska sources. 
4

Figure 1: Map of the 156 mandatory Class I Federal areas

Because the pollutants that lead to regional haze can originate from sources located across broad 

geographic areas, EPA encouraged the States and Tribes to address visibility impairment from a 

regional perspective. Five regional planning organizations (RPOs) were developed to address 

regional haze and related issues. These organizations evaluated technical information to better 

understand how their States and Tribes impact visibility at Class I areas across the country, and 

pursued the development of regional strategies to reduce emissions of pollutants leading to 

regional haze issues. 

Nebraska participated in the planning efforts of the Central Regional Air Planning Association 

(CENRAP). This RPO includes nine states - Nebraska, Iowa, Oklahoma, Texas, Minnesota, Iowa, 

Missouri, Arkansas, and Louisiana. CENRAP and its contractors provided air quality modeling to 

the States to help them determine whether sources located within the State can be reasonably

expected to cause or contribute to visibility impairment in a Class I area.1The modeling 

conducted relied on baseline year (2002) and future planning year (2018) emissions inventories 

that were prepared with participation from each of the CENRAP states. States relied on these 

inventories to develop control strategies to meet the visibility improvement goals of the regional 

haze rule and to develop their SIPs. 

 

1 A contractor to CENRAP, ENVIRON, completed the data analysis. 
5

Figure 2: Geographical area of Regional Planning Organizations

The State of Nebraska relied upon the regional modeling work provided by CENRAP for 

determining the impact that sources within the State might have on Class I areas in the region and 

beyond. The modeling was based on PM Source Apportionment Technology (PSAT) for the 

Comprehensive Air Quality Model with extensions (CAMx) photochemical model. A detailed 

description of this modeling can be found in Chapter 9 and appendix 9.1 and 9.2 of the SIP. This 

tool was used to estimate Nebraska’s contribution to visibility impairment at the Class I areas in 

Arkansas, Colorado, Minnesota, Missouri, Oklahoma, Texas, and South Dakota.

In EPA’s review of Nebraska’s SIP, we accessed the PSAT tool from the CENRAP website. In 

attempting to recreate the charts that Nebraska presented in its SIP using the PSAT tool, we came 

up with slightly different results. The results presented below are from the August 27, 2007 version 

of the tool, which are similar, but not identical, to the results presented in the Nebraska SIP. 22002 

and 2018 figures presented below are PSAT projected results for Nebraska, in terms of absolute 

extinction. 

According to the PSAT modeling, contributions from Nebraska sources for the worst 20% days 

were highest at the South Dakota Class I areas. For the 2002 baseline year, Nebraska sources were 

projected to contribute 7.81% of visibility impairment at Badlands, and 7% at Wind Cave. In 

2018, the projected contribution was reduced to 5.89% and 5.24%, respectively. However, it is 

critical to understand that the 2018 projections were developed assuming presumptive levels of 

control on Nebraska BART sources, which ultimately the State did not require. For that reason, it 

 

2 The information presented in the SIP was in graphical rather than numerical form, which was difficult to read; in 

order to evaluate the information, we accessed the PSAT modeling directly.
6

is likely that Nebraska sources would have a larger contribution to 2018 visibility impairment than 

what is presented in table 1.

Nebraska’s contribution to all other Class I areas was considerably less, and in no case greater than 

1.9%. 

Table 1: State of Nebraska’s contribution to visibility impairment at Class I areas

State Class I area

Class I area total 

extinction (20% 

worst days) 

(1/Mm)

Nebraska 

source

contribution 

(1/Mm)

Percentage 

contribution to 

visibility 

impairment from 

NE sources

2002 2018 2002 2018 2002 2018

South 

Dakota

Badlands National 

Park

44.87 41.20 3.51 2.42 7.81% 5.89%

South 

Dakota

Wind Cave National 

Park

40.71 37.16 2.85 1.95 7.00% 5.24%

Colorado Great Sand Dunes 

National Park

27.88 26.77 0.52 0.39 1.87% 1.46%

Colorado Rocky Mountain 

National Park

32.13 29.41 0.57 0.40 1.76% 1.35%

Minnesota Boundary Waters 

Wilderness Area

61.33 53.32 1.04 0.79 1.70% 1.49%

Texas Guadalupe Mountains 

National Park

47.80 44.43 0.72 0.62 1.51% 1.40%

Minnesota Voyagers National 

Park

59.50 52.10 0.86 0.64 1.45% 1.24%

Oklahoma Wichita Mountains 

Wilderness Area

100.03 75.56 1.11 0.81 1.11% 1.08%

Missouri Hercules-Glades 

Wilderness Area

140.05 92.49 1.34 0.99 0.95% 1.07%

Missouri Mingo Wilderness 

Area

159.83 99.24 1.26 0.85 0.79% 0.86%

Arkansas Caney Creek 

Wilderness Area

133.93 85.84 1.06 0.71 0.79% 0.83%

Texas Big Bend National 

Park 

47.79 44.23 0.29 0.24 0.61% 0.55%

Arkansas Upper Buffalo 

Wilderness Area

131.79 86.16 0.66 0.44 0.50% 0.51%

b. Baseline and natural visibility conditions: 40 CFR 51.308(d)(2)

States that host Class I areas are required to estimate the baseline, natural and current visibility

conditions of those Class I areas. Nebraska does not host a Class I area, therefore, it is not required 

to estimate these metrics.
7

c. Reasonable Progress Goals: 40 CFR 51.308(d)(1)

The RHR requires States and Tribes to establish a reasonable progress goal (RPG) for each Class I 

area within the state. The RPG is measured in deciviews and is to provide for reasonable progress 

towards achieving natural visibility conditions during the first implementation period (through 

2018). RPGs should represent an improvement in visibility for the most impaired days, and ensure 

no degradation in visibility on the least impaired days. 

Nebraska does not have a Class I area within the state and therefore is not required to establish a 

RPG. States hosting Class I areas have established RPGs, and have made assessments regarding 

whether emission reductions are needed from sources in Nebraska in order to meet their RPG. 

Specific State goals and Nebraska’s effect on meeting them are described in further detail in the 

LTS consultation section, below. 

d. Long-Term Strategy: 40 CFR 51.308(d)(3)

States must submit a long-term strategy that addresses regional haze visibility impairment for each 

Class I area within the State and for each Class I area located outside the State which may be 

affected by emissions from the State. The long-term strategy must include enforceable emissions 

limitations, compliance schedules, and other measures as necessary to achieve the reasonable 

progress goals established by States having Class I areas.

States must consider, at a minimum, the following factors in developing their long-term strategy: 

 Emission reductions due to ongoing air pollution control programs, including measures to 

address reasonably attributable visibility impairment;

 Measures to mitigate the impacts of construction activities;

 Emissions limitations and schedules for compliance to achieve the reasonable progress 

goal;

 Source retirement and replacement schedules;

 Smoke management techniques for agricultural and forestry management purposes,

including plans as currently exist within the State for these purposes;

 Enforceability of emissions limitations and control measures; and

 The anticipated net effect on visibility due to projected changes in point, area, and mobile 

source emissions over the period addressed by the long-term strategy.

Nebraska’s LTS for the first implementation period addresses the emissions reductions from 

Federal, State, and local controls that take effect in the state from the end of the baseline period 

through 2018. As described elsewhere in this document, the changes in point, area, and mobile 

source emissions over the first implementation period (through 2018) were taken into account by 

CENRAP and the State in developing the emission inventory for 2018. 

Specifically, Nebraska considered the following Federal and State control measures when 

developing its LTS:

 Clean Air Interstate Rule (CAIR). Although Nebraska was not included in the original 

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. 

 Federal mobile source standards 

 Tier 2 vehicle and low sulfur fuels
8

 Locomotive and Marine engine rules

 Small spark-ignition engine rules

 National Emission Standards for Hazardous Air Pollutants (NESHAP) and associated 

Maximum Achievable Control Technology (MACT) standards

 Nebraska’s Prevention of Significant Deterioration (PSD) construction permitting program. 

Nebraska notes that the visibility protection provisions of PSD found at 40 CFR 52.21(o) 

have been incorporated into Title 129-Nebraska Air Quality Regulations at Chapter 19 

Section 022. Section 40 CFR 52.21(p) requires notification and consultation with federal 

land managers (FLMs) of Class I areas which may be affected by emissions from a new 

source; these requirements under have been incorporated by reference into Title 129 at 

Chapter 19 Section 001.

Nebraska has fugitive dust regulations in Nebraska Title 129 - Chapter 32, which includes a 

provision applicable to construction activities. The rule 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 prevent dust from becoming airborne such that it remains 

visible beyond the property boundary. Nebraska contends that construction activities are not 

expected to cause a significant impact to visibility, and did not require any additional measures to 

mitigate the impacts of construction activities for purposes of visibility improvement.

Nebraska also has regulations that address smoke management for agricultural and forestry

management burns. Title 129 - Chapter 30 is a ban on open burning with some direct exceptions

that include agriculture operations and parks management, and fires set for training purposes.

Other types of exceptions are subject to approval by the NDEQ and the local fire authority. For 

purposes of forestry or land management, such burning is allowed provided it is conducted by a 

limited set of organizations approved by NDEQ. Nebraska contends that, based on the minimal 

impacts from burning, a more stringent smoke management plan is not needed for purposes of 

visibility protection at this time. 

The above programs are fully enforceable, provide for the mitigation of new source impacts 

through new source permitting programs, and reflect appropriate consideration of current programs 

and prospective changes in emissions. Enforceability of Nebraska’s BART control measures are 

more fully described in section III (e) (v) of this TSD.

i. Consultation on other States’ RPGs

Where Nebraska has emissions that are reasonably anticipated to contribute to visibility

impairment in any mandatory Class I Federal area located in another State or States, it 

must consult with the other State(s) in order to develop coordinated emission 

management strategies. If Nebraska causes or contributes to impairment in a Class I area, 

it must demonstrate that it has included in its SIP all measures necessary to obtain its 

share of the emission reductions needed to meet the progress goal for the area.

As mentioned previously, Nebraska participated in the CENRAP planning process, which 

provided the primary venue for State consultation and coordination on emission

management strategies. Nebraska also says in the SIP that it notified the states of South 

Dakota, Oklahoma, Missouri and Colorado while its draft BART permits were open for 

public comment, proposing only control for NOx at the three BART-subject units in the 
9

State. It should be noted that although Nebraska participated as a member State in

CENRAP, the greatest impacts from Nebraska sources occur in a Western Regional Area 

Partnership (WRAP) State – South Dakota. 

1. South Dakota

Nebraska asserts that is has a “minimal” impact on all Class I areas, and points out in 

its SIP that no State asked Nebraska for reductions in order to meet its RPGs. We 

disagree with the characterization of Nebraska’s contribution as minimal, as PSAT 

modeling shows Nebraska sources contribute 7-8% of the total visibility impairment 

at the South Dakota Class I areas, and source-specific CALPUFF modeling shows 

that GGS has a maximum baseline impact at Badlands of 3.12 dv in 2003, and 2.59 

dv at Wind Cave in 2002.3

South Dakota’s reasonable progress goals, which are proposed for approval by EPA 

at the time of this writing, achieve less visibility improvement than the uniform rate 

of progress for the first implementation period. The reasonable progress goals for the 

20% worst days fall short of the uniform rate of progress by 1.28 deciviews (dv) for 

Badlands and 1.34 dv at Wind Cave.

4

Table 2: South Dakota Uniform Rate of Progress (URP) and RPGs

(deciviews)

South 

Dakota

Class I 

areas

2000–

2004 

baseline

20% 

worst 

days

2018

URP

2064 

natural

conditions

2018

reductions

needed

RPG Deficit

Badlands 17.14 15.02 8.06 2.18 16.30 1.28

Wind Cave 15.84 13.94 7.71 1.89 15.28 1.34

Furthermore, the modeling used to estimate achievement of these goals assumed that 

a presumptive level of BART SO2 controls would be installed on Nebraska sources. 

Nebraska did not go on to require that level of control, and in fact required no SO2 

controls, therefore, South Dakota may be even further away from meeting its RPGs 

than what the modeling predicted. 

As described in detail in section III (e) (iv) (2) of this TSD, we propose to disapprove 

Nebraska’s SO2 BART determination for GGS, and also propose to disapprove 

Nebraska’s LTS insofar as it relied on this deficient BART determination. 

 

3

Source-specific CALPUFF modeling for Nebraska City Station and Gerald Gentleman Station is in appendix 10.5 of 

the SIP.

4

76646 Federal Register / Vol. 76, No. 236 / Thursday, December 8, 2011
10

2. Colorado

In a comment letter dated January 21, 2011, the Colorado Department of Public 

Health and Environment (CDPHE) notes that Gerald Gentleman Station has a 

visibility impact of greater than one deciview on Rocky Mountain National Park 

(RMNP). CDPHE reviewed the CALPUFF modeling, and noted that controls at 

Gerald Gentleman Station would provide visibility improvement at both RMNP and 

Great Sand Dunes National Park. They note that both NOx and SO2 controls appear to 

be cost effective.

In comments dated June 23, 2009, CDPHE points out that GGS is the largest EGU in 

Nebraska at 1,365 MW, and has average SO2 emissions (31,135 tpy) that are more 

than half as much as all of the EGUs in Colorado combined. CDPHE questions why

Nebraska would propose no SO2 controls, since such controls are regularly available, 

common controls for EGUs. CDPHE encourages Nebraska to take another look at the 

cost assumptions used for Flue Gas Desulfurization (FGD) controls. They express 

that $2,700 per ton is reasonable, and that the cost is likely even lower. 

CDPHE comments that it understands the significance of water shortages in western 

Nebraska, as the state of Colorado is also in an arid region. They state that all large 

EGUs in Colorado have installed (or are in the process of installing) FGD controls to 

reduce SO2 emissions. 

CDPHE goes on to say that the most recent WRAP modeling, which used the CMAQ 

model, predicts that RMNP is far short of its URP. CDPHE asked that Nebraska 

reconsider SO2 controls at GGS under the RHR to help Colorado make progress at 

RMNP.

Nebraska denies this request in their SIP on the basis that WRAP’s modeling did not 

distinguish Nebraska’s impact from the other CENRAP states. Nebraska also makes 

the argument that a wind rose from RMNP indicates that the wind pattern is rarely 

from the direction of Nebraska. 

We share Colorado’s concerns about the SO2 BART determination for GGS, and as 

described above, we are proposing to disapprove this deficient BART determination 

and Nebraska’s LTS insofar as the State relied on it to meet the LTS requirements. 

3. Minnesota 

Boundary Waters, Voyageurs, Seney, and Isle Royale are referred to as the Northern 

Midwest Class I areas. As identified in the document, “Reasonable Progress for Class 

I Areas in the Northern Midwest – Factor Analysis,” 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.5

Nebraska does not significantly contribute to visibility impairment at the Minnesota 

Class I areas according to PSAT modeling. Through RPO consultation, Minnesota 

 

5 Appendix 11.1 of the SIP
11

determined that no additional emissions reductions from Nebraska sources were 

needed to meet Class I area visibility improvement goals at this point in time. EPA 

believes that this satisfies the requirement for consultation between these States. 

4. Oklahoma 

As identified in the document titled, “Oklahoma‘s Wichita Mountains Wilderness 

Area Regional Haze Planning,” Oklahoma identified Nebraska in its area of influence 

for NOx.

6 Nebraska was initially invited to participate in the Oklahoma consultation 

process. Nebraska states that it provided copies of the draft BART permit packages to 

the State of Oklahoma while on public notice, which only proposed NOx controls on 

OPPD and NPPD. Oklahoma did not provide any comment, or request additional 

controls for the initial planning period. EPA believes that the consultation 

requirement between these states has been satisfied.

5. Missouri and Arkansas

Caney Creek, Upper Buffalo, Hercules Glades, and Mingo are referred to as the 

central Class I areas. As identified in the document, “Central Class I Areas 

Consultation Plan,” CENRAP identified Nebraska in the area of influence for 

nitrogen oxides at the central Class I areas.7 The central states determined whether a 

state was a major contributor based on an analysis of four approaches: trajectories, 

areas of influence, PSAT, and Q/d. If a state was 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. Nebraska was found to be a contributor based upon 

the area of influence only, therefore it was excluded as a major contributing state to 

visibility impairment in Class I areas in Missouri and Arkansas. EPA believes that 

Nebraska’s consultation requirement with these states was satisfied. 

e. Best Available Retrofit Technology (BART): 40 CFR 51.308(e)

States must submit an implementation plan containing emission limitations representing BART 

and schedules for compliance with BART for each BART-eligible source that may reasonably be

anticipated to cause or contribute to any impairment of visibility in any mandatory Class I Federal 

area.

i. BART eligible sources: 40 CFR 51.308(e)(1)(i)

States must identify all BART-eligible sources in their SIP. Sources are subject to BART 

if:

1. One or more emissions units at the facility belong to one of the twenty-six BART 

source categories;8

2. The unit did not operate before 7 August 1962 but was in existence on 7 August 

1977; and

3. The unit has the potential to emit 250 tons per year or more of any visibilityimpairing pollutant, which Nebraska determined to be SO2, NOx, and PM10.

 

6 Appendix 11.3 of the SIP

7 Appendix 11.2 of the SIP

8 BART guidelines, 40 CFR Part 51 Appendix Y
12

The BART Guidelines direct states to exercise judgment in deciding whether VOCs and 

NH3 impair visibility in their Class I area(s). 70 FR 391160. CENRAP performed analyses 

which demonstrated that anthropogenic emissions of VOC and NH3 do not significantly 

impair visibility in the CENRAP region. Therefore, Nebraska did not consider ammonia 

among visibility-impairing pollutants and did not further evaluate NH3 and VOC emissions 

sources for potential controls under BART or reasonable progress.

Nebraska used its database to identify potential BART-eligible units and facilities with 

emission units in one or more of the 26 BART categories. Nebraska then conducted a 

survey to identify facilities within these source categories with potential emissions of 250 

tons per year or more for any visibility-impairing pollutant from any unit that was in 

existence on August 7, 1977 and began operation after August 7, 1962. More detailed 

information regarding each facility‘s BART-eligible units may be found in Appendix 10.2.

EPA proposes to find that Nebraska adequately identified all BART-eligible sources within 

the State.

Table 3: Facilities with BART-eligible units in Nebraska

Source category Facility Location

Number 

of 

emission 

units 

identified 

by date

Potential to emit (dateeligible units, tons per 

year)

PM10 NOx SO2

Fossil-fuel fired steam 

electric plants of more 

than 250 million BTU 

per hour heat input

NPPD Gerald 

Gentlemen 

Station

Sutherland 2 4,460 46,200 79,200

OPPD Nebraska 

City

Nebraska 

City 1 43,792 19,040 45,696

OPPD North 

Omaha Station Omaha 2 910 14,420 34,283

NPPD Sheldon 

Station Hallam 2 908 6,020 15,100

CW Burdick 

Generating 

Station

Grand 

Island 2 997 1,923 10,304

Lon D. Wright 

Power Plant Fremont 2 97 3,784 3,035

Don Henry

Power Center Hastings 1 19 1,360 780

North Denver 

Station Hastings 1 14 426 853

Portland cement plants Ash Grove 

Cement Louisville 7 528 2,373 3,182

Chemical process plant; 

fossil-fuel boilers; 

hydrofluoric, sulfuric, 

and nitric acid plant

Beatrice 

Nitrogen Plant Beatrice 18 48 924 5
13

ii. BART subject sources

Nebraska then screened out some BART-eligible sources from being subject to BART on 

the basis that they do not cause or contribute to visibility impairment in a Class I area. A 

contribution threshold of 0.5 deciviews based on the 98th percentile of daily modeled 

visibility impact over an annual period was used by Nebraska. The BART 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 nearest Class I area from any BART-eligible 

source in Nebraska is over 300 km away, and the State did not have any significant 

clusters of BART-eligible sources, therefore, the State determined the 0.5 dv threshold 

was appropriate. 

Nebraska required the owner of each BART-eligible source to conduct dispersion 

modeling using the CALPUFF model and submit the results to NDEQ. (One exception -

NDEQ conducted modeling for the Lon D. Wright Power Plant). The CALPUFF 

modeling protocol is included in Appendix 10.3.

Nebraska identified eight sources with impacts less than 0.5 deciviews, which were 

therefore determined not to be BART-subject: 

Table 4: BART-eligible facilities determined not to be subject to BART based on 

< 0.5 dv impact

Beatrice Nitrogen Plant (Koch Nitrogen) CW Burdick Generating Station

Ash Grove Cement North Denver Station

Don Henry Power Center NPPD Sheldon Station

Lon D. Wright Power Plant OPPD North Omaha Station

Two facilities had impacts greater than 0.5 deciviews, and were therefore determined to 

be BART-subject: OPPD Nebraska City Station Unit 1 and NPPD Gerald Gentleman 

Station Units 1 and 2. EPA proposes to find that Nebraska adequately determined which 

sources in the State were subject to BART.

Table 5: BART subject facilities in Nebraska

Facility Units Class I area

CALPUFF modeled impacts > 

0.5 dv

2001 2002 2003

OPPD Nebraska 

City Station 1

Hercules Glades 0.933 0.556 < 0.05

Wichita Mountains < 0.05 < 0.05 0.686

NPPD Gerald 

Gentleman Station 1 & 2

Badlands 2.845 2.828 3.121

Wind Cave 2.452 2.591 2.127

Wichita Mountains 1.032 1.206 1.392

Rocky Mountain 1.136 1.246 1.053

Hercules Glades 0.826 0.616 0.594

Mingo 0.615 < 0.05 < 0.05
14

iii. PM evaluation

Nebraska used source-specific CALPUFF modeling to examine the relative 

contribution of PM, NOx, and SO2 emissions to visibility impairment. 

For Nebraska City Unit 1, direct PM emissions only accounted for 0.32% of 

impairment on the most impaired year, 2001, at the closest Class I area, Hercules 

Glades. Nebraska concluded that direct PM emissions from NCS do not significantly

contribute to visibility impairment, and therefore, a full five factor BART analysis for 

PM was not needed. 

For Gerald Gentleman Station, direct PM emissions only accounted for 0.69% of 

impairment on the most impaired year, 2003, at the closest Class I area, Badlands. 

Nebraska concluded that direct PM emissions from GGS do not significantly

contribute to visibility impairment, and therefore, a full five factor BART analysis for 

PM was not needed. 

EPA agrees with these conclusions. 

iv. BART determinations

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

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

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

2. Eliminate Technically Infeasible Options. Technologies demonstrated to be 

infeasible based on chemical, physical, and engineering principles are excluded 

from further consideration. 

3. Evaluate Control Effectiveness of Remaining Control Technologies. Technically

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

reduction to lowest expected emission reduction.

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

each control technology include: cost of compliance, energy impacts, non-air 

quality environmental impacts, and the remaining useful life of the unit to be 

controlled. 

5. Evaluate Visibility Impacts. Modeling should be performed on the pre- and postcontrol emissions to determine the actual impact on visibility and assess the 

visibility improvement achieved and at what cost. This step does not need to be 

performed if the most stringent control technology is chosen. 

1. Omaha Public Power District (OPPD) – Nebraska City Station (NCS) 

Unit 1

Nebraska and EPA have reached different conclusions as to whether NCS 

Unit 1 is located at a power plant with a generating capacity in excess of 750 

megawatts (MW), or not. If NCS falls within this category of sources, then the 

BART Guidelines must be followed in determining BART limits and the 

presumptive limits in the Guidelines would apply. See CAA § 169A (b). In 

September 2008, Nebraska asked EPA for clarification on whether recently 

permitted units, such as NCS Unit 2, should be included in the total plant 

capacity for purposes of applying presumptive BART. In a response dated 
15

November 7, 2008, we indicated it is reasonable to interpret the RHR to mean 

that if the plant capacity is greater than 750 MW 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 the power plant is a facility “having a 

total generating capacity in excess of 750 [MW]” and any unit at the plant 

greater than 200 MW is subject to presumptive BART. 

The groundbreaking for construction of NCS Unit 2 was September 13, 2005. 

Nebraska put the NCS Unit 1 BART permit on public notice on December 12, 

2008. Unit 2 was operational on May 1, 2009.9 Nebraska concluded that 

because NCS Unit 2 was not operational at the time of the BART 

determination for Unit 1, its capacity did not count towards the 750 MW 

threshold, and therefore, it was not mandatory for Nebraska to follow 40 CFR 

51 Appendix Y in making the BART determination.

We concede that there is some question as to whether the NCS Unit 1 is a 

presumptive unit, requiring use of the BART Guidelines, or not. Regardless, 

Nebraska did proceed through a basic step-wise analysis of the costs and 

visibility impacts of available controls. 

The BART evaluation for OPPD NCS Unit 1 was conducted by contractors 

hired by OPPD, and then submitted to Nebraska for review and use. The full 

analysis may be found in appendix 10.6 of the SIP.

a. BART for NOx - NCS Unit 1

Step one of a BART analysis is to identify all available retrofit control 

technologies. Nebraska identified SCONOx,

10 the Pahlman process, 

selective catalytic reduction (SCR), selective non-catalytic reduction 

(SNCR), flue gas recirculation (FGR), reducing air preheat temperature 

(RAP), oxygen trim (OT), low excess air (LEA), over-fire air (OFA), staged 

combustion air (SCA), and low NOx burners (LNB) as available retrofit 

controls for NOx at NCS Unit 1. NCS Unit 1 has existing has overfire air, 

which provides a modest level of NOx control. 

Step two is to eliminate technically infeasible options. SNCR was 

eliminated because the furnace exit temperatures are too high; SCONOx and 

the Pahlman process were determined to be infeasible as they have not been 

demonstrated on large coal-fired boilers.

Step three is to evaluate the control effectiveness of the technologies that 

were deemed feasible.

 

9

http://www.powermag.com/coal/Top-Plants-Nebraska-City-Station-Unit-2-Nebraska-City-Nebraska_2179_p4.html, 

accessed February 7, 2012.

10 SCONOx is a proprietary catalytic oxidation and absorption technology that uses a single catalyst for the removal of 

NOx, CO, and VOC.
16

Table 6: NOx control technology effectiveness, NCS Unit 1

Control 

technology

Emission rate 

(lbs/MMBtu)

Potential 

emissions 

(tpy)

Tons 

NOx 

removed

Control 

efficiency

Baseline 0.57 17,008 N/A N/A

LNB/OFA 0.23 6,827 10,181 60%

LNB/OFA+SCR 0.08 2,375 14,633 86%

Step four is to consider the costs, energy impacts, non-air quality 

environmental impacts, and the remaining useful life of the unit to be 

controlled. These factors are fully described in the OPPD BART analysis; 

only the cost of the various options is presented here. 

Table 7: Cost of NOx control options, NCS Unit 1

Technology Options

LNB/OFA+ 

SCR LNB/OFA

Emission Rate (lb/MMBtu) 0.08 0.23

Emission Reduction (tpy) 14,633 10,181

Percentage Reduction 86% 60%

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

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

Annual Operating Cost $16,910,000 $0 

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

Total Cost Effectiveness ($/ton) $2,611 $166 

Step five is to evaluate the visibility impacts. Results of this analysis are 

presented in table 8 for the two most impacted Class I areas for NCS Unit 1

(impacts > 0.5 dv). Note that the SO2 control options are also presented in 

this table; other parts of the SO2 BART analysis are described in the next 

section. 

Table 8: Visibility improvement analysis, OPPD NCS Unit 1

Class I area Technology Options Deciview impact, 8th high values Improvement 

2001 2002 2003 Average (Average)

Hercules 

Glades 

(Missouri)

Baseline 0.933 0.556 0.473 0.65

LNB/OFA 0.621 0.358 0.324 0.43 0.22

LNB/OFA +SCR 0.450 0.284 0.252 0.33 0.33

FGD – 0.15 lbs/MMBtu 0.530 0.355 0.308 0.40 0.25

FGD – 0.10 lbs/MMBtu11 0.493 - - - 0.4412

LNB/OFA+FGD 0.233 0.159 0.140 0.18 0.47

LNB/OFA+FGD+SCR 0.140 0.084 0.072 0.10 0.55

 

11 Besides these rows, all other references to FGD in this table are modeled at a rate of 0.15 lbs/MMBtu. 

12 Nebraska only presented modeling information for FGD at 0.10 lbs/MMBtu in its SIP for the most impacted year, 

2001 at Hercules Glades. 
17

Wichita 

Mountains 

(Oklahoma)

Baseline 0.306 0.381 0.686 0.46

LNB/OFA 0.233 0.275 0.524 0.34 0.12

LNB/OFA +SCR 0.228 0.258 0.445 0.31 0.15

FGD – 0.15 lbs/MMBtu 0.153 0.205 0.331 0.23 0.23

FGD – 0.10 lbs/MMBtu13- - 0.311 - 0.3814

LNB/OFA+FGD 0.069 0.109 0.165 0.11 0.35

LNB/OFA+FGD+SCR 0.053 0.063 0.112 0.08 0.38

2 Class I areas 

(Cumulative) Baseline 1.11

Table 9 combines the average visibility improvement with the costs of control. Again, the 

two most impacted Class I areas are presented, as well as a cumulative result combining the 

visibility benefit at both areas. 

Table 9: Costs for visibility improvement, NCS Unit 1

Class I area Control Options

Average dv 

improvement 

(2001-03)

Total annualized 

cost $/dv15

Hercules Glades

LNB/OFA 0.22 $1,690,000 $7,681,818

LNB/OFA+SCR 0.33 $38,210,000 $115,787,879

FGD – 0.15 lbs/MMBtu 0.25 $34,720,000 $138,880,000

FGD – 0.10 lbs/MMBtu16 0.4417 $34,720,00018 $78,909,091 

LNB/OFA+FGD 0.47 $36,410,000 $77,468,085

LNB/OFA+FGD+SCR 0.55 $72,930,000 $132,600,000

Wichita Mountains

LNB/OFA 0.12 $1,690,000 $14,083,333

LNB/OFA +SCR 0.15 $38,210,000 $254,733,333 

FGD – 0.15 lbs/MMBtu 0.23 $34,720,000 $150,956,522

FGD – 0.10 lbs/MMBtu19 0.3820 $34,720,000 $91,368,421 

LNB/OFA+FGD 0.35 $36,410,000 $104,028,571

LNB/OFA+FGD+SCR 0.38 $72,930,000 $191,921,053

2 Class I areas 

(Cumulative)

LNB/OFA 0.34 $1,690,000 $4,970,588

LNB/OFA +SCR 0.48 $38,210,000 $79,604,167 

FGD – 0.15 lbs/MMBtu 0.48 $34,720,000 $72,333,333

FGD – 0.10 lbs/MMBtu 0.8221 $34,720,000 $42,341,463 

LNB/OFA+FGD 0.82 $36,410,000 $44,402,439

LNB/OFA+FGD+SCR 0.93 $72,930,000 $78,419,355

 

13 Besides these rows, all other references to FGD in this table are modeled at a rate of 0.15 lbs/MMBtu. 

14 Nebraska only presented modeling information for FGD at 0.10 lbs/MMBtu in its SIP for the most impacted year, 

2003 at Wichita Mountains. 

15 Note that in its SIP, Nebraska calculated the dollars per deciview based on the year of maximum impact, rather than 

a three year average as presented here. 

16 Besides these rows, all other references to FGD in this table are modeled at a rate of 0.15 lbs/MMBtu. 

17 This is maximum improvement, not a three year average. 

18 In Nebraska’s SIP, they appear to have assumed the same cost regardless of the level of control (0.15 or 0.10 

lbs/MMBtu); however, a higher level of control would likely have a slightly higher cost. 

19 Besides these rows, all other references to FGD in this table are modeled at a rate of 0.15 lbs/MMBtu. 

20 This is maximum improvement, not a three year average. 

21 This is maximum improvement, not a three year average. 
18

Nebraska concluded that based on the high incremental cost of $8,20322 per ton for 

the low incremental visibility improvement of 0.11 dv at Hercules Glades, requiring 

SCR was not warranted. BART for OPPD NCS Unit 1 was determined to be the 

installation of LNB/OFA with an emission limitation of 0.23 lbs/MMBtu. EPA 

agrees that the State’s determination is reasonable given the relatively insignificant 

additional visibility improvement associated with SCR for the additional cost. 

b. BART for SO2 - NCS Unit 1

Step one is to identify all available retrofit control technologies. Nebraska identified 

FGD, both throwaway systems (wet and dry FGD) and regenerative processes, as 

possibilities for SO2 control. Step two is to eliminate technically infeasible options.

Coal desulfurization was determined to be infeasible because it has not been 

demonstrated for low-sulfur coal, as is used at NCS; the Pahlman process and other 

regenerative processes were determined to be infeasible because they have not been 

demonstrated on large coal-fired boilers. Therefore, only dry and wet FGD were 

deemed feasible and subject to further analysis.

We note that Nebraska did not evaluate Dry Sorbent Injection (DSI) as a potential 

SO2 control for NCS Unit 1. Since DSI can generally achieve the same control 

efficiency as FGD, we believe that the State has appropriately evaluated the level of 

controls in its analysis.

Step three is to evaluate the control effectiveness of the technologies that were 

deemed feasible. These results are presented in table 10.

Table 10: SO2 control technology effectiveness, NCS Unit 1

Control 

Technology

Emission 

rate 

(lbs/MMBtu)

Potential 

emissions 

(tpy)

Tons SO2

removed 

(tpy)

Control 

efficiency

Baseline 0.815 24,191 N/A N/A

Wet FGD 0.15 4,452 19,739 82%

Dry FGD 0.15 4,452 19,739 82%

Dry FGD23 0.10 2,969 21,222 88%

Step four is to consider the costs, energy impacts, non-air quality environmental 

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

fully described in the OPPD BART analysis; only the cost of the various options is 

presented here.

Nebraska concluded that dry FGD (spray dryer absorber (SDA)) has lower capital 

and operating costs than wet FGD and can achieve the same control efficiency; it 

thus focused its cost analysis on dry FGD.

 

22 ($38,210,000 - $1,690,000) / (14,633-10,181) = $8,203

23 Figures in this row were calculated by EPA; they were not provided in the SIP or in the BART appendices. 
19

Table 11: Cost of SO2 control options, NCS Unit 1

Technology Options

Dry FGD (SDA)

0.15 lbs/MMBtu

Dry FGD (SDA)

0.10 lbs/MMBtu

Emission Reduction (tpy) 19,739 21,22224

Percentage Reduction 82% 88%

Capital Cost $201,660,000 unknown

Annualized Capital Cost $16,180,000 unknown

Annual Operating Cost $18,540,000 unknown

Total Annualized Cost $34,720,000 $34,720,00025

Total Cost Effectiveness ($/ton) $1,759 $1,636

Step five is to evaluate the visibility impacts. These are presented in table 8, in the 

NOx section above. Nebraska concludes that the costs of installing FGD

($34,720,000) are too high for the small amount of visibility improvement (0.44 dv 

maximum improvement at Hercules Glades), and therefore proposes no SO2 

controls as BART for NCS Unit 1. Based on the minimal visibility improvement, 

EPA agrees that the State’s SO2 BART determination for NCS Unit 1 is reasonable.

2. Nebraska Public Power District (NPPD) – Gerald Gentleman Station (GGS) 

Units 1 and 2

Like the BART analysis for OPPD, NPPD hired a contractor to conduct a BART 

analysis, which was then submitted to NDEQ for review and use. Information 

presented here is from the March 2008 revised NPPD BART analysis and Nebraska’s 

SIP.

a. BART for NOx - GGS Units 1 and 2

Step one is to identify available NOx control technologies. NPPD identified 

LNB/OFA, SCR, SNCR, SCONOx, and the Palman Process as available 

technologies for NOx control. In 2006, NPPD installed LNB and OFA for NOx 

control. Note that this is after the 2001-2003 baseline modeling period used in the 

CALPUFF modeling. Therefore, LNB/OFA is still examined in this BART 

analysis.

Step two is to eliminate technically infeasible options. LNB/OFA and SCR were 

determined to be technically feasible based on demonstrated performance on many

similar units. Nebraska eliminated the following technologies from further 

consideration:

 SNCR - Infeasible due to high furnace exit temperatures

 SCONOx - not demonstrated on large coal-fired boilers

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

 

24 The tons of emission reduction and percentage reduction were back calculated by EPA based on other numbers 

provided in the SIP narrative. Nebraska did not provide these numbers directly. 

25 In Nebraska’s SIP, they appear to have assumed the same cost regardless of the level of control (0.15 or 0.10 

lbs/MMBtu); however, a higher level of control would likely have a slightly higher cost. 
20

The third step in the BART analysis is to examine the effectiveness of the feasible 

control technologies. 

Table 12: NOx control technology effectiveness, GGS Units 1 and 2

Control 

technology

Emission rate 

(lbs/MMBtu)

Potential 

emissions 

(tpy)

Tons NOx 

removed

Control 

efficiency

Baseline 0.455 30,243 N/A N/A

LNB/OFA 0.23 15,287 14,956 49%

LNB/OFA+SCR 0.08 5,317 24,926 82%

The fourth step of the BART analysis is to consider the cost of compliance, energy, 

non-air quality environmental impacts, and remaining useful life. These factors are 

described in detail in the BART analysis; only the costs are presented here. 

Table 13: Cost of NOx control options, GGS Units 1 and 2

Technology Options

LNB/OFA+ 

SCR

LNB/OFA

Emission Rate (lb/MMBtu) 0.08 0.23

Emission Reduction (tpy) 24,926 14,956

Percentage Reduction 82% 49%

Capital Cost $515,081,000 $36,930,000

Annualized Capital Cost $41,715,000 $2,960,000

Annual Operating Cost $14,515,000 $0

Annualized Outage Cost $1,021,000 $0

Total Annualized Cost $57,251,000 $2,960,000

Total Cost Effectiveness ($/ton) $2,297 $198

The fifth and final step in a BART analysis is to examine the visibility

improvements of various control options. Results presented in table 14 are for the 

six Class I areas which were modeled to be impaired by GGS > 0.5 dv. Both NOx

and SO2 controls are presented. Note that although both GGS units have an 

individual stack, they were modeled as a single stack, so modeling results presented 

here are for the two units combined.

Table 14: Visibility analysis, NPPD GGS Units 1 and 2

Class I area Control technology 

options

Deciview impact, 8th high 

values Improvement 

2001 2002 2003 Average (Average)

Badlands 

(South Dakota)

Baseline 2.845 2.828 3.121 2.93

FGD (0.15 lbs/MMBtu)26 1.836 2.125 2.478 2.15 0.78

FGD (0.10 lbs/MMBtu) 1.790 2.026 2.443 2.09 0.85

 

26 Note that FGD was modeled at 0.15 lbs SO2/MMBtu in this analysis, except where expressly noted.
21

LNB/OFA 2.224 2.162 2.419 2.27 0.66

LNB/OFA+SCR 1.732 1.728 1.879 1.78 1.15

LNB/OFA+FGD 1.107 1.275 1.537 1.31 1.62

LNB/OFA+FGD+SCR 0.62 0.692 0.757 0.69 2.24

DSI27 1.755 2.147 2.31 2.07 0.86

Wind Cave 

(South Dakota)

Baseline 2.452 2.591 2.127 2.39

FGD 1.61 1.415 1.437 1.49 0.90

LNB/OFA 1.902 2.051 1.586 1.85 0.54

LNB/OFA+SCR 1.565 1.659 1.273 1.50 0.89

LNB/OFA+FGD 1.008 0.856 0.82 0.89 1.50

LNB/OFA+FGD+SCR 0.586 0.47 0.465 0.51 1.88

Wichita 

Mountains 

(Oklahoma)

Baseline 1.032 1.206 1.392 1.21

FGD 0.67 0.734 0.82 0.74 0.47

LNB/OFA 0.846 0.948 1.086 0.96 0.25

LNB/OFA+SCR 0.681 0.82 1.02 0.84 0.37

LNB/OFA+FGD 0.415 0.423 0.504 0.45 0.76

LNB/OFA+FGD+SCR 0.244 0.245 0.294 0.26 0.95

Rocky 

Mountain 

(Colorado)

Baseline 1.136 1.246 1.053 1.15

FGD 0.607 0.822 0.646 0.69 0.46

LNB/OFA 0.927 0.956 0.807 0.90 0.25

LNB/OFA+SCR 0.788 0.777 0.628 0.73 0.42

LNB/OFA+FGD 0.38 0.478 0.376 0.41 0.74

LNB/OFA+FGD+SCR 0.23 0.263 0.205 0.23 0.92

Hercules Glades 

(Missouri)

Baseline 0.826 0.616 0.594 0.68

FGD 0.538 0.327 0.307 0.39 0.29

LNB/OFA 0.64 0.508 0.46 0.54 0.14

LNB/OFA+SCR 0.527 0.456 0.40 0.46 0.22

LNB/OFA+FGD 0.319 0.207 0.201 0.24 0.44

LNB/OFA+FGD+SCR 0.179 0.122 0.115 0.14 0.54

Mingo 

(Missouri)

Baseline 0.615 0.432 0.438 0.5

FGD 0.299 0.168 0.213 0.23 0.27

LNB/OFA 0.495 0.365 0.332 0.4 0.10

LNB/OFA+SCR 0.423 0.308 0.28 0.34 0.16

LNB/OFA+FGD 0.174 0.11 0.13 0.14 0.36

LNB/OFA+FGD+SCR 0.108 0.07 0.077 0.09 0.41

6 Class I areas 

(cumulative) Baseline 8.86

 

27 Nebraska only presented visibility results for DSI at Badlands.
22

The visibility results presented in table 15 are for the closest and most impacted 

Class I area, Badlands; cumulative results include all 6 Class I areas shown to be 

impacted by GGS > 0.5 dv.

Table 15: Costs for visibility improvement, GGS Units 1 and 2

Control Options

Average dv 

improvement 

(2001-03)

Total 

annualized cost $/dv

Badlands

DSI 0.86 $81,958,000 $95,300,000

FGD (0.15 lbs/MMBtu) 0.78 $108,517,000 $139,124,359

FGD (0.10 lbs/MMBtu)28 0.85 $108,517,00029 $127,667,059 

LNB/OFA 0.66 $2,960,000 $4,484,848

LNB/OFA+SCR 1.15 $57,251,000 $49,783,478

LNB/OFA+FGD 1.62 $114,410,000 $70,623,457

LNB/OFA+FGD+SCR 2.24 $168,701,000 $75,312,946

Cumulative, 6 

Class I areas30

DSI unknown31 $81,958,000 $47,650,000

FGD 3.17 $108,517,000 $34,232,492

LNB/OFA 1.94 $2,960,000 $1,525,773

LNB/OFA+SCR 3.21 $57,251,000 $17,835,202

LNB/OFA+FGD 5.42 $114,410,000 $21,108,856

LNB/OFA+FGD+SCR 5.56 $168,701,000 $30,341,906

Nebraska concluded that based on the relatively low incremental visibility 

improvement of adding SCR to the LNB/OFA system (0.49 dv, Badlands) for the 

additional cost ($5,445 incremental cost per ton32), requiring SCR as BART was not 

warranted. BART for OPPD NCS Unit 1 was determined to be the installation of 

LNB/OFA with an emission limitation of 0.23 lbs/MMBtu, averaged across the two 

units. EPA agrees that the State’s NOx BART determination is reasonable. 

b. BART for SO2 - GGS Units 1 and 2

Step one is to identify the available control technologies for SO2. Nebraska 

identified wet and dry FGD, coal desulfurization, the Pahlman process, and other 

regenerative processes as potential controls. Step two is to eliminate the technically

infeasible controls. NPPD eliminated the following controls from further 

consideration:

 Coal desulfurization - not demonstrated for low-sulfur PRB coal

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

 

28 Unless expressly noted, FGD visibility results in this table were modeled at 0.15 lbs/MMBtu. 

29 In Nebraska’s SIP, they appear to have assumed the same cost regardless of the level of control (0.15 or 0.10 

lb/MMBtu); however, a higher level of control would likely have a slightly higher cost.

30 In calculating cumulative visibility improvement, NDEQ only considered the two closest Class I areas, Badlands 

and South Dakota. We believe that it is more appropriate to calculate cumulative improvement from all the Class I 

areas which are impacted greater than 0.5 dv from GGS Units 1 and 2.

31 Visibility improvement for DSI was only evaluated at Badlands; because of the proximity and similarity of impacts 

between Badlands and Wind Cave, we believe it is reasonable to assume similar visibility improvement would be seen 

at Wind Cave from the installation of DSI. 

32 Incremental cost per ton: ($57,251,000 - $2,960,000) / (24,926 - 14,956) = $5,445
23

 Other regenerative processes – none have been demonstrated on large coal-fired 

boilers

In response to comments on the original BART analysis, Nebraska requested that 

NPPD also evaluate Dry Sorbent Injection (DSI) for SO2 control. Nebraska 

determined that DSI is a technically feasible control for GGS Units 1 and 2. 

Step three is to examine the effectiveness of the feasible control technologies. These 

results are presented on table 16.

Table 16: SO2 control technology effectiveness, GGS Units 1 and 2

Control 

technology

Emission rate 

(lb/MMBtu)

Potential 

emissions 

(tpy)

Tons SO2 

removed

Control 

efficiency

Baseline 0.749 49,785 N/A N/A

Wet FGD 0.15 9,970 39,815 80%

Dry FGD 0.15 9,970 39,815 80%

DSI 0.15 9,970 39,815 80%

FGD33 0.10 6,647 43,138 87%

Step four is to consider the cost of compliance, energy, non-air quality

environmental impacts, and remaining useful life. These factors are described in 

detail in the BART analysis; the costs are presented here, as well as a significant 

non-air quality environmental issue (water availability) raised by Nebraska.

Table 17: Cost of SO2 control options, GGS Units 1 and 234

Technology Options

Dry FGD Wet FGD DSI FGD

Emission Rate (lb/MMBtu) 0.15 0.15 0.15 0.10

Emission Reduction (tpy) 39,815 39,815 39,815 43,138

Percentage Reduction 80% 80% 80% 87%

Capital Cost $981,592,000 $1,029,819,000 $208,330,000 unknown

Annualized Capital Cost $80,013,000 $83,965,000 $17,500,000 unknown

Annual Operating Cost $27,806,000 $24,485,000 $64,458,000 unknown

Annualized Outage Cost $698,000 $0 $0 unknown

Total Annualized Cost $108,517,000 $108,450,000 $81,958,00035 $123,933,69436

Total Cost Effectiveness 

($/ton)

$2,726 $2,724 $2,058 $2,873

 

33 Figures in this row were calculated by EPA; they were not provided in the SIP or in the BART appendices.

34 The costs presented in Table 17 include the total cost for controlling SO2 emissions from both units at GGS. 

35 Nebraska adjusted the costs for DSI to 2016 dollars, because they say that’s the likely time when installation would 

occur. Note that the other figures in this table were not adjusted to future years.

36 In Nebraska’s analysis of costs and visibility improvement of FGD at 0.10 lb/MMBtu, they used the total annualized 

cost of $123,933,694. This is the same cost at 0.15 lb/MMBtu, but with costs to purchase water rights and costs of

loss of agricultural revenue added in. The cost does not, however, include increased costs for operating at a more 

stringent level of control, which presumably would be slightly higher. EPA believes that it is appropriate to include the 

costs of obtaining water rights, but not costs for loss of agricultural value for purposes of a BART analysis. 
24

Costs per ton for wet and dry FGD at a rate of 0.15 lbs/MMBtu were nearly 

identical, and Nebraska concluded that these costs were reasonable on a cost per ton 

basis ($2,726/ton). Nebraska found DSI to be more cost effective, at $2,058 per ton. 

Nebraska raises water use of wet and dry FGD as a significant non-air 

environmental impact. In its SIP, Nebraska presents a description of the overappropriation of water resources in the western part of the State, where GGS is 

located. The State described that over-appropriation means that any new use of 

water requires an offset in water consumption in the same area. To do this, NPPD 

would have to purchase the ground water rights from surrounding landowners.

Nebraska did not include the cost of obtaining these water rights in the original 

BART analysis costs; however, in the narrative portion of the SIP, Nebraska 

describes both the costs of obtaining water, and the loss of agricultural revenue due 

to taking land out of agricultural production:

“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 

operate FGD] to $123,933,694, a 14.3% increase. The NDEQ concluded 

this is a significant economic impact.” 

If the costs to obtain water rights were added into the BART analysis, the FGD 

costs would increase to $117,776,000. (EPA is not including the loss of crop value

in its analysis). As seen in table 18, adding in the costs of water rights only 

increases the cost of control by $234 per ton. This brings the cost per ton to $2,958, 

which EPA believes is still a reasonable cost of control. 

Table 18: Cost of SO2 control and visibility benefit, GGS Units 1 and 2

Technology Options

Wet FGD 

(original 

BART 

analysis)

Wet FGD 

(revised 

with water 

offset costs)

Wet FGD 

(with water 

offset costs)

DSI

Emission Rate (lb/MMBtu) 0.15 0.15 0.10 0.15

Total Annualized Cost $108,450,000 $117,776,000 $123,933,69437 $81,958,000

Total Cost Effectiveness ($/ton) $2,724 $2,958 $2,873 $2,058

Average visibility improvement 

(Badlands)

0.78 0.78 0.85 0.86

 

37 In Nebraska’s analysis of costs and visibility improvement of FGD at 0.10 lbs/MMBtu, they used the total 

annualized cost of $123,933,694. This is the same cost at 0.15 lbs/MMBtu, but with costs to purchase water rights and 

costs of loss of agricultural revenue added in. EPA believes that it is appropriate to include the costs of obtaining 

water rights, but not costs for loss of crop value for purposes of a BART analysis. 
25

Average visibility improvement 

(Cumulative)

3.17 3.17 unknown38 unknown39

$/dv (Badlands) $139,124,359 $150,994,872 $145,804,34640 $95,300,000

$/dv (Cumulative) $34,232,492 $37,153,312 unknown unknown

Step five is to examine the visibility improvements of various control options. 

Results are presented in table 14 and 15, above. Significant visibility improvement 

is seen from all of the control options, ranging from 0.78 dv average improvement 

at Badlands from installation of FGD, to 1.62 average dv improvement at Badlands 

from installation of LNB/OFA plus FGD. If considered on a cumulative basis, 

GGS has a baseline impact on 6 Class I areas of 8.86 dv. Installation of FGD would 

offer an average of 3.17 dv cumulative improvement, and in combination with 

LNB/OFA, 5.42 dv cumulative improvement.41

In the SIP, Nebraska says that it used a $40,000,000/yr/dv threshold for determining 

what would be considered reasonable investment for visibility improvement. They

concluded that the costs of FGD control were reasonable on a cost per ton basis, but 

not on a dollars per deciview basis. Furthermore, Nebraska sees the water 

consumption of FGD controls as significant, and concludes that because of this 

unique situation, FGD controls are unreasonable for GGS Units 1 and 2. 

EPA disagrees with this conclusion. Using Nebraska’s costs, we agree that the cost 

per ton for FGD control is reasonable, and also see the visibility improvement, both 

at Badlands and on a cumulative basis, as significant. 

We believe that Nebraska also inappropriately ruled out DSI. Costs for the control 

are reasonable at $2,058 per ton and visibility improvement at Badlands is 

significant at 0.86 dv. If considered cumulatively, visibility improvement would be 

even more significant, although as mentioned previously, Nebraska did not provide 

that analysis in their SIP. Furthermore, DSI does not present the same water 

consumption issues as FGD.

Finally, as described in detail in appendix A, B, and C of this TSD, we believe that

Nebraska’s costs of FGD control are overestimated. EPA conducted an independent 

analysis of the cost information presented by Nebraska in its BART analysis for dry

scrubbers. Although we did not review the BART cost analysis for wet scrubbers, 

many of the same issues likely apply. Note that our analysis of the cost elements 

 

38 Nebraska only provided visibility improvement information for FGD at 0.10 lbs/MMBtu for Badlands, so the 

cumulative benefit is unknown.

39 Nebraska only evaluated visibility improvement for DSI at Badlands, so the cumulative benefit is unknown. 

40 In Nebraska’s analysis of costs and visibility improvement of FGD at 0.10 lbs/MMBtu, they used the total 

annualized cost of $123,933,694. This is the same cost at 0.15 lbs/MMBtu, but with costs to purchase water rights and 

costs of loss of crop value added in. EPA believes that it is appropriate to include the costs of obtaining water rights, 

but not costs for loss of crop value for purposes of a BART analysis. 

41 These figures all assume FGD at the presumptive rate. At the rate of 0.10 lbs/MMBtu, average visibility 

improvement at Badlands would be 0.85 dv. Cumulative improvement is unknown. 
26

was not comprehensive, but only addresses what we see as some of the most 

significant errors and deviations from EPA’s Cost Control Manual.

42

Categories which we found significant overestimations include:

 Engineering Procurement and Construction

 Bond Fees

 Escalation

 Contingency

 Allowance for Funds Used During Construction

 Capital Recovery Factor

 Operation and Maintenance

We also found that Nebraska incorrectly calculated the SO2 emission rates. On page 

15 of its BART analysis, NPPD calculates its SO2 emission baseline based on 

applying a 24 hour maximum emission rate of 0.749 lbs/MMBtu (2001-2003) to a 

maximum heat input of 15,175.5 MMBtu/hr, based on a 100% capacity factor. This 

results in an emissions baseline of 49,785 tons/yr.43 We believe this calculation 

does not appropriately represent GGS’s SO2 emission baseline, and is in fact too 

high. The Regional Haze Rule provides the following regarding the calculation of 

the BART emissions baseline:

“The baseline emissions rate should represent a realistic depiction of 

anticipated annual emissions for the source. In general, for the existing 

sources subject to BART, you will estimate the anticipated annual emissions 

based upon actual emissions from a baseline period. When you project that 

future operating parameters (e.g., limited hours of operation or capacity 

utilization, type of fuel, raw materials or product mix or type) will differ 

from past practice, and if this projection has a deciding effect in the BART 

determination, then you must make these parameters or assumptions into 

enforceable limitations. In the absence of enforceable limitations, you 

calculate baseline emissions based upon continuation of past practice.”

We see no indications that NPPD’s future operating practices are projected to 

deviate from the past. GGS states on page 2 of its BART analysis that it used a 

baseline period of 2001-2003, which was the baseline emission rate period for 

BART modeling in Nebraska. We have downloaded emissions data for GGS from 

our Clean Air Markets web site44and have calculated the average total station SO2

emissions for GGS Units 1 and 2 to be 31,513 tons/yr for the three year period of 

2001-2003. We note that based on GGS’s stated capacity of Units 1 and 2 (665 and 

700 MW, respectively), we calculate capacity factors for Units 1 and 2 to range 

from 89% to 94% and 77% to 85%, respectively, from 2001-2003. Our analysis 

assumes this historic usage is not significantly altered in the future. A summary of 

this data appears in appendix B to the TSD.

 

42

 EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/452/B-02-001, January 2002 

43

 (0.749 lbs/MMBtu) * (15,175 MMBtu/hr) * (8,760 hrs/yr) * (ton/2,000 lbs) = 49,785 tons/yr.

44

 http://camddataandmaps.epa.gov/gdm/index.cfm?fuseaction=emissions.wizard
27

Using the same emissions data from the three year averaging period of 2001-2003, 

we have calculated the three year average annual SO2 emissions for units 1 and 2 of 

the GGS to be 0.565 lbs/MMBtu.45 Reducing this to a controlled SO2 emissions 

level of 0.15 lbs/MMBtu results in a scrubber efficiency of approximately 73.5%. 

Applying this level of control to our adjusted GGS SO2 emission baseline of 31,513 

tons/yr would reduce it to 8,366 tons/yr, resulting in a reduction of 23,147 tons of 

SO2 annually. Applying the same approximate 80% level of reduction GGS 

assumes to our adjusted GGS SO2 emission baseline of 31,513 tons/yr would reduce 

it to 6,311 tons/yr, resulting in a reduction of 25,202 tons of SO2 annually.

46

However, dry scrubbers are capable of much greater control efficiencies than the 

80% level that Nebraska assumes.47 Therefore, for the purpose of calculating the 

cost effectiveness of dry scrubbers at the GGS, we have assumed an SO2 emission 

limit of 0.06 lbs/MMBtu, which results in a scrubber efficiency of approximately

89.4%. Applying this level of control to our adjusted GGS baseline of 31,513 

tons/yr would reduce it to 3,347 tons/yr, resulting in a reduction of 28,166 tons of 

SO2 annually.

Table 19 summarizes EPA’s adjustments to the NPPD cost estimates for dry FGD 

control. 

Table 19: Range of GGS Dry Scrubber Cost Effectiveness

Dry FGD

(original NPPD 

BART analysis)

Dry FGD

EPA’s estimate

SO2 Baseline 49,785 31,513

Uncontrolled Emission Level 

(lbs/MMBtu)

0.749 0.565

Controlled Emission Rate 

(lbs/MMBtu)

0.15 0.15 0.11 0.06

Percent Reduction 80% 73.5% 80% 89.4%

SO2 Emission Reduction (tons) 39,815 23,147 25,202 28,166

Total Annualized Cost $108,535,690 $53,469,570 $54,335,512 $55,543,352

Total Cost Effectiveness ($/ton) $2,726 $2,310 $2,156 $1,972

In summary, we believe that Nebraska overestimated the costs of FGD controls; did 

not do a full evaluation of the potential visibility benefits from levels of control that 

FGD is capable of achieving; and improperly rejected DSI. We believe that the cost 

 

45

 See Attachment B to our TSD. Based on adding the station total pounds of SO2 emissions from 2001-2003 and 

dividing by the station total heat input from 2001-2003.

46

 (39,815/49,785)*31,513 = 25,202.

47

 Response to Technical Comments for Sections E. through H. of the Federal Register Notice for the Oklahoma 

Regional Haze and Visibility Transport Federal Implementation Plan, Docket No. EPA-R06-OAR-2010-0190, 

12/13/2011, Section II., Comments Relating to Our SO2 BART Emission Limit, and elsewhere.
28

per ton of SO2 controls ranging from $1,972 (our analysis) to $2,958 (Nebraska’s 

analysis, plus water) is reasonable; and that the visibility benefits, whether 

considered just at Badlands or cumulatively, are significant. Therefore, EPA 

proposes to disapprove Nebraska’s BART determination for SO2 at Gerald 

Gentleman Station. 

v. BART summary and enforceability: 40 CFR 51.308(e)(1)(iv)–(v)

Table 20 is a summary of the BART determinations made by Nebraska for BARTsubject units. 

Table 20: Summary of BART determinations

Facility, Units Pollutant BART controls determined 

by Nebraska

EPA’s 

proposed 

determination

OPPD Nebraska 

City Station, Unit 1

NOx

Install LNB with OFA, meet 

level of 0.23 lbs/MMBtu. Approval

SO2 No additional controls. Approval

NPPD Gerald 

Gentleman Station, 

Units 1 and 2

NOx

Install LNB with OFA. Meet 

level of 0.23 lbs/MMBtu. Approval

SO2 No additional controls. Disapproval

Each source subject to BART must install and operate BART as expeditiously as 

practicable, but in no event later than 5 years after approval of the SIP revision; and

include monitoring, recordkeeping and reporting requirements to ensure the BART 

limits are enforceable.

Nebraska chose to incorporate BART requirements into PSD permits issued 

pursuant to Title 129 of the Nebraska Air Quality Regulations, Chapter 19. These 

limits will be incorporated into the facility’s Title V permits after SIP approval. The 

permits require that the limits be met within 5 years of approval of Nebraska’s 

regional haze SIP. The limits must be met on a 30-day rolling average basis at all 

times, including periods of startup, shutdown, and malfunction. The permits require 

the use of a NOx continuous emission monitoring system (CEMS) on each unit to 

demonstrate compliance with the BART NOx limits. Each CEMS is required to be 

operated and certified in accordance with 40 CFR Part 75. Recordkeeping and 

reporting is also required to be in accordance with 40 CFR Part 75. We have 

reviewed these requirements and propose to find them adequate as they relate to the 

BART limits we are proposing to approve.

f. Monitoring strategy: 40 CFR 51.308(d)(4)

Because it does not host a Class I area, Nebraska is not required to develop a 

monitoring strategy for measuring, characterizing, and reporting regional haze 

impairment that is representative of Class I areas within the State. However, the 

State is required to establish procedures by which monitoring data and other 

information is used to determine the contribution of emissions from within the State 

to regional haze impairment at Class I areas outside of the State. 
29

Compliance with this requirement is met by participation in the Interagency

Monitoring of Protected Visual Environments (IMPROVE)48 network. 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, although EPA notes that this monitor is not currently operating.

EPA believes the State’s commitment to utilize data from these sites, or any other 

EPA- approved monitoring network location, to characterize and model conditions 

within the state and to compare visibility conditions in the state to visibility

impairment at Class I areas hosted by other states, and proposes that Nebraska has 

satisfied the monitoring requirements of 40 CFR 51.308(d)(4). 

g. Emissions inventory: 40 CFR 51.308 (d)(4)(v)

States are required to develop a statewide inventory of emissions of pollutants that 

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

Class I area. The inventory must include emissions for a baseline year, emissions 

for the most recent year with available data, and future projected emissions. 

As mentioned previously, Nebraska worked with CENRAP and its contractors to 

develop statewide emission inventories for 2002 and 2018. Detailed methodologies

are documented in appendices 8.3 and 9.1. The 2018 emissions inventory was 

developed by projecting 2002 emissions and applying reductions expected from 

federal and state regulations affecting the emissions of the visibility-impairing 

pollutants NOx, PM, SO2, and VOCs. 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 EGUs. The 2018 emissions for EGUs were based on simulations of 

the IPM that took into the account the effects of CAIR on emissions.

At the time modeling was conducted, BART decisions had not been made by many

states, including Nebraska. Presumptive levels of BART control were assumed in 

projections of 2018 emissions. The 2018 inventory was then updated to account for 

Nebraska’s BART decisions. 

Table 21: 2002 Nebraska Emissions Summary (tons per year)

VOC NOx SO2 PM10 PM2.5 

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

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

On-Road 43,113 61,850 1,822 1,277 930

Non-Road 24,882 119,568 11,011 7,491 6,785

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

Biogenic 533,705 39,446 0 0 0

Total 678,947 295,185 94,336 474,633 100,161

 

48 http://vista.cira.colostate.edu/improve
30

Table 22: 2018 Nebraska Projected Emissions Summary

(tons per year)

VOC NOx SO2 PM10 PM2.5 

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 

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

Biogenic 533,705 39,446 0 0 0 

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

The EPA believes the 2002 and 2018 statewide emissions inventories and the 

State’s method for developing the 2018 emissions inventory for Nebraska meets the 

requirements of the RHR. Nebraska has also committed to update inventory 

periodically, therefore, we propose that Nebraska has met the requirements of 40 

CFR § 51.308(d)(4)(v).

h. Federal Land Manager (FLM) consultation: 40 CFR 51.308(i)

By November 29, 1999, Nebraska was required to identify in writing to the FLMs

the title of the official to which the FLM of any Class I area can submit 

recommendations. Nebraska has satisfied this requirement by identifying the Air 

Division Administrator at the Nebraska Department of Environmental Quality as 

this official.

States are required to provide the FLMs an opportunity for consultation, in person 

and at least 60 days prior to holding any public hearing on the SIP (or its revision). 

Consultations should include the opportunity for the FLMs to discuss their 

assessment of impairment of visibility in any Class I area; and recommendations on 

the development of the RPG and on the development and implementation of 

strategies to address visibility impairment. 

Nebraska provided several opportunities for the FLMs to comment on Nebraska’s 

regional haze plan. Nebraska sent the draft BART permits for NPPD and OPPD to 

the FLMs in mid-2008, and again prior to public notice. Nebraska provided the 

FLMs with a draft of the Nebraska regional haze SIP on November 16, 2010, and 

received formal comments from the National Park Service (NPS), the US Fish and 

Wildlife Service (USFWS), and the US Forest Service (USFS) in January 2011.

In developing any SIP (or plan revision), States must include a description of how it 

addressed any comments provided by the FLMs. The FLM comments and 

Nebraska’s responses are provided in appendix 3 of the SIP, and are summarized 

below. 

The FLMs believe that Nebraska did not met the requirement to include the 

measures necessary to achieve the reasonable progress goals established by States 
31

having mandatory Class I Federal areas in its draft SIP. They note that, “the goals 

established by South Dakota for Badlands and Wind Cave National Parks, by

Colorado for Rocky Mountain National Park, by Oklahoma for Wichita Mountains, 

and by Missouri for Mingo Wildlife Refuge and Hercules Glade Wilderness Area, 

as well as other Class I areas, assume that Nebraska will require presumptive BART 

controls for the Gerald Gentleman and Nebraska City power plants as modeled by

WRAP and CENRAP. Nebraska proposes not to require controls of SO2 for any of 

the BART units. Nebraska’s long term strategy does not include the controls 

required to meet its contribution to the reasonable progress goals established by its 

neighboring states through the RPO process.” 

The FLMs also have expressed concerns with Nebraska’s BART analyses at 

Nebraska City Station (NCS) Unit 1 and Gerald Gentleman Station (GGS) Units 1 

and 2. For NCS, the FLMs ask Nebraska to seriously consider all feasible SO2

control options, including DSI, and NOx controls, including SNCR, as part of the 

five factor analysis. They state that $1,636 per ton for SDA with a fabric filter is 

reasonable and should be considered as BART for Unit 1. They disagree with ruling 

out SCR for NOx control, as it is cost effective. The FLMs also questioned whether 

the cost estimates were developed consistent with the EPA Control Cost Manual.

They also ask Nebraska to consider upgrade of the existing PM control as a BART 

alternative. 

The FLMs go on to say that the BART determination for GGS is not acceptable as 

written, disagreeing with Nebraska’s BART determination of no SO2 controls for 

Gerald Gentleman. They point out that the visibility impact of these units is 

significant at more than just the closest Class I area (Badlands); they also take issue 

with several aspects of the cost estimation, such as escalation, contingencies, 

allowance for funds during construction, overestimation of direct annual costs. 

The FLMs did an analysis of what they believe a more appropriate cost estimation 

would be, and found that costs for a dry FGD system should be $87,101,902 in 

annualized cost, or $2,155 per ton. This is 20% lower than NPPD’s estimates. For a 

wet FGD system, annualized costs were estimated to be $85,696,911, or a cost of 

$2,073/ton. This is 21% lower than NPPD’s estimates.

Regarding Nebraska’s argument about the significance of water availability, the 

United States Fish and Wildlife Service Air Branch asked the USFWS’s Nebraska 

Field Office to review Nebraska’s Draft Regional Haze SIP and comment on the 

merits of the arguments on water and endangered species protection. In a memo 

dated December 22, 2010, the USFWS Nebraska Field Office responded that, “the 

arguments given by NDEQ have some merit. However, the Platte River Recovery 

Implementation Program (PRRIP) inherently provides options to offset 

consumptive use that results in depletions to the river and jeopardizes endangered 

species. Additionally, it appears much of the information provided in Nebraska’s 

plan represents a worst-case scenario when describing offsets to water used by the 

NPPD. While not inaccurate, the information tends to overstate implications of any 

new water use by NPPD....in summary, there is no question any new depletions to 
32

central Platte River flows would require offsets. Because of this, there is the 

possibility that accelerating actions to achieve air quality improvements would 

weaken Nebraska’s ability to meet its PRRIP obligations to improve Platte River 

flows on schedule. But we do not believe that it automatically follows that air 

quality improvements cannot be pursued because Nebraska simply could not do 

both.”

Finally, regional haze SIPs must provide procedures for continuing consultation 

between the State and FLMs on the implementation of 51.308, including 

development and review of SIP revisions and 5-year progress reports, and on the 

implementation of other programs having the potential to contribute to impairment 

of visibility in Class I areas. Nebraska has committed to continuing to coordinate 

and consult with the FLMs 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 Class I areas. 

We propose that Nebraska has satisfied the FLM consultation requirements of 40 

CFR 51.308 (i).

i. Periodic SIP revisions and five year progress report: 40 CFR 51.308 (f)-(h)

Nebraska acknowledged the requirement to submit periodic progress reports and 

regional haze SIP revisions, with the first report due by July 31, 2018, and revisions 

due every ten years thereafter. Nebraska committed to meeting this requirement.

Nebraska also acknowledged the requirement to submit periodic reports evaluating 

progress towards the reasonable progress goals established for each mandatory

Class I area. Nebraska committed to complete the first five-year progress report by

December 31, 2016. The 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. Using the findings of 

this first report, Nebraska committed to determining whether the adequacy of the 

plan is sufficient and taking appropriate action to revise the SIP as needed.

We propose to find that Nebraska has satisfied the requirements to commit to

periodic SIP revisions and progress reports as required by 40 CFR 51.308(f)-(h).