Response to Comments for the Federal Register Notice for the State of 

Arkansas; Regional Haze and Interstate Visibility Transport Federal 

Implementation Plan 

Docket No. EPA-R06-OAR-2015-0189

08/31/2016
2 

List of Public Comments 

Docket ID 

Number 

(EPA-R06-

OAR-2015-

0189-xxxx) 

Document 

title number

(AR020.xxx)

Commenter Affiliation 

0141 AR020.0141 Arkansas Electric Cooperative Corporation 

(Request for Extension of Comment Period) 

0142 AR020.0142 Domtar 

(Request for Extension of Comment Period) 

0143 AR020.0143 Energy and Environmental Alliance of 

Arkansas 

(Request for Extension of Comment Period) 

0144 AR020.0144 Arkansas Department of Environmental 

Quality (Request for Extension of Comment 

Period) 

0145 AR020.0145 Arkansas Environmental Federation 

(Request for Extension of Comment Period) 

0146 AR020.0146 

0147 AR020.0147 

0148 AR020.0148 Southwest Electric Power Company 

(Request for Extension of Comment Period) 

0149 AR020.0149 Entergy Arkansas Inc. 

(Request for Extension of Comment Period) 

0150 AR020.0150 Nucor Steel-Arkansas 

(Request for Extension of Comment Period) 

0151 AR020.0151 Arkansas Audubon Society 

0152 AR020.0152 Transcript of Public Hearing in Little Rock, 

Arkansas, April 16, 2015 

0153 AR020.0153 

0154 AR020.0154 Arkansas Public Policy Panel 

0155 AR020.0155 Domtar 

(Request for Extension of Comment Period) 

0156 AR020.0156 

0157 AR020.0157 

0158 AR020.0158 Dover Dixon Horne PLLC 

(Request for Extension of Comment Period) 

0159 AR020.0159 

0160 AR020.0160 Arkansas Department of Environmental 

Quality 

0161 AR020.0161 Domtar A.W. LLC Ashdown Mill 

0162 AR020.0162 The Honorable Leslie Rutledge, Attorney 

General, State of Arkansas 

0163 AR020.0163 Nucor Steel-Arkansas and Nucor-Yamato 

Steel Company 
3 

Docket ID 

Number 

(EPA-R06-

OAR-2015-

0189-xxxx) 

Document 

title number

(AR020.xxx)

Commenter Affiliation 

0164 AR020.0164 Southwest Electric Power Company (AEPSWEPCO) 

0165 AR020.0165 American Chemistry Council, American 

Coke and Coal Chemicals Institute, 

American Farm Bureau Federation, 

American Forest & Paper Association, 

American Iron and Steel Institute, American 

Petroleum Institute, American Public Power 

Association, American Wood Council, 

Arkansas Asphalt Pavement Association, 

Arkansas State Chamber of Commerce, 

Arkansas Environmental Federation, 

Arkansas Farm Bureau, Arkansas Forest & 

Paper Council, Arkansas Ready Mixed 

Concrete Association, Associated Industries 

of Arkansas Inc., Brick Industry 

Association, Corn Refiners Association, 

Council of Industrial Boiler Owners, 

Electricity Consumers Resources Council, 

Gas Processors Association, Industrial 

Energy Consumers of America, National 

Association of Manufacturers, National 

Mining Association, National Oilseed 

Processors Association, and U.S. Chamber 

of Commerce (collectively, “the 

Associations”) 

0166 AR020.0166 Entergy Arkansas Inc. 

0167 AR020.0167 Southwest Electric Power Company (AEPSWEPCO) 

(Supplemental Comments submitted on 

August 7, 2015) 

0168 AR020.0168 Entergy Mississippi Inc. 

0169 AR020.0169 Arkansas Electric Cooperative Corporation 

0170 AR020.0170 Domtar A.W. LLC Ashdown Mill 

(Supplemental Comments submitted on 

August 7, 2015) 

0171 AR020.0171 Sierra Club, Earthjustice, and National Parks 

Conservation Association 

0172 AR020.0172 Conway Corporation, Jonesboro City Water 

and Light, West Memphis Utilities, and 

Osceola Municipal Light and Power 
4 

Docket ID 

Number 

(EPA-R06-

OAR-2015-

0189-xxxx) 

Document 

title number

(AR020.xxx)

Commenter Affiliation 

0173 AR020.0173 Energy and Environmental Alliance of 

Arkansas 

0174 AR020.0174 Edison Electric Institute 

0175 AR020.0175 Arkansas Electric Energy Consumers Inc. 

and Arkansas Gas Consumers Inc. 

0176 AR020.0176 Utility Air Regulatory Group 

0177 AR020.0177 Citizen comments (16) 

0178 AR020.0178 Members of Sierra Club (183) 

0179 AR020.0179 Members of Sierra Club (38) 

0182 AR020.0182 Anonymous comment 

Notes: 

1. The following public submissions were requests for extensions of the public comment 

period that are not summarized in this document: EPA-R06-OAR-2015-0189-0141, 

0142, 0143, 0144, 0145, 0148, 0149, 0159, 0155, and 0158. 
5 

Table of Contents 

List of Public Comments......................................................................................2 

1. General and Miscellaneous..............................................................................6 

2. Entergy’s Proposed Strategy for White Bluff and Independence..................................52 

3. Reasonable Progress Goals and Reasonable Progress Analysis...................................71 

3.a. EPA did not perform an adequate Reasonable Progress Analysis...........................71 

3.b. Controls under reasonable progress/Arkansas’ Class I areas are below URP..............99 

glidepath 

3.c. Consistency........................................................................................148 

3.d. Impacts from other source categories..........................................................170 

3.e. Other................................................................................................185 

4. Specific BART Issues...................................................................................186 

 4a. Control Levels and Emission limits.............................................................186 

 4.b.Technical Feasibility of Controls.................................................................215 

 4.c. Domtar Ashdown Mill Repurposing Project..................................................218 

 4.d. Other Compliance Dates.........................................................................227 

 4.e. Compliance Demonstration Requirements....................................................236 

 4.f. Agreement with EPA’s proposed BART decisions..........................................241 

 4.g. Other................................................................................................245 

5. Reliance on CSAPR Better than BART...............................................................247 

6. Cost.........................................................................................................256 

 6.a. Cost Analyses and Cost-Effectiveness Issues.................................................256 

 6.b. Cost vs. Visibility Benefit........................................................................359 

7. Modeling..................................................................................................365 

 7.a. Cumulative Visibility Impairment..............................................................365 

 7.b. Imperceptible Visibility Improvements........................................................374 

 7.c. Model Selection....................................................................................385 

 7.d. Margin of Error CALPUFF Modeling.........................................................407 

 7.e. Reasonable Progress Analysis for Entergy Independence....................................439 

 7.f. Visibility Benefit of Entergy Arkansas Proposal.............................................458 

 7.g. Observed Visibility Improvements.............................................................461 

 7.h. Reasonable Progress Goals......................................................................466 

 7.i. Additional Modeling Comments................................................................475 

8. Legal......................................................................................................495 

 8.a. Controls will not be in place within the first planning period..............................495 

 8.b. Four-unit approach for White Bluff and Independence.....................................499 

 8.c. Requirements for Reasonable Progress and Long Term Strategy..........................501 

 8.d. States have a leading role and discretion under the Regional Haze program 

 Cooperative Federalism...............................................................................507 

 8.e. EPA does not have authority to finalize the FIP at this time................................513 

 8.f. EPA must address E.O. 12866 and 13211......................................................515 

 8.g. EPA did not adequately consider relevant factors............................................519 

 8.h. Other................................................................................................524 

9. Visibility Transport......................................................................................529 
6 

1. General and Miscellaneous 

Comment: (0178) 183 members of the public stated that as Arkansans, they value the Buffalo 

River, the Caney Creek Wilderness, and the Ouachita Mountains. These are true jewels of “The 

Natural State,” but they are polluted by haze from Arkansas’ dirty power plants. 

These members of the public stated that they support the EPA's plan to reduce haze pollution in 

Arkansas. Our parks are a public resource for our families, and shouldn't be sullied by power 

plant pollution. Our families have long enjoyed our Arkansas parks, as have millions of people 

from both in and out of our state. Our state parks are a treasure to be passed along to future 

generations. They are valuable beyond comparison and must be protected. Our parks are also 

huge economic engines, drawing millions of tourists to experience what Arkansas has to offer. 

This economic activity will be harmed without strong action to protect and clean up our parks. 

One commenter stated that one of the biggest reasons Arkansas is so amazing is its parks, its 

breathtaking natural surroundings, and its pristine condition. Pollution is destroying the very 

essence of what makes “The Natural State” so naturally beautiful. Please continue to fight to 

save our state and preserve its beauty. Another commenter stated that the EPA can make sure 

that Arkansas’ nickname “The Natural State” does not become a joke. The commenter stated it 

seems the new attorney general opposes EPA rules and it’s unclear on whose behalf she is 

working. 

Some commenters stated that EPA's draft regional haze plan makes dirty power plants clean up 

their act‐‐which is leadership they can get behind. One commenter stated that coal‐fired plants 

not only emit particulates, they also put mercury and other heavy metals into the environment. 

The haze is just a visible manifestation of the pollution that worsens our health and makes 

climate change inevitable. Coal plants are endangering our air and consequently are negatively 

impacting tourism and outdoor activities. The commenters asked EPA to do all we can to stop 

the increasing air pollution by passing a strong haze bill. 

One commenter stated that Arkansas needs to step it up and get serious about coal. Instead the 

state tries to convince its citizens that coal is essential. The State claims that without coal, the 

cost of electricity would skyrocket, which is false. Arkansas needs to invest in alternative energy. 

The folks running the Coop's reap their large incomes off customers. Another commenter stated 

that protecting our parks also protects our health. Coal isn't "cheap" when you factor in asthma 

and other illnesses that result from coal plant emissions. Another commenter asked EPA to 

please ensure that we clean up dirty coal power plants, along with other air polluters. 

Some commenters expressed a love of nature and wildlife. They stated that wildlife hinges on the 

protection of these waterways as habitat, and asked EPA to please respect and protect it from 

pollution. One commenter stated that they grew up visiting Devil's Den State Park every summer 

and any time the weather was warm. The commenter stated that they still visit the park in the 

Spring/Summer months, and that people value the parks in Arkansas. 

One commenter stated that not only should strong action be taken to protect our parks, but to also 

protect our health and ecosystem. The Obama Administration should hold firm and make these 
7 

states greatly reduce their emissions. The Turk power plant should NEVER have been built and 

now Arkansas will justly pay the price. One commenter also stated that the Obama 

Administration should nationalize even more incentives to encourage folks to shift to solar 

panels or wind. States such as Arkansas that penalize and place obstacles to using solar should be 

prohibited from enacting those measures. Thank you for all the work you do and please hold firm 

to these measures. 

One commenter stated that the haze represents filth that not only bothers our eyes, but affects 

plants and all wildlife. The health of humans is very much affected as seen by many diseases of 

heart, lungs, and immune system. Another commenter stated that more than the cynical cost‐

benefit analysis, it is vital to remember that everything we do to nature, we do to ourselves and 

the generations to come. 

Another commenter stated that air pollution also limited their ability to enjoy state parks 

because, as never‐smokers, they are extremely sensitive to particulates. 

Many commenters asked EPA to do the right thing and Keep the environment safe and of good 

quality for the generations to come. Many commenters thanked EPA for working to protect their 

state of Arkansas. Commenters stated that they are grateful for EPA’s efforts to make their parks 

more enjoyable. 

Response: We appreciate the commenter’s support of our FIP. We acknowledge these 

commenters for their support of our proposal. 

We appreciate the commenters’ concerns regarding the adverse health effects of the air 

pollutants that also contribute to visibility impairment and the resulting benefits of the air 

pollution controls we are requiring in our FIP. The emission limitations we are requiring in our 

FIP are intended to reduce visibility impairing pollutants and thereby improve visibility in Class 

I areas. We generally agree that the same emissions that cause visibility impairment can also 

cause health related problems, including adverse effects on breathing, respiratory illness, 

alterations in pulmonary defenses, and aggravation of existing cardiovascular disease. We agree 

that our FIP may result in potential ancillary benefits to human health. 

We also appreciate the comments regarding the negative impacts that visibility impairing 

emissions can have on ecosystems and wildlife. We agree that visibility impairing pollutants can 

have negative impacts on ecosystems and wildlife, and agree that our FIP may result in potential 

ancillary benefits to ecosystem health. 

We also recognize that the reduction of regional haze and the preservation and protection of 

visibility in national parks and wilderness areas as a result of our FIP may potentially have a 

positive impact on tourism and the economy. We agree that our Class I areas and other national 

parks and wilderness areas are a source of jobs and contribute to the economies of their 

respective states. 
8 

With regard to the comment that Arkansas needs to invest in alternative energy and that the 

federal government should nationalize more incentives to encourage a shift to renewable energy 

forms, we note that such comments are outside the scope of this action and outside the scope of 

the regional haze program in general. 

We take no position on any other specific statements made in the comment. 

Comment: (0179) 38 members of the public stated they support the EPAs proposed rule. The 

commenters stated that they were particularly encouraged by EPA’s proposal to crack down on 

emissions from the two large Entergy coal plants that cloud the skies in Missouri at the Hercules‐

Glades Wilderness Area and the Mingo National Wildlife Refuge. Missourians greatly enjoy the 

outdoors for family recreation, camping, hiking, and fishing. It is important that these federal 

lands be protected from air pollution and the commenters encourage EPA to finalize a strong rule 

that greatly reduces emissions from the coal plants in Arkansas. 

One commenter stated that the coal plants in Arkansas also threaten the health in the 240 acre 

wilderness preserve Christian retreat he founded in the late 1970's, 18 miles southwest of 

Branson MO, 1 mile north of Arkansas, (where animal factory manure polluted the creeks out of 

Arkansas since the later 1990's, and antibiotic resistant bacteria/viruses in airborne blown dust 

from the scattered manure currently threaten additionally ‐ see recent PBS Frontline reports: 

"The Trouble With Antibiotics" #11 and "Outbreak at National Institute of Health" both Nov. 18, 

2014 and "Trouble With Chicken" #1 May 13, 2015). 

One commenter stated that Mingo is an important bird stopover for waterfowl, as is nearby Otter 

Slough. These areas need to be protected as they are important bird areas. 

One commenter asked EPA not to punish southwest Missouri for sending Billy Long to 

Congress. The commenter stated there are many people in this region who want to see saner 

energy policies than the ones currently exposed by their politicians. 

Response: We appreciate the commenter’s support of our FIP. We agree that the emission 

limitations in our FIP will result in large reductions in visibility impairing pollutants and will 

improve visibility in Arkansas’ and Missouri’s Class I areas. We take no position on any other 

specific statements made in the comment. 

Comment: (0152) At the public hearing in Little Rock, Arkansas, many people expressed 

general support for the plan. The speakers at the public hearing included members of various 

organizations and members of the general public. 

Response: We appreciate the commenter’s support of our FIP. We acknowledge these 

commenters for their support of our proposal. We thank those who attended and participated at 

our public hearing. 
9 

Comment: (0177) A commenter expressed gratitude for EPA holding the information sessions 

and public hearings regarding EPA’s proposal. The commenter noted that they will be unable to 

attend the public hearings and, thus, will be submitting comments electronically. The commenter 

noted they have read many of the acclaimed accounts (Hunter & Dunbar, Schoolcraft, and 

Nuttall) of early exploration of Arkansas and have been fascinated by the descriptions of the 

environment, flora, fauna, soil, rocks, minerals, and water. The commenter states that the rules 

promulgated in EPA’s proposal will help protect the Buffalo National River, Ouachita National 

Forest, and Caney Creek Wilderness area, which are national and Arkansas treasures. Protecting 

these treasures will provide both economic and health benefits in the short term and, certainly, in 

the long term by enhancing tourism and combatting pollution that is hazardous to human health. 

Response: We appreciate the commenter’s support of our FIP. We generally agree that the same 

emissions that cause visibility impairment can also cause health related problems, including 

adverse effects on breathing, respiratory illness, alterations in pulmonary defenses, and 

aggravation of existing cardiovascular disease. As our FIP will reduce these emissions, we agree 

that our FIP may result in potential ancillary benefits to human health. 

EPA also recognizes that the reduction of regional haze and the preservation and protection of 

visibility in national parks and wilderness areas is expected to have a positive impact on tourism 

and the economy throughout the state, as noted by the commenter. We agree that our Class I 

areas and other national parks and wilderness areas are a source of jobs and contribute to the 

economies of their respective states. 

Comment: (0177) One commenter stated that they are in favor of the EPA’s draft plan to reduce 

haze pollution in Arkansas. Arkansas's outdoor recreation opportunities in our natural areas, 

including our national parks and wildlife areas, are one of our greatest assets. Our outdoors are 

enjoyed by Arkansans and people from all across the country. The quality of these areas must be 

supported. The EPA's plan would reduce haze pollution and increase the visibility in these prized 

areas. Hikers, birders, photographers, and others would benefit from this change. It would allow 

Arkansas's great views to be seen by future generations. I favor the reduction of haze pollution 

for two reasons. First, my greatest hobbies involve the outdoors. I take two vacations every year. 

Both of these trips take me to the Buffalo River. I camp, hike, and canoe. I spend my money in 

Arkansas to spend time in Arkansas. I need my time in this area to be preserved. I hope to take 

my kids to these places. Second, I work for a conservation non-profit and teach environmental 

education programs focused on spending time outdoors. I've built a career around encouraging 

students and their families to responsibly spend time in the outdoors and enjoy activities like 

birding and hiking. I consider it a part of my job description to make sure natural areas are 

supported. 

Response: We appreciate the commenter’s support of our FIP. We take no position on any other 

specific statements made in the comment. 

Comment: (0177) One commenter stated that she is a resident of Little Rock, Arkansas, and is 

writing in support of the Regional Haze Plan. Requiring the White Bluff and Independence 
10 

power plants in our state to reduce pollutants by retrofitting their infrastructure will have 

fundamental impacts on our public health and protected natural areas, and could speed the 

transition to a clean energy economy. 

My work in environmental justice communities has shown me the terrible effects of industrial 

pollutants on the poorest residents of our state, who are disproportionately people of color. The 

waste spewing out of power plants, which includes sulfur dioxide, nitrogen oxides and 

particulate matter, affects these disadvantaged communities the most, but wind patterns also 

ensure that these pollutants are carried across our state. Sometimes we even get air pollution 

from power plants in other states. The effects of this air pollution include difficulty in breathing, 

and the pollutants can cause or worsen respiratory illnesses such as asthma and bronchitis. 

Air pollution also mars the experience of people visiting protected natural areas in our state. 

Arkansas is known as “the Natural State” and benefits tremendously from tourism around our 

incredible mountains, lakes, streams, and other scenic places. Many Arkansans, as well as out-ofstate tourists, visit the areas that this plan would protect: the Buffalo National River, Ouachita 

National Forest and Caney Creek Wilderness Area. The plan would improve air quality and 

visibility in these places, generally having a positive impact on the experiences of their visitors. 

Some communities nearby these attractions rely on the economic boost of visitors enjoying 

nature near their towns. However, if air quality continues to decline, the influx of tourists to 

these areas could be compromised as well. 

Finally, the Regional Haze rule could help move Arkansas in the right direction when it comes to 

our energy future. The retrofit technology that the power plants would have to install would be 

extremely expensive, which could lead to these dirty plants being shut down sooner. In putting 

more restrictions on dirty energy sources and potentially moving up the date of retirement for 

coal plants, the rule could push the state toward more clean, renewable sources such as wind and 

solar. 

Response: We appreciate the commenter’s support of our FIP. We generally agree that the same 

emissions that cause visibility impairment can also cause health related problems, including 

adverse effects on breathing, respiratory illness, alterations in pulmonary defenses, and 

aggravation of existing cardiovascular disease. As our FIP will reduce these emissions, we agree 

that our FIP may result in potential ancillary benefits to human health.

EPA also recognizes that the reduction of regional haze and the preservation and protection of 

visibility in national parks and wilderness areas is expected to have a positive impact on tourism 

and the economy throughout the state, as noted by the commenter. We agree that our Class I 

areas and other national parks and wilderness areas are a source of jobs and contribute to the 

economies of their respective states. 

Under the Regional Haze regulations we are authorized to require affected sources to meet 

BART emission limits for visibility impairing pollutants (i.e., SO2, NOX, and PM), through the 

analysis of potential installation of various control technologies. The intent of the regional haze 

program is not to force affected sources to shut down. However, sources may choose to meet our 
11 

emission limits by voluntarily retiring or switching from coal to other fuel types since BART is 

an emissions limit rather than control requirements. 

We take no position on any other specific statements made in the comment. 

Comment: (0177) One commenter expressed gratitude to the EPA administrators for holding 

this hearing on its Draft Regional Haze Plan for Arkansas. The commenter stated that she is a 

former Vice President of the National Audubon Society and Executive Director of Audubon 

Arkansas. I am also a member of the Sierra Club. I am here today to support the plan as proposed 

by the EPA which targets visibility in areas important to tourism in Arkansas; including the 

Buffalo National River, the crown jewel of our parks, the Caney Creek Wilderness Area and the 

Ouachita National Forest. Improving the air quality of our parks and wilderness areas can be 

accomplished by installing retrofit technology on two of Arkansas’ largest and dirtiest coal fired 

plants, namely White Bluff and Independence. The visibility level in all our parks and recreation 

areas have been reduced by the 30 year unchecked pollution of these dirty, old coal plants. They 

must be retrofitted or shut down. The Plan, when implemented, will address toxic emissions that 

are harmful to humans’ health. These plants have been operating without minimal safeguards for 

over three decades. It is time to act. Who has paid the price for the cheap energy provided by 

these plants? Children, the elderly and all those suffering from bronchitis, asthma and other 

respiratory illnesses, our local communities, families and hospitals have been footing the bill. It 

is high time to stop putting the cost of our “cheap energy” on the most vulnerable members of 

our society and on our environment, especially our irreplaceable national parks and wilderness 

areas. I support implementation of the Regional Haze plan because it will move Arkansas 

towards a cleaner and healthier future as the utilities embrace renewable and truly clean energy 

sources. 

Response: We appreciate the commenter’s support of our FIP. We generally agree that the same 

emissions that cause visibility impairment can also cause health related problems, including 

adverse effects on breathing, respiratory illness, alterations in pulmonary defenses, and 

aggravation of existing cardiovascular disease. As our FIP will reduce these emissions, we agree 

that our FIP may result in potential ancillary benefits to human health. 

We take no position on any other specific statements made in the comment. 

Comment: (0177) One commenter stated that she is a supporter of CLEAN air. We need to 

make sure that industry is reined in and held responsible for pollution. Please make that happen 

for our “Natural State.” 

Response: We appreciate commenter’s support of our FIP. 

Comment: (0177) One commenter stated that he is a native and resident of Little Rock, AR. I'm 

writing to express my support for the Regional Haze and Interstate Visibility Transport Federal 

Implementation Plan. The Regional Haze plan will benefit our state's economy, health, and 
12 

natural environment. Reducing the amount of haze in the Buffalo River area will make the area 

more attractive to visitors and ultimately, boost tourism revenue. What's more, the Ozarks and 

Buffalo River are natural treasures of the Natural State. These areas should be preserved to 

benefit local residents, visitors, and future generations. In addition, the Regional Haze plan will 

prevent people in the region from being exposed to harmful pollutants. This plan will reduce the 

risk of asthma and other health concerns in the Ozarks and surrounding areas. Additionally, the 

plan will protect natural ecosystems in the region and reduce the effect of pollution on fragile 

plants, animals, and other living organisms. 

Response: We appreciate the commenter’s support of our FIP. We generally agree that the same 

emissions that cause visibility impairment can also cause health related problems, including 

adverse effects on breathing, respiratory illness, alterations in pulmonary defenses, and 

aggravation of existing cardiovascular disease. As our FIP will reduce these emissions, we agree 

that our FIP may result in potential ancillary benefits to human health. 

We appreciate the comment regarding the negative ecosystem impacts of visibility impairing 

emissions. We agree that visibility impairing pollutants can have negative impacts on 

ecosystems. As our FIP will reduce these emissions, we agree that our FIP may result in potential 

ancillary benefits related to ecosystem health. 

EPA also recognizes that the protection of visibility in national parks and wilderness areas is 

expected to have a positive impact on tourism and the economy, as noted by the commenter. We 

agree that our Class I areas and other national parks and wilderness areas are a source of jobs and 

contribute to the economies of their respective states. 

We take no position on any other specific statements made in the comment. 

Comment: (0177) One commenter stated that she believes that Arkansas companies and 

agencies should be forced to clean up two of the largest and dirtiest coal-fired power plants: 

Entergy’s White Bluff and Independence plants. The resistance to change our dirty energy 

policies is so entrenched that it will take a serious effort to slow down the current business as 

usual mode of operation. As a consumer I am ready to pay more for power. I realize that all 

Arkansans may not welcome an increase in energy costs but I do believe that all Arkansans want 

clean air and a healthy environment. Perhaps a way can be found to help out those poor people 

who cannot afford an increase in costs to pay for their power. Perhaps we should move to a state 

run energy system. Costs of clean-up of these coal plants can and should be borne by the 

companies who created the problem in the first place and who have made significant profit by 

pursuing their dirty coal policies. Climate change is, undeniably, a real threat for the world as we 

know it. While I am not a scientist, I do understand the implications of continuing to ignore the 

ominous signs that we are radically changing the climate of the Earth by continuing to use fossil 

fuels, and especially coal, for energy production. The costs of doing nothing about our reliance 

on fossil fuels will be staggering and a threat to the future of humanity. We need to act NOW, 

and not when these companies run out of coal! My husband and I frequently travel in the West 

and the haze in the national parks is unbelievable. California’s central valley is unbelievably 

polluted with the air visible and shockingly a yellow-grey smog. It is astonishing to see. Pine 
13 

bark beetles have devastated the national forests. Alaska had its warmest winter ever. The ice 

caps are melting. Arkansas is part of the problem and needs to stop relying on fossil fuel for 

energy. What are we waiting for? I urge you to turn the page on energy policy by supporting 

clean and renewable forms of energy such as wind and solar. I urge you to close all of the coal 

fired plants in the country. Please, please do something about this serious issue. 

Response: We appreciate commenter’s support of our FIP. The purpose of the Regional Haze 

program is to protect and improve visibility in mandatory Class I Federal Areas. The air 

pollution control measures we are requiring in our FIP are intended to control emissions of 

visibility impairing pollutants (i.e., SO2, NOX, and PM) and intended to improve visibility 

conditions in Class I areas. As our FIP will reduce these emissions, we agree that our FIP may 

result in potential ancillary benefits related to reduction of greenhouse gases such as carbon 

dioxide and nitrous oxide that contribute to climate change. 

Under the Regional Haze regulations we are authorized to require affected sources to meet 

emission limits for visibility impairing pollutants (i.e., SO2, NOX, and PM), but we are not 

authorized to dictate what type of technology the source must employ to meet those emission 

limits and we are not authorized to force sources to retire or to stop burning fossil fuels. We also 

are not authorized to require a shift to renewable forms of energy. However, sources may choose 

to meet our emission limits by voluntarily retiring or switching fuels. 

We recognize that it is an unfortunate consequence that the requirement of controls to reduce 

emissions from power plants often results in electric companies passing on the costs of these 

controls to ratepayers in the form of increased electricity rates. We are not authorized to prevent 

companies from doing so. However, we are very sensitive to the ramifications of our actions and 

we seek to select the most cost-effective options when we propose and finalize these controls. 

We appreciate the comment regarding the negative ecosystem impacts of visibility impairing 

emissions. We agree that visibility impairing pollutants can have negative impacts on 

ecosystems. As our FIP will reduce these emissions, we agree that our FIP may result in potential 

ancillary benefits related to ecosystem health. 

We take no position on any other specific statements made in the comment. 

Comment: (0177) One commenter stated that she supports the use of EPA authority under the 

Clean Air Act to reduce carbon emissions and commends the Agency on drafting a plan to clean 

up haze and visibility problems in some of Arkansas's most treasured natural areas such as the 

Ozark National Forest, the Buffalo National River corridor and its associated, federally 

designated wilderness, the Ouachita, Caney Creek Wilderness and similar areas in Missouri. The 

best solution for our worst air polluting coal-fired power plants, is to retire them and implement 

clean, renewable and sustainable sources of energy. Arkansas can enjoy better health, robust 

economic growth and the beauty of our state and national parks and other natural environments. 
14 

I support EPA’s Option 1 that will reduce emissions of both SO2 and NOX. This is the least we 

can do until all coal-fired power plants are retired. Until they are phased out, they should be 

required to retrofit with state of the art scrubbers to remove all air pollutants possible. 

Reasons to support Option 1: Regional Haze pollution affects visibility in some of our most 

scenic Arkansas areas. Many Arkansans, as well as out-of-state tourists, visit the areas that the 

draft Regional Haze plan would protect: the Buffalo National River, Ouachita National Forest 

and Caney Creek Wilderness Area. The plan would improve air quality and visibility in these 

places, generally having a positive impact on the experiences of their visitors. 

Our parks and wilderness areas boost the economies of the communities in which they’re 

located, attracting tourists and elevating business. However, if air quality continues to decline, 

the influx of tourists to these areas could be compromised as well. The EPA’s draft Regional 

Haze plan would require some of Arkansas’s dirtiest power plants to install retrofit technology in 

order to reduce pollutants. The power plants affected include Arkansas’s two largest and dirtiest 

coal‐fired power plants, Entergy's 1700MW White Bluff and Independence plants. 

Coal‐fired power plants emit horrendous amounts of pollution that are hazardous to human 

health. These pollutants include sulfur dioxide, nitrogen oxides and particulate matter, which can 

lead to difficulty in breathing, and cause or worsen respiratory illnesses such as asthma and 

bronchitis. These health hazards are particularly dangerous to children, the elderly, and those 

who already have respiratory problems. 

The draft Regional Haze plan could help move Arkansas in the right direction when it comes to 

our energy future. In putting more restrictions on dirty energy sources and potentially moving up 

the date of retirement for coal plants, the rule could push the state toward more clean, renewable 

sources such as wind and solar. 

Response: We appreciate commenter’s support of our FIP, including our proposed Option 1. For 

the reasons discussed elsewhere in this document, we are requiring SO2 and NOX controls for 

Independence in our final FIP. The air pollution control measures we are requiring in our FIP are 

intended to control emissions of visibility impairing pollutants (i.e., SO2, NOX, and PM) and 

improve visibility conditions in Class I areas Under the regional haze regulations, we are 

authorized to require affected sources to meet emission limits for visibility impairing pollutants 

(i.e., SO2, NOX, and PM), but we are not authorized to dictate what type of technology the source 

must employ to meet those emission limits and we are not authorized to force sources to retire or 

to stop burning fossil fuels. Under the regional haze program, we are also not authorized to 

implement or force a shift to renewable forms of energy. However, sources may choose to meet 

our emission limits by voluntarily retiring or switching fuels. 

We generally agree that the same emissions that cause visibility impairment can also cause 

health related problems, including adverse effects on breathing, respiratory illness, alterations in 

pulmonary defenses, and aggravation of existing cardiovascular disease. As our FIP will reduce 

these emissions, we agree that our FIP may result in potential ancillary benefits to human health. 
15 

EPA also recognizes that the protection of visibility in national parks and wilderness areas is 

expected to have a positive impact on tourism and the economy, as noted by the commenter. We 

agree that our Class I areas and other national parks and wilderness areas are a source of jobs and 

contribute to the economies of their respective states, but note that for purposes of this Regional 

Haze action. 

We take no position on any other specific statements made in the comment. 

Comment: (0177) One commenter asked EPA to please pass all legislation needed to clean up 

Entergy’s White Bluff and Independence coal plants. The residents of Arkansas are very proud 

of the quality of our waters and air. We have made great strides in keeping our state clean. 

Indeed, Little Rock was recently named the 2nd cleanest city in the United States. Please allow 

the concerned residents of this beautiful state to continue to praise the clean water, air and cities 

in our state by making Entergy do the right thing and clean up their dirty, polluting power plants 

that are harming our residents and our state reputation. 

Response: We appreciate commenter’s support of our FIP.

Comment: (0177) One commenter stated that she has lived in Swain in Newton County 

Arkansas for the past 40 years, and has increasingly seen the haze increase over this area to 

where it is very rare to see clearly from Highway Seven above Jasper. Tourism is extremely 

important to Newton's county's economy, and the increased haze caused by pollution from 

Arkansas dirty power plants is detrimental to those who come to experience the county's 

magnificent natural areas, and a health hazard for we who live in this scenic area. The draft 

Regional Haze plan under consideration could help move Arkansas energy future in the right 

direction. However, retrofitting the plants and allowing them to continue operation is not a sound 

solution. The plan needs to more restriction on solar and wind sources and potentially move up 

retirement dates for coal plants. 

Response: We appreciate commenter’s support of our FIP. We agree that reducing regional 

haze will help ensure that views in these parks and wilderness areas are preserved. Based on the 

context of the comment, it appears that the commenter intended to state that our plan needs to 

have more emphasis (rather than “more restriction”) on solar and wind sources. Under the 

Regional Haze regulations, we are authorized to require affected sources to meet emission limits 

for visibility impairing pollutants, but we are not authorized to dictate what type of technology 

the source must employ to meet those emission limits and we are not authorized to force sources 

to retire. However, sources may choose to voluntarily retire or switch fuels to meet our emission 

limits. We take no position on any other specific statement made in the comment. 

Comment: (0177) One commenter stated that she lives on the Little Buffalo River. Living here 

on the river I spend most of my time outdoors. She is in support of cleaner air for Arkansas and 

am hoping you will find enough support to implement a plan to help clean up the atmosphere. 
16 

There is nothing more disheartening to begin a beautiful sunny day outside and within a short 

time be driven inside by noxious odors whether they be from a hog concentrated animal feeding 

operation (cafo), a chicken house, smoke, coal dust, crop fumigation, etc. It has happened on 

many occasions and it is sad to think that Arkansas has the education and technology but as a 

state Arkansas does not use it. It is time to crack the whip, spend the money and make Arkansas 

stop polluting not only our own citizens’ livelihood but all others who may visit or live in areas 

that the winds travel. 

Response: We appreciate commenter’s support of our FIP. We take no position on any other 

specific statements made in the comment. 

Comment: (0177) One commenter stated that as a Republican, she stands for a strong 

America...the greatest nation on Earth. That is why the commenter is very concerned about 

pollution from coal powered plants in Arkansas. America is already falling behind so many other 

countries in the areas of literacy, socioeconomic status, security for families and yes, clean air 

and water. Even China, so massive and backward is moving toward clean power. It's a sad day 

when a Communist country is addressing its quality of life issues better than we do. The 

commenter urges EPA to support reduction of pollution from coal powered plants in Arkansas. 

Response: We appreciate commenter’s support of our FIP. We take no position on any other 

specific statement made in the comment. 

Comment: (0177) One commenter expressed support for the EPA plan to clean up haze in the 

northwest Arkansas region of the state. The commenter stated that it is past time to clean up our 

power-generating plants and to switch from burning coal to other technologies that are not 

polluting and that are sustainable. We cannot continue to pollute our planet without paying the 

consequences. As a doctor I am concerned about the health consequences of air pollution. I am 

willing to pay more for energy but I do not think that this argument put forth by the coops is 

valid. We are paying much more than we realize by continuing to burn coal. The cost is only 

being measured in terms of producing energy. The energy coops are not including the costs to 

society of the pollution that is generated by it. These include the health costs, lost productivity, 

lost tourism revenues, global warming and the weather consequences, the costs of polluting the 

ground and rivers, etc. Change is difficult but it is inevitable. The coal-fired generating plant is a 

thing of the past, a relic of an age when we didn’t know any better. 

Response: We appreciate commenter’s support of our FIP. We generally agree that the visibility 

impairing pollutants our FIP will control also have adverse health impacts and may negatively 

affect tourism revenue. As our FIP will reduce these emissions, we agree that our FIP may result 

in potential ancillary benefits to human health. We also agree that our FIP may result in potential 

ancillary benefits in terms of reducing emissions of greenhouse gases such as carbon dioxide and 

nitrous oxide. 

While our FIP will control emissions from certain coal fired power plants in the state, the intent 

of our FIP (and the regional haze program in general) is not to force these power plants to cease 
17 

coal combustion. Under the Regional Haze regulations we are authorized to require affected 

sources to meet emission limits for visibility impairing pollutants, but we are not authorized to 

dictate what type of technology the source must employ to meet those emission limits and we are 

not authorized to force sources to cease coal combustion. However, sources may choose to 

voluntarily retire or switch from coal to other fuels to meet our emission limits. We take no 

position on any other specific statement made in the comment. 

Comment: (0177) One commenter stated she supports bringing Arkansas into compliance. 

Living in Newton County, Arkansas I have some of the best of Arkansas' scenic and recreational 

lands easily available for personal use. The Buffalo National River, Koen National Forest, 

Arkansas Game and Fish and the Ozark National Forest properties surround the privately owned 

lands of all residents here. I was so excited to find property down on the creek and within 2 years 

of living here realized how troubling living on a creek can be. Winters can be cloudy and cold, 

then spring begins and a person is ready to enjoy the fresh spring breezes and feel warm 

sunshine. I didn't realize that living down in the valley smoke from prescribed burns would cloud 

the sky and the sun would be shrouded for weeks. The smoke would cause headaches and sore 

throats and I'd have to shut the windows & doors to try and escape when I was ready to be 

enjoying the spring and gardening. The black soot that coats the log house and windows some 

years is thicker than others. 

In the year 2012, the Arkansas Department of Environmental Quality very quickly permitted a 

6,500 hog factory on one of the largest tributaries to the Buffalo National River. ADEQ director, 

Teresa Marks, stated hog waste was expected to reach the Buffalo National River. The Buffalo 

National River has the highest protection in the state under the Clean Water, anti-degradation 

Act. Hog waste is spread by the millions of gallons from January – November each year. The 

smell, the haze, manure spreading and run-off of this operation is allowed with no consideration 

of the community, the Mt Judea School, its children, teachers, and visitors. The school is less 

than 1/2 air-mile from the hog factory, where the state expects students to concentrate in an 

environment it has permitted with no consideration. Last week while at the Carver recreation site 

on the Buffalo River the smell of hogs was strong and annoying. This is not caused by a feral 

hog running wildly thru the countryside, this is caused by thousands of hogs confined in 2 

buildings with open pit lagoons and the constant evaporation of the waste into the air then 

drifting and settling outside of the hog factory. These are only 2 examples of the state's on-going 

haze issues. The smell and thickening of air from a hog factory and smoke engulfing the valleys 

when I wish to enjoy time on the creeks, my garden or outdoor recreation. 

An old saying in Arkansas is “If you don't like the weather, wait a few minutes and it will 

change.” Weather here can go from 70 to 20 in a couple of hours. 20 degree changes are frequent 

and with that inversions trap air in the steep valleys and along the waterways. 

The state of Arkansas has had ample time to comply with EPA rulings. The state continues to 

subject its residents to unhealthy environments and needs direction and enforcement. Help our 

state come into compliance and enforce positive goals instead of continuing to subject its 

residents to capitalistic enterprises which endanger and reduce the health environments of those 

that live within its borders. 
18 

Response: We appreciate commenter’s support of our FIP. We take no position on any other 

specific statement made in the comment. 

Comment: Multiple public hearing commenters (0152-5, 0152-7, 0152-8, 0152-12, 0152-13, 

0152-16, 0152-17, 0152-18, 0152-19, 0152-20, 0152-21, 0152-22, 0152-23, 0152-24, 0152-25, 

0152-27, 0152-29, 0152-31, 0152-40, 0152-43, 0152-44) noted that the visibility impairing 

pollutants that would be reduced by our FIP also have adverse health impacts and that our FIP 

would have potential ancillary health benefits.

Response: We appreciate the commenters’ concerns regarding the adverse health effects of the 

air pollutants that also contribute to visibility impairment and the resulting benefits of the air 

pollution controls we are requiring in our FIP. The emission limitations we are requiring in our 

FIP are intended to reduce visibility impairing pollutants and thereby improve visibility in Class 

I areas. We generally agree that the same emissions that cause visibility impairment can also 

cause health related problems, including adverse effects on breathing, respiratory illness, 

alterations in pulmonary defenses, and aggravation of existing cardiovascular disease. We agree 

that our FIP may result in potential ancillary benefits to human health. 

Comment: Multiple public hearing commenters (0152-2, 0152-7, 0152-9, 0152-12, 0152-16, 

0152-22, 0152-32, 0152-43) who expressed general support for our FIP proposal noted that our 

FIP would require controls on the two largest coal plants in Arkansas, and some of these 

commenters also noted that these plants do not currently have air pollution controls. These 

commenters were in favor of controls on these two plants 

Response: We appreciate the commenters’ support of our FIP. We agree that our FIP will 

control SO2 and NOX emissions from the two largest point sources in Arkansas, the White Bluff 

and Independence Power Plants. 

Comment: Multiple public hearing commenters (0152-8, 0152-9, 0152-12, 0152-16, 0152-19, 

0152-25, 0152-30, 0152-37, 0152-38, 0152-40, 0152-41, 0152-42, 0152-43, 0152-45, 0152-46, 

0152-47) noted that they enjoy the outdoors and enjoy spending time at Arkansas’ Class I areas 

and are therefore in support of our FIP. 

Response: We appreciate the commenters’ support of our FIP. 

Comment: Some public hearing commenters (0152-8, 0152-13) specifically expressed support 

for requiring controls on the Independence plant in our FIP. 

Response: We appreciate the commenters’ support of our FIP. In our FIP we are requiring both 

SO2 and NOX controls on the Independence plant. 
19 

Comment: Multiple public hearing commenters (0152-9, 0152-11, 0152-12, 0152-16, 0152-21, 

0152-25, 0152-28, 0152-31, 0152-34, 0152-35, 0152-36, 0152-37, 0152-39, 0152-40) expressed 

general support for our FIP, but commented that we also need to move away from coal and 

towards clean, renewable energy. Some of these commenters also indicated that we should work 

towards retiring/shutting down coal plants. 

Response: We appreciate the commenters’ support of our FIP. Under the Regional Haze 

regulations, we are authorized to require affected sources to meet BART emission limits for 

visibility impairing pollutants (i.e., SO2, NOX, and PM), through the analysis of potential 

installation of various control technologies. The intent of the regional haze program is not to 

force affected sources to shut down, nor are we authorized to force them to shut down. However, 

sources may choose to meet our emission limits by voluntarily retiring or switching from coal to 

other fuel types, since BART is an emissions limit rather than control requirements. We also are 

not authorized under the CAA provisions for regional haze to require a shift to renewable forms 

of energy. 

Comment: Some public hearing commenters (0152-12, 0152-24) noted that visibility impairing 

pollutants have adverse impacts on ecosystems and that our FIP would provide ancillary benefits 

in terms of reduced adverse impacts to ecosystems. 

Response: We agree that visibility impairing pollutants can have negative impacts on 

ecosystems and wildlife, and agree that our FIP may result in potential ancillary benefits to 

ecosystem health. 

Comment: Some public hearing commenters (0152-16, 0152-20, 0152-47) noted that by 

reducing visibility impairing pollutants and improving visibility in Arkansas’ Class I areas, our 

FIP would have a positive effect on tourism and the economy. 

Response: We agree that the reduction of regional haze and the preservation and protection of 

visibility in national parks and wilderness areas as a result of our FIP may potentially have a 

positive impact on tourism and the economy. We agree that our Class I areas and other national 

parks and wilderness areas are a source of jobs and contribute to the economies of their 

respective states. 

Comment: Multiple public hearing commenters (0152-17, 0152-19, 0152-21, 0152-22, 0152-

30) generally supported our FIP proposal, noting that the benefits of the controls would outweigh 

the visibility benefits and the ancillary benefits. 

Response: We appreciate the commenters’ support of our FIP. 

Comment: One commenter asked how is it fair to require these coal plants to spend billions of 

dollars to make upgrades while China and other countries are not held to the same standards. If 
20 

the problem is truly as bad as EPA says, why are they given additional time to meet 

requirements? Americans are struggling as it is and a higher electric bill could mean no 

electricity for some people. 

Response: We acknowledge the commenter’s concerns. Consistent with the CAA, the regional 

haze program is concerned with remedying existing and preventing future impairment of 

visibility caused by manmade air pollution in mandatory Class I Federal areas (located in this 

country). Our action requires particular Arkansas sources to control emissions that impact 

visibility at Arkansas and Missouri Class I areas. Our action does not in any way expect 

Arkansas to make up for emissions from international sources. On the other hand, as we 

discussed in the preamble to the Regional Haze Rule, “the States should not consider the 

presence of emissions from foreign sources as a reason not to strive to ensure reasonable 

progress in reducing any visibility impairment caused by sources located within their 

jurisdiction.”1

 While the goal of the regional haze program is to restore natural visibility 

conditions at Class I areas by 2064, the rule requires only that reasonable progress be made 

towards the goal during each planning period. In cases where it is not reasonable to meet the rate 

of progress needed to attain the goal by 2064, the Regional Haze Rule requires a state to 

demonstrate that this rate of progress is not reasonable, and that the state’s selected rate of 

progress is reasonable for that planning period. While there is no indication at this time that 

emissions from international sources are anticipated to prevent Arkansas from attaining the goal 

of natural visibility conditions at its Class I areas, we recognize that in some cases it may not be 

possible to attain the goal by 2064 because of impacts from new or persistent international 

emissions sources or impacts from sources where reasonable controls are not available. 

However, states are still required to demonstrate that they are establishing a reasonable rate of 

progress that includes implementation of reasonable measures within the state to address 

visibility impairment in an effort to make progress towards the natural visibility goal during each 

planning period. We acknowledge the commenter’s concern regarding potential increases in 

electricity rates. While our consideration of cost under the Regional Haze Rule is limited to the 

direct costs incurred by sources, consistent with the CAA’s and Rule’s source-specific focus, we 

are very sensitive to the ramifications of our actions and we seek to select the most cost-effective 

options when we propose and finalize these controls. 

Comment: One public hearing commenter expressed concern for the high cost of the controls in 

our proposed FIP, noting that Arkansas’ ratepayers would ultimately pay the cost in the form of 

electric rate increases. The commenter noted that the FIP is a visibility requirement, not a healthbased requirement. The commenter also noted stated that the FIP is resulting from a lawsuit and 

expressed concern that there are some procedural issues in the lawsuit that have not been 

litigated. 

Response: As noted in our response to the previous comment, we acknowledge the concern 

regarding potential increases in electricity rates. While our consideration of cost under the 

Regional Haze Rule is limited to the direct costs incurred by sources, consistent with the CAA’s 

and Rule’s source-specific focus, we are very sensitive to the ramifications of our actions and we 

seek to select the most cost-effective options when we propose and finalize these controls. We 

 

1

 64 FR 35755 (July 1, 1999). 
21 

agree that the regional haze program is concerned with visibility, and that it is not a health based 

requirement. With regard to the comment that our FIP is resulting from a lawsuit, we explain in 

greater detail elsewhere in this document that under the Clean Air Act requirements, under the 

Clean Air Act, we have an obligation to approve a SIP revision from the State and/or promulgate 

a FIP within two years of our partial disapproval of the SIP submitted by Arkansas in 2008 to 

remedy the disapproved portions of the SIP. Two years elapsed and EPA was sued for failing to 

either approve a SIP or issue a FIP to address the elements we disapproved on the submitted 

2008 Arkansas regional haze SIP. With Arkansas as a party, a district court judge ordered EPA 

to either approve a revised SIP submittal from Arkansas or finalize a FIP for the elements we 

disapproved by August 31, 2016. It is unclear what procedural issues in the lawsuit the 

commenter is referring to, but we note that such comment is outside the scope of our proposed 

action. 

Comment: Some public hearing commenters [0152-1, 0152-15] were against our FIP, and 

expressed concern over the high costs required to comply with the FIP. The commenters also 

noted that it is their understanding that the FIP underestimates the cost of controls and that it 

does not allow for costs during construction. One commenter noted that these costs are real 

world and will have to be passed on to ratepayers. 

Response: We appreciate the comments. We note that the issues raised by the commenters are 

discussed in great detail in the section of this document where we discuss cost issues. 

Comment: ADEQ agrees with EPA’s determination that the Georgia Pacific Crossett Mill 

6A and 9A Power Boilers are not subject-to-BART. [ADEQ (0144) p. 4] ADEQ stated that 

chapter III.A.1 of the Proposed FIP contains an analysis of whether BART controls will be 

required at the Georgia Pacific Crossett Mill 6A and 9A Power Boilers.2

 In the Arkansas 

Regional Haze Approval/Disapproval, EPA disagreed with ADEQ’s assertion that the 6A Power 

Boiler was not BART-eligible and proposed to find that it is BART-eligible.3

In the Proposed FIP, EPA conducts a further analysis of these boilers and determines that, 

whether BART-eligible or not, neither boiler has visibility impacts sufficient to be considered 

subject-to-BART.4

 ADEQ concurs that neither of these boilers should be subject-to-BART. 

Response: We appreciate ADEQ’s support of our proposal. We are finalizing our determination 

that the Georgia Pacific Crossett Mill 6A and 9A Power Boilers are not subject-to-BART. 

Comment: [Arkansas Audubon Society (0151) p. 1] The Arkansas Audubon Society stated that 

it is a statewide organization committed to fostering a greater knowledge of the natural history of 

Arkansas and promoting conservation of natural resources in Arkansas. We would like to voice 

our support of the EPA’s proposed rule Promulgation of Air Quality Implementation Plans; State 

 

2

 80 FR 18944 at 18947. 

3

 77 FR 14604 at 14605. 

4

 80 FR 18944 at 18948. 
22 

of Arkansas; Regional Haze and Interstate Visibility Transport Federal Implementation Plan 

(Docket No. EPA-R06-OAR-2015-0189). 

Arkansas is known as the Natural State, and as such, we take pride in the quality of our 

landscapes especially as it pertains to their ecological integrity and our ability as citizens to enjoy 

these areas. The aforementioned rule would enact regulations to protect the air quality of some of 

our most precious natural areas including the Buffalo National River, Caney Creek Wilderness, 

and Ouachita National Forest. We believe that Option 1, which includes the control of both SO2

and NOx emissions, is the best way forward to reduce haze as well as potentially improve the 

health of Arkansans who live in the affected areas. 

We applaud your move to enforce stricter regulations on emissions in order to reduce their 

negative impacts in our atmosphere. Thank you for considering our comments on this important 

matter. 

Response: We appreciate the commenter’s support regarding our FIP, including support of our 

proposed Option 1. For the reasons discussed in other sections of this document, we are 

finalizing both SO2 and NOX controls for Independence in our final FIP. 

Comment: [Arkansas Public Policy Panel (0154) p. 1-2] The Arkansas Public Policy Panel 

(APPP) stated that it is a statewide organization dedicated to achieving social, economic and 

environmental justice by organizing citizen groups around the state, educating and supporting 

them to be more effective and powerful, and linking them with one another in coalition and 

networks. The Panel seeks to bring balance to the public policy process in Arkansas. 

The APPP supports EPA’s proposed Federal Implementation Plan and favors the proposed 

Option 1 over the proposed Option 2. The draft plan would assist in protecting two of Arkansas’ 

treasured areas, the Caney Creek Wilderness Area and the Upper Buffalo Wilderness Area. The 

proposal to control SO2, NOX, and PM BART for nine units at six facilities in Arkansas will 

clean up haze problems in these unique areas and help uphold our state motto of “The Natural 

State.” 

These Wilderness Areas draw in many visitors both local and out-of-state who contribute 

significantly to Arkansas’ economy. In 2012 tourism in Arkansas accounted for a $5.76 billion 

positive economic impact and employed 58,452 people.5

 The Buffalo River attracted 1,093,083 

visitors who spend $43.78 million in communities surrounding the river.6

 Direct spending from 

visitors to the Buffalo employed 610 people in 2012.7 Arkansans pride themselves on the quality 

of our natural resources and the great outdoors are entrenched in our culture. Preserving the 

 

5

 Arkansas Department of Parks and Tourism Annual Report 2013. 

http://www.arkansas.com/!userfiles/editor/docs/apt--‐2013--‐annual--‐report.pdf 6

 2012 National Park Visitor Spending Effects. National Park Service, U.S. Department of the Interior. Natural 

Resource Report NPS/NRSS/EQD/NRR--‐2014/765. 

http://www.nature.nps.gov/socialscience/docs/NPSVSE2012_final_nrss.pdf 7 Id.
23 

natural visibility and air quality of these areas is detrimental to protecting Arkansas’ economy, 

culture and values. 

The APPP supports a transition away from coal-fired power and does not find that retrofitting the 

plants and allowing them to continue operating is a sound solution, especially if those costs are 

passed on to the ratepayer. However, the draft Regional Haze plan does signal progress in 

Arkansas to push the state towards cleaner and healthier energy sources. 

Response: We appreciate the commenter’s general support of our FIP and the commenter’s 

preference of our proposed Option 1. For the reasons discussed elsewhere in this document, we 

are finalizing both SO2 and NOX controls for Independence in our final FIP. Based on the context 

of the comments, it appears that the commenter intended to state that preserving the natural 

visibility and air quality of these areas is “important” or “vital” to protecting Arkansas’ 

economy, culture, and values, not “detrimental.” We recognize the positive impact that 

protecting visibility and air quality in national parks and wilderness areas is expected to have on 

the economy, culture, values, and tourism throughout the state. We agree with the commenter 

that reducing regional haze will help ensure that views in these parks and wilderness areas are 

preserved, and is expected to potentially have a positive impact on tourism and the economy. 

Under the regional haze regulations we are authorized to require affected sources to meet BART 

emission limits for visibility impairing pollutants (i.e., SO2, NOX, and PM), but we are not 

authorized to dictate what type of technology the source must employ to meet those emission 

limits and we are not authorized to force sources to retire or to stop burning coal. However, 

sources may choose to voluntarily retire or switch fuels in order to comply with our emission 

limits. Additionally, we recognize that it is an unfortunate consequence that the requirement of 

controls to reduce emissions from power plants often results in electric companies passing on the 

costs of these controls to ratepayers in the form of increased electricity rates. However, we do 

not have the authority to prevent companies from doing this. 

We take no position on any other specific statements made in the comment. 

Comment: [Entergy Arkansas Inc. (0166) p. 56] Entergy stated it agrees with EPA’s proposal 

that the existing emission limits at the White Bluff Auxiliary Boiler satisfy BART for SO2, NOX, 

and PM. 80 Fed. Reg. at 18,975. Entergy also agrees that 2009-2011 should be used as the 

baseline period for NOX for White Bluff Units 1 and 2. 80 Fed. Reg. at 18,969. 

Response: We appreciate the commenter’s support of our proposal. 

Comment: [Entergy Arkansas Inc. (0166) p.56] Entergy Arkansas Inc. stated it agrees with 

EPA’s conclusion that wet scrubbers do not constitute BART for White Bluff and should not be 

installed at Independence to meet reasonable progress requirements. 80 Fed. Reg. at 18,972, 

18,993. Entergy also agrees with EPA that LNB/SOFA/SNCR or LNB/SOFA/SCR cannot be 

justified as BART for White Bluff based on the incremental cost effectiveness of the controls. 80 

Fed. Reg. at 18,974. 
24 

Response: We appreciate the commenter’s support of our proposal.

Comment: [Entergy Arkansas Inc. (0166) p.56] Entergy Arkansas Inc. stated that if EPA 

finalizes a source-specific NOX BART limit for Lake Catherine Unit 4, Entergy requests that 

EPA confirm that the unit may continue to conduct monitoring pursuant to 40 C.F.R. Part 75 

Appendix E so long as it qualifies as a peaking unit. In the Proposal, EPA appears to have 

assumed that Unit 4 currently operates “full” NOX CEMS with a continuous NOX analyzer 

pursuant to 40 C.F.R. Part 60. However, because Unit 4 meets the definition of a peaking unit 

under 40 C.F.R. Part 75, and the unit is not subject to any NSPS Part 60 standards, Entergy does 

not currently operate a NOX analyzer for the unit. Under Part 75, Unit 4 qualifies as an Appendix 

E unit, allowing the unit to utilize a NOX correlation curve to estimate emissions and only 

monitor heat input and exhaust O2 concentration. 

Response: We are finalizing the NOX BART limit we proposed for Lake Catherine Unit 4. After 

carefully considering this comment, we have determined that it is appropriate to allow the unit to 

continue to conduct monitoring pursuant to 40 C.F.R. Part 75 Appendix E so long as it qualifies 

as a peaking unit under the Part 75 regulations. As such, the unit may continue to utilize a NOX

correlation curve to estimate NOX emissions and only monitor heat input and exhaust O2

concentration. We are revising our proposed section 52.173(c) to reflect this. 

Comment: [Nucor Steel-Arkansas and Nucor-Yamato Steel Company (0163) p. 1-2] Nucor 

stated that it operates electric arc furnace steel mills in Mississippi County, Arkansas, which 

produce steel products from recycled scrap metal. As a result of mills such as NSA and NYS, 

Nucor Corporation is one of the largest recyclers in the nation. The cost of electric power is a 

significant component of the cost of producing steel in an electric arc furnace and the costs of the 

control technologies required under the Proposed FIP will injure NSA and NYS by increasing 

the cost of electric power needed to operate their facilities. 

NSA and NYS both receive electrical service from Mississippi County Electric Cooperative 

Corporation ("MCECC"), which is a member co-operative of Arkansas Electric Cooperative 

Corporation ("AECC"). AECC is either an owner or co-owner of four facilities that are subject to 

Best Available Retrofit Technology (BART) determinations under EPA's Proposed FIP: 

Entergy's White Bluff power plant (White Bluff), SWEPCO's Flint Creek power plant (Flint 

Creek), AECC's Bailey power plant (Bailey), and AECC's McClellan power plant (McClellan). 

AECC also is a co-owner of Entergy's Independence power plant ("Independence"), for which 

EPA is proposing additional emission limits and controls under the Proposed FIP. These five 

facilities provide a large majority of the baseload generating capacity for AECC and its member 

cooperatives. NSA and NYS's electric power primarily comes from AECC's electric generating 

resources, and NSA and NYS's electricity costs are dependent on AECC's costs of maintaining 

and operating those generating resources, including AECC's interest in White Bluff, 

Independence, and Flint Creek. 

Response: We acknowledge the background information provided by the commenter. We 

address specific comments made by the commenter elsewhere in this document.
25 

Comment: [Nucor Steel-Arkansas and Nucor-Yamato Steel Company (0163) p. 6-9] Nucor 

stated that Congress first adopted regional haze provisions in 1977 to establish a national goal 

that would address haze issues in national parks and other federal “Class I areas” by adding 

Section 169A to the Clean Air Act. See, 42 U.S.C. § 7491. EPA has established three primary 

components for a state's regional haze SIP: (1) reasonable progress goals for Class I areas in the 

state; (2) a long-term strategy; and (3) implementation of BART for certain stationary sources. 

The Clean Air Act requires states to submit SIPs that contain “emission limits, schedules of 

compliance and other measures as may be necessary to make reasonable progress toward 

meeting the national goal.” 42 U.S.C. § 7491(b)(2). The reasonable progress goal “is a goal and 

not a mandatory standard which must be achieved by a particular date.” 64 Fed. Reg. 35,714, 

35,733 (July 1, 1999). Further, States have considerable discretion in establishing reasonable 

progress goals; for instance, the Clean Air Act “requires only that a state establish reasonable 

progress, not the most reasonable progress.” North Dakota v. EPA, 730 F.3d 750, 768 (8th Cir. 

2013). 

States are required to consider four statutory factors when establishing reasonable progress goals 

that are “necessary” for Class I areas. 42 U.S.C. §7491(g)(1); 40 C.F.R. § 51.308(d)(1)(i)(A). 

These factors are: (1) costs of compliance; (2) the time necessary for compliance; (3) the energy 

and nonair quality environmental impacts of compliance; and (4) the remaining useful life of any 

potentially affected sources. 42 U.S.C. § 7491(g)(1). Furthermore, reasonable progress goals are 

“interim goals that represent incremental visibility improvement over time.” See, USEPA, 

“Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program,” June 1, 

2007, section 1.2, p. 1-2. The “first planning period” for the Arkansas Regional Haze Rule SIP 

extends from 2008 to 2018. 

To comply with the BART requirements, states must develop “emission limitations representing 

BART” for a specified set of sources. 42 U.S.C. §7491(b)(2)(A); 40 C.F.R. § 51.308(e). BART 

determinations must consider five statutory factors: (1) the costs of compliance; (2) the energy 

and nonair quality environmental impacts of compliance; (3) any existing pollution control 

technology in use at the source; (4) the remaining useful life of the source; and (5) the degree of 

improvement in visibility which may reasonably be anticipated to result from the use of such 

technology. 42 U.S.C. § 7491(g)(2); see 40 C.F.R. §51.308(e)(1)(ii)(A). 

Congress enacted the Clean Air Act's regional haze provisions with a long-term goal of returning 

national parks and certain scenic areas to a state of natural visibility. However, Congress realized 

such changes could not be fully realized immediately and adopted an approach by which States 

would make incremental improvements over time. In fact, EPA has approved much longer 

reasonable progress goals for Class I areas in the State of California. For example, EPA 

approved almost 300 years for the Desolation Wilderness and Mohalume Wilderness, which 

must achieve compliance by 2307. 76 Fed.Reg. 34,608 (June 14, 2011); 76 Fed.Reg. 

13,951(March 15, 2011). Yet, EPA is attempting in its Proposed FIP to force Arkansas to 

achieve compliance even earlier than the national goal of 2064. 
26 

Despite the fact that real-world, measured air quality demonstrates that Arkansas is on track to 

meet the visibility improvements contemplated by the Regional Haze Rule,8

 EPA has 

unreasonably proposed to supplant the State's authority and impose a FIP that would place 

additional emission control requirements on a handful of sources at significant cost 

notwithstanding expected further emissions reductions from levels that have achieved the desired 

target today. Furthermore, EPA has failed to explain how these costly emissions are reasonably 

certain to achieve actual visibility improvements, as required by the CAA. 

Response: We acknowledge the background information provided by the commenter. We take 

no position on the commenter’s synopsis of the visibility program. 

To the extent the commenter is alleging that our proposed FIP is inappropriate or unnecessary 

because Arkansas Class I areas are already projected to be below the URP glidepath, we address 

such comments elsewhere in this document. We address elsewhere in this document comments 

contending that our proposed FIP is inconsistent with our approval of the RPGs for other states 

that are not expected to reach natural visibility conditions until after 2064. We address elsewhere 

in this document comments contending that ADEQ’s Five-Year Progress SIP revision shows that 

IMPROVE monitor data indicate that Arkansas is on track to meet the state established RPGs for 

2018. We address elsewhere in this document comments alleging that we are supplanting the 

State’s authority in promulgating our FIP. We also address elsewhere in this document 

comments alleging that due to the uncertainty in the CALPUFF model our proposed controls are 

not expected to achieve actual visibility improvement. 

Comment: [Entergy Mississippi Inc. (0168), p. 2] EMI stated that on April 8, 2015, the EPA 

proposed a FIP for the State of Arkansas for Regional Haze and Interstate Visibility Transport 

(the “Proposed Rule”).9

 Specifically, the Proposed Rule addresses the previously disapproved 

elements of the Arkansas State Implementation Plan for Regional Haze, including certain BART 

determinations, RPGs, and long-term strategy (“LTS”) necessary to achieve established RPGs, as 

well as the interstate visibility transport requirements for pollutants that affect visibility in Class I 

federal areas in Arkansas and nearby states. Among other things, the Proposed Rule includes 

emission limitations based on installation of BART controls for sulfur SO2 and NOX at the 

Entergy White Bluff Plant (“White Bluff”) and two proposed alternative options for controlling 

emissions from the Entergy Independence Plant (“Independence Plant”) under the regional haze 

reasonable progress requirements. 

EMI is a corporation organized under the laws of the State of Mississippi and provides electric 

service in Mississippi. EMI is an electric public utility under the Mississippi Public Utilities Act 

of 1956, as amended. EMI provides retail electric service in portions of 45 counties in western 

Mississippi pursuant to certificates of public convenience and necessity issued by the Mississippi 

Public Service Commission (“MPSC”) in Docket U-44 and other Dockets. EMI serves 

approximately 450,000 retail electric customers in those 45 counties. EMI also provides 

wholesale partial requirements service to the Municipal Energy Agency of Mississippi, which is 

 

8

 See Arkansas Department of Environmental Quality, “State Implementation Plan Review for the Five-Year 

Regional Haze Progress Report;” Revised May 2015, pp. 43, 64, attached to Nucor’s comments as Exhibit 3. 

9

 See 80 Fed. Reg. 18,944 (Apr. 8, 2015). 
27 

a state-chartered organization that provides the requirements service to six (6) municipal electric 

utilities in western Mississippi. EMI acquired a 25% undivided ownership interest in 1981 in 

each of the two generating units at the Independence Plant, pursuant to, among other things, the 

approval of the MPSC in Docket U-4873. The Independence Plant provides a significant portion 

of EMI’s baseload generating capacity. As a co-owner of a significant portion of the 

Independence Plant, EMI has a strong interest in ensuring the proper implementation of the 

regional haze and interstate visibility requirements of the Clean Air Act for the protection of its 

customers. 

Response: We acknowledge the background information provided by the commenter.

Comment: [Domtar (0161) p. 14] Domtar stated that the preamble of our proposed FIP makes 

reference to the operations of the Mill’s caustic solution system and a set point in the Mill’s 

operational controls for the caustic addition. For clarification purposes, the set point of 0.86 

lb/MMBTU for Power Boiler No. 2 is a Mill operating parameter and not an operating 

requirement. 

Response: We acknowledge and appreciate the clarification provided by the commenter 

regarding background information discussed in our proposal regarding operation of the existing 

scrubbers on Power Boiler No. 2. We do note that the clarification provided by Domtar does not 

affect our final BART decision regarding SO2 BART for Power Boiler No. 2. 

Comment: [Edison Electric Institute (0174) p. 9-10] EEI stated that as EPA and states begin to 

implement the next round of the regional haze program to address reasonable progress 

requirements in pursuit of the 2064 goal, the Agency should allow states to consider how best to 

assess and plan additional controls activities, consistent with effective long-term utility planning, 

and take into consideration the progress made by the electric power and other sectors in 

improving visibility through the installation of controls to satisfy BART and other regulatory 

programs. 

EEI also stated that it urges EPA to consider the technical comments of both Entergy and 

Southwestern Electric Power Company regarding unit-specific and other technical and legal 

concerns. 

Response: We acknowledge the commenter’s concerns and suggestions with regard to our and 

the states’ work on the regional haze SIPs for future planning periods. However, these types of 

comments are outside the scope of this rulemaking. 

We acknowledge EEI’s support of the comments submitted by both Entergy and the 

Southwestern Electric Power Company (AEP-SWEPCO). Our responses to Entergy’s and AEPSWEPCO’s specific comments are provided throughout this document.
28 

Comment: [Entergy Arkansas Inc. (0166) p.1] Entergy Arkansas Inc. stated that on April 8, 

2015, the EPA published a proposed Federal Implementation Plan (FIP) to address certain 

regional haze and visibility transport requirements for the State of Arkansas (80 FR 18944). The 

proposed FIP would address the requirements of the Regional Haze rule and interstate visibility 

transport for those portions of Arkansas’ SIP that EPA had previously disapproved (77 FR 

14604, March 12, 2012). The proposed FIP addresses the requirements for BART for those 

sources for which EPA did not approve Arkansas’ BART determinations, Reasonable Progress 

Goals, reasonable progress controls and a long-term strategy, as well as the interstate visibility 

transport requirements for pollutants that affect visibility in Class I areas in nearby states.

Entergy Arkansas Inc. owns and operates three facilities that EPA proposes to regulate under the 

FIP: White Bluff Electric Power Plant (“White Bluff”); Independence Steam Electric Station 

(“Independence”); and Lake Catherine Plant (“Lake Catherine”). EPA is proposing SO2 and NOX

BART limits for White Bluff Units 1 and 2, and SO2, NOX, and PM BART limits for the 

Auxiliary Boiler at White Bluff. EPA also is proposing a NOX BART limit for Unit 4 at 

Lake Catherine. Finally, EPA is proposing emissions limits at Independence to meet reasonable 

progress requirements and is seeking comment on two alternative options. Under Option 1, EPA 

is proposing SO2 and NOX emission limits for Units 1 and 2 at Independence. Under Option 2, 

EPA is proposing only SO2 emission limits for Units 1 and 2. EPA also is soliciting comment on 

any alternative control measures for White Bluff Units 1 and 2 and Independence Units 1 and 2 

that would address the BART and reasonable progress requirements for these four units for the 

current regional haze planning period. 

Response: We take no position on Entergy’s synopsis of our FIP proposal. We acknowledge 

that Entergy Arkansas Inc. owns and operates three of the facilities for which we proposed 

emission limits to meet the Regional Haze Rule requirements in Arkansas. 

Comment: [Entergy Arkansas Inc. (0166) p. 1-2] Entergy Arkansas Inc. stated that the Regional 

Haze Program is intended to achieve gradual and steady improvement in visibility at Class I 

areas over the course of 64 years. The program was established under the CAA as a long-term 

program to allow major emitting sources to install controls or be phased out in a rational and 

economical manner to ultimately achieve natural visibility conditions at all Class I areas in the 

United States. The program also is intended to recognize that regional haze is a regional 

problem; one that benefits from broad programmatic changes and the retirement of sources as 

they reach the end of their useful lives. EPA’s proposed FIP for Arkansas largely abandons this 

approach, ignores the significant improvements in visibility in Arkansas’ Class I areas that 

already have occurred, fails to account for the improvements that are anticipated to occur based 

on other regulatory programs, and seeks to impose more than $2 billion in costs on Entergy 

Arkansas Inc.’s customers and co-owners despite the lack of any need for, or benefit from, such 

a massive investment. 

Response: We disagree with Entergy Arkansas Inc.’s statement that our proposed FIP is 

inconsistent with the goal of the Regional Haze Program, that it ignores the significant 

improvements in visibility in Arkansas’ Class I areas, fails to account for the improvements that 

are anticipated to occur based on other regulatory programs, and seeks to impose controls that 

exceed more than $2 billion in cost without the need for or anticipated benefit from such 
29 

controls. These comments are addressed in detail elsewhere in this RTC document. Further, we 

take no position as to Entergy’s characterization of the Regional Haze Program in the comment. 

Comment: [Entergy Arkansas Inc. (0166) p. 2-4] Entergy Arkansas Inc. states that it proposes 

an approach that is more reasonable than EPA’s proposed FIP, and is a long-term, multi-unit 

approach to address regional haze in the Arkansas Class I areas that achieves reasonable 

progress, is consistent with the statutory scheme and allows Entergy to manage its generation 

fleet in a reliable and economic manner. Entergy provides a summary of its proposed approach, 

as well as a summary of its comments on EPA’s proposed FIP. Entergy states its proposed 

approach involves the following: (1) achieving early SO2 reductions by accepting lower interim 

SO2 emission rate limitations at both White Bluff and Independence; (2) achieving NOx 

reductions by installing NOx control technology on all four units within three years of the 

effective date of EPA’s final FIP; and (3) committing to the permanent cessation of coal-fired 

operations at White Bluff by 2028. 

Entergy also provides a summary of its comments, stating that under EPA’s current schedule for 

finalizing the FIP, EPA would require the installation of scrubbers on the four units at White 

Bluff and Independence by 2021, which would result in a six to seven year amortization period 

for Entergy Arkansas Inc., which would drive the costs of the scrubbers to over $7,500-$8,500 

per ton of SO2 removed. Based on modeling conducted by Entergy, which EPA should have 

conducted but failed to undertake, the difference in visibility at the Arkansas Class I areas 

between the proposed FIP controls and Entergy’s proposal is imperceptibly small and does not 

warrant an investment of over $2 billion in scrubber technology at the plants. 

EPA’s proposal to require SO2 and NOX limits based on the installation of dry scrubbers and 

NOx controls on the two coal-fired units at Independence cannot be justified for the first regional 

haze planning period because Independence is not a BART-eligible source, and EPA may 

impose emission reduction requirements on Independence under the Regional Haze Program 

only to the extent necessary to achieve reasonable progress towards natural visibility levels. See

42 U.S.C. §7491(b)(2) (implementation plans must “contain such emission limits ... as may be 

necessary to make reasonable progress”) (emphasis added). The visibility in Arkansas’ Class I 

areas already has improved substantially in the past 10 years such that the haze index for both 

Class I areas currently is well below the uniform rate of progress (“URP” or “glide path”) that 

EPA uses to ensure reasonable progress towards natural visibility conditions and that EPA had 

previously approved for Arkansas.10 Based on the negligible visibility benefit from installing 

scrubbers at Independence, the cost of the controls is an astounding $1.33 billion to $1.53 billion 

per deciview improvement. Scrubbers at Independence are simply not necessary to ensure that 

visibility in Arkansas’ Class I areas remains below the URP, nor are they justifiable based on 

EPA’s own analysis of the visibility benefits resulting from such a huge investment.11 According 

to modeling performed by the Central Regional Air Planning Association (CENRAP), all of 

Arkansas’ elevated point sources (including all power plants and large industrial sources) 

 

10 76 Fed. Reg. 64,186, 64,194-95 (Oct. 17, 2011). 

11 The Class I areas outside of Arkansas that are potentially affected by emissions from Arkansas, similarly, are 

below the URP and do not need additional reductions to achieve reasonable progress or their long-term visibility 

goals. 
30 

account for only about 2.7% and 2.3% of total light extinction within Caney Creek and Upper 

Buffalo, respectively. The overwhelming visibility impact comes from non-Arkansas point 

sources and mobile sources. Because of the Mercury and Air Toxic Standards (“MATS”) rule,12

the continuing benefits of the Clean Air Interstate Rule (“CAIR”), the next phase of the Cross 

State Air Pollution Rule (“CSAPR”), and implementation of the soon-to-be-released revised 8-

hour ozone National Ambient Air Quality Standards (“NAAQS”), along with continuing 

reductions in emissions from mobile sources, the visibility at Caney Creek and Upper Buffalo 

will continue to improve. Based on the visibility trends in both Class I areas, the imposition of 

BART controls, and Entergy’s proposed interim controls and proposed commitment to cease 

coal burning at White Bluff, no further action will be necessary to ensure that Arkansas’ Class I 

areas remain below the URP until at least 2028 and likely even longer as a result of emissions 

controls that will be required by future regulatory programs and planned retirements of numerous 

electric generating units. 

Entergy states that EPA acknowledges that controls on Independence are not needed for 

Arkansas to achieve the URP. 80 Fed. Reg. at 18,992 (“We believe it is appropriate to evaluate 

Entergy Independence even though Arkansas Class I areas and those outside Arkansas most 

significantly impacted by Arkansas sources are projected to meet the URP for the first planning 

period.”). Indeed, after the proposed BART controls are installed and White Bluff ceases coalfired operations, Arkansas sources will not approach the URP, or glide path, for at least another 

decade. Entergy’s analysis, based on the actual visibility impairment data, shows that Caney 

Creek will remain below the glide path until at least 2032 and Upper Buffalo until at least 2028 

with no additional controls on in-state sources. Imposing controls on Independence is simply not 

necessary or justified to achieve reasonable progress towards natural visibility in Arkansas’ Class 

I areas. 

EPA’s reasonable progress analysis and justification for proposing stringent emission limitations 

at Independence are not legally defensible under the Regional Haze Program based on the costs 

and lack of visibility benefits of the proposed limits. EPA suggests it is only logical to require 

Independence to install controls because its SO2 emissions are large and because it would be cost 

effective to control them. Cost-effectiveness is a factor in deciding the degree of controls 

necessary to establish RPGs, but it is not an independent basis for imposing controls and does 

not determine RPGs. In this case, installing the controls on Independence that would be 

necessary to meet the proposed emission limits will cost EIA’s customers and co-owners in 

excess of $1 billion. While the cost per ton of SO2 removed may be within the range that might 

support a BART determination, it is nonetheless high in the context of reasonable progress 

controls, particularly where the benefits are small and reductions are not needed to demonstrate 

that Arkansas is making reasonable progress towards achieving natural visibility conditions at its 

Class I areas. Accordingly, Entergy objects to the RPGs that EPA is proposing for Arkansas. 

 

12 In spite of the Supreme Court decision in Michigan v. EPA, 135 S.Ct. 2699 (2015), which held that EPA must 

evaluate costs in determining whether it is appropriate and necessary to regulate hazardous air pollutant emissions 

from electric generating units (“EGUs”), several EGUs already have installed controls to comply with MATS or 

have undertaken other steps to reduce their emissions. Even if the rule is stayed or vacated while EPA undertakes its 

cost analysis, Entergy expects that the rule will go forward before the end of this planning period along with the 

associated emission reductions. 
31 

EPA also improperly relied on CALPUFF modeling to justify the proposed controls at 

Independence, vastly overstating the impact of emissions from Independence and the benefits of 

installing controls. CALPUFF modeling, a single source puff model, is not an appropriate model 

to determine or project reasonable progress benefits. Reasonable progress is determined by 

evaluating the overall visibility values in Class I areas and the projected trends in visibility as a 

result of emissions, controls and operations at all sources contributing to visibility impairment. 

EPA has recognized in recent rulemakings that CALPUFF cannot do this and it is therefore 

arbitrary and capricious for EPA to rely on CALPUFF for this purpose here. 

Response: We acknowledge Entergy’s summary of its proposed approach and summary of its 

comments. Entergy’s specific comments on its proposed approach and on each of the issues 

mentioned in its summary and our responses to those comments are provided in other sections of 

this document. 

Comment: [Nucor Steel-Arkansas and Nucor-Yamato Steel Company (0163) p. 3-5] Nucor 

Steel-Arkansas (NYS) and Nucor-Yamato Steel Company (NSA) stated they disagree with and 

object to EPA's Proposed FIP. EPA’s Proposed FIP does not comply with the requirements of 

the Clean Air Act (“CAA”) because, among other things: 

(a) EPA has not demonstrated that its BART determinations for White Bluff and Flint Creek and 

its Reasonable Progress decision for Independence are necessary, 

(b) EPA failed to consider relevant factors in its BART and Reasonable Progress determinations 

for White Bluff, Flint Creek and Independence, 

(c) EPA failed to consider all available control technologies in its BART and Reasonable 

Progress determinations for White Bluff, Flint Creek and Independence, 

(d) EPA's determinations on cost-effectiveness of additional controls for White Bluff, Flint 

Creek and Independence are not justified, are unreasonable, are inconsistent and are arbitrary 

and capricious, 

(e) EPA's determinations of visibility impacts from White Bluff, Flint Creek, Independence and 

the other facilities involved in EPA's Proposed FIP are unreasonable and do not support its 

BART and RP determinations, because the CALPUFF model is unsuitable for EPA's 

regulatory determinations under these circumstances (thus, EPA has not demonstrated that 

there is a reasonable certainty that the controls required under its BART and Reasonable 

Progress determinations will result in an improvement in visibility, 

(f) EPA has unduly relied on its cost-effectiveness calculations and has not explained how its 

cost-effectiveness calculations justify its BART and Reasonable Progress determinations 

with respect to anticipated visibility improvements; and 

(g) EPA has not demonstrated that any of the sources regulated in the Proposed FIP interfere 

with control measures in any other state's SIP, especially given the overestimation of the 

CALPUFF modeling results and whether there will be any reasonably certain visibility 

improvement from EPA's proposed control measures (thus EPA has not demonstrated that 

these measures are necessary in order to comply with 42 U.S.C. §7410(a)(2)(D)(i)(II)). 
32 

In addition, EPA did not explain how it exercised its judgment and balanced and weighed the 

BART and Reasonable Progress factors in arriving at its BART and Reasonable Progress 

determinations. 

Also, EPA has failed to fully respond to Nucor's Freedom of Information Act (FOIA) requests 

and has failed to grant Nucor's request to extend the time for comments on the proposed FIP until 

after EPA has fully complied with those requests.13 Presumably, the responses to those FOIA 

requests would be relevant to an explanation of how EPA exercised its judgment in weighing and 

balancing the BART and Reasonable Progress factors.14 Finally, under the clear terms of the 

Clean Air Act, EPA does not have the authority to initiate this rule-making and issue its 

proposed FIP, because more than two years have passed since EPA disapproved Arkansas's 

regional haze SIP. 

Response: This comment lists a number of issues that are raised by the commenter in more 

detail elsewhere. Please see our responses to those more specific comments in other sections 

throughout this document. 

We disagree with the comment that the responses to Nucor’s FOIA request would be relevant to 

EPA’s exercise of judgement in this rulemaking. The basis for our final action, including our 

weighing and balancing of the relevant factors, is contained in the record for this rulemaking 

which is available at regulations.gov. Please see our responses in the legal section regarding 

EPA’s authority to promulgate a FIP more than two years since EPA disapproved Arkansas’s 

regional haze SIP. 

Comment: [Entergy Mississippi Inc. (0168) p. 3] EMI stated that Section 169A of the Clean Air 

Act (“CAA”) establishes as a national goal the prevention of any future, and the remedying of 

any existing man-made impairment of visibility in 156 national parks and wilderness areas 

designated as mandatory Class I federal areas. In 1999, EPA promulgated the Regional Haze 

Rule (“RHR”)15 to address regional haze impairment and establish a comprehensive visibility 

protection program for Class I areas, which calls for the elimination of man-made visibility 

impairment at Class 1 federal areas by 2064. The regional haze program was designed this way 

in recognition of the fact that future advancements in technology and changes in economic 

factors will likely provide opportunities for implementation of new cost-effective control 

measures to assure reasonable progress towards the goal of elimination of visibility impairment 

at Class I areas, and thereby reduce the economic burden of presently installing expensive 

 

13 See, Nucor FOIA request dated, March 13, 2015; letter response from L. Lane at EPA dated May 19, 2015, and 

Nucor's counsel's letter to EPA dated July 10, 2015, attached hereto as Exhibits 1A, 1B and 1C, respectively. Nucor 

reserves the right to submit additional comments in this docket after EPA has fully complied with Nucor's FOIA 

requests. 

14 In a document dated Feb. 11, 2015 at p. 20 (attached as Exhibit 2), EPA discussed an option for the Reasonable 

Progress Analysis for SO2 and NOX controls at Independence as “No Additional Controls” since the CENRAP 

modeling showed that all Arkansas areas were on or below the glide path; however, this option was not included in 

the Federal Register notice and no explanation based on the statutory factors was given why this option was 

discarded. 

15 64 Fed. Reg. 35,714 (July 1, 1999), codified at 40 C.F.R. part 51, subpart P. 
33 

control measures to meet a purely aesthetic standard.16 The structure of EPA’s rule is designed to 

require States, through the state implementation plan (“SIP”) process, to review the statutory 

factors on a periodic basis and determine appropriate changes to their strategies based on that 

review. 

Despite the long-term nature of Congress’ design of the regional haze program and the fact that 

Arkansas is well ahead of the EPA-approved Uniform Rate of Progress (“URP” or “glide path”) 

for elimination of visibility impairment at its Class 1 areas (and is predicted to remain so for at 

least a decade to come), the Proposed Rule would mandate emission limitations based on 

installation of unnecessary and uneconomic controls. Indeed, the Proposed Rule fails to 

accurately account for the costs of the unnecessary and unjustified controls to the electricity 

consumers. The cumulative effect of the legal and factual errors is to impose hundreds of 

millions of dollars of unnecessary expense on Arkansas’ utilities, their co-owners, and their 

customers, including the retail electric customers of EMI. 

Although not an Arkansas utility provider, EMI is a co-owner of a significant portion of the 

Independence Plant and, as such, has particularized concerns about the Proposed Rule’s legal 

and factual errors as they relate to the reasonable progress analysis and determinations in the 

Proposed Rule. Many of the errors and inaccuracies in the reasonable progress determinations 

stem from EPA’s artificially low assumptions regarding the costs of controls for the White Bluff 

Plant. Furthermore, the totality of the Proposed Rule fails to account for Entergy’s alternative 

proposal that would yield equivalent visibility improvements at tremendously less cost (over $2 

billion). Accordingly, EPA’s final rule should reject the proposed reasonable progress 

determinations for the Independence Plant and instead address Entergy’s proposed alternative 

approach for both the Independence and White Bluff Plants. 

Response: The EPA acknowledges the background information provided by the commenter. 

We take no position with respect to the commenter's synopsis. This comment touches on a 

number of issues that are raised by the commenter in more detail elsewhere. Please see our 

responses to those more specific comments. 

Comment: Summary of ADEQ’s comments. [ADEQ (0144), cover letter and p. 1-2] ADEQ 

stated that in 1977, Congress amended the Clean Air Act (“CAA”) to include the national goal of 

preventing any future and remedying any existing impairment of visibility at mandatory Class I 

Federal areas (“Class I areas”). EPA promulgated the Regional Haze Rule in July 1999 to further 

this national goal and established regulations to eliminate man-made visibility impairment in 

those areas by 2064. Nationally, there are 156 Class I areas. There are two Class I areas in 

Arkansas: Upper Buffalo and Caney Creek Wilderness areas. 

The Regional Haze Rule and related regulations contain provisions that encourage state, local, 

and tribal agencies to work cooperatively within regional planning organizations to address 

visibility impairment. In accordance with the regional haze program requirements outlined in 40 

C.F.R. § 51.308, the Arkansas Department of Environmental Quality (“ADEQ”) submitted the 

Arkansas Regional Haze State Implementation Plan (“Regional Haze SIP”) to EPA on 

 

16 Id. at 35,714, 35,752. 
34 

September 23, 2008. On March 12, 2012, EPA partially approved and partially disapproved the 

Regional Haze SIP (“the Arkansas Regional Haze Approval/Disapproval”).17

ADEQ submitted on June 2, 2015, the Five-year Regional Haze Progress Report, which is 

intended to fulfill the requirement in 40 C.F.R. § 51.308(g) that Arkansas provide periodic 

reports to EPA evaluating progress towards the Reasonable Progress Goals (“RPGs”). On April 

8, 2015, EPA promulgated the Proposed FIP for Arkansas.18 On May 1, 2015, 

EPA extended the public comment period for the Proposed FIP until July 15, 2015.19 

ADEQ stated that Arkansas prides itself on being the Natural State and its ongoing efforts to 

maintain excellent air quality. The EPA published on April 8, 2015, a proposed Federal 

Implementation Plan covering Regional Haze and Interstate Visibility Transport for the State of 

Arkansas (“Proposed FIP”). The Arkansas Department of Environmental Quality (ADEQ) has 

reviewed the Proposed FIP and has determined that it contains significant flaws and does not 

accurately reflect the real progress the State has made to fulfill the requirements of the Clean Air 

Act pertaining to Regional Haze and Visibility. EPA failed to use the proper methodology used 

in portions of the Proposed FIP. Moreover, the Proposed FIP is lacking in its legal precedence 

and its analysis appears to be incomplete or lacking in clarity. Furthermore, EPA acted arbitrarily 

in developing a proposal which is inconsistent with the approach taken in other states. 

As a primary example of the Proposed FIP’s infirmity, the Entergy Independence Plant is not 

currently identified as being subject to Best Available Retrofit Technology (BART). Despite this 

fact, EPA improperly performed its own reasonable progress analysis. EPA indicated this was 

performed by applying the reasonable progress factors set forth in the Regional Haze Rule to 

require specific emissions controls for Entergy Independence Units One and Two. This type of 

improper and unlawful analysis has no basis in the Regional Haze Rule or other relevant law. 

Moreover, EPA’s proposed additional control measures for the Entergy Independence Plant are 

both unnecessary and arbitrary. The State of Arkansas has demonstrated that it is on track to 

meet the uniform rate of progress in its Five-Year Regional Haze Progress Report for the first 

planning period, which ends in 2018. EPA singled out the Entergy Independence Plant through a 

cursory evaluation of the National Emissions Inventory data, not a reasoned evaluation utilizing 

the established framework that takes into account, among other factors, the costs of compliance 

and progress made to date. 

Under the Proposed FIP, certain entities that are already complying with portions of the Clean 

Air Act aimed at reducing interstate transport of air pollution under the Cross-State Air Pollution 

Rule (CSAPR) would also have to install additional emissions controls to achieve the same goal. 

This is the case despite EPA’s own assertions that CSAPR is more effective in reducing 

particular emissions during ozone season. Based on EPA’s statements that CSAPR provides for 

greater reasonable progress than source-specific NOX controls, EPA should determine that 

 

17 Approval and Promulgation of Implementation Plans; Arkansas; Regional Haze State Implementation Plan; 

Interstate Transport State Implementation Plan To Address Pollution Affecting Visibility and Regional Haze, 77 FR 

14604. 

18 Promulgation of Air Quality Implementation Plans; State of Arkansas; Regional Haze and Interstate Visibility 

Transport Federal Implementation Plan, 80 FR 18944.

19 Approval and Promulgation of Implementation Plans; Arkansas; Regional Haze and Interstate Visibility Transport 

Federal Implementation Plan; Extension of Comment Period and Notice of Availability, 80 FR 24872. 
35 

facilities included in the Proposed FIP which are already subject to requirements under the 

CSAPR FIP satisfy BART for NOX and therefore should not be required to install additional 

controls. 

Additionally, ADEQ finds that EPA's Proposed FIP is inconsistent with the approaches proposed 

in other states. For example, in developing the Proposed FIP, EPA used a simpler modeling 

method ignoring crucial factors that would provide a more representative accounting of the 

emissions in Arkansas. In support of this simpler method, EPA cites to its use in developing 

reasonable progress goals for Hawaii and Arizona. EPA's decision to utilize this simpler method 

is not supported in the Proposed FIP. EPA used the CAMx photochemical model in its analysis 

to develop RPGs for the Texas-Oklahoma FIP. For Arkansas, EPA chose a method of 

determining RPGs that is admittedly inferior and less sophisticated than the CAMx approach. 

EPA's inconsistency in methodology is not fully explained and represents arbitrary decisionmaking that leads to unjustified disparities in treatment among the states. 

Furthermore, EPA’s metrics used throughout the Proposed FIP are misleading and not supported 

on a legal or technical basis. For instance, the cumulative visibility effects metric lacks a sound 

scientific basis and is not supported in the Regional Haze Rule or EPA guidelines. The metric 

combines slight incremental increases from different locations that do not reflect actual visibility 

improvement in any single location differently. Ultimately, the metric provides no meaningful 

information on progress toward meeting visibility goals. 

Perhaps most troubling, EPA failed to appropriately assess the costs of the overall impact of the 

Proposed FIP. Recent concerns have been raised by the United States Supreme Court in the case 

of Michigan v. EPA regarding the rationality of imposing billions of dollars in economic costs in 

return for a few dollars in health or environmental benefits. Accordingly, EPA should have 

performed an analysis to properly determine the extent of the impacts of the Proposed FIP in the 

State of Arkansas. 

Finally, it is arbitrary and capricious for EPA to force an emissions source to invest millions, 

much less billions, of dollars for new technology that will have no appreciable effect on the haze 

in any Class I Federal area (Class I area). In a recent decision that is further discussed in the 

attached comments, the United States Court of Appeals for the Ninth Circuit recently issued a 

decision that called into question the use and reliability of the CALPUFF visibility model as a 

means of identifying affected facilities when those facilities are more than 200 kilometers from a 

Class I area and the simulated visibility improvements are both within the margin of error of the 

model and imperceptible. The Clean Air Act does not require an improvement that cannot be 

reasonably anticipated. 

Response: We acknowledge the background information provided by the State of Arkansas. 

We take no position with respect to the ADEQ’s synopsis of the issues such as the proposed FIP. 

This comment summarizes the issues raised by the state in its comments. These comments and 

our responses are found in other sections throughout this document. Please see our responses to 

those more specific comments. 
36 

Comment: [ADEQ (0144) p. 30] ADEQ stated that EPA’s Proposed FIP is not a viable option 

for implementation of the Regional Haze program in Arkansas. The Proposed FIP contains 

misleading cumulative visibility metrics. EPA arbitrarily requires sources that are subject to the 

CSAPR Rule to also control NOx emissions as BART. EPA improperly performed the 

reasonable progress analysis required by the Regional Haze Rule, which resulted in requiring 

unneeded emissions controls for the Entergy Independence Plant. EPA also chose to forego 

CAMx photochemical modelling such as that used in Texas in favor of a less accurate algorithm 

that resulted in inferior RPGs. In addition, EPA has not complied with E.O 12866 and E.O. 

13211. 

EPA should withdraw the Proposed FIP, and any subsequent plan should address the issues 

presented in this letter. While ADEQ will continue to work to develop an acceptable SIP for 

approval by EPA, the harsh deadline of December 15, 2015 proposed in a recently proposed 

consent decree between EPA and Sierra Club may stifle those efforts. Nonetheless, ADEQ will 

diligently continue to work towards the resolution of all of the issues raised during the public 

comment period. 

Response: We acknowledge ADEQ’s concerns related to our proposed FIP and to our deadline 

for finalizing the FIP. We do note that EPA did not ask the court to enter the consent decree 

containing the proposed December 15, 2015 deadline for a final action. Following litigation over 

the appropriate date for final action on the Arkansas regional haze plan, litigation in which 

Arkansas participated, the court entered an order establishing a date for final action. We are 

accordingly subject to a court-ordered deadline to take final action to promulgate a FIP or 

approve a SIP revision that addresses the deficiencies in the Arkansas RH SIP by August 31, 

2016.20 Although we have not yet seen a revised SIP revision from Arkansas, should the State 

decide to submit such a plan, we will work expeditiously to review the plan. 

This comment touches on issues raised by the ADEQ in more detail elsewhere. Please see our 

responses to those more specific comments in other sections throughout this document. 

Comment: [Domtar (0161) p. 1-2] Domtar stated that it appreciates the opportunity to provide 

written comments on the EPA’s FIP proposal to address certain regional haze and visibility 

transport requirements for the State of Arkansas. The proposal was published in the April 8, 

2015 Federal Register. Domtar stated that the nature of its comments focuses on the proposed 

BART determinations for the Ashdown Mill Power Boiler 1 and Power Boiler 2. The first 

section addresses concerns associated with the lack of a statutory basis for imposing BART on 

the Ashdown Mill, as the purported visibility improvements asserted by the Agency are so 

insignificant as to fall within the CALPUFF model’s Ashdown Mill specific margin of error. As 

such the purported visibility improvement cannot be reasonably anticipated. See 42 U.S.C. § 

7491(g)(2); Nat’l Parks Conservation Ass’n v. EPA, No. 12-73710, 2015 WL 3559148 (June 9, 

2015). (The supporting report and analysis will be submitted during the reopened comment 

period.) Without waiving the significant legal issues with the BART proposal, the second section 

of the comments focuses on specific issues and concerns with the proposed BART requirements 

for the Ashdown Mill. Domtar’s comments conclude with a recommendation that the proposed 

 

20 Sierra Club v. Gina McCarthy, No. 4.14CV00643JLH (ED Ark. Western Div. Nov. 3, 2015). 
37 

BART requirements for the Mill not proceed or, alternatively, the Agency defer any action on 

BART for 5 years until the Mill completes its repurposing project. Based on the actions taken 

with respect to Power Boilers 1 and 2, BART may be mooted. EPA could review the Mill’s 

status after the full conversion is complete and operational in 5 years at which time it is highly 

unlikely any BART related action will be necessary. 

The Ashdown Mill is part of Domtar Corporation (Domtar). Domtar is a designer, manufacturer, 

marketer and distributer of a wide variety of wood fiber-based products including 

communication papers, specialty and packaging papers and absorbent hygiene products. The 

foundation of Domtar’s business is a network of fiber converting assets that produce paper grade, 

fluff and specialty pulps. While most of our pulp production is consumed internally to 

manufacture paper and consumer products, we are also one of the United States’ largest volume 

exporters. Domtar is the largest integrated marketer of uncoated freesheet paper in North 

America. Domtar operates pulp and paper Mills and personal care facilities in the US, Canada, 

Spain and Sweden. In the US we operate in the following states: Arkansas, Kentucky, Georgia, 

Michigan, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas and 

Wisconsin. 

The Ashdown Mill operates in very dynamic, changing and competitive global markets. The 

global marketplace is very competitive, and as such, managing costs is a key component, 

especially in a business where the ability to pass through costs to customers is limited. Our 

products are sold on the basis of cost, quality and service. We continue to see increased 

competition from “lower” cost imports, with about a 20% increase in imports last year alone. In 

addition, due to the digital revolution, the traditional paper markets continue to shrink rapidly. 

To a significant extent, the market is transitioning away from traditional, higher profit margin 

paper products to newer but lower profit margin items. The ability to maintain operational 

flexibility and be cost effective is essential for the Ashdown Mill to be able to quickly adjust to 

the changing markets and maintain economic viability. 

Response: We acknowledge the background information provided by the commenter. This 

comment summarizes the issues raised by the commenter in more detail elsewhere. Please see 

our responses to those more specific comments. 

Comment: [AEP-SWEPCO July 15, 2015 comments (0164), p. 1, and August 7, 2015 

comments (0167) p. 1-2] Southwestern Electric Power Company (AEP-SWEPCO), an operating 

company of the American Electric Power system (AEP), stated it appreciates the opportunity to 

provide comments to the U.S. Environmental Protection Agency (EPA or the Agency) on its 

proposed FIP to address certain regional haze and visibility transport requirements for the State 

of Arkansas.21 Comments were originally due on May 16, 2015.22 EPA subsequently extended 

that deadline to July 15, 2015 and at the same time announced the availability in the docket of 

 

21 80 Fed Reg. 18944 (April 8, 2015). 22 Id.
38 

supplemental modeling.23 On July 23, 2015, EPA published its notice of the reopening of the 

comment period until August 7, 2015.24 

AEP-SWEPCO owns and operates the Flint Creek Power Plant and supports EPA's approval of 

the SO2 portions of the Flint Creek BART analysis as submitted. AEP-SWEPCO is a 50% owner 

of Flint Creek Power Plant along with Arkansas Electric Cooperative Corporation (AECC). 

AEP-SWEPCO also supports EPA's previous approval of the particulate matter (PM) portions of 

the Arkansas SIP as submitted. 

Response: We acknowledge the background information provided by the commenter. We take 

no position with respect to the commenter's synopsis. Although outside of the scope of this 

rulemaking, we appreciate the commenter’s support of our previous action approving a portion 

of ADEQ’s PM BART determinations. 

Comment: [AECC (0169) p. 1] AECC stated that it appreciates the opportunity to provide 

comment on the potential implications of the proposed FIP on its operations and memberowners. AECC is a generation and transmissions cooperative which is owned by 17 electric 

distribution cooperatives in the State of Arkansas. Together, they provide electricity to 

approximately 500,000 member-owners covering approximately 62% of the geographical area of 

the state. 

Response: We acknowledge the background information provided by the commenter.

Comment: UARG provides a summary of EPA’s proposed Arkansas Regional Haze FIP. 

[UARG (0176) p. 1-2] UARG stated that in a March 12, 2012 final rule, the U.S. Environmental 

Protection Agency (EPA or Agency) disapproved substantial parts of a state implementation plan 

(SIP) intended to implement the Clean Air Act’s (CAA or the Act) regional haze provisions and 

the Act’s interstate transport requirements related to visibility for Arkansas. 77 Fed. Reg. 14,604 

(Mar. 12, 2012). On April 8, 2015, EPA published a proposed federal implementation plan (FIP) 

to address those regional haze provisions and interstate transport requirements that were included 

in the disapproved parts of the Arkansas SIP. “Promulgation of Air Quality Implementation 

Plans; State of Arkansas; Regional Haze and Interstate Visibility Transport Federal 

Implementation Plan.” 80 Fed. Reg. 18,944. The proposed FIP is intended to implement the 

CAA’s best available retrofit technology (“BART”) requirements for nine units at six facilities in 

Arkansas. Id. at 18,945-46. It would also impose emission limits based on the Act’s reasonable 

progress requirements for two units at one facility that are not subject to BART. Id. at 18,946. In 

connection with these proposed BART and reasonable progress requirements, the proposed FIP 

would establish new reasonable progress goals (“RPGs”) for the two Class I areas in Arkansas. 

Id. at 18,997-98. The proposed FIP would incorporate its proposed requirements into the longterm strategy (“LTS”) for Arkansas, id. at 18,998, and would include a determination that the 

FIP, in combination with the provisions of Arkansas’s SIP that EPA approved, would address the 

visibility-related interstate transport requirements for Arkansas for the 1997 national ambient air 

 

23 80 Fed. Reg. 24,872 (May 1, 2015). 

24 80 Fed. Reg. 43,661 (July 23, 2015). 
39 

quality standards (“NAAQS”) for ozone and fine particulate matter (“PM2.5”), id. at 18,946, 

18,998. 

Response: We acknowledge the background information provided by UARG. We take no 

position with regard to UARG’s synopsis of our proposed FIP. 

Comment: UARG provides background information on the statutory and regulatory 

regional haze requirements. [UARG (0176) p. 2-4] UARG stated that the CAA’s visibility 

protection provisions establish 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 manmade air pollution.” CAA § 169A(a)(1). The Act directs EPA to 

promulgate regulations designed “to assure ... reasonable progress toward meeting the national 

goal,” id. § 169A(a)(4), and to require each state to submit a SIP that “contain[s] such emission 

limits, schedules of compliance and other measures as may be necessary to make reasonable 

progress toward meeting the national goal,” id. § 169A(b)(2). Under the Act and EPA’s regional 

haze rules, a plan to implement the regional haze requirements has three main elements: (i) 

RPGs, which are visibility goals for each mandatory Class I federal area located in the state, 40 

C.F.R. § 51.308(d)(1) & (2); (ii) an LTS, which is the state’s plan for meeting the RPGs, CAA § 

169A(b)(2)(B); 40 C.F.R. § 51.308(d)(3); and (iii) BART requirements for certain large 

stationary sources, CAA § 169A(b)(2)(A), 40 C.F.R. §51.308(e). 

UARG stated that EPA’s regional haze rules provide that for each mandatory Class I federal area 

in a state, the state must establish goals, expressed in deciviews (“dv”), that “provide for 

reasonable progress towards achieving natural visibility conditions.” 40 C.F.R. § 51.308(d)(1). 

The rules further require that an RPG “provide for an improvement in visibility for the most 

impaired days over the period of the implementation plan and ensure no degradation in visibility 

for the least impaired days over the same period.” Id. To establish an RPG, a state must consider 

four factors: “[1] the costs of compliance, [2] the time necessary for compliance, [3] the energy 

and non-air quality environmental impacts of compliance, and [4] the remaining useful life of 

any potentially affected sources.” Id. § 51.308(d)(1)(i)(A); CAA § 169A(g)(1). A state must 

include in its SIP “a demonstration showing how these factors were taken into consideration in 

selecting the goal.” 40 C.F.R. § 51.308(d)(1)(i)(A). In setting RPGs for a Class I area, a state 

must determine and consider what EPA refers to as the uniform rate of progress (“URP”), which 

is the rate of improvement in visibility, expressed in dv, that would be needed to attain natural 

visibility conditions by the year 2064. Id. § 51.308(d)(1)(i)(B). A state may establish an RPG for 

a Class I area that “provides for a slower rate of improvement in visibility” than the URP for that 

area if the state demonstrates that the URP is not reasonable for that area and that the RPG 

adopted by the state is reasonable. Id. § 51.308(d)(1)(ii). A state makes such a showing by 

evaluating the four reasonable progress factors as they apply to the Class I area. Id. 

UARG stated that EPA’s regional haze rules also direct each state to submit an LTS to address 

regional haze in its Class I areas and in Class I areas in other states that are affected by emissions 

from the state. Id. § 51.308(d)(3). The LTS “must include enforceable emissions limitations, 

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

established by States having mandatory Class I Federal areas.” Id. 
40 

In addition, the regional haze rules describe requirements for BART. States determine and 

require BART for “BART-eligible” sources that are also determined to be “subject to BART” 

because they “may reasonably be anticipated to cause or contribute” to visibility impairment in a 

Class I area. CAA § 169A(b)(2)(A). Determining BART for a specific source requires 

consideration of five factors as they apply to that source. CAA § 169A(g)(2); see 40 C.F.R. § 

51.301 (definition of BART); id. § 51.308(e)(1)(ii)(A). 

Arkansas’s regional haze SIP addressed these requirements, and states are entitled to significant 

deference regarding how to implement them in SIPs. Nevertheless, EPA disapproved significant 

provisions of the SIP and now proposes a FIP to implement EPA’s policy preferences in place of 

those of the state. 

Response: We acknowledge the background information provided by UARG. We take no 

position with regard to UARG’s synopsis of the statutory and regulatory regional haze 

requirements. We address UARG’s comment as to deference elsewhere in our responses to 

comments. 

We disagree that the Regional Haze SIP submitted by Arkansas addressed all the regional haze 

requirements discussed in UARG’s comment. In a final rule published in the Federal Register on 

March 12, 2012, we issued a partial disapproval of the Arkansas Regional Haze SIP.25 Our final 

rule and proposed rule, along with all associated TSDs,26 discussed in detail how the SIP did not 

fully meet the regional haze requirements and explained that we were therefore partially 

disapproving the SIP. Therefore, UARG’s comments contending that the Arkansas Regional 

Haze SIP submitted by Arkansas addressed all the regional haze requirements is outside the 

scope of this rulemaking, as this rulemaking does not take action on the Arkansas Regional Haze 

SIP. Rather, this rulemaking is a regional haze FIP to correct the parts of the Arkansas RH SIP 

we disapproved in 2012. 

Comment: [The Associations (0165) p. 1-2, 10] The American Chemistry Council, American 

Coke and Coal Chemicals Institute, American Farm Bureau Federation, American Forest & 

Paper Association, American Iron and Steel Institute, American Petroleum Institute, American 

Public Power Association, American Wood Council, Arkansas Asphalt Pavement Association, 

Arkansas State Chamber of Commerce, Arkansas Environmental Federation, Arkansas Farm 

Bureau, Arkansas Forest & Paper Council, Arkansas Ready Mixed Concrete Association, 

Associated Industries of Arkansas, Inc., Brick Industry Association, Corn Refiners Association, 

Council of Industrial Boiler Owners, Electricity Consumers Resources Council, Gas Processors 

Association, Industrial Energy Consumers of America, National Association of Manufacturers, 

National Mining Association, National Oilseed Processors Association, and U.S. Chamber of 

Commerce (collectively, “the Associations”)27 stated they appreciate the opportunity to submit 

comments in response to the EPA’s proposed approval of the Arkansas regional haze federal 

implementation plan (“proposed rule”). 

 

25 77 FR 14604. 

26 See 76 FR 64186 and 77 FR 14604. 

27 A description of each Association is included in Appendix A. 
41 

The Associations represent the nation’s leading energy and manufacturing sectors that form the 

backbone of the nation’s industrial ability to grow our economy and provide jobs in an 

environmentally sustainable and energy efficient manner. The Associations’ members include 

electric utilities, manufacturers and energy developers that own or operate facilities directly 

impacted, or could be directly impacted, by the Regional Haze program. In addition to 

generating electricity, many member companies require reliable and affordable electricity for 

manufacturing and industry. The Associations are key and necessary stakeholders in any 

regulation that directly impacts energy providers and which may impact manufacturers directly 

or indirectly in the future. 

As discussed in more detail in the Associations’ comments, the Associations urge EPA to 

withdraw and modify the proposed rulemaking due to numerous deficiencies within it. These 

deficiencies began with the disapproval of Arkansas’ proposed state implementation plan. The 

Associations believe that EPA is failing to provide the deference due to states that Congress 

intended when it passed the Regional Haze statute. This has resulted in too many instances where 

EPA disapproves reasonable state policy determinations and imposes its own policy preferences 

through a federal implementation plan. Key among these flawed policy preferences are EPA’s 

imposition of costly pollution controls at Independence Steam Electric Station (“Independence 

plant”), a source not eligible for Best Available Retrofit Technology (“BART”) review under the 

Clean Air Act, without any rational basis, and multiple errors in the White Bluff Electric Power 

Plant BART analysis. Beyond these specific issues, what most concerns the Associations is that 

the proposed rule evinces a tendency by EPA to deviate from the Clean Air Act, its own 

regulations, and guidance to require exorbitant pollution controls that would achieve, at most, 

negligible visibility benefits. The Clean Air Act’s Regional Haze program envisions gradual 

improvements to Class I area visibility over long periods of time and through cost-effective 

means. Contrary to EPA’s rationale in the proposed rulemaking, it is not a vehicle to further 

accelerate the retirement of coal-fired power plants. Lastly, the Associations object to EPA 

justifying additional emission control measures on modeled visibility improvements that are less 

than CALPUFF’s margin of error. To do so means that EPA has no credible evidence showing 

that visibility improvements would be greater than zero. Such justifications have already been 

struck down by the U.S. Court of Appeals for the Ninth Circuit and the Associations object to 

EPA ignoring that court’s determination in deciding whether additional emission reductions at 

stationary sources would provide any visibility improvements at Class I areas. 

For the reasons discussed in The Associations’ comments, EPA’s proposal to issue a Regional 

Haze Federal 

Implementation Plan for Arkansas is unlawful, arbitrary, and capricious. The Associations urge 

EPA to withdraw the proposed rule and propose a new rule that is consistent with the Clean Air 

Act and EPA’s Regional Haze regulations. 

Response: We acknowledge the background information provided by the commenter. This 

comment summarizes the issues raised by the commenter in more detail elsewhere. Please see 

our responses to those more specific comments in other sections throughout this document. 
42 

Comment: [Conway Corporation et.al. (0172) p. 2-3] Conway Corporation et. al. stated that on 

April 8, 2015, the U.S. Environmental Protection Agency (“EPA”) proposed a Federal 

Implementation Plan (“FIP”) for the State of Arkansas for Regional Haze and Interstate 

Visibility Transport (the “Proposed Rule”).28 Specifically, the proposed rule addresses the 

previously disapproved elements of the Arkansas State Implementation Plan for Regional Haze, 

including certain Best Available Retrofit Technology (“BART”) determinations, Reasonable 

Progress Goals (“RPGs”), and long-term strategy (“LTS”) necessary to achieve established 

RPGs, as well as the interstate visibility transport requirements for pollutants that affect visibility 

in Class I areas in nearby states. Among other requirements, the Proposed Rule includes 

emission limitations based on installation of BART controls for SO2 and NOX at the White Bluff 

Plant (“White Bluff Plant”) and two alternative options for controlling emissions from the 

Independence Plant (“Independence Plant”) under the regional haze reasonable progress 

requirements. 

Conway Corporation is a non-profit corporation that operates the city-owned utility system and 

provides electric, water, wastewater, cable, Internet, and telephone services for the City of 

Conway, Arkansas, a city of about 64,000 residents. Conway Corporation is dedicated to 

producing and delivering safe, affordable, reliable, innovative and environmentally sound utility 

and telecommunication services while enhancing the quality of life of its community. Conway 

Corporation owns 2% of each unit of the Independence Plant and the White Bluff Plant. 

City Water & Light of the City of Jonesboro, Arkansas (“CWL”) is a municipal improvement 

district and consolidated utility district formed by special act of the Arkansas General Assembly 

(Act 251 of 1921). CWL provides electric, water and wastewater services in Jonesboro, Arkansas 

for approximately 72,000 residents. CWL strives to provide safe, reliable, and cost-effective 

services to its customers. Making sound long-term business decisions have supported this 

customer commitment. CWL’s customers made a substantial investment in both the White Bluff 

and Independence Plants to secure their power needs for the future. CWL currently owns 5% of 

each unit of the White Bluff Plant, and 5% and 15% of Units 1 and 2 of the Independence Plant, 

respectively. 

West Memphis Utilities (“WMU”) is a department of the City of West Memphis, Arkansas, a 

city of approximately 28,000 residents. There are about 10,500 residential, and 1,700 

commercial and industrial customers in WMU’s service area, to whom WMU provides electrical, 

water and wastewater services. WMU strives to deliver safe, reliable, environmentally friendly 

utilities at an affordable cost to its ratepayers. WMU currently owns 1% of each unit of the 

Independence and White Bluff Plants. 

Osceola Municipal Light and Power (“OML&P”) is a non-profit division of the city government 

that operates the city-owned utility system and provides electric, water, and wastewater, for the 

City of Osceola, Arkansas, a city of about 8,000 residents. OML&P is committed to delivering 

safe, affordable, reliable, innovative and environmentally sound utility services while enhancing 

the quality of life in the community. OML&P owns 0.5% of each unit of the Independence Plant. 

 

28 See 80 Fed. Reg. 18944 (Apr. 8, 2015). 
43 

Collectively, Conway Corporation, CWL, WMU and OML&P (“Commenters”) are substantial 

co-owners, with others, of the Independence and White Bluff Plants, which are significantly 

affected under the Proposed Rule. As such, the Commenters have a strong interest in the 

reasonable and proper implementation of the regional haze and interstate visibility requirements 

of the Clean Air Act for the protection of their customers. 

Response: We acknowledge the background information provided by the commenter. We take 

no position with respect to the commenter’s synopsis of our proposed FIP. 

Comment: [Conway Corporation et. al. (0172) p. 3-4] Conway Corporation et. al. stated that 

Section 169A of the Clean Air Act establishes a national goal for the prevention of any future, 

and the remedying of any existing man-made impairment of visibility in the nation’s 156 

national parks and wilderness areas designated as mandatory Class I federal areas.2 In 1999, 

EPA promulgated the Regional Haze Rule (“RHR”) to address regional haze impairment and 

establish a comprehensive visibility protection program for Class I areas. The regional haze 

program is designed to reduce man-made visibility impairment over time (i.e. by 2064)4 and in 

sequenced planning periods. The long-term planning recognizes that advancements in 

technology and changes in economic factors will likely provide opportunities for implementing 

new cost-effective control measures to assure reasonable progress and reduce the economic 

burden of rushing to install costly control measures to meet a purely aesthetic standard.5 The 

EPA’s rule requires states, through the state implementation plan (“SIP”) development process, 

to review the statutory factors on a periodic basis and determine appropriate changes to their 

strategies based on that review. 

Conway Corporation et. al. stated that as discussed in their comments, the Proposed Rule is 

unreasonable, arbitrary and capricious and not in accordance with law. Most importantly, the 

Proposed Rule fails to recognize that the visibility improvement at relevant Class I federal areas 

is well ahead of the approved Uniform Rate of Progress (“URP” or “glide path”) necessary to 

maintain and achieve the national visibility goal, and is projected to remain so for more than a 

decade. Accordingly, the Proposed Rule unnecessarily imposes significant costs on Commenters 

and their customers with little or no corresponding visibility benefit. Finally, in developing the 

Proposed Rule, EPA departed from its own guidance and previous regional haze decisions for 

other states. 

For the reasons discussed in Conway Corporation et. al.’s comments, EPA should abandon the 

Proposed Rule’s determinations regarding reasonable progress determinations for the 

Independence Plant and 

NOx BART determinations for Arkansas’ subject-to-BART sources, and prepare a FIP 

consistent with the requirements of the Clean Air Act and EPA’s own regulations. 

Response: We acknowledge the background information provided by the commenter. We take 

no position with respect to the commenter’s synopsis. This comment summarizes the issues 

raised by the commenter in more detail elsewhere. Please see our responses to those more 

specific comments in other sections throughout this document. 
44 

Comment: [Energy and Environmental Alliance of Arkansas (0173) p. 2] EEAA stated that the 

Energy and Environmental Alliance of Arkansas (“EEAA”) is an ad-hoc collaboration of 

Arkansas’ investor-owned, co-operative, municipal, and independent electric utilities and other 

energy companies formed to advocate, communicate and encourage energy and environmental 

policies that promote sound and predictable regulation of Arkansas’ utility industry, and support 

an economically viable and environmentally secure future for all Arkansans, including access to 

reliable and affordable energy resources.29 Many of EEAA’s members are co-owners of the 

affected units under the Proposed Rule. EEAA and its members therefore have a strong interest 

in the appropriate and coherent implementation of the regional haze program in the most 

economical and reasonable means possible for the benefit of their customers. For the reasons 

explained herein, EEAA believes that the Proposed Rule is arbitrary and capricious in that it is 

inconsistent with EPA’s previous guidance, regulations, and determinations concerning visibility 

protection and imposes significant unnecessary and unjustified costs on Arkansas’ utilities 

providers and their customers. 

EEAA stated that on April 8, 2015, the EPA published a proposed rule for the State of Arkansas 

for Regional Haze and Interstate Visibility Transport (hereinafter, the “Proposed Rule”) 

promulgating a Federal Implementation Plan (“FIP”) to address those portions of Arkansas’ 

regional haze State Implementation Plan (“SIP”) that were disapproved on March 12, 2012.30 

The Proposed Rule includes Best Available Retrofit Technology (“BART”) determinations for 

sulfur dioxide (“SO2”), nitrogen oxides (“NOx”) and particulate matter (“PM”) impacting nine 

units at six facilities in Arkansas,31 and two proposed alternative options for controlling 

emissions from the Entergy Independence Plant (“Independence Plant”) under the regional haze 

reasonable progress requirements. 

Response: We acknowledge the background information provided by the commenter. This 

comment summarizes the issues raised by the commenter in more detail elsewhere. Please see 

our responses to those more specific comments. 

We take no position with respect to the commenter’s synopsis of our proposed FIP.

 

Comment: [Energy and Environmental Alliance of Arkansas (0173), p. 3-4] EEAA stated that 

EPA’s Proposed Rule is replete with legal and factual errors that vastly underestimate the cost 

and cost effectiveness of the proposed emissions controls and simultaneously overestimate the 

necessity and benefit of the controls for maintaining reasonable progress towards the national 

visibility goal. This has the combined effect of imposing hundreds of millions of dollars of 

unnecessary expense on Arkansas’ utilities and their customers. As discussed elsewhere, the 

Proposed Rule is inconsistent with EPA’s own guidance and the regional haze determinations for 

 

29 The members of EEAA are: AEP/Southwestern Electric Power Company (“AEP/SWEPCO”), Arkansas Electric 

Cooperative Corporation (“AECC”), Arkansas Municipal Power Association, Conway Corporation, Empire District 

Electric Company, Entergy Arkansas, Inc. (“Entergy”), Jonesboro City Water & Light, North Little Rock Electric, 

Oklahoma Gas & Electric Company, Plum Point Services Company, LLC, and West Memphis Utility Commission. 30 See 80 Fed. Reg. 18944 (April 8, 2015). 31 The subject-to-BART facilities include AECC Carl E. Bailey and John L. McClellan Generating Stations; AEP 

Flint Creek Power Plant; and Entergy White Bluff and Lake Catherine Plants. Id.
45 

other states, and it fails to account for Arkansas’ current progress towards the national visibility 

goal and the visibility benefits resulting from other programs such as the Cross-State Air 

Pollution Rule (“CSAPR”). The errors and inconsistencies that infect EPA’s BART and 

reasonable progress determinations render the Proposed Rule arbitrary and capricious. As such, 

EPA should abandon the approach and analysis utilized in the Proposed Rule and instead prepare 

a FIP in accordance with the requirements of the Clean Air Act and EPA’s own guidance. 

Response: This comment summarizes the issues raised by the commenter in more detail 

elsewhere. Please see our responses to those more specific comments. 

Comment: [Edison Electric Institute (0174) p. i-2] EEI stated that it appreciates the opportunity 

to submit comments on the proposed Promulgation of Air Quality Implementation Plans for the 

state of Arkansas by the EPA in Docket No. EP A-R06-0AR-2015-0189, 80 Fed. Reg. 18,944 

(Apr. 8, 2015) and 80 Fed. Reg. 24,872 (May 1, 2015). EPA proposes to promulgate 

a Federal Implementation Plan (FIP) for Arkansas to address the requirements of the Regional 

Haze Rule (RHR) and address interstate visibility transport requirements for portions of 

Arkansas’ State Implementation Plan (SIP) that EPA disapproved in a prior action. See id. 

EEI is the association that represents all U.S. investor-owned electric utilities, international 

affiliates and industry associates worldwide. EEI members provide electricity for 220 million 

Americans, operate in all 50 states and the District of Columbia, and directly employ more than 

500,000 workers. With more than $90 billion in annual capital expenditures, the electric power 

industry is responsible for millions of jobs outside our direct operations. Reliable, affordable and 

sustainable electricity powers the economy and enhances the lives of all Americans. As 

generators of electricity and operators of the nation's electric transmission and distribution 

system, EEI's member companies have a strong interest in any proposed rule that potentially 

impacts the industry and the ongoing transition of the domestic fleet. 

EEI member companies operate facilities directly affected by the Agency's proposed action. As 

part of the ongoing transition to cleaner sources of generation, the electric power sector 

generally-and Arkansas electricity generators in particular- have cut emissions significantly in 

recent years and will continue to do so under many recently finalized EPA regulations, even 

without the regional haze Federal Implementation Plan (FIP) proposed by EPA for Arkansas. 

EEI is filing comments to ensure that the Agency allows states to determine how best to consider 

additional controls, consistent with effective long-term utility planning toward the linked goals 

of reliable, affordable and increasingly clean electric power. EEI also offers a number of specific 

comments regarding the proposed FIP, and urges the Agency to consider the technical comments 

of both Entergy and Southwestern Electric Power Company regarding unit-specific and other 

technical and legal concerns. EEI looks forward to continued dialogue with Agency officials on 

this important rulemaking. 

Response: We acknowledge the background information provided by the commenter. As to 

comments that are generally raised here (i.e. proposed FIP comments of Entergy and Electric 

Power Co.), we address those in other sections throughout this document. 
46 

Comment: [Arkansas Electric Energy Consumers Inc. and Arkansas Gas Consumers Inc. (0175) 

p. 1-2] AEEC and AGC stated that they are submitting comments in response to the EPA’s 

“Promulgation of Air Quality Implementation Plans; State of Arkansas; Regional Haze and 

Interstate Visibility Transport Federal Implementation Plan; Proposed Rule” in Docket No. EPAR06-OAR-2015-189, published at 80 Fed. Reg. 18944 on April 8, 2015 (the “Proposed FIP”).32

AEEC and AGC are non-profit corporations organized under the laws of the State of Arkansas 

for the purpose of ensuring just and reasonable utility policies and energy rates in the State of 

Arkansas. The members of AEEC and AGC collectively employ thousands of Arkansans 

through their engagement in energy- intensive industries such as primary metals manufacturing, 

chemical production, brick manufacturing, food processing, refining, and wood products 

manufacturing. The members of AEEC purchase electricity from Entergy Arkansas, Inc. 

(“EAI”). EAI is either an owner or co-owner of certain power plants regulated by the Proposed 

FIP. Since the cost of electricity constitutes a major component of the cost of manufacturing the 

products created by the members of AEEC and AGC, the costs of the various control 

technologies required under the Proposed FIP will injure the members of AEEC and AGC by 

increasing the cost33 of the electricity (and likely natural gas)34 needed to operate their facilities. 

Response: We acknowledge the background information provided by the commenters. We also 

acknowledge the commenters’ concerns. Specific issues raised by the commenter are addressed 

by us elsewhere in this document. Please see our responses to those more specific comments. 

Comment: Summary of the history of the regional haze program. [Sierra Club et. al. (0171) 

p. 2-3] Sierra Club et. al. stated that since the nation’s founding, the United States has valued its 

diverse and stunning natural scenery. See, e.g., John Copeland Nagle, The Scenic Protections of 

the Clean Air Act, 87 N.D. L. Rev. 571, 576 (2011). In what has been lauded as “America’s best 

idea,” Congress first set aside national parks in the 19th century to preserve and celebrate some 

of the nation’s most spectacular scenery. Id. With the nation’s rapid industrialization, however, 

these remarkable scenic views became increasingly marred by air pollution. See id. at 573. 

Today, air pollution is “perhaps the greatest threat to national parks,” and pollution all too often 

degrades visibility in these iconic scenic areas. Id.

 

32 These comments are timely filed. On July 23, 2015, at 80 Fed. Reg. 43661, the EPA published notice that it would 

re-open the comment period in this docket until August 7, 2015. 

33 Act 310 of 1980, as amended, which has been codified at Arkansas Code Annotated sections 23-4-501 et seq., 

allows an Arkansas utility to immediately recover expenditures incurred as a result of regulatory requirements 

relating to the protection of the environment by imposing a surcharge on its customers. See McDaniel v. Arkansas 

Public Service Commission et al., 2014 Ark. App. 529 (Ark. App. 2014). 34 Since the enormous costs of implementing the controls required by the Proposed FIP will necessarily render 

certain coal-fired power plants less economic, the proposed FIP will increase demand for natural gas, thereby 

placing significant upward pressure on natural gas commodity and transportation prices. Thus, the proposed FIP will 

injure the members of AGC. See Energy Ventures Analysis, Inc., EPA Clean Power Plan: Costs and Impacts on 

U.S. Energy Markets, at 20 (October 2014), http://www.countoncoal.org/assets/Executive-Summary-EPA-CleanPower-Plan-Costs-Impacts.pdf. 
47 

Recognizing the “intrinsic beauty and historical and archaeological treasures” of the national 

parks and wilderness areas,35 Congress established “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 manmade air pollution.” 42 U.S.C. § 7491(a)(1). In 

1990, after finding that the EPA and the states had not made adequate progress toward reducing 

visibility impairment in the nation’s Class I areas,36 Congress amended the Clean Air Act 

(“CAA” or “the Act”) to curb emissions that may reasonably be anticipated to cause or 

contribute to visibility impairment at national parks and wilderness areas. Id. § 7492. 

Congress delegated implementation of the Clean Air Act’s visibility program to EPA. In 1999, 

EPA promulgated the Regional Haze Rule, which requires the states (or EPA where a state fails 

to act) to make incremental, “reasonable progress” toward eliminating human-caused visibility 

impairment at each Class I area by 2064. 64 Fed. Reg. 35,714, 35,746 (July 1, 1999), codified at 

40 C.F.R. § 51.308(d)(1), (d)(3). In the 1999 regulations, EPA recognized that visibility 

impairing pollution was a regional problem that required regional solutions; the regulations 

create the necessary region-wide scheme to restore Class I areas to natural conditions. 

In order to achieve the goal of natural visibility in Class I areas, implementation plans must 

contain “emission limits, schedules of compliance and other measures as may be necessary to 

make reasonable progress toward meeting the national goal.” 42 U.S.C. § 7491(b)(2). The 

Regional Haze Rule includes several interlocking measures designed to make “reasonable 

progress” towards achieving the 2064 natural visibility goal. These measures include 

requirements to (1) develop reasonable progress goals based on the evaluation of any and all 

sources contributing to visibility impairment; (2) create a long-term strategy for achieving the 

reasonable progress goals; and (3) require installation and operation of the best available retrofit 

technology (“BART”) for some of the oldest and dirtiest sources of haze-causing pollutants. Id.; 

40 C.F.R. § 51.308(d), (e). 

Response: We acknowledge the background information provided by the commenter. We take 

no position with respect to the commenter’s synopsis. 

Comment: Summary of the statutory and regulatory requirements associated with RPGs.

[Sierra Club et. al. (0171) p. 3] Sierra Club et. al. stated that one of the main features of the 

Regional Haze Rule is the establishment of “goals (expressed in deciviews)37 that provide for 

reasonable progress towards achieving natural visibility conditions.” 40 C.F.R. § 51.308(d)(1). In 

developing these “reasonable progress goals” and the emission reductions needed to meet them, 

the state must consider four factors: (1) the costs of compliance, (2) the time necessary for 

compliance, (3) the energy and non-air quality environmental impacts of compliance, and (4) the 

remaining useful life of any potentially affected sources. 42 U.S.C. § 7491(g)(1); 40 C.F.R. § 

 

35 H.R. Rep. No. 95-294, at 203-04 (1977), reprinted in 1977 U.S.C.C.A.N 1077, 1282. 36 Areas designated as mandatory Class I Federal areas (or Class I for short) consist of national parks exceeding 

6,000 acres, national wilderness areas and national memorial parks exceeding 5,000 acres, and all international parks 

that were in existence on August 7, 1977. See 42 U.S.C. § 7472(a). 37 A deciview is a measurement of visibility impairment. A deciview is a haze index derived from calculated light 

extinction, such that uniform changes in haziness correspond to uniform incremental changes in perception across 

the entire range of conditions, from pristine to highly impaired. 40 C.F.R. § 51.301. 
48 

51.308(d)(1)(i)(A). In contrast to the definition of best available retrofit technology (“BART”), 

the statute does not list visibility improvement as a fifth factor in the reasonable progress 

analysis. Compare 42 U.S.C. § 7491(g)(1) with id. § 7491(g)(2). 

For each Class I area within its borders, a state must determine the uniform rate of progress 

(“URP”), which is the amount of progress that, if kept constant each year, would ensure that 

natural visibility conditions are achieved in 2064. See 40 C.F.R. § 51.308(d)(1)(i)(B). If a state 

selects a reasonable progress goal that achieves a slower rate of progress than the URP, the state 

must demonstrate, based on the four reasonable progress factors, “that the rate of progress for the 

implementation plan to attain natural conditions by 2064 is not reasonable; and that the progress 

goal adopted by the State is reasonable.” Id. § 51.308(d)(1)(ii). 

Response: We acknowledge the background information provided by the commenter. We take 

no position with respect to the Sierra Club et. al synopsis of the statutory and regulatory 

requirements associated with the RPGs. We address elsewhere in this document comments 

contending that the statute does not list visibility improvement as a fifth factor in the reasonable 

progress analysis. 

Comment: Summary of the long-term strategy requirements. [Sierra Club et. al. (0171) p. 4] 

Sierra Club et. al. stated that a regional haze implementation plan must include, among other 

things, emission limits, schedules of compliance, and any other measures necessary to achieve 

the reasonable progress goals—this collection of enforceable measures is called the long-term 

strategy. 40 C.F.R. §51.308(d)(3)(ii). Given the statutory goal to eliminate all haze caused by 

“manmade air pollution,” 42 U.S.C. § 7491(a)(1), states must consider all air pollution sources 

that contribute to impairment in Class I areas. In developing a long-term strategy, a state must 

look beyond major stationary sources to area, mobile, and minor sources, id. § 51.308(d)(3)(iv), 

as well as a number of other sources of impairment such as construction, agricultural, and 

forestry practices. Id. § 51.308(d)(3)(v). The long-term strategy must achieve reasonable 

progress for both the Class I areas within a state’s borders as well as the out-of-state areas 

affected by the state’s emissions. Id. § 51.308(d)(3). To ensure that each state does its part to 

address regional haze, a state that contributes to impairment at another state’s Class I area must 

consult with the state that is home to the Class I area. Id. § 51.308(d)(3)(i). 

Consultation proceeds based in part on analyses of how much impairment at a given Class I area 

is due to emissions from each state. Each state then must document the technical basis by which 

it determines its share of the emissions reductions necessary to make reasonable progress at a 

Class I area. Id. § 51.308(d)(3)(iii). After fulfilling the procedural requirements for consultation, 

a state must ensure that its haze plan satisfies the primary substantive requirement for a long term 

strategy: to include the enforceable measures necessary to meet the reasonable progress goals for 

each Class I area affected by the state’s emissions. Id. § 51.308(d)(3). In determining whether 

each state’s haze plan satisfies the statutory mandate to make reasonable progress, EPA reviews 

whether the state followed the consultation requirements set forth in 40 C.F.R. § 51.308(d)(3)(i) 

and reasonably considered the four statutory factors for reasonable progress. 40 C.F.R. § 

51.308(d)(1)(iii). 
49 

Response: We acknowledge the background information provided by the commenter. We take 

no position with respect to the Sierra Club et. al. synopsis. 

Comment: Summary of the BART requirements. [Sierra Club et. al. (0171) p. 4-5] Sierra 

Club et. al., stated that BART controls are one element of making progress towards the natural 

visibility goal. BART controls are required at fossil fuel-fired power plants and other major 

stationary sources that “may reasonably be anticipated to cause or contribute to any impairment 

of visibility in any such [mandatory Class I Federal] area,” and were in existence in 1977, but 

were not in operation before 1962. 42 U.S.C. § 7491(b)(2)(A); see 40 C.F.R. § 51.308(e). The 

term “major stationary source” is defined to include any source that has the potential to emit 250 

tons per year or more of any pollutant, and falls within one of 26 categories of industrial sources 

defined by the Act. 42 U.S.C. § 7491(g)(7). BART is defined as “an emission limitation based on 

the degree of reduction achievable through the application of the best system of continuous 

emission reduction for each pollutant which is emitted by an existing stationary facility.” 40 

C.F.R. § 51.301 (emphasis added). 

When determining BART, the states and EPA must analyze “the best system of continuous 

emission control technology available” by taking into consideration five factors: (1) the costs of 

compliance, (2) the energy and non-air quality environmental impacts of compliance, (3) existing 

pollution controls at the source, (4) the remaining useful life of the source, and (5) the degree of 

visibility improvement from pollution controls. Id. § 51.308(e)(1)(ii)(A). BART is an essential 

component of the regional haze program because Congress largely grandfathered these 

antiquated sources into many of the Clean Air Act’s other requirements. See 70 Fed. Reg. 

39,104, 39,111 (July 6, 2005). BART compels these older, disproportionately-polluting sources 

to install up-to-date and cost-effective pollution controls. 

BART is a mandatory measure that must be implemented as part of a plan to achieve reasonable 

progress toward restoration of natural visibility conditions. The Clean Air Act expressly requires 

states to adopt SIPs that contain “emission limits, schedules of compliance and other measures as 

may be necessary to make reasonable progress toward meeting the national goal . . . including” 

the installation and operation of BART at eligible sources that emit any air pollutant which may 

reasonably be anticipated to cause or contribute to visibility impairment in any Class I area. 42 

U.S.C. § 7491(b)(2) (emphasis added), § 7491 (b)(2)(A). The only permissible exemption from 

BART is when EPA, by rule promulgated with sufficient notice and opportunity for public 

comment, determines that (1) the source does not “by itself or in combination with other 

sources” cause or contribute to significant visibility impairment at a Class I area; (2) if the power 

plant has a design capacity of 750 megawatts or greater, the owner or operator must demonstrate 

to EPA that the plant is located at such a distance from all Class I areas that it does not “by itself 

or in combination with other sources” emit pollution that may reasonably be anticipated to cause 

or contribute to significant visibility impairment at a Class I area; and (3) the affected Federal 

Land Managers concur with the BART exemption. Id. §7491(c).38 No such determination has 

 

38 See also 40 C.F.R. § 51.308(e) (requiring BART for each eligible source “that may reasonably be anticipated to 

cause or contribute to any impairment of visibility in any mandatory Class I Federal area, unless the State 

demonstrates that an emissions trading program or other alternative will achieve greater reasonable progress toward 

natural visibility conditions.”). 
50 

been proposed or made here, nor could it be given the significant visibility impacts that the Flint 

Creek, Lake Catherine, and White Bluff facilities have on Class I Areas in Arkansas and 

Missouri. 

Response: We acknowledge the background information provided by the commenter. We take 

no position with respect to the commenter’s synopsis.

Comment: Discussion of the Class I areas affected by emissions from Arkansas sources.

[Sierra Club et. al. (0171) p. 7-8] Sierra Club et. al. stated that in finalizing the proposed FIP for 

Arkansas, EPA has a unique opportunity—and an obligation—to improve air quality in multiple 

states, including Arkansas and Missouri. Emissions from Arkansas sources impact two in-state 

Class I areas: Caney Creek Wilderness Area and Upper Buffalo Wilderness Area. Both 

wilderness areas are located in northwestern Arkansas and offer beautiful hiking opportunities, 

natural landscapes, and varied scenery. 

Caney Creek Wilderness straddles two different sections of the Ouachita Mountains in western 

Arkansas. The Fourche Mountain subsection is characterized by “deep slices [carved by streams] 

out of the ridges” and areas of “large rock flows” and “sandstone bluffs.”39 The Central 

Ouachita Mountains subsection is “richest in terms of plant community diversity” with “seeps 

and springs” supporting “stands of American beech and umbrella magnolia in coves, on northfacing slopes, and on stream terraces.”40 Over seventeen miles of hiking trails wind through the 

area and ambitious hikers can climb to the top of several mountains for views of the surrounding 

peaks.41

The Upper Buffalo Wilderness Area in the Ozark Mountains provides visitors the opportunity to 

“be among the headwaters of the extraordinarily pretty Buffalo National River, which flows 

down the center of this Wilderness through a rough forested land of steep slopes that descend 

into deep valleys.”42 The Whitaker Point Trail winds its way to the top of Hawksbill Crag,43 a 

scenic rocky outcropping which is one of the most photographed places in Arkansas.44

Air pollution from Arkansas sources mars the unique scenery outside of the state too, including 

in Missouri’s Hercules Glades Wilderness and Mingo National Wildlife Refuge. The Hercules 

Glades Wilderness spans 12,413 acres of some of the “most scenic and unique country in the 

Midwest” with “[i]ts combination of open grassland, forested knobs, steep rocky hillsides, and 

 

39 “Wilderness Stewardship Challenge: Air Quality Values Monitoring Plan for Ouachita National Forest, Arkansas 

And Oklahoma,” p. 17 (Sep. 30, 2009) available at:

http://www.fs.usda.gov/Internet/FSE_DOCUMENTS/stelprd3811710.pdf. 40 Id. 41 “Caney Creek Wilderness Trails,” available at: 

http://www.fs.usda.gov/Internet/FSE_DOCUMENTS/fsm9_039458.pdf. 42 “Upper Buffalo Wilderness,” Wilderness.net, available at: 

http://www.wilderness.net/NWPS/wildView?WID=621&tab=General (last visited July 8, 2015). 43 “Upper Buffalo Wilderness Area,” available at: 

http://www.fs.usda.gov/recarea/osfnf/recreation/camping-cabins/recarea/?recid=43499&actid=34 44 “Adventure Arkansas: Hawksbill Crag,” available at: 

http://5newsonline.com/2014/05/24/adventure-arkansas-hawksbill-crag/ 
51 

narrow drainages offers unusual beauty.”45 The area contains 32 miles of maintained trails for 

visitors to explore.46 

The 21,592-acre Mingo National Wildlife Refuge “provide[s] food and shelter for migratory 

waterfowl and . . . protect[s] the bottomland hardwood forest,” while providing enjoyment for 

people visiting.47 Along with migratory waterfowl, the refuge is also a wintering ground for bald 

eagles.48 People travel to the Mingo National Wildlife Refuge for hiking, birding, canoeing, and 

kayaking opportunities.49

Response: We acknowledge the background information provided by the commenter.

Comment: A handful of point sources emit the overwhelming majority of haze-causing 

pollutants in Arkansas. [Sierra Club et. al. (0171) p. 8-9] Sierra Club et. al. stated that a handful 

of point sources, mostly electric generating units (“EGUs”), emit the overwhelming majority of 

haze-causing pollutants in Arkansas. Of these pollutants, sulfates and nitrates contribute most 

significantly to the visibility problem in Arkansas’s Class I areas.50 Three EGUs—the Flint 

Creek, Independence, and White Bluff power plants—emitted approximately 84% of Arkansas 

SO2 point-source emissions and 55% of state-wide NOx point source emissions in 2011. 80 Fed. 

Reg. at 18,991. In 2011, Arkansas EGUs accounted for 78.4% of Arkansas’s total SO2 emissions 

(i.e., emissions from both point and non-point sources).51

Flint Creek Unit 1 is a 558 megawatt (“MW”) coal-fired electric generating station that burns 

mostly western subbituminous low-sulfur coal and is operated by Southwestern Electric Power 

Company (a subsidiary of American Electric Power (“AEP”)). Flint Creek currently has no postcombustion SO2 controls. Early generation low-NOx burners have been installed and an 

electrostatic precipitator (“ESP”) is installed to control particulate matter. According to 

emissions data in EPA’s Clean Air Markets Database, in 2011, Flint Creek was the third-largest 

point source of emissions of both SO2 (8,620 tons) and NOx (5,326 tons) in the state. 80 Fed. 

Reg. at 18,991, Table 59. Flint Creek contributes significantly to visibility impairment at all four 

Class I areas modeled by EPA, with the largest impacts at Upper Buffalo (98th percentile 

impairment of .965 dvs) and Caney Creek Wilderness Areas (98th percentile impairment of 

0.963 dvs). See 80 Fed. Reg. at 18,965, Table 25. 

Lake Catherine Unit 4 is a 558 MW electric generating station operated by Entergy. The unit is 

currently permitted to burn natural gas and No. 6 fuel oil, but it has not burned fuel oil for over a 

 

45 “Hercules Glades Wilderness,” available at: 

http://www.fs.usda.gov/recarea/mtnf/recreation/recarea/?recid=21754&actid=51 46 Id. 47 “Mingo National Wildlife Refuge,” U.S. Fish and Wildlife Service available at: 

http://www.fws.gov/uploadedFiles/Mingobrochure(3).pdf. 48 Id. 49 Id. 50 ADEQ, “State Implementation Plan Review for the Five-Year Regional Haze Progress 

Report,” Revised May 2015, at 17, Figure 2.2, available at: 

http://www.adeq.state.ar.us/air/planning/pdfs/ar_5yr_prog_rep_review-final-6-2-2015.pdf. 51 Id. at 18, Figure 2.3.
52 

decade. 80 Fed. Reg. at 18,975. Lake Catherine Unit 4 contributes significantly to visibility 

impairment at all four Class I areas modeled by EPA, with the largest impacts at Caney 

Creek Wilderness Area (98th percentile impairment of 1.371 dvs). See 80 Fed. Reg. at 18,976, 

Table 40. 

The Independence plant is a 1,800 MW coal-fired electric generating station operated by 

Entergy. The plant consists of two nearly identical 900 MW units which burn subbituminous 

coal. The Independents units began operation in 1983 and 1984, respectively, and as such are not 

BART eligible. The Independence units currently have no SO2 or NOx controls. The units are 

equipped with ESPs to control PM emissions. According to emissions data in EPA’s Clean Air 

Markets Database, in 2011, the Independence plant was the second-largest point source of both 

SO2 (30,398 tons) and NOx (13,411 tons) emissions in the state. 80 Fed. Reg. at 18,991, Table 

59. The Independence plant contributes significantly to visibility impairment at all four Class I 

areas modeled by EPA, with the largest impacts at Caney Creek Wilderness Area (98th percentile 

impairment of 2.412 dvs), Upper Buffalo Wilderness Area (98th percentile impairment of 1.764 

dvs), and Mingo National Wildlife Refuge (98th percentile impairment of 1.704 dvs). 

The White Bluff plant is a 1,700 MW coal-fired electric generating facility operated by Entergy. 

The plant consists of two nearly identical 850 MW tangentially fired boilers that burn 

subbituminous coal. 80 Fed. Reg. at 18,969. White Bluff Units 1 and 2 currently have no SO2 or 

NOx controls, but are equipped with ESPs to control PM emissions. According to emissions data 

in EPA’s Clean Air Markets Database, in 2011, the White Bluff plant was the largest point 

source of emissions of both SO2 (31,684 tons) and NOx (16,013 tons) emissions in the state. 80 

Fed. Reg. at 18,991, Table 59. White Bluff Units 1 and 2 contribute significantly to visibility 

impairment at all four Class I areas modeled by EPA, with the largest impacts at Caney Creek 

Wilderness Area (98th percentile impairment of 3.323 dvs), Upper Buffalo Wilderness Area 

(98th percentile impairment of 2.325 dvs), and Hercules-Glades Wilderness Area (98th percentile 

impairment of 2.101 dvs). See 80 Fed. Reg. at 18,970, Table 31. 

Response: We acknowledge the background information provided by the commenter. We take 

no position with respect to the commenter’s synopsis of our proposed FIP.

2. Entergy’s Proposed Strategy for White Bluff and Independence 

Comment: Since Entergy proposes to cease coal-fired operations at White Bluff by 2028 as 

part of a long-term, multi-unit Regional Haze Plan, EPA must take the remaining useful 

life of the White Bluff units into account in the BART analysis. 

[Entergy Arkansas Inc. (0149) p. 5-6, 13-14] Entergy Arkansas Inc. (Entergy) stated that EPA’s 

proposed BART determination for White Bluff appears to be based, in general, on the White 

Bluff five-factor BART analysis that Entergy provided to ADEQ in October 2013 (“Revised 

White Bluff BART Analysis”),52 which assumed White Bluff Units 1 and 2 would continue to 

 

52 Revised BART Five Factor Analysis, White Bluff Steam Electric Station (Oct. 2013), EPA Docket ID EPA-R06- 

OAR-2015-0189-0045. See 80 Fed. Reg. at 18,969-75. However, Entergy is confused by EPA’s references in the 

Proposal to AEP’s modeling and assumptions with respect to the BART analysis for White Bluff. See id. at 18,969. 
53 

combust coal for the foreseeable future. However, as part of a multi-unit plan to improve 

visibility and to better manage its generation assets for reliability and costs, Entergy proposes to 

cease burning coal at White Bluff Units 1 and 2 by 2027 and 2028, one unit per year, and is 

prepared to take an enforceable commitment to that effect. As a result of Entergy’s proposal, 

EPA’s proposed BART determination for White Bluff Units 1 and 2 has been rendered 

inapplicable. Entergy’s proposal for White Bluff requires EPA to undertake a new BART 

analysis to address the now reduced remaining useful coal-fired life of the units. In addition, 

EPA used outdated costs in its BART analysis, improperly eliminated millions of dollars in costs 

necessary to install controls on White Bluff, and did not consider site-specific factors that will 

affect the cost calculation. When the appropriate dry scrubber costs are considered along with the 

units’ remaining useful coal-fired life, the average cost-effectiveness of dry FGD increases to a 

range of over $7,500 to $8,500 per ton at the White Bluff units, costs that are far too high to 

constitute BART. 

Entergy stated that the CAA and EPA regulations dictate that EPA and states consider the 

remaining useful life of a source in BART determinations, which factors into the cost of 

compliance in the BART analysis. 42 U.S.C. § 7491(g)(2); 40 C.F.R. § 51.308(e)(1)(ii)(A). 

EPA’s guidance provides a specific time period for amortization of the costs of controls where a 

unit’s remaining useful life is limited.53 

If the remaining useful life exceeds the amortization period, then the remaining 

useful life has essentially no effect on the control costs and on the BART 

determination process. Where the remaining useful life is less than the time period 

for amortizing costs, [EPA advises] us[ing] this shorter time period in [the BART] 

cost calculations. 

Entergy stated that BART controls that may be cost-effective using the standard amortization 

period (typically 20-30 years) may no longer be cost effective when a source’s remaining useful 

life is factored into the analysis. See 79 Fed. Reg. 74,818, 74,837 (Dec. 16, 2014) (“Proposed 

Texas Regional Haze FIP”) (“[CENRAP] noted that for sources with a relatively short remaining 

useful life, this consideration would have weighed more heavily against a determination that 

controlling those sources would have been reasonable.”). 

Entergy stated that EPA determined that remaining useful life was not a meaningful factor for 

White Bluff given Entergy’s previous plans to continue coal-fired operation at White Bluff. See 

80 Fed. Reg. at 18,971, Tables 34 and 35 (using 30 years and the life of the equipment); 

Technical Support Document for the SDA Control Cost Analysis for the Entergy White Bluff 

and Independence Facilities Arkansas Regional Haze Federal Implementation Plan (SO2 Cost 

TSD), at 16 (“we typically assume a 30 year equipment life for scrubbers, as we do here.”). As a 

result, EPA concluded that dry scrubbers on White Bluff would have an average costeffectiveness at Unit 1 of $2,227/ton and at Unit 2 of $2,101/ton. 80 Fed. Reg. at 18,971, Table 

 

The references to AEP make it unclear whether EPA actually used Entergy’s Revised White Bluff BART Analysis 

in evaluating the BART controls for White Bluff. EPA needs to confirm that it reviewed and analyzed Entergy’s 

Revised White Bluff BART Analysis. 

53 Guidelines for BART Determinations Under the Regional Haze Rule, 40 C.F.R. Part 51, App. Y, 

Section IV.D.4.k (“BART Guidelines”).
54 

32. These cost estimates were based on a 30-year amortization period for the controls, an 

amortization period that is consistent with EPA’s Control Cost Manual when a unit’s remaining 

useful life is not limited. EPA Air Pollution Control Cost Manual (Jan. 2002) (“Control Cost 

Manual”).54 Now, however, given Entergy’s proposed commitment to cease coal-fired operation 

at White Bluff by 2027-2028, EPA will need to revise its BART analysis to take the remaining 

useful life of the units into account. The CAA requires that BART controls be installed “as 

expeditiously as practicable,” but no later than five years from approval of a regional haze SIP or 

the issuance of a FIP. 42 U.S.C. § 7491(b)(2)(A), (g)(4); 40 C.F.R. § 51.308(e)(1)(iv). In this 

case, EPA has stated that it is unable to finalize the FIP until after December 15, 2015,55 which 

means that any final FIP cannot have an effective date earlier than sometime in 2016. Thus, the 

scrubbers would be installed and operational, at the earliest, in 2021.56

Entergy stated that in addition to its plan to cease combusting coal at White Bluff by 2028, 

Entergy proposes to meet interim SO2 emission rate reductions prior to 2028 through a reduction 

in the permitted SO2 emission rates for White Bluff Units 1 and 2 and Independence Units 1 and 

2. The units currently have a permitted 3-hour average SO2 limit of 1.2 lb/MMBtu. Entergy 

proposes to lower this limit to a rolling 30-day average limit of 0.6 lb/MMBtu beginning in 2018. 

NOX BART for all EGUs in Arkansas, should be compliance with CSAPR given that EPA 

already has determined that CSAPR is better than BART. 77 Fed. Reg. 33,642 (June 7, 2012). 

However, in the event EPA continues to require Arkansas’ EGUs to meet source-specific NOX

BART limits in the final FIP, Entergy proposes that the four units at White Bluff and 

Independence meet a rolling 30-boiler operating day average NOX limit of 1,342.5 lb NOX/hr. 

This limit is based on the installation of LNB/SOFA and Entergy would be prepared to meet this 

limit no later than three years from the effective date of the final rule.57 See 79 Fed. Reg. at 

18,974-75. Although the cost-effectiveness of installing LNB/SOFA would significantly 

decrease as a result of a revised remaining useful life analysis for the White Bluff units, if EPA 

does not adopt its CSAPR equals BART approach for Arkansas, Entergy is prepared to install 

these controls as part of its comprehensive visibility improvement proposal. 

Entergy stated that this combination of CSAPR compliance or, in the alternative, LNB/SOFA 

installation, and acceptance of a lower SO2 emission rate through the remaining useful coal-fired 

life of the White Bluff units should be determined to be BART for White Bluff. No additional 

 

54 The Control Cost Manual is available at http://www.epa.gov/ttncatc1/dir1/c_allchs.pdf 55 EPA’s Response to Letter/Order (Dkt. No. 52) at 2, Sierra Club v. McCarthy, No. 14-cv-00643 (Jul. 15, 2015 

E.D.Ark.).

56 EPA has proposed to allow White Bluff the full five years to install the scrubbers and meet the BART SO2

emission limits. 80 Fed. Reg. at 18,973. Entergy agrees with EPA that such major emissions control technology 

could not be designed, contracted for, and installed any earlier than five years from the effective date of the final 

regional haze FIP. 

57 This limit is different from the limit that Entergy proposed as NOX BART in its Revised White Bluff BART 

Analysis. The revised limit is necessary due to the changed operating conditions at White Bluff over the past few 

years. The plant is now economically dispatched through the Midcontinent Independent System Operator (MISO) 

and is spending greater amounts of time at lower load than it did in 2013, when the Revised White Bluff BART 

Analysis was submitted to ADEQ, and in prior years. The emissions guarantee that Entergy received from Foster 

Wheeler, the vendor that Entergy has selected to supply the NOX control technology, only applies to loads of 50% of 

capacity or greater. Therefore, a revised limit is necessary to ensure that the White Bluff units can comply with the 

NOX limit at the lower loads that have become a more common operating condition for the units. 
55 

controls are justified given Entergy’s proposal to limit the number of years of coal-fired 

operation at White Bluff. 

[Conway Corporation et. al. (0172) p. 13, 14, and EEAA (0173) p. 6, 8] Conway Corporation et. 

al. and EEAA both stated that EPA’s proposed FIP fails to properly account for the remaining 

useful life of the White Bluff Plant, which renders EPA’s cost analysis useless for assessing the 

real costs of the proposed controls for them and their customers. 

Conway Corporation et. al. and EEAA stated that the CAA and EPA regulations dictate that EPA 

and states consider the remaining useful life of a source in BART determinations, which factors 

into the cost of compliance in the BART analysis. 42 U.S.C. § 7491(g)(2); 40 C.F.R. § 

51.308(e)(1)(ii)(A). EPA’s guidance provides a specific time period for amortization of the costs 

of controls where a unit’s remaining useful life is limited.58 Thus, BART controls that may be 

cost-effective using the standard amortization period (typically 20-30 years) may no longer be 

cost-effective when remaining useful life is properly factored into the analysis.59 EPA’s cost 

estimates for proposed controls at the White Bluff Plant were based on a 30-year amortization 

period for the controls, an amortization period that is consistent with EPA’s Control Cost Manual 

when a unit’s remaining useful life is not limited.60 However, the Commenters understand that 

Entergy proposed to commit to cease coal-fired operation at the White Bluff Plant by 2027-2028. 

In light of this proposal, EPA should revise its BART analysis to take the remaining useful life of 

the units into account. Using the 2027 and 2028 timeline, the amortization period is shortened to 

approximately six to seven years. This significantly impacts the cost calculation, resulting in 

much higher costs as compared to the emissions reductions achieved. When appropriate costs are 

considered along with the units’ remaining useful coal-fired life, the average cost effectiveness 

of the proposed controls at the 

White Bluff Plant increases to amounts that are far too high to constitute BART. 

[Edison Electric Institute (0174) p. 2, 7-8, 10] EEI stated that EPA concluded that dry flue gas 

desulfurization (FGD) controls are BART for Entergy’s White Bluff Units 1 and 2 given their 

visibility impacts and average cost effectiveness at Unit 1 of $2,227/ton and at Unit 2 of 

$2,101/ton. See 80 Fed. Reg. at 18,971, Table 32. These cost estimates were based on a 30-year 

amortization period for the controls, which is consistent with EPA’s Control Cost Manual when 

a unit’s remaining useful life is not limited. However, Entergy proposes in its own comments to 

agree to an enforceable commitment to cease burning coal at White Bluff Units 1 and 2 by 2027 

and 2028, one unit per year. Accordingly, in light of Entergy’s proposal, EPA should revisit its 

proposed BART determination for White Bluff Units 1 and 2 to address the remaining useful life 

of the units accurately. 

EEI stated that Entergy’s proposal to cease coal-fired operation at White Bluff by 2027-2028—

coupled with a final BART determination in early 2016 (which would result in the proposed dry 

FGD controls being installed and operational no earlier than 2020)—shortens the amortization 

period from EPA’s assumed 30 years to 6-7 years instead. Entergy’s comments contain a revised 

dry FGD cost analysis from Sargent & Lundy (S&L) that takes into account current costs for dry 

 

58 See 79 Fed. Reg. at 74818, 74837 and 40 C.F.R. Part 51, App. Y, Section IV.D.4.k. . 59 Id. 60 The Control Cost Manual is available at http://www.epa.gov/ttncatc1/dir1/c_allchs.pdf.
56 

FGD installation and finds the total costs to install and operate dry FGD at White Bluff will be in 

excess of $1 billion. Based on the S&L analysis, operating the dry FGD systems at White Bluff 

for only six or seven years would result in a cost effectiveness several times higher than EPA 

estimates and above costs that EPA has previously determined on numerous occasions to be too 

expensive to constitute BART.61

EEI stated that in summary, it is unreasonable for EPA to impose a $1 billion control system for 

units that will utilize that system for only six or seven years. Instead of the proposed costly dry 

FGD control, Entergy believes that a combination of Low NOX Burner/Separated Over-Fire Air 

controls coupled with the use of low sulfur coal through the remaining useful coal-fired life of 

the White Bluff units should be BART. No additional controls are justified given the limited 

number of years of coal-fired operation of White Bluff given that the regional haze program 

allows for firm refueling commitments to satisfy regulatory requirements. 

Response: In our FIP proposal, we solicited comment on alternative SO2 and NOX control 

measures that would address the regional haze requirements for White Bluff Units 1 and 2 and 

Independence Units 1 and 2 for this planning period.62 In several instances, after EPA has 

proposed or finalized a BART determination in a FIP, a source has requested that EPA instead 

adopt an alternative to BART or otherwise adjust the assumptions underlying the BART analysis 

based on commitments to shut down or repower.63 We requested comment on alternative 

measures in part to determine whether Entergy in particular would be interested in an alternative 

path. Given the alternatives proposed by owners and operators of other power plants in other 

states, we stated that an alternative could include, but is not limited to, a combination of early 

shutdowns of units and other emission control measures that would achieve greater reasonable 

progress than the BART and reasonable progress controls that we proposed for these four units. 

Entergy’s comments propose a multi-unit strategy as an alternative to the proposed FIP.64 We 

note that we do not interpret Entergy’s comments submitted during the public comment period as 

suggesting that we adopt the elements in its alternative that are unique to White Bluff as an 

alternative to our proposed BART emission limits at the facility unless we also conclude that the 

remaining elements address any reasonable progress requirements for Independence. After 

carefully considering the comments we received specifically on this issue, we do not believe the 

comprehensive multi-unit strategy as presented by the company has potential to satisfy the 

BART requirements for White Bluff Units 1 and 2 and the reasonable progress requirements for 

Independence Units 1 and 2. 

 

61 See 79 Fed. Reg. at 9,331-33 (Proposed Arizona Regional Haze FIP), 79 Fed. Reg. 52,420 and 426 (Final Arizona 

Regional Haze FIP), 77 Fed. Reg. 23,988 and 24,047 (Proposed Montana Regional Haze FIP), 77 Fed. Reg. 57,864-

66 (Final Montana Regional Haze FIP), 76 Fed. Reg. 58,630 (Proposed North Dakota Regional Haze FIP) and 77 

Fed. Reg. 20,894-96 (Final North Dakota Regional Haze FIP). 62 80 FR at 18997. 

63 “Repower” means to change the fuel type for the boiler from coal to natural gas or fuel oil. 64 As discussed in our final rule, Entergy also submitted a comment after the close of the comment period, indicating 

that Entergy intends that a second alternative described in the late comment, involving only White Bluff, is a 

replacement for the multi-unit alternative previously described in its timely comments. Because the late comment is 

not a basis for our decision making in this final rule, we are responding in this RTC document and in our final rule 

to the alternative proposal described in the comments that Entergy filed during the comment period. 
57 

We do believe that the elements of the strategy Entergy has presented in its comments that apply 

specifically to White Bluff have potential merit with respect to addressing the BART 

requirements for White Bluff Units 1 and 2, if they were not linked to our action on 

Independence. Our detailed analysis of Entergy’s alternative strategy is discussed below and 

elsewhere in this document. A chief element of Entergy’s alternative is its proposal to cease coal 

combustion at White Bluff Units 1 and 2. It is unclear from the comments submitted whether this 

would mean the shutdown or the repowering of White Bluff Units 1 and 2. Regardless of this 

ambiguity, a number of commenters have argued that because of Entergy’s proposal, we should 

use a shorter remaining life in assessing the costs of controls at White Bluff. Entergy too 

suggests that EPA must take into account a shorter remaining useful life based on its “proposed 

commitment.” If we were to assume that Entergy were proposing changes at White Bluff 

regardless of our action regarding Independence, we could include in our final FIP an 

enforceable requirement for the shutdown (or repowering) and take that change into 

consideration as part of a BART determination. The BART Guidelines state that where unit 

shutdown affects the BART determination, the shutdown date should be assured by a federally or 

state-enforceable restriction preventing further operation.65 Given the long-life of coal-fired 

power plants such as White Bluff, it would be unreasonable to assume that such shutdowns will 

occur without an enforceable requirement. Although we could include such a requirement in our 

FIP, there is no evidence in the comments submitted by Entergy during the comment period that 

it intends to cease coal combustion at White Bluff Units 1 and 2 at this time absent a broader 

agreement on appropriate controls for both White Bluff and Independence. As such, we do not 

consider it appropriate to include a requirement to cease coal combustion at White Bluff Units 1 

and 2 in our rule unless we were to also accept the Entergy proposal as meeting all requirements 

with respect to Independence. Therefore, we are assuming a remaining useful life of 30 years for 

White Bluff Units 1 and 2 when determining BART for these units. 

We discuss elsewhere in this document (in our response to the next set of comments) the merits 

of Entergy’s proposed strategy as an alternative approach for both meeting the BART 

requirement of section 308(e) for White Bluff and meeting the requirements of sections 

308(d)(1) and 308(d)(3) regarding reasonable progress, which implicate all sources in Arkansas 

including Independence. 

We do note that if Arkansas submits a RH SIP revision to replace our FIP, the State has the 

discretion to consider an approach to address the BART requirements for White Bluff that 

involves ceasing coal combustion at Units 1 and 2 by a date certain, but the SIP revision is 

required to also include consideration and evaluation of dry sorbent injection (DSI) as a possible 

interim BART control option. We discuss this issue in more detail in our response to the next set 

of comments. With respect to Independence, as we stated above, a strategy that includes controls 

for Independence similar to what the company has proposed for White Bluff (i.e., interim SO2

controls, ceasing coal combustion, and NOX controls) would also have potential merit with 

respect to addressing the reasonable progress requirements for Independence Units 1 and 2. The 

state has the discretion to consider submitting a SIP revision that includes such a strategy for 

Independence to replace our FIP. 

 

65 See Appendix Y to 40 CFR Part 51- Guidelines for BART Determinations Under the Regional Haze Rule, section 

IV.D.4.k. 
58 

We address comments stating that we used outdated costs in our BART analysis, improperly 

eliminated millions of dollars in costs necessary to install controls on White Bluff, and did not 

consider site-specific factors that will affect the cost calculation, in the section of this document 

where we discuss cost issues. As discussed there, we have revised our cost calculations for White 

Bluff Units 1 and 2 in response to the comments received on our initial cost analysis. Based on 

this revised analysis, we have determined that dry scrubbers are estimated to cost $2,565/SO2 ton 

removed at Unit 1 and $2,421/SO2 ton removed at Unit 2. Many EGUs have installed and 

operated this type of controls successfully, and our cost analysis indicates that dry scrubbers at 

White Bluff would be cost effective and well within the range of cost of controls found to be 

reasonable by EPA and the States in their BART determinations. We address Entergy’s detailed 

comments regarding the White Bluff cost analysis in the section of this document where we 

discuss cost issues. 

With regard to the comment that NOX BART for all EGUs in Arkansas should be compliance 

with CSAPR given that EPA determined that CSAPR is better than BART, we discuss elsewhere 

in this document why we are not relying on CSAPR to satisfy the NOX BART requirement for 

Arkansas EGUs in this rulemaking. We are instead requiring source specific NOX BART 

controls. We also address elsewhere in this RTC document Entergy’s comments regarding the 

NOX emission limits for White Bluff and Independence. 

Regarding the comment that in our analysis of BART controls for White Bluff we made 

references to AEP that made it unclear whether we actually relied on Entergy’s revised White 

Bluff BART Analysis in our proposal, we confirm that we reviewed and based our analysis on 

Entergy’s 2013 Revised White Bluff BART analysis.66 The reference we made to AEP’s 

modeling and assumptions at 80 FR 18969 was a typographical error; we mistakenly referenced 

materials from AEP, but did not use AEP’s modeling and assumptions in our BART 

determination for White Bluff. This typographical error did not affect our proposed BART 

decision for White Bluff Units 1 and 2. 

Comment: EPA’s final FIP should include Entergy’s proposed multi-unit approach for 

White Bluff and Independence, which achieves virtually identical visibility benefits as 

EPA’s proposal for over $2 billion less. 

[Entergy Arkansas Inc. (0166) p. 45-49] Entergy stated that it is proposing near-term interim 

controls and the cessation of coal combustion at White Bluff by 2028. Entergy is proposing to 

meet lower SO2 emission rates at White Bluff Units 1 and 2 and Independence Units 1 and 2 by 

2018, and is willing to install LNB/SOFA at all four units and meet a 30-day rolling average 

NOX emission rate of 1,342.5 lb NOX/hr, within three years after the effective date of the final 

FIP as part of its multi-unit approach. This combination of controls and lower SO2 emission rates 

will ensure that the Class I areas achieve virtually the same reasonable progress as EPA’s 

proposal but at a cost of over $2 billion less than the proposal. See the figures below, which 

compare the projected 2018 haze index at each Arkansas Class I area based on a Ranked 

Statistical Analysis, to the deciview improvements projected for the following scenarios (1) 

 

66 “Revised BART Five Factor Analysis White Bluff Steam Electric Station Redfield, Arkansas (AFIN 35–00110),” 

dated October 2013, prepared by Trinity Consultants Inc. in conjunction with Entergy Services Inc. 
59 

Entergy’s proposed controls, based on the cessation of coal-fired operations at White Bluff 

(referred to as “WB”) and the installation of LNB/SOFA and lower SO2 emission rate at 

Independence (referred to as “ISES”); and (2) installation of EPA’s proposed FIP controls at all 

BART sources and Independence. Based on Entergy’s modeling, the difference in the haze index 

between the proposed FIP controls and Entergy’s proposal is 0.05 dv at Caney Creek and 0.07 dv 

at Upper Buffalo; differences that are too trivial to justify a $2 billion investment at White Bluff 

and Independence for the installation of dry FGD. 

“Uniform Rate of Progress and 2018 Projected Progress for Caney Creek- Ranked 

Statistical Analysis” 

(provided by Entergy as Figure 13 to AR020.0166) 

Uniform Rate of Progress and 2018 Projected Progress

Caney Creek Wilderness Area – Ranked Statistical Analysis

30.00

1st

Planning

Period

2nd

Planning

Period

3rd

Planning

Period

4th

Planning

Period

5th

Planning

Period

26.36

6th

Planning

Period

25.37

25.00

22.91

20.45

20.00

Projected	Haze	Index,	20.07 17.98

Proposed	FIP	Haze	Index,	19.66

Entergy's Proposal, 19.71 15.52

15.00

13.06

11.58

10.00 11.24		 11.24 11.24 11.24 11.24 11.24 11.24

5.00

Glide path (20% Glide path (20% Best) Observation (20% Observation (20% Best)

Entergy's Proposal ‐ WB/ISES | Others ‐ BART controls

Proposed FIP Haze	‐ All	‐ Proposed FIP Controls
60 

 “Uniform Rate of Progress and 2018 Projected Progress for Upper Buffalo Wilderness 

Area- Ranked Statistical Analysis” 

(provided by Entergy as Figure 14 to AR020.0166) 

Entergy stated that its proposed approach with respect to White Bluff and Independence makes 

sense in light of the long-term objectives of the Regional Haze Program, the high capital costs 

for scrubbers, and the significant long-term environmental co-benefits from the cessation of coalfiring at the White Bluff units. Arkansas’ Five-Year Progress Report demonstrates that the state 

Uniform Rate of Progress and 2018 Projected Progress

Upper Buffalo Wilderness Area	‐	Ranked Statistical

Analysis 30.00	

1st Planning	

Period	

2nd Planning 			

Period

3rd	Planning	

Period

4th Planning

Period

5th	Planning

Period

26.27	

6th Planning

Period

25.29	

25.00	

22.84

Entergy's Proposal,

20.79

20.00	

Projected Haze Index, 20.91

Proposed FIP Haze Index,

20.72

20.39

17.94

15.49	

15.00	

13.04

11.71

11.71 11.57

10.00	

11.71		 	 11.71	 11.71 11.71 11.71	 11.71

5.00	

Glide	path	(20%	Worst)	 Glide path (20% Best) Observation (20%	Worst)	 Observation (20% Best)

Entergy's Proposal ‐ WB/ISES | Others	‐	BART	controls

Proposed	FIP	Haze	‐	All	‐	Proposed	FIP	Controls
61 

currently is below the glide path for Caney Creek and Upper Buffalo, and expects to remain so 

through at least 2018. See Section III.C.1 of Entergy’s comments. Entergy’s approach would 

help ensure that Arkansas remains below the glide path throughout the second planning period, 

and will produce very large additional reductions in NOX, SO2, and PM heading into the third 

planning period. 

Entergy stated that ultimately, its approach would achieve 170,000 tons of NOX reductions from 

White Bluff more than the proposed FIP would achieve. While scrubbers would reduce SO2

emissions substantially, the total visibility benefits from ceasing to use coal are at least as great. 

Entergy’s approach also would achieve multi-pollutant co-benefits. Prior to 2028, SO2 and NOX

would be reduced, which would result in reductions in ozone and PM2.5. Starting in 2028, 

Entergy’s approach would produce even greater reductions in emissions of SO2, NOX and PM2.5, 

as well as achieving reductions in mercury and other hazardous air pollutants, and CO2/CO2e. It 

would reduce annual greenhouse gas emissions by approximately 11.74 million tons per year, a 

275 million ton lifetime benefit over EPA’s proposal. Additionally, the elimination of coal 

combustion in 2027 and 2028 would reduce rail and truck traffic, allow for the closure of 

landfills, and reduce water usage, in addition to other environmental benefits. 

Entergy stated that it opposes the RPGs that EPA has proposed for Caney Creek and Upper 

Buffalo. The RPGs reflect the approved portions of Arkansas’ Regional Haze SIP, the proposed 

FIP BART controls, and the controls proposed for Independence. 80 Fed. Reg. at 18,997. 

Controls at Independence for reasonable progress purposes are not justified and including the 

emissions reductions based on the installation of dry FGD and LNB/SOFA at Independence 

renders EPA’s RPGs arbitrary and capricious. EPA should recalculate the RPGs based on 

Entergy’s proposed approach for controlling emissions at White Bluff and Independence. 

[Entergy Mississippi Inc. (0168) p. 14 and Conway Corporation et. al. (0172) p. 15] Entergy 

Mississippi Inc. (EMI) and Conway Corporation et. al. both stated that EPA requested public 

comment on any alternative SO2 and NOX control measures that would address the regional haze 

requirements for White Bluff Units 1 and 2 and Independence Units 1 and 2 for this planning 

period. According to EPA, this includes, but is not limited to, a combination of early unit 

shutdowns and other emissions control measures that would achieve greater reasonable progress 

than the BART and reasonable progress requirements that EPA proposed for the first planning 

period. 

[Entergy Mississippi Inc. (0168) p. 14] EMI stated it understands that Entergy Arkansas Inc. is 

proposing the cessation of coal combustion at White Bluff by 2028, the installation of 

LNB/SOFA at White Bluff Units 1 and 2 and Independence Plant’s Units 1 and 2, and to meet 

lower SO2 emission rates at all four units by 2018. This combination of controls and lower SO2

emission rates ensures that the relevant Class I areas achieve virtually the same reasonable 

progress as EPA’s proposed rule but at a significantly lower cost to EMI and its customers. 

[Conway Corporation et. al. (0172) p. 15] Conway Corporation et. al. stated it understands that 

Entergy is proposing to cease burning coal at the White Bluff Plant by 2028, and to install 

LNB/SOFA at Independence Units 1 and 2, and to meet lower SO2 emission rates at all four 

units by 2018. Conway Corporation et. al. support this proposed approach, which ensures that the 
62 

Class I areas achieve virtually the same reasonable progress as EPA’s proposal but at 

significantly less cost to commenters and their customers. 

[Entergy Mississippi Inc. (0168) p. 14 and Conway Corporation et. al. (0172) p. 15] EMI and 

Conway Corporation et. al. both stated they strongly encourage EPA to amend the proposed rule 

as described in Entergy’s comments and to adopt a comprehensive approach to regional haze that 

would involve the four coal-fired units at Independence and White Bluff, without requiring 

expensive, unnecessary scrubber technology. Such an approach would ensure comparable or 

superior, long-term visibility benefits than the proposed FIP for $2 billion less. It also would 

deliver important non-haze environmental benefits, including a dramatic decrease in greenhouse 

gas emissions, large reductions in SO2 emissions that also contribute to long-range PM2.5 issues, 

and large reductions in ozone (and PM2.5)-forming NOX emissions. 

Response: After carefully considering the comments we received, we have determined that 

Entergy’s alternative proposal67 is not a better than BART alternative, does not meet the BART 

requirements for White Bluff Units 1 and 2, does not meet the reasonable progress requirements, 

and does not provide for the same visibility benefits as the FIP while delaying a majority of the 

visibility benefits until several years later than the FIP. The details of our assessment of the 

merits of Entergy’s proposed strategy as an alternative approach for both meeting the BART 

requirement of section 308(e) for White Bluff and meeting the requirements of sections 

308(d)(1) and 308(d)(3) regarding reasonable progress, which implicate all sources in Arkansas, 

including Independence, are as follows. 

First, we note that Entergy does not appear to be proposing that we apply the provisions of 

sections 308(e)(2) and 308(e)(3) to determine that its multi-unit strategy is an alternative to 

BART that provides more reasonable progress than BART by the end of the first implementation 

period, which is December 31, 2018. To the extent that this is Entergy’s proposal, those 

provisions clearly would not allow Entergy’s multi-unit plan to be approved as an alternative to 

BART because it does not meet the requirements of section 308(e)(2)(ii) that “all necessary 

emission reductions take place during the period of the first long-term strategy for regional 

haze.” Moreover, Entergy does not argue that its alternative would provide for “greater” 

reasonable progress, only that its proposal would result in “virtually the same” visibility benefits. 

Thus, our analysis considers only the requirements of section 308(e)(1), which contains the 

source-specific BART requirements, in considering the provisions of Entergy’s alternative 

proposal applicable to White Bluff. (We address elsewhere in this document the issue of whether 

our FIP should apply the provisions of section 308(e)(4) for purposes of meeting the BART 

requirement for NOX emissions for EGUs in Arkansas.) 

Next, we also note that Entergy does not appear to be requesting in the comments submitted 

during the comment period that we adopt the elements in its alternative proposal that are unique 

to White Bluff as an alternative to our proposed BART emission limits at the facility unless we 

 

67 As discussed in our final rule, Entergy also submitted a comment after the close of the comment period, indicating 

that Entergy intends that a second alternative described in the late comment, involving only White Bluff, is a 

replacement for the multi-unit alternative previously described in its timely comments. Because the late comment is 

not a basis for our decision making in this final rule, we are responding in this RTC document and in our final rule 

to the alternative proposal described in the comments that Entergy filed during the comment period. 
63 

also conclude that the remaining elements address any reasonable progress requirements for 

Independence. In other words, Entergy’s comments provide no indication that it is willing to 

accept a binding requirement to cease coal combustion at White Bluff by 2027/2028, unless we 

also accept the elements of its alternative proposal that are applicable to Independence as 

satisfying the reasonable progress requirements. As we discuss below, we conclude that the 

elements of Entergy’s alternative proposal that are specific to Independence do not satisfy the 

reasonable progress requirements. Even if we had interpreted Entergy’s comments as requesting 

that we adopt the particular elements in its alternative proposal that apply to White Bluff as an 

alternative to our proposed BART emission limits at the facility without these elements being 

linked to the remaining elements addressing the reasonable progress requirements for 

Independence, we conclude that we would not be able to incorporate the Entergy alternative 

proposal into the final FIP as a way of meeting the BART requirements for White Bluff because, 

as we discuss below, Entergy’s alternative proposal does not satisfy the source-specific BART 

requirements of section 308(e)(1) for White Bluff. 

Entergy’s alternative strategy would achieve minimal SO2 emission reductions over the next 10 

to 11 years. Entergy proposes that White Bluff Units 1 and 2 would meet an SO2 interim 

emission limit of 0.6 lb/MMBtu on a rolling 30-day average beginning in 2018 through 

2027/2028 when coal combustion at the two units would cease.68 We note that the 0.6 lb/MMBtu 

interim emission limit is only slightly lower than the units’ current SO2 emission rates. We have 

no basis to assume that future emissions would be lower than these current rates in the absence 

of new SIP or FIP requirements, and so these current emission rates are the appropriate baseline 

for comparing strategies, rather than the currently permitted emission rates, which are higher; 

Entergy does not appear to dispute this point. The maximum monthly SO2 emission rates for 

White Bluff Units 1 and 2 in 2009-2013 were 0.653 lb/MMBtu and 0.679 lb/MMBtu, 

respectively.69 Thus, under Entergy’s alternative proposal, the White Bluff units would continue 

to operate for the remainder of the first planning period at near the current emission rate and 

throughout most of the second planning period with only a slight actual reduction in SO2

emissions. Entergy has provided no analysis to show that there is no more effective measure for 

White Bluff for this interim period that is needed to make reasonable progress. Section 308(e)(1) 

and the BART guidelines require that a subject-to-BART source install and operate the best 

available emission reduction technology based on the five statutory factors, and it is therefore 

necessary to consider whether there are any additional SO2 control measures, such as dry sorbent 

injection (DSI), that constitute BART during this interim period. Entergy has argued that with 

this limited remaining period of coal combustion, the cost per ton of SO2 emissions reduction for 

scrubbers would be too high for scrubbers to be selected as BART for White Bluff. While we 

agree that a shorter remaining useful life might result in a conclusion that dry scrubbers are not 

cost effective, as part of the BART analysis, technically feasible control technologies beyond the 

interim SO2 emission limit the company has proposed must be evaluated to determine if they are 

 

68 Although not specified in Entergy’s written comments, the company met with us and confirmed that the interim 

SO2 emission limit would be achieved by combusting lower sulfur coal. See file titled “Record of Meeting_October 

27 2015,” which is found in the docket for this rulemaking. 

69 80 FR at 18970; see also the spreadsheet titled “White Bluff_R6 cost revisions2,” which is found in the docket for 

this rulemaking. 
64 

cost effective for use in the period before coal combustion ceases.70 In particular, DSI has a 

relatively low capital cost and may be cost effective even if operated for a short period of time.71

Under Entergy’s proposed strategy, White Bluff Units 1 and 2 would cease coal combustion 

towards the end of the second planning period. Therefore, it would be necessary to consider and 

evaluate DSI as a possible interim BART control option for White Bluff Units 1 and 2. Because 

Entergy has provided no analysis or any pertinent information or documentation to demonstrate 

that there is no more effective interim SO2 control that would constitute BART for White Bluff, 

the company’s proposed strategy is not adequate to ensure that the BART requirements for 

White Bluff Units 1 and 2 will be met. 

Further, even if it were not necessary to evaluate DSI or if we were to determine that DSI is not 

cost effective for use at White Bluff in the interim period before coal combustion ceases, 

Entergy’s alternative proposal would still not satisfy the BART requirements for White Bluff 

because the alternative proposal does not include SO2 and NOX emission limits after coal 

combustion ceases or otherwise propose adopting a binding requirement to burn only natural gas 

or completely shut down the units. Entergy proposes to cease coal combustion at White Bluff 

Units 1 and 2 in 2027/2028, but its comments do not specify the operating conditions of White 

Bluff Units 1 and 2 after coal combustion ceases. The type of fuel White Bluff is permitted to 

burn after ceasing coal combustion will impact the emissions reductions actually achieved under 

Entergy’s alternative proposal. Exhibit C to Entergy’s comments indicates that the company 

assumes in its visibility modeling that SO2 and NOX emissions from White Bluff Units 1 and 2 

will be zero under the company’s alternative proposal (i.e., “Entergy’s proposed controls” 

scenario).72 If Entergy’s alternative proposal had included accepting a binding requirement to 

burn only natural gas at White Bluff Units 1 and 2 after coal combustion ceases, or a binding 

requirement to completely shut down the units, then we would agree that it would be appropriate 

to assume that SO2 emissions from White Bluff will be zero beginning in 2027/2028. Similarly, 

if Entergy’s alternative proposal had included accepting a binding requirement to completely 

shut down White Bluff or included a NOX emissions limit, then we would agree that it would be 

appropriate to assume that NOX emissions from White Bluff will be zero beginning in 

2027/2028. However, Entergy’s alternative proposal does not specify any such binding 

requirements that would ensure SO2 and NOX emissions from White Bluff are appropriately 

controlled after coal combustion ceases. 

With regard to Independence, we note that Entergy’s proposal to cease coal combustion at White 

Bluff does not change our conclusion that it is necessary to control Independence under the 

reasonable progress requirements. Under Entergy’s proposed approach, Independence Units 1 

and 2 would be subject to an SO2 emission limit of 0.6 lb/MMBtu on a rolling 30-day average 

 

70 As discussed elsewhere in this response, the SO2 interim emission limit of 0.6 lb/MMBtu proposed by the 

company for White Bluff Units 1 and 2 is only slightly less than the units’ current SO2 emission rates, meaning that 

only slight actual SO2 emissions reductions are expected to take place as a result of the interim emission limit. 71 For example, Florida evaluated a shutdown option by December 31, 2020 for two BART units. After reviewing 

the Florida Regional Haze SIP, we concluded that the State should have evaluated DSI as a as a possible interim 

BART control option during the interim before the units shut down. We ultimately approved Florida’s determination 

after evaluating the cost-effectiveness of DSI and concluding that such controls were not cost-effective in light of 

the remaining useful life of the units. See 78 FR at 53261. 72 See “Regional Haze Modeling Assessment Report,” dated August 4, 2015, submitted as Exhibit C to Entergy 

Arkansas Inc.’s comments. 
65 

beginning in 2018.73 This emission limit is only slightly lower than the current SO2 emission 

rates from Independence Units 1 and 2. The maximum monthly SO2 emission rates for 

Independence Units 1 and 2 in 2009 – 2013 were 0.631 lb/MMBtu and 0.612 lb/MMBtu, 

respectively.74 We have no basis to assume that future emissions would be different from current 

rates in the absence of new SIP or FIP requirements, and so these current emission rates are the 

appropriate baseline for comparing strategies, rather than the currently permitted emission rates, 

which are higher. As such, under Entergy’s proposal these units would continue to operate with 

minimal SO2 emissions reductions. Unlike Entergy’s proposed approach with respect to White 

Bluff, the proposed SO2 limit for Independence would not be an interim emission limit. The 

company’s alternative proposal does not include any further SO2 controls for Independence Units 

1 and 2, such as DSI or the eventual cessation of coal combustion. In light of the minimal SO2

emissions reductions that would be achieved at Independence under the company’s proposed 

strategy, we expect that there would be correspondingly minimal visibility improvement with 

respect to the SO2 controls it proposes for Independence. SO2 emissions are the primary driver of 

regional haze in Arkansas’ Class I areas on the 20% worst days and Independence is the second 

largest source of SO2 in the State of Arkansas.75 As explained in our proposal, the preamble to 

our final action, and elsewhere throughout this document, our consideration of the four 

reasonable progress factors and consideration of the visibility impacts and visibility 

improvement of controls for Independence revealed that dry scrubbers are needed on both units 

to make reasonable progress. Additionally, we received CAMx source apportionment modeling 

from Entergy during the comment period that estimates the average visibility impairment from 

Independence during the 20% worst days. As we discuss in the section of this document where 

we discuss modeling issues, the results of Entergy’s CAMx modeling confirm and provide 

additional support to our determination that Independence significantly impacts visibility at 

Arkansas’ Class I areas. As such, Entergy’s proposal to cease coal combustion at White Bluff 

does not change our conclusion that it is necessary to control Independence under the reasonable 

progress requirements. Since Entergy’s alternative proposal includes minimal SO2 control for 

Independence, thus omitting controls that we found to be cost effective and that are anticipated to 

result in considerable visibility benefits at Arkansas’ Class I areas, we conclude that the elements 

of Entergy’s alternative proposal that are specific to Independence do not satisfy the reasonable 

progress requirements for Independence. 

Although, as we have already established, Entergy’s alternative proposal cannot constitute a 

BART alternative because all necessary emission reductions will not take place during the first 

implementation period and the alternative proposal also does not satisfy the source-specific 

BART requirements of section 308(e)(1) for White Bluff and the requirements of sections 

 

73 Although not specified in Entergy’s written comments, the company met with us and confirmed that this emission 

limit would be met by combusting lower sulfur coal. See file titled “Record of Meeting_October 27 2015,” which is 

found in the docket for this rulemaking. 

74 See the spreadsheet titled “White Bluff_R6 cost revisions2,” which is found in the docket for this rulemaking. 

75 CENRAP CAMx modeling shows that on most of the 20% worst days in 2002, total extinction is dominated by 

sulfate at both Caney Creek and Upper Buffalo. Therefore, SO2 emissions are considered the primary driver of haze 

in Arkansas’ Class I areas. However, as discussed elsewhere in this RTC document, we consider both SO2 and NOX

to be key visibility impairing pollutants in Arkansas’ Class I areas. See Arkansas RH SIP, Appendix 8.1- “Technical 

Support Document for CENRAP Emissions and Air Quality Modeling to Support Regional Haze State 

Implementation Plans,” sections 3.7.1 and 3.7.2. See the docket for this rulemaking for a copy of the Arkansas RH 

SIP. 
66 

308(d)(1) and 308(d)(3) regarding reasonable progress, in response to Entergy’s comment that its 

alternative proposal would achieve almost the same level of visibility benefit as the FIP, we 

compared the potential impacts of Entergy’s proposal to our FIP. Despite the ambiguity in the 

comments submitted by Entergy regarding its alternative proposal, for purposes of assessing the 

visibility impacts of the company’s proposed approach we have assumed that post-2028 SO2 and 

NOX emissions from White Bluff Units 1 and 2 will be zero under Entergy’s alternative 

proposal. In the Table below, we compare the total annual SO2 emissions reductions that would 

result under our FIP and under Entergy’s alternative proposal when the alternative proposal is 

fully implemented in 2028 (i.e., when coal combustion has ceased at White Bluff).76 For 

consistency and to allow for direct comparison to our FIP proposal, in estimating the SO2

emissions reductions anticipated to result from Entergy’s alternative proposal we have assumed 

the same SO2 baseline emissions we used for White Bluff and Independence in our proposal.77 

Comparison of Annual SO2 Emissions Reductions from White Bluff Units 1 and 2 

and Independence Units 1 and 2 (Post-2028) 

Unit 

SO2

Baseline 

Emissions

(tpy) 

FIP proposalAnnual SO2

reductions1

Entergy 

alternative 

proposalAnnual SO2

reductions2

Additional SO2

Emissions Reductions 

achieved by FIP 

proposal 

White Bluff Unit 1 15,816 14,363 15,816 (1,453) 

White Bluff Unit 2 16,697 15,221 16,697 (1,476) 

Independence Unit 1 14,269 12,912 1,2913 11,621 

Independence Unit 2 15,511 13,990 1,3993 12,591 

Total- All four units 

combined (SO2 tpy) 62,293 56,486 35,203 21,283 

1 These SO2 reductions will begin taking place no later than 5 years from the effective date of this final FIP. 2 This takes into account the full SO2 reductions that would take place under Entergy’s alternative proposal; a small 

amount of SO2 reductions would begin taking place in 2018, but the majority of these SO2 reductions would begin 

taking place in 2027/2028. 

3

 As Entergy’s proposed SO2 emission limit for Independence Units 1 and 2 is one order of magnitude greater than 

our proposed SO2 emission limit (i.e., 0.6 lb/MMBtu vs. 0.06 lb/MMBtu), we have accordingly estimated that the 

SO2 emissions from Independence under the Entergy alternative would be one order of magnitude greater than under 

our FIP. Thus, we estimated SO2 emissions reductions of 1,291 tpy and 1,399 tpy from Units 1 and 2 under the 

Entergy alternative. However, even if we were to accept Entergy’s estimate of SO2 reductions at Independence of 

2,104 tpy at Unit 1 (14,258 – 12,154= 2,104 tpy) and 2,245 tpy at Unit 2 (15,407 – 13,162= 2,245 tpy), this does not 

change our conclusion that substantially greater SO2 emissions reductions would be achieved at Independence under 

our FIP proposal. See Appendix A of “Regional Haze Modeling Assessment Report,” dated August 4, 2015, 

submitted as Exhibit C to Entergy Arkansas Inc.’s comments. 

 

76 The SO2 emissions reductions expected to result from our FIP will take place several years earlier than any 

significant SO2 reductions under Entergy’s alternative proposal. However, for purposes of comparing the long-term 

emissions reductions under the FIP and under the Entergy alternative, we are assessing the annual emissions 

reductions that will take place beginning in 2028, when the Entergy alternative would be fully implemented. 

77 In our proposal, for purposes of estimating the annual SO2 emissions reductions due to controls on White Bluff 

Units 1 and 2 and Independence Units 1 and 2, we assumed an SO2 emissions baseline that was determined by 

examining annual SO2 emissions for the years 2009-2013, eliminating the year with the highest emissions and the 

year with the lowest emissions, and obtaining the average of the three remaining years. See 80 FR at 18971 and 

18992. 
67 

As shown in the Table above, although Entergy’s alternative proposal would, after 2027/2028, 

achieve slightly greater SO2 reductions at White Bluff Units 1 and 2 than our FIP proposal, it 

would achieve substantially lower SO2 reductions at Independence Units 1 and 2. Thus, 

considering the four units combined, we estimate that our FIP proposal would achieve emissions 

reductions of 21,283 SO2 tpy more than Entergy’s alternative proposal. With regard to the 

visibility benefits, Entergy does not assert that its alternative proposal would provide equal of 

greater visibility benefits relative to our proposed FIP once the alternative is fully realized in the 

period after 2027/2028. Entergy states only that its alternative proposal would provide almost the 

same visibility benefit as our proposed FIP post-2027/2028. We conclude that not even this 

assertion is adequately supported, and that the long-term visibility benefits of the Entergy 

alternative proposal would be significantly smaller than those of the proposed and final FIP. As 

we explained above, Entergy assumes in its visibility improvement projections that SO2 and NOX

emissions from White Bluff Units 1 and 2 will be zero under the company’s alternative proposal. 

The assumption of zero SO2 emissions from White Bluff after coal combustion ceases would be 

appropriate only if Entergy’s alternative proposal involves accepting a binding requirement to 

burn only natural gas or permanently shut down after coal combustion ceases.78 With respect to 

NOX emissions from all four units of White Bluff and Independence, Entergy’s multi-unit 

strategy includes the same level of NOX control as our FIP proposal prior to the cessation of coal 

combustion at White Bluff in 2027/2028. Since Entergy’s explanation of its alternative proposal 

does not specify the operating conditions of White Bluff Units 1 and 2 when coal combustion 

ceases in 2027/2028, we find that the assumption of zero NOX emissions is also not adequately 

supported. However, even if we accept Entergy’s assumption that SO2 and NOX emissions from 

White Bluff will be zero after coal combustion ceases and that its alternative proposal would thus 

achieve greater NOX reductions compared to our FIP proposal, given the dominance of visibility 

impact from sulfate compared to nitrate at the affected Class I areas in Arkansas, the higher 

visibility impacts due to sulfate under the Entergy alternative proposal would more than 

outweigh any extra nitrate-related visibility benefit. Entergy’s own CAMx modeling shows that 

even assuming zero SO2 and NOX emissions from White Bluff once it ceases coal combustion, 

its multi-unit alternative proposal would achieve less visibility benefit than the FIP controls at 

Arkansas’ Class I areas, most significantly at Upper Buffalo where the benefit from Entergy’s 

proposal is approximately only 66% of the benefit from the FIP (i.e., 1.54 dv visibility benefit 

from the FIP compared to 0.97 dv from Entergy’s alternative proposal). Thus, we have 

determined that Entergy’s alternative proposal would not achieve “virtually the same” level of 

reasonable progress in Arkansas’ Class I areas as our FIP proposal, and that it would delay a 

majority of the visibility benefits until several years later than the FIP. We address elsewhere in 

this document specific comments regarding Entergy’s photochemical modeling of visibility 

benefits from the controls in our proposed FIP and Entergy’s alternative multi-unit strategy, as 

well as Entergy’s ranked statistical analysis. 

We agree that ceasing coal combustion at White Bluff Units 1 and 2 could result in additional 

PM emissions over our FIP proposal. But since actual PM emissions from the units are already 

 

78 On the other hand, if White Bluff Units 1 and 2 are permitted to burn fuel oil after coal combustion ceases, it is 

not appropriate to assume that SO2 emissions will be “0” under the company’s proposed approach. In fact, if the 

units will be permitted to burn high sulfur fuel oil after coal combustion ceases, we expect that the SO2 emission rate 

under the company’s proposed approach would be even higher than the SO2 emission rate under our proposed FIP. 
68 

very low because the units are equipped with electrostatic precipitators (ESPs), we do not expect 

that the additional PM emissions reductions from ceasing coal combustion would be 

considerable. Additionally, because PM emissions from White Bluff contribute very little to haze 

at Arkansas’ Class I areas, we do not believe that the additional PM reductions that would be 

achieved would provide a significant visibility benefit at the Class I areas.79 We also recognize 

that ceasing coal combustion at White Bluff Units 1 and 2 could result in greater nonair 

environmental benefits and in more emission reductions of mercury and other hazardous air 

pollutants and CO2/CO2e than our proposed FIP. However, in assessing Entergy’s alternative 

proposal, we do not find it necessary to weigh the nonair quality environmental benefits with the 

other statutory factors since we ultimately find that we cannot accept Entergy’s alternative 

proposal because it does not satisfy the requirements of the Regional Haze Rule. As discussed 

earlier in our response, we conclude that Entergy’s proposal does not satisfy the requirements to 

be considered a better-than-BART alternative under sections 308(e)(2) and 308(e)(3); does not 

satisfy the source-specific BART requirements under section 308(e)(1) for White Bluff; does not 

satisfy the reasonable progress requirements under section 308(d)(1); and does not provide for 

the same visibility benefits as the FIP, while delaying a majority of the visibility benefits until 

several years later than the FIP. For these reasons, we cannot adopt Entergy’s alternative 

approach in lieu of our FIP. 

With regard to Entergy’s comment regarding the cost to install dry FGD, we note that we have 

revised our cost calculations of SO2 controls for White Bluff Units 1 and 2 in response to the 

comments received on our initial cost analysis. Based on our revised cost analysis, we have 

found that dry scrubbers on White Bluff are estimated to cost $2,565/SO2 ton removed at Unit 1 

and $2,421/SO2 ton removed at Unit 2. After revising our cost estimates for dry scrubbers on 

White Bluff, we continue to believe that dry scrubber controls and LNB/SOFA controls are cost 

effective at White Bluff Units 1 and 2 and would result in significant visibility improvement at 

Arkansas’ Class I areas based on our CALPUFF modeling of the 98th percentile visibility 

impacts from the facility.80 Based on our consideration of the five BART factors, we have 

determined that controls consistent with dry scrubber and LNB/SOFA installation are BART for 

White Bluff Units 1 and 2. We address Entergy’s comments regarding the cost to install dry 

FGD in the section of this document where we address cost issues. 

As we discuss in our final rule, based on our consideration of the four reasonable progress 

factors and of the visibility impacts and visibility improvement of controls on Independence, we 

have determined that dry scrubbers and LNB/SOFA controls on Independence Units 1 and 2 are 

necessary to make reasonable progress at Arkansas’ Class I areas. We have also revised our cost 

calculations of SO2 controls for these units in response to the comments received on our initial 

cost analysis. Based on our revised cost analysis, we have found that dry scrubbers on 

Independence are estimated to cost $2,853/SO2 ton removed at Unit 1 and $2,634/SO2 ton 

removed at Unit 2. After revising our cost estimates for dry scrubbers on Independence, we 

 

79 “Since we have found that the visibility impact of the source [White Bluff] due to PM emissions alone is so 

minimal such that the installation of any additional PM controls on the units would likely achieve very low 

emissions reductions, have minimal visibility benefits, and not be cost-effective, we are proposing to approve 

ADEQ’s determination that PM BART for both the bituminous and subbituminous coal firing scenarios is the 

existing PM emission limit for [White Bluff] Units 1 and 2.” 76 FR 64205. 

80 See 80 FR at 18972. Our FIP proposal provides a detailed discussion of the visibility improvement of these 

controls based on our CALPUFF modeling. 
69 

continue to believe that both dry scrubber and LNB/SOFA controls are cost effective. We also 

find that these controls on Independence would provide significant visibility improvement as 

projected by our CALPUFF modeling that focuses on the 98th percentile impacts from the 

facility.81 Additionally, the CAMx photochemical modeling submitted by Entergy shows that the 

contribution to visibility impairment due to baseline emissions from the Independence facility 

alone are projected to be approximately 1.3% of the total visibility impairment during the 

average 20% worst days in 2018 at each Arkansas Class I area. We consider this to be a 

significant contribution to visibility impairment at each Class I area and a large portion 

(approximately one-third) of the total contribution from all Arkansas point sources. The results 

of Entergy’s CAMx modeling confirm and provide additional support to our determination that 

Independence significantly impacts visibility at Arkansas’ Class I areas. While the majority of 

the visibility impacts due to Independence on the 20% worst days are due to SO2, we note that 

NOX emissions from the facility also have impacts on the 20% worst days. Entergy’s CAMx 

modeling shows that nitrate from Independence is responsible for 30 – 40% of the visibility 

impairment in Arkansas’ Class I areas on 2 of the 20% worst days.82 We expect that installation 

of cost-effective NOX controls on Independence would provide visibility improvement on this 

portion of the 20% worst days, and as such, are requiring both SO2 and NOX controls under the 

reasonable progress requirements. 

We do note that if Arkansas submits a regional haze SIP revision to replace our FIP, the state has 

the discretion to consider an approach to address the BART requirements for White Bluff that 

involves ceasing coal combustion at Units 1 and 2 by a date certain, but an approvable SIP 

revision must also include consideration and evaluation of DSI as a possible interim BART 

control option. With respect to Independence, a strategy that includes controls for Independence 

similar to the elements of Entergy’s alternative proposal that are specific to White Bluff (i.e., 

interim SO2 controls, ceasing coal combustion in the near future, and NOX controls) would also 

have potential merit with respect to addressing the reasonable progress requirements for 

Independence Units 1 and 2. The state may consider submitting a SIP revision that includes such 

a strategy for Independence to replace our FIP. 

With regard to the numeric RPGs we are finalizing, we note that we proposed RPGs for the 20% 

worst days for Caney Creek and Upper Buffalo of 22.27 dv and 22.33 dv, respectively, that 

reflected the anticipated visibility conditions resulting from the combination of control measures 

from the approved portion of the 2008 Arkansas Regional Haze SIP and our FIP proposal. We 

received comments on our proposal indicating that our proposed RPGs for the 20% worst days 

for Caney Creek and Upper Buffalo improperly incorporated visibility improvements that would 

not occur until after 2018. After considering these comments, we agree that the RPGs should 

reflect anticipated visibility conditions at the end of the implementation period in 2018 rather 

than the anticipated visibility conditions once the FIP has been fully implemented, and we are 

therefore revising the RPGs we proposed. This approach is consistent with the purpose of RPGs 

and the direction provided in our 2007 Reasonable Progress Guidance.83

 

81 80 FR 24872.

82 This means 2 out of the 21 days that are the 20% worst of the days with IMPROVE monitoring data. 

83 “Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program,” dated June 1, 2007. 
70 

Section 169B(e)(1) of the CAA directed the Administrator to promulgate regulations that 

“include[e] criteria for measuring ‘reasonable progress’ toward the national goal.” Consequently, 

we promulgated 40 CFR 51.308(d)(1) as part of the Regional Haze Rule. This provision directs 

states to develop RPGs for the most and least impaired days to “measure” the progress that will 

be achieved by the control measures in the state’s long-term strategy “over the period of the 

implementation plan.”84 The current implementation period ends in 2018. RPGs “are not directly 

enforceable” like the emission limitations in the long-term strategy.85 Rather, they fulfill two key 

purposes: (1) allowing for comparisons between the progress that will be achieved by the state’s 

long-term strategy and the URP,86 and (2) providing a benchmark for assessing the adequacy of a 

state’s SIP in 5-year periodic reports.87 Consequently, in our 2007 Reasonable Progress 

Guidance, we indicated that states could consider the “time necessary for compliance” factor by 

“adjust[ing] the RPG to reflect the degree of improvement in visibility achievable within the 

period of the first SIP if the time needed for full implementation of a control measure (or 

measures) will extend beyond 2018.”88 In other words, RPGs need not reflect the visibility 

improvement anticipated from all of the control measures deemed necessary to make reasonable 

progress (as a result of the four-factor analysis) and included in the long-term strategy. 

In this instance, we are taking final action on the Arkansas Regional Haze FIP 9 years after the 

state’s initial SIP submission was due. As a result, only some of the control measures that we 

have determined are necessary to satisfy the BART and reasonable progress requirements will be 

installed by the end of 2018. Some controls will not be installed until 2021. Because RPGs are 

only unenforceable analytical benchmarks, we think that it is appropriate to follow the 

recommendation in our 2007 Reasonable Progress Guidance and finalize RPGs that represent the 

visibility conditions anticipated on the 20% worst days at Caney Creek and Upper Buffalo by 

2018. These RPGs are listed in the table below:89

Reasonable Progress Goals for 2018 for Caney Creek and Upper Buffalo 

Class I area 2018 RPG 

20% Worst days (dv) 

Caney Creek 22.47 

Upper Buffalo 22.51 

We note that the RPGs we are finalizing are very similar to the ones that we disapproved in the 

Arkansas Regional Haze SIP. The reason for this is that Arkansas’ RPGs were calculated using 

the 2018 CENRAP CAMx modeling completed in 2006/2007, which assumed that Flint Creek 

would install scrubbers to meet the presumptive SO2 BART limit of 0.15 lb/MMBtu, that Flint 

Creek and White Bluff would install low NOX burners to satisfy NOX BART, and that AECC 

Bailey and Entergy Lake Catherine would be shut down by 2018. In contrast, our RPGs reflect a 

 

84 40 CFR 51.308(d)(1). 

85 40 CFR 51.308(d)(1)(iv). 

86 40 CFR 51.308(d)(1)(ii). 

87 40 CFR 51.308(g)-(h). 

88 “Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program,” at 5-2. 89 These RPGs are calculated using the same methodology described in our proposal and TSD. 

See “CACR UPBU RPG analysis 2018.xlsx” for additional information on the calculation of the RPGs. 
71 

more stringent SO2 emission limit of 0.06 lb/MMBtu at Flint Creek and the installation of low 

NOX burners at Independence in addition to Flint Creek and White Bluff, but also the continued 

operation of AECC Bailey and Entergy Lake Catherine. In other words, our RPGs reflect 

additional emission reductions from Flint Creek and Independence, but more emissions from 

AECC Bailey and Entergy Lake Catherine. 

The fact that the RPGs we have calculated are very close to those originally submitted by 

Arkansas does not undermine the reasonableness of our action. We disapproved Arkansas’ RPGs 

in part because Arkansas failed to conduct a four-factor analysis, as required by the CAA and the 

Regional Haze Rule. Without a four-factor analysis, we were unable to verify whether any 

additional control measures were necessary to make reasonable progress—the core requirement 

of the CAA’s visibility program.90 After conducting a full four-factor analysis, we have 

determined that controls at the Independence plant are cost-effective and reasonable and 

therefore necessary to make reasonable progress. The visibility benefits of the SO2 controls at 

Independence, along with benefits of the SO2 BART controls at White Bluff, and additional 

BART controls at AECC Bailey, AECC McClellan, Entergy Lake Catherine, and the Domtar 

Ashdown Mill will be fully realized in 2021, and we expect Arkansas to properly take these 

benefits into account when developing RPGs for 2028. 

With regard to the comment that Entergy’s alternative multi-unit strategy would ensure that 

Arkansas’ Class I areas remain below the URP glidepath, we discuss elsewhere in this RTC 

document that being below the URP glidepath does not mean that the regional haze requirements 

are automatically satisfied or that no controls are necessary under the reasonable progress 

requirements. We also address comments regarding Arkansas’ Five-Year Progress Report and 

comments regarding the URP glide path elsewhere in this RTC document. 

We also address Entergy’s specific comments regarding its proposed NOX emission limits for 

White Bluff and Independence elsewhere in this RTC document. 

3. Reasonable Progress Goals/ Reasonable Progress Analysis 

3.a. EPA did not perform an adequate Reasonable Progress Analysis 

Comment: EPA should allow time to determine the impacts of other regulatory programs 

and allow for better defined and more cost-effective decisions, especially considering there 

will be future opportunities to re-evaluate the RPGs and URPs. 

[Entergy Mississippi Inc. (0168) p. 13; AEP-SWEPCO July 15, 2015 comments (0164) p. 3-5, 

and August 7, 2015 comments (0167) p. 4-5] EMI and American Electric Power/Southwest 

Electric Power Company (AEP-SWEPCO) both stated that EPA failed to consider the full 

improvements in visibility at Class I areas that will result from other emission reduction 

programs currently being implemented and, therefore, underestimated the likely overall visibility 

improvement in those areas. EPA determined CSAPR to be better than BART but did not 

quantify the added benefit that would result from that trading program over and above the site-

 

90 CAA section 169A(b)(1) and (g)(1). 
72 

specific BART NOX controls currently in the FIP. Implementation of the Mercury and Air 

Toxics Standards rule (MATS) will, in many cases, result in PM rates well below current 

emissions rates than those approved in Arkansas’s SIP providing additional benefits not 

quantified in the RPG analysis. Additionally, implementation of the MATS rule and several 

other Clean Air Act programs, including CSAPR, the 1-hour SO2 National Ambient Air Quality 

Standard (NAAQS), and the ozone NAAQS will, in many cases, also result in additional 

reductions in visibility-impairing pollutants beyond those relied upon when analyzing impacts at 

Arkansas’ Class I Federal areas.91 Time should be allowed for evaluating the emission reductions 

and visibility improvement impacts resulting from these programs before requiring the 

installation of expensive controls that may not achieve significant additional visibility benefits. 

[AEP-SWEPCO July 15, 2015 comments (0164) p. 6, and August 7, 2015 comments (0167) p. 7-

8] AEP-SWEPCO stated that imposing costly controls in the first planning period is unwarranted 

in such a long term goal program and that the obligation to consider costs is not only related to 

quantity but also timing. A much more prudent approach would be to allow time to determine the 

impacts of CSAPR, MATS, and other programs before requiring costly controls on a facility that 

will soon also need to reevaluate options related to the 111(d) program. Waiting until that 

program's requirements are better defined will allow for more cost-effective decisions. 

AEP-SWEPCO stated that considering that the visibility improvements of these programs have 

not yet been quantified, and the gradual progress anticipated in establishing such a long term 

goal, EPA should be patient and not take such aggressive action in overriding a reasonable state 

SIP and imposing additional controls at this time. The regional haze program is not for the 

purpose of addressing health issues and the added visibility improvement associated with the 

controls proposed for the Independence facility do not indicate an urgent need to take this action. 

There will be many future opportunities for EPA to reevaluate the RPG and URP and the 

controls being contemplated could be added in later planning periods, if needed. 

[Conway Corporation et. al. (0172) p. 11-12 and EEAA (0173) p. 15] Conway Corporation et. al. 

and EEAA stated that in proposing to require the installation of still more controls, EPA has 

again failed to consider the full improvements in visibility to Class I areas that will result from 

other emission reduction programs currently being implemented and has, therefore, 

underestimated the likely overall visibility improvement to those areas. EPA has determined 

CSAPR to be better than BART and has not quantified the added benefit that would result from 

that trading program over the site-specific BART NOX controls currently in the FIP. 

Furthermore, implementation of the Mercury and Air Toxics Standards (MATS) rule will, in 

many cases, result in PM rates well below current emissions rates and those approved in 

Arkansas’s SIP, providing additional benefits not quantified in the RPG analysis.92 

 

91 Although the MATS rule was remanded by the U.S. Supreme Court in Michigan et al. v EPA, 135 S.Ct. 2699 

(2015), EMI anticipates that, even if the rule is stayed or vacated while EPA undertakes its cost analysis in 

compliance with the Court’s decision, MATS and its associated emission reductions will go forward by the end of 

the first planning period.    92 Although the MATS rule was remanded by the U.S. Supreme Court in Michigan et al. v EPA (June 29, 

2015), Commenters anticipate that even if the rule is stayed or vacated while EPA undertakes its cost analysis in 

compliance with the Court’s decision, MATS and its associated emission reductions will go forward by the end of 

the first planning period. 
73 

Conway Corporation et. al. and EEAA stated that given that Arkansas’ Class I areas are ahead of 

the URP necessary to obtain the national visibility goal even before implementation of BART, 

EPA should allow more time for evaluating the emission reductions and visibility improvement 

impacts resulting from these programs before requiring installation of expensive controls that 

may not achieve perceptible visibility benefits. 

[EEAA (0173) p. 15-16] EEAA stated that in spite of the visibility benefits from other emission 

reduction programs (over and above currently documented visibility improvement), EPA is 

pushing forward with a proposal for additional controls under the guise of reasonable progress. 

EEAA disagrees with EPA’s conclusion that additional controls are necessary to meet reasonable 

progress. A much more prudent approach would be to allow time to determine the impacts of 

CSAPR, MATS and other programs before requiring costly controls on a facility that will soon 

also need to reevaluate options related to the 111(d) program. Waiting until that program’s 

requirements are better defined will allow for more reasonable, cost-effective decisions; and, the 

design and intent of the regional haze program is consistent with such a thoughtful and 

deliberative planning approach. Considering that the visibility improvements of these programs 

have not yet been quantified and the Regional Haze Rule’s design for long-term gradual 

progress, EPA should be patient and should not take such unreasonable and aggressive action to 

impose costly controls that yield imperceptible visibility benefits. 

Response: We disagree that EPA should delay implementation of this FIP to allow time for 

evaluating the emission reductions and visibility improvement impacts resulting from other EPA 

programs. Congress added the visibility provisions in section 169A of the CAA in 1977; 

Congress later amended the Act in 1990 tasking EPA to carry out its regulatory responsibilities 

under 169A. EPA issued the Regional Haze Rule in 1999 requiring states to submit regional haze 

SIPs by 2007. At this point, we do not consider it appropriate to further delay implementation of 

measures to improve visibility in Class I areas. In addition to the many delays in addressing 

visibility, we note that a significant portion of our FIP addresses the requirements for BART. 

Given the statutory and regulatory requirements for BART, we cannot put off implementation of 

these measures to see what other improvements to visibility might happen through the 

implementation of other programs. We further do not agree that the emission limitations for the 

Independence plant should be delayed. As explained elsewhere in this document, we have 

determined that the measures in the FIP applicable to Independence are cost-effective, will have 

a meaningful impact on visibility in Class I areas, and are appropriate for ensuring reasonable 

progress. 

We also note that EPA has an obligation to promulgate a FIP within 2 years of disapproving a 

SIP in whole or in part, unless the State corrects the deficiency and EPA approves the plan. 

There is no authority in the CAA for EPA to further delay our action for the reasons provided by 

the commenter. The fact that we let two years elapse without fully approving a regional haze SIP 

led a district court in Arkansas to order EPA to finalize a RH rulemaking by a date certain 

(August 31, 2016).93

The Regional Haze Rule requires states to estimate 2018 emission inventories as part of the 

planning process. EPA approved Arkansas’ estimates of its 2018 emissions inventory and those 

 

93 Sierra Club v. Gina McCarthy, No. 4.14CV00643JLH (ED Ark. Western Div. Nov. 3, 2015). 
74 

of its neighboring states.94 Each state included projected emissions inventories for 2018 in its 

SIP. As explained in our review of the Arkansas Regional Haze SIP, CENRAP with assistance 

from Arkansas developed an emissions inventory for 2018 “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.” EPA approved Arkansas’ 2018 

emissions inventory in its final action on the SIP. We are not revisiting our prior approval of 

these emissions inventories in today’s rulemaking. 

With regard to the comment that we have underestimated the likely overall visibility 

improvement in Arkansas’ Class I areas by ignoring recent regulatory requirements, we agree 

that there have been a number of regulatory changes over the years since the emission 

inventories for Arkansas and the surrounding states were developed. As noted above, we 

approved these inventories when we took action on Arkansas’ Regional Haze SIP as valid 

estimations of 2018 emissions inventories. We note that Arkansas is required to update these 

inventories in its next regional haze SIP, due at this time in just over two years.95 For the near 

term, we do not expect significant changes in emissions from Arkansas sources between now and 

2018. More significantly, the commenters’ suggestions that EPA should further delay the 

implementation of measures to improve visibility while assessing the visibility improvements 

that will result from other existing programs relies on the conclusion that there is a specific rate 

of improvement that constitutes reasonable progress. The reasonable progress goals are not 

enforceable goals, but rather provide a degree of transparency regarding the rate of improvement 

in visibility anticipated for each Class I area over the planning period of the SIP. That Arkansas 

is meeting the glidepath, largely due to emission reductions in other states, does not support the 

conclusion that the most significant sources of visibility impairment in Arkansas should be left 

for later. 

It appears that the improvements in visibility in Class I areas in Arkansas projected by CENRAP 

were due largely to projected emission reductions from other states. The emissions inventories 

for Arkansas show that the state expected its emissions of every visibility pollutant but for NOX

to increase over the first planning period, notwithstanding the reductions expected from federal 

regulations. Thus, for example, SO2 emissions were expected to increase by 6,000 tons per 

year.96 In terms of changes in emissions inventories in Arkansas, we do not expect significant 

changes in emissions from Arkansas sources between now and 2018. 

The relevance of the comment that EPA determined CSAPR to be better than BART but did not 

quantify the added benefit that would result from that trading program over and above the sitespecific BART NOX controls currently in the FIP is unclear. In determining that CSAPR 

provides for greater reasonable progress than BART, EPA assessed the visibility benefits across 

 

94 See 76 FR at 64212-13 and 77 FR 14604 for our approval of Arkansas’ estimates of its 2018 emissions inventory. 

See 76 FR at 16189 and 76 FR 81728 for our approval of Oklahoma’s estimates of its 2018 emissions inventories 

but for its inclusion of reductions from the OG&E and AEP/PSO coal fired units that were not ultimately required 

by Oklahoma; the Oklahoma BART FIP we promulgated addressed this deficiency. See 77 FR at 11971 and 77 FR 

38007 for our approval of Missouri’s estimates of its 2018 emissions inventory. See 79 FR at 74858-74861 and 81 

FR 296 for our approval of Texas’ estimates of its 2018 emissions inventory.

95 EPA has proposed to give the states an additional three years to submit the next update to their regional haze SIP, 

but as of the date of today’s final action, has not yet taken final action on that proposal. 

96 76 FR at 64213. 
75 

the entire continental United States and found that on average across all Class I areas, CSAPR 

provided for greater visibility improvement than BART. To make this determination, EPA made 

broad assumptions as to what controls would constitute BART based on the presumptive BART 

limits in the BART Guidelines. CSAPR requires significant SO2 and NOX reductions in many 

states; in Arkansas, however, the state is subject only to an ozone season NOX budget 

requirement. The commenters have presented no evidence that CSAPR will result in any added 

benefit over and beyond the site-specific BART controls in the FIP at the Class I areas impacted 

by Arkansas, but if the commenters’ point is that a program requiring hundreds of thousands of 

tons of reductions in SO2 and NOX across a broad region will achieve greater visibility 

improvement than the modest BART NOX controls in the Arkansas FIP, then we would have to 

agree. To the extent the commenter is arguing that our revised reasonable progress goals do not 

account for the improvement that will result from implementation of CSAPR, we note that the 

states assumed the implementation of CAIR in setting their goals but that CAIR has now been 

replaced by CSAPR. 

With regard to the comment that EPA should not “take such aggressive action in overriding a 

reasonable state SIP,” we point out that our proposed partial approval and partial disapproval of 

the Arkansas RH SIP submitted to us in 2008 was published in the Federal Register on October 

17, 2011.97 We held a 66 day public comment period and our final action was published on 

March 12, 2012.98 In our final action, we determined that the Arkansas RH SIP does not meet 

certain elements of the Federal regional haze requirements and partially approved and partially 

disapproved the Arkansas RH SIP. While we did receive adverse comments on that proposal, no 

petitions were filed for judicial review of the final rule, and the rule became effective on April 

11, 2012. Therefore, the comment that we are “overriding a reasonable state SIP” is not germane 

to the proposed action we solicited comments on and is outside the scope of this action. 

We address in other sections of this document comments contending that requiring controls on 

the Entergy Independence Plant is not expected to achieve significant additional visibility 

benefits or perceptible visibility benefits. We also address elsewhere in this section of the 

document comments contending that additional controls are not necessary at this time to make 

reasonable progress because Arkansas’ Class I areas are projected to be below the URP 

glidepath. 

Comment: EPA failed to perform the analysis required to establish RPGs and instead 

arbitrarily required emissions controls for Entergy Independence. 

[ADEQ (0160) p. 8-13] ADEQ stated that EPA improperly performed the reasonable progress 

analysis by applying the reasonable progress factors set forth in the Regional Haze Rule to 

require specific emissions controls for Entergy Independence Units 1 and 2. Despite the fact that 

Entergy’s Independence Plant is not identified as subject to BART, EPA requires specific 

emissions controls for the plant in the proposed FIP under an analysis using four factors intended 

to aid in establishing unenforceable numerical goals for reducing regional haze, called 

 

97 76 FR 64186. 

98 77 FR 14604.
76 

“reasonable progress goals.” This type of analysis has no basis in the Regional Haze Rule or 

other relevant law. 

ADEQ stated that EPA is required to engage in “reasoned decision-making.”99 Not only must an 

agency’s decreed result be within the scope of its lawful authority, “but the process by which it 

reaches that result must be logical and rational.”100 In Michigan v. E.P.A., the Supreme Court of 

the United States explained that “agency action is lawful only if it rests ‘on a consideration of the 

relevant factors.’”101 In the proposed FIP, EPA has disregarded the framework in the Regional 

Haze Rule and failed to consider the factors required for establishing Arkansas’ Reasonable 

Progress Goals (RPGs). 

ADEQ stated that EPA’s Regional Haze Rule primarily addresses visibility impairment from 

point sources by requiring BART for certain existing stationary sources.102 In contrast to the 

BART requirements, which are specific to point sources, EPA also requires states to develop 

broad RPGs to be expressed in deciviews that each state must set based on the URP and the 

following four factors (“reasonable progress factors”): (1) the costs of compliance; (2) the time 

necessary for compliance; (3) the energy and non-air quality environmental impacts of 

compliance; and (4) the remaining useful life of any potentially affected sources.103

ADEQ stated that the Regional Haze Rule uses the imperative “must” in reference to 

consideration of both the URP and the reasonable progress factors.104 Based on these 

considerations, either the state, or EPA in the case of a FIP, must set specific numerical goals in 

deciviews - the RPGs which are intended to ensure that a state is making progress toward 

achieving natural visibility conditions.105 The Regional Haze Rule requires a state, or EPA, to 

consider both the reasonable progress factors and the URP in setting the RPGs.106 However, EPA 

completely disregards its own framework in the proposed FIP. Instead of utilizing the four 

reasonable progress factors in conjunction with the URP to set numerical goals measured in 

deciviews, EPA applies the reasonable progress factors in order to require emissions controls for 

Independence Plant Units 1 and 2, which it refers to as a “reasonable progress source.” 

Effectively, EPA has applied the reasonable progress factors to the Independence Plant as if it 

were a BART analysis. Rather than considering the URP in conjunction with the reasonable 

progress factors, EPA completely dismisses the URP, which Arkansas is on track to meet in the 

 

99 See State of AR, ADEQ, State Implementation Plan Review for the Five-Year Regional Haze Progress Report 

(April 2014) attached as Exhibit 1, at 56. 

100 Id. 101 Id. (citing Motor Vehicle Mfrs. Assn. of United States, Inc. v. State Farm Mut. Automobile Ins. Co., 463 U.S. 29, 

43, 103 S.Ct. 2856, 77 L.Ed.2d 443 (1983) (internal quotation marks omitted)). 

102 40 C.F.R. § 51.308 103 40 C.F.R. § 51.308(d)(1)(i) 104 40 C.F.R. § 51.308 (d)(1)(i)(A)(“ the State must: ... (A) consider the costs of compliance, the time necessary for 

compliance, the energy and non-air quality environmental impacts of compliance, and the remaining useful life of 

any potentially affected sources” (emphasis added)); 40 C.F.R. § 51.308 (d)(1)(i)(A) (“In establishing the reasonable 

progress goal, the State must consider the uniform rate of improvement in visibility and the emission reduction 

measures needed to achieve it for the period covered by the implementation plant” (emphasis added)) 

105 40 C.F.R. § 51.308(d)(1) 106 40 C.F.R. § 51.308(d)(1)(i) 
77 

first planning period, by stating that “the URP does not establish a ‘safe harbor’ for the state in 

setting its progress goals.”107

ADEQ stated that furthermore, EPA fails to explain how factors required to be considered in 

setting specific numerical targets, which are themselves not enforceable, could somehow be used 

to require specific enforceable limits for a single plant. In 40 C.F.R. § 51.308(d)(1)(v), the 

Regional Haze Rule states that “[t]he reasonable progress goals established by the State are not 

directly enforceable.” There is simply no legal justification for the analysis EPA has performed 

using the reasonable progress factors set out in 40 C.F.R. § 51.308(d)(1)(A). EPA cites no legal 

authority for identifying and requiring emissions controls for “reasonable progress sources.” The 

term “reasonable progress source” does not itself appear in the Regional Haze Rule or related 

guidance documents. 

ADEQ stated that the state, or EPA in the case of a FIP, is required to “include a demonstration 

showing how these [reasonable progress] factors were taken into consideration in selecting the 

goal.”108 EPA has not performed this task in the proposed FIP. EPA meticulously presents its 

analysis under headings with each reasonable progress factor clearly marked, but this analysis 

does not explain how those factors were taken into consideration in selecting numerical goals in 

deciviews as required by the Regional Haze Rule. In fact, EPA makes no mention of the factors 

required for consideration under 40 C.F.R. § 51.308(d)(1)(A) except in relation to the analysis of 

“Entergy Independence Plant Units 1 and 2.”109 

ADEQ stated that EPA’s arbitrary use of the reasonable progress factors to evaluate the Entergy 

Independence Plant resulted in EPA foregoing a proper analysis of the reasonable progress 

factors in relation to the RPGs. Critically, EPA has failed to consider the “costs of compliance” 

with the RPGs in the proposed FIP. Although all of the reasonable progress factors are required 

to be considered in setting the RPGs, the Supreme Court of the United States recently reiterated 

the importance of considering cost in relation to electric generating units such as the two units at 

the Entergy Independence Plant. In Michigan v. E.P.A., the Supreme Court held that it was 

unreasonable for EPA to interpret the phrase “appropriate and necessary” as not including an 

analysis of costs in implementing the Mercury and Air Toxics Standards (MATS) for power 

plants.110 In doing so, the Supreme Court stated that “[o]ne would not say that it is even rational, 

never mind ‘appropriate,’ to impose billions of dollars in economic costs in return for a few 

dollars in health or environmental benefits.”111 EPA’s decision to forego any type of analysis 

involving the reasonable progress factors in relation to setting the RPGs is particularly 

troublesome in light of the Supreme Court’s concerns about costs in Michigan v E.P.A.

ADEQ stated that EPA asserts that it is appropriate to evaluate Entergy’s Independence Plant 

“because it is a significant source of SO2 and NOX ... even though Arkansas’s Class I areas and 

those outside of Arkansas most significantly impacted by Arkansas sources are projected to meet 

 

107 See Exhibit 1. 108 40 C.F.R. § 51.308(d)(1)(i)(A). 109 80 FR 18944 at 18992-18998 110 Michigan v. E.P.A., No. 14-46, 2015 WL 2473453, at *7 (U.S. June 29, 2015). 111 Id. 
78 

URP for the first planning period.”112 In fact, Arkansas is projected to meet the URP despite 

none of the controls specified in the SIP or the proposed FIP having been installed to date. The 

additional control measures for the Entergy Independence Plant are especially unnecessary in 

light of Arkansas being on track to meet the Uniform Rate of Progress (URP) for the first 

planning period, which ends in 2018.113 EPA singled out Entergy’s Independence Plant through a 

cursory evaluation of the National Emissions Inventory data that ADEQ provides to EPA 

annually, which EPA then used in modeling for potential visibility impacts.114 In doing so, EPA 

has ignored its own framework for establishing reasonable progress goals and requiring specific 

emissions controls for a point source. EPA should have considered the four factors in 40 C.F.R. § 

51.308(d)(1)(A) along with the URP as set forth in 40 C.F.R. § 51.308(d)(1)(B) in setting 

numerical RPGs. 

ADEQ stated that in the Arkansas Regional Haze Approval/Disapproval, EPA rejected 

Arkansas’s RPGs because the state relied on the URP rather than both the URP and the 

reasonable progress factors to propose its RPGs. EPA stated that “[u]ntil the State conducts a 

proper evaluation of the four statutory factors ... we will not know whether different RPGs are 

appropriate for Arkansas’s Class I areas.”115 Just as EPA was unable to determine whether 

Arkansas’s RPGs were appropriate, ADEQ cannot determine whether the RPGs presented by 

EPA are appropriate because EPA has failed to perform an analysis of its RPGs using the factors 

in 40 C.F.R. §51.308(d)(1) and instead applied those factors to an assessment of controls for 

Entergy’s Independence Plant. Therefore, EPA should withdraw the proposed FIP, and ensure a 

proper analysis is included in any subsequent plan. 

[Arkansas Attorney General (0162) p. 3-4] The Attorney General for the State of Arkansas stated 

that the States must establish Reasonable Progress Goals (RPGs) for each Federal Class I area in 

the state to provide incremental visibility improvements toward he ultimate goal of reaching 

natural background conditions by 2064. 40 C.F.R. § 51.308(d). EPA disapproved Arkansas’s 

RPGs in 2012; however, EPA approved the State’s commitment to submitting periodic progress 

reports. Based on a May 2015 progress report, EPA is aware that Arkansas is meeting the 

Uniform Rate of Progress (URP), which is a “glide path” for reaching the 2064 goal. See State 

Implementation Plan Review for the Five-Year Regional Haze Progress Report, Revised May 

2015, Arkansas Department of Environmental Quality, found at: 

https://www.adeq.state.ar.us/air/planning/pdfs/ar_5yr_prog_rep_review-final-6-2-2015.pdf. 

The Attorney General stated that 40 C.F.R. § 51.308(d)(1) requires the States to “establish goals 

(expressed in deciviews) that provide for reasonable progress towards achieving natural visibility 

conditions.” In setting a reasonable progress goal, the State must “consider the costs of 

compliance, the time necessary for compliance, the energy and non-air quality environmental 

impacts of compliance, and the remaining useful life of any potentially affected sources, and 

include a demonstration showing how these factors were taken into consideration in selecting 

the goal.” 40 C.F.R. § 51.308(d)(1)(i)(A) (emphasis added). In North Dakota v. EPA, 730 F.3d 

 

112 80 FR 18944 at 18992. 113 See State of Arkansas, ADEQ, State Implementation Plan Review for the Five-Year Regional Haze Progress 

Report (April 2014), attached as Exhibit 1 to ADEQ’s comments, at 56. 

114 Id. at 18991-18992. 115 77 FR 14604 at 14621.
79 

750 (2013), the Eighth Circuit Court of Appeals held that EPA was bound to follow the same 

regulatory requirements as the State when promulgating a FIP. 

The Attorney General stated that thus, if EPA proposes RPGs in a FIP it must set those goals 

using the regulatory factors, including a demonstration of how those factors were applied. Then 

EPA may determine that additional measures are necessary to meet the goals. The law clearly 

states that “reasonable progress goals...are not directly enforceable.” 40 C.F.R. §51.308(d)(1)(v). 

However, EPA uses the guise of setting RPGs to unlawfully apply a BART-type analysis to the 

Entergy Independence electric generating unit (“Independence”). Independence is not subject to 

the BART requirements because it was not constructed between 1962 and 1977. Its construction 

commenced after this time period. EPA uses a “reasonable progress analysis for point sources” 

to shoehorn Independence into the use of emission controls without a legal basis for doing so. 

This action is outside the scope of the Clean Air Act and its implementing regulations. 

The Attorney General stated that as cited above, the law clearly sets forth the process for RPGs. 

EPA must begin by setting a RPG and then conduct an analysis of whether additional controls 

are necessary. However, EPA turns this process on its head. First, EPA looked at the emissions 

from Independence as a point source. It then uses the regulatory factors for setting a RPG to 

justify a “cut and paste” of its BART analysis for Entergy White Bluff and calls it a “reasonable 

progress analysis for point sources.” There is no authority for this procedure in the law. This is a 

textbook example of regulatory overreach to achieve a policy goal. Only after completing its 

BART-like analysis for Entergy Independence does EPA discuss the establishment of RPGs. In 

direct contravention of 40 C.F.R. § 51.308(d)(1)(i)(A), EPA fails to demonstrate how the 

regulatory factors were used to set the goals. Its discussion of those factors as it relates to 

Entergy Independence is unlawful and cannot be substituted for the demonstration required by 

law. 

The Attorney General stated that EPA’s proposed “reasonable progress” action clearly exceeds 

its authority under the Clean Air Act and is arbitrary and capricious. 

Response: We disagree with the commenters on all issues raised. As an initial matter, the 

commenters appear to have a misunderstanding of the process for establishing RPGs. One 

commenter contends that the law clearly sets forth that EPA must begin the process for 

[establishing] RPGs by setting the RPGs using the regulatory factors, and only after that may 

EPA determine that additional measures are necessary to meet that goal. The commenter further 

contends that EPA’s analysis was flawed because we turned this process on its head by first 

completing an analysis of the reasonable progress factors for the Independence Plant and then 

discussing establishment of the RPGs. This is incorrect. The CAA requires reasonable progress 

determinations to be based on consideration of “the costs of compliance, the time necessary for 

compliance, the energy and nonair quality environmental impacts of compliance, and the 

remaining useful life of any existing source subject to such requirements.” CAA section 

169A(g)(1). The regional haze regulations under 40 CFR 51.308(d)(1)(i) also require 

consideration of these four statutory factors in establishing the RPGs: 

(i) In establishing a reasonable progress goal for any mandatory 

Class I Federal area within the State, the State must: 
80 

(A) Consider the costs of compliance, the time necessary for 

compliance, the energy and non-air quality environmental impacts 

of compliance, and the remaining useful life of any potentially 

affected sources, and include a demonstration showing how these 

factors were taken into consideration in selecting the goal. 

The statute and regulations are clear that in establishing the RPGs, states (or EPA in standing in 

the shoes of the state and promulgating a FIP) must conduct an analysis of the four statutory 

factors to determine whether additional controls (i.e., beyond those required under BART and 

other “on the books” controls) are necessary to make reasonable progress. These statutory factors 

are only relevant in the context of considering specific possible emission reduction measures for 

specific sources or groups of sources. A state or EPA determines the rate of progress that is 

reasonable for a Class I area after taking into account these factors -- as applied to specific 

sources or groups of sources – to determine what additional controls should be required in its 

regional haze SIP or FIP. The fact that under 40 CFR section 51.308, section 308(d)(1) on setting 

RPGs appears before section 308(d)(3) on long-term strategy requirements does not change this 

fact and does not mean that RPGs can or must be set prior to consideration of specific control 

measures for specific sources under the reasonable progress requirements. 

This approach to setting RPGs was understood and used by the states and the RPOs (including 

Arkansas and CENRAP), which took into account the anticipated emission reductions from 

specific measures adopted to improve visibility as well as from other CAA requirements in 

calculating 2018 emission inventories and then established RPGs based on the anticipated 

changes in emissions over the planning period of the SIP. A description from last year by EPA of 

the design of the regional haze program and how states established reasonable progress goals 

provides a useful overview of how the program has worked in practice, based on these regulatory 

requirements: 

The Regional Haze Rule, which was promulgated not long after the 1997 

revisions to the ozone and fine particulate matter (PM2.5) National 

Ambient Air Quality Standards (NAAQS), was explicitly designed to 

facilitate the coordination of emissions management strategies for regional 

haze with those needed to implement the NAAQS. See 64 FR 35713, 

35719–35720 (July 1, 1999). More generally, the Regional Haze Rule 

requires states to include all air quality improvements that will be 

achieved by other CAA programs and state air pollution control 

requirements when assessing changes in emissions and visibility to be 

expected during the period of their regional haze SIP. 64 FR at 35733. 

This is made clear in the haze regulations which prohibit states from 

adopting RPGs that represent less visibility improvement than is expected 

to result from the implementation of other CAA requirements during the 

planning period. 40 CFR 51.308(d)(1)(vi). Given this requirement, states 

included in their regional haze SIPs a number of Federal regulations for 

mobile and stationary sources that had or were expected to come into 

effect after the baseline period and that were anticipated to result in 
81 

reductions of visibility impairing pollutants. These regulations included 

NAAQS implementation measures as well as other CAA requirements, 

such as mobile source rules or Maximum Achievable Control Technology 

(MACT) standards issued under section 112 of the CAA. . . 

Thus, states took into account the anticipated emission reductions from a 

wide range of measures in setting RPGs. To model the visibility 

conditions in 2018, states used projected emission inventories based on the 

best information before them. Given the significance of emissions from 

EGUs to haze, these projections were based, among other things, on 

expected changes in energy demand affecting capacity utilization of power 

plants. States also sometimes included an emissions buffer to account for 

the possible construction of new power plants or other types of facilities. 

States also took into account, as described above, anticipated reductions in 

emissions resulting from recent Federal rules addressing non-visibilityrelated requirements, as well as consent decrees, significant measures 

adopted by nearby states, and specific measures to address the 

requirements of the visibility program. Thus, in forecasting future 

visibility conditions, states by design took into account to the extent 

possible ‘‘outside forces’’ and a host of overlapping requirements.116

Because the reasonable progress analysis and the BART analysis share some regulatory 

requirements, the commenters argue that we performed “a BART analysis” for Independence. 

States and EPA have generally taken very similar approaches to analyzing BART and reasonable 

progress controls during the first planning period, as the relevant factors to be considered overlap 

to a large degree: Compare section 169A(g)(1) (“the costs of compliance, the time necessary for 

compliance, the energy and nonair quality environmental impacts of compliance, and the 

remaining useful life of any existing source subject to such requirements”) with section 

169A(g)(2) (“the costs of compliance, the energy and nonair quality environmental impacts of 

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

life of the source, and the degree of improvement in visibility which may reasonably be 

anticipated to result from the use of such technology”). The type of source-specific analysis 

undertaken for Independence is a careful and thorough analysis that by its nature tends to require 

cost-effective controls on only the largest contributors to visibility impairment. It is both logical 

and rational and is based on consideration of the relevant statutory factors. 

The commenter’s suggestion that because the RPGs are not themselves enforceable we cannot 

require specific enforceable limits for a single plant is not consistent with the requirement that 

each regional haze SIP or FIP include enforceable emissions limitations as necessary to ensure 

that the SIP or FIP will provide reasonable progress toward the national goal of natural visibility 

conditions. While our FIP does consider and ultimately apply controls on an individual source 

basis to assure reasonable progress, this is consistent with the CAA, our regulations, and past 

EPA guidance. The four statutory factors under CAA Section 169A(g) and 40 CFR 

51.308(d)(1)(i)(A) are directed to the listed possible features or consequences of potential 

emission control measures for sources, including individual stationary sources. The CAA and the 

 

116 80 Fed. Reg. 32019, 32021 (June 5, 2015)(emphasis added). 
82 

Regional Haze regulations expressly set forth that the reasonable progress analysis must consider 

the “compliance” time and costs for “potentially affected sources.” A state determines the rate of 

progress that is reasonable for a Class I area after taking into account the four statutory factors-- 

as applied to specific sources or groups of sources – to determine what additional controls should 

be required in its regional haze SIP. Thus, individual stationary sources may be subject to 

emission limits and source specific analysis when determining whether additional controls are 

necessary to make reasonable progress. We accordingly disagree with the argument that EPA 

should not include enforceable emission limits for an individual source in our FIP to ensure 

reasonable progress. Further, we discuss elsewhere in this document that the numeric RPGs 

established by the state or EPA represent the best estimate of the degree of visibility 

improvement that will result in 2018 from changes in emissions inventories, changes driven by 

the particular set of control measures the state has adopted in its regional haze SIP or EPA in a 

regional haze FIP to address visibility, as well as all other enforceable measures expected to 

reduce emissions over the period of the SIP from 2002 to 2018.117 Thus, the RPGs are intended 

to provide a degree of transparency regarding the rate of improvement in visibility anticipated for 

each Class I area over the planning period of the SIP. But the RPGs themselves are not 

enforceable.118 EPA cannot enforce an RPG in the sense of seeking to apply penalties on a state 

for failing to meet the RPG or obtaining injunctive relief to require a state to achieve its RPG. 

However, the long-term strategy can and must contain emission limits and other control 

measures that apply to specific sources under the reasonable progress requirements, and that are 

themselves enforceable. The fact that the RPGs are not enforceable does not mean that we cannot 

conduct a source-specific evaluation of the reasonable progress factors or require source-specific 

emission limits under the reasonable progress requirements. 

Furthermore, if the CAA’s requirements were such that only sources subject to controls for 

BART could be looked to for emission reductions to promote reasonable progress, then States, or 

EPA acting as necessary in the place of a State, would have little to no room for additional 

progress and even less need for sequential planning periods to build on past progress. Sourcespecific emission limitations, as promulgated in our FIP, are manifestly envisioned by the statute. 

While reasonable progress is not required to be demonstrated on a source-by-source basis (or via 

“source-specific analysis”), this emphatically does not mean that individual sources are free from 

any possibility of required new or stricter controls as part of establishing reasonable progress 

goals or what is necessary as part of a long-term strategy. In other words, an appropriately 

focused and detailed analysis using a so-called category based approach may (and in some cases 

manifestly should) result in a determination that source-specific controls are needed to make 

reasonable progress. To conclude otherwise vitiates the statutory purpose and asks for an entirely 

ineffectual analysis which could not result in possible emission limitations as expressly 

envisioned in the statute. See CAA Section 169A(b)(2); 40 CFR 51.308(d)(1) and (3). We also 

note that even though we are required to prepare our own analysis to do a FIP, this does not 

mean our analysis and conclusions are precisely what Arkansas would itself conclude in its SIP 

to meet the CAA requirements. 

The commenter states that we make reference to “reasonable progress sources” in our FIP 

proposal, and states that this term does not appear in the RH rule or related guidance. The 

 

117 64 FR 35733. 118 See 51.308(d)(1)(v).
83 

commenter contends that we cite no legal authority for identifying and requiring emissions 

controls for “reasonable progress sources.” Where we used the term “reasonable progress 

sources” in our FIP proposal, we used it as shorthand to refer to sources that we are controlling 

or evaluating for controls under the reasonable progress requirements. 

In our Arkansas FIP, we have conducted the requisite analysis to determine what controls are 

necessary to make reasonable progress by considering those sources and source categories with 

the most significant impact on visibility impairment. We explained in our FIP proposal that our 

reasonable progress analysis focused on the point source category since the other source 

categories each contribute a much smaller proportion of the total light extinction at each Class I 

area in Arkansas based on the CENRPAP modeling.119 For example, the point source category 

contributed 81.04 Mm-1 out of a total light extinction of 133.93 Mm-1 for the 20% worst days in 

2002 at Caney Creek, or approximately 60.5% of the total light extinction. Similarly, the point 

source category contributed 77.80 Mm-1 out of a total light extinction of 131.79 Mm-1 for the 

20% worst days in 2002 at Upper Buffalo, or approximately 59% of the total light extinction. In 

comparison, area sources, which are the source category with the next highest contribution to the 

total light extinction at each Class I area, contributed approximately 13.3% of the total light 

extinction at Caney Creek and 15.5% at Upper Buffalo. The remaining source categories each 

contributed less than 6% of the total light extinction at each Class I area.120 Therefore, we found 

it is appropriate for our reasonable progress analysis to focus on the point source category. 

We also note that the CENRAP CAMx modeling shows that on most of the 20% worst days in 

2002, total extinction is dominated by sulfate at both Caney Creek and Upper Buffalo.121

Additionally, total extinction at Caney Creek is dominated by nitrate on four of the 20% worst 

days in 2002, and a significant portion of the total extinction at Upper Buffalo on two of the 20% 

worst days in 2002 is due to nitrate.122 Therefore, we consider both SO2 and NOX to be key 

pollutants that contribute to visibility impairment at Arkansas’ Class I areas and considered both 

SO2 and NOX controls in our reasonable progress analysis. 

We explained in our FIP proposal that as a starting point in our analysis to determine whether 

additional controls on Arkansas point sources are reasonable in the first regional haze planning 

period, we examined the most recent SO2 and NOX emissions inventories for point sources in 

Arkansas. Our examination of the emissions inventory revealed that the magnitude of emissions 

from the Independence Plant warranted further evaluation to determine if the source is a 

significant contributor to regional haze in Arkansas’ Class I areas and whether controls at the 

source are needed under the reasonable progress requirements. Specifically, the Independence 

Plant is the second largest source of SO2 and NOX point source emission in the state, 

contributing approximately 36.2% of the total SO2 point source emissions in the state (i.e., 

 

119 See 80 FR at 18989. 120 Please see our FIP proposal and associated TSDs for a thorough discussion of contributors to visibility 

impairment at Arkansas Class I areas and our rationale for focusing on point sources 

121 See Arkansas RH SIP, Appendix 8.1- “Technical Support Document for CENRAP Emissions and Air Quality 

Modeling to Support Regional Haze State Implementation Plans,” sections 3.7.1 and 3.7.2. See the docket for this 

rulemaking for a copy of the Arkansas RH SIP. 

122 See Arkansas RH SIP, Appendix 8.1- “Technical Support Document for CENRAP Emissions and Air Quality 

Modeling to Support Regional Haze State Implementation Plans,” section 3.7.1 and 3.7.2. See the docket for this 

rulemaking for a copy of the Arkansas RH SIP. 
84 

30,398 SO2 tons out of total SO2 point source emissions of 83,883 SO2 tons, based on the 2011 

NEI) and approximately 21.3% of the total NOX point source emission in the state (i.e., 13,411 

NOX tons out of total NOX point source emissions of 62,984 NOX tons).123 

Our examination of the emissions inventory also revealed that other large point sources emitting 

SO2 and NOX are already being controlled under the BART requirements (i.e., White Bluff and 

Flint Creek) and that further controls during this planning period are not necessary for these 

sources. After White Bluff, Independence, and Flint Creek, the remaining point sources in the 

state have much lower SO2 and NOX emissions than these facilities. In other words, the 

magnitude of SO2 and NOX emissions from point sources in Arkansas drops off considerably 

after the top 3 emitters. For example, the point source with the fourth highest SO2 emissions 

(after White Buff, Independence, and Flint Creek) is Future Fuel Chemical Company, which 

contributes approximately 4.1% of the total SO2 point source emissions in the state (i.e., 3,420 

SO2 tons out of total SO2 point source emissions of 83,883 SO2 tons). The point source with the 

fourth highest NOX emissions is the Natural Gas Pipeline Company of America #308, which 

contributes approximately 5.1% of the total NOX point source emission in the state (i.e., 3,194 

NOX tons out of total NOX point source emissions of 62,984 NOX tons). Based on the much 

smaller magnitude of these sources’ emissions, we determined that the remaining point sources 

in the state are less likely to be significant contributors to regional haze, and thus did not warrant 

closer evaluation under reasonable progress in this planning period. As such, we found that it is 

appropriate to evaluate Independence for controls under reasonable progress. The claim that we 

arbitrarily singled out Independence and that we provided no explanation as to why we did not 

evaluate other point sources under the reasonable progress requirements is incorrect. 

In one part of the comment, the commenter contends that we have failed to conduct any type of 

analysis involving the reasonable progress factors in relation to setting the RPGs for Arkansas 

Class I areas, but another part of the comment contends that while we did apply the reasonable 

progress factors in our analysis, we did not consider the URP in setting the RPGs. We disagree 

that we failed to consider the reasonable progress factors and we also disagree that we did not 

consider the URP in setting the RPGs. Our analysis and consideration of the reasonable progress 

factors under section 51.308(d)(1)(i)(A) is presented in our FIP proposal.124 To the extent the 

commenter suggests that our reasonable progress analysis is inappropriate or insufficient because 

we applied the reasonable progress factors to an individual source (the Independence Plant), we 

discussed above why individual sources may be subject to controls and source specific analysis 

when establishing RPGs. With regard to our consideration of the URP in establishing RPGs for 

Arkansas’ Class I areas, we explained in our Reasonable Progress analysis that: 

The preamble to the Regional Haze Rule also states that the URP 

does not establish a “safe harbor” for the state in setting its 

progress goals. 64 FR 35732. If the state determines that the 

amount of progress identified through the URP analysis is 

reasonable based upon the statutory factors, the state, or us in the 

case of a FIP, should identify this amount of progress as its 

 

123 See NEI 2011 v1. A spreadsheet containing the emissions inventory is found in the docket for our proposed 

rulemaking. 

124 80 FR at 18989. 
85 

reasonable progress goal for the first long-term strategy, unless it 

determines that additional progress beyond this amount is also 

reasonable. If the state or we determine that additional progress is 

reasonable based on the statutory factors, that amount of progress 

should be adopted as the goal for the first long-term strategy.125

That Arkansas’ Class I areas are below the URP glidepath does not divest us from our authority 

and obligation to conduct an analysis of the four statutory factors. The URP is an analytical 

requirement created by regulation to ensure that states consider the possibility of setting an 

ambitious reasonable progress goal. Its purpose is to complement, not usurp, the reasonable 

progress analysis. Based on the analysis of the four statutory factors required under the CAA and 

Regional Haze regulations, a state (or EPA in a FIP) may determine that a greater or lesser 

amount of visibility improvement than what is reflected in the URP is necessary to demonstrate 

reasonable progress.126 Based on our analysis of the four statutory factors, along with 

consideration of the visibility improvement of controls, we determined that there are reasonable 

controls available for Independence that would be cost-effective and would result in meaningful 

visibility benefit at Arkansas’ Class I areas. Because we have identified that additional progress 

(beyond the amount reflected in the URP) is reasonable based on the statutory factors and our 

consideration of the visibility impacts, we are required to adopt that amount of progress under 

the reasonable progress requirements. It is for this reason that we are requiring controls for 

Independence under the reasonable progress requirements. 

With regard to the comment alleging that we did not include a demonstration showing how the 

reasonable progress factors were taken into consideration in establishing the RPGs, the 

commenter is incorrect. Our FIP proposal explained in detail how we took the factors into 

consideration in evaluating controls under reasonable progress.127 Based on consideration of the 

four reasonable progress factors, we determined that there are reasonable controls available for 

Independence Units 1 and 2. With regard to the comment that we took a “cut and paste” 

approach in our evaluation of controls for Independence Units 1 and 2, we explained in our FIP 

proposal that we verified that White Bluff and Independence are sister facilities with nearly 

identical units by constructing a master spreadsheet that contains information concerning 

ownership, location, boiler type, environmental controls, and other pertinent information.128 The 

cost of compliance is a factor that is required for consideration under both a BART and a 

reasonable progress analysis. Due to the similarities in the facilities and the identical requirement 

for consideration of the cost of controls under reasonable progress and BART, our use of the 

total annualized costs of controls on White Bluff Units 1 and 2 in our cost analysis for 

Independence Units 1 and 2 was a reasonable approach. We do note that in calculating the cost 

effectiveness ($/ton removed) of controls for Independence Units 1 and 2, we used actual 

emissions data from Independence Units 1 and 2 to estimate the emission reductions expected to 

take place from the controls we evaluated. In our reasonable progress analysis, we took into 

consideration the cost of controls on Independence and we also considered the other reasonable 

 

125 80 FR at 18992. 126 64 FR 35732. 127 80 FR at 18989. 128 80 FR at 18992. 
86 

progress factors (time necessary for compliance, energy and non-air quality environmental 

impacts of compliance, and the remaining useful life of any potentially affected sources), as well 

as the visibility impacts of Independence and improvement due to controls on the facility. We 

modeled both the baseline visibility impacts from the Independence facility and the visibility 

benefit of controls using CALPUFF dispersion modeling. Based on our consideration of the four 

reasonable progress factors and the modeled visibility improvement of controls, we determined 

that reasonable controls for SO2 and NOX are available for Independence Units 1 and 2 that are 

cost effective and would result in a large amount of visibility improvement in Arkansas’ Class I 

areas in terms of the 98th percentile impacts from the source, and are therefore necessary to make 

reasonable progress.129

After determining that reasonable controls are available for Independence Units 1 and 2, we 

proposed RPGs for Caney Creek and Upper Buffalo that are consistent with the combination of 

control measures from the approved portion of the 2008 Arkansas RH SIP and our proposed 

Arkansas RH FIP. Our methodology for calculating the revised RPGs is explained in detail in 

our FIP proposal and associated TSDs.130 Therefore, comments alleging that we did not explain 

how we took the factors into consideration in selecting numerical RPGs are incorrect. 

We do note that in response to other comments we received stating that our proposed RPGs for 

the 20% worst days for Caney Creek and Upper Buffalo improperly incorporated visibility 

improvements that would not occur until after 2018, we are providing revised RPGs that reflect 

anticipated visibility conditions at the end of the implementation period in 2018 rather than the 

anticipated visibility conditions once the FIP has been fully implemented. We discuss this in 

greater detail in our final rule and elsewhere in this document. 

Comment: [UARG (0176) p. 2] UARG stated that in certain respects, EPA’s proposed rule 

would depart from the requirements of the CAA and EPA’s regional haze rules and would 

disregard EPA’s guidance on reasonable progress.131 UARG urges EPA to withdraw relevant 

provisions of the proposed FIP. 

Response: We acknowledge UARG’s comments. UARG’s detailed comments on our proposed 

FIP are included and addressed by us in various sections throughout this RTC document. 

Comment: EPA inappropriately declined to consider SCR for Independence Units 1 and 2 

under the reasonable progress requirements on the grounds that EPA had found that 

requiring SCR at White Bluff would lead to insufficient visibility benefits. [Sierra Club et. 

al. (0171) p. 35-36] Sierra Club et. al. stated that EPA proposed two control options for the 

 

129 Entergy submitted CAMx source apportionment modeling during the comment period. This modeling shows that 

Independence has significant visibility impacts in Arkansas Class I areas on the 20% worst days, and further 

supports our decision to require controls for Independence under reasonable progress. We discuss Entergy’s 

photochemical modeling and the visibility impacts due to SO2 and NOX from Independence on the 20% worst days 

elsewhere in this final rule and in our RTC document. 

130 See 80 FR 18997. 131 EPA, Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program (June 1, 2007) 

(Reasonable Progress Guidance). 
87 

Independence plant: Option 1, which would require scrubbers as well as LNB/SOFA; and Option 

2, which would require only scrubbers. 80 Fed. Reg. at 18,997. If EPA were faced with the 

choice between LNB/SOFA and no NOX controls at all, LNB/SOFA is the only option consistent 

with the reasonable progress requirements. However, EPA has set up a false choice by failing to 

consider more stringent controls such as SCR. LNB/SOFA+SCR is the only option that fully 

satisfies the NOX reasonable progress requirements at Independence. 

Sierra Club stated that EPA declined to consider SCR for Independence on the grounds that EPA 

had found that requiring SCR at White Bluff would lead to insufficient visibility benefits. 80 

Fed. Reg. at 18,995; see also id. at 18,975. There are two primary flaws in this argument. First, 

even if EPA can consider visibility improvement under reasonable progress, EPA has no rational 

basis for relying exclusively on the White Bluff analysis given the material differences between 

White Bluff and Independence. Independence is closer to Hercules-Glades and Mingo than is 

White Bluff. Reducing a certain amount of NOX at Independence may yield greater 

improvements in visibility at Hercules-Glades and Mingo than reducing the same amount of 

NOX from White Bluff. It is irrational for EPA to fail to even consider SCR at Independence 

based on the visibility benefits from SCR at White Bluff without first determining that the 

visibility improvement from SCR at Independence and White Bluff would be the same or 

substantially the same. Second, EPA cannot rely on its flawed logic from the White Bluff BART 

determination to reach an equally flawed outcome for Independence. As explained elsewhere in 

Sierra Club’s comments, the visibility improvement from SCR is significant enough to warrant 

the reasonable costs of SCR for White Bluff 1 and 2. The same is true at Independence. 

Therefore, EPA inappropriately declined to consider SCR for Independence Units 1 and 2 in its 

reasonable progress analysis. 

Additionally, EPA claimed that because it rejected SCR at White Bluff, EPA would likely reach 

the same conclusion at Independence, given the similarities between the plants. For the White 

Bluff BART determination, EPA rejected SCR because “the incremental visibility benefit over 

LNB/SOFA+SNCR of up to 0.069 dv at a single Class I area is relatively small considering the 

incremental cost-effectiveness of $6,717 per ton of NOX removed for Unit 1 and $5,736 per ton 

of NOX removed for Unit 2.” 80 Fed. Reg. at 18,975. However, it is unreasonable for EPA to 

reject SCR based on the incremental costs and benefits relative to SNCR, given that EPA is not 

proposing to select SNCR as a reasonable progress measure. EPA has provided no rational basis 

for rejecting SCR because of how it compares to a technology, SNCR, which EPA is not even 

proposing to require. To the extent that it is rational to examine the incremental costs and 

benefits of SCR, the proper comparison is between SCR and the technologies that EPA is 

actually proposing to require: LNB/SOFA. 

Response: We disagree that in proposing the two control options for Independence Units 1 and 2 

we set up “a false choice” by not evaluating and proposing more stringent NOX controls, such as 

SCR. The CAA and the RH regulations give us discretionary authority in conducting the 

reasonable progress analysis provided that such discretion is exercised in a reasonable manner. 

We believe that we provided in our proposal a reasonable justification for our decision to focus 

our reasonable progress analysis of NOX controls at Independence on LNB/SOFA. 
88 

We explained in our proposal that in evaluating NOX controls under the BART requirements for 

White Bluff Units 1 and 2, we found that LNB/SOFA is much more cost-effective (lower $/ton) 

than SNCR or SCR, and that the additional visibility benefits that would be obtained with SNCR 

or SCR were not large enough to justify the additional cost of the more stringent controls for this 

planning period.132 Therefore, we proposed to require NOX controls consistent with LNB/SOFA 

for White Bluff Units 1 and 2 under the BART requirements. We reasoned that because (1) the 

Independence and White Bluff facilities are sister facilities and are very similar,133 and (2) we 

found that the additional visibility benefits from SNCR and SCR were not large enough to justify 

the additional cost of these controls at White Bluff for this planning period, we had no reason not 

to conclude the same for the Independence facility. In considering NOX controls on 

Independence under the reasonable progress requirements, we determined that the visibility 

improvement due to the installation of LNB/SOFA at the Independence facility is of a similar 

magnitude to the installation of those same controls at the White Bluff facility (see Table below). 

This indicated that the installation of other NOX controls on Independence would likely have 

similar visibility benefits as for White Bluff, and further supported our reasoning that the 

additional visibility benefits from SNCR and SCR controls on Independence would likely not be 

large enough to justify the additional cost of these controls for this planning period, just as was 

the case for White Bluff. Therefore, our reasonable progress evaluation of NOX controls on 

Independence Units 1 and 2 focused on LNB/SOFA.134 

With regard to the comment that Independence is located closer to Hercules-Glades and Mingo 

(Missouri’s Class I areas) than White Bluff, and that SCR controls on Independence may 

therefore yield greater visibility improvements at these Class I areas than SCR controls on White 

Bluff, we compare the visibility improvement due to the installation of LNB/SOFA at the 

Independence facility to the visibility improvement due to those controls at White Bluff in the 

Table below. We note that while LNB/SOFA controls on Independence are predicted to have 

greater visibility benefits at Mingo than the same controls on White Bluff, the opposite is true at 

Hercules-Glades. 

Furthermore, we note that the baseline visibility impacts from Independence are greater at Caney 

Creek and Upper Buffalo than at Missouri’s Class I areas.135 The predicted visibility benefits of 

LNB/SOFA controls on Independence Units 1 and 2 are also greatest at Caney Creek 

(approximately three times as much compared to Mingo and over twice as much compared to 

Hercules-Glades).136 More importantly, the cumulative visibility benefits across all four Class I 

areas due to LNB/SOFA controls is similar for the two facilities (see Table below). We had no 

reason to not expect that the same would be the case for SNCR and SCR controls. Therefore, we 

 

132 80 FR at 18995. 133 To verify that the White Bluff and Independence Plants are sister facilities, we constructed a master spreadsheet 

that contains information concerning ownership, location, boiler type, environmental controls and other pertinent 

information on these facilities. We also found that the level of SO2 and NOX emissions from the two facilities are of 

similar magnitude and the facilities are located at comparable distances from the affected Class I areas. See 80 FR at 

18992. 

134 80 FR at 18995. 135 80 FR at 24872. 136 80 FR at 24872. 
89 

disagree with the commenters that our reasoning for focusing our reasonable progress analysis 

for NOX controls on Independence was flawed. 

Class I Area 

Visibility 

improvement of 

LNB/SOFA 

 at Independence 

over baseline 

(deciviews) 

Visibility 

improvement of 

LNB/SOFA 

at White Bluff 

over baseline 

(deciviews) 

Caney Creek 0.459 0.391 

Upper Buffalo 0.198 0.240 

Hercules-Glades 0.173 0.366 

Mingo 0.148 0.085 

Cumulative 0.978 1.082 

In any case, even if installation of either SNCR or SCR controls at Independence were to yield 

greater visibility improvement at the Missouri Class I areas than the same controls at White 

Bluff, we note that this does not affect our reasonable progress determination. Our rationale for 

not evaluating the cost and visibility improvement of SNCR and SCR controls for Independence 

was not because we expected small visibility improvement due to these controls. It was because 

we didn’t anticipate that the level of additional visibility benefit of the installation of these 

controls on Independence compared to less stringent controls would be large enough to justify 

the additional costs. We do not expect that the possibility of greater visibility benefits at 

Missouri’s Class I areas from SNCR or SCR controls at Independence compared to SNCR or 

SCR controls at White Bluff would alter our conclusion on this matter. Further, because NOX is 

not a primary driver of regional haze at Arkansas’ Class I areas on the 20% worst days, and 

Arkansas’ Class I areas are below the URP glidepath, we find it reasonable to not require more 

stringent NOX controls under the reasonable progress requirements for Independence for this 

planning period. 

With regard to White Bluff, the commenter argues that it is unreasonable for us to reject SCR in 

our BART analysis for White Bluff based on our examination of the incremental costs and 

visibility benefits relative to SNCR, when we did not even propose to require SNCR. In our 

examination of the incremental costs and visibility benefits of SCR controls for White Bluff, we 

compared LNB/SOFA + SCR to LNB/SOFA + SNCR, and we also compared LNB/SOFA + 

SNCR to LNB/SOFA. We found that the incremental cost effectiveness of LNB/SOFA + SCR 

compared to LNB/SOFA + SNCR at White Bluff Unit 1 is $6,717/ton removed and the 

incremental visibility benefit is 0.069 dv at the most impacted Class I area. We also found that 
90 

the incremental cost effectiveness of LNB/SOFA + SCR compared to LNB/SOFA + SNCR at 

White Bluff Unit 2 is $5,736/ton removed and the incremental visibility benefit is 0.069 dv at the 

most impacted Class I area. As discussed in our proposal, after weighting the five factors, we 

proposed to determine that the level of additional visibility benefit of SCR controls compared to 

SNCR is not large enough to justify the incremental cost of the more stringent control. We also 

proposed to determine that the level of additional visibility benefit of SNCR controls compared 

to LNB/SOFA is not large enough to justify the incremental cost. Nevertheless, even when we 

compare LNB/SOFA + SCR to LNB/SOFA in calculating the incremental cost effectiveness and 

incremental visibility improvements, as the commenters state we should have done, we continue 

to find that the level of additional visibility benefit of SCR controls is not large enough to justify 

the incremental cost. Based on our cost estimates of controls, we estimate the incremental cost of 

SCR over LNB/SOFA for Unit 1 to be $7,338/ton and $6,611/ton for Unit 2. We continue to find 

that incremental visibility benefits ranging from 0.032 to 0.103 dv on a unit-basis at an 

individual Class I area and incremental cumulative visibility benefits of 0.216 dv per unit across 

all 4 impacted Class I areas are not large enough to justify the additional cost of SCR on White 

Bluff for this planning period. Based on our consideration of the five BART factors, we are 

finalizing our determination that NOX BART for White Bluff Units 1 and 2 are controls 

consistent with LNB/SOFA. 

We further address elsewhere in this document comments contending that visibility improvement 

due to installation of SCR at White Bluff Units 1 and 2, and also at Independence Units 1 and 2, 

is sufficiently significant to warrant the costs. 

Comment: The reasonable progress factors, as well as consideration of visibility 

improvement, support finding that LNB/SOFA + SCR are reasonable NOX control 

measures for Independence Units 1 and 2. [Sierra Club et. al. (0171) p. 35-37] Sierra Club et. 

al. stated that LNB/SOFA + SCR is the only option that fully satisfies the reasonable progress 

requirements for NOX at Independence. Sierra Club et. al. stated that its analysis of SCR controls 

on Independence Units 1 and 2 indicates that the four reasonable progress factors weigh in favor 

of SCR. 

Using the IPM Cost Modules, the Sierra Club’s consultant, Ms. Stamper, calculated that the 

average cost-effectiveness of SCR would be less than $3000/ton removed using the 2010 Cost 

Module and between $2700 and $3500/ton removed using the 2013 Cost Module. Stamper 

Report at 66. Sierra Club argue that these average cost-effectiveness values are well within the 

range that EPA has found reasonable in other reasonable progress determinations. See the Table 

of cost-effectiveness values below. The incremental cost-effectiveness of SCR is also within the 

range of incremental cost-effectiveness values that EPA has deemed reasonable when requiring 

SCR for units in other states. See Stamper Report at 25; see also Stamper Report, Exs. 101, 104. 

Thus, even if the incremental cost-effectiveness of SCR is the deciding factor in EPA’s decision, 

there is no basis for rejecting SCR, given that the incremental cost-effectiveness is less than or 

equal to the incremental cost-effectiveness of controls EPA has approved elsewhere. Moreover, 

for the reasons discussed elsewhere in Sierra Club et. al.’s comments, EPA should not place 

undue weight on incremental cost-effectiveness relative to average cost-effectiveness. Entergy 

could install SCR within 3 years, which is a reasonable period of time (Stamper Report at 67). 
91 

Thus, the time necessary for compliance weighs in favor of SCR. The remaining useful life does 

not weigh against SCR. And in other haze rulemakings, EPA has not indicated that there are 

energy or non-air environmental quality impacts from SCR significant enough to avoid selecting 

SCR as a control measure. 

Sierra Club stated it retained an air quality expert, Dr. H. Andrew Gray, to model the visibility 

benefits of operating SCR at Independence Units 1 and 2. In his report, Dr. Gray concludes that 

the sum of the deciview benefit across the four Class I areas of operating SCR at Independence 

Units 1 and 2 is 2.099 deciviews. Gray Report at 6-7. Furthermore, had EPA compared the 

incremental costs and benefits of LNB/SOFA+SCR to LNB/SOFA at Independence, the 

comparison weighs in favor of requiring SCR. The incremental visibility benefit for SCR at both 

Independence units relative to LNB/SOFA is 0.303 deciviews at Caney Creek and 0.743 

deciviews at the four Class I areas (sum of the deciview benefit across the four Class I areas). 

Gray Report at 6. The comparable value is 0.43 deciviews for the benefit of the same controls 

applied at White Bluff. See 80 Fed. Reg. at 18,974. Thus, the incremental improvement from 

SCR relative to the improvement from LNB/SOFA is greater for controls at Independence than 

for the same controls at White Bluff. This undermines EPA’s contention that it can eliminate 

SCR from consideration at Independence for the same reason that it rejected SCR at White Bluff, 

namely, that the incremental visibility benefits did not justify the incremental costs. Using the 

costs calculated by Ms. Stamper, the incremental cost-effectiveness of SCR relative to 

LNB/SOFA is $6,371 at Unit 1 and $6,311 at Unit 2. See Stamper Report at 66. The incremental 

cost-effectiveness of SCR is within the range of costs that EPA has found reasonable when 

approving SCR for units in Wyoming, 79 Fed. Reg. at 5,040-41, and is within the range of 

incremental cost-effectiveness for other controls that EPA has approved, see Stamper Report, 

Exs. 101, 104. 

Sierra Club stated that in sum, the reasonable progress factors, as well as visibility improvement, 

support finding that LNB/SOFA+SCR are reasonable control measures for Independence Units 1 

and 2. EPA should require Independence Units 1 and 2 to install and operate LNB/SOFA+SCR 

under two separate provisions of the regional haze rule. First, the reasonable progress goals for 

Caney Creek and Upper Buffalo should reflect the visibility improvement from operation of 

LNB/SOFA+SCR at Independence Units 1 and 2, and therefore the long-term strategy should 

include SCR in order to meet the goals for Caney Creek and Upper Buffalo. Second, the 

reasonable progress goals for Hercules-Glades and Mingo should reflect the visibility 

improvement from operation of LNB/SOFA+SCR at Independence Units 1 and 2, and therefore 

the long-term strategy should include SCR in order to meet the approvable goals for HerculesGlades and Mingo.137

 

137 If EPA does not require SCR, EPA should require SNCR at Independence Units 1 and 2. While SNCR would 

remove fewer tons of NOx and improve visibility less than SCR, SNCR would be cost-effective, would improve 

visibility at four Class I areas, and could be installed in a reasonable period of time. 
92 

Cost-Effectiveness of Final Reasonable Progress Determinations138

Facility Reasonable Progress 

Control Cost, $/ton 

Hawaii Electric Co., Kanoelehua Power Plant SO2 emissions cap139 5587

Hawaii Electric Co., Puna Power Plant SO2 emissions cap 5583

Hawaii Electric Co., Shipman Power Plant SO2 emissions cap 5583

Tri-State Generation, Craig Unit 3 SNCR 4887

Colorado Springs Utilities, Nixon Unit1 Dry FGD 3744

PacifiCorp Jim Bridger Unit 2 SCR 3015

PacifiCorp Jim Bridger Unit 3 SCR 2961

PacifiCorp Jim Bridger, Unit 4 SCR 2492

PacifiCorp Jim Bridger, Unit 1 SCR 2393

Holcim Florence Cement Plant SNCR 2293

Colorado Springs Utilities, Nixon Unit 1 ULNB/OFA 1372

Phoenix Cement, Clarkdale Kiln 4 SNCR 1142

Rillito Cement Kiln 4 SNCR 1047

Basin Electric, Antelope Valley Unit 2 LNB 661

Montana Dakota Utilities, Heskett Station Limestone Injection 651

Platte River Power Authority, Rawhide Unit 

101 ECC 644

Basin Electric, Antelope Valley Unit 1 LNB 586

Devon Energy Blaine County #1 Compressor NSCR 282

Response: As discussed in our proposal and in our response to the previous comment, we did 

not evaluate SNCR or SCR controls for Independence. Our analysis of NOX controls on 

Independence instead focused on LNB/SOFA. We have reviewed the analysis of the four 

reasonable progress factors for SCR controls on Independence submitted by Sierra Club and 

disagree that it demonstrates that SCR controls are necessary under the reasonable progress 

requirements for Independence Units 1 and 2 for this planning period. 

With regard to Sierra Club’s modeling analysis, we disagree with how the commenters assessed 

and compared the modeled visibility benefits of SCR. The commenters modeled the combined 

visibility benefit of SCR controls and dry FGD at Independence (on a facility-wide basis), but 

based on the information provided it does not appear that they modeled or considered the 

 

138 Sources for the table are as follows: partial FIP for Arizona, 79 Fed. Reg. 9,318, 9,354-56 (Feb. 18, 2104) and 79 

Fed. Reg. 52,420 (Sept. 3, 2014); approval of Colorado’s SIP, 77 Fed. Reg. 18,052, 18,082, 18,084, 18,087 (Mar. 

26, 2012) and 77 Fed. Reg. 76,871 (Dec. 31, 2012); FIP for Hawaii, 77 Fed. Reg. 31,691, 31,711 (May 29, 2012) 

and 77 Fed. Reg. 61,478, 61,506 (Oct. 9, 2012); FIP for Montana. 77 Fed. Reg. 23,988, 24,069 (Apr. 20, 2012) and 

77 Fed. Reg. 57,864 (Sept. 18, 2012); partial SIP approval and partial FIP for North Dakota, 76 Fed. Reg. 58,570, 

58,626, 58,630-32 (Sept. 21, 2011) and 77 Fed. Reg. 20,894, 20,897 (Apr. 6, 2012); FIP for Wyoming, 78 Fed. Reg. 

34,738, 34,754-56, 34,757-78 (June 10, 2013) and 79 Fed. Reg. 5,032 (Jan. 30, 2014). 

139 “This cap [the SO2 emissions cap] was derived from EPA’s analysis of the costs of switching these units to 1% 

sulfur fuel.” Therefore, the cost-effectiveness for the three Hawaii plants represents the cost to meet the SO2 cap by 

switching to low-sulfur fuel. 
93 

visibility improvement of SCR controls alone, as was done for White Bluff. Since the visibility 

benefits due to SCR at White Bluff were modeled using baseline (i.e., uncontrolled) SO2

emission levels, while the commenters’ modeled visibility benefits of SCR at Independence were 

modeled using controlled SO2 emission levels, the commenters’ comparison of visibility benefits 

from SCR at White Bluff to visibility benefits from SCR at Independence is incorrect. If the 

modeling had been performed on a consistent basis allowing for a direct comparison, the 

visibility benefits from SCR at the two facilities would be similar, as demonstrated by our 

modeled visibility benefits of LNB/SOFA at the two facilities shown in the table below.140

Furthermore, the commenter does not provide any modeling for LNB/SOFA and SNCR, so we 

are unable to assess the incremental visibility benefits of SCR over SNCR as we did for White 

Bluff. Despite these issues, we have determined that the additional visibility modeling submitted 

by the commenters does not demonstrate that the visibility benefits due to SCR at Independence 

are larger than that at White Bluff, or that the incremental visibility benefits due to SCR at 

Independence (even when compared to LNB/SOFA) are large enough to justify the additional 

cost of controls. 

Class I Area 

Visibility 

improvement of 

LNB/SOFA at 

Independence over 

baseline 

(deciviews) 

Visibility 

improvement of 

LNB/SOFA at 

White Bluff over 

baseline 

(deciviews) 

Caney Creek 0.459 0.391 

Upper Buffalo 0.198 0.240 

Hercules-Glades 0.173 0.366 

Mingo 0.148 0.085 

Cumulative 0.978 1.082 

The commenters’ modeling analysis estimates the benefits of SCR at Independence and 

compares this to the modeled visibility benefits of LNB/SOFA. The commenters state that the 

incremental visibility benefit of SCR on the two units at Independence relative to LNB/SOFA is 

0.303 dv at Caney Creek, but based on the report by Dr. H Andrew Gray (Gray Report) that is 

referenced in the comment, it appears that the correct number is 0.257 dv. The table below 

summarizes the results of our modeling of LNB/SOFA controls at Independence and the 

commenters’ modeling of SCR controls at Independence. As we discussed above, the modeling 

submitted by the commenters for SCR controls at Independence utilized the dry FGD controlled 

emission rate for SO2 rather than the baseline SO2 emission rate, so these numbers are not 

directly comparable to the visibility benefits of NOX controls at White Bluff summarized above. 

 

140 80 FR at 24872 and 80 FR at 18974. 
94 

Class I Area Independence Modeled visibility benefit 

over BASE2_DFGD 

LNB/SOFA SCR 

Incremental 

benefit of SCR 

over 

LNB/SOFA 

Caney Creek 0.485 0.742 0.257 

Upper Buffalo 0.337 0.557 0.22 

HerculesGlades 0.264 0.388 0.124 

Mingo 0.27 0.412 0.142 

Sum 1.356 2.099 0.743 

As shown in the table above, the largest incremental visibility benefit of SCR on the units at 

Independence over LNB/SOFA (using the controlled SO2 emission rate) is 0.257 dv at Caney 

Creek and 0.22 dv at Upper Buffalo. 

With regard to the commenters’ analysis of the cost of LNB/SOFA and SCR controls on 

Independence, we disagree that we erred in the procedure we used in estimating baseline NOX

emissions for our cost analysis of LNB/SOFA controls at Independence. The fact that the 

commenters can construct an alternative approach to our baseline calculation using 2001-2003 

baseline emissions that results in higher cost-effectiveness values (i.e., lower $/ton) does not 

invalidate our approach. We calculated our baseline NOX emissions by first acquiring the 2009 to 

2013 emissions as reported to us by the facility.141 We eliminated the high and low values from 

the 2009-2013 emissions to better address potential yearly variations in coal sulfur data, capacity 

usage, etc., and make the baseline more representative of plant operations. Our Reasonable 

Progress Guidance notes the similarity between some of the reasonable progress factors and the 

BART factors contained in section 51.308(e)(1)((ii)(A), and suggests that the BART Guidelines 

be consulted regarding cost, energy and non-air quality environmental impacts, and the 

remaining useful life of the unit. We therefore relied on our BART Guidelines for assistance in 

interpreting those reasonable progress factors, as applicable. One of these areas is in the 

calculation of the baseline emissions in determining cost effectiveness. We believe the procedure 

we used is in compliance with the BART Guidelines, and also note that it is consistent with the 

procedure we used in our cost analysis for controls on White Bluff. 

In analyzing the cost of LNB/SOFA + SCR controls on Independence, the commenters assumed 

a controlled NOX emission rate of 0.04 lb/MMBtu. However, the Stamper Report referenced in 

the comment does not provide justification for this assumed controlled emission rate at 

Independence. To the extent that the commenters intended to rely on the same justification they 

provided for assuming a controlled NOX emission rate of 0.04 lb/MMBtu based on LNB/SOFA 

+ SCR controls at White Bluff, we discuss in the section of this document where we discuss cost 

 

141 http://ampd.epa.gov/ampd/ 
95 

issues that we disagree that there is information to support a 30 boiler-operating-day rolling 

average of 0.04 lbs/MMBtu at White Bluff. As with White Bluff, we see no information 

provided by the commenters to support a controlled NOX emission rate of 0.04 lb/MMBtu on a 

30 boiler-operating-day rolling average. We see no evidence of an SCR operating at that level for 

extended periods of time, such that we would feel comfortable that a 30 boiler-operating-day 

rolling average of 0.04 lbs/MMBtu would be sustainable at the Independence facility absent sitespecific engineering information. As the commenters’ cost analysis is based on an assumed NOX

emission rate of 0.04 lb/MMBtu for LNB/SOFA + SCR, we disagree with the cost analysis. 

Due to the issues we discuss above concerning the commenters’ revised NOX baseline and NOX

emission rate, and the significant impact these two inputs have on a cost analysis, we cannot rely 

on the cost estimate of LNB/SOFA + SCR controls on Independence provided by the 

commenters. 

Nevertheless, even if we were to accept the SCR cost estimate provided by the commenters, we 

would still disagree that SCR controls must be required for Independence Units 1 and 2 under the 

reasonable progress requirements for this planning period. We note that the commenters estimate 

that the cost of LNB/SOFA + SCR controls on Independence is $3,570/ton at Unit 1 and 

$2,772/ton at Unit 2. The commenters also estimate that the incremental cost effectiveness of 

SCR compared to LNB/SOFA is $6,371/ton at Unit 1 and $6,311/ton at Unit 2.142 As we 

discussed above, the largest incremental visibility benefit of SCR on the two units at 

Independence (using the controlled SO2 emission rate) is 0.257 dv at Caney Creek and 0.22 dv at 

Upper Buffalo. Although, as we discussed above, we cannot rely on the cost estimate of SCR 

controls on Independence provided by the commenters, even if we were to accept the 

commenter’s cost estimates, we would find that the amount of incremental visibility benefit of 

SCR controls compared to LNB/SOFA (i.e., 0.257 dv at Caney Creek and 0.22 dv at Upper 

Buffalo) is not large enough to justify the incremental cost of SCR as calculated by the 

commenters (i.e., $6,371/ton at Unit 1 and $6,311/ton at Unit 2). 

For the reasons discussed above, we disagree with certain aspects of the commenters’ reasonable 

progress analysis and we also disagree that it demonstrates that SCR controls are necessary under 

the reasonable progress requirements for Independence Units 1 and 2 in this planning period. We 

continue to believe that we took a reasonable approach in concluding that LNB/SOFA is 

expected to be more cost-effective than SNCR or SCR, and that the incremental visibility benefit 

at individual Class I areas as a result of SNCR or SCR controls at each unit of the Independence 

 

142 With regard to the commenters’ reference to the cost effectiveness and incremental cost effectiveness of controls 

we have required in other regional haze actions, we note that in evaluating different control options for reasonable 

progress under the long term strategy, even if a particular control option is cost-effective or has a reasonable 

incremental cost-effectiveness, it may not be the most reasonable and appropriate option when considered alongside 

the other statutory factors and when visibility improvement is considered. Although visibility is not one of the four 

mandatory factors explicitly listed for consideration under CAA section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), 

states or EPA have the option of considering the projected visibility benefits of controls in determining if the 

controls are necessary to make reasonable progress. As the Eighth Circuit Court acknowledged in North Dakota v. 

EPA, states can take visibility improvement into account when evaluating reasonable progress controls so long as 

they do so in a reasonable way (North Dakota v. EPA, 730 F.3d 750, 766 (8th Cir. 2013)). 
96 

facility is not likely to warrant the incremental cost effectiveness.143 In light of this, we believe it 

was reasonable to evaluate only LNB/SOFA in our reasonable progress analysis of NOX controls 

for Independence. We believe this is a reasonable approach and that the CAA, RH regulations, 

and our Reasonable Progress Guidance provide us with discretion to take such an approach in a 

reasonable progress analysis. As discussed in our final rule and elsewhere in this document, we 

are finalizing NOX controls consistent with LNB/SOFA for Independence under the reasonable 

progress requirements. 

With regard to the commenters’ statement that it is appropriate to assume that SCR could be 

installed at Independence within 3 years, we note that the time necessary for compliance was not 

a determining factor in our decision to not evaluate and not ultimately require SCR for 

Independence. 

With regard to the commenters’ contention that we should require Independence Units 1 and 2 to 

install and operate LNB/SOFA + SCR as part of the long-term strategy requirements under 

section 51.308(d)(3) to address Arkansas’ impacts at Class I areas in Missouri, we disagree. In 

our proposed partial approval and partial disapproval action on the Arkansas RH SIP, we stated 

that we agreed that additional emissions reductions in Arkansas, beyond those required under 

BART, are not necessary to protect visibility at Class I areas outside of the state at this time.144

This finding remained unchanged in our final action on the Arkansas RH SIP.145 Therefore, our 

reasonable progress analysis for Arkansas’ Class I areas was conducted to determine if additional 

controls are necessary in this planning period to make reasonable progress at Arkansas’ Class I 

areas. Although our proposed FIP did evaluate the visibility improvement projected to take place 

in Missouri’s Class I areas (Hercules-Glades and Mingo) due to controls at Independence, this 

was done solely to be informative. We noted in our proposal that we modeled the visibility 

improvement projected to result from our proposed controls for Independence in all Class I areas 

located within 300 km of the Independence Plant. The visibility improvement projected to take 

place at Hercules-Glades and Mingo due to controls at Independence did not affect our proposed 

decision for reasonable progress controls. We apologize for any confusion that may have been 

caused by our modeling of the visibility improvement in Missouri’s Class I areas. 

Comment: EPA should reject Option 2 under the reasonable progress requirements and, at 

a minimum, select Option 1, which would require Independence Units 1 and 2 to meet 

emission limits based on the use of a scrubber and LNB/SOFA. [Sierra Club et. al. (0171) p. 

37-39] Sierra Club et. al. stated that EPA has proposed two control options for the Independence 

plant: Option 1, which would require scrubbers as well as LNB/SOFA; and Option 2, which 

would require only scrubbers. 80 FR at 18997. EPA should reject Option 2, which would require 

no NOX controls, because it is inconsistent with the reasonable progress requirements. In contrast 

to Option 2, EPA’s proposed Option 1, which would require Independence Units 1 and 2 to meet 

 

143 Thus, we disagree that we “place[d] undue weight on incremental cost-effectiveness relative to average costeffectiveness.” As discussed in our proposal, in our final rule, and in this document, we considered the average cost 

effectiveness and the incremental cost effectiveness along with the other statutory factors in our cost analysis for 

NOX controls on White Bluff and in developing our cost analysis for NOX controls for Independence. 144 76 FR at 64215. 145 77 FR 14604. 
97 

a NOX emission limit based on the use of LNB/SOFA, is cost-effective and consistent with each 

of the four factors for evaluating reasonable progress controls. As a result, in the event that EPA 

erroneously declines to require LNB/SOFA + SCR at Independence Units 1 and 2, the agency 

must at least adopt Option 1 in any final haze FIP for Arkansas. 

Sierra Club stated that EPA calculated the average cost-effectiveness of LNB/SOFA to be $401 

per ton for Unit 1 and $436 for Unit 2. 80 FR at 18996. The Stamper Report used the Sargent & 

Lundy IPM cost modules to independently calculate the cost of LNB/SOFA for the two 

Independence units. The report concludes that LNB/SOFA is even more cost-effective than EPA 

calculated, at $380 per ton for Unit 1 and $287 per ton for Unit 2. Stamper Report at 66. 

Regardless of whether EPA uses the cost-effectiveness figures from the proposed rule, or Ms. 

Stamper’s calculations, LNB/SOFA at Independence is among the most-cost effective controls 

that EPA has considered for reasonable progress in any rulemaking, as shown by the table below. 

Cost-Effectiveness of Final Reasonable Progress Determinations146

Facility Reasonable Progress 

Control Cost, $/ton 

Hawaii Electric Co., Kanoelehua Power Plant SO2 emissions cap147 5587

Hawaii Electric Co., Puna Power Plant SO2 emissions cap 5583

Hawaii Electric Co., Shipman Power Plant SO2 emissions cap 5583

Tri-State Generation, Craig Unit 3 SNCR 4887

Colorado Springs Utilities, Nixon Unit1 Dry FGD 3744

PacifiCorp Jim Bridger Unit 2 SCR 3015

PacifiCorp Jim Bridger Unit 3 SCR 2961

PacifiCorp Jim Bridger, Unit 4 SCR 2492

PacifiCorp Jim Bridger, Unit 1 SCR 2393

Holcim Florence Cement Plant SNCR 2293

Colorado Springs Utilities, Nixon Unit 1 ULNB/OFA 1372

Phoenix Cement, Clarkdale Kiln 4 SNCR 1142

Rillito Cement Kiln 4 SNCR 1047

Basin Electric, Antelope Valley Unit 2 LNB 661

Montana Dakota Utilities, Heskett Station Limestone Injection 651

Platte River Power Authority, Rawhide Unit 

101 ECC 644

Basin Electric, Antelope Valley Unit 1 LNB 586

 

146 Sources for the table are as follows: partial FIP for Arizona, 79 Fed. Reg. 9,318, 9,354-56 (Feb. 18, 2104) and 79 

Fed. Reg. 52,420 (Sept. 3, 2014); approval of Colorado’s SIP, 77 Fed. Reg. 18,052, 18,082, 18,084, 18,087 (Mar. 

26, 2012) and 77 Fed. Reg. 76,871 (Dec. 31, 2012); FIP for Hawaii, 77 Fed. Reg. 31,691, 31,711 (May 29, 2012) 

and 77 Fed. Reg. 61,478, 61,506 (Oct. 9, 2012); FIP for Montana. 77 Fed. Reg. 23,988, 24,069 (Apr. 20, 2012) and 

77 Fed. Reg. 57,864 (Sept. 18, 2012); partial SIP approval and partial FIP for North Dakota, 76 Fed. Reg. 58,570, 

58,626, 58,630-32 (Sept. 21, 2011) and 77 Fed. Reg. 20,894, 20,897 (Apr. 6, 2012); FIP for Wyoming, 78 Fed. Reg. 

34,738, 34,754-56, 34,757-78 (June 10, 2013) and 79 Fed. Reg. 5,032 (Jan. 30, 2014). 

147 “This cap [the SO2 emissions cap] was derived from EPA’s analysis of the costs of switching these units to 1% 

sulfur fuel.” Therefore, the cost-effectiveness for the three Hawaii plants represents the cost to meet the SO2 cap by 

switching to low-sulfur fuel. 
98 

Devon Energy Blaine County #1 Compressor NSCR 282

The three other reasonable progress factors weigh in favor of requiring at least LNB/SOFA for 

Independence Units 1 and 2. The “time necessary for compliance,” 42 U.S.C. §7491(g)(1), is 

reasonable, since EPA proposed to allow 3 years to install and operate the controls. 80 FR at 

18996. Entergy can install LNB/SOFA in less than a year, Stamper Report at 67, so three years is 

more than reasonable. The “energy and nonair quality environmental impacts” are minimal and 

the “remaining useful life” does not cut against the controls. See 42 U.S.C. § 7491(g)(1). 

If EPA considers visibility improvement as part of the reasonable progress analysis, this factor 

also supports LNB/SOFA as the minimum reasonable progress measure the agency should adopt 

for controlling NOX emissions from Independence. LNB/SOFA would improve visibility by 

0.461 deciviews at Caney Creek and 0.248 deciviews at Upper Buffalo. 80 FR at 18996. 

For all these reasons, EPA should reject Option 2 and, at a minimum, select Option 1, which 

would require Independence Units 1 and 2 to meet emission limits based on the use of a scrubber 

and LNB/SOFA. And it is eminently reasonable to require NOX controls at Independence, given 

that it currently has no NOX controls at all, is the second-largest emitter of NOX in Arkansas, and 

EPA is proposing NOX controls for the first- and third-largest NOX emitters in the state. See 80 

FR at 18991. EPA has not demonstrated that consideration of the four reasonable progress 

factors supports requiring no NOX controls, in light of the record evidence that cost-effective 

NOX controls can be installed in a short period of time at Independence Units 1 and 2 with 

minimal environmental impacts. As EPA has not articulated a rational basis for disregarding the 

evidence in the record that supports Option 1, it would be arbitrary and capricious for EPA to 

select Option 2 on this record. 

Response: Although we disagree with the commenters’ contention that we erroneously declined 

to require LNB/SOFA + SCR at Independence Units 1 and 2, we appreciate the support the 

commenters express for our proposed Option 1. We address more detailed comments arguing 

that we should require LNB/SOFA + SCR at Independence Units 1 and 2 elsewhere in this 

document. As discussed in our final rulemaking and elsewhere in this document, we are 

finalizing Option 1 for Independence Units 1 and 2, which consists of requiring SO2 controls 

consistent with installation of dry scrubbers and NOX controls consistent with installation of 

LNB/SOFA under the reasonable progress requirements. 

Although it does not ultimately affect our final decision to require NOX controls consistent with 

LNB/SOFA, we disagree with the commenters’ contention that we underestimated the cost of 

LNB/SOFA at Independence and address this issue in the section of this document where we 

discuss cost issues. Nevertheless, we agree with the commenters that LNB/SOFA controls at 

Independence are very cost effective, as calculated by us in our cost analysis, and we 

acknowledge the information presented by the commenters concerning the cost-effectiveness of 

reasonable progress determinations made in other regional haze actions. 

We also agree that single source CALPUFF modeling shows that meaningful reductions to the 

maximum 98th percentile visibility impact from the Independence facility are expected to be 
99 

achieved through NOX controls. As discussed in our proposal, we conducted CALPUFF 

modeling of the baseline visibility impacts from Independence and the visibility benefit of 

LNB/SOFA controls.148 We found that LNB/SOFA controls on Independence are expected to 

result in visibility benefits of 0.459 dv at Caney Creek and 0.198 dv at Upper Buffalo (on a 

facility wide basis), and consider this to be meaningful visibility improvement. We also discuss 

in detail elsewhere in this document that CAMx source apportionment modeling conducted by 

Entergy and submitted to us during the comment period for our proposal shows that the 

contribution to visibility impairment due to baseline emissions from the Independence facility 

alone are projected to be approximately 1.3% of the total visibility impairment during the 

average 20% worst days in 2018 at each Arkansas Class I area. We consider this to be a 

significant contribution to visibility impairment at each Class I area and a large portion 

(approximately one-third) of the total contribution from all Arkansas point sources. The results 

of Entergy’s CAMx modeling confirm and provide additional support to our determination that 

Independence significantly impacts visibility at Arkansas’ Class I areas. While the majority of 

the visibility impacts due to Independence on the 20% worst days are due to SO2, we note that 

NOX emissions from the facility also have impacts on the 20% worst days. Entergy’s CAMx 

modeling shows that nitrate from Independence is responsible for 30 – 40% of the visibility 

impairment at Arkansas’ Class I areas on 2 of the 20% worst days.149 We expect that installation 

of cost-effective NOX controls on Independence would provide visibility improvement on this 

portion of the 20% worst days, and as such, we are requiring NOX controls consistent with 

LNB/SOFA under the reasonable progress requirements. 

In response to comments stating that LNB/SOFA controls can be installed in less than a year, we 

are revising our proposed compliance date for NOX controls on Independence Units 1 and 2 (as 

well as White Bluff Units 1 and 2 and Flint Creek Unit 1). As we discuss in the section of this 

document where we discuss compliance date issues, we are finalizing an 18-month compliance 

date for NOX controls for these sources.

3.b. Controls under reasonable progress/Arkansas’ Class I areas are below URP glidepath 

Comment: EPA did not appropriately analyze which sources, if any, should be controlled 

under the Reasonable Progress requirements. 

[Entergy Arkansas Inc. (0166) p. 18] Entergy stated that EPA’s justification for imposing SO2

and NOX emission limits on Independence is not based on rational policy, legal or environmental 

grounds and, as a result, it is arbitrary and capricious. EPA’s primary justification for proposing 

reasonable progress limits at Independence is that “it would be unreasonable to ignore a source 

representing more than a third of the State’s SO2 emissions and a significant portion of NOX

point source emissions.” 80 FR at 18992. EPA further supports its conclusion that emission 

limits based on the installation of major control technology are justified based on a finding that 

the proposed controls at Independence are cost effective. 80 FR at 18994-97. However, the fact 

that a source, which is not subject to BART, may have significant SO2 or NOX emissions, or that 

it would be cost effective to control such emissions, is irrelevant for reasonable progress 

 

148 See our supplemental NOX modeling results for the Independence facility in 80 FR 24872. 149 This means 2 out of the 21 days that are the 20% worst of the days with IMPROVE monitoring data.
100 

purposes. EPA has not used such an inapplicable and inadequate justification to identify sources 

for control under a reasonable progress analysis in any other Regional Haze FIP. EPA did not 

appropriately analyze which sources, if any, should be controlled for reasonable progress and did 

not follow the procedures it has regularly used in other regional haze FIPs. See Section III.B of 

Entergy’s comments. 

[Entergy Arkansas Inc. (0166) p. 14-17] Entergy stated that for reasonable progress purposes, 

EPA failed to undertake an appropriate reasonable progress analysis, including the crucial first 

step of determining whether additional controls are, in fact, necessary for Arkansas to make 

reasonable progress. EPA targeted only Independence in its analysis and subsequent decision to 

impose SO2 and NOX limitations on the two coal-fired units at Independence. EPA’s singular 

attention on Independence for reasonable progress controls is unsubstantiated and is patently 

arbitrary and capricious. Despite identifying the 10 largest point sources of SO2 and NOX within 

Arkansas, EPA focused only on the top three: White Bluff, Independence, and Flint Creek. 

Because White Bluff and Flint Creek are subject to BART, EPA concluded that no additional 

controls are necessary at those sources and the subsequent reasonable progress analysis fell 

solely on Independence. Id. at 18,991-92. Other than stating that these plants are the three largest 

sources, EPA provides no explanation for ignoring the other seven large point sources.150 

Entergy stated that by focusing solely on Independence, EPA’s reasonable progress analysis for 

the proposed Arkansas FIP abandons the analytical approach and determinative standards that 

guided previous reasonable progress analyses and determinations. In place of the criteria and 

procedures that EPA established in its own guidance or utilized and applied in previous 

approvals/disapprovals of regional haze SIPs or promulgation of regional haze FIPs, EPA made 

the arbitrary decision to review Independence simply because it believes “it would be 

unreasonable to ignore” the facility. 80 Fed. Reg. at 18,992. EPA failed to consider any lesser 

level of controls, the relative costs of such controls, the effectiveness of the controls in 

improving visibility or the cost per deciview improvement associated with the proposed controls. 

Entergy stated that EPA arbitrarily elected to propose controls for Independence that are 

unnecessary for Arkansas to demonstrate reasonable progress, provide no perceptible visibility 

improvement and exceed the cost estimates documented for other sources under other approved 

plans where EPA declined to impose reasonable progress controls. Further, EPA failed to follow 

its own guidance, which indicates that “States should consider a broad array of sources and 

activities when deciding which sources or source categories contribute significantly to visibility 

impairment.” Guidance for Setting Reasonable Progress Goals Under the Regional Haze 

Program, at 3-2 (June 1, 2007) (Reasonable Progress Guidance).151 The arbitrary evaluation 

process that EPA followed in the Proposal not only distorts the goals and objectives of the 

Regional Haze Program, but it also is contrary to EPA’s own requirements for uniformity and 

regional consistency. 

 

150 EPA must provide a reasoned basis for failing to analyze whether these other emission sources should be 

evaluated for reasonable progress purposes. Indeed, EPA should have conducted multi-source modeling to 

demonstrate that the other six largest point sources in Arkansas do not contribute to visibility impairment in the 

Arkansas Class I areas. 

151 Available at http://www.epa.gov/ttn/caaa/t1/memoranda/reasonable_progress_guid071307.pdf. 
101 

Entergy stated that EPA’s failure to assess and document the contribution to visibility 

impairment at any relevant Class I area from any Arkansas point source, including 

Independence, is contrary to past rulemakings and is completely inconsistent with the detailed 

approach taken by EPA Region 6 in its promulgation of the regional haze FIP for Texas. See 

generally, Proposed Texas Regional Haze FIP, 79 Fed. Reg. 74,818. There, the Agency 

completed a multi-step evaluation that included: Q/D analysis (i.e., total emissions – 24-hour 

maximum annualized – divided by distance to the Class I area) for each Texas point source and 

relevant Class I area to identify those point sources requiring further evaluation,152 a 

photochemical modeling scenario utilizing source apportionment to quantify visibility impacts 

from the sources identified in the Q/D analysis,153 and an extinction percentage threshold to 

arrive at what EPA claimed was a common breakpoint in potential visibility improvement.154

This analysis was key to the development of EPA’s approach for proposing appropriate controls 

by indicating for which sources the installation of controls are needed and would be worthwhile. 

See id.at 74,839 (explaining that the results “suggest that controlling a small number of sources 

will result in visibility benefits at both Class I areas, and that rather than evaluating controls at all 

facilities identified by Texas combined, a subset of those facilities (and some additional facilities 

not identified) may be reasonable.”). 

Entergy stated that EPA took this same approach in other states. See Proposed Arizona Regional 

Haze FIP, 79 Fed. Reg. at 9,352-53; Proposed Montana Regional Haze FIP, 77 Fed. Reg. at 

24,058-59; and Proposed North Dakota Regional Haze FIP, 76 Fed. Reg. at 58,624-26. By 

notable contrast, EPA’s Region 6 office did not perform any evaluation to identify any Arkansas 

point sources contributing to visibility impairment (or the scope of contribution) at Caney Creek 

or Upper Buffalo. EPA also performed multi-source emissions analysis using CAMx in most of 

those other states rather than looking only at the potential impact on visibility using the 

CALPUFF, single source model, as it did in Arkansas. See Proposed Texas Regional Haze FIP, 

79 Fed. Reg. at 74,877-78; Proposed Montana Regional Haze FIP, 77 Fed. Reg. at 24,050; 

Proposed North Dakota Regional Haze FIP, 76 Fed. Reg. at 58,635. EPA proceeded to complete 

the required four-factor reasonable progress analysis in those other states only after narrowing 

the list of potential point sources. Proposed Texas Regional Haze FIP, 79 Fed. Reg. at 74,872. 

See also Proposed Arizona Regional Haze FIP, 79 Fed. Reg. at 9,138, 9,352-53 (Feb. 18, 2014); 

Proposed Montana Regional Haze FIP, 77 Fed. Reg. 23,988, 24,058-59 (Apr. 20, 2012); and 

Proposed North Dakota Regional Haze FIP, 76 Fed. Reg. 58,570, 58,624-26 (Sept. 21, 2011). No 

doubt, this process was utilized because the Regional Haze Rule requires that additional controls 

for proposed emission reductions, as identified in an implementation plan, must be needed to 

achieve reasonable progress.155 EPA’s failure to follow these same procedures in the Arkansas 

Proposed FIP is completely inconsistent with its prior actions and renders the Proposed FIP 

arbitrary and capricious. 

 

152 Technical Support Document for the Oklahoma and Texas Regional Haze Federal Implementation Plans (FIP 

TSD), Appendix A at A-4 (Nov. 2014) (“TX FIP TSD”). 153 Id. at A-15 – A-26. 154 Id. at A-49. 

155 See 40 C.F.R. §§ 51.308(d)(1)(i)(B) and (d)(3). Logic dictates that if a point source’s contribution to visibility 

impairment is determined to be insignificant then additional controls are not necessary to achieve reasonable 

progress. 
102 

[Entergy Mississippi Inc. (EMI) (0168) p. 4-5) EMI stated that by focusing solely on the 

Independence Plant, EPA’s reasonable progress analysis for the Proposed Rule abandons the 

analytical approach and criteria that guided previous reasonable progress analyses and 

determinations. In place of the criteria and procedures that EPA utilized and applied in previous 

decisions to approve/disapprove regional haze SIPs or promulgate regional haze FIPs, EPA made 

an unsubstantiated decision to evaluate controls for the Independence Plant simply because the 

agency believes “it would be unreasonable to ignore” the facility. In its four-factor analysis, the 

agency further abandoned the standards and thresholds that guided previous determinations, 

choosing instead to propose additional controls for the Independence Plant that exceed the cost 

estimates and fall short of the visibility improvements documented for other sources under other 

approved plans. EPA’s arbitrary evaluation process for the Arkansas FIP not only distorts the 

goals and objectives of the regional haze rule but also is contrary to EPA’s own requirements for 

uniformity and regional consistency. 

As an initial matter, EPA did not meet the Act’s threshold requirement for emission reductions 

for reasonable progress: that they must be necessary. 42 U.S.C. § 7491(b)(2) (implementation 

plans must “contain such emission limits, schedules of compliance and other measures as may be 

necessary to make reasonable progress.”) (emphasis added); Reasonable Progress Guidance at 4-

1 (“Given the significant emissions reductions that we anticipate to result from BART” and other 

Clean Air Act programs “it may be all that is necessary to achieve reasonable progress in the first 

planning period.”). EPA then failed to assess and document the contribution to visibility 

impairment at any class I Federal area from any Arkansas point source, including the 

Independence Plant. The failure to determine visibility impact is contrary to typical practice and 

is completely inconsistent with the detailed approach taken by Region 6 in its promulgation of 

the regional haze FIP for Texas, in which the agency conducted a refined multi-step process to 

identify those point sources requiring further evaluation, quantifying visibility impacts from 

those sources and arriving at a common breakpoint in potential visibility improvement.156 EPA 

proceeded to the required four-factor reasonable progress analysis only after narrowing the list of 

potential point sources.157 No doubt, this process was utilized because it was the same process 

utilized by other regions and other states158 and because, as discussed above, the regional haze 

rule requires that additional controls for proposed emissions reductions, as stated in an 

implementation plan, must be needed to achieve reasonable progress.159

By notable contrast, the same EPA Region did not perform any evaluation to identify any 

Arkansas point sources contributing to visibility impairment (or measure the scope of any 

contribution) at the Upper Buffalo or Caney Creek class I Federal areas. Instead, the Agency 

made the simplistic evaluation that the Independence Plant was a large source of SO2 and NOX

 

156 See generally, Texas Regional Haze FIP (Proposed), 79 Fed. Reg. 74,818 (Dec. 16, 2014); see also Technical 

Support Document for the Oklahoma and Texas Regional Haze Federal Implementation Plans (“TX FIP TSD”), 

Appendix A (Nov. 2014). 

157 See Texas Regional Haze FIP at 74,872. 158 See e.g., 79 Fed. Reg. 9,138, 9,352-53 (Arizona Proposed) (Feb. 18, 2014); 77 Fed. Reg. 23,988, 24,058-59 

(Montana Proposed) (Apr. 20, 2012); and 76 Fed. Reg. 58,570, 58,624-26 (North Dakota Proposed) (Sept. 21, 

2011). 

159 See 42 U.S.C. § 7491(b)(2); Reasonable Progress Guidance at 4-1. See also 40 C.F.R. §§ 51.308(d)(1)(i)(B) and 

51.308(d)(3). Additionally, logic dictates that if a point source’s contribution to visibility impairment is determined 

to be insignificant then additional controls are not necessary to achieve reasonable progress.   
103 

emissions and, therefore, “it would be unreasonable to ignore” the facility.160 This arbitrary 

approach turns the regional haze rule on its head and marks a drastic departure from past 

practices. 

[Entergy Mississippi Inc. (0168) p. 7-8; Conway Corporation et. al. (0172) p. 7-8; and EEAA 

(0173) p. 12-14] EMI, Conway Corporation et. al., and EEAA all stated that EPA’s entire 

justification for proposing additional controls at the Independence Plant is that “it would be 

unreasonable to ignore a source representing more than a third of the State’s SO2 emissions and a 

significant portion of NOX point source emissions.”161 However, the fact that a source not 

otherwise subject to BART may have significant SO2 or NOX emissions is irrelevant for 

reasonable progress purposes. This arbitrary approach to reasonable progress analysis (or lack 

thereof) is grossly inconsistent with the CAA, Regional Haze regulations and guidance, and 

EPA’s own prior efforts; the latter of which first determined a need for additional controls to 

achieve reasonable progress and then sought to identify sources and controls that were 

appropriate and reasonable. EPA’s proposal to implement additional controls for the 

Independence Plant does not further the goal of the regional haze program and, moreover, is 

unnecessary to achieve reasonable progress during the first planning period.162

[Conway Corporation et. al. (0172) p. 4-5, 6-7; and EEAA (0173) p. 8-10, 11-12] Conway 

Corporation et. al. and EEAA stated that EPA’s reasonable progress analysis for the Proposed 

Rule abandons the analytical approach and determinative criteria that guided previous analyses 

and determinations. In the place of the criteria and procedures that EPA utilized and applied in 

previous decisions to approve/disapprove regional haze state implementation plans or 

promulgate regional haze federal implementation plans, EPA made an unsubstantiated decision 

to evaluate controls for the Independence Plant simply because the agency believes “it would be 

unreasonable to ignore” the facility. During its four-factor analysis, the agency further 

abandoned the standards and thresholds that guided previous determinations, choosing instead to 

propose additional controls for the Independence Plant that are not cost-effective and fall short of 

the visibility improvements documented for other sources under other approved plans. EPA’s 

arbitrary evaluation process for the Proposed Rule not only distorts the goals and objectives of 

the regional haze rule but is also contrary to EPA’s own requirements for uniformity and 

regional consistency. 

Conway Corporation et. al. and EEAA stated they provided comments on specific issues relating 

to the inconsistencies in the EPA’s proposed FIP. The commenters stated that reviewed 

individually, each issue evidences an arbitrary, unjustified and inconsistent application of the 

regional haze regulations. Collectively, they demonstrate EPA’s complete disregard for the 

consistent review and uniform evaluation that is required by regulation. EPA’s consistency 

regulations strive for “standardiz[ed] criteria, procedures and policies” when “implementing and 

enforcing the act.163 They further oblige the agency to ensure that actions taken under the Clean 

Air Act: (1) “[a]re carried out fairly and in a manner that is consistent with the Act and Agency 

 

160 80 Fed. Reg. at 18,992. 161 80 FR at 18992. 162 Arkansas Five-Year Progress Report at 39-43 (indicating that all relevant class I Federal areas are ahead of the 

glide path for the first planning period). 

163 40 C.F.R. § 56.3(a) and (b). 
104 

policy as set forth in the Agency rules and program directives” and (2) “[a]re as consistent as 

reasonably possible with activities of other Regional Offices.164 

Conway Corporation et. al. and EEAA stated that in the proposed FIP, Region 6 officials 

abandoned the standardized criteria, procedures and policies previously applied by the agency 

and, in the process, disregarded all notion of uniformity. Moreover, the EPA’s inconsistent 

treatment is due in large measure to the agency’s failure to complete necessary analysis, which is 

the same justification it provided when it rejected Arkansas’ SIP proposal in the first instance.165

Conway Corporation et. al. and EEAA stated that as an initial matter, in conducting its 

reasonable progress analysis, EPA failed to assess and document the contribution to visibility 

impairment at any class I Federal area from any Arkansas point source, including the 

Independence Plant. The failure to determine visibility impact is contrary to typical practice and 

is completely inconsistent with the detailed approach taken by EPA in its promulgation of the 

regional haze FIP for Texas.166 There, the agency completed a refined multi-step evaluation that 

included: Q/D analysis for each Texas point source and relevant Class I Federal area to identify 

those point sources requiring further evaluation;167 a photochemical modeling scenario utilizing 

source apportionment to quantify visibility impacts from the sources identified in the Q/D 

analysis;168 and, an extinction percentage threshold to arrive at a common breakpoint in potential 

visibility improvement.169 EPA proceeded to the required four-factor reasonable progress 

analysis only after narrowing the list of potential point sources.170 No doubt, EPA pursued this 

process because it was the same process utilized previously by EPA and other states171 and 

because the regional haze rule requires that any additional emissions reductions must be 

necessary to achieve reasonable progress.172

Conway Corporation et. al. and EEAA stated that by notable contrast, in the proposed FIP, 

EPA’s Region 6 office did not perform any evaluation to identify any Arkansas’ point sources 

contributing to visibility impairment (or measure the scope of any contribution) at the Upper 

Buffalo or Caney Creek class I Federal areas. Instead, the Agency made the simplistic 

observation that the Independence Plant was a large source of SO2 and NOX emissions and, 

 

164 40 C.F.R. § 56.5(a). 165 80 Fed. Reg. at 18991 (noting that EPA’s partial disapproval of the Arkansas RH SIP was made, in part, on the 

“finding that Arkansas did not complete a reasonable progress analysis and did not properly demonstrate that 

additional controls were not reasonable”). 

166 See generally, 79 Fed. Reg. at 74818. 167 See generally, Texas Regional Haze FIP (Proposed), 79 Fed. Reg. 74818 (Dec. 16, 2014); see also Technical 

Support Document for the Oklahoma and Texas Regional Haze Federal Implementation Plans (FIP TSD), Appendix 

A (Nov. 2014).

168 Id. at A-15 thru A-26. 169 Id. at A-49. 170 See 79 Fed. Reg. at 74872. 171 See e.g., 79 Fed. Reg. 9138, 9352-53 (Arizona Proposed) (Feb. 18, 2014); 77 Fed. Reg. 23988, 24058-59 

(Montana 

Proposed) (Apr. 20, 2012); and 76 Fed. Reg. 58570, 58624-26 (North Dakota Proposed) (Sept. 21, 2011). 

172 See 40 C.F.R. §§ 51.308(d)(1)(i)(B) and 51.308(d)(3). Logic dictates that if a point source’s contribution to 

visibility impairment is determined to be insignificant then additional controls are not necessary to achieve 

reasonable progress. 
105 

therefore, “it would be unreasonable to ignore” the facility.173 This arbitrary approach turns the 

regional haze rule on its head and marks a drastic departure from past practices. 

Response: With regard to the commenters’ contention that our primary justification for 

imposing emission limits under reasonable progress for Independence Units 1 and 2 is that it 

would be unreasonable to ignore a source representing more than a third of the state’s SO2

emissions and a significant portion of NOX point source emissions, this is incorrect. While we 

did state in our FIP proposal that it would be unreasonable to ignore a source representing more 

than a third of the state’s SO2 emissions and a significant portion of NOX point source emissions, 

the commenters took this statement out of context. The full citation from our FIP proposal 

referenced by the commenters is the following: 

 

We believe it is appropriate to evaluate Entergy Independence even 

though Arkansas Class I areas and those outside of Arkansas most 

significantly impacted by Arkansas sources are projected to meet 

the URP for the first planning period. This is because we believe 

that in determining whether reasonable progress is being achieved, 

it would be unreasonable to ignore a source representing more than 

a third of the State’s SO2 emissions and a significant portion of 

NOX point source emissions.174

As evidenced by the full citation from our FIP proposal, the fact that we considered it 

unreasonable to ignore a source representing more than a third of the State’s SO2 emissions and a 

significant portion of NOX point source emissions was our primary justification for looking more 

closely and evaluating the Independence plant in our reasonable progress analysis. It was not, as 

the commenters contend, our justification for imposing controls on Independence. As we 

discussed in our FIP proposal, in our final rule, and elsewhere in this document, our decision to 

require controls on Independence is based on our reasonable progress analysis, as required by the 

CAA and the Regional Haze Rule under section 51.308(d)(1). 

We disagree with commenters contending that the fact that a non-BART source has significant 

SO2 or NOX emissions, or that it would be cost-effective to control such emissions, is irrelevant 

in determining what sources to take a closer look at and evaluate under reasonable progress. As 

noted elsewhere in this document, the cost of compliance is one of the four statutory factors 

under CAA section 169A(g)(1) that EPA is required to consider in a reasonable progress 

analysis, meaning that consideration of the cost effectiveness of potential controls is not 

irrelevant for reasonable progress purposes. As SO2 and NOX are visibility impairing pollutants, 

significant SO2 or NOX emissions from a source is generally an indication that there may be 

significant visibility impacts at nearby Class I areas, and that installation of controls may result 

in substantial emissions reductions and meaningful visibility improvement. Although visibility is 

not one of the four mandatory factors explicitly listed for consideration under CAA section 

169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), states and EPA have the option of considering the 

projected visibility benefits of controls in determining if additional controls are necessary to 

make reasonable progress. Therefore, we find that consideration of a source’s emissions and 

 

173 80 Fed. Reg. at 18992. 174 80 FR at 18992. 
106 

whether it would be cost-effective to control such emissions is appropriate and relevant for 

reasonable progress purposes. 

We disagree with commenters contending that we did not appropriately analyze which sources, if 

any, should be controlled under the reasonable progress requirements. To the extent that the 

commenters contend that our process for determining which sources should be evaluated under 

reasonable progress was incorrect because we did not conduct photochemical modeling, such 

argument is incorrect. As noted above, we are not required to conduct photochemical modeling 

in a reasonable progress analysis. Our 2007 Reasonable Progress Guidance states that: 

The RHR gives States wide latitude to determine additional control 

requirements, and there are many ways to approach identifying 

additional reasonable measures; however, you must at a minimum, 

consider the four statutory factors.175

The states or EPA in the context of a FIP have wide discretion in deciding what approaches, 

methods, and tools to use in identifying source categories, specific point sources, or pollutants to 

evaluate for additional controls under the reasonable progress requirements, provided that a 

reasonable rationale for the approach used is provided. There are a number of different 

approaches states or EPA in the context of a FIP have used in identifying sources for reasonable 

progress evaluation, but they usually center around the general premise of evaluating the biggest 

sources and/or the biggest impactors on visibility. While the states or EPA have the discretion to 

consider visibility in a reasonable progress analysis, photochemical modeling is not required for 

purposes of conducting a reasonable progress analysis. 

Our FIP proposal provided a detailed explanation of how we determined what sources to 

evaluate for controls under reasonable progress, and we provided a reasonable rationale for the 

approach we used. The first step in our analysis involved determining what source categories or 

specific point sources it would be appropriate to look at more closely and evaluate under the 

reasonable progress requirements in section 51.308(d)(1) to determine if additional controls are 

necessary. We explained in our proposal that it was appropriate to focus our analysis on point 

sources since the other source categories (i.e., natural, on-road, non-road, and area) each 

contribute a much smaller proportion of the total light extinction at each Class I area in Arkansas 

based on the CENRAP CAMx modeling.176 At Caney Creek, point sources contribute 81.04 Mm1

 out of a total light extinction of 133.93 Mm-1 on the average across the 20% worst days in 

2002, or approximately 60.5% of the total light extinction. At Upper Buffalo, point sources 

contribute 77.80 Mm-1 out of a total light extinction of 131.79 Mm-1 on the average across the 

20% worst days in 2002, or approximately 59% of the total light extinction. In comparison, area 

sources, which are the source category with the next highest contribution to the total light 

extinction at each Class I area, contribute approximately 13.3% of the total light extinction at 

Caney Creek and 15.5% at Upper Buffalo. The remaining source categories each contribute less 

than 6% of the total light extinction at each Class I area. Therefore, we concluded that it was 

appropriate to focus our analysis on point sources. To the extent some commenters suggested 

 

175 “Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program,” at 4-2. 176 See 80 FR at 18989. 
107 

that our decision to focus our reasonable progress analysis on point sources was unsubstantiated 

or arbitrary, this is incorrect and not supported by the record for this action. 

The CENRAP CAMx modeling shows that on most of the 20% worst days in 2002, total 

extinction was dominated by sulfate at both Caney Creek and Upper Buffalo.177 Additionally, 

total extinction at Caney Creek was dominated by nitrate on 4 of the days that comprise the 20% 

worst days in 2002 and a significant portion of the total extinction at Upper Buffalo on 2 of the 

days that comprise the 20% worst days in 2002 was due to nitrate.178 The CENRAP CAMx 

modeling also shows that sulfate from point sources was responsible for approximately 54.8% of 

the total visibility impairment at Upper Buffalo and 56.1% at Caney Creek on the 20% worst 

days in 2002. Nitrate from point sources was responsible for approximately 3% of the total 

visibility impairment at each Class I area on the 20% worst days in 2002. As such, although SO2

emissions are the primary contributor to regional haze in Arkansas’ Class I areas on the 20% 

worst days, NOX emissions are also a key contributor. Thus, consistent with our 2007 Guidance 

for Setting Reasonable Progress Goals Under the Regional Haze Program,179 we found it 

appropriate to evaluate both SO2 and NOX controls under reasonable progress. 

We explained in our FIP proposal that as a starting point in our analysis to determine whether 

additional controls on Arkansas point sources are reasonable in the first regional haze planning 

period, we examined the most recent SO2 and NOX emissions inventories for point sources in 

Arkansas (NEI 2011 v1).180 We reasoned that examination of the emissions inventories is 

appropriate because significant SO2 or NOX emissions from a source are generally an indication 

that it may be having significant visibility impacts at nearby Class I areas and that installation of 

controls may result in substantial emissions reductions and meaningful visibility improvement. 

We did not conduct photochemical modeling or other more exhaustive analyses to identify 

potential candidates to evaluate under reasonable progress, and while we recognize that this 

approach is different from the approaches and methods that we have used or approved in other 

regional haze actions, we find that the approach we are taking in this action is appropriate given 

the specific circumstances. In particular, our examination of the SO2 and NOX emissions 

inventories for Arkansas’ point sources revealed that the number of point sources that emit SO2

and NOX emissions is relatively small. Furthermore, a very small portion of the point sources in 

the state is responsible for a large portion of the statewide SO2 and NOX point source emissions. 

Specifically, White Bluff, Independence, and Flint Creek are collectively responsible for 

approximately 84% of the SO2 point source emissions and 55% of the NOX point source 

emissions in the state. Consequently, addressing these sources under the regional haze program 

will address a large proportion of the visibility impacts due to Arkansas point sources. We are 

requiring SO2 and NOX controls for White Bluff and Flint Creek under the BART requirements 

in this final action, which will substantially reduce emissions from these two facilities. The 

Independence Plant, which is not a subject-to-BART source, contributes approximately 36.2% of 

 

177 See Arkansas Regional Haze SIP, Appendix 8.1- “Technical Support Document for CENRAP Emissions and Air 

Quality Modeling to Support Regional Haze State Implementation Plans,” sections 3.7.1 and 3.7.2. See the docket 

for this rulemaking for a copy of the Arkansas Regional Haze SIP. 

178 See Arkansas Regional Haze SIP, Appendix 8.1- “Technical Support Document for CENRAP Emissions and Air 

Quality Modeling to Support Regional Haze State Implementation Plans,” section 3.7.1 and 3.7.2. See the docket for 

this rulemaking for a copy of the Arkansas Regional Haze SIP. 

179 “Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program,” at 2-3 and 3-1. 180 80 FR at 18991. 
108 

the total SO2 point source emissions in the state (30,398 SO2 tons out of total SO2 point source 

emissions of 83,883 SO2 tons, based on the 2011 NEI).181 This source also contributes 

approximately 21.3% of the total NOX point source emission in the state (13,411 NOX tons out of 

total NOX point source emissions of 62,984 NOX tons). Based on this examination, we 

determined that the magnitude of emissions from the Independence Plant warranted further 

evaluation of the source to determine if it is a significant contributor to regional haze in 

Arkansas’ Class I areas and whether controls at the facility are needed based on an analysis 

under section 51.308(d)(1). 

After White Bluff, Independence, and Flint Creek, the remaining point sources in the State have 

much lower SO2 and NOX emissions than these facilities. In other words, the magnitude of SO2

and NOX emissions from point sources in Arkansas drops off considerably after the top 3 

emitters. We stated the following in our proposal: 

The fourth largest SO2 and NOX point sources in Arkansas are the 

Future Fuel Chemical Company, with emissions of 3,421 SO2 tpy, 

and the Natural Gas Pipeline Company of America #308, with 

emissions of 3,194 NOX tpy (2011 NEI). In comparison to the 

emissions of the top three sources, emissions from these two 

facilities are relatively small. Therefore, we are not proposing 

controls in this first planning period for these two facilities because 

we believe it is appropriate to defer the consideration of any 

additional sources besides Independence to future regional haze 

planning periods.182 

Future Fuel Chemical Company, the point source with the fourth highest SO2 emissions (after 

White Buff, Independence, and Flint Creek), contributes approximately 4.1% of the total SO2

point source emissions in the state (3,420 SO2 tons out of total SO2 point source emissions of 

83,883 SO2 tons, based on the 2011 NEI). The Natural Gas Pipeline Company of America #308, 

the point source with the fourth highest NOX emissions, contributes approximately 5.1% of the 

total NOX point source emission in the state 3,194 NOX tons out of total NOX point source 

emissions of 62,984 NOX tons, based on the 2011 NEI). Based on the much smaller magnitude 

of these sources’ emissions, we determined that the remaining point sources in the state are less 

likely to be significant contributors to regional haze, and thus did not warrant closer evaluation 

under reasonable progress in this planning period. As such, we found that it is appropriate to 

evaluate Independence, but not other sources in Arkansas, for controls under reasonable progress 

in this planning period. The commenters’ claims that we were arbitrary and capricious in 

determining what sources to evaluate under reasonable progress, that we singled out 

Independence, and that we provided no explanation as to why we did not evaluate other point 

sources under reasonable progress is not supported by the record in this action.183 

 

181 See NEI 2011 v1. A spreadsheet containing the emissions inventory is found in the docket for our proposed 

rulemaking. 

182 80 FR 18992. 183 We do note that because of the controls required during this planning period, we expect that the impact from the 

facilities in Arkansas that were not controlled and not specifically evaluated in the first planning period will become 

larger on a percentage basis. These sources will become the largest impacting sources and should be considered for 

analysis under reasonable progress in future planning periods. The methodology we used here thus allows a 
109 

Because our examination of the Arkansas emissions inventory revealed that the number of point 

sources that emit SO2 and NOX emissions is relatively small and that a very small portion of the 

point sources in the state are responsible for a large portion of the statewide SO2 and NOX point 

source emissions, we concluded that other more exhaustive analyses that we have performed in 

other regional haze actions were unnecessary to identify point sources to evaluate under 

reasonable progress. In contrast, in states such as Texas, where the universe of point sources is 

much larger and the distribution of SO2 and NOX emissions is very widespread, an evaluation of 

the state’s emissions inventory alone was not sufficient to reveal the best potential candidates for 

evaluation under reasonable progress. For this reason, we explained in our Texas Regional Haze 

FIP that due to the challenges presented by the geographic distribution and number of sources in 

Texas, the CAMx photochemical model was best suited for identifying sources to evaluate for 

reasonable progress controls.184 We did not encounter these challenges in the development of our 

reasonable progress analysis for Arkansas and therefore did not conduct photochemical 

modeling. We do note that while we did not conduct photochemical modeling to identify 

Arkansas point sources to evaluate under reasonable progress, Entergy conducted CAMx sourceapportionment modeling and submitted it during the comment period. We discuss elsewhere in 

this document that the results of Entergy’s CAMx modeling confirm and provide additional 

support to our determination that Independence significantly impacts visibility at Arkansas’ 

Class I areas. 

We also note that the Arkansas RH SIP submitted to us in 2008 did not include a four factor 

reasonable progress analysis. Therefore, in contrast to our actions in other states where we 

disapproved the state’s reasonable progress analysis but were able to rely on some aspects of the 

state’s analysis in developing our own analysis, for our Arkansas FIP we had to start from square 

one in developing our analysis and determining what sources to evaluate under reasonable 

progress. 

We disagree with comments arguing that we “failed to assess and document the contribution to 

visibility impairment at any relevant Class I area from any Arkansas point source, including 

Independence.” To the extent the commenters are claiming that we failed to assess the 

contribution to visibility impairment from Arkansas point sources because we did not conduct 

photochemical modeling, we discuss above and elsewhere in this document that we are not 

required to conduct photochemical modeling in a reasonable progress analysis. For consideration 

of the visibility impacts at the affected Class I areas and the visibility benefits of potential 

controls, we relied on the following: CENRAP CAMx source apportionment results, point 

source emission inventory data that initially identified the Independence facility as having the 

greatest potential to impact visibility at nearby Class I areas among all Arkansas sources not 

already controlled under the BART requirements, and the results of our CALPUFF modeling of 

the maximum or 98th percentile impacts from Independence and the visibility benefits of 

 

consistent procedure to identify facilities for additional control analysis in this and future planning periods and 

ensures continuing progress towards the goal of natural visibility conditions. 184 81 FR 296. 
110 

potential controls.185 Therefore, the claim that we did not assess and document the contribution 

to visibility impairment from Arkansas point sources is incorrect. 

We disagree that the controls we are requiring in our final action for the Independence Plant do 

not further the goal of the regional haze program and we disagree that they are unnecessary to 

make reasonable progress during the first planning period. As discussed in our proposal and 

throughout this final notice, based on our analysis of the four reasonable progress factors and our 

consideration of the baseline visibility impacts from Independence and the visibility 

improvement of potential controls, we determined that SO2 and NOX controls at Independence 

would be cost-effective and would result in meaningful visibility benefits at Arkansas’ Class I 

areas, and therefore find that they are reasonable controls and are necessary to make reasonable 

progress. 

We address elsewhere in this document comments claiming that before conducting a reasonable 

progress analysis we must first determine whether additional controls are necessary to make 

reasonable progress. 

With regard to the comment that our reasonable progress analysis failed to consider any lesser 

level of controls for Independence, the relative costs of such controls, and the visibility 

improvement of these controls, we note that for NOX we evaluated LNB/SOFA, which is a 

control technology that generally represents one of the lowest levels of NOX control. For SO2, we 

considered both wet and dry FGD. We did not consider lesser technologies for SO2 since the four 

factor evaluation demonstrated cost effective controls. We address elsewhere in this document 

comments contending that we failed to consider the cost per deciview improvement associated 

with our proposed controls. 

We address elsewhere in this document specific comments contending that the controls we 

proposed for Independence fall short of the visibility improvements documented for other 

sources under other approved regional haze plans. We also address elsewhere in this document 

specific comments contending that our proposed controls for Independence provide no 

perceptible visibility improvement. 

We address elsewhere in this document specific comments contending that the SO2 and NOX

controls we proposed for Independence exceed the cost estimates documented for other sources 

under other approved regional haze plans where we did not impose reasonable progress controls. 

We address elsewhere in this document comments on specific issues relating to what the 

commenters contend are “inconsistencies in the EPA’s proposed FIP.” 

Comment: EPA’s proposed emission limits for Independence are not necessary to achieve 

reasonable progress since ADEQ has demonstrated that Caney Creek and Upper Buffalo 

will be below the glide path in 2018 and will meet the 2018 RPGs established by Arkansas; 

this trend in visibility improvement is expected to continue beyond 2018. 

 

185 We address comments contending that we inappropriately used CALPUFF modeling to determine impacts and 

project visibility benefits from installing controls on Independence elsewhere in this document. 
111 

[Entergy Arkansas Inc. (0166) p. 17-23 ] Entergy stated that Units 1 and 2 at the Independence 

station are not subject to BART. 80 FR at 18991. EPA nonetheless treats the units as if they were 

subject-to-BART units by ignoring whether controls at the units are needed to improve visibility 

and looking only at whether controls are “cost effective.” 

Entergy stated that in a reasonable progress analysis, EPA must first determine that further 

actions are necessary in Arkansas beyond BART to ensure that visibility improvement is 

continuing on or below the glide path. See 42 U.S.C. § 7491(b)(2) (implementation plans must 

“contain such emission limits, schedules of compliance and other measures as may be necessary 

to make reasonable progress.”) (emphasis added); Reasonable Progress Guidance at 4-1 (“Given 

the significant emissions reductions that we anticipate to result from BART” and other Clean Air 

Act programs “it may be all that is necessary to achieve reasonable progress in the first planning 

period.”). The goal of the Regional Haze Program is the prevention of any future, and the 

remedying of any existing, impairment of visibility in mandatory Class I areas resulting from 

manmade air pollution. 42 U.S.C. § 7491(a)(1). Notably, the goal is not simply to reduce 

emissions for the sole purpose of achieving emission reductions; rather, the program is designed 

to reduce emissions where necessary to remedy and prevent visibility impairment. 42 U.S.C. § 

7491(b)(2). The program undertakes a gradual approach toward this goal, to assure that 

reasonable progress is being made while accounting for economic and technological constraints. 

The program is not designed to achieve the ultimate goal of eliminating visibility impairment 

immediately but, rather, over time. As EPA itself noted when establishing the Regional Haze 

Rule, which provides the states with a 64-year period to reach natural visibility conditions at 

Class I areas: 

[a]dvancements in technology and changes in economic factors 

will likely provide opportunities for implementation of new cost 

effective control measures to assure reasonable progress. The 

structure of EPA’s rule is designed to require States, through the 

SIP process, to review the statutory factors on a periodic basis and 

determine appropriate changes to their strategies based on that 

review. 64 FR 35714, 35752 (July 1, 1999). 

Entergy stated that EPA takes this extended period of time into account in providing guidance to 

the states on establishing their RPGs: “you should take into account the fact that the long-term 

goal of no manmade impairment encompasses several planning periods. It is reasonable for you 

to defer reductions to later planning periods in order to maintain a consistent glidepath toward 

the long term goal.” Reasonable Progress Guidance at 1-4; see also id. at 4-1 (“Given the 

significant emissions reductions that we anticipate to result from BART” and other Clean Air 

Act programs “it may be all that is necessary to achieve reasonable progress in the first planning 

period for some States.”). 

Entergy asserted that the threshold question is thus whether reductions in a source’s emissions 

are necessary to achieve reasonable progress for the planning period under consideration. 42 

U.S.C. § 7491(b)(2) (requiring regional haze implementation plans to contain measures 

“necessary to make reasonable progress toward meeting the national goal”) (emphasis added). 
112 

Only if further action is necessary for reasonable progress may EPA require additional controls 

and, even then, EPA must evaluate which controls are appropriate based on the statutory factors. 

See 42 U.S.C. § 7491(g)(1). EPA failed to do this here. Arkansas’ Class I areas, even without the 

proposed BART controls, are significantly below the URP and are on track to remain so for the 

next several years. Here, where Arkansas is already below the URP for this planning period and 

projected to remain so for more than a decade, the answer is clearly that additional emissions 

reductions are not necessary to achieve reasonable progress. EPA’s proposed imposition of 

unnecessary controls is clearly unreasonable. See Michigan v. EPA, 135 S.Ct. at 2706 (requiring 

EPA’s regulatory requirements to be “within the scope of its lawful authority” and its decisionmaking process to be “logical and rational”). Nonetheless, EPA has proposed to require 

emissions limits at Independence Units 1 and 2 based on the installation of SO2 and NOX

controls, ostensibly to achieve reasonable progress, and has offered two options for comment. 

Under Option 1, each coal-fired unit at Independence would be required to meet a rolling 30-day 

average SO2 emission limit of 0.06 lb/MMBtu based on the installation and operation of dry 

FGD systems, and a rolling 30-day average NOX emission limit of 0.15 lb/MMBtu based on the 

installation and operation of LNB/SOFA. Id. at 18994, 18997. Under Option 2, the Independence 

coal-fired units would be required to meet only the SO2 limit. Id. at 18994. 

Entergy asserted that emission limits on Independence during at least the first planning period 

are unnecessary to demonstrate reasonable progress, as ADEQ has demonstrated that Caney 

Creek and Upper Buffalo will be below the glide path in 2018. State of Arkansas, State 

Implementation Plan Review for the Five-Year Regional Haze Progress Report, at 55-56 (May 

2015) (“Arkansas Five-Year Progress Report”).186 Specifically, Caney Creek and Upper Buffalo 

have both shown improved visibility for the most impaired and least impaired days since 2001 

and are projected to continue to improve. The current 5-year average shows that, as of 2011, 

Caney Creek has achieved 73% of Arkansas’ 2018 RPG of 3.88 dv and Upper Buffalo has 

achieved 66% of Arkansas’ 2018 RPG of 3.75 dv. Arkansas Five-Year Progress Report at 60. 

Based on the 5-year rolling averages and projected data, both Class I areas are on schedule to 

achieve their 2018 RPGs for the 20% worst days. Id. at 55, 57. Data from Caney Creek and 

Upper Buffalo show that the goal of no visibility degradation on the 20% best days will be 

achieved and that visibility has and will continue to improve. Id. at 42-43. EPA acknowledges 

these facts in the FIP proposal: “Arkansas Class I areas and those outside of Arkansas most 

significantly impacted by Arkansas sources are projected to meet the URP for the first planning 

period.” 80 FR at 18992. As a result of emission reductions achieved through regional and 

national programs, including MATS, CAIR, and CSAPR, future Clean Air Act programs such as 

implementation of the 1-hour SO2 NAAQS, the revised ozone NAAQS and the Clean Power 

Plan, as well as the reductions for White Bluff and Independence that Entergy is proposing in its 

alternative proposal and the BART controls that EPA has proposed for the other sources in 

Arkansas, there is every reason to project continued improvement in visibility in Caney Creek 

and Upper Buffalo well beyond 2018.187

 

186 Available at http://www.adeq.state.ar.us/air/planning/pdfs/ar_5yr_prog_rep_review-final-6-2-2015.pdf. 

187 The 5-Year Progress Report for Missouri also demonstrates that Mingo and Hercules Glades are on track to meet 

the 2018 visibility goals and Missouri has determined that further reductions are not necessary. Missouri Regional

Haze Plan: 5-Year Progress Report, at 4, 17 (Aug. 29, 2014) (“The [monitoring] analyses in the 2009 RH plan 

demonstrate that the 2018 visibility goals for Mingo and Hercules Glades will be largely achieved from Electric 
113 

[Entergy Mississippi Inc. (0168) p. 7-8; Conway Corporation et. al. (0172) p. 7-8; and EEAA 

(0173) p. 12-14] EMI, Conway Corporation et. al., and EEAA all asserted that the goal of the 

regional haze program is the prevention of any future, and the remedying of any existing, 

impairment of visibility in mandatory Class I Federal areas resulting from manmade air 

pollution.188 The goal is not to simply reduce emissions for the sole purpose of achieving 

emission reductions; rather, the program is designed to reduce emissions where necessary to 

remedy and prevent visibility impairment. The program undertakes a gradual approach toward 

this goal, to assure that reasonable progress is being made while accounting for economic and 

technological constraints. The proposal for additional controls on Independence is not necessary 

to achieve reasonable progress because the Arkansas Department of Environmental Quality 

(ADEQ) 5-Year Progress Report SIP revision demonstrates that both Caney Creek and Upper 

Buffalo are and will be below the glide path in 2018.189 Specifically, monitoring data at Caney 

Creek and Upper Buffalo show improved visibility for the most impaired and least impaired days 

since 2001 -- with projections for continued improvement.190

The commenters asserted that current 5-year averages show that, as of 2011, Caney Creek 

achieved 73% of its 2018 visibility impairment reduction goal of 3.88 dv and Upper Buffalo 

achieved 66% of its 2018 visibility impairment reduction goal of 3.75 dv. Based on the 5-year 

rolling averages and projected data, both Class I areas are on schedule to achieve the state 

proposed 2018 RPGs for the 20% worst days (“W20”). Data from Caney Creek and Upper 

Buffalo also show that the goal of no visibility degradation on the 20% best days (“B20”) will be 

achieved and that visibility has and will continue to improve.191 EPA acknowledges that 

Arkansas’ Class I Federal areas and those outside of Arkansas most significantly impacted by 

Arkansas sources are projected to exceed the URP for the first planning period.192

The commenters argue that in addition to this undisputed evidence, EPA’s own analysis further 

counsels against imposing additional controls on the Independence Plant. EPA asserts that 

CENRAP modeling shows that sulfate from all point sources included in the regional modeling 

is projected to contribute to 57% of the total light extinction at Caney Creek on the W20 in 2018 

and 43% of the total light extinction at Upper Buffalo.193 However, the CENRAP modeling also 

projects that sulfate from Arkansas point sources will be responsible for only 3.58% of the total 

light extinction at Caney Creek and 3.20% at Upper Buffalo.194 The contribution of Arkansas 

point sources’ nitrate emissions to visibility impairment at Arkansas’ Class I areas is even more 

insignificant. According to EPA’s analysis, nitrate from all point sources included in the regional 

modeling is projected to account for only 3% of the total light extinction at the Caney Creek and 

 

Generating Unit (EGU) emission reductions resulting from the federal Clean Air Interstate Rule (CAIR) program.”); 

see also Proposed Missouri SIP, 77 FR 11958, 11966 (Feb. 28, 2012) (“EPA proposes to find that Missouri 

has appropriately established goals that provide for reasonable progress towards achieving natural visibility 

conditions.”); Final Missouri SIP, 77 FR 38007 (June 26, 2012).

188 42 U.S.C. § 7491(a)(1); 64 FR 35714. 189 Arkansas Five Year Progress Report at 42-43.    190 Id. 191 Id. 192 80 FR at 18992. 193 Id. at 18990. 194 Id.
114 

Upper Buffalo Class I areas, with nitrate from Arkansas point sources being responsible for only 

0.29% of the total light extinction at Caney Creek and 0.25% at Upper Buffalo.195 The 

Independence Plant units’ share of emissions to this minimal contribution from Arkansas point 

sources to visibility impairment at Caney Creek and Upper Buffalo is even smaller. Despite these 

very small contributions, the proposed FIP concludes that SO2 and NOX controls at the 

Independence Plant are warranted and reasonable. 

The commenters asserted that EPA ultimately lacks evidence of a sufficient need to evaluate 

additional controls for Arkansas point sources and lacks a sufficient basis (i.e. insignificant 

contribution to visibility impairment) to justify additional controls. 

[AECC (0169) p. 2-5] AECC stated that in its reasonable progress analysis, EPA has proposed to 

require SO2 and NOX controls on Independence Units 1 and 2 in its proposed FIP. However, 

AECC believes that this is completely unfounded. EPA believes it is appropriate to evaluate 

Independence even though EPA acknowledges that the Arkansas Class I areas as well as the ones 

outside of Arkansas most significantly impacted by Arkansas sources are projected to meet the 

uniform rate of progress (“URP” or “glide path”) for the first planning period.196 If Arkansas’ 

Class I areas - the Upper Buffalo Wilderness Area and the Caney Creek Wilderness Area - are 

expected to meet the URP in the first planning period, then evaluations should be limited to units 

that are subject to BART. AECC stated that EPA acknowledges that neither of the units at 

Independence are subject-to-BART sources.197 These units are not even BART eligible based on 

the dates they were commissioned. Therefore, the Independence units should not be evaluated 

during the first planning period. 

AECC stated that ADEQ’s recently issued five-year regional haze progress report states that both 

Arkansas Class I areas are expected to meet their respective 2018 RPGs.198 For both of the 

Arkansas Class I areas, the most recent data from 2011 and the current five-year rolling average 

(2007-2011) show that visibility impairment is decreasing more rapidly than the glide path and 

the RPG.199 Also, the two Missouri Class I areas that may be impacted by Arkansas’ electric 

generating units (EGUs) - the Hercules-Glades Wilderness Area and the Mingo National 

Wildlife Refuge - have demonstrated visibility improvement between 2000 and 2011.200 

AECC stated that the emissions trends for Arkansas EGUs are trended downward from 2000-

2011201 and will likely continue to do so with several other federal environmental rules being 

implemented. The Clean Air Interstate Rule (CAIR) which limited SO2 and NOX emissions from 

EGUs in several states - including Arkansas and most surrounding states - was in effect through 

the end of 2014. CAIR was replaced by the Cross-State Air Pollution Rule (CSAPR) at the 

beginning of 2015, which is more stringent than CAIR. CSAPR will become even more stringent 

in 2017. Indeed CSAPR is already considered “better than BART” for NOX, but EPA did not 

 

195 Id. 196 80 FR at 18992. 197 Id. at 18991. 198 “State Implementation Plan Review for the Five-Year Regional Haze Progress Report,” prepared by the 

Arkansas Department of Environmental Quality, Air Division, Planning Branch, May 2015, at 56 end 57. 199 Id. 200 Id. at 60. 201 Id. at 36. 
115 

even consider the reductions attributable to CSAPR. Compliance with the Mercury and Air 

Toxics Standard (MATS) is either April 16, 2015 or April 16, 2016 with a one-year extension 

approval. Owners of coal-fired EGUs across the country are in the process of closing units or 

installing controls to comply with MATS.202 The operators of the Flint Creek unit are currently 

installing controls to comply with MATS which will have co-benefits of reducing particulate 

matter (PM) and other pollutants which will further improve visibility in nearby Class I areas. 

EPA proposed a new national ambient air quality standard (NAAQS) for ozone in December 

2014. If this rule goes into effect, ozone forming pollutants such as NOX will be reduced across 

the nation in order to meet the new standard. A reduction in nationwide NOX emissions will 

result in visibility improvements in Class I areas. 

AECC asserted that from a technical standpoint, EPA also incorrectly used CALPUFF modeling 

to determine impacts and project reasonable progress benefits for Independence. CALPUFF is a 

single-source puff model which will greatly overstate the impacts of emissions and control 

installation benefits when used for a reasonable progress analysis. When EPA evaluates 

Independence in future planning periods, EPA should use an appropriate model for reasonable 

progress analysis. Based on these facts, the Independence units should not be included in the first 

regional haze planning period. The Arkansas Class I areas are expected to meet their respective 

2018 RPGs - even without additional controls. The Class I areas will continue to be below the 

glide path for years following 2018 due to compliance with the federal rules listed above. 

[The Associations (0165) p. 5-9] The Associations stated that they have serious concerns about 

EPA’s overall approach to the regional haze program in Arkansas and the potential impacts to all 

of the sources identified in EPA’s proposal. One example of these concerns is EPA’s imposition 

of expensive and unnecessary BART controls on the Independence plant, which is arbitrary and 

capricious. In the proposed rulemaking, EPA concedes that the Independence plant is not eligible 

under the BART program. 80 FR 18944, 18991 (April. 8, 2015). It further admits that Arkansas’ 

two Class I areas, as well as those Class I areas that are “most significantly impacted by 

Arkansas sources” would meet the Uniform Rate of Progress established for each Class I area. 

Id. at 18992. Indeed, Arkansas’ five year review report, using the most recent data, shows that 

even without additional stationary source emission controls, visibility impairments on the 20% 

worst days at Arkansas’ two Class I areas are decreasing more rapidly than the glidepath and the 

RPG. Arkansas Department of Environmental Quality, State Implementation Plan Review for the 

Five-Year Regional Haze Progress Report (Revised May 2015) at 55-58. Nevertheless, EPA 

discards its key concessions, and ignores Arkansas’ data on reasonable progress, in favor of 

seeking costly controls on the Independence plant without any demonstration that additional 

emission reductions are necessary to meet the RPGs for these Class I areas. 

The Associations stated that under the Regional Haze program, states establish RPGs for 

reducing visibility impairments by a certain amount of deciviews at Class I areas during each 

planning period. 40 C.F.R. § 51.308(d)(1). These RPGs are established through an 

implementation plan. Id. § 51.308(d). In determining how to meet these reasonable progress 

 

202 In spite of the recent Supreme Court decision in Michigan v. EPA, (U.S. June 29, 2015), several EGUs have 

already installed - or are in the process of installing - controls to comply with MATS or have taken other steps to 

reduce emissions. Even if MATS is stayed or vacated, AECC expects that the rule will go forward before the end of 

this regional haze planning period along with the associated emission reductions.
116 

goals, the state must consider projected emission reductions anticipated from existing Clean Air 

Act programs as well as through BART. RPG Guidance at 4-1. BART is a pollution control 

evaluation scheme that only applies to “BART-eligible” emission sources, meaning those “in 

existence” on August 7, 1977 and which began operation after August 7, 1962. 42 U.S.C. § 

7491(b)(2)(A). Facilities constructed after August 7, 1977 are not subject to BART. 

The Associations argued that emission reductions through BART and other Clean Air Act 

programs may be all that is necessary for states to meet their reasonable progress goals and they 

need do nothing further. RPG Guidance at 4-1. If, however, states require additional emission 

reductions to meet Class I reasonable progress goals, then they may implement “additional 

measures that are reasonable” based on a four-part analysis. Id. at 4-2. This may be done where it 

is necessary for Class I areas to achieve their reasonable progress goals. See 42 U.S.C. § 

7491(b)(2) (implementation plans must “contain such emission limits ... as may be necessary to 

make reasonable progress”) (emphasis added); RPG Guidance at 4-1 (“Given the significant 

emissions reductions that we anticipate to result from BART” and other Clean Air Act programs 

“it may be all that is necessary to achieve reasonable progress in the first planning period for 

some States.”). 

The Associations argued that a key flaw of the proposed rulemaking is EPA’s disregard of the if 

... then decision structure established by its own guidance. EPA freely admits that, after 

considering emission reductions from BART-eligible sources and other Clean Air Act programs, 

“Arkansas Class I areas and those outside of Arkansas most significantly impacted by Arkansas 

sources are projected to meet the [Uniform Rate of Progress] for the first planning period.” 80 

Fed. Reg. at 18,992. Under EPA’s RPG Guidance, this should mark the end of EPA’s RPG 

analysis. However, despite its own guidance, the proposed rule continued on to impose 

unnecessary, costly, and unauthorized controls on the Independence plant – a BART-ineligible 

source – on the grounds that it is somehow reasonable to do so. 

The Associations asserted that EPA’s explanation of “reasonableness,” however, has nothing to 

do with meeting Class I reasonable progress goals, the critical if-then scenario that allows for 

additional emission reduction measures. According to EPA, it has carte blanche discretion to 

impose controls on any facility for any grounds that it considers to be reasonable. Here, the 

entirety of EPA’s “reasonableness” explanation appears to be that the Independence plant is a 

relatively large source of emissions and that controls at the Independence plant would cost the 

same as at the White Bluff units. Id. at 18991. These considerations of “reasonableness” are 

completely unmoored from any discussion of achieving reasonable progress goals at either of the 

Arkansas Class I areas for this planning period. Where Class I areas are projected to meet their 

reasonable progress goals, nothing in the Clean Air Act authorizes EPA (or a state in the case of 

a state implementation plan) to impose new control requirements. This prohibits EPA from going 

further in search of additional emission reductions. See Motion Picture Ass’n of Amer., Inc. v.

FCC, 309 F.3d 796, 804-805 (D.C. Cir 2002) (federal agency power is limited by statutory 

authorization); Ethyl Corp. v. EPA, 51 F.3d 1053, 1060 (D.C. Cir. 1995) (courts will not presume 

a delegation of power were statute is silent on the issue); Aid Ass’n for Lutherans v. U.S. Postal

Service, 321 F.3d 1166, 1175-1178 (D.C. Cir. 2003) (striking down postal regulations related to 

the mailing of insurance offers because the “Postal Service ha[d] no congressionally delegated 

authority to exclude” certain types of mailings). The Clean Air Act simply does not give EPA or 
117 

states the authority to impose emission reductions without linking those reductions to the 

necessity of meeting RPGs. 

The Associations asserted that allowing EPA to impose tens of millions of dollars of controls on 

BART-ineligible sources like the Independence plant, based only on what it claims is 

“reasonable,” is not only economically wasteful but effectively re-writes the definition of what 

sources are BART eligible. Under the Regional Haze program, BART controls may be imposed 

on (1) major stationary sources in 26 listed categories, (2) that existed on August 7, 1977, (3) but 

were not in operation prior to August 7, 1962, and (4) emit air pollutants “which may reasonably 

be anticipated to cause or contribute to any impairment of visibility” at Class I areas. 42 U.S.C. § 

7491(b)(2)(A); 40 C.F.R. § 51.301. Under the proposed rule, the first three of these statutory and 

regulatory criteria would be rendered a nullity. According to EPA, it may impose BART controls 

on any facility (major or minor), regardless of when it was built or when it began operating, so 

long as EPA determines it to be “reasonable.” See 80 FR at 18992 (“it would be unreasonable to 

ignore a source representing more than a third of the State’s SO2 emissions and a significant 

portion of NOX point source emissions.”). As implemented in the proposed rule, EPA has 

effectively adopted a presumption that at least some BART-ineligible sources should be subject 

to BART unless those pollution controls are cost prohibitive.203 Such a presumption effectively 

ignores the operative statute and re-writes EPA’s own regulations. 

The Associations stated that, further, EPA adopts this presumption without first finding it 

necessary to impose additional emission reductions to meet Class I reasonable progress goals. 

This necessity determination – finding additional emission reductions to meet reasonable 

progress goal – anchors the “reasonableness” inquiry in the RPG Guidance. EPA claims that 

imposing tens of millions of dollars in new controls at the Independence plant is “reasonable,” 

but declines to justify the need to do so. If no further emission reductions are needed to meet 

Class I reasonable progress goals, then EPA’s “reasonableness” inquiry becomes a free-floating 

vehicle for EPA to issue pollution control edicts without any goal to accomplish. Imposing 

BART controls on the Independence plant without the need to meet Class I reasonable progress 

goals contravenes the Clean Air Act, EPA’s Regional Haze regulations, EPA’s RPG Guidance 

and is arbitrary and capricious. 

[Energy and Environmental Alliance of Arkansas (EEAA) (0173) p. 3] EEAA stated that Section 

169A of the Clean Air Act (CAA) establishes as a national goal the prevention of any future, and 

the remedying of any existing man-made impairment of visibility in the nation’s 156 national 

parks and wilderness areas designated as mandatory Class I Federal areas.204 In 1999, EPA 

promulgated the Regional Haze Rule to address regional haze impairment and establish a 

 

203 The Independence plant was apparently singled out by EPA for additional pollution controls while other BART 

ineligible emission sources were not. Although the Associations do not believe there were legal or policy 

justifications for any BART-ineligible source to require additional pollution controls, EPA does not provide any 

explanation for its selective treatment in this case other than the Independence plant being among the top three 

largest sources in the state. For states attempting to gain EPA’s approval of their own implementation plan, EPA 

provides no criteria as to how it expects them to treat BART-ineligible sources in the future, or what prevents States 

from imposing new emission controls on all BART-ineligible sources. This is the very definition of arbitrary and 

capricious decision making. 

204 42 U.S.C. § 7491. 
118 

comprehensive visibility protection program for Class I areas.205 Based on the plain language of 

the relevant statute and the Regional Haze Rule, two things are immediately obvious. First, the 

regional haze program is intended to address an aesthetic concern – i.e. visibility impairment in 

distinct areas of the country – not human health concerns. Second, and in part due to the former 

observation, Congress did not design the program to achieve the ultimate goal of eliminating 

visibility impairment immediately but, rather, over time. As EPA itself noted when establishing 

the Regional Haze Rule, which provides the states with a 64-year period to reach natural 

visibility conditions at Class I areas: 

[a]dvancements in technology and changes in economic factors will likely 

provide opportunities for implementation of new cost-effective control 

measures to assure reasonable progress. The structure of EPA’s rule is 

designed to require States, through the SIP process, to review the statutory 

factors on a periodic basis and determine appropriate changes to their 

strategies based on that review.206

EEAA asserted that given the intent of the statute and the goal of the regulations, EPA should 

have based the determinations in the proposed FIP on whether reductions in emissions and the 

associated costs thereof are necessary to maintain and achieve reasonable progress towards the 

national visibility goal. Here, where visibility improvement at relevant Federal Class I areas is 

well ahead of the EPA-approved Uniform Rate of Progress (“URP” or “glide path”) and 

projected to remain so for more than a decade, many of EPA’s proposed determinations are 

unnecessary and unjustified. 

[Edison Electric Institute (0174) p. 4-5, 7] EEI stated that EPA has proposed to require emission 

controls on Independence Units 1 and 2 to achieve reasonable progress requirements. See 80 FR 

at 18991. Neither unit is subject to the BART requirements. Id. The installation of controls at 

Independence 1 and 2 is not necessary to meet the Arkansas Uniform Rate of Progress (URP) 

visibility goal in the impacted Class I areas because the state already is on track to meet the URP 

goals for visibility for the first planning period and beyond.207 Nonetheless, EPA has proposed 

that it must regulate emissions from Independence 1 and 2 on the basis that, essentially, it is a 

large source that is not already regulated for visibility purposes—not on any analysis explaining 

specifically why the emissions from Independence are impairing visibility in a way that does not 

allow the state to meet URP for the first planning period. See 80 FR at 18992. 

EEI asserted that EPA’s disapproval of the 2008 Arkansas Regional Haze SIP was not due to 

lack of reasonable progress to achieve visibility improvement or for failure to meet the state’s 

URP goals. Rather, EPA primarily disapproved Arkansas’ SIP because the underlying emissions 

reduction requirements were based on presumptive limits instead of on properly conducted unitspecific BART evaluations. Therefore, EPA should not−and, at this time, need not−look beyond 

BART-eligible units to achieve the state’s URP goals during the first planning period, 

particularly when the state is on track to meet long-term reasonable progress goals for visibility 

 

205 64 Fed. Reg. 35714 (July 1, 1999), codified at 40 C.F.R. part 51, subpart P. 206 Id. at 35752. 207 State Implementation Plan Review for the Five-Year Regional Haze Progress Report, Arkansas Department of 

Environmental Quality, Revised May 2015. 
119 

for the first planning period and beyond. EPA has provided no rationale for regulating the 

Independence units. 

[Arkansas Electric Energy Consumers Inc. and Arkansas Gas Consumers Inc. (0175) p. 4] 

AEEC/AGC stated that although the data contained in the Five-Year Regional Haze Progress 

Report that ADEQ recently submitted to the EPA reveals that Arkansas is on track to achieve the 

visibility improvements contemplated by the Regional Haze Rule, EPA proposes to supplant the 

State of Arkansas’s primary authority by imposing a proposed FIP that places unnecessary 

additional control requirements on a few sources at a significant cost. The CAA requires states to 

submit SIPs that contain “emission limits, schedules of compliance and other measures as may 

be necessary to make reasonable progress toward meeting the national goal.”208 The CAA 

provides states with discretion in establishing reasonable progress goals; it “requires only that a 

state establish reasonable progress, not the most reasonable progress.”209 

[Conway Corporation et. al. (0172) p. 11] Conway Corporation et. al. stated that EPA 

acknowledges that visibility impairment at Arkansas’ Class I areas is decreasing more rapidly 

than the federally approved URP.210 This improvement is due, in large measure, to the reduction 

in visibility related pollutants resulting from already implemented federal and state programs and 

increased control efficiencies from EGU sources.211 These results validate Arkansas’ original 

determination that existing state and federal programs were adequate to make reasonable 

progress toward natural visibility conditions. 

[Domtar Supplemental Comments (0170) p. 2-3] Domtar stated that EPA’s discussion in the 

proposed Arkansas Regional Haze FIP addressing reasonable progress prompted their review of 

the observations at Arkansas’ Class I areas and a comparison of the observations to the uniform 

rate of progress (URP) or “glide path” predicted for each Class I area. This review reveals that 

Arkansas’ Class I areas are well ahead of their URP glidepaths. EPA recognizes this fact in the 

proposed FIP at 80 FR at 18922. Moreover, if the trend in actual observation data from the 20% 

worst days over the last 10 years continues, the 2064 goals will be achieved decades in advance. 

The figure below shows the observations (and trend line) overlaid on the URP glide path for 

Caney Creek (Upper Buffalo is similar). 

 

208 42 U.S.C. § 7491(b)(2). 209 North Dakota v. EPA, 730 F.3d 750, 768 (8th Cir. 2013) (emphasis added). 210 See 80 FR at 18992. 211 See generally ̧ Arkansas Five-Year Progress Report at 23-37. 
120 

Comparison of Caney Creek Glide Path to Actual Observations on 20% Worst Days 

(provided by Domtar as Figure 7-1 to AR020.0170) 

Domtar stated that EPA’s reasonable progress assessment results are inappropriate and would set 

an unlawful precedent. While Domtar is not directly affected by EPA’s reasonable progress 

evaluation proposal, it argues it is indirectly affected through an inevitable increase in electric 

power prices. As such, Domtar is concerned with EPA’s conclusion in the proposed FIP. Despite 

the fact that visibility improvement in Arkansas’ Class I areas is ahead of schedule, EPA 

proposed emissions controls for SO2 and possibly NOX on two non-BART affected units (at 

Entergy’s Independence facility) as part of its reasonable progress evaluation. EPA’s reasonable 

progress analysis is simply not appropriate, especially when the Class I areas of concern are 

already meeting reasonable progress goals. 

[0152-1, 0152-3, 0152-4, 0152-10, 00152-15] Some public hearing commenters stated that 

ADEQ’s Five Year Progress Report SIP revision shows that visibility at Arkansas’ Class I areas 

is better than the URP and that controls for Independence under the reasonable progress 

requirements are therefore not necessary. The commenters noted that Independence is not a 

BART source and that this FIP, which is for the first planning period, should only include BART 

sources. One commenter notes that additional controls for a non-BART source are especially 

unnecessary given the high cost. 

Response: We disagree that we cannot evaluate or require controls under reasonable progress if 

a Class I area is below the URP glidepath or if subsequent monitoring shows a Class I area meets 

or is projected to meet its RPG. Some commenters reference the CAA in support of the argument 

that controls under reasonable progress can only be required by the state or EPA if further action 

beyond BART is needed to remain on or below the URP glidepath: 
121 

[The RH regulations shall require regional haze SIPs to] contain 

such emission limits, schedules of compliance and other measures 

as may be necessary to make reasonable progress toward meeting 

the national goal...212 

These commenters interpret the term “reasonable progress” to be defined as being on or below 

the URP glidepath, and that as long as a Class I area is on or below the URP glidepath, additional 

controls are not necessary under the reasonable progress requirements. This interpretation is 

incorrect and does not take into account other, more explicit, statutory and regulatory language. 

The term “reasonable progress” is defined under CAA section 169A(g)(1) as consideration of (1) 

the costs of compliance, (2) the time necessary for compliance, (3) the energy and nonair quality 

environmental impacts of compliance, and (4) the remaining useful life of any existing source 

subject to such requirements. The Regional Haze regulations under section 51.308(d)(1)(i)(A) 

also require consideration of these four statutory factors in establishing the RPGs: 

(i) In establishing a reasonable progress goal for any mandatory Class I 

Federal area within the State, the State must: 

(A) Consider the costs of compliance, the time necessary for compliance, 

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

the remaining useful life of any potentially affected sources, and include a 

demonstration showing how these factors were taken into consideration in 

selecting the goal. 

We commonly refer to the evaluation of these four statutory factors as the “four-factor analysis” 

or “reasonable progress analysis.” The statute and regulations are both clear that the states or 

EPA in a FIP have the authority and obligation to evaluate the four reasonable progress factors 

and that the decision regarding the controls required to make reasonable progress and the 

establishment of the RPG must be based on these factors identified in CAA section 169A(g)(1) 

and the Regional Haze regulations under section 51.308(d)(1)(i)(A). 

While the Regional Haze regulations require that a state also consider the URP glidepath in 

establishing the RPGs, this should not be interpreted to mean that the URP can or should be 

automatically adopted as the RPG without completing the requisite analysis of the four statutory 

factors. It also should not be interpreted to mean that a set of controls sufficient to achieve the 

URP is automatically sufficient for an approvable long-term strategy. Clearly, a state’s obligation 

to set reasonable progress goals based on CAA section 169A(g)(1) and section 51.308(d)(1) 

applies in all cases, without regard to the Class I area’s position relative to the URP. Since an 

evaluation of the statutory factors is required regardless of the Class I area’s position relative to 

the glidepath, this necessarily means that the CAA and the Regional Haze regulations envisioned 

that controls could be required under reasonable progress even when a Class I area is on or 

below the URP glidepath. There is nothing in the CAA or Regional Haze regulations that 

 

212 CAA section 169A(b)(2). 
122 

suggests that a State’s obligation, or EPA’s in a FIP, to ensure reasonable progress can be met by 

just meeting the URP.213 

Some commenters also make the argument that EPA’s 2007 Reasonable Progress Guidance 

suggests that controls under reasonable progress are not necessary if a Class I area is on or below 

the URP glidepath. The full citation from the 2007 Reasonable Progress Guidance referenced by 

the commenters is the following: 

Given the significant emissions reductions that we anticipate to 

result from BART, the CAIR, and the implementation of other 

CAA programs, including the ozone and PM2.5 NAAQS, for many 

States this will be an important step in determining your RPG, and 

it may be all that is necessary to achieve reasonable progress in the 

first planning period for some States.214 

We see nothing in the Reasonable Progress Guidance indicating that additional controls under 

reasonable progress can only be evaluated or required if further action beyond BART is needed 

to remain on or below the URP glidepath. Being projected to meet the URP for 2018 does not 

divest a state or EPA from its authority and obligation to conduct the four factor analysis 

required under CAA section 169A(g)(1) and section 51.308(d)(1) in determining reasonable 

progress and establishing the RPGs. We noted in our FIP proposal that the preamble to the 

Regional Haze Rule states that the URP does not establish a “safe harbor” for the state in setting 

its progress goals: 

If the State determines that the amount of progress identified 

through the [URP] analysis is reasonable based upon the statutory 

factors, the State should identify this amount of progress as its 

reasonable progress goal for the first long-term strategy, unless it 

determines that additional progress beyond this amount is also 

reasonable. If the State determines that additional progress is 

reasonable based on the statutory factors, the State should adopt 

that amount of progress as its goal for the first long-term 

strategy.215 

Being projected to meet the URP for 2018 does not automatically mean that no additional 

controls beyond BART are required under the reasonable progress requirements. The URP is an 

analytical requirement created by regulation to ensure that states consider the possibility of 

setting an ambitious reasonable progress goal. Its purpose is to complement, not usurp, the 

reasonable progress analysis. Based on the analysis of the four statutory factors required under 

the CAA and Regional Haze regulations, a state or EPA in a FIP may determine that a greater or 

lesser amount of visibility improvement than what is reflected in the URP is necessary to 

demonstrate reasonable progress.216 The state, or EPA in a FIP, has discretionary authority on 

 

213 See 77 FR 14604, at 14629. 214 “Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program,” at 4-1. 215 80 FR at 18992. 216 64 FR 35732. 
123 

how to weigh the four statutory factors to determine if additional controls are needed to make 

reasonable progress. Based on our analysis of the four statutory factors under CAA section 

169A(g)(1) and under section 51.308(d)(1), along with consideration of the visibility impacts and 

visibility improvement of controls,217 we determined that there are reasonable controls available 

for Independence that would be cost-effective and would result in meaningful visibility benefit at 

Arkansas’ Class I areas. Because we have identified that additional progress (beyond the amount 

reflected in the URP) is reasonable based on our analysis of the four statutory factors and our 

consideration of the visibility impacts from the facility and the visibility improvement from 

controls, we are required to adopt that amount of progress as the RPG for each Class I area in 

Arkansas. It is for this reason that we are requiring controls on Independence under the 

reasonable progress requirements. It is not, as some commenters contend, “for the sole purpose 

of achieving emissions reductions.” 

We note that our conclusion here is consistent with our final action on the Arkansas RH SIP, 

where we disapproved Arkansas’ RPGs precisely because the state established its RPGs without 

conducting an evaluation of the four statutory factors and did so based on the fact that its Class I 

areas are below the URP glidepath. In the preamble to our final action on the Arkansas RH SIP, 

we were clear that an evaluation of the four statutory factors is required regardless of the Class I 

area’s position relative to the URP glidepath: 

[B]eing on the “glidepath” does not mean a state is allowed to 

forego an evaluation of the four statutory factors when establishing 

its RPGs. Based on an evaluation of the four statutory factors, 

states may determine that RPGs that provide for a greater rate of 

visibility improvement than would be achieved with the URP for 

the first implementation period are reasonable.218 

Our final action on the Arkansas RH SIP was published in the Federal Register on March 12, 

2012, and became effective on April 11, 2012. We reiterate in this final action that the CAA and 

Regional Haze regulations require an analysis of the four reasonable progress factors regardless 

of a Class I area’s position relative to the URP and that being below the glide path does not 

automatically mean that no controls are necessary under reasonable progress. 

With regard to comments contending that we are ignoring data from ADEQ’s Five Year Progress 

Report SIP revision, we note that Arkansas submitted the first 5-year Progress Report SIP 

revision in June 2015 and we are not including our analysis of that SIP revision within this 

action.219 The 5-year progress report is a requirement that is separate from the regional haze SIP 

required for the first planning period as well as the subsequent planning periods, and it has 

separate content and criteria for us to review. We are therefore not obligated to consider or take 

action on the 5-year progress report at the same time we promulgate our FIP. Even so, we 

 

217 Alongside the four statutory factors, we also considered the visibility improvement of controls in our reasonable 

progress analysis. Although visibility is not one of the four mandatory factors explicitly listed for consideration 

under CAA section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), states or EPA have the option of considering the 

projected visibility benefits of controls in determining if the controls are necessary to make reasonable progress. 218 77 FR at 14629. 219 We anticipate taking action on ADEQ’s Five Year Progress Report SIP revision in a separate, future action. 
124 

acknowledge that recent monitoring data from IMPROVE monitors indicate there has been 

visibility improvement in Arkansas’ Class I areas. The commenters state that ADEQ’s Five Year 

Progress Report SIP revision shows that even without the BART and reasonable progress 

controls that would be required by our FIP, Caney Creek has achieved 73% and Upper Buffalo 

has achieved 66% of their respective 2018 RPGs established by Arkansas based on 5-year 

average data from IMPROVE monitors as of 2011. However, we disagree that this “validate[s] 

Arkansas’ original determination that the existing state and federal programs were adequate to 

make reasonable progress toward natural visibility conditions.” Here, the commenter is referring 

to the Arkansas Regional Haze SIP submitted to us in 2008, in which the State made the 

determination that no additional controls were needed under the reasonable progress 

requirements. First, we note that the determination of whether additional controls are necessary 

to make reasonable progress toward the national goal of natural visibility conditions must be 

made based on the four factor analysis required under the CAA and section 51.308(d)(1). 

However, the State made its determination without conducting the four factor analysis required 

under the CAA and the Regional Haze regulations, and we partially approved and partially 

disapproved the SIP in our March 12, 2012 final action on the Arkansas Regional Haze SIP.220

That action included disapproval of Arkansas’ RPGs. As such, the State’s RPGs are not a 

reflection of the controls necessary to make reasonable progress, and any arguments upholding 

or suggesting that the state’s RPGs are appropriate or adequate are not germane to the proposed 

action we solicited comments on and are outside the scope of this action. 

Second, we note that the fact that a Class I area is achieving or is projected to achieve the state’s 

disapproved RPG does not divest us from our authority and obligation to conduct a reasonable 

progress analysis. The state, or EPA in the case of a FIP, is still required to complete the 

requisite analyses to determine appropriate controls and emission limits under the BART and 

reasonable progress requirements, and must adopt and enforce these controls and emission limits. 

The emission limitations we are requiring in our final action under the BART and reasonable 

progress requirements, along with other “on the book” reductions, are what we have determined 

represent reasonable progress at Arkansas’ Class I areas, based on our analyses required under 

the CAA and section 51.308(d)(1). These emission limitations required by our FIP will result in 

significant visibility improvements at the affected Class I areas beyond what is currently being 

achieved or observed and will ensure reasonable progress toward the national goal of natural 

visibility conditions. Third, we note that the Regional Haze Rule provides that these emission 

limitations and control measures are what is enforceable, not the RPGs themselves.221 The 

numeric RPGs are calculated by taking into account the visibility improvement anticipated from 

these enforceable emission limitations and other control measures (including BART, reasonable 

progress, and other “on the books” controls). Thus, the RPGs represent the best estimate of the 

degree of visibility improvement that will result in 2018 from changes in emissions inventories, 

changes driven by the particular set of control measures the state has adopted in its regional haze 

SIP or EPA in a regional haze FIP to address visibility, as well as all other enforceable measures 

expected to reduce emissions over the period of the SIP from 2002 to 2018.222 But the RPGs 

themselves are not enforceable. EPA cannot enforce an RPG in the sense of seeking to apply 

penalties on a state for failing to meet the RPG or obtaining injunctive relief to require a state to 

 

220 77 FR 14604. 221 64 FR 35733. 222 64 FR 35733. 
125 

achieve its RPG. However, the long-term strategy can and must contain emission limits and other 

control measures that apply to specific sources, and that are themselves enforceable. Meeting or 

being projected to meet the RPG does not necessarily demonstrate that a state has satisfied its 

requirements under BART and reasonable progress. In sum, the fact that Arkansas’ Class I areas 

are on track to achieve the 2018 RPGs provided by the state in the Arkansas RH SIP does not 

divest us from our authority and obligation to conduct a reasonable progress analysis, nor does it 

justify the dismissal of controls for Independence that we have determined, pursuant to that 

analysis, are cost-effective and would result in meaningful visibility benefit at Arkansas’ Class I 

areas. 

Additionally, while Arkansas’ Class I areas may be below the URP glidepath and be achieving 

the state’s RPGs in 2018, the CENRAP modeling projections for 2018, as well as information 

presented in ADEQ’s Five Year Progress Report SIP revision, suggest that this is due to a large 

extent to emissions reductions taking place outside of Arkansas. As noted in our proposed partial 

approval and partial disapproval of the Arkansas RH SIP, the CENRAP 2018 projections 

indicate that most of the decrease in visibility impairment at Caney Creek and Upper Buffalo in 

2018 is expected to be due to SO2 emissions reductions from point sources in other states: 

Anticipated reductions of SO4 emissions from point sources in Texas, the 

eastern United States, Indiana, and Ohio will account for a decrease of 

24.41 Mm-1 in total light extinction [at Caney Creek in 2018 on the worst 

20% days], which is approximately half of the total expected reduction 

between 2002 and 2018. Even with such large expected reductions in SO4

emissions from point sources in 2018, extinction due to point sources will 

still be the highest contributor to visibility impairment on the worst 20% 

days, accounting for over half of the total extinction. Visibility impairment 

from all Arkansas sources will decrease by 2.32 Mm-1, almost entirely due 

to expected reductions from mobile sources.223 

Anticipated reductions of SO4 emissions from point sources in the eastern 

United States, Indiana, Illinois, Kentucky and Ohio will account for a 

decrease of 28.43 Mm-1 in total light extinction [at Upper Buffalo in 2018 

on the worst 20% days], more than 60% of the total expected reduction in 

impairment between 2002 and 2018. Even with such large expected 

reductions in SO4 emissions from point sources in 2018, extinction due to 

point sources will still be the highest contributor to visibility impairment 

on the worst 20% days, accounting for approximately half of the total 

extinction. Visibility impairment from all Arkansas sources will decrease 

by 1.45 Mm-1, due to expected reductions from mobile sources.224 

We did not conduct photochemical modeling to determine the current contribution from 

Arkansas and other states to visibility impairment at Caney Creek and Upper Buffalo, but 

 

223 76 FR at 64214. 224 76 FR at 64215. 
126 

emissions data presented in ADEQ’s Five Year Progress Report SIP revision225 suggests that the 

recent observed improvement in visibility conditions at Arkansas’ Class I areas is likely due 

primarily to emissions reductions outside Arkansas. For example, Table 5.1 from ADEQ’s Five 

Year Progress Report SIP revision shows that 2011 SO2 emissions from Arkansas EGUs (73,629 

tons) were higher than 2002 levels (70,759 tons) and nearly twice as high as the 2018 projected 

emissions (39,194 tons) that went into the CENRAP modeling projections for 2018.226 The table 

also shows that 2011 SO2 emissions from all Arkansas point sources (EGU and non-EGU 

combined) were 84,870 tons, which is only slightly lower than 2002 levels (89,786 tons) and 

significantly higher than the 2018 projected emissions of 46,665 tons that went into the 

CENRAP modeling projections for 2018.227 In fact, 2011 SO2 emissions from all Arkansas 

source categories combined (95,123 tons) were nearly twice as high as the 2018 projected 

emissions (49,059 tons) that went into the CENRAP modeling projections for 2018.228 Similarly, 

2011 NOX emissions from Arkansas point sources, as well as from all Arkansas source 

categories combined, were over twice as high as the 2018 projected emissions that went into the 

CENRAP modeling projections for 2018.229 This suggests that the observed improvement in 

visibility conditions at Caney Creek, including the fact that the Class I areas are below the URP 

glidepath and are on track to achieve the state established RPGs, even without the controls 

required by our FIP, is not due to emissions reductions that have taken place in Arkansas, but 

rather in other states. To the extent that the commenters are suggesting that Arkansas should be 

relieved of its regional haze obligations because other states’ emission reduction efforts have 

already resulted in significant visibility improvement at Arkansas’ Class I areas, this is incorrect. 

Rather, Arkansas, or EPA in standing in the state’s shoes, must consider the statutory factors in 

addressing the reasonable progress and long term strategy requirements. 

Some commenters point to emissions data between 2000-2011, as presented in ADEQ’s Five 

Year Progress Report, and argue that emissions from Arkansas EGUs trended downward in this 

period, and that they expect this trend to continue and that our proposed controls on 

Independence are therefore not necessary. We note that the emissions data presented in ADEQ’s 

Five Year Progress Report SIP revision230 show that there has been some reduction in NOX

emissions from Arkansas EGUs between 2000 and 2011, but the data show that there has not 

been very much change in SO2 emissions during this same time period. According to ADEQ’s 

Five Year Progress Report SIP revision, SO2 emissions from Arkansas EGUs were 75,057 tpy in 

2000 and 73,623 tpy in 2011, with not much variation in the years in between. Therefore, we 

disagree that SO2 emissions (which are the primary driver of regional haze in Arkansas’ Class I 

areas on the 20% worst days) from Arkansas EGUs have trended downward between 2000 and 

2011. 

The relevance of the comment that EPA determined CSAPR to be better than BART but “did not 

even consider the reductions attributable to CSAPR” is unclear. In determining that CSAPR 

provides for greater reasonable progress than BART, EPA assessed the visibility benefits across 

 

225 As noted earlier in our response, we have not taken action on ADEQ’s Five Year Progress Report SIP revision. 

We anticipate taking action on this SIP revision in a separate, future action. 

226 See ADEQ Five Year Progress Report SIP revision, Table 5.1, at 46. 227 Id. 228 Id. 229 Id. 230 See ADEQ Five Year Progress Report SIP revision, Table 3.1, at 35. 
127 

the entire continental United States and found that on average across all Class I areas, CSAPR 

provided for greater visibility improvement than BART. To make this determination, EPA made 

broad assumptions as to what controls would constitute BART based on the presumptive BART 

limits in the BART Guidelines. CSAPR requires significant SO2 and NOX reductions in many 

states; in Arkansas, however, the state is subject only to an ozone season NOX budget 

requirement. The commenters have presented no evidence that CSAPR will result in any added 

benefit over and beyond the site-specific BART NOX controls in our Arkansas FIP at Arkansas’ 

Class I areas, but if the commenters’ point is that a program requiring hundreds of thousands of 

tons of reductions in SO2 and NOX across a broad region will achieve greater visibility 

improvement than the modest BART NOX controls in the Arkansas FIP, then we would have to 

agree. To the extent the commenter is arguing that our revised RPGs do not account for the 

improvement that will result from implementation of CSAPR, we note that the states assumed 

the implementation of CAIR in setting their goals but that CAIR has now been replaced by 

CSAPR. Furthermore, with regard to the comment that there is every reason to project continued 

improvement in visibility at Caney Creek and Upper Buffalo well beyond 2018 as a result of 

emission reductions achieved through other regional and national programs and that no controls 

are therefore necessary for the Independence plant in this planning period, we discussed in a 

separate response to comment that the commenters’ suggestions that EPA should further delay 

the implementation of measures to improve visibility relies on the conclusion that there is a 

specific pre-determined rate of improvement that constitutes reasonable progress. This is 

incorrect. As we discussed above, the determination of what constitutes reasonable progress is 

based on an analysis of the four statutory factors. 

With regard to comments arguing that we should not require controls under reasonable progress 

in this planning period because the regional haze program undertakes a gradual approach toward 

the national goal of remedying anthropogenic visibility impairment in Federal Class I areas, we 

note that we agree that the regional haze program contemplates gradual visibility improvements 

over several planning periods. Those gradual improvements are guided by the principle that 

controls found to be reasonable in a given planning period should be required now, rather than in 

some unspecified future planning period. That is the very nature of “reasonable progress.” For 

that reason, we do not consider the controls we are finalizing in this action as being frontloading. 

As we discuss elsewhere in this document and in our final rule, our cost analysis indicates that 

the SO2 and NOX controls we are requiring for Independence Units 1 and 2 are cost effective and 

well within the range of cost of controls found to be reasonable by EPA and the states in other 

regional haze actions for this first planning period. Arkansas did not comply with certain aspects 

of the Regional Haze Rule and thus portions of its Regional Haze SIP submitted to us in 2008 

were not approvable, including the state’s reasonable progress determinations and RPGs.231 We 

therefore have an obligation to promulgate this FIP to address the disapproved portions of the 

State’s SIP submission. Pursuant to CAA section 169A(g)(1) and our Regional Haze regulations 

at section 51.308(d)(i)(A), we conducted an evaluation of additional controls under a reasonable 

progress analysis that considered the four statutory factors. As discussed in our proposal and 

throughout this final rule, based on the demonstrations we developed pursuant to the CAA and 

section 51.308(d)(1) and our consideration of the visibility impacts from Independence and the 

visibility improvement of potential controls, we determined that there are reasonable and costeffective SO2 and NOX controls available for Independence that would result in considerable 

 

231 77 FR 14604. 
128 

visibility benefit at Arkansas’ Class I areas. Under the CAA and the Regional Haze regulations, 

if we determine that additional controls are reasonable based on the consideration of the four 

statutory factors, we must require those controls to make reasonable progress toward the national 

goal of natural visibility conditions. Therefore, we are requiring SO2 and NOX controls for 

Independence Units 1 and 2 under the reasonable progress requirements. 

We are requiring controls on Independence under the reasonable progress requirements, not 

under the BART requirements. CAA section 169A required us to promulgate regulations 

directing the States to revise their SIPs to include emission limits and other measures as 

necessary to make “reasonable progress.”232 Congress defined reasonable progress based on the 

consideration of four statutory factors: (1) the costs of compliance, (2) the time necessary for 

compliance, (3) the energy and nonair quality environmental impacts of compliance, and (4) the 

remaining useful life of any existing source subject to such requirements.233 We commonly refer 

to our analysis of these four statutory factors as a reasonable progress analysis. Congress also 

directed EPA to promulgate regulations requiring BART for a specific universe of older sources, 

and again provided a set of statutory factors States must consider: (1) the costs of compliance, 

(2) the energy and nonair quality environmental impacts of compliance, (3) any existing 

pollution control technology in use at the source, (3) the remaining useful life of the source, and 

(5) the degree of improvement in visibility which may reasonably be anticipated to result from 

the use of such technology.234 We note that many of the factors that must be considered in a 

BART analysis must also be considered in the reasonable progress analysis. Therefore, some 

commenters may mistakenly believe that we are somehow stretching the BART analysis to 

impose BART controls on Independence Units 1 and 2. This is not the case. As discussed in our 

proposal and in our final rule, in our reasonable progress analysis we considered the reasonable 

progress statutory factors as well as the visibility improvement of potential controls. Although 

visibility is not one of the four mandatory factors explicitly listed for consideration under CAA 

section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), states and EPA have the option of considering 

the projected visibility benefits of controls in determining if the controls are necessary to make 

reasonable progress. 

We disagree that we are treating Independence Units 1 and 2 as if they were subject-to-BART 

sources by, according to the commenters, “ignoring” whether controls at the units are needed to 

improve visibility and “looking only at whether controls are ‘cost-effective.’” To the extent the 

commenters are suggesting that we are ignoring whether controls are needed to improve 

visibility because we conducted a reasonable progress analysis even though Arkansas’ Class I 

areas are below the URP glidepath, we discussed earlier in this response that the analysis of the 

four statutory factors is a requirement that applies regardless of a Class I area’s position on the 

glidepath. To the extent the commenters are suggesting that we are ignoring whether controls are 

needed to improve visibility because we did not conduct photochemical modeling in our 

analysis, we discuss elsewhere in this document that we are not required to conduct 

photochemical modeling in a reasonable progress analysis. For consideration of the visibility 

impacts at Arkansas’ Class I areas and the visibility benefits of potential controls, we relied on 

the following: CENRAP CAMx source apportionment results, point source emission inventory 

 

232 CAA section 169A(b)(2). 233 CAA section 169A(g)(1). 234 CAA section 169A(b)(2)(A), (g)(2). 
129 

data that initially identified the Independence facility as having the greatest potential to impact 

visibility at nearby Class I areas among all Arkansas sources not already controlled under the 

BART requirements, and the results of our CALPUFF modeling of the maximum or 98th

percentile impacts from Independence and the visibility benefits of potential controls.235

Therefore, we disagree with commenters contending that we did not consider whether controls at 

the units are needed to improve visibility. As we noted above, the “costs of compliance” is a 

factor explicitly listed under the CAA and section 51.308(d)(1)(i)(A) that must be considered in 

a reasonable progress analysis. Therefore, we disagree with commenters contending that it was 

inappropriate for us to consider cost-effectiveness in our decision to require controls at 

Independence. Based on our consideration of the four reasonable progress factors, as well as the 

baseline visibility impacts from Independence and the visibility improvement of potential 

controls, we determined that reasonable controls for SO2 and NOX are available for 

Independence Units 1 and 2 that are cost effective and would result in a large amount of 

visibility improvement in Arkansas’ Class I areas in terms of the 98th percentile impacts from the 

source, and we are therefore requiring these controls. Therefore, the claim that we ignored 

whether controls at the units are needed to improve visibility is incorrect. 

We disagree with comments arguing that it is inappropriate to require additional controls under 

reasonable progress for Independence in light of CENRAP modeling that shows Arkansas point 

sources are responsible for what the commenters contend is only a small portion of the total light 

extinction at Caney Creek and Upper Buffalo on the 20% worst days in 2018. The commenters 

state that CENRAP modeling projects that sulfate from Arkansas point sources will be 

responsible for only 3.58% of the total light extinction at Caney Creek and 3.20% at Upper 

Buffalo. As we discuss elsewhere in this document, we disagree that these are small or 

insignificant visibility impacts. The commenters also contend that the Independence Plant’s 

share of the total contribution from Arkansas point sources is even smaller than this and that 

controls on Independence are therefore not warranted. We disagree that these visibility impacts 

are insignificant. As noted above, Entergy submitted CAMx model results as part of their 

comments. The results of this modeling provide additional support to our determination that 

Independence significantly impacts visibility at Arkansas’ Class I areas. The modeled 

contribution to visibility impairment due to baseline emissions from the Independence facility 

alone were approximately 1.3% of the total visibility impairment at each Arkansas Class I area. 

Considering that the CAMx photochemical modeling takes into account the emissions of 

thousands of sources, both in Arkansas and outside of the state, we consider this to be a 

significant contribution to visibility impairment at each Class I area and a large portion 

(approximately one-third) of the total contribution from all Arkansas point sources that can be 

addressed through installation of controls on two units at a single facility. Entergy’s CAMx 

modeling also shows that at Upper Buffalo, the Independence facility contributes more to 

visibility impairment than all the subject-to-BART sources addressed in this action combined. In 

terms of deciviews, the average impact over the 20% worst days based on Entergy’s CAMx 

modeling (adjusting to natural background conditions) is over 0.5 dv at the Arkansas Class I 

areas and even larger at the Class I areas in Missouri. These results estimate the visibility 

impacts from the source on the 20% worst days and confirm and provide additional support to 

our determination that Independence significantly impacts visibility, both in terms of maximum 

 

235 We address comments contending that we inappropriately used CALPUFF modeling to determine impacts and 

project visibility benefits from installing controls on Independence elsewhere in this document. 
130 

visibility impairment and visibility impairment on the 20% worst days, and that emissions 

controls are expected to provide for meaningful visibility benefits towards the goal of natural 

visibility conditions. We conclude that both approaches, CALPUFF and CAMx, support the 

determination that the required controls on Independence are reasonable. 

While the majority of the visibility impacts due to Independence on the 20% worst days are due 

to SO2, we note that NOX emissions from the facility also have impacts on the 20% worst days. 

The CAMx source apportionment modeling submitted by Entergy showed that NOX emissions 

from Independence are responsible for 30-40% of the visibility impairment in Arkansas’ Class I 

areas on 2 of the 20% worst days (i.e., 2 out of the 21 days that are the 20% worst of the days 

with Interagency Monitoring of Protected Visual Environments (IMPROVE) monitoring data). 

We expect that installation of NOX controls on Independence will provide visibility improvement 

on this portion of the 20% worst days and will also provide meaningful visibility improvement 

on the 98th percentile day, as shown by the CALPUFF dispersion modeling. After carefully 

considering all comments submitted to us during the comment period, we are finalizing both SO2

and NOX controls for Independence Units 1 and 2 to make reasonable progress at Arkansas’ 

Class I areas (i.e., proposed Option 1), because both SO2 and NOX are key pollutants 

contributing to visibility impairment, and because we have determined that these controls are 

cost effective and will provide for significant visibility benefits towards the goal of natural 

visibility conditions at Arkansas’ Class I areas. 

We disagree with comments contending that we inappropriately used CALPUFF modeling to 

determine impacts and project visibility benefits from installing controls on Independence. 

Although the reasonable progress provisions of the Regional Haze Rule place emphasis on the 

20% worst days, the CAA goal of remedying visibility impairment due to anthropogenic 

emissions encompasses all days. Thus, states and EPA have the discretion to consider the 

visibility impacts of sources and the visibility benefit of controls on days other than the 20% 

worst days in making their decisions, such as the days on which a given facility has its own 

largest impacts. Even if the days on which a given facility has its largest impacts are not the 

same as the 20% of days with the worst visibility overall, the facility’s impacts will still need to 

be addressed for Arkansas’ Class I areas to achieve the national goal of natural visibility 

conditions. The Eighth Circuit previously addressed state and EPA use of CALPUFF for 

reasonable progress purposes.236 We address comments contending that CALPUFF modeling 

overestimates the impacts of emissions and the visibility benefits of controls elsewhere in this 

document. 

One commenter alleges that EPA “proposes to supplant the State of Arkansas’ primary authority 

by imposing a proposed FIP” that requires controls under reasonable progress. In arguing that 

our FIP should not require controls under reasonable progress, the commenter further states that 

the CAA provides states with discretion in establishing RPGs and that it requires only that a state 

establish reasonable progress, not the most reasonable progress. First, we point out that our 

proposed partial approval and partial disapproval of the Arkansas RH SIP submitted to us in 

2008 was published in the Federal Register on October 17, 2011.237 We held a 66 day public 

 

236 North Dakota v. EPA, 730 F.3d 750, 764-66 (8th Cir. 2013) (discussing reasonable progress determination for the 

Antelope Valley station). 

237 76 FR 64186. 
131 

comment period and our final action was published on March 12, 2012.238 In our final action, we 

determined that the Arkansas RH SIP does not meet certain elements of the CAA and the Federal 

regional haze requirements and partially approved and partially disapproved the Arkansas RH 

SIP. The portions that we disapproved included Arkansas RPGs for Caney Creek and Upper 

Buffalo because the state did not conduct a reasonable progress analysis and also because the 

RPGs were based on BART determinations that did not meet the requirements of the CAA and 

the Regional Haze regulations. While we did receive adverse comments on that proposal, no 

petitions were filed for judicial review of the final rule, and the rule became effective on April 

11, 2012. Under section 110(c) of the Act, whenever we disapprove a mandatory SIP submission 

in whole or in part, we are required to promulgate a FIP within two years unless we approve a 

SIP revision correcting the deficiencies before promulgating a FIP. To date, Arkansas has not 

submitted a SIP revision following our partial disapproval, and EPA is already past-due on its 

obligation to promulgate a FIP per the statutory deadlines. Therefore, the comment that we are 

“supplant[ing] the State of Arkansas’ primary authority by imposing a proposed FIP” is not 

supported by the facts. To the extent the commenter is suggesting that the RPGs provided by 

Arkansas in its RH SIP are acceptable or appropriate, such comment is not germane to the 

proposed action we solicited comments on and is outside the scope of this action. 

Second, we agree that the CAA provides states with discretion in conducting a reasonable 

progress analysis and establishing RPGs. However, when standing in the shoes of a state and 

promulgating a FIP, EPA has the same discretion as the state. Third, we note that the 

commenter’s statement that the CAA “requires only that a state establish reasonable progress, 

not the most reasonable progress” is taken from a court decision in North Dakota v. EPA, 730 

F.3d 750, 768 (8th Cir. 2013). We interpret the Court’s statement as meaning broadly that just 

because a more stringent level of control could be technically feasible in a particular instance, it 

does not mean it necessarily must be required under reasonable progress. We see no conflict with 

this determination and our proposed Arkansas RH FIP. Extending the Court’s reasoning, we too 

could have proposed additional controls on other sources within Arkansas, or higher levels of 

control on the source for which we proposed controls. We proposed, however, that neither 

additional controls nor a higher level of control on the source for which we proposed controls 

was appropriate, after applying the four reasonable progress factors. In other words, we did not 

propose the highest level of control (referred to by the Court as “most reasonable”). Based on the 

analysis that is required under the CAA and section 51.308(d)(1), we have determined that there 

are cost effective controls available in addition to having significant visibility benefits and we are 

requiring those controls in this FIP. 

Some commenters argue that EPA should not look beyond BART-eligible units to achieve the 

state’s URP goals during the first planning period since “EPA’s disapproval of the 2008 

Arkansas SIP was not due to lack of reasonable progress to achieve visibility improvement or for 

failure to meet the state’s URP goals.” These commenters contend that EPA primarily 

disapproved Arkansas’ SIP because the underlying emissions reduction requirements were based 

on presumptive limits instead of on properly conducted unit-specific BART evaluations. This 

statement is incorrect. Our March 12, 2012 partial approval and partial disapproval of the 

Arkansas RH SIP239 included disapproval of a large portion of the state’s BART determinations, 

 

238 77 FR 14604. 239 77 FR 14604. 
132 

as well as the state established RPGs. We disapproved the state’s RPGs both because the RPGs 

did not reflect appropriate BART determinations and because the state did not conduct the 

reasonable progress analysis required under the CAA and section 51.308(d)(1) in establishing the 

RPGs. In foregoing the reasonable progress analysis, the state did not demonstrate that the RPGs 

it established were a reflection of the control measures and the amount of visibility improvement 

necessary to make reasonable progress. We discuss elsewhere in this response that the 

requirements under section 51.308(d)(1) cannot be satisfied by merely being on or below the 

URP glidepath. 

We continue to hold that our reasonable progress analysis, including our approach for 

determining which sources to look at more closely and evaluate under reasonable progress, is 

appropriate and in accordance with the CAA, the Regional Haze Rule, and our 2007 Reasonable 

Progress Guidance. Based on our analysis of the four statutory factors and our consideration of 

the visibility impacts and visibility benefits of controls, we conclude that the SO2 and NOX

emission limitations we are establishing for Independence Units 1 and 2 are necessary to make 

reasonable progress at Arkansas’ Class I areas for this planning period. 

We disagree with commenters contending that we did not appropriately analyze which sources, if 

any, should be controlled under the reasonable progress requirements and that we arbitrarily 

singled out Independence. We address these comments elsewhere in this document. 

We discuss elsewhere in this document that the purpose of our reasonable progress analysis for 

Arkansas’ Class I areas is to address visibility impacts at Arkansas’ Class I areas and establish 

RPGs for Arkansas’ Class I areas, not to address Arkansas’ impacts on Missouri’s Class I areas. 

We address elsewhere in this document comments stating that our FIP should rely on CSAPR to 

satisfy the NOX BART requirement for Arkansas EGUs. 

Comment: EPA has not demonstrated that its proposed BART and Reasonable Progress 

controls are necessary for Arkansas to maintain reasonable progress and achieve the 

visibility goals of the CAA, especially in view of the uncertainty that those controls will 

result in actual visibility improvements. 

[Nucor Steel-Arkansas and Nucor-Yamato Steel Company (0163) p. 16-19] Nucor stated that 42 

USC §7491 requires that Regional Haze implementation plans contain emission limits, 

compliance schedules and other measures, including BART, “as may be necessary to make 

reasonable progress” toward meeting the CAA’s visibility goals. Monitoring data shows that 

Arkansas has made and will continue to make reasonable progress in visibility improvements 

even without the controls that would be required by EPA’s proposed FIP. (Ex. 3, Arkansas Five 

Year RHR Progress Report, 2015; Ex. 5, ICF International, “Criteria Pollutant Modeling 

Analysis for Arkansas” July 28, 2014, p. 20 (“The IMPROVE data indicate that the 2018 goals 

have been met or nearly met in 2012.”)).

Nucor stated that the additional emission reductions from coal-fired power plants in the states 

surrounding Arkansas and the four Class I areas addressed in the proposed FIP will continue 

Arkansas’ visibility improvement trends. As shown by the spreadsheet attached hereto as Ex. 6, 
133 

of the 68 fossil-fuel electric generating units closest to Arkansas and the four Class I areas 

addressed in the proposed FIP, 17 units are scheduled for or have already been retired or 

converted to natural gas (4.9 GW capacity), and 32 units have had pollution control projects 

announced or completed since 2010 (13.9 GW capacity). Further reductions in emissions due to 

the effects of other regulatory programs and developments will further support Arkansas’s 

visibility improvement trends. (See, Ex. 3, Arkansas Five Year RHR Progress Report, 2015, p. 

23-34.) 

Nucor stated that EPA’s maximum modeled visibility improvements for the affected units at 

White Bluff, Flint Creek and Independence are less than 1dv (the threshold of visibility) for all 

Class I areas.240 This does not even take into account the known overestimation of visibility 

impacts in the CALPUFF model by at least five times, and the fact that these impact levels are 

well below the CALPUFF model's effective limit of usefulness of 2-3 dv. Given this uncertainty, 

EPA has not explained how installation of these controls may reasonably be anticipated to result 

in actual improvement in visibility, which is the purpose of 42 USC §169A and the Regional 

Haze Rule – not just reduction of emissions for the sake of doing so. National Parks 

Conservation Association v. EPA, No. 12-73710, 2015 WL 3559149 (9th Cir., June 9, 2015). 

As the Supreme Court recently held, federal administrative agencies must engage in “reasoned 

decision making,” the agency’s “decreed result must be within the scope of its lawful authority” 

and “the process by which it reaches the result must be logical and rational.” Michigan v. EPA, 

576 U.S, slip op. at 5 (June 29, 2015). Although it should be apparent, the accepted meaning of 

the word “necessary” is “indispensable” or “absolutely needed.” Webster’s New Collegiate 

Dictionary, (8th Ed.) 1973. Thus, as used in 42 U.S.C. §7491 the term “necessary” means 

“absolutely needed.” In view of the existing and future improvements in air quality in the areas 

surrounding these four Class I areas, and in view of the uncertainty that EPA's proposed BART 

and Reasonable Progress controls will result in actual visibility improvements, EPA has not 

explained nor demonstrated that its BART and Reasonable Progress determinations are 

“indispensable” or “absolutely needed,” i.e., that the only way Arkansas can maintain reasonable 

progress and achieve the visibility goals of the CAA is to install these controls. See, North 

Dakota v. EPA, 730 F.3d at 768. The meaning of the word “necessary” requires EPA to take 

these and other relevant factors into consideration in its BART and reasonable progress 

determinations and to demonstrate that these controls are indispensable. EPA has not explained 

how it considered these and other relevant factors in reaching its decision that its BART 

determinations for Flint Creek and White Bluff and its Reasonable Progress determination for 

Independence is “absolutely necessary” either to meet the reasonable progress goals for the 

planning period ending on 2018, or the national goal in 2064. Michigan v. EPA, 576 U.S, (June 

28, 2015). 

[Arkansas Electric Energy Consumers Inc. and Arkansas Gas Consumers Inc. (0175) p. 8-9] 

AEEC and AGC stated that 42 U.S.C. § 7491 requires Regional Haze implementation plans to 

contain emission limits, compliance schedules and other measures, including BART, “as may be 

necessary to make reasonable progress” toward meeting the CAA’s visibility goals.241 Data 

 

240 See, Exhibit 7 to Nucor’s comments, Spreadsheet of Modeled Baseline Visibility Impacts and Visibility 

Improvements from Proposed FIP. 

241 42 U.S.C. § 7491 (emphasis added). 
134 

contained in the Five-Year Regional Haze Progress Report that ADEQ submitted to the EPA 

reveals that Arkansas has made and will continue to make reasonable progress in visibility 

improvements without the controls required by the proposed FIP. Further reductions in emissions 

due to the effects of other regulatory programs and developments will supplement Arkansas’ 

trend toward visibility improvement. As explained in section five of AEEC and AGC’s 

comments, the EPA’s maximum modeled visibility improvements for the affected units at White 

Bluff, Flint Creek and Independence are less than one deciview for all Class I areas. Further, 

these projected improvements fail to account for known problems with the models utilized by the 

EPA. Given these realities, the EPA has utterly failed to demonstrate that installation of the 

controls required by the proposed FIP may reasonably be anticipated to result in actual 

improvement in visibility, which is the purpose of the Regional Haze Rule.242 The accepted 

meaning of the word “necessary” is “indispensable” or “absolutely needed.”243 In light of the 

existing and future improvements in visibility surrounding the affected Class I areas, and the 

uncertainty that the EPA’s proposed controls will result in actual visibility improvements, EPA 

has totally failed to demonstrate that its BART and Reasonable Progress determinations are 

“indispensable;” EPA has not, and cannot, demonstrate that the proposed controls constitute the 

only way Arkansas can achieve the visibility goals of the CAA.244 Since the BART and 

Reasonable Progress determinations contained in the Proposed FIP are not “necessary,” EPA 

should withdraw the Proposed FIP. 

Response: We address in more detail elsewhere in this document comments related to ADEQ’s 

5-Year Progress Report SIP revision and comments asserting that recent monitoring data 

demonstrate that Arkansas’ Class I areas are on track to meet the RPGs provided by the State in 

the Arkansas RH SIP even without the controls under BART and reasonable progress that we 

proposed to require in our FIP. As we discuss in those responses, meeting or being projected to 

meet the RPG does not necessarily demonstrate that a state has satisfied its requirements under 

BART and reasonable progress. 

Clean Air Act section 169A(b)(2) required us to promulgate regulations directing the States to 

revise their SIPs to include emission limits and other measures as necessary to make “reasonable 

progress.” Congress defined reasonable progress based on the consideration of four statutory 

factors: (1) the costs of compliance, (2) the time necessary for compliance, (3) the energy and 

nonair quality environmental impacts of compliance, (4) and the remaining useful life of any 

existing source subject to such requirements.245 We commonly refer to our analysis of these four 

statutory factors as a reasonable progress analysis. Congress also directed EPA to promulgate 

regulations requiring BART for a specific universe of older sources, and again provided a set of 

five statutory factors States must consider: (1) the costs of compliance, (2) the energy and nonair 

quality environmental impacts of compliance, (3) any existing pollution control technology in 

use at the source, (4) the remaining useful life of the source, and (5) the degree of improvement 

in visibility which may reasonably be anticipated to result from the use of such technology.246 

 

242 National Parks Conservation Association, supra. 243 Webster’s New Collegiate Dictionary (8th Ed.), 1973. 244 North Dakota, supra, at 768. 245 CAA section 169A(g)(1). 246 CAA section 169A(b)(2)(A), (g)(2). 
135 

Thus, the BART determination must be based on an analysis that considers the five statutory 

factors under CAA section 169A(g)(2) and the Regional Haze regulations under 40 CFR 

51.308(e)(1). The determination of what is necessary to make reasonable progress, including 

whether additional controls beyond BART and other “on the books” controls are necessary to 

make reasonable progress, must be made based on an analysis of the four statutory factors under 

CAA section 169A(g)(1) and the Regional Haze regulations under 40 CFR 51.308(d)(1). The 

Regional Haze regulations under 40 CFR section 51.308(d)(1) also require consideration of these 

four statutory factors in establishing the RPGs. The Arkansas RH SIP did not meet this statutory 

and regulatory requirement. In our March 12, 2012, final action on the Arkansas RH SIP, we 

disapproved several of the State’s BART determinations and the State’s RPGs. We disapproved 

the State’s RPGs because they were based on BART determinations that did not meet the 

requirements of the CAA and the Regional Haze regulations, and because the RPGs were 

determined without conducting the required four factor analysis. That final action became 

effective on April 11, 2012. Therefore, EPA is required under CAA section 110(c) to promulgate 

a FIP and/or approve a SIP revision for the portions of the Arkansas Regional Haze SIP that we 

disapproved on March 12, 2012. This includes conducting BART analyses and making BART 

determinations for Arkansas’ BART sources and conducting a four factor reasonable progress 

analysis to determine if additional controls (beyond BART and other “on the books” controls) 

are necessary to make reasonable progress in Arkansas’ Class I areas. 

The fact that Arkansas’ Class I area are achieving or are projected to achieve the State’s 

disapproved RPGs does not divest us from our authority and obligation to conduct BART 

analyses as well as a four factor analysis to determine appropriate controls and emission limits. 

As discussed in our proposal and in our final rule, we conducted BART analyses for White Bluff 

and Flint Creek, as well as other Arkansas BART sources. In our BART analyses, we considered 

the five statutory factors required under CAA section 169(g)(2) and the Regional Haze Rule at 

40 CFR section 51.308(e)(1)(A). We also conducted an analysis of the four reasonable progress 

factors required under CAA section 169A(g)(1) and 40 CFR 51.308(d)(1), and considered the 

visibility impacts and visibility improvement of potential controls to determine if additional 

controls (beyond BART and other “on the books” controls) are necessary to make reasonable 

progress in Arkansas’ Class I areas.247 We discuss in our final rule and elsewhere in this 

document that the emission limitations we are requiring under the BART and the reasonable 

progress requirements in this FIP, along with other “on the book” reductions, are what we have 

determined are necessary to make reasonable progress at Arkansas’ Class I areas, based on our 

analyses required under the CAA and the Regional Haze regulations. The discussion of how we 

considered the statutory factors in establishing BART and reasonable progress controls is found 

in our proposal and in our final rule and further discussed elsewhere in this document. 

The Regional Haze Rule provides that these emission limitations and control measures are what 

is enforceable, not the RPGs themselves.248 The numeric RPGs are calculated by taking into 

account the visibility improvement anticipated from these enforceable emission limitations and 

 

247 As discussed in our proposal and in our final rule, although visibility is not one of the four mandatory factors 

explicitly listed for consideration under CAA section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), states and EPA 

have the option of considering the projected visibility benefits of controls in determining if the controls are 

necessary to make reasonable progress. 

248 64 FR 35733. 
136 

other control measures (including BART, reasonable progress, and other “on the books” 

controls). Thus, the RPGs represent the best estimate of the degree of visibility improvement that 

will result in 2018 from changes in emissions inventories, changes driven by the particular set of 

control measures the state has adopted in its regional haze SIP or EPA in a regional haze FIP to 

address visibility, as well as all other enforceable measures expected to reduce emissions over 

the period of the SIP from 2002 to 2018.249 But the RPGs themselves are not enforceable. As 

such, meeting or being projected to meet the RPG does not necessarily demonstrate that a state 

has satisfied its requirements under BART and reasonable progress. 

Further, as we discuss elsewhere in this document, we finalized our disapproval of Arkansas’ 

RPGs for Caney Creek and Upper Buffalo in a previous action that became effective on April 11, 

2012. Therefore, any comments upholding or suggesting that the State’s RPGs are appropriate or 

adequate are not germane to the proposed action we solicited comments on and are outside the 

scope of this action. 

One commenter states that EPA has not, and cannot, demonstrate that the proposed controls 

constitute the only way Arkansas can achieve the visibility goals of the CAA. We agree that the 

controls in our FIP proposal are not the only way Arkansas can fully meet the regional haze 

requirements in the CAA and our regulations. The CAA and the RH rule gives states and EPA 

(in the case of a FIP) wide latitude in considering and weighing the statutory factors that must be 

considered under the requisite analyses under section 51.308(e) in establishing BART and under 

section 51.308(d)(1) in establishing controls under reasonable progress. Even though we are 

required to prepare our own analysis to do a FIP, this does not mean our analysis and conclusions 

are precisely what Arkansas would itself conclude in a SIP revision to meet the CAA 

requirements. In other words, the state could potentially conduct analyses that fully satisfy the 

CAA and Regional Haze rule but arrive at a different, but nonetheless approvable, conclusion for 

BART and reasonable progress controls than we have in this FIP. In our FIP proposal, we stated 

that we will work with the State of Arkansas if it chooses to develop a SIP revision to replace our 

FIP.250 We continue to be committed to work with the state in this process. 

While we acknowledge the data provided by one commenter regarding the actual or scheduled 

retirement or conversion to natural gas, as well as controls on a number of units located close to 

Arkansas and the Class I areas addressed in our FIP, we do not agree that this justifies 

withdrawal of our FIP. As discussed in our proposal, in our final action, and elsewhere in this 

document, the emission limitations we are requiring under the BART and the reasonable 

progress requirements in this FIP, along with other “on the book” reductions, are what we have 

determined are necessary to make reasonable progress at Arkansas’ Class I areas, based on our 

analyses required under the CAA and the Regional Haze regulations. 

We address elsewhere in this document comments suggesting or contending that we cannot 

establish controls under BART or reasonable progress that result in visibility improvement less 

than 1 dv. We also address elsewhere in this document comments contending that there is an 

overestimation of visibility impacts in the CALPUFF model and that there is uncertainty in the 

visibility improvement of the controls we are requiring in our FIP. 

 

249 64 FR 35733. 250 80 FR at 18945. 
137 

Comment: The EPA should not look beyond BART eligible units to achieve greater 

visibility improvements and should instead defer to ADEQ to reevaluate the RPG and URP 

before imposing any additional specific emissions reductions. [AEP-SWEPCO July 15, 2015 

comments (0164) p. 3-5, and August 7, 2015 comments (0167) p. 4-5] AEP-SWEPCO stated that 

the Regional Haze Rule and section 169A of the CAA require the states, or EPA in the case of a 

FIP, to set RPGs by considering four factors: the costs of compliance, the time necessary for 

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

remaining useful life of any potentially affected sources. Also, the Regional Haze Rule does not 

mandate specific milestones or rates of progress towards achieving the national visibility goal, 

but instead calls for states to establish goals that provide for “reasonable progress” toward 

achieving natural (i.e., “background”) visibility conditions.251

In their 5-year Regional Haze Progress Report, ADEQ notes that 40 C.F.R. § 51.308(g)(6) of the 

RHR requires: “An assessment of whether the current implementation plan elements and 

strategies are sufficient to enable the State, or other States with mandatory federal Class I areas 

affected by emissions from the State, to meet all established reasonable progress goals.”252

ADEQ has assessed the current SIP elements and strategies and determined that, based upon 

relevant data (i.e., projected emissions and modeling results), they are sufficient to enable 

Arkansas and other states with Class I areas affected by emissions from Arkansas to meet all 

established reasonable progress goals.253

EPA’s disapproval of the 2008 SIP was not due to lack of reasonable progress to achieve 

visibility improvement or for missing the Uniform Rate of Progress (URP). It was disapproved 

primarily because the underlying emissions were based on presumptive limits and no BART 

evaluations had been conducted. The RPG and URP in the 2008 SIP, and as supported in the 5-

year update, should be accepted as presented by the State. The actions required by EPA in the 

FIP to conduct BART analyses only serve to achieve greater emission reductions than in that 

analysis. Therefore, EPA should not look beyond BART eligible units to achieve greater 

visibility improvements. EPA should not simply use the RH program as leverage to impose 

emissions reductions that have little benefit to the purpose of the rule to improve visibility. EPA 

should allow, and defer to, ADEQ to reevaluate the RPG and URP before imposing any 

additional specific emissions reductions. 

EPA determined that it would be appropriate to evaluate the Entergy Independence facility 

relative to reasonable progress obligations. We, however, disagree with EPA's conclusion that 

imposing emission controls on the Independence facility is needed to meet the statutory 

requirements. 

 

251 80 Fed. Reg. at 18989. 252 STATE OF ARKANSAS, State Implementation Plan Review for the Five-Year Regional Haze Progress Report, 

Prepared by the Arkansas Department of Environmental Quality Air Division Planning Branch, April2014, Revised 

November 2014, p. 55 (hereinafter "Five-Year Progress Report). 253 Five-Year Progress Report, p. 55. 
138 

Response: We address elsewhere in this document comments contending that ADEQ’s Five 

Year Progress Report SIP revision shows that Arkansas’ Class I areas are projected to meet the 

State’s disapproved RPGs, as well as the URP glidepath in 2018, and that the controls required in 

our FIP are therefore not necessary. 

With regard to the comment that our partial disapproval of the Arkansas RH SIP was not due to 

lack of reasonable progress, we discuss elsewhere in this document that our March 12, 2012 final 

action254 partially approving and partially disapproving the Arkansas RH SIP, included a 

disapproval of the majority of the state’s BART determinations as well as disapproval of the 

state established RPGs. We disapproved the state’s RPGs because the RPGs relied on BART 

determinations that did not meet the requirements of the CAA and the RH regulations and 

because Arkansas failed to conduct a four-factor analysis, as required by the CAA and the 

Regional Haze Rule. Without a four-factor analysis, we were unable to verify whether any 

additional control measures were necessary to make reasonable progress—the core requirement 

of the CAA’s visibility program.255 Our final action disapproving the State’s RPGs became 

effective on April 11, 2012. Therefore, any arguments upholding the state’s RPGs or stating that 

we should accept those RPGs are outside the scope of this action. 

The commenter contends that the requirements in our FIP only serve to achieve greater 

emissions reductions than in the Arkansas RH SIP. This is incorrect. Under section 110(c) of the 

Act, whenever we disapprove a mandatory SIP submission in whole or in part, we are required to 

promulgate a FIP within 2 years unless we approve a SIP revision correcting the deficiencies 

before promulgating a FIP. Therefore, the purpose of our FIP is to correct the deficiencies in the 

SIP and conduct the required analyses and establish emission limits in accordance with the CAA 

and the RH rule. We are requiring controls under BART based on our analyses of the five 

statutory factors required under CAA section 169A(g)(2) and the Regional Haze regulations 

under 40 CFR 51.308(e)(1). As discussed in our final rule, based on our analysis of the four 

reasonable progress factors under CAA section 169A(g)(1) and 40 CFR 51.308(d)(1), and our 

consideration of the visibility improvement of potential controls, we have determined that 

controls at the Independence plant are cost-effective, reasonable, and would result in meaningful 

visibility benefits at Arkansas’ Class I areas, and are therefore necessary to make reasonable 

progress. We are therefore requiring these controls. 

With regard to the comment that EPA should defer to ADEQ to reevaluate the RPG and URP 

before imposing any additional specific emissions reductions, we note that Arkansas has not yet 

submitted a SIP revision following our partial disapproval, and EPA is already past-due on its 

action per the statutory deadlines. There is no authority in the CAA for EPA to further delay our 

action for the reasons provided by the commenter. We are operating under a court-ordered 

deadline to take final action to promulgate a FIP or approve a SIP revision that addresses the 

deficiencies in the Arkansas RH SIP by August 31, 2016.256

 

254 77 FR 14604. 255 CAA section 169A(b)(1) and (g)(1). 256 Sierra Club v. Gina McCarthy, No. 4.14CV00643JLH (ED Ark. Western Div. Nov. 3, 2015). 
139 

Comment: Even if EPA were to decide, as it should, not to establish NOX BART emission 

limits for White Bluff, Flint Creek, and Independence, Arkansas would still meet or exceed 

the emissions reductions necessary to meet the URP and satisfy the reasonable progress 

requirements. [UARG (0176) p. 14-15] UARG stated that EPA proposes reasonable progress 

emission limits as part of the FIP. The proposed reasonable progress emission limits are not 

justified under EPA’s visibility rules and the Reasonable Progress Guidance and rest on an 

incorrect legal premise. EPA therefore should not promulgate the proposed reasonable progress 

emission limits. 

Even if a reasonable progress assessment were warranted here, the information in the record 

establishes that no additional emission reduction requirements are necessary or justified to 

achieve reasonable progress during the regional haze program’s first planning period with 

respect to the units that EPA analyzes. In the proposed rule, EPA evaluates three facilities under 

the reasonable progress provisions: the White Bluff Plant, the Flint Creek Power Plant, and the 

Independence Power Plant. 

As for White Bluff and Flint Creek, EPA properly proposes to find that the SO2 and NOX BART 

requirements that EPA proposes for those units are “adequate for this first planning period to 

eliminate these sources from further consideration of controls under the reasonable progress 

requirements for this first regional haze planning period.” 80 Fed. Reg. at 18,991. The proposed 

rule states that the proposed BART FIP requirements for these units are “anticipated to result in a 

substantial reduction in SO2 and NOX emissions from these two facilities.” Id. Relying on BART 

to satisfy reasonable progress is consistent with the Reasonable Progress Guidance. See 

Reasonable Progress Guidance at 4-2 to 4-3, 5-1. It is appropriate, therefore, for EPA to 

determine that no additional emission reduction requirements are needed for these facilities in 

response to the reasonable progress provisions. 

Further, even if EPA were, in effect, to revise its proposed BART determinations for White Bluff 

Units 1 and 2 and Flint Creek Unit 1 by not promulgating the proposed NOX BART limits for 

those units, as recommended in Section II of UARG’s comments, both facilities would still 

satisfy all reasonable progress requirements for the first planning period. As stated above, 

Arkansas’s Regional Haze SIP, as submitted to EPA, required emission reductions that were 

more than adequate to meet the URPs during the first planning period, and those emission 

reductions would have been sufficient to satisfy reasonable progress requirements for that period. 

EPA proposes SO2 and NOX BART emission limits for White Bluff and Flint Creek that – in 

conjunction with other proposed control requirements – are significantly more stringent than 

necessary to meet the URPs, and, as discussed in Section II of UARG’s comments, the proposed 

FIP’s NOX BART limits for these plants would produce negligible visibility improvement, 

according to EPA’s projections. If EPA were to decide – as it should – not to promulgate the 

proposed FIP’s NOX BART requirements for these three units, Arkansas would nevertheless 

meet or exceed the rate of emission reductions necessary to meet the relevant URPs and to 

satisfy reasonable progress requirements. 

Response: We address elsewhere in this document comments contending that an evaluation 

under reasonable progress and that controls under reasonable progress are not necessary because 
140 

Arkansas’ Class I areas are projected to meet the state’s RPGs and are projected to be below the 

URP glidepath in 2018. 

As we discuss in more detail elsewhere in this document, meeting or being projected to meet the 

RPG and/or being below the URP glidepath in 2018 does not necessarily demonstrate that a state 

has satisfied its requirements under BART and reasonable progress for the first planning period. 

Further, the fact that Arkansas’ Class I areas are projected to meet the State’s RPG and are below 

the 2018 URP glidepath, does not divest us from our authority and obligation to conduct NOX

BART analyses for White Bluff and Flint Creek and determine appropriate controls under the 

BART requirements. Nor does it divest us from our authority and obligation to conduct a 

reasonable progress analysis to determine if there are controls in addition to BART that are 

necessary to make reasonable progress for the first planning period. We discuss in our final rule 

and elsewhere in this document that we have determined, based on our analysis of the five 

statutory factors, that NOX emission limits consistent with LNB/SOFA controls are BART for 

White Bluff Units 1 and 2 and that NOX emission limits consistent with LNB/OFA controls are 

BART for Flint Creek Unit 1. We also discuss in our final rule and elsewhere in this document 

that based on our analysis of the four statutory reasonable progress factors and our consideration 

of the visibility improvement of potential controls, we have determined that SO2 and NOX

controls for Independence would be cost-effective and would result in meaningful visibility 

benefits at Arkansas’ Class I areas, and therefore find that these are reasonable controls and are 

necessary to make reasonable progress. As such, we are requiring SO2 and NOX controls for 

Independence Units 1 and 2 under the reasonable progress requirements. 

We discuss elsewhere in this document that in our March 12, 2012 final action257 on the 

Arkansas RH SIP, we disapproved the State’s RPGs because the RPGs relied on BART 

determinations that did not meet the requirements of the CAA and the RH regulations and 

because Arkansas failed to conduct the four-factor analysis required by the CAA and the 

Regional Haze Rule. Without a four-factor analysis, we were unable to verify whether any 

additional control measures were necessary to make reasonable progress—the core requirement 

of the CAA’s visibility program.258 Our final action partially disapproving the Arkansas RH SIP 

became effective on April 11, 2012. Therefore, to the extent the comment contends that the 

Arkansas Regional Haze SIP satisfied the reasonable progress requirements for the first planning 

period, such argument is not germane to the proposed action we solicited comments on and is 

outside the scope of this action. 

 

We appreciate the commenter’s support of our decision not to require additional controls beyond 

BART for White Bluff and Caney Creek to satisfy the reasonable progress requirements. 

We address elsewhere in this document specific comments contending that our NOX BART 

limits for White Bluff, Flint Creek, and Independence would produce negligible visibility 

improvement. 

 

257 77 FR 14604. 258 CAA section 169A(b)(1) and (g)(1). 
141 

Comment: [UARG (0176) p. 18-19] UARG stated that EPA proposes, as Option 1, SO2 and 

NOX emission limits to satisfy reasonable progress requirements for the Independence Power 

Plant. Id. In the alternative, EPA proposes, as Option 2, only the SO2 emission limits due to the 

vanishingly small extent of the putative “visibility improvements” – amounting to “less than 

0.003 dv” – that the proposed NOX emission limits for Independence would produce. Id. If EPA 

proceeds with these unjustified reasonable progress limits at all, it plainly must reject Option 1 

and instead adopt Option 2, as imposition of the proposed NOX emission limits would not be 

remotely defensible. 

In any event, however, neither Option 1 nor Option 2 recognizes that, for SO2 as well as for 

NOX, these proposed reasonable progress emission limits are not compelled by the CAA or 

EPA’s rules and are unwarranted and improper under the circumstances. Because the URPs for 

the relevant Class I areas are projected to be met and even exceeded in the absence of any of 

these proposed emission limits, and because the projected visibility improvements these limits 

would produce are very small and cannot justify the very large costs that would be incurred to 

implement them, EPA should withdraw this part of its proposed rule. 

Response: We disagree that our proposed SO2 and NOX controls for Independence are 

inappropriate and not compelled by the CAA or Regional Haze rule. We disagree that our 

proposed SO2 and NOX controls on Independence are expected to produce “very small” visibility 

benefits and that the costs are therefore not justified. We address specific comments concerning 

these issues elsewhere in this document. As discussed in greater detail in our final rule and 

elsewhere in this document, we are finalizing both SO2 and NOX controls for Independence (i.e., 

proposed Option 1). 

 

We also discuss elsewhere in this document that the fact that a Class I area is below the URP 

glidepath does not automatically mean that no controls or evaluation under reasonable progress 

is necessary. 

Comment: EPA should not require front-loading of extensive control requirements in the 

first regional haze planning period, and should instead delay consideration of controls on 

Independence until the next planning period to allow regulated entities the opportunity to 

conduct integrated compliance planning in ways that are consistent with provision of 

reliable and affordable electric power. 

[Edison Electric Institute (0174) p. 2-4, 7] EEI stated that the Clean Air Act (CAA) regional haze 

program tasks states with determining what is reasonable progress toward elimination of manmade visibility impairment, for which EPA has set a goal of 2064 with required progress 

milestones (i.e., 10-year planning and SIP revisions, with program reviews in the middle of each 

10-year planning period).259 Accordingly, the CAA’s regional haze program contemplates 

gradual visibility improvements along a “glide path” toward the 2064 goal. This program does 

not require immediate and costly reductions in the first planning period or any subsequent 

planning period that go beyond what is needed to make “reasonable progress,” as determined by 

 

259 The first 10-year planning period began in 2009 and ends in 2018. The next runs from 2019-2028, with SIPs due 

in 2018. 
142 

a state based on its assessment of the four statutory factors.260 Thus, it neither requires nor 

authorizes the front-loading of extensive control requirements. See RHR, 64 Fed. Reg. 35,721, 

35,732 (July 1, 1999)(describing the analytical requirements for setting reasonable progress 

goals in terms of achieving a “uniform rate of progress” toward the 2064 goal). 

Delaying consideration of controls on Independence until the next planning period is a more 

reasonable approach that would allow for the consideration of updated information, such as 

control equipment characteristics and costs, emissions reductions attributable to other regulatory 

and market drivers, and contemporaneous monitoring and meteorological conditions, which 

would allow the coordination of these important investment and regulatory decisions with the 

implementation of other pending regulations. Finally, this approach would give states and 

regulated entities the opportunity to conduct integrated compliance planning in ways that are 

consistent with provision of reliable and affordable electric power. EPA should withdraw its 

proposed controls for Independence 1 and 2. 

As EPA and the states begin to implement the next rounds of the regional haze program to 

continue to make reasonable progress, EPA should allow states—through state environmental 

and electric utility regulators and in conjunction with power companies—to consider the timing 

and scope of additional control activities, consistent with effective long-term utility planning. 

This planning process is vital to minimize impacts on the cost and reliable provision of 

electricity to customers and to allow investment decisions to be made over suitable planning 

horizons. EPA also must take into consideration progress already made through the installation 

of controls to satisfy BART requirements and other CAA regulations that can result in reduced 

emissions that may lessen visibility impairment. 

Response: We agree that the regional haze program contemplates gradual visibility 

improvements over several planning periods. Those gradual improvements are guided by the 

principle that controls found to be reasonable in a given planning period should be required now, 

rather than in some unspecified future planning period. That is the very nature of “reasonable 

progress.” For that reason, we do not consider the controls we proposed and those we are 

finalizing in our FIP as being frontloading. As we discuss in our final rule and throughout this 

document, our cost analysis indicates that the SO2 and NOX controls we are requiring for 

Independence Units 1 and 2 are cost effective and well within the range of cost of controls found 

to be reasonable by EPA and the states in other regional haze actions for this first planning 

period. Arkansas did not comply with certain aspects of the Regional Haze Rule and thus 

portions of its Regional Haze SIP submitted to us in 2008 were not approvable, including the 

state’s reasonable progress determinations and RPGs.261 We therefore have an obligation to 

promulgate this FIP to address the disapproved portions of the State’s SIP submission. Pursuant 

to CAA section 169A(g)(1) and our Regional Haze regulations at 40 CFR section 51.308(d)(1), 

we conducted an evaluation of additional controls under a reasonable progress analysis that 

considered the four statutory factors. As discussed in our proposal and throughout this final rule, 

based on the demonstrations we developed pursuant to the CAA and section 51.308(d)(1) and 

our consideration of the visibility impacts from Independence and the visibility improvement of 

 

260 Cost of compliance, time necessary for compliance, energy and non-air quality impacts of compliance and 

remaining useful life of any existing source subject to such requirements. 

261 77 FR 14604. 
143 

potential controls, we determined that there are reasonable and cost-effective SO2 and NOX

controls available for Independence that would result in considerable visibility benefit at 

Arkansas’ Class I areas. Under the CAA and the Regional Haze regulations, if we determine that 

additional controls are reasonable based on the consideration of the four statutory factors, we 

must require those controls. Therefore, we are requiring SO2 and NOX controls for Independence 

Units 1 and 2 under reasonable progress in this planning period. 

The commenter has not presented any information that justifies the dismissal of controls for 

Independence that we have determined, pursuant to the analysis required under CAA section 

169A(g)(1) and 40 CFR section 51.308(d)(1), are reasonable controls that are cost-effective and 

would result in meaningful visibility benefit at Arkansas’ Class I areas. 

The comments regarding implementation of the next rounds of the regional haze program are 

outside the scope of this action. However, we note that, as we have done in the first round of 

regional haze SIPs, we will allow states to consider the timing and scope of additional control 

activities, consistent with effective long-term utility planning, as the states begin to develop 

future SIPs. 

Comment: EPA improperly relied on CALPUFF modeling in its reasonable progress 

analysis, and Entergy has conducted photochemical modeling to demonstrate that imposing 

controls on Independence will not result in any meaningful visibility improvement at 

Arkansas’ Class I areas. [Entergy Arkansas Inc. (0149) p. 18, 20-23] Entergy stated that EPA 

improperly relied on CALPUFF modeling in its reasonable progress analysis and, as a result, has 

significantly over-estimated Independence’s contribution to visibility impairment and the 

deciview improvement that would result from the installation and operation of emissions controls 

at Independence.262 The visibility impairment at Arkansas’ two Class I areas is caused 

overwhelmingly by point sources outside of the state, secondary organic aerosols- biogenic 

(SOAB), mobile sources, and Arkansas area sources,263 not by Arkansas point sources such as 

power plants. EPA’s singular focus on Independence will not result in any meaningful 

improvement in visibility at Caney Creek or Upper Buffalo and will not affect Arkansas’ 

continued progress toward the 2064 natural visibility goal, but will cost Entergy’s customers and 

co-owners over $1 billion. 

Entergy stated that it has conducted additional modeling using the Comprehensive Air Quality 

Model with Extensions (“CAMx”) and statistical analysis that supports this conclusion. The 

CAMx modeling demonstrates that the haze index at Caney Creek and Upper Buffalo will 

remain below the URP for many years to come.264 Recent IMPROVE monitoring data show that 

 

262 It is noteworthy that EPA issued, on July 29, 2015, a proposal to remove CALPUFF from EPA’s preferred list of 

dispersion models used for Clean Air Act purposes. 80 Fed. Reg. 45,340 (July 29, 2015). 263 EPA defines an area source as “a collection of similar emission units within a geographic area.” EPA, 

Introduction to Area Source Emission Inventory Development, at 1.1-3 (Jan. 2001) available at 

http://www.epa.gov/ttnchie1/eiip/techreport/volume03/iii01_apr2001.pdf. “Area sources collectively represent 

individual sources that are small and numerous, and that have not been inventoried as specific point, mobile, or 

biogenic sources. Individual sources are typically grouped with other like sources into area source categories.” Id. 264 The CAMx modeling was conducted by Trinity Consultants, Inc. Trinity’s Regional Haze Modeling Assessment 
144 

the haze index has been consistently below the URP in both Caney Creek and Upper Buffalo. 

Trinity Consultants, Inc. (“Trinity”) also performed statistical analyses on the data from both 

Caney Creek and Upper Buffalo to statistically project the haze index trend through 2018.265

Using a Ranked Statistical Analysis, the haze index for the average of the W20 days in 2018 is 

projected to be 20.07 dv at Caney Creek and 20.91 dv at Upper Buffalo,266 These numbers are far 

below the URP for the first planning period and demonstrate that no source in Arkansas, 

including Independence, needs to install controls for Arkansas to remain below the glide path. 

See Figures 1 and 2. 

“Uniform Rate of Progress and 2018 Projected Progress Caney Creek Wilderness AreaRanked Statistical Analysis” 

(provided by Entergy as Figure 1 to AR020.0166) 

 

Report, which describes the CAMx modeling methodology that Trinity used to evaluate the visibility improvement 

of controls at Independence and White Bluff, is provided as Exhibit C to these comments. 

265 Trinity’s report identifying why a statistical analysis was performed on the IMPROVE data and why the Ranked 

Statistical Analysis was selected is included as Exhibit D to these comments and incorporated by reference herein. 

IMPROVE Data Statistical Analysis, Trinity Consultants (July 2015) (“Trinity Report”). 

266 Trinity also performed a Trend Statistical Analysis of the data, which projects even lower visibility impairment 

of 18.02 dv at Caney Creek and 20.44 dv at Upper Buffalo, Trinity Report at Section 3.1, but Entergy is using the 

more robust and conservative Ranked Statistical Analysis to demonstrate the expected trend in visibility impairment. 
145 

“Uniform Rate of Progress and 2018 Projected Progress Upper Buffalo Wilderness AreaRanked Statistical Analysis 

(provided by Entergy as Figure 2 to AR020.0166) 

Entergy stated that Figures 1 and 2 show the data plots for the 20% worst days and the 20% best 

days from the IMPROVE network for Caney Creek and Upper Buffalo, respectively. These plots 

demonstrate that the W20 days since 2007 have consistently been below the URP and that 

visibility is improving faster than the URP. Trinity applied a Ranked Statistical Analysis to all of 

the haze index values calculated using the new IMPROVE equation and the data from the 

IMPROVE monitoring network and constructed a future projection curve to statistically project 

the haze index at Caney Creek and Upper Buffalo in 2018. Trinity Report at Section 3.2. As 

demonstrated in Figure 1, the Ranked Statistical Analysis indicates that the haze index in 2018 at 

Caney Creek will be 20.07 dv, which is 2.84 dv below the URP. Indeed, if EPA does nothing at 

all (i.e., imposes no BART limits on sources in Arkansas or emission limits on Independence), 

Caney Creek would not approach the glide path until 2030. Figure 2 shows very similar results 

for Upper Buffalo, which would not approach the glide path until at least 2026. In light of these 

projections, which align with ADEQ’s glide path demonstrations (see Arkansas Five-Year 

Progress Report at 57-60), SO2 and NOX emission limits at Independence are unnecessary for 

reasonable progress purposes for at least a decade. 
146 

Notably, the Ranked Statistical Analysis conservatively assumes that there will be no additional 

emissions reductions resulting in visibility improvements after 2018, including emissions 

reductions from out-of-state sources, which cause over 50% of the visibility impairment in 

Arkansas Class I areas, or from area and mobile sources, which account for approximately 

9.25% of the visibility impairment at Caney Creek and 9.68% at Upper Buffalo.267 Assuming 

that MATS achieves the emissions reductions that EPA projects in terms of acid gas controls and 

retirements,268 that CSAPR tightens the SO2 emission budgets in the second phase, that sources 

will be forced to make additional SO2 and NOX reductions to comply with the 1-hour SO2 

NAAQS and the revised ozone NAAQS, and that the Phase 2 CAFE fuel economy standards 

drive further reductions from mobile sources, the haze index in Caney Creek and Upper Buffalo 

will continue to improve beyond 2018 without controls on Independence. 

Response: We acknowledge the data plots provided by the commenter. However, we discuss 

elsewhere in this document that being below the URP glidepath does not automatically mean that 

no controls or evaluation under reasonable progress is necessary in this planning period. 

Additionally, we discuss elsewhere in this document that the improvement in visibility 

conditions in Arkansas’ Class I areas (including the fact that Arkansas’ Class I areas are below 

the URP glidepath), as observed from IMPROVE monitor data, appears to be in large part due to 

emissions reductions outside Arkansas. While we agree that point sources outside Arkansas have 

a significant visibility impact at Arkansas’ Class I areas, we discuss elsewhere in this document 

that most of the visibility improvement currently observed in Arkansas’ Class I areas appears to 

be due to emissions reductions that have taken place outside the state. To the extent that the 

commenter is suggesting that Arkansas should be relieved of its regional haze obligations 

because other states’ emission reduction efforts have already resulted in significant visibility 

improvement at Arkansas’ Class I areas, this is incorrect. Rather, Arkansas or EPA in standing in 

the state’s shoes, must consider the statutory factors in addressing the reasonable progress and 

long term strategy requirements. 

While we agree that Arkansas mobile and area sources have visibility impacts in Arkansas’ Class 

I areas, we disagree that Arkansas point sources do not. Our analysis of the CENRAP 2018 

CAMx photochemical modeling showed that on the 20% worst days, Arkansas point sources 

contribute significantly to visibility impairment at Arkansas’ Class I areas (greater than 4% of 

total visibility impairment at each Arkansas Class I area). We consider this to be a significant 

contribution considering that this percentage is out of the entire universe of sources (spanning all 

source categories both within and outside of the state) that contribute to visibility impairment in 

Arkansas’ Class I areas. As we discussed in our proposal and elsewhere in this document, White 

Bluff, Independence, and Flint Creek are the three largest emitters of SO2 and NOX point source 

emissions in the state, and are responsible for approximately 84% of the SO2 point source 

emissions and 55% of the NOX point source emissions in the state. Independence alone is 

responsible for approximately 36% of the SO2 point source emissions and 21% of the NOX point 

source emissions in the state. Therefore, we expect that addressing these sources under regional 

haze will address a large proportion of the visibility impacts due to Arkansas point sources. We 

also note that the CAMx source-apportionment modeling submitted to us by the commenter also 

 

267 These percentages are based on CENRAP’s Particulate Matter Source Apportionment Technique (“PSAT”) tool. 268 Entergy expects the MATS Rule will go forward before the end of this planning period along with the associated 

emission reductions. 
147 

shows that the Independence Plant has significant visibility impacts in Arkansas’ Class I areas on 

the 20% worst days. 

Entergy’s CAMx modeling shows that the contribution to visibility impairment due to emissions 

from the Independence facility alone are projected to be approximately 1.3% of the total 

visibility impairment during the 20% worst days in 2018 at each Arkansas Class I area. 

Considering that the CAMx photochemical modeling takes into account the emissions of 

thousands of sources, both in Arkansas and outside of the state, we consider this to be a 

significant contribution to visibility impairment at each Class I area and a large portion 

(approximately one-third) of the total contribution from all Arkansas point sources that can be 

addressed through installation of controls on two units at a single facility. The CAMx modeling 

also showed that at Upper Buffalo, the Independence facility’s contribution to visibility 

impairment is greater than the contribution from all of the subject-to-BART sources addressed in 

this final action combined. In terms of deciviews, the average impact from Independence over 

the 20% worst days, based on Entergy’s CAMx modeling and adjusted to natural background 

conditions, is over 0.5 dv at each of the Arkansas Class I areas. The results of Entergy’s CAMx 

modeling provide additional support to our determination that Independence significantly 

impacts visibility, both in terms of maximum visibility impacts from the source and visibility 

impairment on the 20% worst days. 

While the majority of the visibility impacts due to Independence on the 20% worst days are due 

to SO2, we note that NOX emissions from the facility also have impacts on the 20% worst days. 

The CAMx source apportionment modeling submitted by Entergy showed that NOX emissions 

from Independence are responsible for 30-40% of the visibility impairment in Arkansas’ Class I 

areas on 2 of the 20% worst days (i.e., 2 out of the 21 days that are the 20% worst of the days 

with IMPROVE monitoring data). We expect that installation of NOX controls on Independence 

will provide visibility improvement on this portion of the 20% worst days and will also provide 

meaningful visibility improvement on the 98th percentile day, as shown by the CALPUFF 

dispersion modeling. After carefully considering all comments submitted to us during the 

comment period, we are finalizing both SO2 and NOX controls for Independence Units 1 and 2 

because both SO2 and NOX are key pollutants contributing to visibility impairment, and because 

we have determined that these controls are cost effective and will provide for significant 

visibility benefits towards the goal of natural visibility conditions at Arkansas’ Class I areas. 

We discuss Entergy’s CAMx modeling and ranked statistical analysis in greater detail elsewhere 

in this document. We address elsewhere in this document comments contending that we 

improperly relied on CALPUFF modeling in our reasonable progress analysis and that such 

modeling overestimated the visibility impacts from Independence. 

We address specific comments related to the cost of controls for Independence in the section of 

this document where we discuss cost issues. 

Comment: EPA’s proposed BART and reasonable progress determinations are necessary 

to make reasonable progress. [Sierra Club et. al. (0171) p. 46-47] Sierra Club et. al. stated that 

other commenters argue that the regulations require BART only as necessary to make reasonable 
148 

progress, and that EPA has not demonstrated that BART is necessary in order to make 

reasonable progress. This argument ignores that the BART factors overlap with the reasonable 

progress factors; both BART and reasonable progress are defined to include consideration of 

cost, energy and non-air environmental impacts, and the remaining useful life of the source. 

Compare 42 U.S.C. § 7491(g)(1) with id. § 7491(g)(2). In practice, however, both analyses often 

involve the same factors, since states and EPA frequently consider visibility improvement and 

existing controls when conducting reasonable progress analyses (which are required for BART), 

and in practice EPA considers the time necessary for compliance when setting BART 

compliance deadlines (this is required for reasonable progress). 

Here, after considering the five BART factors, EPA has proposed controls for various Arkansas 

sources. EPA has conducted a source-specific BART analysis for Arkansas sources that 

considers all of the elements EPA would be required to consider in a reasonable progress 

analysis.269 Thus, EPA’s BART analysis shows that the controls satisfy the statutory factors for 

reasonable progress. 

For Independence Units 1 and 2, EPA is proposing controls as reasonable progress measures, not 

as BART, and thus commenters’ argument does not apply to the Independence controls. 

Response: We appreciate the commenter’s support of our proposed FIP. 

3.c. Consistency 

Comment: The cost-effectiveness of the SO2 controls EPA proposed for the Independence 

Plant far exceeds the cost-effectiveness standards reviewed and approved by EPA in other 

regional haze actions, and the controls also have lower projected visibility improvement 

than controls rejected by EPA in other Regional Haze actions. 

[Entergy Mississippi Inc. (EMI) (0168) p. 5-6] EMI stated that EPA’s disregard for consistent 

reasonable progress review and analysis continued into the required four-factor analysis. After 

failing to make the threshold determination of whether any emission reductions are necessary for 

the state to make reasonable progress at its Class I areas and then making the unsubstantiated and 

unsupportable determination to target only the Independence Plant, EPA applied dollar per ton 

cost-effectiveness estimates and visibility improvement rates for the proposed controls that are 

out of line with the standards applied in other regional haze SIPs and FIPs. Specifically, EPA’s 

proposal attempts to justify a cost-effectiveness of dry FGD at Independence Plant totaling 

$2,477/SO2 ton removed for Unit 1 and $2,686/SO2 ton removed for Unit 2.270 This far exceeds 

 

269 In situations where a state or EPA does not conduct a source-specific BART analysis that considers the five 

statutory factors, the BART analysis provides no meaningful information as to the conclusions that would be 

reached in a reasonable progress analysis. For example, where states or EPA rely on a trading program, such as 

CSAPR, to satisfy the BART requirements, the BART analysis says nothing about whether additional controls are 

needed to make reasonable progress—since the reasonable progress factors have not been analyzed for each source 

as part of the BART determination. 

270 Id. at 18,933. 
149 

the cost-effectiveness standards reviewed and approved by EPA for the Kentucky271 and North 

Carolina state implementation plans.272

Further, relying on the multisource CENRAP model, EPA projected that the proposed visibility 

benefits from all proposed FIP controls (i.e. BART and Reasonable Progress Determinations) 

would be 0.19 dv at Upper Buffalo and 0.21 dv at Caney Creek over 2018 projections.273 These 

purported results represent the same type of negligible improvement in visibility that was 

specifically avoided in previous EPA actions.274 Proposing such controls with such a low amount 

of visibility benefit also ignores EPA’s previous statement that improvements of less than 0.5 dv 

are “relatively small” and are not reasonable justification for additional controls -- even though 

the controls may be cost-effective.275

[Entergy Arkansas Inc. (0166) p. 16] EPA’s disregard for consistent reasonable progress review 

and analysis continued into the required four-factor analysis. After making the unsubstantiated 

and unsupportable determination to target only Independence, EPA applied different dollar per 

ton cost-effectiveness thresholds for proposed controls at the plant, which are out of line with the 

standards applied in other regional haze SIPs and FIPs. Specifically, EPA’s Proposal attempts to 

justify a cost effectiveness of dry FGD at Independence totaling $2,477/SO2 ton removed for 

Unit 1 and $2,686/SO2 ton removed for Unit 2. 80 Fed. Reg. at 18,944. This far exceeds the cost 

threshold approved by EPA for reasonable progress controls for other states. 

Response: As we discuss in our final rule and elsewhere in this document, in response to 

comments we received on our initial cost analysis presented in our proposal, we have revised our 

cost estimate for dry FGD for Independence Units 1 and 2. Based on this revision to our cost 

analysis, we find that dry FGD is estimated to cost $2,853/SO2 ton removed at Unit 1 and 

$2,634/SO2 ton removed. Although these cost estimates are slightly higher than we estimated in 

our proposal, we continue to find these controls to be cost effective and well within the range of 

cost of controls found to be reasonable by EPA and the States in other regional haze actions. 

We disagree with the statement that our proposal to require SO2 controls for Independence is 

inconsistent with our approvals of the Kentucky and North Carolina Regional Haze SIPs. 

Additionally, the factual contexts of both of these actions are easily distinguished from context in 

which we assessed potential reasonable progress controls for Independence. 

The commenter contends that in our proposed approval of the Kentucky Regional Haze SIP, we 

approved the state’s use of a $2,000/SO2 ton threshold. This is incorrect. In the preamble of our 

proposed approval of the Kentucky Regional Haze SIP, we discussed that the state identified 10 

units for evaluation under reasonable progress, and that 9 of these were EGUs subject to CAIR. 

 

271 76 Fed. Reg. 78,194, 78,206 (Dec. 16, 2011) (approving the use of a $2,000 per ton SO2 screening threshold).    272 77 Fed. Reg. 11,858, 11,870 (Feb. 28, 2012) (approving state’s decision not to implement additional controls for 

reasonable progress despite cost-effectiveness determinations ranging from $912 to $1,922 per ton of SO2 removed). 273 80 Fed. Reg. at 19,998, (Table 67). 274 See e.g., 77 Fed. Reg. at 24,012 (Montana Proposed) (EPA determined that 0.18 dv improvement was too low to 

justify additional SO2 controls on one facility); 76 Fed. Reg. 12,651, 12,661 (Oregon Proposed) (Mar. 8, 2011) 

(EPA rejected relatively low-cost per ton controls that yielded only 0.18 dv improvement). 

275 77 Fed. Reg. 30,454, 30,464 (Oregon Final). (May 23, 2012). 
150 

The remaining facility, Century Aluminum, is not an EGU. We further discussed that for the 

limited purpose of evaluating the cost of compliance for the reasonable progress assessment in 

this first regional haze SIP for the non-EGU Century Aluminum, Kentucky concluded that it was 

not equitable to require non-EGUs to bear a greater economic burden than EGUs for a given 

control strategy. As a result, Kentucky decided to use CAIR as a guide, using a cost of 

$2,000/ton of SO2 reduced as a threshold for cost-effectiveness for that particular non-EGU 

source. Kentucky found that the cost effectiveness of the SO2 control as suggested by the 

VISTAS control cost spreadsheet for potlines 1–4 at Century Aluminum is $14,207/ton of SO2

removed. The State thus concluded that, based on the high cost on a $/ton basis, there are no 

cost-effective SO2 reasonable progress controls available for the Century Aluminum units for the 

first implementation period. We proposed to approve Kentucky’s determination, but we also 

stated the following concerning our position on Kentucky’s use of a $2,000/SO2 ton threshold: 

Although the use of a specific threshold for assessing costs means 

that a state may not fully consider available emissions reduction 

measures above its threshold that would result in meaningful 

visibility improvement, EPA believes that the Kentucky SIP still 

ensures reasonable progress. In proposing to approve Kentucky’s 

reasonable progress analysis, EPA is placing great weight on the 

fact that there is no indication in the SIP submittal that Kentucky, 

as a result of using a specific cost effectiveness threshold, rejected 

potential reasonable progress measures that would have had a 

meaningful impact on visibility in its Class I area.276

It is clear in our proposed approval that we were not approving or otherwise advocating 

Kentucky’s use of a $2,000/SO2 ton threshold in the reasonable progress analysis. On the 

contrary, we expressed concern that the use of a specific threshold for assessing cost may result 

in a state not fully considering potential reasonable control measures above that threshold that 

would have meaningful visibility improvement on its Class I areas. Furthermore, our statements 

in the proposal indicate that had there been evidence of more affordable controls available above 

the $2,000/SO2 ton threshold used by the state that provide meaningful visibility improvement at 

the Class I areas, we might have arrived at a different decision concerning the approvability of 

Kentucky’s reasonable progress analysis for SO2. 

North Carolina took a similar approach to that of Kentucky in its SO2 reasonable progress 

analysis by relying on a cost threshold when deciding on measures for its non-EGUs. North 

Carolina set this threshold based on the estimated cost of compliance with its Clean Smokestacks 

Act, a law establishing a state-wide cap on SO2 and NOX emissions from the State’s two major 

utilities. In our proposed approval of the North Carolina Regional Haze SIP, we discussed that 

the state identified 11 units (non-EGU) for evaluation. We noted that North Carolina decided that 

for the limited purpose of evaluating the cost of compliance for non-EGUs in the SO2 reasonable 

progress assessment for the first implementation period, it was not equitable to require nonEGUs to bear a greater economic burden than EGUs for a given control strategy and therefore 

also used a cost-effectiveness threshold for its non-EGUs. North Carolina’s threshold was based 

 

276 76 FR at 78206. 
151 

on “[t]he facility-by-facility cost for EGUs under [the Clean Smokestacks Act which] ranged 

from 912 to 1,922 dollars per ton of SO2 removed,” a statement which the commenters appear to 

have misinterpreted to mean that North Carolina rejected potential reasonable progress measures 

with costs falling within this range.277 Rather, upon conducting cost evaluations for the nonEGUs and determining that the costs of controls exceeded its threshold, North Carolina 

concluded that there were no cost-effective reasonable progress SO2 controls available for the 

first implementation period. We proposed to approve North Carolina’s determination, but we 

also stated the following concerning our position on North Carolina’s use of a specific costeffectiveness threshold: 

Although the use of a specific threshold for assessing costs means 

that a state may not fully consider available emissions reduction 

measures above its threshold that would result in meaningful 

visibility improvement, EPA believes that the North Carolina SIP 

still ensures reasonable progress. In proposing to approve North 

Carolina’s reasonable progress analysis, EPA is placing great 

weight on the fact that there is no indication in the SIP submittal 

that North Carolina, as a result of using a specific cost 

effectiveness threshold, rejected potential reasonable progress 

measures that would have had a meaningful impact on visibility in 

its Class I areas.278

As in the case of Kentucky, it is clear that in our proposed approval of North Carolina’s 

reasonable progress determination, we were not approving or otherwise advocating North 

Carolina’s use of that specific cost-effectiveness threshold in the reasonable progress analysis. 

Therefore, we disagree that our requirement of SO2 controls for Independence Units 1 and 2 

under reasonable progress is inconsistent with our actions on the Kentucky and North Carolina 

Regional Haze SIPs. 

The commenter contends that the level of visibility improvement projected to result from our 

proposed SO2 controls on Independence is the same level of visibility improvement that we have 

specifically avoided in other EPA actions. This is incorrect. The commenter appears to be 

confusing the results of two different types of modeling assessments: (1) the estimated 

improvement in the 2018 RPG for the average across the 20% worst days at Caney Creek and 

Upper Buffalo that we calculated would result from all the controls in our Arkansas FIP proposal 

in the context of light extinction due to all sources in that time period and (2) the CALPUFF 

modeled visibility improvement due to controls on Independence Units 1 and 2 based on the 

maximum (98th percentile) facility impacts using CALPUFF dispersion modeling and natural 

visibility conditions as background. The commenter references our proposed actions on the 

Montana RH FIP and the Oregon RH SIP. The commenter is specifically referring to our 

statement that 0.18 dv is a relatively small visibility improvement for each of the SO2 controls 

considered for the Ash Grove facility in our Montana RH FIP proposal.279 We were clear in our 

Montana RH FIP proposal that 0.18 dv and the other visibility impacts presented in Table 37 of 

 

277 77 FR at 11870. 278 77 FR 11858, 11872. 279 77 FR 24012. 
152 

that Federal Register notice represent the change in the maximum 98th percentile impact over the 

modeled 3-year meteorological period using CALPUFF dispersion modeling (at the Class I area 

that showed the greatest improvement) for the SO2 controls evaluated.280 The commenter also 

refers to Oregon’s rejection in the Oregon RH SIP of new low-NOX burners with modified 

overfire air (NLNB/MOFA) plus SNCR for the PGE Boardman facility “because adding SNCR 

only provided an additional 0.18 dv of visibility improvement over NLNB/MOFA at the Mt. 

Hood Wilderness Area, and because of concerns about excess ammonia emissions (commonly 

referred to as ammonia slip) which may result in increased rates of secondary particulate matter 

in the form of ammonium sulfate.”281 In our proposed action on the Oregon RH SIP, we 

proposed to approve Oregon’s determination that SNCR is not required under BART for that 

facility. The 0.18 dv visibility improvement the commenter refers to represents the change in the 

maximum 98th percentile impact over the modeled 3-year meteorological period using 

CALPUFF dispersion modeling at the Mt. Hood Wilderness Area.282 

In contrast, the visibility improvement projected to result from our proposed SO2 controls for 

Independence, similarly based on the change in the maximum 98th percentile impact over the 

modeled 3-year meteorological period using CALPUFF dispersion modeling (at the Arkansas 

Class I area that showed the greatest improvement), is 1.178 dv facility wide (i.e., Units 1 and 2 

combined).283 Assuming that the visibility improvement is distributed more or less evenly 

between the two units,284 the amount of visibility improvement expected from our proposed SO2

controls on a per unit basis is significantly higher than the visibility improvement that was 

projected to result from the SO2 and NOX controls that were dismissed in the proposed actions 

for Montana and Oregon referenced by the commenter. The 0.19 dv and 0.21 dv improvement at 

Upper Buffalo and Caney Creek the commenter refers to is not the CALPUFF modeled visibility 

improvement of the maximum 98th percentile impacts from the facility. Instead, it represents the 

estimated improvement in the projected 2018 visibility conditions for the average across the 20% 

worst days for Caney Creek and Upper Buffalo that we calculated based on adjustments to the 

2018 CENRAP photochemical modeling that would result from all the controls in our FIP 

proposal. As we discuss in depth elsewhere in this document, the RPGs are values that will be 

compared in a progress report to actual visibility conditions, and accordingly should represent 

the expected actual overall visibility conditions. CALPUFF modeled estimates of source impacts 

and benefits of controls as discussed above, have a different purpose, which is to help guide 

decisions on the control of individual sources. 

The commenter also claims that our proposed controls for Independence Units 1 and 2 “ignores 

EPA’s previous statement that improvements of less than 0.5 dv are ‘relatively small’ and are not 

reasonable justification for additional controls—even though the controls may be cost-effective.” 

The commenter is referring to a statement we made in our proposed action on the Oregon RH 

SIP with regard to the state’s determination on reasonable progress for Oregon point sources. 

However, the commenter is mischaracterizing our statement. The full citation is the following: 

 

280 77 FR 24012. 281 76 FR 12661. 282 76 FR 12661. 283 80 FR at 24873. 284 We believe this is a reasonable assumption since the two units are nearly identical, have emissions stacks located 

adjacent to each other, and the two units have comparable SO2 emissions. 
153 

Since all of these sources have Q/d values below 20, EPA believes that 

their impacts on nearby Class I areas are expected to be less than 0.5 dv. 

Thus, EPA agrees with Oregon’s conclusion that additional controls of 

non-BART point sources for reasonable progress purposes are not 

reasonable in the first planning period, because even though there are cost 

effective controls identified, visibility improvement is anticipated to be 

relatively small.285 

It is clear that the “0.5 dv” we mention in our proposed action on the Oregon RH SIP refers not 

to the visibility improvement that would result from installation of controls, but rather to the 

baseline visibility impacts of the point sources at the nearby Class I areas. In comparison, we 

found that the baseline impacts from Independence (Units 1 and 2 combined) are 2.512 dv at 

Caney Creek and 2.264 dv at Upper Buffalo, which we consider to be significant impacts.286

Therefore, the claim that our proposed controls on Independence Units 1 and 2 are in 

contradiction with the statement we made in our proposed action on the Oregon RH SIP, is 

incorrect. 

Based on our analysis of the four reasonable progress factors and our consideration of the 

baseline visibility impacts from Independence and the visibility improvement of potential 

controls, we have determined that SO2 and NOX controls at Independence would be costeffective and would result in meaningful visibility benefits at Arkansas’ Class I areas, and 

therefore find that they are reasonable controls and are necessary to make reasonable progress. 

We address elsewhere in this document other specific comments contending that our proposed 

controls on Independence would produce negligible visibility improvement. 

We address elsewhere in this document comments contending that EPA “fail[ed] to make the 

threshold determination of whether any emission reductions are necessary for the state to make 

reasonable progress at its Class I areas.” 

We also address elsewhere in this document comments contending that we were arbitrary and 

capricious in determining what sources to evaluate under reasonable progress, that we “targeted” 

the Independence Plant, and that our decision to evaluate the Independence Plant was 

unsubstantiated and unsupported. 

Comment: EPA’s evaluation and application of NOX control requirements for the 

Independence Plant is inconsistent with EPA’s actions in the Texas Regional Haze FIP. 

[Entergy Mississippi Inc. (EMI) (0168) p. 6-7) EMI stated that EPA’s decision to evaluate and 

propose NOX controls at the Independence Plant also stands completely opposite its decision not 

to even evaluate similar controls for Texas’ point sources despite similar visibility conditions. 

 

285 77 FR 30464. 286See 80 FR 24872. See also the document titled “Summary of Additional Modeling for Entergy Independence,” 

which is found in the docket for our proposed rulemaking. 
154 

EPA elected not to evaluate Texas point sources for NOX controls because modeling suggested 

that impacts from the sources were “primarily due to sulfate emissions” -- i.e. NOX emissions 

from those sources were not significantly impacting class I Federal Areas.287 In Arkansas, EPA 

was even more explicit, stating that “visibility impairment is not projected to be significantly 

impacted by nitrate on the 20% worst days at Caney Creek or Upper Buffalo.”288 Incredibly, 

however, the agency evaluated and proposed NOX controls for the Independence Plant Units 1 

and 2.289 Concern with this point is heightened by the low projection for anticipated visibility 

improvement due to the NOX controls290 and because such controls are completely unnecessary 

to achieve reasonable progress and stay ahead of the uniform rate of progress.291

EMI stated that reviewed individually, each issue evidences an arbitrary, unjustified and 

inconsistent application of the regional haze regulations. Collectively, they demonstrate EPA’s 

complete disregard for the consistent review and uniform evaluation that is required by 

regulation. EPA’s consistency regulations strive for “standardiz[ed] criteria, procedures and 

policies” when “implementing and enforcing the act.292 They further oblige the agency to ensure 

that actions taken under the Clean Air Act: (1) “[a]re carried out fairly and in a manner that is 

consistent with the Act and Agency policy as set forth in the Agency rules and program 

directives” and (2) “[a]re as consistent as reasonably possible with activities of other Regional 

Offices.”293 In EPA’s Arkansas FIP proposal, Region 6 abandoned the standardized criteria, 

procedures and policies previously applied by the agency and, in the process, disregarded all 

notion of uniformity. Even worse, the EPA’s inconsistent treatment is due in large measure to the 

Agency’s failure to complete necessary analysis, which is the same justification it provided when 

it rejected Arkansas’ SIP proposal in the first instance.294

[Entergy Arkansas Inc. (0166) p. 16, 17] Entergy stated that EPA’s decision to evaluate and 

propose NOX controls at Independence stands completely opposite its decision not to even 

evaluate NOX controls for Texas’ point sources despite similar visibility conditions. See 

Proposed Texas Regional Haze FIP, 79 Fed. Reg. at 74,873 (“we are limiting our analyses to 

consideration of SO2 controls for these EGU sources, as our modeling indicates that the impacts 

from these sources on the 20% worst days are primarily due to sulfate emissions.”). EPA’s 

decision in this Proposal to impose NOX limits on Independence is inexplicable given the very 

low visibility improvement projected and the fact that such limits are completely unnecessary for 

 

287 Texas Regional Haze FIP at 74,873 (“we are limiting our analyses to consideration of SO2 controls for these 

EGU sources, as our modeling indicates that the impacts from these sources on the 20% worst days are primarily 

due to sulfate emissions.”).    288 80 Fed. Reg. at 18,994. 289 Id. at 18,996. 290 Compare 79 Fed. Reg. at 9360 (Arizona Proposed) (rejecting installation of selective catalytic reduction 

technology for reasonable progress where it was projected to result in 0.41 dv improvement at affected class I 

Federal areas) with 80 Fed. Reg. at 18,966 (projecting a 0.461 dv improvement over baseline).    291 See State of Arkansas, State Implementation Plan Review for the Five-Year Regional Haze Progress Report, at 

42-43 (May 2015) (hereinafter “Arkansas Five-Year Progress Report”) available at 

http://www.adeq.state.ar.us/air/planning/pdfs/ar_5yr_prog_rep_review-final-6-2-2015.pdf. 292 40 C.F.R. § 56.3(a) and (b). 293 40 C.F.R. § 56.5(a). 294 80 Fed. Reg. at 18,991 (noting that EPA’s partial disapproval of the Arkansas RH SIP was made, in part, on the 

“finding that Arkansas did not complete a reasonable progress analysis and did not properly demonstrate that 

additional controls were not reasonable”).   
155 

Arkansas to stay below the URP. See 40 C.F.R. §§ 51.308(d)(1)(ii) and (d)(3) (explaining that 

“emission reduction measures” must be necessary to achieve reasonable progress goals). 

Visibility at Arkansas’ Class I areas is only insignificantly impacted by all Arkansas point 

sources, even less so by point source contributions of NOX, and almost not at all by 

Independence. Further, Arkansas has sufficiently documented that those same Class I areas 

remain well ahead of the approved URP. 

Entergy stated that reviewed individually, the inconsistencies identified between EPA’s proposed 

FIP for Arkansas and other Regional Haze actions is evidence of an unjustified and inconsistent 

application of the Regional Haze Rule. Collectively, they demonstrate EPA’s complete disregard 

for consistent review and uniform evaluation that is required by regulation. EPA’s consistency 

regulations strive for “standardiz[ed] criteria, procedures and policies” when “implementing and 

enforcing the act.” 40 C.F.R. §§ 56.3(a) and (b). They further oblige the Agency to ensure that 

actions taken under the Clean Air Act: (1) “[a]re carried out fairly and in a manner that is 

consistent with the Act and Agency policy as set forth in the Agency rules and program 

directives” and (2) “[a]re as consistent as reasonably possible with activities of other Regional 

Offices.” 40 C.F.R. § 56.5(a). 

In EPA’s Arkansas FIP Proposal, EPA abandoned the standardized criteria, procedures and 

policies that had been used in other regional haze SIPs/FIPs. Even more remarkable, EPA’s 

failure to complete a necessary reasonable progress analysis is the same justification EPA used to 

reject Arkansas’ SIP proposal in the first instance. See 80 Fed. Reg. at 18,991 (noting that EPA’s 

partial disapproval of the Arkansas regional haze SIP was based, in part, on the “finding that 

Arkansas did not complete a reasonable progress analysis and did not properly demonstrate that 

additional controls were not reasonable”). 

[Conway Corporation et. al. (0172) p. 6; and EEAA (0173) p. 11] Conway Corporation et. al. 

and EEAA stated that EPA’s decision to evaluate and propose NOX controls at the Independence 

Plant also stands completely opposite its decision not to even evaluate similar controls for Texas’ 

point sources despite similar visibility conditions. EPA elected not to evaluate Texas point 

sources for NOX controls because modeling suggested that impacts from the sources were 

“primarily due to sulfate emissions” -- i.e. NOX emissions from those sources were not 

significantly impacting Federal Class I areas.295 In Arkansas, EPA was even more explicit in 

stating that “visibility impairment is not projected to be significantly impacted by nitrate on the 

20% worst days at Caney Creek or Upper Buffalo.”296 Incredibly, however, the agency evaluated 

and proposed NOX controls for the Independence Plant Units 1 and 2.297 The arbitrary nature of 

this aspect of the Proposed Rule is further evidenced by the low projection for anticipated 

 

295 79 Fed. Reg. at 74,873 (“we are limiting our analyses to consideration of SO2 controls for these EGU sources, as 

our modeling indicates that the impacts from these sources on the 20% worst days are primarily due to sulfate 

emissions.”). 

296 80 Fed. Reg. at 18994. 297 Id. at 18966. 
156 

visibility improvement due to the NOX controls298 and because additional controls are completely 

unnecessary to achieve the RPGs and stay ahead of the uniform rate of progress.299

Response: This comment, and our response to it, illustrate the very fact-specific nature of 

individual evaluations and decisions under the regional haze program. It is critical to understand 

the full context of each decision. In each one, the EPA applies the requirements of the statute and 

regulations in a consistent manner, but the different facts—unique to each state and facility—

inevitably lead to different outcomes. We agree that in our Texas FIP action we noted that on the 

20% worst days, the impacts from the EGUs we evaluated under reasonable progress were 

primarily due to sulfate emissions. We also agree that in our Arkansas FIP proposal we 

acknowledged that the CENRAP modeling demonstrates that sulfate is the primary driver of 

regional haze in Arkansas’ Class I areas on the 20% worst days. This does not mean that NOX is 

not a key pollutant contributing to regional haze impairment in both states. For instance, the 

CENRAP CAMx modeling shows that total extinction at Caney Creek is dominated by nitrate on 

4 of the days that comprise the 20% worst days in 2002, and a significant portion of the total 

extinction at Upper Buffalo on 2 of the days that comprise the 20% worst days in 2002 is due to 

nitrate.300 

As a key pollutant, we considered NOX controls under reasonable progress in both Texas and 

Arkansas. In our Texas FIP, we considered NOX controls under reasonable progress for the 

Works No. 4 Glass Plant but ultimately did not require those controls based on the emission 

reductions already occurring at the facility, the anticipated lifetime of the furnaces, and the fact 

that Furnace No. 2 had undergone rebricking within the past few years. Although we determined 

it was reasonable to not require additional controls for Works No. 4 Glass Plant at this time, we 

encouraged Texas to consider additional controls when Furnace No. 2 is scheduled for its next 

rebricking. We also found that in Texas all the EGUs that we evaluated for controls under 

reasonable progress had existing LNB for control of NOX emissions. This is in contrast to 

Independence, which is the second largest source of NOX point source emissions in Arkansas and 

is not currently equipped with any NOX controls. As such, Independence was a more compelling 

candidate for evaluation of NOX controls in the first planning period than were the EGUs in 

Texas that we evaluated for controls under reasonable progress. 

As NOX is a visibility impairing pollutant and Independence is responsible for a very large 

portion of the point source NOX emissions in the state (approximately 21.3%),301 we determined 

that it was reasonable to evaluate NOX controls under reasonable progress in our Arkansas FIP 

proposal. We conducted CALPUFF modeling and found that the Independence Plant has 

 

298 Compare 79 Fed. Reg. at 9,360 (Arizona Proposed) (rejecting installation of selective catalytic reduction 

technology for reasonable progress where it was projected to result in 0.41 dv improvement at affected class I 

Federal areas) with 80 Fed. Reg. at 18,966 (projecting an 0.461 dv improvement over baseline) 299 See State of Arkansas, State Implementation Plan Review for the Five-Year Regional Haze Progress Report 42-

43 and 55-56 (May 2015) (hereinafter “Arkansas Five-Year Progress Report”) available at 

http:www.adeq.state.ar.us/air/planning/odfs/ar_5yr_prog_rep_review-final-6-2-2015.pdf. 

300 See Arkansas Regional Haze SIP, Appendix 8.1- “Technical Support Document for CENRAP Emissions and Air 

Quality Modeling to Support Regional Haze State Implementation Plans,” section 3.7.1 and 3.7.2. See the docket for 

this rulemaking for a copy of the Arkansas Regional Haze SIP. 

301 See NEI 2011 v1. A spreadsheet containing the emissions inventory is found in the docket for our proposed 

rulemaking. 
157 

significant visibility impacts in Arkansas’ Class I areas due to NOX emissions based on the 98th

percentile visibility impacts from the facility, and also found that LNB/SOFA would improve 

these visibility impacts.302 We also found that LNB/SOFA is very cost effective ($401/ton 

removed for Unit 1 and $436/ton removed for Unit 2). For these reasons, we proposed 

LNB/SOFA for Independence Units 1 and 2 under Option 1. In addition, we discuss in more 

detail elsewhere in this document that Entergy submitted CAMx photochemical modeling during 

the public comment period showing that nitrate from Independence is responsible for 30-40% of 

the visibility impairment in Arkansas’ Class I areas on 2 out of the 20% worst days in 2018. We 

expect that the installation of NOX controls at Independence, which we found to be very cost 

effective, would provide visibility improvement on this portion of the 20% worst days, thereby 

assuring reasonable progress toward the goal of natural visibility conditions. Based on our 

consideration of the four statutory factors and the visibility improvement available from controls, 

we have determined that there are reasonable NOX controls available for Independence that are 

cost effective and would result in considerable visibility improvement. Therefore, we are 

requiring these controls. 

We disagree that our decision to require NOX controls for Independence is inconsistent with our 

Arizona FIP proposal. In that action, we proposed that neither SCR nor SNCR was required to 

achieve reasonable progress for Springerville Units 1 and 2 in this regional haze planning period 

because: 

[w]hile the cost per ton for SNCR may be reasonable, the projected 

visibility benefits are relatively small (0.18 dv at the most affected area). 

The projected visibility benefits of SCR are larger (0.41 dv at the most 

affected area), but we do not consider them sufficient to warrant the 

relatively high cost of controls for purposes of RP in this planning period. 

However, these units should be considered for additional NOX controls in 

future planning periods.303

The “relatively high cost” of SCR controls we refer to in that statement is $6,829/ton NOX

removed for Springerville Unit 1 and $6,085/ton NOX removed for Springerville Units 2.304

Thus, our decision to not propose SCR at Springerville Units 1 and 2 was not because we 

considered the visibility benefits to be too small, as the commenter appears to believe. Instead, it 

was because we determined that, under these circumstances, this level of visibility improvement 

was not sufficient to warrant the cost per ton of emissions reduced. In contrast, we found that the 

cost of LNB/SOFA at Independence Units 1 and 2 is significantly lower ($401/ton removed for 

Unit 1 and $436/ton removed for Unit 2), and we determined that 0.459 dv visibility 

 

302 Although the reasonable progress provisions of the Regional Haze Rule place emphasis on the 20% worst days, 

the CAA goal of remedying visibility impairment due to anthropogenic emissions encompasses all days. Thus, states 

and EPA have the discretion to consider the visibility impacts of sources and the visibility benefit of controls on 

days other than the 20% worst days in making their decisions, such as the days on which a given facility has its own 

largest (98th percentile) impacts. Because Independence has significant 98th percentile visibility impacts, these 

impacts will need to be addressed to achieve the CAA goal of remedying visibility impairment due to anthropogenic 

emissions. 

303 79 FR 9318, 9360 (February 18, 2014). 304 79 FR 9318, 9359.
158 

improvement at the most impacted Class I area due to installation of these controls (on a facilitywide basis) warranted the cost of these controls. Therefore, we disagree that the NOX controls we 

proposed and are finalizing in this action for Independence Units 1 and 2 in any way contradict 

our action on the Arizona Regional Haze FIP. 

We disagree that our proposed reasonable progress controls are arbitrary, unjustified, 

inconsistent with the CAA and regional haze regulations, and address specific comments 

concerning this issue elsewhere in this document. 

We address elsewhere in this document other specific comments contending that our FIP 

proposal abandoned the standardized criteria, procedures, and policies applied by EPA in other 

regional haze actions with respect to the reasonable progress analysis. 

We also address elsewhere in this document comments contending that controls under reasonable 

progress are not required when a Class I area is projected to achieve the RPGs established by the 

state or when the Class I area is below the glidepath. 

Comment: The RPGs proposed by EPA reflect an arbitrary and disparate treatment of 

Arkansas in comparison to surrounding states where EPA has proposed or accepted RPGs 

that would allow the states to achieve natural visibility conditions until well beyond the 

national goal of 2064. 

[ADEQ (0160) p. 17-21] ADEQ stated that as pointed out in the Five-Year Progress Report State 

SIP revision, Arkansas is making substantial progress in addressing regional haze in its Class I 

areas and is on schedule to meet its own proposed RPGs and the URP for the first planning 

period.305 This means that Arkansas is well on track to reaching background visibility conditions 

by 2064. Despite this progress, EPA proposed RPGs that are more aggressive than that necessary 

to achieve the program’s goal, which is inconsistent with surrounding states that have wideranging RPGs placing them on a path to achieve background visibility conditions well beyond 

2064. 

Arkansas is making considerable progress in reducing regional haze based on its own RPGs. The 

most recent data from 2011 and the current five-year rolling average shows that visibility 

impairment is decreasing more rapidly than the URP and Arkansas’s proposed 2018 RPGs.306 In 

fact, CENRAP modeling indicates that Arkansas may reach its own 2018 RPGs without 

additional control measures beyond those described in Arkansas’s now-disapproved SIP.307 The 

Upper Buffalo Wilderness area is expected to achieve its 2018 RPG of an improvement of 3.75 

deciviews for the 20% worst days without any additional controls on sources.308 Similarly, the 

Caney Creek Wilderness area is on track to achieve its 2018 RPG of 3.88 deciviews of visibility 

improvement for the 20% worst days.309 Based on Arkansas’ proposed RPGs, Arkansas may 

 

305 Exhibit 1 to ADEQ’s comments, at 56. 306 Exhibit 1 to ADEQ’s comments, at 56. 307 Id. 308 Id. at 55. 309 Id.
159 

reach background conditions in Caney Creek by 2062 and in the Upper Buffalo by 2063.310 Any 

further controls or more stringent RPGs are simply unnecessary to achieve the goal of reaching 

background visibility conditions by 2064. 

Despite Arkansas being on schedule to meet or beat the trajectory needed to achieve background 

visibility conditions by 2064, EPA is proposing more stringent RPGs that would require 

unnecessary additional controls. Specifically, EPA is requiring additional controls on Entergy 

Independence Units 1 and 2.311 EPA’s proposed RPGs are more aggressive, which is inconsistent 

with EPA’s approach in certain other states that allow RPGs that would improve visibility over a 

much longer timeframe.312

EPA has proposed or accepted RPGs for other states that would allow those states to meet 

background visibility conditions well into the next century. In Texas, EPA proposed RPGs that 

would allow that state to achieve natural visibility conditions for the 20% worst days in Big Bend 

Wilderness Area in 194 years and in the Guadalupe Mountains in 159 years.313 In Oklahoma, 

EPA proposed a 2018 RPG for the 20% worst days that put that state on track to attain natural 

visibility in the Wichita Mountains in 92 years.314 For Arkansas, EPA has required RPGs that 

would be even more stringent than those needed to reach background visibility conditions in 49 

years, which is the program’s target. 

In states farther geographically removed from Arkansas, EPA’s treatment disparity becomes 

even more profound. In California, EPA approved that state’s RPGs even though many of its 

Class I areas would not reach natural background conditions until well into the 2100’s and 

beyond. For example, California’s RPGs will not achieve background conditions in Desolation 

Wilderness Area until 2307, in Yosemite National Park until 2160, and in Ansel Adams 

Wilderness Area until 2200.315

There is no justification for EPA arbitrarily setting RPGs that are stricter than those proposed by 

Arkansas and include controls on Entergy’s Independence Plant. EPA’s dramatically disparate 

approach to Arkansas’s RPGs in comparison to other states is unreasonable and unnecessary to 

achieve “reasonable progress” towards reaching background conditions. EPA should withdraw 

the Proposed FIP and any subsequent plan should contain goals that are reasonable in light of 

EPA’s treatment of other states. 

[Arkansas Electric Energy Consumers Inc. and Arkansas Gas Consumers Inc. (0175) p. 12-13] 

AEEC and AGC stated that the Five-Year Regional Haze Progress Report that ADEQ submitted 

to the EPA reveals that Arkansas is on track to meet the visibility improvements contemplated by 

the Regional Haze Rule, meaning that Arkansas is actually on track to reach background 

 

310 Id. 311 80 FR 18944 at 18992. 312 80 FR 18944 at 18997. (“These RPG’s reflect rates of progress that are faster than the rates projected by 

Arkansas.”). 

313 79 FR 74853 at 74887. 314 Id. 315 Approval and Promulgation of Air Quality Implementation Plans; State of California; Regional Haze State 

Implementation Plan and Interstate Transport Plan; Interference With Visibility Requirement, 76 FR 13944, at 

13951
160 

visibility conditions by 2064. Notwithstanding this progress, the Proposed FIP arbitrarily 

contains RPGs more aggressive than necessary to achieve the program’s goal, despite the fact 

that the EPA has approved RPGs for surrounding states that will not attain background visibility 

conditions until well after 2064. 

Despite Arkansas being on track to achieve background visibility conditions by 2064, the 

Proposed FIP contains RPGs more stringent than those contained in the Arkansas SIP. These 

RPGs require unnecessary and costly controls.316 These stringent RPGs simply do not align with 

EPA’s approach in other states, where it has approved RPGs that improve visibility over a much 

longer timeframe.317 

The Proposed FIP contains no justification for EPA’s inconsistent approach, whereby it sets 

strict RPGs for Arkansas and includes unnecessary controls on Entergy’s Independence Plant 

while allowing other states to utilize RPGs that will not attain background visibility conditions 

until hundreds of years after Arkansas will actually achieve background visibility without 

installing the controls required by the Proposed FIP. Since the Proposed FIP contains arbitrary 

and capricious revisions to Arkansas’s RPGs, despite the fact that Arkansas is already well on its 

way to compliance with the Regional Haze Rule and other states have received more generous 

treatment, the EPA should withdraw the Proposed FIP. 

Response: As discussed extensively throughout this document, the CAA and the Regional Haze 

regulations are clear that in establishing the RPGs, states (or EPA in standing in the state’s shoes 

in a FIP) must conduct an analysis of the four statutory factors under CAA section 169A(g)(1) 

section 40 CFR section 51.308(d)(1) to determine whether additional controls (i.e., beyond those 

required under BART and other “on the books” controls) are necessary to make reasonable 

progress. Thus, being projected to meet the state’s 2018 RPGs and/or being below the URP 

glidepath does not automatically mean that a Class I area is making reasonable progress and that 

the requirements under the CAA and section 51.308(d)(1) are fully satisfied without the need for 

analysis of additional controls. The fact that Arkansas’ Class I areas are on track to achieve the 

2018 RPGs provided by the state in the Arkansas RH SIP and are below the URP glidepath does 

not divest us from our authority and obligation to conduct a reasonable progress analysis, nor 

does it justify the dismissal of controls for Independence that we have determined, pursuant to 

that analysis, are cost-effective and would result in meaningful visibility benefit at Arkansas’ 

Class I areas. 

 

316 80 Fed. Reg. 18944 at 18992. 317 EPA has proposed or accepted RPGs for other states that allow those states to meet background visibility 

conditions well into the next century. In Texas, EPA proposed RPGs that allow Texas to achieve natural visibility 

conditions for the 20% worst days in Big Bend Wilderness Area in 194 years and in the Guadalupe Mountains in 

159 years. 79 Fed. Reg. 74853 at 74887. In Oklahoma, EPA proposed a 2018 RPG for the 20% worst days that put 

Oklahoma on track to attain natural visibility in the Wichita Mountains in 92 years. Id. EPA approved California’s 

RPGs even though many of its Class I areas will not reach natural background conditions until well into the next 

century and beyond. California’s RPGs, which EPA approved, will not achieve background conditions in Desolation 

Wilderness Area until 2307, in Yosemite National Park until 2160, and in Ansel Adams Wilderness Area until 2200. 

76 Fed.   
161 

The preamble to the Regional Haze Rule318 states the following with regard to consideration of 

the URP glidepath: 

If the State determines that the amount of progress identified through the 

[URP] analysis is reasonable based upon the statutory factors, the State 

should identify this amount of progress as its reasonable progress goal for 

the first long-term strategy, unless it determines that additional progress 

beyond this amount is also reasonable. If the State determines that 

additional progress is reasonable based on the statutory factors, the State 

should adopt that amount of progress as its goal for the first long-term 

strategy. 

This means that in some cases, the state or EPA may find, based on the required analysis of the 

four statutory factors alongside consideration of the visibility improvement of controls, that there 

are additional reasonable controls available that are cost effective and have meaningful visibility 

improvement, and are therefore necessary for reasonable progress, even if the applicable Class I 

area is below the URP glidepath. On the other hand, there may be cases where the state or EPA 

find, based on the required analysis of the four statutory factors alongside consideration of the 

visibility improvement of controls, that there are no available reasonable progress controls for 

the first implementation period and that a lesser amount of progress than reflected in the URP is 

reasonable. 

Based on our analyses under section 51.308(d)(1) alongside consideration of the visibility 

improvement of controls, we determined that there are reasonable controls available for 

Independence Units 1 and 2 that are cost-effective and would provide for meaningful visibility 

improvement at Arkansas’ Class I areas. Therefore, we must require these controls under 

reasonable progress and provide RPGs that represent our best estimate of the degree of visibility 

improvement that will result in 2018 from the set of control measures in our FIP to address 

visibility, as well as all other enforceable measures expected to reduce emissions over the period 

of the SIP from 2002 to 2018.319 Thus, this comment, and our response to it, illustrate the very 

fact-specific nature of individual evaluations and decisions under the regional haze program. It is 

critical to understand the full context of each decision. In each one, the EPA applies the 

requirements of the statute and regulations in a consistent manner, but the different facts—

unique to each state and facility—inevitably lead to different outcomes. Thus, we disagree that 

our proposed Arkansas FIP and the RPGs we are finalizing are inconsistent with the RPGs we 

have established or approved in other regional haze actions where natural visibility conditions at 

the applicable Class I areas are projected to be achieved beyond 2064. 

We address in greater detail comments related to ADEQ’s Five Year Progress Report SIP 

revision and recent IMPROVE monitor data elsewhere in this document. 

 

318 64 FR 35732 319 64 FR 35733. 
162 

Comment: EPA’s proposed requirement of additional emissions reductions under 

reasonable progress is inconsistent with its action on regional haze in Nevada. [The 

Associations (0165) p. 7-8] The Associations stated that even if EPA had some free-floating 

authority to dictate new controls, it has previously determined that, where mandatory programs 

(including BART) allow a state to meet reasonable progress goals during the first planning 

period, it is “reasonable” to determine that no further emission reductions are required. In 

rebuffing comments by environmental groups demanding that the State of Nevada impose 

additional emission reductions even though the Jarbidge Wilderness Area was slated to meet its 

reasonable progress goals, EPA stated: 

The [Regional Haze Rules] and EPA’s guidance affords the State 

considerable flexibility in determining whether additional emission 

reduction measures are needed to achieve the [Reasonable Progress Goal] 

in the first planning period. [Nevada] reasonably concluded that the cost of 

additional controls was not warranted given projected emissions 

reductions from anthropogenic sources and the fact that the majority of 

haze at Jarbidge is from natural and out of state sources. 77 Fed. Reg. 

17,334, 17337 (Mar. 26, 2012). 

This approach, whereby a state or EPA only imposes reasonable additional controls when 

“needed” to meet reasonable progress goals, is amply supported by the Clean Air Act and EPA’s 

Regional Haze guidance. See 42 U.S.C. § 7491(b)(2) (implementation plans must “contain such 

emission limits ... as may be necessary to make reasonable progress”) (emphasis added); RPG 

Guidance at 4-1 (“Given the significant emissions reductions that we anticipate to result from 

BART” and other Clean Air Act programs “it may be all that is necessary to achieve reasonable 

progress in the first planning period for some States.”). 

For Nevada, EPA found that it was imminently reasonable to forego additional, expensive 

pollution controls when the reasonable progress goals for a Class I area were already being met. 

For Arkansas, however, EPA has completely reversed its prior position without any coherent 

explanation. EPA may not reverse its prior policy positions without providing some reasoned 

explanation for that reversal. See, e.g., Dillman v. NTSB, 588 F.3d 1085, 1089-90 (D.C. Cir. 

2009); California ex rel. Lockyer v. U.S. Dep’t of Agric., 459 F. Supp. 874, 904 (N.D. Cal. 

2006), aff’d, 575 F.3d 999 (9th Cir. 2009) (requiring “new evidence that would lead to a different 

conclusion”). Instead of adhering to its rationale in Nevada, or explaining why it is changing its 

position, EPA “focuses on the” non-BART eligible Independence plant for no reason other than 

it is a relatively large source of emissions. Id. at 18,991-992. It does so “even though Arkansas 

Class I areas and those outside of Arkansas most significantly impacted by Arkansas sources are 

projected to meet the [Uniform Rate of Progress] for the first planning period.” Id. at 18,992. 

Given EPA’s prior position in Nevada, its concession that the Arkansas Class I areas will meet 

their reasonable progress goals should end the inquiry absent some significant concerns about the 

state being able to meet the Uniform Rate of Progress in future planning periods. With respect to 

the first planning period, imposing new pollution controls on the Independence plant serves no 

purpose whatsoever. 
163 

Response: We agree that in some cases it may be appropriate to determine that no additional 

controls beyond BART and “on the books controls” are necessary in the first implementation 

period to make reasonable progress. However, as discussed extensively in our proposal and 

throughout this document, the determination of what is necessary to make reasonable progress, 

including whether additional controls are necessary, must be made based on the required 

analyses under CAA section 169A(g)(1) and section 51.308(d)(1). We discuss extensively 

throughout this document that the fact that Arkansas’ Class I areas are on track to achieve the 

2018 RPGs provided by the state in the Arkansas RH SIP and are below the URP glidepath does 

not divest us from our authority and obligation to conduct a reasonable progress analysis. 

We disagree with the commenter’s contention that our proposed requirement of additional 

controls under reasonable progress for Independence Units 1 and 2 is inconsistent with our 

approval of Nevada’s reasonable progress determination. The commenter’s contention that “For 

Nevada, EPA found that it was imminently reasonable to forego additional, expensive pollution 

controls when the reasonable progress goals for a Class I area were already being met,” 

mischaracterizes our rationale for agreeing with Nevada’s decision not to require additional 

controls under reasonable progress. In our proposed approval of the Nevada RH SIP, we stated 

the following: 

EPA finds that the State’s decision not to seek additional control 

measures is supported by the attributes of regional haze at Jarbidge 

as well as the expected reductions in statewide emissions of SOX

and NOX and BART controls on three facilities. The WRAP’s 

regional analysis indicates that haze at Jarbidge is mostly from 

natural sources like wildfires, and most of the anthropogenic 

sources contributing to that haze are outside the State. Based upon 

everything NDEP considered in its SIP, EPA is proposing to 

approve Nevada’s demonstration that its RPG provides for 

reasonable progress in the first planning period as required in CFR 

51.308(d)(1)(i), (ii) and (vi).320 

Additionally, the commenter references only part of the citation from our final action on the 

Nevada RH SIP. The full citation is the following: 

As explained in the proposed rule, in promulgating the SIP NDEP 

considered the four factors in setting the reasonable progress goal 

for the Jarbidge Wilderness Area, the only Class I area in Nevada. 

The RHR and EPA’s guidance affords the State considerable 

flexibility in determining whether additional emission reduction 

measures are needed to achieve the RPG in the first planning 

period. The NDEP reasonably concluded that the cost of additional 

controls was not warranted given projected emissions reductions 

from anthropogenic sources and the fact that the majority of haze 

at Jarbidge is from natural and out-of-state sources. Moreover, 

 

320 76 FR at 36465. 
164 

NDEP noted in its comments that “of the five proposed electrical 

generating units (EGUs) included in the State’s 2018 emissions 

inventory, only two have moved forward and are now operational,” 

which would further lower emissions projections for both NOX and 

SO2 by 2018. The comments do not demonstrate that the State 

failed to consider reasonably the four factors, but the comments 

question whether the State should have done a more robust 

analysis. EPA has considered the comments and the comments 

have not provided any further specific facts that should have been 

considered in the State’s analysis beyond conclusory criticisms. 

Therefore, given the broad discretion the RHR affords the State, 

and the lack of specificity in the comments on this issue, EPA 

reaffirms its proposed decision to approve the State’s reasonable 

progress goal for Jarbidge.321 

There is nothing in these citations indicating that the reason we approved Nevada’s 

determination that no additional controls were necessary under reasonable progress was because 

“the reasonable progress goals for [the] Class I area were already being met.” On the contrary, 

our statement indicates that Nevada had reasonably considered the four statutory factors and that 

it had reasonably concluded that the cost of additional controls was not warranted given 

projected emissions reductions from anthropogenic sources and the fact that the majority of haze 

at Jarbidge is from natural and out-of-state sources. And it was for these reasons that we 

finalized our approval of Nevada’s reasonable progress determination. 

Furthermore, we note that certain distinctions can be made between Arkansas’ Class I areas and 

that of Nevada (i.e., Jarbidge Wilderness Area). In contrast to Nevada’s Class I area, where it 

was found that the driver of haze is emissions from natural sources, the CENRAP photochemical 

modeling indicated that sulfate from point sources is the primary driver of regional haze in 

Arkansas’ Class I areas, accounting for approximately 56% of the total visibility impairment at 

Caney Creek and approximately 59% of the total visibility impairment at Upper Buffalo on the 

20% worst days in 2002. We do note that the CENRAP modeling for 2002 does indicate that for 

Caney Creek, the largest contributions of visibility impairment due to sulfate emissions come 

from Texas and the eastern United States. For Upper Buffalo, the largest contributions of 

visibility impairment due to sulfate emissions come from the eastern United States, Indiana, 

Illinois, and Kentucky. This bears similarity to our finding in Nevada that most of the 

anthropogenic sources contributing to haze are outside the State. However, we also make the 

important observation that the CENRAP 2018 modeling projections indicate that reductions of 

sulfate from point sources outside Arkansas are expected to account for a large percentage of the 

total expected reduction in impairment between 2002 and 2018. For example, anticipated 

reductions of sulfate from point sources in Texas, the eastern United States, Indiana, and Ohio 

will account for a decrease of 24.41 Mm-1 in total light extinction, which is approximately 50% 

of the total expected reduction in Caney Creek between 2002 and 2018.322 Similarly, anticipated 

reductions of sulfate from point sources in the eastern United States, Indiana, Illinois, Kentucky, 

and Ohio will account for a decrease of 28.43 Mm-1 in total light extinction, which is more than 

 

321 77 FR at 17337. 322 76 FR at 64214. 
165 

60% of the total expected reduction in impairment in Upper Buffalo between 2002 and 2018.323

While it is anticipated that there will be large reductions in impairment due to reductions of 

sulfate from point sources in these other states, sulfate from Arkansas point sources is actually 

expected to increase between 2002 and 2018. This distinguishes Arkansas from Nevada, where 

the expected reductions in Nevada’s statewide emissions of SOX and NOX, including BART 

controls on three facilities, was part of our justification for agreeing with Nevada that controls 

under reasonable progress are not necessary. In the Nevada situation, the relevance of the 

observation that significant reductions in statewide emissions were expected was that this 

suggested that opportunities for even further emission reductions within Nevada were limited. 

This is not the case for Arkansas. We believe that these technical facts distinguish Arkansas’ 

Class I areas from the Jarbidge Wilderness Area. 

We also make the observation that the citation from our final action on the Nevada RH SIP 

explains that the RHR and EPA’s guidance affords the State considerable flexibility in 

determining whether additional emission reduction measures are needed to achieve the RPG in 

the first planning period. In a FIP, EPA must step into the shoes of the state and this flexibility 

and discretion shifts to us. For Arkansas, in 2012, we disapproved Arkansas’ reasonable progress 

goals because Arkansas did not conduct a four factor analysis as required by section 51.308(d)(1) 

and because the state’s reasonable progress goals relied on the state’s BART determinations, a 

large portion of which we disapproved because they did not meet the requirements of the CAA 

and RH regulations.324 We have reasonably exercised our discretion to conduct a four-factor 

analysis of the largest contributors to visibility impairment, which is the same approach we have 

used in multiple FIPs (i.e., Texas, Arizona, North Dakota). Our proposed FIP, which we took 

comment on, conducted a four factor analysis for Arkansas’ Class I areas. Based on our 

consideration of the four statutory factors alongside consideration of the visibility improvement 

of controls, we determined that there are reasonable controls available for Independence Units 1 

and 2 that are cost-effective and would provide for meaningful visibility improvement at 

Arkansas’ Class I areas. Therefore, we must require these controls under reasonable progress and 

establish RPGs that reflect these additional controls as well as the BART controls that are part of 

our FIP. This comment, and our response to it, illustrate the very fact-specific nature of 

individual evaluations and decisions under the regional haze program. It is critical to understand 

the full context of each decision. In each one, the EPA applies the requirements of the statute and 

regulations in a consistent manner, but the different facts—unique to each state and facility—

inevitably lead to different outcomes. Thus, we disagree that our Arkansas RH FIP is 

inconsistent with our action on the Nevada RH SIP. 

The commenter states that EPA made a “concession that the Arkansas Class I areas will meet 

their reasonable progress goals.” This is incorrect. On the contrary, we disapproved the RPGs 

established by Arkansas in our final action on the Arkansas RH SIP, published on March 12, 

2012.325 Therefore, the state established RPGs are not a reflection of the control measures 

necessary to make reasonable progress. We also discuss elsewhere in this document that the 

RPGs are an analytical tool we use to evaluate whether the measures in the implementation plan 

 

323 76 FR at 64215. 324 77 FR 14604. 325 77 FR 14604. 
166 

are sufficient to make reasonable progress, but they are not enforceable.326 The RH rule provides 

that what is enforceable are the emission limitations and other control measures that apply to 

specific sources (including both BART and sources controlled under reasonable progress).327

Achieving or being projected to achieve the RPG does not necessarily demonstrate that a state 

has satisfied the reasonable progress requirement. The state or EPA must complete the required 

four factor analysis to determine appropriate controls and emission limits under reasonable 

progress, and must adopt and enforce these controls and emission limits. 

We address elsewhere in this document comments contending that our approach for determining 

what sources to analyze under reasonable progress is inappropriate, inconsistent and arbitrary, 

and that we inappropriately focused on Independence in our reasonable progress analysis. 

Comment: EPA must consider the four reasonable progress factors for Arkansas’ Class I 

areas, even if the areas are below the glidepath. [Sierra Club et. al. (0171) p. 29-30] Sierra 

Club et. al. stated that the overarching requirement of the Clean Air Act’s haze provisions is for 

each state’s plan to include “emission limits, schedules of compliance and other measures as may 

be necessary to make reasonable progress.” 42 U.S.C. § 7491(b)(2). The statute defines 

reasonable progress to account for four factors: the cost of controls, the time needed to install 

controls, energy and non-air quality environmental impacts of controls, and the remaining useful 

life of the source. Id. § 7491(g)(1); see also 40 C.F.R. § 51.308(d)(1)(i)(A). 

EPA’s implementing regulations require each state with a Class I area to set a reasonable 

progress goal for each area within its borders, 40 C.F.R. § 51.308(d)(1), based on considering the 

four statutory factors for reasonable progress, id. § 51.308(d)(3). Each state must also determine 

the uniform rate of progress. Id. § 51.308(d)(1)(i)(B). If a state set a reasonable progress goal that 

provides for less progress than the URP, the state must demonstrate that achieving the URP is 

unreasonable and that the alternative goal is reasonable. Id. § 51.308(d)(1)(ii). Moreover, each 

state must consult with other states that contribute to haze in the host state’s Class I areas. Id. § 

51.308(d)(1)(iv), (d)(3)(i)-(iii). 

Neither the statute nor the regulations exempts states from the required reasonable progress 

analysis merely because a Class I area is on the glidepath to achieving the URP. To the contrary, 

EPA’s long-standing interpretation of the regional haze rule is that “the URP does not establish a 

‘safe harbor’ for the state in setting its progress goals.” 79 Fed. Reg. 74,818, 74,834 (Dec. 16, 

2014). If it is reasonable to make more progress than the URP, a state must do so, as EPA 

explained in the 1999 regional haze rule: 

If the State determines that the amount of progress identified through the 

[URP] analysis is reasonable based upon the statutory factors, the State 

should identify this amount of progress as its reasonable progress goal for 

the first long-term strategy, unless it determines that additional progress 

beyond this amount is also reasonable. If the State determines that 

additional progress is reasonable based on the statutory factors, the State 

 

326 See 51.308(d)(1)(v). 327 64 FR 35733. 
167 

should adopt that amount of progress as its goal for the first long-term 

strategy. 64 Fed. Reg. at 35,732. 

Having disapproved Arkansas’s regional haze plan, EPA has an obligation to conduct a 

reasonable progress analysis for Caney Creek and Upper Buffalo based on a consideration of the 

four statutory factors for reasonable progress. 40 C.F.R. § 51.308(d)(1). EPA must also ensure 

that the plan contains all measures necessary to meet Arkansas’s share of the reductions needed 

to meet the reasonable progress goals for Class I areas affected by Arkansas’s emissions. 40 

C.F.R. § 51.308(d)(3). In developing the reasonable progress goals and long-term strategy for 

Arkansas, “EPA ‘stands in the shoes of the defaulting State, and all of the rights and duties that 

would otherwise fall to the State accrue instead to EPA.’” Cent. Arizona Water Conservation

Dist. v. EPA, 990 F.2d 1531, 1541 (9th Cir. 1993); see also North Dakota, 730 F.3d at 757 (“[I]f 

a state fails to submit a SIP, submits an incomplete SIP, or submits a SIP that does not meet the 

statutory requirements, EPA is obligated to implement its own FIP to correct the deficiency in 

the SIP”). 

Response: We generally agree with this comment with regard to our decision to evaluate 

Independence Units 1 and 2 under reasonable progress. We address elsewhere in this document 

more specific comments stating that we must address in this FIP the requirements under section 

51.308(d)(3) with regard to Class I areas outside the state affected by Arkansas’ emissions. 

Comment: EPA appropriately prioritized the Independence Power Plant in its Reasonable 

Progress Analysis, and EPA should require installation of scrubbers and SCR at the plant. 

[The Sierra Club et. al. (0171) p. 30-31] Sierra Club et. al. stated that the Entergy Independence 

plant has two coal-fired units, rated at 900 MW each. 80 Fed. Reg. at 18,992. It is the secondlargest point source of SO2 and NOX emissions in Arkansas. Id. The plant is responsible for 36% 

of SO2 and 21% of NOX emissions from all the point sources in Arkansas. Id. at 18,991. These 

huge quantities of pollution degrade air quality in large swaths of Arkansas, including at the 

Caney Creek and Upper Buffalo Class I areas. Id. at 18,994, 18,996. Additionally, air pollution 

from the Independence plant winds up in neighboring states, such as Missouri, where it impairs 

visibility at the Hercules-Glades and Mingo Class I areas. Id. 

The Independence plant lacks modern air pollution controls, despite the availability of costeffective technologies that are widely used at other electric generating units. The plant has no 

scrubbers, and indeed has no post-combustion controls for SO2 emissions. Id. at 18,992. 

Similarly, the plant has no post-combustion controls for NOX emissions. Id. EPA’s analysis 

indicates that installing scrubbers and SCR at Independence Units 1 and 2 would be costeffective and would significantly improve visibility. In the reasonable progress analysis for other 

FIPs, EPA has prioritized point sources that are “upwind” of Class I areas, “have high SO2

emissions and lack modern pollution controls.” 77 Fed. Reg. 61,478, 61,711 (Oct. 9, 2012). 

Given that the Independence plant meets all three of these criteria—it is upwind of Class I areas, 

has very high SO2 emissions (and high NOX emissions), and lacks modern pollution controls— 

EPA properly prioritized the Independence plant for review during the reasonable progress 

analysis. 
168 

In addition, the regional haze screening analysis used by federal land managers (FLMs)—who 

are responsible for protecting visibility in Class I areas—provides further support for EPA’s 

decision to prioritize Independence. As discussed in more detail in the Gray Report,328 FLMs 

rely on a screening methodology based on the potential emissions of certain pollutants as well as 

the distance to the Class I area of interest— referred to as “Q/D”, i.e., emissions rate (Q) divided 

by distance (D)—to make preliminary determinations regarding which emitting facilities will 

have an adverse impact on visibility. Gray Report at 12-16. The FLMs consider a source located 

more than 50 km from a Class I area to have a negligible visibility impact with respect to a Class 

I area if the Q/D value is 10 or less. Id. at 12. The Q/D value for the top three EGU emitters in 

Arkansas (Independence, White Bluff, and Flint Creek) are more than 10 times the threshold, 

which strongly indicates that emissions from these sources have a significant visibility impact at 

the four Class I areas considered by EPA. Id. at 14. The largest Q/D value for any Arkansas 

source is at Independence, for which the computed Q/D value (269) strongly supports the need 

for emission reductions at that facility. Id. The SO2 and NOX emission rates at Independence are 

similar to White Bluff, with distances to the four Class I areas that are generally closer. Id. Dr. 

Gray’s Q/D analysis strongly supports EPA’s recommendation to require emission reductions 

from Independence as the Q/D figures for all four Class I areas far exceed the screening 

threshold. In fact, based on this Q/D analysis, Independence’s impact on visibility appears to far 

exceed that of any other source in Arkansas with the exception of White Bluff, which also 

significantly impacts visibility at all four Class I areas. 

Given the reasonable cost of controls for Independence and the significant visibility 

improvement from their use, the reasonable progress goals for Caney, Upper Buffalo, Mingo, 

and Hercules Glades should reflect installation and operation of a scrubber and SCR controls at 

the Independence plant. Arkansas’s long-term strategy should require Independence Units 1 and 

2 to operate a scrubber and SCR to meet these reasonable progress goals. 

Response: We acknowledge the Q/D analysis provided by the commenter in the Gray Report, 

and agree that it shows that the Independence Plant exceeds the screening threshold that has been 

used in other reasonable progress analyses. The Q/D analysis provided by the commenter 

supports our decision to evaluate controls for Independence under reasonable progress. While we 

generally agree with the necessity to evaluate Independence Units 1 and 2 under reasonable 

progress, and the need for SO2 and NOX control on these units to make reasonable progress, we 

disagree that SCR or SNCR controls are necessary. We address comments arguing that we 

should require SCR or SNCR controls for Independence under reasonable progress elsewhere in 

this document. We also discuss elsewhere in this document that the purpose of our reasonable 

progress analysis is to address the requirements under section 51.308(d)(1) and (d)(3) related to 

visibility impacts in Class I areas within the state. The purpose of the analysis is not to address 

the requirement under section 51.308(d)(3) related to visibility impacts in Class I areas outside 

the state. Although we do recognize that controls on Independence are expected to result in 

visibility improvements in Missouri’s Class I areas. 

 

328 “Visibility Modeling: Technical Support Document to Comments of Conservation Organizations,” EPA’s 

Proposed Federal Implementation Plan for Arkansas for the First Planning Period of 2008 to 2018, Prepared by Dr. 

H. Andrew Gray, August 7, 2015. 
169 

Comment: Along with the consideration of costs of compliance, the remaining three 

reasonable progress factors all weigh in favor of requiring a scrubber at Independence 

Units 1 and 2. [Sierra Club et. al. (0171) p. 32-33] Sierra Club et. al. stated that along with 

consideration of the costs of compliance, the remaining three reasonable progress factors all 

weigh in favor of requiring a scrubber at Independence Units 1 and 2. There are no energy or 

non-air quality environmental impacts from a scrubber that are significant enough to warrant 

rejecting a scrubber, particularly given that EPA has required a scrubber as BART for many 

plants. See, e.g., 76 Fed. Reg. 81,728 (Dec. 28, 2011) (requiring six units in Oklahoma to meet a 

SO2 limit of 0.06 lb/MMBtu based on the use of a scrubber), upheld by Oklahoma, 723 F.3d at 

1206, 1224. Moreover, BART requires the same consideration of non-air quality environmental 

impacts of controls as does the reasonable progress analysis, so EPA’s conclusion in BART 

determinations that scrubbers do not create environmental impacts sufficient to negate their 

benefits should apply with equal force in reasonable progress analyses. Compare 42 U.S.C. 

7491(g)(1) (reasonable progress analyses shall consider “non-air quality environmental impacts 

of compliance”) with 42 U.S.C. § 7491(g)(2) (BART determinations shall consider “non-air 

quality environmental impacts of compliance”). The “time necessary for compliance” factor 

likewise favors requiring a scrubber, given that a scrubber can be installed within 3 years, which 

is a reasonable period of time. See Stamper Report at 32-35. Consideration of the final factor, 

“the remaining useful life” of the Independence plant, does not negate the case for requiring a 

scrubber, given that there is no information in the record regarding the remaining useful life of 

the Independence plant that weighs in favor of any particular control. 

If EPA were to consider visibility improvement, which is not a statutory factor for reasonable 

progress, see 42 U.S.C. § 7491(g)(1), such consideration would support requiring a scrubber. 

Operating a dry scrubber at the Independence plant would improve visibility by 0.938 deciviews 

at Caney Creek and 0.888 deciviews at Upper Buffalo. 80 Fed. Reg. at 18,994. A wet scrubber 

would improve visibility by 0.97 deciviews at Caney Creek and 0.904 deciviews at Upper 

Buffalo. Id. 

In sum, all four statutory factors support finding that a scrubber is necessary to make reasonable 

progress: the cost is reasonable; the time to comply is more than reasonable, since EPA is 

allowing 5 years to install and operate the controls, and controls can and should be installed 

earlier; the energy and non-air impacts are minimal; and the remaining useful life does not cut 

against the controls. Moreover, the visibility improvement from a dry or wet scrubber would be 

significant. Taken together, the reasonable progress factors weigh in favor of requiring 

Independence Units 1 and 2 to install and operate a scrubber in order to make reasonable 

progress at Caney Creek and Upper Buffalo. The visibility improvement from operating a 

scrubber at these two units should be reflected in the reasonable progress goals for Caney Creek 

and Upper Buffalo. 

Response: While we generally agree that the FIP emission limits for Independence Units 1 and 

2 can be achieved by SO2 scrubber controls, we take no position as to specific statements made 

in this comment. We do note that based on additional visibility modeling we conducted for 

Independence Units 1 and 2 following the publication of our April 8, 2015 proposal, we found 

that dry scrubbers on the Independence units would improve visibility by 1.096 dv at Caney 
170 

Creek and 1.178 dv at Upper Buffalo.329 Wet scrubbers on the Independence units would 

improve visibility by 1.113 dv at Caney Creek and 1.196 dv at Upper Buffalo. 

We address elsewhere in this document specific comments regarding the cost of scrubber 

controls and the time necessary for compliance with SO2 controls for Independence Units 1 and 

2. 

3.d. Impacts from other source categories 

Comment: Emissions from out-of-state sources and Arkansas mobile and area sources have 

a more significant impact on Arkansas’ Class I areas than do Arkansas point sources. 

[Entergy Arkansas Inc. (0166) p. 23-29] Entergy stated that in the proposed FIP, EPA’s 

reasonable progress analysis primarily focuses on point source contributions to light extinction at 

Caney Creek and Upper Buffalo. As a result, EPA chose to limit its evaluation of potential 

reasonable progress controls solely to Arkansas’ largest emitting point sources, and, specifically, 

to Independence. However, as demonstrated in Figures 3 and 4 below, Arkansas point sources 

are relatively insignificant contributors to visibility impairment in Caney Creek and Upper 

Buffalo compared to most of the other regions modeled by CENRAP and are not even the 

biggest source group contributor in Arkansas to visibility impairment in these Class I areas.330

 

329 See 80 FR 24872. See also the document titled “Summary of Additional Modeling for Entergy Independence,” 

which is found in the docket for our rulemaking. 

330 Figures 3 and 4, as well as Figures 5 and 6 of Entergy’s comments, were developed by extracting the modeled 

source apportionment extinction data from the CENRAP PSAT tool for Caney Creek and Upper Buffalo. The data 

obtained were organized by geographic region and source category, so that the individual contribution of each 

source category in each geographic region could be determined. 
171 

“Regional Point Source Percentage of Total Extinction at Caney Creek Wilderness Area, 

W20 Group, 2002” 

(provided by Entergy as Figure 3 to AR020.0166) 
172 

“Regional Point Source Percentage of Total Extinction at Caney Creek Wilderness 

Area, W20 Group, 2002” 

(provided by Entergy as Figure 4 to AR020.0166) 

Entergy asserted that Figures 3 and 4, which it provided, display the modeled percent 

contribution of elevated and low-level point sources to the total light extinction from the 

significantly contributing geographic regions. Also included in these figures is the combined 

total percentage contribution from all point sources in all geographic regions. Of a total point 

source contribution of 61.85% at Caney Creek in 2002, Arkansas’s point sources contributed 

only 2.87%, making Arkansas the eighth highest point source contributor. Similarly, of the 

60.35% total point source contribution at Upper Buffalo in 2002, Arkansas was the ninth highest 

point source contributor with only a 2.47% contribution. 

Entergy stated that in addition, unlike these other regions, where point sources contribute the 

majority of visibility impairment to Arkansas’ Class I areas, most of Arkansas’ share of the 

contribution to visibility impairment comes from Arkansas area and mobile sources, not point 

sources. See Figures 5 and 6 of Entergy’s comments. 
173 

“Regional Percentage of Total Extinction at Caney Creek Wilderness Area, 

W20 Group, 2002” 

(provided by Entergy as Figure 5 to AR020.0166) 
174 

“Regional Percentage of Total Extinction at Upper Buffalo Wilderness Area, 

W20 Group, 2002” 

(provided by Entergy as Figure 6 to AR020.0166) 

At Caney Creek, Arkansas area sources contribute 3.75% of the overall extinction while 

Arkansas’ combined point source category (i.e., elevated and low-level point sources) contribute 

only 2.87%. Even more significantly, Arkansas area sources contributed 5.09% towards 

extinction at Upper Buffalo compared to 2.47% from the combined Arkansas point sources. 

Independence’s emissions, which comprise only a portion of Arkansas’ point source emissions, 

have even less of an effect on light extinction in either Class I area. As a result, installing 

emissions controls on Independence will not meaningfully change the haze index at either Class I 

area. 

Response: We acknowledge the graphs and data presented by the commenter. We agree that 

point sources outside Arkansas have a larger contribution to visibility extinction at Caney Creek 

and Upper Buffalo. The commenter’s analysis of contributions to visibility impairment above 

focuses on visibility impairment in 2002. However, the projected 2018 contributions to visibility 

impairment show large anticipated reductions in contributions from many areas outside of 

Arkansas. Arkansas point sources are projected to contribute more than 4% towards total 
175 

visibility impairment at both Caney Creek and Upper Buffalo in 2018. Considering that the 

CAMx photochemical modeling takes into account the emissions of thousands of sources, both 

in Arkansas and outside of the state, we consider this to be a significant contribution to visibility 

impairment at each Class I area. 

The commenter also contends that most of Arkansas’ share of the contribution to visibility 

impairment at Caney Creek and Upper Buffalo comes from Arkansas area and mobile sources, 

not point sources. While we agree that Arkansas area sources do have a slightly greater 

percentage contribution than do Arkansas point sources, we do not agree that Arkansas mobile 

sources have a greater percentage contribution than Arkansas point sources. The fact that 

Arkansas area sources have a slightly greater percentage contribution than Arkansas point 

sources does not justify not evaluating Arkansas point sources in our reasonable progress 

analysis. Additionally, we discuss in detail in our proposal and elsewhere in this document that 

sulfate is the primary driver of regional haze in Arkansas’ Class I areas and sulfate emissions are 

primarily due to point sources. Therefore, it is reasonable and appropriate to focus our analysis 

on Arkansas point sources. We disagree that Arkansas’ point source contribution of 2.87% at 

Caney Creek and 2.47% at Upper Buffalo in 2002 is small or insignificant, and as we noted 

above, projected 2018 point source contributions are even larger, at greater than 4% at each 

Class I area. 

We also disagree that the visibility impacts from the Independence Plant on Arkansas’ Class I 

areas are small or insignificant. As discussed elsewhere in this document, Entergy submitted 

CAMx model results as part of their comments. The results of this modeling provide additional 

support to our determination that Independence significantly impacts visibility at Arkansas’ 

Class I areas. The modeled contribution to visibility impairment due to baseline emissions from 

the Independence facility alone were approximately 1.3% of the total visibility impairment at 

each Arkansas Class I area. Considering that the CAMx photochemical modeling takes into 

account the emissions of thousands of sources, both in Arkansas and outside of the state, we 

consider this to be a significant contribution to visibility impairment at each Class I area and a 

large portion (approximately one-third) of the total contribution from all Arkansas point sources 

that can be addressed through installation of controls on two units at a single facility. Entergy’s 

CAMx modeling also shows that at Upper Buffalo, the Independence facility contributes more to 

visibility impairment than all the subject-to-BART sources addressed in this action combined. In 

terms of deciviews, the average impact over the 20% worst days based on Entergy’s CAMx 

modeling (adjusting to natural background conditions) is over 0.5 dv at the Arkansas Class I 

areas and even larger at the Class I areas in Missouri. These results estimate the visibility 

impacts from the source on the 20% worst days and confirm and provide additional support to 

our determination that the Independence facility significantly impacts visibility, both in terms of 

maximum visibility impairment and visibility impairment on the 20% worst days, and that 

emissions controls are expected to provide for meaningful visibility benefits towards the goal of 

natural visibility conditions. 

We also make the observation that because of the controls required during this planning period, 

we expect that the impact from the point sources and other source types in Arkansas that were 

not controlled and not specifically evaluated in the first planning period will become larger on a 

percentage basis. These sources will become the largest impacting sources and should be 
176 

considered for analysis under reasonable progress in future planning periods. The methodology 

we used here thus allows a consistent procedure to identify sources for additional control 

analysis in this and future planning periods and ensures continuing progress towards the goal of 

natural visibility conditions. 

Comment: Continued emissions reductions from out-of-state sources included in the 

CENRAP modeling will further Arkansas’ progress towards background visibility without 

the need for controls on Independence. [Entergy Arkansas Inc. (0166) p. 29-32] Entergy stated 

that its analysis demonstrates that Arkansas’ Class I areas will remain below the glidepath in the 

first planning period and well into the second based on actual data; however, the analysis also 

demonstrates that, due to continued emissions reductions at sources outside of Arkansas, these 

reductions will continue, furthering Arkansas’ progress towards background visibility, without 

controls on Independence. Point source emissions from the other states included in CENRAP’s 

modeling have been steadily decreasing since the early 2000’s and that trend is expected to 

continue. Indeed, a number of sources in East Coast states have recently announced retirements. 

The U.S. Energy Information Administration predicts that 60 gigawatts of coal-fired power plant 

capacity will retire by 2020.331 These units are significant contributors to visibility impairment at 

Caney Creek and Upper Buffalo and their retirement will further improve visibility. The second 

phase of CSAPR, the 1-hour SO2 NAAQS and the revised ozone NAAQS also will result in 

significant reductions in SO2 and NOX emissions from the largest point source contributors to 

Caney Creek and Upper Buffalo, which are all located outside of Arkansas. See Figures 7 and 8 

of Entergy’s comments (demonstrating declining emissions trends and the contributions of 

EGUs). 

 

331 http://www.eia.gov/todayinenergy/detail.cfm?id=15031# 
177 

“National Emissions Inventory (NEI) Air Pollutant Emissions Trends Data SO2

Emissions” 

(provided by Entergy as Figure 7 to AR020.0166) 
178 

National Emissions Inventory (NEI) Air Pollutant Emissions Trends Data NOX Emissions 

(provided by Entergy as Figure 8 to AR020.0166) 

Entergy stated that according to EPA’s Reasonable Progress Guidance, the Agency should have 

taken the emissions reductions anticipated from CSAPR, as well as other Clean Air Act 

programs, into account in setting the proposed RPGs for Arkansas: 

Given the significant emissions reductions that we anticipate to 

result from BART, the CAIR, and the implementation of other 

CAA programs, including the ozone and PM2.5 NAAQS, for many 

States this will be an important step in determining your RPG, and 

it may be all that is necessary to achieve reasonable progress in the 

first planning period for some States. (Reasonable Progress 

Guidance at 4-1.) 

Entergy stated that EPA completely failed to undertake this “important step” in proposing the 

RPGs for Arkansas and instead simply focused on controls at Independence. 

Response: We address elsewhere in this document comments contending that controls on 

Independence are not necessary because Arkansas’ Class I areas are below the URP glidepath. 

We acknowledge the information presented by the commenter regarding emissions reductions 
179 

from sources outside of Arkansas that impact visibility at Arkansas’ Class I areas. The 

commenter contends that this trend in emissions reductions from sources outside Arkansas will 

continue into the future and will further Arkansas’ progress towards natural visibility conditions, 

even without controls on Independence. The commenter also points to our Reasonable Progress 

Guidance as stating that it is important to account for the emissions reductions anticipated from 

CSAPR and other CAA programs in setting RPGs, and alleges that we failed to take these 

anticipated emissions reductions from sources outside Arkansas into account in revising the 

RPGs for Arkansas’ Class I areas. To the extent the commenter is suggesting that Arkansas 

should be relieved of its obligations to address visibility impairment caused by sources within the 

state because emissions reductions from other states are already resulting in significant visibility 

improvement in Arkansas’ Class I areas, this is incorrect. Rather, Arkansas or EPA in standing 

in the state’s shoes, must consider the statutory factors in addressing the reasonable progress and 

long term strategy requirements. We discuss this issue and also provide a discussion of 

Arkansas’ emissions trends from 2002 to 2011 elsewhere in this document. 

Further, the commenters’ suggestions that EPA should delay the implementation of control 

measures for Independence that we have determined are cost-effective and would result in 

meaningful visibility benefit at Arkansas’ Class I areas, relies on the conclusion that there is a 

specific pre-determined rate of improvement that constitutes reasonable progress. This is 

incorrect. As we discuss elsewhere in this document, the determination of what constitutes 

reasonable progress is based on the required analysis under CAA section 169A(g)(1) and 40 CFR 

section 51.308(d)(1). 

To the extent that the commenter is concerned about whether our proposed RPGs reflect the 

effects of the emission reductions from other regulatory requirements and sources in other states, 

we believe this step of accounting for emissions reductions anticipated from other CAA 

programs has already been addressed through the regional planning organization (RPO) process 

and the 2018 CENRAP modeling projections that included projected reductions due to 

implementation of CAIR that states relied on in setting their RPGs. Under CAIR, point source 

emissions of SO2 were projected to increase in Arkansas. We recognize that in calculating 

proposed revised numeric RPGs for Arkansas’ Class I areas, we did not update the projections to 

take into account any changes in emissions reductions anticipated to take place due to 

implementation of CSAPR and other CAA programs that were not already included in the 2018 

CENRAP modeling projections. But the commenter has not provided any additional information 

to support any anticipated SO2 reductions from Arkansas point sources in the near future to 

address any existing regulatory requirements. In our proposed action in Arkansas,332 as well as 

our actions in Texas and Oklahoma,333 Arizona,334 and Hawaii,335 the 2018 modeled RPGs 

previously developed by the RPO were adjusted based on a methodology of scaling of visibility 

extinction components in proportion to emission changes. We noted that although we recognize 

that this method is not refined, it allows us to translate the emission reductions achieved through 

the FIP into quantitative RPGs, based on modeling previously performed by the RPOs. This 

provides an estimate of the visibility benefit due to the required controls in the context of the 

 

332 80 FR 18944, 18997 333 81 FR 296 334 79 FR 52420, 52468 335 77 FR 31692, 31708
180 

projected 2018 visibility conditions and RPGs established by Arkansas in its 2008 RH SIP. 

While there is limited precedent for adjusting the RPO calculated RPGs to account for emissions 

reductions achieved in a FIP or revised SIP, we took a reasonable approach based on the 

information available. Specifically, we adjusted the 2018 RPGs provided by Arkansas by the 

amount of visibility benefit anticipated from the difference in emissions reductions between the 

estimates that went into the CENRAP modeling and those from our Arkansas FIP that are 

expected to take place by 2018.336 We believe that this is a reliable estimate of the amount of 

visibility benefit anticipated from controls beyond the projected 2018 CENRAP RPGs. We also 

note that we do not believe that our methodology for estimating the revised RPGs is problematic 

because the RPGs are not directly enforceable, unlike the emission limits that apply to specific 

sources under the regional haze requirements. 

Comment: EPA’s Proposed FIP does not include consideration of the substantial impacts 

of the actions of FLMs to haze conditions. [ADEQ (0160) p. 23-24] ADEQ stated that as set 

forth in 40 C.F.R. § 51.308(i), the Regional Haze Rule requires states such as Arkansas to 

coordinate in various ways with Federal Land Managers. For example, states are required to 

provide Federal Land Managers with notice of the identified visibility impairment and an 

opportunity for consultation.337 However, despite EPA requiring this coordination, the actions of 

the Land Managers themselves are responsible for a disproportionate and unmeasured impact on 

the visibility of Arkansas’s Class I areas. States such as Arkansas are required to identify the 

impairment and elements for inclusion in the visibility monitoring strategy. 

In 2007, the Arkansas Forestry Commission approved a Smoke Management Program that was 

developed, among other reasons, as a means of assuring that land managers throughout the State 

use specific techniques designed to ensure that burns conducted for the purpose of forest 

management (prescribed burns) do not interfere with air quality management goals. Prescribed 

burning is widely recognized as a wildfire prevention technique and is also used to revitalize 

forest ecosystems. When properly conducted, prescribed burning is a useful technique for 

various forest management purposes. 

A Federal Land Manager is “the Secretary of the department with authority over the Class I 

areas.”338 While several state agencies and private-sector entities practice prescribed burning, the 

United States Forest Service (“USFS”) is the largest practitioner. The USFS uses prescribed 

burns from within the very Class I areas that are meant to be protected by the Regional Haze 

Rule. For example, in 2006 the USFS was responsible for as much as 60% of the 30,000 acres of 

prescribed burns that were reported in the State.339 In 2011, federal agencies were responsible for 

most of the burns that were conducted in violation of the procedures described in the State’s 

 

336 In response to other comments we received stating that our proposed RPGs for the 20% worst days for Caney 

Creek and Upper Buffalo improperly incorporated visibility improvements that would not occur until after 2018, we 

are providing revised RPGs that reflect anticipated visibility conditions at the end of the implementation period in 

2018 rather than the anticipated visibility conditions once the FIP has been fully implemented. We discuss this in 

greater detail in our final rule and elsewhere in this document. 

337 40 C.F.R. § 51.308 (i). 338 40 C.F.R. § 51.301 339 Dr. Lynne C. Thompson, Presentation to the Arkansas Prescribed Fire Council (May 18, 2015) attached as 

Exhibit 3 to ADEQ’s comments. 
181 

Smoke Management Plan in which voluntary participants including the USFS agree to meet 

certain air-quality related criteria before initiating prescribes burns.340 Most of burns conducted 

by federal agencies such as the USFS in Arkansas were conducted within the boundaries of 

designated National Forests.341

There is currently no accepted regulatory procedure for isolating the visibility impacts of 

prescribed burning from other anthropogenic sources of haze. However, prescribed burns 

continue to be a significant source of the haze in the Class I areas that are meant to be protected 

by the Regional Haze program. As a result, the actions of Federal Land Managers practicing 

prescribed burning should be given due consideration. Therefore, EPA should withdraw the 

Proposed FIP, and any subsequent plan should include consideration of the substantial impacts of 

Federal Land Managers to haze conditions. 

Response: We acknowledge the information provided by the commenter. We take no position 

with respect to specific comments made regarding prescribed burning conducted by FLMs. We 

agree that section 51.308(d)(3)(v) requires that in establishing its long-term strategy, a state must 

consider at a minimum several factors, including smoke management techniques for agricultural 

and forestry management purposes. Section 51.308(d)(3)(v) states the following: 

(v) The State must consider, at a minimum, the following factors in 

developing its long-term strategy: 

(A) Emission reductions due to ongoing air pollution control programs, 

including measures to address reasonably attributable visibility 

impairment; 

(B) Measures to mitigate the impacts of construction activities; 

(C) Emissions limitations and schedules for compliance to achieve the 

reasonable progress goal; 

(D) Source retirement and replacement schedules; 

(E) Smoke management techniques for agricultural and forestry 

management purposes including plans as currently exist within the State 

for these purposes; 

(F) Enforceability of emissions limitations and control measures; and 

(G) 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. 

 

340 Exhibit 3 to ADEQ’s comments. 341 Id.
182 

In our final action on the Arkansas RH SIP, we partially approved and partially disapproved the 

long term strategy for each Arkansas Class I area contained in the Arkansas RH SIP.342 We 

found that Arkansas did not appropriately consider emission limitations and schedules for 

compliance in developing its long-term strategy, which corresponds to the requirement under 

section 51.308(d)(3)(v)(C). Specifically, we found that Arkansas did not follow the CAA and the 

Regional Haze Rule in establishing certain BART emission limits and did not complete a 

reasonable progress analysis to determine if additional controls were necessary in the first 

planning period. We also found that aside from this element of the long-term strategy, remaining 

elements of the long term strategy in the Arkansas RH SIP satisfied the requirements under 

section 51.308(d)(3)(v) for the first planning period. This includes Arkansas’ consideration of 

agricultural and forestry smoke management techniques under section 51.308(d)(3)(v)(E). The 

purpose of our FIP is to address the disapproved portions of the Arkansas RH SIP for the first 

implementation period.343 Since we found in a previous final action that Arkansas adequately 

considered agricultural and forestry smoke management techniques under section 

51.308(d)(3)(v)(E), we do not have the authority to address section 51.308(d)(3)(v)(E) in this 

FIP. Therefore, we believe that this comment contending that our FIP is required to include 

consideration of the impacts of prescribed burning conducted by the FLMs or other parties is 

outside the scope of this action. However, if the state believes that the approved portion of the 

Arkansas RH SIP no longer adequately addresses the requirements under 51.308(d)(3)(v)(E), the 

State may submit a SIP revision that re-evaluates this element of the long term strategy and 

includes any necessary control measures to address impacts from prescribed burning. 

Comment: EPA’s Proposed FIP is improper because it adopts an individual source-based 

approach to setting RPGs. [Nucor Steel-Arkansas and Nucor-Yamato Steel Company (0163) p. 

19-20; and Arkansas Electric Energy Consumers Inc. and Arkansas Gas Consumers Inc. (0175) 

p. 10-11] Nucor and AEEC/AGC both stated that EPA’s Proposed FIP also is improper as to 

Independence because it adopts an individual source-based approach to setting reasonable 

progress goals inconsistent with the Clean Air Act. Reasonable Progress provisions are intended 

to address contributions from a wide range of sources that can be best addressed on a sourcecategory basis. They are fundamentally different from other provisions such as those for BART 

and reasonably attributable visibility impairment (RAVI), which are specifically designed to 

address individual sources. As the Tenth Circuit recently explained, “[n]either the Clean Air Act 

nor the Regional Haze Rule requires source-specific analysis in the determination of reasonable 

progress.” WildEarth Guardians v. EPA, 770 F.3d 919, 944 (10th Cir. 2014). Instead, the Clean 

Air Act discusses “classes or categories of sources” that “may reasonably be anticipated to cause 

or contribute significantly to impairment of visibility” and directs EPA to promulgate rules to 

address them. 42 U.S.C. §7491(a)(3), (b)(1). 

Nucor and AEEC/AGC stated that in contrast, under the Clean Air Act, BART and Reasonably 

Attributable Visibility Impairment (RAVI) provisions are applied individually to “each major 

stationary source” meeting certain threshold criteria. ld. §7491(b)(2)(A)(c). This distinction is 

carried over into EPA's regulations. For example, under the Regional Haze Rule, SIPs that 

incorporate reasonable progress goals are intended to address “regional haze.” 40 .F.R. 

 

342 76 FR at 64218 and 77 FR 14604 343 80 FR at 18946-18947. 
183 

§51.308(d). Regional haze is defined by EPA as “visibility impairment that is caused by the 

emission of air pollutants from numerous sources over a wide geographic area.” Id. § 51.301 

[emphasis added]. In contrast, EPA defines BART as an “emission limitation [that] must be 

applied on a case-by-case basis ....” Id. Likewise, EPA explains that its RAVI provisions are 

designed to address “visibility impairment that is caused by the emission of air pollutants from 

one or a small number of sources.” Id. Thus, EPA's regulations treat reasonable progress goals, 

which address emissions from a broad range of sources, differently than the BART and RAVI 

provisions, which address individual sources. Consequently, EPA does not have the authority 

and should not have established a separate Reasonable Progress control just for Independence. 

AEEC/AGC stated that in the Proposed FIP, the EPA fails to explain how one could somehow 

use factors required to be considered in setting specific numerical targets, which are not 

enforceable,344 to require specific enforceable limits for a single plant. The proposed FIP 

contains no legal justification for the analysis EPA has performed using the reasonable progress 

factors enumerated in 40 C.F.R. § 51.308(d)(1)(A), nor does the EPA cite legal authority for 

identifying and requiring emissions controls for “reasonable progress sources;” indeed, the term 

“reasonable progress source” does not appear in the Regional Haze Rule. Since the reasonable 

progress provisions of the CAA do not permit a source-specific analysis in the determination of 

reasonable progress, the EPA lacks authority to establish separate Reasonable Progress controls 

for the Independence plant; therefore, the EPA should withdraw the Proposed FIP. 

Response: In our Arkansas FIP, we have conducted the requisite analyses to determine what 

controls are necessary to make reasonable progress by considering those sources and source 

categories with the most significant impact on visibility impairment. We explained in our FIP 

proposal that our reasonable progress analysis focused on the point source category since the 

other source categories each contribute a much smaller proportion of the total light extinction at 

each Class I area in Arkansas based on the CENRPAP modeling.345 We then examined Arkansas 

point source emission inventory data that initially identified White Bluff, Flint Creek, and the 

Independence facility as having the greatest potential to impact visibility at nearby Class I areas 

out of all Arkansas point sources. Since we are requiring SO2 and NOX controls for White Bluff 

and Flint Creek under the BART requirements in this final action, which will substantially 

reduce emissions from these two facilities, we determined that it was appropriate to eliminate 

these sources from further consideration of controls under the reasonable progress requirements 

for this planning period. As such, our evaluation of controls under reasonable progress focused 

on the Independence Plant. We discuss our approach to determine what sources to evaluate under 

reasonable progress in greater detail in our proposal, in our final rule, and elsewhere in this 

document. Thus, we did consider those sources and source categories with the most significant 

impact on visibility impairment. 

While our FIP does consider and ultimately apply controls on an individual source basis to 

assure reasonable progress, this is consistent with the CAA, our regulations, and past EPA 

guidance. The four statutory factors under CAA Section 169A(g) and 40 CFR 51.308(d)(1)(i)(A) 

are directed to the listed possible features or consequences of potential emission control 

 

344 The Regional Haze Rule states that “[t]he reasonable progress goals established by the State are not directly 

enforceable.” 40 C.F.R. § 51.308(d)(1)(v). 

345 See 80 FR at 18989. 
184 

measures for sources, including individual stationary sources. The CAA and the Regional Haze 

regulations expressly set forth that the reasonable progress analysis must consider the 

“compliance” time and costs for “potentially affected sources.” A state determines the rate of 

progress that is reasonable for a Class I area after taking into account the four statutory factors-- 

as applied to specific sources or groups of sources – to determine what additional controls should 

be required in its regional haze SIP. Thus, individual stationary sources may be subject to 

emission limits and source specific analysis when determining whether additional controls are 

necessary to make reasonable progress. 

The comment misinterprets the cited 10th Circuit case. In that case, that court found that 

reasonable progress is not required to be demonstrated on a source-by-source basis (or via 

“source-specific analysis”), but this emphatically does not mean that individual sources are free 

from any possibility of required new or stricter controls as part of establishing reasonable 

progress goals or what is necessary as part of a long-term strategy. Nothing in that decision states 

that individual source controls cannot be required when establishing reasonable progress goals. 

When a State or EPA in a FIP conducts the requisite analysis—whether it begins it by analyzing 

sources individually or by analyzing source categories—it should encompass the possibility of 

applying individual source controls, when they are warranted and reasonable. If, for example, a 

source category analysis were supplemented with information showing that one particular point 

source presented the most compelling set of facts in terms of the four factors weighing in the 

direction of an additional emission control measure being necessary for reasonable progress, 

based on that source being responsible for a majority of the emissions from the category and 

there being a feasible and highly cost effective control, then it would be proper for the State (or 

EPA in a FIP) to focus its analysis on that source, including with a source-specific assessment. 

To conclude otherwise vitiates the statutory purpose and asks for an entirely ineffectual analysis 

which could not result in possible emission limitations as expressly envisioned in the statute. If 

the CAA’s requirements were such that the only individual stationary sources that could be 

looked to for emission reductions to promote reasonable progress were sources subject to 

controls for BART, then States, or EPA acting as necessary in the place of a State, would have 

little to no room for additional progress and even less need for sequential planning periods to 

build on past progress. Source-specific emission limitations, as promulgated in our FIP, are 

manifestly envisioned by the statute. See CAA Section 169A(b)(2); 40 CFR 51.308(d)(1) and 

(3). Incidentally, the cited 10th Circuit case had considered the claim that the State of New 

Mexico failed to conduct source-specific analyses for its non-BART sources with specific 

attention to the Escalante plant. However, there was no record evidence that this plant, remote 

from any relevant Class I areas, had notable impacts for regional haze purposes for this initial 

planning period. In future regional haze planning periods, depending on technical evidence, that 

plant (and others in New Mexico) may very well be subject to controls as may be required to 

meet reasonable progress. 

The commenter’s suggestion that because the RPGs are not themselves enforceable we cannot 

require specific enforceable limits for a single plant is not consistent with the requirement that 

each regional haze SIP or FIP include enforceable emissions limitations as necessary to ensure 

that the SIP or FIP will provide reasonable progress toward the national goal of natural visibility 

conditions. We discuss elsewhere in this document that the numeric RPGs provided by the state 

or EPA represent the best estimate of the degree of visibility improvement that will result in 
185 

2018 from changes in emissions inventories, changes driven by the particular set of control 

measures the state has adopted in its regional haze SIP or EPA in a regional haze FIP to address 

visibility, as well as all other enforceable measures expected to reduce emissions over the period 

of the SIP from 2002 to 2018.346 Thus, the RPGs are intended to provide a degree of 

transparency regarding the rate of improvement in visibility anticipated for each Class I area over 

the planning period of the SIP. But, as noted by the commenter, the RPGs themselves are not 

enforceable.347 EPA cannot enforce an RPG in the sense of seeking to apply penalties on a state 

for failing to meet the RPG or obtaining injunctive relief to require a state to achieve its RPG. 

However, the long-term strategy can and must contain emission limits and other control 

measures that apply to specific sources under the reasonable progress requirements, and that are 

themselves enforceable. The fact that the RPGs are not enforceable does not mean that we cannot 

conduct a source-specific evaluation of the reasonable progress factors or require source-specific 

emission limits under the reasonable progress requirements. 

The commenter states that we make reference to “reasonable progress sources” in our FIP 

proposal, and states that this term does not appear in the Regional Haze Rule or related guidance. 

The commenter contends that we cite no legal authority for identifying and requiring emissions 

controls for “reasonable progress sources.” Where we used the term “reasonable progress 

sources” in our FIP proposal, we used it as shorthand to refer to sources that we are controlling 

or evaluating for controls under the reasonable progress requirements. We explained above why 

individual stationary sources may be subject to controls and source-specific analysis when 

establishing reasonable progress goals. 

3.e. Other 

Comment: It would be premature for EPA to finalize its proposed RPGs when the Agency 

intends to revise the Regional Haze Rule. [ADEQ (0160) p. 16-17] ADEQ stated that for some 

time now, EPA has been considering changes to the Regional Haze program’s metrics for 

tracking progress as well as a possible three-year extension of the schedule for submitting 

updated SIPs currently due in 2018. In the July 2015 timeframe, the Air Quality Policy Division 

of the EPA Office of Air Quality Planning and Standards announced a series of conference calls 

with representatives of the U.S. Department of Agriculture, the Department of the Interior, and 

regional, state, local and tribal governments with the following items on the agenda: 

 Rulemaking activities including the proposal to delay of the State Implementation Plan 

(“SIP”) submission deadline to 2021 from 2018, options for the process and schedule for 

submitting progress reports, and options for revising Reasonably Attributable Visibility 

Impairment rule provisions; 

 Guidance to refocus the visibility tracking metric and framework on the controllable 

fraction of visibility impairment; 

 Guidance to determine what constitutes a long-term strategy providing for reasonable 

progress. 

 

346 64 FR 35733. 347 See 51.308(d)(1)(v).
186 

As indicated by the items on this agenda, it is apparent that EPA intends to reconsider the 

manner in which rates of progress toward the visibility goals of the Regional Haze Rule are 

determined and calculated. These changes would likely be made through a combination of 

guidance documents and rulemaking. Due to the EPA’s intent to significantly revise the manner 

in which these metrics are considered, it is premature and unnecessary to revise the RPGs that 

Arkansas has determined to be appropriate. Accordingly, EPA should withdraw the proposed 

FIP. 

Response: The commenter is correct that EPA has been considering delaying until 2021 the 

deadline for the SIP submittals currently due in 2018 to address regional haze in the second 

planning period. This proposal was published in the Federal Register on May 4, 2016. (81 FR 

26943) The EPA has also been considering issuing guidance to refocus the visibility tracking 

metric and framework on the controllable fraction of visibility improvement and guidance to 

determine what constitutes a long-term strategy providing for reasonable progress in the second 

planning period and beyond. The notice of availability of this draft guidance for public comment 

was published in the Federal Register on July 8, 2016. However, we disagree that the possibility 

of future rulemaking revisions and guidance to address reasonable progress for the second 

regional haze period and beyond means that it is premature or unnecessary for EPA to conduct 

the reasonable progress analysis required under CAA section 169A(g)(1) and 40 CFR 

51.308(d)(1) to determine if additional controls are necessary to make reasonable progress and to 

establish RPGs for the first planning period. The proposed rulemaking and draft guidance 

address the second and future implementation periods only, while this action on Arkansas 

concerns the first implementation period. Further, we discuss elsewhere in this document why 

we do not have the authority to further delay promulgation of our FIP to address the disapproved 

portions of the Arkansas RH SIP. 

To the extent the commenter contends that the RGPs in the Arkansas RH SIP are appropriate, we 

discuss elsewhere it this document why such comments are outside the scope of this rulemaking.

4. Specific BART Issues 

4.a. Control Levels and Emission limits 

Comment: EPA’s proposed SO2 BART limit of 0.11 lb/MMBtu for Power Boiler 2 is too 

stringent, and its selection of emission baseline information for the purpose of establishing 

the SO2 BART limit for Power Boiler No. 2 is inappropriate. [Domtar (0161) p. 6, 10-13] 

Domtar stated that table 43 on page 18979 of the FIP proposal identifies the baseline maximum 

24-hour emission rates for the Ashdown Mill. Assuming EPA proceeds with BART for the 

Ashdown Mill, Domtar agrees with EPA that the following are the appropriate 24-hour 

maximum emission rates and baseline periods to be used for purposes of BART. 
187 

BART Unit Baseline Period NOX Emissions 

(lb/hr) 

SO2 Emissions 

(lb/hr) 

PM10/PMF 

(lb/hr) 

Power Boiler 1 2009-2011 207.4 21.0 30.4 

Power Boiler 2 2001-2003 526.8 788.2 81.6 

Domtar stated that, however, it disagrees with EPA’s selection of emission baseline information 

for the purpose of establishing the SO2 BART limit for Power Boiler 2. Instead of using data 

from the BART baseline period of 2001-2003 for calculating the BART SO2 limit, EPA 

arbitrarily selected to use data from the 2011-2013 time period. No changes occurred with 

respect to Power Boiler 2 that would warrant resetting the baseline period for Power Boiler 2 or 

otherwise justify the use of 2011-2013 data as a baseline. In the approved portions of the 

Arkansas SIP, EPA agreed (with respect to the cost of controls) that baseline emissions may 

reflect past practices. Similarly, in EPA’s BART guidelines, reference is made to calculating 

baseline emissions using on a continuation of past practices (Guidelines, at 39167). By analogy, 

in determining the BART limit for SO2, the percent reduction also should be applied to the past 

practice of Power Boiler 2 as reflected in the 2001-2003 timeframe. This approach is consistent 

with prior EPA BART determinations for pulp and paper facilities. 77 Fed. Reg. 46955 (Aug. 7, 

2012) (Response to Comments on BART Baseline). 

Domtar stated that assuming EPA proceeds with BART for the Ashdown Mill, the Mill believes 

an SO2 limit of 155 lb/hr for Power Boiler 2 is appropriate under the BART five factor analysis. 

EPA’s proposed limit of 0.11 lb/MMBTU is too stringent, is based on the use of an inappropriate 

baseline and assumes the existing control equipment can continuously operate at the upper range 

of its capability (90% efficiency) over long periods of time, without supporting data or other 

documentation. 

Domtar stated that in the methodology to calculate the proposed BART limit, EPA used data 

from recent years for determining the proposed BART limit, ignoring the more appropriate 

BART baseline information. No justification is given for not using the baseline, or why the 

particular years selected by EPA are better than the BART baseline years or legally appropriate. 

The variety of data sets EPA used is summarized below: 

 Baseline SO2 emissions of 2,078 TPY determined using 2001-2003 data for determining 

tons of SO2 removal for purposes of calculating cost effectiveness 

 Scrubber efficiency of 69% determined from 2011-2013 data 

 Annual emission rate of 280.9 lb/hr from years 2011-2013 to determine the BART limit 

Domtar stated that EPA’s selection of actual SO2 emission data from 2011-2013 is inconsistent 

with the method used by EPA to set other BART limits where EPA relied on the BART baseline 

information. For example, in a BART matter involving a Georgia-Pacific pulp and paper mill in 

Wisconsin, the State with EPA concurrence used baseline years of 2002-2004 to establish the 

BART emission limitations. 77 Fed. Reg. 46955 (Aug. 7, 2012). In the approved portions of the 

Arkansas SIP, U.S. EPA agreed (with respect to the cost of controls) baseline emissions may 
188 

reflect past practices (Guidelines, at 39167.). By analogy, the percent reduction in SO2 for the 

Ashdown Mill also should be applied to past practice as reflected in the 2001-2003 timeline. 

Domtar stated that deviating from the BART baseline information is appropriate if significant 

changes were made to the emission units or permit conditions were imposed that prevent a unit 

from operating at the BART baseline emission value. However, this is not the case for Power 

Boiler 2. The BART baseline information is representative of Power Boiler 2’s potential 

operations. The fact that the Ashdown Mill voluntarily elects to operate at a lower SO2 level is 

not relevant. Moreover, by not utilizing the BART baseline actual emission in establishing the 

proposed BART SO2 limit, EPA penalizes the Ashdown Mill for its voluntary SO2 emission 

reductions undertaken on its own initiative since the BART baseline period. 

Domtar stated that here, the Mill voluntarily reduced SO2 emissions by over 40% since the 

BART baseline years. The Ashdown Mill was an early actor and voluntarily reduced SO2

emissions prior to the proposed BART requirements. Using the actual emission data from the 

BART baseline period of 2001-2003, gives the Mill credit for its early voluntary action. Also, 

using the earlier baseline appropriately recognizes that the state and federal governments’ delay 

in imposing BART years after it was required to be completed. The Ashdown Mill should not be 

required to use a later baseline because government agencies were dilatory in implementing the 

BART program. If the BART program was implemented as contemplated under the EPA’s 

BART rules, the 2001-2003 baseline information would have been used in setting the BART 

limit. 

Domtar stated that in addition to the use of an inappropriate baseline year, EPA wrongly applied 

the maximum rated heat input capacity of 820 MMBTU/hr when it converted from a lb/hr limit 

to a lb/MMBTU limit. This inaccurate methodology of using emission data and maximum rated 

heat input to calculate the proposed SO2 BART limit is a significant concern. 

Domtar stated that based on monthly SO2 information for the 2011-2013 period, EPA estimated 

that the SO2 control efficiency for the scrubber on Power Boiler 2 to be approximately 69%. The 

scrubber is currently operated based on a pH set point and the use of pH controllers to adjust the 

amount of caustic scrubbing solution needed to maintain continuous compliance with the 

permitted SO2 emission limit of 1.2 lb/MMBTU. Information the Ashdown Mill provided to 

EPA indicated the existing scrubber may achieve on a short-term basis an SO2 control efficiency 

of 90%. However, there is no documentation showing that the scrubber can sustain this 

maximum performance level on a long term basis. 

The Ashdown Mill requests that EPA revise the methodology for calculating the SO2 BART 

emission rate to use average SO2 emissions from the 2001-2003 baseline period as follows: 

 Use the average SO2 emissions in lb/hr from the 2001-2003 BART baseline period 

 Assume the existing scrubbers operated at a 69% control efficiency during the baseline 

period 

 Calculate an SO2 emission limit in lb/hr based on baseline actual emissions and a 90% 

control efficiency (although the Mill believes it is not appropriate to use a short-term very 
189 

high control efficiency for a long-term limit; for purposes of this calculation, the Mill will 

use EPA’s assumed long-term control efficiency of 90%) 

Based on this approach, the revised SO2 limit for Power Boiler 2 is: 

 No. 2 Power Boiler Average SO2 Emissions 

Baseline Year Average SO2 (lb/hr) 

2001 557.0 

2002 475.0 

2003 394.0 

Average SO2 Emission Rate (lb/hr) 475.3 

 Calculating No. 2 Power Boiler BART SO2 Emission Rate at 90% Control 

Efficiency 

475.3 lb/hr at about 69% control efficiency or at 30.7% uncontrolled efficiency 

475.3 lb/hr = 1,548.21 lb/hr uncontrolled SO2 emissions 

 (0.307) 

 SO2 Emission Rate at 90% Control Efficiency

1548.21 lb/hr * (1 - 0.9) = 154.8 lb/hr or 155 lb/hr 

Domtar stated that in summary, the actual average SO2 emission rate in lb/hr for the 2001-2003 

period is 475.3 lb SO2/hr. Using EPA’s assumption that the SO2 control efficiency for the 

scrubber during the baseline period is approximately 69% and using the EPA assumed long-term 

scrubber removal efficiency of 90% equates to an SO2 limit of 155 lb /hr. Thus, The Ashdown 

Mill requests EPA revise the proposed SO2 limit for Power Boiler 2 from 0.11 lb/MMBTU to 

155 lb/hr on a 30-day boiler operating day. As noted above, the Ashdown Mill is requesting a 

boiler operating day be defined as a 24-hr period between 6 a.m. and 6 a.m. the following day 

during which any fuel is fed into and/or combusted at any time in the power boiler. 

Domtar stated that it requests any SO2 emission limit for No. 2 Power Boiler be expressed on a 

lb/hr basis. For EPA’s proposed limit, the boiler’s maximum heat input rating of 820 

MMBTU/hr was used to determine the lb/MMBTU limit. The use of the maximum heat input 

rating is not representative of average (typical) boiler operating conditions, which are lower than 

the maximum heat input capability. In this situation, the use of actual emission data and 

maximum rated heat input to calculate the proposed SO2 BART limit is inappropriate and an 

inaccurate methodology which creates significant concerns. The actual average heat input during 

the 2001-2003 baseline period is 586 MMBtu/hr. It is this value that should have been used to 

calculate a lb/MMBTU limit. However, if EPA expresses the limit on a lb/hr basis as requested, 

the Mill’s concern becomes moot. 
190 

With the SO2 limit being expressed on a lb/hr basis, section 52.173(19)(i) needs to be deleted 

and 52.173(19)( ii) renumbered to 52.173(19)(i) and revised to read as follows: 

NOX and SO2 emissions for each calendar day shall be determined 

by summing the hourly emissions measured in pounds of NOX or 

 pounds of SO2. Each boiler operating day of the 30-day rolling 

average for the power boiler shall be determined by adding 

together the pounds of NOX or SO2 from that day and the 

preceding 29 boiler operating days and dividing the total pounds of 

NOx or SO2 by the sum of the total number of hours during the 

same 30 boiler operating day period. The result shall be the 30 

boiler operating day rolling average in terms of lb/hr emissions of 

NOX or SO2. If a valid NOX pounds per hour or SO2 pounds per 

hour is not available for any hour for the power boiler, that NOX

pounds per hour or SO2 pounds per hour shall not be used in the 

calculation of the 30 boiler operating day rolling average for NOX

or SO2. 

[0152-6] One public hearing commenter also stated that since the regional haze baseline period, 

the Domtar Ashdown Mill has voluntarily reduced SO2 emissions by more than 40%. The 

commenter stated that any decisions on emissions reductions should account for the voluntary 

actions undertaken by Domtar. 

Response: We appreciate the commenter’s support of our use of 2009-2011 as the baseline 

period in our BART analysis for Power Boiler No. 1. 

With regard to Power Boiler No. 2, we discussed in our proposal that we requested information 

from the facility to determine if upgrades to the existing scrubbers are technically feasible and if 

they would be cost effective and provide meaningful visibility benefit. This assessment first 

required us to determine the current control efficiency of the scrubbers. Because our BART 

analysis involved determining the current control efficiency of the existing scrubbers, we found 

that the most reasonable approach was to use data that reflect the current control efficiency of the 

existing scrubbers, as opposed to 2001-2003 data. In order to conduct our BART analysis, we 

requested monthly average data for 2011, 2012, and 2013 on monitored SO2 emissions from 

Power Boiler No. 2, mass of the fuel burned for each fuel type, and the percent sulfur content of 

each fuel type burned.348 These were the three most recent full calendar years of data available at 

the time we conducted our BART analysis. For these reasons, our use of 2011-2013 as the 

baseline for calculating the current control efficiency of the existing scrubbers and our proposed 

SO2 BART limit for Power Boiler No. 2 was appropriate and justified.349 

 

348 See 80 FR at 18984. See also August 29, 2014 letter from Annabeth Reitter, Corporate Manager of 

Environmental Regulation, Domtar, to Dayana Medina, U.S. EPA Region 6. A copy of this letter and an Excel file 

attachment titled “Domtar 2PB Monthly SO2 Data,” are found in the docket for our proposed rulemaking. 

349 The commenter notes that the baseline SO2 emission of 2,078 tpy we used to determine the tons of SO2 removed 

for purposes of calculating the cost effectiveness of controls was based on 2001-2003 emissions data. It is unclear if 

the commenter is suggesting that we should use 2011-2013 data for purposes of calculating the cost effectiveness of 

our proposed control. We note that we are not revising the cost estimate and calculation of the cost effectiveness of 
191 

As discussed in detail in our proposal, based on the emissions data and fuel usage data Domtar 

provided to us, we estimated that the current control efficiency of the existing scrubbers is 

approximately 69% based on 2011-2013 data.350 The data also indicated that the existing 

scrubbers could achieve up to 90% removal efficiency. As discussed in our proposal, Domtar 

indicated that the scrubbers are currently operated in a manner that allows for compliance with 

permitted emission limits.351 In other words, the facility generally uses only the amount of 

scrubbing solution needed to comply with permitted emission limits. The information the facility 

provided indicated that it would be possible to add more scrubbing solution to achieve greater 

SO2 removal than required to meet the boiler’s existing SO2 permit limit; specifically, the 

information indicated that additional scrubbing reagent can be added to increase the control 

efficiency of the existing scrubbers to 90%.352 

We agree that we applied the boiler’s maximum heat input rating of 820 MMBtu/hr when we 

calculated our proposed limit of 0.11 lb/MMBtu, and based on information provided by the 

commenter, we acknowledge that use of the maximum heat input rating is not representative of 

average (typical) boiler operating conditions. To address the commenter’s concern, we are 

finalizing an SO2 BART limit for Power Boiler No. 2 in terms of lb/hr. As we discussed in our 

proposal, based on the emissions data we obtained from Domtar, we determined that the No. 2 

Power Boiler’s annual average SO2 emission rate for the years 2011-2013 was 280.9 lb/hr.353

This annual average SO2 emission rate corresponds to the operation of the scrubbers at a 69% 

removal efficiency. We also estimated that 100% uncontrolled emissions would correspond to an 

emission rate of approximately 915 lb/hr. Application of 90% control to this emission rate results 

in a controlled emission rate of 91.5 lb/hr.354 

We recognize that the boiler’s SO2 emissions are currently lower than they were in the 2001-

2003 period, and that had we used 2001-2003 data to calculate the current control efficiency and 

SO2 BART emission limit, as the commenter requests, this would have resulted in a less 

stringent emission limit. However, as discussed above, the most reasonable approach is to use 

 

SO2 controls on Power Boiler No.2 that we presented in our proposal. However, we have examined the effect of 

using emissions data from 2011-2013 to calculate the cost effectiveness of using additional scrubbing reagent. Based 

on 2011-2013 emissions data previously provided by Domtar, we estimate that 2011-2013 annual average emissions 

from Power Boiler No. 2 were 1,228 tpy and that additional scrubbing reagent would cost approximately $2,387/ton 

removed. Had we used 2011-2013 emissions data to calculate the cost effectiveness, we would still find this control 

to be cost effective. This exercise appears in the file titled “Domtar PB2_Cost2011-2013.” 350 See 80 FR at 18984. See also the spreadsheet titled “Domtar 2PB Monthly SO2 Data.” This spreadsheet was 

included as an attachment to the August 29, 2014 letter from Annabeth Reitter, Corporate Manager of 

Environmental Regulation, Domtar, to Dayana Medina, U.S. EPA Region 6. See also the spreadsheet titled “Domtar 

PB No2—Cost Effectiveness calculations.” Copies of these documents can be found in the docket for this proposed 

rulemaking. 

351 80 FR at 18983 and 18984. 352 80 FR 18984. 353 See 80 FR at 18984. See also the spreadsheet titled “Domtar 2PB Monthly SO2 Data.” This spreadsheet was 

included as an attachment to the August 29, 2014 letter from Annabeth Reitter, Corporate Manager of 

Environmental Regulation, Domtar, to Dayana Medina, U.S. EPA Region 6. See also the spreadsheet titled “No2 

Boiler_Monthly Avg SO2 emission rate and calculations.” Copies of these documents can be found in the docket for 

our rulemaking. 

354 See 80 FR at 18984. See also the spreadsheet titled “No2 Boiler Monthly Avg SO2 emission rate and 

calculations.” A copy of this spreadsheet can be found in the docket for our rulemaking. 
192 

recent data in our calculation of an appropriate SO2 BART emission limit. As Domtar is 

requesting an emission limit in terms of lb/hr, we are finalizing for SO2 BART for Power Boiler 

No. 2 an emission limit of 91.5 lb/hr on a 30 boiler-operating-day rolling average. We believe 

this emission limit reflects operation of the scrubbers at 90% control efficiency and addresses the 

SO2 BART requirement for Power Boiler No. 2. 

We believe it reasonable to set the emission limit using baseline emissions resulting from 

recent/current fuels. Given that we don’t find it appropriate to use emissions from the 2001-2003 

period to calculate the SO2 emission limit, the control efficiency from that period is irrelevant. 

What is relevant are the current uncontrolled SO2 emissions and the possible control efficiency 

of the existing scrubbers, which is what we considered in our BART analysis. We found in our 

analysis that during the 2011-2013 period, the company was able to achieve an average monthly 

control efficiency of 90% and find that this level of control is reasonable, and can be achieved by 

the use of sufficient reagent and scrubber pump upgrades to achieve the lower level. We also 

note that the commenter did not provide additional information to support the claim that the 

existing scrubbers cannot consistently achieve the level of control efficiency necessary to meet 

an emission limit of 91.5 lb/hr on a 30 boiler-operating-day rolling average. 

In sum, we disagree that an emission limit of 155 lb/hr on a 30 boiler-operating-day satisfies the 

SO2 BART requirement for Power Boiler No. 2. We are finalizing an SO2 emission limit of 91.5 

lb/hr on a 30 boiler-operating-day rolling average. 

As requested by the commenter, we are revising the regulatory language at section 52.173 to 

reflect that we are finalizing an SO2 emission limit in lb/hr. We also discuss elsewhere in this 

document that, as requested by Domtar, we are revising the definition in our FIP of “boiler 

operating day” for the Domtar Ashdown Mill Power Boilers No. 1 and 2. 

Comment: EPA’s proposed NOX limits for White Bluff and Independence cannot be 

achieved based on the plants’ current operating conditions. [Entergy Arkansas Inc. (0149) p. 

49-52] Entergy stated that the NOX emission limits proposed by Entergy for the units at White 

Bluff and Independence are based on the emission rate for LNB/SOFA of 0.15 lb/MMBtu that 

Entergy proposed in the Revised White Bluff BART Analysis. At the time Entergy submitted the 

Revised White Bluff BART Analysis in October 2013, all four of the coal-fired units at White 

Bluff and Independence were operated as base load units and spent the overwhelming majority 

of their operating time at loads of greater than 50% of unit capacity. Since submitting the 

Revised White Bluff BART Analysis,355 Entergy transitioned to MISO in December 2013. MISO 

utilizes an economic dispatch model to determine which EGUs within its service territory are 

dispatched to operate and the operating load (MW) for each unit. Initially the MISO operating 

environment resulted in similar unit dispatch schedules for White Bluff and Independence, with 

all four units primarily dispatched as base-load units with some load-following operation. 

However, beginning in December 2014, the units at both White Bluff and Independence began to 

be dispatched primarily as load-following units. Since December 2014, the White Bluff and 

 

355 Entergy notes that EPA relied upon the Revised White Bluff BART Analysis to evaluate controls for 

Independence.
193 

Independence units have been dispatched less frequently and, when dispatched, have spent 

significantly more time at low operating rates of less than 50% of unit capacity. 

Entergy stated that the impact of this change in dispatch of the units can be seen in the following 

table. The data for 2015 (through June 30) reflects a significant increase in the percentage of 

time that each unit is dispatched at less than 50% of operating capacity. Three of the four units 

have spent greater than 40% of their 2015 operating hours at less than 50% of capacity, and the 

two Independence units have spent nearly half of their operating time at less than 50% of 

capacity. 

* 2015 YTD represents Jan-June 2015 

Entergy stated that this change in dispatch coincided with a sharp drop in natural gas prices (see 

Entergy’s August 7, 2015 comments to EPA, Figure 15, p. 50). This drop in gas prices to near $3 

per MMBtu has been sustained since December 2014, and Entergy has no reason to expect any 

significant increase in gas pricing in the near future. 

Entergy stated that this change in dispatch for the units at both White Bluff and Independence is 

significant with regard to NOX emissions as the LNB/SOFA system is designed to operate 

primarily in the range of 50-100% of unit load. Entergy has selected Foster Wheeler as the 

LNB/SOFA vendor for White Bluff and has only been able to obtain a guarantee of less than 

0.15 lb/MMBtu for operating loads in the range of 50-100% of unit capacity.356 Since the 

available emission guarantee does not cover unit operation at less than 50% of capacity, Entergy 

requested a memorandum from Foster Wheeler regarding the impact of unit operation at less 

than 50% capacity on NOX emission rates. This memorandum is attached as Exhibit G to 

Entergy’s comments. Based on input from the LNB/SOFA vendor, Entergy does not believe that 

the proposed emission rate of 0.15 lb/MMBtu is consistently achievable under all operating 

 

356 This range is referred to as the “control range” by Foster Wheeler. See Exhibit F, p. 46, for Foster Wheeler’s 

emissions guarantee. The load ranges identified in the emissions guarantee equate to 50% to 100% of the White 

Bluff units’ operating capacity. Entergy added .01 lb/MMBtu to Foster Wheeler’s emissions guarantee to account 

for fluctuations in NOX emissions from the units. Controlled NOX emissions fluctuate during normal boiler 

operation in response to a number of design/operating parameters including, but not necessarily limited to: inlet 

NOX concentrations, boiler load, load changes, particulate matter loading, flue gas temperatures and flue gas 

velocities. A compliance margin above the vendor’s emissions guarantee is recommended for establishing an 

enforceable limit to address such fluctuations. 

WB1 WB2 ISES1 ISES2

# of Hours 

<50% Load 

% of 

Operating 

Hours <50% 

Load 

# of Hours 

<50% Load

% of 

Operating 

Hours <50% 

Load 

# of Hours 

<50% Load

% of 

Operating 

Hours <50% 

Load 

# of Hours 

<50% Load 

% of Operating 

Hours <50% 

Load 

2013 624 7.96% 606 7.95% 797 10.99% 979 11.60% 

2014 959 12.39% 784 10.32% 818 10.39% 1069 13.69% 

2015 

*(YTD) 1444 42.84% 681 27.54% 1278 48.03% 1267 49.40% 
194 

conditions. Even with a 30-day averaging period for the proposed limit, a unit which is 

frequently dispatched at less than 50% of capacity may not be able to achieve compliance. 

Entergy stated that this was not perceived as an issue at the time that the Revised White Bluff 

BART Analysis was prepared and submitted to ADEQ by Entergy as, historically and at that 

time, the units were operated almost exclusively as base-load units and spent less than 10% of 

their operating time at less than 50% of unit capacity. In the current dispatch environment, with 

some units spending nearly 50% of their operating time outside of the control range for 

LNB/SOFA, Entergy can no longer be confident that the units will be able to achieve compliance 

with a limit of 0.15 lb/MMBtu on a 30-day rolling average basis. 

Entergy stated that the concern arises from low-load operation during which periods of higher 

NOX emissions, on a lb/MMBtu basis, would not be expected to correspond to an increase in the 

maximum mass emission rate (lb/hr) from the units as any increase in the emission rate on a 

lb/MMBtu basis would be expected to be more than offset by the lower unit operating rate in 

MMBtu/hr to arrive at a mass emission rate (lb/hr). 

Entergy stated that to address the potential for a higher NOX emission rate (lb/MMBtu basis) at 

operating rates of less than 50% of unit capacity, Entergy proposes a rolling 30-boiler operating 

day average emission rate of 1,342.5 lb NOX/hr at each coal-fired unit at White Bluff and 

Independence. In the alternative, if EPA believes that a lb/MMBtu limit is necessary for the 

units, Entergy proposes a bifurcated NOX emission limit for each unit at both White Bluff and 

Independence as follows: 

 For all unit operation (0-100% of capacity), a limit of 1,342.5 lb NOX/hr, based on a 

rolling 30-boiler operating day average; and 

 For unit operation at 50-100% of capacity, a limit of 0.15 lb NOX/MMBtu, based on a 

rolling 30-boiler operating day average, to include only those hours for which the unit 

was dispatched at 50% or greater of maximum capacity. 

Entergy stated that this alternative approach would ensure that the units are operated in 

compliance with the LNB/SOFA design within the control range of 50-100% of capacity while 

providing Entergy with flexibility in demonstrating compliance. The lb/hr limit, which would 

apply to all operating hours, will ensure that the 30-day average emission rates remain below 

those on which both EPA and Entergy relied to project visibility improvements from the 

proposed NOX emission reductions. 

Response: We acknowledge the information provided in the comment and in the attachments 

referenced by the commenter. We understand Entergy’s concerns that because of recent changes 

in dispatch of the units, White Bluff Units 1 and 2 and Independence Units 1 and 2 are no longer 

expected to be able to consistently meet our proposed NOX emission limit of 0.15 lb/MMBtu 

over a 30-boiler-operating-day period based on LNB/SOFA controls. We believe the commenter 

has provided sufficient information to substantiate that the units are not expected to be able to 

meet our proposed NOX emission limit of 0.15 lb/MMBtu when the units are primarily operated 

at less than 50% of their operating capacity. In particular, the information provided by the 

commenter indicates that LNB/SOFA achieves optimal NOX control when the boiler is operated 
195 

from 50 to 100% steam flow because the heat input across this range is sufficient to safely 

redirect a substantial portion of combustion air through the overfire air registers.357 This allows 

the combustion zone airflow to be sub-stoichiometric and oxygen to be reduced to the point 

where much of the elemental nitrogen in the fuel and combustion air can pass through the boiler 

without oxidizing (i.e., converting to NOX). When a boiler is operated below the 50 to 100% 

capacity range, NOX concentrations on a lb/MMBtu basis can be elevated due to the lower heat 

input rating, even though the pounds of NOX emitted (i.e., on a mass basis) is less due to the 

reduced amount of fuel and air. In light of the information provided by the commenter, we 

believe it is appropriate to promulgate a bifurcated NOX emission limit for each unit, as 

suggested by the commenter.

Therefore, in this FIP we are requiring White Bluff Units 1 and 2 and Independence Units 1 and 

2 to each meet a NOX emission limit of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling 

average, where the average is to be calculated by including only the hours during which the unit 

was dispatched at 50% or greater of maximum capacity, as requested by the commenter. 

Specifically, the 30 boiler-operating-day rolling average is to be calculated for each unit by the 

following procedure: (1) summing the total pounds of NOX emitted during the current boileroperating-day and the preceding 29 boiler-operating-days, including only emissions during hours 

when the unit was dispatched at 50% or greater of maximum capacity; (2) summing the total heat 

input in MMBtu to the unit during the current boiler-operating-day and the preceding 29 boileroperating-days, including only the heat input during hours when the unit was dispatched at 50% 

or greater of maximum capacity; and (3) dividing the total pounds of NOX emitted as calculated 

in step 1 by the total heat input to the unit as calculated in step 2. 

In addition to this limit that is intended to control NOX emissions when the units are operated at 

50% or greater of maximum capacity, we are also establishing a limit in lb/hr to control NOX

emissions when the units are operated at less than 50% of maximum capacity. However, the 

1,342.5 lb/hr emission limit suggested by the commenter is too high to appropriately control 

NOX emissions when the units are operated at low capacities. There is no indication in the 

comments and attachments submitted by the commenter that the 1,342.5 lb/hr emission limit 

suggested by the commenter was based on a vendor guarantee. The commenter did not explain 

how the 1,342.5 lb/hr limit was calculated, but it appears that it was calculated by multiplying 

the 0.15 lb/MMBtu limit by the maximum heat input rating for each unit (8,950 MMBtu/hr), 

which yielded 1,342.5 lb/hr. We believe that an emission limit of 1,342.5 lb/hr would be 

appropriate when the unit is operated at high capacities, considering that the limit was calculated 

based on the unit’s maximum heat input rating. However, such an emission limit would not be 

sufficiently protective or appropriate when the unit is operated at lower capacities when it is 

expected that NOX emissions on a mass basis would be lower compared to operation at high 

capacity. To address this concern, we have calculated a new emission limit of 671 lb/hr that is 

based on 50% of the unit’s maximum heat input rating, and is applicable only when the unit is 

being operated at less than 50% of the unit’s maximum heat input rating. We calculated this limit 

by multiplying 0.15 lb/MMBtu by 50% of the maximum heat input rating for each unit (i.e., 50% 

of 8,950 MMBtu/hr, or 4,475 MMBtu/hr). This limit is on a rolling 3-hour average, where the 

average is to be calculated by including emissions only from the hours during which the unit was 

operated at less than 50% of the unit’s maximum heat input rating (i.e., hours when the heat 

 

357 See Exhibit G to Entergy Arkansas Inc.’s comments. 
196 

input to the unit is less than 4,475 MMBtu). We are not establishing a lb/hr emission limit that 

applies when the units are operated at 50% or greater of the unit’s maximum heat input rating 

because there is no need for it since the 0.15 lb/MMBtu limit will address NOX emission during 

those operating conditions. 

As such, we are requiring White Bluff Units 1 and 2 and Independence Units 1 and 2 to each 

meet a NOX emission limit of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling average, 

where the average is to be calculated by including only the hours during which the unit was 

dispatched at 50% or greater of maximum capacity, as requested by the commenter. In addition, 

we are requiring White Bluff Units 1 and 2 and Independence Units 1 and 2 to each meet a NOX

emission limit of 671 lb/hr on a rolling 3-hour average that applies only to the hours when the 

unit is operated at less than 50% of the unit’s maximum heat input rating. We believe that these 

limits address the commenter’s concern of not being able to meet the lb/MMBtu emission limit 

when the unit is being operated at lower capacities, and will also ensure that NOX emissions are 

appropriately controlled when the units are operated at higher capacities, as well as when they 

are operated at lower capacities. 

Comment: EPA failed to consider all available control technologies and failed to properly 

evaluate visibility impacts. [Nucor Steel-Arkansas and Nucor-Yamato Steel Company (0163) p. 

28-32] Nucor stated that according to EPA's BART Guidelines, the determination of BART 

should proceed according to the following five steps: 

1. Identify all available retrofit technologies. 

2. Eliminate technically infeasible options. 

3. Evaluate control effectiveness of remaining control technologies. 

4. Evaluate impacts and document the results. 

5. Evaluate visibility impacts. 

80 Fed.Reg. 18944, 18949 (April 8, 2015). After this analysis is complete, the regulatory agency 

still must evaluate the factors and select the best alternative. 70 Fed.Reg. 39104, 39170 (July 6, 

2005). EPA did not identify or evaluate all available retrofit technologies for White Bluff and 

Flint Creek. In addition, while EPA may have modeled visibility impacts from the technologies 

that it did consider, EPA did not adequately evaluate those visibility impacts; for example, EPA 

did not evaluate the cost of the technology compared to the improvement in visibility as 

expressed in deciviews (i.e. $/dv).358

Nucor state that low sulfur coal has been used as the fuel source for White Bluff, Flint Creek and 

Independence for many years. When construction of White Bluff was approved by the Arkansas 

Public Service Commission, it required White Bluff to use low-sulfur coal instead of high sulfur 

coal.359 Entergy’s five-factor analysis points out that the amount of sulfur in coal is the most 

 

358 The $/dv calculation is expressly approved in the BART guidelines. 70 Fed.Reg. 39104, 39170 (July 6, 2005). 359 See Arkansas Public Service Commission Order No. 14, Docket 73-048 U(U- 2488), October 11, 1974, attached 

hereto as Exhibit 11 to Nucor’s comments. 
197 

important factor in controlling SO2 emissions.360 EPA's own documents in support of the 

national Regional Haze Rule indicate that use of 0.7% low-sulfur coal reduces SO2 emissions by 

over 70%.361 The U.S. Energy Information Administration states that low-sulfur coal may reduce 

SO2 emissions by up to 85%.362 EPA has approved the use of low-sulfur coal as Best Available 

Control Technology for purposes of its PSD regulations. In fact EPA has approved the use of 

low-sulfur coal as BART for a coal-fired power plant even though it determined that Dry Sorbent 

Injection (“DSI”) at a cost of only $991/ton S02 was “cost-effective” for that plant.363

Nucor stated that as indicated, White Bluff, Flint Creek and Independence have been using lowsulfur coal for many years. The charts attached as Exhibits 15A and 15B show that White Bluff’s 

average coal sulfur content since 2009 has been in the range of 0.25 – 0.30%; but the BART 

analyses relied on by EPA did not identify, much less evaluate the use of low-sulfur coal as 

BART.364 In addition, although Entergy identified DSI as an available control technology in its 

BART Five-Factor analysis, that control technology was never evaluated by Entergy nor by 

EPA, and no explanation was given as to why DSI was not evaluated.365 DSI also was identified 

in the Flint Creek BART Five-Factor Analysis as an available control technology, but also was 

not evaluated.366 Because low-sulfur coal, DSI and other potential available systems of control 

were not evaluated, EPA's BART analyses did not satisfy the requirements of the BART 

guidelines, and thus EPA's Proposed FIP should be withdrawn. North Dakota v. EPA, 730 F.3d 

750, 764 (8th Cir. 2013) (EPA BART determination vacated where EPA did not consider all 

available control technologies). 

Nucor stated that EPA also failed to adequately evaluate the visibility impacts of the available 

retrofit technologies that were identified and evaluated. Although EPA modeled numeric 

visibility improvements from the control technologies that were evaluated using the CALPUFF 

model, EPA did not explain how it weighed those visibility impacts. At most, EPA stated for a 

particular numerical dv improvement that it was “considerable” or “significant,” however, EPA 

did not explain how it balanced those visibility improvements against the other BART factors to 

determine BART.367 EPA should explain how it weighed the five BART factors and why it made 

the BART determinations that it did - as well as its Reasonable Progress determinations - and 

 

360 See Exhibit 12 to Nucor’s comments, Entergy Revised BART Five-Factor Analysis for White Bluff, dated 

October 14, 2013, included in this Docket as document 0045, p. 5-1. 

361 See Exhibit 13 to Nucor’s comments, Hawes, T., Worksheet from EPA's docket EPA-HQ-OAR-2002-0076, 

document number 145. 

362 See EIA December 21, 2001 forecast, attached as Exhibit 14 to Nucor’s comments. 363 See EPA's Final BART determination for PPL Corrette, 77 Fed.Reg. 23988, 24031 (April 29, 12012) which 

approved the use of coal with a 0.3% sulfur content as BART.

364 EPA admittedly relied on the BART five-factor analyses submitted by Entergy and AEP, rather than performing 

its own five-factor analysis. See, Technical Support Document for EPA's Proposed Action on the Arkansas Regional 

Haze Federal Implementation Plan, p. 13, footnote 13, Docket document No. 0002. Neither the White Bluff nor the 

Flint Creek five-factor analyses identified or considered low-sulfur coal as an available technology. Even if EPA had 

already decided to reject low-sulfur coal as BART, that technology should have been identified and evaluated so that 

the public would be able to provide meaningful comments on EPA’s Proposed FIP. 

365 See Exhibit 12 to Nucor’s comments, p. 5-2. 366 See Exhibit 16 to Nucor’s comments, AEP BART Five-Factor Analysis for Flint Creek, September 2013, p. 5-1. 367 EPA failed to evaluate the cost/dv of the various control technologies. Instead EPA appeared to simply determine 

whether a particular control technology was “cost-effective,” and then to choose a particular control technology 

based only on the incremental cost difference between the control technology choices, irrespective of whether any of 

the evaluated control technologies was reasonably certain to result in an actual improvement in visibility. 
198 

why those costs are reasonable in light any “reasonably certain” visibility benefits, especially 

given the known shortcomings of the CALPUFF model as discussed elsewhere in Nucor’s 

comments. 

Response: We disagree that the CAA or the RH regulations require EPA to consider and 

evaluate every available retrofit technology in evaluating BART. The CAA requires the 

following in evaluating BART: 

[I]n determining best available retrofit technology the State (or the 

Administrator in determining emission limitations which reflect such 

technology) shall take into consideration the costs of compliance, the 

energy and nonair quality environmental impacts of compliance, any 

existing pollution control technology in use at the source, the remaining 

useful life of the source, and the degree of improvement in visibility which 

may reasonably be anticipated to result from the use of such technology.368

Section 51.308(e)(1)(ii)(A) requires the following: 

The determination of BART must be based on an analysis of the best 

system of continuous emission control technology available and associated 

emission reductions achievable for each BART-eligible source that is 

subject to BART within the State. In this analysis, the State must take into 

consideration the technology available, the costs of compliance, the 

energy and nonair quality environmental impacts of compliance, any 

pollution control equipment in use at the source, the remaining useful life 

of the source, and the degree of improvement in visibility which may 

reasonably be anticipated to result from the use of such technology. 

Neither the CAA nor the RH regulations require that every single technology available must be 

considered in the BART analysis. We recognize that the BART Guidelines provide that a BART 

analysis involves the five basic steps listed by the commenter. The BART Guidelines also 

provide further clarification as to what is involved in the step of identifying all available retrofit 

technologies: 

In identifying “all” options, you must identify the most stringent option 

and a reasonable set of options for analysis that reflects a comprehensive 

list of available technologies. It is not necessary to list all permutations of 

available control levels that exist for a given technology— the list is 

complete if it includes the maximum level of control each technology is 

capable of achieving. 40 C.F.R. Part 51, App. Y § (IV)(D). 

In addition, the BART Guidelines provide the following: 

If you find that a BART source has controls already in place which are the 

most stringent controls available (note that this means that all possible 

 

368 CAA section 169A(g)(2). 
199 

improvements to any control devices have been made), then it is not 

necessary to comprehensively complete each following step of the BART 

analysis in this section. As long these most stringent controls available are 

made federally enforceable for the purpose of implementing BART for 

that source, you may skip the remaining analyses in this section, including 

the visibility analysis in step 5. Likewise, if a source commits to a BART 

determination that consists of the most stringent controls available, then 

there is no need to complete the remaining analyses in this section

(emphasis added).369

As noted by the commenter, our FIP proposal did rely on the BART analyses provided by White 

Bluff and Flint Creek. The BART analyses provided by White Bluff370 and AEP Flint Creek371

did identify DSI as an available control option. However, the remainder of each company’s 

analysis focused only on wet FGD and dry FGD. In accordance with the BART Guidelines, 

Entergy assessed the control effectiveness of each of the technically feasible control options and 

ranked them according to their effectiveness. DSI was found to be the least effective. Likewise, 

AEP conducted a similar analysis. DSI, again, was found to be the least effective control option. 

The companies themselves chose to eliminate DSI as a control option, thus voluntarily 

committing to “a BART determination that consists of the most stringent controls available,” and 

relieving us of the duty to consider this less stringent control option in our analysis. We noted in 

our proposal that we concurred with the approach taken by each company as it involved 

evaluating the most stringent option as well as one other option.372 Because each company found 

in their respective BART analysis that SO2 BART is an emission limit of 0.06 lb/MMBtu 

consistent with the installation of dry scrubbing technology, there was no need to evaluate DSI, 

which is a less stringent control option. This is consistent with the CAA, the Regional Haze 

Rule, and the BART Guidelines. 

Additionally, the BART analysis provided by AEP Flint Creek stated that the retrofit controls 

examined are limited to add-on controls that eliminate SO2 after it is formed, as Flint Creek Unit 

1 currently uses a low sulfur fuel and would not achieve significant additional reductions through 

alternative coal supplies.373 Similarly, the BART analysis provided by Entergy White Bluff 

stated that the SO2 controls evaluated are limited to add-on controls that eliminate SO2 after it is 

formed, as Units 1 and 2 currently use a low sulfur fuel and thus would not achieve significant 

additional reductions through alternative fuel supplies comparable to the most efficient add-on 

 

369 40 C.F.R. Part 51, App. Y, section (IV)(D)(1)(9). 370 See “Revised BART Five Factor Analysis White Bluff Steam Electric Station Redfield, Arkansas (AFIN 35–

00110),” dated October 2013, prepared by Trinity Consultants Inc. in conjunction with Entergy Services Inc. A copy 

of this document is found in the docket for our proposed rulemaking. 

371 See “BART Five Factor Analysis Flint Creek Power Plant Gentry, Arkansas (AFIN 04–00107),” dated 

September 2013, Version 4, prepared by Trinity Consultants Inc. in conjunction with American Electric Power 

Service Corporation for the Southwestern Electric Power Company Flint Creek Power Plant. A copy of this 

document is found in the docket for our proposed rulemaking. 

372 80 FR at 18965 and 18970. 373 See “BART Five Factor Analysis Flint Creek Power Plant Gentry, Arkansas (AFIN 04–00107),” at 5-1, dated 

September 2013, Version 4, prepared by Trinity Consultants Inc. in conjunction with American Electric Power 

Service Corporation for the Southwestern Electric Power Company Flint Creek Power Plant. A copy of this 

document is found in the docket for our rulemaking. 
200 

controls.374 Thus, the use of low sulfur coal is reflected in the baseline scenario for these units. 

Furthermore, while a facility can voluntarily agree to switch to a different type of coal to comply 

with BART requirements, we cannot dictate to facilities which coal they should burn as a control 

measure.375 Therefore, we disagree with the claim that our BART analysis is flawed because it 

did not evaluate DSI or other less stringent controls such as lower sulfur coal. 

We also disagree with the commenter’s application of North Dakota v. EPA, 730 F.3d 750 to our 

proposal. The court in that case found that EPA's refusal to consider the existing pollution 

control technology in use at the Coal Creek Station because it had been voluntarily installed, was 

arbitrary and capricious and our FIP promulgating SNCR as BART for the Coal Creek Station 

was therefore vacated. The vacatur of our BART determination was not, as the commenter 

contends, because we did not consider every retrofit control technology available in the BART 

analysis. 

To the extent the commenter suggests that our Arkansas FIP proposal is inconsistent with our 

Montana FIP action because we did not evaluate low sulfur coal for White Bluff and Flint Creek 

in the Arkansas FIP proposal, we disagree. The commenter makes the allegation that in our 

Regional Haze FIP for Montana, we approved the use of low sulfur coal as SO2 BART for PPL 

Corette even though DSI was determined to cost $991/ton SO2 and found to be cost-effective. 

This is incorrect. In that action, we stated the following: 

We identified that three flue gas desulfurization (FGD or “scrubbing ‘) 

technologies as available control technologies for consideration at Corette. 

Two of these options, dry sorbent injection (DSI) and semi-dry scrubbing 

(sometimes referred to as LSD), are dry scrubbing technologies. The third 

option is a wet scrubbing technology known as limestone forced oxidation 

(LSFO). We did not consider fuel-switching options as Corette already 

burns very low-sulfur coal. 77 FR at 24043. 

In our Montana RH FIP action we did not evaluate the use of low sulfur coal in the SO2 BART 

evaluation for Corette. We evaluated two types of dry scrubbing technologies and a wet 

scrubbing technology. In that action, we found the average cost-effectiveness of DSI at PPL 

Corette to be $3,940/SO2 ton removed and not, as the commenter contends, $991/SO2 ton 

removed.376 We also found LSD to have an average cost-effectiveness of $5,442/SO2 ton 

removed and LSFO to have an average cost-effectiveness of $6,365/SO2 ton removed.377 We 

found that the visibility improvement at the Class I area with the greatest improvement is 

 

374 See “Revised BART Five Factor Analysis White Bluff Steam Electric Station Redfield, Arkansas (AFIN 35–

00110),” at 5-1, dated October 2013, prepared by Trinity Consultants Inc. in conjunction with Entergy Services Inc. 

A copy of this document is found in the docket for our rulemaking.

375 We do note that in this FIP we are making the determination that SO2 and PM BART for AECC Bailey Unit 1 

and AECC McClellan Unit 1 is a limit on the sulfur content of the fuel burned. As the sources currently burn fuel oil 

with a sulfur content greater than 0.5%, compliance with the BART requirement will likely necessitate switching to 

fuel oil with lower sulfur content. However, as discussed in our proposal, our SO2 and PM BART determinations are 

based on a BART analysis provided by AECC Bailey and McClellan in which the sources voluntarily accepted a 

limit on the sulfur content of the fuel burned (see 80 FR at 18950). 376 77 FR at 24044. 377 77 FR at 24045. 
201 

expected to be 0.176 dv for DSI, 0.253 dv for LSD, and 0.256 dv for LSFO.378 We stated in that 

action that we weighed costs against the anticipated visibility impacts at Corette, but found that 

the cost of SO2 controls is not justified by the visibility improvement, and determined that BART 

for SO2 is the existing operation at PPL Corette with an emission limit of 0.70 lb/MMBtu.379 Our 

BART determination was an emission limit of 0.70 lb/MMBtu, which reflects existing 

operations. Our BART determination for Corette was not, as the commenter contends, use of low 

sulfur coal. 

In our Arkansas FIP proposal, for both Flint Creek Unit 1 and White Bluff Units 1 and 2 we 

evaluated a wet scrubbing technology and one type of dry scrubbing technology. We did not 

evaluate DSI for these units, but as discussed above, we believe that our analyses are still in 

accordance with the CAA, the RH rule, and our BART Guidelines. We also note that the SO2

controls we evaluated for Flint Creek Unit 1 and White Bluff Units 1 and 2 were more costeffective (i.e., lower $/ton removed) and are expected to have greater visibility improvement 

compared to the SO2 controls we evaluated for Corette in the Montana FIP proposal, which we 

ultimately determined were not BART. For example, in our Arkansas FIP proposal we found that 

the average cost-effectiveness of NID at Flint Creek Unit 1 was $3,845/SO2 ton removed, and 

that the visibility improvement at the Class I area with the greatest improvement is expected to 

be 0.615 dv.380 As discussed in our final rule and elsewhere in this document, in light of 

comments we received during the comment period, we have revised our initial cost estimate for 

dry scrubbers on White Bluff Units 1 and 2. Based on these revisions, we determined that dry 

scrubbers are estimated to cost $2,565/SO2 ton removed at Unit 1 and that the visibility 

improvement at the Class I area with the greatest improvement expected to be 0.813 dv.381 We 

also determined that dry scrubbers are estimated to cost $2,421/SO2 ton removed at Unit 2 and 

the visibility improvement at the Class I area with the greatest improvement is expected to be 

0.767 dv.382The costs on a dollar per ton removed basis are lower and the projected visibility 

improvement is higher for the controls we evaluated in our Arkansas FIP compared to the SO2

controls we evaluated and determined were not BART for Corette in our Montana FIP action. 

Therefore, we see nothing in our Montana RH FIP that is in contradiction with our Arkansas FIP. 

We disagree that we did not explain how we considered the statutory factors in our BART 

analyses and our reasonable progress analysis. Specifically, the commenter contends that we did 

not explain how we weighed the visibility improvement of controls versus the cost and the other 

statutory factors. This is not true. Our FIP proposal discussed in detail how we considered and 

weighed the statutory factors, and our rationale for determining what control option is BART. In 

particular, we carefully considered whether the visibility improvement expected from controls 

warranted the costs in terms of cost-effectiveness. When considering one control option versus 

the next most stringent option (i.e., wet scrubbers vs. dry scrubbers), we also carefully 

considered whether the additional visibility improvement of the more stringent option warranted 

the additional cost. To the extent the commenter is alleging that we did not explain how we 

weighed the visibility improvement versus the cost because we did not calculate and consider the 

 

378 77 FR at 24046. 379 77 FR at 24047. 380 80 FR at 18966. 381 80 FR 18972. 382 80 FR 18972. 
202 

cost in dollars per deciview improvement ($/dv) in our FIP proposal, we disagree that we are 

required to do this and address this comment elsewhere in this document. 

With regard to the comment claiming that there is uncertainty in the CALPUFF model and 

therefore no reasonable certainty in the visibility improvement of controls, we address this issue 

elsewhere in this document. 

Comment: EPA’s proposed FIP did not evaluate the maximum degree of SO2 emissions 

reduction achievable with a NID scrubber. [Sierra Club et. al. (0171) p. 13-14] Sierra Club et. 

al. stated that while they support EPA’s proposed SO2 BART determination for Flint Creek Unit 

1 as the minimum that BART requires for this plant, a NID scrubber can easily achieve an 

emission rate of 0.04 lbs/MMBtu. We urge EPA to conclude that SO2 BART at Flint Creek 

requires an emission limit of 0.04 lb/MMBtu based on the use of a scrubber. 

Sierra Club et. al stated that under the CAA and applicable regulations, to determine BART, 

EPA must evaluate the highest control efficiency achievable by a particular technology. 42 

U.S.C. § 7491(b)(2)(A) (requiring “best available retrofit technology”) (emphasis added); 40 

C.F.R. Part 51, Appendix Y (“in analyzing the technology you take into account the most 

stringent emission control level that the technology is capable of achieving”); see 76 Fed. Reg. 

64,186, 64,202 (Oct. 17, 2011) (“in identifying all options, you must identify the most stringent 

option (i.e., maximum level of control each technology is capable of achieving) as well a 

reasonable set of options for analysis.”); see also 64 Fed. Reg. 35,714, 35,740 (July 1, 1999) (“In 

establishing source specific BART emission limits, the State should identify the maximum level 

of emission reduction that has been achieved in other recent retrofits at existing sources in the 

source category.”). As demonstrated in the attached Stamper Report, AEP’s analysis (relied on 

by EPA) fails to consider the highest control efficiency of a NID scrubber. Several sources of 

information demonstrate that EPA has not based its BART determination on the highest control 

efficiency for this technology, including: industry experience and vendor guarantees that indicate 

that NID scrubbers can achieve lower emission limits than .06 lb/MMBtu; AEP’s own 

discussions with vendors and its representations to the Arkansas Public Service Commission 

(“APSC”); and flaws in AEP’s calculations of baseline SO2 emissions that distort the achievable 

emission limit of this technology. 

First, actual performance and vendor guarantees indicated that a NID scrubber can achieve a 

control efficiency of greater than 95%. Stamper Report at 8-9. Flint Creek could achieve a 0.04 

lb/MMBtu limit, which reflects 91% control from recent 30-day average SO2 emission rates at 

Flint Creek and 94.8% SO2 removal from the maximum annual average SO2 rate that occurred 

during 2001. Id. at 13. According to EPA, AEP’s “discussions with vendors” indicated an outlet 

achievable SO2 emission rate of 0.06 lb/MMBtu with NID technology, which reflects 92% SO2

removal from 0.75 lb/MMBtu, the baseline emission rate assumed by AEP. See 80 Fed. Reg. at 

18,965. This statement is belied by data from other EGUs. For example, Sargent & Lundy 

reports that vendors have guaranteed an emission limit of 0.04 lb/MMBtu limit for circulating 

dry scrubbers, such as a NID scrubber. Id. at 9. Thus, a circulating dry scrubber such as a NID 

system at Flint Creek could readily achieve a 0.04 lb/MMBtu SO2 limit. Id. at 6-9. 
203 

Second, a lower limit is supported by the fact that AEP represented to the APSC that NID 

technology can attain 98% removal: 

[NID technology] can attain higher levels of SO2 reduction, with vendor 

guarantee removal rates of 98% compared to maximum removal rates of 

95% for [spray dryer absorbers] and other [dry FGD] technologies....The 

[dry FGD] system that is proposed for installation at Flint Creek will 

remove 95% of the SO2 in the flue gas to meet anticipated emission limits 

for the design basis fuel.383

Moreover, AEP’s assumed SO2 emission limit is inconsistent with its vendor’s guarantee that the 

NID scrubber would meet a limit of 0.055 lb/MMBtu. Stamper Report at 8. Since such a 

guarantee is likely based on a short-term stack test, rather than a 30-day rolling average, the 

technology could likely achieve a lower limit over a longer-term period. Id. 

Finally, flaws in calculating baseline SO2 emissions distort the achievable emission limit of this 

technology. AEP assumed an uncontrolled emission rate of 0.75 lb/MMBtu using data likely 

from 2001 to 2003. See Stamper Report at 8 (noting that AEP likely used 2001-2003 as the 

baseline period). But the maximum 30-day average SO2 limit from January 2012 to December 

2014 has been much lower: 0.48 lb/MMBtu. Id. EPA should use this more-recent data, 

presumably reflective of the use of a lower sulfur coal, in assessing the control efficiency of this 

technology as the more-recent data better reflects anticipated Flint Creek SO2 emissions. See 40 

C.F.R. Part 51, App. Y, § IV.D.4.c. Using this revised baseline, a NID scrubber at Flint Creek 

would have to achieve a 91% removal efficiency to meet an emission limit of 0.04 lb/MMBtu. 

Stamper Report at 9. Installation of NID technology at Flint Creek could easily achieve such 

removal efficiency. Accordingly, EPA should revise its Flint Creek BART analysis to include an 

emission limit of 0.04 lb/MMBtu based on installation of a NID scrubber. 

Response: We agree with the commenter that the Regional Haze rule requires that in 

establishing source specific BART emission limits, the State (or EPA in a FIP) should identify 

the maximum level of emission reduction that has been achieved in other recent retrofits at 

existing sources in the source category.384 The BART Guidelines also provide that in analyzing 

the control technology available, the most stringent control level that the technology is capable 

of achieving should be considered.385 

We acknowledge the information provided in the comment as well as in the referenced 

attachments regarding the level of control efficiency that has been demonstrated and guaranteed 

by vendors for NID installation at other EGUs. We acknowledge that the lowest SO2 emission 

guarantees for a NID system are 0.04 lb/MMBtu. The comment cites to proposed NIDs at Homer 

City 1 & 2 (2016), Indian River Unit 4 (2011), Brayton Point Unit 3 (2013), and (Clay) Boswell 

 

383 See February 8, 2012 Direct Testimony of Christian T. Beam on behalf of Southwestern Electric Power 

Company, In the Matter of Southwestern Electric Power Company’s Petition for a Declaratory Order Finding that 

Installation of Environmental Controls at the Flint Creek Power Plant is in the Public Interest, Before the Arkansas 

Public Service Commission, Docket 12-008-U, at 22 (Ex. 11 to Stamper Report). 

384 64 FR at 35740. 385 40 C.F.R. Part 51, App. Y § (IV)(D)(3)(3). 
204 

Unit 4 (2016). We researched each one of these facilities and learned that only Indian River Unit 

4 and Brayton Point Unit 3 are currently operating. We downloaded the SO2 CEMS data for 

these two facilities from CAMD, computed 30-day BOD averages, achieved SO2 control 

efficiencies, and determined the maximum 30-day BODs. This analysis is present in our final 

docket.386 Neither of these units is performing at a level of 98% SO2 control or 0.04 lb/MMBtu. 

Indian River Unit 4 has achieved only 86% SO2 removal based on a design level of 96%, rather 

than 98%.387 The maximum 30-day BOD is 0.94 lb/MMBtu and the lowest 30-day BOD, 

representing its best performance, is 0.07 lb/MMBtu. Brayton Point Unit 3 has achieved 94% 

SO2 removal and the maximum 30-day BOD is 0.16 lb/MMBtu. Brayton Point Unit 3 is 

scheduled for shutdown in 2017.388 Thus, the limited available SO2 CEMs data for these two 

NIDs indicate that they are not yet achieving the theoretical 98% level of control. 

The other NIDs cited in this comment are “polishing” scrubbers on circulating fluidized bed 

boilers, which are not similar boiler types. As explained by the Guidance, similar sources with 

the control technology already in place should be used to evaluate what level of control can be 

achieved at the source. Further, Flint Creek Unit 1 burns low sulfur western coal, and none of the 

units cited by the commenter burn this type of coal. Seward burns high sulfur waste coal; Gilbert 

Unit 3 burns high sulfur bituminous coal; and Spurlock Unit 4 burns high sulfur bituminous coal 

and switchgrass.389 The Guidance provides us with the discretion to consider “special 

circumstances pertinent to the specific source under review.” In this case, we must consider the 

different coals being utilized by each respective unit in determining what emission limit is 

achievable. As the coal used in the units mentioned by the commenter differs from the coal used 

in the unit at Flint Creek, it would be inequitable to compare these units. 

We agree that, in some cases, NID systems may be capable of achieving a lower emission rate 

than that assumed in the AEP Flint Creek analysis. However, when the sulfur content of the coal 

is low, a lower control efficiency is anticipated. Due to the low sulfur content of the coal burned 

at Flint Creek Unit 1, it is uncertain whether the high control efficiencies cited by the commenter 

could be achieved. There is no information available to us demonstrating that NID installation at 

Flint Creek Unit 1 can consistently achieve an emission level of 0.04 lb/MMBtu. As noted by the 

commenter, the vendor’s performance guarantee for NID installation at Flint Creek Unit 1 is an 

average emission rate of less than or equal to 0.055 lb/MMBtu. The commenter is correct that 

only one page from the Alstom proposal that includes the vendor’s performance guarantee was 

included in the docket because this is what was provided to us by AEP. However, based on 

discussions with AEP, the vendor’s performance guarantee was based on a 30-day rolling 

average. As such, the BART analysis provided by AEP Flint Creek states that discussions with 

vendors have indicated that an outlet emission rate of 0.06 lb/MMBtu at Flint Creek will be 

 

386 See “Selected NID BOD SO2 Averages.xlsx,” found in the docket for our rulemaking. 387 Burns & McDonnell, Indian River Unit 4, http://www.burnsmcd.com/Resource_/Project/1302/ProjectPdf/IndianRiver-Unit-4.pdf. 

388 Dorothy Davis Ballard, Brayton Point Coal-Fired Power Plant Confirmed for Shut Dow by 2017, Power, January 

29, 2014, http://www.pennenergy.com/articles/pennenergy/2014/01/brayton-point-coal-fired-power-plantconfirmed-for-shut-down-by-2017.html. 

389 http://www.ekpc.coop/pressreleases/2009%20press%20releases/2009-04-01_Spurlock4_commercial_start.pdf 
205 

achievable with the NID technology evaluated,390 and the company’s BART analysis assumed 

this emission rate. Since BART emission limits, which apply at all times (including during 

startup and shutdown), must allow an adequate margin for compliance, we believe that it is 

appropriate for the BART analysis to assume an SO2 emission rate of 0.06 lb/MMBtu for NID. 

There is no information available to us to substantiate that an emission rate of 0.04 lb/MMBtu 

can be consistently achieved at Flint Creek Unit 1. Therefore, we continue to believe that an 

emission limit of 0.06 lb/MMBtu on a 30-boiler operating-day rolling average is reasonable for 

NID at Flint Creek Unit 1. 

Regarding the testimony presented by AEP to the Arkansas Public Service Commission 

indicating that NID can attain 98% removal of SO2 emissions, AEP communicated to us that the 

testimony before the Arkansas Public Service Commission discusses the maximum design 

capability based on the “design basis fuel” (i.e., potential emissions) whereas the BART analysis 

is based on the actual average baseline emission rate and projected unit performance.391 AEP 

also explained that the outlet emission rate evaluated in the BART analysis was based on the 

vendor’s performance guarantee, which was quoted as an outlet rate (i.e., 0.06 lb/MMBtu) rather 

than a percent control efficiency.392 For all the reasons discussed above, even if we were to 

revise the baseline to be 2012-2014 instead of 2001-2003, as the commenter suggests, we still do 

not know with certainty whether NID installation on Flint Creek Unit 1 would be able to 

consistently achieve an emission level of 0.04 lb/MMBtu. We continue to believe that an 

emission limit of 0.06 lb/MMBtu on a 30-boiler operating-day rolling average is reasonable and 

appropriate for NID at Flint Creek Unit 1. 

Comment: EPA’s proposal did not evaluate the maximum degree of emissions reductions 

achievable with NOX controls at AEP Flint Creek Unit 1. [Sierra Club et. al. (0171) p. 15-16] 

Sierra Club et. al. stated that EPA proposes that NOX BART for Flint Creek Unit 1 is an 

emission limitation based on the installation of LNB/OFA. Such controls would cost-effectively 

achieve some emissions reductions and, as such, represent the minimum that EPA must require, 

as shown by EPA and confirmed by the Stamper Report. LNB/OFA does not, however, represent 

“the application of the best system of continuous emission reduction” as required by BART. 

Instead, as Ms. Stamper’s report shows, SCR is a cost-effective control that fully satisfies all of 

the BART requirements. The Stamper Report discusses several ways in which EPA and AEP 

underestimated the removal efficiency of SNCRs and SCRs and thus underestimated the cost 

effectiveness of these technologies. Stamper Report at 15-27. Ms. Stamper’s analysis shows that 

these controls are even more efficient at NOX removal than EPA assumed because: EPA failed to 

appropriately consider a control scenario that included SCR or SNCR with LNB/OFA; SCR can 

achieve a greater than 90% control efficiency; SCR can achieve much higher removal efficiency 

in practice; and AEP’s vendor guarantees are inconsistent with EPA’s assumed removal rates. 

 

390 “BART Five Factor Analysis Flint Creek Power Plant Gentry, Arkansas (AFIN 04–00107),” dated September 

2013, Version 4, prepared by Trinity Consultants Inc. in conjunction with American Electric Power Service 

Corporation for the Southwestern Electric Power Company Flint Creek Power Plant. A copy of the BART analysis 

is found in the docket for our proposed rulemaking. 

391 See document titled “March 4, 2013 email from AEP,” found in the docket for our proposed rulemaking. 392 Id. 
206 

AEP underestimated the cost-effectiveness of LNB/OFA plus SCR because AEP underestimated 

the NOX reductions achievable by these technologies. AEP analyzed SCR control efficiency 

alone (without LNB/OFA) to meet a NOX limit of 0.07 lb/MMBtu. This reflects 77% NOX

removal efficiency from AEP’s assumed 0.31 lb/MMBtu baseline NOX emission rate. The 

assumed 0.07 lb/MMBtu NOX emission limit does not reflect the maximum degree of NOX

reduction achievable with this technology. Stamper Report at 16. 

First, EPA’s analysis for both SCR and SNCR should have begun with the assumed NOX control 

rate achieved by LNB/OFA of .23 lb/MMBtu. Stamper Report at 15, 23. AEP could install SCR 

or SNCR concurrently with LNB/OFA and the combination of these controlsimproves their cost 

effectiveness. AEP’s analysis of SNCR and SCR must be revised to account for the control rate 

achieved by LNB/OFA. 

Second, AEP’s analysis, which EPA relied on, fails to account for the maximum control 

efficiency achievable by SCR. SCR is routinely designed to achieve greater than 90% control 

and all major SCR catalyst vendors can guarantee at least 90% efficiency for SCRs burning coals 

with a wide range of properties, including from low sulfur Powder River Basin (“PRB”) 

subbituminous coal. Stamper Report at 16-19. Further, permitting agencies have required lower 

NOX limits than the 0.07 lb/MMBtu based on operation of SCR. For example, the Plant 

Washington PSD permit requires a 0.05 lb/MMBtu on a 30-day rolling average basis, while the 

PSD permit for the Desert Rock power plant requires a 0.05 lb/MMBtu limit over a rolling 365- 

day period during a 60-month “Optimization Period.” Id. at 19. In the New Mexico regional haze 

FIP, EPA determined that SCR was the “most cost-effective pollution control” and imposed a 

NOX BART emission limit of 0.05 lb/MMBtu on a 30 boiler-operating-day average basis for the 

San Juan Generating Station. Id. at 19. 

Third, in practice, many other EGUs with SCRs have achieved emission rates of 0.05 

lb/MMBtu or lower. In its response to comments document for its NOX BART finding for the 

San Juan Generating Station, EPA found significant support in actual emissions data to support 

its finding that a 0.05 lb/MMBtu NOX limit was achievable on a 30-boiler operating day average 

basis, including a study that identified 25 units that are achieving NOX emission rates lower than 

0.05 lb/MMBtu on an hourly basis. Id. Ms. Stamper’s report cites several plants that have 

achieved rate lower than 0.05 lb/MMBtu: Seminole Units 1 and 2 (achieving 0.04 lb/MMBtu), 

Morgantown Units 1 and 2 (achieving 0.043 to 0.054 lb/MMBtu), Trimble Unit 1 (achieving 

0.032 lb/MMBtu), Cope Generating Station (achieving 0.032 lb/MMBtu), as well as the 

Mountaineer plant, Cliffside Unit 5, Havana Unit 9, Parish Unit 7, and Parish Unit 8. Id. at 20- 

21. 

Thus, AEP’s evaluation of SCR to meet an emission rate of 0.07 lb/MMBtu at Flint Creek, 

which reflects only 77% NOX removal across the SCR system, is inconsistent with the higher 

levels of NOX removal guaranteed by vendors, required by permits, and achieved in practice in 

the industry. SCR plus LNB/OFA should be able to readily achieve a 0.04 lb/MMBtu emission 

limit on a 30-day average basis at Flint Creek. This reflects an 87% removal efficiency from 

2001-2003 maximum 30-day average rates, and it represents 83% NOX control from the 0.23 

lb/MMBtu emission rate expected with the LNB/OFA. Id. at 23. 
207 

Response: We disagree with Sierra Club’s position that BART controls must be selected solely 

based on which are the “best system of control.” This viewpoint disregards the fact that the 

regulations require that the State, and the EPA in the case of a FIP, consider the following five 

factors in determining what controls are appropriate: cost, energy and nonair quality 

environmental impacts, pollution controls in use at the source, remaining useful life, and 

visibility improvement.393 The “best system of continuous emission reduction” can only be 

determined once these factors are considered.

Sierra Club and Ms. Stamper also state that AEP overestimated the cost of SNCR and SCR 

because the analysis should have begun with the assumed NOX control rate of 0.23 lb/MMBtu, 

achieved by the first-in-line LNB/OFA controls, which would result in a lesser loading to the 

SNCR and SCR systems and reduce their operating costs. Instead, the analysis for SNCR was 

based on a reduction from 0.31 lb/MMBtu to 0.2 lb/MMBtu and the analysis for SCR was based 

on a reduction from 0.31 lb/MMBtu to 0.07 lb/MMBtu. We agree with the Sierra Club and Ms. 

Stamper on this point. For SNCR controls on Flint Creek, we have corrected this error. As 

discussed in the section of this document where we discuss cost issues, we have also corrected 

the error in AEP SWEPCO’s assumed 20 year equipment life for SNCR. The following table 

provides AEP SWEPCO’s SNCR cost analysis with another column added to include these 

corrections: 

Parameters/Costs Equation AEP SWEPCO EPA

Boiler design capacity, mmBtu/hr 

(QB) 

QB 6324 6324 

Total operating time (top, hrs/yr) top = CFtotal × 8760 hrs/yr 7752 7752 

Total Capacity Factor (CFtotal) CFtotal = CFplant × CFSNCR 0.92 0.92 

Plant Capacity Factor (CFplant)

2

 0.92 0.92 

SNCR Capacity Factor (CFSCNR)

3

 CFSNCR = tSNCR/365 1 1 

Assumed NOx removal efficiency 

(ηNOx)

4

 35% 13.04% 

Uncontrolled NOx rate (NOxin,

lb/MMBtu)5

 0.33 0.23 

Electricity Cost (Costelect, $/kwh)6 $0.05 $0.05 

Water Cost (Costwater, $/gal)7 $0.00362 $0.00362 

Coal Cost (Costcoal, $/MMBtu)8 $2.50 $2.50 

Coal HHV (Btu/lb)9 9,000 9,000 

Cost of Ash Disposal (Cash, $/ton)10 $9.0 $9.0 

Capital recovery factor (CRF) CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where 

I = interest rate, a = equipment life 

0.0944 0.0806 

 a. Equipment CRF, 20-yr life, 7% 

interest 

 

Cost Index11 

a. 2011 Cost Index 585 

b. 1998 Cost Index 389.5 

 

393 Summarized from Section 51.308(e)(1)(ii)(A). 
208 

Capital Costs 

Direct Capital Cost (A) DC ($) = ($950/MMBtu) × QB × ((2375 

MMBtu/hr/QB)^0.577) × (0.66 + 

0.85ηNOx) × (CI2011/CI1998) 

$5,007,199 $4,031,069 

Indirect Installation Costs ($) 

General Facilities 0.05 × A $250,360 $201,553 

Engineering and Home Office Fees 0.10 × A $500,720 $403,107 

Process Contingency 0.05 × A $250,360 $201,553 

Total Indirect Installation Costs (B) = General Facilities Cost + Engineering 

and Home Office Fees + Process 

Contingency 

$1,001,440 $806,214 

Other Installation Costs ($) 

Project Contingency (C) C = 0.15 × (A + B) $901,296 $725,592.50 

Total Plant Cost (D) D = A + B + C $6,909,934 $5,562,876 

Allowance for Funds During 

Construction (E) 

E = 0 (Assumed for SNCR) $0 $0 

Royalty Allowance (F) F = 0 (Assumed for SNCR) $0 $0 

Preproduction Cost (G) G = 0.02 × (D + E) $138,199 $111,258 

Inventory Capital (H)12 H = Volreagent (gal) × Costreagent ($/gal) $76,102 $8,957 

Costreag, 50% Urea solution 

($/gal)13

 1.54 1.54 

Volume of Reagent Tank (Volreagent

(gal)) 

Volreagent (gal) = qsol x days of reagent 

supply × 24 hr/day 

49,417 5,817 

Urea solution volumetric flow rate 

(qsol, gal/hr)14

qsol = (msol x 7.481 gal/ft3

)/ρreagent 147.07 17.31 

Mass flow rate of urea solution 

(msol, lb/hr)15

msol = mreagent/Cureasol 1,395.84 164.30 

Mass flow rate of reagent (mreagent, 

lb/hr)16

mreagent = (NOxin x QB x ηNOx × NSR x 

Mreagent)/(MNOx x SRT) 

697.92 82.15 

Normalized Stoichiometric Ratio 

(NSR) 

NSR = ([2 × NOxin + 0.7] × ηNOx)/NOxin 1.43 0.66 

Initial Catalyst and Chemicals (I) I = 0 (Assumed for SNCR due to no 

catalyst) 

$0 $0 

Total Capital Investment (TCI) 

(Capital Cost) 

TCI = D + E + F + G + H + I $7,124,235 $5,683,091 

Annual Costs ($) 

Annual Maintenance Cost (J) J = 0.015 × TCI $106,864 $85,246 

Annual Reagent Cost (K) K = qsol × Costreag × top $1,755,781 $206,662 

Annual Electricity Cost (L) L = P × Costelect × top $58,064 $18,344 

Power (P, kW) P = (0.47 × NOxin × NSR × QB)/9.5 149.80 47.33 

Annual Water Cost (M) M = qwater × Costwater × top $18,775 $2,210 

Water flowrate for SNCR system 

(qwater, gal/hr)17

qwater = (msol/ρwater) × 

[(Cureasolstored/Cureasolinj) - 1] 

669.06 78.75 

Annual ΔCoal Cost (N) N = ΔCoal × Costcoal × top $109,558 $12,895 

Additional coal required (ΔCoal, 

MMBtu/hr)18

ΔCoal = (Hv × mreagent × [(1/Cureasolinj) - 

1])/106 Btu/MMBtu 

5.65 0.67 

Annual ΔAsh Cost (O) O = (ΔAsh × Costash × top)/2000 lb/ton $1,643 $193 

Additional ash generated (ΔAsh , 

lb/hr)19

ΔAsh = (ΔCoal × ashproduct × 106

Btu/MMBtu)/HHV 

47.11 5.54 

Direct Annual Costs 

(DAC)/Variable O&M 

DAC = J + K + L + M + N + O $2,050,684 $325,551 
209 

Indirect Annual Costs 

(IDAC)/Annualized Capital Cost 

IDAC = CFR × TCI $672,477 $457,980 

Total Annualized Costs (TAC) TAC = DAC + IDAC $2,723,162 $783,531 

TAC = DAC + IDAC $2,723,162 

Note in the above table, we have added another column with our corrections to (1) the assumed 

NOX removal efficiency (ηNOX), (2) the uncontrolled NOX rate (NOxin, lb/MMBtu), and (3) a 

recalculation of the capital recovery factor (CRF), corresponding to a 30 year life. The resulting 

annualized cost drops from $2,723,162 to $783,531. 

We have also recalculated AEP SWEPCO’s cost-effectiveness calculation.394 Below is AEP 

SWEPCO’s cost-effectiveness calculation as presented in its BART analysis,395 along with our 

corrections. The first table is AEP SWEPCO’s cost-effectiveness calculation. In the second table, 

we make corrections to errors in both AEP SWEPCO’s summing of the total annual costs, and in 

the tons reduced calculations. In the third table, we carry those corrections forward, and 

incorporate the corrections to the SNCR cost analysis we discuss above. 

 

394 See the file, AR020-0037-02_Consolidated_Spreadsheet_2013-09-09-EPA.xlsx. 395 Bart Five Factor Analysis, Flint Creek Power Plant, September 2013, Version 4. Table 6-3. 
210 

AEP SWEPCO 

Control Technology 

Baseline 

NOX

Emission 

Rate (tpy) 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Controlled 

Emission Rate

(NOX tpy) 

Annual 

Emissions 

Reductions 

(NOX tpy) 

Capital Cost 

($) 

Annual Capital 

Cost ($.yr) 

Annual 

Fixed 

O&M 

($/yr) 

Annualized 

Variable 

O&M ($/yr) 

Tota

Annu

Cost ($/

LNB/OFA 5,120.27 0.23 4,294.65 825.62 $16,000,000 $1,289,382 $240,000 $132,364 $1,454LNB/OFA/SNCR 5,120.27 0.20 3,771.82 1,348.45 $16,000,147 $1,398,940 $240,000 $133,033 $4,177

AEP SWEPCO (tons reduced and total annl cost corrected) 

Control Technology 

Baseline 

NOX

Emission 

Rate (tpy) 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Controlled 

Emission Rate

(NOX tpy) 

Annual 

Emissions 

Reductions 

(NOX tpy) 

Capital Cost 

($) 

Annual Capital 

Cost ($.yr) 

Annual 

Fixed 

O&M 

($/yr) 

Annualized 

Variable 

O&M ($/yr) 

Tota

Annu

Cost ($/

LNB/OFA 5,120.27 0.23 3,798.91 1,321.36 $16,000,000 $1,289,382 $240,000 $132,364 $1,661LNB/OFA/SNCR 5,120.27 0.20 3,303.40 1,816.87 $23,124,235 $1,961,859 $240,000 $2,183,048 $4,384

EPA (tons reduced, total annl costs, control level and control efficiency corrected) 

Control Technology 

Baseline 

NOX

Emission 

Rate (tpy) 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Controlled 

Emission Rate

(NOX tpy) 

Annual 

Emissions 

Reductions 

(NOX tpy) 

Capital Cost 

($) 

Annual Capital 

Cost ($.yr) 

Annual 

Fixed 

O&M 

($/yr) 

Annualized 

Variable 

O&M ($/yr) 

Tota

Annu

Cost ($/

LNB/OFA 5,120.27 0.23 3,798.91 1,321.36 $16,000,000 $1,289,382 $240,000 $132,364 $1,661LNB/OFA/SNCR 5,120.27 0.20 3,303.40 1,816.87 $21,683,091 $1,747,362 $240,000 $457,915 $2,445
211

As can be seen from the third table above, we calculate that SNCR + LNB/OFA has a revised 

cost-effectiveness of $1,346/ton, as opposed to cost effectiveness of $1,258/ton for LNB/OFA 

alone. Also, we calculated that the incremental cost effectiveness of SNCR + LNB/OFA over 

LNB/OFA alone is $1,581/ton. We re-apply the BART five factors, with emphasis on cost and 

visibility improvement. We conclude that despite the improvement in the cost-effectiveness of 

SNCR + LNB/OFA over LNB/OFA alone, the resulting relatively small visibility improvement 

is not worth the cost. 

As for SCR, we note Ms. Stamper’s separate SCR cost analysis, which we address in the cost 

section of this document. In Ms. Stamper’s SCR cost analysis, she assumes a NOX control level 

of 0.04 lbs/MMBtu, using the IPM SCR cost algorithms. Ms. Stamper makes a case that because 

her resulting $/ton figures are in line with other required SCR installations, the Flint Creek 

facility should similarly be required to install SCR. First, as we discuss in our response to 

another comment concerning the White Bluff facility, we do not believe that Ms. Stamper has 

demonstrated that her assumed level of control has been maintained on a 30 day BOD average at 

other similar facilities, such that it can be applied to the Flint Creek facility. However, we have 

reviewed the information Ms. Stamper presents and conclude, as we did in our New Mexico FIP, 

that it supports a 30 Boiler Operating Day (BOD) NOX average of 0.05 lbs/MMBtu for a SCR 

installation at the Flint Creek facility. 

Second, as we indicate in Table 44 of our TSD and Ms. Stamper notes in her report, the 

maximum visibility improvement due to SCR at Flint Creek was 0.245 dv, which occurred at 

Caney Creek. We further note that AEP SWEPCO’s SCR cost analysis is almost completely 

undocumented. However, due to the relatively low visibility incremental improvement expected 

from SCR compared to SNCR, cost was not the only factor in our decision making. For instance, 

if we make reasonable, conservative adjustments to the anticipated visibility benefit, based on a 

control level of 0.055 lbs/MMBtu rather than the modeled rate of 0.067 lbs/MMBtu396, we 

estimate that the resulting visibility improvement at Caney Creek would be no higher than 0.26 

dv.397 Even accepting Ms. Stamper’s SCR cost analysis of $3,511/ton (which would be higher 

were it revised using a controlled NOX rate of 0.05 lbs/MMBtu), we do not consider the 

relatively small visibility improvement to be worth the cost of the SCR installation. 

Therefore, we are requiring Flint Creek Unit 1 to meet an emission limit of 0.23 lb/MMBtu on a 

30 boiler-operating-day rolling average based on LNB/OFA to comply with the NOX BART 

requirement. 

Comment: EPA’s proposal did not evaluate the maximum control level achievable with dry 

scrubbers at White Bluff Units 1 and 2. [Sierra Club et. al. (0171) p. 21] Sierra Club et. al. 

stated that EPA proposed that SO2 BART for White Bluff Units 1 and 2 is an emission limitation 

 

396 Modeled emission rates were based on a maximum heat input of 6324 MMBtu/hr multiplied by the anticipated 

control rate (e.g. 0.067 lb/MMBtu) Baseline emissions determined from 2001-2003 CAMD data were 1945 lb/hr, 

approximately 0.308 lb/MMbtu. 

397 Modeled visibility benefit at CACR over baseline from SCR at 0.067 lb/MMbtu was 0.245 dv. SCR at 0.055 

lb/MMBtu would result in an additional reduction in emissions from baseline of only 4%. Assuming a linear 

relationship between emission and visibility impacts, this would also result in an increase in visibility benefit of only 

4%. 
212

of 0.06 lb/MMBtu on a 30-day rolling average based on the operation of a dry scrubber or 

another technology. 80 Fed. Reg. at 18,972-73. Entergy’s SO2 BART analysis for White Bluff 

evaluated the control efficiencies of wet and dry scrubbers. Entergy did not consider a NID 

technology dry scrubber. As demonstrated in Section I.A.1.b of the Sierra Club’s comments, 

both wet and dry scrubbers (including circulating dry scrubbers such as NID technology) can 

achieve SO2 removal levels in the 95-99% range. Entergy should have evaluated a dry scrubber, 

such as NID scrubber, as an SO2 BART option at White Bluff with an emission limit of 0.04 

lb/MMBtu. Such an emission limit is readily achievable with this technology. Ms. Stamper’s cost 

analysis assumes a more-appropriate .04 lb/MMBtu limit for dry scrubbers, including a NID 

scrubber. 

Response: We agree that the Alstom NID circulating dry scrubber is a promising SO2 control 

option. However, as we discuss elsewhere in this document, the limited available SO2 CEMs 

data for NID system installations indicate that they are not yet achieving the same performance 

as a conventional wet scrubber (i.e., 0.04 lb/MMBtu) that was evaluated for White Bluff Units 1 

and 2. Therefore, we believe it would be reasonable to assume that NID can consistently achieve 

an SO2 emission limit of 0.06 lb/MMBtu, but not 0.04 lb/MMBtu. We also believe it was 

appropriate to evaluate in the BART analysis an emission limit of 0.04 lb/MMBtu for wet FGD 

and 0.06 lb/MMBtu for semi-dry scrubbers. The BART Guidelines provide the following: 

A possible outcome of the BART procedures discussed in these guidelines 

is the evaluation of multiple control technology alternatives which result 

in essentially equivalent emissions. It is not our intent to encourage 

evaluation of unnecessarily large numbers of control alternatives for every 

emissions unit. Consequently, you should use judgment in deciding on 

those alternatives for which you will conduct the detailed impacts analysis 

(Step 4 below). For example, if two or more control techniques result in 

control levels that are essentially identical, considering the uncertainties of 

emissions factors and other parameters pertinent to estimating 

performance, you may evaluate only the less costly of these options. You 

should narrow the scope of the BART analysis in this way only if there is 

a negligible difference in emissions and energy and non-air quality 

environmental impacts between control alternatives.398 

As the BART analysis for White Bluff Units 1 and 2 evaluates semi-dry scrubbers and assumes a 

control efficiency of 0.06 lb/MMBtu, which is the same level of control we expect can be 

consistently achieved with NID, we disagree that it is necessary to also evaluate NID for White 

Bluff Units 1 and 2. 

We also note that as NID technology is theoretically capable of achieving the same or better SO2

control efficiency as the SO2 controls that we evaluated, White Bluff is free to choose NID or 

any other technology to satisfy its emission limits. Thus, if the NID is as claimed in this 

comment — low capital investment and maintenance costs, low power consumption, and high 

removal of hazardous pollutants for about the same cost— the plant owner may choose to select 

 

398 40 C.F.R. Part 51, App. Y § (IV)(D)(2). 
213

the NID to satisfy its emission limits. Thus, including NID in our evaluation would not have 

changed our proposed SO2 emission limits. We further address the emissions limit achievable 

through the use of NID scrubbers elsewhere in this document. 

Comment: EPA’s proposal did not evaluate the maximum degree of NOX emissions 

reductions achievable with LNB/SOFA plus SCR at White Bluff Units 1 and 2. [Sierra Club 

et. al. (0171) p. 23, 25] Sierra Club et. al. stated that EPA proposed that NOX BART for White 

Bluffs Units 1 and 2 is an emission limitation of 0.15 lb/MMBtu based on the installation of 

LNB and separated overfire air (“SOFA”). 80 Fed. Reg. at 18974. Ms. Stamper’s Report shows 

that when the appropriate degree of emission reductions is evaluated, SCR is BART for White 

Bluff. Entergy assumed that installation of SCR along with LNB/SOFA at White Bluff Units 1 

and 2 could achieve an emission rate of 0.055 lb/MMBtu. Stamper Report at 35. A NOX limit of 

0.055 lb/MMBtu reflects a 63% NOX removal with SCR, with the LNB/SOFA alone achieving a 

NOX limit of 0.15 lb/MMBtu. Id. at 40. This assumption (which EPA relied on) unlawfully fails 

to reflect the maximum degree of NOX emissions reductions achievable with this control 

scenario. See 42 U.S.C. § 7491(b)(2)(A) (requiring “best available retrofit technology”) 

(emphasis added). 

As demonstrated in Section I.A.2.a of the Sierra Club et. al.’s comments, SCR systems are 

routinely designed, with vendor guarantees, to achieve greater than 90% NOX removal. An 

emission limit of 0.04 lb/MMBtu at the White Bluff units, which reflects 73% removal from the 

0.15 lb/MMBtu NOX rate achieved with the LNB/SOFA alone, is easily achievable by pairing an 

SCR with LNB and SOFA. Stamper Report at 39-40. 

Entergy’s air dispersion modeling (which EPA relied on) underestimated the visibility benefits 

from LNB/SOFA plus SCR at White Bluff for two reasons. First, Entergy modeled the visibility 

benefits of LNB/SOFA at an emission limit of 0.15 lb/MMBtu and of LNB/SOFA plus SCR at 

an emission limit of 0.055 lb/MMBtu. These modeled visibility benefits underestimate the true 

benefits to visibility because, as noted elsewhere in the Sierra Club et. al.’s comments, Entergy 

relied on the 2009-2011 NOX baseline which reflected the period of lowest NOX emission rates 

at White Bluff Units 1 and 2. Second, Entergy failed to evaluate LNB/SOFA plus SCR at an 

emission limit of 0.04 lb/MMBtu, which is readily achievable with these controls. Accordingly, 

EPA should re-model the visibility benefits of these controls using more appropriate emissions 

reflective of baseline and post-control emissions. 

Response: As we discuss in the section of this document where we discuss cost issues, we have 

reviewed the information Ms. Stamper presents regarding the level of control that can be 

achieved with LNB/SOFA + SCR and conclude that it supports a 30 Boiler Operating Day 

(BOD) NOX average of 0.05 lbs/MMBtu for a SCR installation at the White Bluff facility. We 

disagree with Ms. Stamper that it supports a 30 BOD average of 0.04 lbs/MMBtu, as she 

contends. We see no evidence of an SCR operating at that level for extended periods of time, 

such that we would feel comfortable that a 30 BOD average of 0.04 lbs/MMBtu would be 

sustainable at the White Bluff facility absent site-specific engineering information. Although in 

our proposal we made corrections to Entergy’s NOX BART cost analyses, we did not criticize its 

choice of a SCR NOX emission limit of 0.055 lbs/MMBtu. Entergy’s SCR NOX emission rate of 
214

0.055 lbs/MMBtu was based on “permitted emission compliance”399 which for this type of rate is 

generally based on 30 day calendar compliance period. Entergy confirms this on page 6-3 of its 

BART analysis.400 Our New Mexico FIP decision to which Ms. Stamper cites, is based on a 30 

BOD compliance period. As we discuss in our New Mexico FIP, “[Use of a] BOD would ensure 

that, when an outage occurs, the emissions following startup will be averaged with the emissions 

data from before the outage, rather than with the period of time during which the unit did not 

have any emissions at all because it was offline.”401 In other words, a 30 BOD averaging period 

is in effect less stringent that a straight 30 calendar averaging period because it doesn’t 

overweigh emissions spikes as a 30 calendar day average can do during an extended outage. As a 

consequence, we considered Entergy’s 0.055 lb/MMBtu average to be essentially equivalent to, 

or potentially more stringent than the 0.05 lb/MMBtu 30 BOD average we required in our New 

Mexico FIP, which forms the bulk of Ms. Stamper’s support. Thus we (1) disagree with Ms. 

Stamper that SCR for White Bluff should be evaluated on the basis of a NOX rate of 0.04 

lbs/MMBtu, and (2) we believe Entergy’s use of a 30 day calendar NOX rate of 0.055 lb/MMBtu 

in its evaluation of SCR was reasonable (although as discussed elsewhere, we had other issues 

with Entergy’s White Bluff BART analyses). This renders moot Ms. Stamper’s contention that 

Entergy’s air dispersion modeling (which we relied on) underestimated the visibility benefits 

from LNB/SOFA plus SCR at White Bluff because the analysis is based on an emission limit of 

0.055 lb/MMBtu and did not evaluate an emission limit of 0.04 lb/MMBtu. 

In critiquing our NOX BART evaluation, Ms. Stamper also argues that Entergy’s 2009-2011 

baseline maximum 24-hour NOX emission rates of 3,001.4 lb/hr for Unit 1 and 3,527.4 lb/hr for 

Unit 2 were not appropriate for use in the BART analysis because they reflected the period of 

lowest NOX emission rates for the units and therefore “underestimate the true benefits to 

visibility.” However, the BART Guidelines do not require that the baseline used in the BART 

analysis be constructed from the highest emissions from any given year or years, only that, as 

Ms. Stamper acknowledges, the “baseline emissions rate should represent a realistic depiction of 

anticipated annual emissions for the source.”402 We believe it was reasonable to select baseline 

maximum 24-hour NOX emission rates that reflected the installation of controls and a change in 

operations after the neural network was installed in 2006, which eliminates from consideration 

the highest NOX annual emission average for Unit 1 from the 2001-2003 period. Any additional 

controls would be implemented in combination with the existing neural network. Therefore one 

method to consider the existing controls is to consider the use of the neural network as the 

baseline for visibility assessments for additional NOX controls 

Comment: EPA was not required to consider DSI and low-sulfur coal as control options for 

White Bluff and Flint Creek because EPA proposed to require the most stringent control 

and the BART Guidelines do not require analysis of less stringent controls. [Sierra Club et. 

al. (0171) p. 45-46] Sierra Club et. al. stated that Nucor argues in its comments that EPA erred 

by failing to evaluate low-sulfur coal and dry sorbent injection (“DSI”) as control options in the 

 

399 See page 8 of Appendix E (the Sargent & Lundy NOX control cost study for Entergy) to the White Bluff Plant 

Revised BART Five-Factor Analysis, dated 10/14/13. 

400 Id. “this rate includes consideration of normal fluctuations which may occur over a 30-day compliance period.” 401 76 FR 52402. 402 70 FR 39167. 
215

BART analyses. But where a source proposes the most stringent control as BART, and EPA 

proposes to require the most stringent control, the BART Guidelines do not require analysis of 

less stringent controls. Specifically, the BART Guidelines state: 

If you find that a BART source has controls already in place which are the 

most stringent controls available (note that this means that all possible 

improvements to any control devices have been made), then it is not 

necessary to comprehensively complete each following step of the BART 

analysis in this section. As long these most stringent controls available are 

made federally enforceable for the purpose of implementing BART for 

that source, you may skip the remaining analyses in this section, including 

the visibility analysis in step 5. Likewise, if a source commits to a BART 

determination that consists of the most stringent controls available, then 

there is no need to complete the remaining analyses in this section. 40 

C.F.R. Part 51, App. Y § (IV)(D)(1)(9) (emphasis added). 

Sierra Club stated that here, Entergy submitted a BART analysis for White Bluff Units 1 and 2 

that proposes the most stringent SO2 control—a scrubber. See Entergy, Revised BART Five 

Factor Analysis, White Bluff Steam Electric Station at 5-6 (Oct. 2013), EPA Docket ID No. 

EPA-R06-OAR-2015-0189-0045. EPA has agreed with Entergy and proposed a BART limit for 

SO2 emissions based on the use of a scrubber. Because the source here, Entergy, proposed, and 

EPA accepted, “a BART determination that consists of the most stringent controls available,” 

“there is no need to complete the remaining analyses in this section.” 40 C.F.R. Part 51, App. Y 

§ (IV)(D)(1)(9). Thus, neither Entergy nor EPA was required to analyze less stringent control 

options such as low-sulfur coal or DSI. 

Sierra Club stated that similarly, AEP has not only committed to installing the most stringent 

control for SO2 emissions, AEP is already constructing a scrubber at Flint Creek. See Stamper 

Report at 14; see also AEP, BART Five Factor Analysis Flint Creek Power Plant at 5-6 (Sept. 

2013), EPA Docket ID No. EPA-R06-OAR-2015-0189-0037 (proposing that BART be based on 

the installation and operation of a NID scrubber). Even if the scrubber is not “already in place,” 

AEP has “commit[ted] to a BART determination that consists of the most stringent controls 

available,” and thus “there is no need to complete the remaining analyses in this section.” 40 

C.F.R. Part 51, App. Y § (IV)(D)(1)(9). Under the BART Guidelines, EPA was not required to 

analyze SO2 controls, such as low-sulfur coal and DSI, which are less effective than a scrubber. 

Response: We appreciate the commenter’s support of our FIP proposal. 

4.b. Technical Feasibility of Controls 

Comment: Domtar believes that SNCR is a technically infeasible technology for Power 

Boiler No. 1. [Domtar (0161) p. 8-9] Domtar stated that assuming EPA proceeds with BART for 

the Ashdown Mill, the Mill conceptually agrees with the proposed NOX BART limit for Power 

Boiler 1 of 207.4 lb/hr on a 30-day averaging basis with no add-on control. 
216

The Ashdown Mill agrees with EPA’s determination that for Power Boiler 1 the installation of 

FGR, LNB, Ultra Low NOX Burners (ULNB), OFA, Methane-de- NOX and SCR are technically 

infeasible. EPA’s review of SNCR concludes that the technology is feasible but the high costs on 

a dollar per ton of NOX removal basis403 does not justify the purported small visibility 

improvement ranging from 0.061 dv to 0.136 dv at any single Class 1 area. This level of 

“improvement,” if it even exists, would be imperceptible to the human eye, which cannot detect 

a change of less than 1.0 dv. Moreover, as discussed in other comments, the purportedly 

visibility increase is within the margin of error of the CALPUFF mode, and any visibility 

improvements cannot be reasonably anticipated to occur. 

The Ashdown Mill disagrees with EPA’s determination that SNCR is a feasible technology for 

Power Boiler 1. We base our conclusion on a study404 that was performed for Power Boiler 2 but 

the results are also applicable to Power Boiler 1. See Appendix A to Domtar’s comments. Both 

Power Boiler 1 and Power Boiler 2 provide steam for the pulp and papermaking processes at the 

Mill. Due to large fluctuations in steam demand inherent in the pulp and paper making 

operations, the boilers require continuous adjustment of fuel firing rates and excess air levels. 

These boilers are operated to track steam loads required for the pulp and papermaking processes 

and are not operated under base load conditions as occurs with utility boilers. The study shows 

furnace temperature tracking steam demand. Due to the combustion on mainly biomass fuels, the 

furnace temperature in the area where SNCR nozzles would be installed is usually below the 

temperature needed for the SNCR reaction to take place. Since optimal furnace temperatures 

cannot be consistently maintained, the urea injection needed for reducing NOX emissions will 

result in excess ammonia being present. This ammonia will combine with chlorides and sulfides 

in the combustion gas producing increased corrosion on downstream metal and heat surfaces. In 

addition, it is known that chlorides in the gas stream will combine with excess ammonia to create 

condensable PM2.5 particles in the flue gas, thereby increasing PM2.5 emissions. With respect 

to Power Boiler 1, SNCR is not a technically feasible control technology, and its use potentially 

will result in increased PM2.5 emissions which can further affect visibility. 

Response: We appreciate the commenter’s support of our proposed NOX BART emission limit 

of 207.4 lb/hr for Power Boiler No. 1. 

We do not believe the commenter has provided sufficient information to demonstrate that SNCR 

is a technically infeasible control technology for Power Boiler No. 1. The BART Guidelines 

provide the following regarding the determination of technical feasibility: 

“Control technologies are technically feasible if either (1) they have 

been installed and operated successfully for the type of source 

under review under similar conditions, or (2) the technology could 

be applied to the source under review. Two key concepts are 

important in determining whether a technology could be applied: 

“availability” and “applicability.” As explained in more detail 

 

403 SNCR removal costs estimated to be $12,700 per ton of NOX removed at 20% removal efficiency and $7,640 per 

ton of NOX removed at 45% removal efficiency and $7,640 per ton of NOX removed at 32.5% removal efficiency. 404 International Applied Engineering, Inc. Observations of Chartered Steam Rates and Furnace Exit Gas 

Temperature.
217

below, a technology is considered “available” if the source owner 

may obtain it through commercial channels, or it is otherwise 

available within the common sense meaning of the term. An 

available technology is “applicable” if it can reasonably be installed 

and operated on the source type under consideration. A technology 

that is available and applicable is technically feasible.405 

The NSR permit for the Temple-Inland Kraft Linerboard Mill, located in Orange County Texas, 

requires that the bark boiler install and operate SNCR to achieve a NOX emission limit of 0.166 

lb/MMBtu based on a 30 day rolling average. Like the Domtar Power Boilers No. 1 and 2, the 

Temple Inland Kraft boiler exhibits load swing. We also note there are other similarities in the 

operating parameters of the bark boiler at Temple Inland Kraft and Power Boiler No. 1 at the 

Domtar Ashdown Mill. For example, similar to Domtar’s Power Boiler No. 1, the bark boiler at 

Temple Inland Kraft is permitted to burn, among other fuel types, bark/wood biomass, natural 

gas, and tire-derived fuel. The Temple Inland Kraft bark boiler has a maximum heat input rating 

of 656 MMBtu/hr, which is comparable to the maximum heat input rating of 580 MMBtu/hr for 

Domtar’s Power Boiler No. 1. Therefore, we believe that this type of technology meets the 

technical feasibility definition under the BART Guidelines for power boilers of this type. But we 

acknowledge Domtar’s concerns that because Power Boiler No. 1 is a high load swing boiler, 

there is uncertainty as to the level of NOX control that SNCR can achieve at this boiler on a longterm basis, including whether optimal furnace temperature can be consistently maintained to 

achieve appreciable NOX control. Additional information specific to Power Boiler No. 1 would 

be necessary to support the claim that SNCR operation at this power boiler would not achieve 

appreciable NOX emissions reductions on a long-term basis. However, we are finalizing our 

determination that NOX BART for Power Boiler No. 1 is an emission limit of 207.4 lb/hr, which 

is a reflection of the boiler’s operation at the baseline emission rate and does not require SNCR 

installation. Therefore, the uncertainty related to the technical feasibility of SNCR raised by the 

commenter does not affect our final BART decision. 

We address comments related to the CALPUFF margin of error in the modeling section of this 

document. 

Comment: Domtar believes that MdN and SNCR for NOX control on Power Boiler 2 are 

not technically feasible. [Domtar (0155) p. 14-15] Domtar stated that it agrees with EPA’s 

determination that MdN for NOX control is not technically feasible. The Ashdown Mill also 

agrees with EPA’s assessment the installation of SNCR on Power Boiler 2 is not appropriate. 

EPA concludes it is not appropriate due to the NOX control efficiency of SNCR. The Ashdown 

Mill believes the installation and operation of SNCR on Power Boiler 2 is not technically 

feasible based on the observations in a study conducted on Power Boiler 2 by International 

Applied Engineering406 (see Appendix A to Domtar’s comments). The study concludes that with 

the large fluctuations in steam demand inherent in the pulp and paper making operations the 

boilers require continuous adjustment of fuel firing rates and excess air levels. 

 

405 40 C.F.R. Part 51, App. Y § (IV)(D)(2). 406 International Applied Engineering, Inc. Observations of Chartered Steam Rates and Furnace Exit Temperature. 
218

These boilers are operated to track steam loads required for the pulp and papermaking processes 

and are not operated under base load conditions. The study shows that Power Boiler 2’s furnace 

temperature tracks steam demand. Due to the combustion of biomass fuels, the furnace 

temperature in the area where SNCR nozzles would be installed is usually below the temperature 

needed for the SNCR reaction to take place. Since optimal furnace temperatures cannot be 

consistently maintained, the urea injection needed for reducing NOX emissions will either be too 

much or too little. When too little, NOX removal will be less than projected; when too much, 

excess ammonia slip will occur. The excess ammonia will combine with chlorides and sulfides in 

the combustion gas producing increased corrosion on downstream metal and heat surfaces. In 

addition, it is known that chlorides in the gas stream will combine with excess ammonia to create 

condensable PM2.5 particles in the flue gas, thereby increasing PM2.5 emissions. The Ashdown 

Mill believes the technical studies show that SNCR is not a technically feasible control 

technology for Power Boiler 2 and potentially will increase PM2.5 emissions. 

Response: We appreciate the commenter’s support of our position that MdN is a technically 

infeasible control option for Power Boiler No. 2. While we believe that SNCR may be a 

technically feasible control technology for similar power boilers, as discussed in our proposal, 

we believe Domtar provided sufficient information to demonstrate that because of the wide 

variability in steam demand and wide range in furnace temperature observed at Power Boiler No. 

2, the NOX control efficiency of SNCR at the boiler would not reach optimal control levels on a 

long-term basis.407 There is uncertainty as to the actual level of NOX control that SNCR would be 

able to achieve on a long term basis at Power Boiler No. 2, but we agree that the information 

provided by Domtar indicates it is likely to be well below optimal control levels. We are 

finalizing a BART emission limit consistent with LNB controls. 

4.c. Domtar Ashdown Mill Repurposing Project 

Comment: [Domtar (0155) p. 3-5] Domtar stated that in late 2014 significant changes to the 

Domtar Ashdown Mill were announced. The Ashdown Mill is undergoing a major re-purposing 

project to realign the Mill’s manufacturing processes with the changing pulp and paper market. 

This project takes the Mill in a new direction by converting an existing paper machine that 

manufactures high quality, value-added paper to a fluff pulp line. The fluff pulp will be used in 

absorbent personal care products. While the fluff pulp to be produced will be high quality, the 

profit margin is substantially less than with the production of paper. As such, the economic 

profile of the re-purposed Mill is important to continued operations. 

The re-purposing project will require reconfiguration of the Mill and will affect or require major 

changes to many of the Mill’s systems including the power boilers used to produce steam for the 

paper machines, the converted fluff pulp equipment and other Mill process systems. Most 

significantly for purposes of BART involving Power Boiler 1 and Power Boiler 2, this 

reconfiguring of the Mill and the ultimate product mix is expected to substantially alter steam 

demand from No. 1 and No. 2 Power Boilers. Once the re-purposing and re-configuration of the 

Mill systems is complete and fully operational, the final state of Mill operations is anticipated to 

require changes in steam production from Power Boiler 1 and Power Boiler 2. In addition, the 

 

407 80 FR 18986. 
219

Mill is also initiating other projects that will improve process efficiencies and may also affect 

steam production needs. The machine conversion portion of the re-purposing project is 

scheduled to start up in the third quarter of 2016. The next phase will be a shakedown period in 

2017 where the Mill will obtain a greater understanding of the fluff pulp production process and 

the Mill’s steam needs. Following this shakedown, 2018 will be the first year of full production. 

Key to understanding steam demand needs and correspondingly the changes in the use of Power 

Boilers 1 and 2 is running the boilers through both the shakedown period and first full production 

year. This schedule allows the Mill to determine the effects of seasonal weather changes (winter 

conditions) and the inherent variability that occurs when operating (and learning) a new 

production process. The Mill needs to have sufficient time to re-balance the Mill operations in its 

newly reconfigured state. For that reason, data from 2017 and 2018, including the winter 

seasons, is essential for the Mill in making the decision as to whether to continue full or 

intermittent operation of Power Boilers 1 and 2 and, if so, using what fuels, at what cost, or to 

retire or mothball one of these units. 

Related to the re-purposing of the Mill and future post-project operations are the noncondensable gas (“NCG”) and bark feed systems. Currently, NCG gases are incinerated in Power 

Boiler 2 (as required by other Clean Air Act rules). In addition, both Power Boilers 1 and 2 share 

a common bark feed system. Changes in steam needs, changes in utilization or retirement of 

Power Boilers 1 or 2 will affect these interrelated systems. Assuming EPA proceeds in finalizing 

BART for the Ashdown Mill, a 5-year compliance schedule for achieving the SO2 and NOX

BART requirements for Power Boiler 2 is essential, given the integrated nature of the Mill and 

the complexities resulting from the re-purposing project. 

For BART compliance plan purposes, the first unknown that needs to be resolved (once the 

project is fully completed and operating during 2017 and 2018) is the Mill’s steam needs. 

Understanding whether Power Boilers 1 and 2 will be required to operate and, if so, whether one 

or both will fully operate, only need to operate intermittently or not at all is essential. In addition, 

to determining which boilers will operate and how they will be operated, a decision on fuel mix 

also will need to be made. The project schedule sets these key decision(s) to be made in late 

2018. Once the decision on Mill steam needs and boiler utilization occurs, the BART compliance 

schedule needs to allow additional time for implementation of the boiler scenario option selected 

by the Mill. These scenarios could range from the mothballing or retiring Power Boilers 1 or 2 to 

shifting fuels. In addition, changes involving the NCG gases, an integral part of the kraft pulping 

process, and the shared biomass feed system also need to be determined, new systems engineered 

and environmental permits obtained as required. 

The Ashdown Mill takes its environmental compliance obligations very seriously. At the same 

time, the need to expend funds wisely and to structure flexibility into regulatory compliance 

programs so that the Mill remains a viable entity in the global market is also essential. Both of 

these elements need to be incorporated into BART requirements and BART compliance schedule 

for Power Boilers 1 and 2 to balance environmental obligations with the practical management, 

engineering and financial issues associated with this and the Mill’s re-purposing project. 
220

It is against this backdrop that the Domtar Ashdown Mill is offering specific comments 

regarding the EPA’s proposed BART Requirements for Power Boiler 1 and Power Boiler 2 at the 

Ashdown Mill. 

Summary of Key Mill Specific BART Issues: 

 5-year compliance period is essential for Power Boiler 2 SO2 and NOX

 Include alternate compliance options that remove BART limits when no longer 

applicable (e.g., units are fuel switched, retired, etc.) 

 Boiler operating day for Power Boiler 1 and Power Boiler 2 should be defined as a Mill 

operating day 

 Express the SO2 BART limit for Power Boiler 1 in an alternate form of lb/day instead of 

lb/hr 

 Modify the stack testing frequency for demonstrating compliance with the NOX BART 

limit for Power Boiler 1 to 5 years 

 Adjust the SO2 BART limit for Power Boiler 2 and express in an alternate form of lb/hr 

instead of lb/MMBTU 

 Adjust the timeline for adopting a FIP to allow ADEQ to develop and obtain approval of 

a BART SIP for the Mill. 

[0152-6] One public hearing commenter noted that in late 2004, Domtar announced a major 

project that will convert a paper machine at the Ashdown Mill to produce high quality fluff pulp. 

The project will repurpose some of the mill’s assets. 

Response: We acknowledge the information presented by the commenter regarding the 

repurposing project the Domtar Ashdown Mill is currently undergoing and how this may result 

in changes in steam needs, changes in utilization, or retirement of Power Boilers 1 and 2. We 

address elsewhere in this document the commenter’s detailed comments on each of the key 

issues listed. 

Comment: [Domtar (0161) p. 3-5] Domtar stated that it understands EPA is proposing BART 

for the Ashdown Mill as part of the FIP process. However, other major aspects of the Mill, 

including Power Boilers 1 and 2, are regulated by the Arkansas Department of Environmental 

Quality (ADEQ) under the Arkansas State Implementation Plan (SIP). Dual regulation over 

Power Boilers 1 and 2 (key components of the Mill) creates a significant regulatory burden. The 

dynamic, changing nature of the global pulp and paper market requires flexibility in 

implementing changes at the Ashdown Mill in order to remain competitive. Being required not 

only to change permit requirements with ADEQ but also potentially modify the Mill-specific FIP 

rule likely will delay the ability to react quickly to changing market conditions and customer 

demands and can seriously affect future Mill operations. 

Assuming EPA proceeds with BART for the Ashdown Mill, we believe EPA should work with 

ADEQ to convert EPA’s current FIP approval process into an approved ADEQ SIP. Doing so is 

consistent with cooperative federalism built into the Clean Air Act and will avoid the delays, 

costs and likely inconsistencies that will result from regulating Power Boilers 1 and 2 by both 
221

Arkansas under the SIP and EPA under the FIP. Also, given the requested compliance schedule 

and the ongoing conversion project, allowing ADEQ the time to develop a SIP will not adversely 

affect the Agency’s BART timetable for the Ashdown Mill. Finally, information in Arkansas 

DEQ recently released 5 year Regional Haze Progress Report408 shows Arkansas as meeting or 

exceeding its glide path so additional time to develop a SIP will not affect Arkansas’ ability to 

meet its 2018 reasonable progress goals. 

Response: As we note in our final rule, the State retains its authority to submit a revised state 

plan consistent with CAA and Regional Haze Rule requirements. EPA stands ready to work with 

the State on a SIP revision that would replace some or all elements of the FIP. 

To the extent the commenter is requesting that we delay finalizing our FIP such as to allow time 

for Arkansas to submit a SIP revision before a FIP is promulgated, we do not have the authority 

to delay finalizing our FIP. The CAA section 110(c) provides that the Administrator shall 

promulgate a FIP within 2 years after the Administrator disapproves a state implementation plan 

submission “unless the State corrects the deficiency, and the Administrator approves the plan or 

plan revision, before the Administrator promulgates such Federal implementation plan.” Our 

partial approval and partial disapproval of the Arkansas RH SIP was published in the Federal 

Register on March 12, 2012 and the rule became effective on April 11, 2012.409 Arkansas has not 

yet submitted a SIP revision following our partial disapproval, and EPA is already past-due on its 

action per the statutory deadlines. There is no authority in the CAA for EPA to further delay our 

action for the reasons provided by the commenter. We are operating under a court-ordered 

deadline to take final action to promulgate a FIP or approve a SIP revision that addresses the 

deficiencies in the Arkansas RH SIP by August 31, 2016.410 

We address elsewhere in this document comments related to ADEQ’s Five Year Progress Report 

SIP revision. 

We address comments on Domtar’s request to extend the compliance date for BART for its 

affected boilers elsewhere in this document. 

Comment: Domtar requests that the final FIP include an alternate compliance option for 

SO2 BART for Power Boiler 1 in the event the boiler is converted to natural gas or retired 

as part of the Domtar Ashdown Mill’s re-purposing project. [Domtar (0161) p. 8] Domtar 

stated that the Ashdown Mill is in the process of re-purposing and is in a state of transition. Once 

the re-purposing and re-configuration is complete and the Mill is fully operational, the Mill will 

need to decide if Power Boiler 1 will continue with full or intermittent operation, if so, what 

fuels will be used or will be retired. If the boiler is fuel switched to natural gas or the boiler 

retired, the SO2 BART limit will be unnecessary along with the associated monitoring, 

recordkeeping and reporting requirements for the SO2 BART limit. The Ashdown Mill is 

 

408 State of Arkansas State Implementation Plan Review for the Five-Year Regional Haze Progress Report, 

Arkansas 

Department of Environmental Quality, Air Division Planning Branch, Revised May 2015.

409 77 FR 14604. 410 Sierra Club v. Gina McCarthy, No. 4.14CV00643JLH (ED Ark. Western Div. Nov. 3, 2015). 
222

requesting EPA include in the BART FIP final rule an alternate compliance option that removes 

all of SO2 BART related requirements for Power Boiler 1 if this boiler is fuel switched to natural 

gas or permanently retired. 

Domtar stated that if Power Boiler 1 is fuel switched to burn only natural gas, an alternate 

compliance option needs to be developed to allow compliance to be based on the use of AP-42 

emission factors and fuel use records. Requirements for NOX testing need to be removed. If 

Power Boiler 1 is retired, there is no need to retain the NOX BART limit and the associated 

monitoring, recordkeeping and reporting requirements for the NOX BART limit. An alternate 

compliance option should address this retirement scenario as well. 

Response: We proposed an SO2 BART emission limit of 21.0 lb/hr for Power Boiler No. 1. As 

discussed in our final rule and elsewhere in this document, we are finalizing an emission limit in 

terms of lb/day, as requested by Domtar in a separate comment. We proposed to find that to 

demonstrate compliance with its SO2 BART emission limit, the facility was required to use a 

site-specific curve equation (provided to us by the facility) to calculate the SO2 emissions from 

Power Boiler No. 1 when combusting bark, and to confirm the curve equation using stack 

testing.411 We also proposed to find that to calculate the SO2 emissions from Power Boiler No. 1 

when combusting fuel oil, the facility must assume that the SO2 inlet is equal to the SO2 being 

emitted at the stack.412 In our proposal we invited public comment specifically on the issue of 

whether our proposed method of demonstrating compliance is appropriate. 

We note that we became aware that Power Boiler No. 1 wished to burn only natural gas after the 

end of the comment period for our proposal, and that the facility has submitted a permit renewal 

application to ADEQ that will reflect this enforceable change.413 We do not agree that the SO2

BART emission limit becomes “unnecessary” when a unit is switched to burn only natural gas. 

The Regional Haze regulations define BART as an emission limitation based on the degree of 

reduction achievable through the application of the best system of continuous emission reduction 

for each pollutant which is emitted by an existing stationary facility.414 Therefore, a BART 

emission limit is still applicable and is required regardless if the unit switches to natural gas. 

However, the repurposing project the mill is currently undergoing and the fact that the facility’s 

air permit will be revised such that Power Boiler No. 1 will be permitted to burn only natural gas, 

which generally results in negligible SO2 emissions, render it appropriate to provide the facility 

with flexibility in demonstrating compliance with the SO2 emission limit. Therefore, in addition 

to the method we proposed for demonstrating compliance with the SO2 BART emission limit for 

Power Boiler No. 1, we are also finalizing one alternative method for demonstrating compliance: 

the owner or operator may demonstrate compliance with the SO2 emission limit by switching 

Power Boiler No. 1 to burn only pipeline quality natural gas. Therefore, if the facility’s air 

permit is revised to reflect that Power Boiler No. 1 is permitted to burn only pipeline quality 

natural gas, this would satisfy the requirement for demonstrating compliance with the boiler’s 

SO2 BART emission limit, and the reporting and recordkeeping requirements would be waived. 

 

411 80 FR 18980. 412 80 FR 18980. 413 See file “Record of Meeting_March 10 2016,” which can be found in the docket for this rulemaking. 414 40 CFR 51.301. 
223

We are revising proposed section 52.173 to reflect this alternative method for demonstrating 

compliance. 

We are finalizing our determination that NOX BART for Power Boiler No. 1 is an emission limit 

of 207.4 lb/hr. We proposed that to demonstrate compliance with this NOX BART emission 

limit, the facility was required to conduct annual stack testing. In response to a separate comment 

provided by Domtar, in our final FIP we are requiring stack testing every five years instead of 

annually to demonstrate compliance with the NOX BART emission limit. The repurposing 

project the mill is currently undergoing and the fact that the facility’s air permit will be revised 

such that Power Boiler No. 1 will be permitted to burn only natural gas render it appropriate to 

provide the facility with flexibility in demonstrating compliance with the NOX emission limit. 

Therefore, we are also providing one alternative method for demonstrating compliance with the 

NOX emission limit: if the facility’s air permit is revised to reflect that Power Boiler No. 1 is 

permitted to burn only pipeline quality natural gas, the facility may demonstrate compliance with 

the NOX emission limit by calculating emissions using AP-42 emission factors and fuel usage 

records. Under these circumstances, the facility would not be required to demonstrate 

compliance with the NOX BART emission limit for Power Boiler No. 1 through stack testing. 

We are revising proposed section 52.173 to reflect this alternative method for demonstrating 

compliance. 

With regard to the request that we include a provision in our FIP that removes all SO2 and NOX

BART related requirements for Power Boiler 1 if this boiler is permanently retired in the future, 

we noted above that the Regional Haze regulations define BART as an emission limitation based 

on the degree of reduction achievable through the application of the best system of continuous 

emission reduction for each pollutant which is emitted by an existing stationary facility. The 

BART emission limits and applicable requirements continue to apply regardless if a BART 

source is mothballed or retired/shut down without being dismantled, decommissioned, and 

having the air permit revoked. In the event that the BART source is permanently shut down, 

dismantled, decommissioned, and the permit revoked in the future, the process for removing the 

BART emission limits and applicable requirements would necessarily involve a request by the 

company for partial FIP withdrawal or a SIP revision from the State in the event that we have 

approved a SIP revision that replaces our FIP. We are committed to work with ADEQ and the 

facility to partially withdraw our FIP with respect to the emission limits for the BART unit or 

revise the SIP if at some point in the future the company decides to permanently shut down, 

dismantle, and decommission the boiler and surrender the air permit. 

Further, we consider the conditions under which a unit is permanently retired and the mechanism 

by which this is made enforceable to be critical. Because the company has not decided if and 

when Power Boiler No. 1 will be permanently retired or decided what the conditions of the 

retirement will be, we believe that it is reasonable and appropriate to wait until the company 

makes these decisions instead of including a provision in our FIP that waives the BART 

recordkeeping requirements in anticipation that the unit’s permanent retirement will take place 

under certain conditions and made enforceable through a particular mechanism that may be 

different from what ultimately takes place. 
224

Comment: Domtar requests that the final FIP include an alternative compliance option for 

the SO2, NOX, and PM BART limits for Power Boiler 2 in light of the Mill’s repurposing 

project. [Domtar (0155) p. 14, 15, and 17] Domtar stated that if Power Boiler 2 is fuel switched 

to natural gas or retired as part of the Domtar Ashdown Mill’s repurposing project, there is no 

need to retain the SO2 and PM BART limits and the associated monitoring, recordkeeping and 

reporting requirements for the SO2 and PM BART limits. The Ashdown Mill requests that EPA 

include in the BART FIP final rule an alternative compliance option which removes the SO2 and 

PM BART limits and the associated monitoring, recordkeeping and reporting requirements if the 

boiler is fuel switched to natural gas or permanently retired. 

Additionally, if Power Boiler 2 is fuel switched to natural gas as part of the Domtar Ashdown 

Mill’s repurposing project, the NOX BART requirements need to be modified to require 

compliance based on the use of AP42 emission factors and fuel use records. The requirement to 

operate and maintain a NOX CEM needs to be removed. If Power Boiler 2 is retired, the NOX

BART requirements are unnecessary. The Ashdown Mill requests EPA include alternate 

compliance options in the BART FIP final rule provisions to address these potential scenarios. 

Response: As discussed in our final rule and elsewhere in this document, we are finalizing an 

SO2 BART emission limit of 91.5 lb/hr and we are finalizing our determination that compliance 

with the Boiler MACT PM standard as revised satisfies the PM BART requirement for Power 

Boiler No. 2. We proposed to require the facility to demonstrate compliance with the SO2

emission limit for Power Boiler No. 2 using the existing CEMS, and to demonstrate compliance 

with the PM emission limit using the same method that is used for demonstrating compliance 

with the Boiler MACT PM standard. We are finalizing these methods for demonstrating 

compliance with the SO2 and PM emission limits for Power Boiler No. 2. 

With regard to the commenter’s request that we include an alternate compliance option in our 

FIP that removes the SO2 and PM BART limits if the boiler is switched to natural gas, we do not 

have the authority to do this. The Regional Haze regulations define BART as an emission 

limitation based on the degree of reduction achievable through the application of the best system 

of continuous emission reduction for each pollutant which is emitted by an existing stationary 

facility.415 The BART emission limits are still applicable and are required regardless if the unit is 

switched to natural gas. However, the repurposing project the mill is currently undergoing and 

the possibility of Power Boiler No. 2 being converted to burn only natural gas render it 

appropriate to provide the facility with flexibility in demonstrating compliance with the SO2 and 

PM emission limits for Power Boiler No. 2. Therefore, we are providing one alternative method 

for demonstrating compliance with the SO2 and PM emission limits: the owner or operator may 

demonstrate compliance with these emission limits by switching Power Boiler No. 2 to burn only 

pipeline quality natural gas. Therefore, if Power Boiler No. 2 is switched to burn only pipeline 

quality natural gas, and the air permit is revised to reflect this change, this would satisfy the 

requirement for demonstrating compliance with the boiler’s SO2 and PM BART emission limits, 

and the related reporting and recordkeeping requirements would be waived. Under these 

circumstances, the SO2 and PM BART determinations for Power Boiler No. 2 would continue to 

apply but the facility would be able to demonstrate compliance with these emission limits by 

virtue of switching to natural gas and it would not be required to use the existing CEMS to 

 

415 40 CFR 51.301. 
225

demonstrate compliance with the SO2 BART emission limit. We are revising proposed section 

52.173 to reflect this. 

We are requiring Power Boiler No. 2 to meet an emission limit of 345 lb/hr to satisfy the NOX

BART requirement. We proposed to require the facility to demonstrate compliance with this 

NOX emission limit using the existing CEMS, and we are finalizing this method for 

demonstrating compliance. However, the repurposing project the mill is currently undergoing 

and the possibility of Power Boiler No. 2 being converted to burn natural gas only render it 

appropriate to provide the facility with flexibility in demonstrating compliance with the NOX

emission limit. Therefore, we are providing one alternative method for demonstrating 

compliance with the NOX emission limit: if Power Boiler No. 2 is switched to burn only pipeline 

quality natural gas, and the air permit is revised to reflect this and the operation of the CEMS is 

not required under other applicable regulatory requirements,416 the facility may demonstrate 

compliance with the NOX emission limit by calculating emissions using AP-42 emission factors 

and fuel usage records. Under these circumstances, the facility would not be required to use the 

existing CEMS to demonstrate compliance with the NOX BART emission limit. We are revising 

proposed section 52.173 to reflect this. 

We do not have the authority to include in our FIP a provision that removes all SO2, NOX, and 

PM BART requirements for Power Boiler No. 2 if it is permanently retired in the future. As 

noted above, the Regional Haze regulations define BART as an emission limitation based on the 

degree of reduction achievable through the application of the best system of continuous emission 

reduction for each pollutant which is emitted by an existing stationary facility. The BART 

emission limits and applicable requirements continue to apply regardless if a BART source is 

mothballed or retired/shut down without being dismantled, decommissioned, and having the air 

permit revoked. In the event that the BART source is permanently shut down, dismantled, 

decommissioned, and the permit revoked in the future, the process for removing the BART 

emission limits and applicable requirements would necessarily involve a request for a partial FIP 

withdrawal or a SIP revision in the event that we have approved a SIP revision that replaces our 

FIP. We are committed to work with ADEQ and the facility to partially withdraw our FIP with 

respect to the emission limits for the BART unit or revise the SIP if at some point in the future 

the company decides to permanently shut down, dismantle, and decommission the boiler and 

surrender the air permit. 

Further, we consider the conditions under which a unit is permanently retired and the mechanism 

by which this is made enforceable to be critical. Because the company has not decided if and 

when Power Boiler No. 2 will be permanently retired or decided what the conditions of the 

retirement will be, we believe that it is reasonable and appropriate to wait until the company 

makes these decisions instead of including a provision in our FIP that waives the BART 

recordkeeping requirements in anticipation that the unit’s permanent retirement will take place 

under certain conditions and made enforceable through a particular mechanism that may be 

different from what ultimately takes place. 

 

416 We find that as long as the operation of the existing CEMS is required under other applicable regulatory 

requirements, the most reasonable approach is to continue demonstrating compliance with the NOX BART emission 

limit using data from the CEMS. 
226

Comment: Domtar requests that the final FIP include a five year schedule for complying 

with the SO2 and NOX BART emission limits for Power Boiler 2 in light of the Mill’s 

repurposing project. [Domtar (0155) p. 13-14, 15] Domtar stated that EPA proposes to require 

compliance with the SO2 BART emission limit for Power Boiler 2 within 3 years of the effective 

date of the final rule. EPA also proposes compliance with the NOX BART emission limit within 

3 years of the effective date of the final rule. With the Mill transformation and re-purposing 

project and all of the work associated with this huge undertaking, the Ashdown Mill needs a 5-

year compliance window from the effective date of the final rule for the SO2 and NOX BART 

requirements for Power Boiler 2 (assuming EPA decides to proceed with BART for the Mill). It 

is anticipated that this Mill transformation project may significantly affect Mill steam demands 

reducing the amount of steam needed from Power Boiler 1 and 2. Ultimately, this transformation 

project may determine future use of Power Boiler 2. Once the re-purposing and re-configuration 

of the Mill systems is complete and fully operational, the Mill will decide whether Power Boiler 

2 will continue with full or intermittent operation, if so, using what fuels, or will it be 

permanently retired. A 5-year schedule recognizes the interconnected operations of the Mill, in 

which changes to one system or component requires changes to other interconnected 

components. Given the Mill’s interconnected nature as well as the complex aspects of the repurposing project, a 5-year compliance schedule for achieving the SO2 BART and NOX BART 

requirements for Power Boiler 2 is essential. 

As announced late last year, the Mill is converting a paper machine to produce fluff pulp. This 

transformation project is being driven by the continued decline in the demand for paper products. 

Power 1 and Power Boiler 2 are part of the Mill’s steam generating components. The steam 

generating units are operated to produce steam that is needed for the manufacturing of pulp and 

paper products. Once the re-purposing and re-configuration of the Mill systems is complete and 

fully operational, the Mill will decide whether Power Boiler 2 will continue with full or 

intermittent operation, if so, using what fuels, or will it be permanently retired. 

In order to make this decision, the Mill will need to go through the startup, initial operation and a 

shakedown period with the new fluff pulp process. Since this is a significant change for the Mill 

it is uncertain how long it will take to learn how to operate and to optimize in this newly 

configured state. The Mill will then need at least 2 winter cycles to understand what the 

maximum steam demand requirements will be for the newly configured Mill. 

In addition, related to the re-purposing of the Mill and future post-project operations is the noncondensable gas (NCG) and bark feed systems. Currently, NCG gases are incinerated in Power 

Boiler 2 (as required by other Clean Air Act rules) and both Power Boilers 1 and 2 share a 

common bark feed system. Changes in the utilization or retirement of Power Boilers 1 or 2 will 

affect these interrelated systems. Significant time will be required to engineer new or modified 

systems, obtain environmental permits and implement the changes. 

The re-purposing project is scheduled to be completed and the newly configured Mill is 

anticipated to start-up in late 2016. A current unknown associated with the project is the Mill’s 

steam needs. The Mill will operate through the winter of 2016-2017 and will be learning how to 

operate and optimize the new process. The winter of 2017-2018 will be the first real indicator of 
227

what winter steam demands will be in the re-purposed state. For the purposes of selecting an 

appropriate BART compliance schedule and future Mill operations, the understanding of how 

Power Boiler 2 will operate and on what fuels is essential. The project schedule will set these key 

decision points in late 2018. Once the decision on Mill steam needs and boiler utilization is 

made, additional time is required to implement the boiler scenario selected by the Mill. These 

scenarios could range from the mothballing or retiring Power Boilers 1 or 2 to shifting fuels. In 

addition, changes involving the combustion of the NCG gases and the shared biomass feed 

system also need to be determined and new systems engineered and permitted, as needed. 

Another factor to be considered is determining the ability of the existing SO2 scrubber to 

continuously operate at 90% removal on a long term basis. If Power Boiler 2 continues to use 

solid fuels, additional time is needed to optimize the existing scrubber to consistently perform at 

this higher level of control efficiency on a long-term basis. 

Response: We have reconsidered the SO2 and NOX BART compliance dates for Power Boiler 

No. 2 in response to this comment. We understand the commenter’s concerns with respect to 

how the transformation and repurposing project the mill is currently undertaking may 

significantly affect mill steam demands and may ultimately determine future use of Power Boiler 

No. 2. We understand that the mill will decide the future use of Power Boiler No. 2, including 

whether it will be converted to other fuels or permanently retired, after the repurposing and 

reconfiguration of the mill systems is complete and fully operational and after the mill has 

learned how to operate and to optimize in its newly configured state. Our understanding from the 

comments is that Ashdown Mill expects to make this decision in late 2018, but that additional 

time will be needed to implement the boiler scenario selected by the mill, which could include 

switching fuels, mothballing or retiring the boilers, or continued operation and combustion of 

solid fuels and installation of air pollution controls to meet the BART emission limits. It is not 

EPA’s intention to place an undue burden on the Domtar Ashdown Mill by requiring a 

compliance date that may not provide sufficient time for the mill to install controls or otherwise 

make the necessary operating changes to meet the boiler’s BART emission limits. While we 

believe that a 3-year compliance date is generally sufficient for installation of the controls on 

which the BART emission limits are based, due to the special circumstances in this case we 

believe that it is reasonable and appropriate to establish a longer compliance date particularly 

since it could avoid unnecessary investment in controls that may be no longer needed due 

shutdown or fuel switch. Therefore, we are requiring that the mill comply with the SO2 and NOX

BART emission limits no later than 5 years from the effective date of this final rule and have 

amended the proposed regulatory text to reflect this change. We believe that this adequately 

addresses the commenter’s concerns while in keeping with the CAA mandate that compliance 

with BART requirements must be as expeditiously as practicable but no later than 5 years after 

promulgation of this FIP. 

4.d. Other Compliance Dates 

Comment: Domtar requests that the compliance date for SO2 and NOX BART for Power 

Boiler 1 and PM BART for Power Boiler No. 2 be changed to 30 calendar days. [Domtar 

(155) p. 7-8, 9, 17] Domtar stated that EPA is proposing compliance with the NOX BART limit 

for Power Boiler 1 to be on the effective date of the final rule. Should EPA proceed with 
228

imposing BART limits on Power Boiler 1, the Ashdown Mill requests the compliance date be 

changed to 30 calendar days after effective date of the final rule. That will give the Mill 

additional time to prepare the compliance records if there is a short period (e.g., 30 days) 

between when the rule is promulgated and the effective date, especially if the effective date of 

the final rule falls on a weekend or a holiday. In addition, if any confusion exists regarding 

exactly when the effective date is, the cushion of 30 days helps to provide more certainty. This 

extra time will be needed if EPA finalizes any changes to definitions or other requirements that 

require the Ashdown to adjust recordkeeping systems. 

Domtar stated that EPA is proposing compliance with the SO2 BART limit for Power Boiler 1 to 

be effective on the date of the final rule. The Ashdown Mill is requesting the compliance date be 

changed to 30 calendar days after effective date of the final rule. The 30 days will give the Mill 

time to prepare the compliance records if there is a short period (e.g., 30 days) between when the 

rule is promulgated and the effective date, especially if the effective date of the final rule falls on 

a weekend or a holiday. In addition, if for some reason there is confusion regarding exactly when 

the effective date is, the cushion of 30 days helps to provide certainty. This extra time will also 

be needed if EPA finalizes any changes to definitions or requirements and the Ashdown Mill will 

need the additional time to adjust recordkeeping systems. 

Domtar stated that EPA is proposing compliance with the PM BART limit for Power Boiler 2 to 

be on the effective date of the final rule. The Ashdown Mill is requesting the compliance date be 

changed to 30 calendar days after the effective date of the final rule. The additional 30 days will 

provide additional time to prepare the necessary compliance records especially if there is a short 

period between when the rule is promulgated and the effective date or if the effective date of the 

final rule falls on a weekend or a holiday. In addition, if confusion exists regarding the effective 

date of the final rule, deferring the effective date helps provide more certainty. This extra time 

will also be needed by the Ashdown Mill if EPA adopts changes to definitions or requirements, 

which mandate adjustments to recordkeeping systems. 

Response: We are finalizing a NOX BART emission limit of 207.4 lb/hr for Power Boiler No. 1, 

which is what we proposed. We proposed an SO2 BART emission limit of 21.0 lb/hr for Power 

Boiler No. 1, and as discussed in our final rule and elsewhere in this document, we are finalizing 

an emission limit of 504 lb/day in response to a separate comment provided by Domtar. We are 

finalizing our determination that compliance with the Boiler MACT PM standard satisfies the 

PM BART requirement for Power Boiler No. 2. As discussed elsewhere in this section of the 

final rule, we are finalizing some changes to the definitions and BART requirements for Power 

Boiler No. 1. After carefully considering this comment, we have determined that extending the 

compliance dates associated with the aforementioned BART emission limits for Power Boiler 

No. 1 is appropriate because it is a reasonable request that will allow the owner or operator of the 

affected facility to prepare applicable compliance records and adjust recordkeeping systems 

without unduly delaying compliance with the BART requirements. Therefore, we are revising 

the compliance dates we proposed for the SO2 and NOX BART emission limits for Power Boiler 

No. 1 and the PM BART requirement for Power Boiler No. 2 such that the owner or operator 

must comply with these emission limits no later than 30 calendar days from the effective date of 

the final rule. 
229

Comment: EPA should use its discretion under the Regional Haze Rule and delay the 

Arkansas BART requirements for all sources for five years to avoid a piecemeal approach 

and align compliance timelines so that the full effects of other regulatory changes will be 

known. [Domtar Supplemental Comments (0170) p. 3] Domtar stated that EPA’s proposed 

BART requirements will require installation of new emission controls on utility electric 

generation resources at a significant cost. The utilities will pass these costs on to Arkansas 

ratepayers. The Ashdown Mill, like other energy intense manufacturers, will be affected by the 

increasing cost of electric power needed to operate our processes. With other emerging 

regulatory initiatives targeting coal burning utilities, EPA should also consider these other 

factors which will be driving substantial changes to major coal burning facilities. 

Not only are manufacturing facilities, such as the Ashdown Mill, undertaking major 

transformation projects that potentially may result in a move away from coal. Other emerging 

regulations targeting major utility units, such as the recently released final Clean Power Plan rule 

and the upcoming final rule on ozone standards, are likely to further reduce coal burning and 

further remove visibility concerns. 

Domtar stated that while the Ashdown Mill’s technical analysis on the CALPUFF margin of 

error shows no BART controls are warranted, it understands EPA may disagree. A practical 

alternative is for EPA to use its discretion under the Regional Haze Rule and delay the Arkansas 

BART requirements for all sources for five years. This will align compliance timelines so that 

the full effects of all of these regulatory changes will be known. Facilities affected by these other 

requirements can plan holistic compliance strategies rather than being compelled to follow an 

expensive and potentially wasteful piecemeal approach. Using the maximum five-year window 

allowed under BART will provide the Ashdown Mill the time to determine if coal will continue 

as a fuel for the facility. It will also provide the other affected sources in Arkansas with time to 

address the Clean Power Plan strategies and other significant regulatory programs that may also 

remove coal as a fuel. The effect of allowing a full five-year compliance program will thereby 

minimize the potential for stranded assets and minimize the cost increases on companies and on 

ratepayers. This approach is further compelled by the fact that Arkansas is more than meeting its 

“glide path” as discussed above. 

Response: We acknowledge the commenter’s concerns related to the potential increase in utility 

rates for Arkansas ratepayers as well as to potential requirements related to other CAA and EPA 

regulatory actions. We agree that multiple regulatory actions are pending that will affect the 

power sector and that regulatory development should be coordinated when possible while still 

meeting the statutory and regulatory requirements for compliance. We also recognize the 

importance of long-term and coordinated planning on the parts of owners of industrial sources 

that are subject to BART. However, we disagree that our FIP presents a tight or unreasonable 

regulatory timeline. It is an appropriate timeline for cost-effective control measures needed to 

meet the regional haze requirements. 

The CAA and Regional Haze Rule require the installation and operation of BART, in particular, 

to be carried out expeditiously. The CAA defines the term “as expeditiously as practicable” to 

mean “as expeditiously as practicable but in no event later than five years after the date of 
230

approval of a [Regional Haze] plan revision . . . .”417 Therefore, we do not have the authority to 

delay compliance dates across the board for all subject-to-BART sources in Arkansas to allow 

time for greater certainty regarding requirements associated with other CAA and regulatory 

requirements. We also disagree that ADEQ’s finding that Arkansas Class I areas are projected to 

be below the URP glidepath in 2018 is sufficient justification for delaying the compliance dates 

for all subject-to-BART sources in Arkansas. We address other more specific comments related 

to this issue in a separate response. 

In determining what is “as expeditiously as practicable” for installation and operation of a 

particular control technology, the states and EPA usually consider the amount of time it 

generally takes to install and operate that type of technology at similar sources and the 

compliance dates that have been required for the installation and operation of the same type of 

control technology at similar sources in other regional haze actions, especially if there are no 

source-specific considerations or other special circumstances that would prevent the source from 

installing and operating the control technology within the same amount of time. For example, 

where a particular control technology can generally be installed and operated in 3 years, and 

where there are no source-specific considerations or other special circumstances that would 

affect the facility’s ability to install and operate the control technology within that time frame, it 

would not be in accordance with the CAA and the Regional Haze Rule to allow a 5-year 

compliance period because that would not be as expeditiously as practicable. Additionally, 

considering that most other states already have plans in place that fully address the regional haze 

requirements, it would be inequitable and contrary to the intent of the CAA and the Regional 

Haze Rule to further delay implementation of regional haze requirements in Arkansas by 

allowing a 5-year compliance date across the board for all of Arkansas’ subject-to-BART 

sources. Therefore, we disagree that it is appropriate for us to allow a 5-year compliance date for 

all subject-to-BART sources in Arkansas, rather than establishing deadlines consistent with the 

facts and regulatory requirements in each instance. 

We do note that we are revising some of the compliance dates we proposed in response to 

source-specific considerations raised in other comments. We address these comments in separate 

responses. 

We disagree that the BART controls we proposed are unwarranted because of the “CALPUFF 

margin of error.” We address specific comments related to the CALPUFF margin of error 

elsewhere in this document. 

Comment: EPA should impose a shorter SO2 BART compliance deadline for Flint Creek 

Unit 1 considering AEP is currently in the process of installing the NID scrubber with a 

planned operation date of May 2016. [Sierra Club et. al. (0171) p. 14-15] Sierra Club et. al. 

stated that if EPA’s final SO2 BART determination is based on installation of a NID dry 

scrubber, EPA should impose a shorter compliance deadline, as required by the Act. EPA’s 

proposed FIP requires Flint Creek Unit 1 to comply with the SO2 BART determination within 

five years from the effective date of the final rule. 80 Fed. Reg. at 18,967. Yet the statute 

requires a source to comply with BART as expeditiously as possible, but no later than five years 

 

417 CAA section 169A(b)(2)(A) and (g)(4). 
231

from the effective date of EPA’s action on the regional haze plan. 40 C.F.R. §51.308(e)(1)(iv). 

AEP could install a NID scrubber at Flint Creek much more expeditiously than five years from 

the effective date of the rule. The utility has already obtained an APSC order finding that NID 

dry scrubber installation is in the public interest.418 ADEQ has already issued a Title V air permit 

for scrubber construction and operation at Flint Creek.419 Further, it appears that on-site 

construction of the NID scrubber has begun, and that the Flint Creek owners intend to operate it 

by May 29, 2016, in order to comply with EPA’s MATS rule.420 Thus, given that AEP is 

currently installing the NID scrubber with a May 2016 planned operation date, EPA’s five-year 

SO2 BART compliance deadline does not comply with the statutory requirement that BART 

controls be installed “as expeditiously as practicable,” 42 U.S.C. § 7491(b)(2)(A). Since AEP is 

installing the NID scrubber for MATS as well as BART compliance, EPA should require SO2

BART compliance at Flint Creek by no later than May 29, 2016. 

Response: We acknowledge the information provided by the commenter regarding AEP Flint 

Creek’s plans to complete installation of the NID system in 2016 in order to comply with 40 

CFR Part 63, Subpart UUUUU - National Emission Standards for Hazardous Air Pollutants: 

Coal- and Oil-Fired Electric Utility Steam Generating Units, otherwise known as the Utility 

MATS Rule. MATS establishes emission limits for three categories of pollutants: mercury, acid 

gases (HCl and SO2), and non-mercury hazardous air pollutant (HAP) metals. To address acid 

gases, an EGU must comply with an HCl emission limit unless it is equipped with a wet or dry 

FGD or DSI and an SO2 CEMS, in which case it has the option of complying with an alternative 

SO2 emission limit. The applicable alternative SO2 emission limit is 0.2 lb/MMBtu. 

The commenter has made us aware that the Arkansas PSC has determined that dry scrubber 

installation at Flint Creek is in the public interest and that the installation of those controls is 

already underway and anticipated by the company to be complete by May 29, 2016. The 

commenter also points to the air permit issued to Flint Creek by ADEQ on October 25, 2013, 

which allows for the installation and operation of new control equipment and associated material 

handling systems to comply with the requirements of the Utility MATS Rule. These controls 

include a NID system on Unit 1. The AEP-SWEPCO website also indicates that the installation 

of these scrubber controls is driven by MATS and future Regional Haze rules.421 A timeline 

provided on the website states that construction of these controls began in October 2013 and that 

installation will be complete and the facility will be operating with these controls by the end of 

May 2016. In addition, the commenter has made us aware that the Arkansas PSC requires Flint 

Creek to provide quarterly reports on the progress of the installation of these controls. The first 

report the company submitted to the Arkansas PSC is dated March 26, 2014, and stated that the 

FGD project includes the installation of an Alstom NID system to comply with MATS and in 

anticipation of the BART requirements. The report also stated that the NID system and 

associated equipment are to be constructed at Flint Creek Unit 1, and that the company 

 

418 See 7/10/2013 SWEPCO News Release, SWEPCO Receives Arkansas Commission Approval for Flint Creek 

Plant Project, at https://www.swepco.com/info/news/viewRelease.aspx?releaseID=1424. 419 See Stamper Report at 14 (citing October 25, 2013 Permit No. 0276-AOP-R6 at 5 (Ex. 29 to Stamper Report)). 420 Stamper Report at 14 (citing Flint Creek Retrofit Project, SWEPCO News & Info Site at 

https://swepco.com/info/projects/FlintCreek/; March 26, 2014 Independent Monitor Report for AEP Flint Creek 

Plant Unit 1, submitted to the Arkansas Public Service Commission under Docket No. 12-008-U, at (Ex. 30 to 

Stamper Report)). 

421 https://www.swepco.com/info/projects/FlintCreek/ 
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established design, procurement, and construction schedules to bring the upgraded plant fully on 

line by May 29, 2016. The commenter provided the report as an attachment to the comments 

submitted, but this and all other quarterly reports the company submitted to the Arkansas PSC 

are available online.422 The most recent quarterly report available on the Arkansas PSC website 

is dated March 10, 2016, and covers the fourth quarter in 2015. This report indicated that the 

company still expected the upgraded plant to be fully on line by May 29, 2016. We verified the 

status of the installation of the controls with the company, who confirmed that installation of the 

NID controls was completed in June 2016, and that the plant is now operating with those 

controls.423

After carefully considering the information the commenter has brought to our attention, we no 

longer believe that a 5-year compliance date is appropriate for the SO2 BART controls we are 

requiring for Flint Creek. We agree with the commenter that BART controls must be installed as 

expeditiously as practicable.424 Therefore, we are finalizing a shorter compliance date. The 

information made available to us during the comment period, as discussed above, indicates that 

Flint Creek intends to operate the NID system to comply with the alternative SO2 emission limit 

under the Utility MATS rule. The applicable SO2 emission limit is 0.2 lb/MMBtu. The SO2

emission limit we are requiring in our FIP to satisfy the BART requirement is 0.06 lb/MMBtu. 

As indicated in the information and other documentation the commenter provided, the company 

plans to use the same NID system to comply with MATS and to comply with the facility’s SO2

BART requirement. We expect that to achieve an emission rate of 0.06 lb/MMBtu, additional 

scrubbing reagent would be needed beyond that required to meet the 0.2 lb/MMBtu emission 

limit the company is required to meet by April 2016 under MATS. We also recognize that it is 

possible that the reagent handling system installed to meet the 0.2 lb/MMBtu emission limit 

would need some upgrades in order to accommodate the additional scrubbing reagent that would 

be needed to achieve the more stringent 0.06 lb/MMBtu emission limit we are requiring in this 

FIP. Therefore, to allow the facility sufficient time to secure the additional scrubbing reagent that 

would be needed to comply with the SO2 BART emission limit and to make any necessary 

upgrades to the reagent handling system, we are finalizing an 18-month compliance date for Flint 

Creek Unit 1 to comply with the SO2 BART requirement. We believe this is will provide 

sufficient time for the facility to be able to achieve the SO2 BART requirement while still 

meeting the statutory mandate that BART controls be installed as expeditiously as practicable. 

Comment: EPA should impose a shorter NOX BART compliance deadline for Flint Creek 

Unit 1. [Sierra Club et. al. (0155) p. 19] Sierra Club et. al. stated that if EPA’s final NOX BART 

determination for Flint Creek is based on installation of LNB/OFA, in order to comply with its 

statutory mandate, EPA should establish a shorter compliance deadline. EPA’s proposed FIP 

requires Flint Creek Unit 1 to comply with the NOX BART determination within three years 

from the effective date of the rule. 80 Fed. Reg. at 18,969. As noted above, compliance with 

BART is required as expeditiously as practicable. 40 C.F.R. §51.308(e)(1)(iv). AEP has been 

planning for the installation of LNB/OFA and construction has already begun. Stamper Report at 

 

422 See the Arkansas PSC website at http://www.apscservices.info/efilings/docket_search.asp. The quarterly reports 

the company is required to submit to the Arkansas PSC are available by searching for docket No. 12-008-U. 

423 See file titled “Record of Call- Flint Creek_August 10 2016,” which is found in the docket for this rulemaking. 424 CAA section 169A(b)(2)(A). 
233

27. Given that the utility is currently installing LNB/OFA with a May 2016 planned operation 

date, EPA’s three-year NOX BART compliance deadline does not represent the expeditious 

implementation required by law. If EPA selects LNB/OFA only as BART NOX for Flint Creek, 

it should require a NOX BART compliance date of no later than May 2016. Id. 

If EPA selects SCR plus LNB/OFA as NOX BART for Flint Creek, EPA should establish a 

compliance date of May 2016 for LNB/OFA and within three years of the final rule’s effective 

date for SCR. As demonstrated in Ms. Stamper’s report, three years is more than sufficient for 

installation of SCR and would represent expeditious implementation. Id. 

Response: We are finalizing our determination that NOX BART for AEP Flint Creek Unit 1 is 

an emission limit of 0.23 lb/MMBtu on a 30 boiler-operating-day rolling average, which is 

consistent with the installation and operation of LNB/OFA. The commenter has not provided 

sufficient information to corroborate the claim that installation of LNB/OFA at Flint Creek Unit 

1 is expected to be completed by May 2016. We acknowledge that on July 10, 2013, the 

Arkansas PSC filed an order agreeing that the installation of additional environmental controls at 

Flint Creek Unit 1, including LNB/OFA to meet the NOX BART requirement, is in the public 

interest.425 In the attachments to the comment, the commenter points to a news article that 

references a January 21, 2014 report submitted by AEP/SWEPCO to the Arkansas PSC.426 In 

that January 21, 2014 report, AEP/SWEPCO announces that construction of environmental 

controls at Flint Creek commenced on January 20, 2014.427 However, the January 21, 2014 

report does not specify if this includes construction of LNB/OFA. While we acknowledge that 

there is publicly available information indicating that the company planned to complete 

installation of a NID system and activated carbon injection by May 2016 to comply with the 

Utility MATS rule, there is no information available to us corroborating that the expected date of 

LNB/OFA installation was also May 2016. 

In fact, the comments submitted by the company itself indicate that the company has not begun 

installation of these controls.428 The company submitted comments requesting a 5 year 

compliance date (instead of the 3 year compliance date we proposed) for LNB/OFA installation 

to allow time for planning, selection of engineering and design professionals, vendors, 

contractors, permitting, start up and commissioning, and coordinating and scheduling unit 

outages. The comments submitted by AEP/SWEPCO are in contradiction to the commenter’s 

allegations that LNB/OFA installation is already underway and expected to be complete by May 

2016. We address the company’s comments regarding this issue in a separate response to 

comment. 

 

425 See Arkansas Public Service Commission, Docket No. 12-008-U, Order No. 14, dated July 10, 2013. A copy of 

the order can be found at http://www.apscservices.info/pdf/12/12-008-u_227_1.pdf 

426 See the document titled “Technical Support Document to Comments of Conservation Organizations,” which is an 

attachment to the comments submitted by Earthjustice, the National Parks Conservation Association, and Sierra 

Club. These and all other comments submitted during the public comment period are found in the docket associated 

with this rulemaking. 

427 http://www.apscservices.info/pdf/12/12-008-u_238_1.pdf 428 See the comments submitted by AEP-SWEPCO, dated July 15, 2015 and August 7, 2015. These and all other 

comments submitted during the public comment period are found in the docket associated with this rulemaking. 
234

Nonetheless, we agree with the commenter that LNB/OFA can typically be installed within a 6-8 

month timeframe. However, in determining the appropriate compliance date for these NOX

controls, we have also taken into consideration that we are finalizing NOX emission limits 

consistent with the installation of LNB/OFA or LNB/SOFA controls for a total of 5 EGUs in this 

FIP and that the installation of these controls will require outage time. These 5 EGUs are Flint 

Creek Unit 1, White Bluff Units 1 and 2, and Independence Units 1 and 2, and combined they 

accounted for approximately 45% of the state’s 2015 heat input.429 Because of the heavy reliance 

on these EGUs for electricity generation in the state, we recognize that it may be difficult to 

schedule outage time to install LNB/OFA or LNB/SOFA on all 5 of these Arkansas units within 

the typical installation timeframe of 6 – 8 months and at the same time supply adequate 

electricity to meet demand in the state. In light of these unique circumstances, we find that it is 

appropriate to finalize an 18-month compliance date for Flint Creek Unit 1, White Bluff Units 1 

and 2, Independence Units 1 and 2, to comply with the NOX emission limits required by this FIP. 

This compliance date provides the affected utilities sufficient time beyond typical LNB/OFA 

installation timeframes to install these controls and comply with their NOX emission limits, while 

safeguarding the continuity of Arkansas’ electricity supply. 

As discussed elsewhere in this document, we are not requiring SCR controls on Flint Creek Unit 

1. Therefore, the comment related to the compliance date of SCR controls is moot. 

Comment: EPA should impose a shorter NOX BART compliance deadline for White Bluff 

Units 1 and 2. [Sierra Club et. al. (0171) p.25] Sierra Club et. al. stated that if EPA’s final NOX

BART determination for White Bluff is based on installation of a SCR with LNB/SOFA, EPA 

should establish a deadline that requires compliance as expeditiously as possible. See 40 C.F.R. 

§51.308(e)(1)(iv). As noted in Section I.A.2.c of the Sierra Club’s comments, SCRs can be 

installed in three years. If EPA’s final BART determination requires SCR, EPA should require a 

NOX BART compliance date for SCR at White Bluff of no later than within three years of the 

final rule’s effective date, which would represent the expeditious implementation required by 42 

U.S.C. § 7491(b)(2)(A). The NOX BART compliance date for LNB/SOFA should be eight 

month’s from the final rule’s effective date. Stamper Report at 46. 

Alternatively, if EPA finalizes its proposal to require LNB/SOFA only as NOX BART for White 

Bluff, EPA should require compliance within eight months of the final rule’s effective date. 

Eight months is sufficient time for installation of these controls. Id. 

These comments also apply and are extended to Independence Units 1 and 2. 

Response: We are requiring White Bluff Units 1 and 2 and Independence Units 1 and 2 to each 

meet a NOX emission limit of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling average, 

where the average is to be calculated by including only the hours during which the unit was 

dispatched at 50% or greater of maximum capacity. In addition, we are requiring each unit to 

meet a NOX emission limit of 671 lb/hr on a rolling 3-hour average that is applicable only when 

the unit is being operated at less than 50% of the unit’s maximum heat input rating. These 

emission limits are consistent with the installation and operation of LNB/SOFA controls. In light 

 

429 Based on data reported to us by these facilities. See http://ampd.epa.gov/ampd/. 
235

of the comment, we have reconsidered the compliance date for the NOX BART requirements for 

White Bluff Units 1 and 2 and for the NOX controls under reasonable progress for Independence 

Units 1 and 2. Based on the supporting information provided by the commenter, we agree with 

the commenter that 6 – 8 months is the typical installation timeframe for LNB/OFA controls. 

However, in determining the appropriate compliance date for these NOX controls, we have also 

taken into consideration that we are finalizing NOX emission limits that are consistent with the 

installation of LNB/OFA or LNB/SOFA controls for a total of five EGUs in this FIP and that the 

installation of these controls will require outage time. These 5 EGUs are White Bluff Units 1 and 

2, Independence Units 1 and 2, and Flint Creek Unit 1. These 5 units combined accounted for 

approximately 45% of the state’s 2015 heat input.430 Because of the heavy reliance on these 

EGUs for electricity generation in the state, we recognize that it may be difficult to schedule 

outage time to install LNB/OFA or LNB/SOFA on all 5 of these Arkansas units within the 

typical installation timeframe of 6 – 8 months and at the same time supply adequate electricity to 

meet demand in the state. In light of these unique circumstances, we find that it is appropriate to 

finalize an 18-month compliance date for White Bluff Units 1 and 2, Independence Units 1 and 

2, and Flint Creek Unit 1 to comply with the NOX emission limits required by this FIP. This 

compliance date provides the affected utilities sufficient time beyond typical LNB/OFA 

installation timeframes to install these controls and comply with their NOX emission limits, while 

safeguarding the continuity of Arkansas’ electricity supply.

We address elsewhere in this document specific comments contending that we should require 

installation of SCR with LNB/SOFA at White Bluff Units 1 and 2 to address the BART 

requirements and at Independence Units 1 and 2 to address the reasonable progress requirements. 

Comment: If EPA’s FIP does not rely on CSAPR to meet the NOX BART requirement for 

Arkansas EGU’s and the requirement to install LNB/OFA at Flint Creek Unit 1 is 

finalized, the EPA should extend the compliance date to allow 5 years for installation of 

controls. [AEP-SWEPCO July 15, 2015 comments (0164) p. 1-3, and August 7, 2015 comments 

(0170) p. 2-4] AEP-SWEPCO stated that if CSAPR=BART is not established in Arkansas for 

compliance with the NOX regional haze requirements, AEP-SWEPCO does support EPA’s 

determination of accepting the LNB/OFA controls as BART and the associated limits included in 

our submittal. However, if this requirement to install LNB/OFA remains in the final FIP, the 

proposed 3 year compliance timeframe is unreasonable. The regional haze rule provides for 

compliance with BART as soon as practicable, but no later than 5 years. The time frame must 

allow for planning, selection of engineering and design professionals, vendors, contractors, 

permitting, start up and commissioning, and coordinating and scheduling unit outages. Further, 

EPA has allowed installation schedules up to 5 years in other states and EPA should allow such a 

time frame here. 

Response: We are finalizing our determination that NOX BART for AEP Flint Creek Unit 1 is 

an emission limit of 0.23 lb/MMBtu on a 30 boiler-operating-day rolling average, which is 

consistent with the installation and operation of LNB/OFA. In response to a separate comment, 

we agree that LNB/OFA can typically be installed within a 6-8 month timeframe. We have also 

determined that the company has not provided any information regarding any special 

 

430 Based on data reported to us by these facilities. See http://ampd.epa.gov/ampd/. 
236

circumstances specific to the facility that sets it apart from other facilities and that would prevent 

it from completing installation of controls within typical 3-year LNB/OFA installation 

timeframes. Although, as discussed elsewhere in this document, we agree that LNB/OFA can 

typically be installed within a 6-8 month timeframe, in determining the appropriate compliance 

date for these NOX controls, we have also taken into consideration that we are finalizing NOX

emission limits consistent with the installation of LNB/OFA or LNB/SOFA controls for a total of 

5 EGUs in this FIP and that the installation of these controls will require outage time. These 5 

EGUs are Flint Creek Unit 1, White Bluff Units 1 and 2, and Independence Units 1 and 2, and 

combined they accounted for approximately 45% of the state’s 2015 heat input.431 Because of the 

heavy reliance on these EGUs for electricity generation in the state, we recognize that it may be 

difficult to schedule outage time to install LNB/OFA or LNB/SOFA on all 5 of these Arkansas 

units within the typical installation timeframe of 6 – 8 months and at the same time supply 

adequate electricity to meet demand in the state. In light of these unique circumstances, we find 

that it is appropriate to finalize an 18-month compliance date for Flint Creek Unit 1, White Bluff 

Units 1 and 2, Independence Units 1 and 2, to comply with the NOX emission limits required by 

this FIP. This compliance date provides the affected utilities sufficient time beyond typical 

LNB/OFA installation timeframes to install these controls and comply with their NOX emission 

limits, while safeguarding the continuity of Arkansas’ electricity supply. 

4.e. Compliance Demonstration Requirements 

Comment: EPA’s definition of Boiler Operating Day in the proposed FIP. [Domtar (0161) p. 

6-7] Domtar stated that the July 6, 2005 BART Guidelines final rule states the following: 

For EGU’s, specify an averaging time of a 30-day rolling average, and 

contain a definition of “boiler operating day” that is consistent with the 

definition in the proposed revisions to the NSPS for utility boilers in 40 

C.F.R. Part 60, subpart Da.22 You should consider a boiler operating day 

to be any 24-hour period between 12:00 midnight and the following 

midnight during which any fuel is combusted at any time at the steam 

generating unit. This would allow 30 day rolling average emission rates to 

be calculated consistently across sources. 

Domtar stated that for purposes of BART for Ashdown’s Power Boiler 1 and Power Boiler 2, 

EPA is defining boiler operating day as a 24-hour period between 12 midnight and the following 

midnight during which any fuel is fed into and/or combusted at any time in the power boiler, 

consistent with the guidelines for utility boilers. However, the Ashdown Mill boilers are not 

utility boilers; they are industrial boilers. The Ashdown Mill defines a Mill operating day to be a 

24-hour period between 6 a.m. and 6 a.m. the following day. All of the Mill’s systems for Power 

Boiler 1 and Power Boiler 2 are programmed around this definition of a Mill operating day and 

to modify these systems requires a significant amount of effort and requires the gathering and 

maintaining of multiple sets of records. Assuming EPA proceeds with BART for the Ashdown 

Mill, the Mill requests that for Power Boiler 1 and Power Boiler 2 a boiler operating day be 

 

431 Based on data reported to us by these facilities. See http://ampd.epa.gov/ampd/. 
237

defined as a 24-hr period between 6 a.m. and 6 a.m. the following day during which any fuel is 

fed into and/or combusted at any time in the power boiler. 

Domtar stated that harmonizing the definitions of a boiler operating day and a Mill operating day 

helps address the inherent management issues that occur with dual EPA and ADEQ regulation of 

Power Boilers 1 and 2. In addition, harmonizing the definitions does not increase costs for the 

Mill, reduces confusion for the Mill operators, multiple sets of records will not be required and 

unnecessary changes to existing monitoring systems will not be necessary. We believe EPA is 

authorized or can use its discretion to define a boiler operating day for the Ashdown Mill to be 

consistent with the Mill’s boiler operating day definition. 

Response: After carefully considering the comment, we agree that Domtar’s request is 

reasonable and that it is appropriate to harmonize the definitions of a boiler operating day and a 

Mill operating day to avoid any unnecessary modification or reprogramming of Power Boilers 1 

and 2. To accommodate Domtar’s request, for purposes of Power Boiler 1 and Power Boiler 2, 

we are defining a boiler operating day as “a 24-hr period between 6 a.m. and 6 a.m. the following 

day during which any fuel is fed into and/or combusted at any time in the power boiler.” We are 

revising our final action to reflect this change. 

Comment: Domtar requests changes to the requirements for demonstrating compliance 

with the NOX BART limit for Power Boiler 1. [Domtar (0161) p. 9-10] Domtar stated that 

proposed Section 52.173(19)(ii) requires compliance with the BART NOX limit for Power 

Boiler 1 be demonstrated with an annual stack test. We agree, in general, stack testing is an 

appropriate method for demonstrating compliance. However, the proposed frequency of an 

annual stack test is not appropriate. Historical NOX stack test data from 2001, 2002, 2003, 2004, 

2005 and 2010 for Power Boiler 1 show the NOX emissions to be fairly consistent. 

Domtar stated that based on the numerous previous stack tests, conducting stack tests annually is 

not warranted. Should EPA proceed with BART for the Ashdown Mill, the Mill is requesting the 

stack testing requirement be modified to require NOX stack testing every 5 years to demonstrate 

compliance with the BART NOX limit, which is consistent with the Ashdown Mill’s Title V 

permit requirements. 

Domtar stated that in addition, proposed section 52.173(16)(iii) requires for both SO2 and NOX, 

that for each boiler operating day a 30-day rolling average determined by (i) adding together the 

pounds from that day of SO2 and NOX and the preceding 29 boiler operating days and (ii) 

dividing the total pounds of SO2 or NOx by the sum of the total number of hours during the same 

30 boiler operating day period. The reference to NOX in this section needs to be removed as 

compliance with the NOX limit is determined with stack testing. In addition, the discussion 

regarding SO2 in this section can be moved to proposed Section 52.173(16)(i) and proposed 

Section 52.173(16)(iii) can be eliminated altogether. 

Response: After carefully considering the comment, we have reconsidered our proposed 

requirement of annual stack testing. We agree that the results of the NOX stack testing conducted 

by Domtar for Power Boiler No. 1 demonstrate that NOX emissions have historically remained 
238

well below the NOX emission limit we are finalizing for the boiler.432 Therefore, we agree with 

the company that it is appropriate to require stack testing every 5 years instead of annually. In 

our final action we are requiring that the facility demonstrate compliance with the NOX BART 

emission limit for Power Boiler No. 1 by conducting stack testing every five years, beginning no 

later than 1 year from the effective date of our final action. As discussed in a separate response, 

we are also providing one alternative method for demonstrating compliance with the NOX BART 

emission limit for Power Boiler No. 1. Specifically, if the facility’s air permit is revised to reflect 

that Power Boiler No. 1 is permitted to burn only pipeline quality natural gas, the facility may 

demonstrate compliance with the NOX emission limit by calculating emissions using AP-42 

emission factors and fuel usage records. Under these circumstances, the facility would not be 

required to demonstrate compliance with the NOX BART emission limit for Power Boiler No. 1 

through stack testing. 

As compliance with the NOX BART emission limit is to be determined through stack testing, we 

agree with the commenter that the reference to NOX in our proposed section 52.173(16)(iii) 

should be removed. We acknowledge this error and are correcting this in our final action. 

Comment: Domtar requests that EPA’s proposed BART SO2 limit for Power Boiler 1 of 21 

lb/hr be expressed as 504 lb/day. [Domtar (0161) p. 7-8] Domtar stated that assuming EPA 

proceeds with BART for the Ashdown Mill, the Mill conceptually agrees with the proposed 

BART SO2 limit for Power Boiler 1 of 21.0 lb/hr on a 30-day averaging basis with no add-on 

control. However, based on the methodology the Mill uses to determine fuel usage, the limit 

needs to be expressed in an alternative form to better match with the compliance averaging time 

of 30 days. The Mill uses monthly fuel usage records and reconciles the monthly usage records 

based on fuel inventory records at the end of each month. Records of daily fuel usage may be 

adjusted at the end of the month as part of the reconciliation process. Domtar requests the BART 

limit of 21.0 lb/hr be expressed as 504 lb/day. 

Domtar stated that section 52.173(19)(iii) of the proposed rule requires SO2 emissions for each 

day are determined by summing the hourly emissions measured in pounds of SO2. Calculating 

hourly SO2 emissions using hourly fuel throughput information is not a workable approach for 

Power Boiler 1 where the practice is to use monthly fuel throughput information that is 

reconciled at the end of each month. The Ashdown Mill requests the requirement referencing 

summing of hourly SO2 emission be removed. The Mill will track daily SO2 emissions and 

requests the 30-day rolling averages for compliance purposes be determined within 15 days of 

the end of each month to allow time for the monthly fuel reconciliation processes to be 

completed and the daily fuel throughput values adjusted accordingly. After the fuel 

reconciliation is completed, the 30-day rolling averages for compliance purposes will be 

determined and the “official” compliance records maintained. 

 

432 See Excel file titled “Email from Domtar Regarding NOx Stack Test for PB1,” found in the docket for this final 

rule. The data provided by Domtar indicate that out of the stack testing conducted in 2001, 2002, 2003, 2004, 2005, 

and 2010, the highest NOX emission rate from Power Boiler No. 1 was 171.3 lb/hr, compared to the 207.4 lb/hr NOX

emission limit we are finalizing. 
239

Response: After carefully considering this comment we have determined that Domtar’s request 

for an SO2 BART emission limit in terms of lb/day is reasonable. An emission limit in terms of 

lb/day will be better suited for the mill’s methodology of using monthly fuel throughput 

information. Therefore, as requested by the facility, we are finalizing an SO2 BART emission 

limit of 504 lb/day for Power Boiler No. 1. 

In addition, as the Mill reconciles the monthly fuel usage records based on fuel inventory records 

at the end of each month and may have to adjust records of daily fuel usage as part of the 

reconciliation process, we believe it is reasonable and appropriate for the Mill to determine 30-

day rolling averages within 15 days of the end of each month to allow time for the monthly fuel 

reconciliation process to be completed. 

Comment: EPA should revise the requirements for demonstrating compliance with the SO2

and NOX BART limits for Domtar Power Boiler 2. [Domtar (0161) p. 13, 15] Domtar stated 

that EPA is proposing compliance with the proposed SO2 and NOX BART limits for Power 

Boiler 2 be determined by using the existing CEM system. In Section 52.173(19)(iii), EPA 

requires the owner/operator to comply with the CEMs quality assurance procedures in 40 C.F.R. 

Part 75. Since the Ashdown Mill is an industrial facility, the Mill is complying with the CEM 

requirements including the quality assurance requirements contained in 40 C.F.R. Part 60. EPA 

needs to correct this language to reference 40 C.F.R. Part 60 and not 40 C.F.R. Part 75. In 

addition, any existing CEM systems and associated methods and procedures (e.g., QA/QC, etc.) 

approved by the State should be adequate and appropriate for use in SO2 and NOX BART 

monitoring. No need exists for EPA to review and approve these existing systems when they 

were previously reviewed and approved by the State. 

Response: We agree with the commenter that since the Domtar Ashdown Mill is an industrial 

facility, it is complying with the CEM requirements including the quality assurance requirements 

contained in 40 C.F.R. Part 60 instead of those contained in 40 C.F.R. Part 75. We acknowledge 

this error and are correcting section 52.173 to reflect this. 

Comment: EPA must clarify the PM BART requirements for Domtar Power Boiler 2 so 

these requirements are consistent with definitions and requirements of Boiler MACT.

[Domtar (0161) p. 16-17] Domtar stated that assuming EPA proceeds with BART for the 

Ashdown Mill, the Mill agrees with the proposed BART PM limit of 0.44 lb/MMBTU based on 

the MACT standard for the “biomass hybrid suspension grate” sub-category contained in the 

2013 Boiler MACT final rule. The Ashdown Mill also agrees with EPA’s approach of relying on 

the Boiler MACT standards for PM to satisfy the PM BART requirement. However, for this 

streamlined BART approach, EPA must also ensure that the monitoring, recordkeeping, 

reporting requirements for PM BART are consistent with the monitoring, recordkeeping and 

reporting requirements under Boiler MACT. Deviating from the MACT requirements will result 

in additional administrative burden for the facility in maintaining “multiple sets of compliance 

books.” It also will create confusion for external stakeholders if different values and information 

are being reported. 
240

Domtar stated that EPA is proposing compliance with the PM emission limit be determined by 

maintaining the 30-day rolling average wet scrubber pressure drop and the 30-day rolling 

average wet scrubber liquid flow rate at or above the lowest one-hour average pressure drop and 

the lowest one hour average liquid flow rate, respectively, measured during the most recent 

performance test demonstrating compliance with the PM limit according to 40 C.F.R. Part 63 § 

7530(b) and Table 7 to subpart DDDDD of Part 63. 

Domtar stated that EPA is essentially proposing the same methods for demonstrating compliance 

with the Boiler MACT PM standard be used for demonstrating compliance with the PM BART 

emission limit. However, several of the definitions in Boiler MACT are different than in the 

existing BART rules and in this BART proposal. For example, under Boiler MACT the 30-day 

rolling average is defined to be the arithmetic mean of the previous 720 hours of valid operating 

data. In contrast, for purposes of BART, EPA defines a 30-day rolling average to consist of 30 

consecutive boiler operating days. 

Examples of other inconsistencies between BART definitions/requirements and Boiler MACT 

follow: 

 During periods of startup and shutdown, Boiler MACT uses work practices and does not 

require data collected during startup and shutdown periods to be used in calculating 

averages. In Boiler MACT Section 63.7500(f) states standards apply at all times the 

affected units is operating, except during periods of startup and shutdown during which 

time comply only with the Table 3 work practices. Section 63.7505(a) further states: 

These emission limits and operating limits apply at all times the affected unit is operating 

except for periods noted in §63.7500(f). The proposed BART requirements require 

continuous emissions monitoring during all periods of operation including periods of 

startup, shutdown, and malfunction. In addition proposed BART requirements in Section 

52.173(27) states: At all times, including periods of startup, shutdown and malfunction, 

the owner or operator to the extent practical, maintain and operate the unit including air 

pollution control equipment in a manner consistent with good air pollution control 

practices for minimizing emissions. In contrast, Boiler MACT requirements allow certain 

air pollution control equipment to startup up as expeditiously as possible. 

 Boiler MACT is Section 63.7540((a)(1) states: Operating limits must be confirmed or 

reestablished during performance tests. Unlike the BART proposed language in § 

52.173(22) that requires the one-hour pressure drop and the one-hour average liquid flow 

rate measured during each performance test, Boiler MACT only requires confirmation 

and not re-establishing the pressure drop and flow rate operating limits during 

performance tests subsequent to the initial performance test. 

 Section 63.7540((a)(1) states: “operation above the established maximum or below the 

established minimum operating limits shall constitute a deviation of established operation 

limits listed in Table 4 of this subpart except during performance tests conducted to 

determine compliance with emission limits or to establish new operating limits.” Under 

Boiler MACT, a deviation of an operating limit does not mean a violation of the emission 

standard. 
241

For the final rule, assuming EPA proceeds with BART for the Ashdown Mill, EPA must clarify 

the PM requirements for BART so these requirements are consistent with the definitions and 

requirements of Boiler MACT. 

Response: We generally agree with the comment. We proposed to find that the Domtar 

Ashdown Mill may rely on compliance with the Boiler MACT PM standard to satisfy the PM 

BART requirement for Power Boiler No. 2, and we did not intend for our FIP to establish 

requirements for compliance demonstration, monitoring, recordkeeping, and reporting different 

from those the mill is already required to comply with under the Boiler MACT PM standard. In 

our proposal, our intent was to propose requirements for compliance demonstration, monitoring, 

recordkeeping, and reporting for the PM BART limit for Power Boiler No. 2 that are consistent 

with those under the Boiler MACT PM standard. However, the commenter has brought to our 

attention that only some of the compliance demonstration, monitoring, recordkeeping, and 

reporting requirements associated with the Boiler MACT PM standard were included under our 

proposed section 52.173(c)(21) and (22) and that it appeared that we were proposing a separate 

and distinct set of requirements associated with our PM BART determination for Power Boiler 

No.2. Therefore, to ensure clarity and consistency, we are revising the regulatory text found 

under 40 CFR section 52.173(c) that applies to Power Boiler No. 2 for PM BART to state that 

the mill shall rely on compliance with the Boiler MACT PM standard under 40 CFR Part 63 

Subpart DDDDD as revised to satisfy the PM BART requirement for Power Boiler No. 2. We 

interpret this to mean that compliance with the applicable Boiler MACT PM standard as revised 

is sufficient to demonstrate compliance with the PM BART requirement. We are not establishing 

a separate set of requirements for compliance demonstration, monitoring, recordkeeping, and 

reporting (i.e., in addition to those already required under the Boiler MACT PM standard, as 

revised), that Power Boiler No. 2 is required to comply with to satisfy the PM BART 

requirement. 

4.f. Agreement with EPA’s Proposed BART decisions 

Comment: AECC agrees with EPA’s proposed BART determinations for AECC Bailey 

Generating Station Unit 1 and AECC McClellan Generating Station Unit 1. [AECC (0169) 

p. 1-2] AECC stated that the EPA’s BART determination for SO2 and particulate matter (PM) 

emissions for these two units is to switch to a lower sulfur fuel oil. EPA’s BART determination 

for NOX emissions is to maintain the existing NOX emission limit in the respective unit’s air 

permit with no additional controls. AECC agrees with these determinations. 

 

Response: We appreciate AECC’s support of our proposed SO2 and PM BART determinations 

for these two units. In our final action, we are finalizing these BART determinations. 

Comment: AECC agrees that wet scrubbers are not BART at the Flint Creek Power Plant 

Unit 1 and the White Bluff Steam Electric Station Units 1 and 2. [AECC (0169) p. 2] AECC 

stated that for the Flint Creek Unit 1, EPA states that a wet scrubber is projected to result in 

“minimal incremental visibility improvement” over a dry scrubber, and, therefore, EPA did not 
242

consider a wet scrubber to be BART.433 For the White Bluff units, EPA states that dry scrubbers 

are more cost-effective than wet scrubbers and the additional visibility benefits obtained as a 

result of the greater level of control wet scrubbers offer over dry scrubbers are not worth the 

additional cost of wet scrubbers.434 AECC agrees with these assessments. 

Response: We appreciate AECC’s support of our proposed SO2 BART determinations for Flint 

Creek Unit 1 and White Bluff Units 1 and 2. In our final action, we are finalizing these BART 

determinations. 

Comment: AECC agrees that both SNCR and SCR are not justified at Flint Creek Unit 1 

and White Bluff Units 1 and 2. [AECC (0169) p. 2] AECC stated that EPA believes that adding 

SNCR at Flint Creek is not justified due to the minimal incremental visibility improvement over 

use of low- NOX burners (LNB) with over-fire air (OFA).435 Also, EPA believes that the addition 

of SCR cannot be justified due to a small visibility improvement relative to the high costs 

associated with SCR.436 The results of EPA’s SNCR and SCR analyses for White Bluff are 

similar. AECC agrees with these assessments. 

Response: We appreciate AECC’s support of our proposed NOX BART determinations for Flint 

Creek Unit 1 and White Bluff Units 1 and 2. In our final action, we are finalizing these BART 

determinations.

Comment: EPA’s proposed FIP properly uses a streamlined approach to assess BART 

where circumstances make a full BART analysis unnecessary. [UARG (0176) p. 9-10] 

UARG stated that in certain BART analyses presented in the proposed rule, EPA uses “a more 

streamlined approach to making BART determinations” where baseline visibility impacts are 

small. 80 Fed. Reg. at 18,975 (quoting 70 Fed. Reg. at 39,116); see also id. at 18,980, 18,988. 

For example, in light of the 0.01-dv baseline impact of the White Bluff Auxiliary Boiler at the 

most-affected Class I area, “the visibility improvement that could be achieved through the 

installation and operation of controls would be negligible, such that the cost of those controls 

could not be justified.” Id. at 18,975; see id. at 18,970 Table 31 (showing the magnitude of 

estimated baseline visibility impacts from White Bluff Auxiliary Boiler). EPA likewise explains 

that small baseline visibility impacts from SO2 emissions from the Domtar Ashdown Mill Power 

Boiler No. 1 (ranging from 0.014 dv to 0.335) cannot be addressed in a way that would produce 

meaningful visibility improvement at reasonable cost and, therefore, that unit warrants 

streamlined BART analysis with respect to its SO2 emissions. Id. at 18,979-80 & Tables 44 & 

45; see id. at 18,980 (observing that “any visibility improvement that could be achieved as a 

result of emissions reductions associated with the installation and operation of SO2 controls [at 

that unit] would be negligible, and ... the cost of those controls could not be justified”). As EPA 

explains in the proposed rule, the BART Guidelines allow and contemplate such streamlined 

assessments in these circumstances: 

 

433 80 Fed. Reg. al 18966 (April 8, 2015). 434 Id. at 18993. 435 Id. at 18968. 436 Id.
243

Consistent with the CAA and the implementing regulations, States can 

adopt a more streamlined approach to making BART determinations 

where appropriate. Although BART determinations are based on the 

totality of circumstances in a given situation, such as the distance of the 

source from a Class I area, the type and amount of pollutant at issue, and 

the availability and cost of controls, it is clear that in some situations, one 

or more factors will clearly suggest an outcome. Thus, for example, a 

State need not undertake an exhaustive analysis of a source’s impact on 

visibility resulting from relatively minor emissions of a pollutant where it 

is clear that controls would be costly and any improvements in visibility 

resulting from reductions in emissions of that pollutant would be 

negligible. 70 Fed. Reg. at 39,116, quoted in 80 Fed. Reg. at 18,975; see 

also id. at 18,980 & n.81. 

UARG stated that EPA presents a similar, albeit augmented, rationale for its streamlined BART 

assessment for particulate matter (“PM”) emissions from the Domtar Ashdown Mill Power 

Boiler No. 2.EPA refers to “the very low baseline visibility impacts” from that boiler’s PM 

emissions and the “potential for a very small amount of visibility improvement” from installation 

of emission controls for BART. Id. at 18,988. EPA further notes that the unit is subject to a 

“maximum achievable control technology,” or “MACT,” standard for its PM emissions under 

section 112 of the CAA and that the BART Guidelines provide that PM emission sources 

regulated by MACT standards generally may rely on compliance with those standards to satisfy 

BART requirements for their PM emissions. Id. 

UARG stated that in sum, it is appropriate and consistent with the BART Guidelines for EPA to 

make a streamlined BART assessment where, as in the circumstances discussed above, no 

reasonable possibility exists that installation and operation of BART emission controls could 

feasibly and cost-effectively produce appreciable visibility improvement in relevant Class I 

areas. 

Response: We appreciate UARG’s support of the streamlined approach we took for making 

BART determinations for these sources. 

Comment: The statutory factors support EPA’s determination that a scrubber is SO2

BART for Flint Creek Unit 1. [Sierra Club et. al. (0171) p. 12-13] Sierra Club et. al. stated that 

the statutory BART factors—in addition to cost effectiveness—support EPA’s determination that 

BART limits for SO2 emissions from Flint Creek should be based on the use of a scrubber. See 

42 U.S.C. § 7491(g)(2); 40 C.F.R. § 51.308(e)(1)(ii)(A). First, EPA has reasonably considered 

the degree of visibility improvement that is expected to result from the use of a scrubber at Flint 

Creek. AEP’s modeling, on which EPA relies, indicates that the installation of a NID scrubber at 

Flint Creek would result in significant visibility improvements at all four Class I areas that were 

considered (relying on 98th percentile impacts): .615 dv (Caney Creek); 0.464 dv (Upper 

Buffalo); 0.414 (Mingo); and 0.345 dv (Hercules-Glades). 80 Fed. Reg. at 18,966. These 

visibility improvements are significant and securing them is essential to achieving the national 
244

visibility goal. Second, EPA appropriately considered the existing SO2 controls for Flint Creek 

(i.e., there are none), and recognized also that Flint Creek primarily burns low-sulfur coal. 80 

Fed. Reg. at 18,964; Stamper Report at 3. Third, EPA appropriately evaluated the energy and 

non-air quality environmental impacts of compliance and reasonably determined that no such 

impacts argued against selection of a scrubber as SO2 BART for Flint Creek. See 80 Fed. Reg. at 

18,966. EPA noted that some energy impacts (i.e., the potential increased power requirements of 

wet scrubbers) were included in the cost-effectiveness calculations. Id. Finally, EPA reasonably 

considered the remaining useful life of the source, as it noted that AEP has not established any 

shutdown date and thus the anticipated useful life of the boiler should be as long as the capital 

cost recovery period of controls. See id. at 18,967. As Ms. Stamper notes, an equipment life of 

30 years is an appropriate assumption for determining cost effectiveness of wet and dry 

scrubbers as many such control systems have been operated for longer than 30 years. Stamper 

Report at 9. 

Response: We appreciate the commenter’s support of our determination that SO2 BART for 

Flint Creek Unit 1 is an emission limit that is based on the use of a scrubber. 

Comment: The statutory factors support EPA’s determination that scrubbers are SO2

BART for White Bluff Units 1 and 2. [Sierra Club et. al. (0171) p. 22] Sierra Club et. al. stated 

that the other BART statutory factors—in addition to cost effectiveness—also support EPA’s 

determination that a scrubber is SO2 BART for White Bluff. See 42 U.S.C. § 7491(g)(2) 40 

C.F.R. § 51.308(e)(1)(ii)(A). First, EPA has reasonably considered the degree of visibility 

improvement that is expected to result from the use of a scrubber at White Bluff. Entergy’s 

modeling, on which EPA relies, indicates that the installation of a dry scrubber at White Bluff 

Unit 1 would result in significant visibility improvements at all four Class I areas that were 

considered (relying on 98th percentile impacts): 0.813 dv (Caney Creek); 0.762 dv (Upper 

Buffalo); 0.683 dv (Hercules-Glades); and 0.620 (Mingo). 80 Fed. Reg. at 18,972. The modeled 

visibility improvements resulting from operation of a dry scrubber at White Bluff Unit 2 are 

similarly significant though, with the exception of Upper Buffalo, slightly less than the visibility 

improvement predicted for Unit 1. See id. Entergy’s modeling for a wet scrubber at White Bluff 

Units 1 and 2 shows similar visibility improvements as compared to dry scrubbers, with slightly 

larger improvements predicted for the Arkansas Class I areas and slightly smaller improvements 

for the Missouri Class I areas. See id. These visibility improvements are significant and securing 

them is essential to achieving the national visibility goal. Second, EPA appropriately considered 

the existing SO2 controls for White Bluff (i.e., there are none.). 80 Fed. Reg. 18,969; Stamper 

Report at 28. Third, EPA appropriately evaluated the energy and non-air quality environmental 

impacts of compliance and reasonably determined that no such impacts argued against selection 

of a scrubber as SO2 BART for White Bluff. See 80 Fed. Reg. 18,971-72. EPA noted that some 

energy impacts (i.e., the potential increased power requirements of wet scrubbers) were included 

in the cost-effectiveness calculations. Id. at 18,972. Finally, EPA reasonably considered the 

remaining useful life of the source, as there is no indication in the record that Entergy has 

established any shutdown date for the White Bluff units and thus the anticipated useful life of 

these boilers should be as long as the capital cost recovery period of controls. As Ms. Stamper 

notes, an equipment life of 30 years is an appropriate assumption for determining cost-
245

effectiveness of wet and dry scrubbers as many such control systems have been operated for 

longer than 30 years. See Stamper Report at 9, 41. 

Response: We appreciate the commenter’s support of our determination that SO2 BART for 

White Bluff Units 1 and 2 is an emission limit that is based on the use of a scrubber. 

4.g. Other 

Comment: [Domtar (0161) p. 5] Domtar stated that a description of the Power Boiler 1 and 

Power Boiler 2 begins on page 18978 of the proposal. With respect to the description of heat 

input ratings, the word “maximum” should be used. For Power Boiler 1, the average steaming 

rate is approximately 130,000 lb/hr and for Power Boiler 2, the average steaming rate is 

approximately 340,000 lb/hr. 

Response: We acknowledge the comment and agree that the description of heat input ratings in 

our proposed FIP at 80 FR at 18978-79 refers to maximum heat input rating. We also appreciate 

the correction provided by the commenter for the average steaming rate for Power Boiler 1 and 

Power Boiler 2. These errors did not affect our proposed BART determinations. 

Comment: [Domtar (0161) p. 14] Domtar stated that assuming EPA proceeds with BART for 

the Ashdown Mill, the Mill agrees with the proposed BART NOX limit for Power Boiler 2 of 345 

lb/hr on a 30 boiler operating day averaging basis. However, the preamble discussion on pages 

18987-18988 discusses the installation of LNB and further comments that the emission limit of 

345 lb/hr (on a 30 boiler operating day rolling average basis) is based on the installation and 

operation of LNB. As noted in the proposed rule text and in the associated table on page 19003, 

the limit is not tied to the installation of LNB. EPA needs to correct the preamble discussion to 

remove the references to installing and operating LNB. 

Response: We appreciate the commenter’s support of our proposed NOX BART emission limit 

for Power Boiler 2 of 345 lb/hr on a 30 boiler operating day averaging basis. We are finalizing 

this emission limit. While this limit was determined based on the NOX emission rate expected 

from the installation and operation of LNB at Power Boiler No. 2, we agree with the commenter 

that Domtar is not required to install LNB to comply with this emission limit. Domtar is free to 

choose any technology that meets the NOX limit we are establishing. 

Comment: EPA should withdraw the BART emission limits for Bailey Unit 1 if the State 

submits to EPA a revised Regional Haze SIP contains a demonstration that the unit is not 

subject to BART. [UARG (0176) p. 7] UARG stated that in light of revised modeling 

concerning the visibility impacts of emissions from Bailey Unit 1, as described by EPA in the 

proposed rule, see 80 Fed. Reg. at 18,949, EPA should withdraw the proposed BART emission 

limits (or, if the Agency promulgates those limits at the conclusion of this rulemaking, should 

subsequently rescind those limits) if the state submits to EPA a revised regional haze SIP that 

contains or reflects the demonstration that EPA acknowledges has already been made that that 
246

unit is not properly deemed subject to BART. EPA notes that revised modeling conducted after 

EPA promulgated its 2012 final rule on the Arkansas SIP “shows visibility impacts from Bailey 

Unit 1 below 0.5 dv, which is the threshold used by Arkansas to determine if a source is subject 

to BART.” Id. EPA thus does not dispute that the newer modeling shows that Bailey Unit 1 has 

only a below-threshold impact, see id., but assert that at this time it lacks “discretion to reopen 

the issue of whether the source is subject to BART because we [i.e., EPA] already approved the 

portion of the 2008 Arkansas [regional haze] SIP in which Arkansas determined AECC Bailey 

Unit 1 is subject to BART and Arkansas has not provided us a SIP revision to replace the 

previous determination.” Id. (footnote omitted). EPA should commit to promptly withdraw the 

proposed FIP BART emission limits for Bailey Unit 1, or to rescind any final FIP BART 

emission limits that EPA may hereafter promulgate for this unit, if Arkansas submits a SIP 

revision containing a determination that the unit is not subject to BART. 

Response: We disagree with the commenter that in our proposed FIP we made the admission 

that ADEQ has made a demonstration that AECC Bailey Unit 1 “is not properly deemed subject 

to BART.” In our proposal we merely made the observation that the revised modeling provided 

to us shows visibility impacts from Bailey Unit 1 below 0.5 dv, which is the threshold used by 

Arkansas to determine is a source is subject to BART.437 We also specifically stated that our 

proposal is not reconsidering or reopening the issue of whether the source is subject to BART 

because we do not have the discretion to do this.438

We are willing to work with ADEQ and the facility to develop a SIP that could replace our FIP. 

Such a SIP will need to meet the CAA and the Regional Haze regulations. We will take action on 

such SIP revision according to the statutory timeframes allowed under the CAA. Additionally, if 

such a SIP includes a determination made by the State that AECC Unit 1 is not subject to BART, 

ADEQ must include the appropriate supporting documentation to substantiate this. We will work 

with ADEQ during the SIP revision process to ensure the necessary supporting documentation is 

part of the SIP submittal. 

Comment: EPA’s NOX BART analysis for Lake Catherine Unit 4 did not adequately 

consider non-environmental impacts of BOOS, along with other statutory BART factors, 

and is therefore legally flawed. [Sierra Club et. al. (0171) p. 26-27] Sierra Club et. al. stated 

that EPA must base BART determinations on an analysis of the five statutory BART factors: (1) 

the costs of compliance, (2) the energy and non-air quality environmental impacts of compliance, 

(3) existing pollution controls in use at the source, (4) the remaining useful life of the source, and 

(5) the degree of visibility improvement. 42 U.S.C. §7491(g)(2); 40 C.F.R. § 51.308(e)(1)(ii)(A). 

The Lake Catherine Unit 4 BART analysis fails to accurately consider non-environmental 

impacts, along with compliance costs and the degree of visibility improvement. EPA incorrectly 

found that “there are not any energy or non-air quality environmental impacts associated with the 

operation of NOX controls at Entergy Lake Catherine Unit 4 that would affect our proposed 

BART determination.” 80 Fed. Reg. at 18,977. EPA and Entergy relied on a Sargent & Lundy 

May 2013 report to support their Lake Catherine Unit 4 NOX BART determination. Stamper 

Report at 53. Sargent & Lundy found, based on its BOOS testing, that Entergy would need to 

 

437 80 FR 18949. 438 80 FR 18949.
247

increase the firing rate of natural gas by approximately 25% to operate the unit at the same 

capacity factor. Id at 54. Neither EPA nor Entergy recognized the increased use of natural gas 

required for operation of BOOS in their Lake Catherine Unit 4 NOX BART analyses or analyzed 

the additional environmental impacts associated with increased fossil fuel use, such as increased 

greenhouse gas and toxic air emissions. Id. Sargent and Lundy found no need for increased 

natural gas usage with the other control scenarios. Id. 

Response: We acknowledge the information provided in the comment and in the attachments 

referenced in the comment. However, we disagree with the commenter that we made an incorrect 

finding that there are no energy or non-air quality environmental impacts associated with the 

operation of NOX controls at Entergy Lake Catherine Unit 4 that would affect our proposed 

BART determination. While BOOS could be expected to increase the firing rate of natural gas to 

operate the unit at the same capacity factor, other control options such as SCR typically have 

several associated impacts as well, including increased auxiliary power requirements, waste 

associated with catalyst replacement and disposal, ammonia slip, and the partial conversion of 

SO2 to sulfuric acid. As post combustion controls would result in increased power requirements 

to operate the control equipment, we expect that this too may indirectly result in increased fossil 

fuel use to a certain extent. However, we believe that the scope of the collateral impacts 

associated with the NOX control options we evaluated do not outweigh the benefits in terms of 

NOX emissions reductions and visibility improvement that would be provided by these controls. 

The commenter has not presented any specific data or information that establishes that the 

energy or nonair quality impacts of BOOS operation at Lake Catherine Unit 4 would make this 

option unacceptable. Thus, we continue to believe that there are no energy or non-air quality 

environmental impacts that warrant elimination of BOOS for Lake Catherine Unit 4. 

We address elsewhere in this document the commenter’s specific comments regarding 

consideration of compliance costs and degree of visibility improvement. 

5. Reliance on CSAPR Better than BART 

Comment: EPA is acting arbitrarily and inconsistently with its own past positions in 

requiring sources that are subject to the CSAPR to also control NOX emissions as BART. 

[ADEQ (0160) p. 4-8] ADEQ stated that presently, Arkansas is subject to a Cross-State Air 

Pollution Rule Federal Implementation Plan (“CSAPR FIP”) for ozone-season NOX. Despite 

EPA’s own guidance stating that CSAPR makes greater reasonable progress than BART for 

ozone-season NOX.

439 EPA makes no mention of CSAPR emissions controls in the Proposed FIP 

and requires BART for Electricity Generating Units (“EGUs”) that are subject to CSAPR. EPA 

should not require sources that are subject to the CSAPR FIP to also install BART or additional 

emissions controls based on a reasonable progress analysis, such as is the case with the Entergy 

Independence Plant. 

 

439 See Regional Haze: Revisions to Provisions Governing Alternatives to Source-Specific Best Available Retrofit 

Technology (BART) Determinations, Limited SIP Disapprovals, and Federal Implementation Plans, 77 FR 33642 at 

3365-33651. 
248

ADEQ stated that on May 12, 2005, EPA published the Clean Air Interstate Rule (“CAIR”), 

which was intended to address interstate transport of air pollution as required by §110(a)(2)(D) 

of the CAA.440 The rule affected 28 states and the District of Columbia and included a cap-andtrade program targeting SO2 and NOX.

441 The rule required 25 states, including Arkansas, to 

reduce their state-wide emissions of NOX for the purposes of the 8-hour ozone National Ambient 

Air Quality Standard (“NAAQS”) by specifying ozone-season NOX emissions budgets.442 The 

emission limitations were intended to reduce or eliminate each state’s contributions to ozone air 

quality in other states, which would thereby help downwind states meet the 1997 ozone NAAQS. 

EPA approved Arkansas’s CAIR SIP submission on August 04, 2009.443 CAIR was heavily 

litigated and eventually remanded to EPA. However, CAIR remained in effect until EPA could 

promulgate a replacement, the result of which was CSAPR. 

ADEQ stated that EPA published CSAPR as a replacement to CAIR on August 8, 2011.444

Similar to CAIR, CSAPR requires certain states to reduce annual SO2 emissions, annual NOX

emissions and ozone season NOX emissions to assist with other states’ attainment of the 1997 

ozone NAAQS, the 1997 fine particulate matter with an aerodynamic diameter less than or equal 

to a nominal two and one-half (2.5) micrometers (PM2.5) NAAQS, and the 2006 fine particulate 

matter with an aerodynamic diameter less than or equal to a nominal ten (10) micrometers PM2.5 

NAAQS. Initially, CSAPR addressed emissions from Electric Generating Units (“EGUs”) 

beginning in the year 2012. However, CSAPR was also subject to litigation, which prompted a 

stay of the rule until litigation was concluded. The Supreme Court upheld CSAPR,445 and EPA 

published an interim final rule on December 3, 2014 revising the CSAPR compliance 

deadlines.446 CSAPR became effective on January 1, 2015.447

ADEQ stated that the Regional Haze Rule allows states to implement an alternative program in 

lieu of BART so long as the alternative program has been demonstrated to achieve greater 

reasonable progress toward the national visibility goal than would BART.448 EPA proposed that 

a state in the CAIR trading program would be allowed to rely on EPA’s determination that CAIR 

makes greater reasonable progress than source-specific NOX controls.449 In the final Transport 

rule, EPA demonstrated that CSAPR, which replaced CAIR, would make greater reasonable 

progress toward national visibility goals than would BART.450

 

 

440 See Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule); 

Revisions to Acid Rain Program; Revisions to the NOX SIP Call, 70 FR 25162. 441 Id. 442 Id. 443 74 FR 38536. 444 See Federal Implementation Plans: Interstate Transport of Fine Particulate Matter and Ozone and Correction of 

SIP Approvals, 76 FR 48208. 

445 See E.P.A. v. EME Homer City Generation, L.P., 134 S. Ct. 1584, 1587, 188 L. Ed. 2d 775 (2014). 446 Rulemaking To Amend Dates in Federal Implementation Plans Addressing Interstate Transport of Ozone and 

Fine Particulate Matter, 79 FR 71663. 

447 79 FR 71663. 448 40 C.F.R. § 51.308(e); 77 FR 33642. 449 Regional Haze: Revisions to Provisions Governing Alternatives to Source-Specific Best Available Retrofit 

Technology (BART) Determinations, Limited SIP Disapprovals, and Federal Implementation Plans” proposed rule, 

76 FR 82219. 

450 See 77 FR 33642. 
249

ADEQ stated that consistent with the requirements of the Regional Haze Rule, EPA found that 

the CSAPR trading program did not cause degradation in any affected Class I area.451 In 

addition, EPA found that CSAPR implementation combined with implementation of BART 

elsewhere achieved greater visibility improvement on both the 20% best and 20% worst days.452

As a result, EPA found that CSAPR met all requirements under 40 C.F.R. § 51.308(e)(4) to 

qualify as a substitute for BART. 

ADEQ stated that EPA concluded in the final rule that a state in the CSAPR region whose EGUs 

are subject to the requirements of the CSAPR trading program for ozone season NOX may rely 

on its determination that CSAPR makes greater reasonable progress than source-specific BART. 

EPA specifically noted that “[t]he states to which this aspect of our final rule applies are 

Arkansas, Florida, Louisiana, Mississippi and Oklahoma.”(emphasis added).453 Despite EPA’s 

demonstration that CSAPR makes greater reasonable progress than source-specific BART, EPA 

has nevertheless proposed NOX BART for certain units covered by CSAPR in the Proposed FIP. 

ADEQ stated that the approach that EPA has proposed for Arkansas is inconsistent with that 

taken for other States. EPA promulgated FIPs to replace reliance on CAIR with reliance on 

CSAPR for the following states: Georgia, Indiana, Iowa, Kentucky, Michigan, Missouri, Ohio, 

Pennsylvania, South Carolina, Tennessee, Virginia and West Virginia.454 Similarly, Virginia is 

revising the Virginia Regional Haze SIP to rely on the Virginia CSAPR FIP to meet BART and 

reasonable progress requirements for SO2 and NOX.

455

ADEQ stated that perhaps most noteworthy, EPA has proposed reliance on CSAPR in states that 

border Arkansas. The Texas-Oklahoma Regional Haze Plan does not require BART for sources 

that are subject to CSAPR.456 In that plan, EPA reiterates its position that “CSAPR, like CAIR, 

provides for greater reasonable progress towards the national goal than would BART.”457 EPA 

proposes replacing reliance on CAIR with reliance on the trading programs of CSAPR as an 

alternative to BART for SO2 and NOX emissions from EGUs.458

ADEQ stated that not only is EPA requiring sources subject to CSAPR to control emissions as 

BART in the Proposed FIP, but EPA has not even considered CSAPR as an option for making 

reasonable progress. Even if EPA ultimately rejected CSAPR as a means to meet the reasonable 

progress requirements under the Regional Haze Rule, EPA is required to “cogently explain why 

 

451 Id. at 33652. 452 77 FR 33642 at 33648. 453 77 FR 33642. 454 Id. 455 Virginia Dep’t of Env. Quality, Commonwealth of Virginia State Implementation Plan, available at 

http://www.deq.state.va.us/Portals/0/DEQ/Air/PublicNotices/Drafts/mspro.pdf 456 Approval and Promulgation of Implementation Plans; Texas and Oklahoma; Regional Haze State Implementation 

Plans; Interstate Transport State Implementation Plan To Address Pollution Affecting Visibility and Regional Haze; 

Federal Implementation Plan for Regional Haze and Interstate Transport of Pollution Affecting Visibility, 79 FR 

74818. 

457 79 FR 74818 at 74851. 458 79 FR 74818 at 74853 (the proposed [Texas-Oklahoma] FIP ... substitutes Texas' reliance on the Clean Air 

Interstate Rule (CAIR) to satisfy BART requirements at its EGUs with reliance on CAIR's successor, the CrossState Air Pollution Rule (CSAPR)).” 
250

it has exercised its discretion in a given manner.”459 EPA’s failure to consider CSAPR is 

arbitrary and capricious in light of its treatment of other states. 

ADEQ stated that as a result of EPA’s position that CSAPR provides for greater reasonable 

progress than source-specific NOX, facilities subject to the CSAPR FIP should not also be 

required to install, operate, or maintain BART for NOX. In Arkansas, the following units should 

not be required to install the NOX BART proposed by EPA in the Proposed FIP because they are 

also subject to CSAPR for ozone-season NOX: (1) AEP Flint Creek Unit One; (2) Entergy White 

Bluff Unit One; (3) Entergy White Bluff Unit Two; and (4) Entergy Lake Catherine Unit Four.460

Accordingly, EPA should withdraw the Proposed FIP and remove the requirements that the 

aforementioned units be subject to BART in addition to CSAPR emissions controls for ozone 

season NOX in any subsequently proposed plan. 

 

[Entergy Arkansas Inc. (0166) p. 13] Entergy stated that NOx BART for all EGUs in Arkansas, 

including White Bluff, should be compliance with CSAPR given that EPA already has 

determined that CSAPR is better than BART. 77 Fed. Reg. 33,642 (June 7, 2012). EPA has 

proposed to take this same approach in the Texas Regional Haze FIP and has approved several 

state regional haze SIPs that adopted this approach. Proposed Texas Regional Haze FIP, 79 Fed. 

Reg. at 74,821; see also Proposed Pennsylvania SIP Approval, 80 Fed. Reg. 2,841, 2,844 (Jan. 

21, 2015); Final Minnesota SIP Approval, 77 Fed. Reg. 34,801, 34,801-02 (June 12, 2012). EPA 

should adopt this same approach in the final Arkansas Regional Haze FIP and provide that 

compliance with CSAPR is NOX BART for all of Arkansas’ EGUs. 

[AEP-SWEPCO July 15, 2015 comments (0164) p. 1-3, and August 7, 2015 comments (0167) p. 

2-4] AEP-SWEPCO stated it disagrees with EPA’s proposed LNB/OFA controls for NOX for the 

Flint Creek Power Plant. EPA issued a final rule allowing states that are subject to the CSAPR 

trading program for seasonal NOX to rely on the reductions achieved through that trading 

program to satisfy the regional haze program requirements for units subject to BART.461 

AEP-SWEPCO stated that EPA has an obligation to issue a FIP within 2 years of disapproving a 

SIP to correct identified deficiencies. In preparing a FIP to address those deficiencies, EPA 

should select and propose options that are in the best interests of all stakeholders. EPA makes no 

mention of CSAPR=BART in their proposed FIP. Although ADEQ did not propose 

CSAPR=BART in their submitted SIP, EPA should have evaluated that alternative in developing 

the FIP. AEP-SWEPCO specifically identified CSAPR=BART in the five factor analysis 

 

459 Nat'l Parks Conservation Ass'n v. E.P.A., No. 12-73710, 2015 WL 3559149, at *3 (9th Cir. June 9, 2015); (citing 

Motor Vehicle Mfrs. Ass'n of U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 48, (1983)); Greater 

Yellowstone Coalition, Inc. v. Servheen, 665 F.3d 1015, 1030 (9th Cir.2011) (requiring “a rational connection 

between the data before [the agency] and its conclusion”); Nw. Envtl. Def. Ctr. v. Bonneville Power Admin., 477 

F.3d 668, 691 (9th Cir.2007). 

460 EPA has included Independence as a “Reasonable Progress Source” in the Proposed FIP rather than a source that 

is subject-to-BART. This distinction is important as there is no definitive process that EPA has described for 

determining the degree of control it might require for a specific “Reasonable Progress Source.” Independence, being 

already subject to CSAPR should not be included in any discussion of BART controls.

461 See Regional Haze: Revisions to Provisions Governing Alternatives to Source-Specific Best Available 

Technology (BART) Determinations, Limited SIP Disapprovals and Federal Implementation Plans" 77 Fed. Reg. 

33651 (June 7, 20 12).
251

submitted to ADEQ462 as the primary option for compliance with NOX at the Flint Creek facility. 

The BART analysis for NOX was conducted as a second option because CAIR, CSAPR, and the 

state regional haze SIP were all in a state of flux during the time the five-factor analysis was 

being conducted. EPA did not address that issue in the section of the FIP that discusses the Flint 

Creek facility. 

AEP-SWEPCO stated that EPA has made clear their determination that CSAPR is “better than 

BART” in addressing NOX in ozone season only states. If CSAPR is indeed “better” than BART 

for NOX, then EPA should have proposed the CSAPR trading program as an alternative to BART 

and selected that program in the regional haze FIP for addressing NOX emissions. Regardless of 

implementation of the Regional Haze Rule, CSAPR will be in effect in Arkansas and NOX

emissions will be reduced accordingly. It is unnecessary to also require site-specific NOX

reduction controls which will result in reduced flexibility and increased costs without providing 

any additional visibility improvements. It should also be noted that EPA recently issued a FIP for 

Texas proposing “... reliance on the trading programs of CSAPR as an alternative to BART for 

SO2 and NOX emissions from EGUs in the regional haze plan for Texas.”463 EPA also “... found 

that CSAPR, like CAIR, provides for greater reasonable progress towards the national goal than 

would BART.”464 The same approach should be allowed in Arkansas for NOX emissions. EPA 

should establish CSAPR=BART for NOX and eliminate all site specific NOX controls identified 

in the Arkansas FIP. 

[AECC (0169) p. 6-7] AECC stated that the latest Transport Rule is CSAPR. Arkansas is subject 

to the CSAPR ozone season NOX trading program. EPA's own guidance states that CSAPR 

makes greater reasonable progress than BART for ozone season NOX. EPA specifically states, " 

... a state in the Transport Rule region whose EGUs are subject to the requirements of the 

Transport Rule trading program only for ozone season NOX is allowed to rely on our 

determination that the Transport Rule makes greater reasonable progress than source-specific 

BART for NOX. The states to which this aspect of our final rule applies are Arkansas, Florida, 

Louisiana, Mississippi, and Oklahoma.”465

AECC stated that there is no mention of CSAPR compliance in EPA’s proposed Arkansas FIP, 

and yet EPA requires BART for EGUs that are subject to CSAPR. All EGUs in Arkansas rated 

25 megawatts or greater are subject to the seasonal NOX trading program under CSAPR; 

therefore, those EGUs should not be subject to additional BART controls for NOX. Specifically, 

the NOX controls for the Flint Creek and White Bluff units should be removed from the proposed 

FIP. 

[Conway Corporation et. al. (0172) p. 12-13; and EEAA (0173) p. 4-5] Conway Corporation et. 

al. and the Energy and Environmental Alliance of Arkansas both stated that on May 30, 2012, 

EPA finalized the rule: “Regional Haze: Revisions to Provisions Governing Alternatives to 

 

462 BART Five Factor Analysis, Flint Creek Power Plant, Prepared by Trinity Consultants for American Electric 

Power Service Corp., September 2013, Version 4, page 6-l. 

463 79 Fed. Reg. 74818 December 16, 2014. 464 79 Fed. Reg. at 74853. 465 Regional Haze: Revisions to Provisions Governing Alternatives to Source-Specific Best Available Retrofit 

Technology (BART) Determinations, Limited SIP Disapprovals, and Federal Implementation Plans. 77 FR 

33652 (June 7, 2012).
252

Source-Specific BART Determinations, Limited SIP Disapprovals, and Federal Implementation 

Plans.466 This rule allows the trading programs in CSAPR to serve as an alternative to 

determining source-by-source BART. It provides that states in the CSAPR region can substitute 

participation in CSAPR for source-specific BART for SO2 and/or NOX emissions from power 

plants. This determination is commonly referred to as CSAPR being “better-than-BART.” EPA 

also determined “that a state in the CSAPR region whose EGUs are subject to the requirements 

of the CSAPR trading program only for ozone season NOX is allowed to rely on our 

determination that CSAPR makes greater reasonable progress than source-specific BART for 

NOX.”467 Arkansas is included in this determination, therefore the state’s subject-to-BART EGUs 

were not required to perform a five factor analysis of NOX emissions. Beginning May 1, 2015, 

CSAPR is in effect and being implemented in Arkansas. ADEQ is currently reevaluating the 

NOX emission limits that are in the disapproved SIP and considering appropriate revisions. EPA 

should have proposed the CSAPR trading program as an alternative to BART and selected that 

program in the Proposed Rule for addressing NOX emissions from Arkansas’ subject-to-BART 

sources, including AECC Bailey and McClellan plants, AEP/SWEPCO Flint Creek Plant and 

Entergy White Bluff and Lake Catherine468 Plants. 

Conway Corporation et. al. and EEAA stated that regardless of implementation of the regional 

haze program, CSAPR will be in effect in Arkansas and NOX emissions will be reduced 

accordingly. Thus, it is unnecessary to also require site-specific NOX reduction controls which 

will result in reduced flexibility and increased costs without providing any additional visibility 

improvements. EPA recently issued a FIP for Texas proposing “...reliance on the trading 

programs of CSAPR as an alternative to BART for SO2 and NOX emissions from electric 

generating units (“EGUs”) in the regional haze plan for Texas.469 EPA also “found that CSAPR 

provides for greater reasonable progress towards the national goal than would BART.”470 The 

same approach should be allowed in Arkansas for NOX emissions, and EPA should establish 

CSAPR=BART for NOX emissions and eliminate all site-specific NOX controls for Arkansas’ 

EGUs identified in the Proposed Rule. 

[Edison Electric Institute (0174) p. 2, 8-10] EEI stated that in the Arkansas FIP proposal, EPA 

makes no mention of its previous determination that “CSAPR=BART” in which EPA has 

previously made clear its determination that CSAPR is “better than BART” in addressing NOX in 

CSAPR ozone season-only states. See 79 Fed. Reg. at 74,818. EPA should have proposed the 

CSAPR trading program as an alternative to BART for Arkansas given the Agency’s prior 

determination. Id. EPA’s CSAPR=BART policy, which would apply to several Arkansas 

facilities—such as the Southwestern Electric Power Company’s Flint Creek facility—should be 

an acceptable option since the proposed site-specific NOX reduction controls will result in 

reduced flexibility and increased costs without providing any additional visibility improvements. 

 

466 77 Fed. Reg. 33643 (June 7, 2012). 467 Id. at 33652. 468 Alternatively, it appears that the CALPUFF modeling relied upon in support of the BART determinations for the 

Lake Catherine Plant predicts visibility improvements for Arkansas’ Class I areas which are within the CALPUFF 

model’s margin of error, and therefore such visibility benefits from the proposed BART controls cannot be 

reasonably anticipated (see Nat’l Parks Conservation Ass’n v. EPA, No. 12-73710, 2015 WL 3559149 (9th Cir. June 

9, 2015). 

469 79 Fed. Reg. at 74818. 470 Id. at 74853. 
253

See 80 Fed. Reg. at 18965-68. EPA should establish CSAPR=BART for NOX and withdraw all 

site-specific NOX controls identified in the Arkansas FIP. 

Response: Arkansas EGUs are subject to CSAPR for ozone season NOX, and we acknowledge 

that a state in the CSAPR region whose EGUs are subject to the requirements of the CSAPR 

trading program for ozone season NOX may rely on CSAPR to satisfy the NOX BART 

requirement for its EGUs. However, when standing in the shoes of a state and promulgating a 

FIP, EPA has the same discretion as the state to choose to either conduct source-specific BART 

determinations or to rely on EPA’s 2012 finding that CSAPR is better than BART. Our decision 

to make source-specific NOX BART determinations for Arkansas is reasonable for multiple 

reasons: it is the approach Congress chose in the statute itself;471 it is consistent with Arkansas' 

earlier decision to conduct source-specific NOX BART determinations in lieu of relying on CAIR 

to meet the BART requirements; and at the time of our proposed action, it properly accounted for 

uncertainty in the CSAPR better-than-BART regulation created by ongoing litigation regarding 

the CSAPR program. Further explanation of these reasons is given below. 

The Regional Haze regulations provide generally that “[a] State may opt” to rely on an emissions 

trading program rather than to require source-specific BART controls.472 More specifically, in 

2005 EPA revised the Regional Haze regulations to provide that a state subject to CAIR “need 

not require affected BART-eligible EGUs to install, operate, and maintain BART.”473 Following 

the D.C. Circuit’s vacatur and remand of CAIR,474 EPA issued CSAPR as a replacement rule. 

EPA revised its regulations in 2012 to allow states to rely on CSAPR in lieu of source-specific 

BART.475

In its 2008 regional haze SIP submittal, Arkansas decided to not rely on CAIR to satisfy the NOX

BART requirement for its EGUs.476 In our Regional Haze FIP proposal for Arkansas, we did not 

rely on CSAPR (the follow up rule to CAIR) to satisfy the NOX BART requirement for EGUs 

because we chose to follow the same source-specific approach to NOX BART that Arkansas 

selected in its Regional Haze SIP submittal. In addition, litigation surrounding CSAPR was 

ongoing at the time that we issued our proposed Arkansas Regional Haze FIP. CSAPR was 

issued in 2011, but on December 30, 2011, the D.C. Circuit stayed the rule prior to 

implementation. The D.C. Circuit subsequently vacated CSAPR, an action later reversed by the 

Supreme Court in 2014. The case was then remanded to the D.C. Circuit. Then, after our April 

2015 Regional Haze FIP proposal, the D.C. Circuit issued a July 2015 decision in EME Homer 

City Generation v. EPA477 upholding CSAPR but remanding without vacatur a number of the 

 

471 See CAA section 169A(g)(2) in which Congress defined the five factor analysis for determining BART but did 

not expressly provide for an alternative to source by source BART. 472 40 CFR 51.308(e)(2). 473 70 FR 39104, 39156 (July 6, 2005). 474 North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008). 475 77 FR 33642 (June 7, 2012). 476 As Arkansas did not rely on CAIR to satisfy requirements in the regional haze SIP, Arkansas is not included in 

the EPA’s limited disapproval of regional haze SIPs that relied on CAIR to satisfy certain regional haze 

requirements. See 77 FR 33643, at 33654. In that same rulemaking, the EPA promulgated FIPs to replace reliance 

on CAIR with reliance on CSAPR in many of those regional haze SIPs; however, Arkansas was likewise not 

included in that FIP action. 

477 795 F.3d 118 (D.C. Cir 2015). 
254

Rule’s state NOX and SO2 emissions budgets. Arkansas’ ozone season NOX budget is not itself 

affected by the remand. However, the Court’s remand of the affected states’ emissions budgets 

has implications for CSAPR better-than BART, since the demonstration underlying that 

rulemaking relied on the emission budgets of all states subject to CSAPR, including those that 

the D.C. Circuit remanded, to establish that CSAPR provides for greater reasonable progress 

than BART. As of the time EPA is taking this action to finalize Arkansas’ Regional Haze FIP, 

we are in the process of acting on the Court’s remand consistent with the planned response we 

outlined in a June 2016 memorandum.478

Our final action on the Arkansas Regional Haze FIP is consistent with our final action on the 

Texas Regional Haze FIP. Although we proposed to rely on CSAPR to address the NOX BART 

requirements for EGUs in Texas, we did not finalize that portion of our proposed Texas FIP 

given the uncertainty arising from the remand of the CSAPR budgets for Texas and other 

states.479 In light of the above, the comments that we are treating Arkansas differently than other 

states where EPA relied on CSAPR to meet the BART requirements are no longer applicable. 

As we have noted throughout this document, we are willing to work with ADEQ to develop a 

SIP revision that could replace our FIP. Such a SIP revision will need to meet the CAA and 

EPA’s Regional Haze regulations. In its SIP revision, ADEQ may elect to rely on CSAPR to 

satisfy the NOX BART requirements for Arkansas’ EGUs instead of doing source-specific NOX

BART determinations. Such an approach could be appropriate if, as we expect, the uncertainty 

created by the D.C. Circuit’s remand of the affected states’ emission budgets will shortly be 

resolved. 

With regard to the comment that we should not require EGUs that are covered under CSAPR to 

also install additional emissions controls under reasonable progress analysis, we disagree. In our 

2012 finding that CSAPR is better than BART, we stated that states with EGUs covered under 

CSAPR may rely on CSAPR to satisfy the BART requirement. However, controls under 

reasonable progress are a separate requirement from BART, and we disagree that states can rely 

on CSAPR to satisfy the reasonable progress requirements under section 51.308(d)(1). As 

explained in the 2005 rulemaking addressing reliance on CAIR, our determination that a trading 

program provides for greater reasonable progress than BART is not a determination that the 

trading program satisfies all reasonable progress requirements.480

We address elsewhere in this document comments alleging that the projected visibility 

improvement of NOX controls on Lake Catherine Unit 4 are within the CALPUFF model’s 

margin of error. 

Comment: The NOX controls EPA evaluated for Lake Catherine Unit 4 cannot be justified 

as BART, and instead of imposing source-specific controls on Lake Catherine Unit 4 and 

the other EGUs in Arkansas, EPA should find that CSAPR is better than NOX BART. 

[Entergy Arkansas Inc. (0166) p.53-54] Entergy stated that if EPA finalizes a determination that 

 

478 https://www3.epa.gov/airtransport/CSAPR/pdfs/CSAPR_SO2_Remand_Memo.pdf 479 81 FR 296, at 302. 480 70 FR at 39143; see also 77 FR at 33653 
255

Lake Catherine Unit 4 should be subject to NOX BART controls, EPA should not impose sourcespecific NOX controls on Lake Catherine Unit 4 but should instead find that CSAPR is better 

than NOX BART in Arkansas for all EGUs. Compliance with CSAPR will ensure that NOX

emissions from Arkansas’ EGUs are limited and will improve visibility in Arkansas’ Class I 

areas. 

Entergy stated that EPA also had evaluated controls other than BOOS for Lake Catherine Unit 4. 

See 80 Fed. Reg. at 18,976-78. Similar to BOOS, however, these controls would result in 

imperceptible visibility improvements in Arkansas’ Class I areas. Although Entergy did not 

evaluate the margin of error with respect to the CALPUFF predicted visibility improvement from 

these other controls, EPA had rejected these controls as NOX BART for Lake Catherine Unit 4 

based on costs and Entergy agrees with EPA’s determination that these controls should not be 

considered as NOX BART for Lake Catherine Unit 4. Specifically, Entergy agrees with EPA that 

the incremental cost-effectiveness of installing LNB/SOFA at Lake Catherine Unit 4 cannot be 

justified as BART. See id. at 18,978. Similarly, the installation of LNB/SOFA and selective noncatalytic reduction (“SNCR”) or selective catalytic reduction (“SCR”) cannot be justified as 

BART based on either average cost effectiveness or incremental cost effectiveness. Id. Lake 

Catherine Unit 4 is a peaking unit and operated at only a two percent capacity factor in 2014.481

The estimated incremental costs of installation of LNB/SOFA (at $14,246/ton), SNCR (at 

$16,029/ton), and SCR (at $11,767/ton) are simply not warranted for a unit that operates so 

infrequently. See id. At 18,978. Installation of these controls would require a massive capital 

investment and significant operation and maintenance costs that are impracticable for a peaking 

unit. 

Response: We address elsewhere in this document why it would not be appropriate to make a 

determination to rely on CSAPR as an alternative to NOX BART for EGUs in Arkansas at this 

time. As discussed elsewhere in this document, we are finalizing source-specific NOX BART 

determinations for Arkansas’ EGUs, including Lake Catherine Unit 4. 

We acknowledge the commenter’s support of our proposed determination that LNB/SOFA, 

SNCR, and SCR are not BART for Lake Catherine Unit 4. We disagree that BOOS would result 

in imperceptible visibility improvements in the affected Class I areas and that we should 

therefore not require BOOS controls for NOX BART. We address elsewhere in this document 

comments on this issue, including comments alleging that the projected visibility improvement 

of NOX controls on Lake Catherine Unit 4 are within the CALPUFF model’s margin of error. As 

discussed in our proposal and elsewhere in this document, BOOS controls are expected to result 

in meaningful visibility improvement in the affected Class I areas and is very cost effective 

($138/ton removed). Therefore, we are finalizing our proposed determination that NOX BART 

for Lake Catherine Unit 4 for the natural gas firing scenario is an emission limit of 0.22 

lb/MMBtu on a 30 boiler-operating-day average consistent with the installation and operation of 

BOOS. 

 

481 Entergy’s current resource planning assumption is that Lake Catherine Unit 4 will be de-activated in mid-2025, 

though no final decision to this effect has yet been made. 
256

Comment: CSAPR could not possibly serve as a BART control because CSAPR does not 

regulate SO2 emissions from Arkansas sources and regulates NOX emissions only during 

the ozone season. [Sierra Club et. al. (0171) p. 46] Sierra Club et. al. stated that other 

commenters claim that EPA errs in not at least considering CSAPR as a potential control in the 

BART analysis. This argument fails for at least two reasons. First, Arkansas sources are not 

subject to SO2 limits under CSAPR. See 77 Fed. Reg. 34,830, 34,845 (June 12, 2012).482 Given 

that CSAPR does not limit SO2 emissions from any Arkansas sources, the commenters’ 

suggestion that CSAPR could represent the best available technology for reducing SO2 emissions 

is plainly incorrect. 

CSAPR contains unit-level allocations for NOX emissions for several Arkansas sources for 

which EPA is proposing BART determinations. However, under CSAPR, Arkansas sources are 

subject to NOX emission limits only during the ozone season. 77 Fed. Reg. at 34,845. CSAPR 

contains no annual NOX emission limits for Arkansas sources. 

By contrast, BART represents a year-round limit on emissions. See 40 C.F.R. § 51.301 (BART is 

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

existing stationary facility.”). Given that CSAPR does not limit annual NOX emissions from 

Arkansas sources, CSAPR cannot satisfy the NOX BART requirements for annual emission 

limits on Arkansas sources. EPA therefore acted properly by not considering CSAPR as a 

potential control in the BART analysis for NOX emissions. 

Response: We acknowledge the background information provided by the commenter. We agree 

that since Arkansas is not subject to CSAPR for SO2, Arkansas EGUs cannot rely on CSAPR to 

satisfy the SO2 BART requirements. For the reasons discussed elsewhere in this document, we 

are finalizing source specific NOX BART determinations for Arkansas EGUs subject to BART 

instead of relying on CSAPR to satisfy the NOX BART requirement. 

Comments disagreeing with our finding that CSAPR is “better-than-BART” for states subject to 

CSAPR for ozone season NOX only (77 FR 33642) are outside the scope of today’s rulemaking.

6. Cost 

6.a. Cost Analyses and Cost Effectiveness Issues 

Comment: EPA underestimated the costs of scrubbers at White Bluff by basing its cost 

analysis on Entergy’s outdated cost estimate, eliminating legitimate costs, using the IPM 

cost model, and revising Entergy’s assumed uncontrolled SO2 emission rate. 

[Entergy Arkansas Inc. (0166) p. 8-11] EAI stated that EPA based its cost calculations for dry 

FGD on the costs provided by Entergy in its Revised White Bluff BART Analysis, and presented 

its analysis of the costs for scrubber installation at White Bluff in its SO2 Cost TSD. However, 

 

482 See also Unit Level Allocations Under the CSAPR FIPs After Tolling, available at 

http://www.epa.gov/crossstaterule/actions.html
257

EPA’s analysis is full of errors, which resulted in an underestimation of the scrubber costs at 

White Bluff by approximately $200 million. 

First, the costs in the Revised White Bluff BART Analysis are significantly outdated, and EPA 

failed to adequately account for this factor in its analysis. The costs for a dry scrubber provided 

in the Revised White Bluff BART Analysis were based on (1) a study provided to Entergy by 

S&L in 2009, which provided a line-itemized cost estimate that included contractor equipment, 

material, and labor costs for two semi-dry scrubbing systems; and (2) costs provided by Alstom 

in December 2009 to supply two semi-dry scrubbing systems, escalated by 10% based on 

updated price information from Alstom. SO2 Cost TSD, at 2. However, even with the updated 

cost information from Alstom, the information provided in the Revised White Bluff BART 

Analysis is now at least five years out of date and significantly undervalues the costs of installing 

dry scrubbers at White Bluff. EPA attempted to address this issue by escalating the Alstom cost 

information to 2013 dollars using the Chemical Engineering Plant Cost Indices (CEPCI). 

However, EPA’s use of the CEPCI inadequately escalated the projected vendor costs. According 

to S&L, EPA underestimated escalation significantly using the CEPCI – by over $36 million – 

rather than using updated vendor pricing. S&L FIP Cost Report at 11. Further, this 

underestimation of the cost escalation was carried throughout EPA’s analysis in the SO2 Cost 

TSD and resulted in a total underestimation of the costs for scrubber installation of over $85 

million. Id. at 12, Table 7. 

Second, EPA improperly excluded from the cost calculation legitimate costs that Entergy would 

incur to install dry scrubbers at White Bluff. EPA incorrectly eliminated over $115 million in 

costs from Entergy’s cost analysis. See S&L FIP Cost Report at 8, 10. EPA mistakenly assumed 

certain Balance of Plant (“BOP”) costs were included in the Alstom scope of work, so it 

eliminated these costs as duplicative. As the S&L FIP Cost Report explains, EPA improperly 

eliminated several BOP costs from Entergy’s cost analysis: costs for the reagent handling 

system; costs for the ductwork to supply the flue gas to the SDA and the ductwork from booster 

fans to the existing chimney; the costs to apply an acid resistant coating to the chimney shell to 

protect the concrete from downwash effects; the costs associated with replacing the continuous 

emissions monitoring systems (CEMS) and associated recalibration and testing costs; and costs 

calculated as percentages of the BOP equipment, material and labor costs. In total, by 

eliminating these costs, EPA underestimated the BOP costs by approximately $31 million. Id. At 

8. EPA also suggested that the costs for one absorber vessel could be eliminated but cited no 

basis for its assumption that two absorber vessels are adequate for White Bluff. Entergy 

disagrees with EPA’s assumption regarding the number of absorber vessels for White Bluff. See 

S&L FIP Cost Report at 17. 

EPA also eliminated approximately $41.7 million for Entergy’s Owner’s costs,483 despite the fact 

that such costs are allowed under EPA’s Coal Quality Environmental Cost (CUECost) model. Id. 

at 10. EPA claimed that such costs had not been documented, were duplicative of other costs or 

did not appear to be valid costs under the Control Cost Manual methodology. 80 Fed. Reg. at 

18,971. For example, EPA improperly eliminated Entergy’s capital suspense costs without 

explaining why such costs were duplicative of other costs or not valid under the Control Cost 

 

483 These same improper exclusions were made with respect to EPA’s analysis of BART controls for NOx at White 

Bluff and Lake Catherine Unit 4. 
258

Manual methodology. Capital expenditure costs include both direct assigned and allocated 

expenses. Allocated expenses represent overhead costs associated with administrators, engineers 

and supervisors to the capital projects for which they provide services. Each function at Entergy 

charges its overhead costs to a “Capital Suspense” project, which is then allocated to the 

appropriate capital project. Capital suspense, therefore, is a distribution of overhead costs 

associated with administrators, engineers, and supervisors and includes function specific rates 

and Administrative and General (“A&G”) (Corporate Accounting) rates. Because capital 

suspense costs are a portion of total capital expenditure costs, these costs are not duplicative of 

other costs.484 For example, capital suspense costs do not include labor, administrative, and 

related elements that are present in Entergy’s Internal Control costs. See SO2 Cost TSD at 9. It 

was entirely proper for Entergy to include these costs in its control technology cost estimates. 

According to EPA’s Control Cost Manual, overhead costs should be counted in the total annual 

cost of a project. Total annual cost is comprised of direct costs, indirect costs, and recovery 

credits. Control Cost Manual at 2-7. Indirect costs specifically include overhead costs. Id. at 2- 

8; 3-32. 

Third, EPA significantly under-estimated the direct Operating and Maintenance (“O&M”) costs 

projected for the scrubbers by using its Integrated Planning Model (“IPM”) Spray Dryer 

Absorber (“SDA”) cost model to scale the O&M costs rather than estimating these costs using 

current utility pricing information. See SO2 Cost TSD at 14, Table 8. The IPM model includes 

several assumptions that fail to take into account site-specific factors. S&L FIP Cost Report at 

13-14. Accordingly, the IPM model is not consistent with the BART Guidelines, which requires 

a source-specific evaluation of controls costs. BART Guidelines, at Section IV.D.5. EPA also 

erroneously scaled the indirect annual costs, all of which were estimated as percentages of 

capital cost, by using a scaling factor that did not depend at all on the capital costs. See S&L FIP 

Cost Report at 17. 

Fourth, in the design for the dry scrubbers, the Revised White Bluff BART Analysis had 

assumed that White Bluff would burn a coal corresponding to an uncontrolled SO2 emission rate 

of 2.0 lb/MMBtu, which is in excess of the sulfur level of the coals the units have historically 

burned. EPA criticized Entergy for this assumption and revised the White Bluff baseline 

emission rates and projected post-control emission rates used for the cost effectiveness analysis. 

See SO2 Cost TSD at 12-14. However, it is proper, when conducting a BART cost analysis, to 

consider future fuel flexibility. The BART Guidelines advise that “[t]he baseline emissions rate 

should represent a realistic depiction of anticipated annual emissions for the source.” 70 Fed. 

Reg. 39,104, 39,167 (July 6, 2005) (codified at 40 C.F.R. Part 51 App. Y). Although the BART 

Guidelines explain that anticipated annual emissions are generally estimated based on annual 

emissions from a baseline period assuming conditions of past practice, id. at 39,167-68, EPA has 

approved BART determinations that assume “worst-case coal scenarios.” See Proposed Arizona 

Regional Haze FIP, 79 Fed. Reg. 9,318, 9,325-26 (Feb. 18, 2014); Proposed North Dakota 

Regional Haze FIP, 76 Fed. Reg. 58,570, 58,584-85 (Sept. 21, 2011). Hourly CEMS data 

confirm that EPA’s selection of 0.68 lb/MMBtu as the design basis for the capital costs is 

completely inadequate and would not achieve compliance with the FIP-proposed emission limit 

of 0.06 lb/MMBtu unless fuel sulfur limitations were imposed. Based on historical data and 

 

484 Entergy had previously supplied this information on capital suspense costs to EPA. See 80. Fed. Reg. at 18,971, 

n. 55.
259

potential fuels that can be fired at White Bluff, 1.2 lb/MMBtu is an appropriate fuel sulfur level 

to design dry FGD systems for White Bluff. See S&L FIP Cost Report at 15-16. 

If Entergy were constrained as to the type of coal that it could burn at White Bluff after the 

installation of controls, it would be necessary to reflect such a constraint in the cost of 

compliance, as it would force Entergy to continue purchasing higher-cost, low sulfur coal. 

Historically, Entergy has purchased lower sulfur coal than required by permit to ensure full 

compliance with applicable emission rates and to minimize costs of compliance with marketbased emission programs. If White Bluff were to install BART controls, such considerations 

would become less meaningful and lower-cost, higher sulfur coal would enable Entergy to meet 

its BART obligations for less cost. Nonetheless, in the S&L FIP Cost Report, S&L used White 

Bluff’s current emission rate of 0.68 lb/MMBtu to evaluate site-specific O&M costs. S&L FIP 

Cost Report at 15. 

Finally, although Entergy removed Allowance for Funds Used During Construction (AFUDC) 

from the final Revised White Bluff BART Analysis in response to comments from EPA on the 

Proposed White Bluff BART Analysis, Entergy disagrees with EPA that AFUDC should not be 

considered in the control costs.485 AFUDC is the time value of money on the investment in the 

technology that is incurred during the construction, which could reach $30 million to $60 million 

during the 30-46 months of construction that would be needed to install major control equipment 

such as scrubbers on a large unit. AFUDC includes the interest as part of the capital cost, which 

is standard accounting and rate-making treatment of such costs and it was appropriate for 

Entergy to have initially included AFUDC in the White Bluff control costs. In its comments on 

the Proposed White Bluff BART Analysis, EPA claimed that AFUDC is not allowed by EPA’s 

Control Cost Manual because “the CCM uses overnight costing methodology.” EPA Region 6 

Comments on White Bluff BART Analysis, at 1 (Aug. 21, 2013) EPA Docket ID EPA-R06-

OAR-2015-0189-0044. However, contrary to EPA’s assertion, the Control Cost Manual does not 

even address the use of the overnight methodology as being the basis for estimating costs. See 

S&L FIP Cost Report at 6. In fact, the calculation provided as an example in the Control Cost 

Manual specifically includes AFUDC as a variable. Control Cost Manual at 1-32, 2-44. The fact 

that the example “assumes” AFUDC is equal to zero does not reflect a decision by EPA that 

AFUDC should be excluded from emissions control costs, but instead is an explicit recognition 

of that category of costs. 

EPA also has claimed that the U.S. Energy Information Administration (“EIA”) uses overnight 

costs to project plant costs. See S&L FIP Cost Report at 6. However, this is a mischaracterization 

of the EIA methodology. According to EIA, “[s]tarting from overnight cost estimates, EIA’s 

electricity modeling explicitly takes account of the time required to bring each generating 

technology online and the costs of financing construction in the period before a plant becomes 

operational.” EIA, Updated Capital Cost Estimates for Electricity Generation Plants, at 2, n.2 

(Nov. 2010).486 Despite EPA’s claims, the Control Cost Manual does not preclude inclusion of 

AFUDC and the EIA specifically takes such costs into account for an electric generating unit. 

 

485 As noted in the Revised White Bluff BART Analysis, Entergy revised its five-factor analysis of controls at White 

Bluff as requested by EPA staff in an effort to expedite consideration of the analysis but expressly reserved the 

ability to include AFUDC in future cost control analyses. Revised White Bluff BART Analysis, at 5-4. 486 Available at http://www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf.
260

Accordingly, the costs of controls for dry scrubbers at White Bluff should appropriately include 

AFUDC. 

[AECC (0169) p. 5-6] AECC stated that EPA based its White Bluff dry scrubber technology 

estimates on costs associated with reports commissioned by Entergy in 2009, but these costs are 

now five years old and need to be updated. EPA also followed its 2002 Control Cost Manual 

(CCM), which is more than a decade old and significantly underestimates current market costs of 

designing, engineering, and installing controls. EPA erroneously believes that allowance for 

funds used during construction (AFUDC) should not be used in the cost analysis. AFUDC 

recognizes the cost of funds dedicated to construction of large projects. For major environmental 

control installations on units the size of the White Bluff units, this cost can reach $30 million to 

$60 million.487 This is a real world cost that AECC's members will bear, and these costs should 

be included in the White Bluff scrubber cost analysis. EPA needs to re-evaluate the White Bluff 

control cost estimates with the issues listed above in mind. 

Comment: EPA incorrectly excluded certain costs for White Bluff [S&L Entergy Report, 

page 6]. S&L objects to our removal of certain costs from the cost analysis of our White Bluff 

scrubber cost analysis including owner’s costs and interest incurred during the construction 

period. S&L disagrees that the CCM describes an overnight approach to calculating capital 

costs. The CCM does not once define or even mention the overnight methodology as being the 

basis for estimating costs. Rather, the CCM describes a constant dollar approach that annualizes 

all capital costs and O&M costs (on a constant-dollar basis) over the useful life of the project. 

In the Oklahoma rule EPA cited to an Energy Information Administration (EIA) document as 

support for using the overnight cost estimating concept. In fact, EPA stated that “EIA presents all 

of its projected plant costs in terms of overnight costs.” However, this is a mischaracterization of 

the methodology the EIA uses to develop capital costs for new power generation. The EIA 

document upon which EPA relied includes a clarifying footnote that states: “Starting from 

overnight cost estimates, EIA’s electricity modeling explicitly takes account of the time required 

to bring each generating technology online and the costs of financing construction in the period 

before a plant becomes operational.” Therefore, EIA cost evaluations take into account financing 

costs, including AFUDC, one of the line items EPA insisted that Entergy remove from the SDA 

capital cost estimate. 

Finally, EPA states that the overnight method is appropriate for BART determinations “because 

it allows different pollution controls equipment to be compared in a meaningful manner.” 

However, excluding financing costs will bias the cost-effectiveness comparison toward the high 

capital options with extended construction periods. Project financing costs such as AFUDC may 

be minimal on projects that do not require significant capital and with short construction periods, 

but can be very significant on projects with large capital costs and extended construction periods. 

Excluding financing costs from the capital cost estimate results in the high-capital cost option 

appearing more cost-effective. Including financing costs allows the analyst to compare projects 

with varying capital requirements and varying construction periods. 

 

487 Entergy Response to 8/21/2013 EPA Region 6 comments on the White Bluff BART FFA at 2. 
261

Response: Entergy states that we based our cost analysis for a dry scrubber for the White Bluff 

facility on an outdated 2009 S&L analysis, “rather than using the updated vendor pricing.” This 

is a misrepresentation of the facts. Not disclosed by Entergy is that fact that the analysis we 

relied upon was not outdated at the time we were developing our Arkansas Regional Haze FIP 

proposal, was in fact the most recent analysis available to us, that it was used by Entergy itself, 

and has only been recently updated by Entergy in response to our proposed Arkansas FIP.488 We 

address Entergy’s new cost analysis in our responses to other comments. 

Entergy criticizes our use of the CEPCI to escalate the 2009 S&L cost analysis to current dollars 

(at the time of our analysis). However this is a standard approach in control cost analysis and 

has in fact been utilized by Entergy’s consultant, S&L (and many other consultants who perform 

control cost analyses) on numerous occasions. Again, had we had more updated cost 

information at the time we proposed our FIP, we would have used it, but Entergy failed to supply 

it. Thus, we used what was available to us, and properly escalated it using the CEPCI. 

Entergy objects to our disallowance of owner’s costs, stating such costs are allowed under “our” 

CUECost model, and our disallowance of AFUDC. Our use of the term, “overnight method” is 

merely a shorthand way of referring to the costing methodology required by the Control Cost 

Manual. The fact that the Control Cost Manual itself does not use that term does not obviate the 

need to adhere to that methodology. As we have noted in a number of our FIPs, AFUDC and 

Owner’s Costs are not valid costs under our Control Cost Manual methodology. We invite 

Entergy to examine our response to similar comments we received in response to those 

actions.489 We did not use the CUECost model, which estimates control costs using the levelized 

cost method developed by Electric Power Research Institute (EPRI), which is not approved for 

BART determinations. We followed the “overnight” methodology outlined in our Control Cost 

Manual. We were recently upheld in the Ninth Circuit490 regarding our use of the overnight cost 

methodology. 

Entergy objects to our correction of the mismatch it introduced in its BART analysis between the 

cost of its scrubbers and its SO2 baseline. As we discuss in Appendix A of our TSD,491 we noted 

that Entergy historically burned coals at the White Bluff and Independence plants with sulfur 

contents corresponding to typical Power River Basin coals, resulting in annual uncontrolled SO2

emissions ranging from 0.46 lbs/MMBtu to 0.625 lbs/MMBtu, but designed its White Bluff 

scrubber systems assuming a coal with an uncontrolled SO2 emission rate of 2.0 lbs/MMBtu. 

This has ramifications for the scrubber cost effectiveness calculation, in which the annualized 

cost of the controls are compared to the tons of SO2 reduced from its SO2 baseline. A scrubber 

capable of treating a higher sulfur coal is more expensive. Entergy is free to design a scrubber 

 

488 This is described beginning on page 2 of Appendix A to the Technical Support Document for the SDA Control 

Cost Analysis for the Entergy White Bluff and Independence Facilities, Arkansas Regional Haze Federal 

Implementation Plan (SO2 Cost TSD). 489 See for instance our “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. 

490 See Ariz. ex rel. Darwin v. EPA, 815 F.3d 519 (9th Cir. 2016), page 39: “This argument restates Petitioners’ 

objections to EPA’s reliance on the overnight costing methodology when it partially disapproved Arizona’s SIP. See 

supra note 14. EPA’s use of such a methodology in its own FIP’s cost analysis is, without doubt, reasonable.” 491 See the discussion beginning on page 11 of our SO2 Cost TSD. 
262

capable of burning a coal with a higher sulfur content (assuming all regulatory requirements are 

otherwise met). However, unless this expense is balanced against the greater SO2 removal 

capabilities of such a scrubber, the cost effectiveness calculation is skewed. 

Nevertheless, Entergy continues to argue that it can legitimately introduce a mismatch between 

the cost of its scrubber systems and the SO2 emission baseline against which its cost 

effectiveness will be measured, by reproducing an incomplete quote from the BART Guidelines 

to support its position that future fuel flexibility be considered “[t]he baseline emissions rate 

should represent a realistic depiction of anticipated annual emissions for the source.” 

The full quote which Entergy references above (which we reproduce in our SO2 Cost TSD in the 

section referenced above) is actually: 492

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.

Reading the full quote from the BART Guidelines reveals several points: The presumption is 

that the baseline emissions should be based on historical emissions. If future operations are 

expected to differ from past practices, and this impacts the BART analysis, an enforceable 

mechanism must be in place. The example in the above quote anticipates that future operations 

will cause the baseline to be lower, resulting in a correspondingly lower denominator in the $/ton 

cost effectiveness calculation, thus resulting in the cost effectiveness seeming less attractive 

(higher), thus triggering the need for an enforceable mechanism to ensure the integrity of the cost 

effectiveness calculation into the future. The same principle applies to Entergy’s situation, in 

that using a higher scrubber cost for scrubbing a higher sulfur coal, in conjunction with using an 

unrepresentative (lower) baseline, both act to make the $/ton cost effectiveness of the scrubber 

seem less attractive (higher). In this instance, we would not require an enforceable mechanism 

to ensure Entergy burns a higher sulfur coal, but the need to ensure the future integrity of the cost 

effectiveness calculation nevertheless remains. 

There are two obvious ways to address this situation: either (1) this higher cost be balanced 

against its greater SO2 reduction potential, or (2) that the scrubber system’s capability and cost 

be adjusted down to match the facility’s historical emissions. Lacking any information from 

Entergy regarding its preferences, we chose the latter course of action. As we discuss in our 

TSD, our approach was to use our IPM SDA cost model to adjust Entergy’s total annualized 

cost, and then use that adjusted figure when calculating the cost effectiveness. We did this by 

calculating the ratios of the annualized capital costs and operating costs for two SDA cases: a 

 

492 70 FR 39167. 
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2.0 lb/MMBtu case, and one based on Entergy’s historical SO2 emissions. We then applied these 

ratios to Entergy’s annualized capital costs and the sum of its direct and indirect capital costs. 

We continue to believe the approach we adopted was reasonable, corrects the mismatch between 

the cost of its scrubbers and its SO2 baseline Entergy introduced, and comports with the BART 

Guidelines. We explore this issue in more detail in other responses to comments. 

Entergy also states that we have approved BART determinations that assume “worst-case coal 

scenarios” and cites to our proposed North Dakota and Arizona actions. We do not believe that 

the circumstances of these BART determinations are applicable here, or that they support 

Entergy’s contention. In the North Dakota proposal, Coal Creek Station had recently installed a 

coal drying system and in performing the BART evaluation, North Dakota assumed a baseline 

corresponding to undried coal. As explained in our proposal, this was a “worst case” 

assumption. In other words, it had the effect of increasing the denominator in the $/ton cost 

effectiveness determinant, resulting in the true cost effectiveness of the technologies being 

considered being higher than what was evaluated—the opposite of what Entergy is proposing 

here. In addition, the issue was largely moot in that we proposed approval of what the State of 

North Dakota had itself proposed as BART for Coal Creek—that the existing scrubbers be 

upgraded to 95% efficiency, arguably a very stringent level of control. In the Arizona proposal, 

the Sundt Unit 4 was converted to burn coal in addition to natural gas. Its annual SO2 emissions 

varied greatly, as a result of years in which more or less natural gas was burned, presently a 

problem when selecting its SO2 emission baseline. We therefore chose a year in which the Sundt 

Unit 4 burned predominantly coal to represent the SO2 baseline, when evaluating it for SO2

BART. This results in a reasonably conservative, “worst case” evaluation—again, not what 

Entergy is proposing here. 

We address all of Entergy’s other comments, which are summaries of its contractor S&L’s 

comments, in our responses to S&L’s comments. 

Comment: Entergy objects to our calculation of O&M costs in our White Bluff cost 

analysis. [S&L Entergy Report, page 13]. Although EPA claims in its proposal that it relied on 

the methods and principals contained within the Control Cost Manual in developing its 

individual control technology cost estimates, in the supporting Cost TSD EPA stated that “we 

can compare Entergy’s O&M costs to those obtained through the use of our IPM SDA cost 

model.” 

The IPM model and the Control Cost Manual provide two entirely different approaches to 

calculating control system capital and O&M costs. IPM is described by EPA as a multi-regional, 

dynamic, deterministic linear programming model used by EPA to analyze system-wide impacts 

of air emissions policies on the U.S. electric power sector in the 48 contiguous states and the 

District of Columbia. The model has been used by EPA to analyze impacts associated with 

proposed regulatory programs such as the Clean Air Interstate Rule (CAIR) and Mercury and Air 

Toxics Standard (MATS). The primary purpose of the model is to provide forecasts of least-cost 

capacity expansion, electricity dispatch and emission control strategies for meeting energy 

demand and environmental, transmission, dispatch and reliability constraints. The model 

includes cost modules for various air quality control technologies, and S&L developed the cost 
264

algorithms used in the IPM model to estimate costs associated with DSI, SDA, and wet FGD 

control systems. The IPM model is not referred to in either the Control Cost Manual or the 

BART Guidelines as an acceptable tool to develop site specific capital or O&M cost estimates. 

Cost algorithms in the IPM model were developed based on a statistical evaluation of cost data 

available from various industry publications, and do not take into consideration site-specific cost 

issues. The primary purpose of the IPM cost modules is to provide generic order-of-magnitude 

costs for various air quality control technologies that can be applied to the electric power 

generating industry on a system-wide basis, not on an individual unit basis. By necessity, the 

cost algorithms were designed to require minimal site-specific information available from 

publicly available sources. Because of the limited number of site-specific inputs, the IPM cost 

algorithms provide order-of-magnitude control system cost estimates, but they do not provide 

case-by-case project-specific cost estimates meeting the requirements of the BART Guidelines, 

nor do the IPM equations incorporate the cost estimating methodology described in the Control 

Cost Manual. 

Regarding O&M costs for SDA FGD systems, the IPM model includes the following 

assumptions that are not consistent with a site-specific O&M cost estimates: 

 A fixed quantity of additional personnel to operate the equipment is included, not for 

site-specific project and staffing needs; 

 While we agree with the general practice of estimating maintenance material and 

labor costs as percentage of capital costs, the IPM model does not estimate sitespecific capital costs sufficiently upon which to apply this percentage, and the 

assumed percentage cannot be modified to accommodate project specific 

requirements; 

 The assumptions incorporated in the maintenance material and labor costs are 

propagated into the administrative labor item, and is therefore limited by the same 

items as the previous item; 

 Reagent consumption assumes a stoichiometry that cannot be modified to match 

vendor-supplied guarantees for a specific application; 

 Reagent consumption also depends upon a flue gas temperature into the SDA of 

300°F and cannot be modified to apply site-specific temperatures; 

 Reagent consumption also depends upon lime purity, which the IPM model assumes 

to be 90% and cannot be modified to match actual reagent supply information; 

 The IPM model estimates water consumption based on gas flow and fuel sulfur levels 

instead of performing site-specific calculations using actual fuel properties and 

operating conditions; 

 Waste generation is a function of the assumed lime stoichiometry discussed above as 

well as an assumed moisture content of 10% that cannot be modified to match 

vendor-supplied mass balances for specific applications; and 
265

 The SDA flue gas pressure drop estimate included in the IPM model is an average 

value based on flue gas flow rate and sulfur levels instead of performing site-specific 

calculations that consider the actual fuel properties, operating conditions, and actual 

equipment sizing and arrangement. 

EPA’s use of IPM to benchmark O&M costs is thus not an appropriate choice for a unit-specific 

analysis consistent with BART guidelines. By relying on the IPM cost modules to verify dry 

FGD O&M costs, EPA did not adequately evaluate and account for potential project-specific site 

constraints that Entergy would incur to operate the FGD control systems EPA is proposing. In 

addition, using the IPM cost algorithms to calculate FGD control system capital or O&M costs is 

inconsistent with the case-by-case BART cost analysis described in the BART Guidelines for at 

least two reasons. First, the IPM model does not account for unit-specific design and operating 

parameters that can affect control system design and costs, including operating costs. Second, the 

IPM cost equations do not take into consideration site-specific conditions that could affect the 

O&M costs to operate the control system. 

Response: Our approach using the IPM SDA cost algorithm to recalculate the costs was 

necessary and reasonable. As we discuss in our TSD,493 we had to recalculate Entergy’s O&M 

costs for its White Bluff SDA model because of a discrepancy between Entergy’s SO2 emission 

baseline used in its cost analysis and the assumed SO2 inlet it assumed in the design of its 

scrubber. Entergy costed a scrubber capable of treating a SO2 level of 2.0 lbs/MMBtu, when it 

historically burned coal that averaged less than 0.6 lbs/MMBtu from 2009 – 2013. We could not 

directly adjust Entergy’s O&M costs because Entergy’s O&M cost estimates were based on a 

S&L economic model from May 2008, which it did not supply.494 Consequently, when issues 

we discuss in our responses to comments elsewhere dictated a revision to Entergy’s cost 

estimate, we were left with no choice but to seek an alternative means of estimating Entergy’s 

O&M costs, in order to address the mismatch described above. Entergy now criticizes us for 

making this adjustment to its O&M costs by employing a scrubber cost model—our IPM SDA 

cost algorithm that its own contractor designed for us. 

Entergy criticizes us for using our IPM SDA cost algorithm to estimate the O&M, stating this is 

in contradiction to our Control Cost Manual. On the contrary, as we stated in our TSD, we 

“relied on the methods and principles contained within the EPA Air Pollution Control Cost 

Manual.”495 Our TSD goes on to explain that by this, it means the general costing methodology, 

namely the use of the overnight costing method.496 

The BART Guidelines state: “In order to maintain and improve consistency, cost estimates 

should be based on the OAQPS Control Cost Manual, where possible.”497 This statement is 

footnoted to indicate: “You should include documentation for any additional information you 

used for cost calculations, including any information supplied by vendors that affects your 

 

493 See Section 3.1 in Appendix A of our TSD. 494 See Section 2.7 in Appendix A of our TSD. 495 See Section 2 of Appendix A to our TSD. 496 Ibid. 497 70 FR 39166. 
266

assumptions regarding purchased equipment costs, equipment life, replacement of major 

components, and any other element of the calculation that differs from the Control Cost 

Manual.” Our TSD satisfies this requirement. 

The Control Cost Manual does not include any method for estimating the costs of any of the SO2

control methods evaluated in this action. In fact, the Table of Contents of the Control Cost 

Manual indicates that the chapter on “Wet and Dry Scrubbers for SO2,” two of the three controls 

EPA costed, is a “planned chapter.” This chapter was never developed.498 Thus, it is not possible 

to use the Control Cost Manual to cost dry and wet scrubbers directly, except through the 

overnight cost methodology and the other general principles contained therein, which we 

followed. As a consequence, faced with having to perform cost analysis on an applicable control 

technology, we elected to use the only publically available current SO2 costing model, the SDA 

cost model developed by S&L for use in our IPM. 

Thus, the only relevant portion of the Control Cost Manual to our present work is the general 

methodology chapter, Chapter 2: Cost Estimation: Concepts and Methodology. We did adopt 

the Control Cost Manual general cost methodology, the overnight method, as we did in all of our 

previous FIPs. As explained in the Cost TSD, we modified the IPM cost models to use the 

overnight cost method by removing AFUDC and owner’s costs and to additionally calculate cost 

effectiveness, rather than just total capital and O&M costs. 

This comment states that the “IPM model is not referred to in either the Control Cost Manual or 

the BART Guidelines as an acceptable tool to develop site specific capital or O&M cost 

estimates.” These models were developed by Sargent & Lundy, under contract to us.499 They 

were first published in 2010,500 after the last Control Cost Manual modification (2002) and after 

the BART Guidelines were published in 2004.501 Thus, it is illogical to expect the IPM cost 

algorithms to be cited in either the Control Cost Manual or the BART Guidelines. Regardless, 

the absence of a specific cite to a model in the Control Cost Manual is not evidence that the 

model is not acceptable. We have the authority to select the best tool for the job. 

We have used IPM cost models to estimate BART costs in other similar rulemakings including 

our Arizona Regional Haze Federal Implementation Plans502 the Wyoming Regional Haze 

Federal Implementation Plan,503 to supplement our analysis in the Oklahoma Federal 

Implementation Plan,504 and in our Texas-Oklahoma Regional Haze Federal Implementation 

 

498 Control Cost Manual, Table of Contents, Section 5.2, Chapter 2, footnote 2. 499 Section 5. Emission Control Technologies, Explaining: “EPA Base Case v.4.10 includes a major update of 

emission control technology assumptions. For this base case EPA contracted with engineering firm Sargent and 

Lundy to perform a complete bottom-up engineering reassessment of the cost and performance assumptions for 

sulfur dioxide (SO2) and nitrogen oxides (NOx) emission controls.” Available at: 

http://www.epa.gov/airmarkets/documents/ipm/Chapter5.pdf. 

500 See Chapter 5 at http://www.epa.gov/airmarkets/programs/ipm/BaseCasev410.html. 501 40 CFR Part 51: Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) 

Determinations; Proposed Rule, 69 FR 25,184 (May 5, 2004). 

502 77 FR 42852 (July 20, 2012). 503 Memorandum from Jim Staudt to Dough Grano, EPA, Re: Review of Estimated Compliance Costs for Wyoming 

Electricity Generating Units (EGUs) – Revision of Previous Memo, February 7, 2013, EPA-R08-OAR-2012-0026-

0086_Feb 7 2013. 

504  76 FR 81728.
267

Plan.505 As explained in the Arizona rulemaking: “EPA’s Clean Air Markets Division contracted 

with engineering firm Sargent and Lundy to perform a complete bottom-up engineering 

reassessment of the cost and performance assumptions for SO2 and nitrogen oxides NOX

emission controls.”506 

This comment also confuses “the IPM model” and the cost models that are inputs to the IPM 

model. The comment asserts that the IPM model and the Control Cost Manual provide two 

entirely different approaches to calculating control system capital costs. In supporting this 

argument, it states: “IPM is described by EPA as a multi-regional, dynamic, deterministic linear 

programming model used by EPA to analyze system-wide impacts of air emissions policies on 

the U.S. electric power sector in the 48 contiguous states and the District of Columbia.” This is 

an accurate description of “IPM model”, but not of the cost models that generate input to the 

IPM.507 The models used to generate these cost inputs are not “multi-regional, dynamic, 

deterministic linear programming models” but rather conventional costing models that use the 

same general methods set out in the Control Cost Manual to estimate total capital and O&M 

costs based on various design parameters. We only used the control technology cost models, not 

the IPM model itself. 

Accuracy of IPM Cost Algorithms for Site-Specific Costs Estimates 

Entergy argues that the IPM model only provides “generic order-of-magnitude costs,” implying 

they are not acceptable for unit-specific cost estimates for the individual plants included in this 

rulemaking. We believe these cost models are adequate for projecting unit-level control costs for 

the purpose of conducting the type of cost-benefit analysis we have done in our proposal. For 

instance, S&L’s own documentation for the wet FGD cost model states the following: 

The 2004 to 2006 industry cost estimates for wet FGD units from the "Analysis of 

MOG and LADCO's FGD and SCR Capacity and Cost Assumptions in the 

Evaluation of Proposed EGU 1 and EGU 2 Emission Controls" prepared for 

Midwest Ozone Group (MOG) were used by Sargent & Lundy LLC (S&L) to 

develop the wet FGD cost model. In addition, S&L included data from “Current 

Capital Cost and Cost-effectiveness of Power Plant Emissions Control 

Technologies” prepared by J. E. Cichanowicz for the Utility Air Regulatory 

Group (UARG) in 2010. The cost increases reported from 2007 to 2008 by G. 

W. Sharp in “Update: What’s That Scrubber Going to Cost?” published in Power 

Magazine, March 2009 were also considered. The published data was 

significantly augmented by the S&L in-house database of recent wet FGD 

projects. Cost data from the various sources showed similar trends versus 

generating capacity. Escalation based on the CEPI was deemed acceptable. All 

data sources were combined so as to provide a representative wet FGD cost basis. 

The data was converted to 2012 dollars based on the Chemical Engineering Plant 

Index (CEPI) data. Additional proprietary S&L in-house data from 2007 to 2012 

were included to confirm the index validity. Finally, the cost estimation tool was 

 

505 81 FR 296. 506 77 FR 42852. 507 http://www.epa.gov/airmarkets/programs/ipm/index.html. 
268

benchmarked against recent wet FGD projects to confirm the applicability to the 

current market conditions. 

As discussed above, S&L used real world cost data to construct its cost algorithms and confirm 

its validity. These cost models have been updated and maintained since their introduction in 

2010 and have been continuously used by EPA since that time. These control costs are based on 

databases of actual control project costs and account for project specifics such as unit size, coal 

type, gross heat rate, retrofit factor, and require unit specific inputs such as reagent cost, waste 

disposal cost, auxiliary power cost, labor cost, gross load, and emission information. We believe 

that the IPM cost models provide sufficiently accurate, study-level, unit-specific costs for 

regulatory cost analysis such as required for BACT, BART, and reasonable progress. 

This comment argues that the use of IPM algorithms is “not an appropriate choice for a unitspecific analysis consistent with BART guidelines” because: (1) it does not account for unitspecific design and operating parameters and (2) it does not consider site-specific conditions that 

could affect O&M costs. First, this comment redefines “case-by-case” as used in “case-by-case 

BART.” BART means “an emission limitation based on the degree of reduction achievable 

through the application of the best system of continuous emission reduction for each pollutant 

which is emitted by . . . [a BART-eligible source]. The emission limitation must be established, 

on a case-by-case basis, taking into consideration the technology available, the costs of 

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

control equipment in use or in existence at the source, the remaining useful life of the source, and 

the degree of improvement in visibility....”508 In this context, case-by-case refers to each 

pollutant at each emission unit. We applied the IPM cost models for SO2 at each emission unit 

using unit-specific inputs. Thus, the “case-by-case” requirement of the definition of BART is 

satisfied. Second, we accounted for “unit-specific design and operating parameters” by using 

unit and site-specific data as we discussed in our TSD.509 Every input parameter to our SDA cost 

analysis was presented and discussed. 

Accuracy of IPM Cost Estimates 

Entergy asserts that the IPM cost models provide only “order of magnitude” control cost 

estimates. However, as the Control Cost Manual explains, the sole input required for making an 

“order of magnitude” estimate is “the control system’s capacity (often measured by the 

maximum volumetric flow rate of the gas passing through the system).”510 Such an estimate, for 

example, could be obtained from the cost reported in dollars per megawatt ($/MW) or dollars per 

million BTUs fired ($/MMBtu), metrics that are widely reported in the literature. A quick look 

at the many inputs to the IPM cost models511 demonstrates that they provide more accurate 

estimates than “order of magnitude.” The Control Cost Manual indicates that “the costs and 

estimating methodology in this Manual are directed toward the “study” estimate with a nominal 

accuracy of +/-30% percent.”512 This is the long-standing rule of thumb for cost estimate 

 

508 70 FR 39163. 509 See Section 3.2 of Appendix A to our TSD. 510 Control Cost Manual, p. 2-3. 511 See Cost TSD, Sections 3, 4, and 5 and Tables 6 (DSI), 6 (SDA), and 10 (WFGD). 512 Control Cost Manual, p. 2-3. 
269

accuracy used by the EPA for regulatory cost effectiveness analyses.513 

Site-Specific Inputs 

This comment also argues: “the cost algorithms were designed to require minimal site-specific 

information available from publicly available sources.” The IPM SDA cost model includes a 

range of site-specific information, including: unit size, retrofit factor, gross heat rate, SO2 rate, 

type of coal, coal factor, SO2 removal efficiency, auxiliary power cost, lime cost, waste disposal 

cost, makeup water cost, operating labor rate, elevation, interest rate, equipment lifetime, and the 

SO2 baseline. This large number of site-specific inputs is a clear demonstration that these cost 

models provide more accurate estimates than “order-of-magnitude,”514 which only require a 

single parameter as the input. 

We have enough confidence in the basic methodology behind the S&L cost algorithms that in 

our recent proposal for updating the SCR chapter of the Control Cost Manual,515 we presented an 

example costing methodology that is based on the IPM S&L SCR algorithms, which were 

developed using a similar methodology to the wet FGD, SDA, and DSI cost algorithms discussed 

herein For the reasons we describe above, we disagree with S&L that our modifications to and 

use of the cost algorithms it has supplied us are inappropriate for use in regional haze control 

cost analysis. 

Lastly, we note that Entergy used a number of general approximations when estimating the wet 

scrubbing costs for White Bluff, as we describe in our TSD:516

Entergy uses a 2012 S&L wet FGD estimate for the White Bluff Units 1 and 2 as 

the starting point for its cost analysis. It then subtracts out all total construction 

and erection costs from the total project costs in order to obtain a total Equipment 

Cost (EC). Entergy then calculates the Purchased Equipment Costs (PEC), using 

this approximation from our Control Cost Manual: 

PEC = 1.18 X EC 

Although not stated, Entergy then calculates the Total Capital Investment (TCI) 

using the following approximation from our Control Cost Manual: 

TCI = DC + IC = (1.85 X B) + Site Preparation + Bldg + (0.35 X B) 

Where DC = Direct Costs, IC = Indirect Costs, and B= PEC. It appears Entergy 

assumed no cost for site preparation and buildings. 

Entergy calculated the direct annual costs, using fixed and variable O&M costs 

from a 2011 S&L cost summary as a surrogate for the apparently unavailable 

 

513 EPA, New Source Review Workshop Manual, Draft, October 1990, p. B.35. 514 Control Cost Manual, p. 2-3. 515 80 FR 33515. 516 See discussion beginning on page 19 of Appendix A to our TSD. 
270

direct annual costs from the 2012 S&L estimate. Entergy then calculated the 

indirect annual costs using multiplier approximations from our Control Cost 

Manual. Lastly, Entergy calculated the annualized capital cost in the usual 

manner by multiplying the TCI by the capital recovery factor. 

We disagree with S&L’s comments. As can be seen from the above, Entergy employed a number 

of very general approximations that are not site-specific and there was a discrepancy between 

Entergy’s SO2 emission baseline used in its cost analysis and the assumed SO2 inlet it assumed in 

the design of its scrubber. Therefore, our approach using the IPM SDA cost algorithm to 

recalculate the costs was necessary and reasonable. 

Comment: EPA arbitrarily eliminated two of five years in calculating baseline emissions 

for White Bluff and used an incorrect methodology that inflates SO2 emissions reductions. 

[Entergy Arkansas Inc. (0166) p. 7-8] EAI stated that the BART Guidelines state that baseline 

emissions from existing sources “should represent a realistic depiction of anticipated annual 

emissions for the source.” 40 C.F.R. Part 51, App. Y, Section IV.D.4.d.1. In general, for the 

existing sources, facilities should estimate the anticipated annual emissions based upon actual 

emissions from a baseline period. Entergy originally had used the 2001 - 2003 baseline period. 

See Revised White Bluff BART Analysis at 4-1. EPA looked at the five-year period between 

2009 and 2013, SO2 Cost TSD at 13, Table 7, but inexplicably excluded the maximum and 

minimum years during this five-year period. Id. The effect of excluding these two years is to 

increase artificially the emissions baseline for White Bluff. S&L FIP Cost Report at 3. There is 

no reasoned explanation for excluding two of the five recent years’ of emissions data in 

calculating the baseline. EPA should use the average emissions from all five years to determine 

the baseline as it is more representative of the anticipated annual emissions from the White Bluff 

units. 

After having incorrectly identified the baseline emissions for White Bluff, EPA then apparently 

ignores the baseline emissions when estimating the SO2 reductions that are achievable with the 

scrubbers. In an apparent attempt to inflate the emission reductions achievable at White Bluff 

through the installation of scrubbers, EPA identified the maximum monthly SO2 emission rate in 

the baseline period of 2009 to 2013 for each unit and then calculated the percent reduction that 

would be required to achieve a controlled emission rate of 0.06 lb/MMBtu. See White Bluff_R6 

cost revisions2.xlsx, “Cost Effectiveness” tab, EPA Docket ID EPA-R06-OAR-2015- 0189-

0093. The percent reduction calculated was then multiplied by the baseline emission tons to 

determine the tons of SO2 reduced. Id. This methodology is patently incorrect. It assumes the 

baseline emissions are based on maximum monthly averages, which significantly overstates the 

annual averages actually used to calculate baseline emissions. 

To correctly estimate the SO2 emission reductions, EPA must multiply the outlet emission rate of 

0.06 lb/MMBtu by the average heat input to the boiler (MMBtu/year) from the five-year baseline 

period. S&L FIP Cost Report at 3. As detailed in the S&L FIP Cost Report, EPA’s inappropriate 

use of maximum monthly emission rates overstates the achievable emission reductions at White 

Bluff by between 150 and 900 tons per year. Id. at 4, Table 2. 
271

Response: We address these comments, which are summaries of its contractor S&L’s 

comments, in our responses to S&L’s comments. 

Comment: The costs for dry scrubbers at White Bluff are too high to constitute BART 

based on Entergy’s updated S&L cost analysis. [Entergy Arkansas Inc. (0166) p. 11-13] EAI 

stated that EPA’s use of outdated costs in its cost calculation, its exclusion of certain legitimate 

costs for the construction of dry scrubbers, and its failure to take into consideration fuel 

flexibility at White Bluff renders EPA’s analysis artificially low and inappropriate for evaluating 

the cost effectiveness of dry scrubbers on White Bluff for regional haze purposes. To correct 

EPA’s deficiencies, Entergy commissioned a revised dry FGD cost analysis from S&L that takes 

into account the current costs for dry scrubber installation as compared to the costs that would 

have been incurred in 2009 or 2010. See White Bluff Dry FGD Cost Estimate and Technical

Basis, Report No. SL-012831, Sargent & Lundy (July 2015) (“2015 S&L FGD Report”) 

(attached as Exhibit B and incorporated by reference herein). The 2015 S&L FGD Report also 

takes into account site-specific factors at White Bluff that have an effect on costs. Finally, the 

study also uses the current SO2 emission rates at White Bluff for the O&M costs. For the capital 

cost estimate, S&L uses a design basis of 1.2 lb/MMBtu sulfur coal. As explained in the S&L 

FIP Cost Report, the current maximum monthly average emission rates are not an appropriate 

basis for sizing the scrubbers. The equipment must be sized to handle the maximum short-term 

emission rate. S&L FIP Cost Report at 14-15. 

The Revised White Bluff BART Analysis had estimated the costs to install dry scrubbers at 

White Bluff to be approximately $670 million. Revised White Bluff BART Analysis, at 5-6, 

Table 5-3. The 2015 S&L FGD Report estimates that the total costs of dry scrubbers at White 

Bluff will be in excess of $1 billion. 2015 S&L FGD Report at ES-1. When the remaining useful 

coal-fired life of these units is factored into the analysis, dry FGD installation at White Bluff 

would be indisputably cost-prohibitive. 

Based on the S&L analysis, operating the dry FGD systems at White Bluff for only six to seven 

years would result in an average cost effectiveness of $7,689-$8,599/ton at Unit 1 and of $7,642-

$8,546/ton at Unit 2. S&L FIP Cost Report at 23, Table 11. EPA has determined costs of 

substantially less than this magnitude to be cost-prohibitive on numerous occasions, including in 

this very same rulemaking. For example, for AECC McClellan Unit 1, even though EPA claimed 

that “[s]witching to diesel is projected to result in considerable visibility improvement,” EPA 

rejected SO2 BART limits based on switching to diesel because EPA determined that diesel, with 

an average cost effectiveness of $7,145/ SO2 ton removed, was not “cost-effective in view of the 

incremental visibility improvement.” 80 Fed. Reg. at 18,959. EPA also rejected combustion 

controls as NOx BART for AECC McClellan Unit 1 based on an average cost-effectiveness of 

$6,261/NOx ton removed, which, according to EPA “is not within the range of what we 

generally consider to be cost-effective.” Id. at 18,961. Further, EPA declined to impose dry FGD 

as BART in Arizona, where the average cost effectiveness was estimated to be $5,091/ton. 

Proposed Arizona Regional Haze FIP, 79 Fed. Reg. at 9,331-33; Final Arizona Regional Haze 

FIP, 79 Fed. Reg. 52,420, 52,436 (Sept. 3, 2014). In North Dakota, EPA approved the state’s 

determination that a cost effectiveness of $6,525 per ton was excessive for NOx controls and did 

not constitute BART. Proposed North Dakota FIP, 76 Fed. Reg. at 58,630; Final North Dakota 
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Regional Haze FIP, 77 Fed. Reg. 20,894, 20,896 (Apr. 6, 2012). And, in Montana, EPA 

concluded that certain SO2 controls with a cost effectiveness of $5,442/ton and $6,365/ton were 

not cost effective. Proposed Montana Regional Haze FIP, 77 Fed. Reg. 23,988, 

24,047 (Apr. 20, 2012); Final Montana Regional Haze FIP; 77 Fed. Reg. 57,864, 57,866 (Sept. 

18, 2012). Notably, although EPA found that dry sorbent injection was cost effective on a costper-ton basis, 77 Fed. Reg. at 24,047, EPA concluded that the costs were not justified by the 

visibility improvement, which it calculated to be $30 million per deciview. 77 Fed. Reg. at 

57,895. This is magnitudes lower than the cost-per-deciview of dry FGD at White Bluff Units 1 

and 2, which, for Unit 1, would be approximately $3.1 billion per deciview at Caney Creek and 

$2.7 billion per deciview at Upper Buffalo and, for Unit 2, approximately $2.9 billion per 

deciview at Caney Creek and $2.6 billion per deciview at Upper Buffalo.517

The CAA requires that a BART determination consider the degree of anticipated visibility 

improvement. 42 U.S.C. § 7491(g)(2). Accordingly, EPA cannot mandate that a source “spend 

millions of dollars for new technology that will have no appreciable effect on the haze.” Am. 

Corn Growers v. EPA, 291 F.3d 1, 7 (D.C. Cir. 2002). However, EPA’s proposed controls do 

exactly this. The improvements predicted at Caney Creek and Upper Buffalo from controls on 

White Bluff Units 1 and 2 based on EPA’s scaling methodology are only a fraction of a 

deciview. Even the CALPUFF predicted visibility improvements at Caney Creek and Upper 

Buffalo from the installation of dry FGD at White Bluff Units 1 and 2 are less than 1 deciview 

from each unit, see 80 Fed. Reg. 18,972, making them imperceptible to the human eye. See

Section III.C.2 of EAI’s comments. The massive cost of installing dry scrubbers at White Bluff 

to achieve these insignificant improvements, whether on a dollar per deciview basis or a dollar 

per ton basis, would be much higher than the costs that EPA has previously rejected as BART 

and that EPA proposes to reject as BART in this Proposed Rule. Accordingly, the installation of 

dry scrubbers cannot be considered BART for SO2 at White Bluff. 

Response: As we discuss in our responses to other comments that treat the issues raised here in 

more detail, we disagree with many aspects of Entergy’s comments concerning the cost of 

installing scrubbers at the White Bluff facility. We conclude that the cost effectiveness of 

installing scrubbers at White Bluff is not $7,689-$8,599/ton at Unit 1 and $7,642-$8,546/ton at 

Unit 2, (see our response to other comments). Hence, Entergy’s comparison to our previous 

actions is not valid. When considered in conjunction with the significant visibility benefits 

expected to occur from the installation of these scrubbers, we consider the cost effectiveness of 

installing scrubbers at the White Bluff facility to be reasonable. We discuss in a separate 

response our position regarding the $/deciview metric. 

 

517 These numbers were calculated from the deciview improvement attributable to White Bluff Units 1 and 2 based 

on EPA’s “scaling methodology.” See 80 Fed. Reg. 18,997. This methodology results in an improvement at Caney 

Creek of .036 dv from Unit 1 and .038 from Unit 2 and an improvement at Upper Buffalo of .040 from Unit 1 and 

.043 from Unit 2. Even if the deciview improvements projected from EPA’s CALPUFF modeling were used, see 80 

Fed. Reg. at 18,972, the $/deciview calculation would not support the installation of dry FGD as BART at White 

Bluff. Entergy estimates that the costs based on the CALPUFF modeled improvement for Unit 1 would be 

approximately $135 million per deciview at Caney Creek and $144 million per deciview at Upper Buffalo and, at 

Unit 2, the costs would be approximately $145 million per deciview at Caney Creek and $143 million per deciview 

at Upper Buffalo. 
273

Comment: EPA’s cost estimates for controls on White Bluff and Flint Creek do not include 

significant costs that EPA says are not allowed by the EPA Control Cost Manual, even 

though these costs will be incurred by the owners of the facilities and ultimately passed on 

to ratepayers. 

[Nucor Steel-Arkansas and Nucor-Yamato Steel Company (0163) p. 32-36] Nucor stated that 

EPA is requiring control technology for White Bluff SN-01, SN-02 and Flint Creek at a cost 

determined by the plant operators to be $2,913/ton SO2, $3,355/ton SO2, and $3,845/ton SO2, 

respectively. These figures do not include significant costs such as AFUDC that will be incurred 

by the owners of those facilities and that will be recoverable ultimately from rate-payers in rate 

making proceedings before the Arkansas Public Service Commission.518 In addition, EPA 

believes that the costs of controls at Independence would be similar to the costs at White Bluff. 

EPA claims that such additional costs, including AFUDC, are not allowable costs under EPA's 

Cost Control Manual. However, EPA's Cost Control Manual does not recognize the economic 

and financial realities of public utility operations, and thus it ignores important factors that 

should be considered.519 EPA does not have any special expertise in power plant construction, 

public utility financing, or public utility cost recovery and rate regulation; thus its cost estimates 

for White Bluff, Flint Creek and Independence are not entitled to deference. See, King v. 

Burwell, 135 S. Ct. 2480 (2015) (where regulatory agency does not have expertise in the field, its 

interpretations are not subject to deference.) The ultimate cost of EPA's BART and Reasonable 

Progress determinations to Entergy, AEP/SWEPCO, and AECC and its member cooperatives is 

limited, because they will be entitled by law to recover their costs from ratepayers, regardless of 

whether those costs are “allowed” under EPA's Cost Control Manual. See Ark. Code Ann. §23-

4-501 (recently amended to explicitly provide for cost recovery of AFUDC under an interim rate 

surcharge). Thus, for purposes of White Bluff, Flint Creek and Independence, which are public 

utility BART sources, the proper cost to be considered in EPA's BART and Reasonable Progress 

determinations is the costs that the owners of White Bluff, Flint Creek and Independence will be 

allowed to recover from ratepayers. 

AFUDC stands for “Allowance for Funds Used During Construction.” AFUDC is part of the 

Federal Energy Regulatory Commission Uniform System of Accounts, and is utilized by both the 

FERC and state regulatory commissions, including the Arkansas Public Service Commission to 

account for construction financing costs which are added to the cost of the plant for rate recovery 

when the plant is put into service. AFUDC can easily amount to tens of millions of dollars. EPA 

also omitted other costs in its BART and Reasonable Progress determinations that the operators 

of White Bluff, Flint Creek and Independence will be permitted to recover in their electric 

rates.520 Another cost to ratepayers that EPA failed to take into consideration is the rate of return 

that will be allowed to the owners of White Bluff, Flint Creek and Independence on the total 

allowable costs of the control technology required by EPA. Recently, Arkansas utilities have 

 

518 See Entergy's White Bluff and AEP's Flint Creek Final BART Five Factor Analyses, attached as Exhibits 12 and 

16 to Nucor’s comments. 

519 It should be noted that EPA's Cost Control Manual is just a rough guide, with an admitted error of +/- 30%. 

(Docket document No. 139-3, p. 1-4) 

520 See Entergy's “Response to EPA Region 6 comments on Entergy White Bluff draft BART Report, 06/10/13,” 

Docket Doc. No. 0043, pp. 6-10; Ex. 12 to Nucor’s comments, Entergy’s “Response to 8/21/2013 EPA Region 6 

comments on White Bluff BART FFA,” Docket Doc. No. 0045, pp. 2-3. 
274

been permitted a rate of return between 4 and 6% on the total cost. The Arkansas Public Service 

Commission is obligated to allow public utilities to recover their actual costs, plus a reasonable 

return on investment, regardless of whether those costs are recognized under EPA’s Cost Control 

Manual. Since these costs are legally allowed under Arkansas law, they are relevant factors that 

should have been taken into account by EPA in its BART and Reasonable Progress 

determinations. Michigan v. EPA, 135 S. Ct. 2699 (2015) (unreasonable for EPA to not take into 

consideration relevant factors).521

[Arkansas Electric Energy Consumers Inc. and Arkansas Gas Consumers Inc. (0175) p. 13-15] 

AEEC and AGC stated that the EPA’s proposed FIP requires controls for White Bluff SN-01, 

SN-02 and Flint Creek at a cost determined by the plant’s owners and operators to be $2,913/ton 

SO2, $3,355/ton SO2, and $3,845/ton SO2, respectively. In addition, the EPA states that the costs 

of controls at Independence would be similar to the costs at White Bluff. Notably, these 

estimates do not include significant costs, such as Allowance for Funds Used During 

Construction (AFUDC)522 and rate of return,523 that the owners of those facilities will ultimately 

recover from Arkansas ratepayers.524

The EPA asserts that such additional costs are not allowable costs under the EPA’s Cost Control 

Manual. The Cost Control Manual, however, fails to comprehend the realities of public utility 

operations in Arkansas; thus, it ignores important factors the EPA should have considered when 

assessing the cost-effectiveness of the controls required by the Proposed FIP. The ultimate cost 

of EPA’s BART and Reasonable Progress determinations to the public utilities who own the 

facilities is limited, because Arkansas law allows them to recover their costs from Arkansas 

ratepayers, regardless of whether said costs are “allowed” under the Cost Control Manual.525

Thus, for the public utility sources affected by the proposed FIP, the proper costs to be 

considered in the EPA’s BART and Reasonable Progress determinations is the costs that 

Arkansas law allows the plant owners to recover from Arkansas ratepayers. Since Arkansas law 

allows public utilities to recover these additional costs that the EPA failed to consider due to its 

arbitrary and capricious application of the Cost Control Manual, these costs are relevant factors 

that the EPA should have considered in its BART and Reasonable Progress determinations.526

Further, since the EPA lacks special expertise in public utility financing and public utility cost 

recovery and rate regulation, the EPA’s cost estimates for these utility-owned sources are not 

 

521 EPA’s adjusted and proposed cost-effectiveness numbers for White Bluff, Flint Creek and Independence exceed 

the upper limit of EPA's projected cost-effectiveness range of $400 – 2,000/ton SO2 for EPA’s presumptive SO2

BART limits in support of the national Regional Haze Rule. Exhibit 17 to Nucor’s comments, Technical Support 

Document for BART, April 2005, p. 8. 

522 AFUDC is part of the Federal Energy Regulatory Commission’s Uniform System of Accounts, and is utilized by 

both the FERC and state regulatory commissions, including the Arkansas Public Service Commission (“APSC”), to 

account for construction financing costs which are added to the cost of the plant for rate recovery when the plant is 

put into service. 

523 Arkansas law obligates the APSC to allow public utilities to recover their actual costs, plus a reasonable return on 

investment fixed by the APSC. 

524 See Ark. Code Ann. § 23-4-502; see also McDaniel v. Arkansas Public Service Commission et al., 2014 Ark. 

App. 529 (Ark. App. 2014). 

525 See also Ark. Code Ann. § 23-4-501 (amended during the 2015 General Assembly to explicitly allow recovery of 

AFUDC through an interim surcharge). 

526 Michigan v. EPA, 135 S. Ct. 2699 (2015) (unreasonable for EPA to not take into consideration relevant factors). 
275

entitled to deference.527 Since the EPA failed to consider relevant factors when it rendered its 

BART and Reasonable Progress determinations for the power plants affected by the Proposed 

FIP, the Proposed FIP is unreasonable, arbitrary, and capricious, and the EPA should withdraw 

it. 

In rejecting and adjusting Entergy’s cost calculations for White Bluff, it is not clear whether EPA 

accounted for the differential cost of low-sulfur coal in its BART analysis. Entergy’s cost 

calculations were based on uncontrolled SO2 emissions of 2.0 lb/MMBtu, a level much higher 

than the emission rate from White Bluff’s historical use of more-expensive low—sulfur coal.528

EPA's BART analysis requires continued use of low sulfur coal, at a level of 0.65 to 0.68 lb 

SO2/MMBtu, based on 2009-2013 data.529 EPA should explain whether it took the cost 

difference between low-sulfur coal and high-sulfur coal into account in its BART determination, 

and if not, it should do so. 

Response: It has been our long-standing position in the regional haze program that AFUDC is 

not allowed under the Control Cost Manual approach of cost estimating. A cost effectiveness 

analysis is a regulatory analysis that is based on current annual dollars without any inflation. 

AFUDC is an accounting method. Assets under construction do not provide service to current 

customers and thus associated interest and allowed return on equity are not charged to current 

customers. Instead, AFUDC capitalizes these costs and adds them to the rate base so that they 

can be recovered from future customers when the assets are used. Thus, these charges represent 

future cash income to the utility. In other words, AFUDC is the accumulated cost of carrying 

capital and holding it waiting to spend, so money can be made in the future by selling electricity. 

Future income should not be charged against the cost of a control in a BART cost-effectiveness 

analysis. These costs are not part of the constant dollar approach found in the Cost Manual and 

should not be included in BART cost-effectiveness analyses. We invite Nucor to examine our 

response to similar comments we received in response to those actions. Our position regarding 

AFUDC has been upheld in the ninth circuit court of appeals. As explained in more detail by the 

court: 

The purpose of the cost analysis required as part of a BART determination 

is to foster comparison of the cost of the visibility improvements enabled 

by various control technologies. As EPA’s comments indicate, crossfacility comparisons of similar sources with regard to the costeffectiveness of a given control option aid in determining costeffectiveness at a specific source. Control options are likely to impact 

similar sources similarly; comparisons assure that the cost and benefit 

figures used for a particular site are realistic, rather than inflated in one 

direction or another. Consideration of AFUDC would not further this 

inquiry, as AFUDC is ultimately reflective of the implementing entity’s 

financial and logistical situations, grounded in past decisions and in the 

 

527 See King v. Burwell, 135 S. Ct. 2480 (2015) (where regulatory agency lacks expertise in the particular field at 

issue, its interpretations are not entitled to deference). 

528 See Exhibits 15A and 15B to Nucor’s comments, demonstrating the reduction in SO2 emissions and coal sulfur 

concentrations for White Bluff in 2009-2011, compared to 2001-2003. 

529 80 Fed.Reg. 18970, April 8, 2015. 
276

company’s financial policies and attitudes, not of the hard costs of the 

equipment and construction, which should be consistent across sites. 

While AFUDC and similar concepts are relevant for sales and ratemaking, 

including them would undermine the sort of “apples-to-apples” 

comparison that EPA asserts is necessary as part—but only part—of 

assessing the control options. 

This approach is consonant with the Guidelines, which specifically advise 

that “reasonable range[s]” for cost effectiveness are those that are 

“consistent with the range of cost effectiveness values used in other 

similar permit decisions over a period of time.” Guidelines at 39,168; see

also Oklahoma, 723 F.3d at 1213 (“The guidelines say that states should 

follow the manual’s methodology so that projects can be more easily 

compared.”). Moreover, adopting a costing methodology which focuses on 

achieving consistency and facilitating comparisons aligns with the CAA 

itself, which empowers EPA to promulgate national regulations 

concerning BART determinations. See 42 U.S.C. § 7491(a)(4), (b)(1). 

Nucor states we should explain whether we took the cost difference between low-sulfur coal and 

high-sulfur coal into account in our BART determination, and if not, that we should do so. In 

our response to another comment, we have discussed how we addressed the mismatch Entergy 

introduced in its BART cost analysis by burning coals at White Bluff with sulfur contents 

corresponding to typical Power River Basin coals (resulting in annual uncontrolled SO2

emissions ranging from 0.46 lbs/MMBtu to 0.625 lbs/MMBtu), while designing its White Bluff 

scrubber systems assuming a coal with an uncontrolled SO2 emission rate of 2.0 lbs/MMBtu. 

Comment: Entergy objects to the disallowance of owner’s costs in our White Bluff cost 

analysis. [S&L Entergy Report, page 10]. Entergy explained that Owner’s Costs are projectspecific, but generally include costs incurred by the Owner to manage the project, hire and retain 

staff to support the project, and costs associated with third party assistance associated with 

project development and financing. Owner’s Costs typically include, but may not necessarily be 

limited to: 

 Site investigations (geotechnical, hydrology, etc.) for project design 

 Environmental permitting/approvals 

 Insurance during construction 

 Site security during construction 

 Transmission interconnection (if applicable) 

 Fuel interconnection (if applicable) 

 Owner’s mobilization costs 

 Owner’s project management and support staff 

 Insurance advisor 

 Labor relations consultant 
277

 Tax consultant 

 Financial advisor 

 Legal advisor 

 Market consultant 

 Community relations/community outreach program. 

Entergy states that Owner’s Costs are real costs that the owner will incur during the project and 

are typically included in cost estimates prepared for large air pollution control retrofit projects. In 

fact, U.S. EPA’s Coal Quality Environmental Cost (CUECost) model includes Owner’s Costs 

(or “Home Office” costs) in its air pollution control system cost estimating workbook and 

interrelated set of spreadsheets. CUECost uses a factor of 10% of the total installed cost to 

estimate Owner’s Costs and Engineering Costs for limestone forced oxidation and lime spray 

dryer control systems. Entergy refers to the a section in S&L Report #012831 it included in its 

comments that describes Entergy’s Owner’s costs and how they were developed. 

Response: As we have noted in many previous actions, owner’s costs are not included in a cost 

analysis performed according to the Control Cost Manual methodology. None of the costs that 

Entergy notes in its comment is accompanied by any documentation, and in fact some appear 

optional. Entergy cites to the CUECost model, which estimates control costs using the levelized 

cost method developed by the EPRI (as opposed to the overnight method employed by the 

Control Cost Manual), is thus not approved for BART determinations, and thus has no relevance 

here. 

Comment: EPA’s cost analysis for the Independence Plant is legally and factually flawed, 

as it inappropriately relies on the White Bluff cost analysis, for which EPA inappropriately 

eliminated legitimate costs. 

[Entergy Mississippi Inc. (0168) p. 10-11] EMI stated that EPA justifies imposition of controls at 

the Independence Plant on the basis that doing so is cost-effective.530 However, there are 

numerous legal and factual errors affecting EPA’s determination of the cost-effectiveness of the 

proposed controls for Independence. First, cost-effectiveness is not a stand-alone justification for 

imposing reasonable progress emission limitations, although it is a factor in deciding the level of 

control necessary to establish RPGs. Second, EPA’s cost analysis for the proposed controls at the 

Independence Plant relies upon the control cost analysis for White Bluff, which is inappropriate. 

By simply relying on the White Bluff cost analysis without undertaking a site-specific analysis 

for the Independence Plant, EPA has arbitrarily departed from its own guidance for determining 

the costs of controls for reasonable progress purposes. Specifically, EPA’s Reasonable Progress 

Guidance requires that EPA (1) identify the emissions units to be controlled; (2) identify the 

design parameters for the controls; and (3) develop cost estimates based upon those design 

parameters.531 Additionally, even if the White Bluff cost analysis were sufficiently indicative of 

the costs to install controls at Independence, EPA’s proposed FIP grossly underestimates those 

 

530 80 Fed. Reg. at 18,994-97. 531 See Environmental Protection Agency, Guidance for Setting Reasonable Progress Goals Under the Regional 

Haze Program 5-1 – 5-2 (Jun. 1, 2007). 
278

costs. EPA’s cost analysis for White Bluff and Independence contains multiple errors and 

inaccuracies which have resulted in a vast underestimation of the true cost of controls to the 

utility owners and their customers. Finally, even if EPA’s cost analysis as detailed in EPA’s SO2

Cost TSD were correct, EPA’s determination that the controls are cost-effective is an insufficient 

basis to conclude that they must be installed for reasonable progress purposes. 

[Entergy Mississippi Inc. (0168) p. 10-11; Conway Corporation et. al. (0172) p. 13, 14-15; and 

EEAA (0173) p. 6, 7-8] EMI, Conway Corporation et. al., and EEAA stated that among other 

errors in the White Bluff analysis which EPA relied on to develop the Independence cost 

analysis, EPA improperly excluded from the cost calculation legitimate costs to install scrubbers, 

thereby eliminating millions of dollars in costs from Entergy’s cost analysis.532 EPA mistakenly 

assumed certain costs were included in the vendor estimates, so it eliminated these costs as 

duplicative, including costs for: the reagent handling system; the ductwork to supply the flue gas 

to the SDA and the ductwork from booster fans to the existing chimney; the application of acid 

resistant coating to the chimney shell; replacing the continuous emissions monitoring systems; 

and, material and labor costs.533 EPA also inexplicably eliminated the costs for one absorber 

vessel and cited no basis for its assumption that two absorber vessels are adequate for the White 

Bluff Plant despite the fact that dry scrubbers of this type have not been applied to units the size 

of the White Bluff Plant. EPA, which has no expertise in the design of FGD systems, offered no 

explanation for overriding the FGD supplier’s determination regarding the number of absorber 

vessels that would be needed at the White Bluff Plant. These errors alone result in significant 

underestimation of the costs to be borne by the White Bluff Plant’s owners and their customers, 

therefore rendering EPA’s cost analysis clearly erroneous. 

EPA also wrongly eliminated and/or failed to consider millions of dollars of owner’s costs such 

as capital suspense costs, operating and maintenance costs attributable to site-specific factors, 

post-control fuel costs, and costs related to Allowance for Funds Used During Construction 

(“AFUDC”). EPA’s elimination of these costs is contrary to EPA’s own guidance534 and 

previously approved regional haze implementation plans for other states.535 Also, although the 

subject-to-BART sources removed AFUDC from the final five-factor BART analysis in response 

to comments from EPA, we disagree with EPA that AFUDC should not be considered in the 

control costs.536 AFUDC is the time value of money on the investment in the technology that is 

incurred during the construction, which could reach $30 million to $60 million during the 30 - 46 

months of construction that would be needed to install major control equipment such as 

scrubbers on a large unit. AFUDC, which can be thought of generally as carrying costs on not-

 

532 See S&L FIP Cost Report at 7, 9 (attached as Exhibit A to Entergy Arkansas, Inc.’s comments on the Proposed 

FIP, filed July 15, 2015). 

533 Id. at 6-7. 534 The BART Guidelines advise that “[t]he baseline emissions rate should represent a realistic depiction of 

anticipated annual emissions for the source.” 70 Fed. Reg. 39,104, 39,167 (July 6, 2015) (codified at 40 C.F.R. Part 

51 App. Y). EPA’s elimination of certain operating and maintenance costs and post-control fuel costs contravenes 

this requirement. 

535 For example, EPA previously approved BART determinations that assumed “worst-case coal scenarios.” See e.g., 

Proposed Arizona Regional Haze FIP, 79 Fed. Reg. 9,318, 9,325-26 (Feb. 18, 2014); Proposed North Dakota 

Regional Haze FIP, 76 Fed. Reg. 58,570, 58,584-85 (Sep. 21, 2011). 

536 As noted in the White Bluff BART Analysis, Entergy revised its five-factor analysis of controls at White Bluff as 

requested by EPA staff in an effort to expedite consideration of the analysis but expressly reserved the ability to 

include AFUDC in future control cost analyses. White Bluff BART Analysis, at 5-4. 
279

yet-rate-based capital costs (i.e., includes interest as part of capital cost), is standard accounting 

and rate-making treatment of such costs, and it was appropriate to include AFUDC in the 

sources’ cost analyses. Contrary to EPA’s assertions, the EPA Control Cost Manual does not 

preclude inclusion of AFUDC and, in fact, the calculation provided as an example in the Control 

Cost Manual specifically includes AFUDC as a variable.537 The fact that the example “assumes” 

AFUDC is equal to zero does not reflect a decision by EPA that AFUDC should be excluded 

from emissions control costs, but actually is a recognition of that category of costs. Plain and 

simple, carrying costs (AFUDC) accumulate on any capital project until it is placed into rate 

base. That is Utility Rate Regulation 101. Accordingly, the costs of controls for the subject-toBART sources should appropriately include AFUDC. 

For all these reasons, EPA should reject the existing cost analysis for the proposed controls and 

conduct an appropriate and accurate estimate of the cost of controls for the Independence Plant. 

[Entergy Arkansas Inc. (0166) p.43-44; Conway Corporation et. al. (0172) p. 10-11; and EEAA 

(0173) p. 16-17] Entergy Arkansas Inc., Conway Corporation et. al., and EEAA stated that 

EPA’s secondary justification for imposing controls on Independence is that it is, in EPA’s 

opinion, cost-effective to do so. 80 Fed. Reg. at 18,994-97. EPA’s determination that the 

proposed controls for the Independence Plant are cost-effective is arbitrary and capricious and 

represents a clear error of judgment. 

First, EPA’s cost analysis for the proposed controls at Independence relies upon the control cost 

analysis for White Bluff, see SO2 Cost TSD at 16, which is inappropriate. By simply relying on 

its White Bluff cost analysis without undertaking a site-specific analysis for Independence, EPA 

did not follow the steps necessary to identify the costs of controls for reasonable progress 

purposes. EPA’s Reasonable Progress Guidance requires that EPA (1) identify the emissions 

units to be controlled; (2) identify the design parameters for the controls; and (3) develop cost 

estimates based upon those design parameters. Reasonable Progress Guidance at 5-1.

Second, even if the White Bluff cost analysis were sufficiently indicative of the costs to install 

controls at Independence, we disagree with EPA’s estimated costs for the installation of dry 

scrubbers at White Bluff. EPA inappropriately revised Entergy’s control cost analysis by 

eliminating the consideration of appropriate costs. EPA’s cost estimates are artificially low 

because they fail to account for key considerations. As discussed elsewhere in Entergy’s 

comments, EPA unjustifiably revised important aspects of Entergy’s Revised White Bluff BART 

Analysis, upon which the reasonable progress controls cost analysis for Independence is based. 

At the least, EPA must re-evaluate the costs of controls based upon the 2015 S&L FGD Cost 

Estimate, attached as Exhibit B to EAI’s comments. As discussed elsewhere in EAI’s comments, 

S&L estimated that the costs of dry FGD at White Bluff Units 1 and 2 would be over $1 billion, 

which is approximately 220% higher than EPA’s estimate. Based on the 2015 S&L FGD Cost 

Estimate, and assuming a 30-year life for the dry FGD systems at Independence and identical 

costs, this results in an average cost-effectiveness at Independence Unit 1 of $4,234 and of 

$3,909 at Independence Unit 2, which is not cost effective on a $/ton basis for reasonable 

progress purposes and is much higher than cost per ton thresholds EPA rejected for reasonable 

progress determinations in other states. As importantly, the cost per deciview improvement that 

 

537 See Control Cost Manual at 1-32, 2-44. 
280

would result from installing these controls is estimated at approximately $1.33 billion at Caney 

Creek and $1.53 billion at Upper Buffalo. See S&L FIP Cost Report at 21, Table 8. Such a 

massive investment cannot be justified in light of the continuous improvement in visibility being 

achieved at both Caney Creek and Upper Buffalo. 

Entergy Arkansas Inc., p.43-44, (0021); Entergy Mississippi Inc., p. 12-13, (009); Conway 

Corporation et. al., p. 10-11, (008); and EEAA, p. 17, (0014)] EAI, EMI, Conway Corporation 

et. al., and EEAA stated that despite the flaws in EPA’s analysis of Entergy’s costs, EPA 

concludes that dry FGD is cost-effective at $2,477 per ton of SO2 removed for Independence 

Unit 1 and $2,286 per ton of SO2 removed for Unit 2. 80 Fed. Reg. at 18,994. Dry FGD is not 

cost-effective for reasonable progress controls. These costs are higher than other cost per ton 

thresholds in RPG determinations in EPA-approved SIPs. The Kentucky Regional Haze SIP, 76 

Fed. Reg. 78,194, 78,206 (Dec. 16, 2011), used $2,000 per ton SO2 as a screening threshold for 

cost-effectiveness based on CAIR. In the North Carolina Regional Haze SIP, 77 Fed. Reg. 

11,858, 11,870 (Feb. 28, 2012), EPA approved the state’s decision not to implement reasonable 

progress controls due to limited improvement in visibility even though cost effectiveness values 

were described as ranging “from 912 to 1,922 dollars per ton of SO2 removed ($/ton SO2), and 

the average costs per utility system ranged from $1,231 to $1,375/ton SO2.” EPA’s estimated 

cost effectiveness of dry FGD at Independence is significantly higher than these thresholds, at 

$2,477/SO2 ton removed for Unit 1 and $2,286/SO2 ton removed for Unit 2. 80 Fed. Reg. at 

18,994. Further, EPA has indicated that control costs found to be reasonable in the BART 

context may nonetheless be considered too costly in the reasonable progress context. See Final 

North Dakota SIP Approval/Disapproval, 77 Fed. Reg. 20,894, 20,936 (Apr. 6, 2012) (accepting 

North Dakota’s determination that a level of $2,593 per ton of SO2 removed was not reasonable 

and too costly in the reasonable progress context even though it is within the range EPA “ha[s] 

considered reasonable in the BART context”). Such an acknowledgement is particularly 

appropriate in the present case where the state’s Class I areas are already meeting and exceeding 

the URP necessary to achieve the national visibility goal. Despite these prior actions, EPA 

unreasonably concludes that the proposed controls at Independence are cost effective for 

reasonable progress purposes. 

Finally, even if EPA’s cost analysis as detailed in the SO2 Cost TSD were correct, EPA’s 

determination that the controls are cost-effective is an insufficient basis to conclude that they 

must be installed for reasonable progress purposes. 

Response: We have addressed AFUDC and owner’s costs in our responses to other comments. 

We agree with Entergy that cost-effectiveness is not a stand-alone justification for imposing 

reasonable progress emission limitations, although it is one of the statutory factors. We believe 

we followed our regulations when assessing reasonable progress for the Independence facility, as 

we describe in our proposal.538 We also believe we were consistent with our reasonable progress 

Guidance. We disagree that for the purposes of assessing reasonable progress, we erred in using 

our scrubber cost analysis for the White Bluff facility as a good starting point for assessing the 

scrubber cost-effectiveness of the Independence facility. As we note in more detail in our 

proposal, the White Bluff and Independence Plants are sister facilities with nearly identical units. 

 

538 See the discussion in our proposal beginning on 80 FR 18989 regarding how we assessed reasonable progress at 

the Independence facility. 
281

We explained that we verified that the two plants are sister facilities by constructing a master 

spreadsheet that contains information concerning ownership, location, boiler type, environmental 

controls, and other pertinent information. Based on the similarities between the two facilities, in 

our analysis of costs for controls on Independence we relied on the total annualized costs of 

controls we developed for White Bluff. Due to the similarities in the facilities and the identical 

requirement for consideration of cost of controls under reasonable progress and BART, using the 

cost of controls from White Bluff was a reasonable approach for estimating the cost of controls 

for Independence Units 1 and 2. Using control costs from similar (let alone sister facilities, as in 

this case) as the basis to assess the cost of controls is a common practice. We do note that in 

calculating the cost effectiveness of SO2 controls for Independence Units 1 and 2, we used 

baseline SO2 emissions data specific to the Independence units to estimate the annual SO2

emissions reductions due to controls. Entergy has submitted comments critiquing our White 

Bluff scrubber cost analysis, and has submitted a revised White Bluff scrubber cost analysis. We 

incorporate Entergy’s revised White Bluff cost analysis into our White Bluff cost analysis. 

However, Entergy has not submitted any scrubber cost analysis for the Independence facility or 

other information that would cause us to conclude that the cost of installing scrubbers would be 

significantly higher at the Independence facility in comparison to the White Bluff facility. Thus, 

considering the information we have available to us, we conclude that the cost to install 

scrubbers at the Independence facility is similar to what we have calculated for the White Bluff 

facility. In any case, we have not seen any information presented by Entergy to conclude that the 

differences in scrubber costs between the White Bluff and Independence facilities are outside the 

+/-30% accuracy required for study level estimates, which are based on “rough sketches,” 

“preliminary sizes,” “approximate sizes,” “rough estimates,” etc., which is the level of accuracy 

required for regional haze cost analyses.539 Thus, we continue to base our Independence scrubber 

cost analysis on our White Bluff cost analysis, which we have revised based on Entergy’s 

comments. We address this issue, as well as other criticisms our White Bluff cost analysis in 

more detail in our response to other comments. 

Entergy states that our proposed costs for the installation of scrubbers at the Independence 

facility are higher than other reasonable progress costs that we have deemed to be too high in 

other instances. As an initial matter, cost is only one of four required factors that must be 

considered in determining reasonable progress for Independence, as Entergy itself acknowledges 

earlier in its comments.540 We note that the cost of compliance is also a factor that must be 

considered in a BART analysis.541 In addition, in our reasonable progress analysis for 

Independence, we also considered the visibility improvement of controls. We discuss elsewhere 

in this document that although visibility is not one of the four mandatory factors explicitly listed 

for consideration under CAA section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), states or EPA 

have the option of considering the projected visibility benefits of controls in determining if the 

controls are necessary to make reasonable progress. As we have discussed in our Texas and 

Oklahoma FIP final decision, “...we believe that states (or EPA when promulgating a FIP) can 

 

539 Control Cost Manual, p. 2-3. 540 See section 51.380(d)(1)(i): “(i) In establishing a reasonable progress goal for any mandatory Class I Federal 

area within the State, the State must: (A) Consider the costs of compliance, the time necessary for compliance, the 

energy and non-air quality environmental impacts of compliance, and the remaining useful life of any potentially 

affected sources, and include a demonstration showing how these factors were taken into consideration in selecting 

the goal. 

541 CAA section 169A(g)(2) and 40 CFR section 51.308(e)(1). 
282

consider visibility when determining reasonable progress....”. Regardless, we have recently 

finalized reasonable progress and long-term strategy SO2 emissions in our Texas and Oklahoma 

FIP based on scrubber retrofits, similar to those discussed herein, at cost-effectiveness figures 

above those for the Independence facility.542 

Regarding the Kentucky proposal cited by Entergy, we disagree that requiring SO2 controls for 

Independence is inconsistent with our approvals of the Kentucky and North Carolina RH SIPs. 

As discussed elsewhere in this document, in response to comments we received, we have revised 

our initial cost analysis for Independence Units 1 and 2. We have determined that dry scrubbers 

are estimated to cost $2,853/SO2 ton removed for Unit 1 and $2,634/SO2 ton removed for Unit 2. 

Even with these cost adjustments, we continue to believe that these controls are cost effective 

and disagree that requirement of these controls is inconsistent with our approvals of the 

Kentucky and North Carolina RH SIPs. The commenter contends that in our proposed approval 

of the Kentucky RH SIP, we approved the state’s use of a $2,000/SO2 ton threshold. This is 

incorrect. In the preamble of our proposed approval of the Kentucky RH SIP, we discussed that 

the state identified 10 units for evaluation under reasonable progress, and that 9 of these were 

EGUs subject to CAIR. The remaining facility, Century Aluminum, is not an EGU. We further 

discussed that for the limited purpose of evaluating the cost of compliance for the reasonable 

progress assessment in this first regional haze SIP for the non-EGU Century Aluminum, 

Kentucky concluded that it was not equitable to require non-EGUs to bear a greater economic 

burden than EGUs for a given control strategy. As a result, Kentucky decided to use CAIR as a 

guide, using a cost of $2,000 per ton of SO2 controlled or reduced as a threshold for costeffectiveness for that particular non-EGU source. We stated the following regarding Kentucky’s 

evaluation of the Century Aluminum facility: 

The Century Aluminum facility in Hawesville, Kentucky, has four potlines with 

2002 base year emissions of 4,985 tons per year of SO2 which were identified as 

having a significant contribution at the Mammoth Cave Class I area. VISTAS 

evaluated control options and costs for sources within the AOI for the Class I 

areas of concern. VISTAS used EPA’s AirControlNet software to evaluate 

control options and costs for controls. The cost effectiveness of SO2 control 

suggested by the VISTAS control cost spreadsheet for potlines 1– 4 at Century 

Aluminum is $14,207 per ton of SO2 removed. Since the cost of compliance for 

the control option is over seven times greater than the Commonwealth’s costeffectiveness threshold [$2,000] for reasonable progress, KYDAQ concludes that 

there are no cost-effective controls available for these Century Aluminum units at 

this time within the cost threshold established for this reasonable progress 

assessment for the first implementation period.543

 

542 See Table 32 on our proposal for this action at 79 FR 74876 for a cost-effectiveness summary. As we discuss in 

our final action, 81 FR 317, “We received other comments relating to our scrubber retrofit cost analyses, but none of 

them caused us to revise our scrubber retrofit cost-effectiveness basis.” 543 76 FR 78206. 
283

We proposed to approve Kentucky’s determination that there are no reasonable controls 

available for the Century Aluminum units for the first implementation period, but we also stated 

the following concerning our position on Kentucky’s use of a $2,000/SO2 ton screening 

threshold:544

Although the use of a specific threshold for assessing costs means that a state may 

not fully consider available emissions reduction measures above its threshold that 

would result in meaningful visibility improvement, EPA believes that the 

Kentucky SIP still ensures reasonable progress. In proposing to approve 

Kentucky’s reasonable progress analysis, EPA is placing great weight on the fact 

that there is no indication in the SIP submittal that Kentucky, as a result of using a 

specific cost effectiveness threshold, rejected potential reasonable progress 

measures that would have had a meaningful impact on visibility in its Class I area. 

EPA notes that given the emissions reductions resulting from CAIR, Kentucky’s 

BART determinations, and the measures in nearby states, the visibility 

improvements projected for the affected Class I area are in excess of that needed 

to be on the uniform rate of progress glidepath. 

It is clear that in our proposed approval of Kentucky’s reasonable progress determination for the 

Century Aluminum units, we were not approving or otherwise advocating Kentucky’s use of a 

$2,000/SO2 ton threshold in the reasonable progress analysis. On the contrary, we expressed 

concern that the use of a specific threshold for assessing cost may result in a state not fully 

considering potential reasonable control measures above that threshold that would have 

meaningful visibility improvement on its Class I areas. But in this particular instance, we do not 

believe that the use of a cost threshold in Kentucky’s SIP resulted in the state overlooking 

potential controls in its reasonable progress analysis. Furthermore, our statements in the 

proposal indicate that had there been evidence of controls available above the $2,000/SO2 ton 

threshold used by the state that provide meaningful visibility improvement at the Class I areas, 

we might have arrived at a different decision concerning the approvability of Kentucky’s 

reasonable progress analysis. 

North Carolina took a similar approach as Kentucky in its reasonable progress analysis. In our 

proposed approval of the North Carolina RH SIP, we discussed that the state identified 11 units 

(non-EGU) for evaluation under reasonable progress. We noted that North Carolina decided that 

for the limited purpose of evaluating the cost of compliance for the reasonable progress 

assessment in this first regional haze SIP for these non-EGs, it was not equitable to require nonEGUs to bear a greater economic burden than EGUs for a given control strategy. Regarding 

Entergy’s reference to our North Carolina reasonable progress proposal, we stated: 

NCDAQ believed that it was not equitable to require non- EGUs to bear a greater 

economic burden than EGUs for a given control strategy. The facility-by-facility 

costs for EGUs under CSA ranged from 912 to 1,922 dollars per ton of SO2

removed ($/ton SO2), and the average costs per utility system ranged from $1,231 

to $1,375/ ton SO2. These costs were estimated using the capital costs from the 

 

544 76 FR 78206. 
284

CSA 2006 compliance plans and the projected operating costs provided by Duke 

Energy and Progress Energy. These costs were used as a guide in determining 

cost effectiveness.545

We proposed to approve North Carolina’s determination that there are no reasonable controls 

available for sources in the state for the first implementation period, but we also stated the 

following concerning our position on North Carolina’s use of a specific screening threshold: 

Although the use of a specific threshold for assessing costs means that a state may 

not fully consider available emissions reduction measures above its threshold that 

would result in meaningful visibility improvement, EPA believes that the North 

Carolina SIP ensures reasonable progress. In approving North Carolina’s 

reasonable progress analysis, EPA is placing great weight on the fact that there is 

no indication in the SIP revision that North Carolina, as a result of using a specific 

cost effectiveness threshold, rejected potential reasonable progress measures that 

would have had a meaningful impact on visibility in its Class I areas.546

Thus, we do not believe that the use of a cost threshold in North Carolina’s SIP resulted in the 

state overlooking potential controls. As in the case of Kentucky, it is clear that in our proposed 

approval of North Carolina’s reasonable progress determination, we were not approving or 

otherwise advocating North Carolina’s use of that specific screening threshold in the reasonable 

progress analysis. 

Entergy also points to our North Dakota final decision as evidence that we have concluded that 

cost-effectiveness values for BART may be too high for reasonable progress determinations. 

This conclusion is not borne out by the facts. First, the unit in question in our North Dakota 

decision already had a dry scrubber, albeit one that is underperforming relative to typical dry 

scrubber efficiencies. The control cost evaluation discussed in the response to comment that 

Entergy cites would have replaced the existing dry scrubber with a new wet scrubber. Thus, the 

basic facts between our Independence reasonable progress analysis and our North Dakota 

decision are not comparable. Beyond that, we did not make the kind of blanket statement 

concerning the acceptability of reasonable progress cost-effectiveness in comparison to that of 

BART that Entergy claims. The full quote that Entergy partially reproduces is: 

As stated in our proposal, while this value is within the range of cost effectiveness 

values that North Dakota, other states, and we have considered reasonable in the 

BART context, it is not so low that we are prepared to disapprove the State’s 

conclusion in the reasonable progress context. 

As can be seen from an examination of the full quote, this statement in no way constitutes a 

blanket comparison of the acceptability of BART cost-effectiveness to that of reasonable 

progress determinations. 

Entergy further states that re-applying its revised White Bluff cost analysis to the Independence 

 

545 77 FR 11870. 546 77 FR 38189. 
285

facility would result in a cost-effectiveness $4,234 at Unit 1 and $3,909 at Independence Unit 2. 

Entergy states that those figures are not cost effective and results in a much higher cost per ton 

than values we have rejected for reasonable progress determinations in other states. As we 

discuss in our response to other comments, we do not agree with Entergy’s revised scrubber cost 

analysis for the White Bluff facility and believe it is much lower. 

Comment: EPA and Entergy’s evaluations of the cost of dry and wet scrubbers for White 

Bluff contained conservative assumptions and included errors that inflated the cost of these 

controls. [Sierra Club et. al. (0171) p. 19-21] Sierra Club et. al. stated that EPA proposed that 

SO2 BART for White Bluff Units 1 and 2 is an emission limitation of 0.06 lb/MMBtu on a 30-

day rolling average based on the operation of a dry scrubber or another technology. 80 Fed. Reg. 

at 18,972-73. EPA estimated that this technology would have an average cost-effectiveness of 

$2,227 per ton of SO2 removed for Unit 1 and $2,101 per ton of SO2 removed for Unit 2. 80 Fed. 

Reg. at 18,972. We strongly support EPA’s proposal to require the installation of a scrubber at 

White Bluff and to set a limit on SO2 emissions. The attached Stamper report confirms EPA’s 

conclusion that the controls proposed in the FIP are cost-effective and readily satisfy the other 

BART requirements, and any less effective controls would not comply with BART. Stamper 

Report at 30-32. In fact, Ms. Stamper conducted her own analyses of the proposed controls and 

concludes that the proposed controls are even more cost-effective than EPA considered, can 

achieve an emission rate of 0.04 lb/MMBtu, will provide greater visibility benefit, and are 

reasonable compared to costs borne by sources in other states. Id. As such, EPA should 

determine that SO2 BART for the White Bluff units is an emission rate of 0.04 lb/MMBtu based 

on the use of either a wet or a dry scrubber. 

The Technical Support Document to Comments of Conservation Organizations, Prepared by 

Victoria R. Stamper, August 5, 2015 (“Stamper Report”), discusses several ways in which EPA 

and Entergy used conservative assumptions that inflated the cost of the controls EPA is 

proposing and concludes that these controls are even more cost-effective than EPA calculated. 

First, EPA itself identified several flaws with Entergy’s cost analysis but failed to correct the 

analysis. Ms. Stamper’s revised cost analysis addresses the problems EPA identified with 

Entergy’s dry and wet scrubber cost estimates. First, Entergy based its operation and 

maintenance (“O&M”) costs on burning coal with an uncontrolled SO2 rate of 2.0 lb/MMBtu. 

See 80 Fed. Reg. at 18,970. As EPA correctly noted, actual uncontrolled SO2 emissions rates for 

the White Bluff units have been 35% of what Entergy assumed. Id. The Clean Air Act requires 

that EPA determine BART using a “baseline emission rate [that] represent[s] a realistic depiction 

of anticipated annual emissions.” 40 C.F.R. Part 51, App. Y § (D)(4)(d)(1). As such, a lower 

uncontrolled SO2 rate than that assumed by Entergy is appropriate for BART evaluation. 

Second, EPA found that Entergy included undocumented costs that, under EPA’s Cost Control 

Manual, are inappropriate and could constitute double counting. See 80 Fed. Reg. at 18,971. EPA 

should require that Entergy appropriately document all costs and prohibit the inclusion of costs 

that other EGUs in other states were precluded from including pursuant to the Cost Control 

Manual. Similar cost estimate rules across states are necessary for reasonable comparison of 

cost-effectiveness. 
286

Ms. Stamper revised the cost analyses for a wet scrubber, a dry scrubber, and a NID scrubber 

that reflect achievable emission rates. Ms. Stamper used the SO2 control cost spreadsheets that 

EPA recently used in the Texas regional haze rulemaking, which are based on Sargent & Lundy 

Integrated Planning Model (“IPM”) cost modules. Stamper Report at 30-32. EPA’s conservative 

cost-effectiveness calculations and Ms. Stamper’s revised cost-effectiveness calculations both 

demonstrate that EPA should base the SO2 BART emission limit on installation of scrubbers: 

Revised SO2 Control Cost-Effectiveness Evaluation for 

White Bluff Units 1 and 2547

White Bluff 

Unit 

SO2

Control

Total 

Annualized 

Costs

Tons SO2

Removed

Cost 

Effectiveness

EPA’s Cost 

Effectiveness548

1 Wet FGD $38,113,408 18,569 tpy $2,053/ton $3,336/ton 

1 NIDTM CDS $40,584,907 18,569 tpy $2,186/ton -- 

1 Dry FGD (SDA) $40,103,035 17,995 tpy $2,229/ton $2,227/ton 

2 Wet FGD $37,304,852 15,975 tpy $2,335/ton $3,152/ton 

2 NIDTM CDS $39,191,891 15,975 tpy $2,453/ton -- 

2 Dry FGD (SDA) $39,046,260 15,459 tpy $2,526/ton $2,101/ton 

These cost-effectiveness estimates, assuming actual uncontrolled SO2 emissions during the 2001-

2003 baseline period—which are lower than the emissions assumed by Entergy—show that a 

wet scrubber, a dry scrubber, and a NID scrubber are all cost effective as compared to BART 

determinations in other states. See Section I.A.1.a.i of the Sierra Club et. al.’s comments 

(providing SO2 BART costs from other states). 

Response: We have reviewed the section of the Stamper report that treats this issue in more 

detail and respond to both it and this comment here. We confirm that we intended to construct 

conservative cost analyses. The Sierra Club states that we identified several flaws with 

Entergy’s cost analysis but failed to correct the analysis. We do not find any flaws in the White 

Bluff BART analysis that we did not propose to correct, except for minor oversights (noted in 

our responses to Entergy’s comments) that do impact our proposed BART determinations. 

Ms. Stamper proposes that we should have required the installation of scrubbers in three years, 

citing to a letter to Senator Carper dated November 3, 2010, in which David Foerter, executive 

director of the Institute of Clean Air Companies (ICAC), which stated that wet scrubbers could 

be installed in 36 months, dry scrubbing technology could be installed in 24 months, and dry 

sorbent injection could be installed in 12 months. Ms. Stamper also cites to a number of 

scrubber installations that are planning on completing within three years, or thereabouts. We 

agree that in some cases scrubbers can be installed in less than the five years that we proposed. 

However, this is site-specific and we cannot guarantee that an installation timeframe of less than 

 

547 Stamper Report at 31. 548 80 Fed. Reg. 18,971, Tables 32 and 33. 
287

five years would be achievable for White Bluff. Thus, we have defaulted to the maximum time 

allowed under the Regional Haze Rule for BART, which is five years. This has been our 

position on all scrubber installations we have required in our FIPs. 

We disagree with the position Ms. Stamper takes in her report that wet scrubbers are, in the 

specific cases of the White Bluff and Independence facilities, more cost effective than dry 

scrubbers (SDA; we discuss NID below) and that BART should have been based on a wet 

scrubber control level of 0.04 lbs/MMBtu for the White Bluff facility (Independence is not 

subject to BART). Our scrubber cost analyses was built off of the analyses supplied by Entergy, 

and we determined that wet scrubbers were significantly less cost effective—again, in the 

specific cases of the White Bluff and Independence facilities for BART and reasonable progress 

respectively. The scrubber analysis that Ms. Stamper performs, uses a modified version of the 

IPM cost algorithms we used in our TX-OK FIP. Although we find the use of those algorithms 

perfectly adequate for cost analysis for both BART and reasonable progress, we disagree with 

the SO2 baseline Ms. Stamper uses, rendering her scrubber cost analysis and ours not directly 

comparable. However, we generally agree with Ms. Stamper that an independent cost analysis 

such as she presents does support our basic position that scrubbers are cost effective at the White 

Bluff and Independence facilities. 

We agree that the Alstom NID circulating dry scrubber is a promising SO2 control option. We 

reviewed NID in our preliminary work but ultimately decided not to evaluate it as a control 

because we had no relevant operating data and no method to estimate costs. As part of our work 

related to our recent TX-OK FIP,549 we addressed a similar comment. In so doing, we reviewed 

the proposed NIDs at Flint Creek (2016550), Homer City 1 & 2 (2016), Indian River Unit 4 

(2011), Brayton Point Unit 3 (2013), and (Clay) Boswell Unit 4 (2016). We researched each one 

of these facilities and learned that only Indian River Unit 4 and Brayton Point Unit 3 were 

currently operating. 

We downloaded the SO2 CEMS data for these two facilities from CAMD, computed 30-day 

BOD averages, achieved SO2 control efficiencies, and determined the maximum 30-day BODs. 

This analysis is present in the final docket for our TX-OK FIP.551 Neither of these units is 

performing at the level of a wet FGD – 98% SO2 control or 0.04 lb/MMBtu. 

Indian River Unit 4 has achieved only 86% SO2 removal based on a design level of 96%, rather 

than our target of 98% using wet FGD.552 The maximum 30-day BOD is 0.94 lb/MMBtu and the 

lowest 30-day BOD, representing its best performance, is 0.07 lb/MMBtu. Brayton Point Unit 3 

has achieved 94% SO2 removal and the maximum 30-day BOD is 0.16 lb/MMBtu. Brayton 

 

549 81 FR 296. 550 Parenthetical dates are projected or actual startup dates, as reported in the McIlvaine Utility Tracking System or 

in CAMD. 

551 http://www.regulations.gov/#!docketBrowser;rpp=50;po=0;dct=PS;D=EPA-R06-OAR-2014-0754. See 

“Selected NID BOD SO2 Averages.xlsx.” 552 Burns & McDonnell, Indian River Unit 4, http://www.burnsmcd.com/Resource_/Project/1302/ProjectPdf/IndianRiver-Unit-4.pdf. 
288

Point Unit 3 is scheduled for shutdown in 2017.553 Further, these facilities are not similar to the 

White Bluff units as they burn bituminous coal with higher sulfur contents.554 

However, this technology is promising, and we will continue to monitor NID performance for 

consideration in the next round of SIPs, when the technology has more relevant operating 

history. 

The other NIDs we reviewed are “polishing” scrubbers on circulating fluidized bed boilers, 

which are not similar boiler types. Further, none of them burn PRB coal. For example, Seward 

burns high sulfur waste coal; Gilbert Unit 3 burns high sulfur bituminous coal; and Spurlock 

Unit 4 burns high sulfur bituminous coal and switchgrass.555

Finally, we note that as NID technology is theoretically capable of achieving the same SO2

control efficiency as the wet FGD scrubber retrofits that we evaluated, the facilities in question 

are free to choose NID or any other technology to satisfy their emission limits. 

Comment: EPA has overestimated the costs of SCR and underestimated the costeffectiveness of SCR and SNCR for White Bluff Units 1 and 2. [Sierra Club et. al. (0171) p. 

22-25] Sierra Club et. al. stated that EPA proposed that NOX BART for White Bluffs Units 1 and 

2 is an emission limitation of 0.15 lb/MMBtu based on the installation of Low NOX Burners 

(LNB) and separated overfire air (“SOFA”). 80 Fed. Reg. at 18974. EPA estimated that 

operation of LNB/SOFA would have an average cost effectiveness of $350 and $340 per ton of 

NOx removed for Unit 1 and Unit 2, respectively. Id. EPA’s proposal to require LNB/SOFA 

represents a cost-effective way to achieve some NOX emission reductions at White Bluff and, 

therefore, is the absolute minimum that EPA must require as selection of anything less stringent 

would be arbitrary, capricious, and contrary to law. The LNB/SOFA proposal, however, does not 

satisfy BART, which requires “the application of the best system of continuous emission 

reduction.” Such best system is an SCR. The Stamper Report concludes that EPA has 

overestimated the costs of SCR, underestimated the visibility benefits of SNCR and SCR, and 

underestimated the cost-effectiveness of SCR and SNCR. Stamper Report at 35-45. The costs of 

these controls are reasonable compared to costs borne by sources in other states. Id. at 40-43. For 

these reasons, we urge EPA to conclude that NOx BART at White Bluff Units 1 and 2 requires an 

emission limit of 0.04 lb/MMBtu based on installation of SCR with LNB/SOFA. 

To more appropriately consider the cost of controls, Ms. Stamper revised the cost-effectiveness 

calculations for all of the NOX BART controls evaluated by EPA and Entergy for the White Bluff 

Units 1 and 2. Ms. Stamper’s cost-effectiveness estimates rely on the Sargent & Lundy IPM SCR 

Cost Module and assume an achievable NOx emission rate of 0.04 lb/MMBtu for LNB/SOFA 

 

553 Dorothy Davis Ballard, Brayton Point Coal-Fired Power Plant Confirmed for Shut Dow by 2017, Power, January 

29, 2014, http://www.pennenergy.com/articles/pennenergy/2014/01/brayton-point-coal-fired-power-plantconfirmed-for-shut-down-by-2017.html. 

554http://www.google.com/url?sa=t&rct=j&q=&esrc=s&source=web&cd=8&ved=0CFEQFjAHahUKEwifqrrXvc_H

AhWFjw0KHQL9Cc8&url=http%3A%2F%2Fpennwell.websds.net%2F2013%2Fbangkok%2Fpga%2Fpapers%2F

T2S4O1-paper.pdf&ei=GkXiVZ1GoWfNoL6p_gM&usg=AFQjCNFWrXl39kOm6Ya_4YnvwtYZItZDOQ&cad=rja 

555 http://www.ekpc.coop/pressreleases/2009%20press%20releases/2009-04-01_Spurlock4_commercial_start.pdf 
289

plus SCR. As noted elsewhere in the Sierra Club et. al.’s comments, EPA has relied on the 

Sargent & Lundy cost modules to estimate the cost for SCR in its evaluation of NOX BART in 

other states. Stamper Report at 40-42. Ms. Stamper’s revised cost analysis relies on baseline NOx 

emissions from 2012-2014. Entergy used a 2009-2011 baseline for its NOX BART analysis 

because the company had installed in 2006 a “neural network system” and conducted “extensive 

boiler tuning” at White Bluff Units 1 and 2 that resulted, according to Entergy, in reduced NOX 

emission rates. 80 Fed. Reg.18,969. In fact, NOx emission rates have increased from the NOX 

rates achieved during the 2009-2011 timeframe at both of the White Bluff units. Stamper Report 

at 35-39. Based on data from EPA’s Clean Air Markets Database, White Bluff Unit 1’s NOX 

rates have been steadily increasing since the neural network installation, whereas White Bluff 

Unit 2’s NOx rates have oscillated higher and lower. See id.

The BART guidelines require that the “baseline emission rate should represent a realistic 

depiction of anticipated annual emissions for the source.” 40 C.F.R. Part 51, Appendix Y, 

Section IV.D.4.c. Given the variability of NOx emission rates, Entergy’s selection of a 2009- 

2011 baseline period is not a realistic depiction of anticipated annual NOx emissions from the 

White Bluff units. In fact, Entergy’s selection of the 2009-2011 timeframe for a baseline period 

reflects the period of lowest annual average NOx emissions for White Bluff Unit 1 since the 2006 

installation projects. Stamper Report at 37. For White Bluff Unit 2, the 2009-2011 annual 

average NOx emissions were the second lowest three-year period of NOX emissions after 2006, 

and more recent periods of NOx emissions have been about 3% higher than the 2009-2011 

timeframe. Id. Based on data compiled by Ms. Stamper, the period 2012-2014 appears to most 

realistically depict anticipated annual emissions for White Bluff. As such, Ms. Stamper’s cost 

analysis assumes baseline emissions over the period 2012-2014 timeline, which is the highest 

three year period since the installation of the neural network system. 

Ms. Stamper’s revised estimates (and even Entergy’s unrevised estimates) show that LNB/SOFA 

plus SCR and LNB/SOFA plus SNCR are both cost effective as NOx BART for 

White Bluff: 

Revised NOx Control Cost-Effectiveness Evaluation for White Bluff Units 1 and 2 to Reflect 

a 2012-2014 Baseline and to Recalculate Costs for SCR to Achieve a 0.04 lb/MMBtu 

Emission Rate556

White Bluff 

Unit 

NOx 

Control

Total 

Annualized 

Costs

Tons NOx 

Removed

Cost 

Effectiveness

EPA’s Cost 

Effectiveness557

1 LNB/SOFA $1,085,904 4,262 tpy $255/ton $350/ton 

1 LNB/SOFA 

plus SNCR $6,430,580 4,826 tpy $1,332/ton $1,758/ton 

1 

LNB/SOFA 

plus SCR 

(Aug 2010 IPM 

SCR Cost Module) 

$17,708,428 7,364 tpy $2,405/ton $3,552/ton 

 

556 Stamper Report at 41-42. 557 80 Fed. Reg. 18973, Table 36. 
290

1 

LNB/SOFA 

plus SCR 

(Mar 2013 IPM 

SCR Cost Module) 

$21,713,253 7,364 tpy $2,949/ton $3,552/ton 

2 LNB/SOFA $1,403,376 3,968 tpy $354/ton $340/ton 

2 LNB/SOFA 

plus SNCR $6,759,102 4,537 tpy $1,490/ton $1,449/ton 

2 

LNB/SOFA 

plus SCR 

(Aug 2010 IPM 

SCR Cost Module) 

$18,083,166 7,099 tpy $2,547/ton $2,749/ton 

2 

LNB/SOFA 

plus SCR 

(Mar 2013 IPM 

SCR Cost Module) 

$22,099,642 7,099 tpy $3,113/ton $2,749/ton 

The above table demonstrates that the use of the higher NOX emissions during 2012 to 2014 

results in greater NOX reductions and lower cost-effectiveness numbers for LNB/SOFA, 

LNB/SOFA plus SNCR, and LNB/SOFA plus SCR (when SCR costs are based on the August 

2010 module). As discussed in Section I.A.2.b of Sierra Club’s comments, EPA and states have 

found that costs of SCR plus combustion controls in the range of $2,000/ton to $4,500/ton were 

reasonable and cost-effective. Therefore, it is cost effective for White Bluff Units 1 and 2 to 

install LNB/SOFA plus SCR, and such controls will provide for the greatest improvement in 

visibility impairment due to White Bluff’s NOX emissions compared to all other NOX controls 

evaluated by EPA. 

Ms. Stamper states that we have not proposed to require installation of low NOX burners and 

separated overfire air as expeditiously as possible. Specifically, EPA proposed to allow three 

years from the effective date of the final rule to install low NOx burners/SOFA at White Bluff 

Units 1 and 2. 80 Fed. Reg.18,975. While three years from the effective date of EPA’s final 

rulemaking may be necessary to install an SCR system, low NOX burners and SOFA can be 

installed in much shorter timeframes. 

Specifically, the Institute of Clean Air Companies (ICAC) has indicted that the typical 

installation timeframe for low NOX burners would take between 6-8 months from bid evaluation 

through startup of the technology. Most of the components can be installed while the boiler is 

operating, and the boiler may need to be shut down for as little as 1 day or up to a week. Based 

on the ICAC report, eight months from the effective date of EPA’s final regional haze rule for 

Arkansas should be sufficient time for Entergy to install low NOX burners and SOFA at White 

Bluff Units 1 and 2, and thus reflects implementation of BART as expeditiously as practicable. 

With respect to SCR systems, three years is more than sufficient time for installation of SCR 

systems at White Bluff Units 1 and 2. In fact, other utilities have installed SCR systems on 

multiple units within very short periods of time. 
291

As previously discussed, SCRs were installed and began operation on the W.A. Parish Units 5-8 

over a period of about one year and three months. Specifically, an SCR was installed on W.A. 

Parish Unit 6 in Jan 2003, on W.A. Parish Unit 5 in April 2003, on W.A. Parish Unit 8 in Dec 

2003, and on W.A. Parish Unit 7 in March 2004. SCRs were installed at four units of the Big 

Bend power plant over four year – one unit per year – during 2007-2010.177 SCR systems were 

installed at five units at Kyger Creek power plant over 2002 to 2003.178 SCR systems were 

installed at Units 1-5 of the Clifty Creek power plant also over 2002 to 2003.179 In 2005, Santee 

Cooper installed SCR systems on Cross Units 1 and 2 and Winyah Units 1-4, all in South 

Carolina.18 

Response: We have reviewed the section of the Stamper report that treats this issue in more 

detail and respond to both it and this comment here. We disagree with the Sierra Club’s apparent 

position that BART controls must be selected based on which are the “best system of control,” 

without apparent consideration of the five BART factors: cost, energy and nonair quality 

environmental impacts, pollution controls in use at the source, remaining useful life, and 

visibility improvement.558 

In critiquing our NOX BART evaluation for White Bluff, Ms. Stamper argues that Entergy’s 

2009-2011 NOx baseline of 7,255 tons/yr for Unit 1 and 8,193 tons/yr for Unit 2 were not 

reflective of anticipated future actual emissions. Based on the annual emissions Ms. Stamper 

presents in Table 7, we agree that a three year average of the annual emissions from 2009-2011, 

7,255 tons/yr does not represent the highest emitting three year average period for Unit 1, which 

was 10,041 in 2001-2003, seconded by the 8,492 value from 2012-2014. Similarly, the 2009-

2011 average for Unit 2 of 8,193 tons/yr lags behind the 8,586 value from 2001-2003, the 8,297 

value in 2011-2013, and the 8,238 value from 2012-2014. However, the BART Guidelines do 

not require that the baseline used in the cost effectiveness analysis be constructed from the 

highest emissions from any given year or years, only that, as Ms. Stamper acknowledges, the 

“baseline emissions rate should represent a realistic depiction of anticipated annual emissions for 

the source.”559 As a first matter, we believe it was reasonable to select a baseline after the neural 

network was installed in 2006, which eliminates from consideration the highest NOX annual 

emission average for Unit 1 from the 2001-2003 period. We further note that were we to have 

selected a NOx baseline from the most recent three year average, 2013 to 2015, which arguably 

more “represent[s] a realistic depiction of anticipated annual emissions for the source,” the result 

would have been 7,731 tons/yr for Unit 1 and 7,406 tons/yr for Unit 2. This would have 

produced a baseline only slightly higher for Unit 1, decreasing the cost-effectiveness calculation 

by 6.6%, which would not have materially impacted our proposed NOx BART determination. In 

contrast, this would have produced a baseline lower for Unit 2, increasing the cost-effectiveness 

calculation by 9.6%, making the NOX controls less attractive. Hence, we find that no change is 

necessary to the White Bluff NOx baseline. 

Ms. Stamper goes on to select a revised NOX baseline based on a maximum three year NOX

average emissions calculation and inputs that, along with a rejection of our acceptance of 

Entergy’s SCR NOx emission rate of 0.55 lbs/MMBtu in favor of a lower SCR outlet of 0.04 

lbs/MMBtu, into a revised SCR cost analysis. She supports her 0.04 lbs/MMBtu NOX rate by 

 

558 Summarized from Section 51.308(e)(1)(ii)(A). 559 70 FR 39167. 
292

pointing to a number of high performing SCR installations, including those we presented in our 

San Juan SCR cost analysis in our New Mexico FIP, and a number of others that we did not 

include in our New Mexico FIP. We have re-reviewed/reviewed the information Ms. Stamper 

presents and conclude that, as we did in our New Mexico FIP, that it supports a 30 Boiler 

Operating Day (BOD) NOX average of 0.05 lbs/MMBtu for a SCR installation at the White Bluff 

facility. We disagree with Ms. Stamper that it supports a 30 BOD average of 0.04 lbs/MMBtu, 

as she contends. We see no evidence of an SCR operating at that level for extended periods of 

time, such that we would feel comfortable that a 30 BOD average of 0.04 lbs/MMBtu would be 

sustainable at the White Bluff facility absent site-specific engineering information. 

Although in our proposal we made corrections to Entergy’s NOX BART cost analyses, we did 

not criticize its choice of a SCR NOX emission limit of 0.055 lbs/MMBtu. Entergy’s SCR NOX

emission rate of 0.055 lbs/MMBtu was based on “permitted emission compliance”560 which for 

this type of rate is generally based on 30 day calendar compliance period. Entergy confirms this 

on page 6-3 of its BART analysis.561 Our New Mexico FIP decision to which Ms. Stamper cites, 

is based on a 30 BOD compliance period. As we discuss in our New Mexico FIP, “[Use of a] 

BOD would ensure that, when an outage occurs, the emissions following startup will be averaged 

with the emissions data from before the outage, rather than with the period of time during which 

the unit did not have any emissions at all because it was offline.”562 In other words, a 30 BOD 

averaging period is in effect less stringent than a straight 30 calendar averaging period because it 

does not overweigh emissions spikes as a 30 calendar day average can do during an extended 

outage. As a consequence, we considered Entergy’s 0.055 lb/MMBtu average to be essentially 

equivalent to, or potentially more stringent than the 0.05 lb/MMBtu 30 BOD average we 

required in our New Mexico FIP, which forms the bulk of Ms. Stamper’s support. Thus we (1) 

disagree with Ms. Stamper that SCR for White Bluff should be evaluated on the basis of a NOX

rate of 0.04 lbs/MMBtu, and (2) we believe Entergy’s use of a 30 day calendar NOX rate of 0.055 

in its evaluation of SCR was reasonable (although as discussed elsewhere, we had other issues 

with Entergy’s White Bluff BART analyses). 

Ms. Stamper goes on to incorporate her adjusted NOX baseline and a NOX emission rate of 0.4 

lbs/MMBtu into a revised SCR cost analysis, using the IPM SCR Cost algorithms. Due to the 

issues we discuss above concerning her revised baseline and NOX emission rate, and the 

significant impact these two inputs have to such an analysis, we cannot agree that her revised 

SCR cost estimate is more representative of the cost of installing SCR at the White Bluff facility. 

Ms. Stamper ends her critique of our SCR cost analysis by arguing that SCR + combustion 

controls in the range of $2,000 to $4,500/ton have been found to be reasonable by us in other 

situations. That statement is true, and our SCR cost-effectiveness calculations for the White 

Bluff facility fall within that range. However, we note that the mere fact that the costeffectiveness of a control (the familiar $/ton calculation) falls within a range that we have 

previously found to be acceptable is not the sole determinant we rely upon when either 

approving a state’s BART determination or in finalizing BART in a FIP. As required by the 

CAA and reflected in Section 51.308(e)(1)(ii)(A), visibility improvement is also one of the five 

 

560 See page 8 of Appendix E (the Sargent & Lundy NOx control cost study for Entergy) to the White Bluff Plant 

Revised BART Five-Factor Analysis, dated 10/14/13. 

561 Id. “this rate includes consideration of normal fluctuations which may occur over a 30-day compliance period.” 562 76 FR 52402. 
293

required factors. In other words, the other BART factors aside, cost must balance visibility 

benefit. In this case, we do not believe that the cost effectiveness of SCR or SNCR fall within a 

range that justifies the relatively small incremental visibility improvement (over our NOX BART 

determination based on LNB/SOFA) that would result from the installation of SNCR or SCR at 

the White Bluff facility. 

We agree with Ms. Stamper that the typical installation timeframe for LNB/SOFA is a shorter 

timeframe than the three years we proposed for the White Bluff facility. As we discuss 

elsewhere in this document, we are finalizing an 18-month compliance date for White Bluff to 

comply with its NOX BART emission limit. We are not requiring SCR controls for White Bluff 

and we discuss this elsewhere in this document. Because we are not requiring that SCRs be 

installed at the White Bluff facility, this comment is moot and we will not further address it. 

Comment: The costs of both a wet and a dry scrubber are reasonable at the two 

Independence units, and EPA’s cost-estimates are actually conservative. [Sierra Club et. al. 

(0171) p. 31-33] Sierra Club et. al., stated that the costs of both a wet and a dry scrubber are 

reasonable at the two Independence units. This along with consideration of the other reasonable 

progress factors supports EPA’s requirement of the installation of scrubbers for Independence 

under the reasonable progress requirements. EPA largely relied on Entergy’s cost calculations to 

conclude that a dry scrubber would cost $2,477 per ton for Unit 1 and $2,286 per ton for Unit 2, 

while a wet scrubber would cost $3,706 per ton for Unit 1 and $3,416 per ton for Unit 2. 80 Fed. 

Reg. at 18,993. All of these costs are within the range of costs that EPA has found reasonable in 

other reasonable progress determinations. See, below; Stamper Report at 60-62. 

Moreover, Ms. Stamper independently calculated the costs of scrubbers at Independence Units 1 

and 2, and her calculations confirm that a scrubber is cost-effective. See Stamper Report at 60-

62. Ms. Stamper used the Sargent & Lundy IPM cost modules for wet and dry scrubbers. She 

concluded that EPA’s cost-effectiveness estimates are conservative, given that a wet scrubber 

has a cost-effectiveness of $2,657 per ton for Unit 1 and $2,540 per ton for Unit 2. Id. at 61. 

Additionally, Ms. Stamper noted that EPA should have evaluated a NID circulating dry scrubber, 

which has a higher removal efficiency than traditional dry scrubbers for the same cost. Ms. 

Stamper calculated that a NID scrubber would cost $2,816 per ton for Unit 1 and $2,676 per ton 

for Unit 2. Id. The costs that Ms. Stamper calculated for dry and wet scrubbers are reasonable 

costs in light of other reasonable progress determinations. See pages 11-12, above (citing 

Stamper Report) and, below. As discussed in the Stamper Report, id. at 4-9, these cost-effective 

controls can achieve a SO2 emissions rate of 0.04 lb/MMBtu, which is lower than the 0.06 

lb/MMBtu rate that EPA assumed could be achieved with a scrubber. 

This significant visibility improvement from a scrubber at Independence Units 1 and 2 would 

equal or exceed the visibility improvement from other reasonable progress controls EPA has 

approved. For example, EPA approved as reasonable progress measures Wyoming’s decision to 

require SCR at the Jim Bridger units after finding that the costs would range from $2,258 to 

$2,961 per ton of NOx removed and the visibility improvement would range from 0.26 to 0.45 

deciviews at the most impacted area. See 79 Fed. Reg. 5,032, 5,040-41 (Jan. 30, 2014). EPA 

approved dry FGD controls as reasonable progress measures at the Colorado Springs Nixon 
294

plant, after finding that the controls would cost $3,744 per ton of SO2 removed (which is more 

than FGD would cost at Independence) and would improve visibility by 0.46 deciviews at the 

most impacted area (which is less improvement than a scrubber at Independence would achieve). 

See 77 Fed. Reg. 18,052, 18,082 (Mar. 26, 2012), finalized by 77 Fed. Reg. 76,871 (Dec. 31, 

2012). In addition, EPA’s proposed reasonable progress determination for the Tolk units in 

Texas would require scrubbers that have cost-effectiveness values of $3,178 per ton and $2,998 

per ton, see 79 Fed. Reg. at 74,876; scrubbers would cost less per ton of SO2 removed at the 

Independence units than at the Tolk units. Moreover, the visibility improvement from a scrubber 

at the Independence units exceeds the visibility improvement from the scrubbers EPA is 

proposing for the Tolk units. See 79 Fed. Reg. at 74,882 (scrubbers at both Tolk units would 

result in a combined improvement of 0.188 deciviews at Guadalupe Mountains, the most 

impacted area). 

Cost-Effectiveness of Final Reasonable Progress Determinations563

Facility Reasonable Progress 

Control Cost, $/ton 

Hawaii Electric Co., Kanoelehua Power Plant SO2 emissions cap564 5,587

Hawaii Electric Co., Puna Power Plant SO2 emissions cap 5,583

Hawaii Electric Co., Shipman Power Plant SO2 emissions cap 5,583

Tri-State Generation, Craig Unit 3 SNCR 4,887

Colorado Springs Utilities, Nixon Unit1 Dry FGD 3,744

PacifiCorp Jim Bridger Unit 2 SCR 3,015

PacifiCorp Jim Bridger Unit 3 SCR 2,961

PacifiCorp Jim Bridger, Unit 4 SCR 2,492

PacifiCorp Jim Bridger, Unit 1 SCR 2,393

Holcim Florence Cement Plant SNCR 2,293

Colorado Springs Utilities, Nixon Unit 1 ULNB/OFA 1,372

Phoenix Cement, Clarkdale Kiln 4 SNCR 1,142

Rillito Cement Kiln 4 SNCR 1,047

Basin Electric, Antelope Valley Unit 2 LNB 661

Montana Dakota Utilities, Heskett Station Limestone Injection 651

Platte River Power Authority, Rawhide Unit 

101 ECC 644

Basin Electric, Antelope Valley Unit 1 LNB 586

Devon Energy Blaine County #1 Compressor NSCR 282

 

563 Sources for the table are as follows: partial FIP for Arizona, 79 Fed. Reg. 9,318, 9,354-56 (Feb. 18, 2104) and 79 

Fed. Reg. 52,420 (Sept. 3, 2014); approval of Colorado’s SIP, 77 Fed. Reg. 18,052, 18,082, 18,084, 18,087 (Mar. 

26, 2012) and 77 Fed. Reg. 76,871 (Dec. 31, 2012); FIP for Hawaii, 77 Fed. Reg. 31,691, 31,711 (May 29, 2012) 

and 77 Fed. Reg. 61,478, 61,506 (Oct. 9, 2012); FIP for Montana. 77 Fed. Reg. 23,988, 24,069 (Apr. 20, 2012) and 

77 Fed. Reg. 57,864 (Sept. 18, 2012); partial SIP approval and partial FIP for North Dakota, 76 Fed. Reg. 58,570, 

58,626, 58,630-32 (Sept. 21, 2011) and 77 Fed. Reg. 20,894, 20,897 (Apr. 6, 2012); FIP for Wyoming, 78 Fed. Reg. 

34,738, 34,754-56, 34,757-78 (June 10, 2013) and 79 Fed. Reg. 5,032 (Jan. 30, 2014). 

564 “This cap [the SO2 emissions cap] was derived from EPA’s analysis of the costs of switching these units to 1% 

sulfur fuel.” Therefore, the cost-effectiveness for the three Hawaii plants represents the cost to meet the SO2 cap by 

switching to low-sulfur fuel. 
295

Response: We have reviewed the section of the Stamper report that treats this issue in more 

detail and respond to both it and this comment here. We take no position on the separate cost 

analysis that Ms. Stamper has conducted for dry and wet scrubbers that she uses to conclude that 

our cost analyses are reasonable. We agree with the Sierra Club that a reasonable progress 

determination based on a positive assessment of the cost-effectiveness alongside consideration of 

the visibility benefit of dry scrubbers at the Independence facility was proper.565 Ms. Stamper 

incorporates her comments concerning our White Bluff scrubber cost analyses, that we should 

have required that scrubbers be installed in three years, and further notes that the Independence 

facility will benefit from coordinated and shared engineering design and FGD fabrication, 

economies of scale benefits with FGD suppliers, and more consistent staffing levels with on-site 

contractors for concurrent FGD installations. We refer Ms. Stamper to our general response to 

her similar comment regarding the White Bluff facility. We add that certain economies of scale 

may well present opportunities for a quicker installation of scrubbers at the Independence 

facility. However, we have no way to quantify to what extent that may be the case. We 

therefore stay with our five year installation requirement. 

Ms. Stamper emphasizes that there will be no significant energy and non-air quality impacts of 

these controls, stating that auxiliary power requirements were included with the costs of controls 

and thus this non-air quality issue is reflected in the cost effectiveness numbers. Further, she 

notes that these SO2 controls are commonly utilized, and thus it is not expected that there would 

be any adverse energy or non-air quality impacts that would justify excluding any of these 

controls from being adopted as a reasonable progress measure. We agree with these statements. 

Ms. Stamper states that we should have required a SO2 control level of 0.04 lbs/MMBtu in our 

reasonable progress determination for the Independence facility, citing to the ability of wet 

scrubbing and NID scrubbing to meet that level. We take no position on the separate cost 

analysis that Ms. Stamper has conducted for dry and wet scrubbers that she uses to conclude that 

our cost analyses are reasonable. We agree with the Sierra Club that a reasonable progress 

determination based on a positive assessment of the cost-effectiveness alongside consideration of 

the visibility benefit of dry scrubbers at the Independence facility was proper.566 

We disagree with the Sierra Club, as we have discussed in our response to the previous 

comment, that for the purposes of determining reasonable progress, the cost-effectiveness of a 

control falling into a range we have previously found acceptable obviates the need to consider 

the visibility of that control. As we have discussed in our responses to other comments, we 

disagree that in this instance the cost of wet scrubbers was reasonable, in light of their higher 

cost and the relatively low additional improvement in visibility over dry scrubbers. Although 

visibility is not one of the four mandatory factors explicitly listed for consideration under CAA 

section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), states or EPA have the option of considering 

 

565 Although visibility is not one of the four mandatory factors explicitly listed for consideration under CAA section 

169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), states or EPA have the option of considering the projected visibility 

benefits of controls in determining if the controls are necessary to make reasonable progress. 566 Although visibility is not one of the four mandatory factors explicitly listed for consideration under CAA section 

169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), states or EPA have the option of considering the projected visibility 

benefits of controls in determining if the controls are necessary to make reasonable progress. 
296

the projected visibility benefits of controls in determining if the controls are necessary to make 

reasonable progress. Therefore, in our reasonable progress analysis for Independence, we 

considered the visibility benefits of controls alongside the four statutory factors, and we discuss 

this in more detail elsewhere in this document. Lastly, as we have discussed in our response to 

another comment, we disagree that we should have considered NID in our reasonable progress of 

the Independence facility. 

Comment: EPA should have evaluated SNCR and SCR for the Independence facility. 

[Stamper Report]. Ms. Stamper stated that because the Independence facility is “potentially one 

of the largest single contributors to visibility impairment at Class I areas in Arkansas,” EPA 

found it was appropriate to evaluate NOx controls for reasonable progress measures. 80 Fed. 

Reg. at 18,995. Due to the similarity between Independence Units 1 and 2 and White Bluff Units 

1 and 2, EPA applied the same costs for low NOx burners/SOFA that were developed for the 

White Bluff units, but determined cost effectiveness of these controls based on the NOx 

emissions reductions that would occur at the Independence units. Id. 

However, EPA did not evaluate SNCR or SCR at Independence Units 1 and 2. EPA’s reasoning 

was that, since they did not find the visibility benefits of SCR or SNCR at White Bluff Units 1 

and 2 to be worth the additional costs of these controls, the visibility benefits of such postcombustion controls at Independence Units 1 and 2 would not be worth the additional costs 

either. Id. 

However, SCR along with low NOx burners/SOFA can meet lower NOx emission rates than 

evaluated by Entergy and EPA, thus providing greater visibility benefits than modeled by 

Entergy for White Bluff, and such controls were cost effective. Thus, EPA should have 

evaluated low NOx burners/SOFA + SCR as reasonable progress measures for the Independence 

units. Ms. Stamper presents her own cost analyses for LNB/SOFA/SCR. 

Response: We have reviewed the section of the Stamper report that treats this issue in more 

detail and respond to both it and this comment here. First, there is no requirement in the 

Regional Haze Rule that all possible controls be analyzed conducting a reasonable progress 

analysis of a source. As we discussed in our proposal,567 our modeling indicated that the 

cumulative visibility improvement of LNB/SOFA at the Independence facility was less than at 

the White Bluff facility: 

Class I Area 

Visibility 

improvement of 

LNB/SOFA at 

Independence over 

baseline 

(deciviews) 

Visibility 

improvement of 

LNB/SOFA at White 

Bluff over baseline 

(deciviews) 

Caney Creek 0.459 0.391

 

567 See our supplemental NOx modeling results for the Independence facility in 80 FR 24872 vs. our NOx modeling 

results for the White Bluff facility in 80 FR 18974. 
297

Upper Buffalo 0.198 0.240

Hercules-Glades 0.173 0.366

Mingo 0.148 0.085

Cumulative 0.978 1.082

As can be seen from the above comparison, the visibility improvement due to the installation of 

LNB/SOFA at the Independence facility is of a similar magnitude to that of the White Bluff 

facility. We reasoned that because (1) the Independence and White Bluff facilities were sister 

facilities and very similar, and (2) we found that the incremental costs of SNCR and SCR for 

White Bluff were not worth the resulting incremental visibility improvement,568 we had no 

reason not to conclude the same for the Independence facility.569 We therefore disagree with Ms. 

Stamper that the incremental visibility benefits due to the installation of SNCR or SCR at the 

Independence facility justify the additional cost of those controls. We discuss in a separate 

response to comment the issues we identified with Ms. Stamper’s cost analysis for SCR for 

White Bluff, and we find that the same issues we identified there apply to her cost analysis of 

SCR for Independence. We do agree with Ms. Stamper’s support for Option 1—requiring 

reductions corresponding to both dry SO2 scrubbers and LNB/SOFA. 

Comment: EPA’s determination that SO2 BART for AEP Flint Creek is a Novel Integrated 

Desulfurization (NID) dry scrubber is appropriate, but that control technology is even 

more cost-effective than what AEP and EPA have estimated. [Sierra Club et. al. (0171) p. 9-

12] Sierra Club et. al. stated that EPA must base BART determinations on an analysis of the five 

statutory BART factors: (1) the costs of compliance, (2) the energy and non-air quality 

environmental impacts of compliance, (3) existing pollution controls in use at the source, (4) the 

remaining useful life of the source, and (5) the degree of visibility improvement. 42 U.S.C. 

§7491(g)(2); 40 C.F.R. §51.308(e)(1)(ii)(A). 

Sierra Club et. al. stated that EPA has proposed to determine that BART for SO2 at Flint Creek 

Unit 1 is an emission limit of 0.06 lb/MMBtu on a 30-day rolling average based on the operation 

of a Novel Integrated Desulfurization (“NID”) dry scrubber. 80 Fed. Reg. at 18,966. We strongly 

support EPA’s proposal to require the installation of a NID scrubber at Flint Creek and to set a 

limit on SO2 emissions. AEP’s evaluation, which EPA relied on in its proposal, shows that a NID 

scrubber is cost effective, would produce significant visibility improvements at the affected 

Class I areas, and readily satisfies the other BART requirements. See 80 Fed. Reg. 18,966-67; 

Stamper Report, at 3-14. EPA’s proposed FIP represents a minimum floor for SO2 BART 

compliance and any less effective controls would not comply with BART. 

 

568 See the section of this RTC document where we discuss visibility issues for a more detailed discussion of the 

incremental visibility improvement of SCR controls. 

569 We discuss elsewhere throughout this RTC document that it is appropriate for us to consider visibility alongside 

the four statutory factors in a reasonable progress analysis. 
298

EPA estimated that a NID scrubber would have an average cost-effectiveness of $3,845 per ton 

of SO2 removed. See 80 Fed. Reg. 18,966-67. The attached Stamper Report confirms EPA’s 

conclusion that the controls proposed in the FIP are cost-effective. Ms. Stamper conducted her 

own analyses of the proposed controls and concludes that the proposed controls are even more 

cost-effective than EPA assumed, can readily achieve even lower emission rates than EPA 

assumed, and cost a reasonable amount compared to costs borne by sources in other states. The 

Stamper Report discusses several ways in which EPA and AEP used very conservative 

assumptions that inflated the cost of the controls 

AEP escalated costs to 2016 dollars, which is inconsistent with the EPA’s Control Cost Manual. 

Stamper Report at 4 (citing 80 Fed. Reg. at 18,965). Despite acknowledging AEP’s inappropriate 

cost escalation, EPA did not correct the estimate to reflect present dollars. Id. Ms. Stamper’s 

cost-effectiveness figures (presented below) rely on present dollars. Furthermore, as discussed 

elsewhere in Sierra Club et. al.’s comments, a NID scrubber can achieve a lower emission rate 

than assumed by AEP, so Ms. Stamper’s cost-effectiveness analysis assumes the lower emission 

limit (0.04 lb/MMBtu). 

To provide a cost estimate for the wet scrubbers and NID dry scrubber that is based on present 

dollars and reflects the emission rates achievable with a NID scrubber, Ms. Stamper revised 

AEP’s cost analyses using EPA’s SO2 control cost spreadsheets that it recently used in the Texas 

regional haze rulemaking. Stamper Report at 9-11. These cost spreadsheets are based on Sargent 

& Lundy cost modules for wet and dry scrubbers. Based on Ms. Stamper’s revised costeffectiveness estimates, both a wet scrubber and a NID dry scrubber are highly cost-effective as 

SO2 BART for Flint Creek: 

Revised SO2 Control Cost-Effectiveness Evaluation for Flint Creek Unit 1570

Flint Creek 

Unit 1 SO2 Control 

Total 

Annualized 

Costs 

Tons SO2

Removed 

CostEffectiveness AEP’s CostEffectiveness571

1 Wet FGD $27,189,756 10,866 tpy $2,498/ton $4,919/ton 

1 NIDTM CDS $26,183,791 10,886 tpy $2,405/ton $3,845/ton 

As the above table demonstrates, the costs for both wet and NID scrubbers are significantly 

lower than AEP’s cost estimates and the technologies are equally cost effective. Moreover, wet 

and NID scrubbers can achieve an emission rate of 0.04 lb/MMBtu, which is lower than EPA 

assumed in its proposed BART determination. 

EPA’s conservative cost-effectiveness calculations and Ms. Stamper’s revised cost-effectiveness 

calculations both demonstrate that it was reasonable to establish an SO2 BART emission limit 

based on installation of scrubbers, as shown by SO2 control determinations in other regional haze 

plans. Stamper Report at 12-13. As discussed in the Stamper Report, data compiled by the 

National Park Service on state SO2 BART determinations show that the costs of SO2 controls to 

 

570 Stamper Report at 11. 571 80 Fed. Reg. 18966, Table 26. 
299

meet BART at EGUs range from $1,571 to $7,309 per ton of SO2 removed.572 Wyoming, for 

example, found that a new dry scrubber and baghouse at Dave Johnston Unit 4 was cost effective 

at $5,028 per ton of SO2 removed.573 EPA proposed a FIP of reasonable progress measures based 

on switching to a lower sulfur fuel oil at the fuel oil-fired boilers at the Kanoelehua Hill Power 

Plant, the Puna Power Plant, and the Shipman Power Plant at a cost-effectiveness of 

approximately $5,600 per ton.574 Colorado based its SO2 BART determination for Martin Drake 

Units 6 and 7 on installation of dry scrubbers at a cost effectiveness of $2,808/ton and 

$2,345/ton, respectively.575 In EPA’s recently proposed FIP for Texas, EPA has proposed to find 

that scrubber retrofits are cost effective at costs ranging from $1,255/ton to $3,500/ton of SO2 

removed.576 EPA approved installation of a dry FGD at the Colorado Springs Nixon Unit 1 as a 

reasonable progress measure at a cost effective of $3,744/ton.577 Wyoming also found that the 

costs of SO2 retrofit controls at Naughton Units 1 and 2 were cost effective at $1,622 to 

$2,654/ton.578,579

Ms. Stamper’s revised cost-effectiveness calculations of $2,498 (wet scrubber) and $2,405 (NID 

scrubber) per ton of SO2 removed for Flint Creek are comparable to, or lower than, the costeffectiveness of each of the referenced approved controls. Stamper Report at 12-13. Thus, either 

a wet scrubber or a NID dry scrubber can meet an SO2 BART limit of 0.04 lb/MMBtu and is cost 

effective for Flint Creek. See 42 U.S.C. § 7491(g)(2) (requiring consideration of the costs of 

compliance and degree of visibility improvement). 

Response: We have reviewed the section of the Stamper report that treats this issue in more 

detail and respond to both it and this comment here. We agree with the Sierra Club that we must 

base BART determinations (and judge those submitted to us by states) on the five statutory 

BART factors it cites. 

We also confirm that the NID cost analysis we employed was largely derived from AEP’s own 

cost analysis. As we discuss in our TSD,580 we noted a number of issues with AEP’s NID and 

wet scrubber cost analyses that if corrected would have resulted in more favorable (lower $/ton) 

 

572 Stamper Report at 12 (citing March 2011 National Park Service spreadsheet “EGUs with Proposed BART 

Controls.” (Ex. 27 to Stamper Report)). 

573 See Stamper Report at 13 (citing May 28, 2009 Wyoming Department of Environmental Quality BART 

Application Analysis, Dave Johnston Plant, at 23 (Ex. 28 to Stamper Report)). 

574 77 Fed. Reg. 61,478, 61,490 (Oct. 9, 2012); see also 77 Fed. Reg. 31,692, 31,711-2 (May 29, 2012). 575 77 Fed. Reg. 18051, 18,070-1 (Mar. 26, 2012). 576 See 79 Fed. Reg. 74,818 (Dec. 16, 2014). 577 77 Fed. Reg. at 18,082. 578 See Stamper Report at 12 (citing May 28, 2009 Wyoming Department of Environmental Quality BART 

Application Analysis, Naughton Plant, at 26-28 (Ex. 26 to Stamper Report)). 

579 Even AEP’s unrevised cost estimates are reasonable compared to the costs other similar sources have had to bear 

to comply with regional haze requirements. 580 See page 65 of our TSD: “[W]e believe that AEP’s escalation of the cost of controls to 2016 dollars has likely 

resulted in the over estimation of the average cost-effectiveness values. Therefore, we believe a wet scrubber and 

NID are more cost-effective (i.e., less dollars per ton of SO2 removed) than estimated by AEP (see table above). 

However, we did not adjust the cost numbers and cost-effectiveness values because we do not believe that doing so 

would change our proposed BART determination. We believe that the average cost-effectiveness of both control 

options was likely over-estimated and the costs associated with a wet scrubber would continue to be higher than the 

costs associated with NID if the estimates were adjusted, yet the installation and operation of a wet scrubber is 

projected to result in minimal incremental visibility improvement over NID. 
300

cost-effectiveness values. Nevertheless, even disregarding those errors, we concluded that NID 

was cost-effective and worth the visibility benefit that will result from its installation. We also 

concluded that Ms. Stamper presents her own cost analyses for wet and NID scrubbing, based on 

the IPM cost algorithms we used in our recent Texas-Oklahoma FIP. In so doing, she applies the 

SDA cost algorithm to NID, citing to documentation that indicates that NID may be 1-2% lower 

in cost to an SDA system. Ms. Stamper concludes that AEP’s wet FGD and NID cost analyses 

(largely accepted by us) employed overly conservative inputs and are likely high. In instances in 

which NID cost information is totally lacking, it may be reasonable to rely on the SDA IPM cost 

algorithms as a substitute for NID cost analysis. However, in this case, we do not believe that 

enough information has been presented by Ms. Stamper for us to conclude that her reliance on 

SDA costing as a substitute for NID should supplant AEP’s more site-specific cost analysis. We 

also determined that wet scrubbing would remain less cost-effective than NID, and that the 

incremental visibility benefit of wet scrubbers over NID at each impacted Class I area is very 

small (ranging from 0.007 dv to 0.014 dv).581 We therefore concluded that wet scrubbing was not 

worth the small additional visibility that would result from its installation in this particular 

instance. 

As we have discussed above, we do not believe that cost-effectiveness comparisons ($/ton) to 

other decisions can be effectively made absent consideration of the other statutory factors. 

Visibility is one of the five statutory factors we are required to consider in a BART analysis. In a 

reasonable progress analysis, although visibility is not one of the four mandatory factors 

explicitly listed for consideration under CAA section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), 

states or EPA have the option of considering the projected visibility benefits of controls. In our 

reasonable progress analysis for Independence, we chose to also consider visibility alongside the 

four reasonable progress factors. 

Ms. Stamper argues that both wet and dry scrubbers are capable of even greater levels of control 

than what we assumed. She presents a number of examples of documentation to support her 

conclusion consisting of vendor advertisement summaries, contractor statements, industry 

literature, and some actual monitoring data. Of these, we place the highest priority on the latter – 

actual monitoring data that demonstrates that on similar units burning similar coals the control 

technology is capable of the level of control we are requiring. We believe it is important in 

making such an analysis to focus on the level of control, rather than on just the emission limit. 

We do not believe emission limits can be compared across units, unless similarity can be 

demonstrated, including the sulfur content of the coal being burned. We extensively analyzed 

the performance potential of wet scrubbers in our recent Texas-Oklahoma FIP.582 We accounted 

for the many factors that could influence wet scrubber performance, including principally, the 

type of coal burned and the sulfur level in that coal. We concluded that a control level of 98%, 

not to go below an emission rate of 0.04 lbs/MMBtu on a 30 BOD average, was a reasonable 

lower level of control. This same reasoning was applied to our Arkansas proposal. None of the 

information presented by Ms. Stamper causes us to conclude that reasoning is in error. As we 

 

581 80 FR at 18966. 582 See response to comment beginning on page 310 of our Response to Comments for the Federal Register Notice 

for the Texas and Oklahoma Regional Haze State Implementation Plans; Interstate Visibility Transport State 

Implementation Plan to Address Pollution Affecting Visibility and Regional Haze; and Federal Implementation Plan 

for Regional Haze, Docket No. EPA-R06-OAR-2014-0754, 12/9/2015. 
301

discuss in our response to another comment, although we regard NID as a promising technology 

that may in fact be capable of greater levels of control than what we have assumed, there is no 

real long-term monitoring data to substantiate such a conclusion. Therefore, because we have 

concluded that in this instance the cost-effectiveness of wet scrubbers is not justified by their 

relatively small additional visibility benefit, we disagree that SO2 BART for Flint Creek Unit 1 

should be 0.04, based on the performance of a wet scrubber. We agree with Ms. Stamper that the 

emission rate proposed for the Flint Creek Unit 1 can be achieved by SDA, NID, or wet FGD, 

and depending on the technology used, that emission rate may not represent the greatest 

achievable level of control. We are, however, confident that we have correctly determined 

BART for this facility, based on the five BART statutory factors and the data that is available to 

us. 

Ms. Stamper also makes a number of observations regarding our cost analyses. We agree with 

her that an equipment life of 30 years is appropriate for a scrubber cost analysis. We also agree 

that our use of a 7% interest rate may be higher than the actual cost that AEP may incur in 

financing the cost of a scrubber system that were we to adopt a lower interest rate, the cost 

effectiveness of our proposed controls would become much more attractive (lower $/ton). For 

cost analyses related to government regulations, an appropriate ‘‘social’’ interest (discount) rate 

should be used, not the source’s actual rate of borrowing. OMB Circular A–4, providing Federal 

agencies guidance on developing regulatory analyses, and dated September 17, 2003,583

reiterates the guidance found in the earlier Circular A–94:584

As a default position, OMB Circular A–94 states that a real discount rate of 7 

percent should be used as a base-case for regulatory analysis. The 7 percent rate 

is an estimate of the average before-tax rate of return to private capital in the U.S. 

economy, based on historical data. It is a broad measure that reflects the returns 

to real estate and small business capital as well as corporate capital. It 

approximates the opportunity cost of capital, and it is the appropriate discount rate 

whenever the main effect of a regulation is to displace or alter the use of capital in 

the private sector. 

The yearly updates to OMB Circular A-94 to which the commenter references, are to Appendix 

C. However, as the letter that transmits these yearly updates explains:585 “The rates presented in 

Appendix C do not apply to regulatory analysis or benefit-cost analysis of public investment. 

They are to be used for lease-purchase and cost-effectiveness analysis, as specified in the 

Circular.” Note that the reference to “cost-effectiveness analysis” here does not refer to that used 

in the regional haze program, but rather to the analysis of programs requiring the expenditure of 

federal funds. 

Ms. Stamper also argues that because it appears that construction has already begun on the Flint 

Creek NID system, and AEP will be using it to comply with our MATS Rule, we should truncate 

the 5 years we have proposed for compliance to May, 2016, which by the publication of this rule, 

will already have passed. As discussed elsewhere in this document, we were unaware at the time 

 

583 https://www.whitehouse.gov/sites/default/files/omb/assets/omb/circulars/a004/a-4.pdf 584 https://www.whitehouse.gov/sites/default/files/omb/assets/a94/a094.pdf 585 https://www.whitehouse.gov/sites/default/files/omb/memoranda/2015/m-15-05.pdf 
302

of our proposal that the Flint Creek NID system installation was already underway and 

anticipated by the company to be complete by May 2016. We agree with the commenter that 

BART controls must be installed as expeditiously as practicable. 42 U.S.C. § 7491(b)(2)(A). 

After carefully considering the information the commenter has brought to our attention, we 

believe that a five year compliance date is not appropriate for the SO2 BART controls we are 

requiring for Flint Creek. Therefore, based on the information that was made available to us 

during the comment period, we are finalizing a shorter compliance date. As discussed in more 

detail in a separate response, we are finalizing an 18-month compliance date for the SO2 BART 

emission limit for Flint Creek Unit 1. 

Comment: Control scenarios that include SCR and SNCR are both cost-effective as NOX

BART for Flint Creek Unit 1. [Sierra Club et. al. (0171) p. 17-18] Sierra Club et. al. stated that 

for NOX, EPA has proposed to determine that BART for Flint Creek is an emission limit of 0.23 

lb/MMBtu on a 30-day rolling average based on the operation of new low- NOX burners 

(“LNB”)/over-fired air (“OFA”). 80 Fed. Reg. 18968. EPA estimated that LNB/OFA would have 

an average cost-effectiveness of $1,761 per ton of NOX removed. EPA’s proposal to require 

LNB/OFA represents a cost-effective way to achieve some NOX emission reductions at Flint 

Creek and, therefore, is the absolute minimum that EPA must require as selection of anything 

less stringent would be arbitrary, capricious, and contrary to law. The LNB/OFA proposal, 

however, does not satisfy BART, which requires “the application of the best system of 

continuous emission reduction.” Such best system is an SCR, which Ms. Stamper explains in her 

report is far more cost-effective than EPA calculated, would achieve lower emission rates and 

greater visibility benefits, and satisfies all of the BART standards. As such, we urge EPA to find 

that NOX BART for the Flint Creek plant is an emission rate of 0.04 lb/MMBtu based on the 

installation of an SCR. 

Sierra Club et. al. stated that the Stamper Report discusses several ways in which EPA and AEP 

used very conservative assumptions that inflated the cost of the SCRs and SNCRs as NOX BART 

options for Flint Creek. Ms. Stamper’s analysis shows that these controls are even more costeffective than EPA calculated. 

AEP overestimated the costs of LNB/OFA plus SNCR at Flint Creek. AEP amortized the SNCR 

over a 20 year life rather than the 30 year life assumed for all other controls. By amortizing the 

SNCR over a shorter time period, AEP’s annualized costs for SNCR are overstated and must be 

revised. Stamper Report at 14, 16. Ms. Stamper’s revised cost-effectiveness estimates (provided 

below) use a 30-year life. 

To more properly evaluate the cost effectiveness of LNB/OFA plus SCR and LNB/OFA plus 

SNCR at Flint Creek, Ms. Stamper has provided revised cost-effectiveness analysis of these 

controls using the Sargent & Lundy SCR Cost Module. As noted by Ms. Stamper, EPA has 

relied on the Sargent & Lundy module to estimate SCR costs in its evaluation of NOX BART for 

rulemakings in other states. Stamper Report at 22-23. Using the Sargent & Lundy modules, Ms. 

Stamper calculated revised cost effectiveness for LNB/OFA plus SCR at Flint Creek. This 

revised cost-effectiveness analysis assumes that LNB/OFA plus SCR at Flint Creek can achieve 

a 0.04 lb/MMBtu emission limit on a 30-day average basis. 
303

Revised NOx Control Cost-Effectiveness Evaluation for Flint Creek Unit 1586

NOX 

Control

Total 

Annualized 

Costs

Tons NOX

Removed

Cost 

Effectiveness

AEP’s Cost 

Effectiveness587

Incremental Cost 

Effectiveness 

Relative to 

LNB/OFA/SNCR

LNB/OFA $1,454,621 956 tpy $1,521/ton $1,761/ton 

SNCR plus LNB/OFA $4,177,782 1,518 tpy $2,752/ton $3,099/ton 

LNB/OFA plus SCR 

(Mar 2013 IPM SCR 

Cost Module) 

$15,851,747 4,515 tpy $3,511/ton $3,805/ton $3,895/ton 

LNB/OFA plus SCR 

(Aug 2010 IPM SCR 

Cost Module) 

$13,399,388 4,515 tpy $2,968/ton $3,805/ton $3,077/ton 

As this analysis shows, LNB/OFA plus SCR to meet a NOX limit of 0.04 lb/MMBtu is very cost 

effective (based on either version of the Sargent & Lundy SCR cost module). These NOX 

controls would also remove close to 700 tons per year more NOX than evaluated by AEP. As this 

analysis also shows, LNB/OFA plus SNCR is also very cost effective. 

Moreover, as demonstrated in the Stamper Report, these costs are well within the range of costs 

that EPA has required similar sources to bear to meet BART in other states. EPA has required 

SCR as BART for the Four Corners Units 1 - 5 at a cost effectiveness of $2,515 to $3,163 per ton 

of NOX removed in 2008 dollars,588 or $2,560 to $3,220 per ton in 2011 dollars. Stamper Report 

at 24-25. In its FIP for Montana, EPA found that the cost effectiveness of SCR controls for 

Colstrip Units 1 and 2 of approximately $3,200 per ton (in 2010 dollars), or $3,403 per ton in 

2011 dollars, was reasonable.589 In its Arizona regional haze FIP, EPA required SCR along with 

combustion controls to meet BART at the Apache, Cholla, and Coronado power plants at costeffectiveness values ranging from $2,275 to $3,472 per ton of NOX removed.590 EPA proposed 

SCR as BART at the Leland Olds Unit 1, Milton R. Young Unit 1, and Milton R. 

Young Unit 2 at costs of $1,800/ton, $2,600/ton, and $2,700/ton in 2009 dollars (or $2,020/ton, 

$2,918/ton, and $3,030/ton in 2011 dollars), respectively.591 For the Wyoming regional haze 

plan, EPA found that costs for SCR plus LNB/OFA ranging from $2,635 to $4,461 per ton of 

NOx removed (2008 dollars) are reasonable to require SCR as BART.592 These costs range from 

$2,682 to $4,541 per ton in 2011 dollars. Stamper Report at 25. 

 

586 Stamper Report at 24. 587 80 Fed. Reg. 18,966, Table 28. AEP only evaluated SCR alone, to meet a less stringent NOx limit of 0.07 

lb/MMBtu. See 80 Fed. Reg. at 18,967. 588 See 75 Fed. Reg. 64, 221, 64,227 (Oct. 19, 2010); see also 77 Fed. Reg. 51,619, 51,621-22 (Aug. 24, 2012). 589 See 77 Fed. Reg. 23,987, 24,026-27, 24,034-35 (Apr. 20, 2012). 590 77 Fed. Reg. 42,833, 42,857, 42,860, 42,862 (July 20, 2012). 591 See 76 Fed. Reg. 58,569, 58,599 (Sept. 21, 2011). While EPA did not ultimately require SCR as BART for these 

North Dakota EGUs in its final regional haze action, EPA’s decision was based on whether SCR was technically 

feasible for these lignite-fired units and not based on costs of controls. See 77 Fed. Reg. 20,893, 20,897-98 (Apr. 6, 

2012). 

592 79 Fed. Reg. 5,031, 5,039-43 (Jan. 30, 2014). 
304

In addition, the incremental costs of SCR plus LNB/OFA compared to the next most stringent 

control technology—SNCR plus LNB/SOFA—are also reasonable to justify SCR plus 

LNB/OFA as BART. In past regional haze rulemakings that required SCR plus combustion 

controls on EGUs, EPA did not consider incremental cost-effectiveness numbers ranging from 

$1,903/ton to as high as $8,968/ton to be unreasonable and did not eliminate SCR from 

consideration. Stamper Report at 25. Based on the SCR costs that EPA has deemed reasonable in 

other haze rulemakings, the costs of SCR plus LNB/OFA are reasonable to justify requiring this 

combination of control technologies to meet the NOX BART requirements at Flint Creek. 

Response: We have reviewed the section of the Stamper report that treats this issue in more 

detail and respond to both it and this comment here. We disagree with the Sierra Club’s apparent 

position that BART controls must be selected based on which are the “best system of control,” 

without apparent consideration of the five BART factors: cost, energy and nonair quality 

environmental impacts, pollution controls in use at the source, remaining useful life, and 

visibility improvement.593 

We note that we provided comments to ADEQ594 which included stating that 30 years should be 

used as an equipment life for SNCR. This, was subsequently not adopted by AEP in its 

September 2013 BART analysis for the Flint Creek facility. However, as we discuss in our 

TSD,595 

AEP assumed a 30-year amortization period in the evaluation of LNB/OFA and 

SCR and a 20-year amortization period in the evaluation of SNCR. We disagree 

with AEP’s assumption of a 20-year amortization period in the cost analysis of 

SNCR. Any air pollution controls on the unit are expected to have the same life as 

the boiler. Therefore, we believe it is appropriate to assume a 30-year 

amortization period for SNCR, as was done for SCR and combustion controls. 

Assuming a 30-year amortization period, SNCR would have a lower estimated 

total annual cost and would therefore be more cost-effective (i.e., less dollars per 

ton removed) than estimated in AEP’s evaluation. However, we did not adjust the 

amortization period assumed in AEP’s evaluation because we do not believe this 

has an impact on our proposed BART decision. [T]he incremental visibility 

benefit expected from the installation and operation of SNCR is too small to 

justify the cost of these controls compared to combustion controls alone. 

Therefore, we did not revise the amortization period and the average cost 

effectiveness calculations for SNCR. 

Ms. Stamper also states that AEP overestimated the cost of SNCR because it based it on a 

reduction of from 0.31 lbs/MMBtu to 0.2 lbs/MMBtu, when in fact, the first-in-line LNB/OFA 

controls would have already reduced the NOx to 0.23 lbs/MMBtu, resulting in a lesser loading to 

the SNCR system and reducing its operating costs. We agree with Ms. Stamper on this point. 

We have corrected this error, and the error in AEP SWEPCO’s 20 year equipment life. The 

 

593 Summarized from Section 51.308(e)(1)(ii)(A). 594 See email from Dayana Medina to Mary Pettyjohn on 8/21/13. 595 See discussion beginning on page 68. 
305

following table provides AEP SWEPCO’s SNCR cost analysis with another column added to 

include these corrections: 
306

Parameters/Costs Equation AEP SWEPBoiler design capacity, mmBtu/hr (QB) QB 6Total operating time (top, hrs/yr) top = CFtotal × 8760 hrs/yr 7Total Capacity Factor (CFtotal) CFtotal = CFplant × CFSNCR Plant Capacity Factor (CFplant)2 SNCR Capacity Factor (CFSCNR)3 CFSNCR = tSNCR/365 Assumed NOx removal efficiency (ηNOx)4 Uncontrolled NOx rate (NOxin, lb/MMBtu)5 Electricity Cost (Costelect, $/kwh)6 $Water Cost (Costwater, $/gal)7 $0.00Coal Cost (Costcoal, $/MMBtu)8 $Coal HHV (Btu/lb)9 9Cost of Ash Disposal (Cash, $/ton)10 Capital recovery factor (CRF) CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, 

a = equipment life 

0.0

 a. Equipment CRF, 20-yr life, 7% interest Cost Index11a. 2011 Cost Index 585 b. 1998 Cost Index 389.5 Capital Costs Direct Capital Cost (A) DC ($) = ($950/MMBtu) × QB × ((2375 

MMBtu/hr/QB)^0.577) × (0.66 + 0.85ηNOx) × 

(CI2011/CI1998) 

$5,007

Indirect Installation Costs ($) General Facilities 0.05 × A $250Engineering and Home Office Fees 0.10 × A $500Process Contingency 0.05 × A $250Total Indirect Installation Costs (B) = General Facilities Cost + Engineering and Home Office 

Fees + Process Contingency 

$1,001

Other Installation Costs ($) Project Contingency (C) C = 0.15 × (A + B) $901Total Plant Cost (D) D = A + B + C $6,909
307

Allowance for Funds During Construction (E) E = 0 (Assumed for SNCR) Royalty Allowance (F) F = 0 (Assumed for SNCR) Preproduction Cost (G) G = 0.02 × (D + E) $138Inventory Capital (H)12 H = Volreagent (gal) × Costreagent ($/gal) $76Costreag, 50% Urea solution ($/gal)13 Volume of Reagent Tank (Volreagent (gal)) Volreagent (gal) = qsol x days of reagent supply × 24 hr/day 49Urea solution volumetric flow rate (qsol, gal/hr)14 qsol = (msol x 7.481 gal/ft3)/ρreagent 14Mass flow rate of urea solution (msol, lb/hr)15 msol = mreagent/Cureasol 1,39Mass flow rate of reagent (mreagent, lb/hr)16 mreagent = (NOxin x QB x ηNOx × NSR x Mreagent)/(MNOx x 

SRT) 

69

Normalized Stoichiometric Ratio (NSR) NSR = ([2 × NOxin + 0.7] × ηNOx)/NOxin Initial Catalyst and Chemicals (I) I = 0 (Assumed for SNCR due to no catalyst) Total Capital Investment (TCI) (Capital Cost) TCI = D + E + F + G + H + I $7,124Annual Costs ($) Annual Maintenance Cost (J) J = 0.015 × TCI $106Annual Reagent Cost (K) K = qsol × Costreag × top $1,755Annual Electricity Cost (L) L = P × Costelect × top $58Power (P, kW) P = (0.47 × NOxin × NSR × QB)/9.5 14Annual Water Cost (M) M = qwater × Costwater × top $18Water flowrate for SNCR system (qwater, gal/hr)17 qwater = (msol/ρwater) × [(Cureasolstored/Cureasolinj) - 1] 66Annual ΔCoal Cost (N) N = ΔCoal × Costcoal × top $109Additional coal required (ΔCoal, MMBtu/hr)18 ΔCoal = (Hv × mreagent × [(1/Cureasolinj) - 1])/106

Btu/MMBtu 

Annual ΔAsh Cost (O) O = (ΔAsh × Costash × top)/2000 lb/ton $1Additional ash generated (ΔAsh , lb/hr)19 ΔAsh = (ΔCoal × ashproduct × 106 Btu/MMBtu)/HHV 4Direct Annual Costs (DAC)/Variable O&M DAC = J + K + L + M + N + O $2,050Indirect Annual Costs (IDAC)/Annualized Capital Cost 

IDAC = CFR × TCI $672

Total Annualized Costs (TAC) TAC = DAC + IDAC $2,723

TAC = DAC + IDAC $2,723,162
308

Note in the above table, we have added another column with our corrections to (1) the assumed 

NOx removal efficiency (ηNOX), (2) the uncontrolled NOx rate (NOXin, lb/MMBtu), and (3) a 

recalculation of the capital recovery factor (CRF), corresponding to a 30 year life. The resulting 

annualized cost drops from $2,723,162 to $783,531. 

We have also recalculated AEP SWEPCO’s cost-effectiveness calculation.596 Below is the AEP 

SWEPCO’s cost-effectiveness calculation as presented in its BART analysis, 597 along with our 

corrections. The first table is AEP SWEPCO’s cost-effectiveness calculation. In the second 

table, we make corrections to errors in both AEP SWEPCO’s summing of the total annual costs, 

and in the tons reduced calculations. In the third table, we carry those corrections forward, and 

incorporate the corrections to the SNCR cost analysis we discuss above. 

 

596 See the file, AR020-0037-02_Consolidated_Spreadsheet_2013-09-09-EPA.xlsx. 597 Bart Five Factor Analysis, Flint Creek Power Plant, September 2013, Version 4. Table 6-3. 
309

AEP SWEPCO 

Control 

Technology 

Baseline 

NOx

Emission 

Rate 

(tpy) 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Controlled 

Emission 

Rate

(NOx tpy) 

Annual 

Emissions 

Reductions 

(NOx tpy) 

Capital 

Cost ($) 

Annual 

Capital 

Cost 

($.yr) 

Annual 

Fixed 

O&M 

($/yr) 

Annualized 

Variable 

O&M 

($/yr) 

Tot

Annu

Cos

($/y

LNB/OFA 5,120.27 0.23 4,294.65 825.62 $16,000,000 $1,289,382 $240,000 $132,364 $1,454LNB/OFA/SNCR 5,120.27 0.20 3,771.82 1,348.45 $16,000,147 $1,398,940 $240,000 $133,033 $4,177

AEP SWEPCO (tons reduced and total annl cost corrected) 

Control 

Technology 

Baseline 

NOx

Emission 

Rate 

(tpy) 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Controlled 

Emission 

Rate

(NOx tpy) 

Annual 

Emissions 

Reductions 

(NOx tpy) 

Capital 

Cost ($) 

Annual 

Capital 

Cost 

($.yr) 

Annual 

Fixed 

O&M 

($/yr) 

Annualized 

Variable 

O&M 

($/yr) 

Tot

Annu

Cos

($/y

LNB/OFA 5,120.27 0.23 3,798.91 1,321.36 $16,000,000 $1,289,382 $240,000 $132,364 $1,661LNB/OFA/SNCR 5,120.27 0.20 3,303.40 1,816.87 $23,124,235 $1,961,859 $240,000 $2,183,048 $4,384

EPA (tons reduced, total annl costs, control level and control efficiency corrected) 

Control 

Technology 

Baseline 

NOx

Emission 

Rate 

(tpy) 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Controlled 

Emission 

Rate

(NOx tpy) 

Annual 

Emissions 

Reductions 

(NOx tpy) 

Capital 

Cost ($) 

Annual 

Capital 

Cost 

($.yr) 

Annual 

Fixed 

O&M 

($/yr) 

Annualized 

Variable 

O&M 

($/yr) 

Tot

Annu

Cos

($/y

LNB/OFA 5,120.27 0.23 3,798.91 1,321.36 $16,000,000 $1,289,382 $240,000 $132,364 $1,661LNB/OFA/SNCR 5,120.27 0.20 3,303.40 1,816.87 $21,683,091 $1,747,362 $240,000 $457,915 $2,445
310

As can be seen from the third table above, we calculate that SNCR + LNB/OFA has a revised 

cost-effectiveness of $1,346/ton, as opposed to cost effectiveness of $1,258/ton for LNB/OFA 

alone. Also, we calculated that the incremental cost effectiveness of SNCR + LNB/OFA over 

LNB/OFA alone is $1,581/ton. We re-apply the BART five factors, with emphasis on cost and 

visibility improvement. The incremental visibility improvement of SNCR + LNB/OFA over 

LNB/OFA alone is 0.033 dv at Caney Creek and ranges from 0.005 to 0.01 dv at each of the 

other affected Class I areas. As discussed in our proposal, we consider the incremental visibility 

improvement of SNCR + LNB/OFA to be relatively small at Caney Creek and to be very small 

in the remaining three affected Class I areas.598 We conclude that despite the improvement in the 

cost-effectiveness of SNCR + LNB/OFA over LNB/OFA alone, the resulting relatively small 

incremental visibility improvement is still not worth the additional cost of the more stringent 

controls. 

We agree with Ms. Stamper’s statement in her report that BART cost determinations should be 

based on the Control Cost Manual in order to result in a consistent basis for comparisons to other 

cost determinations. We note Ms. Stamper’s separate SCR cost analysis, in which she assumes a 

NOx control level of 0.04 lbs/MMBtu, using the IPM SCR cost algorithms. Ms. Stamper makes 

a case that because her resulting $/ton figures are in line with other required SCR installations, 

the Flint Creek facility should similarly be required to install SCR. First, as we discuss in our 

response to another comment concerning the White Bluff facility, we do not believe that Ms. 

Stamper has demonstrated that her assumed level of control has been maintained on a 30 day 

BOD average at other similar facilities, such that it can be applied to the Flint Creek facility. 

However, we have re-reviewed/reviewed the information Ms. Stamper presents and conclude, as 

we did in our New Mexico FIP, that it supports a 30 Boiler Operating Day (BOD) NOx average 

of 0.05 lbs/MMBtu for a SCR installation at the Flint Creek facility. 

Second, as we indicate in Table 44 of our TSD and Ms. Stamper notes in her report, the 

maximum visibility improvement due to SCR at Flint Creek based on the modeled rate of 0.067 

lb/MMBtu was 0.245 dv, which occurred at Caney Creek. We further note that AEP SWEPCO’s 

SCR cost analysis is almost completely undocumented. However, due to the relatively low 

visibility improvement expected from SCR, cost was not the only factor in our BART decision 

making. For instance, if we make reasonable, conservative adjustments to the anticipated 

visibility benefit, based on a control level of 0.055 lbs/MMBtu rather than the modeled rate of 

0.067 lbs/MMBtu599, we estimate that the resulting visibility improvement at Caney Creek would 

be no higher than 0.26 dv.600 Based on this adjustment, the incremental visibility improvement 

of SCR + LNB/OFA over SNCR + LNB/OFA is 0.146 dv. Even accepting Ms. Stamper’s SCR 

cost analysis of $3,511/ton (which would be higher were it revised using a controlled NOX rate 

of 0.05 lbs/MMBtu) and taking into consideration the adjustments we have made to the cost 

analysis for SNCR + LNB/OFA, the incremental cost effectiveness of SCR + LNB/OFA over 

 

598 80 FR at 18968 599 Modeled emission rates were based on a maximum heat input of 6,324 MMBtu/hr multiplied by the anticipated 

control rate (e.g. 0.067 lb/MMBtu) Baseline emissions determined from 2001-2003 CAMD data were 1,945 lb/hr, 

approximately 0.308 lb/MMBtu. 

600 Modeled visibility benefit at CACR over baseline from SCR at 0.067lb/MMBtu was 0.245 dv. SCR at 0.055 

lb/MMBtu would result in an additional reduction in emissions from baseline of only 4%. Assuming a linear 

relationship between emission and visibility impacts, this would also result in an increase in visibility benefit of only 

4%. 
311

SNCR + LNB/OFA is $4,969/ton. We do not consider the relatively small incremental visibility 

improvement to be worth the incremental cost of the SCR installation. 

Comment: EPA’s NOX BART analysis for Lake Catherine Unit 4 is legally flawed because 

it did not appropriately consider the costs of compliance and other statutory BART factors.

[Sierra Club et. al. (0171) p. 26-27] Sierra Club et. al. stated that EPA proposed a FIP for Lake 

Catherine Unit 4 that requires an emission limit of 0.22 lb/MMBtu on a 30 boiler operating-day 

rolling average based on the installation and operation of burners out of service (BOOS). 80 Fed. 

Reg. at 18,978. EPA conducted its own analysis of NOx BART controls at Lake Catherine, 

making adjustments to Entergy’s BART analysis to reflect costs not allowed in the EPA’s 

Control Cost Manual but relying on other elements of Entergy’s analysis. Id. 

EPA must base BART determinations on an analysis of the five statutory BART factors: (1) the 

costs of compliance, (2) the energy and non-air quality environmental impacts of compliance, (3) 

existing pollution controls in use at the source, (4) the remaining useful life of the source, and (5) 

the degree of visibility improvement. 42 U.S.C. § 7491(g)(2); 40 C.F.R. § 51.308(e)(1)(ii)(A). 

The Lake Catherine Unit 4 BART analysis fails to accurately consider compliance costs, nonenvironmental impacts, and the degree of visibility improvement. EPA’s Lake Catherine Unit 4 

determination is based on an invalid five-factor BART analysis because it over-estimated the 

costs for SCRs, SNCRs, low NOX burners, and over-fired air, underestimated the cost 

effectiveness of all control scenarios by using an unenforceable capacity factor that is below 

actual averages, assumed an achievable emission rate despite contrary evidence, failed to 

consider the increased greenhouse gas emissions associated with its selected control technology, 

and overstated the visibility benefits of each control scenario due to a reliance on Entergy’s 

flawed maximum daily average NOX emission rate. Therefore, EPA must do a new NOX BART 

analysis that corrects these flaws and considers whether SCR represents the best system of 

continuous emission reduction for NOX at Lake Catherine Unit 4. 

EPA miscalculated the cost effectiveness for all control scenarios. While EPA disapproved and 

corrected some of Entergy’s inflated costs, EPA nonetheless significantly underestimated the 

costs of BOOS in its FIP. As Ms. Stamper’s report explained, installation and operation of the 

BOOS will require modifications to the existing “fuel piping, superheat and reheat attemperation 

sprays, tube metal temperatures and burner tilt positions.” Stamper Report at 54 (citing to the 

Sargent & Lundy report relied on by Entergy for its NOX BART analysis). EPA failed to include 

these additional costs in its BOOS cost estimate. Including all of the costs for BOOS installation 

and operation will make BOOS less cost effective. In addition, EPA likely overestimated the 

labor installation costs of low NOX burners, over-fired air, SNCRs, and SCRs in its FIP. As Ms. 

Stamper’s report noted, EPA likely double-counted labor costs for installation of all of these 

pollution control equipment. Stamper Report at 53. Removal of these duplicative costs would 

make SCRs, SNCRs, LNB, and OFA more cost effective than calculated by EPA. 

Moreover, EPA’s cost-effectiveness analysis is based on an unenforceable 10% capacity factor 

for Lake Catherine Unit 4. Entergy based all of its cost-effectiveness analyses for NOX controls 
312

on an unenforceable 10% capacity factor.601 In 2011, EPA found this assumption problematic as 

it was unenforceable, inconsistent with actual operations (as the unit had operated at a 46% 

average capacity factor between 2001 and 2005), and would likely “significantly inflate the cost 

per ton of controlling this unit.” Id. Nonetheless, EPA found that “based on information provided 

by [Entergy], we agree that the source has historically operated at less than a 10% capacity 

factor.” 77 Fed. Reg. at14,641 (Mar. 12, 2012). This was an error. As Ms. Stamper’s report 

explained, for the 2001-2003 timeframe used by Entergy for the BART NOX analysis, this unit 

had an average capacity factor of 21.2% based on heat input. Stamper Report at 52. In fact, Lake 

Catherine Unit 4 has operated at a capacity factor based on operating days more than 10% for all 

but three of the last 14 years. Id. EPA skewed the cost-effectiveness analysis by using a lower 

than actual (and unenforceable) capacity factor. Had EPA used a higher capacity factor, it would 

have found an increase in the tons of NOX emissions removed by the various pollution control 

equipment and an increase in cost-effectiveness. 

The Sierra Club et. al. stated that EPA’s Lake Catherine Unit 4 NOX BART analysis fails to 

accurately consider the cost of compliance, as well as the non-environmental impacts and 

visibility impacts of controls. Therefore, EPA’s analysis is legally flawed. EPA must conduct a 

new NOx BART analysis that corrects these flaws and considers whether SCR represents the best 

system of continuous emission reduction for NOX at Lake Catherine Unit 4. In doing so, we urge 

EPA to not place inappropriate weight on the incremental cost-effectiveness of controls in its 

revised analysis. Undue focus on “incremental cost effectiveness can give an impression that the 

cost of a control alternative is unreasonably high, when, in fact, the cost-effectiveness, in terms 

of dollars per ton removed [average cost effectiveness], is well within the normal range of 

acceptable” BART costs. See, e.g., NSR Manual at B-45 – B-46. Focusing on incremental costeffectiveness is especially inappropriate when dealing with a widely-used control technology, 

such as SCR. See, e.g., NSR Manual B-44. EPA should instead place greater emphasis on 

average cost-effectiveness of the controls options. The average cost-effectiveness of SCR for 

Lake Catherine Unit 4 from EPA’s revised BART analysis should be well within the range of 

acceptable costs as EPA has considered costs as high as $7,309/ton acceptable for EGUs to meet 

BART. See Section A.1.a.i of the Sierra Club et. al.’s comments. 

Response: We have reviewed the section of the Stamper report that treats this issue in more 

detail and respond to both it and this comment here. Again, we agree with the Sierra Club that 

we must base BART determinations (and judge those submitted to us by states) on the five 

BART statutory factors it cites. The Sierra Club alleges that we over-estimated the costs for 

SCRs, SNCRs, low NOX burners, and over-fired air, underestimated the cost effectiveness of all 

control scenarios for the Lake Catherine Unit 4 by using an unenforceable capacity factor that is 

below actual averages, assumed an achievable emission rate despite contrary evidence, failed to 

consider the increased greenhouse gas emissions associated with its selected control technology, 

and overstated the visibility benefits of each control scenario due to a reliance on Entergy’s 

flawed maximum daily average NOX emission rate. 

 

601 See Revised BART Five Factor Analysis, Lake Catherine Steam Electric Station, May 2014, at 6-7 [EPA-R06-

OAR-2015-0189-0055]. 
313

As a first order issue, we cannot consider the increase in greenhouse gas emissions that may 

occur as a result of a potential control strategy, as there is no basis for doing so in the Regional 

Haze Rule.602

Ms. Stamper states that we erred in agreeing to the use of a 10% capacity factor in our cost 

calculations. She states that we previously noted that Unit 4 had previously operated at a 46% 

capacity factor in our 2011 proposal.603 The language that Ms. Stamper refers to is as follows: 

The computer model Entergy used to estimate the cost effectiveness of postcombustion controls likewise assumed a 10% capacity factor in the calculation of 

the metrics for tons removed and $/ton removed. Given that there are no permit 

requirements in place that would limit the operation of this unit to 10% capacity, 

the facility can legally be operated well above the 10% capacity factor assumed 

by Entergy. Thus, any cost effectiveness analysis based on a 10% capacity factor 

is likely to significantly inflate the cost per ton of controlling this unit. In support 

of the 10% capacity utilization factor, Entergy stated that the unit has operated, on 

average, at a capacity of 6.9% for the past three years. However, past use of this 

unit was much higher— approximately 46% on average—over the 2001–2005 

period.604 

As the footnote indicates, our reference to the 46% figure was taken from Entergy’s BART 

analysis, which was a reference to the percent of hours of operation. As we note in that proposal 

in the footnote just preceding this one: 

40 CFR 72.2 defines capacity factor as either ‘‘(1) The ratio of a unit’s actual 

annual electric output (expressed in MWe/hr) to the unit’s nameplate capacity (or 

maximum observed hourly gross load (in MWe/hr) if greater than the nameplate 

capacity) times 8760 hours; or (2) The ratio of a unit’s annual heat input (in 

million British thermal units or equivalent units of measure) to the unit’s 

maximum rated hourly heat input rate (in million British thermal units per hour or 

equivalent units of measure) times 8,760 hours. 

Thus, a capacity factor is usually better calculated on the basis of heat input or electric output. 

Nevertheless, Ms. Stamper states that she believes that we should have calculated the Lake 

Catherine Unit 4 capacity on the basis of operating time. In response, we investigated the 

correlation between heat input and operational time to NOX emissions for Lake Catherine Unit 4, 

reasoning that because our cost analyses was for NOX control, changes in capacity should 

correlate to changes in NOX.

605 As the following graph indicates, there is a good correlation 

between heat input and NOX, but no correlation between operational time and NOX for Lake 

Catherine Unit 4: 

 

602 See the BART requirements at 40 CFR 51.308. 603 76 FR 64204. 604 Note that we footnoted this passage in 76 FR 64204 with the following reference: Table 2–1 of the ‘‘BART 

Analysis for Lake Catherine Plant- Unit 4,’’ prepared by Robert Paine, December 2006 notes that Unit 4 was 

operated 6,988 hours in 2001 (79.7% utilization); 5,651 hours in 2002 (64.5% utilization); 3,972 hours in 2003 

(45.3% utilization); 1,534 hours in 2004 (17.5% utilization); and 2,059 hours in 2005 (23.5% utilization). 605 See the file, “Lake Catherine Monthly Data.xlsx,” which is in our docket. 
314

Thus, we disagree with Ms. Stamper that capacity should be based on hours operated per year, 

and conclude that the historical capacity factor for Lake Catherine should be based on heat input. 

On 3/29/13, we provided comments to Entergy that addressed this issue. We calculated the 

historical capacity for this unit from 2001 to 2012. Below we reproduce that data and update it 

to 2015:606

Lake Catherine Unit 4 Historical Capacity 

Year 

Capacity 

Factor 

(%) 

2001 28.2 

2002 24.2 

2003 11.3 

2004 3.7 

2005 4.7 

 

606  See the file, “R6 Comments 3‐23‐13.pdf” and the spreadsheet “Lake Catherine Monthly Data.xlsx,” both of

which are in our docket.
315

2006 0.6 

2007 0.8 

2008 2.3 

2009 2.8 

2010 3.5 

2011 2.9 

2012 14.3 

2013 11.1 

2014 2.0 

2015 3.9 

We do agree with Ms. Stamper that the Lake Catherine Unit 4 historical capacity has sometimes 

exceeded the 10% capacity Entergy has assumed in its control cost analyses. However, the 

average from the last ten years of data (2006 to 2015) has been 4.4%. When we questioned 

Entergy about its assumption of a 10% capacity factor in its cost analyses, it responded607 by 

pointing us to our BART Guidelines, which states that, “The baseline emissions rate should 

represent a realistic depiction of anticipated annual emissions for the source.”608 Our conclusion 

is that like an emission baseline, the assumed capacity factor should “represent a realistic 

depiction of anticipated annual emissions for the source,” and be based on an annual average. 

Typically, we place the most emphasis on the last five years of data, and our recent practice has 

been to discard the high and low values and average the remaining three years.609 Applying that 

procedure to the Lake Catherine Unit 4 capacity factor results in a value of 6.0%. Alternatively 

calculating a straight average of the last five years results in a value of 6.8%. Thus, assuming a 

10% capacity factor is conservative, and we disagree with Ms. Stamper that we erred in 

accepting Entergy’s assumption of a 10% capacity factor in its control cost analysis. We note 

that in its response to us, Entergy stated, “If future capacity factors change, ADEQ and EPA may 

impose further NOX emission reductions on Unit 4, if necessary, in later planning periods to 

show reasonable progress.” We believe that is an appropriate strategy and we will re-examine 

Lake Catherine’s historical capacity in our review of Arkansas’ next regional haze SIP. 

Ms. Stamper alleges that the Sargent & Lundy documentation submitted by Entergy to support 

its analysis and cost calculations is not consistent with the BART analysis presented in Entergy’s 

2013 revised BART analysis or with our proposed rulemaking. She also states that the 

documentation is also inconsistent with the 2006 BART analysis submitted for Lake Catherine 

Unit 4, and that Entergy’s revised analysis also did not evaluate the full suite of controls the 

company had evaluated in 2007. To the extent these comments are generalized summaries of 

more specific comments, we address them below. Otherwise, we conclude that Ms. Stamper 

does not present any specific information to substantiate these allegations or why they are 

germane, so we are unable to assess them. 

Ms. Stamper states that the NOX BART analysis for Lake Catherine Unit 4, found in the May 

2013 Sargent & Lundy report, includes an Estimate No. 31815A, for low NOX burners and 

separated overfire air at Lake Catherine Unit 4 with a total cost of $7,803,995. She states: 

 

607 See the file, “Response to R6 Comments – Lake Catherine – 6-25-13.pdf,” which is in our docket. 608 70 FR 39167. 609 This was our approach in calculating the SO2 baselines used in our recent TX-OK FIP. 
316

Entergy added costs to that total including $1,634,363 in Entergy employee labor 

and loaders. Yet, the Sargent & Lundy cost estimate included costs for labor of 

$331,677, as well as costs for subcontract (which likely covered labor) of 

$2,850,000, and another $2,000,000 under the category of “other.” Thus, Entergy 

increased the Sargent & Lundy’s cost estimate for LNB/SOFA by 20%, and it 

seems very likely that Entergy’s additional cost for Entergy labor and loaders was 

already included in the Sargent & Lundy low NOX burner/SOFA estimate. 

Further, Entergy added the same amount of $1,634,363 in Entergy employee labor 

and loaders to the Sargent & Lundy estimates for low NOX burners/SOFA plus 

SNCR and to the Sargent & Lundy costs for low NOx burners/OFA plus SCR. 

The estimate Ms. Stamper cites, Estimate No. 31815A, refers to the Lake Catherine, Unit 4 – 

SNCR estimate (not LNB/OFA). Also, the total Ms. Stamper refers to, $7,803,995.193, is the 

total to install LNB/OFA to Lake Catherine Unit 1 (not Unit 4). Nevertheless, we were able to 

find the $1,634,363 charge that Entergy added to the S&L cost estimate, for Entergy employee 

labor and loaders.610 Ms. Stamper contends that the S&L estimate likely already includes these 

charges. We confirm that the Lake Catherine Unit 4 LNB/OFA estimate contain entries for costs 

for labor of $331,677, as well as costs for subcontract of $2,850,000. However, based upon the 

information discussed previously, these costs cover the labor and subcontract to install the 

LNB/OFA system, whereas the $1,634,363 Entergy added refers to its own employee labor and 

loaders. We therefore conclude that Ms. Stamper has not demonstrated that the additional charge 

of $1,634,363 in Entergy employee labor and loaders was inappropriate for the LNB/OFA, 

SNCR, and SCR cost estimates. 

Ms. Stamper states that it appears that Entergy overstated the NOX reductions from BOOS at 

Lake Catherine Unit 4. She states the Entergy 2013 revised report assumes lower NOX emission 

rates for BOOS than previously evaluated in the 2007 BART analysis for Lake Catherine, and 

Entergy’s 2013 revised BART analysis assumed a NOX rate of 0.22 lb/MMBtu with BOOS, 

despite the Sargent & Lundy analysis of Lake Catherine Unit 4 found the achievable NOX rate 

with BOOS to be 0.24 lb/MMBtu. She states it is unclear that Entergy has any operating 

experience to rely on to estimate the NOX rate may be met with BOOS and an increase in fuel 

flow of 25% (required to make up for the lost capacity). She concludes there is a lack of 

adequate justification that Entergy can meet its proposed NOX limit with BOOS. Regarding this, 

Entergy itself states, “Based on the level of control expected to be achieved by BOOS and the 

expected utilization levels at Unit 4, Entergy believes that an emission rate of 0.22 lb/MMBtu is 

achievable on a 30-day rolling average basis.”611 We see no reason to conclude that Entergy 

cannot achieve the NOX limit that it itself claims to be able to achieve. We therefore disagree 

with Ms. Stamper. Furthermore, as we discuss elsewhere, the 0.22 lb/MMBtu emission limit 

refers to the 30-day BOD limit and the 0.24 lb/MMBtu emission rate is a short-term emission 

rate based on a 50% reduction of the maximum 24-hr emission rate. 

Ms. Stamper states that the cost analysis for BOOS also appears to be incomplete and likely 

underestimates costs. Specifically, Sargent & Lundy stated that, to achieve current generation 

 

610 Appendix A to the Revised Bart Five Factor Analysis, Lake Catherine Steam Electric Station, May 2014. See 

pdf page 32. 

611 Revised Bart Five Factor Analysis, Lake Catherine Steam Electric Station, May 2014. See pdf page 16. 
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rates with BOOS, there would need to be an increase in the original high burner header pressure 

to increase fuel flow to the boiler, and this might require modifications to the existing “fuel 

piping, superheat and reheat attemperation sprays, tube metal temperatures and burner tilt 

positions, for the new operating conditions.” However, she states that none of these boiler 

modifications were included in the costs for BOOS. She also states that the costs for BOOS at 

Lake Catherine Unit 4 were based on vendor cost data adjusted to $/kW to Lake Catherine, and 

were not based on site-specific estimates. S&L’s full statement regarding this situation is: 

Recovery of the lost unit capacity is possible by increasing the fuel fired in the 

three levels of burners that remain in service. The burners remaining in service 

would have to increase fuel throughput by 25%. The natural gas piping to each 

burner may also have to be increased in size for the higher fuel flow rates. ETEC, 

Inc. has experience with several units similar in design to Lake Catherine – Unit 4 

that have been able to achieve full capacity by increasing the original “high” 

burner header pressure (BHP) to increase fuel flow to the burners (See Appendix 

D). The increase in BHP from 42 to 50 psig at Lake Catherine – Unit 4 would 

increase fuel flow by 25% and the burners would be operated “fuel rich”, 

lowering NOX formation. Using this approach would reduce NOx emissions at a 

small capital cost. The costs for BOOS with recovery of full unit capacity were 

based on vendor cost information for a previous project adjusted on a $/kW basis 

to Lake Catherine – Unit 4 and escalated to 2012. The cost provided does not 

include any modifications to the boiler. A boiler OEM or consultant would need 

to evaluate the existing fuel piping, superheat and reheat attemperation sprays, 

tube metal temperatures and burner tilt positions for the new operating conditions. 

The expected NOX reduction would range from 40% at low load to 50% at full 

load and NOX levels of 0.24 lb/MMBtu. 

It appears to us that the costs Ms. Stamper references for BHP are covered in the costs S&L 

states, were “based on vendor cost information for a previous project adjusted on a $/kW basis 

to Lake Catherine.” It appears that the only costs that may not have been included are any 

“modifications to the boiler.” Regarding these, S&L states that “A boiler OEM or consultant 

would need to evaluate the existing fuel piping, superheat and reheat attemperation sprays, tube 

metal temperatures and burner tilt positions for the new operating conditions.” However, 

Entergy states, “It is anticipated that BOOS can be implemented on the unit without any capital 

expenditures.”612 We therefore conclude that the “any modifications to the boiler” costs 

discussed above were not specifically applicable to Lake Catherine Unit 4 and disagree with Ms. 

Stamper. 

Ms. Stamper criticizes our determination that BART of the Lake Catherine Unit 4 is BOOS, 

stating that the cost effectiveness of LNB/SOFA, LNB/SOFA/SNCR, and LNB/SOFA/SCR are 

likely lower than we have determined, and are all within a range that has previously been found 

to be acceptable for BART. She also cites to BACT determinations for SCR determinations at 

coal-fired and gas-fired units with incremental cost-effectiveness as high as $30,000 to 

$57,000/ton. She states that we must correct these errors by properly calculating the cost and 

 

612 Revised Bart Five Factor Analysis, Lake Catherine Steam Electric Station, May 2014. Appendix A. See pdf 

page 31. 
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achievable emission reductions from NOX controls and then redo the five factor NOx BART 

analysis for Lake Catherine. As we have discussed in our replies to other comments, in a BART 

analysis, the cost of controls must balance visibility benefit. Visibility is one of the five statutory 

factors under CAA section 169A(g)(2) and 40 CFR section 51.308(e)(1) we are required to 

consider in a BART analysis. In this case, we do not believe that Ms. Stamper has demonstrated 

that we erred in our cost estimate of BOOS and we do not believe that the increased cost 

effectiveness of these technologies over BOOS justify their increased visibility benefit for the 

Lake Catherine Unit 4 to meet BART. We address specific comments concerning the modeled 

visibility benefit of controls at Lake Catherine elsewhere in this document where we address 

modeling comments. If we were convinced that this unit was going to operate substantially in 

excess of the 10% capacity we have assumed in our analysis, we would perhaps have reached a 

different conclusion. As we state above, we may revisit our determination when we review 

Arkansas’ next regional haze SIP. 

Comment: EPA did not appropriately consider the true cost of controls on the 

Independence Plant because it eliminated costs that it says are not allowed by EPA’s 

Control Cost Manual. [AEP-SWEPCO July 15, 2015 comments (0164) p. 5, and August 7, 

2015 comments (0167) p. 6] AEP-SWEPCO stated that the analysis EPA conducted for 

Independence included a cost analysis where EPA estimated $/ton costs based on similarities 

with the White Bluff units and, therefore, according to the methodology found in EPA’s Cost 

Manual.613 As noted by EPA numerous times in their RH evaluations, EPA’s Cost Manual, does 

not allow inclusion of all actual costs associated with retrofitting various control technologies. 

The Cost Manual results serve as a reasonable tool for comparing one technology to another, but 

in the case of the Independence facility, it does not represent a true $/ton value and 

underestimates the cost relative to the actual $/ton by excluding these significant real costs. 

Therefore, EPA has not properly considered the four RPG factors by accurately considering the 

whole cost impact. The Cost Manual is fundamentally flawed (“ ... this Manual does not directly 

address the controls needed to control air pollution at electrical generating units (EGUs) because 

of the differences in accounting for utility sources.”) relative to producing a value to be 

compared to actual $/ton by excluding real costs and should not be used to justify costeffectiveness compared to market value.614 Based on our experience in other BART cost 

analyses, these costs could be only 60% of the actual installed costs. 

Response: We address specific criticisms concerning our reasonable progress cost analysis for 

the Independence facility in our responses to other comments. AEP SWEPCO does not provide 

any references to support its statement, that we have noted in our regional haze evaluations 

numerous times that our Control Cost Manual does not allow inclusion of all actual costs 

associated with retrofitting various control technologies. We cannot find any specific reference 

to our making such a statement and we believe AEP SWEPCO’s statement is inaccurate and 

misleading. Certain costs (e.g., AFUDC) are disallowed (see our response to related comments), 

but that does not invalidate the use of the Control Cost Manual—it merely points to the fact that 

the Control Cost Manual’s overnight methodology uses a different accounting approach than is 

used by power companies. As we state in our AR Cost TSD Appendix A: 

 

613 EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/452/B-02-001 (hereinafter "EPA Cost Manual"). 614 See, EPA Cost Manual at p. 3-1. 
319

In developing our cost estimates for the units in Table 1, we relied on the methods 

and principles contained within the EPA Air Pollution Control Cost Manual. As 

we describe in our Oklahoma final action the CCM uses the “overnight” method 

of cost estimation: 

The Control Cost Manual uses the overnight method of cost estimation, widely 

used in the utility industry. The U.S. Energy Information Administration (EIA) 

defines ‘‘overnight cost’’ as ‘‘an estimate of the cost at which a plant could be 

constructed assuming that the entire process from planning through completion 

could be accomplished in a single day. This concept is useful to avoid any impact 

of financing issues and assumptions on estimated costs.’’ EIA presents all of its 

projected plant costs in terms of overnight costs. The overnight cost is the present 

value cost that would have to be paid as a lump sum up front to completely pay 

for a construction project. The overnight method is appropriate for BART 

determinations because it allows different pollution control equipment to be 

compared in a meaningful manner. Because ‘‘different controls have different 

expected useful lives and will result in different cash flows, the first step in 

comparing alternatives is to normalize their returns using the principle of the time 

value of money ... The process through which future cash flows are translated into 

current dollars is called present value analysis. When the cash flows involve 

income and expenses, it is also commonly referred to as net present value 

analysis. In either case, the calculation is the same: Adjust the value of future 

money to values based on the same point in time (generally year zero of the 

project), employing an appropriate interest (discount) rate and then add them 

together.’’ Our proposed approach is as follows: 

 Start with material we and Arkansas received from Entergy to support its 

White Bluff control cost analysis. 

 Analyze that material for compliance with the Regional Haze Rule and our 

guidance. 

 Critique that material and adjust it as necessary. 

 Justify and extend that analysis to the Independence facility. 

The BART Guidelines require that the Control Cost Manual be used when possible, when 

conducting a BART analysis,615 and we have not seen an instance where the Control Cost 

Manual’s overnight methodology cannot be used. Furthermore, we believe the overnight 

methodology is appropriate for use in reasonable progress cost evaluations as well, to ensure 

consistency in evaluating cost-effectiveness calculations across BART and non-BART 

evaluations. Although the Control Cost Manual provides for specific methods for estimating 

capital costs in some instances, its use of the overnight method, the issue here, is applicable to 

every control cost analysis. We also disagree with AEP SWEPCO’s statement that the Control 

Cost Manual is fundamentally flawed. AEP SWEPCO’s statement that the Control Cost Manual 

 

615 70 FR 39166. In order to maintain and improve consistency, cost estimates should be based on the OAQPS 

Control Cost Manual, where possible. 
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does not directly address the controls needed to control air pollution at electrical generating units 

is based on an incomplete and misleading reproduction of a quote. The full quote is actually:616

This Manual provides up-to-date information on point source and stationary area 

source air pollution controls for volatile organic compounds (VOCs), particulate 

matter (PM), oxides of nitrogen (NOX), and some acid gasses (primarily SO2 and 

HCl). It is not a source of information for non-stationary area (e.g. emissions from 

fugitive dust sources, agricultural sources) and mobile sources. Furthermore, this 

Manual does not directly address the controls needed to control air pollution at 

electrical generating units (EGUs) because of the differences in accounting for 

utility sources. Electrical utilities generally employ the EPRI Technical 

Assistance Guidance (TAG) as the basis for their cost estimation processes.1

Finally, new and emerging technologies are not generally within the scope of this 

Manual. The control devices included in this Manual are generally well 

established devices with a long track record of performance 

1 This does not mean that this Manual is an inappropriate resource for utilities. In 

fact, many power plant permit applications use the Manual to develop their 

costs. However, comparisons between utilities and across the industry generally 

employ a process called “levelized costing” that is different from the 

methodology used here. 

As can be seen from the portion of the quote that AEP SWEPCO left out, the Control Cost 

Manual (specifically the overnight methodology) can be used for estimating the cost of controls 

for power plants, which is why the BART Guidelines require its use, and why it has in fact been 

used to do so in numerous instances. 

Comment: EPA did not justify why it refused to take into account actual costs of emission 

controls when evaluating BART. [UARG (0176) p. 8-9] UARG stated that the CAA and EPA’s 

BART rules require EPA to take actual costs of emission controls into account when it evaluates 

a control technology as BART. See, e.g., Am. Corn Growers, 291 F.3d at 6-7 (emphasizing the 

need to address real-world costs of controls in relation to projected Class I area visibility 

improvements that may result from installation and use of such controls). In several regional 

haze rulemaking proceedings, including the present rulemaking, EPA instead has taken the 

position that rigid adherence to the cost-accounting methodology in its Control Cost Manual – 

or, to be more precise, EPA’s current interpretation of that methodology – is legally mandated. 

For instance, with respect to the White Bluff Plant, EPA proposes to reject elements of a cost 

analysis prepared by the facility’s owner because that analysis “includes line items that ... do not 

appear to be valid costs under our Control Cost Manual methodology.” 80 Fed. Reg. at 18,971; 

see also id. at 18,973 (stating, in proposing to reject capital suspense costs, that those costs “do 

not appear to be valid costs under the Control Cost Manual methodology”). EPA’s proposed rule 

excludes similar costs in its NOx BART assessment for Lake Catherine Unit 4. Id. at 18,977 

(rejecting capital suspense and “allowance for funds used during construction” because such 

 

616 Control Cost Manual, Sixth Edition, EPA/452/B-02-001, January 2002. Section 1, page 1-3. 
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costs are not, or “do not appear to be,” “valid costs under the Control Cost Manual methodology” 

as construed by EPA). 

The BART Guidelines make clear the nonbinding nature of the Control Cost Manual 

methodology; they state that the basis for BART control-equipment cost estimates “should be 

documented, either with data supplied by an equipment vendor (i.e., budget estimates or bids) or

by a referenced source (such as the OAQPS Control Cost Manual ...).” 70 Fed. Reg. at 39,166 

(emphases added) (footnote omitted). 

BART determinations properly take into account additional information ... used 

for the cost calculations, including any information supplied by vendors that 

affects ... assumptions regarding purchased equipment costs, equipment life, 

replacement of major components, and any other element of the calculation that 

differs from the Control Cost Manual. 

Id, at n.15 (emphasis added). Similarly, the rules’ preamble states: 

...the Control Cost Manual provides a good reference tool for cost calculations, 

but if there are [cost] elements or sources that are not addressed by the Control 

Cost Manual or there are additional cost methods that could be used, we [i.e., 

EPA] believe that these could serve as useful supplemental information. 

Id. at 39,127 (emphases added). Thus, the Control Cost Manual is “a ... reference tool” but is not 

binding in any way,617 and EPA has no legitimate basis for excluding real-world costs identified 

by facility owners and operators from BART analyses. EPA should withdraw any of its proposed 

BART determinations that is based on an inadequate or incomplete cost assessment. 

Response: We disagree with UARG on all points. See our responses to other similar comments 

regarding the use of the Control Cost Manual when performing BART cost analyses. There is no 

conflict between considering real capital costs and the use of the Control Cost Manual’s 

overnight methodology and in fact, we often use vendor quotes for various controls in 

conjunction with the overnight methodology. We address specific line item cost comments in 

our responses to other more specific comments. 

Comment: Economic and social factors must be factored into EPA’s analysis of controls, 

especially for the Domtar Ashdown Mill, where the asserted visibility gains cannot be 

predicted to occur. [Domtar Supplemental Comments (0170) p. 2] Domtar stated that related to 

the Trinity Consultants analysis of the CALPUFF model’s margin of error for Power Boiler 2, 

there is the need for EPA to consider the adverse economic and social effects of environmental 

rules. As noted in the Ashdown Mill’s prior comments, adding millions in additional annual 

operating costs threatens the competitive position of the Ashdown Mill. Loss of competitive 

 

617 Regarding design parameters for emission controls, the BART Guidelines call for “documentation of ... 

assumptions regarding design parameters” and explain that the Control Cost Manual would be one – but only one – 

“[e]xample[] of [a] supporting reference[]” that could be used for documentation. 70 Fed. Reg. at 39,166 (emphasis 

added). 
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position means lost profits translating into lost jobs and significant adverse social consequences. 

The United States Supreme Court recognized these economic and social costs are a significant 

factor that must be considered before imposing costly regulatory requirements. Michigan v. 

EPA, 576 U.S. __ (June 29, 2015) (“[t]he Agency must consider cost ... including, most 

importantly, cost of compliance, ... before deciding whether regulation is appropriate and 

necessary”). In addition, the D.C. Circuit Court explained in vacating portions of the Regional 

Haze Rule that it is arbitrary and capricious for EPA to force an emission source “to spend 

millions of dollars for new technology that will have no appreciable effect on the haze in a Class 

I area.” Am. Corn Growers Ass’n, 291 F.3d at 7. 

In the case of the Ashdown Mill, where the asserted visibility gains cannot be predicted to occur, 

these economic and social factors are of paramount importance and must be factored into the 

analysis. On this basis alone, the lack of a cost and social affects analysis requires withdrawal of 

the Ashdown Mill’s proposed BART rules. 

Response: The CAA and the Regional Haze Rule require that when assessing BART, the state 

or we must take into consideration five factors:618 

the technology available, the costs of compliance, the energy and nonair quality 

environmental impacts of compliance, any pollution control equipment in use at 

the source, the remaining useful life of the source, and the degree of improvement 

in visibility which may reasonably be anticipated to result from the use of such 

technology.619

As we have discussed in our TSD,620 we have complied with that requirement, which includes 

the consideration of cost. We are certainly sensitive to the need of the facilities affected by the 

regional haze program to remain competitive. However, in every instance we are aware of, the 

installation of pollution controls necessary for compliance with the CAA and the Regional Haze 

Rule requires the expenditure of capital, which carries with it the possibility of reduced profits. 

Domtar has not supplied any specific information that would cause us to conclude that 

compliance with BART would impact its continued viability. Consequently, we see no reason to 

conclude that we should change our proposed BART determinations for Domtar. 

We address Domtar’s comments on the CALPUFF model margin of error in the section of this 

document where we address modeling issues. 

Comment: EPA failed to consider the cost of controls for the Independence Plant relative 

to the visibility benefit that would result. [Entergy Arkansas Inc. (0166) p.43-44; and Conway 

Corporation et. al. (0172) p. 10-11] Entergy and Conway Corporation et. al. stated that EPA 

failed to consider the cost-effectiveness of the controls relative to the visibility benefit that would 

result. EPA’s own guidance notes that for “individual, large scale sources, simple cost 

effectiveness estimates based on a dollar-per-ton calculation may not be as meaningful as a 

 

618 40 CFR 51.308(e)(1)(ii)(A). 619 40 CFR 51.308(e)(1)(ii)(A). 620 See the discussion beginning on page 100. 
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dollar-per-deciview calculation.” Reasonable Progress Guidance at 5-2. Here, EPA gave no 

consideration to the dollar-per-deciview resulting from installing scrubbers at Independence. If 

EPA had done so, it would recognize that the costs are approximately $1.33 billion per dv 

improvement at Caney Creek and $1.53 billion per dv improvement at Upper Buffalo based on 

Entergy’s revised S&L cost analysis. See S&L FIP Cost Report at 21, Table 8. Where additional 

visibility improvement is not needed to remain below the glide path, such an exorbitant cost 

cannot be justified. See Nat’l Parks Conservation Ass’n v. EPA, 788 F.3d 1134, 1149 (9th Cir. 

2015) (“NPCA”) (upholding EPA’s decision not to require reasonable progress controls because 

of lack of cost-effectiveness, finding reasonable EPA’s explanation that “cost of compliance is 

only one of the four statutory requirements for reasonable progress analysis.”). 

Ultimately, the insignificant level of projected visibility improvement does not justify the costs 

associated with adding a dry FGD, does not meet the statutory RPG requirement for proper 

consideration of the cost of controls, and is patently unreasonable, arbitrary, and capricious. 

[Entergy Mississippi Inc. (0168) p. 12-13; AEP-SWEPCO July 15, 2015 comments (0164) p. 5, 

and August 7, 2015 comments (0167) p. 6; and Conway Corporation et. al. (0172) p. 10-11] 

EMI, AEP-SWEPCO, and Conway Corporation et. al. stated that the Independence Plant is not a 

BART-eligible source and therefore, cost-effectiveness should be determined not only on the 

calculated $/ton cost, but also relative to the installed capital cost and the resulting visibility 

improvement for the determination of reasonability.621

 

[Entergy Mississippi Inc. (0168) p. 12-13] EMI stated that EPA notes that its BART-type 

evaluation for NOX for the Independence Plant would result in visibility improvements ranging 

from 0.148 to 0.459 dv with a cumulative improvement of 0.978 dv.622 EPA recognized that 

these improvements were relatively small and proposed an option (Option 2) that did not include 

the LNB/SOFA NOX controls.623 EPA, however, did not recognize that the Independence Plant is 

subject to the Cross-State Air Pollution Rule (“CSAPR”) and that NOX reductions “better than 

BART” would already be achieved by participation in that program without specifically 

requiring emissions limits based on the installation of low NOX burners and separated overfire 

air as proposed in the FIP. For SO2 emissions, EPA estimated improvements with dry FGD 

ranging from 1.045 to 1.178 dv with a cumulative benefit of 4.375 dv. Three of the four Class I 

areas would realize visibility improvements barely discernible to the human eye (< 1.1 dv). The 

best improvement is for Upper Buffalo and is only 1.178 dv. It is not appropriate to use the 

cumulative values as a representation of the visibility benefit of adding controls since only the 

improvement at each individual Class I area could actually be recognized (see Comment III.F., 

below). This level of visibility improvement is virtually insignificant and does not justify the 

costs associated with adding a dry flue gas desulfurization (“FGD”). Therefore, EPA’s proposal 

does not meet the statutory RPG requirement for proper consideration of the cost of controls and 

so is not “reasonable.” 

Response: See our response to another comment concerning the use of the $/dv metric. In our 

reasonable progress analysis, alongside the four statutory factors, we also considered the 

 

621 80 Fed. Reg. at 18993 (SO2 costs, Unit 1, Unit 2 are $3,706 and $3,416.) 622 80 Fed. Reg. at 24,873 (supplemental modeling values). 623 80 Fed. Reg. at 18,995 and 18,997. 
324

visibility improvement of controls. Although visibility is not one of the four mandatory factors 

explicitly listed for consideration under CAA section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), 

states or EPA have the option of considering the projected visibility benefits of controls in 

determining if the controls are necessary to make reasonable progress. We disagree with Entergy 

that the projected visibility improvement does not justify the installation of controls at the 

Independence facility to meet reasonable progress. As we state in our TSD,624 “The Entergy 

Independence Plant is not subject to BART, but its emissions were 30,398 SO2 tpy and 13,411 

NOx tpy based on the 2011 NEI. The Entergy Independence Plant is the second largest source of 

SO2 and NOx point-source emissions in Arkansas, accounting for approximately 36% of the SO2

point-source emissions and 21% of the NOx point-source emissions in the State.625 As we 

discuss in detail elsewhere in this document, the installation of the controls on Independence we 

are finalizing in this action will result in significant visibility benefits and meaningful progress 

towards the goal of natural visibility conditions. 

We agree with Entergy that the Independence facility is not a BART-eligible source. However, 

Entergy cites to no justification in the Regional Haze Rule to support its contention that, “costeffectiveness should be determined not only on the calculated $/ton cost, but also relative to the 

installed capital cost and the resulting visibility improvement,” nor does Entergy provide 

specifics as to how this should be done. In addition, capital costs are already considered, as they 

are an input (along with operational and maintenance costs) to the total annualized costs that 

form the numerator in the $/ton metric. 

We address elsewhere in this document comments stating that we should substitute CSAPR 

participation for source-by-source NOX BART. 

We disagree that the Regional Haze Rule requires that controls on a source or group of sources 

result in perceptible visibility improvement and discuss that issue in more detail in our responses 

to other comments regarding modeling. 

Comment: The cost-effectiveness of dry FGD at Independence far exceeds the costeffectiveness standards reviewed and approved by EPA for the Kentucky and North 

Carolina Regional Haze SIPs, and are not justified based on the low visibility 

improvement. [Conway Corporation et. al. (0172) p. 5-6; and EEAA (0173) p. 10-11] Conway 

Corporation et. al. and EEAA stated that EPA’s disregard for consistent reasonable progress 

review and analysis continued into the statutory four-factor analysis. After making the arbitrary 

and capricious determination to target only the Independence Plant, EPA approved dollar per ton 

cost-effectiveness estimates and visibility improvement rates for the proposed controls that are 

out of line with the standards applied in other regional haze SIPs and FIPs. EPA’s proposal 

attempts to justify a cost-effectiveness of dry FGD at the Independence Plant totaling $2,477/SO2

ton removed for Unit 1 and $2,686/SO2 ton removed at Unit 2.626 However, this far exceeds the 

 

624 See page 133 of our TSD. Based on 2011 data, Entergy’s White Bluff facility is the largest sources of SO2 and 

NOx in the state, with slightly higher totals than the Independence facility. 

625 The first and third largest sources of SO2 and NOx point-source emissions in Arkansas (White Bluff and Flint 

Creek) are being controlled under the BART requirements in this action. 

626 Id. at 18933. 
325

cost-effectiveness standards reviewed and approved by EPA for the Kentucky627 and North 

Carolina628 state implementation plans. 

Further, relying on the multisource CENRAP model, EPA projected that the visibility benefits 

from all proposed FIP controls (i.e. BART and Reasonable Progress Determinations) would be 

0.19 dv (Upper Buffalo) and 0.21 dv (Caney Creek) over 2018 projections.629 These benefits 

represent the same type of negligible improvement in visibility that was specifically avoided in 

previous EPA actions.630 Proposing controls with such a low amount of visibility benefit also 

ignores EPA’s previous determination that improvements of less than 0.5 dv are “relatively 

small” and are not reasonable justification for additional controls -- even when the controls may 

be cost-effective.631 

Response: As discussed in our responses to other comments, we do not judge the 

appropriateness of controls based solely on cost-effectiveness (the $/ton metric). Rather, we 

weigh the cost with the other statutory factors. In our reasonable progress analysis we also 

considered the visibility improvement of controls alongside the four statutory factors. Although 

visibility is not one of the four mandatory factors explicitly listed for consideration under CAA 

section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), states or EPA have the option of considering 

the projected visibility benefits of controls in determining if the controls are necessary to make 

reasonable progress. In some cases, for reasonable progress determinations, we have calculated 

cost-effectiveness values for controls that fall within a range we have previously found to be 

acceptable, but the visibility improvement was not large enough to consider as beneficial at this 

time.632 Thus, it is inappropriate to simply compare cost-effectiveness values. Nevertheless, the 

Independence cost-effectiveness values fall squarely within a range of value we have previously 

found to be acceptable—again, even if the visibility benefits are not considered—for the same 

types of controls.633 

We have responded to arguments that we have been inconsistent with regards to our Kentucky 

and North Carolina actions, and comments concerning the estimated visibility benefits from all 

controls in our responses to other comments. 

The commenter incorrectly compares the CAMx photochemical model results for the overall 

visibility benefit of controls on the average of the 20% Worst days for 2018 to the CALPUFF 

modeled visibility benefit from controls that is modeled based on maximum emission levels and 

using a natural background approach. As we discuss in more detail elsewhere in this document, 

 

627 76 Fed. Reg. 78194, 78206 (Dec. 16, 2011) (approving the use of a $2,000 per ton SO2 screening threshold). 628 77 Fed. Reg. 11858, 11870 (Feb. 28, 2012) (approving state’s decision not to implement additional controls for 

reasonable progress despite cost-effectiveness determinations ranging from $912 to $1,922 per ton of SO2 removed). 629 80 Fed. Reg. at 18998 (Table 67). 630 See e.g., 77 Fed. Reg. at 24012 (Montana Proposed) (EPA determined that 0.18 dv improvement was too low to 

justify additional SO2 controls on one facility); 76 Fed. Reg. 12651, 12661 (Oregon Proposed) (Mar. 8, 2011) (EPA 

rejected relatively low-cost per ton controls that yielded only 0.18 dv improvement). 

631 77 Fed. Reg. 30454, 30464 (Oregon Final). (May 23, 2012). 632 For instance, see the reasonable progress control determination for the Parish facility in our recent TexasOklahoma FIP. 81 FR 296. 

633 76 FR 81746. Note that Option 2 concerning dry scrubbers included cost-effectiveness values that ranged to 

$3,032/ton. 
326

these CAMx modeled values are not directly comparable to the CALPUFF modeled 

improvement from controls cited to by the commenter, due to differences in models, model 

inputs and metrics. The commenter does not provide a direct comparison between the modeled 

visibility benefit of controls in Montana and Oregon to the CALPUFF modeled visibility benefit 

of controls on the Independence facility and is incorrect in their assertion that the benefits from 

controls at Independence are the same type of improvement that was avoided in other EPA 

actions. Our CALPUFF modeling estimated that the required SO2 controls at Independence 

provide for improvements in visibility on any single Class I area ranging from 1.05 to 1.18 dv 

and the required NOx controls result in improvements ranging from 0.15 to 0.46 dv.634 These 

visibility benefits are much larger than the CALPUFF estimated visibility benefits of 0.18 dv for 

scrubbers at the Ash Grove facility in Montana or the 0.18 dv incremental benefit of NOx 

controls at PGE Boardman in Oregon cited to by the commenter. 

The commenter also implies that our evaluation of controls for Independence was different and 

more stringent compared to other states because, for other states, EPA determined that “a 

predicted impact on a Class I area of 0.5 deciview ("dv") was "relatively small" and that a source 

with a predicted impact on a Class I area at or below 0.5 dv should not be required to install 

additional emission controls to meet reasonable progress.” The inference from the commenter 

that a modeled impact of 0.5 dv is a “bright line” for reasonable progress decision has been 

improperly taken out of context. The actual passage that the commenter cites is: 

All sources with a Q/d ratio of less than 26.1 had visibility impacts of less than 

0.5 dv. The resultant average of the range is about 0.3 dv, which is more 

conservative than the 0.5 dv that was used in determining which sources would be 

subject-to-BART under the federal BART regulations. Since the threshold is more 

conservative than the subject-to-BART threshold, we believe that a Q/d value of 

20 is reasonable for determining which point sources the State should consider for 

the reasonable progress analysis. ... Since all of these sources have Q/d values 

below 20, EPA believes that their impacts on nearby Class I areas are expected to 

be less than 0.5 dv. Thus, EPA agrees with Oregon's conclusion that additional 

controls of non-BART point sources for reasonable progress purposes are not 

reasonable in the first planning period, because even though there are cost 

effective controls identified, visibility improvement is anticipated to be relatively 

small.635

We therefore disagree with the commenter that our determination of controls for Independence is 

inconsistent with previous EPA actions. 

Comment: EPA did not propose to require the Bailey and McClellan units to burn natural 

gas exclusively. [Stamper Report, page 47]. Ms. Stamper stated that visibility modeling for the 

Bailey and McClellan facilities reveals that the units have much lower impacts when burning 

natural gas compared to when burning fuel oil. The modeling for the Bailey unit did not predict 

any days with impacts greater than 0.5 dv when combusting natural gas and the modeling for the 

McClellan unit only shows three days in excess of 0.5 dc impacts over three years of modeling 

 

634 See Summary of Additional Modeling for Entergy Independence available in the docket for this action 635 77 FR 30464 
327

when burning natural gas. In contrast, the Bailey plant was modeled to have 6-12 days over the 

three years of meteorological data modeled with impacts greater than 0.5 dv at each Class I area 

when burning fuel oil. When burning fuel oil, the McClellan plant was modeled to have as high 

as 23 days over the three years of meteorological data modeled with 0.5 dv impacts or greater at 

Caney Creek, and 2-5 days greater than 0.5 dv at the other Class I areas modeled. Clearly, the 

combustion of fuel oil is the reason these units are subject to BART and should be EPA’s 

primary focus for BART. Ms. Stamper presented information that indicated that based on 2012 

and 2013 data, these plants have not burned much fuel oil. She concludes that switching to 

natural gas at the Bailey and McClellan units would provide the greatest improvement to 

visibility at the four Class I areas modeled. 

She questions why we did not propose to require the Bailey and McClellan units to burn natural 

gas exclusively. She notes it appears the main reason for not requiring the Bailey and McClellan 

units to only burn natural gas was because of AECC’s concern that during periods of natural gas 

curtailment and other emergencies, the units would not be able to burn fuel oil. 80 Fed. Reg. at 

18,951, 18,958. She acknowledges that we stated that the BART Guidelines provide that it is not 

EPA’s intent to direct sources to switch fuel forms. 80 Fed. Reg. at 18,953, 18,959. She 

concludes that if AECC is only concerned with the need to burn fuel oil during periods of natural 

gas curtailment and emergencies, which are rare events, that means the primary fuel for Bailey 

and McClellan is natural gas and it would not necessarily be considered fuel “switching” to 

require the Bailey and McClellan units that primarily burn natural gas to stop burning fuel oil 

altogether to meet BART. Natural gas constitutes the majority of the heat input to these boilers. 

Not only would the cessation of burning fuel oil satisfy SO2 BART, but it would also satisfy 

BART for PM. 

Ms. Stamper notes that in contrast, Entergy is willing to be restricted from burning fuel oil at the 

558 MW Lake Catherine Unit 4 to meet BART. 80 Fed. Reg. at 18,975-76. Entergy 

acknowledged that it might want to burn fuel oil in the future, and if that was the case, it would 

apply for a BART determination before doing so. Id. She questions why, if Entergy can take a 

fuel restriction for the much larger Lake Catherine plant, it can’t do the same at the Bailey and 

McClellan plants. EPA should impose such a restriction for these units, along with allowing the 

Bailey and McClellan plants to burn fuel oil if the units obtain a BART determination first. 

She concludes that the cessation of fuel oil burning at the Bailey and McClellan plants will 

reduce the plants’ operational expenses and will provide for the greatest improvement in 

visibility impairment caused by the Bailey and McClellan plants. Thus, EPA should require the 

cessation of burning fuel oil at the Bailey and McClellan plants to meet BART for both SO2 and 

PM. If AECC needs the ability to burn fuel oil in the future, EPA could allow the plant to do so, 

but only after obtaining a BART determination for fuel oil, consistent with what it has proposed 

as BART for Lake Catherine Unit 4. 80 Fed. Reg. at 19,002. 

Relatedly, Ms. Stamper supports our proposed determination that no additional NOX controls to 

meet BART at the Bailey and McClellan plants should be required, agreeing that the small 

visibility benefits do not justify the costs. 
328

Response: As Ms. Stamper notes, in our proposal we noted that the BART Guidelines provide 

that it is not our intent to direct subject-to-BART sources to switch fuel forms, such as from coal 

or fuel oil to gas (40 CFR part 51, Appendix Y, section IV.D.1). Whether or not gas is in fact the 

primary source of fuel for these facilities has no bearing on this. Therefore, we cannot require a 

facility to cease burning a particular type of fuel unless the facility itself offers to switch fuels or 

to voluntarily accept a restriction on burning a particular type of fuel as part of a BART 

determination. We can, however, require that these facilities include consideration of that fuel in 

their BART analyses, which is what we have done. In addition, Lake Catherine Unit 4 

voluntarily offered to accept a restriction on burning any fuel oil until BART determinations are 

made for the fuel oil firing scenario through either promulgation of a FIP and/or through EPA 

approval of a SIP revision. Therefore, we proposed to promulgate this restriction on Lake 

Catherine Unit 4 in our FIP. On the other hand, AECC Bailey and McClellan did not offer to 

accept a restriction on burning fuel oil and we therefore cannot impose such a restriction in our 

FIP. They did, however, offer to accept a restriction on the sulfur content of the fuel burned and 

our SO2 and PM BART determinations for these two facilities is based on this voluntary 

acceptance. Therefore, we disagree that our treatment of Lake Catherine Unit 4 is inconsistent 

with how we address AECC Bailey and McClellan in this FIP. 

Comment: EPA incorrectly calculated baseline emissions for White Bluff and 

Independence [S&L Entergy Report, page 2]. S&L objects to our approach of calculating a SO2

baseline for the White Bluff and Independence facilities, in which we eliminated the high and 

low annual emission values from 2009 to 2013, and averaged the remaining values. S&L 

presents the following table contrasting our approach to calculating SO2 baseline emissions with 

4 alternative approaches: 

Unit

EPA Approach 3 

Year Average* 

(tons)

3 Year 

Average 

2009-2011

(tons)

3 Year 

Average 

2010-2012

(tons)

3 Year 

Average 

2011-2013

(tons)

5 Year 

Average 

2009-2013

(tons)

White Bluff 1 15,816 15,745 15,395 15,826 15,939

White Bluff 2 16,697 15,582 15,217 16,697 16,034

Independence 1 14,269 14,160 15,486 14,707 14,258

Independence 2 15,511 14,673 15,196 16,035 15,407

S&L concludes that in all cases, there is at least one other approach that would result in lower 

baseline SO2 emissions. 

Response: We disagree with S&L that we erred in the procedure we used in estimating baseline 

emissions for our BART and reasonable progress scrubber upgrade cost analyses. The fact that 

S&L can construct alternative approaches to our baseline calculation that result in lower values 

does not invalidate our BART and reasonable progress approaches. As can be seen from an 

examination of S&L’s own data, regardless of whether a three year average or a five year 

average of a particular set of years is employed, the results are all similar. In fact, for three out 

of four units one of S&L’s alternative approaches would have produced higher SO2 baselines, 
329

which if used would have resulted in the cost analyses we performed being even more costeffective. 

Regarding the calculation of baseline emissions, the BART Guidelines state636: 

How do I calculate baseline emissions? 

1. 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. 

2. 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. 

Our Reasonable Progress Guidance notes the similarity between some of the reasonable progress 

factors and the BART factors contained in Section 51.308(e)(1)((ii)(A), and suggests that the 

BART Guidelines be consulted regarding cost, energy and non-air quality environmental 

impacts, and remaining useful life. We are therefore relying on our BART Guidelines for 

assistance in interpreting those reasonable progress factors, as applicable. One of these areas is 

in the calculation of the baseline emissions in determining cost effectiveness. 

We believe the procedure we used is in compliance with this language. We calculated our 

baseline SO2 emissions by first acquiring the 2009 to 2013 emissions as reported to us by the 

facilities in question.637 We eliminated the high and low values from the 2009-2013 emission to 

better address potential yearly variations in coal sulfur data, capacity usage, etc., and make the 

baseline more representative of plant operations. The difference between our baseline 

calculations and any of the alternative procedures S&L outlines is small and would not change 

our proposed conclusions for the White Bluff BART determinations and the Independence 

reasonable progress determinations. 

Comment: EPA incorrectly calculated the SO2 emissions reductions for White Bluff and 

Independence [S&L Entergy Report, page 3]. S&L states that SO2 emission reductions were 

estimated incorrectly by EPA for White Bluff and Independence. For each unit, EPA identified 

the maximum monthly SO2 emission rate in the baseline period of 2009 to 2013 and then 

calculated the percent reduction that would be required to achieve a controlled emission rate of 

0.06 lb/MMBtu. The percent reduction calculated was then multiplied by the baseline emission 

tons to determine the tons of SO2 reduced. This methodology is incorrect because it assumes the 

baseline emissions calculated in the previous section are based on maximum monthly averages, 

 

636 70 FR 39167. 637 http://ampd.epa.gov/ampd/ 
330

which are significantly higher than the annual averages actually used to calculate baseline 

emissions. The correct way to project the SO2 emission reduction is to multiply the outlet 

emission rate of 0.06 lb/MMBtu by the average heat input to the boiler (MMBtu/year) from the 

baseline period. For example, the average heat input to White Bluff 1 over the baseline period of 

2009 to 2013 was 55,829,551 MMBtu/year. Multiplying by 0.06 lb/MMBtu and then converting 

from pounds to tons results in estimated SO2 emission reductions of 14,264 tons per year, as 

compared to EPA’s 14,363. This method has been utilized by S&L on previous BART analyses, 

and has been accepted previously by EPA. S&L presents its calculations below. We added the 

percent difference column: 

Unit 

EPA Approach Using 

Maximum Monthly 

SO2 emission and 3-

Year Baseline 

(tons) 

Using 5-Year 

Average Heat 

Input and 

Baseline 

(tons) 

Percentage 

difference EPA 

vs. S&L 

(%) 

White Bluff 1 14,363 14,264 0.7

White Bluff 2 15,221 14,353 5.7

Independence 1 12,912 12,607 2.4

Independence 2 13,990 13,655 2.4

Response: We disagree with S&L that our methodology for calculating the SO2 tons reduced 

was incorrect for the White Bluff BART determinations and the Independence reasonable 

progress determinations. We began by selecting the monthly maximum emission rate from 2009 

to 2013 emissions data. We then had to test to ensure we did not assume a scrubber percentage 

reduction that exceeded the ability of the technology.638 We set this test at a 95% control 

efficiency, not to exceed a floor of 0.06 lbs/MMBtu. Because we condition emission limits on 

the basis of monthly data, we selected the maximum monthly emissions from 2009-2013 and 

applied the aforementioned test to this figure to establish our control efficiencies. This control 

efficiency was then applied to the SO2 baseline. Using S&L’s proposed methodology of simply 

multiplying 0.06 by the average heat input to the boiler would not have tested to ensure that 0.06 

lbs/MMBtu was actually achievable, and achievable on a monthly basis. We note there are more 

involved methods for ensuring the technology is capable of achieving the control emission rate 

on a monthly basis that involve a more detailed examination of the historical data, but we believe 

the one we selected is technically adequate. We also note that S&L’s method of using an annual 

average heat input introduces a mismatch in that annual data would be used to set an emission 

rate that is required to be met on a monthly basis. In any event, as can be seen from the data in 

the above table, the differences between our method and S&L’s method are small, with a 

maximum difference of less than 6%. This would not have changed our proposed determinations 

for either the White Bluff BART or Independence reasonable progress facilities. Lastly, as S&L 

has not provided any specific references to instances in which its methodology has been found to 

be acceptable, we cannot check its claim. 

 

638 See that tab, “Cost Effectiveness” in the file, “AR020.0093 White Bluff_R6 cost revisions2.xlsx,” in our docket. 
331

Comment: EPA’ proposed SO2 emission limit for White Bluff and Independence is too 

stringent [S&L Entergy Report, page 4]. S&L states that EPA’s proposal is too stringent to be 

achievable with the retrofit of an existing unit. A controlled SO2 limit of 0.06 lb/MMBtu is not a 

realistic or sustainable value to maintain on a long-term basis when considering the normal 

variation in operation that occurs at all coal-fueled facilities. As noted in the IPM dry FGD 

document, the 0.06 lb/MMBtu emission rate corresponds to the lowest available SO2 emission 

guarantees from dry FGD suppliers. Compliance with a vendor’s guarantee value is typically 

demonstrated during very short term testing conducted at ideal operating conditions. Vendor 

guarantees do not reflect controlled emission rates that may be achievable on a consistent longterm basis as the unit operation varies from design conditions. S&L then presents information 

that it states represents permit limits for dry FGD projects for Spray Dryer Absorber (SDA) 

projects similar to the dry FGD technology proposed for the White Bluff units, and Circulating 

Dry Scrubber (CDS) technology, which it states are more efficient dry scrubber systems because 

of increased flue gas and reagent contact through the use of a fluidized bed. As indicated, the 

lowest permit value for all units retrofitting dry FGD systems with averaging periods of 30 days 

was 0.09 lb/MMBtu. S&L concludes that EPA’s approach to estimating controlled SO2 emission 

rates is incorrect and based on a misunderstanding of the actual performance and operation of 

dry FGD technology. By using this approach, EPA is overestimating the tons of SO2 removed 

and thus overstating the cost-effectiveness of the retrofit FGD control systems. 

Response: As we indicate in our TSD, we accepted Entergy’s own use of the 0.06 lbs/MMBtu 

emission limit in its cost analysis, so we find it odd that S&L would now argue against that 

figure.639 Nevertheless, we address S&L’s objection. 

First, S&L does not provide the source of its information or even name the facilities it cites to in 

its comment, so we are unable to verify any of the information it presents. Second, there is no 

reason to conclude that a permit limit represents the maximum performance potential of any 

control device to limit emissions. Third, we do not believe a limit (or even a verified maximum 

control level) can be used as a basis for the comparison of the performance potential of one 

scrubber to another, because doing so does not consider the sulfur content of the coal. 

Our conclusion that the White Bluff and Independence dry scrubbers are capable of 95% control, 

not to exceed a floor of 0.06 lbs/MMBtu, is an often cited, widely accepted statement of the 

capability of dry scrubbers. S&L itself has published papers that cite to this capability.640 As we 

state in our TSD,641 we demonstrated in our Oklahoma FIP that this level of performance is 

achievable on a long term basis for this type of technology, considering the type of coal that is 

being burned.642 We therefore disagree with S&L that our proposed SO2 emission limit of 0.06 

 

639 See page 2 of appendix A to our TSD. 640 See for instance, Sargent & Lundy, Flue Gas Desulfurization Technology, Dry Lime vs. Wet Limestone FGD, 

Prepared for National Lime Association, March 2007, pp. 6, 14 (Table 4.1-1), 25 (Table 5.1-1), p. 41 (Table 7.2). 

See also S&L’s more recent study, White Bluff Station Units 1 And 2, Evaluation Of Wet Vs. Dry FGD 

Technologies, SL-009510, Rev. 3, October 28, 2008, Project 12303-004. Figure 2-1 

641 See footnote 7 in appendix A to our TSD. 642 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. See discussion beginning on page 93. 
332

lbs/MMBtu on a 30 BOD average is improper, or that it results in our overestimating the tons of 

SO2 removed and thus overstating the cost-effectiveness of the retrofit FGD control systems. 

Comment: Entergy states EPA incorrectly subtracted BOP costs for White Bluff [S&L 

Entergy Report, page 7]. S&L states that we mistakenly subtracted BOP costs because we 

believed the equipment to be included in Alstom’s scope. As described in S&L Report #012831, 

the reagent handling system, which feeds the dry FGD supplier’s reagent preparation system was 

not included in Alstom’s scope. The “Dry FGD Island” supplied by the dry FGD vendor includes 

lime day bins, slakers, slurry transfer tanks, slurry transfer pumps, slurry storage tanks, and 

slurry feed pumps. The BOP system includes the cost associated with the “Reagent Handling 

System,” which includes a rail delivery and unloading system for the lime, new rail spur, 

renovation of existing rail spur, delivery shed building, long-term storage silos, and a pneumatic 

conveying system to transfer the lime reagent from the long-term storage silos to the day bins, 

which are within the dry FGD vendor’s scope. 

We agree with EPA’s comment that including the NOx control equipment for Units 1 and 2 was 

an oversight and should not be incorporated into the Dry FGD estimates. 

EPA mistakenly subtracted a total of $1,754,000 from the BOP quote because they mistakenly 

believed that all of the ductwork to be in Alstom’s scope. The Dry FGD supplier’s scope only 

includes ductwork between the dry FGD, the baghouse, and the booster fans. The ductwork to 

supply the flue gas to the SDA and the ductwork from booster fans to the existing chimney are 

within the BOP scope. EPA mistakenly deleted a total of $255,000 to paint the chimney because 

it did not understand this line item. Due to lower temperatures and higher moisture of the flue 

gas, downwash from the gas is more likely to occur and can lead to acid attack of concrete on the 

chimney shell; therefore, the costs to apply an acid resistant coating to the top 50 feet of the 

existing chimney shell was included in the estimate. EPA mistakenly removed a total of 

$390,000 for costs associated with replacing and recalibrating the Continuous Emission 

Monitoring Systems (CEMS). The CEMS equipment reflected in Entergy’s BART analysis was 

required because the existing CEMS was not capable of measuring SO2 concentrations in the 

controlled range with Dry FGD technology. The costs included in the original estimate to cover 

replacement of the existing equipment with new equipment rated for the lower SO2

concentrations as well as the cost to calibrate and certify these monitors including conducting a 

Relative Accuracy Test Audit (RATA) test. Based on these comments, we have corrected EPA’s 

cost subtractions in Table 4. 

Excluded BOP Costs (Corrected, Total for Both Units) 

Equipment Material Labor Total

Total BOP Cost $45,561,000 $35,120,000 $80,863,000 $161,544,000

Eliminate U1 NOx Equipment $3,622,000 $1,600,000 $3,073,000 $8,295,000

Eliminate U2 NOx Equipment $3,622,000 $1,600,000 $3,073,000 $8,295,000

Total Eliminated Cost $7,244,000 $3,200,000 $6,146,000 $16,590,000

% BOP Items Reduced 15.90 9.11 7.60 N/A
333

EPA then adjusted additional cost items in the BOP estimate that were either percentages of the 

equipment, material, and labor costs or were related to equipment, material, and labor costs. EPA 

adjusted these items by applying the % reduction in cost of equipment, material and labor. Since 

EPA mistakenly removed cost items that should be included in the estimate, they over-estimated 

and misapplied percent reduction to the other items. In the table below, we correct EPA’s 

adjustments to remaining Entergy BOP costs by employing EPA’s methodology but reducing the 

percentage factors to the values indicated in Table 5. EPA excluded a total of $51,733,667 from 

the estimate, but Tables 4 and 5 show that only $20,724,543 was justified because NOx control 

equipment had been included. Because of EPA’s misconception as to the scope of work included 

in the BOP and Alstom estimates, they mistakenly concluded that costs were double-counted and 

removed $31,009,123 (total for both units) in costs that should be included. This resulted in EPA 

overstating the cost-effectiveness to retrofit dry FGD systems at White Bluff.
334

Adjustment to Remaining Entergy BOP Costs (Total for Both Units) 

EPA Cost TSD Reductions Corrected R

DESCRIPTION Equipment Material Labor Total Equipment Material MOBILIZE/DEMOBILIZE @ 1% OF LABOR $0 $0 $0 $0 $0 $0 MOBILIZE/DEMOBILIZE @ 1% OF LABOR $0 $0 $546,061 $546,061 $0 $0 MOBILIZE/DEMOBILIZE @ 1% OF LABOR $0 $0 $0 $0 $0 $0 COST DUE TO OVERTIME ‐ 5‐

10'S $0 $0 $7,970,183 $7,970,183 $0 $0 

COST DUE TO OVERTIME ‐ 5‐

10'S $0 $0 $0 $0 $0 $0 

PER DIEM ‐ @ $10 PER HOUR $0 $0 $7,888,659 $7,888,659 $0 $0 PER DIEM ‐ @ $10 PER HOUR $0 $0 $0 $0 $0 $0 SPARE PARTS @ 1% OF EQUIPMENT $0 $0 $0 $0 $0 $0 SPARE PARTS @ 1% OF EQUIPMENT $327,060 $0 $0 $327,060 $400,318 $0 FREIGHT @ 5% OF MATERIAL $0 $0 $0 $0 $0 $0 FREIGHT @ 5% OF MATERIAL $0 $1,413,404 $0 $1,413,404 $0 $1,596,000 GENERAL & ADMINISTRATIVE (G&A) @ 5% OF MATERIAL AND LABOR 

$0 $0 $0 $0 $0 $0 

GENERAL & ADMINISTRATIVE (G&A) @5% OFMATERIAL AND LABOR 

$0 $1,413,404 $2,417,281 $3,830,686 $0 $1,596,000 

GENERAL & ADMINISTRATIVE (G&A) $0 $0 $1,119,810 $1,119,810 $0 $0 
335

@5% OF MATERIAL AND LABOR PROFIT @ 10% OF MATERIAL AND LABOR $0 $0 $0 $0 $0 $0 PROFIT @ 10% OF MATERIAL AND LABOR $0 $2,826,809 $4,833,794 $7,660,602 $0 $3,192,000 PROFIT @ 10% OF MATERIAL AND LABOR $0 $0 $2,240,388 $2,240,388 $0 $0 NON CONTRACTOR INDIRECTS $0 $0 $0 $0 $0 $0 ENGINEERING ‐ BOP $0 $0 $7,579,481 $7,579,481 $0 $0 Totals $40,576,333 Reduction in Remaining BOP Costs $11,905,667 Excluded BOP Costs from Table 4 TOTAL BOP Reduction 
Response: In Appendix A to our TSD, we noted that Entergy used the Balance of Plant (BOP) 

costs from a 2008 S&L quote to supplement its adjusted 2009 Alstom quote in its 2013 SDA cost 

analysis for the White Bluff BART determination. However, due to a lack of documentation, it 

appeared that a number of items were either not appropriate for a SO2 scrubber, or were already 

covered as part of the Alstom quote. We removed those items from our proposed SDA cost 

analysis and invited Entergy to supply additional documentation to verify these costs. S&L now 

points to a S&L Report #012831, which contains a 2015 White Bluff SDA cost estimate, for that 

documentation. 

First, Entergy states that its 2015 SDA cost estimate is based on a 2013 Alstom quote. As with 

the 2009 Alstom quote it used to support its 2013 SDA cost analysis, Entergy does not provide 

this Alstom quote. Consequently, and as we discuss in a later response to comments, we have no 

way of verifying Entergy’s 2015 cost calculations. Second, Entergy points to a description of the 

reagent handling system in its 2015 SDA cost analysis (which depends on the 2013 Alstom 

quote), as proof that the updated reagent handling system was not included within the scope of 

the 2009 Alstom quote. Not having access to the 2009 and 2013 Alstom quotes, we have no 

reason to conclude that their scopes are the same. Therefore, we have no choice but to conclude 

that Entergy has not demonstrated that our removal of $20,542,000 in reagent preparation 

enclosure and reagent handling system BOP costs in its 2013 SDA cost analysis due to overlap 

with the 2009 Alstom quote was incorrect. 

Similarly, Entergy states that the $1,754,000 in ductwork we subtracted from the BOP quote was 

not in Alstom’s scope. Again, because we do not have the 2009 Alstom scope of work, we 

cannot verify this. Therefore, we have no choice but to conclude that Entergy has not 

demonstrated that our removal of $1,754,000 in ductwork BOP costs in its 2013 SDA cost 

analysis due to overlap with the 2009 Alstom quote was incorrect. 

Entergy states it agrees with our exclusion of NOX controls from its BOP costs. However, it 

does not discuss our exclusion of $1,166,000 for booster fans. We noted in our TSD that 

Alstom’s payment schedule indicated that booster fans were scheduled to be delivered in month 

22, and installed in month 30. We assume Entergy agrees with this exclusion. However, due to 

an oversight on our part this charge was never subtracted from the BOP costs. Because this 

change would have further improved the cost-effectiveness (lower $/ton) of the White Bluff and 

Independence SDA scrubbers, it adds to the conservativeness of our calculation. 

We also accept Entergy’s explanation that a $390,000 charge to replace and recalibrate the 

CEMS was justified because the existing system was not capable of measuring SO2 in the range 

that would result from the SDA control. Again, due to an oversight on our part, this charge was 

never subtracted from Entergy’s BOP costs, so no change is needed, and it adds to the 

conservativeness of our calculation. 

We accept Entergy’s explanation that $255,000 to paint the chimney was justified to mitigate the 

potential effects of acid corrosion of the chimney due to flue gas downwash as a result of the 

SDA installation. We have revised our cost analysis to include these costs,643 which are 

 

643 See the file, “White Bluff_R6 cost revisions2-revised.xlsx” in our docket. 
337

inconsequential to our final determination that dry scrubbers are cost-effective for the White 

Bluff facility. 

Comment: Entergy objects to the escalation calculation in our White Bluff scrubber cost 

analysis. [S&L Entergy Report, page 11]. Entergy states that it agrees with our assertion that the 

application of escalation is allowed by the CCM. However, EPA’s method of using Chemical 

Engineering Plant Cost Indices (CEPCI) to escalate costs to the year 2013 resulted in severely 

underestimating the costs associated with escalation. CEPCI are sometimes used to estimate 

escalation by multiplying base costs by the ratio of the index for the year costs are to be escalated 

to the index for the year in which the costs were originally generated. For example, EPA used 

CEPCI from 2009 (521.9) and 2013 (550.8) to escalate the FGD costs from a 2009 basis to a 

2013 basis. Thus, EPA applied the following formula, 550.8/521.9*$247,856,184 to obtain an 

estimated 2013 FGD cost of $261,581,119 for both units. Rather than estimating escalation of 

Alstom’s pricing from 2010, S&L (on behalf of Entergy) requested updated FGD pricing from 

Alstom in 2013. We agree with a reference cited in the CCM and authored by EPA which states, 

“At best [cost indices] provide a cloudy mirror...there is no substitute for current price 

information obtained from suppliers of those goods and services.” Nothing illustrates EPA’s 

conclusion that cost indices are not to be substituted for supplier information better than 

comparing EPA’s escalation rate to the actual escalation rate indicated in Alstom’s budgetary 

quotations as shown below: 

Alstom Quotation Comparison (Total for Both Units) 

Parameter EPA Vendor Quotation

FGD Cost 2009 $247,856,184 $247,856,184 

FGD Cost 2013 $261,581,119 $297,904,000 

Average Escalation 1.36% 4.7% per year

As shown above, EPA underestimated escalation significantly, resulting in underestimating the 

2013 dry FGD costs by $36,322,881 (total for both units). In fact, EPA applied CEPCI indices in 

several instances from 2008 that de-escalated costs, resulting in lower costs in 2013 as compared 

to 2008. We note specifically that EPA’s cost calculations ignored the updated 2012 direct 

annual costs provided by Entergy, and instead included the 2008 costs. 

Response: For our proposal, we used Entergy’s revised BART analysis for the White Bluff 

facility, as submitted by it on October 14, 2013, because at the time it was the latest information 

available to us.644 In our proposal, our control cost analysis used the same basic information that 

Entergy previously presented to us in 2013. As we describe in Appendix A of our TSD, Entergy 

stated that it received two different SDA cost estimates for White Bluff: an early 2009 Sargent 

and Lundy (S&L) estimate with a total contractor cost of $291,930,000, and a December 2009 

 

644 See section 2.1 of Appendix A to our TSD. 
338

estimate from Alstom of $247,856,184. Entergy stated that unlike the S&L quote, the Alstom 

estimate was not itemized and only included a total price. Entergy used the 2009 Alstom price 

quote as the basis for its BART cost analysis for White Bluff by increasing it by 10%, and 

scaling the S&L itemized cost to match the 110% adjusted Alstom total price. As we describe 

elsewhere in our response to comments, we critiqued certain aspects of Entergy’s use of this 

information. For example, Entergy mistakenly included certain NOx controls in its 2013 cost 

analysis. It also failed to document certain BOP costs that we had no choice but to exclude. 

However, between the 2009 S&L and the 2009 Alstom quotes, and with these corrections, we 

were able to construct a reasonable control cost estimate. In so doing, we used the same 2009 

Alstom total, and the Alstom payment schedule for its quote, as the actual Alstom quote was not 

supplied and no better information was presented by Entergy. Because Entergy’s 2013 cost 

estimate used 2009 Alstom pricing, we had no choice but to escalate it to 2013—more recent 

information was not available. 

Entergy did not provide its updated 2015 cost estimate, which it references in its comment, until 

after our proposal. Entergy’s 2015 report uses updated 2013 pricing from Alstom as its basis. 

As we discuss in a previous comment, we reviewed this 2015 cost analysis and found that it 

presents problems that prevent us from using it, primarily because it is undocumented. 

In this comment, Entergy attempts to use its newly submitted 2015 cost analysis to discredit the 

escalation technique we employed to adjust its previous 2013 cost analysis. It does so without 

even presenting the 2013 Alstom quote on which it states the 2015 cost estimate relies. Thus, we 

have no basis to conclude that the costs Entergy presents in its first table above even cover the 

same scope of work. This is an important consideration and a different scope can cause a 

significant difference in cost. Entergy itself noted this when it used a revised BOP estimate to 

adjust its 2009 Alstom quote because the scope had changed. Even different cost estimates 

received in the same year can result in significantly different totals. For instance, as we also note 

in our TSD, Entergy stated that it received two different SDA cost estimates for White Bluff: an 

early 2009 S&L estimate with a total contractor cost of $291,930,000, and a December 2009 

estimate from Alstom of $247,856,184.645 We note that the difference between these two quotes 

is $44,073,816, which is more than Entergy calculates in its first table above is the difference 

between our escalated 2013 quote ($261,581,119) and its revised 2015 cost estimate, based on 

the its 2013 Alstom quote ($297,904,000). 

Escalation from one year’s cost basis to another646 is not only allowed by the Control Cost 

Manual, it is a required procedure in order to allow an apples-to-apples comparison between 

control cost analyses. Our use of the Chemical Engineering Plant Cost Index (CEPCI) is a 

standard method of escalating costs,647 and one that power companies have also used on 

numerous occasions. Entergy itself has used the CEPCI in an attempt to escalate its costs. 

Unfortunately, as we explain in our TSD, Entergy did so incorrectly and we corrected that 

error.648 We certainly prefer revised vendor quotations to escalating older cost estimates. 

 

645 See section 2.1 of Appendix A to our TSD. 646 Note that escalation during the construction period is disallowed, however, because that is not a part of the 

overnight method. 

647 Vatavuk, William, M., “Updating the CE Plant Cost Index,” Chemical Engineering, January 2002. 648 See section 2.6 of Appendix A to our TSD. 
339

However, when revised vendor quotes are not available as in this case, we have no choice but to 

escalate older cost estimates in order to bring the cost basis to the present. 

Entergy also apparently objects to any escalation technique that results in a reduction in a future 

year’s cost basis, holding it up as evidence of our error.649 This is a fundamental 

misunderstanding of escalation. Although most cost escalation does result in an increase in the 

cost basis, occasionally the opposite occurs. This is mainly due to broad economic factors that 

influence the cost of raw materials, supply and demand, vendor profit, etc. This can be 

illustrated by the following table of the CEPCI Composite Index: 

Year 

Composite 

CE Index 

Percent 

Change 

over 

Previous 

Year 

2004 444.2

2005 468.2 5.40%

2006 499.6 6.71%

2007 525.4 5.16%

2008 575.4 9.52%

2009 521.9 -9.30%

2010 550.8 5.54%

2011 585.7 6.34%

2012 584.6 -0.19%

2013 567.3 -2.96%

2014 576.1 1.55%

As the above table indicates, although the Composite CE index usually increases from year to 

year, it does occasionally decrease, due to various broad economic factors, such as it did from 

2008 to 2009, and again from 2011 to 2013. Thus, Entergy’s objection over the “de-escalation” 

of cost from 2008 to 2013 is entirely misplaced. In other words, escalation is escalation: most of 

the time it is positive but sometimes it is negative. We therefore do not agree with Entergy’s 

objections to our escalation technique. We take up the issue of Entergy’s 2015 cost estimate in 

our response to another comment. 

Entergy states that our cost calculations ignored the updated 2012 direct annual costs provided 

by Entergy, and instead included the 2008 costs. As noted in the first sentence of our response to 

this comment, we were constrained to use Entergy’s revised BART analysis for the White Bluff 

facility, as submitted by Entergy on October 14, 2013 (hereafter referred to as the “2013 SDA 

Cost Analysis”). These costs employed a 2008 vintage total direct annual cost, as we indicate in 

Appendix A of our TSD.650 Regarding its direct annual costs, Entergy further states, “The cost 

estimates were scaled to reflect 2012 dollars.”651 We therefore agree that Entergy did provide 

 

649 Entergy’s reference to de-escalated costs. 650 See section 2.7 of Appendix A to our TSD. 651 Revised Bart Five Factor Analysis, White Bluff Steam Electric Station, Redfield, Arkansas (AFIN 35-00110). 
340

what it stated was 2012 vintage direct annual costs. We did not use those costs because Entergy 

incorrectly escalated them from 2008, as we discuss above. For instance, Entergy presented its 

2008 direct annual cost as $7,901,369. It then “scaled” them to 2012 using a 2008 CEPCI index 

of 530.7 and a 2012 CEPCI index of 593.6, resulting in a 2012 value of $8,837,861. As we 

discuss in Appendix A of our TSD, Entergy appears to have incorrectly used the January 

monthly CEPCI value for each year instead of the annual CEPCI value. Entergy should have 

used a 2008 CEPCI index of 575.4 and a 2012 CEPCI index of 584.6, resulting in a 2012 

escalated direct annual cost of $8,027,703 ($7,901,369 X 584.6/575.4). As we also discuss in 

our TSD, because we were conducting our analysis later, we escalated Entergy’s 2008 direct 

annual cost to 2013, resulting in a value of $7,790,140 ($7,901,369 X 567.3/575.4). These facts 

appear to have been ignored by Entergy in its comment. We therefore have no choice but to 

disagree with Entergy’s comment concerning our not using its 2012 direct annual cost. 

Comment: Entergy summarizes its objections to our escalation calculations in our White 

Bluff scrubber cost analysis. [S&L Entergy Report, page 12]. Continuing from its previous 

comment on escalation, Entergy presents the table below. Entergy states it summarizes how 

EPA incorrectly estimated escalation in its analysis for White Bluff Unit 1 and corrects that by 

applying an average escalation rate of 4.7% to match the Alstom quotation. Entergy states that 

information from Alstom showed their pricing escalated nearly equivalently for 

equipment/material (~4.8%) and for installation (~4.6%). Since the difference was negligible 

Entergy applied the average 4.7% in the revised costs shown in the table below. EPA’s 

underestimation of cost escalation carried through their analysis and resulted in an incorrect 

reduction in the cost estimate of over $42 million per unit. 

Entergy’s Summary of EPA’s Escalation Errors (Per Unit) 

Item Entergy EPA (2013)

Corrected 

Costs 

Including 

Escalation 

(2013)

Escalation 

Costs 

Omitted by 

EPA

Total Contractor Costs* (2010) $156,974,274 $161,676,662 $180,164,213 $18,487,550

Contingency (2010) $20,875,711 $21,501,073 $23,959,697 $2,458,624

Balance of Plant (2008)** $102,085,500 $75,145,724 $115,401,842 $13,316,342

Balance of Plant Indirect Costs (2012) *** $9,768,175 $0 $10,227,279 $1,494,175

Misc Contract Labor (2012) $4,583,719 $0 $4,799,154 $215,435

Entergy Internal Costs (2012) $20,076,644 $0 $21,020,246 $943,602

Capital suspense (2012) $8,348,276 $0 $8,740,645 $392,369

Total Capital Investment (TCI) $258,323,459 $319,525,752

Direct Annual Costs (2008) $7,901,369 $7,790,140 $9,941,130 $2,150,990

Indirect Annual Costs 

 Overhead (2008) $2,572,707 $2,536,491 $3,236,859 $700,368

 Administrative Charges @ 2% of TCI $5,166,469 $6,390,515 $1,224,046

 Property Tax @ 1% of TCI $2,583,235 $3,195,258 $612,023

 

Appendix A, SDA cost analysis, June 2013, Appendix A. 
341

 Insurance @ 1% of TCI $2,583,235 $3,195,258 $612,023

Total Indirect Annual Costs $12,869,429 $16,017,889

Total Escalation Costs Underestimated by EPA $42,607,547

* This item reflects the updated dry FGD pricing received in 2013 

** As EPA did, this item subtracts the excluded BOP costs discussed in Section 3.3 before 

applying the escalation 

*** In the Cost TSD, EPA incorrectly used the 2008 BOP Indirect Costs from the Revised Bart 

Five Factor Analysis, 

SDA Cost analysis rather than the 2012 BOP Indirect Costs as identified. The differential 

between the 2008 and 2012 

BOP Indirect Costs ($1,035,071) was included in the column for Escalation Costs Omitted by 

EPA. 

Response: Entergy’s comments concerning its 2015 cost estimate present several problems that 

prevent us from being able to properly review them. We discuss these problems below and we 

treat each of the items in the table it presents below: 

 As we state in our response to the previous comment, Entergy does not supply the 2013 

Alstom quote which it references in its comments. In fact, Entergy has not supplied any 

information that indicates the scope of the Alstom quote. As we stated in our TSD, 

Entergy’s similar failure to supply the 2009 Alstom quote and its scope was a key 

problem in our observations that Entergy’s 2013 SDA cost analysis contained 

inappropriate cost items and double counting. 

 Entergy states that it applied an escalation rate of 4.7% per year in the revised costs 

shown in the table it presents. We are able to duplicate its figures for the Total 

Contractor Costs and the Contingency (2010) using following formula: 

Pn = P(1+i)n

Where: 

Pn = Future Cost 

P = Present Cost 

i = Annual percentage increase 

n = Difference between base year and future year. Ex: 2013 - 2010 = 3 

However, as we discuss in our response to another comment, we must reject Entergy’s 

escalation technique. Entergy does not provide either the 2009 or the 2013 Alstom 

quotes on which it states its cost estimates rely. Thus, we have no basis to conclude that 

the costs Entergy presents in its 4.7% escalation calculation even cover the same scope of 

work. We find it perplexing that Entergy did not just supply the 2013 Alstom quote, 

eliminate the usual disallowed cost items (AFUDC, escalation during construction, 

owner’s costs, etc.) and provide an updated cost analysis. Instead, its comments seem to 
342

be focused on attempting to shore up an older 2013 cost analysis it has apparently already 

replaced. 

 We have addressed Entergy’s objections to our BOP cost revisions in a previous 

comment and have concluded that $255,000 to paint the chimney was a justified BOP 

costs. We will add those costs back into our revised White Bluff cost analysis. 

 Entergy provides a footnote to its BOP Indirect Costs (2012): “In the Cost TSD, EPA 

incorrectly used the 2008 BOP Indirect Costs from the Revised Bart Five Factor 

Analysis, SDA Cost analysis rather than the 2012 BOP Indirect Costs as identified. The 

differential between the 2008 and 2012 BOP Indirect Costs ($1,035,071) was included in 

the column for Escalation Costs Omitted by EPA.” First, we did not incorrectly use a 

2008 BOP Indirect Cost in lieu of one for 2012. Rather we excluded Entergy’s 2008 

BOP indirect costs because they were undocumented and appeared to be captured 

elsewhere in its costs. As we explain in our TSD:652

In addition to the BOP costs that we discuss above, Entergy also includes a BOP 

indirect cost of $8,733,104 per unit. Regarding this, Entergy states:653 

BOP indirect costs are costs associated with engineering, 

construction management, startup and commissioning and are 

estimates provided by the contractor. Miscellaneous contractor 

labor is inclusive of legal support, owner’s insurance, S&L 

engineering costs, and Entergy’s environmental permitting costs. 

No documentation of these costs was provided. We agree that BOP indirect costs 

are certainly legitimate under the Control Cost Manual. However, the BOP quote 

discussed above already contains Item 360, entitled “Non Contractor Indirects,” 

under which is the subcategory Item 360.8 entitled “Engineering BOP,” for 

$9,855,000. Furthermore, we note that the BOP quote also contains two 

additional charges for “General and Administration” (Items 307.5 and 307.6) for a 

total of $6,355,000. These General and Administrative and Non Contractor 

Indirects categories are broad in scope, unspecific in description, and 

undocumented. Together, they total $16,210,000. Lacking any documentation to 

the contrary, we must assume any work associated with the support or 

administration of the BOP items are contained within these cost items. We 

therefore propose to delete the additional BOP indirect cost item from the SDA 

costs. 

Entergy does not address this lack of documentation and simply adds the costs back in. 

Second, despite Entergy’s note, $1,035,071 does not appear to be included in “the 

column for Escalation Costs Omitted by EPA.” Rather, a figure of $1,494,175 appears, 

 

652 See section 2.5.2 of Appendix A to our TSD. 653 Original footnote from our Cost TSD: “Entergy Response to EPA Region 6 comments on Entergy White Bluff 

draft BART Report 06/10/13. Page 9.” 
343

which is not explained. Third, we suspect that Entergy may be confusing this cost item 

with its Direct Annual Costs. As we discuss in our response to another comment, we did 

not use those costs because Entergy incorrectly escalated them from 2008. We instead 

properly escalated the 2008 Direct Annual Costs to 2013. Consequently, we cannot 

accept Entergy’s revision to our BOP Indirect Costs. 

 

 Entergy has added in the figures shown in its above table for Misc. Contract Labor, Entergy 

Internal Costs (2012), and Capital suspense. We assume Entergy disagrees with our exclusion of 

these costs,654 and we invited it to provide documentation to the contrary. However, we cannot 

locate any documentation of these costs in its comments. Consequently, we cannot accept 

Entergy’ corrections to our cost analysis. 

 In our response to a previous comment, we have discussed our rejection of Entergy’s revision to 

our Direct Annual Cost calculation due to errors in Entergy’s escalation. 

 For the same reasons we must reject Entergy’s escalation of its Total Contractor Costs and 

Contingency, we must similarly reject its escalation of its Overhead (2008) cost. 

 Because the Administrative Charges, Property Tax, and Insurance are all percentages of the TCI, 

they will be adjusted in our final cost analysis after we make the adjustments to the BOP costs 

we discuss above. 

Comment: Entergy objects to our adjustment of O&M costs due to coal sulfur content in 

our White Bluff cost analysis. [S&L Entergy Report, page 14]. EPA states that an uncontrolled 

SO2 emission rate of 2.0 lb/MMBtu at White Bluff is “far in excess of sulfur level of the coals it 

has historically burned,” and concludes, “[t]hus Entergy has costed SO2 scrubber systems for the 

White Bluff facility that are overdesigned compared to its historical needs.” Based on this 

conclusion, EPA adjusts the capital and O&M costs using a design sulfur level selected by EPA. 

While we agree with EPA that direct O&M costs be revised to 0.68 lb/MMBtu, this sulfur level 

is completely inadequate for the Dry FGD equipment design basis. 

EPA correctly assumes that the 2.0 lb/MMBtu design basis was to preserve fuel flexibility, but 

their conclusions that, “either (1) this higher cost be balanced against its greater SO2 reduction 

potential, or (2) that the scrubber system’s capability and cost be adjusted down to match the 

facility’s historical emissions,” are without basis and inconsistent with BART guidelines. 

The SO2 emission reduction calculation depends upon the baseline emissions, baseline heat 

input, and the required outlet emission rate (see Section 2.2 of our comments). SO2 emission 

reduction does not depend on the fuel sulfur levels selected for FGD system design, neither the 

BART guidelines nor the CCM address evaluating potential future SO2 reduction based on 

design fuels as part of the BART analysis or cost estimating methodology. Therefore, EPA’s first 

 

654 See Section 2.5 of Appendix A to our TSD. 
344

conclusion that the higher costs be balanced against greater SO2 reduction potential is 

inconsistent with BART requirements and has no basis. 

Although the BART guidelines and the CCM both account for the development of a design basis, 

there are no specific requirements that air pollution control design be tied to historical operating 

trends. Therefore, EPA’s second conclusion that capital costs must be adjusted to match 

historical emissions is arbitrary and without basis. 

Based on its erroneous conclusions, EPA selected a maximum monthly fuel sulfur level of 0.68 

lb/MMBtu as the design basis used to estimate the capital costs. Entergy presents the figure 

below to illustrate why the use of White Bluff’s maximum monthly fuel sulfur level is 

completely insufficient. 

The ability to reduce SO2 emissions depends critically upon the amount of reagent, or lime that 

can be added to the FGD system. With a 0.68 lb/MMBtu design basis, the reagent preparation 

and delivery equipment would be inadequately sized to add lime when sulfur levels increase 

beyond that level. As shown in Figure 1, EPA’s design basis would result in emissions above the 

proposed emission rate for almost half of the operating time. This design approach would 

require limiting fuel sulfur levels to below 0.68 lb/MMBtu to ensure continuous compliance. If 

this is the approach EPA is intending, then the cost analysis would need to be revised to 

incorporate significant additional costs associated with fuel purchasing limitations. We did not 

include any additional O&M costs associated with fuel limitations because we believe EPA 
345

selected the design basis due to a lack of experience rather than intending to place enforceable 

limits on fuel purchasing at White Bluff station. 

Entergy states that while it believes that the 2008 design basis of 2.0 lb/MMBtu was appropriate 

at that time based on the potential to fire fuels with higher sulfur levels, based on more recent 

information, Entergy now believes that they will not purchase fuels with sulfur levels higher than 

1.2 lb/MMBtu. The operating data shown in the above figure confirms that 1.2 lb/MMBtu would 

result in a design basis that would ensure continued compliance with EPA’s proposed FIP 

emission rates. Therefore, we have provided a revised cost estimate based on 1.2 lb/MMBtu. To 

illustrate the small difference in capital costs associated with the revised design basis (1.2 

lb/MMBtu versus 0.68 lb/MMBtu), S&L has included a sensitivity analysis in S&L Report 

#012831. As discussed previously, we agree that it is appropriate to base direct O&M cost 

estimates on 0.68 lb/MMBtu fuel sulfur levels to represent average operational costs. However, 

EPA’s adjustment factor of 0.5823 applied to direct O&M costs severely underestimated these 

costs. In agreement with EPA’s sulfur basis, S&L developed O&M costs for the 0.68 lb/MMBtu 

operating case in S&L Report #012831 based on site specific consumption rate estimates and 

unit costs. Our report estimated O&M costs including direct variable and fixed O&M costs to be 

a total of $10,166,000 per unit in the first year. By comparison, EPA’s calculation scales direct 

O&M costs of $7,790,140 by 0.5823, resulting in direct O&M costs of $4,536,199 per unit being 

included in its cost-effectiveness calculation. This methodology underestimated direct O&M 

costs by $5,629,801 per unit. 

In addition, EPA applied the same O&M factor of 0.5823 to the indirect annual costs, including 

overhead, administrative charges, property tax and insurance, all of which depend on capital 

cost. Therefore, assuming EPA’s capital cost scaling methodology for capital cost is correct 

(which we do not believe is the case), then EPA should have applied the 0.9584 factor used to 

correct capital costs to the indirect annual costs. EPA’s methodology underestimated indirect 

O&M costs by $4,840,192 per unit. 

Response: Entergy states that we correctly assumed that the 2.0 lb/MMBtu design basis was to 

preserve fuel flexibility, but our conclusions that, “either (1) this higher cost be balanced against 

its greater SO2 reduction potential, or (2) that the scrubber system’s capability and cost be 

adjusted down to match the facility’s historical emissions,” are without basis and inconsistent 

with the BART guidelines. We thoroughly explained our reasoning for this statement in our 

TSD,655 including appropriate references to the BART Guidelines. As we noted in our TSD, 

“either (1) this higher cost be balanced against its greater SO2 reduction potential, or (2) that the 

scrubber system’s capability and cost be adjusted down to match the facility’s historical 

emissions.” Entergy chose to do neither and costed a scrubber capable of treating a coal far in 

excess of what it historically burned, but continued to base the capabilities of the scrubber on its 

historical SO2 baseline. Thus, either Entergy’s annualized cost (the “$”) or its tons reduced (the 

“tons”) in the $/ton cost effectiveness calculation are misrepresented. Our approach was to 

recalculate Entergy’s scrubber cost to bring its scrubber design in line with the historical coal it 

has burned. Entergy could have taken the alternative approach of calculating a new baseline on 

the basis of its higher sulfur design coal, but it chose not to. We see nothing in Entergy’s 

comments that would cause us to conclude our reasoning was in error. We therefore disagree 

 

655 See Section 3.1 of Appendix A to our TSD. 
346

with Entergy’s assertion that our conclusion that capital costs must be adjusted to match 

historical emissions is arbitrary and without basis.

Entergy also states, “While we agree with EPA that direct O&M costs be revised to 0.68 

lb/MMBtu, this sulfur level is completely inadequate for the Dry FGD equipment design basis.” 

Entergy then presents the above SO2 emissions plot as evidence of our error. We do not believe 

this statement accurately represents our approach. We did not choose 0.68 lbs/MMBtu as a 

design basis for Entergy’s scrubber systems. As we explain in our TSD,656 we ran two IPM 

SDA cost model cases: one using Entergy’s 2.0 lb/MMBtu design value, and one using a design 

value of 0.68 lbs/MMBtu. We then constructed a table that included a ratio of certain capital and 

operating costs of the 0.68 lbs/MMBtu case to the 2.0 lbs/MMBtu case. We then applied these 

ratios to Entergy’s own cost analysis (with the corrections we discuss in our responses to 

Entergy’s comments). That table is reproduced below: 

0.68 lb/MMBtu 

Case 

2.0 lb/MMBtu 

Case 

Ratio of 

Selected 0.68 lb 

/MMBtu to 

2.0 lb/MMBtu 

Costs 

Capital, engineering and 

construction cost $328,680,000 $342,944,000 0.9584

Capital Recovery factor 0.0806 0.0806

Annualized capital costs $26,487,139 $27,636,624

Variable operating costs $8,581,744 $17,332,840 0.5823 Fixed operating costs $3,812,705 $3,953,100

Total annualized costs $38,881,588 $48,922,564

Furthermore, Entergy does not state so, but it appears that its SO2 plot contains hourly SO2

emissions data. Thus, Entergy appears to argue that its scrubber systems must be designed to 

treat every hourly fluctuation in SO2, which is borne out by its statement, “[EPA’s] design 

approach would require limiting fuel sulfur levels to below 0.68 lb/MMBtu to ensure continuous 

compliance.” This is incorrect, as we did not propose that the White Bluff facility meet an 

hourly SO2 limit. Our proposed limit is a 30 Boiler Operating Day (BOD) average. Thus, 

individual hourly SO2 emissions are inconsequential. In fact, even daily SO2 averages are 

relatively unimportant, since they constitute only one day out of a 30 day average. Below we 

present a plot of the White Bluff Unit 1 daily emissions for the last three years:657

 

656 See Sections 3.2 and 4 of Appendix A to our TSD. 657 See the file, White Bluff Daily and Hourly Emissions.xlsx” in our docket.
347

The above is a plot of the average daily averages and the running 30 BOD average for White 

Bluff Unit 1. A plot of White Bluff Unit 2 yields similar results. This plot illustrates two things: 

First, the maximum daily averages are significantly below the maximum hourly averages 

Entergy presents in its plot. Thus the individual hourly data fluctuations Entergy presents are 

inconsequential. Second, the running 30 BOD average indicates that our decision to fix the 

mismatch between Entergy’s scrubber costs and its historical SO2 baseline on the basis of a SO2

inlet of 0.68 lbs/MMBtu is reasonable. 

Entergy states that it has determined its assumption that a 2.0 lb/MMBtu scrubber inlet was in 

error and a 1.2 lb/MMBtu inlet assumption is now appropriate. As we demonstrated, the primary 

change to Entergy’s SDA cost analysis is to the variable operating costs, which reflects the need 

for less reagent to treat the low sulfur coal Entergy has traditionally burned, and the associated 

equipment to unload, transfer, and store that reagent. In apparent agreement with our basic 

approach, Entergy states it is also appropriate to base direct O&M cost estimates on 0.68 

lb/MMBtu fuel sulfur levels to represent average operational costs. Entergy proceeds by 

recalculating its variable O&M costs in Report #012831,658 using a 0.68 lbs/MMBtu inlet. The 

results of that calculation are presented below: 

S&L Report #012831 Variable O&M Rates and First Year Costs, per Unit 

Units

Design

0.68 lb SO2/MMBtu

Dry FGD System Parameters

 

658 S&L Report #012831. Page 23. 
348

Reagent Consumption lb/hr 7,000

Byproduct Waste Production lb/hr 16,000

Aux Power Consumption kW 11,000

High Quality Water Consumption gpm 75

Low Quality Water Consumption gpm 775

First Year Variable O&M Costs (@CF)

Reagent Cost $/year $2,888,000

Byproduct Waste Disposal Cost $/year $380,000

Aux Power Cost $/year $3,027,000

Water Cost $/year $214,000

Bag and Cage Replacement Cost $/year $372,000

Total First Year Variable O&M Cost $/year $6,881,000

Entergy then calculates its fixed O&M costs using a 0.68 lbs/MMBtu inlet. The results of that 

calculation are presented below: 

First Year Fixed O&M Costs for Dry FGD, per Unit 

First Year Fixed O&M Costs Units 

Design 

0.68 lb SO2/MMBtu 

Operating Labor $/year $1,660,000

Maintenance Material $/year $975,000

Maintenance Labor $/year $650,000

Total First Year Fixed O&M Cost $/year $3,285,000

S&L notes that its variable and fixed O&M costs are “first year costs” that are provided in 2015 

dollars. As can be seen from a comparison of S&L’s variable and fixed O&M costs for a 0.68 

lb/MMBtu inlet to those we have calculated, our variable and fixed O&M costs are actually 

greater, at $8,581,744, and $3,812,705, respectively. Were we to adopt Entergy’s variable and 

fixed O&M costs, our White Bluff and Independence SDA cost-effectiveness calculations would 

become even more attractive (lower $/ton). 

Entergy then states that to illustrate the small difference in capital costs associated with the 

revised design basis (1.2 lb/MMBtu versus 0.68 lb/MMBtu), it has included a sensitivity analysis 

in S&L Report #012831. Entergy concedes there is a, “small difference in capital costs 

associated with the revised design basis (1.2 lb/MMBtu versus 0.68 lb/MMBtu) ....” As can be 

seen from the table we present above, this conclusion is borne out by our own figures which 

indicate there is a small difference in capital costs to even the 2.0 lbs/MMBtu case: The capital, 

engineering and construction costs, which cover the fundamental design parameter of a 

scrubber—gas flow rate, were only changed by less than 5%. Thus, Entergy’s assertion that our 

cost analysis improperly designed the White Bluff scrubber system is without merit. 
349

As we discuss in our TSD,659 we applied the capital, engineering and construction cost ratio of 

0.9584 to our annualized capital costs, and the variable and fixed O&M ratio of 0.5823 to our 

total direct and indirect costs. We did this in order to adjust Entergy’s White Bluff SDA costs to 

account for the sulfur level of the fuel it historically burned. Entergy argues that our O&M 

factor of 0.5823 should not have been applied to the indirect annual costs, including overhead, 

administrative charges, property tax and insurance, all of which depend on capital cost. 

Therefore, argues Entergy, even if our capital cost scaling methodology for capital cost is correct 

(which it does not believe is the case), then we should have applied the 0.9584 factor used to 

correct capital costs to the indirect annual costs. We agree with Entergy that it would have been 

more appropriate to apply the 0.9584 factor to the indirect annual costs and will incorporate that 

correction in our final SDA cost analysis for the White Bluff and Independence facilities, which 

we discuss in more detail in our response to other comments. However, this correction is 

relatively minor. 

Comment: Entergy objects to our noting certain aspects of conservativeness in our White 

Bluff cost analysis. [S&L Entergy Report, page 17]. EPA lists two assumptions it believes are 

conservative in its Cost TSD. In one assumption, EPA noted that amortization from the 2008 

S&L cost analysis was 40 years, but they lowered the remaining useful life to 30 years, which 

increases the cost-effectiveness. EPA’s estimate is not conservative with regard to equipment life 

because, as EPA states, they, “typically assume a 30 year equipment life for scrubbers,” and the 

2008 amortization value from S&L was not intended to be used to conduct the BART analysis. 

Furthermore, as discussed in Section 3.9, the actual remaining life of these units is far below 

what EPA assumed. 

In the second assumption, EPA concludes that two absorber vessels are not required and, thus, a 

7% cost savings that could have been realized was not applied. We do not believe EPA is 

qualified to design dry FGD systems, and therefore not qualified to evaluate the number of 

vessels that are suitable for White Bluff. Dry FGD systems of this type have not been applied to 

units of this size, and the dry FGD supplier quoted three absorber vessels for this application 

based on their expertise. EPA cites no reference where fewer absorber vessels have been 

installed for a unit with an identical design basis, and therefore its assertion that two absorber 

vessels is adequate is arbitrary and without basis. 

Response: We disagree with Entergy regarding our conclusion that a 30 year equipment life is a 

conservative value for the White Bluff scrubbers. Entergy’s own contractor, S&L used a 40 year 

scrubber life in its cost analysis.660 This indicates that Entergy concluded that was an appropriate 

value when S&L performed that cost analysis. The fact that we typically assume a 30 year 

equipment life in BART determinations has no bearing on this. Our use of a 30 year life reflects 

our conclusion that a 30 year equipment life is a minimum value that can be applied to any 

scrubber cost analysis, not secured by a federally enforceable document for a shorter life. Just as 

we occasionally adopt a shorter equipment life (given an appropriate federally enforceable 

 

659 See discussion beginning on page 14 of Appendix A to our TSD. 660 See our discussion of this in Section 4.1 of Appendix A to our TSD. 
350

document), we are free to assume a longer equipment life, given the appropriate evidence that 

life is justified. This is clearly the case in this instance. 

Regarding Entergy’s second objection, again, we drew upon information that Entergy itself had 

supplied.661 As we discussed in our TSD, S&L noted in its 2008 cost analysis that an Alstom 

cost estimate assumed that its SDA FGD system is based on the use of three absorber modules. 

Alstom had proposed two modules on units with a similar gas flow in the past, which would 

result in an approximately 7% savings in capital cost. In fact, S&L itself presents Figure 3-3, 

“Impact of Two Dry FGD Absorber Modules on Levelized Cost,” documenting this potential 

cost savings.662 Thus, our expertise in designing scrubber systems is not an issue, as we were 

relying on statements made by Entergy’s own contractor. Furthermore, we are aware of industry 

publications that conclude that single SDA modules can be fitted to EGUs of 450-500 MW in 

size, one of which is again from Entergy’s own contractor.663 Consequently, White Bluff’s 

nominal 850 MW units may well only require two SDA modules, and we believe our statement 

that this represents a conservative point in our cost analysis remains correct. 

Comment: Entergy objects to our assumption of a 30 year operating life in our White Bluff 

cost analysis. [S&L Entergy Report, page 17]. EPA states, “With regard to consideration of the 

remaining useful life of the units, we are not aware of any enforceable shutdown date for the 

Entergy White Bluff Plant, nor did Entergy’s evaluation indicate any future planned shutdown.” 

Therefore, EPA utilized 30-years as the remaining useful life in its cost-effectiveness 

calculations. As stated in Entergy’s comments to the proposed rule, Entergy proposes to cease 

coal-firing at the White Bluff units between 2027 and 2028. The proposed rule requires that the 

FGD controls on White Bluff be operational 5 years after the effective date of the rule. Assuming 

the effective date of the final rule is one year after the comment period closes, then the White 

Bluff FGD’s will need to be operating by July of 2021. Based on the coal-cessation dates of 

White Bluff Units 1 and 2, the remaining useful life of these FGD systems is therefore between 6 

and 7 years, instead of 30 years used in EPA’s analysis. 

Response: As we discussed in the section of our TSD that Entergy quotes, in order for us to 

incorporate a shorter scrubber life into the White Bluff SDA cost analysis, Entergy must be 

subject to a federally enforceable document to shut down the units in question. We have not 

received such an enforceable document. We discuss this issue in more detail elsewhere in this 

document. 

Comment: Entergy objects to our scrubber cost analysis for Independence. [S&L Entergy 

Report, page 19]. EPA included Entergy’s Independence Plant in its RPG analysis based on 

annual emissions from the facility. It is beyond the scope of S&L’s comments to address the 

 

661 Ibid. 662 White Bluff Station Units 1 And 2, Evaluation of Wet Vs. Dry FGD Technologies, SL-009510, Rev. 3, October 

28, 2008. See page 3-21. 

663 See for instance: Wet & Dry Scrubbers, Paul Farber, Sargent & Lundy, LLC, Chicago, IL. 2012 Mega 

Symposium. Page 10: Maximum SDA absorber size is listed as 450 MW. 

GEA Niro Spray Drying Absorption, page 4: “SDA is suitable for power plants of all sizes, requiring only a single 

absorber and a single rotary atomizer per 500 MWe. 
351

basis upon which EPA decided to include Independence in its RPG analysis for Caney Creek and 

Upper Buffalo. Instead, our comments focus on the inconsistencies and errors included in EPA’s 

RPG analysis for the Independence station. 

In EPA’s RPG analysis for SO2 Controls, EPA concluded that the units at White Bluff and 

Independence Stations are similar enough to apply “the total annualized dry FGD and wet FGD 

costs [they] developed for the White Bluff units to the Independence units.” EPA then calculates 

the cost-effectiveness to retrofit FGD systems at Independence by adjusting the White Bluff cost 

effectiveness calculations to account for the differences in SO2 emissions at Independence. This 

approach is flawed for several reasons. First, this approach includes all of the errors in EPA’s 

cost-effectiveness analysis for White Bluff as described in the preceding sections, including 

errors in calculating baseline emissions, errors in calculating emission reductions, and errors 

associated with estimating annualized costs. Second, applying the White Bluff annualized costs 

to Independence is inconsistent with EPA’s RPG guidance which requires cost estimates based 

on design parameters be developed for air pollution control systems. 

To determine whether air pollution controls would be required at Independence Units 1 & 2 to 

meet the Reasonable Progress Goals at Caney Creek and Upper Buffalo, EPA conducted an RPG 

four factor analysis. The four factor analysis is described in EPA’s RPG Guidance Document, 

and includes an evaluation of: (a) costs of compliance; (b) time necessary for compliance; (c) 

energy and non-air impacts; and (d) the remaining useful life of the source. Regarding the first 

factor listed, costs of compliance, EPA suggests that, for stationary sources, the following steps 

be performed: 

a) Identify the emissions units to be controlled; 

b) Identify the design parameters for emission controls; and 

c) Develop cost estimates based upon those design parameters 

EPA did not perform steps b and c of the RPG compliance cost evaluation. Rather, EPA relied 

upon an EIA database comparison as well as an aerial photo comparison of the two units to 

justify applying the White Bluff FGD costs to Independence. The EIA information does not 

contain any information that would be used to set the design basis for either FGD system; 

therefore it cannot be used to conclude the FGD system design at Independence would be 

identical to White Bluff. Furthermore, EPA’s use of aerial photos to indicate visual similarities 

between White Bluff and Independence ignores many site-specific factors that cannot be 

captured in a Google Earth image downloaded from the internet. Some of the site-specific 

factors that EPA did not account for by using this approach and which could result in different 

costs to retrofit FGD technology at Independence as compared to White Bluff include: 

 EPA proposes the same timeline for compliance for White Bluff and Independence which 

will add significant labor costs due to the amount of skilled labor that would be required 

to construct four FGD systems in the same time period; 

 EPA did not review plant operating data, such as flue gas temperatures, which affect flue 

gas volume, potentially requiring different equipment sizing for Independence; 
352

 EPA did not review operating and maintenance practices at Independence, which could 

result in different O&M costs; 

 EPA did not assess differences in underground utility interferences that could potentially 

change the equipment arrangement at Independence; 

 EPA did not conduct subsurface geotechnical investigations to determine differences in 

soil conditions or distances to reach bedrock that would impact foundation design or 

seismic design requirements; 

 EPA did not assess other seismic design requirements such as seismic risk or magnitude 

of potential earthquakes to determine steel design differences that may be required; and 

 EPA did not assess differences in wind loads which could impact foundation and 

structural steel design. 

In its guidance document, EPA states, “[f]or additional guidance on applying the cost of 

compliance factor to stationary sources, you may wish to consult the BART guidelines.” We note 

that, for EPA’s RPG analysis for Independence, EPA did not revisit any of the steps required as 

part of a BART analysis; therefore, EPA ignored other lower cost technologies or methodologies 

to reduce SO2 emissions at Independence station. EPA’s inherent assumption is that BART-level 

SO2 reductions are required at Independence to meet the RPGs, but it does not adequately 

support that assumption. EPA modeled visibility impacts of SO2 reductions assuming FGD 

systems would be retrofitted at Independence, but they failed to conduct modeling using any 

other technology or methodology that could provide more cost-effective SO2 reductions. 

Finally, EPA also states in its RPG guidance document that for, “individual, large scale sources, 

simple cost effectiveness estimates based on a dollar-per-ton calculation may not be as 

meaningful as a dollar-per-deciview calculation.” EPA’s CENRAP modeling showed that the 

cumulative benefit of installing all of the controls proposed in the FIP would result in visibility 

benefits at Caney Creek of only 0.21 dv and at Upper Buffalo of only 0.19 dv. Considering that 

Independence represents only approximately 36% of the SO2 point source emissions and 29% of 

the point source NOX emissions in Arkansas, Entergy estimated the visibility improvement due 

to retrofitting FGD systems at Independence would be approximately 0.08 dv at Caney Creek 

and 0.07 dv at Upper Buffalo. Although we do not support EPA’s use of the White Bluff cost 

estimates for Independence, we applied the White Bluff costs to retrofit dry FGD and the 

estimated visibility improvement due to retrofitting dry FGD systems at Independence to 

estimate dollar-per-deciview as suggested in EPA’s RPG guidance document. The table below 

shows that retrofitting dry FGD systems at Independence is clearly not cost effective when 

considering the insignificant visibility improvements. 

Dollar-Per-Deciview Reduction for Dry FGD at Independence 

Class I Area Caney Creek Upper Buffalo

Estimated Visibility Improvement 0.08 0.07

Revised Annualized Costs $106,765,022 $106,765,022

$/Δdv $1,334,562,775 $1,525,214,600

Note: Entergy’s revised annual costs in the above table refer to its 2015 S&L cost analysis. 
353

Response: Entergy presents a number of reasons why it believes our scrubber cost analysis for 

the Independence facility is flawed. In other responses to comments, we address Entergy’s 

objections to our White Bluff cost analysis, so they will not be repeated here. Entergy alleges 

that we failed to properly identify the design parameters for emission controls; and develop cost 

estimates based upon those design parameters. Entergy lists a number of areas it believes 

differentiates the White Bluff and Independence facilities to the extent these differences would 

impact the Independence scrubber cost analysis. 

We agree that there are likely differences between the two facilities that would have some minor 

impact on the scrubber cost analyses. As we discuss in our TSD: 

The White Bluff and Independence facilities are sister facilities. According to 

EIA,664 the boilers were manufactured by Combustion Engineering with inservice dates of 1980 and 1981 for White Bluff, and 1983 and 1985 for 

Independence. All four units are tangentially firing boilers having nameplate 

capacities of 900 MW and similar gross ratings. As we indicate above, all four 

units burn coal from the Powder River Basin of Wyoming with similar 

characteristics. All four units employ cold side electrostatic precipitators for 

particulate collection. Other pertinent characteristics are similar. 

We further presented satellite photographs to demonstrate that the layout of these facilities are 

extremely similar. We consequently expect that the differences Entergy describes in its 

comments result in minor differences in cost. We are not obligated to conduct such a detailed 

cost analysis that would include these relatively minor differences. As we have discussed in our 

response to another comment, as the Control Cost Manual explains, the sole input required for 

making an “order of magnitude” estimate is “the control system’s capacity (often measured by 

the maximum volumetric flow rate of the gas passing through the system).” Such an estimate, 

for example, could be obtained from the cost reported in dollars per megawatt ($/MW) or dollars 

per million BTUs fired ($/MMBtu), metrics that are widely reported in the literature. The 

Control Cost Manual indicates that “the costs and estimating methodology in this Manual are 

directed toward the “study” estimate with a nominal accuracy of +/-30% percent.” This is the 

long-standing rule of thumb for cost estimate accuracy used by the EPA for regulatory cost 

effectiveness analyses. 

We see nothing in Entergy’s comments that would suggest that the differences between these 

two facilities are so significant they would impact this required level of accuracy. Indeed, 

Entergy does not attempt to estimate the capital costs of these differences. 

We address the $/dv metric in our responses to other comments. We see no reason in the 

Regional Haze Rule, despite the fact that we evaluated the Independence facility in our proposed 

Arkansas FIP under the reasonable progress section of the Regional Haze Rule, to deviate from 

our view of the dollar per deciview metric here. 

 

664 See “EIA Consolidated Data_WB and IND_Y2012.xlsx.” 
354

Comment: Entergy summarizes its objections to our White Bluff scrubber cost analysis. 

[S&L Entergy Report, page 22]. Entergy presents the table below which it states shows how the 

approach EPA took understated the annualized cost of the control systems and the adjustments 

S&L made to correct EPA’s errors. 

Adjustments to EPA’s Annualized Cost for a Single Unit at White Bluff

Item

Total Capital Investment 

($)

Annualized Cost 

($/year)

EPA FIP $247,537,295 $31,981,230

Corrected BOP Cost Exclusions $263,041,857 $33,230,898

Corrected Owner’s Cost Exclusions $304,783,600 $36,595,282

Corrected Escalation $347,391,147 $40,029,450

Corrected Operating Costs $347,391,147 $50,499,444

Remaining Useful Lifetime Adjustment $347,391,147 $86,975,068 to 

$95,381,830

2015 Estimate (S&L Report #012831) * $536,185,000 $109,681,936 to 

$122,657,613

Differential from EPA FIP* + $99,853,852 + $54,993,838 to

$63,400,600

* Entergy proposes to cease to use coal at White Bluff 1 and 2 between 2027 and 2028; 

therefore, the annualized costs are shown as a range based on a remaining useful life of 6 or 7 

years. 

In addition, the table below shows how EPA’s approach overstated the tons of SO2 that would be 

removed by its FIP-imposed dry FGD and the adjustments S&L made to correct EPA’s mistakes. 

Adjustments to EPA’s SO2 Emission Reductions

Item 

White Bluff 1 

(tons) 

White Bluff 2 

(tons) 

EPA FIP 14,363 15,221 

Corrected Baseline Emission 

Calculation 14,474 14,617 

Corrected SO2 Emission 

Reduction Calculation 14,264 14,353 

Differential from EPA FIP -99 -868 

EPA’s errors resulted in severely overstating the cost-effectiveness to retrofit dry FGD systems 

at White Bluff 1 and 2 (and then by extension in its reasonable progress analysis for 

Independence 1 and 2). The table below summarizes how EPA’s errors systematically 

underestimated cost and overstated the cost-effectiveness to install these dry FGD systems. As 

the table below indicates when the errors are corrected and updated costs incorporated, 

retrofitting dry FGD systems at these units is clearly not cost-effective. 
355

Summary Cost-Effectiveness Impacts

Item

White Bluff 1 

($/ton)

White Bluff 2 

($/ton)

EPA’s Cost Effectiveness $2,227 $2,101

Corrected Baseline Emission Calculation $2,210 $2,188

Corrected SO2 Emission Reduction Calculation $2,242 $2,228

Corrected BOP Cost Exclusions $2,330 $2,315

Corrected Owner’s Cost Exclusions $2,566 $2,550

Corrected Escalation $2,806 $2,789

Corrected Operating Cost $3,540 $3,518

Corrected Remaining Useful Life * $6,097 to $6,687 $6,060 to $6,646

2015 Estimate (S&L Report #012831) * $7,689 to $8,599 $7,642 to $8,546

Differential from EPA FIP + $5,462 to $6,372 + $5,541 to $6,445

* Entergy proposes to cease to use coal at White Bluff Units 1 and 2 between 2027 and 2028; 

therefore, the cost effectiveness values are shown as a range based on a remaining useful life of 6 

or 7 years. 

With respect to EPA’s RPG analysis for SO2 controls, EPA did not follow its own guidance 

document when conducting its four factor analysis of Independence. EPA failed to consider 

lower cost options that could reduce SO2 emissions at Independence and instead concluded that 

BART-level controls were required to meet RPG. EPA did not prepare cost estimates based on 

design parameters for FGD systems retrofit at Independence, as required by their RPG guidance 

document. EPA did not conduct a dollar-per-deciview analysis, as recommended in its RPG 

document for these analyses, to demonstrate the benefit of retrofitting dry FGD at Independence 

accounting for visibility benefits. When applying annualized costs to projected visibility 

improvements the result is over $1.3 billion/Δdv for Caney Creek and over $1.5 billion/Δdv for 

Upper Buffalo, which is clearly not cost effective. 

Response: With the exception of the 2015 estimate that is based on the S&L Report #012831, 

which we address in another comment, we have discussed each of the cost items Entergy 

presents above in our responses to other comments. Below we summarize our determinations: 

 Regarding the Corrected Baseline Emission Calculation and the Corrected SO2 Emission 

Reduction Calculation, we determined that Entergy’s recalculations were not justified. 

 Regarding the Corrected BOP Exclusions, we have determined that Entergy has provided 

an adequate explanation or otherwise demonstrated that a $255,000 charge to paint the 

chimney was justified. We add that charge back into our BOP costs correction in our 

final SDA cost analysis for the White Bluff and Independence facilities. 

 Regarding the Corrected Owner’s Cost Exclusions and Corrected Escalation, we 

determined that Entergy’s recalculations were not justified. 

 Regarding the Corrected Operating Cost, we agreed with Entergy that it would have been 

more appropriate to apply the 0.9584 factor to the indirect annual costs and will 
356

incorporate that correction in our final SDA cost analysis for the White Bluff and 

Independence facilities. 

 Regarding the Corrected Remaining Useful Life, we determined that Entergy has not 

supplied an enforceable commitment to shut down the units in question by the dates it 

assumes in its calculation. 

The corrections to our White Bluff and Independence SDA cost estimates are contained in the 

file, “White Bluff_R6 cost revisions2-revised.xlsx,” which appears in our docket. Below we 

summarize those corrections: 

Unit 

Proposed Cost-Effectiveness 

($/ton) 

Final Cost-Effectiveness 

($/ton) 

White Bluff Unit 1 $2,227 $2,565

White Bluff Unit 2 $2,101 $2,421

Independence Unit 1 $2,477 $2,853

Independence Unit 2 $2,286 $2,634

We find that these revised cost-effectiveness calculations do not change our proposed findings 

for BART and reasonable progress for these units. 

In addition, we have examined the effect of adding back in a number of the BOP and other costs 

we excluded (based on these costs being either disallowed by the Control Cost Manual, or having 

lacked documentation from Entergy). This exercise also appears in the file “White Bluff_R6 

cost revisions2-revised.xlsx.” These costs include: 

 BOP Costs associated with the reagent prep enclosure and the reagent handling system, 

totaling $21,229,000. 

 BOP Costs associated with the flue gas system ductwork, totaling $1,754,000. 

 BOP indirect costs of $8,474,666 (escalated to 2013). 

 Miscellaneous contract labor costs of $4,448,074 (escalated to 2013). 

 Entergy internal costs of $19,482,518 (escalated to 2013). 

 Capital suspense costs of $8,101,226 (escalated to 2013). 

Unit 

Alternate Cost-Effectiveness 

($/ton) 

White Bluff Unit 1 $3,013 

White Bluff Unit 2 $2,843 

Independence Unit 1 $3,351 

Independence Unit 2 $3,093 

We continue to believe that these costs are either disallowed by the Control Cost Manual, or are 

properly disallowed because they lack documentation from Entergy. We have presented this 

information to indicate that these costs have a relatively minor effect on the final cost 

effectiveness. Although our final decision regarding BART and reasonable progress for the 

White Bluff and Independence units does not rest upon these cost-effectiveness determinations, 
357

had we included these costs in our cost-effectiveness calculations, we would have reached the 

same conclusions regarding BART and reasonable progress for these units. 

Comment: Entergy refers to a revised 2015 cost estimate [S&L SL-012831, July 14, 2015]. 

In various places in its comments,665 Entergy refers to “S&L Report #012831.” We are unsure of 

the exact significance of this report, as it appears it is primarily used by Entergy to support its 

previous 2013 Cost estimate. We have addressed these issues in our responses to other 

comments. However, in other comments, Entergy states, “At the least, EPA must re-evaluate the 

costs of controls based upon the 2015 S&L FGD Cost Estimate, attached as Exhibit B to EAI’s 

comments.” Based on this general comment, we will review Entergy’s revised 2015 report. Our 

observations follow: 

 As we note in the response to one of our comments, Entergy states that its 2015 SDA cost 

estimate is based on a 2013 Alstom quote. As with the 2009 Alstom quote it used to 

support its 2013 SDA cost analysis, Entergy does not provide this Alstom quote. 

Consequently, we have no way of verifying Entergy’s 2015 cost calculations. 

 The S&L Report #012831 uses an Engineering, Procurement and Construction (EPC) 

contract, which S&L describes as follows:666

[T]he EPC Contractor takes full responsibility for the equipment and work 

supplied by each of its subcontractors. With this approach the Owner 

takes on less risk in the overall management and coordination of the 

project. However, shifting this risk to the EPC Contractor increases the 

total price for the EPC contract; “Whilst there are... numerous advantages 

to using an EPC contract, there are some disadvantages. These include the 

fact that it can result in a higher contract price than alternative contractual 

structures. This higher price is a result of a number of factors not least of 

which is the allocation of almost all the construction risk to the 

contractor.” The additional cost due to an EPC contracting approach is 

represented in our cost estimate as an EPC Risk Fee 

 This is in contrast to Entergy’s previous cost estimates, and the majority of control cost 

analyses conducted for other projects we have reviewed, which did not use EPC contacts, 

and the corresponding higher fees associated with EPC contracts. For instance, the S&L 

2015 SDA cost analysis includes an EPC Engineering Services Fee of $23,000,000, for 

which S&L provides no documentation, except to state, “The EPC engineering services 

was estimated based on recent projects with similar scopes and schedules.” The S&L 

2015 SDA cost analysis also includes an EPC risk fee of 10% of the total EPC project 

cost, or $60,898,000. Regarding that, S&L states, “[t]he EPC Risk Fee is a premium 

included by the contractor which accounts for the additional coordination and 

 

665 Review Of EPA’s Cost Analysis For Arkansas Regional Haze Proposed Federal Implementation Plan, SL012913, Final July 14, 2015. 

666 S&L Report #012831, page 1. 
358

management of the project as well as the additional risk assumed by the contractor.”667 

The additional cost of an EPC contract for the White Bluff SDA cost analysis makes it 

difficult to compare the cost-effectiveness ($/ton) to other non-EPC SDA cost estimates. 

 In addition to the EPC risk fee, S&L includes a contingency of $111,145,700, which 

represents 18.3% of the total EPC project cost. First, we question the use of such a high 

contingency for a mature technology like SDA, in combination with an EPC risk fee. 

Both the EPC risk fee and the contingency appear to be basic assessments of risk. 

Because S&L does not describe the scope of the EPC risk fee, we cannot determine if 

these charges overlap. However, the Control Cost Manual defines contingency in the 

context of separating it from a retrofit factor:668

Retrofit factors should be reserved for those items directly related to the 

demolition, fabrication, and installation of the control system. A 

contingency factor should be reserved (and applied to) only those items 

that could incur a reasonable but unanticipated increase but are not 

directly related to the demolition, fabrication, and installation of the 

system. For example, a hundred year flood may postpone delivery of 

materials, but their arrival at the job site is not a problem unique to a 

retrofit situation. 

S&L states this contingency was based on cost qualitative risk assessment (QRA) using 

Palisade Corporation's @RISK software. The contingency risk inputs appear to be based 

on assigned probabilities of various events with the possibility of causing the cost of the 

project to increase. No documentation was provided for any of these risks. It appears 

that a number of the inputs to this calculation are outside of the above definition of 

contingency. In addition, a number of the risk items appear to be related to issues that are 

separate from the actual construction or are otherwise risks to Entergy itself, and not S&L 

as the EPC contractor. For instance, one assessed risk is a delay in receiving the air 

permit. This does not appear to be a risk that S&L should assume since it is separate 

from the actual construction of the scrubber system. Another questionable S&L risk is 

the cost of capital increasing over the life of the project. S&L states it assumed our 

Control Cost Manual value of 7%, causing us to assume this risk deals with the 

possibility of the interest used in calculating the annualized capital cost. Since Entergy is 

required to use a 7% interest rate in this calculation under the Control Cost Manual, 

assessing the risk of it increasing is inappropriate. S&L appears to assess both the risks 

due to a longer compliance timeframe and a shorter compliance timeframe. Since we are 

not changing our proposed compliance timeframe from what we proposed, the latter is 

plainly not appropriate 

 The S&L 2015 SDA cost estimate includes a number of cost items disallowed under the 

Control Cost Manual’s overnight methodology. These include an AFUDC charge of 

$134,949,000; an owner’s cost of $58,546,000; an escalation during construction charge 

 

667 S&L Report #012831, page 18. 668 Control Cost Manual, Chapter 2, Section 2.5.4.2. 
359

of $83,034,100; and a separate escalation charge of $2,273,000 on owner’s costs, third 

party services, and contingency. 

As described above, we have noted many problems with Entergy’s 2015 White Bluff SDA cost 

analysis, as contained in S&L Report #012831. We therefore cannot accept it. In instances like 

this, we often present our own cost analysis, eliminating the disallowed costs and making other 

necessary corrections in order to bring the flawed cost analysis in conformance with the Control 

Cost Manual. However, in this instance, we would still be left with many unanswered questions 

concerning the EPC fees and the contingency. As a consequence, we cannot present such an 

analysis, and we must fall back on our previous White Bluff SDA cost analysis, with the 

corrections we describe in our responses to other comments. 

6.b. Cost vs. Visibility Benefit 

Comment: EPA should have evaluated the visibility improvement of controls for BART 

and Reasonable Progress on a $/dv basis. [Nucor Steel-Arkansas and Nucor-Yamato Steel 

Company (0163) p. 36-37] Nucor stated that EPA’s BART and Reasonable Progress 

determinations are inconsistent with other EPA BART determinations, which would have been 

evident if EPA had evaluated visibility improvements on a $/dv basis. When evaluated on that 

basis, the costs of EPA's Proposed FIP are as follows: 

Flint Creek $65,769,250/yr./dv 

White Bluff 1 $39,337,306/yr./dv 

White Bluff 2 $42,415,424/yr./dv 

Independence 1 $64,219,337/yr./dv 

Independence 2 $52,171,663/yr./dv 

Although EPA claims that the costs of its BART and Reasonable Progress determinations are 

justified here, in its BART determination for the Corette facility in Montana, EPA found that 

costs/dv of $30,477,272 for DSI and $50,308,300 for a semi-dry scrubber were excessive (even 

though EPA determined that both of those controls were “cost-effective” on a $/ton SO2 basis), 

and determined that BART constituted the low-sulfur coal already in use at that facility.669

Existing use of low-sulfur coal as BART also avoids the additional energy costs and water/land 

impacts of scrubber technology. This is an important factor that EPA failed to consider in its 

analysis of the energy and nonair quality environmental impacts of compliance that must be 

considered. All $/dv calculations for White Bluff, Flint Creek and Independence based on EPA’s 

adjusted costs are higher than the $/dv ratio that EPA determined was not justified in its Corette 

BART determination. EPA has failed to explain why it did not consider use of low-sulfur coal as 

 

669 See Exhibit 18 to Nucor’s comments, Comparison of Scrubber Cost- Effectiveness in Dollars per Deciview, 

attached hereto as Exhibit 18. See 77 Fed.Reg. 23998 (April 20, 2012), for the explanation of EPA's BART 

determination for Corette. 
360

BART for the Arkansas facilities, and further has failed to explain how its determinations in the 

Proposed FIP are justified, consistent with its Corette BART determination. 

Comment: EPA is not required to consider the dollar per deciview cost of controls, and in 

any event, the dollar per deciview cost of controls EPA is proposing to require is within the 

range of other approved controls. [Sierra Club et. al., p. 47-48, (0042)] Sierra Club et. al. 

stated that Nucor contends that EPA has failed to consider the cost of the proposed controls 

relative to their visibility improvement using the dollar per deciview metric. Furthermore, had 

EPA done so, Nucor contends that the dollar per deciview values for the proposed controls are 

unreasonably high. Neither of Nucor’s arguments has merit. 

First, EPA is not required to assess BART or reasonable progress controls based on the dollar per 

deciview metric. Tellingly, Nucor fails to cite to any legal authority for the proposition that EPA 

must consider the dollar per deciview value of controls. For BART determinations, the statute 

instructs EPA to consider the costs of compliance and the expected visibility improvement from 

controls. 42 U.S.C. § 7491(g)(2). The statute does not direct EPA to consider costs and visibility 

improvement using any particular method. 

The BART Guidelines recommend considering costs in part by considering the costeffectiveness of controls, measured as the annualized control costs divided by the tons of 

pollutants removed. 40 C.F.R. pt. 51 App. Y § (IV)(4)(b)-(c). The Guidelines state that EPA 

should consider visibility improvement by using dispersion modeling to calculate the 

improvement from controls. Id. § (IV)(5). The BART Guidelines mention the dollar per deciview 

metric in only one place, as an example of one method among many for displaying the costs of 

compliance. Id. § (E)(1). Put simply, the BART Guidelines do not require the use of a dollar per 

deciview metric.

Setting aside that EPA is not required to consider the dollar per deciview value of controls, the 

dollar per deciview values for the proposed controls are comparable to other controls EPA has 

approved, given that EPA has approved SO2 controls that cost as much as approximately $50 

million per deciview. See Stamper Report, Ex. 6. As described elsewhere in the Sierra Club et. 

al.’s comments and in the Stamper Report, the costs and visibility benefits of the proposed 

controls are comparable to the costs and benefits of other control determinations EPA has 

approved or made itself. See pages 11-12 of the Sierra Club et. al.’s comments; and Stamper 

Report at 11-13. 

Response: We disagree with Nucor that we erred in not using the $/dv metric. We agree with 

the Sierra Club that we are not required to consider the $/dv metric, but take no position on its 

statement that the dollar per deciview values for the proposed controls are comparable to other 

controls we have previously approved. We disagree that the $/dv metric is more meaningful than 

our use of the $/ton metric in conjunction with our consideration of the visibility benefit from the 
361

installation of controls.670 As we note in our Oklahoma FIP:671

[T]he BART Guidelines require that cost effectiveness be calculated in terms of 

annualized dollars per ton of pollutant removed, or $/ton.672 OG&E provided a 

$/deciview analysis for its units and comparable BART determination performed 

by us. In our analysis for our BART FIP for OG&E and AEP/PSO, we did not 

evaluate $/deciview. We explain that the BART Guidelines list the $/deciview 

metric as an optional cost effectiveness measure that can be employed along with 

the required $/ton metric for use in a BART evaluation. The metric can be useful 

in comparing control strategies or as additional information in the BART 

determination process; however, due to the complexity of the technical issues 

surrounding regional haze, we have never recommended the use of this metric as 

a cutpoint in making BART determinations. We note that to use the $/deciview 

metric as the main determining factor would most likely require the development 

of thresholds of acceptable costs per deciview of improvement for BART 

determinations for both single and multiple Class I analyses. We have not 

developed such thresholds for use in BART determination made by us. As 

OG&E acknowledges, EPA did not use this metric as part of its proposed BART 

determinations for either the Four Corners Power Plant FIP in AZ, or the San Juan 

Generating Station FIP in NM. Generally speaking, while the metric can be 

useful if thoughtfully applied, we view the use of the $/deciview metric as 

suggesting a level of precision in the calculation of visibility impacts that is not 

justified in many cases. While we did not use a $/deciview metric, we did, 

however, consider the visibility benefits and costs of control together, as noted 

above by weighing the costs in light of the predicted visibility improvement. 

Our decision was reviewed and upheld in Oklahoma v. EPA, 723 F.3d 1201 by the Tenth Circuit 

which ruled: 

Oklahoma first suggests EPA should not have rejected the visibility analysis it 

conducted in the SIP, which used the dollar-per-deciview method. This argument 

is misguided. The EPA rejected the SIP because of the flawed cost estimates. 

When promulgating its own implementation plan, it did not need to use the same 

metric as Oklahoma. The guidelines merely permit the BART-determining 

 

670 Visibility is one of the five statutory factors we must consider in a BART analysis under CAA section 

169A(g)(2) and 40 CFR 51.308(e)(1)(ii)(A). In our reasonable progress analysis, alongside the four statutory factors, 

we also considered the visibility improvement of controls. Although visibility is not one of the four mandatory 

factors explicitly listed for consideration under CAA section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), states or 

EPA have the option of considering the projected visibility benefits of controls in determining if the controls are 

necessary to make reasonable progress. 

671 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, pdf 116. 

672 70 FR 39167.
362

authority to use dollar per deciview as an optional method of evaluating cost 

effectiveness. See 40 C.F.R. pt. 51 app. Y(IV)(E)(1).673 

And in the final rule, the EPA explained why it did not use the dollar-perdeciview metric used by Oklahoma. "Generally speaking, while the metric can be 

useful if thoughtfully applied, we view the use of the $/deciview metric as 

suggesting a level of precision in the calculation of visibility impacts that is not 

justified in many cases." 76 Fed.Reg. at 81,747. The EPA has never mandated the 

use of this metric, and has not developed "thresholds of acceptable costs per 

deciview improvement." Id. While the federal land managers have developed 

thresholds, these thresholds were apparently developed without input from the 

EPA and without notice-and-comment review. EPA Br. at 54 n. 13. In light of 

this, we do not find it arbitrary or capricious that the EPA chose not to use the 

dollar-per-deciview metric in evaluating BART options in creating the FIP. We 

therefore also conclude that any argument by the petitioners that the dollar-perdeciview measurement proves the scrubbers are not cost effective lacks merit. 

See Pet. Reply Br. at 16. 

We see no reason to deviate from our view of the dollar per deciview metric here. 

Nucor is also incorrect in its assertion that we used the $/dv metric in determining BART for the 

Corette facility. This can be seen from Table 138 in our Montana proposal, which summarizes 

cost-effectiveness in $/ton,674 and this quote concerning the Corette facility from our Montana 

final decision:675

The BART Guidelines require that cost effectiveness be calculated in terms of 

annualized dollars per ton of pollutant removed, or $/ton. 70 FR 739167. The 

BART Guidelines list the $/deciview ratio as an additional cost effectiveness 

metric that can be employed along with $/ton for use in a BART evaluation. 

However, we did not use this metric for the reasons that were explained in other 

responses. As we stated in the proposed FIP, we weighed costs against the 

anticipated visibility impacts and we explained that any of the control options 

would have a positive impact on visibility; however, the cost of controls was not 

justified by the visibility improvement. As we have explained elsewhere, in our 

proposal, we considered the visibility improvement at all Class I areas within 300 

km of the subject BART unit. 

 

673 We note, however, that in both its final rule and in its brief the EPA asserts that the guidelines require the use of 

the dollar-per-ton metric in evaluating cost effectiveness. The guidelines themselves are a bit unclear. In the section 

on cost effectiveness, the guidelines mention only the dollar-per-ton metric. 40 C.F.R. pt. 51 app. Y(IV)(D)(4)(c). 

However, the guidelines later state that in evaluating alternatives, "we recommend you develop a chart (or charts) 

displaying for each of the alternatives" that includes, among other factors, the cost of compliance defined as 

"compliance — total annualized costs ($), cost effectiveness ($/ton), and incremental cost effectiveness ($/ton), 

and/or any other cost-effectiveness measures (such as $/deciview)." Id. app. Y(IV)(E)(1) (emphasis added). 

674 77 FR 24046. 675 77 FR 57895. 
363

Nucor is also incorrect that we failed to consider the additional energy costs and water/land 

impacts of scrubber technology. Any costs associated with these energy and nonair quality 

environmental impacts of compliance were included in our analysis. Thus we see no 

inconsistency with our Corette BART determination. 

Comment: EPA does not complete the analysis by giving a rational explanation as to why 

the costs of the proposed controls were justified by the visibility improvement. [Arkansas 

Attorney General (0162) p. 4-6] The Attorney General for the State of Arkansas stated that in 

Nat’l. Parks Conservation Ass’n. v. EPA, -- F.3d --, 2015 WL 3559149 (9th Cir. 2015), the Ninth 

Circuit Court of Appeals struck down parts of the EPA’s Regional Haze FIP for Montana as 

arbitrary and capricious. The Court found that EPA “failed to explain what makes a cost 

reasonable in light of potential visibility benefits.” The same fatal flaw plagues the proposed FIP 

for Arkansas. 

This is an aesthetic standard, not a public health standard. As such, EPA must justify its decision 

in terms of improving visibility. As with the Montana FIP, EPA fails to explain why the costs are 

reasonable in light of the limited visibility improvements cited in the proposed FIP. EPA 

provides the cost calculations and it provides the visibility calculations; however, the agency 

does not connect the two. It does not complete the analysis by giving a rational explanation as to 

why the costs of the chosen controls were justified by the visibility improvement. 

In Michigan v. EPA, 135 S. Ct. 2699 (2015), the United States Supreme Court reaffirmed that 

“[f]ederal administrative agencies are required to engage in reasoned decision making.” (Internal 

quotes and citation omitted). As the Ninth Circuit clearly stated, “[T]he law does require EPA to 

‘cogently explain why it has exercised its discretion in a given manner.” Nat’l Parks at *5 (citing 

Motor Vehicle Mfrs. Ass’n of U.S., Inc. v. State Farm Auto Ins. Co., 463 U.S. 29 (1983)). The 

Eighth Circuit has agreed, stating: “A rule is arbitrary and capricious if ‘the agency fails to 

articulate a satisfactory explanation for its action, including a rational connection between the 

facts found and the choice made.” Menorah Medical Center v. Heckler, 768 F.2d 292, 295 (8th 

Cir. 1985) (internal quotations omitted). Thus, without a satisfactory explanation of its decision, 

there is no way that EPA can justify its decision. 

Without an adequate explanation, the EPA cannot prove that it adequately considered costs in 

developing the proposed FIP. Costs are an important factor in both determining appropriate 

BART controls and in setting reasonable progress goals. In fact, it is the first factor listed for 

both determinations. Based on the data provided in the proposed rule, the total capital costs for 

compliance with the proposed FIP will be over $278 million.676 Other commenters to the FIP 

argue that the actual cost is much higher than has been determined by EPA. Total annual costs 

for compliance will be over $175 million.677 When compared to the imperceptible visibility 

improvements that will be gained, this is too costly for the State of Arkansas and its citizens. 

In Michigan v. EPA, supra, the United States Supreme Court reiterated its support for sensible 

consideration of cost within a regulatory scheme: 

 

676 80 Fed. Reg. 18944 (April 8, 2015). 677 Id.
364

Consideration of cost reflects the understanding that reasonable regulation 

ordinarily requires paying attention to the advantages and the disadvantages of 

agency decisions. It also reflects the reality that too much wasteful expenditure 

devoted to one problem may well mean considerably fewer resources available to 

deal effectively with other (perhaps more serious) problems. 

Id., Slip Opinion at 7 (citing Entergy Corp. v. Riverkeeper, Inc., 556 U.S. 208, 233 (2009)). EPA 

should seriously consider the costs imposed by the proposed FIP to achieve minimal aesthetic 

improvement. Resources are likely more wisely spent on public health programs under the Clean 

Air Act. 

Justice Scalia succinctly sums up my concern with the proposed FIP. “One would not say that it 

is even rational, never mind ‘appropriate’ to impose billions of dollars in economic costs in 

return for a few dollars in health or environmental benefits.” Id., Slip Opinion at 7. EPA fails to 

explain its rationale from imposing significant costs upon Arkansans without significant 

environmental benefits. As such, the proposed FIP is unlawful and should be withdrawn by the 

EPA. 

Additionally, the Arkansas Department of Environmental Quality (“ADEQ”) will be filing 

extensive comments on the proposed FIP. I support the comments of ADEQ. I encourage EPA to 

carefully consider the comments from ADEQ and the parties affected by the proposed FIP. 

Response: The commenter states that EPA failed to conduct a rational cost-benefit analysis and 

makes improper comparisons to suggest that our proposed costs do not justify the expected 

visibility benefits. These arguments are without merit. We conducted a robust and detailed 

analysis of costs in the Rule using the same approach we have used in multiple regional haze 

BART rulemakings and that has been affirmed by multiple circuit courts. We then weighed the 

costs against predicted visibility benefits. Visibility is one of the five statutory factors we must 

consider in a BART analysis under CAA section 169A(g)(2) and 40 CFR 51.308(e)(1)(ii)(A). In 

our reasonable progress analysis, alongside the four statutory factors, we also considered the 

visibility improvement of controls. Although visibility is not one of the four mandatory factors 

explicitly listed for consideration under CAA section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), 

states or EPA have the option of considering the projected visibility benefits of controls in 

determining if the controls are necessary to make reasonable progress. Our long-standing 

approach in conducting these analyses was neither arbitrary nor capricious.

Additionally, commenter’s focus on the total cost of the proposal is misleading because it is not 

the appropriate metric for evaluating “the costs of compliance.” Consistent with guidance and 

prior regional haze rulemakings, we evaluated the cost-effectiveness of available control options 

on a dollar-per-ton of emissions reduced ($/ton) basis. Our analyses conservatively estimated 

many individual cost parameters, resulting in higher cost estimates. We then validated the cost 

effectiveness of each control option with a detailed technical record and thorough consideration 

of comments. 

The commenter’s reliance on Michigan v. EPA, which interprets a different part of the CAA, is 

misplaced. The Supreme Court expressly stated that we were not required to conduct a formal 
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cost-benefit analysis, which commenter appears to claim is required here. Michigan v. EPA, 135 

S. Ct. 2699, 2711 (2015). Instead, the Court held that it was arbitrary and capricious for EPA to 

fail to consider costs at all when determining whether regulating hazardous air pollutants was 

“necessary and appropriate.” Id. at 2706, 2711. 

The proposal’s controls fall within the range of cost-effectiveness values established across a 

range of regional haze actions. The Ninth Circuit recently affirmed EPA’s costing method, see 

Arizona, 2016 WL 722685 at **16-18, explaining that “cross-facility comparisons of similar 

sources with regard to the cost-effectiveness of a given control option aid in determining cost 

effectiveness at a specific source.” Id. at *17. Further, in Oklahoma v. EPA, the Tenth Circuit 

affirmed our disapproval of Oklahoma’s “cost of compliance” analysis and affirmed as 

reasonable our FIP that required scrubber retrofits with cost effectiveness values similar to those 

here. 723 F.3d at 1206, 1224. 

7. Modeling 

7.a. Cumulative Visibility Impairment 

Comment: EPA’s reliance on a “cumulative visibility improvement” metric has no basis in 

the CAA and EPA’s regulations and mischaracterizes visibility improvements in Class I 

areas. 

[Entergy Arkansas Inc. (0166) p.54-55; Entergy Mississippi Inc. (0169) p. 13; Conway 

Corporation et. al. (0172) p. 13; and EEAA (0173) p. 5-6] EAI, EMI, Conway Corporation et. 

al., and EEAA stated that EPA’s reliance on a “cumulative visibility improvement” metric is 

arbitrary and capricious, and has no basis in law. In assessing the visibility improvements that 

are predicted to be achieved through the installation of proposed controls at White Bluff, Lake 

Catherine, Independence, Bailey, McClellan, and Flint Creek, EPA totaled the predicted 

improvements at all affected Class I areas to yield a cumulative visibility improvement 

associated with each facility. See 80 Fed. Reg. at 18951-59 (Tables 8-18); 18961 (Tables 20 and 

21); 18966 (Tables 27 and 29); 18972 (Tables 34 and 35); 18974 (Tables 37 and 38); 18,978 

(Table 42); and 18,994 (Table 64). EPA appears to have relied upon the cumulative visibility 

improvement across the four affected Class I areas to support its proposed NOx BART 

determination for Lake Catherine. 80 Fed. Reg. 18,978 (where EPA identified the cumulative 

visibility impact in its rationale for the Lake Catherine “Proposed NOx BART Determination”). 

EPA also appears to have relied upon the cumulative visibility improvement across the four 

affected Class I areas to support its proposed BART determinations and reasonable progress 

determinations for the other aforementioned facilities. It is improper for EPA to rely upon the 

cumulative visibility improvement across all affected Class I areas. BART and reasonable 

progress determinations instead should be based on the predicted visibility improvements at 

individual Class I areas. Furthermore, the cumulative metric is deceptive and provides no 

information that could be used to assess whether any single Class I area would experience 

perceivable visibility improvements as a result of BART or reasonable progress controls, and 

may mask the fact that no individual Class I area would experience any discernible visibility 

improvement from control of emissions at any particular source. 
366

[Entergy Arkansas Inc. (0166) p.54-55; and EEAA (0173) p. 5-6] EAI and EEAA stated that the 

preamble to the BART Guidelines states that the focus of an analysis of visibility improvements 

associated with BART controls is to be on the “nearest Class I area” to the facility in question. 

70 Fed. Reg. 39,104, 39,170 (July 6, 2005) (“One important element of the [modeling] protocol 

is in establishing the receptors that will be used in the model. The receptors that you use should 

be located in the nearest Class I area with sufficient density to identify the likely visibility effects 

of the source.”) (emphasis added). While the Rule allows consideration of impacts at other 

nearby Class I areas, it is for the purpose of “determin(ing) whether effects at those areas may be 

greater than at the nearest Class I area.” Id. (emphasis added). Summing the predicted visibility 

improvements at multiple Class I areas does not facilitate a determination that effects at more 

distant Class I areas are more significant than those at the closest Class I area. 

[Entergy Arkansas Inc. (0166) p.54-55] In addition to having no basis in EPA’s own regulations, 

the cumulative metric is deceptive and provides no information that could be used to assess 

whether any single Class I area would experience perceivable visibility improvements as a result 

of BART or reasonable progress controls. For example, EPA appears to have selected BOOS as 

NOx BART for Lake Catherine in part because it would achieve a cumulative visibility 

improvement across the four affected Class I areas of 1.215 dv. 80 Fed. Reg. at 18,978. But the 

cumulative metric masks the fact that no individual Class I area would experience any 

discernible visibility improvement. Instead, Mingo would experience a 0.196 dv improvement, 

Hercules-Glades would experience a 0.175 dv improvement, Upper Buffalo would experience a 

0.248 dv improvement, and Caney Creek would experience a 0.596 dv improvement. See id. 

These are imperceptible levels of improvement that do not justify installation of controls.678 The 

metric therefore equates imperceptible visibility “benefits” in different areas with a much larger 

and indisputably discernible visibility improvement in a single area. 

[Entergy Arkansas Inc. (0166) p.54-55; and EEAA (0173) p. 5-6] EAI and EEAA stated that on 

a practical level, reliance on a cumulative visibility improvement is illogical. Deciview 

improvements at multiple areas cannot be added together to form a meaningful metric. A 

deciview is a logarithmic scale based on the concept that one deciview is the minimum change in 

visibility perceptible to a human observer. Deciviews cannot be directly added or subtracted. To 

add or subtract the haze, one must add or subtract the total extinction values and then recalculate 

the haze index in deciviews. Considering the Class I areas addressed in the Proposal are 

hundreds of kilometers away from each other, particles from one Class I area cannot contribute 

to or improve the light extinction at another Class I area, therefore, adding or subtracting light 

extinction values is not an accurate representation of reality and would be illogical. In simple 

terms, a visitor to a Class I area cannot benefit from any visibility improvement that might be 

occurring at another Class I area. The cumulative metric represents an illusory visibility benefit; 

it is an improvement that cannot be perceived and therefore provides no indication of whether 

the proposed controls will contribute to the goal of the Regional Haze Program: to reduce human 

perception of visibility impairment in Class I areas. This cumulative visibility metric should be 

eliminated from any consideration of whether proposed controls will result in visibility 

improvement, including for the Lake Catherine BART analysis. 

 

678 As discussed above in Section III.F.1, EPA did not perform an analysis to confirm that the model predictions are 

not within the model’s margin of error and, therefore, EPA has not justified that the predicted visibility 

improvements are “reasonably anticipated.” 
367

[Edison Electric Institute (0174) p. 2, 4] EEI stated that EPA’s reliance on a “cumulative 

visibility improvement” metric has no basis in the CAA or EPA's own regulations and is 

misleading. EPA's practice of summing up the predicted visibility improvements at all affected 

Class I areas resulting from emissions controls at one specific facility, to yield a cumulative 

visibility improvement, is improper and meaningless. For example, the cumulative visibility 

improvement metric frequently will be constructed by summing up visibility improvements that 

may be perceptible for one or more Class I areas with visibility improvements that are not 

perceptible for one or more other Class I areas. The only purpose of the cumulative visibility 

improvement indicator is to imply that facilities are having a large impact across numerous Class 

I areas, but this indicator can be deceptive if it includes imperceptible visibility improvements 

for some Class I areas. EPA should not use a cumulative metric and should instead assess only 

the impacts of controls at individual Class I areas directly. 

[Arkansas Electric Energy Consumers Inc. and Arkansas Gas Consumers Inc. (0175) p. 7-8] 

AEEC and AGC stated that on page 18951 of the Proposed FIP, the EPA uses the term 

“cumulative visibility benefits” and indicates that this concept factored into its determinations in 

the Proposed FIP.679 In various tables contained in the Proposed FIP, the EPA adds visibility 

improvement values at one Class I area to the visibility improvement values at other Class I areas 

to arrive at a “cumulative visibility improvement.”680 The “improvement” referenced in the 

tables refers to “cumulative visibility benefits.” Similarly, in other tables, EPA adds the visibility 

impacts at individual Class I areas to arrive at a “total visibility impact.”681 The Proposed FIP, 

however, does not contain a discussion of the origin or purpose of a “total visibility impact” 

metric, nor does it provide a sound scientific explanation for either the “total visibility impact” 

metric or the “cumulative visibility improvement” metric. 

Neither the Regional Haze Rule nor the EPA’s own guidelines provide a basis for a cumulative 

visibility metric or a total visibility impact metric. Since the Regional Haze Rule aims to improve 

visibility in individual Class I areas, adding slight improvements in visibility from separate areas 

together does not offer a useful method for measuring overall visibility improvement. Many 

small incremental changes in perception in various locations do not create one large uniform 

incremental change in perception when aggregated. Providing cumulative numbers as a measure 

of overall visibility improvement, when the incremental changes may be minor, barely 

perceptible, and/or separated by large distances, lacks a scientific and legal basis. Since the 

cumulative visibility metrics in the Proposed FIP lack a legal or scientific basis, the EPA should 

withdraw the Proposed FIP. 

[ADEQ (0144) p. 2-3] ADEQ stated that the cumulative visibility effects metric used in many 

tables and discussions in the Proposed FIP is not scientifically sound, has no legal basis in the 

Regional Haze Rule, and is grossly misleading. On page 18951 of the Proposed FIP, EPA first 

uses the term “cumulative visibility benefits” and indicates that this was a factor in its 

deliberations.682 In Tables 8, 10, 11, 13, 18, 20, 21, 23, 27, 29, 37, 38, 42, 47, 49, 51, and 53, 

 

679 80 Fed. Reg. 18944 at 18951. 680 Id. 681 Id. 682 80 FR 18944 at 18951.
368

EPA adds visibility improvement values at one Class I area to the visibility improvement values 

at other Class I areas to arrive at a “cumulative visibility improvement.683 This “improvement” 

referenced in the tables refers to the “cumulative visibility benefits.” EPA does not discuss any 

purpose for calculating the “cumulative visibility benefits” in the Proposed FIP. Similarly, EPA 

adds the visibility impacts at individual Class I areas to arrive at a “total visibility impact” in 

Tables 34, 35, 62, 63, 64, and 66.684 EPA also provides no discussion of the origin or purpose of 

a “total visibility impact” metric. In fact, EPA does not provide a sound scientific explanation for 

either the “total visibility impact” metric or the “cumulative visibility improvement” metric 

anywhere in the Proposed FIP. 

There is no basis in the Regional Haze Rule or EPA guidelines for either a cumulative visibility 

metric or a total visibility impact metric. In the “Guidelines for BART (“Best Available 

Retrofit Technology”) Determinations under the Regional Haze Rule,” EPA only requires an 

evaluation of the change at each receptor located “at the nearest Class I area with sufficient 

density to identify the likely visibility effects of the source.”685 (emphasis added). This 

requirement is clearly intended to help “identify the likely visibility effects” of the specific 

visibility improvement of a particular source. Using data from these receptors to create a global 

visibility increase metric is improper. 

Given that the purpose of the Regional Haze Rule is to provide improved visibility in individual 

and unique Class I areas, adding together slight improvements in visibility from separate areas is 

not a useful method for measuring overall increased visibility improvement. EPA’s chosen 

measurement of visibility impairment is a “deciview,” which is defined in part as “uniform 

incremental changes in perception.”686 Many small separate incremental changes in perception in 

various locations do not create one large uniform incremental change in perception when added 

together. These metrics simply do not convey any meaningful information related to progress 

toward reaching the ultimate goal of restoring background visibility conditions at Class I areas. 

It is grossly misleading to provide cumulative numbers as a measurement of overall 

improvement when the incremental changes may only be slight, barely perceptible, and separated 

by large distances. The methodology behind these metrics lacks any scientific basis. Due to the 

misleading nature of the cumulative visibility metric and the total visibility impact metric, EPA 

should withdraw the Proposed FIP and remove all references to either of these metrics in any 

subsequently proposed plan. 

Comment: [Arkansas Attorney General (0162) p. 2-3] The Attorney General for the State of 

Arkansas stated that the purpose of the Regional Haze Rule is to improve visibility in the 

nation’s national parks and wilderness areas. For Arkansas, the Caney Creek and Upper Buffalo 

Wilderness Area are the areas where visibility must be improved. EPA measures visibility 

impairment and improvement in terms of “deciviews.” A deciview is “a haze index derived from 

calculated light extinction, such that uniform changes in haziness correspond to uniform 

 

683 Id. 684 Id. 685 40 C.F.R. § Pt. 51, App. Y, § IV, D.5, Step 5 686 40 C.F.R. § 51.301
369

incremental changes in perception across the entire range of conditions.” 40 C.F.R. § 51.301. 

One deciview equals a slightly perceptible change in visibility to the human eye. 

The required improvements for each area will yield a less than one deciview improvement to 

visibility. The fraction of improvement will be imperceptible to the human eye. If a deciview is a 

measurement of perception of a landscape, it is essentially a snapshot in time. It is physically 

impossible for a person to look at the vistas of all class I Federal areas at the same time. Thus, 

small, imperceptible changes in visibility across the four class I Federal areas cannot be 

combined to manufacture a measure of perceptible improvement in visibility. It is, therefore, not 

logical then to aggregate the visibility improvements across all four class I Federal areas for each 

source, as is done in the proposed FIP. As such, one may question how the cost can be justified 

when visibility will not be perceptibly improved. 

EPA has invented the concept of “cumulative visibility improvement” to get around this 

question. The Clean Air Act does not define, nor even mention “cumulative visibility 

improvement” (“CVI”) as a measurement under the five-factor analysis for choosing an 

appropriate Best Available Retrofit Technology (“BART”). CVI is a construct of the EPA that 

defies common sense and cannot be used to justify its chosen BART controls. The deciview is 

not a measurement that can be added together to get a total sum and have that total sum indicate 

positive results. It defies logic that the affect in the Caney Creak area can be added to the affect 

in the Upper Buffalo Wilderness Area and that such will result in overall improvement. At best, 

this standard confuses the public and incorrectly represents the actual visibility improvements 

that will result from the chosen controls. At worst, this inflated number was impermissibly used 

by EPA to justify the enormous costs of BART controls. 

The use of CVI is not grounded in law or fact. As such, its use is arbitrary and capricious. 

Comment: EPA has the legal authority to consider cumulative visibility improvement when 

promulgating a FIP. [Sierra Club et. al. (0171) p. 41-44] The Sierra Club et. al. stated that in 

claiming that EPA inappropriately considered the cumulative visibility improvement of controls, 

commenters invent facts and overlook the law. To begin, commenters misunderstand how EPA 

is considering how pollution controls improve visibility at multiple Class I areas. EPA modeled 

the visibility improvement from controls at four separate Class I areas: two areas in Arkansas 

and two areas in Missouri. In addition to presenting the improvement at each Class I area, EPA 

sums the improvement at the four areas. See, e.g., 80 Fed. Reg. at 18,966. 

In presenting, and summing, the improvement at the four Class I areas, EPA is not implying that 

the improvements are visible simultaneously to a single observer, as some of the commenters 

accuse EPA of doing. Instead, EPA is showing that where a source has baseline impacts at 

multiple Class I areas, operating pollution controls will improve visibility at multiple Class I 

areas. As EPA explained in the Wyoming regional haze rule, “a summation of visibility benefits 

is not intended to suggest that individually imperceptible levels of improvement are somehow 

perceptible, but rather to provide a single metric that can simultaneously capture both the number 

of Class I areas affected and the magnitude of improvement at those areas for comparison 

purposes.” 79 Fed. Reg. at 5,120. There is nothing inappropriate, much less anything unlawful, 

about considering the visibility improvement at multiple Class I areas from controls at a source. 
370

To the contrary, it is within the spirit of the statutory mandate and expressly permissible within 

the regulation to consider cumulative impacts. 

Commenters do not dispute that operating pollution controls will improve visibility at multiple 

Class I areas, nor could they. All of the evidence in the record suggests that the BART and 

reasonable progress sources for which EPA proposed controls impair visibility in at least four 

Class I areas, and that reducing pollution from these sources would improve visibility in at least 

these areas. 

Given the uncontroverted evidence that Arkansas sources impact multiple Class I areas, it would 

be inconsistent with the record, the statute, and with EPA’s approach to other haze plans for EPA 

to fail to consider the cumulative visibility improvement here. The legal requirement to consider 

cumulative visibility impacts is rooted in the Clean Air Act’s goal to eliminate haze at all Class I 

areas, not just certain Class I areas. See 42 U.S.C. § 7491(a)(1) (“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 manmade air 

pollution.”). EPA has interpreted the statutory goal of improving visibility at all Class I areas as 

requiring states to consider the cumulative visibility improvement from potential BART controls. 

E.g., 76 Fed. Reg. 52,388, 52,430 (Aug. 22, 2011) (“Given that the national goal of the program 

is to improve visibility at all Class I areas, it would be short-sighted to limit the evaluation of the 

visibility benefits of a control to only the most impacted Class I area.”); 77 Fed. Reg. 51,620, 

51,631-32 (Aug. 24, 2012) (“EPA believes that it is important to consider the visibility impact on 

multiple Class I areas. The goal of the visibility program is to remedy visibility impairment at all 

Class I areas.”). 

Around the country, EPA has disapproved plans in which the state failed to consider the 

cumulative visibility improvement from pollution controls, and the state indicated that the 

cumulative visibility improvement was significant. Similarly, when developing federal plans, 

EPA has considered cumulative visibility improvement in its BART determinations. For 

example, in reviewing the Arizona regional haze plan, EPA stated that: 

[I]nstallation of more stringent controls . . . would result in 

visibility benefits at multiple Class I areas, yet [Arizona] chose to 

consider the benefits only at the most impacted area. Where, as 

here, the benefits of controls have been modeled for a number of 

surrounding areas and consideration of these benefits is useful in 

determining the appropriate level of controls, EPA does not agree 

that these benefits may be ignored . . . EPA disagrees that state 

flexibility extends to categorically excluding consideration of 

visibility improvements occurring at multiple Class I areas. 

77 Fed. Reg. 72,512, 72,519 (Dec. 5, 2012). EPA disapproved several of Arizona’s BART 

determinations because “while the State has some flexibility in choosing a specific procedure to 

consider these cumulative area and multiple unit benefits, when such benefits are significant, it is 

not reasonable to ignore them altogether as ADEQ did.” Id. 
371

Similarly, EPA disapproved the state of New York’s determination as to the controls that are 

BART for SO2 pollution from the Danskammer power plant after finding that “EPA’s analysis 

of the cumulative visibility improvements at all 7 Class I areas justifies a more stringent BART 

emission limit [than the State proposed].” 77 Fed. Reg. 24,794, 24,814 (Apr. 25, 2012), finalized 

by 77 Fed. Reg. 51,915, 51,916 (Aug. 28, 2012). EPA explained its decision by noting that “[i]n 

making BART determinations, EPA also recommends the consideration of cumulative impacts 

and improvements that could occur at all of the Class I areas a particular facility might impact.” 

Id. EPA also disapproved several BART determinations in Oklahoma’s regional haze SIP, and 

EPA considered cumulative visibility improvement in developing a federal implementation plan. 

76 Fed. Reg. 81,728, 81,736 (Dec. 28, 2011) (“[c]learly, the visibility benefits from . . . emission 

reductions will be spread among all affected Class I areas, not only the most affected area, and 

should be considered in evaluation of benefits from proposed reductions.”). 

With one exception, EPA has approved state plans that entirely failed to consider cumulative 

visibility improvement only where the cumulative visibility improvement was too small to have 

changed the ultimate BART determination. E.g., 77 Fed. Reg. 76,871, 76,875 (Dec. 31, 2012) 

(“... as we suggested during the State’s public comment period, the State [of Colorado] should 

have more thoroughly considered the visibility impacts of controlling emissions from Craig 1 on 

the various impacted Class I areas and not just have focused on the most impacted Class I 

area.”);687 78 Fed. Reg. 53,250, 53,262 (Aug. 29, 2013) (“As a general matter, EPA agrees that 

Florida should have considered the visibility improvements at all affected Class I areas in its 

BART visibility assessments.”).688

And in at least one case where a state never submitted a regional haze SIP, and thus EPA 

developed a federal implementation plan, “[EPA] did assess cumulative visibility impacts.” 77 

Fed. Reg. 57,864, 57,869 (Sept. 18, 2012). In explaining the final regional haze plan for 

Montana, EPA noted that “[i]n our analysis of visibility impacts, we considered the visibility 

improvement at all Class I areas within 300 km of the subject BART unit.” Id. Likewise, after 

EPA disapproved the SO2 BART determination for the Intalco aluminum smelter in Washington 

State, EPA considered cumulative visibility impacts when developing a FIP. 79 Fed. Reg. 

33,438, 33,447 (June 11, 2014) (“. . . [A]s explained in the proposal, the EPA considered 

cumulative visibility impacts, as well as the other BART factors in reaching its BART 

determination for this facility.”). Of particular relevance to this case, EPA announced the 

principle that “where a control might not be warranted as BART based on the improvement at a 

single Class I area, significant cumulative benefits are an additional consideration that could 

warrant that the control be selected as BART.” 79 Fed. Reg. 5032, 5050 (Jan. 30, 2014). 

 

687 After parties challenged EPA’s approval of the BART determination for Craig Unit 1, and consistent with 

parties’ Settlement Agreement on November 20, 2014, the Air Quality Control Commission of Colorado adopted 

revisions to Regulation Number 3, Part F and Colorado’s regional haze SIP revising the NOx emissions limit, 

compliance date, and BART determination for Craig Unit 1 encompassing a more stringent BART determination 

than in Colorado’s initial regional haze plan. The State of Colorado has advanced this revision to EPA for approval. 

See Nat’l Parks Conservation Ass’n v. EPA, Settlement Agreement, July 10, 2014, No. 13-9525 (10th Cir.). 688 The Colorado and Florida examples demonstrate that EPA has approved plans that failed to consider cumulative 

visibility benefits only where the cumulative benefits were not significant. As discussed herein, that is not the case 

for the Arkansas proposed FIP. For several Arkansas sources, installing pollution controls would significantly 

improve visibility if the improvement at all affected Class I areas is considered. 
372

In short, the record, the statute, and EPA’s approach to other haze plans all support EPA’s 

practice of considering how proposed controls would improve visibility at all affected Class I 

areas. We believe that EPA is required to consider the visibility improvement at all affected 

Class I areas as this approach gives meaning to the statute’s visibility goal for all Class I areas. 

But even if EPA were not required to do so, EPA is authorized to do so when promulgating a 

FIP, just as a state would be authorized to do so when submitting a SIP. 

Response: We agree with the comments supporting the consideration of cumulative visibility 

impacts and benefits. We disagree with the other commenters that cumulative improvement over 

multiple areas is an inappropriate metric, or that examining a single Class I area is sufficient. The 

cumulative improvement metric (i.e., the simple sum of impacts or improvements over all the 

affected Class I areas) is not intended to correspond to a single human's perception at a given 

time and place. The approach is simply one way of assessing improvements at multiple areas, for 

consideration along with other visibility metrics. Another approach would be to simply list 

visibility improvements at the various areas, and qualitatively weigh the number of areas and the 

magnitudes of the improvements. The cumulative sum is simply an easily understood and 

objective way of weighing cumulative visibility improvement, as part of the overall control 

evaluation along with the visibility improvement at each impacted Class I area. As noted by 

some comments, we have calculated cumulative visibility in a number of Regional Haze actions 

evaluating the benefits of controls under BART and when visibility is considered in the 

reasonable progress analysis. Furthermore, the FLMs have provided comments in support of the 

use of this metric in past actions.689 

 

The comment opposing cumulative modeling does not provide the full context when citing to the 

BART guidelines. The portion referred to by the commenter discusses the development of a 

modeling protocol and establishing the receptors to model. The full portion of the BART 

Guidelines that the commenter referenced states: 

The receptors that you use should be located in the nearest Class I area with sufficient 

density to identify the likely visibility effects of the source. For other Class I areas in 

relatively close proximity to a BART-eligible source, you may model a few strategic 

receptors to determine whether effects at those areas may be greater than at the nearest 

Class I area. For example, you might chose to locate receptors at these areas at the closest 

point to the source, at the highest and lowest elevation in the Class I area, at the 

IMPROVE monitor, and at the approximate expected plume release height. 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 as additional analyses might be unwarranted.690

This section of the BART Guidelines addresses how to determine visibility impacts as part of the 

BART determination. Several paragraphs later in the BART Guidelines it states: “You have 

flexibility to assess visibility improvements due to BART controls by one or more methods. You 

may consider the frequency, magnitude, and duration components of impairment,” emphasizing 

the flexibility in method and metrics that exists in assessing the net visibility improvement. 

 

689 For example see 76 FR 52429 690 40 CFR 51 Appendix Y, IV.D.5 
373

In fully considering the visibility benefits anticipated from the use of an available control 

technology as one of the factors in selection of BART, it is appropriate to account for visibility 

benefits across all affected Class I areas and the BART guidelines provide the flexibility to do 

so. One approach as noted above is to qualitatively consider, for example, the frequency, 

magnitude, and duration of impairment at each and all affected Class I areas. Where a source 

significantly impacts more than one Class I areas, the cumulative visibility metric is one way to 

take magnitude of the impacts of the source into account. 

With respect to our analysis of controls under reasonable progress, we rely on our reasonable 

progress Guidance.691 Our Reasonable Progress Guidance notes the similarity between some of 

the reasonable progress factors and the BART factors contained in Section 51.308(e)(1)((ii)(A), 

and suggests that the BART Guidelines be consulted regarding cost, energy and non-air quality 

environmental impacts, and remaining useful life. We are therefore relying on our BART 

Guidelines for assistance in interpreting those reasonable progress factors, as applicable. 

Also, similar to a BART analysis, we are also considering the projected visibility benefit in our 

analysis following the BART guidelines and the use of CALPUFF.692 We rely on the 

BART Guidelines here and in other actions evaluating reasonable progress controls because they 

provide a reasonable and consistent approach regarding visibility modeling. This includes the 

flexibility in metrics that exists in assessing the net visibility improvement, and the use of 

cumulative visibility, along with visibility impacts at individual Class I areas, as one way to take 

magnitude of the impacts of the source into account where a source evaluated under reasonable 

progress significantly impacts more than one Class I area. 

For each subject-to-BART source and the source evaluated for reasonable progress controls, we 

evaluated the visibility impacts from the source and benefits of controls at four separate Class I 

areas. In addition to providing the visibility impacts and potential benefits at each Class I area in 

the proposal, we also summed the impact and improvement across the four Class I areas. The 

results show that some sources significantly impact visibility at more than one Class I area, 

emission reductions result in visibility benefits at all impacted class I areas, and in some 

situations, the largest visibility benefits from controls can occur at Class I areas other than the 

most impacted. 

Therefore, consistent with the BART Guidelines, and based upon these facts, we determined 

additional analyses were not only warranted but necessary. The BART Guidelines only indicate 

that additional analyses may be unwarranted at other Class I areas, and in no way exclude such 

analyses, as the commenter suggests. We concluded that a quantitative analysis of visibility 

impacts and benefits at only the most impacted area would not be sufficient to fully assess the 

impacts and benefits of controlling emissions from the sources evaluated for BART and reasonable 

progress. 

 

691 Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program, June 1, 2007 692 As we explain in our proposed action (80 FR 18993): “While visibility is not an explicitly listed factor to 

consider when determining whether additional controls are reasonable under the reasonable progress requirements, 

the purpose of the four-factor analysis is to determine what degree of progress toward natural visibility conditions is 

reasonable. Therefore, it is appropriate to consider the projected visibility benefit of the controls when determining 

if the controls are needed to make reasonable progress”. See 79 FR at 74838, 74840, and 74874.
374

Nothing in the Regional Haze Rule suggests that a state (or EPA in issuing a FIP) should ignore 

the full extent of the visibility impacts and improvements from controls at multiple Class I areas. 

Given that the national goal of the program is to improve visibility at all Class I areas, it would 

be short-sighted to limit the evaluation of the visibility benefits of a control to only the most 

impacted Class I area. We believe such information is useful in quantifying the overall benefit of 

controls. As discussed in our proposal, we evaluated the statutory factor, visibility benefits 

anticipated due to controls, at each Class I area in making BART determinations and considered 

the visibility benefits in consideration of controls for reasonable progress. 

We respond to comments regarding visibility improvements that may be imperceptible elsewhere 

in this section of the response to comments document. 

7.b. Imperceptible Visibility Improvement 

Comment: EPA must withdraw the proposed FIP because the FIP would only achieve 

visibility improvements below one deciview, which is not discernible to the naked eye. 

[ADEQ (0144) p. 15-16; and Arkansas Electric Energy Consumers Inc. and Arkansas Gas 

Consumers Inc. (0175) p. 9-10] ADEQ, AEEC, and AGC stated that EPA’s revisions to 

Arkansas’s proposed RPGs are unnecessary and beyond the authority granted by Congress. 

EPA’s own estimates of the effects of the Proposed FIP are reductions for the 20% worst days of 

-0.21 deciviews for Caney Creek and -.19 deciviews for the Upper Buffalo.693 Since these 

reductions would not be visible to the naked eye,694 achieving these slight reductions exceeds the 

scope of regulatory regime specifically designed to address “the impairment of visibility.”

The CAA only provides EPA with the authority to regulate the “impairment of visibility.”695

Visibility extends only to things that humans can see with their naked eyes.696 By extension, 

EPA only has authority to regulate the impairments of visibility that are perceptible to the human 

eye. A “deciview” is a haze index derived from calculated light extinction, such that uniform 

changes in haziness correspond to uniform incremental changes in perception across the entire 

range of conditions, from pristine to highly impaired.”697 The human eye can only detect a 

change in haziness of 1.0 or more deciviews.698 Measurements of 0.21 and 0.19 deciviews are 

both well below amount of haze discernable to the naked eye. Under both the plain language and 

dictionary definitions of “visibility,” the statute does not provide EPA with the authority to 

 

693 80 FR 18944 at 18998. 694 The human eye can only detect a change in haziness of 1.0 or more deciviews. See, e.g. 79 Fed. Reg. 58302 at 

58303. 

695 42 U.S.C.A. § 7491 (“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 

manmade air pollution.)(emphasis added). 

696 E.g. Webster’s Third New International Dictionary 2557 (1981)(“visible” means “capable of being seen”; 

“visibility” means “the degree or extent to which something is visible ... [by] the observer’s eye unaided by special 

optical devices”). 

697 40 C.F.R. § 51.301. 698 e.g.79 FR 58302 at 58,303. 
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regulate haze below a single deciview, which would be invisible to the naked eye. Since the 

Proposed FIP will only achieve visibility improvements smaller than one deciview, the EPA 

lacks authority to revise the RPGs suggested by Arkansas, and it should withdraw the Proposed 

FIP 

Comment: [Nucor Steel-Arkansas and Nucor-Yamato Steel Company (0163) p. 12; and 

Arkansas Electric Energy Consumers Inc. and Arkansas Gas Consumers Inc. (0175) p. 5] Nucor 

and AEEC/AGC both stated that the sole purpose of the regional haze program is to address 

visibility impairment. See 42 U.S.C. §7491(a)(1). It is not a health based standard, and EPA may 

not require emissions reductions just for sake of doing so under the guise of imperceptible 

visibility improvements or solely for the sake of reducing emissions.699 Consistent with this 

purpose, the Clean Air Act requires that EPA's BART determination take into account, among 

other things, the cost of compliance and the "degree of improvement in visibility which may 

reasonably be anticipated to result from the use of such technology." Id. §7491(g)(2) [emphasis 

supplied]. EPA may not require a source “to spend millions of dollars for new technology that 

will have no appreciable effect on haze in any Class I area.” Am. Corn Growers v. EPA, 291 

F.3d 1, 7 (D.C. Cir. 2002) (vacating EPA's BART determinations because EPA left open the 

possibility that it could require a source to install technologies even when those technologies had 

no appreciable effect on visibility). Yet that is precisely what EPA has done here. Despite these 

limits on its authority, through the proposed FIP, the EPA requires certain stationary sources of 

immense value to the State of Arkansas and its citizens to install controls that will cost billions of 

dollars in order to achieve imperceptible visibility improvements. 

Response: We disagree with commenters that the Regional Haze Rule requires that controls on 

a source or group of sources result in perceptible visibility improvement.700 We believe, for 

reasons we have outlined in our proposal and elsewhere in our response to comments, that the 

controls we proposed under our FIP will result in significant improvements in visibility at a 

number of Class I areas. In a situation where the installation of BART may not result in a 

perceptible improvement in visibility, the visibility benefit may still be significant, as explained 

by the Regional Haze Rule:701

Even though the visibility improvement from an individual source may not be 

perceptible, it should still be considered in setting BART because the contribution to haze 

may be significant relative to other source contributions in the Class I area. Thus, we 

disagree that the degree of improvement should be contingent upon perceptibility. 

Failing to consider less-than-perceptible contributions to visibility impairment would 

ignore the CAA’s intent to have BART requirements apply to sources that contribute to, 

as well as cause, such impairment.” 

Section 169A of the CAA requires that certain major sources that emit any pollutant which may 

reasonably be anticipated to cause or contribute to visibility impairment in Class I Areas install 

BART. The following factors must be taken into account in determining BART: the costs of 

 

699 National Parks Conservation Association v. EPA, No. 12-73710, 2015 WL 3559149 (9th Cir. June 9, 2015). 700 It is generally recognized that a change in visibility of 1.0 deciview is humanly perceptible. 701 70 FR 39104, 39129 
376

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

pollution control technology in use at the source, the remaining useful life of the source, and the 

degree of improvement in visibility which may reasonably be anticipated to result from the use 

of such technology.702

The CAA also requires that in determining reasonable progress there shall be taken into 

consideration the costs of compliance, the time necessary for compliance, the energy and non-air 

quality environmental impacts of compliance, and the remaining useful life of any existing 

source subject to such requirements. Our Reasonable Progress Guidance703 notes the similarity 

between some of the reasonable progress factors and the BART factors contained in Section 

51.308(e)(1)((ii)(A), and suggests that the BART Guidelines be consulted regarding cost, energy 

and non-air quality environmental impacts, and remaining useful life. We are therefore relying 

on our BART Guidelines for assistance in interpreting those reasonable progress factors, as 

applicable, including visibility improvement even though it may not be perceptible from an 

individual source. Also, similar to a BART analysis, we are also considering the projected 

visibility benefit in our analysis of reasonable progress controls following the BART 

guidelines.704 We rely on the BART Guidelines here and in other actions evaluating reasonable 

progress controls because they provide a reasonable and consistent approach regarding visibility 

modeling. 

We accordingly disagree that selection of control measures under BART or for reasonable 

progress should be contingent upon perceptible visibility improvement. As we stated in our 

previous rulemaking addressing the BART determinations in Oklahoma:705

Given that sources are subject to BART based on a contribution threshold of no greater 

than 0.5 deciviews, it would be inconsistent to automatically rule out additional controls 

where the improvement in visibility may be less than 1.0 deciview or even 0.5 deciviews. 

A perceptible visibility improvement is not a requirement of the BART determination 

because visibility improvements that are not perceptible may still be determined to be 

significant. 

The Regional Haze Rule provides that BART–eligible sources with a 0.5 dv impact at a Class I 

area “contribute” to visibility impairment and must be analyzed for BART controls. BART 

determining authorities, however, are free to establish thresholds less than 0.5 dv. Consequently, 

even though the visibility improvement from controlling an individual source may not be 

perceptible, it should still be considered because the contribution to haze may be significant 

when the aggregate contribution of other sources in the Class I area is taken into account and 

because the contribution to haze from the source may be significant relative to other source 

contributions in the Class I area. Thus, in our visibility improvement analysis for BART sources 

 

702 CAA section 169A(g)(2). 703 “Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program,” June 1, 2007 704 As we explain in our proposed action (80 FR 18993): “While visibility is not an explicitly listed factor to 

consider when determining whether additional controls are reasonable under the reasonable progress requirements, 

the purpose of the four-factor analysis is to determine what degree of progress toward natural visibility conditions is 

reasonable. Therefore, it is appropriate to consider the projected visibility benefit of the controls when determining 

if the controls are needed to make reasonable progress”. See also 79 FR at 74838, 74840, and 74874.

705 76 FR 81739. 
377

and in consideration of visibility benefits from controls under our reasonable progress analysis, 

we have not considered perceptibility as a threshold criterion for considering improvements in 

visibility to be meaningful. 

We have considered visibility improvement in a holistic manner, taking into account all 

reasonably anticipated improvements in visibility, and the fact that, in the aggregate, 

improvements from controls on multiple sources (either under BART or reasonable progress) 

will contribute to visibility progress towards the goal of natural visibility conditions. Visibility 

impacts below the thresholds of perceptibility cannot be ignored because regional haze is 

produced by a multitude of sources and activities which are located across a broad geographic 

area. In this action, we found that the required cost-effective controls reduce visibility 

impairment from those BART sources that contribute or cause visibility impairment at nearby 

Class I areas and result in meaningful visibility benefits towards the goal of natural visibility 

conditions. Similarly, we also found that the required cost-effective controls at the Entergy 

Independence facility reduce visibility impairment from the source with the largest potential 

visibility impacts (among all Non-BART sources) and result in meaningful visibility benefits 

towards the goal of natural visibility conditions. 

The commenter mischaracterizes a statement made by the D.C. Circuit Court of Appeals in Am. 

Corn Growers Ass’n v. EPA. The statement made by the Court is as follows: “[u]nder EPA's take 

on the statute, it is therefore entirely possible that a source may be forced to spend millions of 

dollars for new technology that will have no appreciable effect on the haze in any Class I area.” 

706 The Court made this statement based on EPA’s approach to the BART requirements in the 

Regional Haze Rule promulgated in 1999 which did not require the source-specific assessment 

of a BART eligible source’s visibility impacts at any step of the process..707 

The Court disagreed with the approach used by EPA to determine what BART eligible sources 

are reasonably anticipated to cause or contribute to regional haze and therefore subject to 

BART.708 The approach in the Regional Haze Rule required a State to analyze “the degree of 

visibility improvement that would be achieved in each mandatory Class I Federal area as a result 

of the emission reductions achievable from all sources subject to BART located within the region 

that contributes to visibility impairment in the Class I area."709 The Court held that the Rule’s 

treatment of “the degree of improvement in visibility which may reasonably be anticipated to 

result from the use of such technology” factor infringed on states’ authority with respect to 

BART determinations under the Act.710. The Court noted that the Act does not assign a specific 

weight with which to consider each factor, it solely mandates that all the factors be considered in 

making a BART determination.711. The Court’s issue was not with the weight, or lack thereof, 

placed on this factor by EPA. It found issue with what it considered to be “dramatically” 

different treatment of the visibility factor by EPA. Id. While the court in American Corn 

Growers Ass’n. v. EPA found that we had impermissibly constrained State authority, it did so 

 

706 Am. Corn Growers Ass’n v. EPA, 291 F.3d 1, 7 (D.C. Cir. 2002). 707 Id. 708 Id. at 7-8. 709 40 C.F.R. § 51.308(e)(1)(ii)(B). 710 Id. 711 291 F.3d at 6 
378

because it found that we forced States to require BART controls without first assessing a source's 

particular contribution to visibility impairment. This is not the case with our action in Arkansas. 

In response to this court decision and to address these concerns we finalized revised Regional 

Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) 

Determinations.712

Our analysis does not give greater weight to one factor over another; rather, we considered all 

five BART factors fully, revealing that costs and visibility improvement were the two most 

important factors in our decisions. In American Corn Growers Ass’n. v. EPA, the D.C. Circuit 

Court faulted how EPA assessed the statutory fifth factor of visibility improvement in a BART 

determination by using a regional, multi-source, group approach to assessing the visibility 

improvement factor, while assessing the other four statutory BART factors on a source-specific 

basis. Here, we did not give greater weight to our consideration of visibility improvement or 

consider the visibility in a different fashion from the other factors. All BART factors were 

evaluated on a source-specific basis. 

The Court also noted that it is the State’s and not EPA’s duty to determine what BART is 

(provided that the State’s determination complies with the Act and EPA guidelines.713) When 

EPA promulgates a FIP, it is acting in the place of the State, and thus has the same authority a 

state has when the state promulgates a SIP. It is therefore our duty to determine what BART is 

since we are proposing a FIP for Arkansas. We must also consider the same factors that the State 

is mandated to consider by the CAA. The "degree of improvement in visibility which may 

reasonably be anticipated to result from the use of such [best available retrofit] technology" is 

just one of several factors the State, or EPA in the case of a FIP, must consider in determining 

what BART is for a specific source. 

We also disagree with commenter's statement that we required emissions reductions just for the 

sake of doing so under the guise of imperceptible visibility improvements or solely for the sake 

of reducing emissions and their citation to National Parks Conservation Association v. EPA, No. 

12-73710, 2015 WL 3559149 (9th Cir. June 9, 2015). As discussed above, we considered all the 

statutory factors, including the "degree of improvement in visibility which may reasonably be 

anticipated to result from the use of such [best available retrofit] technology” in our BART 

determinations. We do not consider perceptibility as a threshold criterion for considering 

improvements in visibility to be meaningful. Failing to consider less-than-perceptible 

contributions to visibility impairment would ignore the CAA’s intent to have BART 

requirements apply to sources that contribute to, as well as cause, such impairment. 

Comment: Comments that suggest that each control measure by itself must lead to 

perceptible improvement to the human eye reflects a misunderstanding of the nature of the 

Regional Haze problem. [Sierra Club et. al. (0171) p. 39-41] The Sierra Club et. al. stated that 

various commenters criticize the proposed FIP on the grounds that the expected visibility 

improvement will not be perceptible to the human eye because it will be less than 1.0 deciview. 

This argument fails for several reasons. First, the argument is factually incorrect. The scrubbers 

 

712 70 FR 39104 713 291 F. 3d at 8‐9.
379

EPA proposes to require at Independence Units 1 and 2 will lead to more than one deciview of 

improvement at Hercules-Glades, and approximately one deciview improvement at Caney Creek 

and Upper Buffalo. 80 Fed. Reg. at 18,994. Similarly, if EPA had presented the improvement 

expected from both of the new scrubbers combined at White Bluff Units 1 and 2 (instead of 

separately as EPA did in the proposed rule), the results would be greater than one deciview in 

improvement at Caney Creek. See id. at 18972. 

Moreover, when the different Arkansas sources are operating the new controls, the emissions 

reductions from each source will result in combined visibility improvement that is greater than 

the improvement from controls on any one source. For example, when Flint Creek, White Bluff, 

and Independence operate new scrubbers, the resulting visibility improvement at Caney Creek 

will reflect the total reduction in emissions from all three facilities. The combined improvement 

in visibility from scrubbers at these three facilities is not linear so cannot be determined by 

simply summing the CALPUFF results for each individual unit, but the combined improvement 

from controls will exceed one deciview. 

Not only is it appropriate to consider the combined visibility benefits from all of the SO2 controls 

at all of the controlled sources, it is appropriate to consider the combined benefit from both SO2 

and NOx controls. In the real world, the benefits from operating SO2 and NOx controls are not 

experienced separately; actual visibility conditions depend on the effects of both SO2 and

NOx emissions on atmospheric chemistry. The visibility improvement from all the SO2 and NOx 

controls EPA is proposing far exceeds one deciview. Thus, when all the controls are considered

together, the proposed FIP will result in visibility improvement far greater than one deciview,

and will be perceptible. 

Moreover, it is factually incorrect to assume, as the commenters do, that a change of less than 

one deciview is not perceptible to the human eye. EPA made precisely this point in the preamble 

to the original regional haze regulations, stating that: 

The EPA agrees with the comment that a one deciview change 

should not be considered the threshold of perception in all cases 

for all scenes. The EPA believes that visibility changes of less than 

one deciview are likely to be perceptible in some cases, especially 

where the scene being viewed is highly sensitive to small amounts 

of pollution. 64 Fed. Reg. 35,714, 35,726 (July 1, 1999). 

The comments regarding the perceptibility of controls are based on factual errors. And they also 

misapprehend the legal requirements. There is no requirement in the statute or the regulations 

that visibility improvement exceed one deciview from each control at each unit. The statute 

requires each haze plan to make “reasonable progress” toward the goal of eliminating haze. 42 

U.S.C. § 7491(a)(1), (b)(2). Congress defined reasonable progress to include consideration of 

four factors, id. § 7491(g)(1), but Congress did not dictate the minimum amount of improvement 

that it would deem reasonable. Instead, Congress specifically delegated to EPA the task of 

issuing regulations that specify the requirements for haze plans. Id. § 7491(b)(2). The 

commenters have pointed to no provision in EPA’s regulations requiring that control measures at 
380

each source individually produce visibility improvement equal to at least one deciview—because 

no such provision exists. 

To the contrary, EPA promulgated the regional haze rule after finding that much of the haze 

pollution that Congress wants eradicated is caused by emissions from a large number of sources, 

each of which, aside from the largest EGUs, makes only a small contribution to the haze 

problem. See, e.g., 64 Fed. Reg. 35,715, 35,715 (July 1, 1999) (“Regional haze is visibility 

impairment that is produced by a multitude of sources and activities which emit fine particles 

and their precursors and which are located across a broad geographic area.”). The regional haze 

regulations reflect EPA’s finding that the Congressional goal of eliminating haze can be 

achieved only by tackling the multitude of sources that contribute to haze in national parks and 

wilderness areas. For this reason, EPA has stated that “visibility improvement does not need to 

be perceptible to be deemed significant for BART purposes.” 79 Fed. Reg. 5,032, 5,120 (Jan. 30, 

2014). In arguing that each control must produce visually perceptible visibility improvement, the 

commenters advance a position that is inconsistent with EPA’s long-standing interpretation of 

the regional haze rule. Commenters’ suggestion would also thwart Congress’s goal of ensuring 

progress toward the national visibility goal given EPA’s recognition that the visibility problem is 

caused by a multitude of sources, many of which have only a relatively small impact on 

visibility. 

Response: We agree with the commenter. As we discuss in response to comments above, the 

Regional Haze Rule does not require that controls on a source or group of sources result in 

perceptible visibility improvement. We also agree that in some cases required controls either 

individually or in combination with other required controls will result in perceptible visibility 

improvements at impacted Class I areas on some days. 

Comment: The purported visibility improvement that would result from the SO2 BART 

limit on Domtar Power Boiler 2 would not be perceivable to the human eye and is beyond 

the CALPUFF model’s ability to predict with confidence. [Domtar (0161) p. 10] Domtar 

stated that EPA’s analysis identifies a purported visibility improvement of 0.139 dv. The 

purported level of visibility improvement will not lead to any reasonably anticipated visibility 

improvements as this claimed level of improvement is beyond the CALPUFF model’s ability to 

predict with confidence. At the same time, imposing the BART requirement will add $1.96 

million per year in additional operating cost for the Ashdown Mill. As noted in Nat’l Parks

Conservation Ass’n, it is arbitrary and capricious for EPA to compel a facility (such as the 

Ashdown Mill) to spend millions with no reasonable anticipation of any visibility improvements. 

(Domtar’s detailed comments discussing the CALPUFF model’s Ashdown Mill specific margin 

of error and the Nat’l Parks Conservation Ass’n decision are found elsewhere in this RTC 

document.) 

Moreover, even assuming the purported visibility can be shown to be reasonably anticipated, the 

predicted visibility improvement is almost 10 times less than what can be perceived by the 

human eye. While on a dollar per ton removal basis the limit may appear to be cost effective, the 

significant increase in annual operating expense will adversely affect the Mill‘s competitiveness 

in global markets and negatively affect its economic viability. Such a minor incremental 
381

visibility improvement, so small as to be insignificant and not perceivable to the human eye, 

does not justify the very high additional operating expense proposed to be imposed on the 

Ashdown Mill.

Response: We respond to comments concerning the “margin of error” and comments that 

modeled visibility benefits are below the capabilities of the CALPUFF model and cannot be 

reasonably anticipated elsewhere in this section of the Response to Comments document. We 

address comments concerning the perceptibility of visibility benefits in a separate response to 

comment above. In our analysis, we determined that the BART-eligible source, Domtar, 

“causes” or “contributes” to visibility impairment at downwind Class I areas. As discussed in 

our proposal and demonstrated in our technical record, the FIP emission limit can be achieved by 

additional scrubber reagent in the existing scrubber, which is cost-effective and results in a 

decrease in the visibility impacts from this source at the nearest Class I area. 

We note that the commenter’s characterization of the court’s decision in Nat’l Parks

Conservation Ass’n elsewhere in their submitted comments is incorrect. The Ninth Circuit 

decision cited did not rule on any specific issue related to CALPUFF. Rather, the court ruled on 

a procedural error that EPA did not respond to the comment received regarding the CALPUFF 

margin of error in its rulemaking as required under the law. 714

Comment: Some of EPA’s proposed BART determinations are not justified based on the 

negligible projected visibility improvements. [UARG (0176) p. 4-7] UARG stated that EPA 

proposes BART determinations for certain facilities that are based on EPA projected “visibility 

improvements” that are so minimal – indeed, hypothetical, because they are below, and in most 

cases far below, the level of human perceptibility – that they cannot support any BART 

requirement that entails installation and operation of additional emission controls. EPA’s BART 

Guidelines contemplate use of threshold targets of visibility improvement as appropriate tools for 

evaluating whether a BART-eligible source is properly deemed subject to BART and therefore, 

at least potentially, subject to BART emission limits. 70 Fed. Reg. 39,104, 39,120-21 (July 6, 

2005). The BART Guidelines refer to a 1.0-dv threshold for a source’s “causation” of visibility 

impairment at a Class I area and a 0.5-dv threshold for a source’s “contribution” to visibility 

impairment at a Class I area. Id. at 39,161. Indeed, in promulgating the BART Guidelines, EPA 

stated that “for purposes of determining which sources are subject to BART, States should 

consider a 1.0 deciview change or more from an individual source to ‘cause’ visibility 

impairment, and a change of 0.5 deciviews to ‘contribute’ to impairment.” Id. at 39,120. A 1.0 

dv impact is EPA’s threshold for human perceptibility of visibility impairment. Id. at n.32. 

EPA’s proposed FIP includes proposed BART determinations that would produce projected 

visibility improvements (as estimated by EPA) that do not even approach these thresholds. 

Particularly in light of the significant costs that most of these BART determinations would 

impose, these proposed EPA actions are unreasonable because they would not appreciably 

 

714 “Concurring, Judge Berzon wrote separately to emphasize her understanding that the lead opinion is not 

impugning the EPA’s use of the CALPUFF model generally, but only requiring a sufficiently reasoned response to a 

particular comment regarding CALPUFF’s usefulness in these specific circumstances.” Nat’l Parks Conservation 

Ass’n vs. EPA 
382

mitigate any contribution to visibility impairment. These unreasonable proposed BART 

determinations include the following: 

 Sulfur dioxide (“SO2”) BART for Bailey Unit 1: EPA projects that its proposed SO2

BART emission limit will result in visibility improvement ranging from 0.188 dv to 

0.233 dv at the Class I areas the Agency modeled. 80 Fed. Reg. at 18,952. EPA estimates 

this proposed BART limit has an average cost-effectiveness of $2,559 per ton of SO2

removed. Id. 

 SO2 BART for McClellan Unit 1: EPA projects that its proposed SO2 BART limit will 

result in visibility improvement ranging from 0.3 dv down to only 0.12 dv or less at the 

Class I areas the Agency modeled. Id. at 18,959 & Table 18. EPA estimates this proposed 

BART limit has an average cost-effectiveness of $3,823 per ton of SO2 removed. Id. at 

18,959. 

 Nitrogen oxide (“NOx”) BART for Flint Creek Unit 1: EPA projects that its proposed 

NOx BART limit will result in visibility improvement ranging from only 0.014 dv to 

0.081 dv at the Class I areas the Agency modeled. Id. at 18,968 & Table 29. EPA 

estimates this proposed BART limit has an average cost-effectiveness of $1,761 per ton 

of NOx removed and entails $16 million in capital costs. Id. at 18,967 Table 28. 

 NOx BART for White Bluff Units 1 and 2: EPA projects that its proposed NOx BART 

limit will result in visibility improvement ranging from only 0.038 dv to 0.176 dv at the 

Class I areas EPA modeled for Unit 1 and only 0.047 dv to 0.225 dv at the Class I areas 

modeled for Unit 2. Id. at 18,974 & Tables 37 & 38. Even with estimated average costeffectiveness values of $350 per ton of NOx removed for Unit 1 and $340 per ton of NOx 

removed for Unit 2, id. at 18,974, such negligible – indeed, merely hypothetical – 

visibility improvements are insufficient to justify a requirement of additional emission 

controls to satisfy BART, particularly given that EPA estimates the required controls will 

entail more than $9.5 million in capital costs at Unit 1 and more than $13.5 million in 

capital costs at Unit 2, id. at 18,973 Table 36.715

 SO2 BART for Domtar Ashdown Mill Power Boiler No. 2: EPA projects that its 

proposed SO2 BART determination will result in visibility improvement ranging from 

only 0.139 dv down to 0.05 dv or less at the Class I areas EPA modeled. Id. at 18,985 & 

Table 51. EPA estimates this proposed BART determination has an average costeffectiveness of $1,411 per ton of SO2 removed, id. at 18,984 & Table 50, 18,985, and 

would cost almost $2 million annually, according to EPA, id. at 18,984 & Table 50. 

 

715 EPA’s proposed rule properly recognizes that the minuscule additional visibility improvement that could be 

achieved through installation and operation of more stringent NOx emission controls at White Bluff Units 1 and 2 

(i.e., low NOx burners and separated overfire air together with selective noncatalytic reduction or selective catalytic 

reduction) is far too small to justify the very high additional incremental costs of such controls. See 80 Fed. Reg. at 

18,975; id. at 18,973 Table 36. EPA should apply the same reasoning to withdraw its proposed BART requirement 

for the less costly, but still unjustified, NOx combustion controls for these units. 
383

 NOX BART for Domtar Ashdown Mill Power Boiler No. 2: EPA projects that its 

proposed NOX BART determination will result in visibility improvement ranging from 

only 0.005 dv to 0.181 dv at the Class I areas modeled. Id. at 18,987 & Table 53. EPA 

estimates this BART determination has an average cost-effectiveness of $1,951 per ton of 

NOX removed and entails more than $6.1 million in capital costs. Id. at 18,987 & Table 

52. 

The visibility improvements that these proposed BART emission limits are projected to produce 

are, according to EPA, far from being humanly imperceptible and thus entirely hypothetical. Yet 

the costs these proposed BART controls would impose are very real and quite significant – 

totaling, in some cases, several million dollars. The proposed FIP thus presents a result that 

Congress sought to prevent in enacting the Act’s BART provisions – i.e., to avoid the possibility 

“that a source may be forced to spend millions of dollars for new technology that will have no 

appreciable effect on the haze in any Class I area.” Am. Corn Growers Ass’n v. EPA, 291 F.3d 1, 

7 (D.C. Cir. 2002). EPA cannot square these proposed BART determinations with the statutory 

BART provisions as interpreted in American Corn Growers because the controls EPA proposes 

to impose would force sources “to spend millions of dollars” on new controls that, under EPA’s 

own definition of humanly perceptible visual change, “will have no appreciable effect on the 

haze in any Class I area.” To avoid taking actions that would be inconsistent with the Act, EPA 

should withdraw these unjustified proposed BART limits. 

Response: We address comments concerning the perceptibility of visibility improvements in a 

separate response to comments above. We disagree with the commenter that imperceptible 

visibility benefits are “hypothetical.” As we state in the Regional Haze Rule, “Failing to 

consider less-than-perceptible contributions to visibility impairment would ignore the CAA’s 

intent to have BART requirements apply to sources that contribute to, as well as cause, such 

impairment.”716

The commenter confuses the threshold applied to total visibility impacts from all BART-eligible 

units at a facility and the potential visibility improvement from controls at individual units. The 

Regional Haze Rule provides that BART–eligible sources with a 0.5 dv impact at a Class I area 

“contribute” to visibility impairment and must be analyzed for BART controls. BART 

determining authorities, however, are free to establish thresholds less than 0.5 dv. The 0.5 dv 

threshold in the context of BART is used to assess the maximum total visibility impact from all 

BART units at a facility, typically based on CALPUFF modeling. If the impact from all the 

BART sources at a facility is above the threshold, then each BART unit must be evaluated for 

controls, and therefore the visibility improvement anticipated from controls would be less than 

0.5 dv on a facility basis, and may be much less than 0.5 dv on a unit specific basis for BART 

sources with multiple BART units. For example, a facility comprised of four identical BARTeligible units, would be subject to BART if the total visibility impact of the source was 0.5 dv. 

In this case, the maximum visibility benefit that could be achieved from controls on both NOx 

and SO2 on any individual unit would be 0.125 dv (one-fourth of 0.5 dv). The level of visibility 

benefit would be one factor to consider along the cost of controls and other factors in informing 

 

716 70 FR 39104, 39129
384

the BART determination. For each of the required controls listed by the commenter, we 

evaluated the cost of controls along with the anticipated visibility benefit due to controls, the 

remaining useful life of the source, energy and non-air quality environmental impacts, and 

existing pollution control technology of all potential available controls in arriving at a BART 

determination. 

The commenter mischaracterizes a statement made by the D.C. Circuit Court of Appeals. The 

statement made by the Court is as follows: “[u]nder EPA's take on the statute, it is therefore 

entirely possible that a source may be forced to spend millions of dollars for new technology that 

will have no appreciable effect on the haze in any Class I area.”717 The Court made this statement 

based on its interpretation of our Regional Haze Rule, and merely alluded to the possibility that, 

as is, the Rule may result in a situation where new retrofit technology is required for a source 

when the technology will not have an appreciable effect on visibility.718 We note that the court 

does not establish perceptibility as a threshold in determining what an appreciable effect on 

visibility is. As discussed elsewhere, “Failing to consider less-than-perceptible contributions to 

visibility impairment would ignore the CAA’s intent to have BART requirements apply to 

sources that contribute to, as well as cause, such impairment.”719 Furthermore, the "degree of 

improvement in visibility which may reasonably be anticipated to result from the use of such 

[best available retrofit] technology" is just one of several factors the State, or EPA in the case of 

a FIP, must consider in determining what BART is for a specific source. 

In Am. Corn Growers Ass’n, the Court disagreed with the approach used by EPA to determine 

what BART eligible sources are reasonably anticipated to cause or contribute to regional haze 

and therefore subject to BART.720 The approach in the Regional Haze Rule required a State to 

analyze “the degree of visibility improvement that would be achieved in each mandatory Class I 

Federal area as a result of the emission reductions achievable from all sources subject to BART 

located within the region that contributes to visibility impairment in the Class I area."721 The 

Court held that the Rule’s treatment of “the degree of improvement in visibility which may 

reasonably be anticipated to result from the use of such technology” factor infringed on states’ 

authority with respect to BART determinations under the Act.722 The Court noted that the Act 

does not assign a specific weight with which to consider each factor, it solely mandates that all 

the factors be considered in making a BART determination.723 The Court’s issue was not with 

the weight, or lack thereof, placed on this factor by EPA. It found issue with what it considered 

to be “dramatically” different treatment of the factor by EPA.724 While the court in American 

Corn Growers found that we had impermissibly constrained State authority, it did so because it 

found that we forced States to require BART controls without first assessing a source's particular 

contribution to visibility impairment. This is not the case with our action. In response to this 

 

717 Am. Corn Growers Ass’n v. EPA, 291 F.3d 1, 7 (D.C. Cir. 2002) 718 Id. 719 70 FR 39104, 39129 720 Am. Corn Growers Ass’n v. EPA, 291 F.3d 1, 7 (D.C. Cir. 2002) at 7-8 721 40 C.F.R. § 51.308(e)(1)(ii)(B) 722 Am. Corn Growers Ass’n v. EPA, 291 F.3d 1, 7 (D.C. Cir. 2002) 723 291 F.3d at 6 724 Id. 
385

court decision and address these concerns we finalized a revised Regional Haze Regulations and 

Guidelines for Best Available Retrofit Technology (BART) Determinations.725

With regard to the comment we properly recognize that the minuscule additional visibility 

improvement that could be achieved through installation and operation of LNB/SOFA and 

SNCR at White Bluff Units 1 and 2 is too small to justify the very high additional incremental 

costs of controls, and that the same reasoning should apply to the required NOx combustion 

controls for these units, we disagree that the same reasoning would apply. As we detail in our 

proposal, LNB/SOFA was determined to be very cost-effective (approximately $350/ton) and 

result in visibility improvements ranging from 0.038 to 0.176 dv for Unit 1 and 0.047 to 0.225 dv 

for Unit 2 at each of the affected Class I areas (98th percentile basis). We determined that the 

addition of SNCR was not justified given the smaller additional visibility benefits (ranging from 

0.007 to 0.034 dv for Unit 1 and 0.007 to 0.033 dv for Unit 2 at each of the affected Class I 

areas) and incremental costs in excess of $9,000/ton. 

7.c. Model Selection 

Comment: CALPUFF modeling cannot be used to justify controls at Independence under 

the reasonable progress requirements. 

[Entergy Arkansas Inc. (0166) p.35-37] Entergy Arkansas Inc. stated that it acknowledges that, 

under the Regional Haze Rule, “the URP does not establish a “safe harbor” for the state in setting 

its reasonable progress goals.” 80 Fed. Reg. at 18,992 (referencing 64 Fed. Reg. at 35,732). 

Nonetheless, EPA must demonstrate that additional controls are rational and economically 

justifiable and that the amount of progress that would result will be “reasonable based upon the 

statutory factors.” Id. EPA has explained that this requires a consideration of the projected 

visibility benefit expected from the controls. Id. At 18,993. 

EPA admits that it did not perform refined, multi-state modeling to determine the amount of 

visibility improvements that would be achieved through the installation of controls because it 

would be difficult, time-consuming, and expensive. Instead, the Agency took a “thumbnail” 

approach in an attempt to justify the proposed controls based on how long it would take to 

achieve background levels. 80 Fed. Reg. at 18,997-98. EPA’s use of CALPUFF, a single source 

model, for evaluating the reasonable progress benefits of installing controls at Independence is 

misplaced and clearly in error. CALPUFF is not appropriate for reasonable progress purposes as 

it addresses a fundamentally different question than a proper reasonable progress analysis. TX 

FIP TSD at A-35. As EPA itself has recognized, CALPUFF is overly simplistic and greatly 

overstates the effect of single source emissions. BART Guidelines, 70 Fed. Reg. 39,104, 39,121 

(July 6, 2005) (“there are other features of our recommended modeling approach that are likely 

to overstate the actual visibility effects of an individual source. Most important, the simplified 

chemistry in the model tends to magnify the actual visibility effects of that source.”). CALPUFF 

also fails to show the effects of multiple sources, and is much less sophisticated in its treatment 

of the chemical interactions of the different pollutants in the atmosphere than CAMx. 

 

725 70 FR 39104. 
386

EPA has recognized that CAMx, a photochemical transport 3-dimensional grid model, is a more 

appropriate modeling tool for reasonable progress purposes. Proposed Texas Regional Haze FIP, 

79 Fed. Reg. at 74,877-78. BART analyses assess the impact of a single facility based on the 

maximum or 98th percentile impacts, regardless of whether the Class I area was actually 

experiencing high visibility impairment on any given day. Since CALPUFF does not conduct an 

analysis considering all the emissions from all potential sources, some of the days with the worst 

model-predicted concentrations could be days that are not significantly impaired. Reasonable 

progress modeling using a photochemical model, such as CAMx, allows EPA to evaluate 

impacts from a source (with all other sources included in the modeling) on a Class I area’s best 

and worst days. Id. at 74,878. 

The draft EPA Modeling Guidance for Demonstrating Attainment of Air Quality Goals for 

Ozone, PM2.5, and Regional Haze (Dec. 2014) (“Draft Modeling Guidance”) discusses the use of 

photochemical grid models and notes that Community Multiscale Air Quality Model) 

(“CMAQ”) and CAMx are the most commonly used models for attainment demonstrations. The

Draft Modeling Guidance specifically notes that “a modeling based demonstration of the impacts 

of an emissions control scenario... as part of a regional haze assessment usually necessitates the 

application of a chemical transport grid model.” Draft Modeling Guidance at 22.726 Throughout 

the Draft Modeling Guidance, the discussion is focused on items specific to photochemical grid 

models such as CAMx, including emissions inventories, supporting models, pre-processors, and 

applying a model to changes in visibility. 

According to the Draft Guidance, “the emission sources included in the analysis must be 

comprehensive, including emissions from all source categories” (i.e., point sources, non-point 

stationary sources, on-road and non-road mobile sources, fires, and biogenic sources) and “‘all’ 

sources of emissions.” Id. at 32, 36. A CAMx modeling analysis includes a comprehensive 

inventory, capturing each of these source categories, which are then available to react with 

available precursors. By using the comprehensive inventory, this limits the amount of precursors 

available to react with the emissions from a facility or source in question. This has been referred 

to by EPA as a “dirty background analysis.” CALPUFF analyses conducted in support of BART 

determinations do not consider the full inventory of sources and thus do not account for other 

pollutants challenging and consuming precursor emissions. As such, ammonia and other 

precursor pollutants are more fully available to react with a facility’s emissions and generate 

haze impacts in a modeled simulation using CALPUFF. This is referred to by EPA as a “clean 

background analysis.” Therefore, the use of CALPUFF does not reflect the interaction of 

pollutants in the atmosphere as accurately as CAMx does. 

Notably, EPA recently issued a proposal on July 29, 2015, which would remove CALPUFF from 

EPA’s preferred list of air dispersion models in its Guideline on Air Quality Models 

(“Guideline”), in Appendix W to 40 C.F.R. Part 51. Although EPA states that the proposed 

changes to the Guideline would not affect its recommendation that CALPUFF be used in the 

BART determination process, EPA made no such assurances regarding the use of CALPUFF for 

a reasonable progress analysis. Instead, EPA’s proposal emphasizes the use of chemical transport 

 

726 The Draft Modeling Guidance is available at http://www.epa.gov/scram001/guidance/guide/Draft_O3-PMRH_ 

Modeling_Guidance‐2014.pdf.
387

models for assessing visibility impacts from a single source or small group of sources. According 

to the Agency, 

Chemical transport models are well suited for the purpose of 

estimating long-range impacts of secondary pollutants, such as 

PM2.5, that contribute to regional haze and other secondary 

pollutants, such as ozone, that contribute to negative impacts on 

vegetation through deposition processes. These multiple needs 

require a full chemistry photochemical model capable of 

representing both gas, particle, and aqueous phase chemistry for 

PM2.5, haze, and ozone. 80 Fed. Reg. at 45,349. 

CALPUFF is clearly inferior in this regard. Indeed, EPA’s Interagency Workgroup on Air 

Quality Modeling Phase 3 Summary Report: Long Range Transport and Air Quality Related 

Values,

727 which EPA has made available as a supporting document for the proposed revisions to 

Appendix W, makes clear that CALPUFF should not be used for a reasonable progress analysis. 

The report explains that, “[a] modeling system that treats emissions from all known 

anthropogenic and biogenic emissions sources with realistic chemical and physical 

transformations should be utilized to estimate future visibility conditions at a Class I area. The 

most appropriate tool that contains these qualities is a photochemical grid model [such as 

CAMx].” Id. at 6. It further explains that “the results from a BART determination or similar 

modeling using CALPUFF cannot be directly compared to estimated impacts of emissions 

controls from a single source on a reasonable progress goal.... Lagrangian puff models are not 

ideal for reasonable progress demonstrations since they typically characterize one or a small 

group of sources.” Id. at 9. 

[Entergy Mississippi Inc. (0168) p. 8-10; Conway Corporation et. al. (0172) p. 8-9; and EEAA 

(0173) p. 14-15] EMI, Conway Corporation et. al., and EEAA stated that EPA improperly relied 

on CALPUFF modeling in its reasonable progress analysis and, as a result, significantly overestimated the Independence Plant’s contribution to visibility impairment and the deciview 

improvement that would result from the installation and operation of emissions controls at the 

Independence Plant.728 The visibility impairment at Arkansas’ two Class I areas is caused 

overwhelmingly by point sources outside of the state, secondary organic aerosols - biogenic 

(“SOAB”), mobile sources, and Arkansas area sources729- not by Arkansas point sources such as 

power plants. Therefore, EPA’s singular focus on the Independence Plant will not result in any 

meaningful improvement in visibility at Caney Creek or Upper Buffalo and will not affect 

Arkansas’ continued progress toward the 2064 natural visibility goal. 

 

727 Docket ID EPA-HQ-OAR-2015-0310-0004. 728 Notably, EPA issued on July 29, 2015, a proposal to remove CALPUFF from EPA’s preferred list of dispersion 

models used for Clean Air Act purposes. 80 Fed. Reg. 45,340 (July 29, 2015). 

729 EPA defines an area source as “a collection of similar emission units within a geographic area.” EPA, 

Introduction to Area Source Emission Inventory Development, at 1.1-3 (Jan. 2001) available at 

http://www.epa.gov/ttnchie1/eiip/techreport/volume03/iii01_apr2001.pdf. “Area sources collectively represent 

individual sources that are small and numerous, and that have not been inventoried as specific point, mobile, or 

biogenic sources. Individual sources are typically grouped with other like sources into area source categories.” Id. 
388

EPA admits that it did not perform the refined, multi-state modeling necessary to determine the 

amount of visibility improvements that would be achieved because it would be difficult, timeconsuming, and expensive. Instead, the Agency took a “thumbnail”/abbreviated and unlawful 

approach in an attempt to justify the proposed controls based on how long it would take to 

achieve background levels.730 The failure to perform a necessary and proper analysis is not 

insignificant and only undermines the basis of EPA’s proposal to require the installation and 

operation of controls at the Independence Plant. 

EPA’s use of CALPUFF, a single source model, for evaluating the reasonable progress benefits 

of installing controls at the Independence Plant is misplaced and clearly in error. While 

CALPUFF may be appropriate for a BART analysis, CALPUFF is not appropriate for reasonable 

progress purposes as it addresses a fundamentally different question.731 CALPUFF is overly 

simplistic, greatly overstates the effect of single source emissions, does not show the effects of 

multiple sources and is much less sophisticated in its treatment of the chemical interactions of 

the different pollutants in the atmosphere than CAMx, which EPA has recognized is the more 

appropriate modeling tool for reasonable progress purposes.732 Accordingly, EPA’s inappropriate 

use of CALPUFF for reasonable progress purposes vastly overstates the visibility improvements 

that would result from the proposed controls for the Independence Plant.733

Comment: [EarthJustice/ Dr. Gray] On Page 13 of ADEQs comments23, ADEQ claims: “The 

Reasonable Progress Goals chosen by EPA are based on admittedly flawed methods that reject 

the refined modeling approach used by EPA in states such as Texas.” 

Firstly, USEPA made it clear why they did not use CAMx to determine the impact of FIP 

controls on visibility. The RPG modeling must consider impacts from all sources which would 

require much larger and more comprehensive modeling than the “comparatively simple single 

source CALPUFF modeling used for individual BART assessments.” A “refined” modeling 

approach would require compilation of a very large emission inventory for Arkansas and the 

surrounding states, and more sophisticated modeling to account for the interactions of many 

pollutants. (The objective of a BART analysis using CALPUFF is to determine the impact of a 

single source against a “clean background”.) As EPA states: “Developing all of the necessary 

input files, running the photochemical model, and post-processing the model outputs would take 

several months at a minimum.” The modeling system is being used to determine the change in 

visibility (delta dV) at Class I areas due a relatively small change in the overall emissions 

patterns within the entire modeling domain. The only change within the entire model, which 

includes the emissions from thousands of sources, is the emission level of a single modeled 

Arkansas source (Independence). In other words, the model is being used for the RPG analysis to 

determine the sensitivity of the computed visibility metrics (due to all sources) to changes in 

emission rates at just one source within the modeling system. 

Secondly, ADEQs assessment of the methodology used for Texas sources is incorrect. In fact, 

 

730 80 Fed. Reg. at 18,997-98. 731 TX FIP TSD at A-35. 732 Texas Regional Haze FIP, 79 Fed. Reg. 74,877-78. 733 EPA’s CALPUFF modeling indicates that the SO2 and NOx controls proposed for Independence will result in a 

1.952 dv improvement in Caney Creek and a 1.782 dv improvement in Upper Buffalo. 
389

EPA Region 6 also used an emission "scaling" approach to determine the effects of various 

control scenarios for their evaluation of Texas sources. For Arkansas, EPA Region 6 used the 

CENRAP 2018 base case projections as its starting point. For Texas, EPA Region 6 also used the 

same CENRAP 2018 base case projections, but supplemented it with a couple additional CAMx 

model runs (with updated emission levels), representing low and high control levels. The 

modeled species concentrations (contributions from individual sources) for the evaluated control 

scenarios were determined using interpolation (or extrapolation, in many cases) of the two (low 

and high) modeled levels using a similar source-by-source SO2 and NOX emissions scaling 

approach that is currently being applied for the evaluation of the sources in Arkansas. EPA 

Region 6 did not run the CAMx model repeatedly to determine the visibility effects of 

controlling individual sources. 

In Texas, the model results were used to demonstrate that the overall change in species 

concentrations was very nearly linearly proportional to the change in emission levels for an 

individual source (with very high linear correlation coefficients near 1.0). This strongly supports 

their use of the emission scaling approach for Arkansas. If the CAMx model were used to 

determine the impact of emission controls on a single source in Arkansas (such as 

Independence), it is therefore expected that the modeled reductions in sulfate and nitrate 

concentrations at each of the Class I areas will be very nearly proportional to the SO2 and NOX 

concentration reductions. In other words, the emission scaling approach has been shown to be 

mathematically sound and quite appropriate, especially considering the resources that would be 

required to exercise CAMx separately for each control measure at each evaluated source. 

Response: The commenters confuse the single source analysis for evaluating the visibility 

impact and benefits of controls on units at the Independence facility and the analysis to estimate 

the visibility benefits of all controls on the 20% worst days in establishing a new reasonable 

progress goal for 2018. We utilized CALPUFF modeling following the same modeling protocol 

relied on for the BART analyses to assess the visibility impacts and potential benefits of controls 

for the units at the Independence facility. For estimating the total visibility benefit from all 

controls and estimating a new reasonable progress goal that reflects those controls, we relied on 

the CENRAP’s 2018 CAMx modeling results, including source apportionment results, and the 

projected emission inventories, and scaled the results as described in the TSD. While we 

acknowledge that this approach is not as refined an estimate as would be attained in performing a 

new photochemical modeling run, it is based on scaling of earlier photochemical modeling 

results and not on CALPUFF modeling, as the commenter suggests. We disagree with the 

commenter’s characterization of our analysis as a “thumbnail” approach and noted in our 

proposal that similar approaches have been used in other actions in Hawaii and Arizona. As 

discussed in the proposed action, our determination that controls were reasonable for the 

Independence units was based on our evaluation of the four-factors and including consideration 

of the visibility benefit of controls. For consideration of the visibility benefits, we relied on the 

results of our CALPUFF modeling, the CENRAP CAMx source apportionment results, and point 

source emission inventory data that initially identified the Independence facility as having the 

greatest potential to impact visibility at nearby Class I areas among all sources not already 

controlled under the BART requirements. 
390

The 2005 BART Guidelines recommended the use of CALPUFF for assessing visibility 

(secondary chemical impacts) but noted that CALPUFF’s chemistry was fairly simple. The 

visibility results from CALPUFF could be used as one of the five factors in a BART evaluation 

and the impacts should be utilized somewhat in a relative sense because CALPUFF was not 

explicitly approved for full chemistry calculations.734 The BART guidelines also provided the 

option to potentially use photochemical grid models (such as CAMx) in the future if modeling 

tools available were appropriate and EPA approved of the technical approaches and how the 

model would be utilized.735 Appendix W gives us discretionary authority in the selection of what 

models to use for visibility assessments with modeling systems, and models such as CALPUFF, 

CMAQ, REMSAD, and CAMx have all been used for that purpose. Specifically for singlesource reasonable progress assessments similar to that done here for Independence, CALPUFF 

has been used for the majority of sources, while CAMx has been used in some situations, most 

notably and as noted by the commenter, in evaluating specific Texas sources for reasonable 

progress. In 2006/7, EPA OAQPS and EPA Region 6 consulted with FLM representatives and 

approved Texas’ BART screening modeling protocol using source apportionment tools in 

CAMx.736 

Under the BART guidelines, CALPUFF should be used as a screening tool and appropriate 

consultation with the reviewing authority is required to use CALPUFF in a BART determination 

as part of a SIP or FIP. The BART Guideline cited and referred to EPA’s Guideline on Air 

Quality Models (GAQM)737 which includes provisions to obtain approval through consultation 

with the reviewing authority. Moreover, we also note that in EPA’s document entitled Guidance 

on the Use of Models and Other Analyses for Demonstrating Attainment of Air Quality Goals 

for Ozone, PM2.5, and Regional Haze (EPA-454/B-07-002), that Appendix W does not identify 

a particular modeling system as ‘preferred’ for modeling conducted in support of state 

implementation plans under 40 CFR 51.308(b). A model should meet several general criteria for 

it to be a candidate for consideration. These general criteria are consistent with the requirements 

of 40 CFR 51.112 and 40 CFR 51, Appendix W. Therefore, it is correct to interpret that no 

model system is considered ‘preferred’ under 40 CFR 51, Appendix W, Section 3.1.1 (b) for 

either secondary particulate matter or for visibility assessments. Under this general framework, 

we followed the general recommendation in Appendix Y to use CALPUFF as a screening 

 

734 70 FR 39123, 39124. ‘‘We understand the concerns of commenters that the chemistry modules of the CALPUFF 

model are less advanced than some of the more recent atmospheric chemistry simulations. To date, no other 

modeling applications with updated chemistry have been approved by EPA to estimate single source pollutant 

concentrations from long range transport.’’ and in discussion of using other models with more advanced chemistry it 

continues, ‘‘A discussion of the use of alternative models is given in the Guideline on Air Quality in appendix W, 

section 3.2.’ 

735 70 FR 39123, 39124. “The use of other models and techniques to estimate if a source causes or contributes to 

visibility impairment may be considered by the State, and the BART guidelines preserve a State’s ability to use 

other models. Regional scale photochemical grid models may have merit, but such models have been designed to 

assess cumulative impacts, not impacts from individual sources. Such models are very resource intensive and time 

consuming relative to CALPUFF, but States may consider their use for SIP development in the future as they are 

adapted and demonstrated to be appropriate for single source applications.” 736 See “Revised Draft Final Modeling Protocol, Screening Analysis of Potentially BART-Eligible Sources in 

Texas” Prepared for TCEQ by ENVIRON, September 27, 2006; “Modeling Guidance: Guidance for the 

Application of the CAMx Hybrid Photochemical Grid Model to Assess Visibility Impacts of Texas BART Sources 

at Class I Areas,” Prepared for TCEQ by ENVIRON, December 13, 2007. 737 40 CFR part 51 Appendix W, Guideline on Air Quality Models, 70 FR 68218 
391

technique since the modeling system has not been specifically approved for chemistry. The use 

of CALPUFF is subject to GAQM requirements in section 3.0(b), 4, and 6.2.1(e) which includes 

an approved protocol to use the current version.

We and some states have used CALPUFF to model visibility benefits as part of the reasonable 

progress analysis, and have used largely the same methodology as in BART modeling (i.e. use of 

24 hour or hourly maximum emissions, a “clean” background condition, and a maximum or 98th 

percentile metric).738 This approach provides information on the relative visibility benefits of 

controls to inform the evaluation of cost-effectiveness as part of the four factor analysis and has 

the benefit that it is immediately comparable to modeling used for BART determinations. 

Compared to a CAMx modeling exercise, CALPUFF modeling of one or more sources requires 

much less resources and time. However, the CALPUFF approach models the impacts from the 

single facility with limited chemistry and focuses on the maximum impacts from the source 

rather than the visibility impairment on the 20% worst days. We agree with the commenter that 

the CAMx model, may be better suited for evaluating the average visibility impairment due to 

individual sources during the 20% worst days as part of reasonable progress analysis. 

Photochemical models, like the CAMx model, provide a complete representation of emissions, 

chemistry, transport, and deposition, while CALPUFF treats a single source with simplified 

chemistry and parameterized physical processes. Furthermore, the CAMx model can be used to 

evaluate a large number of individual sources, and there are concerns in using CALPUFF for 

modeling impacts at distances much greater than 300 km from the source. In our analysis of 

source-specific impacts of Texas sources, we determined that CAMx was best suited for the 

complex analysis that we needed to perform in evaluating a large number of sources (38 separate 

facilities for our initial analysis) at distances from impacted Class I areas much larger than 

300km, and in focusing on the 20% worst days. We discuss our selection of CAMx modeling in 

our Texas analysis in depth in the Response to Comments Document that accompanies that 

action.739 As noted by EarthJustice, we did not perform a final CAMx model scenario to obtain 

the new RPGs in our Texas action, and instead relied on a scaling analysis similar to the 

methodology used in this action to adjust the CENRAP modeled RPG values based on the source 

apportionment data and emissions data available. As discussed above, RPGs were adjusted in 

actions in Arizona, Hawaii, Texas/Oklahoma and in this action by estimating the visibility 

improvement due to required controls based on scaling the anticipated emission reductions and 

the source apportionment modeling. In Texas/Oklahoma, source-specific source apportionment 

data and emissions were utilized. In the other states, emissions and source-apportionment data 

on a state and source category level were utilized. 

 

Consistent with the examples discussed above740, in evaluating the sources in Arkansas, we 

determined that CALPUFF was adequate since we determined that only one source needed to be 

assessed for a reasonable progress evaluation, and that source was well within the recommended 

range for CALPUFF modeling of under 300km from the Class I areas of interest. In fact, three 

 

738 For example see summary of the reasonable progress analyses for specific sources in Arizona (79 FR 9353), 

North Dakota (76 FR 58631), Montana (77 FR 24065), and Wyoming (78 FR 34785) 

739 Texas Regional Haze FIP, EPA Response to Comments Document, available at www.regulations.gov, Document 

ID: EPA-R06-OAR-2014-0754-0087. 

740 For example see summary of the reasonable progress analyses for specific sources in Arizona (79 FR 9353), 

North Dakota (76 FR 58631), Montana (77 FR 24065), and Wyoming (78 FR 34785) 
392

of the four impacted Class I areas lie within 200km of the source. We discuss comments 

concerning why our reasonable progress screening analysis focused on NOx and SO2 emissions 

from Arkansas point sources and our determination that additional analysis was necessary for the 

Independence facility in response to comments elsewhere in this document. In evaluating 

visibility impacts and benefits for those sources subject to BART, we relied on CALPUFF 

modeling prepared by the facilities. Utilizing CALPUFF for the reasonable progress analysis on 

Independence provided for a consistent approach for all facilities and allowed for direct 

comparison of the visibility impacts and benefits across all facilities impacted by the proposed 

rulemaking. In some situations, the CALPUFF modeled maximum or 98th percentile impacts of 

the facility may not coincide with the days that make up the worst 20% monitored days at the 

Class I area. Therefore, the visibility benefits modeled by CALPUFF are not directly 

comparable to the visibility benefits that would be anticipated on the 20% worst days from those 

specific controls. However, our analysis of the CENRAP 2018 CAMx photochemical modeling 

showed that: on the 20% worst days, Arkansas point sources contribute significantly to visibility 

impairment at Arkansas’ Class I areas (greater than 4% of total visibility impairment at each 

Arkansas Class I area); review of the emission inventory revealed that a very small number of 

point sources are responsible for the majority of the point source emissions of NOx and SO2 and 

therefore a very small number of point sources are responsible for the portion of visibility 

impairment due to Arkansas point sources on the 20% worst days; and the Independence facility 

is one of the very largest emission sources and it is located relatively close (under 200 km) to 

three Class I areas. Therefore, we identified Independence as having the greatest potential to 

impact visibility on the 20% worst days based on emissions and location and should be evaluated 

for reasonable progress controls. We determined that CALPUFF modeling was appropriate and 

sufficient to provide information on the degree of visibility benefits of controls on Independence 

to inform the reasonable progress assessment. Through our evaluation of the four statutory 

factors, we identified cost-effective controls. We then considered visibility benefits of the costeffective controls. We conducted CALPUFF modeling to determine the level of visibility 

impacts and benefits anticipated by SO2 and NOx controls at nearby impacted Class I areas, 

evaluating the 98th percentile visibility impacts.741 

As we discuss elsewhere, Entergy submitted CAMx model results as part of their comments. 

The modeled contribution to visibility impairment due to baseline emissions from the 

Independence facility alone were approximately 1.3% of the total visibility impairment at each 

Arkansas Class I area. In terms of deciviews, the average impact over the 20% worst days based 

on Entergy’s CAMx modeling (adjusting to natural background conditions) is over 0.5 dv at the 

Arkansas Class I areas and even larger at the Class I areas in Missouri. These results estimate 

the visibility impacts from the source on the 20% worst days and confirm and provide additional 

support to our determination that Independence significantly impacts visibility, both in terms of 

maximum visibility impairment and visibility impairment on the 20% worst days, and that 

emissions controls provide for meaningful visibility benefits towards the goal of natural visibility 

conditions. In conclusion, both approaches, CALPUFF and CAMx, support the determination 

that the required controls are reasonable. 

 

741 See Summary of Additional Modeling for Entergy Independence and Appendix C to the TSD, available in the 

docket for this action 
393

The commenter cites the BART guidelines and asserts that EPA recognizes that the CALPUFF 

model is overly simplistic and overstates the effect of single-source emissions. This is not an 

accurate characterization. The CALPUFF model can both under-predict and over-predict 

visibility impacts. For example, the 2012 ENVIRON report on Comparison of Single-Source Air 

Quality Assessment Techniques for Ozone, PM2.5, other criteria pollutants and AQRVs found 

that CALPUFF predicted highest 24-hr nitrate and sulfate concentrations lower than those 

predicted by the CAMx photochemical grid model in some areas within the modeling domain.742 

In a presentation for the 2010 annual Community Modeling and Analysis System conference, 

Anderson et al. (2010)743 found that the CALPUFF model frequently predicted lower nitrate 

concentrations compared to the CAMx photochemical grid model which has a much more 

rigorous treatment of photochemical reactions. EPA recognized the uncertainty in the CALPUFF 

modeling results when EPA made the decision, in the final BART Guidelines, to recommend that 

the model be used to estimate the 98th percentile visibility impairment rather than the highest 

daily impact value. We made the decision to consider the less conservative 98th percentile 

primarily because the chemistry modules in the CALPUFF model are simplified and likely to 

provide conservative (higher) results for peak impacts. Since CALPUFF’s simplified chemistry 

could lead to model over predictions and thus be conservative, EPA decided to use the less 

conservative 98th percentile.744 While recognizing the limitations of the CALPUFF model in the 

Preamble, EPA concluded that, for the specific purposes of the Regional Haze Rule's BART 

provisions, CALPUFF is sufficiently reliable to inform the decision making process.745 

With regard to comments concerning the draft EPA modeling Guidance for Demonstrating 

Attainment of Air Quality Goals for Ozone, PM 2.5, and Regional Haze (Dec. 2014), the 

commenter confuses the single-source analysis to evaluate visibility impacts and benefits of 

controls on an individual source with the analysis of overall visibility conditions at a Class I area 

due to the complete emission control strategy for all sources developed under the reasonable 

progress and long-term strategy requirements. The draft modeling guidance (as does the current 

guidance746) discusses the projection of overall visibility conditions and the need for 

photochemical grid modeling to account for all emission sources to model current visibility 

conditions and project future visibility conditions in response to the overall emission control 

scenarios. The section of the modeling guidance on regional haze747 describes the recommended 

modeling analysis to assess overall future visibility improvement relative to the uniform rate of 

progress or “glidepath” (for each Class I area) as part of a reasonable progress analysis, and does 

 

742 Comparison of Single‐Source Air Quality Assessment Techniques for Ozone, PM2.5, other Criteria Pollutants 

and AQRVs, ENVIRON, September 2012. 

743 Anderson, B., K. Baker, R. Morris, C. Emery, A. Hawkins, E. Snyder “Proof-of-Concept Evaluation of Use of 

Photochemical Grid Model Source Apportionment Techniques for Prevention of Significant Deterioration of Air 

Quality Analysis Requirements” Presentation for Community Modeling and Analysis System (CMAS) 2010 Annual 

Conference, (October 11-15, 2010) can be found at http://www.cmascenter.org/conference/2010/agenda.cfm. 744 “Most important, the simplified chemistry in the model tends to magnify the actual visibility effects of that 

source. Because of these features and the uncertainties associated with the model, we believe it is appropriate to use 

the 98th percentile—a more robust approach that does not give undue weight to the extreme tail of the distribution.” 

70 FR 39104, 39121. 

745 70 FR 39123 746 2007 EPA modeling Guidance on the Use of Models and other Analyses for Demonstrating Attainment of Air 

Quality Goals for Ozone, PM 2.5, and Regional Haze

747 draft EPA modeling Guidance for Demonstrating Attainment of Air Quality Goals for Ozone, PM 2.5, and

Regional Haze (Dec. 2014)Section 4.8 “What Is The Recommended Modeling Analysis for Regional Haze?”
394

not discuss source-specific analyses that may be completed to inform a reasonable progress 

assessment.748 Because the CALPUFF model only evaluates visibility impacts from a singlesource or a limited group of sources, it is not capable of projecting overall visibility conditions 

due to all sources and controls. Consistent with this draft guidance and the current guidance, 

CENRAP and Arkansas utilized CAMx and CMAQ modeling to project future visibility 

conditions for 2018 for establishment of the RPGs and comparison with the URP. Similarly, we 

utilized the CENRAP CAMx model results and adjusted them based on source apportionment 

and emissions data, to estimate the new RPGs for the Arkansas Class I areas considering the 

anticipated changes in emissions due to all required controls. We discuss the selection of models 

for assessing individual visibility impacts and benefits of controls above. 

The commenters cite to the proposed revisions to the Guideline on Air Quality Models 

(Appendix W) and the IWAQM Phase 3 modeling report749 and assert that they support the 

conclusion that the use of CALPUFF for Independence was inappropriate. We disagree with the 

commenter. As we discuss above, we agree with the commenter that the CAMx model, may be 

better suited for a reasonable progress analysis in certain situations. Proposed revisions to 

Appendix W discuss removing the requirement to use CALPUFF for long-range transport 

assessments and as a preferred model due to the need to provide flexibility in estimating singlesource secondary pollutant impacts and concerns about management and maintenance of the 

CALPUFF modeling code.750 These proposed changes do not affect EPA's recommendation that 

States use CALPUFF to determine the applicability and level of BART in regional haze 

implementation plans. The proposed changes also do not preclude the use of CALPUFF for any 

other non-BART analysis, such as long-range transport PSD increment assessment, but 

recognizes that modern chemical transport models have evolved sufficiently and provide a 

credible platform for estimating potential visibility impacts from a single or small group of 

emission sources.751. The proposed Appendix W rule simply proposes to remove CALPUFF as a 

preferred model. If the proposed changes are finalized, CALPUFF or any other model can still be 

used for any non-BART analysis with the appropriate justification as an “alternative model”. 

 

748 draft EPA modeling Guidance for Demonstrating Attainment of Air Quality Goals for Ozone, PM 2.5, and 

Regional Haze (Dec. 2014) at 173: “The modeling can be used to determine the predicted improvement in visibility 

and whether the visibility levels are on, above, or below the glidepath. It cannot by itself determine the reasonable 

progress goals or determine whether the reasonable progress goal is met, and it does not satisfy the requirements for 

the statutory four factor analysis. See the Regional Haze Rule and related guidance documents for more information 

on the four factor analysis, including control strategy analysis for single sources.” 749 Interagency Workgroup on Air Quality Modeling Phase 3 Summary Report: Long Range Transport and Air 

Quality Related Values (July 2015) 

750 80 CFR 45349: “in order to provide the user community flexibility in estimating single-source secondary 

pollutant impacts and given the availability of more appropriate modeling techniques, such as photochemical 

transport models (which address limitations of models like CALPUFF [37] ), the EPA is proposing that the 

Guideline no longer contain language that requires the use of CALPUFF or another Lagrangian puff model for longrange transport assessments. Additionally, the EPA is proposing to remove the CALPUFF modeling system as an 

EPA-preferred model for long-range transport due to concerns about the management and maintenance of the model 

code given the frequent change in ownership of the model code since promulgation in the previous version of the 

Guideline. [38] The EPA recognizes that long-range transport assessments may be necessary in certain limited 

situations for PSD increment. For these situations, the EPA is proposing a screening approach where CALPUFF 

along with other appropriate screening tools and methods may be used to support long-range transport PSD 

increment assessments” 

751 80 CFR 45349. 
395

The IWAQM Phase 3 modeling report752 discusses in detail the difference between the 

CALPUFF analysis typically followed under BART and the use of photochemical grid models 

for assessing reasonable progress and overall visibility conditions. The report does not identify a 

preferred model for single-source analysis but rather identifies the difference between the 

modeling approaches and cautions that the model results are not directly comparable.753 The 

report also states that puff-models, such as CALPUFF, are not suited for reasonable progress 

demonstrations assessing overall visibility conditions and improvement because they are only 

able to model a single or small group of sources. Accordingly, we utilized CAMx model results 

to project overall future visibility conditions and establish the new RPGs in our reasonable 

progress demonstration. We used CALPUFF visibility modeling along with our evaluation of 

the costs of controls to inform our decision on the reasonableness of controls at the Independence 

facility. We also used CALPUFF visibility modeling as only one factor to inform our decisions 

on BART for subject-to-BART facilities. We also note that both the proposed revisions and the 

IWAQM report were published after the proposed rule for Arkansas regional haze was published 

and well before the technical analysis and modeling were completed. 

We address comments concerning the contribution to visibility impairment from Arkansas point 

sources and the benefit of controls on Independence on Arkansas Class I areas elsewhere. We 

find that the contribution to visibility impairment from Arkansas point sources to be significant 

and that controls on Independence will result in meaningful visibility improvements towards the 

goal of natural visibility conditions and addresses a significant portion of the visibility 

impairment due to Arkansas sources. 

Comment: Use of CALPUFF modeling does not support EPA’s determination to require 

controls at the three coal-fired power plants. [Nucor Steel-Arkansas and Nucor-Yamato Steel 

(0163) p.40-50] Nucor stated that the EPA's reliance on CALPUFF modeling results to make 

regulatory decisions in this case is not justified due to CALPUFF's well-known overestimation of 

visibility impacts.754 Under the circumstances here, it is highly likely that CALPUFF 

overestimated the visibility impacts of White Bluff, Flint Creek and Independence by at least 

five (5) times. One component of this overestimation is the failure to incorporate the puff 

splitting option within the CALPUFF model into the development of visibility results. Appendix 

B of the CENRAP BART Modeling Guidelines specifically recommends that the option for 

incorporating puff splitting in the model not be included; yet the CALPUFF User's Manual 

(Scire et al. 2000) states on page 2-37 that "across-puff shear is likely to be important for well 

mixed puffs after stable surface flows develop in the evening' as an example of when puff 

 

752 Interagency Workgroup on Air Quality Modeling Phase 3 Summary Report: Long Range Transport and Air 

Quality Related Values (July 2015) 

753 IWAQM Phase 3 Report (July 2015) at 9: “In sum, the differences in the types of models, the inputs to the 

models, and how the models and model results are used means that the results from a BART determination or 

similar modeling using CALPUFF cannot be directly compared to estimated impacts of emissions controls from a 

single source on a reasonable progress goal. If recommended procedures change for either BART determination 

impact assessments or reasonable progress goal impact assessments the comparability between approaches would 

also change. Photochemical grid models could be applied to estimate single source impacts and post-processed in a 

manner consistent with requirements for a BART-like assessment but Lagrangian puff models are not ideal for 

reasonable progress demonstrations since they typically characterize one or a small group of sources” 754 Coincidentally, the EPA Administrator on July 14, 2015, signed a proposed notice to remove CALPUFF as a 

model for long-range transport in EPA's Guideline on Air Quality Models in Docket No. EPA-HQ-OAR-2015-0310. 
396

splitting should be employed. While the use of puff-splitting alone does not resolve all potential 

issues with regard to the accuracy of the CALPUFF model, it is a component that when 

eliminated will cause visibility impacts to be overestimated. CALPUFF's overestimation of 

visibility impacts by a factor of 2-10 times under similar circumstances has been previously 

identified755 and is described with specific reference to EPA's Proposed FIP for Arkansas in a 

report by Dr. Richard T. McNider.756 Dr. McNider's report explains that the CALPUFF protocols 

used in the Proposed FIP fail to account for several well-known meteorological phenomena and 

processes, and causes it to overestimate visibility impacts by a factor of 2-3 times at distances 

between 40-100 km. At distances beyond 100 km, CALPUFF likely overestimates visibility 

impacts by a factor of 5-10 based on observations of plume widths at long-range.757 Among other 

things, this is due to the impact of plume transport during the overnight period in which the 

plume is distorted by wind shear resulting in a very wide plume. By not utilizing the puffsplitting option, this wind shear effect is ignored. As noted above, the developers of CALPUFF 

explicitly stated that puff splitting should be used if an evening transition is encountered. 

Because a majority of sources affected by the Proposed FIP have plume transport times that 

exceed 9 to 12 hours — resulting in some measure of overnight transport — the failure to 

account for overnight decoupling within the model likely understates plume widths by a factor of 

at least five and corresponding overstatement of concentrations by a similar factor. These 

evening transitions and associated plume distortion are a regular part of atmospheric behavior 

and cannot be neglected in regulatory actions assessing the cost benefits of controls. 

As described in Dr. McNider's report, the CALPUFF and CALMET protocols employed in the 

Proposed FIP neglect important physical behavior that control plume growth beyond a travel 

distance of 40-50 km. As found in observations of power plant plumes in Tennessee, wind 

fluctuations at a scale above boundary layer turbulence not captured in CALMET or realized in 

CALPUFF likely cause a plume to grow at 2 to 3 times that produced in CALPUFF. The neglect 

of these intermediate scales of motion is likely part of the reason the Hoffnagle report (Ex. 19) 

found CALPUFF to over-estimate concentrations. 

The electric generating units that are the subject of the Proposed FIPs sit at distances between 

100 and 400 kilometers from the closest Class I areas. Using the dates of the 98th percentile 

visibility impacts, transport wind speeds were found to be generally less than 3 m/s. Thus, 

transport times for all plumes would have exceeded 10 hours and most transport times were 15-

24 hours. Thus, almost all plumes would have encountered an evening transition and overnight 

transport. The following tables demonstrate the distance in kilometers (km) and plume transport 

times for White Bluff, Flint Creek, and Independence. 

Travel Time at 3m/s 

Re

ceptor

Caney 

Creek

Upper 

Buffalo

Hercules 

Glades Mingo 

 

755 See Exhibit 19 to Nucor’s comments, Hoffnagle, G., “Accuracy of Visibility Protocol Modeling in BART 

Evaluations” (June 15, 2012); EPA Docket EPA-R08-OAR-2011-0851. 

756 See, McNider, R. “Inadequacy of CALPUFF and CALMET Protocols for Visibility Impact Analysis in the 

Arkansas RHR FIP,” July 13, 2015, attached hereto as Exhibit 20 to Nucor’s comments. 757 White Bluff, Flint Creek and Independence are all more than 100 km from the nearest Class I area. 
397

Fac

ility 

D

istance 

T

ravel 

Time 

(hrs) 

D

istance 

T

ravel 

Time 

(hrs) 

D

istance 

T

ravel 

Time 

(hrs) 

D

istance 

T

ravel 

Time 

(hrs) 

En

tergyWhite Bluff 

1

76 

1

6.3 

2

00 

1

8.5 

2

66 

2

4.6 

3

35 

3

1.0 

 

Fli

nt Creek 

2

04 

1

8.9 

1

04 

9

.6 

1

53 

1

4.2 

3

95 

3

6.6 

 

En

tergyIndependen

ce

2

70 

2

5.0 

1

88 

1

7.4 

1

86 

1

7.2 

1

91 

1

7.7 

Travel Time at 2m/s 

Re

ceptor

Caney 

Creek

Upper 

Buffalo

Hercules 

Glades Mingo 

Fac

ility 

D

istance 

T

ravel 

Time 

(hrs) 

D

istance 

T

ravel 

Time 

(hrs) 

D

istance 

T

ravel 

Time 

(hrs) 

D

istance 

T

ravel 

Time 

(hrs) 

En

tergyWhite Bluff 

1

76 

2

4.4 

2

00 

2

7.8 

2

66 

3

6.9 

3

35 

4

6.5 

 

Fli

nt Creek 

2

04 

2

8.3 

1

04 

1

4.4 

1

53 

2

1.3 

3

95 

5

4.9 

 

En

tergyIndependen

ce

2

70 

3

7.5 

1

88 

2

6.1 

1

86 

2

5.8 

1

91 

2

6.5 

This table demonstrates that the plume transport times for each facility and Class I area crosses 

into evening and overnight mixing zones. The choice of not including the puff splitting option 

for the FIP modeling means that CALPUFF most likely is underestimating the effects during 

these overnight hours, which results in underestimating plume widths by a factor of five to ten, 

and corresponding overestimations of plume concentrations. This results in visibility impacts that 
398

are not accurate and should not be utilized to make regulatory decisions that have significant 

economic impacts. 

EPA has acknowledged the shortcomings of CALPUFF and that it is primarily limited to use as a 

screening tool to evaluate dv changes of at least 2-3 dv. Indeed, the Hoffnagle report 

demonstrates that CALPUFF modeling has not been validated by real world observations and 

that the current regulatory version of CALPUFF used by EPA is outdated.758 Consequently, 

CALPUFF is not “sufficiently accurate to make determinations of deciview differences of 1 

deciview.”759

It is not appropriate under the circumstances here to rely on CALPUFF beyond use as a 

screening tool. Specifically, it is inappropriate to utilize CALPUFF as a screening tool to qualify 

a source as subject to BART and subsequently use it to determine a facility's required 

implementation of a control technology at a significant financial cost. EPA in its final regional 

haze rules stated that “because of the scale of the predicted impacts from these sources, 

CALPUFF is an appropriate or a reasonable application to determine whether such a facility can 

reasonably be anticipated to cause or contribute to any impairment of visibility. In other words, 

to find that a source with a predicted maximum impact greater than 2 to 3 deciviews meets the 

contribution threshold adopted by the States does not require the degree of certainty in the results 

of the model that might be required for other regulatory purposes.” 70 F.R. 39104, 39123; July 6, 

2005; Regional Haze Regulations and Guidelines for Best Available Retrofit Technology 

(BART) Determinations; Final Rule [emphasis supplied]. For regulatory action such as 

evaluating the level of controls for a FIP, much more realistic modeling should be used to 

determine visibility impacts. For the Arkansas FIP, this should include at a minimum usage of 

the puff splitting option in CALPUFF. It should also include an evaluation of CALMET to 

ensure that its assimilation of winds at the 00Z and 12Z GMT times are not adversely impacting 

boundary layer decoupling and the development of inertial oscillations in the wind field. If at a 

minimum, the CALPUFF model results are overestimated by a factor of 5, the maximum 98th

percentile baseline visibility impact for White Bluff, Flint Creek, or Independence would be 

lowered to a level that removes any reasonable likelihood that it would exceed 0.5 deciviews and 

thus even be subject to BART, much less result in visibility improvement that may be reasonably 

anticipated. 

There has been no explanation or justification by EPA that demonstrates that the visibility 

impacts obtained from the CALPUFF model are precise enough to reliably differentiate results 

that are fractions of a deciview apart. In the proposed FIP, the maximum visibility improvement 

reported for any single Class I area for the subject to BART units is 0.813 dv.760 Not only is this 

overstated as discussed elsewhere in Nucor’s comments, this is below even EPA's 1 dv level at 

which a discernible difference in visibility can be registered by a human.761 In evaluating the 

 

758 Hoffnagle, Exhibit 19 at p. 4. 759 Hoffnagle, Exhibit 19 at p. 23. 760 See Proposed FIP and Exhibit 7 to Nucor’s comments. 761 See 62 Fed.Reg. 41138, 41145 (July 31, 1997) (“A one deciview change in haziness is a small but noticeable 

change in haziness under most circumstances when viewing scenes in mandatory Class I Federal areas.”); 70 

Fed.Reg. 39104, 39120 (July 6, 2005) (1.0 deciview is the “appropriate perceptibility threshold”); but see, Henry, R. 

“Just Noticeable Differences in Atmospheric Haze”, J. Air and Waste Management Assoc. 52: 1238, 1243, attached 

hereto as Exhibit 21 (“A 1- deciview change is never noticeable.”) 
399

significance of the modeled visibility improvements in the proposed FIP, EPA subjectively 

labels them as “considerable” (7 times), “significant” (1 time), and “meaningful” (1 time),762

even though each of these impacts is below the admitted minimum level of visual perceptibility. 

EPA does not explain how these impacts can be considerable, significant or meaningful from a 

visibility standpoint, when these impacts are not able to be perceived.763

If adjusted to account for the overestimation of the CALPUFF model and the distances and 

transport times involved in this case, the modeled visibility improvements would be even further 

below the 1dv perceptibility threshold. As explained in Dr. McNider's report, based on the 

studies of observed plume width versus modeled plume width, dispersion results beyond 100 

kilometers can be expected, at a minimum, to be overestimated by a factor of at least 5. This 

would bring the modeled visibility improvement results down to a level well below anything that 

would be observable and far below what CALPUFF can reasonably predict. 

EPA's visibility analysis in the Proposed FIP systematically overstates both the baseline visibility 

impacts of White Bluff, Flint Creek and Independence, and the visibility benefits that would 

result from installation of EPA’s required controls.764 EPA's Proposed FIP presumes greater 

accuracy and precision than is reasonable or that may be expected from CALPUFF under the 

circumstances here. The EPA has utilized a model that was developed as a screening method, 

and has improperly utilized it as a way to make regulatory determinations to establish mandatory 

control technologies. As indicated in the Hoffnagle and McNider reports, the errors in this model 

make it impossible to predict with a reasonable degree of confidence visibility changes at the 

levels involved, and call into question EPA's predictions of the tiny visibility benefits projected 

from installation of additional controls. As indicated, EPA has not validated that the results 

within CALPUFF align with any real-world data or observations; however, the Hoffnagle and 

McNider reports demonstrate that at the distances and transport times involved here, CALPUFF 

does not align with observed plume dispersion. EPA has failed to update its model or to address 

any of these deficiencies considering currently available state-of-the-art modeling science. EPA's 

consideration of visibility impacts is fundamentally flawed and should be withdrawn and 

corrected. 

EPA’s admission that CALPUFF is a reasonable tool to evaluate a facility’s visibility impacts 

only if those impacts exceed 2 to 3 deciviews, combined with the inability of the model to make 

accurate determinations below the 1 deciview threshold of perceptibility, discredits the results of 

the baseline visibility analyses in the Proposed FIP, as well as the claimed level of visibility 

improvement that can reasonably be anticipated from EPA's BART and Reasonable Progress 

determinations. For these reasons, EPA has not adequately explained how the baseline and 

subsequent controlled visibility analyses in the Proposed FIP justify the selected control 

technologies. 

 

762 “Considerable” - pp. 18952; 18959; 18959; 18966; 18972; 18978; 18994; “Significant” - p. 18994; “Meaningful” 

— p. 18952. 

763 To the extent EPA's decisions in the Proposed FIP were based on “cumulative visibility benefits” or “total 

visibility benefits,” that is misleading, has no legal basis, and is not scientifically defensible. See, Exhibit 19, 

Hoffnagle Report, p. 3 (deciviews cannot be directly added or subtracted.) 

764 As well as the other sources that were modeled using CALPUFF. 
400

Response: In promulgating the 2005 BART guidelines, we responded to comments concerning 

the limitations and appropriateness of using CALPUFF. There we respond:

CALPUFF is the best modeling application available for predicting a single source’s 

contribution to visibility impairment. It is the only EPA-approved model for use in 

estimating single source pollutant concentrations resulting from the long range transport 

of primary pollutants. In addition, it can also be used for some purposes, such as the 

visibility assessments addressed in today’s rule, to account for the chemical 

transformation of SO2 and NOX. As explained above, simulating the effect of precursor 

pollutant emissions on PM2.5 concentrations requires air quality modeling that not only 

addresses transport and diffusion, but also chemical transformations. CALPUFF 

incorporates algorithms for predicting both. At a minimum, CALPUFF can be used to 

estimate the relative impacts of BART-eligible sources. We are confident that CALPUFF 

distinguishes, comparatively, the relative contributions from sources such that the 

differences in source configurations, sizes, emission rates, and visibility impacts are wellreflected in the model results. 

The use of CALPUFF in the context of the Regional Haze rule provides results that can be used 

in a relative manner and are only one factor in the overall BART determination. We determined 

the visibility results from CALPUFF could be used as one of the five factors in a BART 

evaluation and the impacts should be utilized somewhat in a relative sense because CALPUFF 

was not explicitly approved for full chemistry calculations.765

EPA's modeling in this action was consistent with the BART Guidelines and Appendix W. In 

recommending the use of CALPUFF for assessing source specific visibility impacts, EPA 

recognized that the model had certain limitations but concluded that “[f]or purposes of the 

regional haze rule's BART provisions . . . CALPUFF is sufficiently reliable to inform the 

decision-making process.”766 To the extent that the comment takes issue with the provisions in 

the BART Guidelines for use of CALPUFF, the legal deadline for challenging the use of 

CALPUFF has passed. 

The commenters also refer to the 2005 Rule where we discuss the use of CALPUFF as a 

screening tool to qualify a source as subject to BART767 and claim that we state that CALPUFF 

is only a reasonable tool when impacts exceed 2 to 3 deciviews. This is incorrect. The BART 

Guidelines finalized in the 2005 Rule establish a maximum threshold of 0.5 deciviews for 

determining whether sources cause or contribute to visibility impairment for purposes of 

 

765 70 FR 39123, 39124. ‘‘We understand the concerns of commenters that the chemistry modules of the CALPUFF 

model are less advanced than some of the more recent atmospheric chemistry simulations. To date, no other 

modeling applications with updated chemistry have been approved by EPA to estimate single source pollutant 

concentrations from long range transport.’’ and in discussion of using other models with more advanced chemistry it 

continues, ‘‘A discussion of the use of alternative models is given in the Guideline on Air Quality in appendix W, 

section 3.2.’ 

766 70 FR 39123. 767 70 FR 39123. 
401

BART768 and recommends the use of CALPUFF769 to predict the visibility impacts from a single 

source at a Class I area to compare against this threshold. The commenters fail to note that later 

in that same section of the Rule we also discuss the recommended use of CALPUFF to evaluate 

visibility benefits of controls. There we state: 

“...we also recommend that the States use CALPUFF as a screening application in 

estimating the degree of visibility improvement that may reasonably be expected from 

controlling a single source in order to inform the BART determination. As we noted in 

2004, this estimate of visibility improvement does not by itself dictate the level of control 

a State would impose on a source; ‘‘the degree of improvement in visibility which may 

reasonably be anticipated to result from the use of [BART]’’ is only one of five criteria 

that the State must consider together in making a BART determination. “770

We note that the 0.5 dv threshold in the context of BART is used to assess the maximum total 

visibility impact from all BART units at a facility based on CALPUFF modeling. If the impact 

from all the BART sources at a facility is above the threshold, then each BART unit must be 

evaluated for controls, and therefore the modeled visibility improvement anticipated from 

controls would be less than 0.5 dv on a facility basis, and may be much less than 0.5 dv on a unit 

specific basis for BART sources with multiple BART units. For example, a facility comprised 

of four identical BART-eligible units, would be subject to BART if the total modeled visibility 

impact of the source was 0.5 dv. In this case, the maximum visibility benefit that could be 

achieved from controls on both NOx and SO2 on any individual unit would be 0.125 dv (onefourth of 0.5 dv). The level of visibility benefit would be one factor to consider along the cost of 

controls and other factors in informing the BART determination. 

With respect to our analysis of controls under reasonable progress, we rely on our Reasonable 

Progress Guidance.771 Our Reasonable Progress Guidance notes the similarity between some of 

the reasonable progress 4 statutory factors and the BART 5 statutory factors contained in the Act 

and repeated in the Guidance, and suggests that the BART Guidelines be consulted regarding 

cost, energy and non-air quality environmental impacts, and remaining useful life. We are 

therefore relying on our BART Guidelines for assistance in interpreting those reasonable 

progress factors, as applicable. Also, similar to a BART analysis, we are also considering the 

projected visibility benefit in our reasonable progress analysis following the BART guidelines 

and the use of CALPUFF.772 We rely on the BART Guidelines here and in other actions 

evaluating reasonable progress controls because they provide a reasonable and consistent 

approach regarding visibility modeling. 

 

768 40 CFR 51 Appendix Y, III(A)(1): “As a general matter, any threshold that you use for determining whether a 

source ‘‘contributes’’ to visibility impairment should not be higher than 0.5 deciviews.” 769 40 CFR 51 Appendix Y, III(A)(3): “CALPUFF is the best regulatory modeling application currently available 

for predicting a single source’s contribution to visibility impairment” 

770 Id. 771 Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program, June 1, 2007 772 As we explain in our proposed action (80 FR 18993): “While visibility is not an explicitly listed factor to 

consider when determining whether additional controls are reasonable under the reasonable progress requirements, 

the purpose of the four-factor analysis is to determine what degree of progress toward natural visibility conditions is 

reasonable. Therefore, it is appropriate to consider the projected visibility benefit of the controls when determining 

if the controls are needed to make reasonable progress”. See 79 FR at 74838, 74840, and 74874. 
402

We also disagree with the commenters conclusions concerning CALPUFF model performance 

and assertions that model predictions are overestimated by a factor of 5. We note that our 

regulations do not allow for the calibration of model results to try to adjust for potential biases as 

suggested by the commenter.773 

In order to develop a coherent understanding of performance of long-range transport (LRT) 

models used for regulatory purposes, we examined all of EPA’s prior LRT model evaluation 

efforts. These evaluation studies included the 1986 8-Model Study (Carhart , et al., 1989), 

Rocky Mountain Acid Deposition Model Assessment Project (Godowitch, 1989a, 1989b), 

IWAQM Phase I and II (EPA, 1998a, 1998b), and the 2012 EPA LRT model evaluation study 

(ENIVRON, 2012a).774 From this review, we drew the following conclusions that are relevant to 

commenters concerns: 

1. The results of both the 1986 and 2012 EPA evaluation efforts clearly identified that LRT 

model performance is highly sensitive to the quality of the meteorological inputs, 

meaning that LRT model performance will vary with the performance of the 

meteorological simulation used to supply meteorological information to the LRT model. 

Thus, in context, one cannot arbitrarily conclude that any modeling platform will 

consistently over-predict with every application as LRT model performance is 

inextricably linked to prognostic meteorological model performance. 

2. Carhart et al. (1989) concluded that, in general, LRT models tend to underestimate the 

horizontal spreading of the plume at ground level resulting in too high peak (centerline) 

concentrations when compared to the observations. For Lagrangian models compared in 

the 1986 study, this was believed to be due to using sigma-y dispersion (Turner) curves 

that are representative of near-source and are applied for longer (> 50 km) downwind 

distances. The underestimation of the lateral spread of plumes will consistently result in 

over-prediction of ground level concentrations, resulting in higher bias and error scores. 

This observation is consistent with the findings of the EPA 2012 model study which 

showed that the model CALPUFF underestimated the observed lateral distance of the 

plume by as much as 51% for the SRL75 database and 34% for the GP80 on the 100-km 

 

773 App. W, Section 7.2.9(a) “...Therefore, model calibration is unacceptable.” 774 Carhart, R.A., A.J. Policastro, M. Wastag, and L. Coke, 1989: Evaluation of Eight Short-Term Long-Range 

Transport Models Using Field Data. Atmos. Environ., 23, 85 – 105 

Godowitch, J.M. 1989a. Evaluation and Sensitivity Analyses Results of the MESOPUFF II Model with CAPTEX 

Measurements. EPA-600/3-89-056. U.S. Environmental Protection Agency, Atmospheric Research and Exposure 

Assessment Laboratory, Research Triangle Park, NC. 

Godowitch, J.M., 1989b: Evaluation and Testing of the MESOPUFF II Model System with CAPTEX 

Measurements. 6th Joint Conference On Applications of Air Pollution Meteorology, American Meteorological 

Society, Anaheim, CA, 56-59. 

USEPA, 1998a: A Comparison of CALPUFF Modeling Results to Two Tracer Field Experiments. Tech. Rep., EPA454/R-98-009, Research Triangle Park, NC, 48 pp. http://www.epa.gov/scram001/7thconf/calpuff 

USEPA, 1998b: Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary Report and 

Recommendations for Modeling Long Range Transport Impacts. Tech Rep., EPA-454/R-98-009, Research Triangle 

Park, NC, 160 pp. http://www.epa.gov/scram001/7thconf/calpuff/phase2.pdf

USEPA, 2012a: Documentation of the Evaluation of CALPUFF and Other Long Range Transport Models Using 

Tracer Field Experiment Data. Tech. Rep., EPA-454/R-12-003, Research Triangle Park, NC. 

https://www3.epa.gov/scram001/reports/EPA-454_R-12-003.pdf 
403

monitor arcs (ENVIRON, 2012). This phenomenon was also observed in the original 

report published in 1998 as part of the IWAQM Phase II process. CALPUFF 

underestimated lateral plume spread by as much as 24% for the GP80 study and as much 

as 49% for SRL75 (EPA, 1998a). At greater distances, both the 1998 and 2012 studies 

showed that this phenomena reversed itself, with much greater lateral distances compared 

to observed (GP80, 600-km arc). This would result in a lower model bias at greater 

distances. 

The graphical analysis of the 1994 European Tracer experiment (ETEX) results provided in the 

2012 report also shows an underestimation of the lateral spread of almost all models compared to 

observations. This appears to be an artifact that affects most models used for LRT purposes, 

irrespective of whether the dispersion is based upon Turner stability classes or not. We do not 

disagree that some elements of scales of motion are potentially neglected by the 

CALMET/CALPUFF system. CALPUFF modeling utilizes CALMET to construct the 

meteorological inputs using surface and aloft meteorological observations and three-dimensional 

output from the MM5 prognostic numerical model. Performance evaluations of MM5 generated 

data sets against surface meteorological observations were completed for the datasets used to 

evaluate CENRAP BART sources, including the modeling performed to support this action. 775 

EPA’s overall analysis of the CALPUFF/CALMET system focused on the end result impacts, 

which includes any potential issues with use of upper air observations and boundary layer 

interaction. All air quality models are a simplification of a very complex and dynamic system. 

Events are characterized by known or measured conditions that are input into the model, such as 

emissions and observed meteorological conditions at specific locations, and unknown or 

unresolved details of atmospheric flow, such as the turbulent velocity field throughout the model 

domain. The approach employed is consistent with all relevant guidance provided by EPA and 

FLM’s, with consideration for the limitations and capabilities of the available models. 

The CALPUFF model can both under-predict and over-predict visibility impacts. For example, 

the 2012 ENVIRON report on Comparison of Single-Source Air Quality Assessment Techniques 

for Ozone, PM2.5, other criteria pollutants and AQRVs found that CALPUFF predicted highest 

24-hr nitrate and sulfate concentrations lower than those predicted by the CAMx photochemical 

grid model in some areas within the modeling domain.776 In a presentation for the 2010 annual 

Community Modeling and Analysis System conference, Anderson et al. (2010)777 found that the 

CALPUFF model frequently predicted lower nitrate concentrations compared to the CAMx 

photochemical grid model which has a much more rigorous treatment of photochemical 

reactions. EPA recognized the uncertainty in the CALPUFF modeling results when EPA made 

the decision, in the final BART Guidelines, to recommend that the model be used to estimate the 

 

775 Performance evaluations of the 2001, 2002, and 2003 MM5 generated data sets are discussed in the CENRAP 

BART Modeling Guidelines available in the docket for this action 

776 Comparison of Single‐Source Air Quality Assessment Techniques for Ozone, PM2.5, other Criteria Pollutants 

and AQRVs, ENVIRON, September 2012. 

777 Anderson, B., K. Baker, R. Morris, C. Emery, A. Hawkins, E. Snyder “Proof-of-Concept Evaluation of Use of 

Photochemical Grid Model Source Apportionment Techniques for Prevention of Significant Deterioration of Air 

Quality Analysis Requirements” Presentation for Community Modeling and Analysis System (CMAS) 2010 Annual 

Conference, (October 11-15, 2010) can be found at http://www.cmascenter.org/conference/2010/agenda.cfm. 
404

98th percentile visibility impairment rather than the highest daily impact value. We made the 

decision to consider the less conservative 98th percentile primarily because the chemistry 

modules in the CALPUFF model are simplified and likely to provide conservative (higher) 

results for peak impacts. Since CALPUFF’s simplified chemistry could lead to model over 

predictions and thus be conservative, EPA decided to use the less conservative 98th percentile.778 

Therefore, in recognizing some of the limitations of the CALPUFF model, we determined that 

use of the maximum modeled impact may be overly conservative and recommended the use of 

the 98th percentile value. While recognizing the limitations of the CALPUFF model in the 

Preamble of the Regional Haze Rule, EPA concluded that, for the specific purposes of the 

Regional Haze Rule's BART provisions, CALPUFF is sufficiently reliable to inform the decision 

making process.779 

We disagree with the commenter’s assertion that we were incorrect in not utilizing the puffsplitting option780 and that this resulted in an overestimation of model results Tests conducted 

by the EPA and the FLM’s have shown that the CALPUFF puff-splitting algorithm does not 

behave in the manner posited in Dr. McNider’s document. The EPA 2012 report summarizes 

tests of the puff-splitting algorithm for the 1994 European Tracer experiment (ETEX). That 

sensitivity analysis determined that “the CALPUFF puff splitting sensitivity tests did not have 

any significant effect on CALPUFF model performance. Whether puff splitting was used or not 

produced essentially identical model performance for the ETEX experiment and certainly did not 

improve the CALPUFF model performance.”781 Tests of puff-splitting with the GP80 mesoscale 

tracer experiment at a distance of 600 km showed that CALPUFF underestimated concentrations 

and the use of puff-splitting resulted in higher concentrations. 

Additionally, we ran the puff splitting feature in its default configuration for the Four Corners 

Air Quality Task Force CALPUFF dataset782 modeling visibility impacts due to emissions from 

the San Juan Generating Station. This test also confirmed that the use of puff-splitting does not 

result in a uniform decrease in concentrations. In our tests of puff-splitting, visibility impacts 

(and thus concentrations) both increased and decreased across various Class I areas.783 All of 

these results are contrary to the claims of the commenter that CALPUFF over-predicts 

downwind concentrations at distances beyond 100 km and that the use of puff-splitting would 

result in lower concentrations. Furthermore, commenters have not provided any additional 

CALPUFF modeling to support their claims concerning model performance using the nondefault puff splitting option. 

 

 

778 “Most important, the simplified chemistry in the model tends to magnify the actual visibility effects of that 

source. Because of these features and the uncertainties associated with the model, we believe it is appropriate to use 

the 98th percentile—a more robust approach that does not give undue weight to the extreme tail of the distribution.” 

70 FR 39104, 39121. 

779 70 FR 39123 780 CALPUFF contains an optional puff splitting algorithm that can further account for vertical wind shear effects 

across individual puffs when this is of specific concern. Dispersion and transport can act on separate puffs 

generated from the original puff. This option is not part of the regulatory default set-up. 

781 See page 134 of Documentation of the Evaluation of CALPUFF and Other Long Range Transport Models Using 

Tracer Field Experiment Data, ENVIRON, May 2012. 

782 See Comparison of Single‐Source Air Quality Assessment Techniques for Ozone, PM2.5, other Criteria 

Pollutants and AQRVs, ENVIRON, September 2012.for description of dataset. 

783 See CALPUFF_SJGS_SPLIT_summary.xls 
405

The analysis that appears in Table 1 of the McNider analysis is flawed because surface wind 

speeds do not define puff transport. According the CALPUFF User’s Guide784, the transport 

wind is defined as the average wind across the depth of the puff. This means that if a puff is in a 

well-mixed environment, the puff is in contact with both the surface and the planetary boundary 

layer, and the transport wind is the average across the depth of the puff. The McNider analysis 

incorrectly relies on observed wind speeds at two ground sites rather than the transport wind to 

estimate the travel time to the Class I areas. 

The commenter states that the largest visibility benefit from controlling a single EGU is 0.813 

dv, an imperceptible amount and that impacts cannot be considerable, significant or meaningful 

from a visibility standpoint, when they are imperceptible. We disagree and address this 

comment elsewhere where we discuss that perceptibility is not a threshold criterion for 

considering improvements in visibility to be meaningful. 

The commenter refers to the Hoffnagle report (Ex. 19 of Nucor comments) to support claims that 

the CALPUFF model over-predicts concentrations. The Hoffnagle report claims that 

comparisons of CALPUFF modeled visibility impacts to observed data demonstrates that 

CALPUFF over-predicts nitrate extinction by a factor of 2 to 10, that the model is unreliable 

beyond 200km, and that the modeling is not sufficiently accurate to make determinations of 

deciview differences of 1 dv. We disagree with the conclusions of the Hoffnagle report and note 

significant flaws in that analysis. Regarding the use of CALPUFF beyond 200km, EPA 

concluded from the evaluation of the IWAQM phase 2 report case studies that the CALPUFF 

dispersion model had performed in a reasonable manner, and had no apparent bias toward over 

or under prediction, so long as the transport distance was limited to less than 300km.785,

786 

Furthermore, we note that all the large EGU sources modeled in this action are less than 200 km 

for at least one Class I area. We specifically address Hoffnagle’s analysis of modeled to 

measured results in response to comments elsewhere where we address comments concerning the 

“margin of error” of the model and case study comparisons of CALPUFF modeled values to 

measured values. 

We disagree with the commenter that the model we utilized is outdated. We used the regulatory 

version of the CALPUFF model at the time we performed our analysis.787 The Hoffnagle report 

discusses CALPUFF version 6.4 and alleges that that it is more scientifically robust and included 

updated chemistry and technical enhancements to improve the model’s performance and 

accuracy. We responded to a similar comment in depth in our response to comments on our FIP 

for New Mexico.788 We disagree that the newer versions of CALPUFF should be used in this 

 

784 A User’s Guide for the CALPUFF Dispersion Model (Version 5), Scire, et al., January 2000. Available at: 

http://www.src.com/calpuff/download/CALPUFF_UsersGuide.pdf 785 Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary Report and Recommendations 

for Modeling Long-Range Transport Impacts. Publication No. EPA–454/R–98–019. Office of Air Quality Planning 

& Standards, Research Triangle Park, NC. 1998. 

786 68 FR 18458, 2003 Revisions to Appendix W, Guideline on Air Quality Models 787 On December 4, 2013, EPA approved an update to v5.8.4 that contains bug fixes to the previous version. See 

December 3, 2013 CALPUFF Update Memo for a discussion of model changes. 788 See response beginning page 124 of Complete Response to Comments for NM Regional Haze/Visibility 

Transport FIP, August 5, 2011. Available at: https://www.regulations.gov/#!documentDetail;D=EPA-R06-OAR2010-0846-0127 
406

action to determine potential visibility impacts. The newer version(s) of CALPUFF have not 

received the level of review required for use in regulatory actions subject to EPA approval and 

consideration in a BART decision making process. Based on our review of the available 

evidence we do not consider these newer versions of CALPUFF to have been shown to be 

sufficiently documented, technically valid, and reliable for use in a BART decision making 

process. 

The commenters also refer to the proposed revisions to the Guideline on Air Quality Models 

(Appendix W). Proposed revisions to Appendix W discuss removing the requirement to use 

CALPUFF for long-range transport assessments and as a preferred model due to the need to 

provide flexibility in estimating single-source secondary pollutant impacts and concerns about 

management and maintenance of the CALPUFF modeling code.789 These proposed changes do 

not affect EPA's recommendation that States use CALPUFF to determine the applicability and 

level of BART in regional haze implementation plans. The proposed changes also do not 

preclude the use of CALPUFF for any other non-BART analysis. The proposed changes to the 

Appendix W rule simply propose to remove CALPUFF as a preferred model for long-range 

transport assessments. If the proposed changes are finalized, CALPUFF or any other model can 

still be used with the appropriate justification as an “alternative model.” 

Finally, the CAMx modeling provided by Entergy Arkansas provides additional information that 

directly contradicts the commenter’s assertion that CALPUFF greatly overestimates visibility 

impacts by at least a factor of 5. As we discuss elsewhere, the CAMx visibility modeling 

estimates a maximum visibility impact (limited to only the days comprising the 20% worst days 

and based on annual emissions) of over 1.5 dv from the Independence facility at both Caney 

Creek and Upper Buffalo. For the White Bluff facility, the CAMx maximum visibility impact is 

approximately 3.5 dv at Caney Creek and 0.8 dv at Upper Buffalo. In some situations, the 

CALPUFF modeled maximum or 98th percentile impacts of the facility may not coincide with 

the days that make up the worst 20% monitored days at the Class I area, therefore the true 

maximum impact considering all days based on CAMx modeling could be even higher. This 

compares to a CALPUFF modeled visibility 98th percentile impact (based on maximum 

emissions) due to the Independence facility of 2.5 dv at Caney Creek and 2.3 at Upper Buffalo. 

For White Bluff, the CALPUFF modeled impact (98th percentile) is approximately 3.3 dv at 

Caney Creek and 2.3 dv at Upper Buffalo. 

 

We address more general comments concerning the use of CALPUFF modeling and model 

uncertainty in separate response to comments. 

 

789 80 CFR 45349: “in order to provide the user community flexibility in estimating single-source secondary 

pollutant impacts and given the availability of more appropriate modeling techniques, such as photochemical 

transport models (which address limitations of models like CALPUFF [37] ), the EPA is proposing that the 

Guideline no longer contain language that requires the use of CALPUFF or another Lagrangian puff model for longrange transport assessments. Additionally, the EPA is proposing to remove the CALPUFF modeling system as an 

EPA-preferred model for long-range transport due to concerns about the management and maintenance of the model 

code given the frequent change in ownership of the model code since promulgation in the previous version of the 

Guideline. [38] The EPA recognizes that long-range transport assessments may be necessary in certain limited 

situations for PSD increment. For these situations, the EPA is proposing a screening approach where CALPUFF 

along with other appropriate screening tools and methods may be used to support long-range transport PSD 

increment assessments” 
407

7.d. Margin of Error in CALPUFF modeling 

Comment: [ADEQ (0144) p. 28-30] ADEQ stated that in determining what specific controls are 

BART, EPA is required to take into consideration a number of factors including “the degree of 

improvement in visibility which may reasonably be anticipated to result from the use of such 

technology.”790 In Nat'l Parks Conservation Ass'n v. E.P.A., PPL Montana, a part-owner of a 

coal-fired power plant, objected to EPA’s use of the CALPUFF visibility model in determining 

BART for two units at one of its coal-fired power plants.791

The basis of PPL Montana’s objection was that the maximum potential incremental visibility 

benefit of emissions control technology chosen by EPA fell within the model's margin of error, 

meaning such improvement cannot be “reasonably ... anticipated” as required by the Act.792 The 

Ninth Circuit Court of Appeals recently held that EPA had not “considered the relevant factors 

and articulated a rational connection between the facts found and the choice made.”793 As a 

result, EPA acted in an arbitrary and capricious manner by failing to provide an adequate 

explanation as to how the degree of visibility improvement could be reasonably anticipated.794

At least one facility affected by the Proposed FIP has conducted an analysis to determine 

whether or not the maximum potential incremental visibility benefit of emissions control 

technology chosen by EPA fell within the margin of error. Specifically, ADEQ is aware that 

Domtar is currently performing modeling to determine whether or not predicted visibility 

improvements fell within the margin of error at its Ashdown Mill.795 Other facilities are likely 

performing modeling to make similar determinations. Accordingly, ADEQ reserves the right to 

comment on this issue until such time as Arkansas’s facilities have had adequate time to make 

those determinations. 

As the D.C. Circuit explained in vacating a portion of the Regional Haze Rule itself, it is 

arbitrary and capricious for EPA to force an emissions source “to spend millions of dollars for 

new technology that will have no appreciable effect on the haze in any Class I area.”796 In its 

Proposed Rule, EPA dictates the imposition of control equipment for emissions reduction under 

BART in instances where CALPUFF predicted minor visibility improvements. EPA did so 

without first undertaking any site specific analytical analysis to determine if the visibility 

improvements were in fact within the CALPUFF margin of error. 

 

790 42 U.S.C.A. § 7491. 791 See generally, Nat'l Parks Conservation Ass'n v. E.P.A., No. 12-73710, 2015 WL 3559149, at *13 (9th Cir. June 

9, 2015). 

792 See 42 U.S.C. § 7491(g)(2); Nat'l Parks Conservation Ass'n v. E.P.A., No. 12-73710, 2015 WL 3559149, at *8 

(9th Cir. June 9, 2015). 

793 Nat'l Parks Conservation Ass'n v. E.P.A., No. 12-73710, 2015 WL 3559149, at *13 (9th Cir. June 9, 2015). 794 Id. 795 Letter from Annabeth Reitter, Corporate Manager, Domtar, to Guy Donaldson, Chair of the Air Planning Section, 

E.P.A., (July 6, 2015) attached as Exhibit 4. 

106 Nat'l Parks Conservation Ass'n v. E.P.A., 796 Nat'l Parks Conservation Ass'n v. E.P.A., No. 12-73710, 2015 WL 3559149, at *10 (9th Cir. June 9, 2015)(citing 

Am. Corn Growers Ass'n v. EPA, 291 F.3d 1, 7 (D.C.Cir.2002)
408

Specifically, it appears from the Proposed FIP that the highest modeled visibility improvement 

after EPA’s BART determinations for any of the three Arkansas EGUs at any Class I area is 

0.813 deciviews attributed to SO2 controls at the Entergy White Bluff Unit I at 

Caney Creek, which is below the 1 deciview threshold of visibility perception. Furthermore, 

EPA required the installation of low-NOx burners and over fire air at SWEPCO’s Flint Creek 

Unit, even though the highest modeled visibility improvement was 0.081 deciviews for NOx. 

Given the acknowledged over-prediction of the CALPUFF model and its inaccuracy at these low 

levels, the actual visibility impact for the State’s EGUs (and most likely the other subject-toBART sources as well) would be much lower. 

The CAA does not require visibility improvements that cannot be reasonably anticipated. 

Conversely, visibility improvements that are less than the margin of error were expressly found 

to be invalid. Until such time as EPA can provide assurance that the CALPUFF model is a 

reliable indicator of visibility projections, many of the numerical projections contained in the 

Proposed FIP are themselves, unreliable. For this reason, the Proposed FIP is flawed and is 

overly expansive and should be withdrawn. 

Comment: [Domtar (0161) p. 2-3] Domtar stated that in response to the recent June 9, 2015 

decision of the 9th Circuit Court of Appeals in Nat’l Parks Conservation Ass’n v. EPA, No. 12-

73710, 2015 WL 3559149 (9th Cir. June 9, 2015), the Ashdown Mill engaged a study to 

determine if the visibility improvement claimed to be derived from the proposed BART FIP can 

be reasonably anticipated. Since the 9th Circuit decision became available late in the public 

comment period for the proposed Arkansas Regional Haze FIP and in order to complete the full 

study for the Ashdown Mill, Domtar requested a short, limited extension of the comment period 

to allow for a full and complete analysis for the Ashdown Mill to be performed and submitted to 

the Agency.

Domtar stated it understands the Agency will be reopening the comment period. The full report 

will be submitted during the reopened comment period. Domtar stated it appreciates EPA’s 

accommodation of its request and believes the additional analysis will be very useful and 

informative in the Agency’s review of the Mill’s situation. In particular, Domtar stated the 

analysis will show that the purported visibility improvement for the Ashdown Mill is within the 

Mill specific margin of error for the CALPUFF model, and as such, visibility improvements 

cannot be reasonably anticipated to occur. See 42 U.S.C. §7491(g)(2); Nat’l Parks Conservation 

Ass’n v. EPA, No. 12-73710, 2015 WL 3559148 at *8 (9th Cir. June 9, 2015). 

In the record supporting the proposed BART FIP for the Ashdown Mill, there is no 

demonstration by the Agency that the purported visibility improvements can be reasonably 

anticipated to occur as required by 42 U.S.C. § 7491(g)(2). As noted by the court in Nat’l Parks

Conservation Ass’n, the Agency needs to show that the anticipated improvement from the 

imposition of BART is within the CALPUFF model’s capability to measure and not in the 

model’s margin of error. If the model cannot predict visibility gains that are capable of being 

measured by the CALPUFF model, then the Agency fails to show that visibility improvements 

can be reasonably anticipated – a crucial statutory prerequisite to proceeding with the BART FIP 

for the Ashdown Mill. 
409

No analysis exists in the record of the model’s margin of error with respect to the Ashdown 

Mill’s alleged visibility improvement. Without such an analysis, there is no means of knowing if 

the predicted values are within the model’s ability to predict or in the model’s margin of error. 

The Ashdown Mill will be submitting its full analysis showing that the purported visibility 

improvements associated with the proposed Ashdown Mill BART requirements are within the 

Mill specific margin of error for the CALPUFF model, and as such, there is no reasonably 

anticipated visibility improvement achieved by the imposition of BART on the Ashdown Mill. 

The report will be provided during the reopened comment period. 

Response: We disagree with the commenter's characterization of the Ninth Circuit decision 

regarding the “margin of error” of the CALPUFF model. The Ninth Circuit decision cited did 

not rule on any specific issue related to CALPUFF or the “margin of error”. Rather, the court 

ruled on a procedural error that EPA did not respond to the comment received regarding the 

CALPUFF margin of error in its rulemaking as required under the law. 797 

We discuss below in a separate response to comment in this section that the analysis performed 

by Trinity Consultants798that purports to calculate a “margin of error” of the CALPUFF 

modeling for the Arkansas BART sources (Domtar and Lake Catherine), is flawed for many 

reasons and fails to provide any assessment of the ability of the CALPUFF model to evaluate 

“the degree of visibility improvement that may be expected from available control technology” 

to inform BART and reasonable progress evaluations. Whether or not the modeled visibility 

impacts or benefits lie below this erroneous, calculated “margin of error” is immaterial to any 

assessment of whether or not the visibility impairment or benefits from controls can reasonably 

be anticipated to occur. The notion of a calculated “margin of error” is not part of any modeling 

guidance and has no legal or regulatory basis or applicability here. We disagree that we must 

undertake a “site-specific analytical analysis” for every application of the CALPUFF model to 

assess uncertainty in model results. 

In response to the court’s finding in American Corn Growers Ass’n. v. EPA799 that we failed to 

provide an option for BART evaluations on an individual source-by-source basis, we had to 

identify the appropriate analytical tools to estimate single-source visibility impacts. The 2005 

BART Guidelines recommended the use of CALPUFF for assessing visibility (secondary 

chemical impacts) but noted that CALPUFF’s chemistry was fairly simple and the model has not 

been fully tested for secondary formation and thus is not fully approved for secondary-formed 

particulate. In the preamble of the final 2005 BART guidelines we identify CALPUFF as the best 

available tool for analyzing the visibility effects of individual sources, but we also recognized 

 

797 “Concurring, Judge Berzon wrote separately to emphasize her understanding that the lead opinion is not

impugning the EPA’s use of the CALPUFF model generally, but only requiring a sufficiently reasoned response to a

particular comment regarding CALPUFF’s usefulness in these specific circumstances.”  Nat’l Parks Conservation

Ass’n vs. EPA

798 Evaluation of the CALPUFF Modeling System Margin of Error for a BART Analysis, Entergy Services, Inc. – 

Lake Catherine Plant, available as Exhibit H to comments submitted by Entergy Arkansas, Inc.; “Evaluation of the 

CALPUFF Modeling System Margin of Error Report for BART Analysis, Domtar A. W. LLC, Ashdown Mill” 

Prepared by Trinity Consultants, August 2015

799 Am. Corn Growers Ass'n v. EPA, 291 F.3d 1 (D.C. Cir. 2002). 
410

that it is a model that includes certain assumptions and uncertainties.800 Evaluation of 

CALPUFF model performance for dispersion (no chemistry) to case studies using inert tracers 

has been performed.801 It was concluded from these case studies the CALPUFF dispersion model 

had performed in a reasonable manner, and had no apparent bias toward over or under 

prediction, so long as the transport distance was limited to less than 300km.802,

803 

In promulgating the 2005 BART guidelines, we responded to comments concerning the 

limitations and appropriateness of using CALPUFF. There we respond: 

CALPUFF is the best modeling application available for predicting a single source’s 

contribution to visibility impairment. It is the only EPA-approved model for use in 

estimating single source pollutant concentrations resulting from the long range transport 

of primary pollutants. In addition, it can also be used for some purposes, such as the 

visibility assessments addressed in today’s rule, to account for the chemical 

transformation of SO2 and NOX. As explained above, simulating the effect of precursor 

pollutant emissions on PM2.5 concentrations requires air quality modeling that not only 

addresses transport and diffusion, but also chemical transformations. CALPUFF 

incorporates algorithms for predicting both. At a minimum, CALPUFF can be used to 

estimate the relative impacts of BART-eligible sources. We are confident that CALPUFF 

distinguishes, comparatively, the relative contributions from sources such that the 

differences in source configurations, sizes, emission rates, and visibility impacts are wellreflected in the model results. 

In the 2003 revisions to the Guideline on Air Quality Models, CALPUFF was added as an 

approved model for long –range transport of primary pollutants. At that time, we considered 

approving CALPUFF for assessing the impact from secondary pollutants but determined that it 

was not appropriate in the context of a PSD review because the impact results could be used as 

the sole determinant in denying a permit.804 However, the use of CALPUFF in the context of the 

Regional Haze rule provides results that can be used in a relative manner and are only one factor 

in the overall BART determination. We determined the visibility results from CALPUFF could 

be used as one of the five factors in a BART evaluation and the impacts should be utilized 

somewhat in a relative sense because CALPUFF was not explicitly approved for full chemistry 

calculations.805 

 

800 70 FR 39121 801 “more recent series of comparisons has been completed for a new model, CALPUFF (Section A.3). Several of 

these field studies involved three-to-four hour releases of tracer gas sampled along arcs of receptors at distances 

greater than 50km downwind. In some cases, short-term concentration sampling was available, such that the 

transport of the tracer puff as it passed the arc could be monitored. Differences on the order of 10 to 20 degrees were 

found between the location of the simulated and observed center of mass of the tracer puff. Most of the simulated 

centerline concentration maxima along each arc were within a factor of two of those observed.” 68 FR 18458, 2003 

Revisions to Appendix W, Guideline on Air Quality Models 

802 Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary Report and Recommendations 

for Modeling Long-Range Transport Impacts. Publication No. EPA–454/R–98–019. Office of Air Quality Planning 

& Standards, Research Triangle Park, NC. 1998. 

803 68 FR 18458, 2003 Revisions to Appendix W, Guideline on Air Quality Models 804 70 FR 39123 805 70 FR 39123, 39124. ‘‘We understand the concerns of commenters that the chemistry modules of the CALPUFF 

model are less advanced than some of the more recent atmospheric chemistry simulations. To date, no other
411

We also recognized the uncertainty in the CALPUFF modeling results when we made the 

decision, in the final BART Guidelines, to recommend that the model be used to estimate the 

98th percentile visibility impairment rather than the highest daily impact value. We made the 

decision to consider the less conservative 98th percentile primarily because the chemistry 

modules in the CALPUFF model are simplified and likely to provide conservative (higher) 

results for peak impacts. Since CALPUFF’s simplified chemistry could lead to model over 

predictions and thus be conservative, EPA decided to use the less conservative 98th percentile.806 

Examining the distribution of CALPUFF modeled visibility impacts, it can be seen that the few 

values at the extreme of the distribution are much higher than the rest of the values.807 Therefore, 

in recognizing some of the limitations of the CALPUFF model, we determined that use of the 

maximum modeled impact may be overly conservative and recommended the use of the 98th

percentile value. 

We disagree with the commenter’s general statement that there is an acknowledged overprediction of the CALPUFF model or an acknowledged inaccuracy at low levels, and that the 

actual visibility impact from the BART sources are lower. The CALPUFF model can both 

under-predict and over-predict visibility impacts when compared to photochemical grid model. 

For example, the 2012 ENVIRON report on Comparison of Single-Source Air Quality 

Assessment Techniques for Ozone, PM2.5, other criteria pollutants and AQRVs found that 

CALPUFF predicted highest 24-hr nitrate and sulfate concentrations lower than those predicted 

by the CAMx photochemical grid model in some areas within the modeling domain.808 In a 

presentation for the 2010 annual Community Modeling and Analysis System conference, 

Anderson et al. (2010)809 found that the CALPUFF model frequently predicted lower nitrate 

concentrations compared to the CAMx photochemical grid model which has a much more 

rigorous treatment of photochemical reactions. As discussed above, model evaluations 

examining how the model captures the transport and diffusion of pollutants showed that the 

model performed in a reasonable manner for modelled distances less than 300km.810 The 

selection of the 98th percentile value rather than the maximum value was made to address 

concerns that the maximum may be overly conservative. 

 

modeling applications with updated chemistry have been approved by EPA to estimate single source pollutant 

concentrations from long range transport.’’ and in discussion of using other models with more advanced chemistry it 

continues, ‘‘A discussion of the use of alternative models is given in the Guideline on Air Quality in appendix W, 

section 3.2.’ 

806 “Most important, the simplified chemistry in the model tends to magnify the actual visibility effects of that 

source. Because of these features and the uncertainties associated with the model, we believe it is appropriate to use 

the 98th percentile—a more robust approach that does not give undue weight to the extreme tail of the distribution.” 

70 FR 39104, 39121. 

807 See figures below for Lake Catherine and Domtar in our response to comments on the “Margin of Error” analysis 808 Comparison of Single‐Source Air Quality Assessment Techniques for Ozone, PM2.5, other Criteria Pollutants 

and AQRVs, ENVIRON, September 2012. 

809 Anderson, B., K. Baker, R. Morris, C. Emery, A. Hawkins, E. Snyder “Proof-of-Concept Evaluation of Use of 

Photochemical Grid Model Source Apportionment Techniques for Prevention of Significant Deterioration of Air 

Quality Analysis Requirements” Presentation for Community Modeling and Analysis System (CMAS) 2010 Annual 

Conference, (October 11-15, 2010) can be found at http://www.cmascenter.org/conference/2010/agenda.cfm. 810 68 FR 18458, 2003 Revisions to Appendix W, Guideline on Air Quality Models 
412

The CALPUFF modeling following the BART guidelines and using the 98th percentile value 

does not lend itself to model performance evaluations of the type suggested by the commenters 

(see comments below concerning the “Margin of error” analysis), comparing measured visibility 

impairment at a specific time and place to modeled impairment at that same time and place to 

derive some “margin of error” in the modeled estimates. The BART modeling is a worst case 

assessment, utilizing maximum emissions811, assumptions of background ammonia and ozone, 

and simplified chemistry, modeled over a period of three years. 812 The modeling also does not 

capture the effect of competition with other emission sources for the available ammonia. The 

goal of this modeling is to estimate the maximum anticipated impact from the source in the 

vicinity of a Class I area (typically an area on the order of several hundred square miles or more), 

and not to provide an estimate of downwind concentrations or visibility conditions for a specific 

place at a specific time. 

CALPUFF uses a pseudo-first-order chemical reaction mechanism to model the conversion of 

SO2 to SO4 and NOx (NO + NO2) to NO3. We find the representation of key chemical 

conversions of precursors to PM2.5 in CALPUFF are appropriate for estimating a worst-case 

scenario for this particular source and region. We note that small changes in emission levels will 

not significantly perturb the available ammonia. Therefore, the relative difference between two 

scenarios with similar emissions will not be overly influenced by assumptions of background 

concentrations of ammonia. 

The utility of the model used must be judged based on the available data, the known limitations 

or simplifications inherent to the model, and the purpose of the modeling or manner in which the 

model results are used in informing decisions. The use of the 98th percentile value and 

considering a minimum of three years of meteorological data within CALPUFF provides a 

snapshot of the worst case visibility impacts, simulating impacts (based on maximum emissions 

and assumed ammonia concentrations) on a day when modeled meteorological conditions are 

most conducive to formation and transport of visibility impairing pollutants to a receptor within a 

Class I area. While there is some uncertainty in the absolute visibility impacts and benefits due 

to the model and some of the simplifications and assumptions used in the BART guideline 

modeling approach, the relative level of impact is a reliable assessment of the degree of visibility 

impacts and benefit from controls. Any uncertainties in meteorological conditions that govern 

the transport and diffusion of pollutants are less important in comparing impacts between two 

control scenarios, since the same effects will be included in both the base and the control 

scenario model simulations. CALPUFF modeling will be better at predicting changes in 

visibility impairment due to the application of controls than at predicting the absolute visibility 

impacts. BART determinations are only made for sources that have already been shown to 

reasonably be anticipated to cause or contribute to any visibility impairment in a Class I area. 

Modeling of control scenarios is used to estimate the amount that this visibility impact can be 

 

811 Page 39129 of BART Rule, “We believe the maximum 24hour modeled impact can be an appropriate measure in 

determining the degree of visibility improvement expected from BART reductions (or for BART applicability)” 

812 Pages 39107-3918 of BART Rule. For assessing the fifth factor, the degree of improvement in visibility from 

various BART control options, the States may run CALPUFF or another appropriate dispersion model to predict 

visibility impacts. Scenarios would be run for the pre-controlled and post-controlled emission rates for each of the 

BART control options under review. The maximum 24-hour emission rates would be modeled for a period of three 

or five years of meteorological data. 
413

reduced due to a reduction in emissions. The modeling of these control scenarios is done in a 

manner that holds all variables constant except for the emissions of the pollutant of interest. A 

relative reduction in visibility impact due to a change in emissions is an indication that visibility 

benefits are reasonably anticipated to occur. The modeled magnitude of the visibility 

improvement is not a determinative factor in the BART determination, but only one factor and is 

considered on a relative basis to the baseline impact and the benefits of other controls. The 

relative visibility benefit of all controls is weighed along with the absolute and relative costs of 

controls, energy and non-air environmental impacts, any existing controls, and the remaining 

useful life of the source. As stated above, we are confident that CALPUFF distinguishes, 

comparatively, the relative contributions from sources such that the differences in source 

configurations, sizes, emission rates, and visibility impacts are well-reflected in the model 

results. 

CALPUFF visibility modeling, performed using the regulatory CALPUFF model version and 

following all applicable guidance and EPA/FLM recommendations, provides a consistent tool for 

comparison with the 0.5 dv subject-to-BART threshold. The CALPUFF model, as 

recommended in the BART guidelines, has been used for almost every single-source BART 

analysis in the country and has provided a consistent basis for assessing the degree of visibility 

benefit anticipated from controls as one of the factors under consideration in a five-factor BART 

analysis. Since almost all states have completed their BART analyses and have either approved 

SIPs or FIPs in place, there is a large set of available data on modeled visibility impacts and 

benefits, and how those model results were utilized to screen out sources and as part of the fivefactor analysis in making BART control determinations for comparison with. 

The commenter states that the largest visibility benefit from controlling a single EGU is 0.813 

dv, an imperceptible amount. We address this comment elsewhere where we discuss that 

perceptibility is not a threshold criterion for considering improvements in visibility to be 

meaningful. 

Comment: [Domtar Supplemental Comments (0170) p. 1] The Domtar Ashdown Mill stated 

that it is submitting supplemental comments on the EPA’s proposed BART rules for the 

Ashdown Mill. The Ashdown Mill appreciates the EPA’s willingness to reopen the comment 

period on the proposed BART requirements to allow the Ashdown Mill to complete its very 

detailed and comprehensive analysis of CALPUFF’s model’s “margin of error.” Based on the 

report, the Ashdown Mill’s proposed BART requirements will not result in any reasonably 

anticipated improvements in visibility and should be withdrawn. Without waiving any of our 

supplemental comments, should EPA proceed to finalize the proposed Ashdown Mill BART, we 

incorporate by reference the prior comments submitted on July 15, 2015, including the 

comments justifying an extension of the compliance period for five years. 

In these supplemental comments, the Domtar Ashdown Mill is providing the following 

additional information: 

(1) Margin of Error Analysis for the Ashdown Mill; 

(2) reasonable progress; and 

(3) other considerations. 
414

Response: We acknowledge Domtar’s supplemental comments. We address Domtar’s July 15, 

2015 comments elsewhere throughout this RTC document. We address the specific comments 

provided in Domtar’s supplemental comments in the sections of the RTC document where we 

discuss modeling, cost, and reasonable progress analysis issues. The “margin of analysis” 

evaluation submitted by Domtar is addressed in response to comments below. 

Comment: EPA improperly uses CALPUFF to justify emission reduction measures when 

the visibility improvements predicted by the CALPUFF model are within CALPUFF’s 

margin of error. [The Associations (0165) p. 9-10] The Associations stated that in at least two 

instances, the proposed Arkansas federal implementation plan FIP imposes emission reduction 

measures through BART on the grounds that CALPUFF modeling showed that those measures 

would reduce visibility impairments, yet those improvements are within CALPUFF’s margin of 

error. This means that EPA has no credible demonstration that there would be any visibility 

improvements attributable to those determinations. 

BART requires that states (or EPA in the case of a federal implementation plan) consider “the 

degree of improvement in visibility which may reasonably be anticipated to result from the use 

of such technology.” 42 U.S.C. § 7491(g)(2). The Ninth Circuit, in National Parks Conservation 

Association v. EPA, Case No. 12-73710, 2015 WL 3559149 at *8 (9th Cir. June 9, 2015), held 

that an estimated visibility improvement of 0.085 deciviews was less than CALPUFF’s margin 

of error, and thus, EPA had no basis to believe that BART controls in that case could 

“reasonably be anticipated” to improve visibility. In the proposed rule, EPA imposes emission 

reduction requirements under BART in situations where CALPUFF predicted very small 

visibility improvements without completing any site specific analyses to determine if these 

visibility improvements are within the margin of error. For example, EPA would require the 

installation of low NOX burners and overfire air at Flint Creek Unit 1 even though the highest

modeled visibility improvement was 0.081 dv. Based on the site specific analysis that was 

completed for Montana in the Ninth Circuit decision for National Parks and Conservation

Association, this very small visibility improvement may be less than the margin of error. EPA 

needs to justify that the small visibility improvement is “reasonably anticipated”. The Clean Air 

Act does not require visibility improvements that cannot be reasonable anticipated. Visibility 

improvements that are less than the margin of error are not “reasonably anticipated” and found to 

be invalid by the Ninth Circuit in National Parks Conservation Association. 80 Fed. Reg. at 

18,968. Visibility improvements at other Class I areas were a fraction of this: 0.026 deciviews at 

Upper Buffalo, 0.024 deciviews at Hercules-Glades, and 0.014 deciviews at Mingo. 

Further, EPA’s own guidelines establish that a threshold of 1.0 deciviews for when a stationary 

source “causes” visibility impairments at a Class I area and 0.5 deciview threshold of when a 

stationary source “contributes” to visibility impairments. 70 Fed. Reg. 39,161 (July 6, 2005). In 

other words, EPA is imposing costly emission reduction requirements on sources that, even if 

their emissions were much higher, would not even rise to the level of “contributing to” visibility 

impairments at the Arkansas Class I areas. EPA cannot rationally hold that emission reductions 

at these stationary sources would be “reasonably anticipated” to improve visibility at Class I 

areas when EPA’s own modeling shows that they do not even contribute to visibility 

impairments. 
415

Sensing that infinitesimal visibility improvements (tiny fractions of what the human eye may 

perceive) cannot justify the imposition of new emission controls, EPA adds these supposed 

improvements through a “Cumulative Visibility Improvement” metric. In this case, the purported 

visibility improvements are 0.145 deciviews – just over 1/10th of what a person may perceive. 

Justifying emission reductions on cumulative visibility improvements is arbitrary and capricious, 

even if the modeled visibility improvements could be believed. In this case, however, where each 

constituent modeled visibility improvement is below CALPUFF’s margin of error, EPA can have 

no confidence that visibility will improve at any individual Class I area through new reduction 

measures. By adding modeled visibility improvements that should individually be treated as 

zero, EPA arbitrarily attempts to create something out of nothing (and even here the “something” 

is far below human perception). EPA should abide by the Ninth Circuit’s decision and avoid 

basing BART determinations on modeled visibility improvements that are within the margin of 

error. This includes its attempt in this case to avoid the decision’s holding by adding low 

confidence modeling results in order to artificially exaggerate the impact of emission reduction 

measures. 

Response: The commenter is mistaken regarding the Ninth Circuit decision including the 

“margin of error” of the model. The Ninth Circuit decision cited did not rule on any specific 

issue related to CALPUFF or the “margin of error”. Rather, the court ruled on a procedural error 

that EPA did not respond to the comment received regarding the CALPUFF margin of error in its 

rulemaking as required under the law. We respond to comments concerning the calculated 

“margin of error” of CALPUFF modeling in a separate response. 

The BART guidelines establish that a visibility impacts from a stationary source of 1.0 deciviews 

or greater are considered “causing” visibility impairments at a Class I area and a 0.5 deciview 

impact as “contributing” to visibility impairments.813 The commenter confuses visibility impacts

with potential unit-level visibility improvements from controls. Given that sources are subject to 

BART based on a contribution threshold of no greater than 0.5 deciviews, it would be 

inconsistent to automatically rule out additional controls where the improvement in visibility 

may be less than 1.0 deciview or even 0.5 deciviews. A visibility improvement greater than 0.5 

dv, as the commenter suggests, is not a requirement of the BART determination because 

visibility improvements less than 0.5 dv may still be determined to be significant. Similarly, as 

discussed in depth in a separate response to comment above, we have not considered 

perceptibility as a threshold criterion for considering improvements in visibility. 

We address comments concerning the use of cumulative visibility in a separate response to 

comment above. 

Comment: Visibility improvement from controls on Lake Catherine Unit 4 cannot be 

reasonably anticipated due to the margin of error in the CALPUFF model. [Entergy 

Arkansas Inc. (0166) p.52-53] Entergy Arkansas Inc. stated that EPA has proposed NOx BART 

controls for Lake Catherine Unit 4 based on the installation of burners out of service (“BOOS”). 

See 80 Fed. Reg. at 18,978. To justify the visibility improvement resulting from installation of 

 

813 70 Fed. Reg. 39161
416

the proposed controls, EPA relied on the CALPUFF dispersion modeling system without 

assessing the reliability of the model to predict very small changes in visibility. In NPCA, the 

Ninth Circuit concluded that EPA had failed to justify that predicted visibility improvements 

were “reasonably anticipated,” as required by the Clean Air Act, where the improvements were 

so insignificant that they were within the CALPUFF model’s margin of error. NPCA, 788 F.3d 

1134, 1146-47. 

On behalf of Entergy, Trinity completed a quantitative analysis to evaluate the margin of error in 

the CALPUFF model for Lake Catherine Unit 4. As part of this analysis, Trinity modeled the 

following three scenarios: 

 All BART – Includes all sources subject to BART, modeled using Pre-BART 

representations; 

 Pre-BART – Includes only Lake Catherine Unit 4, modeled based on the current permit 

representation; and 

 Post-BART – Includes only Lake Catherine Unit 4, modeled using Post-BART emission 

rate and stack parameters. 

Trinity calculated the average difference between modeled values obtained using CALPUFF 

(including the CENRAP background) and IMPROVE monitored values for Caney Creek and 

Upper Buffalo for each of the three modeling scenarios. Trinity compared the regional haze 

design value format of average W20 days visibility for this analysis. Specifically the following 

comparisons were made: 

 Modeled vs Measured W20 Days: The W20 days based on IMPROVE measurements 

were selected for each Class I area and compared with the CALPUFF results from the 

corresponding days. 

 Measured vs. Modeled W20 Days: The W20 days based on CALPUFF modeling results 

were selected considering only days when IMPROVE measurements were taken. 

Modeled values were then compared to the IMPROVE measurements from the 

corresponding days. 

 Measured and Modeled W20 Days: The W20 days based on IMPROVE measurements 

were selected and compared with the W20 days based on CALPUFF modeling 

disregarding temporal correlation. 

A complete discussion of Trinity’s analysis and results is presented in Evaluation of the 

CALPUFF Modeling System Margin of Error for a BART Analysis, Entergy Services, Inc. - Lake 

Catherine Plant, Trinity Consultants (Aug. 4, 2015). (“CALPUFF Margin of Error Report”), 

which is attached as Exhibit H and is hereby incorporated by reference. As demonstrated in the 

CALPUFF Margin of Error Report, the Pre-BART impact from Lake Catherine Unit 4 at Caney 

Creek and Upper Buffalo is inconsequential when compared with the IMPROVE measurements, 

which capture the impact of all other sources, including Lake Catherine, on the Class I areas. 

The proposed NOx BART controls for Lake Catherine Unit 4 will result in visibility 

improvements that are even more inconsequential and cannot accurately be predicted by 
417

CALPUFF. Based on Trinity’s analysis, the minimum calculated margin of error for CALPUFF 

for Lake Catherine Unit 4 is 0.93 dv. The CALPUFF predicted visibility improvement associated 

with EPA’s proposed BART controls for Lake Catherine Unit 4 at Caney Creek and Upper 

Buffalo falls within this margin of error. See 80 Fed. Reg. at 18,978, Table 42. As such, the 

visibility improvements at each of these Class I areas associated with the proposed BART 

controls for Unit 4 cannot “reasonably be anticipated.” 42 U.S.C. § 7491(g)(2); see NPCA, 788 

F.3d 1134, 1146-47. Accordingly, EPA has not adequately demonstrated that it is appropriate to 

require NOX BART controls on Lake Catherine Unit 4. 

[Exhibit H to EAI Comments, p. 6-1] Based on the analysis completed for the Entergy Lake 

Catherine Plant, the minimum calculated margin of error for CALPUFF for the Lake Catherine 

Plant is 0.93 dv. The CALPUFF predicted visibility improvement associated with EPA’s 

proposed BART for Lake Catherine at Caney Creek and Upper Buffalo fall within this margin of 

error. As such, the visibility improvements at each of these Class I areas associated with the 

proposed BART cannot be reasonably anticipated, as is required by the Clean Air Act. (42 

U.S.C. 7491(g)(2). 

Comment: Domtar’s Margin of Error Analysis demonstrates that the predicted visibility 

improvement from EPA’s proposed BART controls for Power Boiler 2 fall within the 

CALPUFF model’s margin of error. [Domtar Supplemental Comments (0170) p. 1-2] Domtar 

stated that as demonstrated in the Trinity Consultants report enclosed with Domtar’s comments, 

the predicted visibility improvements associated with the imposition of the proposed BART 

requirements for Power Boiler 2 at the Ashdown Mill fall within the CALPUFF model’s margin 

of error. The CALPUFF model’s predicted visibility gains are mere artifacts of the model and do 

not show that any real world improvements in visibility will occur. Since these visibility 

improvements cannot be “reasonably anticipated,” the proposed BART requirements for Power 

Boiler #2 should be withdrawn. See Am. Corn Growers Ass’n v. EPA, 291 F.3d 1, 7 (D.C. Cir. 

2002). 

As highlighted in Nat’l Parks Conservation Ass’n v. EPA, No. 12-73710, 2015 WL 3559149 (9th 

Cir. June 9, 2015), it is essential that EPA demonstrate that any BART requirements result in 

visibility improvements that can be reasonably anticipated. See 42 U.S.C. § 7491(g)(2). This 

showing is even more important in situations, such as the proposed BART requirements for the 

Ashdown Mill, where the annual cost of meeting the proposed rule is projected to be in the 

millions and threatens the competitive position of the Ashdown Mill. The enclosed report by 

Trinity Consultants demonstrates that EPA cannot show any “reasonably anticipated” 

improvements in visibility will result, and as such, this fundamental predicate to the imposition 

of BART on the Ashdown Mill is lacking. [See “Evaluation of the CALPUFF Modeling System 

Margin of Error For a BART Analysis- Domtar A.W. LLC, Ashdown Mill,” prepared by Trinity 

Consultants, dated August 2015.] 

[Domtar Supplemental Comments, Attachment p. 7-1] Based on the analysis completed for the 

Domtar Ashdown Mill, the minimum calculated margin of error for CALPUFF for the Ashdown 

Mill is 0.93 dv. The CALPUFF predicted visibility improvement associated with EPA’s 

proposed BART controls for the Ashdown Mill Power Boiler No. 2 at Caney Creek and Upper 

Buffalo fall within this margin of error. As such, the visibility improvements at each of these 
418

Class I areas associated with the proposed BART requirements cannot be reasonably anticipated, 

as is required by the Clean Air Act.27 As such, it is not appropriate for EPA to require controls 

on the unit based on the CALPUFF model’s predicted visibility impacts. 

Response: The commenters mischaracterize the Ninth Circuit decision regarding the “margin of 

error” of the model. The commenter suggests that the Court agreed that the anticipated visibility 

benefits in that case were within the margin of error of the model. This is incorrect. The Ninth 

Circuit decision cited did not rule on any specific issue related to CALPUFF. Rather, the court 

ruled on a procedural error that EPA did not respond to the comment received regarding the 

CALPUFF margin of error in its rulemaking as required under the law. 814 Here and elsewhere in 

our response to comments we address a very similar comment with respect to CALPUFF 

modeling for Arkansas sources, as well as the commenter’s analysis claiming to estimate the 

“margin of error”. 

The Trinity analysis815 purports to calculate a “margin of error” of the CALPUFF modeling for 

Lake Catherine. In general, the commenter’s analysis adds CALPUFF model results for a 

specific source or sources with CAMx model results and compares this value to visibility 

conditions derived from monitored data at each Class I area. This analysis is flawed for many 

reasons as discussed in detail below and fails to provide any assessment of the ability of the 

CALPUFF model to evaluate the “degree of visibility improvement that may be expected from 

available control technology” to inform BART and reasonable progress evaluations. We note 

that the commenter did not provide any spreadsheets or detailed calculations to support this 

analysis, therefore we were unable to fully review and respond to the individual calculations or 

specific methodology underlying the presented values in the commenter’s summary report. We 

therefore focus our comments on the general methodology described in the report. 

CALPUFF modeling following the BART Guideline approach is used to provide estimates of the 

maximum visibility impacts from a source based on maximum emissions and simplified 

chemistry, irrespective of the relationship to the 20% worst days. The CALPUFF visibility 

analysis performed for each of the sources in this action modeled a period of three years and 

utilized a constant emission rate (equal to the maximum 24-hr emissions for baseline and 

estimated control-level emissions), assumptions of constant background ammonia, and 

simplified, limited chemistry. Modeling of a three year period allows for consideration of 

climatological worst case conditions. The goal of this modeling is to estimate the maximum 

anticipated impact from the source, and not to provide an estimate of downwind concentrations 

or visibility conditions for a specific place at a specific time. 

In promulgating the BART guidelines we made the decision in the final BART Guideline to 

recommend that the model be used to estimate the 98th percentile visibility impairment rather 

than the highest daily impact value as proposed. We made the decision to consider the less 

 

814 “Concurring, Judge Berzon wrote separately to emphasize her understanding that the lead opinion is not 

impugning the EPA’s use of the CALPUFF model generally, but only requiring a sufficiently reasoned response to a 

particular comment regarding CALPUFF’s usefulness in these specific circumstances.” Nat’l Parks Conservation 

Ass’n vs. EPA 

815 Evaluation of the CALPUFF Modeling System Margin of Error for a BART Analysis, Entergy Services, Inc. – 

Lake Catherine Plant, available as Exhibit H to comments submitted by Entergy Arkansas, Inc.
419

conservative 98th percentile primarily because the chemistry modules in the CALPUFF model 

are simplified and likely to provide conservative (higher) results for peak impacts. Since 

CALPUFF’s simplified chemistry could lead to model over predictions and thus be conservative, 

EPA decided to use the less conservative 98th percentile.816 As a starting point, a BART-eligible 

source is identified as subject-to-BART and subjected to a five-factor BART analysis only if it 

may reasonably be anticipated to cause or contribute to any impairment of visibility based on the 

baseline CALPUFF modeling following the protocol and using the inputs discussed above. The 

assessment of anticipated visibility benefits due to controls is then done in a relative sense 

following the same modeling procedure and comparing the modeled impact from baseline 

emissions to the reduced modeled impact of the various control scenarios. This visibility 

analysis is only one factor of the BART determination and is used to weigh the visibility benefits 

of controls in consideration of costs and incremental costs of controls, other environmental 

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

source. 

Our CALPUFF visibility modeling, performed using the regulatory CALPUFF model version 

and following all applicable guidance and EPA/FLM recommendations, showed significant 

visibility impacts due to the source and benefits from controls. The CALPUFF model, as 

recommended in the BART guidelines, has been used in almost every single-source BART 

visibility impact analysis in the country and has provided a consistent basis for determining if a 

source is anticipated to “cause” or “contribute” to visibility impairment at a Class I area and in 

assessing the degree of visibility benefit anticipated from controls as one of the factors under 

consideration in a 5-factor BART analysis. CALPUFF modeling, following the BART modeling 

protocol, has also been used to evaluate the visibility benefit of controls in a number of 

reasonable progress analyses. 

Inappropriately combines model results from two different models 

The commenter’s analysis asserts that adding a “background” light extinction value derived 

from the 2002 CENRAP CAMx photochemical model results for the 20% worst days to the 

CALPUFF model results accounts for the impact of all other emissions sources and allows for a 

“like-kind comparison” with the monitored values. The commenter is incorrect because the 

CALPUFF modeling following the BART guidelines is designed to provide a maximum, worst 

case value. The CALPUFF modeling utilized a constant emission rate based on the maximum 

actual 24-hr emissions during the baseline period. In addition, the CALPUFF modeling used a 

constant background ammonia value of 3 ppb, and a limited, simplified chemistry mechanism. 

Meteorological data is based on an initial wind field based on prognostic data from the MM5 

model which is then adjusted based on terrain and land use data and then further adjusted based 

on observational data. A model such as CALPUFF essentially holds constant a number of 

factors in order to isolate the impacts of a single source. It is extremely difficult in observational 

analyses to sufficiently control for all factors, including emissions from other sources, to be able 

to isolate the impacts of a single facility. 

 

816 “Most important, the simplified chemistry in the model tends to magnify the actual visibility effects of that 

source. Because of these features and the uncertainties associated with the model, we believe it is appropriate to use 

the 98th percentile—a more robust approach that does not give undue weight to the extreme tail of the distribution.” 

70 FR 39104, 39121. 
420

Simply adding a background value does not address many of the issues that cause the 

comparison to not be a “like-kind” comparison. We discuss below why the CAMx 

“background” value does not properly represent the impact from all other emission sources for 

the purposes of the commenters comparison. In addition, the use of this “background” value 

does not address or adjust for the maximum constant emissions and background ammonia 

assumptions used in the CALPUFF model, nor does it address the issue of considering the 

competition for available ammonia that other emission sources represent. As discussed by the 

commenter, CALPUFF is a “clean background analysis” because it only models emissions from 

one source. Therefore all of the ammonia present in the model is available to react to the 

emissions from this one source. In a “dirty background analysis” emissions from all sources 

interact and compete for available ammonia in forming particulate matter. This limits the 

amount of ammonia available to react with the emissions from the source of interest to form 

visibility impairing particulate matter. 

CAMx photochemical modeling using actual or typical emissions (which includes all emissions 

sources and has a more realistic representation of formation, transport, and removal processes of 

particulate matter that causes visibility degradation) provides an estimate of downwind 

concentrations paired in space and time. The CENRAP 2002 CAMx modeling utilized actual 

available emissions data, including hourly measured emissions data from EGUs and prognostic 

meteorological data from the MM5 model that went through extensive meteorological model 

performance analysis.817 Ammonia concentrations are calculated based on emissions, transport, 

deposition, and chemistry. It is not appropriate to simply add predicted concentrations or 

visibility impacts from two very different models that rely on different model inputs (emissions 

and meteorological data), utilize different chemistry, and are used for different purposes. 

Furthermore, because the CENRAP CAMx modeling already contains emissions from the BART 

sources, simply adding the two model estimates results in a double counting of the impact from 

these sources. As we discuss in more detail below, it is unclear if or how there was an attempt to 

adjust this “background” value to avoid double counting in this manner. 

Fails to consider uncertainty in “background” value 

The commenter’s analysis fails to consider any uncertainty in the CAMx derived “background” 

value that is added to the CALPUFF modeled visibility impact. As demonstrated below, the 

“margin of error” calculated by the commenter is dominated by the under-prediction in the 

CAMx derived “background” value. The CENRAP 2002 CAMx model results the commenter 

uses to estimate the “background” were compared to monitored values and a thorough model 

performance analysis was performed by CENRAP to assess the model’s ability to estimate 

visibility conditions at the Class I areas.818 In reviewing the 2008 Arkansas Regional Haze SIP, 

we reviewed the CENRAP model selection and performance of the CAMx and CMAQ modeling 

performed.819 In that review we summarized the CENRAP model performance evaluation the 

 

817 See CENRAP TSD at section 1.3.9 and Appendix A 818 See the CENRAP TSD 819 See Appendix A to the TSD, Review of Modeling and Emission Inventory Development for the Regional Haze 

Implementation Plan for the State of Arkansas available at: http://www.regulations.gov/#!documentDetail;D=EPAR06-OAR-2008-0727-0013 
421

2002 CENRAP modeling for Caney Creek and Upper Buffalo on the days that comprise the 20% 

worst days as defined by the monitor: 

On most of the worst 20 % days at Caney Creek, total extinction is dominated by sulfate 

extinction with some extinction due to OMC. On four of the worst 20% days, extinction 

is dominated by nitrate. Sulfate is underestimated and results in an under-prediction (-

33% bias) on total extinction. There is an overestimate of extinction (+44% bias) on the 

20% best days due to an over-prediction of NO3. For Upper Buffalo, the worst 20% days 

are dominated by sulfate extinction, however two of these worst days are dominated by 

nitrate. Sulfate and OMC under-prediction results in an under-prediction (-40%) on total 

extinction. Overall performance is good on the 20% best days at Upper Buffalo, however 

there are large over-predictions of nitrate on some days. 

The model performance evaluation performed by CENRAP found that total extinction at both 

Arkansas Class I areas was under-predicted by the model. Therefore, the “background” value 

added by the commenter has uncertainty associated with it that it alone can explain any 

difference between modeled and measured values evaluated by the commenter. In other words, 

it is impossible to discern from the commenter’s evaluation whether any of the difference 

calculated between monitored and measured values are due to over or under performance of the 

CALPUFF modeled values. 

As we noted earlier, the commenter did not provide any supporting spreadsheets or datasets, so 

we are unable to review the individual calculations or specific methodology underlying the 

presented values in the commenter’s summary report. The commenter did not provide the 

“background” values that were added as part of the analysis. From the submitted reports, it is 

unclear for Lake Catherine if any adjustment was made to address double counting from the 

BART source(s). The Domtar analysis discusses subtracting out impacts from the BART 

sources, but does not discuss how this was done or provide any additional information to 

determine the values that were used. The CENRAP CAMx source apportionment modeling does 

not provide any source-specific impact information that could be subtracted from the CENRAP 

modeling. 

For the Lake Catherine analysis, the report states the following concerning background value 

used: 

In order to obtain an estimate of the impact of other emission sources (i.e., point, nonpoint, mobile, biogenic, etc.), Entergy obtained a background value from CAMx 

modeling completed for the Central Regional Air Planning Association (CENRAP) by 

ENVIRON using the CENRAP PM Source Apportionment Technology (PSAT) Tool.820 

The CENRAP's CAMx analysis was completed for actual emissions from 2002; 

therefore, the background value from 2002 was added to the CALPUFF predicted 

impacts for all modeling scenarios and compared to 2002 IMPROVE data for Caney 

Creek and Upper Buffalo. 

 

820 See the CENRAP TSD and the August 27, 2007 CENRAP PSAT tool - 

CENRAP_PSAT_Tool_ENVIRON_Aug27_2007.mdb 
422

For the Domtar analysis, the report states the following concerning background value used: 

In order to estimate the impact of other emission sources (i.e., point, non‐point, mobile, 

etc.), Domtar obtained a background value from the CAMx modeling completed for the 

Central Regional Air Planning Association (CENRAP) by ENVIRON using the 

CENRAP PM Source Apportionment Technology (PSAT) Tool.15 The CENRAP PSAT 

tool is determined by subtracting contribution of all BART source (for scenario 1) or 

contribution of the Ashdown Mill (for scenario 2 and 3) from the total CENRAP 

predicted concentrations. The CENRAP’s CAMx analysis was completed for actual 

emissions from 2002; therefore, the background value from 2002 was added to the 

CALPUFF predicted impacts for all modeling scenario runs performed using 2002 

meteorological data and compared to 2002 IMPROVE data for Caney Creek and Upper 

Buffalo. 

The Domtar analysis provided CALPUFF modeled and observed data points for the Pre-BART 

scenario821 in some of the figures included in that report. We reviewed the 2002 Lake Catherine 

baseline modeling that was prepared for the BART analysis and downloaded the observed data 

for 2002 for Caney Creek and Upper Buffalo.822 From this data we attempted to back calculate 

the “background” values used by the commenter in their analysis.823 We estimate that the 

“background” values that were added to the CALPPUFF model results are approximately 133.9 

Mm-1 for Caney Creek and 124.7 Mm-1 for Upper Buffalo. We compared these to the 2002 

CAMx model results from the CAMx PSAT tool. The value used for Caney Creek appears 

consistent with the projected 20% worst days value of 133.93 Mm-1, but the value used for 

Upper Buffalo is not consistent with the projected 20% worst days value of 131.79 Mm-1 from 

the CENRAP CAMx modeling. From the available data, we are unable to determine from where 

the value used for the Upper Buffalo “background” was derived. As best we can conclude, the 

“background” values represent the 2002 CAMx projections of the total visibility impairment 

from all sources. Any adjustments to those values were not documented in the submitted 

comments. 

This “background” value derived from the CENRAP CAMx photochemical modeling constitutes 

the majority of the modeled value (CALPUFF modeled impact plus “background”) that is being 

compared to the monitored value. For example, the table below summarizes the modeled and 

observed values that were used in the Domtar analysis for Caney Creek. The calculated “margin 

of error” is dominated by the difference between the observed values and the CAMx modeled 

visibility impairment due to all sources. As discussed above, the model performance of the 

CENRAP 2002 CAMx modeling is well understood and it was demonstrated that this CAMx 

model scenario underestimates visibility impairment by 30-40% at these two Class I areas. The 

commenter’s analysis shows this under-prediction. 

 

821 See Figures 5-1 through 5-6, “Evaluation of the CALPUFF Modeling System Margin of Error Report for BART 

Analysis, Domtar A. W. LLC, Ashdown Mill” Prepared by Trinity Consultants, August 2015 8222002 monitor data was obtained from the WRAP Technical Support System website at: 

http://vista.cira.colostate.edu/tss/ 

823 See ”EPA calcs RTC margin of error.xlsx” in the docket for this action
423

Following the commenter’s methodology, even if the CALPUFF modeled values were increased 

by a factor of ten, the commenter’s estimated “margin of error” of the model would not change 

significantly. The table below summarizes the change in margin of error due to a ten-fold 

increase in the CALPUFF modeled values. For example, for the “modeled vs. measured” 

scenario the margin of error changes by only 4% due to a ten-fold increase in the CALPUFF 

modeled values. This clearly demonstrates the disconnect between the commenter’s estimated 

“margin of error” and any assessment of the CALPUFF model’s ability to estimate visibility 

impairment from a source. Furthermore, because of the under-prediction in the “background” 

value, increasing the CALPUFF modeled value tenfold actually results in a slight improvement 

in what the commenters asserts is an indication of model performance by decreasing the 

calculated “margin of error” for two of the comparisons. For the “modeled vs. measured” 

scenario the margin of error decreases from -29.02 Mm-1 to 27.9 Mm-1 when the CALPUFF 

modeled values are increased by a factor of ten. We explain further below the over-prediction 

seen on the measured vs. modeled comparison. 

 

Domtar impacts on Caney Creek. Modeled and observed values and estimated “margin of error” 

Do

mtar PreBART 

Sce

nario 

o

bserved 

CA

LPUFF 

modeled 

CA

Mx derived 

“background

” 

“Margin of Error” 

M

odeled 

minus 

Observed 

10xCA

LPUFF 

Model

ed minus 

Observed 

Change in 

Margin of error due 

to ten-fold increase 

in CALPUFF results 

Mo

deled vs. 

Measured 

1

63.05 

0.12

4 

133.

9 

-

29.02 -27.9 -4% 

Me

asured vs. 

Modeled 

7

0.23 

1.13

7 

133.

9 

64

.81 75.05 16% 

Mo

deled & 

Measured 

1

63.05 

1.13

7 

133.

9 

-

28.01 -17.77 -37% 

 

Considered Scenarios 

The commenter’s comparison includes consideration of three scenarios: 

 All BART – Includes all sources subject to BART, modeled using Pre-BART 

representations; 

 Pre-BART – Includes only Lake Catherine Unit 4, modeled based on the current permit 

representation; and 

 Post-BART – Includes only Lake Catherine Unit 4, modeled using Post-BART emission 

rate and stack parameters. 

Because the commenters did not submit any spreadsheets or supporting data, it is not clear how 

CALPUFF results for all BART sources were combined for the first scenario. It is unclear how 
424

the inclusion of all BART sources would provide useful information on the uncertainty of 

modeling the impact from a single source. The second scenario still suffers from all the issues 

discussed above concerning the uncertainty in the selected “background” concentration and the 

combining of CAMx and CALPUFF results. The third scenario, modeling post-control 

emissions, attempts to compare monitored visibility conditions in 2002 to a future scenario that 

would only result from the installation of additional controls. As such this scenario would not 

provide any useful information on the ability of the model to reproduce past visibility conditions. 

The commenter provides no explanation to support the selection of these scenarios or why 

analysis of any one scenario would be preferable to the other. 

Flaws with the Modeled Versus Measured Visibility comparison 

The commenter calculates the difference between the modeled values (the commenter calculated 

average CALPUFF impact summed with the CAMx derived “background” concentration for the 

20% worst days) and the monitored values during 2002 at Caney Creek and Upper Buffalo for 

the three scenarios described above. Specifically, the commenter made the following 

comparisons: 

 Modeled vs Measured W20 Days: The 20% Worst days based on IMPROVE 

measurements were selected for each Class I area and compared with the CALPUFF 

results from the corresponding days. 

 Measured vs. Modeled W20 Days: The W20 days based on CALPUFF modeling results 

were selected considering only days when IMPROVE measurements were taken. 

Modeled values were then compared to the IMPROVE measurements from the 

corresponding days. 

 Measured and Modeled W20 Days: The W20 days based on IMPROVE measurements 

were selected and compared with the W20 days based on CALPUFF modeling 

disregarding temporal correlation. 

We note that for all comparisons and calculated difference between modeled and monitored 

values, as discussed above, the 2002 CENRAP CAMx modeled concentrations for the 20% 

worst days were added to the CALPUFF model results before comparison to the monitored 

values. The observational data used in the comparison is from the IMPROVE network monitors 

at the Class I areas. These monitors only take measurements every third day, so the data set is 

limited to approximately 120 days of measurements over 2002. We also note that the strength of 

the CALPUFF model for BART and RP analysis is to predict the highest values (8th High value) 

that would occur sometime during a 3 year period at a Class I area and not to model specific 

values tied to specific time and location. 

 

The first comparison looks at the 20% worst days (24 highest days) measured at the monitor and 

the corresponding CALPUFF modeled impact on that day. We discuss above the goal of the 

CALPUFF modeling for the BART analysis is to estimate the maximum anticipated impact from 

the source (based on constant maximum emissions, constant background ammonia, and 

simplified chemistry) at a Class I area that is typically at least several hundred square miles, and 

not to provide an estimate of downwind concentrations or visibility conditions for a specific 

place and at a specific time. Nevertheless, the commenter attempts to do just that by examining 
425

the specific modeled values on those days with measured high visibility impairment during 2002. 

As can be seen by the CALPUFF model results used for this comparison,824 the Domtar and 

Lake Catherine facilities do not have large modeled impacts during the 20% worst days at the 

monitor. In fact for many of these days, there is no visibility impairment due to these sources as 

the transport patterns on these days do not carry emissions from these sources to the Class I area. 

As discussed elsewhere, the days that CALPUFF model maximum or 98th percentile value 

impacts of the facility occur may not coincide with any of the days that make up the days in the 

worst 20% days at the Class I area. As such, this comparison provides little value in assessing 

the CALPUFF model’s ability to estimate the maximum visibility impairment or assessing the 

benefit of controls in reducing this impact. 

The second comparison looks at the 20% highest modeled days, only looking at the subset of 

days with corresponding measurements. While the monitored data corresponds to the days with 

the highest CALPUFF modeled values, the “background” value derived from the CAMx 

modeling corresponds to the 20% worst days as defined by the monitor. This “background” 

value represents the average visibility impairment over the worst 20% days (as defined by the 

monitor) due to the visibility impact from all sources. This mismatch between the set of days in 

the observations and the set of days estimated in the photochemical modeling “background” 

results in a “background” value that is much higher than the observational data set, and an 

overall over-prediction in the comparison. As can be seen in the table above, the “background” 

value is almost twice the observed visibility impairment and results in a large calculated 

difference in modeled versus observed values in the commenter’s analysis. 

The third comparison looks to compare the set of days with the highest monitored visibility 

impairment with the set of days with the highest modeled visibility impairment. As discussed 

above, in general, the visibility impairment on the highest (worst) monitored days is due to 

sources other than the Domtar or Lake Catherine facilities. Those days with high CALPUFF 

modeled impacts are a different set of days that have different meteorological/transport 

conditions that are conducive to the chemistry and transport needed to cause visibility impacts 

from Domtar or Lake Catherine to occur at the Class I area. Therefore, in addition to the 

problems discussed throughout this response, this comparisons does not provide for a “like-kind” 

comparison as it attempts to compare observations that occur under one set of meteorological 

conditions to a set of days with completely different overall meteorological conditions. 

Gives undue weight to values at extreme tail of distribution of CALPUFF model results 

 

As discussed above, the BART guidelines recommend the use of the 98th percentile value as to 

not give undue weight to the extreme tail of the distribution of modeled values. Since 

CALPUFF’s simplified chemistry could lead to model over predictions and thus be conservative, 

EPA decided to use the less conservative 98th percentile. The commenter’s analysis utilizes 

those values at the extreme end of the distribution that can significantly impact their calculated 

average of the 20% worst days, despite EPA guidance recommending not to use those extreme 

values because they may be overly conservative (high). For example, the 100 highest modeled 

days for 2002 baseline visibility impacts at Caney Creek from Lake Catherine and Domtar Power 

 

824 See Figures 4-1 and 4-4 of the Margin of Error Analysis for Lake Catherine and Figures 5-1 and 5-4 of the 

Margin of Error Analysis for Domtar. 
426

Boiler #2 are shown in the figures below. It can be seen that the few values at the extreme of the 

distribution are much higher than the rest of the values. Any averaging across a set of days of 

CALPUFF values, whether averaging the 20% worst days as defined by the monitor or by the 

model, that includes some of the values at the extreme end of the distribution (within the top 7 

days) would be shifted towards possibly being overly conservative. For example, one of the 

comparisons made by the commenter included the average over the 24 highest CALPUFF 

modeled impacts. This average value included values for the seven highest modeled impacts in 

the average despite EPA recommendations to avoid these values at the extreme end of the 

distribution because they may be overly conservative. 

CALPUFF Modeled Impacts at Caney Creek 

 

CALPUFF Modeled Impacts at Caney Creek 

0

1

2

3

4

5

6

7

8

9

147

101316192225283134374043464952555861646770737679828588919497

100

Extinction (1/Mm)

CALPUFF ‐ Lake Catherine 2002 baseline ‐ top 100 days
427

Model Performance Evaluation 

Finally, even if the commenter’s comparison of observed versus modeled values were 

appropriate and free from all of the flaws detailed above, the analysis performed does not 

constitute a proper model performance evaluation. Visibility impairment is calculated based on 

the summation of extinction due to each visibility impairing pollutant. The concentration of each 

visibility impairing pollutant is either measured or obtained from the model estimates. These 

concentrations are then used to calculate the total visibility impairment based on the light 

absorbing or scattering characteristic of each pollutant specie and adjustment for relative 

humidity. As we discuss in our modeling guidance, the individual components of the total 

visibility impairing particulate matter should be evaluated individually. Good performance for 

total visibility impairment does not indicate if the model performed well for “the right reasons” 

or the right mix of components.825,826 This type of evaluation should be comprised of statistical 

assessments of modeled versus observed data. Model performance can best be assessed using 

extensive data bases, such as those obtained in major field studies with many monitors and more 

intensive monitoring. In the commenter’s analysis, the comparisons are limited to only 24 data 

points. Limitations in the available monitored data (observational data is only available for 

every third day at one monitor) further limits the amount of available data used in the 

commenter’s analysis for certain comparisons. Section 3.2.1 of the draft modeling guidance827

provides a description of recommended metrics to be used in this type of evaluation. As we 

discuss in this guidance, it is important to include multiple statistical measures in any operational 

evaluation to fully characterize model performance. At a minimum, we recommend evaluating: 

Mean obs, Mean Model, Mean Bias, Mean Error and/or Root Mean Square Error, Normalized 

Mean Bias and/or Fractional Bias, Normalized Mean Error and/or Fractional Error, and the 

correlation coefficient. In addition to these metrics, graphical displays of data allow for a fuller 

characterization of model performance. Therefore, plots play a key role in any model 

performance evaluation. Our guidance details a number of different plots that should be 

evaluated including scatter plots, bugle plots, and soccer plots. The commenter’s analysis does 

not provide an adequate analysis of the available data and improperly focuses on the total 

visibility impairment rather than the individual visibility impairing components. 

Conclusion 

In conclusion, the commenter’s assessment of the “margin of error” of the model suffers from a 

number of fatal flaws and does not provide any useful evaluation of CALPUFF’s ability or utility 

in screening sources that contribute to visibility impairment and “the degree of visibility 

improvement that may be expected from available control technology” as part of a BART 

visibility analysis to inform a BART determination. Whether or not the modeled visibility 

impacts or benefits lie below this calculated “margin of error” is immaterial to any assessment of 

whether or not the visibility impairment or benefits from controls can reasonably be anticipated 

 

825 Guidance on the Use of Models and Other Analyses for Demonstrating Attainment of Air Quality Goals for 

Ozone, PM2.5, and Regional Haze (2007) 826 Draft Modeling Guidance for Demonstrating Attainment of Air Quality Goals for Ozone, PM2.5, and Regional 

Haze (2014) 

827 Draft Modeling Guidance for Demonstrating Attainment of Air Quality Goals for Ozone, PM2.5, and Regional 

Haze (2014) 
428

to occur. BART determinations are only made for sources that have already been shown to 

reasonably be anticipated to cause or contribute to any visibility impairment in a Class I area. 

Modeling of control scenarios is used to estimate the amount that this visibility impact can be 

reduced due to a reduction in emissions. The modeling of these control scenarios is done in a 

manner that holds all variables constant except for the emissions of the pollutant of interest. A 

relative reduction in visibility impact due to a change in emissions is an indication that visibility 

benefits are reasonably anticipated to occur. The modeled magnitude of the visibility 

improvement is not the determinative factor in the BART determination, but only one factor and 

is considered on a relative basis to the baseline impact and the benefits of other controls. The 

relative visibility benefit of all controls is weighed along with the absolute and relative costs of 

controls, energy and non-air environmental impacts, any existing controls, and the remaining 

useful life of the source. As discussed elsewhere, we are confident that CALPUFF distinguishes, 

comparatively, the relative contributions from sources such that the differences in source 

configurations, sizes, emission rates, and visibility impacts are well-reflected in the model 

results. 

Comment: Case study comparisons of CALPUFF modeled values to measured values 

As part of the submitted “Margin of Error for a BART Analysis” reports prepared for the Domtar 

and Lake Catherine facilities,828 the commenters include a discussion of work performed by TRC 

Environmental Corporation. This work includes a June 2012 paper prepared by Gale Hoffnagle 

that discusses several case studies that compared CALPUFF modeled values to measured values 

from the IMPROVE monitoring network.829 The commenter’s state that PPL Montana relied on 

this study in its successful challenge to the Montana FIP, for its argument that EPA failed to 

explain why it could reasonably anticipate a visibility improvement when the improvement was 

within CALPUFF's margin of error.830 This 2012 Hoffnagle analysis is also referred to in 

comments from Nucor Steel-Arkansas and Nucor-Yamato Steel. 

Response: We respond to comments concerning each separate case study below. As we discuss 

above, the commenter mischaracterizes the Court’s finding in the Montana Case. 

Comment: Mohave Generation Station 

CALPUFF modeling completed for the Mohave Generating Station (Mohave Station) showed 

that the 1,590 megawatt (Mw) coal-fired power plant was causing visibility impacts of 2.31 dv at 

the Grand Canyon National Park. The plant was permanently shut down in 2005. A review of 

monitored visibility at IMPROVE stations as close as 90 km to the plant showed no change in 

either nitrate concentrations or visibility impacts subsequent to the closure of the plant. The 

measured visibility impairment at the Grand Canyon National Park during the three years prior to 

(2003-2005) and subsequent to the permanent shutdown (2006-2008) of the Mohave Station 

 

828 “Evaluation of the CALPUFF Modeling System Margin of Error Report for BART Analysis, Domtar A. W. 

LLC, Ashdown Mill” Prepared by Trinity Consultants, August 2015 and “Evaluation of the CALPUFF Modeling 

System Margin of Error Report for BART Analysis, Entergy Arkansas, Inc., Lake Catherine Plant” Prepared by 

Trinity Consultants, August 2015 

829 Gale F. Hoffnagle, Accuracy of Visibility Protocol Modeling in BART Evaluations, TRC Environmental 

Corporation, June 15, 2012. 

830 National Parks Conservation Ass’n v. EPA, 788 F.3d 1134, 1146-47 (9th Cir. 2015) 
429

were analyzed.18 Based on a review of data from three (3) IMPROVE monitoring sites, 

summarized in Table 5-1 below, the changes in visibility were not statistically significant. 

Table 5-1. Mohave Visibility Impairment – Before and After 

IMPROVE

Monitor

2003‐2005

(dv)

2006‐2008

(dv)

Difference

(dv)

Meadview 8.24 8.23 0

Indian	Gardens 8.92 8.86 0.1

Hance	Camp 6.54 6.61 ‐0.14

While the actual change at the nearest monitor between pre- and post-shutdown of the Mohave 

Station, Meadview, was zero dv, the CALPUFF results indicated that visibility impairment 

caused by the Mohave Station was twice the level detectable by the human eye.19 The maximum 

CALPUFF predicted visibility impairment was 3.94 dv over 3 years, with a 98th percentile 

visibility impairment of 2.31 dv from the Mohave Station. Based on the IMPROVE monitoring 

data, CALPUFF highly overestimated the visibility impairment attributable to the Mohave 

Station. In reality, the Mohave Station had essentially no impact on the visibility impairment at 

the Grand Canyon National Park as documented by the change in monitoring values pre- and 

post-shutdown. 

18 Jonathan Terhorst and Mark Berkman, Effect of Coal-fired Power Generation on Visibility in a Nearby National Park, 

Atmospheric Environment 44, 2010. 

19 Gale F. Hoffnagle, Accuracy of Visibility Protocol Modeling in BART Evaluations, TRC Environmental Corporation, June 15, 2012 

Response: The study by Terhorst and Berkman does not convince us that use of CALPUFF 

modeling is inappropriate or that the modeled visibility impacts and benefits should not be 

considered as one of the factors in a BART analysis. The findings of Terhorst and Berkman 

that are summarized and cited to here have been rebutted in the same journal, disputing the 

author’s representation of their findings.831 In their rebuttal, the authors state that Terhorst and 

Berkman’s data analysis actually validate EPA’s interpretation of the data and clearly establish 

the impact of the Mohave Station emissions on visual air quality in the Grand Canyon. The 

authors also warn of the “sensational characterizations” of Terhorst and Berkman, and that such 

“careless claims invite mischievous citation in regulatory contexts.” The commenter does not 

address or acknowledge the findings of this rebuttal. 

As also noted by the authors in their rebuttal, the comparison above of CALPUFF modeled 

visibility impairment from the Mohave station to measured visibility impairment over time, is 

an improper comparison of deciview values. The CALPUFF modeled impairment is based on a 

natural background approach, where the measured change in deciview impairment is a change 

relative to the degraded or dirty background conditions. As we discuss elsewhere, the deciview 

 

831 White, W.H., Farber, R.J., et al. Comment on “Effect of coal-fired power generation on visibility in a nearby 

National Park (Terhorst and Berkman, 2010)” Atmospheric Environment 55, 2012. 
430

is a logarithmic function of extinction and the different deciview calculations are not directly 

comparable. Had the CALPUFF values been adjusted to account for the degraded background 

conditions, the modeled impairment would be calculated as much smaller. Furthermore, the 

CALPUFF modeled impairment is the maximum (or 98th percentile) impairment from the 

source and it would be incorrect to attempt to compare that to a long-term average of observed 

visibility conditions. In addition, a model such as CALPUFF essentially holds constant a 

number of factors in order to isolate the impacts of a single source. As acknowledged by 

Terhorst and Berkman, it is extremely difficult in observational analyses to sufficiently control 

for all factors, including emissions from other sources, to be able to isolate the impacts of the 

closure of a facility. 

Comment: Craig Station 

The Craig Station is located approximately 90 km west of the Mt. Zirkel Wilderness Area (Mt. 

Zirkel) in northwestern Colorado. A study was completed during the development of the 

Colorado Regional Haze SIP to compare CALPUFF predicted impacts for the Craig Station to 

IMPROVE data at Mt. Zirkel.14 Modeled impacts for the Craig Station on the highest 25 days 

were compared against IMPROVE data, which includes impacts from all other sources (e.g., 

other point sources, area sources, mobile sources, etc.). The results showed that the modeled 

impacts from the Craig Station exceeded the monitored values on 14 out of 19 days, and in some 

instances by a significant amount. Given that the IMPROVE data reflects the cumulative impact 

of all sources, both within Colorado and outside of the state, the magnitude of the CALPUFF 

model over-prediction is severe. Although there is another large power plant located between 

the Craig Station and Mt. Zirkel, the modeled impacts from the Craig Station alone were larger 

than the monitored values for all sources combined, which further highlights the degree of over 

prediction. The modeled values were on average ten times the IMPROVE monitored values (i.e., 

9.56 Mm-1).15

14 Gale Hoffnagle, Evaluation of Craig Bart Modeling for Regional Haze Analysis, testimony before the Colorado 

Air Quality Commission, November 18, 2010. 

15 Gale F. Hoffnagle, Accuracy of Visibility Protocol Modeling in BART Evaluations, TRC 

Environmental Corporation, June 15, 2012. 

Response: As we discuss above, the CALPUFF modeling following the BART guidelines 

approach is used to estimate the maximum visibility impact from the source, modeling maximum 

emissions using simplified chemistry and an assumption of constant background ammonia over a 

period of three years. Since CALPUFF’s simplified chemistry could lead to model over 

predictions and thus be conservative (high), EPA decided to use the less conservative 98th 

percentile. The goal of this modeling is to estimate the maximum anticipated impact from the 

source, and not to provide an estimate of downwind concentrations or visibility conditions for a 

specific place at a specific time. 

EPA has recognized that the CALPUFF model can be conservative in estimating visibility 

impairment, and therefore, EPA has used the 98th percentile model results instead of the 

maximum modeled visibility impairment to address the possibility of model over-predictions. 

We have also recognized the model’s sensitivity to background ammonia concentrations, 
431

particularly in the arid regions of the Western United States where ambient ammonia 

concentrations can be low. In development of the Colorado BART modeling protocol832, the 

Colorado Department of Public Health and Environment investigated the sensitivity of 

CALPUFF modeling for the northwestern portion of the state (where Craig station and Mt. 

Zirkel are located) and determined that “while there is a moderate drop in impacts when 

ammonia is dropped from 10 ppb to 1.0 ppb, the model is very sensitive to ammonia when the 

background ammonia level is less than 1.0 ppb.” 

The background ammonia concentration input into CALPUFF is constant in space and time. As 

discussed in the IWAQM Phase 2 Report: 

A further complication is that the formation of particulate nitrate is dependent on the 

ambient concentration of ammonia, which preferentially reacts with sulfate. The ambient 

ammonia concentration is an input to the model. Accurate specification of this parameter 

is critical to the accurate estimation of particulate nitrate concentrations. Based on a 

review of available data, Langford et al. (1992) suggest that typical (within a factor of 2) 

background values of ammonia are: 10 ppb for grasslands, 0.5 ppb for forest, and 1 ppb 

for arid lands at 20 C. Langford et al. (1992) provide strong evidence that background 

levels of ammonia show strong dependence with ambient temperature (variations of a 

factor of 3 or 4) and a strong dependence on the soil pH. However, given all the 

uncertainties in ammonia data, IWAQM recommends use of the background levels 

provided above, unless specific data are available for the modeling domain that would 

discredit the values cited. 

Accordingly, Colorado selected a background ammonia value of 1.0 ppb based on available 

information and the IWAQM recommendations for their BART modeling. This represented a 

worst case assumption for the available ammonia in that area. We note that for CALPUFF 

modeling for sources in Arkansas, the selected background ammonia value utilized in our 

analysis and agreed upon by CENRAP in developing their BART modeling protocol is 3 ppb. 

For some areas of Arkansas, this may be an underrepresentation of the ammonia levels due to the 

numerous sources of ammonia emissions in the state, such as poultry and livestock operations. 

Therefore, the sensitivity of model results to the background ammonia assumption is much less 

for CALPUFF modeling of Arkansas sources. Estimated impacts from sulfate emissions are 

less impacted by the simplified chemistry and ammonia assumptions used in the BART 

modeling than nitrate impacts. 

Comparison of observed visibility versus modeled impacts 

In evaluating the total visibility impacts, Hoffnagle concludes that the results showed that the 

modeled impacts from the Craig Station alone exceeded the monitored values on 14 out of 19 

days. However the values used in the comparison do not represent the impact from the source 

alone as claimed in the report and Hoffnagle’s conclusion is incorrect. Hoffnagle compares the 

total impact, which includes an estimate of background visibility, rather than the impact from the 

source alone, to the measured impairment. As can be seen in the second table below, the 

estimated background value (input into the CALPUFF modeling to provide a background level 

 

832 Supplemental BART Analysis CALPUFF Protocol for Class I Federal Area Visibility Improvement Modeling (DRAFT)

April 15, 2010 (revised June 25, 2010 and August 19, 2010)
432

for the deciview impact calculation) adds an extinction of approximately 12.2 Mm-1 on top of 

the modeled visibility impact from the source. This is a significant level of extinction, 

particularly for a relatively clean Class I area with an average visibility condition of 

approximately 20 Mm-1 (average over 2001-2003). When this estimated background extinction 

is eliminated from the comparison, the measured visibility impairment on 15 of the 19 evaluated 

days is larger than the extinction from this source alone, contrary to the claims of Hoffnagle. If 

the analysis is limited to those specific days where appreciable visibility impairment is measured 

(impairment greater than the 12.2 Mm-1 natural background level) the average modeled 

visibility impairment is less than half the average observed impairment due to particulates. The 

table below shows the IMPROVE monitor data for Mt. Zirkel,833 the model data used in 

Hoffnagle’s analysis,834 and our calculation of the extinction due to Craig Station when the 

approximate background value is subtracted. 

Observed Visibility Conditions at Mt. Zirkel compared to Modeled impacts from Craig Station 

day 

monitor Modeled 

Dv Total 

extinction 

Particle 

extinction Total impact 

Total 

modeled 

extinction 

Background 

Estimated 

extinction 

from source 

4 4.200 15.22 7.22 4.5 15.68 12.20 3.48 

22 1.275 11.36 3.36 5 16.49 12.20 4.29 

46 7.300 20.75 12.75 4.6 15.84 12.20 3.64 

61 4.213 15.24 7.24 4.2 15.22 12.20 3.02 

364 5.092 16.64 8.64 5.1 16.65 12.20 4.45 

32 3.507 14.2 6.2 6.7 19.54 12.20 7.34 

143 3.271 13.87 5.87 4.6 15.84 12.20 3.64 

287 3.365 14 6 4.7 16.00 12.20 3.80 

305 8.368 23.09 15.09 5.1 16.65 12.20 4.45 

332 -0.704 9.32 1.32 5.2 16.82 12.20 4.62 

335 3.228 13.81 5.81 5 16.49 12.20 4.29 

341 4.656 15.93 7.93 4.8 16.16 12.20 3.96 

42 2.445 12.77 4.77 4.6 15.84 12.20 3.64 

57 6.355 18.88 10.88 6.7 19.54 12.20 7.34 

141 5.429 17.21 9.21 4.8 16.16 12.20 3.96 

177 6.549 19.25 11.25 4.6 15.84 12.20 3.64 

249 6.647 19.44 11.44 4.3 15.37 12.20 3.17 

345 4.543 15.75 7.75 4.5 15.68 12.20 3.48 

351 0.266 10.27 2.27 4.8 16.16 12.20 3.96 

Nitrate Over-prediction 

 

833 Data obtained from WRAP TSS website: http://vista.cira.colostate.edu/tss/ 834 Data estimated from Figure 3 and 4 of Gale F. Hoffnagle, Accuracy of Visibility Protocol Modeling in BART 

Evaluations, TRC Environmental Corporation, June 15, 2012. 
433

We have reviewed the data presented in the 2010 and 2012 reports and have determined that the 

reported over-prediction of nitrate of 9.56 Mm-1 was also arrived at in error and is greatly 

overstated. The commenter did not provide any supporting data for these reports, but the initial 

comparison discussed in the 2010 report refers to the 2005 BART analysis developed by the 

Colorado Department of Public Health and Environment.835 Figure 25 of this analysis lists the 

25 highest days of modeled visibility impact for 2002 including the day, receptor, total 

deciviews, background deciviews, delta deciviews due to the source and the % Nitrate 

contributing to the impairment (as shown in the table below). Hoffnagle compares this data to 

monitored data using the same methodology as he did for the updated model data discussed later 

in the 2010 report and discussed in the 2012 report. Based on the modeling data from the 2005 

CDPHE analysis, we have calculated the total modeled extinction due to emissions from Craig 

Station is approximately 5 Mm-1 for the highest modeled value and 3.76 Mm-1 for the 8th high. 

However, Hoofnagle calculates that the extinction from nitrate alone is between 10 Mm-1 and 14 

Mm-1 over the 25 highest modeled days836, 2 to 3 times higher than the actual maximum modeled 

extinction due to all pollutants. Hoffnagle incorrectly calculated the total extinction and nitrate 

extinction based on the delta deciview value rather than calculating the difference in extinction 

between the total and background extinction. As we discuss elsewhere, the deciview is a 

logarithmic function of extinction, therefore the change in extinction that results in a certain delta 

deciview is dependent on where on the deciview scale you are. A delta deciview of 2 dv in near 

pristine conditions would be a much smaller change in extinction than a delta deciview of 2 dv in 

degraded conditions. Using the correct methodology, the modeled nitrate extinction from the 

source on the highest modeled impact day is 4.327 Mm-1 and 3.191 on the 8th highest modeled 

day. While the average monitored nitrate extinction value over all monitored days during 2001-

2003 is approximately 1.23 Mm-1, the maximum observed nitrate extinction value does exceed 6 

Mm-1 in 2002837 and exceeds 3 Mm-1 on 18 monitored days during 2001-2003 (greater than 5% 

of all monitored days). Recognizing the assumptions in the modeling that result in evaluating a 

worst case scenario, the sensitivity to background ammonia levels, and that available monitored 

data is limited to one measurement every three days, we consider these results to be reasonable. 

If actual ammonia levels during these particular days where conditions were conducive to 

transporting the plume to the Class I area were lower, we would anticipate less nitrate formation 

than modeled using the assumed 1ppb. 

 

835 BART CALPUFF Class I Federal Area Individual Source Attribution Visibility Impairment Modeling Analysis 

For Tri-State Generation & Transmission Association Craig Station Units 1 and 2 (Revised) March 3, 2006 

836 See Figure 4 of EXHIBIT 7: G. Hoffnagle, TRC Environmental Corporation, Evaluation of Craig BART 

Modeling for Regional Haze Analysis to Tri-State Generation and Transmission Association, Inc.’s Detailed 

Comments to EPA Proposed Rule Published at 77 Fed. Reg. 18052 to 18098 Submitted May 25, 2012; available in 

the docket for this action. 

837 See Figure 4 of EXHIBIT 7: G. Hoffnagle, TRC Environmental Corporation, Evaluation of Craig BART 

Modeling for Regional Haze Analysis to Tri-State Generation and Transmission Association, Inc.’s Detailed 

Comments to EPA Proposed Rule Published at 77 Fed. Reg. 18052 to 18098 Submitted May 25, 2012; available in 

the docket for this action. 
434

Modeled Total Impacts and Impacts due to nitrate from Craig Station 

Year

1

Day1 Receptor 1DV 

(Total)

1

DV 

(BKG)

1

Delta 

DV1

%_NO3

1

Total 

extinction

2

BKG 

extinction

2

Extinction 

due to 

source2

Nitrate 

extinction 

due to 

source2

2002 359 2948 5.463 1.974 3.489 85.07 17.269 12.182 5.086 4.327

2002 38 2880 5.175 1.996 3.179 84.68 16.778 12.209 4.569 3.869

2002 335 3075 4.907 1.974 2.932 89.78 16.335 12.182 4.152 3.728

2002 34 3075 4.894 1.996 2.898 84.88 16.313 12.209 4.104 3.484

2002 332 2880 4.84 1.974 2.866 86.83 16.226 12.182 4.043 3.511

2002 30 2855 4.749 1.996 2.753 85.03 16.079 12.209 3.869 3.290

2002 293 2949 4.653 1.93 2.723 79.15 15.925 12.129 3.796 3.005

2002 118 3021 4.663 1.974 2.689 84.89 15.941 12.182 3.759 3.191

2002 145 2852 4.457 1.996 2.461 83.72 15.616 12.209 3.407 2.852

2002 124 2855 4.32 1.996 2.324 87.48 15.403 12.209 3.194 2.794

2002 344 3011 4.285 1.974 2.311 89.05 15.350 12.182 3.167 2.820

2002 360 2868 4.242 1.974 2.268 87.81 15.284 12.182 3.101 2.723

2002 298 3075 4.092 1.93 2.162 86.24 15.056 12.129 2.927 2.525

2002 341 3075 4.075 1.974 2.101 89.47 15.031 12.182 2.848 2.548

2002 84 3075 4.042 1.952 2.09 86.58 14.981 12.156 2.825 2.446

2002 12 2868 4.05 1.996 2.054 87.69 14.993 12.209 2.784 2.441

2002 325 2868 4.016 1.974 2.041 87.59 14.942 12.182 2.760 2.417

2002 137 2855 4.013 1.996 2.017 86.75 14.938 12.209 2.729 2.367

2002 326 2915 3.976 1.974 2.002 89.47 14.882 12.182 2.700 2.416

2002 255 3011 3.94 1.952 1.988 87.74 14.829 12.156 2.673 2.346

2002 85 2852 3.91 1.952 1.958 84.85 14.785 12.156 2.629 2.231

2002 292 2855 3.878 1.93 1.948 77.8 14.737 12.129 2.609 2.029

2002 51 2852 3.94 1.996 1.944 89.7 14.829 12.209 2.620 2.350

2002 297 3032 3.832 1.93 1.901 83.26 14.670 12.129 2.541 2.116

2002 302 2915 3.83 1.93 1.9 85.65 14.667 12.129 2.538 2.174

1

Data obtained from Figure 25 of BART CALPUFF Class I Federal Area Individual Source Attribution Visibility 

Impairment Modeling Analysis For Tri-State Generation & Transmission Association Craig Station Units 1 and 2 

(Revised) March 3, 2006 

2

Values calculated by EPA using the relationship extinction = 10*exp(dv/10)

Additional considerations 

In addition, another factor to consider in evaluating the difference between the modeled and 

monitored results is that the CALPUFF model estimates visibility impacts at discrete receptors 

located throughout the Class I area and returns the maximum modeled value for each day 

regardless of location while the monitor (located south of the Class I area) only measures 

visibility conditions at this one site. Given the North to South orientation of the Class I area, the 

complex terrain and that Craig Station is located to the west of the Class I area, it is likely that 

for many of the days analyzed the emission plume from the source was carried towards a portion 

of the Class I area north of the monitor’s location so that the maximum modeled impact from the 

source could be significant, while conditions at the monitor location would be much cleaner. 

Hoffnagle acknowledges this possibility but does not limit his analysis to days where the 

modeled maximum is near the monitor location, and simply states that on some days the receptor 

with the maximum modeled impact is near the monitor location. As discussed elsewhere, the 

analysis utilizes those values at the extreme end of the distribution that can significantly impact 
435

the analysis examining a small number of days, despite EPA guidance recommending not to use 

those extreme values because they may be overly conservative (high). The analysis of modeling 

at Craig station does not consider the impact of including these extreme values in their analysis. 

Furthermore, model performance compared to measurements at one fixed site under a specific 

set of conditions, does not invalidate the model for all applications and conditions. 

Comment: North Dakota SIP 

In the development of the North Dakota Regional Haze SIP, the North Dakota Department of 

Health (NDDH) relied on photochemical modeling conducted by the Western Regional Air 

Partnership (WRAP) to determine the impact of sources located outside of the state, as well as 

non‐utility sources in North Dakota.22 CALPUFF was utilized to determine the impacts of 

utility sources within the state; however, NDDH utilized alternate options in the CALPUFF 

model to address known areas of inaccuracy. The specific areas where they deviated from the 

EPA BART prescribed approach include: 

 Consideration of boundary conditions based on CMAQ modeling, rather than 

ignoring the impact of sources outside of the domain as is done in the EPA 

approach; 

 Puff splitting; 

 Diffusion coefficients based on actual measurements of turbulence rather than the 1952 

Pasquill‐Gifford diffusion confidents required by the EPA approach; 

 Meteorological data from the National Center for Environmental Predictions (NCEP) 

Rapid Update Cycle (RUC) forecast model; and 

 Use of hourly average ammonia concentrations instead of an annual average value. 

The resulting CALPUFF values were then compared to IMPROVE monitoring data from 

the South Unit at Theodore Roosevelt National Park, as summarized in Table 6‐2 below.23

A review of extinction values showed that the average difference between measured and 

modeled extinction was 0.37 Mm‐1 with a standard deviation of 12.6 Mm‐1

.

24 EPA 

rejected NDDH’s modeling on the basis that it included impacts from other sources rather 

than evaluating the impairment due to BART sources against the natural background 

visibility impairment (“dirty” background analysis vs. “clean” background analysis). EPA 

did not specifically comment on the accuracy of NDDH’s CALPUFF modeling. Even with 

the revisions to the modeling methodology applied by NDDH, the margin of error was 

still 0.39 dv on average.25

Table 6‐2. NDDH Measured versus Modeled Nitrate Concentrations

Theodore Roosevelt 

South Unit

Observed 

(μg/m3)

Predicted 

(μg/m3)
436

98th Percentile 2.03 2.06 

90th Percentile 1.21 1.21 

Average of 20% Worst Days 1.42 1.41 

Annual Average 0.53 0.53 

20 Gale Hoffnagle, Evaluation of Craig BART Modeling for Regional Haze Analysis, testimony before the Colorado Air Quality 

Commission, November 18, 2010. 

21 Gale F. Hoffnagle, Accuracy of Visibility Protocol Modeling in BART Evaluations, TRC Environmental Corporation, June 15, 2012. 22 North Dakota State Implementation Plan, February 24, 2010. 

23 North Dakota State Implementation Plan, Chapter 8, February 24, 2010. 24 These statistics are based on the exclusion of January 26, 2002 which was an outlier. 

25 Gale F. Hoffnagle, Accuracy of Visibility Protocol Modeling in BART Evaluations, TRC Environmental Corporation, June 15, 2012.

Response: The commenter states that EPA did not comment on the accuracy of the hybrid 

modeling developed by North Dakota. Because the modeling approach, including impacts from 

other sources and consideration of visibility impacts using a degraded or “dirty” background 

were inconsistent with the modeling approach necessary to assess single-source visibility 

impacts, whether or not the model performed well in predicting the overall visibility conditions 

was irrelevant. We note that Appendix W outlines specific criteria for the use of alternate 

models and it does not appear that those criteria have been satisfied for the use of North Dakota's 

hybrid modeling. Summarizing model results at one Class I area is not sufficient to demonstrate 

model performance. Furthermore, the commenter does not include model results for the other 

Class I area that is included in North Dakota’s modeling, Lostwood, where the hybrid modeling 

does not compare as favorably to the observed results or the WRAP CMAQ modeling. In 

conclusion, the commenter does not provide sufficient data to determine model performance of 

the hybrid modeling or support any of the non-default modeling options employed in CALPUFF. 

We discuss more specific comments concerning puff splitting in a separate response to 

comments. 

We also disagree with the use of the Ammonia Limit Method (ALM) in North Dakota’s 

modeling and note that it is inconsistent with the nitrate repartitioning approach that has been 

previously accepted by the FLMs and EPA. There is a lack of documentation, adequate 

technical justification, and validation for the development and use of the ALM. We and the 

FLMs have previously reviewed protocols proposing using ALM and we and/or the FLMs have 

not approved the use of the proposed ALM procedure. In general terms, one of the key issues is 

ALM is a method to have emissions from other sources consume ammonia, so there is less 

ammonia to react with the source of interest being modeled. Since ammonia levels from the local 

area were used by North Dakota, to do calculations in the modeling to consume ammonia from 

surrounding sources would unnaturally consume ammonia that was actually monitored in the 

North Dakota area modeled. The ALM has not been approved by EPA and the FLMs through 

interagency workgroups (IWAQM or FLAG) as an approved part of CALPUFF based visibility 

analyses. The commenter has not provided any adequate justification, documentation, or other 

analyses to justify the proposed use of ALM. 
437

Comment: Colstrip 

TRC (Gale Hoffnagle) conducted an analysis of measured versus modeled visibility impacts for 

the Colstrip Generating Station (Colstrip Station) located in eastern Montana, which is 

partially owned and operated by PPL Montana, LLC. TRC specifically completed 

comparisons for the worst 20% measured days and worst 20% modeled days (where a 

corresponding measurement was available). TRC found CALPUFF significantly over predicted 

the visibility impacts from the Colstrip Station, as impacts from this source alone were 

frequently higher than the monitored values, which include all other sources (e.g., point, area, 

mobile etc.) as well as the Colstrip Station. Modeled nitrate extinction from the Colstrip 

Station alone was higher than the monitored values on 11 out of 22 of the worst 20% modeled 

days at the Theodore Roosevelt IMPROVE monitoring site. At the UL Bend Wilderness Area 

IMPROVE monitor, modeled nitrate extinction from the Colstrip Station exceeded the 

monitored values on 11 out of 28 of the worst 20% modeled days. At the North Absaroka 

IMPROVE site, the impact from the Colstrip Station was over predicted on 9 out of 20 days of 

the worst 20% modeled days. At the Yellowstone IMPROVE site there are 10 days when the 

modeled extinction from the Colstrip Station exceeded the monitored values for the worst 20% 

modeled days. 

Based on this analysis, PPL Montana, LLC, the operator and partial owner, challenged EPA’s 

BART rules, in part, on the basis that the maximum predicted visibility improvement for 

Colstrip Units 1 and 2 was below the range of perceptibility and falls within the model’s 

margin of error, “meaning that such improvement cannot be reasonably anticipated as required 

by the Act.”26 The U.S. Court of Appeals for the Ninth Circuit upheld PPL Montana LLC’s 

position stating that “the issue is not the perceptibility of the proposed improvements, but the 

model’s ability to anticipate improvements at a level allegedly within its margin of error, 

whether perceptible or not to the human eye. EPA simply offered no response to this 

objection.” 

Response: As discussed elsewhere, the commenters misrepresents the Ninth Circuit decision 

regarding the “margin of error” of the model. The commenter suggests that the Court agreed 

that the anticipated visibility benefits in that case were within the margin of error of the model. 

This is incorrect. The Ninth Circuit decision cited did not rule on any specific issue related to 

CALPUFF. Rather, the court ruled on a procedural error that EPA did not respond to the 

comment received regarding the CALPUFF margin of error in its rulemaking as required under 

the law. 838 

The commenter did not provide the modeling data to allow for a complete review of this 

analysis. It is very likely that this analysis suffers from the same calculation errors noted above 

for the Craig Station/Mt. Zirkel analysis (also performed by TRC) that resulted in a calculated 

“modeled nitrate extinction” value much higher than the actual model estimated value. In the 

 

838 “Concurring, Judge Berzon wrote separately to emphasize her understanding that the lead opinion is not 

impugning the EPA’s use of the CALPUFF model generally, but only requiring a sufficiently reasoned response to a 

particular comment regarding CALPUFF’s usefulness in these specific circumstances.” Nat’l Parks Conservation 

Ass’n vs. EPA 
438

case of the Craig Station analysis, the incorrectly calculated nitrate extinction was 2 to 3 times 

larger than the total extinction estimated by the model. The commenter’s comparison between 

modeled and observed nitrate would be significantly impacted by this error as correcting for this 

error would result in much smaller modeled nitrate extinction values for comparison with the 

monitored values. 

Furthermore, as discussed elsewhere, the analysis examining the 20% worst modeled days 

utilizes those values at the extreme end of the distribution that can significantly impact the 

analysis examining only a small number of days, despite EPA guidance recommending not to 

use those extreme values because they may be overly conservative (high). The analysis of 

modeling at Colstrip station does not consider the impact of including these extreme values in 

their analysis. 

The CALPUFF modeling following the BART guidelines and using the 98th percentile value 

does not lend itself to model performance evaluations of the type suggested by the commenters, 

comparing measured visibility impairment at a specific time and place to modeled impairment at 

that same time and place (see additional discussion in response to comments on the “margin of 

error” analysis submitted by commenters). The BART modeling is a worst case assessment, 

utilizing maximum emissions839, assumptions of background ammonia and ozone, and simplified 

chemistry, modeled over a period of three years. 840 The modeling also does not capture the 

effect of competition with other emission sources for the available ammonia. The goal of this 

modeling is to estimate the maximum anticipated impact from the source in the vicinity of a 

Class I area (typically an area on the order of several hundred square miles or more), and not to 

provide an estimate of downwind concentrations or visibility conditions for a specific place at a 

specific time. BART determinations are only made for sources that have already been shown to 

reasonably be anticipated to cause or contribute to any visibility impairment in a Class I area. 

Modeling of control scenarios is used to estimate the amount that this visibility impact can be 

reduced due to a reduction in emissions. The modeling of these control scenarios is done in a 

manner that holds all variables constant except for the emissions of the pollutant of interest. A 

relative reduction in visibility impact due to a change in emissions is an indication that visibility 

benefits are reasonably anticipated to occur. 

Comment: 

In 1998, the Interagency Workgroup on Air Quality Modeling (IWAQM) conducted a study 

using tracers to test the ability of CALPUFF to match measured concentrations.9

 The study 

specifically involved non‐reacting tracers and focused on the model’s ability to predict plume 

location and concentration rather than accuracy of the model chemistry. Table 3‐1 below 

summarizes the results of the IWAQM study. 

 

839 Page 39129 of BART Rule, “We believe the maximum 24hour modeled impact can be an appropriate measure in 

determining the degree of visibility improvement expected from BART reductions (or for BART applicability)” 

840 Pages 39107-3918 of BART Rule. For assessing the fifth factor, the degree of improvement in visibility from 

various BART control options, the States may run CALPUFF or another appropriate dispersion model to predict 

visibility impacts. Scenarios would be run for the pre-controlled and post-controlled emission rates for each of the 

BART control options under review. The maximum 24-hour emission rates would be modeled for a period of three 

or five years of meteorological data. 
439

Based on the results shown above, IWAQM concluded that CALPUFF could be used to predict 

concentrations at distances of “200 kilometers or less” from the source and that “transport 

beyond 200 to 300 km should be done cautiously with an awareness of the likely problems 

involved.”10 Despite this, EPA’s BART guidelines fails to address the uncertainties in the 

modeling predictions at greater than 200 km and requires sources to add on expensive controls 

based on small impacts predicted by CALPUFF at distances in excess of 200 km. The Ashdown 

Mill is located approximately 250 km from Upper Buffalo. Due to the large distance from the 

source, the predicted visibility improvements at Upper Buffalo for the proposed BART controls 

on Power Boiler No. 2 should be used with caution since EPA did not consider the uncertainties 

in the modeling predictions. 

9

 EPA-454/R-98-019, December 1998 

10 EPA-454/R-98-019, December 1998 

Response: The commenter claims that our action requires controls based on small impacts 

predicted by CALPUFF at distances in excess of 200 km. We disagree with the commenter. 

EPA concluded from the evaluation of the IWAQM phase 2 report case studies that the 

CALPUFF dispersion model had performed in a reasonable manner, and had no apparent bias 

toward over or under prediction, so long as the transport distance was limited to less than 

300km.841,

842 Domtar Ashdown Mills is within 300km of Upper Buffalo. Our BART 

determination was based on consideration of the five-factors, including the anticipated visibility 

benefit due to controls at all impacted Class I areas. The BART visibility analysis for Domtar 

includes assessment of visibility impacts and benefits at Caney Creek as well, which is less than 

100 km from the source. Visibility impacts and anticipated benefits from controls are much 

larger at this nearby class I area than at Upper Buffalo. 

7.e. Reasonable Progress Analysis for Entergy Independence 

 

841 Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary Report and Recommendations 

for Modeling Long-Range Transport Impacts. Publication No. EPA–454/R–98–019. Office of Air Quality Planning 

& Standards, Research Triangle Park, NC. 1998. 

842 68 FR 18458, 2003 Revisions to Appendix W, Guideline on Air Quality Models 
440

Comment: Regional Haze Modeling Assessment Report, Entergy Arkansas, Inc, 

Independence Plant [Exhibit C to EAI Comments]. Entergy contracted with Trinity 

Consultants to perform regional haze modeling using CAMx and PSAT based on the modeling 

originally developed for CENRAP. This modeling was performed to assess the proposed control 

options for Independence units 1 and 2, as well as White Bluff units 1 and 2. In addition to the 

baseline scenario modeling, the FIP scenario (proposed controls in EPA’s FIP) and Entergy’s 

proposed control approach consisting of installed LNB/SOFA on Independence, and the 

cessation of coal combustion at White Bluff were modeled. The CENRAP 2018 emission 

inventory as developed for the Texas and Oklahoma regional haze FIP was utilized. 2002 NEI 

data was substituted for the BART units, with the exception of the Entergy units that were 

revised based on information from Entergy (see table below). 

Unit 

Uncontrolled 

Baseline (tpy) 

Entergy’s 

Proposal Arkansas FIP 

N

Ox SO2 NOx SO2 NOx 

SO

2 

IND

E 1 

63

13 

142

58 

31

50 

121

54 

36

19 

13

57 

IND

E 2 

65

16 

154

07 

33

47 

131

62 

31

67 

15

21 

WB 

1 

75

80 

159

39 --- --- 4145 

14

53 

WB 

2 

81

45 

160

34 --- --- 4060 

14

76 

LC 

4 

12

28 3.26 564 3.26 564 

3.2

6 

 

Source apportionment was used on the baseline modeling scenario to assess the individual source 

contributions to visibility impairment. 

Response: Results from Entergy’s CAMx modeling analysis are discussed below in response to 

more specific comments. 

We note that it is unclear how the above modeled baseline emissions for the Entergy units were 

derived. The table below shows recent actual annual emission levels and emissions during the 

baseline period of 2000-2004. Baseline modeled impacts for the subject to BART White Bluff 

facility would be larger had the modeling utilized historic baseline emissions rather than 

emissions closer to the more recent actual emissions. We also note that the commenter mentions 

additional adjustments to stack locations and stack parameters in the modeling inputs but did not 

provide any documentation on these adjustments in their modeling report. 
441

Uni

t 

Average annual 

emissions 2010-2014 

(tpy) 

Average annual 

emissions 2010-2014 

excluding max and min 

(tpy) 

Average 

emissions 2000-2004 

(tpy) 

N

Ox 

SO

2 

N

Ox 

SO

2 

NO

x 

SO

2 

IN

DE 1 

61

81 

147

85 

61

09 

150

37 

738

5 

112

25 

IN

DE 2 

62

42 

154

01 

62

43 

155

02 

897

4 

118

19 

WB 

1 

81

34 

161

83 

81

47 

161

32 

105

09 

200

69 

WB 

2 

82

67 

158

68 

83

96 

166

14 

881

2 

185

19 

LC 

4 

44

1 

1.0

4 

37

8 

0.9

0 

116

5 

2.9

4 

Comment: Installation of controls on Independence Units 1 and 2 cannot be justified 

because of the de-minimis visibility benefit toward reasonable progress. [Entergy Arkansas 

Inc. (0166) p. 32-34] Entergy Arkansas Inc. stated that EPA’s own analysis counsels against 

imposing emission limits on Independence. EPA asserts that CENRAP modeling shows that 

sulfate from all point sources included in the regional modeling is projected to contribute to 57% 

of the total light extinction at Caney Creek on the W20 days in 2018 and 43% of the total light 

extinction at Upper Buffalo. 80 Fed. Reg. at 18,990. However, EPA recognizes that the 

CENRAP modeling also demonstrates that sulfate from all (elevated and low level) Arkansas 

point sources is projected to be responsible for only 3.58% of the total light extinction at Caney 

Creek and 3.20% at Upper Buffalo. Id. The contribution of Arkansas point sources’ nitrate 

emissions to visibility impairment at Arkansas’ Class I areas is even more insignificant. 

According to EPA’s analysis, nitrate from all point sources included in the regional modeling is 

projected to account for only 3% of the total light extinction at the Caney Creek and Upper 

Buffalo Class I areas, with nitrate from Arkansas point sources being responsible for only 0.29% 

of the total light extinction at Caney Creek and 0.25% at Upper Buffalo. Id. The Independence 

units’ share of emissions to this minimal contribution from Arkansas point sources to visibility 

impairment at Caney Creek and Upper Buffalo is even less. 

Entergy’s CAMx modeling confirms that Independence’s contribution to visibility impairment is 

insignificant in both Class I areas. Independence is projected to contribute to only 0.119 dv of 

visibility impairment at Caney Creek and Upper Buffalo on W20 days in 2018. See Figures 

below for Caney Creek and Upper Buffalo.843 This reflects only one half of one percent of the 

 

843 Figures assume no FIP controls on any of the Arkansas sources. Also, the total haze index values 
442

visibility impairment, based on modeling, on the W20 days in either Caney Creek or Upper 

Buffalo. Yet, based on such a miniscule contribution and with no credible explanation, EPA 

arbitrarily concludes that SO2 and NOX controls at Independence are warranted. 

 

presented in the figures are based on Entergy’s CAMx model predicted total contribution calculated using the new 

IMPROVE equation, whereas the projected haze index values in Figures 1, 2, and 11 - 14 are based on Trinity’s 

Ranked Statistical Analysis and represent the average haze index for the W20 days.
443

Response: We disagree with the commenter’s assertion that the contribution to visibility 

impairment from Entergy Independence is “insignificant” or “minimal.” For example, as the 

commenter states, the CENRAP source apportionment data shows that sulfate from Arkansas

point sources are projected to be responsible for 3.58% of the total light extinction at Caney 

Creek and 3.20% at Upper Buffalo in 2018. As we discuss in our proposal, based on 2011 NEI 

data the Entergy Independence Plant is the second largest source of both SO2 and NOx point 

source emissions in Arkansas, accounting for approximately 36% of the SO2 point-source 

emissions and 21% of the point source NOx emissions in the State.844 Therefore, a significant 

portion of the total visibility impairment on the 20% worst days, on the order of 1% or more, can 

be expected to be attributable to SO2 emissions from a single facility, the Independence facility. 

As we discuss in more detail elsewhere, given their contribution to visibility impairment on the 

20% worst days, we consider both SO2 and NOX to be key pollutants contributing to visibility 

impairment at Arkansas’ Class I areas. Our CALPUFF modeling evaluating the baseline 98th

percentile impacts confirmed that the Independence facility was estimated to impact visibility at 

levels much larger than the level considered to “cause” visibility impairment (greater than 1 dv) 

at nearby Class I areas, ranging from 2.512 dv at Caney Creek, to 1.859 dv at Mingo. CALPUFF 

modeling also showed that anticipated visibility benefits from SO2 and NOX controls at the 

facility exceeded 1 dv at each of the four impacted Class I areas. Although we recognize that 

Independence is not a subject to BART source, for comparison purposes we note that the 

 

844 80 FR 18991
444

threshold used for visibility impacts to determine whether facilities are subject to BART is 0.5 

dv.845 

We disagree with the commenter that the CAMx modeling submitted by the commenter confirms 

that contributions to visibility impairment from the Independence facility are insignificant. When 

properly assessed, as detailed below, the commenter’s CAMx modeling supports and reinforces 

our finding that visibility impairment from Entergy Independence is significant and emission 

reductions will result in meaningful visibility benefits towards the goal of natural visibility 

conditions. Entergy’s CAMx modeling shows a visibility impact of 0.12 dv at both Caney 

Creek and Upper Buffalo when compared to 2018 “dirty” or “degraded” background conditions. 

The commenter then calculates that this 0.12 dv impact is 0.5% of the total 23 dv visibility 

impairment. As discussed below, the deciview scale is a logarithmic function of extinction, and 

therefore the calculations by the commenter are incorrect because they are based on deciview 

values and must be performed based on light extinction to properly calculate the percent 

contribution to visibility impairment. Spreadsheets submitted by the commenter presents the 

light extinction attributable to each source (in inverse megameters) based on the results of their 

CAMx source apportionment modeling and calculates the percent contribution to total visibility 

impairment at each Class I area.846 The table below summarizes these results for Entergy White 

Bluff and Independence. 

Entergy Arkansas’ 2018 CAMx Modeling Percent Contribution to Total Visibility Impairment 

on the 20% worst days (calculated using Mm-1) 

Unit Caney 

Creek 

Upper 

Buffalo 

Independence 

Unit 1 0.611% 0.618% 

Independence 

Unit 2 0.706% 0.687% 

White Bluff 

Unit 1 1.489% 0.327% 

White Bluff 

Unit 2 1.455% 0.302% 

 

As can be seen in the table above, the commenter is incorrect in their statement that the impact 

from the Independence facility is one half of one percent and is in fact, based on their own 

modeling and calculation, approximately 1.3% of the total visibility impairment at each Arkansas 

Class I area. Considering that the CAMx photochemical modeling takes into account the 

emissions of thousands of sources, both in Arkansas and outside of the state, we consider this to 

be a significant contribution to visibility impairment at each Class I area and a large portion 

 

845 “As a general matter, any threshold that you use for determining whether a source ‘‘contributes’’ to visibility 

impairment should not be higher than 0.5 deciviews.” BART Guidelines, App. Y to 40 CFR 51 

846 See “Entergy Scenario 01 Contribution 2015-1124_FINAL.xlsx” , “Avg_Impacts” tab, column “AA” for Caney 

Creek and Upper Buffalo Class I areas.   
445

(approximately one-third) of the total contribution from all Arkansas point sources that can be 

addressed through installation of controls on two units at a single facility. The CAMx modeling 

also showed that at Upper Buffalo, the Independence facility’s contribution to visibility 

impairment is greater than the contribution from all of the subject-to-BART sources addressed in 

this final action combined. 

Furthermore, the deciview visibility impacts for individual sources should be assessed based on 

natural “clean” background visibility conditions. The deciview improvement based on the 2018 

background conditions provides an estimate of the amount of benefit that can be anticipated in 

2018 and the impact a control/emission reduction may have on the established RPG for 2018. 

However, this estimate based on degraded or “dirty” background conditions underestimates the 

visibility improvement that would be realized for the control options under consideration. 

The source impacts and the potential benefits of controls must be considered relative to a light 

extinction level that represents a clean/natural background, rather than the current visibility 

conditions or projected visibility conditions at the end of the planning period.847 

The need for consideration of visibility impacts and benefits relative to clean/natural conditions 

was explained in the preamble to the final BART Guidelines:848

Using existing conditions as the baseline for single source visibility impact 

determinations would create the following paradox: the dirtier the existing air, the less 

likely it would be that any control is required. This is true because of the nonlinear nature 

of visibility impairment. In other words, as a Class I area becomes more polluted, any 

individual source's contribution to changes in impairment becomes geometrically less. 

Therefore the more polluted the Class I area would become, the less control would seem 

to be needed from an individual source. ... Such a reading would render the visibility 

provisions meaningless, as EPA and the States would be prevented from assuring 

“reasonable progress” and fulfilling the statutorily-defined goals of the visibility 

program. Conversely, measuring improvement against clean conditions would ensure 

reasonable progress toward those clean conditions. 

The same logic applies to the evaluation of visibility impacts and benefits for sources examined 

for controls for reasonable progress. Accordingly, the EPA has used clean background conditions 

in evaluating the benefits of controls on individual reasonable progress sources and has 

 

847 This recommended approach to the treatment of background air quality when quantifying source impacts and 

potential benefits from additional measures is different than the approach to background air quality when projecting 

how all emission reductions measures combined will determine visibility conditions at the end of the 

implementation period, i.e., how background assumptions relate to the RPGs. It is not appropriate to consider only 

the amount by which a potential measure or combination of measures would change the projected overall deciview 

index value as of the end of the implementation period, i.e., the degree by which the RPGs would differ with and 

without the control being included in the LTS. The RPGs are values that will be compared in a progress report to 

actual visibility conditions, and accordingly must represent the expected actual overall visibility conditions. 

Estimates of source impacts and measure benefits have a different purpose, which is to help guide decisions on the 

control of individual sources. 

848 70 FR 39124, July 6, 2005 
446

disapproved reasonable progress decisions by states that relied on modeling employing dirty 

background conditions.849 This approach has been upheld by the Eighth Circuit.850 

Because of the logarithmic deciview scale, the use of dirty background conditions will result in 

much lower values for deciview impacts than when using natural background. The figure below 

shows that an increment in light extinction of 10 MM-1 causes a deciview scale increment of only 

1.26 dv when the light extinction increment is assumed to be a ”on top of” a degraded extinction 

level of 75 MM-1 from all other sources. However, if the same light extinction increment is 

assumed to be ”on top of” the natural light extinction value for this Class I area, the deciview 

scale increment is 3.86 dv. In this example, the ‘clean background’ situation yields a del-dv 

improvement 3 times greater than the ‘dirty background’ for the same level of extinction 

improvement. 

 

849 The EPA has followed this logic in the ND (77 FR 20894, April 6, 2012), MT (77 FR 57864, September 18, 2012),

AZ (79 FR 52420, September 3, 2014), and TX (81 FR 296, January 5, 2016) FIPs and partial disapprovals of ND (77

FR 20894, April 6, 2012) and TX (81 FR 296, January 5, 2016). 850 North Dakota v. EPA, 730 F.3d 750, 764‐766 (8th Cir. 2013). “Although the State was free to employ its own

visibility model and to consider visibility improvement in its reasonable progress determinations, it was not free to

do so in a manner that was inconsistent with the CAA. Because the goal of § 169A is to attain natural visibility

conditions in mandatory Class I Federal areas, see 42 U.S.C. § 7491(a)(1), and EPA has demonstrated that the

visibility model used by the State would serve instead to maintain current degraded conditions, we cannot say that

EPA acted in a manner that was arbitrary, capricious, or an abuse of discretion by disapproving the State’s

reasonable progress determination based upon its cumulative source visibility modeling.”
447

Illustration of the different “delta deciview” values, depending on whether projected 

conditions or natural background conditions are used as the starting point. (“WIMO” 

means the Wichita Mountains Class I area. “Mm” means megameters.) 

Because of the non-linear nature of the deciview metric, as a Class I area becomes more polluted 

the visibility impairment from an individual source in terms of deciviews becomes geometrically 

less. Results based solely on a degraded background, will rarely if ever demonstrate an 

appreciable effect on incremental visibility improvement in a given area. Rather than providing 

for incremental improvements towards the goal of natural visibility, degraded background results 

will serve to instead maintain those current degraded conditions. Therefore, the visibility benefit 

estimated based on natural or “clean” conditions is needed to assess the full benefit from 

potential controls. We note that while CALPUFF results are not directly comparable to CAMx 

model results due to differences in metrics, models and model inputs851, CALPUFF visibility 

impacts are also calculated based on natural or “clean” background conditions. 

We recalculated the average modeled visibility impact for the 20% worst days based on the 

commenter’s CAMx modeled average visibility impact for the 20% worst days using a clean 

 

851 Some of the major differences are: (1) CALPUFF uses maximum 24-hour emission rates, while CAMx uses 

annual average emission rates; (2) CALPUFF focuses on the day with the 98th percentile highest visibility impact 

from the source being evaluated, whereas CAMx focuses on the average visibility impacts across the 20% worst 

days regardless of whether the impacts from a specific facility are large or small; and (3) CAMx models all sources 

of emissions in the modeling domain, which includes all of the continental U.S., whereas CALPUFF only models 

the impact of emissions from one facility without explicit chemical interaction with other sources’ emissions. 
448

background approach (using annual average natural conditions background).852 The results are 

shown in the table below.853

Entergy Arkansas 2018 CAMX Modeling - Average Deciview Impacts on the 20% Worst days 

Unit 

Caney Creek Upper Buffalo 

“dirt

y” 

background 

“clean” 

backgrou

nd 

“dirty” 

backgrou

nd 

“clean” 

backgrou

nd 

Independen

ce Unit 1 0.05 0.27 0.06 0.26

Independen

ce Unit 2 0.06 0.32 0.06 0.28

White 

Bluff Unit 1 0.13 0.65 0.03 0.14

White 

Bluff Unit 2 0.13 0.64 0.03 0.13

We note that the Independence facility (units 1 and 2 combined) has impacts greater than 0.5 dv 

at both Caney Creek and Upper Buffalo on average across the 20% worst days on a “clean” 

background basis based on CAMx modeling submitted by the commenter. These CAMx model 

results for the average across the 20% worst days show that the Independence facility contributes 

significantly to visibility impairment on the 20% worst days and controls will result in 

meaningful visibility benefit towards the goal of natural visibility conditions. Furthermore, the 

maximum visibility impact on an individual day within the subset of days that make up the 20% 

worst days are much larger. The table below summarizes the maximum impacts as modeled by 

Entergy using CAMx. Facility-wide visibility impacts from Independence exceed 1 dv at each 

Class I area. We note that in some situations, the days that CALPUFF model maximum or 98th 

percentile value impacts of the facility occur may not coincide with any of the days that make up 

the days in the worst 20% days at the Class I area and the visibility impacts modeled by 

CALPUFF are not directly comparable to the visibility benefits that would be anticipated on the 

20% worst days. 

Entergy Arkansas 2018 CAMX Modeling- Maximum Deciview Impacts (“clean” background) 

on an individual day within the 20% Worst days 

Unit Caney 

Creek (dv) 

Upper 

Buffalo (dv) 

Independence 

Unit 1 0.76 0.75

 

852 Deciview impacts are calculated using the following equation: Δdv = 10 ln((bbackground+ bsource)/ bbackground), where 

b is extinction (Mm-1) and Δdv is the delta-deciview visibility impact. 853 See ” Entergy Arkansas CAMx - EPA calcs max and clean background.xlsx” available in the docket for this 

action 
449

Independence 

Unit 2 0.88 0.83

White Bluff 

Unit 1 1.77 0.40

White Bluff 

Unit 2 1.73 0.37

Comment: The level of improvement expected from EPA’s proposed controls for 

Independence is virtually insignificant and does not justify the costs of controls. [AEPSWEPCO July 15, 2015 comments (00164), p. 5-6, and August 7, 2015 comments (0167), p. 6-

7] AEP-SWEPCO stated that EPA’s evaluation of the impact of emissions on visibility notes that 

their BART-type evaluation for NOx for the Independence Power Plant Units 1 and 2 would 

result in visibility improvements ranging from 0.148 to 0.459 dv with a cumulative improvement 

of 0.978 dv.854 EPA recognized that these improvements were relatively small and proposed an 

option (Option 2) that did not include the LNB/SOFA NOx controls for Units 1 and 2.855 EPA, 

however, did not recognize that the Independence facility is subject to CSAPR and that NOx 

reductions “better than BART” would already be achieved by participation in that program 

without specifically requiring the LNB/SOFA in the FIP. 

For SO2 emissions for Independence Units 1 and 2, EPA estimated improvements with dry FGD 

ranging from 1.045 to 1.178 dv with a cumulative benefit of 4.375 dv. Three of the four class I 

areas would realize visibility improvements barely discernible to the human eye (< 1.1 dv). The 

best improvement is for Upper Buffalo and is only 1.178 dv. It is not appropriate to use the 

cumulative values as a representation of the visibility benefit of adding controls since only the 

improvement at each particular Class I area could actually be recognized. This level of visibility 

improvement is virtually insignificant and does not justify the costs associated with adding a dry 

FGD and, therefore, does not meet the statutory RPG requirement for proper consideration of the 

cost of controls and so is not “reasonable.” 

Response: We disagree with the commenter and do not believe that visibility improvements 

from NOx controls ranging from 0.128 to 0.459 dv are relatively small. Given that sources are 

subject to BART based on a contribution threshold of no greater than 0.5 deciviews, it would be 

inconsistent to consider an improvement in visibility of nearly 0.5 dv to be insignificant or small 

for reasonable progress. In our proposed action, we noted that “The single source CALPUFF 

modeling shows that sizeable reductions to the maximum 98th percentile visibility impact from 

the Independence facility may be achieved through NOX controls.” 856 Furthermore, total 

modeled extinction at Caney Creek is dominated by nitrate on 4 of the days that comprise the 

20% worst days in 2002, and a significant portion of the total extinction at Upper Buffalo on 2 of 

 

854 80 Fed. Reg. At 24873, supplemental modeling values 855 80 Fed. Reg. at 18995 and 18997. 856 80 FR at 18995.
450

the days that comprise the 20% worst days in 2002 is due to nitrate.857 Both NOx and SO2 are 

key pollutants that contribute to visibility impairment at the Arkansas Class I areas. Because we 

have identified these two pollutants as key, we are obligated to determine which sources or 

source categories are responsible for emitting these pollutants and evaluate them for reasonable 

progress. Independence is the second largest point source of both SO2 and NOx in the State.858

Therefore, we evaluated it for reasonable progress controls for both pollutants. We recognized, 

however, that at this time, even though NOx emissions are a key pollutant, point source NOx 

emissions are not the main contributors to visibility impairment on the average of the 20% worst 

days at Arkansas’ Class I areas in 2018, as projected by CAMx source apportionment 

modeling.”859 Even though we recognized that NOx emissions are a key pollutant to reaching 

the regional haze goals, and that the visibility benefits from NOx controls were sizeable, we took 

comment on two options because the visibility impairment due to Arkansas point source 

emissions on the average of the 20% worst days were primarily due to sulfate emissions. We 

also found that significant reductions could be achieved very cost effectively through the 

implementation of low NOx burners. In our final action, we have determined that it is 

appropriate to require the NOx controls as proposed under Option 1 because the goal of the longterm strategy and reasonable progress requirements is to improve visibility and make progress 

towards natural conditions and NOx is a key pollutant impacting visibility at the Arkansas Class 

I areas. We used a shorthand term, driver, in our proposal discussing SO2, and did not mean to 

imply that NOx was not also a key pollutant. While point source NOx emissions are not the 

primary contributor to impairment on most of the 20% worst days, NOx is a key contributor to 

visibility on other days of the year and on some days that make up the 20% worst days (in 2002, 

IMPROVE monitor data shows that two days that make up the 20% worst days at Upper Buffalo 

and three days at Caney Creek are more significantly impacted by nitrate than sulfate). So in 

considering reasonable progress factors, we have determined that because NOx and SO2 are both 

key visibility impairing pollutants, for Independence there are technically feasible and cost 

effective controls available for both SO2 and NOx, and those controls will provide significant 

visibility improvement. Therefore, both SO2 and NOx controls are reasonable and necessary to 

eventually achieve the national goal. We have determined that it is appropriate to reduce NOx 

emissions and finalize Option 1. As to the comment that we did not recognize “better than 

BART” coverage due to CSAPR, we address this comment elsewhere in a separate response to 

comment. 

With respect to the anticipated visibility improvement due to SO2 controls, we consider visibility 

benefits ranging from 1.045 to 1.178 dv at each Class I area to be significant. We note that, the 

Regional Haze Rule provides that sources with a 0.5 dv impact at a Class I area “contribute” to 

visibility impairment and must be analyzed for BART controls, and that source with a 1.0 dv 

impact at a Class I area to “cause” visibility impairment. Given that sources are subject to 

BART based on a contribution threshold of no greater than 0.5 deciviews and visibility impacts 

greater than 1.0 deciview are considered a level to be “causing” visibility impairment, it would 

 

857 See Arkansas RH SIP, Appendix 8.1‐ “Technical Support Document for CENRAP Emissions and Air Quality

Modeling to Support Regional Haze State Implementation Plans,” section 3.7.1 and 3.7.2. See the docket for this

rulemaking for a copy of the Arkansas RH SIP. 858 See Table 59 80 FR 18991 859 80 FR 18995
451

be inconsistent to consider a potential improvement in visibility of greater than twice the BART 

threshold to be insignificant. 

Furthermore, as discussed elsewhere, results of Entergy Arkansas’ CAMx modeling with 

source apportionment provide additional support that the Independence facility has 

significant impacts on visibility at nearby Class I areas on the 20% worst days and that 

controlling these units would result in significant visibility benefits towards the goal of 

natural visibility conditions. 

We address comments concerning the consideration of cumulative visibility benefits and 

imperceptible visibility benefits elsewhere. 

Comment: The CALPUFF modeling vastly overstates the potential visibility improvement 

from controls on Independence. 

[Entergy Arkansas Inc. (0166) p.37-4; Entergy Mississippi Inc. (0168) p. 8-10; Conway 

Corporation et. al. (0172) p. 8-9; and EEAA (0173) p. 14-15] Entergy Arkansas Inc., Entergy 

Mississippi Inc., Conway Corporation et. al., and EEAA stated that EPA’s CALPUFF modeling 

indicates that the SO2 and NOx emission limits proposed for Independence will result in a 1.952 

dv improvement in Caney Creek and a 1.782 dv improvement in Upper Buffalo. See Summary of 

Additional Modeling for Entergy Independence, at 8, Table 5 (Apr. 2015), EPA Docket ID EPAR06-OAR-2015-0189-0147. However, this range is vastly overstated. Based on the current 

monitored visibility levels in Caney Creek and Upper Buffalo, the W20 days show that the 

visibility impairment in 2018 will be approximately 23 to 24 dv. EPA recognizes that sulfate 

from all of Arkansas’ point sources are projected to be responsible for only about 3.6% of total 

light extinction at Arkansas’ Class I areas based on CENRAP modeling. 80 Fed. Reg. at 18,990. 

This means that sulfate from all Arkansas point sources are projected to be responsible for only 

about 0.81 - 0.86 dv of impairment (23-24 dv x 3.6%). For nitrates, EPA projects that Arkansas 

point source emissions will account for, at most, 0.29% of the total light extinction at Arkansas’ 

Class I areas. Id. At 18,990. Independence’s SO2 and NOx emissions contribute only a portion to 

the sulfate and nitrate percentages estimated from Arkansas point sources. It would, therefore, be 

impossible for the SO2 and NOX limits proposed for Independence to result in deciview 

improvements at Caney Creek and Upper Buffalo of 1.952 dv and 1.782 dv, respectively. This 

simple example demonstrates the obvious flaw in EPA’s use of CALPUFF for its reasonable 

progress analysis and, thus, its justification for imposing emission limits on Independence 

despite the fact that the Class I areas are below the URP. 

[Entergy Arkansas Inc. (0166) p.37-41] Entergy Arkansas Inc. stated that another illustration 

demonstrates why CALPUFF greatly overstates the benefits of overall visibility benefits from 

proposed emission limits. In the Proposal, EPA projects the visibility benefits from the proposed 

BART controls based on CALPUFF modeling. Based on CALPUFF, EPA’s proposed BART 

limits at White Bluff, Flint Creek Power Plant, Carl E. Bailey Generating Station, John L. 

McClellan Generating Station, Lake Catherine and Domtar Ashdown Power Boilers will result in 
452

projected combined visibility benefits of approximately 4.3 dv at Caney Creek.860 See first figure 

below. Based on a statistical projection of the haze index in Caney Creek (see Section III.C.1 of 

EAI’s comments), that would result in a haze index of 15.76 dv, which would put Caney Creek 

closer to natural background levels than the glide path. The URP would not reach that haze level 

until approximately 2048.861 Indeed, even if you ascribed the CALPUFF-projected benefits to 

Caney Creek based on the recent IMPROVE levels (approximately 22 dv between 2009 and 

2012), the projected haze index would drop to 17.7 dv, which indicates no further action should 

be needed to remain below the URP until approximately 2038. 

 

860 Trinity derived the 4.3 dv improvement from the CALPUFF modeling by determining the total extinction (in 

inverse megameters) from each proposed BART source, adding them together, and then calculating the deciview 

improvement. The resulting 4.3 dv improvement is over five times the total visibility impact attributed to all point 

sources in Arkansas based on CENRAP’s CAMx modeling and 14 times the impact attributed to point sources based 

on Entergy’s current CAMx modeling. 

861 The projected haze index at Upper Buffalo of 18.05 dv would keep Upper Buffalo below the glide path until 

approximately 2038 - the end of the third planning period. See second figure below. 
453

If EPA insists on relying on CALPUFF to evaluate the projected visibility benefits of requiring 

controls on Independence, it must be consistent and use CALPUFF to evaluate the need for such 

controls for purposes of demonstrating reasonable progress. As demonstrated in Figures 11 and 

12, controls at Independence cannot be justified for reasonable progress based on the CALPUFF 

results, which predict an improvement of several deciviews solely from BART controls. 

Response: As more fully explained above, the commenter’s analysis fails to account for the fact 

that deciviews are a logarithmic function of extinction, that CALPUFF results are for the 

maximum impact (98th percentile impact from each source) in contrast to the CENRAP projected 

visibility conditions that are for the average visibility over the 20% worst days, and also fails to 

differentiate between deciview values calculated based on natural background conditions (as the 

CALPUFF results are) and the deciview values relative to a degraded or dirty background. 

First, the commenter incorrectly estimates that the impact from sulfate point source emissions in 

Arkansas is 0.81-0.86 dv. Because the deciview metric is a logarithmic function of extinction, 

the percent extinction cannot be directly applied to the total deciview impairment. On the 20% 

worst days in 2018, sulfate from Arkansas point sources is projected to contribute 3.58% of the 

total light extinction at Caney Creek and 3.20% at Upper Buffalo, and nitrate from Arkansas 

point sources is projected to contribute 0.29% of the total light extinction at Caney Creek and 

0.25% at Upper Buffalo. 3.58% of the total extinction in 2018 at Caney Creek is 3.073 Mm-1. 

Converting to deciviews, yields approximately 0.32 dv based on a “dirty” background 2018 

projected visibility conditions and 0.92 dv based on a natural background approach. 
454

Second, 0.92 dv represents the estimated deciview improvement from eliminating sulfate 

emissions at all point sources in Arkansas (based on typical or average emissions) on average 

across the 20% worst days, as defined by the 20% worst days of monitored visibility at Caney 

Creek. This CAMx derived value is not directly comparable to the CALPUFF modeled 1.952 dv 

improvement from controls on both units at Independence, due to differences in models, model 

inputs and metrics. CALPUFF modeling following the BART guidelines and recommended 

protocol, provides an estimate of the maximum (98th percentile) visibility benefit based on 24-hr 

maximum actual emissions modeled over a period of three years. The CAMx modeling results 

presented by the commenter represent the average visibility impacts over the 20% worst days (as 

defined by monitored data) based on modeling actual emissions levels. In addition, CALPUFF 

uses an estimated constant background ammonia level and does not account for the competition 

for ammonia due to emissions from other sources. A maximum value of 1.952 dv for visibility 

benefits of controlling Independence based on CALPUFF modeling is not inconsistent with an 

estimated 0.92 dv impact from all sulfate point source emissions averaged over the 20% worst 

days. In general, the maximum value could be several times larger than the average over the 

20% worst days (representing the average visibility over the 73 days, or 24 monitored days with 

the worst visibility). Furthermore, the maximum value as modeled by CALPUFF is based on 

maximum 24-hr emissions which may be much higher than the average emissions. As discussed 

in a separate response to comment above, CAMx modeling using source apportionment provided 

by the commenter (Entergy) modeled a facility-wide impact from Entergy Independence of 1.64 

dv on the maximum day within the subset of days that make up the 20% worst days. The 

maximum modeled impact across the full 365 days modeled could be much larger. Furthermore, 

this modeling is based on actual emissions and not maximum 24-hr emissions as modeled by 

CALPUFF. Therefore, the 1.952 dv visibility benefit estimated by CALPUFF is not 

“impossible” and is in fact in line with the visibility impacts estimated using the CAMx model as 

supplied by the commenter. 

Third, the commenter is incorrect in estimating a 4.3 dv improvement from all BART controls 

and using this value to adjust projected visibility conditions in 2018 on the 20% worst days in the 

above figures. The cumulative visibility impacts cited to by the commenter (e.g., 4.3 dv 

improvement at Caney Creek due to all BART controls) combines the maximum visibility 

improvements from each facility that would result from required NOx or SO2 controls without 

any consideration of the location of the source or if the impacts and benefits would occur on the 

same day. The commenter’s approach overstates the combined impact at a given Class I area and 

does not contemplate if sources are located near each other and would likely impact a Class I 

area at the same time. Contrary to the commenter’s description of the methodology used to 

estimate the total visibility benefits of BART controls,862 the commenter simply added the 

CALPUFF modeled deciview visibility benefits for each control. These benefits represent the 

maximum (98th percentile) visibility benefits at each source based on reductions to the maximum 

24-hr emissions modeled over a period of three years. The maximum benefits from controlling 

one source cannot be added to the maximum benefits of controlling another source as these 

 

862 Commenter states: “Trinity derived the 4.3 dv improvement from the CALPUFF modeling by determining the

total extinction (in inverse megameters) from each proposed BART source, adding them together, and then

calculating the deciview improvement. The resulting 4.3 dv improvement is over five times the total visibility

impact attributed to all point sources in Arkansas based on CENRAP’s CAMx modeling and 14 times the impact

attributed to point sources based on Entergy’s current CAMx modeling.”
455

benefits are not likely to occur on the same day since the sources are not collocated. In addition, 

the maximum benefits from NOx controls and SO2 controls at the same facility cannot be added 

as they may not occur on the same day. Furthermore, these values represent the benefit on an 

individual day and not the average visibility benefit on the 20% worst days so it is not 

appropriate to adjust the visibility conditions on the 20% worst days by this amount as the 

commenter does in the above figures. In some situations, the days that CALPUFF model 

maximum or 98th percentile value impacts of the facility occur may not coincide with any of the 

days that make up the days in the worst 20% days at the Class I area and the visibility benefits 

modeled by CALPUFF are not directly comparable to the visibility benefits that would be 

anticipated on the 20% worst days from those specific controls. Furthermore, as discussed 

elsewhere, because deciviews are a logarithmic function of extinction, they cannot be added as 

the commenter does here. The CALPUFF modeled visibility benefits represent the visibility 

benefits of controls based on a clean background approach, and not the amount of benefit that 

would occur from degraded conditions, which would be needed to estimate the improvement in 

overall visibility conditions in 2018. We estimated the amount of visibility benefit anticipated 

from all controls against 2018 visibility conditions in estimating the proposed RPGs for 2018. In 

this calculation we estimated the benefit from all required controls to be 0.21 dv at Caney Creek 

and 0.19 dv at Upper Buffalo. 

Comment: CALPUFF overstates the visibility improvement expected from EPA’s proposed 

controls on Independence. [Entergy Arkansas Inc. (0166) p.41-42] Entergy Arkansas Inc. 

stated that EPA’s CALPUFF modeling greatly overstates the visibility benefits that would result 

from installing controls at Independence (as discussed elsewhere in Entergy’s comments) and 

should be disregarded. Further, when EPA used the CENRAP model (an appropriate multisource model) to assess overall visibility impairment, EPA concluded that the cumulative benefit 

of installing all of the controls in the Proposed FIP – all BART controls plus controls at 

Independence – would result in visibility benefits at Caney Creek of only 0.21 dv and at Upper 

Buffalo of only 0.19 dv. 80 Fed. Reg. at 18,998, Table 67. Since Independence represents only 

approximately 36% of the SO2 point source emissions and 21% of the point source NOx 

emissions in Arkansas, see id. At 18,991, one can ascribe only a minor portion of this projected 

insignificant deciview improvement to controls on Independence (approximately 0.08 dv at 

Caney Creek and 0.07 dv at Upper Buffalo).863 Based on this, installation of controls on 

Independence will yield no discernible visibility improvements. 

Not only does this demonstrate the illogic of relying on CALPUFF for reasonable progress, it 

demonstrates that the realistic benefits resulting from installing controls at Independence will be 

inconsequential and will contribute virtually nothing to visibility improvement at either Class I 

area. According to EPA, one deciview reflects “perceptible changes” in visibility. See Proposed 

Regional Haze Rule, 62 Fed. Reg. 41,138, 41,145 (July 31, 1997) (“A one deciview change in 

haziness is a small but noticeable change in haziness under most circumstances when viewing 

scenes in mandatory Class I Federal areas.”). Thus, the measure of visibility improvement is 

based on noticeable changes. By EPA’s own standard, a total deciview improvement at Caney 

Creek of 0.21 dv from the installation of controls at all of the proposed FIP sources would not be 

perceptible to the human eye. Likewise, a total deciview improvement at Upper Buffalo of 0.19 

 

863 These values are the calculated improvement based on EPA’s “scaling methodology.” See 80 Fed. Reg. at

18,997.
456

dv would not be discernable. Independence’s contribution to the deciview improvements EPA 

projects based on the CENRAP modeling would be much less; nowhere close to the 1.95 dv and 

1.78 dv improvement that EPA is claiming based on CALPUFF.864 Requiring imperceptible 

visibility improvements is simply unreasonable. The CAA requires only “reasonable progress, 

not the most reasonable progress.” North Dakota v. EPA, 730 F.3d 750, 767 (8th Cir. 2013).

Response: We address comments concerning perceptibility of visibility improvements 

elsewhere in this document. There we explain that in our visibility improvement analysis, we 

have not considered perceptibility as a threshold criterion for considering improvements in 

visibility to be meaningful. 

As we discuss in depth elsewhere, visibility improvements from controls must be evaluated on a 

“clean” background basis to fully assess the benefits from controls. It is not appropriate to 

consider only the amount by which a potential measure or combination of measures would 

change the projected overall deciview index value as of the end of the implementation period, 

i.e., the degree by which the RPGs would differ with and without the control being included in 

the LTS, as the commenter does here. We also discuss elsewhere that the deciview scale is a 

logarithmic function of extinction and calculations to determine benefits or amount of 

contribution to visibility impairment must be based on extinction and then converted into 

deciviews. Nevertheless, the commenter’s estimated visibility benefits of 0.08 dv at Caney 

Creek and 0.07 dv at Upper Buffalo on average across the 20% worst days are approximately a 

reduction in extinction of 0.8 Mm-1 at Caney Creek and 0.7 Mm-1 at Upper Buffalo, which is 

0.37 dv and 0.32 dv based on a clean background approach for the 20% worst days. In our 

response to a separate comment above, we discuss that due to the differences in models, model 

inputs, and metrics, the estimated visibility benefits estimated from CAMx modeling cannot be 

directly compared to CALPUFF modeled visibility benefits. For one, CALPUFF modeling is 

used to estimate the maximum visibility benefit based on maximum emissions whereas the 

CAMx modeling estimates the average visibility benefit over the 20% worst days (as defined by 

the monitored data) using actual or typical emission levels. As we also discuss above in a 

separate response to comment, CAMx visibility modeling with source apportionment submitted 

by Entergy estimates a maximum visibility impact (limited to only the days comprising the 20% 

worst days) of over 1.5 dv from the Independence facility at both Caney Creek and Upper 

Buffalo. In some situations, the CALPUFF modeled maximum or 98th percentile impacts of the 

facility may not coincide with the days that make up the Worst 20% monitored days at the Class 

I area, therefore the maximum impact based on CAMx modeling could be even higher. 

 

864 Even if the CALPUFF results were accurate, it is highly unlikely that such improvements would be perceptible. 

Studies have demonstrated that not only is the deciview scale not uniform in perception over a wide range of 

visibility conditions, but a 1-deciview change in visibility is not even perceptible to the human eye. See Exhibit E, 

Just-Noticeable Differences in Atmospheric Haze, Ronald C. Henry, Department of Civil and Environmental 

Engineering, University of Southern California, Los Angeles, Air & Waste Manage. Assoc. (2002). Instead, 

according to the Study, deciview improvements likely would need to be in the range of 2 to 5 dv to be perceptible. 

Id. at 1242, Figure 2
457

With regard to the quote the commenter reproduced from the Eighth Circuit Court’s decision in 

North Dakota v. EPA865, several environmental groups challenged a portion of our final action 

on North Dakota’s regional haze SIP that ultimately approved North Dakota’s reasonable 

progress determination for NOx controls for the Coyote Station.866 The environmental groups 

objected to North Dakota’s decision to reject a control it had evaluated, after having applied the 

four reasonable progress factors, and subsequently approving another NOx control as reasonable 

progress. 

We interpret the Court’s statement as meaning broadly that just because a more stringent level of 

control could be technically feasible in a particular instance, it does not mean it necessarily must 

be required under reasonable progress. We see no conflict with this determination and our 

proposed Arkansas FIP and requiring controls that may not result in perceptible visibility 

improvements. In North Dakota’s case, we noted technical flaws in North Dakota’s analysis, 

and we noted that we could have reached a different conclusion had we conducted the analysis 

ourselves, but we ultimately determined these issues did not prevent us from accepting North 

Dakota’s reasonable progress determination. The Court did not find that our conclusions on the 

issue were arbitrary, stating in part that, “[e]ven if [the control in question] were perhaps the 

most reasonable technology available, the CAA requires only that a state establish reasonable 

progress, not the most reasonable progress. In contrast, and as explained in greater detail 

elsewhere, in our 2012 rulemaking,867 we made a finding that Arkansas did not complete a 

reasonable progress analysis and therefore did not properly demonstrate that additional controls 

were not reasonable under 40 CFR 51.308(d)(1)(i)(A). Thus we disapproved the RPGs Arkansas 

established for Caney Creek and Upper Buffalo. Our proposed rulemaking completed the 

reasonable progress analysis and established revised RPGs, since we have not received a revised 

SIP to correct the portions of the SIP submittal we disapproved. We determined that cost 

effective controls were in fact available that would have very significant visibility benefits. 

Comment: [UARG (0176) p. 16-18] UARG stated that certain elements of EPA’s assessment 

demonstrate that the Independence Power Plant’s emissions have, and will continue to have, very 

little effect on visibility in any Class I area. EPA’s reasonable progress analysis shows that “[o]n 

the 20% worst days in 2002, sulfate from Arkansas point sources contributed 2.20% of the total 

light extinction at Caney Creek and 1.99% at Upper Buffalo, and nitrate from Arkansas point 

sources contributed 0.27% of the total light extinction at Caney Creek and 0.14% at Upper 

Buffalo.” 80 Fed. Reg. at 18,989 (footnote omitted). According to EPA, these very small 

percentages reflect contributions from all “Arkansas point sources,” not for the Independence 

Power Plant alone, whose emissions of course contribute only a fraction of these small amounts. 

Response: We disagree with the commenter’s assertion that the contribution to visibility 

impairment from Independence is “insignificant” or “minimal”. As the commenter states, the 

CENRAP source apportionment data shows that sulfate from Arkansas point sources contributed 

2.20% of the total light extinction at Caney Creek and 1.99% at Upper Buffalo in 2002. The 

 

865 The commenter states that requiring imperceptible visibility improvements is simply unreasonable and refers to

the 8th circuit decision that the CAA requires only “reasonable progress, not the most reasonable progress.” North

Dakota v. EPA, 730 F.3d 750, 767 (8th Cir. 2013) 866 See EPA’s final rule at 77 FR 20,894‐945 (April 6, 2012) 867 64 FR 35732
458

CENRAP modeling also projects that Arkansas point sources will be responsible for 3.58% of 

the total light extinction at Caney Creek and 3.20% at Upper Buffalo in 2018. As we discuss in 

our proposal, based on 2011 NEI data the Entergy Independence Plant is the second largest 

source of both SO2 and NOx point source emissions in Arkansas, accounting for approximately 

36% of the SO2 point-source emissions and 21% of point-source NOX emissions in the State.868

Therefore, a significant portion of the total projected visibility impairment on the 20% worst 

days, on the order of 1% or more, can be expected to be attributable to SO2 emissions from a 

single facility, the Independence facility, based on the CERNAP modeling. We discuss in a 

separate response to comment that results of our CALPUFF modeling, as well as the results of 

additional CAMx modeling submitted by Entergy, confirm and support that the visibility 

impairment due to the Independence facility is significant and that emission reductions will 

result in meaningful visibility benefits towards natural visibility conditions. We address 

comments concerning the magnitude of the projected benefits from controls for the projected 

2018 visibility conditions, as well as the perceptibility of those benefits in a separate response to 

comment elsewhere in this document. 

7.f. Visibility Benefit of Entergy Arkansas Proposal 

Comment: Entergy’s proposed combination of controls and lower SO2 emission rates will ensure 

that the Class I areas achieve virtually the same reasonable progress as EPA’s Proposal but at a 

cost of over $2 billion less than the Proposal. 869 See Figures below, which compare the projected 

2018 haze index at each Arkansas Class I area based on a Ranked Statistical Analysis, to the 

deciview improvements projected for the following scenarios (1) Entergy’s proposed controls, 

based on the cessation of coal-fired operations at White Bluff (referred to as “WB”) and the 

installation of LNB/SOFA and lower SO2 emission rate at Independence (referred to as “ISES”); 

and (2) installation of EPA’s proposed FIP controls at all BART sources and Independence. 

Based on Entergy’s CAMx modeling, the difference in the haze index between the proposed FIP 

controls and Entergy’s proposal is 0.05 dv at Caney Creek and 0.07 dv at Upper Buffalo. 

 

 

868 80 FR 18991 869 Entergy Arkansas Inc. stated that it is proposing near‐term interim controls and the cessation of coal

combustion at White Bluff by 2028. Entergy is proposing to meet lower SO2 emission rates at White Bluff Units 1

and 2 and Independence Units 1 and 2 by 2018, and is willing to install LNB/SOFA at all four units and meet a 30‐

day rolling average NOX emission rate of 1,342.5 lb NOx/hr, within three years after the effective date of the final

FIP as part of its multi‐unit approach [Entergy’s comments with regard to the proposed NOX rate is included as a

separate comment in this RTC document].
459
460

Response: We discuss the “ranked statistical analysis” submitted by the commenter in the 

response to comments below in this section. We disagree with the commenter that the Entergy 

proposed control scenario achieves “virtually” the same visibility benefits as does the controls 

required in this FIP. The table below summarizes the estimated visibility benefits of the FIP and 

Entergy’s proposal from the commenter’s CAMx photochemical modeling. We note that both 

scenarios include benefits from all required BART controls at all subject-to-BART facilities with 

the exception of White Bluff. The modeled FIP scenario also includes SO2 and NOx controls at 

both Independence and White Bluff. The modeled Entergy proposal scenario includes the 

elimination of emissions from White Bluff, an approximate 15% reduction in SO2 emissions 

from Independence and roughly similar NOx reductions at Independence as required in the FIP. 

Entergy Arkansas CAMx model results average 20% worst days 

Modeled 

Scenario 

Caney Creek Upper Buffalo 

Change in 

Light extinction 

from 2018 baseline 

(Mm-1)870

Deltadv (clean 

background) 

Change in 

Light extinction 

from 2018 baseline 

(Mm-1)871

Deltadv (clean 

background) 

FIP 2.95 1.29 1.54 0.70 

Entergy 

Proposal 

2.66 1.17 0.97 0.45 

Difference 0.29 0.12 0.57 0.35 

 

Entergy’s proposal achieves less visibility benefit than the FIP controls at Arkansas’ Class I 

areas, most significantly at Upper Buffalo where the benefit from Entergy’s proposal is 

approximately only 63% of the benefit from the FIP (1.54 Mm-1 from the FIP compared to 0.97 

Mm-1 from Entergy’s Proposal). CAMx source apportionment modeling submitted by Entergy 

shows that Entergy Independence has significant visibility impacts at both Arkansas Class I 

areas. At Upper Buffalo, the Independence facility contributes more to visibility impairment 

than all the subject-to-BART sources addressed in this action combined. Additional reductions 

from the elimination of emissions from the White Bluff facility under Entergy’s proposal are 

much too small to compensate for the lack of significant SO2 reductions at Independence. 

Visibility impacts due to emissions from Independence at nearby Class I areas in Missouri (not 

shown in the table) are also larger than the combined impacts from all subject-to-BART sources. 

Furthermore, Entergy’s proposal does not achieve these benefits until 2028, seven years after the 

full benefits from the FIP would be realized. We discuss other aspects of Entergy’s proposal, 

including uncertainty in emissions at White Bluff after the cessation of coal-burning, and issues 

concerning the BART requirements for White Bluff in separate responses to comment elsewhere 

in this document. 

 

870See “Entergy CAMx Results 2015-1124_FINAL.xls” submitted with comments from Entergy Arkansas, Inc. and 

available in the docket for this action 

871See “Entergy CAMx Results 2015-1124_FINAL.xls” submitted with comments from Entergy Arkansas, Inc. and 

available in the docket for this action. 
461

We also disagree with the commenter’s use of the results of their ranked statistical analysis (the 

“projected haze index” shown in the figures above, Entergy Arkansas Inc.’s submitted comments 

in figures 13 and 14) as the starting point for calculating the overall visibility benefits from the 

FIP or the commenter’s proposed alternative. As discussed elsewhere, the ranked statistical 

analysis is simply a projection of future visibility conditions based on past improvement and is 

not directly tied to any additional required emission reductions in the next few years that would 

result in this future visibility improvement from current conditions to this projected value in 

2018. 

7.g. Observed Visibility Improvements 

Comment: Trinity Consultants Inc. (Trinity) was tasked by Entergy Arkansas with conducting a 

statistical analysis of observed visibility data gathered through the Interagency Monitoring of 

Protected Visual Environment (IMPROVE) program to statistically determine the future trends 

in the regional haze index values. Trinity conducted a simple Trend Statistical Analysis and more 

robust Ranked Statistical Analysis to determine the projected haze index in 2018. 

For Caney Creek and Upper Buffalo, respectively, the observed values are well below the glide 

path with a consistent downward trend in the observations (see URP and projected visibility 

figures below). This downward trend is consistent with the historical (2002 – 2011) trend in 

decreasing sulfur dioxide (SO2) emissions from tier 1 sources located in the states contributing 

significantly to the Caney Creek and Upper Buffalo Class I Areas. Figure 2‐3 of the submitted 

comments presents the National Emissions Inventory (NEI) SO2 emissions from 2002, 2005, 

2008, and 2011. Pursuant to the NEI emissions data, the SO2 emissions have significantly 

decreased since 2005 to 2011 in all source categories, including especially a more than 50% drop 

due to fuel combustion from electric utilities and a 67% drop in the fuel combustion from 

industrial sources. Based on the significant downward trend in the observed data and the actual 

SO2 emissions data, the future haze index value in 2018 is expected to be lower than the 

currently predicted glide path. The lower haze index value in 2018 will be additionally supported 

by the anticipated implementation of regulations further curbing emissions. 
462

Based on the above, when looking at the observed values, the CENRAP model predicted 

regional haze value for 2018 is overly conservative and over predicting the future haze index. 

Although the predicted 2018 haze index values are good conservative estimates for attainment 

demonstrations, the values are misleading when assessing the effect of proposed controls on 

single sources. Additionally, the CENRAP CAMx model predicted haze index does not account 

for the observed values and the trend predicted if an assessment occurred evaluating the observed 

values. Therefore, instead of using the CENRAP CAMx predicted 2018 haze index to understand 

the effect of the control options, a statistically derived projected haze index must be used. 

In order to statistically calculate the future deciview haze index values using observed data 

instead of relying on the CENRAP modeling, two statistical analyses were performed and 

evaluated to determine the most appropriate analysis for predicting the haze index values based 

on observed data: Trend Analysis, and Ranked Statistical Analysis. 872 The results of the ranked 

statistical analysis are summarized in the following figures and display the predicted 2018 values 

in relation to the URP curves for each Class I Area and the estimated proposed FIP haze index 

and the haze index based on Entergy’s proposed controls based on CAMx modeling performed 

by Trinity for Entergy Arkansas. The 2018 average of the 20% worst days for visibility was 

 

872 Trinity’s report identifying why a statistical analysis was performed on the IMPROVE data and why the Ranked 

Statistical Analysis was selected is included as Exhibit D to these comments and incorporated by reference herein. 

IMPROVE Data Statistical Analysis, Trinity Consultants (July 2015) (“Trinity Report”).
463

calculated to be 20.07 dv for Caney Creek and 20.91 dv for Upper Buffalo. 873 These numbers 

are far below the URP for the first planning period and demonstrate that no source in Arkansas, 

including Independence, needs to install controls for Arkansas to remain below the glide path. 

 

873 Trinity also performed a Trend Statistical Analysis of the data, which projects even lower visibility impairment 

of 18.02 dv at Caney Creek and 20.44 dv at Upper Buffalo, Trinity Report at Section 3.1, but Entergy stated it is 

using the more robust and conservative Ranked Statistical Analysis to demonstrate the expected trend in visibility 

impairment. 
464

Response: As we discuss elsewhere in this document and in section V.C of the final rule, being 

projected to be on or below the URP glidepath in 2018 (or even beyond) does not automatically 

mean that no controls or evaluation under reasonable progress is needed in this planning period. 

The commenter presents SO2 emissions data from 2002, 2005, 2008, and 2011 for states 

identified by the commenter as impacting visibility at the Arkansas Class I areas. This data 

shows significant emissions reductions over this time period and is consistent with observed 

visibility improvement at the Arkansas Class I areas. However, most of the visibility 

improvement currently observed in Arkansas appears to be due to emissions reductions that have 

taken place outside the state. Arkansas emissions do not exhibit the same downward trend as 

presented for the other states that impact visibility at the Arkansas Class I areas. The figure 

below shows Arkansas SO2 emissions from all source categories for 2004-2014.874 More recent 

annual emissions from 2012-2014 are actually higher than emissions from the 2008-2011 period 

and there is no downward trend in emissions from those point sources with the largest visibility 

impacts, those from fuel combustion at electric utilities. To the extent that the commenters are 

suggesting that Arkansas should be relieved of its regional haze obligations because other states’ 

emission reduction efforts have already resulted in significant visibility improvement at 

Arkansas’ Class I areas, this is incorrect. Rather Arkansas, and EPA in standing is Arkansas’s 

 

874 Data available from EPA air pollutant emission trend data: https://www.epa.gov/air-emissions-inventories/airpollutant-emissions-trends-data
465

shoes, must consider the statutory factors in addressing the long term strategy and reasonable 

progress requirements. 

The commenter asserts that the CENRAP CAMx predicted 2018 haze index is overly 

conservative and that to understand the effect of the control options, a statistically derived 

projected haze index must be used. We disagree with the commenter. The comments indicate a 

lack of understanding of how reasonable progress goals are established, as well as the imports of 

the goals as opposed to the measures adopted to ensure reasonable progress. As we state in the 

Regional Haze Rule, the reasonable progress goal(s) set by the state, or EPA when promulgating 

a FIP, are not enforceable. The reasonable progress goals are an analytical tool used by EPA and 

the states to estimate future visibility conditions and track progress towards the goal of natural 

visibility conditions. Accordingly, the RPGs must represent an estimate of the degree of 

visibility improvement that will result in a future year from changes in emissions inventories, 

changes driven by the particular set of control measures adopted in the regional haze SIP or FIP 

to address visibility, as well as all other enforceable measures expected to reduce emissions.875

Given the forward-looking nature of reasonable progress goals and the range of assumptions that 

must be made as to emissions in the future, we expect there to be some uncertainty in the 

estimates of future visibility. 

The statistical analyses provided by the commenter are simply extrapolations of future visibility 

conditions based on observed reductions in visibility impairment in the past. Future visibility 

projections must be directly tied to projections of future emissions, and anticipated reductions 

 

875 64 FR 35733
466

due to federal and state requirements. Current 5-yr average (2010-2014) observed visibility 

conditions are 21.8 dv at Caney Creek and 21.6 dv at Upper Buffalo.876 Any future 

improvements in overall visibility conditions at the Arkansas Class I areas between now and 

2018 will be due to future emission reductions during that time period. Commenters have not 

provided any specific information suggesting anticipated enforceable emission reductions from 

those Arkansas point sources with significant visibility impacts or other sources that would result 

in the almost 2 dv visibility improvement by 2018 projected by the commenter at Caney Creek in 

their statistical analysis. Furthermore, as discussed above, any anticipated emission reductions 

from sources in other states does not relieve Arkansas of its regional haze obligations. The 

BART requirements under section 51.308(e) must be met for those specific sources that meet the 

BART criteria and contribute to visibility impairment. The determination of whether an RPG 

and the emission limitations and other control measures upon which it is based constitute 

reasonable progress is made by conducting certain analyses and meeting the requirements under 

section 51.308(d)(1). 

As discussed in depth elsewhere in a separate response to comment, it is necessary to assess the 

visibility benefit of individual controls compared to natural or “clean” background conditions. 

It is not appropriate to consider only the amount by which a potential measure or combination of 

measures would change the projected overall deciview index value as of the end of the 

implementation period, i.e., the degree by which the RPGs would differ with and without the 

control being included in the LTS, as the commenter does here. The RPGs are an analytical tool 

the state and we use to evaluate whether the measures in the implementation plan are sufficient 

to achieve reasonable progress.877 Instead, what is enforceable under the RH rule are the 

emission limitations and other control measures that apply to specific sources, and upon which 

the RPGs are based. Since the emission limitations we are requiring in our FIP for specific 

Arkansas sources (which is what our revised RPGs are based upon) are not currently being 

achieved, we disagree that visibility at the Class I areas has already improved beyond what we 

would require in our FIP and that our FIP is therefore unjustified and unwarranted. The emission 

reductions required in this action will result in significant visibility improvements at the Class I 

areas beyond what is currently being achieved or observed. As discussed elsewhere, the 

commenter’s photochemical modeling analysis provides an additional demonstration that the 

controls required in this action result in visibility benefits beyond current observed visibility 

conditions and serve to accelerate progress towards natural visibility conditions. 

7.h. Reasonable Progress Goals 

Comment: [ADEQ (0160) p. 15-16] EPA’s proposed RPGs are more stringent than Arkansas’s 

proposed RPGs in its 2008 Regional Haze State Implementation Plan, which would have ensured 

that Arkansas is on track to achieve natural visibility conditions by 2064. Arkansas is reducing 

regional haze in its Class I areas at a higher rate than both the URP, which was approved by 

EPA, and Arkansas’s initial proposed RPGs.878 EPA’s RPGs in the Proposed FIP are only about 

 

876 IMPROVE monitoring data obtained from: http://vista.cira.colostate.edu/TSS/Results/HazePlanning.aspx 877 See 51.308(d)(1)(v). 878 See Exhibit 1 to ADEQ’s comments.
467

0.2 deciviews lower than those developed by Arkansas.879 Even if EPA’s RPGs were the result 

of proper analysis and modeling, the difference between the State-established and EPA-proposed 

RPGs is insignificant and below the range of human perceptibility. As indicated by the URP, 

Arkansas is well on track to reaching natural visibility conditions by 2064 and more stringent 

RPGs than those in Arkansas’s 2008 Regional Haze State Implementation Plan are not 

necessary. EPA should withdraw the Proposed FIP and ensure that revised RPGs in any 

subsequent plan are within the scope of EPA’s authority to address impairment of visibility. 

Comment: [UARG (0176) p. 16-18] The differences in projected 2018 visibility conditions at 

Caney Creek and Upper Buffalo that are attributable to all of the proposed FIP controls – 

including both FIP BART and FIP reasonable progress requirements – will be imperceptibly 

small (i.e., improvements of, at most, 0.21 dv and 0.19 dv, respectively, at Caney Creek and 

Upper Buffalo). Id. at 18,997-98 & Table 67. Yet the minimal visibility improvements that 

EPA’s proposed reasonable progress emission control requirements would produce would come 

at exorbitant cost – nearly $64 million per year for SO2 controls and almost $2.5 million 

annually for NOx controls, according to EPA. See id. at 18,993 Table 60, 18,996 Table 65. 

Response: As we discuss in more detail elsewhere in response to comments, we agree that 

Arkansas proposed RPGs in its 2008 regional haze SIP that fell below the URP. However, in our 

2012 rulemaking,880 we made a finding that Arkansas did not complete a reasonable progress 

analysis and therefore did not properly demonstrate that additional controls were not reasonable 

under 40 CFR 51.308(d)(1)(i)(A). Thus we disapproved the RPGs Arkansas established for 

Caney Creek and Upper Buffalo. In our proposed rulemaking, we completed the reasonable 

progress analysis and established revised RPGs, since we have not received a revised SIP to 

correct the portions of the SIP submittal we disapproved. As discussed in our proposal and 

elsewhere in this response to comments document, we focused our reasonable progress analysis 

on the Entergy Independence facility because of its significant emissions of NOx and SO2 and its 

large potential to impact visibility at nearby Class I areas. We determined that cost-effective 

controls were available for units at this facility and that they would result in significant visibility 

benefits. We respond to specific comments concerning the visibility benefits from controls on 

the Independence facility in separate responses to comments. We also completed five-factor 

BART analyses and determinations for subject-to-BART facilities where we had previously 

disapproved the BART determination in the 2008 Arkansas regional haze SIP. Our proposed 

RPGs reflected the visibility benefits anticipated from the implementation of controls across the 

subject-to-BART facilities and the Independence facility required in this action. As we discuss 

in our proposal and in response to comments, we have determined that these controls are costeffective and result in significant visibility benefits that provide for progress towards the goal of 

natural visibility conditions. As we discuss below in a separate response to comment, after 

considering comments received, we agree that the RPGs should reflect anticipated visibility 

conditions at the end of the implementation period in 2018 rather than the anticipated visibility 

conditions once the FIP has been fully implemented. We are finalizing RPGs that represent the 

visibility conditions anticipated on the 20% worst days at Caney Creek and Upper Buffalo by 

2018. 

 

879 77 FR 14604 at 18998, Table 67. 880 64 FR 35732
468

We disagree with the commenter that the amount of visibility improvement due to our proposed 

FIP is “insignificant.” We address comments concerning the perceptibility of visibility 

improvements in response to comments above. The required controls are estimated to improve 

overall visibility benefits compared to the CENRAP projected visibility conditions for 2018 by 

approximately 0.2 deciviews, a reduction in light extinction of about 2 Mm-1 at Caney Creek 

and 1.8 Mm-1 at Upper Buffalo. Once fully implemented, the required controls to meet the 

BART requirements, as well as required controls on the Independence facility result in an 

approximate 2% improvement in overall visibility conditions projected by CENRAP at both 

Caney Creek and Upper Buffalo on the 20% worst days. Our technical record demonstrates that 

the required controls reduce impacts from these sources and result in meaningful visibility 

benefits towards the goal of natural visibility conditions. The required controls reduce the 

projected visibility impairment due to all Arkansas point sources by 50% at Caney Creek and 

50% at Upper Buffalo. We note that the required controls actually result in larger visibility 

improvements than calculated here because the CENRAP projections already included an 

assumption of large emission reductions due to SO2 BART at Flint Creek, as well as NOX

controls at White Bluff and Flint Creek.881

Comment: The RPGs chosen by EPA are based on admittedly flawed methods that reject 

the refined modeling approach used by EPA in other states. [ADEQ (0160) p. 13-15] ADEQ 

stated that not only did EPA improperly perform the reasonable progress analysis necessary to 

establish RPGs, but EPA also used an admittedly inferior method to model Arkansas’s RPGs. In 

supporting the RPGs in the Proposed FIP, EPA substituted a method that relies on “a scaling of 

visibility extinction components in proportion to emission changes.”882 In support of this method, 

EPA cites to its use in developing RPGs for Hawaii and Arizona.883 EPA offers little in the way 

of positive support for its choice in the Proposed FIP. Rather, EPA chose a method of 

determining RPGs that is admittedly inferior and less sophisticated than the alternative approach, 

which EPA rejected in Arkansas but used in Texas: CAMx photochemical modeling. 

EPA admits that it has not performed its own modeling in a manner adequate to develop “refined 

numerical RPGs.”884 EPA seems to acknowledge the infirmity in its modeling by explaining its 

methodology as follows: “Development of refined numerical RPGs for Arkansas’s Class I areas 

would require photochemical grid modeling of a multistate area, involving thousands of emission 

sources, unlike the comparatively simple single-source CALPUFF modeling used for individual 

BART assessments.”885 EPA further explains that “[d]eveloping all of the necessary input files, 

running the photochemical model, and post-processing the model outputs would take several 

months at a minimum.”886 EPA cites additional reasons for rejecting the approach using 

photochemical grid modeling such as the part that it is requiring an “update of the emission 

inventory for Arkansas and surrounding states,” which would include the effects of all EPA and 

 

881 2002 CENRAP modeled SO2 emissions for Flint Creek were 11,165 tpy and 2018 CENRAP modeled SO2 emissions

were 2,896 tpy, an assumed 75% reduction in emissions. 882 80 FR 18944 at 18997. 883 Id. 884 Id. 885 Id. 886 Id.
469

state regulatory actions on point, area, and mobile sources.887 EPA states this approach would 

require “specialized and extensive computing hardware and expertise.”888 

Despite the additional complexity and time needed, EPA chose to use the more refined CAMx 

photochemical model in the Texas-Oklahoma FIP.889 As evidenced by EPA’s actions in the 

Texas-Oklahoma FIP, EPA certainly possesses the “specialized and extensive computing 

hardware and expertise” needed to perform modeling using the CAMx photochemical model. 

EPA fails to justify this disparate treatment in Arkansas’s Proposed FIP. Instead, EPA arbitrarily 

used an alternative algorithm to develop RPGs that resulted in admittedly inferior numerical 

goals. 

In fact, the only modelling EPA performed for the Proposed FIP was “comparatively simple 

single-source CALPUFF modeling used for individual BART assessments.”890 EPA used this 

modeling only to justify additional emissions controls on Entergy’s Independence Plant outlined 

in the reasonable progress analysis and not in support of the proposed state-wide RPGs. 

Given the substantial impact on Arkansas businesses and rate-payers that the potential 

differences in RPGs would make, ADEQ is troubled by EPA’s decision to forego methods that 

would ensure the same degree of accuracy for RPGs in Arkansas’s Proposed FIP as in the TexasOklahoma FIP. EPA should withdraw the Proposed FIP, and any subsequent plan should include 

a method of analysis sufficient to establish “refined numerical RPGs.” 

Response: We discuss our selection of the CALPUFF model for evaluating single-source 

visibility impacts in a separate response to comment above. In the response, we also explain the 

model selection for our Texas action and refer the reader to our detailed explanation in the RTC 

that accompanies that action.891 Commenters are incorrect in their comparison of approaches for 

establishing new RPGs between this action for Arkansas and our previous action in Texas. For 

both Texas and Arkansas, we utilized the CENRAP 2018 CAMx modeling that estimated the 

2018 RPGs and then adjusted those RPGs to account for estimated visibility improvement due to 

required controls. In neither case did we perform a full photochemical modeling analysis to 

model all the required controls and project the future visibility conditions. In both cases, the 

2018 RPGs were adjusted based on a scaling of the source apportionment model results and 

emission inventory changes. 

 

887 80 FR 18944 at 18997. 888 Id. 889 Approval and Promulgation of Implementation Plans; Texas and Oklahoma; Regional Haze State

Implementation

Plans; Interstate Transport State Implementation Plan To Address Pollution Affecting Visibility and Regional Haze;

Federal Implementation Plan for Regional Haze and Interstate Transport of Pollution Affecting Visibility, 79 FR

74818.

890 80 FR 18944 at 18997. 891 See “Response to Comments for the Federal Register Notice for the Texas and Oklahoma Regional Haze State

Implementation Plans; Interstate Visibility Transport State Implementation Plan to Address Pollution Affecting

Visibility and Regional Haze; and Federal Implementation Plan for Regional Haze,” December 9, 2015. Available at

www.regulations.gov, Document ID: EPA‐R06‐OAR‐2014‐0754‐0087
470

The primary difference between the two actions was that in evaluating the visibility impacts and 

benefits of potential controls at individual sources we relied on CAMx modeling for Texas 

sources and CALPUFF modeling for Arkansas sources. Among the key differences that resulted 

in the selection of different models was the number of sources that needed to be analyzed (38 

facilities in Texas compared to 1 facility in Arkansas) and the distances from the sources to the 

impacted Class I areas (distances in many cases ranging from 300 to 1000 km or more for Texas 

sources compared to four impacted Class I areas less than 300km from the source in Arkansas). 

Furthermore, as we noted in our proposal892, “RPGs, unlike the emission limits that apply to 

specific RP sources, are not directly enforceable. Rather, they are an analytical framework 

considered by us in evaluating whether measures in the implementation plan are sufficient to 

achieve reasonable progress. Arkansas may choose to use these RPGs for purposes of its 

progress report, or may develop new RPGs for approval by us along with its progress report, 

based on new modeling or other appropriate techniques, in accordance with the requirements of 

40 CFR 51.308(d)(1).” 

Comment: [Entergy Arkansas Inc. (0166) p.41-42] Entergy Arkansas Inc. stated 

The demonstration methodology used by EPA is unscientific. EPA used a ratio of emission rates 

from BART sources to Arkansas point sources to scale the modeled predicted haze index. First, 

there is no evidence to prove that the CAMx predicted modeling results are linearly correlated 

with emission rates. In fact, the CAMx modeling fundamentally is based on photochemical 

reactions. Therefore, the relationship between variation in the emission rates and predicted 

concentration is complicated. See Chemical Characteristics of Inorganic Ammonium Salts in 

PM2.5 in the Atmosphere of Beijing (China), A. Ianniello, F. Spataro, G. Esposito, I. Allegrini, M. 

Hu, and T. Zhu, 11 Atmos. Chem. Phys., at 10804 (2011).893 For example, due to a high 

chemical affinity, an ammonia molecule reacts with SO2 molecules to form sulfate before 

reacting with NOX molecules to form nitrate. If abundant SO2 is present in the atmosphere, any 

increase in NOX emissions will not result in a linear increase in nitrate formation. As a result, 

there may not be any increase in the predicted regional haze. On the contrary, if abundant NOX

molecules are present, then any reduction in SO2 molecules will not result in a significant 

reduction in haze as NOX will substitute the reduced SO2 in the reaction. Second, a deciview is a 

logarithmic scale based on the concept that one deciview is the minimum change in the visibility 

perceptible to a human observer. See 40 C.F.R. § 51.301 (definition of “deciview”). As such, 

deciviews cannot be added or subtracted directly. Therefore, fractioning or scaling deciviews 

based on emission rates is illogical. 

Comment: [EarthJustice/ Dr. Gray] In Texas, the model results were used to demonstrate that 

the overall change in species concentrations was very nearly linearly proportional to the change 

in emission levels for an individual source (with very high linear correlation coefficients near 

1.0). This strongly supports their use of the emission scaling approach for Arkansas. If the 

CAMx model were used to determine the impact of emission controls on a single source in 

Arkansas (such as 

Independence), it is therefore expected that the modeled reductions in sulfate and nitrate 

concentrations at each of the Class I areas will be very nearly proportional to the SO2 and NOX 

 

892 80 FR 18997‐18998 893 Available at http://www.atmos‐chem‐phys.net/11/10803/2011/acp‐11‐10803‐2011.pdf.
471

concentration reductions. In other words, the emission scaling approach has been shown to be 

mathematically sound and quite appropriate, especially considering the resources that would be 

required to exercise CAMx separately for each control measure at each evaluated source. 

Response: We disagree with the comments that the methodology used to estimate overall 

visibility benefits from all required controls control level emissions was unreasonable or 

unscientific. We agree with comments that the approach we followed is reasonable and based on 

a scaling of visibility extinction components due to Arkansas point sources in proportion to 

emission changes from the required controls at Arkansas point sources. The commenter is 

incorrect in suggesting that we developed a linear relationship between emissions and deciviews 

and then commenting that this “fractioning or scaling of deciviews” is flawed because the 

relationship between light extinction and deciviews is exponential. We properly developed a 

linear relationship between emissions and light extinction (inverse Megameters), not deciviews. 

We agree with the commenters, that in general, the relationship between downwind 

concentrations and emissions can be complicated and non-linear due to complex chemistry, 

including the fact that reductions in sulfur emissions can result in an increase in ammonium 

nitrate. For estimating the total visibility benefit from all controls and estimating a new 

reasonable progress goal that reflects those controls, we relied on the CENRAP’s 2018 CAMx 

modeling results, including source apportionment results, and the projected emission inventories, 

and scaled the results as described in the TSD, similar to what was done in our previous action in 

Arizona and Texas. While we acknowledge that this approach is not as refined an estimate as 

would be attained in performing a new photochemical modeling run, it is based on scaling to 

adjust earlier photochemical modeling results that took into account the complex chemistry that 

impacts the overall visibility. The uncertainty in the visibility benefit from these controls 

introduced by the linear extrapolation does not impact the overall conclusions. Furthermore, in 

our technical analysis developed to support our action on Texas regional haze, we observed that 

for each facility and Class I area, the available modeled visibility impact was linear with respect 

to emissions with high correlation.894 Following this approach we estimated that when fully 

implemented, the required controls would result in a reduction in light extinction of about 2 Mm1

 at Caney Creek and 1.8 Mm-1 at Upper Buffalo on the 20% worst days. As discussed 

elsewhere, Entergy Arkansas submitted additional CAMx modeling with their comments. This 

photochemical modeling projects a 2.95 Mm-1 reduction at Caney Creek and 1.54 Mm-1

reduction at Upper Buffalo when compared to the Entergy’s base case modeling for 2018 for the 

20% worst days.895 

Comment: [UARG (0176) p. 16-18] Even the negligible changes in visibility represented by 

EPA’s proposed revised RPGs are greatly overstated: Even though, as EPA observes, “some FIP 

controls will not be in place by 2018,” id. at 18,997 – an observation that is indisputably correct 

with respect to the FIP’s SO2 control requirements that have compliance deadlines that are five 

years after the final EPA rule’s effective date – EPA counterfactually calculates its proposed 

2018 RPGs assuming that all of the proposed FIP’s BART and reasonable progress emission 

 

894 See 81 FR 335 and the FIP TSD that accompanies that action (Available at www.regulations.gov, document ID:

EPA‐R06‐OAR‐2014‐0754‐0007) 895 See Entergy CAMx Results  2015‐1124_FINAL.xls
472

limits are in place by 2018, see id. (stating that although “[w]e note that some [of the proposed] 

FIP controls will not be in place by 2018, ... for the purpose of this calculation, we included 

reductions from all FIP controls”). Because the bulk of the EPA-projected visibility 

improvements are due to proposed SO2 emission limits for BART and reasonable progress that 

have a five-year compliance deadline and thus will not become operative until at least 2020, no 

sound basis exists for the projections of visibility improvements by 2018 that EPA sets out in the 

proposed rule. Those EPA projections are not merely, as EPA concedes, “not refined,” id.; they 

are flatly inaccurate and unsupportable. 

In this regard, EPA fails to explain why (a) the Agency may permissibly use a concededly 

oversimplified and inaccurate shortcut methodology for calculating RPGs in its FIP, on the 

grounds that EPA otherwise would have to conduct time-consuming and complicated modeling, 

see id., but (b) Arkansas and other states apparently are held to a much higher standard for their 

RPG analyses, see id. In proposing and promulgating a FIP for Arkansas, EPA merely stands in 

the state’s shoes. Accordingly, if EPA may lawfully comply with the CAA and the regional haze 

rules by conducting and relying on this sort of analysis that is “not refined” but (purportedly) 

sufficient to support its FIP’s RPGs, then states also may do so to support their SIPs’ RPGs. On 

the other hand, to the extent EPA does not believe that RPGs based on such an abbreviated 

analysis would be approvable if submitted by a state in a SIP, EPA cannot lawfully promulgate 

the RPGs that it proposes based on the analysis presented in its proposed rule. 

Response: We proposed RPGs for the 20% worst days for Caney Creek and Upper Buffalo of 

22.27 dv and 22.33 dv, respectively that reflected the anticipated visibility conditions resulting 

from the combination of control measures from the approved portion of the 2008 Arkansas 

Regional Haze SIP and our FIP proposal. After considering these comments, we agree that the 

RPGs should reflect anticipated visibility conditions at the end of the implementation period in 

2018 rather than the anticipated visibility conditions once the FIP has been fully implemented. 

This approach is consistent with the purpose of RPGs and the direction provided in our 2007 

Reasonable Progress Guidance.

Section 169B(e)(1) of the CAA directed the Administrator to promulgate regulations that 

“include[e] criteria for measuring ‘reasonable progress’ toward the national goal.” Consequently, 

we promulgated 40 CFR 51.308(d)(1) as part of the Regional Haze Rule. This provision directs 

states to develop RPGs for the most and least impaired days to “measure” the progress that will 

be achieved by the control measures in the state’s long-term strategy “over the period of the 

implementation plan.”896 The current implementation period ends in 2018. RPGs “are not 

directly enforceable” like the emission limitations in the long-term strategy.897 Rather, they fulfill 

two key purposes: (1) allowing for comparisons between the progress that will be achieved by 

the state’s long-term strategy and the URP,898 and (2) providing a benchmark for assessing the 

adequacy of a state’s SIP in 5-year periodic reports.899 Consequently, in our 2007 Reasonable 

Progress Guidance, we indicated that states could consider the “time necessary for compliance” 

factor by “adjust[ing] the RPG to reflect the degree of improvement in visibility achievable 

 

896 40 CFR 51.308(d)(1). 897 40 CFR 51.308(d)(1)(iv). 898 40 CFR 51.308(d)(1)(ii). 899 40 CFR 51.308(g)‐(h).
473

within the period of the first SIP if the time needed for full implementation of a control measure 

(or measures) will extend beyond 2018.”900 In other words, RPGs need not reflect the visibility 

improvement anticipated from all of the control measures deemed necessary to make reasonable 

progress (as a result of the four-factor analysis) and included in the long-term strategy. 

In this instance, we are taking final action on the Arkansas Regional Haze FIP 9 years after the 

state’s initial SIP submission was due.901 As a result, only some of the control measures that we 

have determined are necessary to satisfy the BART and reasonable progress requirements will be 

installed by the end of 2018. Some controls will not be installed until 2021. Because RPGs are 

only unenforceable analytical benchmarks, we think that it is appropriate to follow the 

recommendation in our 2007 Reasonable Progress Guidance and finalize RPGs that represent the 

visibility conditions anticipated on the 20% worst days at Caney Creek and Upper Buffalo by 

2018. These RPGs are listed in the table below:902

Reasonable Progress Goals for 2018 for Caney Creek and Upper Buffalo 

Class I area 2018 RPG 

20% Worst days (dv) 

Caney Creek 22.47 

Upper Buffalo 22.51 

We note that the RPGs we are finalizing are very similar to the ones that we disapproved in the 

Arkansas Regional Haze SIP. 903 The reason for this is that Arkansas’ RPGs were calculated 

using the 2018 CENRAP CAMx modeling completed in 2006/2007, which assumed that Flint 

Creek would install scrubbers to meet the presumptive SO2 BART limit of 0.15 lb/MMBtu, that 

Flint Creek and White Bluff would install low NOX burners to satisfy NOX BART, and that 

AECC Bailey and Entergy Lake Catherine would be shut down by 2018. In contrast, our RPGs 

reflect a more stringent SO2 emission limit of 0.06 lb/MMBtu at Flint Creek and the installation 

of low NOX burners at Independence in addition to Flint Creek and White Bluff, but also the 

continued operation of AECC Bailey and Entergy Lake Catherine. In other words, our RPGs 

reflect additional emission reductions from Flint Creek and Independence, but more emissions 

from AECC Bailey and Entergy Lake Catherine. 

The fact that the RPGs we have calculated are very close to those originally submitted by 

Arkansas does not undermine the reasonableness of our action. We disapproved Arkansas’ RPGs 

because Arkansas failed to conduct a four-factor analysis, as required by the CAA and the 

Regional Haze Rule. Without a four-factor analysis, Arkansas was unable to determine whether 

control measures were necessary to make reasonable progress—the core requirement of the 

CAA’s visibility program.904 After conducting a full four-factor analysis, we have determined 

 

900 2007 Reasonable Progress Guidance at 5‐2. 901 We discuss in section II.A of the final rule the history of the state’s submittals and our actions. 902 These RPGs are calculated using the same methodology described in our proposal and TSD.   

See “CACR UPBU RPG analysis 2018.xlsx” for additional information on the calculation of the RPGs. 903 77 FR 14604. 904 CAA section 169A(b)(1) and (g)(1).
474

that controls at the Independence plant are cost-effective and reasonable and therefore necessary 

to make reasonable progress. The visibility benefits of the SO2 controls at Independence, along 

with benefits of the SO2 BART controls at White Bluff, and additional BART controls at AECC 

Bailey, AECC McClellan, Entergy Lake Catherine, and the Domtar Ashdown Mill will be fully 

realized in 2021, and we expect Arkansas to properly take these benefits into account when 

developing RPGs for 2028.905

We disagree with the commenter that the proposed RPGs overstated the visibility benefit of 

controls or that they are inaccurate. In our proposal, we acknowledged that the methodology we 

utilized to estimate the RPGs is not as refined as developing an updated model projection. 

However, it allows us to translate the emission reductions contained in the proposed FIP into 

quantitative RPGs, based on modeling previously performed by the CENRAP.906 The proposed 

RPGs provided an estimate of the visibility benefit of all the required controls compared to the 

2018 visibility conditions projected by the state and established in their SIP that would result 

without the required controls. Our final RPGs, calculated using the same methodology, reflect 

the anticipated visibility conditions at the end of the implementation period in 2018 and the 

visibility benefit from those controls required to be implemented by the end of 2018. RPGs, 

unlike the emission limits that apply to specific reasonable progress and BART sources, are not 

directly enforceable.907 Rather, the RPGs are an analytical framework considered by us in 

evaluating whether measures in the implementation plan are sufficient to achieve reasonable 

progress.908 Our FIP imposes emissions limitations that we conclude to be necessary under the 

CAA for the first planning period. Ideally, these controls would be installed and the emission 

limitations achieved, so the visibility improvements can be realized and built on in a subsequent 

comprehensive periodic SIP revision (see 40 C.F.R. 51.308(f)). Arkansas may choose to use 

these RPGs for purposes of its progress report (along with a consideration for what controls had 

already been implemented and what controls would be implemented in the near future), or may 

develop new RPGs for approval by us along with its progress report, based on new modeling or 

other appropriate techniques, in accordance with the requirements of 40 CFR 51.308(d)(1) in 

evaluating the adequacy of their SIP (or this FIP) to meet the established RPGs. 

We disagree that Arkansas would be held to a higher standard or that the methodology utilized 

by EPA to adjust the RPGs would not be approvable if submitted by a state. The approach 

followed by EPA in this action, using scaling to adjust the modeled RPGs based on 

photochemical source apportionment model results is reasonable and meets the requirements of 

the Regional Haze Rule. In our 2012 rulemaking,909 we made a finding that Arkansas did not 

complete a reasonable progress analysis and therefore did not properly demonstrate that 

additional controls were not reasonable under 40 CFR 51.308(d)(1)(i)(A). Thus we disapproved 

the RPGs Arkansas established for Caney Creek and Upper Buffalo. In our proposed 

 

905 The RPGs we are finalizing today for Caney Creek and Upper Buffalo are a logical outgrowth of our proposed

RPGs based on comments we received, which are discussed in more detail elsewhere in the final rule and our RTC

document. See Int'l Union,UMW, 407 F.3d at 1259; Fertilizer Inst., 935 F.2d at 1311; and Chocolate Mfrs. Ass'n v.

Block, 755 F.2d 1098. 906 80 FR 18998 907 40 CFR 51.308(d)(1)(v). 908 64 FR 35733 and 40 CFR 51.308(d)(1)(v). 909 64 FR 35732
475

rulemaking, we completed the reasonable progress analysis and established revised RPGs using 

the methodology described above, since we have not received a revised SIP to correct the 

portions of the SIP submittal we disapproved. 

Comment: EPA did not appropriately develop the revised RPGs for Caney Creek and 

Upper Buffalo. [AECC (0169) p. 3-4] AECC stated that EPA explains how to appropriately 

develop RPGs for Class I areas in the proposed Rule, but EPA states that it did not use this 

approach in developing RPGs for the proposed Rule.910 AECC stated that EPA explains that to 

develop an appropriate RPG analysis there should be: 

 Use of a photochemical grid model for a multi-state area; 

 An update of the emissions inventory for Arkansas and the surrounding states; and 

 Specialized and extensive computing hardware and expertise to develop input files, run 

the models, and post-process the model outputs.911

AECC stated that EPA explains that this process was not used to develop RPGs for Caney Creek 

and Upper Buffalo because it would take several months.912 

AECC stated that EPA used CALPUFF, which is not a photochemical grid model, to develop a 

“quick-and-dirty” RPG analysis in proposed Rule. CALPUFF is a single-source model used for 

individual BART assessments. A photochemical grid model would use data from thousands of 

emission sources to determine the impact on a given Class I area. 

Based on the information above, AECC believes that EPA used an inappropriate process to 

develop RPGs for the Arkansas Class I areas. EPA is using the results of this inappropriate 

analysis to subject the Independence plant to installation of controls. AECC believes that this is 

arbitrary on the part of EPA and the Independence units should be removed from the scope of 

this proposed Rule. 

Response: The commenter is incorrect and confuses the single-source visibility analysis used to 

evaluate the visibility benefit of controls on a specific source with the assessment of overall 

visibility conditions. We did not use the CALPUFF modeling to develop the new reasonable 

progress goals we establish in this rulemaking. The RPGs are based on adjusting the CENRAP 

2018 CAMx photochemical modeling based on source apportionment modeling results and 

emission inventory data. As we stated in the proposed rulemaking, we did not perform 

additional photochemical modeling to directly model the new projected visibility goals due to the 

time and resource demands associated with photochemical modeling. 

7.i. Additional Modeling Comments 

Comment: EPA should have used realistic data for its visibility analysis [Nucor SteelArkansas and Nucor-Yamato Steel (0163) p.38-40] Nucor stated that according to EPA's BART 

 

910 80 FR 18997. 911 Id. 912 Id.
476

Guidance “The baseline emissions rate should represent a realistic depiction of anticipated 

annual emissions for the source.” 40 CFR Part 51, Appendix Y, Section IV.D.4.c. However, 

EPA’s BART and Reasonable Progress determinations do not comply with this requirement. 

First, EPA’s use of the maximum 24-hour recorded emissions extrapolated across the three year 

analysis period significantly overestimates the visibility impacts from a facility. For example, 

from 2001 to 2003, Entergy Independence reported maximum 24-hour SO2 emission rates of 

5,463 lb/hr and 6,337 lb/hr from Unit 1 and Unit 2, respectively. However, the average daily 

emission rate over that same three year period (with downtime omitted) for Unit 1 and Unit 2 is 

2,927 lb/hr and 3,088 lb/hr, respectively. Actual average emissions from the facility are half of 

what is represented in the modeling analysis. 

Additionally, EPA admits in the Regional Haze Regulations and Guidelines for Best Available 

Retrofit Technology Determinations that modeled impacts are overstated. Specifically, EPA 

states that “there are other features of our recommended modeling approach that are likely to 

overstate the actual visibility effects of an individual source. Most important, the simplified 

chemistry in the model tends to magnify the actual visibility effects of that source.” 70 Fed.Reg. 

39104, 39121 (July 6, 2005). This led the EPA to its decision to use the 98th percentile of 

modeled visibility values, which eliminates roughly 7 days per year from the analysis. However, 

this approach has no rational or generally accepted scientific basis as a way to “normalize” the 

emissions data. Using the same example for Entergy Independence, if the maximum 7 days of 

each year from 2001 to 2003 is eliminated for each unit, the maximum 24-hour emissions rates 

across that timeframe become 4,768 lb/hr and 5,357 lb/hr at Unit 1 and Unit 2, respectively. This 

is still far above the actual average daily emission rate and continues to severely overestimate the 

reasonable amount of emissions that would occur over an extended period of time at the 

facility.913 

In addition, EPA failed to use the most recent SO2 emissions data for the White Bluff and Flint 

Creek BART determinations, relying instead on continuous emissions data from 2001-2003 to 

establish baseline visibility impacts. EPA should have used 2009-2011 emissions data, which 

Entergy specifically proposed for its White Bluff BART Five Factor Analysis, and which reflects 

a significant decrease in SO2 emissions.914 Because use of low-sulfur coal is an acceptable 

pollution control technology, it was wrong for EPA not to accept the emissions data from 2009-

2011 just because use of low-sulfur coal was not required by a permit condition. North Dakota v. 

EPA, 730 F.3d 750, 764 (8th Cir. 2013). 

Response: The portion of the BART Guidelines cited by the commenter (40 CFR Part 51, 

Appendix Y, Section IV.D.4.c.) refers to the section that discusses how to estimate costeffectiveness of controls using annualized costs and annual emission reductions. Our costeffectiveness analysis for the BART units (developed by the facilities) and our cost analysis for 

Independence, under reasonable progress, follows this guidance and utilizes average emissions 

from the baseline period. Elsewhere in the guidance, for visibility analyses, the BART 

 

913 EPA’s 98th percentile approach also does not suffice to “normalize” the maximum visibility impacts, since there

is no demonstrated relationship between the modeled highest visibility impacts and the highest observed visibility

impacts.

914 See Exhibits 15A and 15B to Nucor’s comments, demonstrating the reduction in SO2 emissions and coal sulfur

concentrations for White Bluff in 2009‐2011, compared to 2001‐2003.
477

guidelines state:915 “Use the 24-hour average actual emission rate from the highest emitting day 

of the meteorological period modeled (for the precontrol scenario).” 

With respect to our analysis of controls under reasonable progress, we rely on our reasonable 

progress Guidance.916 Our Reasonable Progress Guidance notes the similarity between some of 

the reasonable progress factors and the BART factors contained in Section 51.308(e)(1)((ii)(A), 

and suggests that the BART Guidelines be consulted regarding cost, energy and non-air quality 

environmental impacts, and remaining useful life. We are therefore relying on our BART 

Guidelines for assistance in interpreting those reasonable progress factors, as applicable. 

Also, similar to a BART analysis, we are also considering the projected visibility benefit in our 

analysis following the BART guidelines.917 We rely on the BART Guidelines here and in other 

actions evaluating reasonable progress controls because they provide a reasonable and consistent 

approach regarding visibility modeling. 

Therefore, our analysis for the Independence facility followed the BART guidance and was 

consistent with the BART analyses done for all subject-to-BART facilities. Consistent with this 

guidance, we utilized the 24-hr maximum emission rate from the 2001-2003 baseline period and 

modeled using 2001-2003 meteorological data. The BART Guidelines also state that the 

emissions estimates used in the models are intended to reflect steady-state operating conditions 

during periods of high capacity utilization. We recommend that States use the 24 hour average 

actual emission rate from the highest emitting day of the meteorological period modeled, unless 

this rate reflects periods start-up, shutdown, or malfunction. In addition, the monthly average 

relative humidity is used, rather than the daily average humidity—an approach that effectively 

lowers the peak values in daily model averages.918 As discussed elsewhere in this document, the 

BART guidelines also recommend the model be used to estimate the 98th percentile visibility 

impairment rather than the highest daily impact value as proposed. We made the decision to 

consider the less conservative 98th percentile primarily because the chemistry modules in the 

CALPUFF model are simplified and likely to provide conservative (higher) results for peak 

impacts. Since CALPUFF’s simplified chemistry could lead to model over predictions and thus 

be conservative, EPA decided to use the less conservative 98th percentile.919 Therefore, our 

modeling approach is consistent with the guidance and focuses on estimating the maximum 

potential visibility impacts that correspond to periods of high utilization and not the average 

emission rate over the baseline period. 

 

915 40 CFR Part 51, Appendix Y, Section IV.D.5 916 Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program, June 1, 2007 917 As we explain in our proposed action (80 FR 18993): “While visibility is not an explicitly listed factor to 

consider when determining whether additional controls are reasonable under the reasonable progress requirements, 

the purpose of the four-factor analysis is to determine what degree of progress toward natural visibility conditions is 

reasonable. Therefore, it is appropriate to consider the projected visibility benefit of the controls when determining 

if the controls are needed to make reasonable progress”. See 79 FR at 74838, 74840, and 74874. 918 40 CFR Part 51, Appendix Y, Section III 919 “Most important, the simplified chemistry in the model tends to magnify the actual visibility effects of that

source. Because of these features and the uncertainties associated with the model, we believe it is appropriate to

use the 98th percentile—a more robust approach that does not give undue weight to the extreme tail of the

distribution.”

70 FR 39104, 39121.
478

The commenter does not provide the full context from the preamble to the final Regional Haze 

Rule920 discussing the use of the 98th percentile value. The full text states: 

“...there are other features of our recommended modeling approach that are likely to overstate 

the actual visibility effects of an individual source. Most important, the simplified chemistry in 

the model tends to magnify the actual visibility effects of that source. Because of these features 

and the uncertainties associated with the model, we believe it is appropriate to use the 98th 

percentile—a more robust approach that does not give undue weight to the extreme tail of the 

distribution. The use of the 98th percentile of modeled visibility values would appear to exclude 

roughly 7 days per year from consideration. In our judgment, this approach will effectively 

capture the sources that contribute to visibility impairment in a Class I area, while minimizing 

the likelihood that the highest modeled visibility impacts might be caused by unusual 

meteorology or conservative assumptions in the model.” 

As we discuss above in a separate response to comment, the extreme tail of the distribution of 

modeled results are typically much higher than the remainder of the modeled values and can be 

an overly conservative estimate of the maximum impact. The commenter confuses eliminating 

the highest modeled impacts (that may reflect unusual meteorology or conservative model 

assumptions) with eliminating the highest emission rates and using the 8th highest emission rate. 

The commenter claims that the use of the 98th percentile is an attempt to “normalize” the 

emissions data, but this is not correct. As we discuss above, the modeling approach is to 

estimate the impact from the highest emission days (using actual emission data), not the average 

or a “normalized” emission rate. 

The commenter also states that we should have utilized emissions data from 2009-2011 rather 

than the 2001-2003 baseline emissions for the evaluation of controls at White Bluff and Flint 

Creek. As stated above, consistent with the BART guidance, we utilized the 24-hr maximum 

emission rate from the 2001-2003 baseline period and modeled using 2001-2003 meteorological 

data. The commenter provides emissions data for the White Bluff units for 2001-2012, but this 

data only shows average monthly emissions and monthly sulfur content of coal and does not 

provide any information on shorter term emission rates or the maximum 24-hr emission rates 

during those years. This data also shows an upward trend in monthly SO2 emissions, 

particularly at Unit 1 from 2010 through the end of the data in 2012. Similar to the information 

we presented in Appendix C of the TSD for the Independence units, the table below shows the 

maximum 24-hr emission rate for each year for the White Bluff units. As can be seen in the 

table below, more recent data shows high variability in maximum emissions with 2014 

maximum emissions higher than emissions in 2009-2011. Furthermore, the recent utilization of 

lower-sulfur coal does not provide any assurance that the suggested 2009-2011 baseline would 

be representative of future emissions because there is no requirement or physical control 

technology in place to reasonably prevent emissions from increasing in the future, emission rates 

in 2013 and 2014 are higher than the 2009-2011 period,921 and it is possible that the addition of 

potential control equipment would allow for the utilization of cheaper, higher-sulfur coal. 

Consistent with the BART analysis prepared by Flint Creek, we utilized emissions from the 

 

920 70 FR 39104, 39121 921 See “whitebluff unit1 and 2 EI.xlsx” in the docket for this action for additional emission inventory data for thiese

units
479

2001-2003 baseline. In the case of NOx emissions, in 2006 Entergy completed the addition of a 

neural network system and conducted extensive boiler tuning that substantially reduced NOX

emissions, resulting in an actual change in operations and emissions between the original 

baseline period (2001–2003) and current operations. For NOx, we did utilize more recent 

emissions data from the 2009-2011 period because this data reflected the installation of controls, 

a change in operations and emissions, and any additional NOx controls would be applied in 

combination with these existing controls. 

Year

SO2

24‐hr Max (lb/hr)

unit 1 unit 2

2000 7214 8212

2001 6983 6858

2002 6986 6635

2003 7764 7825

2004 7944 7801

2005 7123 6772

2006 7628 7948

2007 6664 7685

2008 6975 7121

2009 6772 6622

2010 5833 5598

2011 6485 6435

2012 5532 6131

2013 5999 6133

2014 7251 6852

    

2001‐2003 7764 7825

2009‐2011 6772 6622

2012‐2014 7251 6852

Comment: [UARG (0176) p. 15-16] UARG stated that EPA proposes reasonable progress 

requirements for the Independence Power Plant, which is not subject to BART. EPA attempts to 

support its proposed reasonable progress determination for Independence with supplemental 

visibility modeling that EPA conducted after learning of an error in the Agency’s previous 

modeling. See Summary of Additional Modeling for Entergy Independence, Docket ID No. 

EPA- R06-OAR-2015-0189-0147, at 3 (Apr. 20, 2015). In conducting this supplemental 

modeling, EPA evaluated projected visibility improvements using different baselines. For SO2, 

EPA evaluated visibility improvements against a 2001-2003 baseline period (“BASE”) and 

against an alternative baseline that included 2001 2003 SO2 emissions and updated NOx 

emissions using 2011-2013 data (“BASE2”). See id. at 5 6. For NOx, EPA only evaluated 

visibility improvements against the BASE2 (i.e., the 2011-2013) scenario. See id. at 6-7. 
480

Modeled visibility impacts for SO2 depend on whether EPA used the BASE period or the 

BASE2 period, with impacts varying by as much as 0.461 dv. See id. at 5-6; compare id. at 5 

Table 2 (projected visibility improvement of 1.056 dv with dry FGD at Hercules-Glade using 

BASE) with id. at 6 Table 3 (projected visibility improvement of 0.595 dv with dry FGD at 

Hercules-Glade with BASE2). In the Federal Register notice announcing the availability of 

EPA’s supplemental modeling, EPA presented only the SO2 modeling results using BASE and 

the NOx modeling results using BASE2, thereby suggesting that those values are the ones on 

which EPA proposes to rely in this rulemaking. 80 Fed. Reg. 24,872, 24,873 (May 1, 2015). EPA 

did not, however, provide any rationale for using an updated, 2011-2013 baseline for NOx 

modeling while retaining the 2001-2003 baseline for evaluating visibility impacts of SO2 and 

SO2 reductions. If EPA intends to proceed to promulgate a final FIP based on this proposed rule 

and the Agency’s additional modeling, it must first publish a supplemental notice of proposed 

rulemaking with an adequate explanation of its reasons, together with any supporting 

information, for its decisions on this matter and must allow a reasonable opportunity for public 

comment on that explanation and information. 

Response: We disagree with the commenter's characterization of our action. For our visibility 

impact analysis of the Independence facility, we modeled using both the baseline period of 2001-

2003 as well as the updated baseline period for NOx in order to consider the currently existing 

NOx controls. As we explained in the TSD, modeled visibility benefits from the use of DFGD 

using the updated NOx emissions baseline from 2011-2013 are similar to those modeled with the 

2001-2003 baseline NOx emissions values.922 We also noted that had we modeled a more recent 

baseline for SO2 emissions, the baseline visibility impact would be greater and the visibility 

benefits modeled from the control scenarios would also be greater. In Appendix C of the TSD 

we explain the baseline emissions we identified for our analysis, using an updated baseline to 

evaluate NOx controls due to changes in operation between the baseline period and when the 

modeling was performed. We noted that this was similar to the adjustment made to the White 

Bluff NOx emissions discussed in the response to comment above. As can be seen in Table 3-1 

of Appendix C of the TSD, the NOx emission levels, particularly for unit 2 are much lower for 

the 2011-2013 time period than the 2001-2003 baseline, reflecting a change in operation and 

emissions. 

Our Federal Register notice on May 1, 2015, provided notice of supplemental modeling available 

in the docket and provided a summary of the model results. The supplemental modeling 

corrected an error in the modeled location of the facility due to a typographical error. All other 

model inputs and model scenarios were identical to the previous modeling described in 

Appendix C of the TSD. A summary of all the results of the supplemental modeling was made 

available in the docket, including results using both NOx baseline emission levels.923 The 

commenter incorrectly calculates the difference between modeled visibility impacts for SO2 

control scenarios between the BASE and BASE2 modeled scenarios. The projected visibility 

improvement at Hercules-Glade using BASE is 1.056 dv compared to a projected visibility 

 

922 Appendix C to the TSD, Section 3.1, available in the docket for this action 923 Summary of Additional Modeling for Entergy Independence, available in the docket for this action
481

improvement at Hercules-Glade using BASE2 of 1.139 dv, a difference of 0.083 dv.924 We 

noted that these results are similar and that either modeled scenario supports our conclusion that 

visibility impacts from these units are large and that controls will result in meaningful visibility 

benefits towards the goal of natural visibility conditions. We disagree with the commenter and 

have provided opportunity for comment on all aspects of the modeling that we conducted 

including our additional modeling for the Independence facility. 

Comment: EPA’s NOX BART analysis for Lake Catherine Unit 4 did not adequately 

consider the visibility improvements from potential NOX controls, along with other 

statutory BART factors, and is therefore legally flawed. [Sierra Club et. al. (0171) p. 27-28] 

The Sierra Club et. al. stated that EPA must base BART determinations on an analysis of the five 

statutory BART factors: (1) the costs of compliance, (2) the energy and non-air quality 

environmental impacts of compliance, (3) existing pollution controls in use at the source, (4) the 

remaining useful life of the source, and (5) the degree of visibility improvement. 42 U.S.C. 

§7491(g)(2); 40 C.F.R. § 51.308(e)(1)(ii)(A). The Lake Catherine Unit 4 BART analysis fails to 

accurately consider the visibility improvement from NOX controls, along with compliance costs 

and the non-environmental impacts of controls. [The Sierra Club’s detailed comments regarding 

consideration of compliance costs and non-environmental impacts of controls are found in the 

sections of this RTC document where we discuss cost and other BART issues.] EPA incorrectly 

analyzed the visibility improvements from potential controls in several ways. EPA failed to 

provide sufficient documentation for the proposed achievable NOx limit of BOOS and, as a 

result, EPA likely overstated the visibility benefits of this control scenario. In 2007, ENSR 

Consulting found that BOOS could achieve an emission rate of 0.280 lb/MMBtu. Stamper 

Report at 53. Sargent & Lundy found, based on BOOS testing, that an emission rate of 0.24 was 

achievable. Id. Sargent & Lundy, however, also found that Entergy would need to increase 

natural gas firing by 25% to operate the unit at the same capacity factor. Id. at 53-54. Sargent & 

Lundy never calculated what emission rate was achievable with this additional natural gas usage. 

Id. Then in 2015, EPA proposed an emission limit of 0.22 lb/MMBtu on a 30 boiler operating 

day rolling average based on the installation and operation of BOOS. 80 Fed. Reg. at 18,978. 

Neither EPA nor Entergy explained or documented why the new rate is achievable despite these 

past findings. Id. As the Stamper Report explained, Entergy appeared to rely on the long 

averaging time and the fact that this facility is a peaking unit, to find that this emission rate is 

achievable. If EPA or Entergy used averaging times to find this lower emission rate achievable 

than it is likely that Entergy did not properly model short term NOx emissions for Lake 

Catherine. Stamper Report at 54. 

In addition, EPA overestimated the visibility benefits of BOOS because it did not analyze 

whether NOx emissions under this scenario would be higher than the assumed baseline due to 

additional natural gas usage. Id. Finally, EPA overestimated the visibility benefits of each control 

scenario as it relied on Entergy’s flawed maximum daily average NOx emission rate. As 

described in Ms. Stamper’s report, Entergy incorrectly determined the maximum daily rates for 

each control scenario, which resulted in applying a percent reduction that was higher than 

 

924 Summary of Additional Modeling for Entergy Independence, available in the docket for this action.  See Table 2

for visibility improvement over baseline using BASE and Table 3 for visibility improvement over baseline using

BASE2
482

required by the proposed NOx rates for each control scenario. Id. at 55-57. As a result, Entergy 

understated the maximum daily NOx emission rates under each control scenario. This in turn 

overstated the visibility benefit from each control scenario. 

Comments [Sierra Club Stamper Report]: Typically, the determination of the maximum 24-hour 

emission rate for a control scenario is determined through the following steps: 1) Determine the 

24-hour period of maximum daily emissions during the baseline period. 2) Determine the NOx 

rate in lb/MMBtu that the unit achieved during the baseline period over a long term average. 

Usually, the annual average NOx rate over the baseline is determined, although sometimes the 

maximum 30-day average NOx rate during the baseline period is evaluated. 3) Determine the 

percent reduction from the annual average or from the 30-day average NOx emission rate during 

the baseline period needed to achieve the proposed 30-day averaging limit for the proposed 

control scheme. 4) Apply that percent reduction to the maximum daily NOx rate over the 

baseline period to predict maximum daily NOx emissions under the control scheme being 

evaluated to meet BART.

Entergy correctly determined the baseline NOx emission rate for Lake Catherine Unit 4 during 

the 2001-2003 baseline period as the maximum daily emissions during the baseline period, 

divided by 24 hours per day to lb/hr rate of 2,456.4 lb/hr.208 Entergy also assumed a 

maximum emission rate of 0.4825 lb/MMBtu for Lake Catherine Unit 4 during the baseline 

period.209 To project maximum daily rates under the various control scenarios, Entergy 

determined the percent NOx reduction from 0.4825 lb/MMBtu to the proposed 30-day average 

NOx emission rate for each control scenario, and applied that to the 2001-2003 maximum daily 

rate of 2,564.4 lb/hr to estimate maximum daily NOx emissions under each control scenario.210

However, the 0.4825 lb/MMBtu baseline emission rate was not a long term average NOx rate at 

Lake Catherine Unit 4: instead, it was the maximum 24-hour average NOx emission rate at 

Lake Catherine Unit 4 during the 2001-2003 baseline period.211 By using a maximum daily 

NOx rate during the baseline period and comparing it to proposed 30-day average emission 

rates for each control scenario to determine the percent removal, Entergy has greatly 

understated the maximum daily NOx emission rates under each control scenario (because 

Entergy’s approach overstates the percent reduction from each control evaluated). As a result, 

Entergy’s modeling overstates the visibility benefits with each control scheme evaluated. 

As stated above, the commonly applied approach for determining emission rates to model for 

BART visibility analyses is to determine the annual average NOx rate or, at most, the 

maximum 30-day average NOx rate during the baseline period, and then to evaluate the percent 

reduction from that annual or 30-day average rate to achieve the 30-day average emission rate 

assumed for each control scenario. The 2001-2003 annual average NOx rate for Lake Catherine 

Unit 4 was 0.18 lb/MMBtu212, which is lower than the NOx rate assumed for BOOS and low 

NOx burners/OFA (meaning BOOS would provide no NOx reductions from an annual average 

baseline). The maximum 30-day average NOx rate at Lake Catherine Unit 4 during the 2001- 

2003 baseline period was 0.27 lb/MMBtu.213 Entergy should not have assumed a baseline 

NOx rate any higher than 0.27 lb/MMBtu in projecting emissions rates under each control 

scenario. 

In Table 15 below, I recalculate the projected maximum daily emission rates based on a 0.27 

lb/MMBtu baseline and the 30-day average NOx rates assumed by Entergy in its BART analysis.
483

208 See Entergy Revised BART Five Factor Analysis, Lake Catherine Steam Electric Station, May 2014 at 4-1. 209 Id. at 6-5; Appendix D at 17 -18. 

210 Id. 211 Id., App. D at 18 (Note 1). 212 See spreadsheet with Lake Catherine Unit 4 annual emissions CAMD data for 2001 to 2003 (Ex. 92). 213 See spreadsheet with Lake Catherine Unit 4 daily emissions CAMD data for 2001 to 2003 (Ex. 93). 

Table 15. Maximum Daily NOx Emission Rates for Various NOx Controls 

Evaluated for Lake Catherine Unit 4 Based on Percent NOx Reduction from 30-Day 

Average NOx Baseline Rate, Rather than Entergy’s Maximum Daily NOx Baseline Rate

NOx Control 

Scenario

30-Day Average 

NOx Rate, 

lb/MMBtu

Max Daily NOx 

Emissions, lb/hr

Max Daily NOx

Emissions Modeled 

by Entergy, lb/hr214

Baseline 0.27 2,456.4

BOOS 0.22 1,999.5 1,287.0 

LNB/SOFA 0.19 1,726.8 1,111.5 

LNB/SOFA Plus 

SNCR

0.14 1,272.4 819.0 

LNB/SOFA Plus SCR 0.03 272.7 175.5 

As Table 15 demonstrates, the use of the commonly-applied methodology for estimating 

maximum daily NOx emissions under each control scenario predicts significantly higher 

maximum NOx emission rates for each control scenario, which means that Entergy’s 

modeling overstates the visibility benefits for all controls evaluated. 

For BOOS, it may not even be appropriate to assume an 18.5% reduction in daily NOx 

emissions.215 As discussed above, it is not clear what the maximum short term NOx rate 

would be with BOOS at Lake Catherine Unit 4, because the fuel firing rate will need to be 

increased by 25% to achieve maximum generation capacity with BOOS.216 Sargent & 

Lundy predicted a 0.24 lb/MMBtu emission rate with BOOS at Lake Catherine Unit 4.217 

Entergy has assumed it could meet a lower 0.22 lb/MMBtu NOx limit with BOOS on a 30-

day averaging basis based on the expected utilization rate of Unit 4.218 It appears Entergy 

was assuming it could average in peak NOx rates with lower NOx rates to achieve a 30-day 

average rate of 0.22 lb/MMBtu. That may be acceptable for demonstrating compliance with 

a 30-day average BART limit, but modeling a lower NOx limit would overstate the 

visibility benefits of BOOS at Lake Catherine Unit 4 by failing to reflect the max daily NOx 

rate that would be emitted at Unit 4 with BOOS. 

EPA should carefully estimate the maximum daily emissions expected from the operation of 

BOOS (along with the increased firing rate) at Lake Catherine Unit 4 to ensure it is basing its 

BART determination on an accurate prediction of the visibility benefits of BOOS. 

214 See Entergy Revised BART Five Factor Analysis, Lake Catherine Steam Electric Station, May 2014 at 4-1 and 6-

10. 
484

215 This is the percent reduction from the 0.27 lb/MMBtu 30-Day Average NOx baseline rate and the proposed NOx 

limit with BOOS of 0.22 lb/MMBtu. 

216 See Id. at 6-2, 6-4, Appendix D at 15-16. 217 Id. 218 Id. at 6-2. 

Response: See our response to the issue of whether Entergy can achieve the NOx emission limit 

of 0.22 lbs/MMBtu due to the installation of BOOS in the Cost section of our Response to 

Comments Document.

The commenter states that we overestimated the visibility benefits from controls because we 

used a maximum daily NOx rate during the baseline period and compared it to proposed 30-day 

average emission rates for each control scenario to determine the percent removal. 

The BART guidelines recommend the following approach in developing the modeled scenarios: 

For each source, run the model, at precontrol and post-control emission rates 

according to the accepted methodology in the protocol. Use the 24-hour average actual 

emission rate from the highest emitting day of the meteorological period modeled (for the 

precontrol scenario). Calculate the model results for each receptor as the change in 

deciviews compared against natural visibility conditions. Post-control emission rates are 

calculated as a percentage of precontrol emission rates. For example, if the 24-hr precontrol emission rate is 100 lb/hr of SO2, then the post control rate is 5 lb/hr if the control 

efficiency being evaluated is 95 percent.925

As discussed in detail previously, we rely on the BART Guidelines here and in other actions 

evaluating reasonable progress controls because they provide a reasonable and consistent 

approach regarding visibility modeling. 

This is the general approach followed by us and the BART analysis prepared by the facility for 

the Lake Catherine analysis. The baseline emission rate was based on maximum actual 24-hr 

emission rate during the baseline period of 0.4825 lb/MMBtu. The modeled controlled emission 

rates were then estimated based on a percentage reduction anticipated by each control 

technology, as identified in the Sargeant and Lundy report926, from this maximum emissions rate, 

as shown in the table below. The commenter is incorrect in their assertion that all the modeled 

emission rates represent 30-day average emission rates. We disagree that it is necessary to 

remodel the baseline and control scenarios utilizing a long-term emission rate. 

 

Control % reduction 

from baseline 

NOx emission 

rate (lb/MMBtu) 

NOx 

emission rate (lb/hr)1

Baseline --- 0.4825 2456.42

 

925 40 CFR 51 Appendix Y IV.D.5 926 NOx Control Technology Cost and Performance Study Entergy Services, Inc. White Bluff & Lake Catherine, May

16, 2013 (Appendix D to the Entergy Revised BART Five Factor Analysis, Lake Catherine Steam Electric Station, May

2014)
485

BOOS 50% 0.24 (0.22)3 1404.0 

(1287.0) 

LNB/SOFA 60% 0.19 1111.5 

LNB/SOFA + 

SNCR 70% 0.14 819.0 

LNB/SOFA + 

SCR 94% 0.03 175.5 

1

lb/hr emission rate for control scenarios based on percent reduction applied to 0.4825 lb/MMBtu rate and maximum 

heat input rate of 5850 MMBtu/hr 

2

Baseline lb/hr rate based on actual emissions from highest emitting day during baseline period 

3

 Entergy Lake Catherine final analysis utilized 0.22 lb/MMBtu, previous analyses used 0.24 lb/MMBtu 

The commenter is correct that the final BART analysis927 prepared by the facility utilized a 0.22 

lb/MMBtu emission rate for the BOOS control scenario, which represents the 30-day average 

emission rate rather than the 0.24 lb/MMBtu estimated short term emission rate estimated as a 

50% reduction from the baseline maximum short term rate of 0.4825 lb/MMBtu. The previous 

BART analysis928 prepared by the facility utilized the 0.24 lb/MMbtu emission rate for modeling 

the BOOS control scenario. We evaluated the difference between these modeled scenarios and 

summarize the results below for most impacted Class I area, Caney Creek. 

 

Control Visibility 

impact 

Visibility 

improvement 

from baseline 

Incremental improvement over BOOS 

0.22 

lb/MMBtu 

0.24 

lb/MMBtu 

Baseline 1.371 

BOOS 

(0.22lb/MMBtu) 0.775 0.596 

BOOS 

(0.24lb/MMBtu) 0.835 0.536 

LNB/SOFA 0.683 0.688 0.092 0.152 

LNB/SOFA + SNCR 0.529 0.842 0.246 0.306 

LNB/SOFA + SCR 0.163 1.208 0.612 0.672 

 

We note that the BART determination is based on consideration of five factors, including the 

degree of improvement in visibility which may reasonably be anticipated to result from the use 

of such technology. The visibility modeling is intended to give a reasonable best estimate of the 

visibility impacts from an evaluation of emission reductions. The visibility analysis is only one 

of the factors in a BART determination. In this final action, we are setting a NOx limit of 0.22 

lb/MMBtu to be calculated on a 30-day rolling average Boiler Operating Day. We modeled the 

 

927 Entergy Revised BART Five Factor Analysis, Lake Catherine Steam Electric Station, May 2014 928 BART Five Factor Analysis, Lake Catherine Steam Electric Station, March 2013
486

0.22 lb/MMBtu in our proposal, because we have determined this emission rate to be achievable 

based on information supplied by the facility. In response to comments, we have also examined 

that visibility impacts and benefits based on the shorter-term emission rate of 0.24 lb/MMBtu 

from the previous analysis available in the record. We find that consideration of the visibility 

impacts and benefits at the higher, short-term rate does not change our determination that BOOS 

is BART for this source. While the incremental visibility benefits over BOOS are larger by 0.06 

dv, the total visibility benefit of higher control levels is unchanged. As we discuss in the 

proposal929, the incremental costs for more effective controls above BOOS remain high. BOOS 

was estimated to cost $138/ton compared to $1,450/ton for LNB/SOFA (an incremental cost of 

more than $14,000/ton). Furthermore, while the visibility benefits from SCR are not 

insignificant, we do not consider the cost per ton removed ($5,614/ton) and the incremental costs 

of SCR to be cost-effective. 

Comment: EPA should revise its NOX BART analysis for Lake Catherine Unit 4 and in 

doing so should give due consideration to SCR’s superior visibility benefits. [Sierra Club et. 

al. (0171) p. 28] The Sierra Club et. al. stated that EPA’s Lake Catherine Unit 4 NOX BART 

analysis fails to accurately consider the degree of visibility improvement of controls, as well as 

the compliance costs and non-environmental impacts. Therefore, EPA’s analysis is legally 

flawed. [The Sierra Club et. al.’s detailed comments regarding consideration of the degree of 

visibility improvement of controls, as well as the compliance costs and non-environmental 

impacts in the NOX BART analysis for Lake Catherine Unit 4 are found throughout different 

sections of this RTC document.] EPA must conduct a new NOx BART analysis that corrects 

these flaws and considers whether SCR represents the best system of continuous emission 

reduction for NOx at Lake Catherine Unit 4. In doing so, we urge EPA to give due consideration 

to the superior visibility benefits of control scenarios that include SCRs and to not place 

inappropriate weight on the incremental cost-benefit analysis in its revised BART analysis. 

When EPA corrects its BART analysis to address the flaws that Ms. Stamper identified, the 

agency will likely find that control scenarios that include SCR are more cost-effective than EPA 

originally calculated and will provide for the greatest visibility benefits at Caney Creek and the 

other Class I areas. [Our responses to comments regarding the cost-effectiveness and incremental 

cost-effectiveness of NOX controls for Lake Catherine Unit 4 are found in the section of this 

RTC document where we discuss cost issues.] While EPA overestimated the visibility 

improvements from the use of SCR by relying on Entergy’s flawed maximum daily average NOx 

emission rate, its modeling of the SNCR control scenario does provide an approximation of 

SCR’s likely visibility benefits under correct modeling, as discussed in Ms. Stamper’s report. 

Stamper Report at 59. This means that the 98th percentile visibility improvement at Caney Creek 

would be at least 0.842 dv and the cumulative benefit across all four Class I areas would be at 

least 1.702 dvs. Id.; see also Table 42 at 80 Fed. Reg. 18,978. No other suite of NOx controls 

would come close to providing as much visibility improvement as the SCR control scenario at 

Lake Catherine Unit 4. We thus urge EPA to give due consideration to these significant and 

superior visibility benefits in its revised Lake Catherine NOx BART analysis. 

 

Response: We disagree with the commenter that we overestimated visibility benefits from SCR. 

We address comments concerning the estimated visibility improvements from controls at Lake 

Catherine in the response to comments above. The BART determination is based on 

 

929 80 FR 18978
487

consideration of five factors, including the degree of improvement in visibility which may 

reasonably be anticipated to result from the use of such technology. The visibility modeling is 

intended to give a reasonable best estimate of the visibility impacts from an evaluation of 

emission reductions. The visibility analysis is only one of the factors in a BART determination. 

In the visibility analysis, we modeled the 24-hr maximum emission rate and percent reductions 

anticipated from available control technologies, following the BART guidelines, as discussed 

above. As we discuss in the proposal930, the incremental costs for more effective controls above 

BOOS, such as SCR remain high. BOOS provides for very inexpensive emission reductions and 

significant visibility improvement. While the visibility benefits from SCR are not insignificant, 

we do not consider the cost per ton removed and the incremental costs of SCR to be costeffective. If the commenter were correct that we over-estimated the visibility benefits of SCR 

this would serve only to only reinforce our determination that the visibility benefits, while not 

insignificant, do not justify the costs of SCR in this case. 

Comment: [Dr. Gray]: EPA compared the visibility outcomes from the revised modeling for the 

various control scenarios to the baseline emission scenarios to determine the benefits associated 

with each of the potential control measures. The baseline emission scenarios (BASE and 

BASE2) represent emission levels during two previous time intervals (2001-2003 and 2011-

2013) and do not necessarily reflect future emission levels (without controls). EPA should have 

used projected future year emissions with controls (baseline) and then compared that to a control 

scenario with commensurate emission reductions as this would be a more-appropriate 

comparison. 

EPA’s BASE2 scenario consists of actual SO2 emission levels from 2001-2003 and NOx levels 

from 2011-2013. The SO2 emission levels are not representative of recent (or projected) 

emission levels for Independence. As EPA states (in their additional modeling report): “We note 

that had we modeled a more recent baseline for SO2 emissions, the baseline visibility impacts 

would be greater and the visibility benefits modeled from the control scenarios would also be 

greater.” 

EPA thus underestimated the differences between baseline (using either BASE or BASE2) and 

the various control scenarios (“visibility improvement over baseline”). Ultimately, a more logical 

approach is for EPA to simply compare the visibility impacts between the different control 

scenarios. 

Examination of the modeling results shows that the peak days are typically caused by a 

combination of high sulfate and high nitrate concentration impacts, although high sulfate impacts 

dominate the highest visibility impact days under the baseline emission scenarios. When 

significant SO2 emission reductions are applied however (such as through the application of 

DFGD), the remaining peak days are dominated by high nitrate events, which require NOX 

reductions to mitigate. Although DFGD controls at Independence achieve a significant reduction 

in the visibility impact, the modeling shows that the peak impact is still over 1 delta dV at Caney 

Creek. 

 

930 80 FR 18978
488

The combined control strategy consisting of LNB and DFGD results in the largest visibility 

improvement of EPA’s modeled scenarios. The modeled peak delta dV impact is less than 0.6 at 

all affected Class I areas. The combined LNB and DFGD scenario is the only control strategy for 

which the peak delta dV impact would be less than 1.0 at all Class I areas. When the modeled 

control scenarios for Independence (WFGD, DFGD, LNB, etc.) are compared, it is apparent that 

the combined SO2 and NOX control scenario consisting of both LNB and DFGD achieves the 

best visibility outcomes in the four modeled Class I areas of the scenarios considered. 

Response: We agree with the commenter that we likely underestimated visibility benefits of 

controls at the Independence facility using the 2001-2003 emissions baseline because recent SO2 

emissions (and possibly projected future emissions) are higher than the modeled baseline 

emissions from the 2001-2003 time frame. We acknowledged this in our analysis stating: “We 

note that had we modeled a more recent baseline for SO2 emissions, the baseline visibility 

impacts would be greater and the visibility benefits modeled from the control scenarios would 

also be greater.” In our analysis, as documented in our proposed rulemaking, we determined that 

modeled visibility impacts were large, visibility benefits from reductions in SO2 emissions from 

controls were significant, and controls (DFGD) were reasonable in consideration of the cost of 

the controls. Using a higher SO2 emission baseline in our analysis would result in even larger 

visibility benefits from proposed installation of controls and would have reaffirmed this 

determination. We agree with the commenter that after significant projected SO2 emission 

reductions, the remaining visibility impact from the source is still significant (> 1 dv at Caney 

Creek). This remaining visibility impact was shown to be reduced by highly cost-effective NOx 

reductions from the use of LNB. The combined use of LNB and DFGD does provide for the 

largest reduction in visibility impairment from the source among the options evaluated. As we 

discuss in our proposal, we also found these reductions from LNB and DFGD to be costeffective. 

Comment: [Dr. Gray/EarthJustice]: Consideration of SCR for Independence Units 1 and 2 and 

Reconsideration of SCRs for White Bluff Units 1 and 2.

EPA did not evaluate SCR on the two Independence power plant units using the CALPUFF

modeling system. Instead EPA claimed that SCR at White Bluff would not achieve a large

enough visibility improvement and therefore EPA need not consider SCR for Independence

either. 

CALPUFF modeling following the EPA’s protocol and model inputs, was used to evaluate SCR 

at an emission rate of 0.055 lb/MMBtu. The emission rate for SO2 was assumed to be the 0.06 

lb/MMBtu . The modeled emission rates for the SCR_DFGD scenario are shown in Table 2. 

Table 2. Modeled Emission Rates for Independence Power Plant for SCR. 

Modeled Emission Rate (lb/hr) 
489

Scenario Source SO2 SO4 NOX PMC PMF EC SOA 

SCR_DFGD Unit 1 537.00 0.05 492.25 11.10 10.70 0.40 16.60 

 Unit 2 537.00 0.05 492.25 11.10 10.70 0.40 16.60 

 Total Facility 1,074.00 0.10 984.50 22.20 21.40 0.80 33.20 

The modeled visibility impacts for each Class I area are shown below in Table 3, and in Figure 2 

(not reproduced here). 

Table 3. Modeled Maximum 98th percentile delta dV for the SCR_DFGD scenario

CACR HERC MING UPBU TOTAL

2001 0.303 0.187 0.196 0.186 

2002 0.193 0.207 0.142 0.239 

2003 0.246 0.207 0.165 0.262 

3-yr max 0.303 0.207 0.196 0.262 0.968

Improvement 

over LNB_DFGD 0.257 0.124 0.142 0.220 0.743

The cumulative delta dV (sum of all four Class I areas) for each of the modeled emission

scenarios (see Figures 1 and 2) is summarized below (total facility impact): 

Cumulative delta dV, Independence: 

----------------------------------- 

Baseline (BASE2): 7.526 

LNB: 6.548 

DFGD: 3.067 

LNB_DFGD: 1.711 

SCR_DFGD: 0.968 

----------------------------------- 

From these model results, it can be seen that the application of NOX emission reductions using

LNB (LNB_DFGD) would achieve a cumulative delta dV improvement of 1.356 over the DFGDonly scenario. If SCR were applied, the improvement to the cumulative 98th percentile delta dV 

would be 2.099 (relative to DFGD-only). 

The cumulative visibility (delta dV) improvement for SCR at Independence relative to LNB was

modeled to be 0.743. SCR at White Bluff resulted in a cumulative delta dV improvement of

about 0.43 (relative to LNB/SOFA) – which EPA did not consider sufficient to recommend SCR

over LNB/SOFA. The current modeling shows that SCR at Independence would achieve a

much larger incremental visibility improvement relative to LNB (0.74 dV) than SCR would

achieve at White Bluff relative to LNB (0.43 dV). 
490

If LNB and DFGD were first applied at Independence, then the addition of SCR would remove

over 40 percent of the remaining visibility impact from this source, leaving only a small

remaining cumulative impact (less than 1 delta dV). If one were then to consider LNB in place

of SCR, it would approximately double the visibility impact (to 1.71). 

EPA used the modeling results for SCR at White Bluff to discount the consideration of SCR at

Independence. EPA’s White Bluff model results are shown below: 

Cumulative delta dV, White Bluff: 

----------------------------------- 

Baseline: 9.540 

DFGD: 3.902 

LNB/SOFA: 8.457 

LNB/SOFA_SNCR: 8.313 

LNB/SOFA_SCR 8.025 

----------------------------------- 

Relative to LNB, SCR at White Bluff achieves a small additional visibility improvement (the

cumulative delta dV is reduced by 0.29). EPA observed that the largest incremental visibility

improvement over LNB/SOFA was 0.069 at Caney Creek. However, this was for a single unit

and also relative to SNCR, which was not proposed; the impact for the total facility (both units)

at Caney Creek relative to LNB was 0.21. 

EPA understated the benefits of SCR relative to LNB at White Bluff. The cumulative visibility

benefit at the four modeled Class I areas was modeled to be 0.43 (delta dV) for SCR relative to

LNB at White Bluff9, much larger than the 0.069 delta dV (for one unit at one Class I area,

relative to SNCR) that EPA apparently used to dismiss SCR at White Bluff. 

The current modeling shows that SCR at Independence would achieve a much larger cumulative

visibility improvement at the modeled Class I areas than SCR at White Bluff. SCR controls

should therefore be considered for both the White Bluff and Independence power plants. The 

current modeling shows that SCRs at Independence provide significant visibility benefit,

including significant incremental visibility benefit relative to less stringent controls, such as

LNB. The cumulative visibility improvement for SCR at Independence relative to LNB is 0.743

deciview (“dV”), which is larger than EPA assumed in failing to review this technology. 

Moreover, EPA significantly undervalued the incremental visibility improvement between LNB

and SCRs at White Bluff. The cumulative visibility benefit at the four modeled Class I areas for

SCRs at White Bluff relative to LNB is 0.43 (delta dV),10 which is much larger than the 0.069

delta dV (for one unit at one Class I area, relative to SNCR) than EPA assumed. EPA should

consider requiring this technology in its Final Rule for both White Bluff and Independence. 

Response: We disagree with the commenter that we undervalued the incremental visibility 

benefit for SCRs at White Bluff. In evaluating the visibility benefit from controls we considered 
491

the total and incremental visibility benefit at each impacted Class I area as well as the cumulative 

visibility benefits.931 For the White Bluff facility, we found that LNB/SOFA and SNCR had a 

cost-effectiveness of a factor of 4 to 5 times larger than that of LNB/SOFA in terms of $/ton and 

SCR had a cost-effectiveness approximately 8 to 10 times larger than LNB/SOFA. Based on our 

cost estimates of controls, we estimate the incremental cost of SCR over LNB/SOFA for unit 1 

to be $7,338/ton and $6,611/ton for unit 2. The incremental visibility benefit of SCR over LNB 

is summarized below. We continue to find that incremental visibility benefits ranging from 

0.032 to 0.103 dv on a unit-basis at an individual Class I area and incremental cumulative 

visibility benefits of 0.216 dv per unit across all 4 impacted Class I areas are not large enough to 

justify the additional cost of SCR for this planning period. 

Class I 

Area 

White Bluff modeled visibility benefit over baseline (dv) 

LNB SCR Incremental benefit of 

SCR over LNB/SOFA 

Unit 1 Unit 2 Unit 1 Unit 2 Unit 1 Unit 2 

Caney 

Creek 0.166 0.225 0.269 0.327 0.103 0.102 

Upper 

Buffalo 0.101 0.139 0.149 0.188 0.048 0.049 

HerculesGlades 0.176 0.190 0.209 0.222 0.033 0.032 

Mingo 0.038 0.047 0.07 0.08 0.032 0.033 

Sum 0.481 0.601 0.697 0.817 0.216 0.216 

In considering NOx controls at Independence we determined that the visibility improvement due 

to the installation of LNB/SOFA at the Independence facility is of a similar magnitude to that of 

the White Bluff facility. As explained in our proposed rule, we applied the total annualized 

LNB/SOFA cost developed by Entergy for White Bluff Units 1 and 2, with one line item 

revision made by us, to Independence Units 1 and 2. However, we adjusted the costeffectiveness ($/ton) due to the differing NOx emissions from the units. We reasoned that 

because (1) the Independence and White Bluff facilities were sister facilities and very similar, 

and (2) we found that the costs of SNCR and SCR for White Bluff were not worth the resulting 

visibility improvement, we had no reason not to conclude the same for the Independence facility. 

The additional visibility benefit from SNCR and SCR did not justify the additional cost of 

controls at White Bluff for this planning period. Therefore, our evaluation of NOx controls for 

Independence Units 1 and 2 focused on LNB/SOFA. 

We disagree with how the commenters assessed and compared the modeled visibility benefits of 

SCR. The commenters modeled the combined visibility benefit of SCR controls and dry FGD at 

Independence (on a facility wide basis), but based on the information provided it does not appear 

that they modeled or considered the visibility improvement of SCR controls alone, as was done 

 

931 80 FR 18974
492

for White Bluff. The commenter’s comparison of visibility benefit from SCR at White Bluff to 

visibility benefits at Independence is incorrect because the visibility benefits due to SCR at 

White Bluff were modeled using baseline SO2 emission levels, while the commenter’s modeled 

benefits of SCR at White Bluff are modeled using controlled SO2 emission levels. If the 

modeling had been performed on a consistent basis allowing for a direct comparison, the 

visibility benefits from SCR at the two facilities would be similar, as demonstrated by the 

modeled visibility benefits for LNB/SOFA shown in the table below. Furthermore, the 

commenter does not provide any modeling for LNB/SOFA and SNCR, so we are unable to 

assess the incremental visibility benefits of SCR over SNCR as we did for White Bluff. Despite 

these differences, we have determined that the additional visibility modeling submitted by the 

commenter does not demonstrate that the visibility benefits due to SCR at Independence are 

larger than that at White Bluff or are large enough to justify the additional cost of controls. 

Class I Area 

Visibility improvement of 

LNB/SOFA at 

Independence over 

baseline 

(deciviews) 

Visibility improvement of 

LNB/SOFA at White 

Bluff over baseline 

(deciviews) 

Caney Creek 0.459 0.391 

Upper Buffalo 0.198 0.240 

Hercules-Glades 0.173 0.366 

Mingo 0.148 0.085 

Cumulative 0.978 1.082 

The commenter’s modeling analysis estimates the benefits of SCR at Independence and 

compares this to the modeled visibility benefits of LNB/SOFA. The table below summarizes the 

results of our modeling for LNB/SOFA and the commenter’s modeling of SCR. As we discuss 

above, the modeling submitted by the commenters utilized the DFGD controlled emission rate 

for SO2 rather than the baseline SO2 emission rate so these numbers are not directly comparable 

to the visibility benefits for White Bluff summarized above. 

Class I 

Area 

Independence Modeled visibility benefit 

over BASE2_DFGD 

LNB/SOFA SCR1

Incremental 

benefit of SCR 

over 

LNB/SOFA 

Caney 

Creek 0.485 0.742 0.257 

Upper 

Buffalo 0.337 0.557 0.22 

HerculesGlades 0.264 0.388 0.124 
493

Mingo 0.27 0.412 0.142 

Sum 1.356 2.099 0.743 

1

SCR model results submitted by commenter 

As shown in the table above, the largest incremental visibility benefit of SCR on both units over 

LNB/SOFA (using the reduced SO2 emission rate) is 0.257 dv at Caney Creek and 0.22 dv at 

Upper Buffalo. We do not believe this amount of incremental visibility benefit justifies the 

incremental cost of SCR, estimated to be approximately $6,600/ ton and $7,300/ton based on the 

White Bluff cost-estimate, at this time. We address comments concerning the commenter’s costestimates for SCR at Independence and White Bluff in separate responses to comment. 

 

Comment: EPA Used a Few Non-Default CALPUFF Modeling Options That, When

Returned to the Default, Had No Material Impact on the Analysis.

Examination of EPA’s modeling files for Independence11 revealed that the agency used a few

non-default options. I reviewed these and found that, when returned to the default, the use of

these options did not materially impact EPA’s analysis. The two parameters evaluated were 

minimum vertical divergence criteria (“CDIV”) and the dispersion parameter 

(“XSAMLEN”). 

The commenter states that the vertical divergence (dw/dz) is a measure of the change in the 

vertical wind speed (w) per meter of depth (the units of dw/dz are 1/s). In the CALPUFF input 

control file, the user must set a minimum divergence criterion (“CDIV”) for dw/dz that is used 

to initiate an adjustment to the vertical mixing parameter (sigma-z) for modeled puffs. The 

vertical mixing is adjusted (sigma-z is increased) whenever the vertically averaged dw/dz across 

the height of the puff exceeds CDIV (and then the increase in sigma-z is proportional to the 

value of dw/dz). Increasing sigma-z shifts a larger portion of each puff upward and downward 

from its center point height. 

The default value for CDIV of 0.0 (for which sigma-z will always be adjusted) was used for all 

BART modeling. For the Independence modeling only, EPA used a value of CDIV = 0.01 

(equivalent to a change of 1 m/s per 100 m of depth). The result is that for a large number of 

puffs (whenever the averaged dw/dz is less than 0.01), a larger portion of the puff will be closer 

to the puff’s center height. Shifting a larger portion of the puff closer to the center height will 

mean that the wind data (which are used for transporting the center of the puff horizontally) 

may be collected from fewer vertical levels, potentially resulting in somewhat different wind 

speeds (and directions). 

The commenter modeled both values for CDIV and compared the results for 2001. The 

commenter noted that some days are higher and some are lower, however overall it balances out 

such that the 98th percentile days (8th highest) were not significantly affected at the four modeled 

Class I areas (see Table 5). At Upper Buffalo, the use of CDIV=0.01 increased the 98th 

percentile delta dV by 11 percent. The cumulative delta dV (for 2001) increased by only about 

2 percent (from 7.66 to 7.84). 
494

XSAMLEN is a dispersion parameter that is input by the user in the CALPUFF control file.

XSAMLEM is the maximum travel distance of a puff/slug (in grid units) allowed during one

sampling step. The commenter states that the default value of XSAMLEN is 1.0 but EPA used 

XSAMLEN=10.0 for all modeled sources. By allowing the value of XSAMLEN to be greater 

than 1.0, faster moving puffs may stretch over multiple horizontal grid cells. The 

meteorological parameters affecting the movement of each modeled puff are obtained from the 

center point of each puff. Using a lower value for XSAMLEN forces the CALPUFF model to 

release more puffs per time step, so that each individual puff can be adequately represented by 

the meteorological parameters at its center point. 

Setting XSAMLEN=10 will cause fewer puffs to be modeled which will speed up the time of

model run slightly. However, the horizontal motion of each puff will be determined by the

parameters at its center point location which may not adequately represent the motion of a large

puff that is stretched out over multiple meteorological grid cells. Using the meteorology at a

single location to represent the entire puff will increase the uncertainty of the location of a 

portion of the puff’s mass. The differences in wind speeds from one grid cell to the next are

randomly distributed (with a mean of zero), so the overall effect on a large collection of modeled

puffs that have each travelled over numerous time steps will likely be minimal (and unbiased). 

The commenter evaluated CALPUFF results with both settings for XSAMLEN for 2001. 

The model results (see Table 6) indicate that the peak daily delta dV at Upper Buffalo changed

by 5 percent or more on eight of the top twenty impact days by using XSAMLEN=10 instead of

the default value. Nonetheless, the unbiased nature of the increase in uncertainty of the 

modeled puffs’ locations associated with the larger XSAMLEN model option resulted in a 

small overall effect on the 98th percentile delta dV at each of the four modeled Class I areas (see 

Table 7). Using XSAMLEN=10 instead of the default value resulted in a decrease in the 

modeled cumulative visibility impact of less than 1 percent. 

Table 7. 98th Percentile Delta dV (2001)

98th Percentile delta dV (2001)

XSAMLEN = 1 XSAMLEN = 10

Caney Creek 2.471 2.484

Hercules-Glades 1.758 1.760 

Ming Junction 1.867 1.827 

Upper Buffalo 1.563 1.532 

Total 7.659 7.603 

Although the use of the CDIV=0.01 and XSAMLEN=10 options lead to small (and largely

unbiased) errors in the modeling results, and these non-default options are not recommended, 

the overall effect on the modeled 98th percentile delta dV impacts at the four Class I areas is 

small. Furthermore, it is expected that the differences in model results would be similar for 

each of the modeled emission scenarios, so that the conclusions drawn when using the model 

results to compare various emission control strategies would not be changed at all. 
495

Response: We appreciate the sensitivity analysis provided by the commenter. The selection of 

CDIV = 0.01 and XSAMLEN =10 in the modeling performed by EPA for the Independence 

facility was consistent with the CENRAP’s BART modeling protocol932 developed by CENRAP 

with input from the EPA and FLMs. The BART modeling performed by the facilities deviated 

from these settings in selecting CDIV = 0 rather than CDIV =0.01. We agree with the 

commenter that the differences in these settings would not significantly change the estimated 98th

percentile visibility impacts and visibility benefits of controls and would not have impacted our 

control determinations based on consideration of all the relevant factors. 

8. Legal 

8.a. Controls will not be in place within the first planning period 

Comment: EPA has offered no justification for requiring controls under Reasonable 

Progress when controls will not be installed until the next planning period [Entergy 

Arkansas Inc. (0166) p.42-43] Entergy Arkansas Inc. stated that EPA exceeds its authority by 

proposing to require controls in the name of achieving reasonable progress during the first 

planning period even though the emissions reductions the Agency proposes would not be 

achieved until well into the second planning period. The Proposed FIP covers a planning period 

of 2008-2018. The major SO2 emissions control technology that would have to be installed at 

Independence to meet the proposed SO2 emission rate limitation cannot be designed, constructed 

and operational in less than five years.933 Given the likely effective date of the FIP in 2016, SO2

controls at Independence could not be installed and operational before sometime in 2021.934

Adopting a reasonable progress goal for the first planning period based on the installation of 

controls that will not be completed until well after the deadline to achieve that reasonable 

progress goal makes no sense, and EPA has completely failed to explain why it is appropriate. 

Indeed, EPA will have multiple bites at this apple – there are still four more planning periods 

during which the necessity of reasonable progress controls can be evaluated. Controls on 

Independence should not be considered until these subsequent planning periods, and should not 

be imposed for a planning period that will have ended by the time any emissions reductions can 

be achieved at Independence. This is consistent with EPA’s Reasonable Progress Guidance: “It is 

reasonable for [a state] to defer reductions to later planning periods in order to maintain a 

consistent glidepath toward the long-term goal.” Reasonable Progress Guidance at 1-4. 

 

932 See CENRAP BART Modeling Guidelines, Appendix B.  Available in the docket for this action under document ID:

EPA‐R06‐OAR‐2015‐0189‐0095. 933 EPA recognizes this timeframe is necessary for the installation of SO2 controls at Independence by proposing that 

Independence meet the SO2 emissions limits no later than five years after the effective date of the final rule. 80 Fed. 

Reg. at 18,994. Entergy agrees with EPA’s conclusion that a five-year timeframe would be necessary for the 

installation of controls at Independence. 934 The Proposed FIP provides for NOX emission limitations to be met three years after the effective date of the FIP, 

which would not be earlier than sometime in 2019.
496

Response: We disagree with this comment. The Clean Air Act clearly establishes our authority 

and responsibility to promulgate a FIP that addresses the requirements of the Regional Haze 

Program where a State’s SIP submission fails to meet the program requirements. We 

disapproved Arkansas’ regional haze SIP in 2012. Under these circumstances, the Clean Air Act 

requires EPA to promulgate a FIP within two years unless the State has corrected the deficiency 

by submitting a SIP revision and EPA has approved that revision. As Arkansas has not 

submitted a SIP revision to address the deficiencies in its regional haze SIP, we must promulgate 

a FIP addressing the applicable requirements. 

The first planning period, ending in 2018, includes reasonable progress goals (RPGs) specific to 

that planning period that reflect the rate of progress for remedying visibility impairment that is 

reasonable, taking into consideration certain factors set out in the CAA. Although States are 

required to establish RPGs for 2018 to provide transparency regarding the degree of 

improvement predicted to result as of that date from the suite of controls in the SIP, there is no 

limitation in the CAA or the Regional Haze Rule that controls to improve visibility contained in 

a SIP must be fully implemented by the end of the planning period. In particular, as discussed 

below, there is no requirement that long-term strategy and BART requirements be fully 

implemented by 2018. As these major components of the Regional Haze program may extend 

beyond the first planning period, it follows that EPA has FIP authority fill in “gaps” or 

“inadequacies” related to those components irrespective of whether such controls can be put into 

place by 2018. 

 

Congress declared that the “national goal” of the Regional Haze program is “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.”935 To meet this goal, 

Congress ordered us to issue regulations requiring States to implement SIPs “to contain such 

emission, limits, schedules of compliance and other measures as may be necessary to make 

reasonable progress toward meeting the national goal[,]” and the SIPs must include, among other 

requirements, “a long-term (ten to fifteen years) strategy for making reasonable progress toward 

meeting the national goal[.]”936 Congress stated that “in determining reasonable progress there 

shall be taken into account [...] the time necessary for compliance[.]”937 Thus, the Clean Air Act 

does not restrain EPA from requiring sources to install controls outside of the initial planning 

period in the long-term strategy, but rather, it requires us to consider the time necessary for 

compliance when determining what constitutes “reasonable progress” toward the national 

goal.938

 

We issued regulations including, in addition to BART requirements, four “core requirements” 

including reasonable progress goals, calculations of baseline and natural visibility conditions, a 

long-term strategy and a monitoring strategy and other implementation plan requirements.939 As 

part of these SIP requirements, a State must “consider [...] the time necessary for compliance” 

 

935 42 U.S.C. § 7491(a)(1). 936 Id. at 7491(b)(2). 937 Id. at 7491(g)(1). 938 While the CAA does provide the statutory factors, including “time necessary for compliance,” we note that it 

does not delineate 10 year planning periods. These are specified by the RHR. 

939 40 C.F.R. § 51.308(d). 
497

when establishing RPGs.940 The long-term strategy component “must include enforceable 

emission limitations, compliance schedules, and other measures necessary to achieve the 

[RPGs]” however, this “must include” language does not limit the long-term strategy to only 

those measures to achieve RPGs.941 Rather, it mandates inclusion of certain requirements to 

meet the RPGs without limiting planning authority to include other requirements to meet the 

national goal. Thus, there is no explicit statutory or regulatory requirement to limit control 

options to the first planning period. 

Further, EPA’s long-standing interpretation of the Clean Air Act and its regulations explicitly 

provide for the type of post-planning period controls to which Commenter objects. In issuing the 

Regional Haze rule and consistent with 42 U.S.C. 7491(b)(2)(B), we interpreted “long-term 

strategy” as the “control measures that are needed to ensure reasonable progress, together with a 

demonstration that those measures will provide for reasonable progress during the 10 to 15 year 

period.”942 Again, the reference to “reasonable progress,” as opposed to RPG, refers to the 

national goal, and as noted above, the regulation provides for flexibility to achieve the national 

goal. In issuing its guidance on RPGs, the very situation to which Commenter objects is laid 

clear: 

The second factor is the “time necessary for compliance.” It may be appropriate 

for you to use this factor to adjust the RPG to reflect the degree of improvement 

in visibility achievable within the period of the first SIP if the time needed for full 

implementation of a control measure (or measures) will extend beyond 2018. For 

example, if you anticipate that constraints on the availability of construction labor 

will preclude the installation of controls at all sources of a particular category by 

2018, the visibility improvement anticipated from installation of controls at the 

percentage of sources that could be controlled within the strategy period should be 

considered in setting the RPG and in establishing the SIP requirements to meet 

the RPG.943 

In this passage, the intention in saying that “the percentage of sources that could be controlled 

within the strategy period should be considered ...in establishing the SIP requirements to meet 

the RPG” is that the SIP deadline for compliance by the remaining sources should be set after the 

end of the implementation period, not that the SIP should contain no emission limits for the 

remaining sources. By noting that scrubber retrofits may take up to five years to install, yet also 

noting that scrubber upgrades may be installed within three years, we proposed RPGs for our FIP 

for Texas that only account for the visibility benefits associated with scrubber upgrades.944 In 

doing so, we considered the time necessary for compliance in establishing RPGs, yet exercised 

our authority to propose a long-term plan including emission limits that likely require controls 

that may not be operational during the planning period. 

 

940 Id. at 51.308(d)(1). 941 Id. at 51.308(d)(3). 942 64 Fed. Reg. 35714, 35734. 943 OAQPS, EPA, Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program (June 1, 

2007), 5–2. 

944 79 Fed. Reg. 74818, 74874. 
498

We also note that, due to sequencing of the SIP process, including submission, review, revisions, 

re-review, and FIP preparation, public notice and promulgation, the CAA anticipates a 

substantial period of time between SIP submission and the promulgation of a FIP, as may 

ultimately be essential for carrying out CAA requirements. Those sources that should be subject 

to new controls under the CAA may take certain advantages from delays in having those control 

requirements imposed, but they do not have the benefit of an exclusion from CAA requirements. 

Instead, any emission limitations that prove to be required by the CAA for the first planning 

period need to be achieved at their soonest opportunity, not delayed, deferred or avoided for later 

planning periods at those times when other sources should be the focus of potential additional 

controls. Accordingly, we do not think the comment takes proper account of the time 

engagement required to promulgate a FIP within a planning period (if a FIP proves needed) or 

the significance of the CAA’s contemplated ten- to fifteen-year long-term strategy, which could 

not be included in a FIP absent some degree of flexibility to extend FIP requirements beyond the 

date set for the end of the first planning period.945

Finally, we note that we have proposed controls outside of the planning period in other FIPs, 

including our proposed FIP for Arkansas and the FIP for Wyoming and Texas. Additionally, the 

Oklahoma FIP was stayed during litigation, resulting in a revised compliance date beyond 2018. 

Comment: [Edison Electric Institute (0174) p. 5-6, 9-10] EEI stated that EPA has provided no 

rationale for regulating the Independence units. Further, even if EPA could articulate a need to 

regulate these units on reasonable progress grounds, the efficacy of doing so is thrown into 

further question by the timing of the proposed emission control requirements and the structure of 

the RHR. As noted, the regional haze program contemplates gradual visibility improvements 

along a “glide path” that considers the 2064 goal, and does not require immediate reductions that 

exceed making “reasonable progress.” See 64 Fed. Reg. at 35,721. Here, the proposed FIP is 

attempting to require controls for Independence units that EPA knows cannot be in place or 

effective within the first planning period, i.e., prior to 2018. See 80 Fed. Reg. at 19,004. Given 

that the regional haze program’s target extends to 2064, EPA’s insistence that sources install 

extensive control equipment that technically will not be in place or effective to meet a 2018 

milestone is unreasonable and unjustified, especially considering that impacted Class I areas are 

on track to meet upcoming reasonable progress goals for visibility. Instead, these controls, if they 

will be necessary at all, should only be considered by Arkansas during the next planning period, 

which runs between 2019 and 2028.

Response: Please see the above response explaining why we are imposing emission limits 

requiring installation of control equipment for this planning period, even though such control 

equipment will not be installed until after 2018. 

 

945 Additionally, the State’s responsibility for its SIP, or EPA’s authority when needing to promulgate a FIP, is not 

shown to be discontinuous or intermittent because of the requirement to conduct comprehensive periodic plan 

revisions. Instead, there is ongoing authority to ensure reasonable progress from sources within the State. As 

demonstrated by the progress report requirements of the RHR, the regional haze program expressly contemplates 

that a State may determine the need for “further revision of the existing implementation plan” because the existing 

plan” is or may be inadequate”; in such situations, the rule sets out, deficiencies are to be addressed promptly 

(“within one year”), not deferred to the next comprehensive periodic plan revision, as the comment thinks to be 

necessary. See 40 CFR 51.308(h). 
499

 

In addition to the question of timing, we disagree with the commenter’s suggestion that visibility 

improvements beyond that associated with the glidepath exceed “reasonable progress.” 

Assessing the measures necessary to achieve visibility improvement commensurate with the 

glidepath, as required by the Regional Haze Rule, ensures that States consider a relatively 

stringent suite of control measures in determining the appropriate measures to include in their 

regional haze SIPs. The glidepath, however, is an analytical requirement, and as explained in 

our prior disapproval of Arkansas’ regional haze SIP, “being on the ‘glidepath’ does not mean 

that a state is allowed to forego an evaluation of the four statutory factors,” as Arkansas did in its 

SIP.946 In other words, a prediction that a Class I area will be “on the glidepath” is not enough to 

conclude that no further analysis of reasonable progress measures can or should be done. 

We explained in our proposed rule that we focused on the Entergy Independence Power Plant in 

our analysis of reasonable progress measures “because it is one of most significant sources of 

SO2 and NOx, as it is the second largest point source for both SO2 and NOx point source 

emissions in the State.”947 (The largest point source of SO2 and NOx, the Entergy White Bluff 

Plant, is subject to the BART requirements). Given that it is our obligation to ensure that 

reasonable progress is made toward meeting the national goal, it “would be unreasonable to 

ignore a source representing more than a third of the State’s SO2 emissions and a significant 

portion of NOx point source emissions.”948 

 

We agree with EEI that the regional haze program contemplates gradual visibility improvements 

over time. The measures in our FIP, as well as the other CAA programs, will provide 

improvements in visibility after 2018 and help to ensure that Class I areas continue to make 

reasonable progress in the second planning period. We do not consider the emission limits that 

can be achieved by installation of scrubbers and combustion controls we have proposed and 

those we finalize in this action as being extensive or frontloading but instead represent a level of 

control consistent with the reasonable application of the four reasonable progress factors. As we 

have outlined in our proposal and our final rulemaking, Arkansas failed to comply with certain 

aspects of the Regional Haze Rule and thus portions of its regional haze plan were not 

approvable, triggering the requirement for EPA to implement a FIP. 

8.b. Four unit approach for White Bluff and Independence 

Comment: EPA has no legal basis for requiring that a four-unit approach achieve greater 

reasonable progress. [Entergy Arkansas Inc. (0166) p. 45] Entergy Arkansas Inc. stated that 

EPA has requested public comment on any alternative SO2 and NOx control measures that would 

address the regional haze requirements for White Bluff Units 1 and 2 and Independence Units 1 

and 2 for this planning period. 80 Fed. Reg. at 18,997. According to EPA, this includes, but is 

not limited to, a combination of early unit shutdowns and other emissions control measures at the 

 

946 77 FR at 14629 947 80 FR 18944, 18992 (April 8, 2015). 948 Id. 
500

four units that would achieve greater reasonable progress than the BART and reasonable 

progress requirements that EPA has proposed for the first planning period. See id.

EPA has offered no legal basis for its claim that an alternative four-unit approach must achieve 

greater reasonable progress than the controls that EPA has proposed, 80 Fed. Reg. at 18,997, and 

Entergy disagrees that such a requirement is applicable or mandated by the Clean Air Act or 

EPA’s own Regional Haze Rule. Neither the Act nor EPA’s rules impose such a requirement. To 

the contrary, EPA noted in the final Regional Haze Rule that states have discretion to determine 

what control measures must be implemented to achieve reasonable progress. 64 Fed. Reg. at 

35,721. EPA further explained that “States may conclude that control strategies specifically for 

protection of visibility are not needed at this time because the analyses may show that existing 

measures are sufficient to meet reasonable progress goals.” Id. Indeed, not only is it up to the 

states to determine how much must be done to ensure reasonable progress, but states conceivably 

could conclude that nothing must be done. There is no provision setting a “floor” for reasonable 

progress.

Response: White Bluff Units 1 and 2 are BART-eligible sources that reasonably may be 

anticipated to cause or contribute to any impairment of visibility in any class I area and must 

undergo a BART evaluation under Section 51.308(e). Under 51.308(e) of the RHR, a state must 

submit an implementation plan containing emission limitations representing BART and 

schedules for compliance with BART “unless the state demonstrates that an emissions trading 

program or other alternative will achieve greater reasonable towards natural conditions.” In 

several cases, after EPA has proposed or finalized a BART determination in a FIP, a source has 

requested that EPA instead adopt an alternative to BART under these provisions. We requested 

comment on alternative measures to determine whether the Entergy would be interested in an 

alternative path. 

Entergy did provide comments tentatively suggesting a possible multi-unit alternative to the 

proposed FIP that would have included emission reductions at both White Bluff and 

Independence.949 EPA could not complete an evaluation of an alternative proposal (as described 

more fully in another section of our response to comments) for White Bluff and Independence 

because EPA did not have, and Entergy did not provide in its comments, all the technical 

information required in which to perform the evaluation required under 51.308(d)(1) 

and51.308(e). 

EPA agrees that the regional haze rule does not provide a floor for reasonable progress much in 

the same way that it does not provide a ceiling. Instead, states must determine appropriate 

measures for making reasonable progress based on consideration of the relevant factors and 

establish RPGs reflecting these and other measures likely to reduce emission over the planning 

 

949 While states that opt to implement an emissions trading program or other alternative measure rather than require 

sources to install, operate, and maintain BART are required to demonstrate that this alternative will achieve greater 

reasonable progress than would be achieved through the installation of source-specific BART, 40 C.F.R. § 

51.308(e)(2), Entergy is not proposing a BART alternative. Rather, EPA’s understanding is that under Entergy’s 

four-unit approach, the NOX control measures and lower SO2 emission rate proposed for White Bluff would be 

considered to constitute BART for White Bluff while the NOx control measures and lower SO2 emission rate 

proposed for Independence combined with the cessation of coal combustion at White Bluff would be considered to 

be more than sufficient for reasonable progress purposes for this planning period. 
501

period. It is helpful to consider the language from the preamble to the RHR quoted by the 

commenter (“States may conclude that...”) in context, however. In the RHR, EPA determined 

that it was likely that all states -- including those without Class I areas -- contain sources whose 

emissions are reasonably anticipated to contribute to regional haze in a Class I area. In addition, 

the preventative component of the national goal requires states to have a framework in place to 

address emissions growth. For these reasons, EPA concluded that all states must therefore submit 

regional haze SIPs. In explaining why it did not consider it appropriate to establish criteria for 

excluding states from the regional haze program, we explained that EPA is not specifying what 

control measures a state must implement in its regional haze SIP. As more fully explained in the 

preamble, we noted: 

That determination can only be made by a State once it has conducted the 

necessary technical analyses of emissions, air quality, and the other factors that go 

into determining reasonable progress ... EPA recommends that these analyses and 

the determination of the extent of emissions reductions needed from individual 

States be developed and refined through multistate planning efforts using the best 

available technical tools, such as regional-scale modeling. The EPA also 

recommends the coordination of resulting strategies for regional haze with 

strategies needed to attain the PM2.5 NAAQS. The EPA anticipates that as a 

result of the more refined analyses required by this rule, some States may 

conclude that control strategies specifically for protection of visibility are not 

needed at this time because the analyses may show that existing measures are 

sufficient to meet reasonable progress goals. The EPA is requiring States to 

document their analyses, including any consultations with other States in support 

of their conclusions that further controls are not needed at this time. The EPA 

believes that there is more than enough evidence to support our conclusion that 

emissions from each of the 48 contiguous States may be reasonably anticipated to 

cause or contribute to visibility impairment in a Class I area.950

As the full quote makes clear, the determination that no control strategies specifically are needed 

to protect visibility depends on a thorough technical analysis. 

EPA previously determined that Arkansas failed to reasonably address certain of the BART and 

reasonable progress requirements in its SIP, as explained in the final action partially 

disapproving Arkansas’ regional haze plan.951 We are not reopening that determination in this 

rulemaking. 

8.c. Requirements for Reasonable Progress and Long Term Strategy 

Comment: [UARG (0176) p. 11-14] UARG stated that EPA proposes reasonable progress 

emission limits as part of the FIP. The proposed reasonable progress emission limits are not 

justified under EPA’s visibility rules and the Reasonable Progress Guidance and rest on an 

 

950 64 Fed. Reg. at 35721. 951 76 Fed, Reg. 64186 (Oct. 17, 2011) (proposed rule); 77 Fed. Reg. 14604 (March 12, 2012) (final rule). 
502

incorrect legal premise. EPA therefore should not promulgate the proposed reasonable progress 

emission limits. 

EPA’s decision to conduct a reasonable progress analysis in this rulemaking is not adequately 

justified. EPA explains that it disapproved Arkansas’s RPGs for Caney Creek Wilderness Area 

(“Caney Creek”) and Upper Buffalo Wilderness Area (“Upper Buffalo”) because, in EPA’s 

view, Arkansas “believed, incorrectly, that no additional analysis of potential reasonable 

progress measures was necessary because visibility projections for the Class I areas indicated 

improvements in visibility consistent with the URP.” Id. at 18,989. EPA does not dispute 

Arkansas’s conclusion that the projected emission levels resulting from the emission controls 

that Arkansas’s SIP would have required would have more than met the URPs for 

Caney Creek and Upper Buffalo. 

Rather, EPA’s view is that even if those controls (including BART) are projected to produce a 

rate of progress on visibility improvement that equals or exceeds the URP for the Class I area in 

question, a full reasonable progress analysis is required to permit a determination of whether 

additional emission reduction requirements are warranted and, if they are, the nature and the 

degree of stringency of the required emission reductions. Along these lines, EPA asserts that 

“[t]he preamble to the Regional Haze Rule ... states that the URP does not establish a ‘safe 

harbor’” in the establishment of RPGs. Id. at 18,992 (citing 64 Fed. Reg. 35,714, 35,732). 

EPA fails to reconcile its stated position with the language of the preamble to the 1999 regional 

haze rule on which the Agency here relies. In that preamble, at 64 Fed. Reg. at 35,732 (the same 

page that EPA’s proposed rule cites, see 80 Fed. Reg. at 18,992 n.117), EPA explains that the 

URP is the starting point for analysis and that the rule does not require assessing the reasonable 

progress criteria with respect to a potentially faster rate of progress if the rate of progress 

represented by the URP is deemed to be reasonable. A reasonable progress assessment for a rate 

that is more stringent than the URP is required only if a state chooses to make a determination 

“that additional progress beyond this [URP] amount is also reasonable”: 

If the State determines that the amount of progress identified 

through the analysis is reasonable based upon the statutory factors, 

the State should identify this amount of progress as its reasonable

progress goal for the first long-term strategy, unless it determines 

that additional progress beyond this amount is also reasonable. If 

the State determines that additional progress is reasonable based on 

the statutory factors, the State should adopt that amount of 

progress as its goal for the first long-term strategy. 64 Fed. Reg. at 

35,732 (emphases added). 

Thus, only if a state were to “determine [] that additional progress [beyond the URP] is 

reasonable” would consideration of an RPG that is more accelerated than the URP – together 

with assessment of the additional emission control measures that would be needed to achieve that 

more accelerated RPG – be warranted. Id. 
503

Moreover, the regional haze rule preamble explains why states, or at least states that are located 

in the eastern half of the country (as Arkansas is), ordinarily – and properly – would decline to 

consider and adopt rates of progress that are more accelerated than the URP, particularly for the 

first planning period. EPA explained that it selected the 2064 “goal” year in light of its projection 

that a 60-year period would provide time to “reach the national [visibility] goal ... given that this 

rate of [visibility] improvement is expected to be achieved due to emissions [reductions] under 

[existing] CAA programs.” Id. at 35,731-32. In promulgating the rule, EPA stated its 

“understanding” that “in the eastern United States ... the [emission] reductions from measures 

implementing the CAA requirements will provide the visibility improvement and emissions 

[reductions] needed for reasonable progress during the first regional haze implementation plan.” 

Id. at 35,733; see also id. at 35,737 (“It is expected that for some areas of the country, such as 

parts of the eastern United States, emissions [reductions] achieved for the [CAA] acid rain 

program and for meeting the PM2.5 NAAQS, will lead to substantial improvements in visibility 

as well. .... We [i.e., EPA] expect that some States may be able to demonstrate reasonable 

progress based on these emissions [reductions] alone, particularly for the first 10-year [planning] 

period.”). 

Similarly, EPA states in the Reasonable Progress Guidance that “[g]iven the significant 

emissions reductions that we anticipate to result from BART, the [Clean Air Interstate Rule], and 

the implementation of other CAA programs, including the ozone and PM2.5 NAAQS, for many 

States this ... may be all that is necessary to achieve reasonable progress in the first planning 

period.” Reasonable Progress Guidance at 4-1; see id. at 5-1 (same). More broadly, the 

Reasonable Progress Guidance states that “[i]n deciding what amount of emissions reduction is 

appropriate in setting the RPG, you should take into account the fact that the long-term goal of 

no manmade [visibility] impairment encompasses several planning periods. It is reasonable ... to 

defer [emission] reductions to later planning periods in order to maintain a consistent glidepath 

toward the long-term goal.” Id. at 1-4. 

Accordingly, as the 1999 rule preamble and the Reasonable Progress Guidance indicate, no 

requirement exists to consider or adopt reasonable progress requirements that go beyond what is 

needed to meet the URP if the state (or EPA) decides to rely on consistency with the URP. 

Because it appears from the proposed rule that EPA fails to understand the breadth of discretion 

under the regional haze rule to rely on consistency with the URP, this aspect of EPA’s proposed 

rule is arbitrary, capricious, and unlawful and should be withdrawn. Cf. Prill v. Nat’l Labor

Relations Bd., 755 F.2d 941, 942 (D.C. Cir. 1985) (stating that “judicial deference is not 

accorded a decision of [an agency] when the [agency] acts pursuant to an erroneous view of law 

and, as a consequence, fails to exercise the discretion delegated to it by Congress”). 

Response: In 2012, EPA disapproved Arkansas’ reasonable progress determination and longterm strategy as submitted in their RH SIP as well as other elements related to BART.952 We are 

not reopening our partial disapproval of Arkansas’ SIP in this action. As explained in our prior 

action, Arkansas did not conduct a four factor analysis as is required under 51.3018(d)(i). Our 

decision to disapprove Arkansas reasonable progress determination was not challenged. 

 

952 See Proposed Rule: 76 FR 64186 (Oct. 17, 2011); Final Rule: 77 FR 14604 (March 12, 2012). 
504

As EPA is issuing a FIP, the relevant question is not whether EPA overstepped its authority in 

partially disapproving Arkansas’ regional haze SIP; the question is whether anything in the CAA 

or the 1999 Regional Haze Rule limits EPA’s authority to require additional controls beyond 

those needed to achieve the URP if such controls are considered reasonable based on a four 

factor analysis. See 51.308(d)(i)(A). As commenter notes, the preamble to the RHR makes clear 

that “if the State [or EPA] determines that additional progress is reasonable based on the 

statutory factors, the State [or EPA] should adopt that amount of progress as its goal for the first 

long-term strategy.”953 

We disagree with the commenter’s general characterization of the URP (or “glidepath”) or the 

conclusion that EPA anticipated that emissions reductions from other CAA programs could be 

relied on without further analysis to ensure reasonable progress. With respect to the URP, it is 

clear that this is an analytical requirement adopted by EPA to ensure that states carefully and 

transparently consider the reasonableness of the suite of controls needed to achieve that rate of 

progress in each Class I area. EPA developed this requirement in large part in response to 

concerns that our proposed presumptive rate of progress of 1 dv per 10 years that for some Class 

I areas would result in reaching the national goal in 200 years should not be considered 

reasonable. The rate of progress reflected in the URP is based on EPA’s conclusion that the 

emission reductions achieved by the CAA from the mid-1990s to about 2005 would result, on 

average, to improvements in visibility that, if sustained, would lead to attainment of the national 

goal in 60 years. EPA “concluded that it would be reasonable to establish an analytical 

requirement based on this rate of progress given that this rate of improvement is expected to be 

achieved due to emissions under CAA programs.”954 As the full quote makes clear, the URP is 

only an analytical requirement, not as suggested by the commenter, a safe harbor for states in 

developing their SIPs. 

The basis for commenter’s suggestion that this language in the preamble explains why Arkansas 

would not adopt a more aggressive RPG than the URP is unclear. EPA’s statement regarding 

emission reductions from other CAA programs in this context is a description of the emission 

reductions occurring between the mid-1990s and 2005 that if sustained would result in 

attainment of the national goal in 60 years, based on the average degree of impairment across all 

Class I areas. EPA was not suggesting that states could therefore delay the adoption of 

reasonable measures to avoid reaching the national goal more quickly. Nothing in the record for 

the regional haze rule supports a conclusion that attaining natural conditions before 2064 would 

be unreasonable. The commenter also cites to language indicating EPA’s belief that future 

emission reductions resulting from the strategies to ensure compliance with the NAAQS and 

other CAA programs might constitute reasonable progress in some states. We note that in 

considering the appropriate reasonable progress measures for Arkansas, EPA has taken into 

account the extent to which CAA programs have reduced emissions from the largest point 

sources of SO2 and NOx emissions in Arkansas; as explained in the preamble to our proposed 

rule, three sources in Arkansas – White Bluff, Independence, and Flint Creek - make up a large 

majority of the SO2 point source emissions (84%) and a large proportion of the NOx point 

source emissions (55%). Unlike in some states, where other programs under the CAA have 

resulted in significant emission reductions, emissions from these three sources have not 

 

953 64 FR at 35732. 954 64 Fed. Reg. at 35,732.
505

substantively changed since the baseline date of the SIP. Thus, EPA’s general predictions that 

some states may be able to rely on measures to comply with CAA programs to make reasonable 

progress does not support a conclusion that the reasonable progress measures in our FIP are 

either unnecessary or unreasonable. 

 As EPA has concluded that additional controls are reasonable, we are including these measures 

in our FIP. EPA’s reasonable progress analysis is explained more fully in the reasonable 

progress section of the RTC. 

Comment: Two separate legal authorities require that EPA determine that scrubber 

installation at Independence Units 1 and 2 is necessary to meet the regional haze 

requirements. [Sierra Club et. al. (0171) p. 31, 33-34] Sierra Club et. al. stated that the final rule 

should find that reasonable progress requires the Entergy Independence plant to meet an SO2

emission limit of 0.04 based on the use of a scrubber. Two separate legal authorities require this 

conclusion, and thus EPA has two independent grounds for requiring the Independence plant to 

install and operate a scrubber under the reasonable progress provisions. 

First, EPA should require a scrubber under the reasonable progress analysis required to 

set the reasonable progress goals for Caney Creek and Upper Buffalo. See 42 U.S.C. § 

7491(g)(1), 40 C.F.R. § 51.308(d)(1). 

Second, EPA should require a scrubber as part of the long-term strategy that must include the 

emissions reductions necessary to meet the reasonable progress goals for Class I areas in other 

states affected by the Independence plant’s emissions, namely, Hercules-Glades and Mingo in 

Missouri. See 40 C.F.R. § 51.308(d)(3). Each state’s plan “must include enforceable emissions 

limitations . . . and other measures as necessary to achieve the reasonable progress goals 

established by states having mandatory Class I areas.” Id. Similarly, each state must demonstrate 

that its plan contains the measures “necessary to obtain its share of the emission reductions 

needed to meet the progress goal for the area.” Id. § 51.308(d)(3)(ii). EPA interprets these 

provisions as requiring a state to include the emissions reductions necessary to meet the 

approved or approvable reasonable progress goals for out-of-state Class I areas. 79 Fed. Reg. at 

74,828-30. Arkansas was obligated to consult meaningfully with Missouri, id. § 51.308(d)(3)(i), 

which includes providing Missouri with the technical information necessary to determine 

whether the implementation of reasonable control measures in Arkansas would improve 

visibility in Missouri’s Class I areas. 

Arkansas and Missouri consulted during the development of their respective plans. However, 

Arkansas neither considered nor proposed reasonable progress controls for the Independence 

plant. As a result, Arkansas did not provide Missouri with information on available future 

controls at Independence Units 1 and 2. EPA disapproved Arkansas’s reasonable progress 

analysis because it did not comply with applicable requirements. 

The regulations required Arkansas to “document the technical basis . . . on which the State is 

relying to determine its apportionment of emission reduction obligations necessary for achieving 

reasonable progress in each mandatory Class I Federal area it affects.” 40 C.F.R. 

51.308(d)(3)(iii). “This documentation is necessary so that the interstate consultation process can 
506

proceed on an informed basis.” 80 Fed. Reg. at 74,829. Here, Arkansas failed to properly 

document its portion of reductions necessary to achieve reasonable progress in Missouri’s Class I 

areas because Arkansas never properly developed this information in the first place—as 

evidenced by EPA’s disapproval of Arkansas’s analysis of reasonable progress. Thus, Missouri 

developed its reasonable progress goals for Hercules-Glades and Mingo based on Arkansas’s 

reasonable progress analysis that was so deficient that EPA disapproved it. 

EPA addressed a similar situation in the proposed Texas plan, noting that there may be situations 

where “the [reasonable progress] goal itself is flawed precisely because the upwind state never 

proposed sufficient control measures to ensure reasonable progress in the first place.” 80 Fed. 

Reg. at 74,829. After acknowledging the problem, EPA proposed a solution: “where a RPG in a 

downwind state’s SIP does not account for adequate visibility improvement from an upwind 

state for this reason, we must disapprove both the downwind state’s goal and the upwind state’s 

long-term strategy.” Id. 

EPA should remedy the deficiency in Missouri’s reasonable progress goals, which resulted from 

a consultation in which Arkansas failed to provide Missouri with a proper analysis of available 

future controls on Arkansas sources that impact Missouri’s Class I areas. The Independence plant 

has large baseline impacts at the Hercules-Glades Wilderness Area and Mingo National Wildlife 

Refuge in Missouri. Installing and operating a scrubber at the Independence plant would improve 

visibility by 1.056 deciviews at Hercules-Glades and 0.871 deciviews at Mingo, 80 Fed. Reg. at 

18,994, at a reasonable cost of less than $3,000 per ton of SO2 removed. Id. at 18,993; see also 

Stamper Report at 63. Given that a scrubber meets all of the four reasonable progress factors, the 

reasonable progress goals for Hercules-Glades and Mingo must reflect operation of a scrubber at 

the Independence plant. Reasonable progress goals for Hercules-Glades and Mingo that do not 

reflect the reductions from a scrubber at Independence are not approvable;955 for the same 

reason, an Arkansas plan that does not require a scrubber at Independence is not approvable 

under 40 C.F.R. § 51.308(d)(3). 

In sum, EPA has two separate legal bases for requiring Independence Units 1 and 2 to install and 

operate a scrubber to achieve a SO2 emission limit of 0.04 lb/MMBtu. First, consideration of the 

reasonable progress factors indicates that a scrubber is a reasonable control measure at 

Independence Units 1 and 2 and thus the reasonable progress goals for Caney Creek and Upper 

Buffalo should reflect operation of scrubbers at Independence. The long-term strategy for 

Arkansas must require operation of a scrubber at Independence Units 1 and 2 in order to meet the 

reasonable progress goals for Caney Creek and Upper Buffalo. Second, the reasonable progress 

goals for Hercules-Glades and Mingo must reflect operation of a scrubber at both Independence 

units, and therefore Arkansas’s long-term strategy must require scrubbers in order to achieve the 

reasonable progress goals for Hercules and Mingo. 

 

955 While EPA has already approved the reasonable progress goal that Missouri developed for Hercules-Glades and 

Mingo, it did so prior to proposing a FIP for Arkansas. Thus, when EPA acted on Missouri’s SIP, the agency did not 

have before it a proper and approvable analysis of achievable emissions reductions at Arkansas sources that impact 

Missouri Class I areas. EPA should ensure that the Missouri RPGs are revised to remedy the deficiencies in the 

consultation process and in Arkansas’s long-term strategy. See 40 C.F.R. § 51.308(d)(3)(i)(iii). 
507

Response: We take no position on the legal rationale that commenter cites. Our legal and 

technical rationale for requiring controls under reasonable progress for the Independence facility 

at Units 1 and 2 is discussed in the reasonable progress section of the response to comments. 

8.d. States have a leading role and discretion under the Regional Haze cooperative 

federalism 

Comment: The Regional Haze program is built on principles of cooperative federalism that 

require EPA to defer to states in developing SIPs. [Nucor Steel-Arkansas and Nucor-Yamato 

Steel (0163) p. 5-6, 9-12; and Arkansas Electric Energy Consumers Inc. and Arkansas Gas 

Consumers Inc. (0175) p. 3-5] 

AEEC/AGC stated that Congress amended the Clean Air Act (“CAA”) in 1977 to include the 

national goal of remedying any impairment of visibility at mandatory Class I Federal areas 

(“Class I areas”). Two of these Class I areas are located in Arkansas: the Upper Buffalo and 

Caney Creek Wilderness Areas. In 1999, when it promulgated the Regional Haze Rule, the EPA 

established regulations to eliminate man-made visibility impairment in these Class I areas by 

2064. On September 23, 2008, the ADEQ submitted the Arkansas Regional Haze State 

Implementation Plan (“Arkansas SIP”) to the EPA. Over three years later, on March 12, 2012, 

the EPA partially approved and partially disapproved the Arkansas SIP.956 Despite the EPA’s 

partial disapproval of the Arkansas SIP in 2012, ADEQ recently submitted a Five-Year Regional 

Haze Progress Report to the EPA, to fulfill the requirement in 40 C.F.R. § 51.308(g) that 

Arkansas provide periodic reports to the EPA evaluating its progress towards the Reasonable 

Progress Goals (“RPGs”). The EPA promulgated the Proposed FIP on April 8, 2015.957

Nucor and AEEC/AGC stated that EPA's disapproval of the Arkansas Regional Haze SIP 

together with its decision to initiate this rule-making and impose the proposed FIP far exceeds 

EPA's legal authority under the Clean Air Act. EPA's actions improperly transform the structure 

of the regional haze program from a state-driven program grounded in cooperative federalism to 

a centrally controlled, federally managed program with no meaningful role for the states, 

regulated entities, or in the case of electric public utilities, the end users and consumers who 

ultimately will bear the brunt of and have to pay for EPA's determinations. Nothing in the Clean 

Air Act or the administrative record supports EPA's determination that mandates the installation 

of over $2 billion in new emission controls on public utility electric generation resources that 

have significant social and economic value in and to the State of Arkansas.

Nucor and AEEC/AGC stated that the Clean Air Act, including the regional haze program, is 

built on principles of cooperative federalism that require EPA to defer to states in developing 

implementation plans so long as necessary statutory requirements are met, and it sets forth 

specific time limits for action by both the States and EPA. EPA v. EME Homer City Generation, 

L.P., 134 S.Ct. 1584, 1600 (2014). EPA's Proposed FIP ignores those limits and timelines and 

would impose a plan that ignores the primary implementation role given to Arkansas. Not only is 

 

956 77 Fed. Reg. 14604. 957 80 Fed. Reg. 18944.   
508

EPA's approach inconsistent with the Clean Air Act, it gives EPA power to arbitrarily substitute 

its own judgment for that of a state at virtually any stage of the implementation process. 

As courts have recognized, the Clean Air Act was intended by Congress to be “a model of 

cooperative federalism.” Sierra Club v. Korleski, 681 F.3d 342, 343 (6th Cir. 2012); Michigan v. 

EPA, 268 F.3d 1075, 1083 (D.C. Cir. 2001); Florida Power & Light Co. v. Costle, 650 F.2d 579, 

581 (5th Cir. 1981). Under this structure, Congress specifically found that “air pollution 

prevention ... is the primary responsibility of States and local governments.” 42 U.S.C. 

§7401(a)(3). The Eighth Circuit recently noted that "the [Clean Air Act] grants states the primary 

role in determining the appropriate pollution controls within their borders." North Dakota v. 

EPA, 730 F.3d at 760-61. Thus, "states have broad authority to determine the methods and 

particular control strategies they will use to achieve the statutory requirements." BCCA Appeal 

Group v. EPA, 355 F.3d 817, 822 (5th Cir. 2003). Specifically, the states have "broad authority 

over BART determinations." American Corn Growers v. EPA, 291 F.3d 1, 8(D.C.Cir. 2002). 

EPA's role is limited to ensuring that the States' implementation is consistent with the CAA. 

Florida Power & Light, 650 F.2d at 587 (“The great flexibility accorded the states under the 

Clean Air Act is ... illustrated by the sharply contrasting, narrow role to be played by EPA.”). 

Nucor stated that rather than establishing strict implementation requirements, EPA's rule 

“requires States to determine the rate of progress for remedying existing impairment that is 

reasonable, taking into consideration the statutory factors, and the informed input from all 

stakeholders.” 64 Fed. Reg. at 35,731; see also 40 C.F.R. § 51.308(d)(1)(i)(A). In its guidance to 

States, EPA emphasized that the regional haze rule “gives States wide latitude to determine 

additional control requirements” and, in applying the required statutory factors, the states “have 

flexibility in how to take into consideration these statutory factors and any other factors that you 

have determined to be relevant.” USEPA, “Guidance for Setting Reasonable Progress Goals 

Under the Regional Haze Program,” June 1, 2007, p. 4-2, 5-1 [emphasis supplied]. Thus, EPA 

has explained that “[a]s long as this evaluation is done adequately and the States provide a 

reasoned basis for their decision, EPA will defer to the state.” 77 Fed. Reg. 40,150, 40,156 (July 

6, 2012). 

Nucor and AEEC/AGC stated that in the Proposed FIP, EPA ignores these well-established 

principles of cooperative federalism, disregards the right of the State of Arkansas to make BART 

and Reasonable Progress decisions, and imposes a radically different implementation plan based 

on its own independent analysis. This over-reaching is contrary to the Clean Air Act and is 

unlawful. This hijacking of Arkansas’ primary authority to implement the regional haze program 

exceeds the EPA’s authority under the CAA. 

Nucor stated that even in its over-reaching, the EPA is held to the same standards as state 

agencies to not act arbitrarily and capriciously, to make decisions based on sound reasoning, to 

take into account important and relevant factors, and to act within the scope of statutory 

authority, which includes demonstrating that EPA's determinations are "necessary" to achieve the 

requirements of 42 U.S.C. §7491. EPA has not done so. 
509

Response: As noted above, we previously determined that portions of the Arkansas SIP do not 

meet certain elements of the Federal regional haze requirements, and we identify and discuss 

those portions in our final action on the Arkansas RH SIP.958 We are not reopening our partial 

disapproval of the Arkansas regional haze SIP. 

We do not agree with the commenter’s characterization of our action. Our action does accord 

with the CAA. Congress crafted the CAA to provide for States to take the lead in developing 

implementation plans, but also required EPA to review SIPs for compliance with statutory and 

regulatory requirements. We recognize that States have the primary responsibility of drafting an 

implementation plan to address the requirements of the regional haze program. We also 

recognize that we have the responsibility of ensuring that the State plans, including Regional 

Haze SIPs, conform to the CAA requirements. We do not agree with the commenter that EPA is 

ignoring the principles of cooperative federalism. The Clean Air Act provides that if a state plan 

is disapproved, EPA is required, within two years of the effective date of the final federal register 

notice disapproving the state plan, to approve a state SIP revision submittal that corrects the 

deficiency or promulgate a FIP. During this two-year time frame, states have the opportunity to 

submit a corrected SIP for review and approval by EPA. However, the Clean Air Act creates an 

end point in a state meeting the requirements of the CAA through an approved plan, by creating 

a mandatory duty for EPA to either approve the state SIP submissions or issue a FIP. 

 

That is what has happened for the Arkansas RH and Visibility IT SIP. Here, Arkansas submitted 

to EPA for approval a SIP revision to address the requirements of RH and Visibility IT. As 

explained in an earlier response to comments, in 2012, EPA, after notice and comment, finalized 

rulemaking partially approving and disapproving the Arkansas RH and Visibility IT SIP. While 

we did receive adverse comments on the rulemaking, no party, including the state, filed a lawsuit 

challenging our partial approval and disapproval. After our disapproval, EPA worked with 

Arkansas to develop a revised SIP to address the elements we disapproved. Two years elapsed 

and EPA was sued for failing to either approve or issue a FIP to address the elements we 

disapproved on the submitted Arkansas regional haze SIP. With Arkansas as a party, a district 

court judge ordered EPA to either approve a revised SIP submittal from Arkansas or finalize a 

FIP for the elements we disapproved by August 31, 2016. That order is included in the docket to 

this rulemaking action. To date, EPA has not received a revised SIP for RH.959

Comment: The Associations provide a summary of the Regional Haze program and state 

that EPA should respect the primacy role Congress assigned to states in determining the 

best path of reasonable progress. [The Associations (0165) p. 3-5] The Associations stated that 

in recognition of diminished visibility at national parks and other scenic areas, Congress enacted 

the Clean Air Act’s regional haze provisions with a long-term goal of improving the state of 

visibility. Regional haze is the “impairment of visual range or coloration caused by emissions of 

air pollution produced by numerous sources and activities, located across a broad regional area.” 

 

958 77 FR 14604. 959 EPA also partially disapproved Arkansas’ visibility transport SIP addressing the requirements of CAA section 

110(a)(2)(D)(i)(II) for the 1997 8-hour ozone and PM2.5 NAAQS in the same action in which we acted on 

Arkansas’ regional haze SIP. We are also addressing our obligation to address the deficiencies identified in the 

transport SIP in today’s action. 
510

77 Fed. Reg. 30,248, 30,249 (May 22, 2012). Congress first adopted regional haze provisions in 

1977 to address haze issues in national parks and other federal “Class I areas” by adding Section 

169A to the Clean Air Act. See 42 U.S.C. § 7491. 

At the same time, however, Congress realized such changes could not be fully realized rapidly 

and adopted an approach by which States would make incremental improvements over time. 

Section 169A requires EPA to “promulgate regulations to assure ... reasonable progress toward 

meeting the national goal” of visibility. 42 U.S.C. § 7491(a)(4). EPA has established three 

primary components for a State’s regional haze implementation plan: (1) reasonable progress 

goals (“RPGs”) for Class I areas in the State; (2) a long-term strategy; and (3) implementation of 

BART for certain stationary sources. Through this program, each state charts a “Glidepath” 

towards natural visibility at the Class I areas within their borders by 2064. States then are 

provided significant flexibility in crafting the emission reductions necessary for meeting that 

Glidepath by assessing reasonable progress goals at regular planning period intervals. 

Reasonable progress goals are therefore “interim goals that represent incremental visibility 

improvement over time.” EPA, Guidance for Setting Reasonable Progress Goals Under the 

Regional Haze Program (June 1, 2007) (“RPG Guidance”) at 1-2. 

Due to the array of options to meet these goals, and the co-benefits of reducing visibility 

impairments through other Clean Air Act programs, Congress intended states to have 

extraordinary flexibility in determining how they meet reasonable progress goals. See North

Dakota v. EPA, 730 F.3d 750, 768 (8th Cir. 2013) (the Regional Haze program “requires only 

that a state establish reasonable progress, not the most reasonable progress.”). Reasonable 

progress goals for Class I areas are based on four factors: (1) “costs of compliance;” (2) “the 

time necessary for compliance;” (3) “the energy and nonair quality environmental impacts of 

compliance;” and (4) “the remaining useful life of any potentially affected sources.” 42 U.S.C. 

§ 7491(g)(1). States are not obliged to reduce emissions from any type of source in particular and 

EPA acknowledges that states may not need any additional emission reductions for some 

planning periods. See EPA, Additional Regional Haze Questions, at 9 (Sept. 26, 2009) 

(“Reasonable progress is not required to be demonstrated on a source-by-source basis.”); RPG 

Guidance at 4-1 (“Given the significant emissions reductions that we anticipate to result from 

BART” and other Clean Air Act programs “it may be all that is necessary to achieve reasonable 

progress in the first planning period for some States.”). Through the state’s consideration of these 

factors, each Class I area need only make incremental progress through reasonable, cost-effective 

means. 

Perhaps more than any other program under the Clean Air Act, the Regional Haze program 

provides states with the leading role in exercising their discretion regarding how they meet 

reasonable progress goals for the Class I areas within their borders. Despite Congress’ intention 

for states to have primary responsibility in implementing the program within their borders, EPA 

arbitrarily disapproved Arkansas’ Regional Haze State Implementation Plan in 2012, 77 Fed. 

Reg. 14,604 (Mar. 12, 2012), and issued the proposed rule as a federal regional haze implemental 

plan in its place. 

Beyond the strict violations of the Clean Air Act in EPA’s approach described below, the 

Associations are concerned this is a further instance in a disturbing trend of EPA disregarding 
511

the considerable discretion Congress assigned to states in the Clean Air Act and inappropriately 

substituting its own judgment in areas that are local in nature, state-specific, and incredibly 

complex. EPA justifies many of these disapprovals by amorphous demands for “additional 

analysis,” disagreements over modeling details, minor divergences in cost considerations, or 

simply EPA’s opinion that it believes states should have done more than what the Regional Haze 

program requires. This is not only inconsistent with the specific Clean Air Act provisions, but 

violates the prominent role Congress assigned to states in the system of cooperative federalism 

throughout the Act. 

Ultimately, states are in the best position to make these determinations, as Congress recognized. 

Each state invests significant time and resources working with its neighboring states to 

understand out-of-state influences on visibility impairment and managing its own federal and 

state programs to enact a careful balancing act. This balancing act carefully considers the 

expected emission reductions from existing programs, emission reductions through BART, and 

several other emission reduction options to find the most efficient and affordable means of 

meeting federal requirements. As EPA has recognized, at least at the outset of the Regional Haze 

program, Congress intended to “provide States considerable discretion in establishing reasonable 

progress goals for improving visibility in Class I areas.” EPA, Response to Petition for 

Reconsideration of Regional Haze Rule 11 (Jan. 10, 2001); RPG Guidance at 4-2 (states have 

“wide latitude to determine additional control requirements”); id. at 5-1 (states “have flexibility 

in how to take into consideration these statutory factors and any other factors that you have 

determined to be relevant”). EPA has acknowledged that, so long as states consider the statutory 

factors required by the Regional Haze program and “provide a reasoned basis for their decision, 

EPA will defer to the state” with respect to reasonable progress determinations. 77 Fed. Reg. 

40,150, 40,156 (July 6, 2012). Yet, as is becoming increasingly common and problematic, EPA 

is ignoring this deference under the Regional Haze program. 

Fulfilling the role intended by Congress, states have a successful and demonstrated track record 

in creating the real-world, measured visibility improvements Congress envisioned under the 

Regional Haze program. It is increasingly troubling that EPA appears eager to disapprove state 

implementation plans in order to substitute its own judgment on matters affecting not just 

technical details, but state regulatory and economic concerns. EPA’s intrusion into these areas 

has frequently led to costly and unnecessary burdens on state industries while failing to deliver 

any demonstrable visibility improvements to Class I areas over what states would have achieved. 

In most instances, EPA’s stated rationale for imposing millions (or billions) of dollars in 

additional costs yield visibility improvements that cannot be perceived by the human eye. EPA’s 

pattern of second-guessing the reasoned decisions of expert state agencies is not only 

economically wasteful, but it contravenes the state primacy that is the Regional Haze program’s 

core characteristic. 

For these reasons, the Associations urge EPA to reset its approach to Regional Haze and respect 

the primacy role that Congress assigned to the states in determining the best path of reasonable 

progress taking into account unique local circumstances to realize visibility improvements. EPA 

has failed to demonstrate any rational grounds to supplant its own judgment for Arkansas’ and, 

as described below, lacks the legal authority to impose the proposed controls here. 
512

Response: Please see our above responses which address EPA’s authority and obligation to 

promulgate a FIP that satisfies the requirements of the Regional Haze Program when a state fails 

to submit a plan which meets the program’s requirements. In addition, EPA’s action today 

finalizing the proposed rule to address the submitted Arkansas regional haze SIP (and visibility 

transport SIP we disapproved in 2012) is in keeping with Congressional intent on the roles 

prescribed for states and EPA under the Clean Air Act. As explained earlier, EPA reviewed 

Arkansas’ submitted regional haze and visibility Interstate Transport SIP and partially approved 

and disapproved through notice and comment rulemaking. EPA received comments on that 

action and we addressed them in our final rulemaking in 2012. No party challenged us in court 

on the rulemaking within 60 days of publication and the effective date of the final federal register 

notice disapproving the state action started the two year clock by which EPA is required to act 

under the Clean Air Act to either approve a revised SIP from Arkansas that corrects the 

deficiencies or promulgate a FIP. During the two-year period, EPA met with Arkansas on 

revising the SIP. After the two years elapsed, EPA was sued by Sierra Club for failure to meet 

our mandatory duty to act to address the disapproved elements of RH and Visibility IT by either 

approving a SIP or promulgating a FIP. In that mandatory duty suit, the state of Arkansas 

intervened and participated in the judicial proceedings whereby the judge ordered EPA to either 

approve a SIP or promulgate a FIP by August 31, 2016. To date, we have not received a revised 

SIP to address the disapproved elements for RH and Visibility IT. We have undergone notice 

and comment rulemaking in order to meet our August 31, 2016 court ordered rulemaking 

deadline. 

Comment: [Edison Electric Institute (0174) p. 2, 6] EEI stated that delaying consideration of 

additional controls for the Independence units also is justified by the statutory context of the 

regional haze program, which is designed to respect the cooperative federalism principles 

embedded in the CAA. These principles gives states, and not EPA, the primary role in 

determining how best to regulate emissions sources within their borders. Arkansas has 

determined that controls for these units are not needed to achieve the URP goals for this first 

period. Arkansas’s SIP works: the URP goals are being met for this first period. 

EPA claims the authority to require more than reasonable progress under the guise that the RHR 

does not provide a “safe harbor” for units. See 80 Fed. Reg. at 18,992. This is misleading. Not 

regulating the Independence units during the first period does not insulate them from 

consideration by the state as it moves forward with its next SIP, covering the second planning 

period. Further, it is a weak justification for setting the concerning precedent that EPA can 

override reasonable state SIPs, in contravention of the cooperative federalism embodied in the 

Clean Air Act and the RHR. 

Response: Our legal and technical rationale for requiring controls under reasonable progress for 

the Independence facility at Units 1 and 2 in the first planning period is discussed in the 

reasonable progress section of this RTC document. See our above responses concerning the 

roles of states and EPA and the role of the URP. Our proposed and final rules assessing the 

Arkansas regional haze SIP provide additional background information regarding our prior 

partial disapproval of sections of Arkansas’ SIP addressing reasonable progress in which 

Arkansas did not conduct a four factor analysis as required under the RHR, 51.308(d)(1).76 FR 

64186 (Oct. 17, 2011)(proposed rule); 77 FR 14604 (March 12,2012) (final rule).That action 
513

underwent notice and comment pursuant to the Administrative Procedures Act and no party 

challenged the rulemaking within the required 60 days after the publication date of the final 

federal register notice. To address reasonable progress, EPA did the four-factor analysis for 

Arkansas two class I areas as required under the RHR. It is speculative and not germane as to 

whether Arkansas would have the same RPG if they conducted a four factor RPG analysis in 

accordance with 51.308(d)(1). EPA is undergoing notice and rulemaking for Arkansas’ two 

Class I areas RPGs simply because we are under a court order deadline to either approve a state 

revised SIP or promulgate a FIP. Since we do not have a SIP before us, we are undergoing 

notice and comment rulemaking in order to comply with a court ordered deadline. 

As discussed in the preamble to our proposed FIP, the URP does not establish a “safe harbor” for 

the state in setting its reasonable progress goals.960 Rather, regardless of the amount of the 

visibility improvement anticipated from the implementation of other CAA programs, BART, or 

forecasted levels of economic activity, a state (or EPA) must provide a reasoned analysis to 

support its determination as to appropriate reasonable progress measures for its regional haze 

SIP. As explained elsewhere in this document, we have concluded that control measures for 

Independence --the second largest source in Arkansas of SO2 and NOx –should be included in 

our FIP. We agree with the commenter that sources not controlled for reasonable progress in 

implementation plans for this first planning period may be controlled in later planning periods. 

The conclusion that measures might be adopted at some point in the future, however, does not by 

itself support a decision to put off measures to some future planning period. As EPA is issuing a 

FIP, we have considered the appropriateness of additional measures on Arkansas sources to 

ensure reasonable progress, and as explained elsewhere, reached the conclusion that SO2 and 

NOX control measures for Independence should be included in the FIP for this planning period. 

8.e. EPA does not have authority to finalize the FIP at this time 

Comment: [Nucor Steel-Arkansas and Nucor-Yamato Steel (0163) p. 13-16; Arkansas Electric 

Energy Consumers Inc. and Arkansas Gas Consumers Inc. (0175) p. 5-7] Nucor and AEEC/AGC 

both stated that Section 110(c)(1) of the CAA (42 U.S.C. §7410(c)(1)) states: 

The Administrator shall promulgate a Federal implementation plan at any time within 2 

years after the Administrator — 

(A) Finds that a State has failed to make a required submission or finds that the plan or 

plan revision submitted by the State does not satisfy the minimum criteria established 

under section 110(k)(1)(A), or 

(B) Disapproves a State implementation plan submission in whole or in part, unless the 

State corrects the deficiency, and the Administrator approves the plan or plan revision 

before the Administrator promulgates such Federal implementation plan. [Emphasis 

supplied]. 

 

960 80 Fed. Reg. at 18992. 
514

EPA partially disapproved the Arkansas Regional Haze SIP on March 12, 2012 (77 Fed.Reg. 

14604); however, EPA did not take any action to issue a FIP during the two year period after that 

disapproval. Not until April 8, 2015, more than three years after EPA's disapproval of the 

Arkansas SIP, did EPA even publish notice of its Proposed FIP in the Federal Register (80 

Fed.Reg. 18944). 

The plain language of §110(c)(1) limits EPA to a two year time-limit to issue a FIP.961 By 

initiating this rule-making and issuing its Proposed FIP after that time, EPA impermissibly 

ignores and does not give effect to the words “within 2 years.” Statutes must be construed in a 

manner that gives effect to every word. 

In EPA v. EME Homer City Generation, L.P., 572 U.S., 134 S.Ct. 1584 (2014), the Court 

examined section 110(c)(1), and held that because the clear language of that section allowed 

EPA to file a FIP “at any time” within the two year FIP deadline, EPA did not have to first allow 

states to issue SIPs under the Cross-State Air Pollution Rule (“CSAPR”). The lower court had 

held that the CAA required EPA to give states a reasonable period of time to comply with the 

reductions under the CSAPR rule, but the Supreme Court reversed. The Court stated: 

[T]he CAA sets a series of precise deadlines to which the States and EPA must 

adhere... If EPA determines a SIP to be inadequate, the Agency's mandate to replace 

it with a FIP is no less absolute.... In other words, once EPA has found a SIP 

inadequate, the Agency has a statutory duty to issue a FIP “at any time” within two 

years... The D.C. Circuit, however, found an unwritten exception to this strict time 

prescription for SIPs aimed at implementing the Good Neighbor Provision.... 

However sensible (or not) the Court of Appeals position a reviewing court's “task is 

to apply the text [of the statute], not to improve upon it.... The Act empowers the 

Agency to promulgate a FIP “at any time” within the two-year limit.... Carving out 

an exception to the Act's precise deadlines, as the D.C. Circuit did, “rewrites a 

decades-old statute whose plain text and structure establish a clear chronology of 

federal and State responsibilities.” The practical difficulties cited by the Court of 

Appeals do not justify departure from the Act's plain text... We “must presume that a 

legislature says in a statute what it means and means in a statute what it says there.” 

EME Homer, 134 S.Ct. at 1600-1601 (internal citations omitted). 

Congress clearly intended to give the states the primary authority to make BART and Reasonable 

Progress decisions. American Corn Growers v. EPA, 291 F.3d 1(D.C.Cir. 2002); North Dakota 

v. EPA, 730 F.3d 750 (8th Cir. 2013). In implementing SIPs, States cannot wait indefinitely for 

EPA to act on State submissions or to belatedly issue FIPs; consequently, in section 7410(c)(1) 

Congress set a two year limit on EPA's ability to issue a FIP after a SIP disapproval. The State of 

Arkansas has given EPA assurances that it will continue to work to address the concerns raised 

 

961 EPA has previously recognized this limitation. See, 79 Fed.Reg. 29354, 29356 (May 22, 2014) (“CAA section 

110(c) provides that EPA can promulgate a FIP immediately after making the finding of failure to submit a required 

SIP, as late as two years after making the finding, or any time in between.” [emphasis supplied]) Furthermore, EPA's 

Region 6 office also recognized that the two year deadline for an Arkansas RHR FIP had passed. See, internal EPA 

email dated May 9, 2014, attached as Exhibit 4 to Nucor’s comments. 
515

by EPA in its March 12, 2012 disapproval.962 EPA’s Proposed FIP should be withdrawn so that 

the State of Arkansas can revise its RH SIP in accordance with the requirements of the CAA. 

Response: Section 110(c)(1) of the Clean Air Act does not release EPA from its statutory 

mandate to promulgate a FIP or approve a state SIP after the elapse of two years. Oklahoma v. 

EPA, 723 F.3d 1201 (10th Cir. 2013), cert. denied (U.S. May 27, 2014)(EPA’s authority to 

promulgate a FIP is not subject to a two year time limit). The appropriate remedy for EPA’s 

failure to act within two year is to seek an order compelling agency action. The Eastern District 

of Arkansas agreed and ordered EPA to promulgate a FIP or approve a SIP submittal addressing 

the disapproved portions of the Arkansas’ regional haze and visibility transport SIP by August 

31, 2016. 

8.f. EPA must address E.O. 12866 and 13211 

Comment: EPA must address the requirements of Executive Orders 12866 and 13211. 

[Entergy Arkansas Inc. (0166) p. 55-56] Entergy Arkansas Inc. stated that EPA claims that the 

Proposal is not a “significant regulatory action” under Executive Order 12866. 80 Fed. Reg. at 

18,999. Entergy disagrees. The Proposal’s implementation cost to EAI alone of over $2 billion 

exceeds the $100 million threshold for economic significance. “By virtue of [the] longstanding 

Executive Order [12866] applying to significant rules issued under the Clean Air Act (as well as 

other statutes), the Agency must systematically assess the regulation’s costs and benefits.” 

Michigan v. EPA, 135 S.Ct. at 2715 (Kagan, J. dissenting). EPA states that the Proposal is not 

generally applicable, and therefore not subject to Executive Order 12866, because the rule “only 

proposes source specific requirements for particular, identified facilities (six total).” 80 Fed. Reg. 

at 18,999. However, a count of the number of entities regulated under a rule is not indicative of 

the general applicability or the significance of the economic impacts of the rule. Requiring 

additional controls at power plants initiates a cascade of impacts, including changes in the 

regional distribution of electricity and rates of thousands of electricity customers in multiple 

states. These far-reaching impacts merit classifying the Proposed FIP as a regulation with general 

applicability and significant economic impact. 

Entergy also disagrees with EPA’s conclusion that the Agency is not required to assess the 

energy impacts of the Proposed FIP under Executive Order 13211. 80 Fed. Reg. at 19,000. The 

Proposal will have a significant impact on the supply, distribution, and use of energy. 

Installation of additional controls will require outages at multiple power plants, altering the 

normal supply and distribution of energy. Additionally, the more than $2 billion cost of 

implementing the Proposed FIP will be imposed upon EAI’s customers and co-owners, 

impacting energy use as electricity rates climb. 

EPA must prepare a cost/benefit analysis and evaluate the energy impacts of the 

Proposed FIP and issue these analyses for public comment before finalizing the FIP. 

 

962 See Exhibit 3 to Nucor’s comments, Arkansas RHR Five Year Progress Report, transmittal letter to Hon. Ron 

Curry, EPA, Region VI Regional Administrator. 
516

Response: We disagree with the commenter’s interpretation of Executive Orders (“E.O.”) 12866 

and 13211. E.O. 12866 defines “regulations” or “rules,” as “an agency statement of general 

applicability and future effect.” An “agency statement of general applicability” refers to 

statements that apply to groups or classes of entities, as opposed to a regulation or rule which 

applies only to named entities. Our FIP is not, therefore, a rule of general applicability because 

its requirements apply and are specifically tailored to six individually identified facilities. Thus, 

it is not a “rule” or “regulation” within the meaning of E.O. 12866 and this action is not a 

“regulatory action” subject to 12866. As E.O. 13211 applies only to “significant regulatory 

actions” under E.O. 12866, this action is not subject to review under E.O. 13211.963 Evaluation 

of the proposal under E.O. 13211’s criteria is therefore not required. It should be noted that the 

agency action which was at the center of the Supreme Court’s opinion in Michigan v. EPA, was a 

regulatory action within the meaning of E.O. 12866. The action was applicable to all EGUs 

meeting certain requirements, as opposed to specifically identified entities. 

We note that because the commenter provided only conclusory speculations concerning energy 

impacts and grid reliability concerns with no data, we cannot speculate on how our rulemaking 

will affect the distribution of electricity or electric rates. 

Comment: EPA has failed to comply with the requirements under Executive Order 12866 

and 13211. [ADEQ (0160) p. 24-28] ADEQ stated that EPA asserts that its Proposed FIP is not a 

“significant regulatory action” within the meaning of Executive Order 12866 (“E.O. 12866”).964

However, the proposed FIP would result in substantial and material costs being transferred onto 

Arkansas communities through increased electricity rates due to the installation of costly control 

equipment at affected EGUs. This is a material adverse effect, which renders the Proposed FIP 

subject to the requirements of E.O. 12866. EPA has not complied with the requirements of E.O. 

12866, and the Proposed FIP should be withdrawn until such time as requirements of this 

executive order have been met. 

Under E.O. 12866, a “significant regulatory action” is subject to certain review requirements by 

the Office of Information and Regulatory Affairs (“OIRA”), which is a subdivision the Office of 

Management & Budget (“OMB”).965 For each significant regulatory action under E.O. 12866, 

OIRA must be provided with a copy of the draft regulation, together with a reasonably detailed 

description of the need for the regulatory action, and an explanation of how that action will meet 

that need.966 In addition, the relevant agency must provide OIRA with an assessment of the costs 

and benefits of the regulatory action as well as the costs and benefits of reasonably feasible 

alternatives for each significant regulatory action.967 By issuance of E.O. 13563 on January 18, 

2011, the sitting President reaffirmed “the principles, structures, and definitions governing 

contemporary regulatory review that were established in Executive Order 

12866 of September 30, 1993, were re-affirmed.968

 

963 79 FR 74890. 964 80 FR 18944 at 19000. 965 Exec. Order No. 12866, 58 FR 51735, (Sept. 30, 1993). 966 Id. at Sec. 6(a)(1)(B) 967 Exec. Order No. 12866, 58 FR 51735, Sec. 6(c), (Sept. 30, 1993). 968 Exec. Order No. 13563, 76 FR 3821, (Jan. 18, 2011) 
517

In this instance, EPA’s Proposed FIP falls within the definition of significant regulatory action as 

set out in E.O. 12866 and reaffirmed in E.O. 13563. A “Significant regulatory action” means any 

regulatory action that is likely to result in a rule that may: (1) Have an annual effect on the 

economy of $100 million or more or adversely affect in a material way the economy, a sector of 

the economy, productivity, competition, jobs, the environment, public health or safety, or State, 

local, or tribal governments or communities; (2) create a serious inconsistency or otherwise 

interfere with an action taken or planned by another agency; (3) materially alter the budgetary 

impact of entitlements, grants, user fees, or loan programs or the rights and obligations of 

recipients thereof; or (4) raise novel legal or policy issues arising out of legal mandates, the 

President's priorities, or the principles set forth in this Executive Order.969

The Proposed FIP would adversely affect in a material way Arkansas communities by causing 

increased electricity rates that would be passed on to Arkansas consumers. Specifically, the 

following facilities owned by electric utilities engaged in interstate commerce were determined 

to be subject-to-BART or otherwise required to install emissions controls: the Arkansas Electric 

Cooperative (“AECC”) Carl E. Bailey Generating Station; the AECC John L. McClellan 

Generating Station; the American Electric Power (“AEP”) Flint Creek Power Plant; the Entergy 

White Bluff Plant; the Entergy Lake Catherine Plant; and the Entergy Independence Plant. 

These facilities are operated by public utilities with the ability to shift the costs of these controls 

from the utilities to the consumers of the electricity generated by these plants and generators. 

Under Arkansas law, a public utility such as those operating the aforementioned plants, may 

petition to the Arkansas Public Service Commission to recover costs for emissions control costs 

through a surcharge for those expenses so long as specific statutory elements have been met.970

This statute specifically provides for the recovery of costs that “[r]elate to the protection of the 

public health, safety of the environment” so long as other elements have been met.971 That 

surcharge would allow the affected utilities to transfer costs of compliance with the Proposed FIP 

onto Arkansas ratepayers. These costs would place a substantial burden on Arkansas 

communities. This burden constitutes a material adverse impact that renders this action subject to 

requirements of E.O. 12866. 

In addition, a significant regulatory action under E.O. 12866 is considered a “significant energy 

action” and subject to yet further review by OIRA under E.O. 13211 if that action is also ‘likely 

to have a significant adverse impact on the supply, distribution, or use of energy.”972 The 

Proposed FIP will likely have a significant adverse impact on use of energy through decreased 

use by electricity consumers responding to increased rates as a result of the emissions controls 

required. As a result of this adverse impact, the Proposed FIP is a “significant energy action.” In 

order to comply with E.O. 13211, EPA is required to submit to OIRA a “Statement of Energy 

Effects,” which describes the effects of certain regulatory actions on energy supply, distribution, 

or use.973

 

969 Id. at Sec.3(f). 970 Ark. Code Ann. § 23-4-501. 971 Ark. Code Ann. § 23-4-501(a)(1)(E). 972 Exec. Order No. 13211, 66 FR 28355, (May 18, 2001). 973 Id. 
518

ADEQ disagrees with EPA that the Proposed FIP is not subject to E.O. 13211 and E.O. 12866. 

The impacts of the Proposed FIP render it subject to both executive orders, and ADEQ is 

troubled that the EPA has not provided OIRA with the statements and other information required 

to comply with those orders. ADEQ is greatly concerned that EPA has not provided OIRA with 

the cost-benefit analysis required by E.O. 12866. This is a particular concern because EPA failed 

to perform a proper analysis of the costs of meeting EPA’s proposed RPGs. 

As a result of EPA’s failure to analyze the “cost of compliance” factor in relation to the RPGs,974

EPA has not performed any analysis of the costs of the overall impact of the Proposed FIP. 

Without EPA complying with the required additional review by OIRA, there would be no 

oversight of the costs of the Proposed FIP at all. Given the recent concerns by the Supreme Court 

in Michigan v. EPA about the rationality of imposing billions of dollars in economic costs in 

return for a few dollars in health or environmental benefits,975 EPA should strictly comply with 

E.O. 12866 and 13211 in order to properly determine the extent of the impacts of the Proposed 

FIP on the state of Arkansas. Since EPA has failed to do so, ADEQ requests that EPA withdraw 

the Proposed FIP.976

Response: Please see the above response in reference to E.O. 12866 and E.O. 13211.In the 

process of developing the FIP, we analyzed all the required factors, including the cost of 

compliance, at each source. Our detailed cost analysis can be found elsewhere in the proposed 

rulemaking and in this document. 

Comment: AECC stated there should be further federal review of the cost impacts of 

EPA’s proposed Rule. [AECC (0169) p. 6] AECC stated that EPA states that the proposed Rule 

is not a “significant regulatory action” as defined in Executive Order 12866.977 AECC disagrees. 

A “significant regulatory action" is defined as an action that may have an annual effect on the 

economy of $100 million or more.978 

The cost impacts of the proposed Rule are over $2 billion which would be spent in the five years 

subsequent to the effectiveness date of the final rule. This is well over the annual $100 million 

threshold. Therefore, the proposed Rule should have been sent to the federal Office of 

Management and Budget for review prior to its issuance. 

Additionally, in a recent decision involving costs of MATS, the U.S. Supreme Court recognized 

that costs of environmental regulations should be taken into account by EPA.979 Therefore, EPA 

should provide a cost-benefit analysis of the proposed Rule. 

 

974 See Supra pp. 14-15. 975 Michigan v. E.P.A., No. 14-46, 2015 WL 2473453, at *7 (U.S. June 29, 2015) (“[o]ne would not say that it is 

even rational, never mind ‘appropriate,’ to impose billions of dollars in economic costs in return for a few dollars in 

health or environmental benefits.”). 

976 Ark. Code Ann. § 23-2-304. 977 80 Fed. Reg. at 18999 (April 8, 2015). 978 Executive Order 12866 of September 30, 1993, Sec. 3(t)(l). 979 U.S. Supreme Court decision in Michigan v. EPA (June 29, 2015). 
519

Response: Please see the above responses in reference to the Executive Orders. We disagree 

with the commenter’s overly broad characterization of the Supreme Court’s decision in Michigan 

v. EPA. The Court ruled in Michigan v. EPA that EPA acted unreasonably when it determined 

that cost was irrelevant to the threshold appropriate and necessary finding under section 111 of 

the Clean Air Act. 135 S.Ct. 2699 (2015). The Court’s holding was based on its reading of the 

phrase “appropriate and necessary.” Even in this context, however, the Court found that “a 

formal cost-benefit analysis in which each advantage and disadvantage is assigned a monetary 

value” is not required. In our action on Arkansas, the CAA and our regulations require the state 

(or EPA standing in the shoes of the state) to take into account certain factors in both the BART 

and reasonable progress analyses. One such factor in both analyses is the “cost of compliance.” 

We note that EPA has explicitly considered the costs (and visibility benefits) of the measures in 

the FIP. 

8.g. EPA did not adequately consider relevant factors 

Comment: EPA improperly failed to consider relevant factors in its BART and reasonable 

progress determinations. 

[Nucor Steel-Arkansas and Nucor-Yamato Steel (0163) p. 21-28; and Arkansas Electric Energy 

Consumers Inc. and Arkansas Gas Consumers Inc. (0175) p. 15-16] Nucor and AEEC/AGC both 

stated that EPA has approved Ark. Code Ann. §8-4-312 as part of the Arkansas infrastructure 

SIP pursuant to 42 USC §7410. See, 40 C.F.R. §52.170(e), which certifies EPA's approval of 

Ark. Code Ann. §8-4-312 — “Factors in Exercise of Commission Powers” (identified as former 

Arkansas Statutes Annotated §82-1936). When a State Implementation Plan is approved by the 

EPA, its requirements become federal law and are fully enforceable in federal court. See, e.g., 

Safe Air for Everyone v. United States EPA, 488 F.3d 1088, 1091(9th Cir. 2007); Natural Res. 

Def. Council, Inc. v. S. Coast Air Quality Mgmt. Dist., 651 F.3d 1066, 1069 (9th Cir. 2011); EI 

Comite Para EI Bienestar De Earlimart v. Warmerdam, 539 F.3d 1062, 1066 (9th Cir. 2008); 

GenOn REMA, LLC v. EPA, 722 F.3d 513, 516 (3rd Cir. 2013) (“If the EPA approves the SIPs, 

they become enforceable as federal law.”); US Magnesium, LLC v. EPA, 690 F.3d 1157, 1159 

(10th Cir. 2012) (“Approved SIPs are enforceable as federal law....”). Thus, Ark. Code Ann. §8-

4-312 is federal law for purposes of the Clean Air Act in Arkansas and it is as equally binding on 

EPA as it is on the Arkansas state environmental agencies. See, e.g., United States v. Cinergy 

Corp., 623 F. 3d 455 (7th Cir. 2015); Sierra Club v. Ga. Power Co., 443 F.3d 1346 (11th Cir. 

2006); United States v. General Motors Corp., 702 F.Supp. 133 (D.C. Tex. 1988). 

Ark. Code Ann. §8-4-312 sets out several factors that must be taken into account in decisions to 

regulate air quality in Arkansas, including “the economic and industrial development of the state 

and the social and economic value of the air contamination sources,” Ark. Code Ann. §8-4 

312(14). Although the Clean Air Act requires that certain factors must be “taken into 

consideration” in determining BART, 42 U.S.C. §7491(g)(2), and in establishing reasonable 

progress goals, 42 U.S.C. §7491(g)(1), the statute does not make those factors exclusive. In fact, 

EPA's BART guidelines indicate that “unusual circumstances...[including] the economic effects 

of requiring the use of a given control technology” may be considered. 40 C.F.R. Part 51, 

Appendix Y, IV.E.3 (70 F.R. 39,104; 39,171, July 6, 2005). 
520

EPA’s BART and Reasonable Progress determinations for Flint Creek, White Bluff and 

Independence will cost over $2 Billion and will result in significant increases in electric and 

natural gas rates over most of the State of Arkansas for residential, commercial, governmental, 

agricultural and industrial customers of Entergy, SWEPCO, AECC and the municipal owners of 

those facilities. These three sources constitute a large part of the baseload electric generation for 

the State of Arkansas, and an even larger proportion of the baseload generation for AECC and its 

member cooperatives. Nowhere in the Proposed FIP does EPA consider the social and economic 

value of these sources, and the economic effects of EPA's actions. Since the public utilities who 

will incur costs under the proposed FIP will certainly pass those costs through to ratepayers, the 

proposed FIP will have a profound effect on the Arkansas economy. 

Nucor stated that not only does EPA's failure to consider the economic consequences of its 

BART and Reasonable Progress determinations violate Ark. Code Ann. §8-4-312 as part of 

EPA's approved infrastructure SIP for Arkansas, it also violates the spirit and purpose of EPA's 

own Environmental Justice (EJ) guidelines which requires EPA to “consider the impacts of our 

regulatory actions on populations documented as frequently bearing the greatest burdens 

imposed by environmental pollution.” EPA, “Guidance on Considering Environmental Justice 

During the Development of Regulatory Actions,” May 2015, at p. 2.980 These same populations 

that EPA's EJ guidelines seek to protect would be adversely impacted by EPA's Proposed FIP. 

Arkansas is the second poorest state (49/50) with a median household income of $40,768.981 It 

has the 4th highest percentage (ranked 46/50) of poverty stricken residents.982 The areas in 

Arkansas that White Bluff, Independence and Flint Creek serve have an average of 19.2% of 

residents living below the federal poverty level. Several counties in east Arkansas that are served 

by these facilities have more than 30% of their residents living below the federal poverty level.983

Federal data illustrates that the poorer a household is, the more that higher energy rates harm the 

occupants.984 In 2012, families with annual pre-tax incomes of over $50,000 spent 9% of their 

household budgets on energy, compared to only 5% in 2001. Those earning between $30,000 

and $50,000 saw an even larger percentage of their budgets consumed by rising energy costs —

17% in 2012 compared to 10% in 2001. Most drastically, families making $10,000 to $30,000 

spent 24% of their incomes on energy in 2012 compared to 14% in 2001.985 EPA’s proposed FIP 

will increase electric rates even more, and amplify these economic disparities and income 

inequality even further. The increases in electric rates that electricity providers would charge 

ratepayers in order to comply with EPA's proposed FIP will push more Arkansans deeper into 

poverty. 

There is an important relationship between utility rates, poverty and poor health. One study 

concluded that an additional regulatory cost of $8.9 million related to electricity use causes one 

 

980 Available at http://www.epa.Rov/environmentaliustice/resources/policy/considering-ei-in-rulemaking-guidefinal.pdf. 

981 U.S. Census Bureau. Accessed 7/2/15. http://quickfacts.census.gov/qfd/states/05000.html 982 Id. 983 Information obtained by going county by county (on above website), accessed 7/2/15. 984 http://www.forbes.com/sites/realspin/2015/06/15/epa-clean-power-plan-may-do-more-harm-than-good/ Citing: 

http://www.americaspower.org/sites/default/files/Energy_Cost_Impacts_2012_FINAL.pdf 985 Id. 
521

additional adult death, and that such impacts are highly concentrated in lower income groups and 

disproportionately affect certain minority groups. The study concludes that 43% of such deaths 

would occur in households with incomes of less than $15,000.986 The higher energy prices 

resulting from EPA's Proposed FIP will force many Arkansans to spend an even higher 

percentage of their income on electric bills, leaving them less money for food, use of heating and 

air conditioning, paying health insurance premiums, buying medicine, transport to work, and to 

see their doctors. In forcing its proposed FIP onto Arkansas, EPA has failed to consider whether 

it would harm thousands of Arkansans, which likely would be the poorest Arkansans.987

EPA also failed to consider whether the economic impact of its proposed FIP costs would lead to 

closure or curtailment of White Bluff, Independence, or Flint Creek resulting in local adverse 

economic impacts, the impact of such closures or curtailment on electric grid reliability in the 

State of Arkansas, and the State of Arkansas's interest in maintaining sufficient electric 

generation resources within its own borders and subject to state regulation. Under EPA's BART 

guidance, EPA states that BART should not be so economically onerous that it brings a facility 

to the brink of shutdown or substantial curtailment of operations.988 This consideration is echoed 

in EPA's BART Guidelines, 40 C.F.R. Part 51, Appendix Y, IV.E.3 (70 F.R. 39,104, 39,171; 

July 6, 2005), yet EPA did not consider whether the $2.0+ billion cost imposed by its BART and 

Reasonable Progress determinations would result in the shutdown or curtailment of operations at 

White Bluff, Flint Creek and Independence. 

Under EPA's proposed Clean Power Plan, the possible impacts of the closure or curtailment of 

fossil-fuel electric generating units like White Bluff, Independence and Flint Creek on electric 

grid reliability was deemed to be an important factor, with several regional transmission 

organizations commenting on the adverse impacts of EPA’s 111(d) plan on grid reliability.989

Yet, EPA improperly failed to consider or take into account the impacts of its Proposed FIP on 

electric grid reliability, either regionally or within the State of Arkansas as a whole, or within 

discrete electric service territories within the State of Arkansas.990

Nucor and AEEC/AGC both stated that EPA did not consider whether its proposed FIP would 

result in economic harms and negative health impacts in Arkansas. Not only are these factors 

“appropriate,” as indicated above they are “necessary” and required under Ark. Code Ann. §8-4-

312, EPA's own BART Guidelines, and its EJ Guidelines. “No regulation is ‘appropriate’ if it 

does significantly more harm than good.” Michigan v. EPA, 576 U.S. (2015). EPA should 

consider whether its proposed FIP “reflects the reality that too much wasteful expenditure 

 

986 See Exhibit 8 to Nucor’s comments, Klein, D., and Keeney, R., "Mortality Reductions from Use of Low-Cost 

Coal-Fueled Power: An Analytical Framework" (December 2002). 987 See, Exhibit 23 to Nucor’s comments, AECC Letter dated Sept. 26, 2014 to Hon. G. McCarthy regarding the 

impacts of EPA's Clean Power Plan. 

988 See Exhibit 9 to Nucor’s comments, "Guidelines for Determining Best Available Retrofit Technology for 

Coal-Fired Power Plant and Other Stationary Sources, USEPA," November 1980, EPA 450/3-80-009b, section 

2.6.3, p. 20.

989 See, Exhibits 10A, 10B, and 10C to Nucor’s comments, Southwest Power Pool and Midcontinent Independent 

System Operator comments, Docket No. EPA-HQ-OAR-2013-0602. 

990 The impact of EPA's proposed Clean Power Plan by way of closure or curtailment of operations of White Bluff, 

Flint Creek or Independence would also be a relevant factor in determining the costs of compliance, remaining 

useful life and the visibility impacts of those sources under the Regional Haze Rule statutory factors for BART and 

Reasonable Progress. 
522

devoted to one problem may well mean considerably fewer resources available to deal 

effectively with other (perhaps more serious) problems.” Michigan v. EPA, 576 U.S. (2015). 

Expending billions of dollars for imperceptible visibility changes under these circumstances is 

simply not defensible, and has not been properly justified by EPA. EPA should have considered 

the economic impact of the Regional Haze Rule and its BART and Reasonable Progress 

determinations on the ratepayers who will be paying for these expensive controls. EPA's failure 

to take these and other relevant factors into consideration in its BART and reasonable progress 

determinations is unreasonable, arbitrary, and capricious. Michigan v. EPA, 576 U.S. (June 28, 

2015). Therefore, EPA should withdraw the proposed FIP. 

Response: We disagree with this comment. When a State Implementation Plan is approved by 

EPA it is true that it “‘[h]a[s] ‘the force and effect of federal law.’’” Safe Air for Everyone v. 

U.S. EPA, 488 F.3d 1088, 1091 (9th Cir. 2007), quoting, Trs. for Alaska v. Fink, 17 F.3d 1209, 

1210 (9th Cir. 1994). However, we reject the assertion that EPA was required to consider the 

factors listed in Ark. Code Ann. §8-4-312 when promulgating a FIP to address the portions we 

disapproved in Arkansas’ SIP. 

 

As explained in other responses above and by the U.S. Supreme Court in Union Electric Co. v. 

EPA, 427 U.S. 246,249-50 (1976), Congress has given States the primary responsibility in 

preventing and controlling air pollution. States are under an obligation to submit a Regional 

Haze SIP to EPA which complies with federal requirements. While states have flexibility in 

developing a SIP, EPA must ensure that the plan meets all federal requirements. In the event that 

a state fails to submit a SIP that meets federal requirements, EPA must step in and create a FIP to 

address the portions of the disapproved the state’s plan which meets all federal requirements. 

 

Ark. Code Ann. §8-4-312 provides that “[i]n exercising their powers and responsibilities under 

this chapter, the Arkansas Department of Environmental Quality and the Arkansas Pollution 

Control and Ecology Commission shall take into account and give consideration to the following 

factors:...” (emphasis added). Arkansas has failed to develop a Regional Haze SIP which meets 

all applicable federal requirements. As a result, EPA is required to develop and implement a FIP. 

While Arkansas had the discretion to require that additional factors be considered in developing 

its SIP, it cannot impose that same requirement on EPA. EPA is not exercising powers granted to 

us by Arkansas’ Air Pollution Control Act, rather we are acting under the CAA. In this situation, 

EPA is required to follow the requirements listed in both the CAA and our rules. It should be 

noted that there is a provision in Arkansas’ Act which more directly targets the issue mentioned 

by the Commenter. That provision is not in the federally-approved SIP. Ark. Code Ann. §8-4-

317 provides that “[i]n developing and implementing a state implementation plan, the Arkansas 

Department of Environmental Quality shall consider and take into account the factors specified 

in §8-4-312 and the [Arkansas] Clean Air Act...” While the CAA does not prevent states or EPA 

from considering other factors in its BART and reasonable progress determinations, it only 

mandates that the factors listed in the Act be considered. EPA considered all the factors deemed 

necessary to be considered by the CAA. 

We disagree that our action violates the spirit and purpose of our Environmental Justice 

Guidelines. The full sentence from which the commenter quotes reads: “In particular, the U.S. 

Environmental Protection Agency has a responsibility under Executive Order 12898, Federal 
523

Actions to Address Environmental Justice in Minority Populations and Low-Income Populations 

to consider the impacts of our regulatory actions on populations documented as frequently 

bearing the greatest burdens imposed by environmental pollution.” Executive Order 12898 states 

that each Federal agency is required to make “achieving environmental justice part of its mission 

by identifying and addressing, as appropriate, disproportionately high and adverse human health 

or environmental effects of its programs, policies, and activities on minority populations and 

low-income populations in the United States and its territories and possessions, the District of 

Columbia, the Commonwealth of Puerto Rico, and the Commonwealth of the Mariana Islands.” 

Contrary to the commenter’s assertion, our action embodies the spirit in which the Executive 

Order was written. The reduction in air pollution that will be attributed to the controls being 

required in our final rule will result in improved visibility, and Arkansas residents living in the 

surrounding areas will reap ancillary health benefits achieved by the reduction. We do, however, 

note that our decision was not based on these additional health benefits. The Regional Haze 

Program was designed solely to improve visibility in Class I areas, it is not a health based 

program. Any other benefits received as a result of the Program are an added bonus. 

In regards to the comments about the cost of the controls and the possible closure or curtailment 

of units, we note that controls achieving the level of control that we are requiring are highly costeffective, are in wide use in the industry, and thus should not require a source to shut down to 

comply. During our comment period, we received no, non-speculative information to validate 

claims that sources would retire rather than install demonstrably cost-effective controls. 

Commenters who have alleged grid reliability concerns in response to our proposed controls 

have not provided adequate documentation for their assertions. Please see our responses to the 

comments regarding cost analysis that we have provided elsewhere in this document as well as 

out Cost TSD for a more in depth analysis. 

We believe, for reasons we have outlined in our proposal and elsewhere in our response to 

comments, that the controls we proposed under our FIP are cost-effective and will result in 

significant improvements in visibility at a number of Class I areas and meet the requirements of 

the CAA and the RHR. We do note that we are not subject to state law requirements related to 

how the cost analysis must be conducted or what specific factors need to be considered. We did 

consider costs in great detail to ensure that the controls required by the FIP are cost-effective, 

worth the visibility reductions achieved, and consistent with expectations in other SIPs and FIPs. 

For the comments regarding costs, economics, see the previous responses.

Comment: If there is no available information showing the potential for units to close, EPA 

is not required to consider whether the rule may cause units to close. [Sierra Club et. al. 

(0171) p. 44-45] Sierra Club et. al. stated that comments submitted by other parties suggest that 

EPA is required to consider the potential closure of units as part of considering the cost of 

controls. However, there is no evidence in the record that any of the units would close since they 

could not afford the controls. To the contrary, EPA has proposed controls in part because they 

have cost-effectiveness values and absolute costs comparable to what similar sources have had to 

bear around the country. See, e.g., pages 11-12, above. In the absence of information to the 

contrary, EPA can rationally conclude that when it proposes controls that have absolute costs and 

cost-effectiveness values similar to the costs that other utilities around the country found 

affordable, that the sources in Arkansas can also afford such control costs. 
524

EPA’s BART Guidelines include a provision regarding the affordability of controls. See 40 

C.F.R. Part 51, App. Y § IV(E)(3). In the course of reviewing scores of BART determinations in 

haze plans across the country, EPA has relied on the affordability provision only once. 79 Fed.

Reg. 33,438, 33,442-43 (June 11, 2014) (controls that would otherwise be BART are not

affordable for the Intalco smelter). This is consistent with the BART Guidelines’ instruction that

EPA should rely upon the affordability provision only in “unusual circumstances.” 40 C.F.R. pt.

51 App. Y § IV(E)(3). In this rare instance, the affected BART source took the affirmative step

of providing information to EPA that allegedly indicated that the company would close the

source if required to install certain BART controls. 79 Fed. Reg. at 33,439. Where a company

has not substantiated the claim that otherwise cost-effective controls are not affordable, EPA has

found that the controls are affordable. 76 Fed. Reg. 36,329, 36,334-36 (June 22, 2011) (rejecting

claim by sugar beet processing facility in Idaho that it could not afford controls); 77 Fed. Reg. at 

72,539-42 (concluding that there is no evidence that the Apache power plant in Arizona cannot 

afford BART controls). 

It would be difficult for EPA to accurately assess the likelihood that BART controls would lead a 

source to close unless the source provides EPA with access to its confidential financial data. To 

date, no source has claimed that EPA’s proposed plan would lead to plant closure due to 

unaffordable costs. In the absence of such claims and supporting information, EPA properly 

assumed that control costs which similar sources have found affordable are also affordable to 

Arkansas sources. 

Response: EPA agrees with the commenter that the BART Guidelines include a provision 

allowing for the consideration of the affordability of controls. As the commenter notes, 

however, none of the sources subject to control measures in our FIP have claimed that the 

installation of the controls required by the FIP would lead to plant closures or curtailments. 

8.h. Other 

Comment: EPA arbitrarily chose the options for emissions control for Entergy 

Independence Units 1 and 2. [ADEQ (0144) p. 22-23] ADEQ stated that EPA arbitrarily chose 

the two options it presented for emissions controls at Entergy Independence Units One and Two 

as evidenced by EPA’s failure to discuss a third option, which EPA presented to ADEQ for 

consideration prior to the promulgation of the Proposed FIP.991 ADEQ received a technical 

support document dated February 11, 2015 within which EPA Region 6 presented three options 

for Entergy Independence: “Option 1: Propose No Additional Controls under Reasonable 

Progress”; “Option 2: Propose Only SO2 Controls under Reasonable Progress”; and “Option 3: 

propose Both SO2 and NOX Controls Under Reasonable Progress.”992

Although ADEQ received this document on February 12, 2015, EPA never included it in the 

Rulemaking Docket.993 When EPA published the Proposed FIP on April 8, 2015, the option to 

 

991 EPA, Arkansas Regional Haze FIP Update, (February 11, 2015), see Exhibit 2 to ADEQ’s comments. 992 Id. 993 EPA Docket Number EPA-R06-OAR-2015-0189 
525

“Propose No Additional Controls under Reasonable Progress” had been inexplicably removed as 

an option from the proposed Regional Haze FIP. EPA completely excluded this option from 

consideration and no mention of it was made in the Proposed FIP. 

While EPA has considerable discretion interpreting its own regulations, the law requires EPA to 

“cogently explain why it has exercised its discretion in a given manner.”994 Whether or not EPA 

ultimately chose to reject the option, it is legally obligated to consider and explain its decision to 

or not to include it. The decision to provide ADEQ with a certain set of options prior to 

promulgation of the Proposed FIP and simply excise one of those options from the Proposed FIP 

without due consideration is arbitrary and capricious. EPA should withdraw the Proposed FIP 

and any subsequent plan that might include emissions controls for Entergy Independence Units 1 

and 2 should include a proper consideration of the available options. 

Response: The document to which the commenter refers, “EPA, Arkansas Regional Haze FIP 

Update, (February 11, 2015)” (Exhibit 2 to ADEQ’s comments), is a briefing paper based on 

EPA staff-level advice and recommendations. The briefing paper was provided as a courtesy to 

ADEQ for informational purposes and is not part of the basis for EPA’s decision. For this 

reason, it was not included in the docket. Under Section 307(d)(3) of the Clean Air Act, the 

docket is required to include the factual data on which the proposed rule is based, the 

methodology used in obtaining the data and in analyzing the data, and the major legal 

interpretations and policy considerations underlying the proposed rule. The briefing paper does 

not fall within any of these categories. We provided the proposed factual, technical, and legal 

basis for requiring controls at Independence to ensure reasonable progress in our proposed rule. 

In doing so, we have “cogently explain[ed]” the basis for our proposed decision. In today’s 

action, we again explain our decision to require reasonable progress measures at Independence. 

Although the briefing paper shared with ADEQ did not create a distinct obligation for us to 

propose an option of “no controls” at Independence, we have met the basic requirement that we 

explain our exercise of discretion in deciding to require reasonable progress measures at 

Independence. In explaining why we are requiring these measures, we inherently have also 

explained why we have not decided to not require any measures at all.

Comment: [Arkansas Attorney General (0162) p. 1-2] The Attorney General for the State of 

Arkansas stated that the Environmental Protection Agency (“EPA” or “Agency”) has acted in an 

arbitrary and capricious manner by proposing a FIP to address certain regional haze and visibility 

transport requirements for the State of Arkansas. The proposed FIP has no basis in law or science 

and is a prime example of overreaching federal regulation in response to “sue and settle” 

litigation brought by the Sierra Club. As such, the EPA should withdraw the proposed FIP and 

consult with the State in developing an approvable SIP. 

 

994 Nat'l Parks Conservation Ass'n v. E.P.A., No. 12-73710, 2015 WL 3559149, at *3 (9th Cir. June 9, 2015); (citing 

Motor Vehicle Mfrs. Ass'n of U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 48, (1983)); Greater 

Yellowstone Coalition, Inc. v. Servheen, 665 F.3d 1015, 1030 (9th Cir.2011) (requiring “a rational connection 

between the data before [the agency] and its conclusion”); Nw. Envtl. Def. Ctr. v. Bonneville Power Admin., 477 

F.3d 668, 691 (9th Cir.2007).
526

The Attorney General stated that there is concern with the abbreviated time frame being forced 

upon this review by a third party lawsuit. On February 11, 2015, the EPA lodged a proposed 

Consent Decree in Sierra Club v. McCarthy, Case No. 4:14-CV-00643-JLH, Eastern District of 

Arkansas (“Sierra Club”). The proposed Consent Decree requires EPA to issue a final regional 

haze FIP on or before December 15, 2015. The Attorney General submitted comments regarding 

the proposed Consent Decree on April 20, 2015. Contemporaneously, EPA submitted the 

proposed FIP for public comment on April 8, 2015 and extended that period until July 15, 2015. 

As I stated in my comments regarding the proposed Consent Decree in Sierra Club, the Attorney 

General does not believe that five (5) months is an adequate time period for the EPA to fully 

analyze and respond to the public comments. Again, the Attorney General urges the EPA to 

reconsider the Sierra Club December 15, 2015 deadline for the issuance of a final FIP. EPA must 

take an appropriate amount of time to address the many concerns that are being raised in the 

public comments. A rushed process that fails to fully review all considerations will lead to an 

arbitrary and capricious decision. Such a decision will most certainly lead to protracted litigation, 

not protection of the environment. In the light of recent case law, EPA is not likely to prevail in 

litigation challenging the proposed FIP.995

Response: Sierra Club brought suit against EPA because we have a mandatory duty under the 

Clean Air Act to address deficiencies in SIPs in a timely manner. Consent decrees establishing 

dates by which EPA must take action do not address the content of final action by the Agency. 

In this case, as explained in more detail earlier, after the close of the comment period, EPA 

concluded that it would not ask the court to enter the proposed consent decree that it had made 

available for public comment. Instead, the parties filed motions in the Eastern District Court of 

Arkansas in a case in which the state of Arkansas was a party. The court ordered EPA to 

promulgate a FIP or approve a state SIP by August 31, 2016, nearly 15 months after our 

proposed FIP. We believe this date provides adequate time for EPA to address all comments and 

to finalize a FIP. See Sam Coleman declaration submitted under the mandatory duty suit 

(provided in our docket to this rulemaking). The proposed FIP, as explained in greater detail 

elsewhere, addresses the portions of the Arkansas SIP we disapproved in 2012. . 

Comment: EPA has broad oversight authority over the regional haze program and final 

say on whether state regional haze SIPs comply with the CAA and regulatory 

requirements. [Sierra Club et. al. (0171) p. 5-6] Sierra Club et. al. stated that the Clean Air 

Act’s regional haze program provides states with the initial opportunity to develop regional haze 

SIPs that clean up the air in our nation’s national parks and wilderness areas in accordance with 

the Regional Haze Rule and EPA guidance. See 42 U.S.C. § 7491(b)(2). If a state’s regional haze 

plan fails to establish a haze program that complies with the applicable legal requirements, the 

Clean Air Act requires EPA to disapprove the state plan and issue a federal implementation plan 

(“FIP”) in its place. 42 U.S.C. § 7410(c)(1); Oklahoma v. EPA, 723 F.3d 1201, 1207-10 (10th 

Cir. 2013). 

Congress gave EPA the final say on whether a state’s regional haze SIP complies with the Clean 

Air Act. 42 U.S.C. §§ 7410(c)(1), (k)(3), (l), 7491. EPA has broad oversight authority over the 

regional haze program and is obligated to disapprove state haze SIPs that fail to comply with the 

 

995 Nat’l. Parks Conservation Ass’n. v. EPA, -- F.3d --, 2015 WL 3559149 (9th Cir. 2015). 
527

Act. North Dakota v. EPA, 730 F.3d 750, 760-62 (8th Cir. 2013); Oklahoma v. EPA, 723 F.3d at 

1207-10. Congress gave EPA this broad oversight authority to prevent recalcitrant states from 

undermining the purposes of the Clean Air Act through inadequate state plans. See, e.g., Alaska 

Dep’t of Envtl. Conservation v. EPA, 298 F.3d 814, 819-20 (9th Cir. 2002) (Congress gave EPA 

oversight authority because of “disappointing state response[s] to air pollution concerns” and its 

recognition that “states experience[] internal industry ‘pressure . . . to relax their standards’”), 

aff’d, 540 U.S. 461 (2004). 

Response: We agree with the commenter that EPA is required to approve only those provisions 

of a SIP that comply with the Clean Air Act. When EPA disapproves a SIP in whole or part, the 

Clean Air Act obligates EPA to promulgate a FIP or to approve a SIP within two years of EPA’s 

disapproval. 

Comment: Since no party challenged EPA’s March 12, 2012 final rule partially approving 

and partially approving the Arkansas Regional Haze SIP by filing a petition for review, 

any right to challenge EPA’s final partial approval and partial disapproval of the SIP has 

been waived. [Sierra Club et. al. (0171) p. 6-7] Sierra Club et. al. stated that ADEQ submitted a 

proposed regional haze SIP to EPA on September 23, 2008 and August 3, 2010. 77 Fed. Reg. 

14,603, 14,604 (Mar. 12, 2012). On September 27, 2011, ADEQ submitted supplemental 

information. Id. Less than a month later, EPA proposed to partially approve and partially 

disapprove Arkansas’s SIP. 76 Fed. Reg. 64,185 (October 17, 2011). On March 12, 2012, EPA 

issued a final rule approving in part and disapproving in part Arkansas’s regional haze and 

interstate transport SIP. 77 Fed. Reg. 14,603. 

In the 2012 action, EPA approved Arkansas’s identification of subject-to-BART sources, with 

the exception of the 6A and 9A Boilers at Georgia-Pacific Crossett Mill, which EPA found 

subject-to-BART. 77 Fed. Reg. 14,603. EPA approved some of Arkansas’s BART 

determinations, and disapproved others. As most relevant to these comments, EPA disapproved 

these BART determinations: 

 SO2 and NOx BART for AEP Flint Creek Boiler No. 1; 

 SO2 and NOx BART for the bituminous and subbituminous coal firing scenarios for 

Entergy White Bluff Plant Units 1 and 2; and 

 NOx BART for the natural gas firing scenario for Entergy Lake Catherine Unit 4; and 

 SO2, NOx, and particulate matter (“PM”) for the fuel oil firing scenario for Entergy Lake 

Catherine Unit 4. 

77 Fed. Reg. at 14, 605; see also 80 Fed. Reg. at 18,947. EPA found that ADEQ “did not satisfy 

all the regulatory and statutory requirements in making [] BART determinations” for certain 

sources. Id. at 14,605. 

In addition, EPA partially approved and partially disapproved Arkansas’s long-term strategy 

because it relied on portions of the regional haze SIP that EPA disapproved, including some of 

the BART emissions limits. 77 Fed. Reg. at 14, 605. EPA disapproved ADEQ’s reasonable 

progress goals (“RPGs”) because Arkansas did not consider the four factors that states are 
528

required to consider in establishing RPGs under the CAA and 40 C.F.R. § 51.308(d)(1)(A). 77 

Fed. Reg. at 14, 605. 

No party challenged EPA’s 2012 disapproval decision by filing a petition for review in the 

appropriate Circuit Court of Appeals. Accordingly, any right to challenge EPA’s approval or 

disapproval decisions in the 2012 final action has been waived. See 42 U.S.C. § 7607(b)(1). 

Following EPA’s disapproval decision, Arkansas began the process of collecting technical 

documentation from the companies whose BART determinations were disapproved. 80 Fed. Reg. 

at 18,947. Those documents were provided to EPA and form the basis of its evaluation of BART 

determinations in the proposed FIP. See 80 Fed. Reg. at 18,947. 

Response: We agree with the commenter. As explained in another response, we partially 

approved and partially disapproved the submitted regional haze SIP of Arkansas in 2012. We 

received adverse comments on our proposed action; however, no party filed suit challenging our 

action. The proposed rulemaking before us only addresses EPA’s determinations for 

disapproved elements that need to be addressed as required by the Clean Air Act. 

Comment: EPA can satisfy the standard articulated in NPCA vs. EPA. [Sierra Club et. al. 

(0171) p. 41] The Sierra Club et. al. stated that other commenters cited National Parks 

Conservation Association v. EPA to argue that EPA has failed to rationally explain how the 

benefits justify the costs of the proposed controls. 788 F.3d 1134, 1138 (9th Cir. 2015). Not so. 

EPA can easily satisfy the standard articulated in NPCA v. EPA that EPA provide an explanation 

that is “not elaborate, but rational, and thus adequate.” Id. at 1145. The court held that if EPA 

points to the costs and benefits of other control determinations it has approved, EPA satisfies the 

requirement to provide some metric by which it weighs costs and visibility improvement. In 

particular, the court stated that: 

EPA explained that it had found improvements of 0.2 deciviews at 

each unit of that location to be cost-justified for reasonable 

progress purposes when the costs of such improvement ranged 

from $586/ton to $661/ton. See id. EPA’s comparison of the two 

sources provided NPCA with at least some broad metric for 

understanding which cost-per-ton ratios EPA will approve and 

which it will not—a rational explanation why the reasonable 

progress options available at Colstrip Units 3 and 4 were not 

feasible. Id. at 1149. 

As we note elsewhere in our comments and as explained in the Stamper Report, EPA has 

approved both BART and reasonable progress determinations in which the cost-effectiveness of 

controls was equal to or higher than the cost-effectiveness of the Arkansas FIP controls and in 

which the visibility benefits were equal to or lower than the improvement expected from the 

Arkansas FIP controls. See, e.g., pages 11-12 of Sierra Club comments; see Stamper Report at 

12, 60-62. EPA should cite these examples in order to satisfy the concerns expressed by the court 

in NPCA v. EPA. 
529

Response: We agree with the commenter that the cost effectiveness of the controls in our 

proposed FIP are comparable -- and in some cases more cost effective (i.e., lower $/ton) -- than 

similar controls in other regional haze actions that we have approved or promulgated. These 

controls are also anticipated to result in comparable or greater visibility benefits than controls in 

other regional haze actions. Below, we specifically point out some examples of this. 

As pointed out in the Stamper Report at 12, we approved Colorado’s determination that dry 

scrubbers on CSU Nixon Unit 1 are reasonable and cost effective controls and are required under 

reasonable progress.996 In its SIP, Colorado determined that the cost effectiveness of dry 

scrubbers on CSU Nixon Unit 1 would be $3,744/ton SO2 removed and that the visibility 

improvement (delta dv for the maximum 98th percentile impact) was projected to be 0.46 dv. 

We approved Colorado’s determination that dry scrubbers are BART for SO2 for CSU Martin 

Drake Units 6 and 7.997 The state determined that the cost effectiveness of dry scrubbers is 

$2,808/ton SO2 removed for Unit 6 and $2,345/ton SO2 removed for Unit 7. The state found that 

the visibility improvement (delta dv for the maximum 98th percentile impact) is projected to be 

0.25 dv for Unit 6 and 0.40 dv for Unit 7. 

We also approved Colorado’s determination that BART for NOX for Martin Drake Unit 5 is ultra 

LNB/OFA, which the state estimated to cost $1,342/ton removed and to result in projected 

visibility improvement of 0.08 dv.998

In our North Dakota RH FIP, we required NOX combustion controls under the reasonable 

progress requirements for Antelope Valley Station Units 1 and 2 that were estimated to cost 

$586/ton removed at Unit 1 and $661/ton removed at Unit 2, and the anticipated visibility 

benefits are estimated to be 0.754 dv for the two units combined.999

Thus, we agree with the commenter that the cost and visibility improvement of the controls we 

are requiring in our Arkansas FIP are comparable and consistent with the BART and reasonable 

progress controls we have approved or promulgated in other regional haze actions 

9. Visibility Transport 

Comment: The Arkansas RH SIP satisfies the Prong 4 requirement; EPA does not have 

authority to require controls at these sources for purposes of “Visibility” Interstate 

Transport. 

[Entergy Arkansas Inc. (0166) p.56] Entergy Arkansas Inc. stated it disagrees that the proposed 

regional haze FIP will satisfy the requirements of CAA Section 110(a)(2)(D)(i)(II), 80 Fed. Reg. 

at 18,998, for the reasons explained in Entergy’s comments on EPA’s proposed disapproval of 

 

996 77 FR 18052 and 77 FR 76871. 997 77 FR 18052 and 77 FR 76871. 998 77 FR 18052 and 77 FR 76871. 999 77 FR at 20899. 
530

Arkansas’ SIP revision addressing interference with other states’ programs for visibility 

protection for the 2006 revised 24-hour PM2.5 NAAQS. These comments are attached as Exhibit 

I and Entergy hereby incorporates these by reference. 

Contrary to EPA’s position, the Arkansas SIP submittal satisfies Prong 4, rendering the regional 

haze FIP unnecessary to address interference with other states’ visibility SIPs. First, the 

SIP submittal does explain how it complies with Prong 4 by specifically identifying the state 

regulations that ensure emissions from Arkansas sources will not interfere with other states’ 

regional haze SIPs. Second, while EPA has issued guidance documents stating that Prong 4 may 

be satisfied through the promulgation of a regional haze SIP, this is not the only way in which a 

state may meet its obligation. See Guidance for State Implementation Plan Submissions to Meet 

Current Outstanding Obligations Under Section 110(a)(2)(D)(i) for the 8-hour Ozone and PM2.5 

National Ambient Air Quality Standards, at 9-10 (Aug. 15, 2006). Indeed, EPA itself has 

acknowledged states may satisfy Prong 4 by something other than an EPA-approved regional 

haze SIP. 76 Fed. Reg. 8326, 8328 (Feb. 14, 2011) (Proposed Approval and Promulgation of 

State Implementation Plans; State of Colorado; Interstate Transport of Pollution Revisions for 

the 1997 8-Hour Ozone and 1997 PM2.5 NAAQS: “Interference With Visibility” Requirement). 

Arkansas emissions cause and contribute to visibility impairment primarily in two Class I areas 

in Missouri, Hercules Glades Wilderness Area and Mingo National Wildlife Refuge, and 

potentially other Class I areas in Oklahoma, Kentucky, Illinois and Louisiana. Proposed 

Approval Regional Haze Interstate Transport SIP, 76 Fed. Reg. 64,186, 64,193, 64,215 (Oct. 17, 

2011); Final Approval Regional Haze Interstate Transport SIP, 77 Fed. Reg. 14604, 14623 (Mar. 

12, 2012). Of these states, only Missouri relied upon anticipated BART controls from sources in 

Arkansas when developing its regional haze SIP. See Missouri Regional Haze SIP. (June 25, 

2009). Subsequent to EPA’s partial disapproval of the Arkansas BART limits, Missouri released 

a 5-Year Progress Report demonstrating that Mingo and Hercules Glades are on track to meet the 

2018 visibility goals. Missouri Regional Haze Plan: 5-Year Progress Report (Aug. 29, 2014). 

Missouri concluded that this progress was the result of emissions reductions at Missouri sources 

and that further reductions are not necessary. Thus, Missouri has determined that no additional 

measures are needed in Arkansas to prevent Arkansas sources from interfering with Missouri’s 

reasonable progress efforts. 

EPA proposes to find that the requirements of Prong 4 will be satisfied by the combination of the 

emission control measures in the proposed regional haze FIP, and the already approved portions 

of the Arkansas regional haze SIP. It is inappropriate for EPA to propose such a finding when the 

Agency has not yet finalized its regional haze FIP. As EPA recognizes, the Agency cannot 

finalize this proposal unless and until it finalizes its action on the regional haze FIP. Depending 

upon the comments submitted to EPA on the proposed FIP, the final regional haze FIP could be 

substantially different from the proposal. 

It is impossible to know, during the comment period on this rulemaking, whether the final 

FIP will rectify these problems. Because significant changes could be made to the final FIP, 

because these changes are unforeseeable, and because Entergy has significant concerns that the 

final FIP may be legally and technically deficient, it is unreasonable to request public comment 

on a proposal that the final FIP will satisfy Prong 4. This is a clear violation of EPA’s obligation 
531

under the Administrative Procedure Act to provide adequate notice and opportunity to comment 

on a proposed rule. 5 U.S.C. § 553. EPA should defer requesting public comment on this issue 

until after the Arkansas regional haze FIP has been finalized. 

[Nucor Steel-Arkansas and Nucor-Yamato Steel Company (0163) p. 50-53] Nucor stated the 

good neighbor visibility provision in 42 U.S.C. 7410(a)(2)(D)(i)(II) prohibits interference with 

“measures” required to be included in another State’s implementation plan to protect visibility. 

EPA has not demonstrated that any of these sources in its Proposed FIP are interfering with any 

visibility control measure in any other state’s SIP. Nucor disagreed with EPA’s determination to 

disapprove the Arkansas interstate visibility transport SIP provisions submitted to EPA on April 

2, 2008 based on the same reasoning.1000 In EPA’s 2011 proposed decision to disapprove that 

SIP submission, EPA stated that the Clean Air Act requires states to prevent “sources in the state 

from emitting pollutants in amounts which will interfere with efforts to protect visibility in other 

states.” 76 Fed.Reg. 53189, 64219. In its Proposed FIP in 2015, EPA states that the Arkansas SIP 

did not ensure that emissions from Arkansas sources “do not interfere with other states’ visibility 

programs as required by section 110(a)(2)(D)(i)(II) of the CAA.” 80 Fed.Reg. 18998, April 8, 

2015. The visibility protection requirement of §110(a)(2)(D)(i)(II) does not protect against 

interference with either other states “efforts” or other states “programs.” Unlike the language in 

§110(a)(2)(D)(i)(I), which prohibits emissions that contribute significantly to nonattainment or 

maintenance of a NAAQS in another state, the visibility protection requirement is narrower and 

only protects against interference with specific measures, that is, actions included in another 

state's plan to achieve a visibility goal. Reasonable progress goals, projected deciview 

improvements from regional efforts, and the like are goals or standards; they are not “measures” 

taken by or enforced by a state. 

There is nothing in the record demonstrating that any of the sources in the Proposed FIP interfere 

with any measure included in any other state’s SIP for the purpose of protecting or improving 

visibility. To the extent that EPA’s proposed interstate visibility transport FIP is not based on 

direct interference with a control measure in another state’s regional haze SIP (in contrast to 

interference with a regional haze related visibility goal), EPA’s interpretation is contrary to the 

clear and express language of Section 110. EPA’s interpretation also is contrary to the Clean Air 

Act’s clear direction that each state is to determine its own emission limits, schedules of 

compliance and other measures for sources in that state for purposes of visibility protection 

under section 169A. EPA’s interpretation would impermissibly give one state the power to 

control another state’s regional haze SIP decisions, including its BART and Reasonable Progress 

determinations. 

Finally, even if the CAA's good neighbor visibility provision required a state SIP to contain 

emission limits for sources that contribute to visibility impairment at a Class I area in another 

state, EPA has not demonstrated that any of the controls in its Proposed FIP are “necessary” for 

that purpose, considering based on the uncertainty in the modeling that these controls will result 

in actual visibility improvements. 

Response: Section 110(a)(2)(D)(i)(II) requires that each state’s SIP contain adequate provisions 

to ensure that emissions from sources within the state do not interfere with any measures to 

 

1000 Exhibit 22, Nucor's Comments in Docket EPA-R06-OAR-2008-0727 (without exhibits), December 2011. 
532

protect visibility required to be included in another state’s SIP. EPA has concluded that our FIP 

and the elements we approved in the Regional Haze SIP on March 12, 2012, together meet these 

requirements.1001

Section 110(a)(2)(D)(i)(II) does not explicitly define what is required in SIPs to prevent the 

prohibited impact on visibility in other states nor does it explicitly define how to determine if a 

state’s emissions are interfering with another state’s measures to protect visibility. We have 

interpreted this statutory requirement as providing that a Regional Haze SIP that requires 

emission reductions consistent with the assumptions the relevant RPO used to model the RPGs 

for Class I areas in other states satisfies a state’s obligation to ensure that its own emissions do 

not interfere with another state’s visibility measures. States may rely on a fully approved 

Regional Haze SIP to demonstrate that a SIP for 8-hour ozone or PM2.5 contains adequate 

provisions to prohibit emissions that interfere with visibility measures in other states.1002

Arkansas chose to address the interstate visibility transport requirement under section 

110(a)(2)(D)(i)(II) for the 1997 8-hour ozone and 1997 PM2.5 NAAQS by relying on the BART 

determinations it made in its 2008 Regional Haze SIP submittal. However, due to our previous 

partial disapproval of this submittal,1003 the Arkansas SIP does not currently include all of the 

emission reductions Arkansas agreed to achieve in its RPO process. Arkansas is a member state 

of CENRAP, the regional planning committee on regional haze. Each CENRAP state based its 

regional haze plan and RPGs on the CENRAP modeling, which was based in part on the 

emissions reductions each state intended to achieve by 2018. Within the CENRAP process, 

Arkansas promised to achieve emission reductions corresponding to BART, and these emissions 

reductions were included in the CENRAP modeling used by the participating states to develop 

their RPGs and Regional Haze SIPs. However, many of the BART determinations in the SIP did 

not meet the CAA and Regional Haze regulations, and were disapproved by EPA; therefore, the 

State’s SIP does not currently provide for all the emissions reductions that Arkansas itself 

determined to be necessary to meet the interstate visibility transport requirement. Because 

Arkansas has not provided any other analysis or explanation of how the Arkansas SIP fulfills the 

requirement of 110(a)(2)(D)(i)(II), it follows that the Arkansas SIP does not contain adequate 

provisions to prohibit emissions that would interfere with other states’ visibility protection 

measures. Therefore, we disagree with the commenters’ argument that the Arkansas RH SIP 

satisfies the interstate visibility transport requirement under section 110(a)(2)(D)(i)(II) for the 

1997 8-hour ozone and 1997 PM2.5 NAAQS. 

We disagree with Nucor’s contention that our interpretation is contrary to the CAA because the 

Act gives clear direction that each state is to determine its own emission limits, schedules of 

compliance and other measures for sources in that state for purposes of visibility protection 

under section 169A. The commenter states that our interpretation would impermissibly give one 

state the power to control another state’s regional haze SIP decisions. However, the commenter’s 

 

1001 Guidance on Infrastructure State Implementation Plan (SIP) Elements Under Clean Air Act. Sections 110(a)(1) 

and 110(a)(2) (2013) at 33; see also 76 Fed. Reg. 491 (Jan. 5, 2011) for additional explanation of EPA’s 

interpretation of these provisions of the Clean Air Act. 

1002 See “2006 Guidance for SIP Submissions to Meet Current Outstanding Obligations Under Section 

110(a)(2)(D)(i) for the 8-Hour Ozone and PM2.5 NAAQS” at pages 9-10. 

1003 77 FR 14604 (Mar, 12, 2012). 
533

interpretation is inconsistent with section 110(a)(2)(D)(i)(II)’s “good neighbor” provision, which 

requires states to prohibit emissions that interfere with other states’ measures to protect visibility. 

This statutory requirement anticipates that a state may be required to adjust its own emissions 

based on the impacts of those emissions on other states. Our Regional Haze Rule, which was 

promulgated through notice-and-comment rulemaking in 1999, also requires that states develop 

“coordinated emission management strategies” when necessary to prevent interstate visibility 

impairment.1004 Thus, while the CAA and our regulations do not allow one state to “control” 

another’s regional haze planning, they do contemplate that a state may be required to prohibit 

emissions that interfere with visibility in another state’s Class I areas. 

As stated above, Arkansas elected to address the interstate visibility transport requirement under 

section 110(a)(2)(D)(i)(II) by relying on the BART determinations that are part of its Regional 

Haze SIP submittal. Arkansas could have elected to address the interstate visibility transport 

requirement under section 110(a)(2)(D)(i)(II) by other means; we have elsewhere determined 

that states may also be able to satisfy the requirements of CAA section 110(a)(2)(D)(i)(II) with 

something less than an approved Regional Haze SIP.1005 In other words, an approved Regional 

Haze SIP is not the only possible means to satisfy the requirements of CAA section 

110(a)(2)(D)(i)(II) with respect to visibility; however such a SIP could be sufficient.1006 We also 

note that following our March 12, 2012, partial disapproval of the Arkansas RH SIP and 

Interstate Visibility Transport SIP, the State has not submitted a SIP revision with an analysis or 

explanation of how it fulfills the interstate visibility transport requirement of section 

110(a)(2)(D)(i)(II) for the 1997 8-hour ozone and PM2.5 NAAQS. 

The approved portion of the Arkansas Regional Haze SIP and our Regional Haze FIP together 

will ensure emissions reductions from Arkansas sources consistent with the assumptions used in 

the CENRAP modeling, and meets Arkansas’s obligations to address the interstate visibility 

transport requirement under section 110(a)(2)(D)(i)(II). 

We disagree with Nucor’s contention that our interpretation of section 110(a)(2)(D)(i)(II) is 

contrary to the CAA because reasonable progress goals are not “measures.” In section 169A, the 

CAA gives clear direction that each state is to include in its SIP emission limits, schedules of 

compliance and other measures as may be necessary to make reasonable progress toward the 

national goal. The reasonable progress goals are themselves “criteria for measuring ‘reasonable 

progress’ toward the national goal.” 1007 The regional haze rule, in turn, requires the following: 

Each State ... must submit a long-term strategy that addresses regional haze 

visibility impairment for each mandatory Class I Federal area within the State and 

for each mandatory Class I Federal area located outside the State which may be 

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

 

1004 40 CFR 51.308(d)(3)(i). 1005 See, e.g., Colorado (76 FR 22036 (April 20, 2011)), Idaho (76 FR 36329 (June 22, 2011)), and New Mexico (76 

FR 52388 (August, 22, 2011)). 

1006 We’ve allowed states to rely on their approved regional haze plan to meet the requirements of the visibility 

component of 110(a)(2)(D)(i)(II) because the regional haze plan achieved at least as much emissions reductions as 

projected by the RPO modeling. See 76 FR 34608, June 14, 2011 (California); 79 FR 60985, October 9, 2014 (New 

Mexico); 76 FR 36329, June 22, 2011 (Idaho); and 76 FR 38997, July 5, 2011 (Oregon). 

1007 See CAA section 169B(e)(1)(emphasis added). 
534

enforceable emissions limitations, compliance schedules, and other measures as 

necessary to achieve the reasonable progress goals established by States having 

mandatory Class I Federal areas. . . 

Where other States cause or contribute to impairment in a mandatory Class I 

Federal area, the State must demonstrate that it has included in its implementation 

plan all measures necessary to obtain its share of the emission reductions needed 

to meet the progress goal for the area. If the State has participated in a regional 

planning process, the State must ensure it has included all measures needed to 

achieve its apportionment of emission reduction obligations agreed upon through 

that process.1008

We consider it reasonable to consider the requirements of section 110(a)(2)(D)(i)(II) with respect 

to visibility in light of this requirement in the regional haze rule which explicitly requires that a 

SIP include a long-term strategy that ensures a state achieves its share of emissions reductions 

needed to meet the reasonable progress goals of the Class I areas both inside and outside the 

state. 

More fundamentally, our determination is that the controls required to meet the BART and 

reasonable progress requirements of the regional haze program will also ensure that the visibility 

transport requirements of section 110(a)(2)(D)(i)(II) will be met. We have not determined that 

this level of control is necessary to meet the visibility transport requirements but rather that these 

controls (adopted for other reasons) are sufficient to ensure compliance with the CAA’s visibility 

transport provisions (as well as the parallel regional haze requirements). Given that the level of 

control that we have determined must be provided by our regional haze FIP satisfies visibility 

transport requirements, we have not explored other approaches that would also satisfy visibility 

transport requirements. If our only obligation were to adopt a FIP to satisfy visibility transport 

requirements, we could have and would have considered such other approaches. 

In arguing that the Arkansas Regional Haze SIP satisfies the interstate visibility transport 

requirement, one commenter says that Missouri is the only state that relied upon anticipated 

BART controls from Arkansas sources, and that since Missouri’s 5-Year Progress Report SIP 

revision indicates that Missouri’s Class I areas are on track to meet the 2018 RPGs, this 

demonstrates that no additional measures are needed in Arkansas to prevent Arkansas sources 

from interfering with other states’ measures to protect visibility. As noted above, Arkansas 

promised to achieve emission reductions corresponding to BART, and these emissions 

reductions were included in the CENRAP modeling used by the participating CENRAP states, 

not just Missouri, to develop their RPGs and Regional Haze SIPs. We also noted above that 

following our March 12, 2012, partial disapproval of the Arkansas RH SIP and Interstate 

Visibility Transport SIP, the State has not submitted a SIP revision with an analysis or 

explanation of how it fulfills the interstate visibility transport requirement of section 

110(a)(2)(D)(i)(II) for the 1997 8-hour ozone and PM2.5 NAAQS. We have an obligation to 

promulgate a FIP to remedy this deficiency. Further, as we explained above, we have not 

determined that the controls required by our FIP are necessary to meet the visibility transport 

requirements but rather that these controls (adopted for other reasons) are sufficient to ensure 

 

1008 40 CFR 51.308(d)(3). 
535

compliance with the CAA’s visibility transport provisions (as well as the parallel regional haze 

requirements). As such, we disagree that the Arkansas Regional Haze SIP satisfies the interstate 

visibility transport requirement. For the reasons discussed elsewhere in our response, we are 

finalizing our determination that our Regional Haze FIP together with the approved portion of 

the Regional Haze SIP satisfy this requirement for the 1997 8-hour ozone and PM2.5 NAAQS. 

We disagree that proposing our Arkansas Regional Haze FIP and Interstate Visibility Transport 

FIP in the same action violated the Administrative Procedures Act resulting in our not providing 

adequate notice and opportunity to comment on the proposed rule. Arkansas stated in its April 2, 

2008 submittal that it is relying on the Arkansas Regional Haze Rule, the Arkansas Pollution 

Control & Ecology Commission (APC&E) Regulation 19, chapter 15 to satisfy the requirements 

of section 110(a)(2)(D)(i)(II) that emissions from Arkansas sources not interfere with measures 

required in the SIP of any other state under part C of the CAA to protect visibility. APC&E 

Regulation 19 provided for Arkansas BART emission limits for subject to BART sources some 

of which we partially disapproved in our 2012 action. Our finalized FIP addresses the emissions 

from those subject to BART sources we disapproved and the emission limits are as stringent as 

provided in the disapproved portions of the APC&E Regulation 19. Therefore, it is appropriate 

to finalize our finding that our FIP combined with the portions of the Arkansas Regional Haze 

SIP we approved meets the requirements of section 110(a)(2)(D)(i)(II) that emissions from 

Arkansas sources not interfere with measures required in the SIP of any other state under part C 

of the CAA to protect visibility. 

With regard to the comment that we cannot finalize our proposed finding that the approved 

portion of the Arkansas Regional Haze SIP and our Regional Haze FIP together will satisfy the 

interstate visibility transport requirement under section 110(a)(2)(D)(i)(II) for the 1997 8-hour 

ozone and 1997 PM2.5 NAAQS unless and until we finalize the Regional Haze FIP, based on the 

proposal, commenters were on sufficient notice regarding whether section 110(a)(2)(D)(i)(II) is 

met. We note that we are finalizing our Regional Haze FIP in today’s action and our finalized 

findings on emission limits for subject to BART sources follow are in keeping with what we 

proposed. 

We address elsewhere in this document comments contending that there is uncertainty in the 

CALPUFF modeling and uncertainty that our proposed controls will result in actual visibility 

improvements.