### Response to Comments for the Federa l Register Notice for the State of Arkansas; Regional Haze and Inters tate Visibility Transport Federal Implementation Plan

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

08/31/20162 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 Extensi on of Comment Period)

0142 AR020.0142 Domtar (Request for Extensi on of Comment Period) 0143 AR020.0143 Energy and Envi ronmental Alliance of

Arkansas (Request for Extensi on of Comment Period) 0144 AR020.0144 Arkansas Department of Environmental Quality (Request for Extension of Comment Period)

0145 AR020.0145 Arkansas Envi ronmental Federation (Request for Extensi on of Comment Period)

0146 AR020.0146

0147 AR020.0147 0148 AR020.0148 Southwest Electric Power Company (Request for Extensi on of Comment Period) 0149 AR020.0149 Entergy Arkansas Inc. (Request for Extensi on of Comment Period)

0150 AR020.0150 Nucor Steel-Arkansas (Request for Extensi on 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 Extensi on of Comment Period)

0156 AR020.0156

0157 AR020.0157

0158 AR020.0158 Dover Dixon Horne PLLC (Request for Extensi on 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 Company3 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, Ameri can 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, Earthj ustice, and National Parks

Conservation Association

0172 AR020.0172 Conway Corporation, Jonesboro City Water

and Light, West Memphis Utilities, and

O s c eo la Municipal Light and Power4 Docket ID

Number (EPA-R06-

OAR-2015- 0189-xxxx) Document

title number (AR020.xxx) Commenter Affiliation

0173 AR020.0173 Energy and Envi ronmental 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 request s 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 adequa te Reasonable Progress Analysis...........................71 3.b. Controls under reasonable progress/Arkans as’ 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 Benefi t 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 fi rst planning period..............................495 8.b. Four-unit approach for White Bluff and Independence.....................................499 8.c. Requirements for Reasona ble 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 author ity to finalize the FIP at this time................................513

8.f. EPA must address E.O. 12866 and 13211......................................................515 8.g. EPA did not adequate ly consider relevant factors............................................519

8.h. Other................................................................................................524 9. Visibility Transport......................................................................................5296 1. General and Miscellaneous

Comment: (0178) 183 members of the public stated that as Arkansan s, they value the Buffalo River, the Caney Creek Wilderness, and the Ouach ita 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 su pport 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 park s 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 ha rmed without strong action to pr otect and clean up our parks.

One commenter stated that one of the biggest re asons Arkansas is so amazing is its parks, its breathtaking natural surroundings, and its pristi ne condition. Pollution is destroying the very

essence of what makes “The Natural State” so na turally 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” doe s not become a joke. The commenter stated it seems the new attorney general opposes EPA rule s and it’s unclear on whose behalf she is working.

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

their act

‐‐ which is leadership they can get be hind. 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 th e pollution that worsens our health and makes climate change inevitable. Coal plants are enda ngering our air and cons equently are negatively impacting tourism and outdoor ac tivities. The comment ers 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 st ep it up and get serious about coal. Instead the

state tries to convince its citizens that coal is essential. The Stat e claims that without coal, the cost of electricity would skyrocket, which is fals e. Arkansas needs to inve st in alternative energy. The folks running the Coop's reap their large inco mes 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 pl ant 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 as ked 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 st ated that they still visit the park in the Spring/Summer months, and that pe ople value the parks in Arkansas.

One commenter stated that not only should strong ac tion be taken to protect our parks, but to also protect our health and ecosystem. The Obama Administration should hold firm and make these7 states greatly reduce their emissions. The Turk power plant should NEVER have been built and now Arkansas will justly pay the price. On e commenter also stated that the Obama

Administration should nationalize ev en more incentives to encour age folks to shift to solar panels or wind. States such as Arkansas that pe nalize and place obstacles to using solar should be prohibited from enacting those m easures. Thank you for all the work you do and please hold firm

to these measures.

One commenter stated that the haze represents fi lth 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 comme nter stated that more than the cynical cost

‐ benefit analysis, it is vital to remember that ev erything we do to nature, we do to ourselves and the generations to come.

Another commenter stated that air pollution al so 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 thin g and Keep the environment safe and of good quality for the generations to come. Many comment ers thanked EPA for working to protect their state of Arkansas. Commenters stated that they ar e grateful for EPA’s efforts to make their parks more enjoyable.

Response: We appreciate the commenter’s suppor t of our FIP. We acknowledge these commenters for their suppor t of our proposal.

We appreciate the commenters’ concerns regard ing 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 visibil ity impairing pollutants and there by improve visibility in Class I areas. We generally agree that the same emi ssions that cause visibili ty impairment can also cause health related problems, including adve rse effects on breathing, respiratory illness, alterations in pulmonary defenses, and aggravati on of existing cardiovascula r disease. We agree that our FIP may result in potential ancillary benefits to human health.

We also appreciate the comments regarding th e 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 regiona l 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 ag ree that our Class I areas and other national parks and wilderness areas are a source of j obs and contribute to the economies of their respective states.8 With regard to the comment that Arkansas need s to invest in alternative energy and that the federal government should nationalize more incentiv es to encourage a shif t to renewable energy
forms, we note that such comments are outside th e scope of this action an d 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 co mmenters encourage EPA to finalize a strong rule that greatly reduces emissions from the coal plants in Arkansas.

One commenter stated that the co al plants in Arkansas also th reaten the health in the 240 acre wilderness preserve Christian retreat he founde d 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, a nd antibiotic resi stant bacteria/viruses in airborne blown dust

from the scattered manure curr ently 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 reduc tions 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 Ro ck, Arkansas, many people expressed general support for the plan. The speakers at the public hearing incl uded members of various organizations and members of the general public.

Response: We appreciate the commenter’s suppor t 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 EP A’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 acclaime d accounts (Hunter & Dunbar, Schoolcraft, and Nuttall) of early exploration of Arkansas and ha ve been fascinated by th e descriptions of the environment, flora, fauna, soil, rocks, minerals, and water. The commenter states that the rules promulgated in EPA’s proposal wi ll help protect the Buffalo Na tional River, Ouachita National Forest, and Caney Creek Wilderness area, which are national and Arkansas treasures. Protecting these treasures will provide both eco nomic 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, re spiratory illness, alterations in pulmonary defenses, and aggravation of existing cardiovasc ular 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 regi onal 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 ar eas 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, photographe rs, and others would benefit from this change. It would allow Arkansas's great views to be seen by future ge nerations. I favor the reduction of haze pollution for two reasons. First, my greates t hobbies involve the outdoors. I take two vacations every year. Both of these trips take me to the Buffalo Ri ver. I camp, hike, and canoe. I spend my money in Arkansas to spend time in Arkansas. I need my tim e 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 out doors. 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 th at she is a resident of L ittle Rock, Arkansas, and is writing in support of the Regi onal Haze Plan. Requiring the White Bluff and Independence10 power plants in our state to reduce pollutants by retrofitting their infr astructure 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 ha s 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 in cludes sulfur dioxide, nitrogen oxides and particulate matter, affects these disadvantaged communities the most, but wind patterns also ensure that these pollutants ar e 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 respirat ory 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” a nd 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 Ar ea. The plan would improve air quality and visibility in these places, gene rally having a positive impact on th e experiences of their visitors. Some communities nearby these attractions re ly on the economic boost of visitors enjoying nature near their towns. However, if air quality conti nues to decline, the influx of tourists to these areas could be compromised as well.

Finally, the Regional Haze rule could help move Ar kansas 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 pot entially moving up the date of retirement for coal plants, the rule could push the state toward more clean, rene wable 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, re spiratory illness, alterations in pulmonary defenses, and aggravation of existing cardiovasc ular 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 regi onal 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 ar eas are a source of jobs and contribute to the economies of their respective states.

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

BART emission limits for visibil ity impairing pollutants (i.e., SO 2 , NO X , and PM), through the analysis of potential installati on 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 our11 emission limits by voluntarily retiring or switching fr om 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 expre ssed gratitude to the EPA administrators for holding this hearing on its Draft Regiona l Haze Plan for Arkansas. The commenter stated that she is a

former Vice President of the National A udubon 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 im portant 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 ha ve 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 elde rly and all those suffering from bronchitis, asthma and other respiratory illnesses, our local communities, familie s and hospitals have been footing the bill. It is high time to stop putting the cost of our “ch eap 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 Regiona l Haze plan because it will move Arkansas

towards a cleaner and healthier future as the utilities embrace renewabl e 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, re spiratory illness, alterations in pulmonary defenses, and aggravation of existing cardiovasc ular 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 H aze and Interstate Visibility Transport Federal Implementation Plan. The Regional Haze plan will benefit our state's economy, health, and12 natural environment. Reducing th e amount of haze in the Buffalo River area will make the area more attractive to visitors and ultimately, boos t tourism revenue. What's more, the Ozarks and

Buffalo River are natural treasures of the Natura l State. These areas s hould be preserved to benefit local residents, visitors, and future ge nerations. 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 re gion and reduce the effect of pollution on fragile plants, animals, and ot her 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, re spiratory illness, alterations in pulmonary defenses, and aggravation of existing cardiovasc ular 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 negati ve ecosystem impacts of visibility impairing emissions. We agree that visibility impairi ng 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 prot ection of visibility in national parks and wilderness areas is expected to have a positive impact on tourism a nd the economy, as noted by the commenter. We agree that our Class I areas and other national pa rks 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 be lieves that Arkansas companies and agencies should be forced to clean up two of th e 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 se rious effort to slow dow n the current business as usual mode of operation. As a consumer I am r eady 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 fo r 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 firs t 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 scien tist, I do understand the implicatio ns 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 producti on. 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 unbelievabl e. California’s central valley is unbelievably polluted with the air visible and shockingly a yell ow-grey smog. It is asto nishing to see. Pine13 bark beetles have devastated th e 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, pleas e 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., SO 2 , NO X , and PM) and intended to improve visibility

conditions in Class I areas. As our FIP will re duce these emissions, we agree that our FIP may result in potential ancillary benefits relate d to reduction of greenhous e gases such as carbon

dioxide and nitrous oxide that contribute to climate change.

Under the Regional Haze regulations we are aut horized to require affected sources to meet emission limits for visibility impairing pollutants (i.e., SO 2 , NO X , 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 en ergy. However, sources may choose to meet our emission limits by volunt arily retiring or switching fuels.

We recognize that it is an unfor tunate consequence that the requ irement 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 el ectricity rates. We are not authorized to prevent companies from doing so. However, we are very sens itive to the ramificati ons of our actions and we seek to select the most cost-effective opti ons when we propose and fi nalize these controls.

We appreciate the comment regarding the negati ve ecosystem impacts of visibility impairing emissions. We agree that visibility impairi ng 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 comme nds 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 Ri ver corridor and its associated, federally designated wilderness, the Ouachita, Caney Creek W ilderness 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 en ergy. Arkansas can enj oy better health, robust economic growth and the beauty of our state an d national parks and other natural environments.14 I support EPA’s Option 1 that will reduce emissions of both SO 2 and NO X . This is the least we can do until all coal-fired power plants are re tired. 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 pollu tion 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 Buffa lo 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 el evating business. However, if ai r 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 dirtie st power plants to inst all retrofit technology in order to reduce pollutants. The pow er plants affected include Arka nsas’s two largest and dirtiest

coal

‐ fired power plants, Entergy's 1700MW Wh ite Bluff and Independence plants.

Coal

‐ fired power plants emit horrendous amounts of pollution that are hazardous to human health. These pollutants include su lfur dioxide, nitrogen oxides a nd 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 resp iratory problems.

The draft Regional Haze plan could help move Arka nsas in the right direction when it comes to our energy future. In putting more restrictions on di rty energy sources an d 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 SO 2 and NO X controls for Independence in our final FIP. The air pollution c ontrol measures we are requiring in our FIP are

intended to control emissions of visi bility impairing pollutants (i.e., SO 2 , NO X , and PM) and improve visibility conditions in Class I area s Under the regional haze regulations, we are authorized to require affected sources to meet emission limits for visibility impairing pollutants (i.e., SO 2 , NO X , and PM), but we are not authorized to di ctate what type of technology the source must employ to meet those emission limits and we ar e 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 re tiring or switching fuels.

We generally agree that the same emissions that cause visibil ity impairment can also cause health related problems, including adverse effect s 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 bene fits to human health.15 EPA also recognizes that the prot ection 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 pa rks and wilderness areas are a source of jobs and contribute to the economies of their respective stat es, but note that for pur poses 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 plan ts. 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 cl eanest city in the United States. Please allow

the concerned residents of this beau tiful state to continue to praise the clean water, air and cities in our state by making Entergy do th e right thing and clean up thei r dirty, polluting power plants that are harming our resident s 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 incr easingly 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 th e 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 park s and wilderness areas are preserved. Based on the context of the comment, it appear s that the commenter intended to state that our plan needs to have more emphasis (rather than “more rest riction”) 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 no t authorized to dictate what type of technology the source must employ to meet those emission lim its and we are not author ized to force sources to retire. However, sources may choose to voluntarily retire or switch fu els to meet our emission limits. We take no position on any other spec ific 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 th ey be from a hog concentrated animal feeding operation (cafo), a chicken house, smoke, coal dus t, crop fumigation, etc. It has happened on many occasions and it is sad to think that Arka nsas 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 literac y, 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 is sues better than we do. The commenter urges EPA to support reduction of pollu tion 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 expre ssed support for the EPA plan to clean up haze in the northwest Arkansas region of the state. The commen ter stated that it is past time to clean up our power-generating plants and to switch from bur ning coal to other technologies that are not polluting and that are sustainable. We cannot con tinue to pollute our pl anet 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 reali ze by continuing to burn coal. The cost is only being measured in terms of producing energy. Th e energy coops are not including the costs to society of the pollution that is generated by it. Th ese include the health costs, lost productivity, lost tourism revenues, global warming and the we ather consequences, the costs of polluting the ground and rivers, etc. Change is difficult but it is inevitable. The coal-fir ed 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 FI P. 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 thes e 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 cease17 coal combustion. Under the Regiona l Haze regulations we are aut horized to require affected

sources to meet emission limits fo r visibility impairing pollutants, but we are not authorized to dictate what type of technology th e source must employ to meet those emission limits and we are

not authorized to force sources to cease co al combustion. However, sources may choose to voluntarily retire or switch from coal to othe r fuels to meet our emission limits. We take no position on any other specific statem ent 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 Bu ffalo 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 th e valley smoke from prescribed burns would cloud the sky and the sun would be shrouded for week s. The smoke would cause headaches and sore

throats and I'd have to shut the windows & door s to try and escape when I was ready to be enjoying the spring and gardening. The black so ot 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 th e state under the Clean Water, anti-degradation Act. Hog waste is spread by the millions of ga llons from January – November each year. The smell, the haze, manure spreading and run-off of this operation is allowe d with no consideration of the community, the Mt Judea School, its childr en, 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. La st week while at the Carver recreation site on the Buffalo River the smell of hogs was str ong 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 wast e into the air then drifting and settling outs ide of the hog factory. These are onl y 2 examples of the state's on-going haze issues. The smell and thickening of air fr om a hog factory and smoke engulfing the valleys when I wish to enjoy time on the cree ks, my garden or outdoor recreation.

An old saying in Arkansas is “If you don't lik e the weather, wait a few minutes and it will change.” Weather here can go from 70 to 20 in a couple of hours. 20 degr ee changes are frequent and with that inversions trap air in th e 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 di rection and enforcement. Help our state come into compliance and enforce positiv e goals instead of continuing to subject its residents to capitalistic enterprises which endang er 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 comme nters (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 h ealth impacts and that our FIP would have potential ancillary health benefits.

Response: We appreciate the commenters’ concerns rega rding the adverse health effects of the air pollutants that also c ontribute to visibility impairment a nd 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 visibil ity impairing pollutants and there by improve visibility in Class I areas. We generally agree that the same emi ssions that cause visibili ty impairment can also cause health related problems, including adve rse effects on breathing, respiratory illness, alterations in pulmonary defenses, and aggravati on of existing cardiovascula r disease. We agree that our FIP may result in potential ancillary benefits to human health.

Comment: Multiple public hearing comment ers (0152-2, 0152-7, 0152-9, 0152-12, 0152-16, 0152-22, 0152-32, 0152-43) who expressed general suppo rt for our FIP proposal noted that our FIP would require controls on th e two largest coal plants in Arkansas, and some of these commenters also noted that these plants do not currently have air po llution 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 SO 2 and NO X emissions from the two largest point sources in Arkansas, the White Bluff and Independence Power Plants.

Comment: Multiple public hearing comme nters (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 commente rs’ support of our FIP.

Comment: Some public hearing co mmenters (0152-8, 0152-13) specifically expressed support for requiring controls on the I ndependence plant in our FIP.

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

SO 2 and NO X controls on the Independence plant.19 Comment: Multiple public hearing comment ers (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 co mmenters also indicated that we should work towards retiring/shutting down coal plants.

Response: We appreciate the commenters’ suppor t 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., SO 2 , NO X , and PM), through the analysis of potential

installation of various c ontrol 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 lim it rather than control requirements. We also are not authorized under the CAA provisions for regiona l haze to require a shift to renewable forms of energy.

Comment: Some public hearing comme nters (0152-12, 0152-24) noted th at visibility impairing pollutants have adverse impacts on ecosystems and that our FIP would provi de ancillary benefits in terms of reduced adverse impacts to ecosystems.

Response: We agree that visibility impairing po llutants 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 impr oving visibility in Arka nsas’ 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 ag ree that our Class I areas and other national parks and wilderness areas are a source of j obs and contribute to the economies of their respective states.

Comment: Multiple public hearing co mmenters (0152-17, 0152-19, 0152-21, 0152-22, 0152- 30) generally supported our FIP prop osal, noting that the benefits of the controls would outweigh the visibility benefits and the ancillary benefits.

Response: We appreciate the commen ters’ 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 count ries are not held to the same standards. If20 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 electr ic bill could mean no electricity for some people.

Response: We acknowledge the commenter’s concerns. Co nsistent 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 Fe deral areas (located in this country). Our action requires pa rticular Arkansas sources to control emissions that impact visibility at Arkansas and Missouri Class I areas. Our acti on does not in any way expect Arkansas to make up for emissions from inte rnational sources. On the other hand, as we discussed in the preamble to the Regional H aze 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 impairme nt caused by sources located within their jurisdiction.” 1 While the goal of the regional haze progr am 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 pr ogress 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 anticipat ed to prevent Arkansas from attaining the goal of natural visibility conditions at its Class I areas, we recognize th at 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 fr om sources where reasonable c ontrols are not available. However, states are still required to demonstrate that they are establishing a reasonable rate of progress that includes implementation of reasona ble measures within the state to address visibility impairment in an effo rt to make progress towards the na tural visibility goal during each planning period. We acknowledge the commenter’s concern regarding potential increases in electricity rates. While our consideration of co st 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 conc ern 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 comm enter noted that the FIP is a visi bility 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 previ ous comment, we acknowledge the concern regarding potential incr eases in electricity rates. While our consideration of cost under the Regional Haze Rule is limited to the direct cost s 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 la wsuit, 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 St ate and/or promulgate a FIP within two years of our partial disappr oval 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 th e scope of our proposed

action.

Comment: Some public hearing commenters [0152- 1, 0152-15] were against our FIP, and expressed concern over the high co sts 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 th is document where we discuss cost issues.

Comment: ADEQ agrees with EPA’s determinatio n 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 Cros sett 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 anal ysis of these boilers and determines that, whether BART-eligible or not, neith er boiler has visibility impact s sufficient to be considered subject-to-BART. 4 ADEQ concurs that neither of thes e boilers should be subject-to-BART.

Response: We appreciate ADEQ’s support of our propos al. We are finalizing our determination that the Georgia Pacific Crosse tt Mill 6A and 9A Power Boile rs are not subject-to-BART.

Comment: [Arkansas Audubon Society (0151) p. 1] Th e Arkansas Audubon Society stated that it is a statewide organization committed to fosteri ng 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 Trans port 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 ecologi cal integrity and our abil ity as citizens to enjoy these areas. The aforementioned rule would enact regul ations to protect the ai r quality of some of our most precious natural areas including the Bu ffalo National River, Caney Creek Wilderness,

and Ouachita National Forest. We believe that Option 1, which includes the control of both SO 2 and NOx emissions, is the best way forward to reduce haze as well as potentially improve the

health of Arkansans who liv e in the affected areas.

We applaud your move to enforce stricter regu lations on emissions in order to reduce their negative impacts in our atmosphere. Thank you fo r considering our comments on this important

matter.

Response: We appreciate the commenter’s support rega rding our FIP, incl uding support of our proposed Option 1. For the reasons discussed in other sections of th is document, we are finalizing both SO 2 and NO X 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 stat ewide organization dedicated to achieving social, economic and environmental justice by organi zing citizen groups around the stat e, 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 Im plementation Plan and favors the proposed Option 1 over the proposed Option 2. The draft plan would assist in prot ecting two of Arkansas’ treasured areas, the Caney Creek Wilderness Area and the Upper Buffalo Wilderness Area. The proposal to control SO 2 , NO X , and PM BART for nine units at six facilities in Arkansas will clean up haze problems in these unique areas an d 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 th e great outdoors are entr enched 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 Pa rk Service, U.S. Department of the Interior. Natural Resource Report NPS/NRSS/EQD/NRR--

‐ 2014/765. http://www.nature.nps.gov/socialscie nce/docs/NPSVSE2012_final_nrss.pdf

7 Id.23 natural visibility and ai r quality of these areas is detrimental to protecting Arkansas’ economy,

culture and values.

The APPP supports a transition away from coal-fir ed power and does not fi nd that retrofitting the plants and allowing them to continue operating is a sound solution, especia lly if those costs are passed on to the ratepayer. However, the dr aft 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 s upport of our FIP and the commenter’s preference of our proposed Option 1. For the reas ons discussed elsewhere in this document, we are finalizing both SO 2 and NO X controls for Independence in our final FIP. Based on the context of the comments, it appears that the commente r intended to state that preserving the natural visibility and air quali ty 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 quali ty in national parks and wilderne ss 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 a ffected sources to meet BART emission limits for visibility impairing pollutants (i.e., SO 2 , NO X , 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 unf ortunate consequence th at the requirement of

controls to reduce emissions from power plants often results in electric companies passing on the costs of these controls to ratepa yers in the form of increased el ectricity rates. However, we do not have the authority to prev ent companies from doing this.

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

Comment: [Entergy Arkansas Inc. (0166) p. 56] Enter gy stated it agrees with EPA’s proposal that the existing emission limits at the White Bluff Auxiliary Boiler satisfy BART for SO 2 , NO X , and PM. 80 Fed. Reg. at 18,975. Entergy also agr ees that 2009-2011 should be used as the baseline period for NO X 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 scrubb ers do not constitute BART for White Bluff and should not be installed at Independence to meet reasonable progress re quirements. 80 Fed. Reg. at 18,972, 18,993. Entergy also agrees with EPA that LN B/SOFA/SNCR or LNB/SOFA/SCR cannot be justified as BART for White Bluff based on the incr emental 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] Enter gy Arkansas Inc. stated that if EPA finalizes a source-specific NO X BART limit for Lake Catherine Unit 4, Entergy requests that EPA confirm that the unit may continue to c onduct monitoring pursuant to 40 C.F.R. Part 75 Appendix E so long as it qualifie s as a peaking unit. In the Pr oposal, EPA appears to have assumed that Unit 4 currently operates “full” NO X CEMS with a continuous NO X analyzer pursuant to 40 C.F.R. Part 60. However, becaus e Unit 4 meets the definition of a peaking unit under 40 C.F.R. Part 75, and the unit is not subjec t to any NSPS Part 60 standards, Entergy does not currently operate a NO X analyzer for the unit. Under Part 75, Unit 4 qualifies as an Appendix E unit, allowing the unit to utilize a NO X correlation curve to es timate emissions and only monitor heat input and exhaust O 2 concentration.

Response: We are finalizing the NO X 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 NO X correlation curve to estimate NO X emissions and only monitor heat input and exhaust O 2 concentration. We are revising our propos ed section 52.173(c) to reflect this.

Comment: [Nucor Steel-Arkansas and Nucor-Yamat o Steel Company (0163) p. 1-2] Nucor stated that it operates electric arc furnace st eel 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 recycler s 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 T echnology (BART) determinations under EPA's Proposed FIP: Entergy's White Bluff power plant (White Bluf f), SWEPCO's Flint Creek power plant (Flint Creek), AECC's Bailey power plant (Bailey), an d AECC's McClellan power plant (McClellan). AECC also is a co-owner of Entergy's Indepe ndence 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 baselo ad generating capacity for AECC and its member cooperatives. NSA and NYS's elect ric 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, incl uding 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-Yamat o Steel Company (0163) p. 6-9] Nucor stated that Congress first adopted regional ha ze provisions in 1977 to establish a national goal

that would address haze issues in national parks and other fe deral “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) re asonable progress goals for Class I areas in the state; (2) a long-term strategy; and (3) implemen tation 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 n ecessary 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 ach ieved by a particular date.” 64 Fed. Reg. 35,714, 35,733 (July 1, 1999). Further, States have consid erable discretion in establishing reasonable progress goals; for instance, the Clean Air Act “r equires only that a st ate 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 esta blishing 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 complia nce; 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 vi sibility improvement over time.” See, USEPA, “Guidance for Setting Reasonable Progress Goal s 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 fact ors: (1) the costs of co mpliance; (2) the energy and nonair quality environmental impacts of compliance; (3) any ex isting pollution control technology in use at the source; (4 ) the remaining useful life of th e 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 Ac t's regional haze provisions with a long-term goal of returning national parks and certain scenic areas to a state of natural visibility. Ho wever, Congress realized such changes could not be fully realized immedi ately 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 em issions reductions from levels that have achieved the desired target today. Furthermore, EPA has failed to e xplain 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 ou r proposed FIP is inappropriate or unnecessary because Arkansas Class I areas are already projec ted 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 approva l of the RPGs for other states that are not expected to reach natural visibility c onditions until after 2064. We address elsewhere in this document comments contending that ADE Q’s Five-Year Progress SIP revision shows that

IMPROVE monitor data indicate th at 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 promulga ting 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 ac tual 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 Re gional Haze and Interstate Visibility Transport (the “Proposed Rule”). 9 Specifically, the Proposed Rule addr esses 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 requiremen ts for pollutants that affect visibility in Class I federal areas in Arkansas and nearby states. Am ong other things, the Pr oposed Rule includes

emission limitations based on installati on of BART controls for sulfur SO 2 and NO X at the Entergy White Bluff Plant (“White Bluff”) and two proposed alternative options for controlling emissions from the Entergy Independence Plan t (“Independence Plant” ) under the regional haze reasonable progress requirements.

EMI is a corporation organized under the laws of the State of Mississippi and pr ovides electric service in Mississippi. EMI is an electric public utility under the Mississippi Public Utilities Act of 1956, as amended. EMI provides retail electric se rvice in portions of 45 counties in western Mississippi pursuant to certificates of public convenience and necessi ty issued by the Mississippi Public Service Commission (“MPSC”) in Dock et 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 Mu nicipal 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 ow nership interest in 1981 in each of the two generating units at the Independ ence Plant, pursuant to, among other things, the approval of the MPSC in Docket U-4873. The Inde pendence 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 st rong interest in ensuring th e proper implementation of the regional haze and interstate visi bility 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 se t point in the Mill’s operational controls for the cau stic addition. For cl arification 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 clar ification provided by the commenter regarding background information discussed in ou r proposal regarding oper ation of the existing

scrubbers on Power Boiler No. 2. We do note that the clarification provi ded by Domtar does not affect our final BART decision regarding SO 2 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 goa l, the Agency should allow stat es to consider how best to assess and plan additional controls activities, cons istent 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 in stallation 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 regardin g unit-specific and other technical and legal

concerns.

Response: We acknowledge the commenter’s concerns a nd suggestions with regard to our and the states’ work on the regional ha ze SIPs for future planning peri ods. 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-SWE PCO). Our responses to Entergy’s and AEPSWEPCO’s specific comments are pr ovided throughout this document.28 Comment: [Entergy Arkansas Inc. (0166) p.1] Enter gy Arkansas Inc. stated that on April 8, 2015, the EPA published a proposed Federal Implem entation Plan (FIP) to address certain regional haze and visibility tr ansport requirements for the Stat e of Arkansas (80 FR 18944). The proposed FIP would address the requirements of th e Regional Haze rule and interstate visibility transport for those portions of Arkansas’ SIP that EPA had previous ly disapproved (77 FR 14604, March 12, 2012). The proposed FIP addresse s the requirements for BART for those sources for which EPA did not approve Arkans as’ BART determinations, Reasonable Progress Goals, reasonable progress contro ls and a long-term strategy, as we ll 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 f acilities 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 SO 2 and NO X BART limits for White Bluff Units 1 and 2, and SO 2 , NO X , and PM BART limits for the Auxiliary Boiler at White Bluff. EPA also is proposing a NO X BART limit for Unit 4 at Lake Catherine. Finally, EPA is proposing emissi ons limits at Independence to meet reasonable progress requirements and is seeking comment on two alternative options. Under Option 1, EPA is proposing SO 2 and NO X emission limits for Units 1 and 2 at Independence. Under Option 2, EPA is proposing only SO 2 emission limits for Units 1 and 2. EPA also is soliciting comment on any alternative control measures for White Blu ff Units 1 and 2 and Independence Units 1 and 2 that would address the BART and reasonable prog ress requirements for these four units for the current regional haze planning period.

Response : We take no position on Entergy’s synops is 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 In c. 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 y ears. 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 visi bility conditions at a ll Class I areas in the United States. The program also is intende d to recognize that regional haze is a regional problem; one that benefits from broad programma tic changes and the retirement of sources as they reach the end of their usef ul 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 im pose more than $2 billion in costs on Entergy Arkansas Inc.’s customers and co-owners despite th e lack of any need for, or benefit from, such

a massive investment.

Response: We disagree with Entergy Arkansas In c.’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 such29 controls. These comments are addressed in detail elsewhere in this RTC document. Further, we take no position as to Entergy’s characterizati on 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 EP A’s proposed FIP, and is a long-term, multi-unit approach to address regional haze in the Arka nsas Class I areas that achieves reasonable progress, is consistent with th e statutory scheme and allows En tergy to manage its generation

fleet in a reliable and economic manner. Enter gy 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 follo wing: (1) achieving early SO 2 reductions by accepting lower interim

SO 2 emission rate limitations at both White Bluff and Independence; (2) achieving NOx reductions by installing NOx c ontrol technology on all four units within three years of the effective date of EPA’s final FIP; and (3) comm itting 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 re quire the installation of scrubbe rs 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 driv e the costs of the scrubbers to over $7,500-$8,500 per ton of SO 2 removed. Based on modeling conducte d 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 SO 2 and NO X limits based on the installation of dry scrubbers and

NOx controls on the two coal-fired units at Inde pendence 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 Inde pendence 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 ra te of progress (“URP” or “glide path”) that EPA uses to ensure reasonable progress towards natural visibility condi tions and that EPA had previously approved for Arkansas. 10 Based on the negligible visibi lity benefit from installing scrubbers at Independence, the cost of the cont rols is an astounding $1.33 billion to $1.53 billion per deciview improvement. Scrubbe rs at Independence are simply not necessary to ensure that visibility in Arkansas’ Class I areas remains be low the URP, nor are they justifiable based on EPA’s own analysis of the visibility bene fits resulting from such a huge investment. 11 According to modeling performed by the Central Regiona l Air Planning Associat ion (CENRAP), all of Arkansas’ elevated point sources (including all power plants a nd 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 ac hieve 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 visibili ty impact comes from non-Arkansas point

sources and mobile sources. Becau se of the Mercury and Air T oxic Standards (“MATS”) rule, 12
the continuing benefits of the Cl ean Air Interstate Rule (“CAIR”) , the next phase of the Cross State Air Pollution Rule (“CSAPR”), and implem entation of the soon-to-b e-released revised 8- hour ozone National Ambient Air Quality St andards (“NAAQS”), along with continuing reductions in emissions from mobile sources, th e 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 interi m controls and proposed commitment to cease coal burning at White Bluff, no fu rther 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 regulat ory 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 a ppropriate to evaluate Entergy Independence even though Arkansas Cla ss I areas and those outside Arkansas most significantly impacted by Arkansas sources are pr ojected to meet the URP for the first planning period.”). Indeed, after the proposed BART contro ls 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 Buffa lo 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 natura l visibility in Arkansas’ Class

I areas.

EPA’s reasonable progress analys is and justification for proposi ng 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 suggest s it is only logical to require Independence to install controls because its SO 2 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 SO 2 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 smal l and reductions are not needed to demonstrate that Arkansas is making reasonabl e progress towards achieving natura l 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 an d necessary to regulate hazardous air pollutant emissions from electric generating units (“EGUs”), several EGUs alre ady have installed controls to comply with MATS or have undertaken other steps to reduce thei r emissions. Even if the rule is stayed or vacated while EPA undertakes its cost analysis, Entergy expects that the rule will go forwar d before the end of this planning period along with the

associated emission reductions.31 EPA also improperly relied on CALPUFF mode ling to justify the proposed controls at Independence, vastly overstating the impact of emissions from Independence and the benefits of installing controls. CALPUFF mode ling, a single source puff model, is not an appropriate model to determine or project reasonable progress be nefits. Reasonable progress is determined by evaluating the overall visibility valu es in Class I areas and the projec ted trends in visibility as a result of emissions, controls a nd operations at all sources contri buting to visibility impairment. EPA has recognized in recent rulemakings that CALPUFF cannot do this and it is therefore arbitrary and capricious for EPA to re ly on CALPUFF for this purpose here.

Response: We acknowledge Entergy’s summary of its proposed approach and summary of its comments. Entergy’s specific co mments on its proposed approach and on each of the issues mentioned in its summary and our responses to t hose comments are provided in other sections of

this document.

Comment: [Nucor Steel-Arkansas and Nucor-Yamat o Steel Company (0163) p. 3-5] Nucor Steel-Arkansas (NYS) and Nucor-Yamato Steel Comp any (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 Progre ss decision for Independence are necessary, (b) EPA failed to consider releva nt factors in its BART and R easonable Progress determinations for White Bluff, Flint Creek and Independence, (c) EPA failed to consider al l available control technologies in its BART and Reasonable Progress determinations for White Blu ff, Flint Creek and Independence, (d) EPA's determinations on cost-effectiveness of additional controls for White Bluff, Flint Creek and Independence are not ju stified, are unreasonable, are in consistent and are arbitrary and capricious, (e) EPA's determinations of visi bility 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 th e CALPUFF model is unsuitable for EPA's regulatory determinations under these circumstan ces (thus, EPA has not demonstrated that there is a reasonable certainty that the c ontrols required under its BART and Reasonable Progress determinations will result in an improvement in visibility, (f) EPA has unduly relied on its cost-effectivene ss calculations and has not explained how its cost-effectiveness calculations justify its BART and Reasonable Progress determinations with respect to anticipated vi sibility 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 SI P, 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 co mply with 42 U.S.C. §7410(a)(2)(D)(i)(II)).32 In addition, EPA did not explain how it exercise d 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 exercise d its judgment in weighing and balancing the BART and R easonable 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 rulemaki ng. The basis for our fina l action, including our weighing and balancing of the rele vant factors, is contained in the record for this rulemaking which is available at regulations.gov. Please se e our responses in the legal section regarding EPA’s authority to promulgate a FIP more than two years si nce EPA disapproved Arkansas’s regional haze SIP.

Comment: [Entergy Mississippi Inc. (0168) p. 3] EMI st ated 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 visibil ity in 156 national parks and wilderness areas designated as mandatory Class I federal ar eas. In 1999, EPA promulgated the Regional Haze Rule (“RHR”) 15 to address regional haze impairment a nd establish a comprehensive visibility protection program for Class I ar eas, which calls for the eliminat ion of man-made visibility impairment at Class 1 federal areas by 2064. Th e 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 th e 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 EP A 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 SO 2 and NO X 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), codi fied 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 pl an (“SIP”) process, to review the statutory factors on a periodic basis and determine appropria te 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 Unif orm Rate of Progress (“URP” or “glide path”) for elimination of visibility impair ment 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 lega l and factual errors is to impose hundreds of millions of dollars of unnecessary expense on Arka nsas’ 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 signi ficant portion of the Independence Plant and, as such, has particulari zed concerns about the Proposed Rule’s legal and factual errors as they relate to the reasona ble progress analysis and determinations in the Proposed Rule. Many of the errors and inaccuraci es in the reasonable progress determinations stem from EPA’s artificially low assumptions rega rding the costs of controls for the White Bluff Plant. Furthermore, the totality of the Proposed Rule fails to account fo r Entergy’s alternative proposal that would yield equivalent visibility improvements at tremendously less cost (over $2 billion). Accordingly, EPA’s final rule shoul d 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 info rmation 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 commen ter in more detail elsewhere. Please see our responses to those more specific comments.

Comment: Summary of ADEQ’s comments. [ADEQ (0144), cover le tter and p. 1-2] ADEQ stated that in 1977, Congress amended the Clean Ai r Act (“CAA”) to include the national goal of preventing any future and remedying any existing im pairment 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, th ere 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 cont ain provisions that encourage state, local, and tribal agencies to work cooperatively w ithin regional planning or ganizations to address visibility impairment. In accord ance 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 Implementati on 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 partia lly 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 be ing the Natural State a nd its ongoing efforts to maintain excellent air quality. The EPA published on April 8, 2015, a proposed Federal Implementation Plan covering Regional Haze and Inte rstate Visibility Transport for the State of Arkansas (“Proposed FIP”). The Arkansas Depa rtment of Environmenta l Quality (ADEQ) has reviewed the Proposed FIP and ha s 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 Visibilit y. 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 lack ing in clarity. Furthermore, EPA acted arbitrarily in developing a proposal which is inconsistent with the approach ta ken 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 Av ailable Retrofit Technology (BART). Despite this fact, EPA improperly performed its own reasonabl e progress analysis. EPA indicated this was performed by applying the reasonable progress f actors set forth in the Regional Haze Rule to require specific emissions controls for Enter gy 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 meas ures for the Entergy Independence Plant are both unnecessary and arbitrary. The State of Arkans as 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 Inde pendence Plant through a cursory evaluation of the National Emissions Inve ntory data, not a reason ed evaluation utilizing

the established framework that takes into accoun t, among other factors, the costs of compliance and progress made to date.

Under the Proposed FIP, certain entities that ar e already complying with portions of the Clean Air Act aimed at reducing interstate transport of air pollution under the Cr oss-State Air Pollution Rule (CSAPR) would also have to install additiona l 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 NO X controls, EPA should determine that

17 Approval and Promulgation of Impl ementation Plans; Arkansas; Region al Haze State Implementation Plan; Interstate Transport State Implementati on 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 Implem entation Plans; Arkansas; Regional H aze 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 NO X 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 re presentative accounting of the emissions in Arkansas. In support of this simp ler 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 represen ts arbitrary decisionmaking that leads to unjustified dispar ities in treatment among the states.

Furthermore, EPA’s metrics used throughout th e Proposed FIP are misleading and not supported on a legal or technical basis. Fo r instance, the cumulative visib ility effects metric lacks a sound scientific basis and is not supported in the Regi onal 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 th e 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 dolla rs in economic costs in

return for a few dollars in health or envir onmental benefits. Accordingly, EPA should have performed an analysis to properly determine the ex tent 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 re cent decision that is fu rther discussed in the attached comments, the United States Court of A ppeals for the Ninth Circuit recently issued a decision that called into question the use and relia bility of the CALPUFF visibility model as a means of identifying affected faci lities when those facili ties are more than 200 kilometers from a

Class I area and the simulated visi bility 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 synops is 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 Re gional Haze Rule, which resulted in requiring unneeded emissions controls for the Entergy In dependence 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 additi on, 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 Dece mber 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 resolutio n 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. Fo llowing litigation over the appropriate date for final action on the Ar kansas regional haze plan, litigation in which Arkansas participated, the court entered an orde r establishing a date fo r final action. We are accordingly subject to a court-or dered deadline to take final ac tion to promulgate a FIP or approve a SIP revision that addr esses the deficiencies in th e Arkansas RH SIP by August 31,

2016. 20 Although we have not yet seen a revised SIP revision from Arkans as, 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 ADE Q 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 th at 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 mode l’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 wi ll be submitted during the reopened comment period.) Without waiving the signif icant legal issues with the BA RT 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 proj ect. 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 y ears 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 vari ety 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 a ssets 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 larges t integrated marketer of uncoa ted freesheet paper in North America. Domtar operates pulp a nd paper Mills and personal care facilities in the US, Canada, Spain and Sweden. In the US we operate in th e following states: Arkansas, Kentucky, Georgia, Michigan, North Carolina, Ohio, Pennsylvani a, South Carolina, Tennessee, Texas and

Wisconsin.

The Ashdown Mill operates in very dynamic, ch anging 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 th rough 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 traditio nal paper markets continue to shrink rapidly. To a significant extent, the market is transiti oning 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 comme nter in more detail elsewhere. Please see our responses to those more specific comments.

Comment: [AEP-SWEPCO July 15, 2015 commen ts (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 (A EP), stated it appreciates the opportunity to provide comments to the U.S. Environmental Pr otection 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 ti me announced the availab ility 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 Cree k Power Plant and supports EPA's approval of

the SO 2 portions of the Flint Creek BART analysis as submitted. AEP-SWEPCO is a 50% owner of Flint Creek Power Plant along with Arkans as Electric Cooperative Corporation (AECC). AEP-SWEPCO also supports EPA's previous approval of the partic ulate 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 suppo rt 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 transmissi ons 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 appr oximately 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 s ubstantial parts of a st ate 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 inters tate 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 tec hnology (“BART”) requirements for ni ne units at six facilities in

Arkansas. Id . at 18,945-46. It would also impose emi ssion 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 re quirements, the proposed FIP would establish new reasonable pr ogress goals (“RPGs”) for the tw o Class I areas in Arkansas.

Id. at 18,997-98. The proposed FIP would incorporat e 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 Ar kansas’s SIP that EPA a pproved, would address the visibility-related interstate transport requireme nts 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 informa tion provided by UARG. We take no position with regard to UARG’s s ynopsis of our proposed FIP.

Comment: UARG provides background inform ation 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 preven tion of any future, and the remedying of any existing, impairment of visibili ty 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 progre ss toward meeting the national goal,” id. § 169A(a)(4), and to require each state to s ubmit a SIP that “contain[s] such emission limits, schedules of compliance and other measures as may be necessary to make reasonable progress toward meeti ng 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 (i ii) 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 provid e that for each mandatory Class I federal area in a state, the state must establish goals, e xpressed in deciviews (“dv”), that “provide for reasonable progress towards achievi ng natural visibility conditi ons.” 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 implementati on plan and ensure no degr adation 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 demonstrati on showing how these factors were taken into consideration in selecting the goal.” 40 C.F.R. § 51.308(d)(1)(i)(A). In se tting 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, expresse d 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 reasonabl e 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 ar eas 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 nece ssary to achieve the reasonable progress goals established by States having manda tory Class I Federal areas.” Id

.40 In addition, the regional haze rules describe re quirements 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 visi bility 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 addr essed 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 pr eferences in place of

those of the state.

Response: We acknowledge the background inform ation provided by UARG. We take no position with regard to UARG’s synopsis of the statutory and regul atory 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 fi nal rule published in the Federal Register on March 12, 2012, we issued a partial disappr oval 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 comm ents 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 doe s not take action on the Arkansas Regional Haze SIP. Rather, this rulemaking is a regional haze FI P to correct the parts of the Arkansas RH SIP we disapproved in 2012.

Comment: [The Associations (0165) p. 1-2, 10] Th e American Chemistry Council, American Coke and Coal Chemicals Institute, American Farm Bureau Federation, American Forest & Paper Association, American Iron and Steel Instit ute, American Petroleum Institute, American Public Power Association, Amer ican Wood Council, Arkansas Asphalt Pavement Association, Arkansas State Chamber of Commerce, Arkans as Environmental Federation, Arkansas Farm Bureau, Arkansas Forest & Paper Council, Ar kansas Ready Mixed Concrete Association, Associated Industries of Arkansas, Inc., Brick In dustry Association, Corn Refiners Association,

Council of Industrial Boiler Owner s, Electricity Consumers Resources Council, Gas Processors Association, Industrial Energy C onsumers of America, National Association of Manufacturers, National Mining Association, Nation al Oilseed Processors Associ ation, 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 ap proval 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 Associati on 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 efficien t manner. The Associations’ members include electric utilities, manufacturers and energy devel opers 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 requi re 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 im pact manufacturers directly or indirectly in the future.

As discussed in more detail in the Associa tions’ comments, the Associations urge EPA to withdraw and modify the proposed rulemaking due to numerous deficiencies within it. These deficiencies began with the di sapproval of Arkansas’ proposed state implementation plan. The Associations believe that EPA is failing to provi de 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 determin ations and imposes its own policy preferences through a federal implementation plan. Key amo ng these flawed policy preferences are EPA’s imposition of costly pollution controls at Inde pendence Steam Electric Station (“Independence plant”), a source not eligible for Best Available Retrofit Tech nology (“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, wh at 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 requir e exorbitant pollution controls that would achieve, at most, negligible visibility benefits. The Clean Ai r 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 pr oposed rulemaking, it is not a vehicle to further accelerate the retirement of coal-fired power pl ants. 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 m eans that EPA has no credible evidence showing that visibility improvements woul d be greater than zero. Such jus tifications have already been struck down by the U.S. Court of Appeals for the Ninth Circuit and the As sociations object to EPA ignoring that court’s determination in de ciding whether additional emission reductions at stationary sources would pr ovide any visibility impr ovements 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 ne w rule that is consiste nt 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 comme nter 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 Corpor ation et. al. stated that on April 8, 2015, the U.S. Environmental Prot ection 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 T echnology (“BART”) determinations, Reasonable Progress Goals (“RPGs”), and long-term strategy (“LTS”) necessary to achieve established RPGs, as well as the interstate visibility transpor t requirements for pollutants that affect visibility in Class I areas in nearby states. Among othe r requirements, the Proposed Rule includes

emission limitations based on instal lation of BART controls for SO 2 and NO X at the White Bluff Plant (“White Bluff Plant”) and two alternativ e options for controlling emissions from the Independence Plant (“Independence Plant”) unde r the regional haze reasonable progress requirements.

Conway Corporation is a non-profit corporation th at operates the city-owned utility system and provides electric, water, wastew ater, cable, Internet, and telep hone services for the City of Conway, Arkansas, a city of about 64,000 reside nts. Conway Corporation is dedicated to producing and delivering safe, affordable, reliab le, innovative and enviro nmentally sound utility and telecommunication services while enhancing the quality of life of its community. Conway Corporation owns 2% of each unit of the I ndependence 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 s ubstantial investment in both the White Bluff and Independence Plants to secure their power ne eds 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. Th ere are about 10,500 residential, and 1,700

commercial and industrial customers in WMU’s se rvice area, to whom WM U 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, innova tive 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 regiona l haze and interstate vi sibility 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 Co rporation 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 im pairment 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 protecti on 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 pl anning recognizes that advancements in technology and changes in economic factors will likely provide opportun ities for implementing

new cost-effective control measures to assure reasonable progress and reduce the economic burden of rushing to install cos tly control measures to meet a purely aesthetic standard.5 The EPA’s rule requires states, through the state impl ementation plan (“SIP”) development process, to review the statutory factors on a periodic basis and determin e 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 th at the visibility improvement at relevant Class I federal areas is well ahead of the approved Unif orm 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 unnecess arily imposes significa nt costs on Commenters and their customers with little or no corresponding visibility benefit. Fi nally, in developing the Proposed Rule, EPA departed from its own guida nce and previous regional haze decisions for

other states.

For the reasons discussed in Conway Corporat ion et. al.’s comments, EPA should abandon the Proposed Rule’s determinations regarding r easonable progress determinations for the Independence Plant and

NOx BART determinations for Arkansas’ su bject-to-BART sources, and prepare a FIP consistent with the requirements of th e 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 syno psis. This comment summarizes the issues raised by the commenter in more detail elsewher e. Please see our responses to those more specific comments in other sections throughout this document.44 Comment: [Energy and Environmental Alliance of Ar kansas (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 electr ic utilities and other energy companies formed to advocate, communi cate and encourage energy and environmental policies that promote sound and predictable regu lation of Arkansas’ utility industry, and support an economically viable and envir onmentally 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 implementati on 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 Ru le is arbitrary and capri cious in that it is inconsistent with EPA’s previous guidance, regulations, and determ inations concerning visibility protection and imposes significan t 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 Tr ansport (hereinafter, the “Proposed Rule”) promulgating a Federal Implementation Plan (“FI P”) 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 Re trofit Technology (“BART”) determinations for sulfur dioxide (“SO2”), nitrog en 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 Plan t (“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 comme nter 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 Ar kansas (0173), p. 3-4] EEAA stated that EPA’s Proposed Rule is replete w ith legal and factual e rrors that vastly un derestimate the cost and cost effectiveness of the proposed emissions controls and simultaneously overestimate the necessity and benefit of the c ontrols for maintaining reasonab le 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 Elect ric Power Company (“AEP/SWEPCO”), Arkansas Electric Cooperative Corporation (“AECC”), Arkansas Municipal Power Association, Conway Corporation, Empire District Electric Company, Entergy Arkansas, Inc. (“Entergy”), J onesboro 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. Ba iley 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 Propos ed Rule arbitrary and capricious. As such, EPA should abandon the approach an d analysis utilized in the Propos ed 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 ra ised by the commenter in more detail

elsewhere. Please see ou r 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 Qua lity 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 requir ements 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 Distri ct of Columbia, and directly employ more than 500,000 workers. With more than $90 billion in a nnual capital expenditures, the electric power industry is responsible for millions of jobs outside our direct operations. Re liable, affordable and sustainable electricity powers the economy and enhances the lives of all Americans. As generators of electricity and operators of the nation's electri c transmission and distribution system, EEI's member companies have a strong in terest in any proposed rule that potentially impacts the industry and the ongoing transition of the domestic fleet.

EEI member companies operate facilities direct ly affected by the Agency's proposed action. As part of the ongoing transition to cleaner sources of genera tion, the electric power sector generally-and Arkansas electricit y generators in particular- have cut emissions significantly in recent years and will continue to do so under ma ny recently finalized EPA regulations, even without the regional haze Fede ral Implementation Plan (FIP) proposed by EPA for Arkansas. EEI is filing comments to ensure that the Agency a llows states to determine how best to consider additional controls, consistent w ith effective long-term utility planning toward the linked goals of reliable, affordable and increasingly clean el ectric power. EEI also offers a number of specific comments regarding the proposed FIP, and urges th e Agency to consider the technical comments of both Entergy and Southwestern Electric Powe r Company regarding un it-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 othe r 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; Propos ed 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-prof it corporations organized under the laws of the State of Arkansas for the purpose of ensuring just and reasonable ut ility policies and energy rates in the State of

Arkansas. The members of AEEC and AGC co llectively employ thousands of Arkansans through their engagement in energy- intensive in dustries 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 owne r or co-owner of certain power plants regulated by the Proposed FIP. Since the cost of electricity constitutes a major component of the co st of manufacturing the products created by the members of AEEC a nd AGC, the costs of the various control technologies required under the Proposed FIP wi ll injure the member s of AEEC and AGC by increasing the cost 33 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 co mmenter 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 th e 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 natio nal 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 beca me increasingly marred by air pollution. See id. at 573. Today, air pollution is “perhaps th e 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 expend itures 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 propo sed FIP will increase demand for natural gas, thereby placing significant upward pressure on natural gas commod ity 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.countoncoa l.org/assets/Executive-Summary-EPA-CleanPower-Plan-Costs-Impacts.pdf.47 Recognizing the “intrinsic beauty and historical and archaeological trea sures” of the national parks and wilderness areas, 35 Congress established “as a natio nal goal the prevention of any future, and the remedying of any existing, impair ment of visibility in mandatory class I Federal areas which impairment results from ma nmade air pollution.” 42 U. S.C. § 7491(a)(1). In 1990, after finding that the EPA and the states ha d 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 re quires the states (or EPA where a state fails to act) to make incremental, “reasonable progres s” 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 re gulations, EPA recognized that visibility impairing pollution was a regional problem that required regional soluti ons; 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 th e national goal.” 42 U.S.C. § 7491(b)(2). The Regional Haze Rule includes several interlocki ng 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 av ailable retrofit technology (“BART”) for some of the oldest and dirtiest sour ces 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 regul atory requirements associated with RPGs. [Sierra Club et. al. (0171) p. 3] Si erra Club et. al. stated that on e of the main features of the Regional Haze Rule is the establishmen t 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 en vironmental impacts of compliance, and (4) the remaining useful life of any potentially affect ed 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 (o r 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 de rived 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 retr ofit 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 stat e 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 conditi ons 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 sl ower rate of progress th an the URP, the state must demonstrate, based on the four reasonable progr ess factors, “that the rate of progress for the implementation plan to attain na tural conditions by 2064 is not r easonable; 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 a ddress 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 st atutory goal to eliminate all haze caused by “manmade air pollution,” 42 U.S.C. § 7491(a)(1), st ates 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, ag ricultural, and forestry practices. Id. § 51.308(d)(3)(v). The long-term stra tegy must achieve reasonable progress for both the Class I areas within a stat e’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 stat e then must document the technical basis by which

it determines its share of the emissions reducti ons necessary to make reasonable progress at a

Class I area. Id. § 51.308(d)(3)(iii). After fulfilling the proc edural 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 nece ssary 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 ma ndate to make reasonable progress, EPA reviews

whether the state followed the c onsultation requirements set fort h 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 r easonably be anticipated to cause or contribute to any impairment of visibility in any such [mandatory Class I Fe deral] 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 incl ude 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 mu st analyze “the best system of continuous emission control technology availabl e” by taking into consideration fi ve factors: (1) the costs of compliance, (2) the energy and non-air quality en vironmental impacts of compliance, (3) existing pollution controls at the source, (4 ) the remaining useful life of th e 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 b ecause 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 olde r, disproportionately-polluting sources to install up-to-date and cost -effective polluti on controls.

BART is a mandatory measure that must be implem ented 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 progr ess 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 im pairment 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 no t “by itself or in combination with other

sources” cause or contribute to si gnificant visibility impairment at a Class I area; (2) if the power plant has a design capacity of 750 megawatts or gr eater, 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 pollu tion 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 a lternative will achieve greater reasonable progress toward natural visibility conditions.”).50 been proposed or made here, nor could it be give n the significant visibility impacts that the Flint Creek, Lake Catherine, and White Bluff facilit ies 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 affe cted 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 ob ligation—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 straddle s two different sections of th e Ouachita Mountains in western

Arkansas. The Fourche Mountain subsection is char acterized 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 te rms 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 fo r 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 extraordinaril y pretty Buffalo National River, which flows down the center of this Wilderness through a rou gh 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 source s mars the unique scenery outsi de of the state too, including

in Missouri’s Hercules Glades Wilderness a nd 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 gra ssland, forested knobs, steep rocky hillsides, and

39 “Wilderness Stewardship Challenge: Air Quality Values M onitoring 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/w ildView?WID=621&tab=General (l ast 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/adve nture-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 “p rovide[s] food and shelter for migratory waterfowl and . . . protect[s] the bottomland ha rdwood forest,” while providing enjoyment for people visiting. 47 Along with migratory waterfowl, the ref uge is also a wintering ground for bald eagles. 48 People travel to the Mingo National Wildlif e 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 th e overwhelming majority of haze-causing pollutants in Arkansas. [Sierra Club et. al. (0171) p. 8-9] Si erra Club et. al. stat ed that a handful of point sources, mostly electric generating uni ts (“EGUs”), emit the overwhelming majority of haze-causing pollutants in Arkansas. Of these pollu tants, 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 pl ants—emitted approximately 84% of Arkansas SO2 point-source emissions and 55% of state-wi de NOx point source em issions 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 a nd is operated by Southwestern Electric Power Company (a subsidiary of American Electric Po wer (“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 Data base, in 2011, Flint Creek was the third-largest point source of emissions of both SO2 (8,620 to ns) 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 larg est impacts at Upper Buffalo (98th percentile impairment of .965 dvs) and Caney Creek Wilder ness Areas (98th percen tile impairment of 0.963 dvs). See 80 Fed. Reg. at 18,965, Table 25.

Lake Catherine Unit 4 is a 558 MW electric gene rating 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/reca rea/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/uploadedF iles/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/pdf s/ar_5yr_prog_rep_revie w-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 signific antly to visibility impairment at all four Class I areas modele d by EPA, with the largest impacts at Caney Creek Wilderness Area (98th percen tile impairment of 1.371 dvs). See 80 Fed. Reg. at 18,976,

Table 40.

The Independence plant is a 1,800 MW coal-fir ed electric generati ng station operated by Entergy. The plant consists of two nearly id entical 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. A ccording to emissions da ta in EPA’s Clean Air Markets Database, in 2011, the Independence plan t 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 contribu tes significantly to visibility im pairment at all four Class I areas modeled by EPA, with the largest im pacts at Caney Creek Wilderness Area (98 th percentile impairment of 2.412 dvs), Upper Buffalo Wilder ness 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 faci lity 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 Bl uff 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 Bl uff Units 1 and 2 contribute si gnificantly 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), a nd Hercules-Glades Wilderness Area (98 th 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 operatio ns 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] Enter gy Arkansas Inc. (Enter gy) stated that EPA’s proposed BART determination for White Bluff a ppears to be based, in general, on the White Bluff five-factor BART analysis that Enter gy 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 re spect 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 asse ts 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 us eful coal-fired life of the units. In addition, EPA used outdated costs in its BART analysis, imp roperly eliminated millions of dollars in costs necessary to install controls on White Bluff, and did not consider site-spe cific factors that will

affect the cost calcula tion. When the appropriate dry scrubber costs are considered along with the units’ remaining useful coal-fired life, the aver age 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 sour ce in BART determinations, whic h 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 th e amortization period, then the remaining

useful life has essentiall y 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 th e standard amortization period (typically 20-30 years) may no longer be co st 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 remain ing useful life was not a meaningful factor for White Bluff given Entergy’s previo us plans to continue coal-fir ed 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 Regi onal Haze Federal Implementation Plan (SO 2 Cost TSD), at 16 (“we typically assume a 30 year equi pment 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 ne eds to confirm that it review ed and analyzed Entergy’s Revised White Bluff BART Analysis.

53 Guidelines for BART De terminations 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-ye ar amortization period for the controls, an amortization period that is consistent with EP A’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 re quires that BART controls be installed “as expeditiously as practicable,” but no later than five years from a pproval 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 effec tive date earlier than sometime in 2016. Thus, the scrubbers would be installed and op erational, at the earliest, in 2021. 56

Entergy stated that in additi on to its plan to cease combus ting coal at White Bluff by 2028, Entergy proposes to meet interim SO 2 emission rate reductions pr ior to 2028 through a reduction in the permitted SO 2 emission rates for White Bluff Units 1 and 2 and Independence Units 1 and 2. The units currently have a permitted 3-hour average SO 2 limit of 1.2 lb/MMBtu. Entergy proposes to lower this limit to a rolling 30-da y average limit of 0.6 lb/MMBtu beginning in 2018.

NO X BART for all EGUs in Arkansas, should be compliance with CSAPR given that EPA already has determined that CSAPR is bett er than BART. 77 Fe d. Reg. 33,642 (June 7, 2012). However, in the event EPA continues to requir e Arkansas’ EGUs to meet source-specific NO X BART limits in the final FIP, Entergy propos es that the four units at White Bluff and Independence meet a rolling 30- boiler operating day average NO X limit of 1,342.5 lb NO X /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 in stalling LNB/SOFA wo uld significantly

decrease as a result of a revise d 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 compre hensive visibility improvement proposal.

Entergy stated that this combination of CSAP R compliance or, in the alternative, LNB/SOFA installation, and accepta nce of a lower SO 2 emission rate through the re maining 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 scrubb ers and meet the BART SO 2 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 NO X BART in its Revised White Bluff BART Analysis. The revised limit is necessary due to the chan ged 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 NO X 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

NO X limit at the lower loads that have become a more common operating condition for the units.55 controls are justified given En tergy’s proposal to limit the numb er 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 FI P fails to properly account for the remaining useful life of the White Bluff Plant, which render s 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 remaini ng 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 Bl uff Plant were based on a 30-year amortization period for the controls, an amorti zation 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-fir ed operation at the White Bluff Plant by 2027-2028. In light of this proposal, EPA shoul d revise its BART analysis to ta ke the remaining useful life of the units into account. Using the 2027 and 2028 time line, the amortization period is shortened to approximately six to seven years. This signifi cantly 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’ re maining 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 EP A concluded that dry flue gas desulfurization (FGD) controls are BART for En tergy’s White Bluff Units 1 and 2 given their visibility impacts and averag e 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 estim ates were based on a 30-year amortization period for the controls, which is co nsistent with EPA’s Control Cost Manual when a unit’s remaining useful life is not limited. Howe ver, Entergy proposes in its own comments to agree to an enforceable commitment to cease burning coal at White Bl uff Units 1 and 2 by 2027 and 2028, one unit per year. Accord ingly, in light of Entergy’s proposal, EPA should revisit its proposed BART determination for White Bluff Units 1 and 2 to address th e remaining useful life of the units accurately.

EEI stated that Entergy’s proposal to cease co al-fired operation at White Bluff by 2027-2028— coupled with a final BART determination in ear ly 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 instal l 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 co st effectiveness severa l 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 th at system for only six or seven years. Instead of the proposed costly dry FGD control, Entergy believes that a combination of Low NO X Burner/Separated Over-Fire Air controls coupled with the use of low sulfur coal through the rema ining useful coal-fired life of

the White Bluff units should be BART. No additi onal controls are justif ied given the limited number of years of coal-fired operation of White Bluff given that the regional haze program allows for firm refueling commitment s to satisfy regulatory requirements.

Response: In our FIP proposal, we solic ited comment on alternative SO 2 and NO X 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 dete rmination in a FIP, a source has requested that EPA instead adopt an alternative to BART or otherwise adju st 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 intere sted in an alternative path. Given the alternatives proposed by owners and operators of other power plants in other states, we stated that an altern ative could include, but is not li mited to, a combination of early

shutdowns of units and other emission control measures that would ach ieve greater reasonable progress than the BART and reason able 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 al ternative that are unique to White Bluff as an alternative to our proposed BART emission limits at the facility unless we al so conclude that the remaining elements address any reasonable pr ogress requirements for Independence. After carefully considering the comments we received sp ecifically 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 Ariz ona 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 th e 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 pr eviously 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 presen ted in its comments that apply specifically to White Bluff have potential me rit 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 anal ysis of Entergy’s alternative strategy is discussed below and

elsewhere in this document. A chief element of En tergy’s alternative is its proposal to cease coal

combustion at White Bluff Units 1 and 2. It is un clear from the comments submitted whether this would mean the shutdown or the repowering of Wh ite 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 co sts of controls at White Bluff. Entergy too suggests that EPA must take into account a shor ter 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 regard ing Independence, we could in clude in our final FIP an enforceable requirement for the shutdown (or repowering) and take that change into consideration as part of a BA RT determination. The BART Guid elines state that where unit shutdown affects the BART determination, the shut down 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 subm itted by Entergy during th e comment period that

it intends to cease coal combustion at White Bluf f 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 accep t the Entergy proposal as meeting all requirements with respect to Independence. Therefore, we ar e assuming a remaining usef ul life of 30 years for

White Bluff Units 1 and 2 when de termining BART for these units.

We discuss elsewhere in this doc ument (in our response to the next set of comments) the merits of Entergy’s proposed strategy as an altern ative approach for both meeting the BART requirement of section 308(e) for White Blu ff and meeting the requi rements of sections 308(d)(1) and 308(d)(3) rega rding reasonable progress, which im plicate 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 addre ss the BART requirements for White Bluff that involves ceasing coal combustion at Units 1 and 2 by a date cert ain, but the SIP revision is required to also include consideration and evalua tion of dry sorbent inject ion (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 Inde pendence, as we stated above, a strategy that includes controls for Independence similar to what the company has proposed for White Bluff (i.e., interim SO 2 controls, ceasing coal combustion, and NO X controls) would also ha ve potential merit with respect to addressing the reasonable progress re quirements 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 out dated 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 fact ors that will affect the cost calcul ation, 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 th at dry scrubbers are estimated to cost $2,565/SO 2 ton removed at Unit 1 and $2,421/SO 2 ton removed at Unit 2. Many EGUs have installed and operated this type of controls su ccessfully, and our cost analysis indicates that dry scrubbers at

White Bluff would be cost effective and well with in 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 NO X BART for all EGUs in Arkansas should be compliance with CSAPR given that EPA determined that CS APR is better than BART, we discuss elsewhere in this document why we are not relying on CSAPR to satisfy the NO X BART requirement for Arkansas EGUs in this rulemaking. We are instead requiring source specific NO X BART

controls. We also address elsewhere in this RTC document Entergy’s comments regarding the

NO X 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 whethe r we actually relied on Entergy’s revised White Bluff BART Analysis in our pr oposal, 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 typogr aphical error; we mistakenly referenced materials from AEP, but did not use AEP’ s modeling and assumptions in our BART determination for White Bluff. This typographi cal error did not affect our proposed BART

decision for White Bluff Units 1 and 2.

Comment: EPA’s final FIP should include En tergy’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 st ated that it is propos ing near-term interim

controls and the cessation of coal combustion at White Bluff by 2028. Ente rgy is proposing to

meet lower SO 2 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

NO X emission rate of 1,342.5 lb NO X /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 SO 2 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 improve ments projected for the following scenarios (1)

66 “Revised BART Five Factor Analys is 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 cessa tion of coal-fired operations at White Bluff (referred to as “WB”) and the inst allation of LNB/SOFA and lower SO 2 emission rate at Independence (referred to as “ISES”); and (2) in stallation of EPA’s proposed FIP controls at all BART sources and Independence. Based on Enter gy’s modeling, the difference in the haze index between the proposed FIP controls and Enter gy’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 Proj ected 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 1 st Planning

Period 2 nd Planning

Period 3 rd Planning

Period 4 th Planning

Period 5 th Planning

Period 26.36 6 th 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 p ath ( 20% Glide p ath ( 20% Best ) Observation ( 20% Observation ( 20% Best )

Entergy's Proposal

‐ WB/ISES | Others

‐ BART controls

Proposed FIP Haze ‐ All ‐ Proposed FIP Controls60 “Uniform Rate of Progress and 2018 Project ed 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-ter m objectives of the Regional Haze Program, the high capital costs for scrubbers, and the significant long-term enviro nmental co-benefits fromthe cessation of coalfiring at the White Bluff units. Arkansas’ Five-Year Progress Repor t demonstrates that the state 

### Uniform Rate of Progress and 2018 Projected Progress Upper Buffalo Wilderness Area ‐ Ranked Statistical Analysis 30.00 1 s t Planning
Period 2 nd Planning

Period 3rd	Planning Period 4 th Planning
Period 5 th Planning
Period

26.27 6 th 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	Controls61 currently is below the glide path for Caney Cree k and Upper Buffalo, and expects to remain so through at least 2018. See Section III.C.1 of Entergy’s comme nts. Entergy’s approach would help ensure that Arkansas remains below the glide path throughout th e second planning period, and will produce very large additional reductions in NO X , SO 2 , and PM heading into the third planning period.

Entergy stated that ulti mately, its approach woul d achieve 170,000 tons of NO X reductions from White Bluff more than the proposed FIP w ould achieve. While scrubbers would reduce SO 2 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, SO 2 and NO X would be reduced, which would resu lt in reductions in ozone and PM 2.5 . Starting in 2028, Entergy’s approach would produce even greater reductions in emissions of SO 2 , NO X and PM 2.5 , as well as achieving reductions in mercur y and other hazardous air pollutants, and CO 2 /CO 2e . 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. Additionall y, 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 a ddition 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 propos ed for Independence. 80 Fed. Reg. at 18,997. Controls at Independence for r easonable 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 Conw ay Corporation et. al. (0172) p. 15] Entergy Mississippi Inc. (EMI) a nd Conway Corporation et. al. both stated that EPA requested public comment on any alternative SO 2 and NO X control measures that w ould 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 requirem ents 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 I ndependence Plant’s Units 1 and 2, and to meet

lower SO 2 emission rates at all four units by 2018. This combination of controls and lower SO 2 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 Corporatio n 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 SO 2 emission rates at all four units by 2018. Conway Corporation et. al. support this proposed a pproach, which ensures that the62 Class I areas achieve virtually the same r easonable progress as EPA’s proposal but at significantly less cost to commenters and their customers.

[Entergy Mississippi Inc. (0168) p. 14 and Conw ay Corporation et. al. (0172) p. 15] EMI and Conway Corporation et. al. both stated they stro ngly 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-fir ed units at Independence and Wh ite 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 billi on less. It also would deliver important non-haze environmental benefits , including a dramatic decrease in greenhouse gas emissions, large reductions in SO 2 emissions that also c ontribute to long-range PM 2.5 issues, and large reductions in ozone (and PM 2.5 )-forming NO X emissions.

Response: After carefully considering the comments we received, we have determined that Entergy’s alternative proposal 67 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 benef its 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 Blu ff and meeting the requi rements of sections 308(d)(1) and 308(d)(3) rega rding reasonable progress, which im plicate all sources in Arkansas, including Independence, are as follows.

First, we note that Entergy does not appear to be proposing that we a pply 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 reasona ble 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 peri od 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 pr oposal would result in “virtually the same” visibility benefits. Thus, our analysis considers onl y the requirements of section 308(e)(1), which contains the source-specific BART requirements, in consider ing the provisions of Entergy’s alternative proposal applicable to White Blu ff. (We address elsewhere in this document the issue of whether our FIP should apply the provisi ons of section 308(e)(4) for purposes of meeting the BART requirement for NO X emissions for EGUs in Arkansas.)

Next, we also note that Entergy does not appe ar to be requesting in the comments submitted during the comment period that we adopt the elemen ts 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 pr eviously 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 a ddress 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 co mbustion 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 progre ss requirements. As we discuss below, we conclude that the elements of Entergy’s alternative proposal that are specific to Indepe ndence do not satisfy the reasonable progress requirements. Even if we ha d interpreted Entergy’s comments as requesting that we adopt the particular elem ents in its alternative proposal th at 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 addressi ng 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 meeti ng the BART requirements for White Bluff because, as we discuss below, Entergy’s alternative pr oposal does not satisfy th e source-specific BART requirements of section 308( e)(1) for White Bluff.

Entergy’s alternative strategy would achieve minimal SO 2 emission reductions over the next 10 to 11 years. Entergy proposes that White Bluff Units 1 and 2 would meet an SO 2 interim

emission limit of 0.6 lb/MMBtu on a rolli ng 30-day average begi nning 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 SO 2 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 cu rrent emission rates are the appropriate baseline for comparing strategies, rather than the curr ently permitted emission rates, which are higher; Entergy does not appear to dispute this point. The ma ximum monthly SO 2 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 planni ng period at near the cu rrent emission rate and throughout most of the second planning period with only a slight actual reduction in SO 2 emissions. Entergy has provided no analysis to show that there is no more effective measure for White Bluff for this interim period that is need ed to make reasonable pr ogress. Section 308(e)(1) and the BART guidelines require that a subject-to-BART source install and operate the best

available emission reduction techno logy based on the five statutory factors, and it is therefore necessary to consider whether there are any additional SO 2 control measures, such as dry sorbent injection (DSI), that constitute BART during th is interim period. Entergy has argued that with this limited remaining period of coal combustion, the cost per ton of SO 2 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 us eful life might result in a conclu sion that dry scrubbers are not cost effective, as part of the BART analysis, technically feasible cont rol technologies beyond the

interim SO 2 emission limit the company has proposed must be evaluated to determine if they are

68 Although not specified in Entergy’s written comments, th e company met with us and confirmed that the interim

SO 2 emission limit would be achieved by combusting lower su lfur 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 effectiv e 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. Theref ore, it would be necessary to consider and evaluate DSI as a possible interim BART contro l 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 SO 2 control that would constitu te 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 pr oposal does not include SO 2 and NO X 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 prop oses to cease coal combustion at White Bluff Units 1 and 2 in 2027/2028, but its comments do not specify the operatin g 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 En tergy’s comments indicates that the company assumes in its visibility modeling that SO 2 and NO X 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 include d accepting a binding requirement to burn only natural gas at White Bluff Units 1 a nd 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 SO 2 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 NO X emissions limit, then we would agree that it would be appropriate to assume that NO X emissions from White Bluff will be zero beginning in 2027/2028. However, Entergy’s alternative prop osal does not specify any such binding requirements that would ensure SO 2 and NO X 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 contro l Independence under the reasonable progress requirements. Under Enterg y’s proposed approach, Independence Units 1 and 2 would be subject to an SO 2 emission limit of 0.6 lb/MMBtu on a rolling 30-day average

70 As discussed elsewhere in this response, the SO 2 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 SO 2 emission rates, meaning that only slight actual SO 2 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 SO 2 emission rates from Independence Units 1 and 2. The maximum monthly SO 2 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 requireme nts, and so these current emission rates are the appropriate baseline for comparing strategies, ra ther than the currently permitted emission rates, which are higher. As such, under Entergy’s proposa l these units would con tinue to operate with

minimal SO 2 emissions reductions. Unlike Entergy’s pr oposed approach with respect to White Bluff, the proposed SO 2 limit for Independence would not be an interim emission limit. The company’s alternative proposal does not include any further SO 2 controls for Independence Units 1 and 2, such as DSI or the eventual cessation of coal combustion. In light of the minimal SO 2 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 SO 2 controls it proposes for Independence. SO 2 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 SO 2 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 I ndependence significantly impacts visibility at Arkansas’ Class I areas. As such, Entergy’s pr oposal to cease coal combustion at White Bluff does not change our conclusion that it is necessa ry to control Independence under the reasonable progress requirements. Since Entergy’s alternative proposal includes minimal SO 2 control for Independence, thus omitting controls that we found to be cost effective and that are anticipated to result in considerable visibility benefits at Arka nsas’ Class I areas, we conclude that the elements of Entergy’s alternative proposal that are specific to Independ ence do not satisfy the reasonable progress requirements for Independence.

Although, as we have already established, Enterg y’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 satisf y 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, th e 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, SO 2 emissions are considered th e primary driver of haze in Arkansas’ Class I areas. However, as discussed elsewhere in this RTC document, we consider both SO 2 and NO X to be key visibility impairing pollutants in Arkansas’ Class I areas. See Arkansas RH SI P, Appendix 8.1- “Technical Support Document for CENRAP Emissions and Air Qu ality 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) rega rding reasonable progress, in respons e to Entergy’s comment that its alternative proposal would achieve almost the same level of visibility be nefit as the FIP, we compared the potential impacts of Entergy’s propos al 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 SO 2 and

NO X emissions from White Bluff Units 1 and 2 will be zero under En tergy’s alternative proposal. In the Table below, we compare the total annual SO 2 emissions reductions that would

result under our FIP and under Ente rgy’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 compar ison to our FIP proposal, in estimating the SO 2 emissions reductions anticipated to result from En tergy’s alternative proposal we have assumed

the same SO 2 baseline emissions we used for White Bluff and Independence in our proposal. 77

Comparison of Annual SO 2 Emissions Reductions from White Bluff Units 1 and 2 and Independence Units 1 and 2 (Post-2028)

Unit SO 2 Baseline

Emissions (tpy) FIP proposalAnnual SO 2 reductions 1 Entergy

alternativeproposalAnnual SO 2 reductions 2 Additional SO 2 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 1,291 3 11,621 Independence Unit 2 15,511 13,990 1,399 3 12,591

Total- All four units combined (SO 2 tpy) 62,293 56,486 35,203 21,283

1 These SO 2 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 SO 2 reductions that would take place under Entergy’s alternative proposal; a small

amount of SO 2 reductions would begin taking place in 2018, but the majority of these SO 2 reductions would begin taking place in 2027/2028.

3 As Entergy’s proposed SO 2 emission limit for Independence Units 1 and 2 is one order of magnitude greater than our proposed SO 2 emission limit (i.e., 0.6 lb/MMBtu vs. 0.06 lb/MMB tu), we have accordingly estimated that the

SO 2 emissions from Independence under the Entergy alternative would be one order of magnitude greater than under our FIP. Thus, we estimated SO 2 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 SO 2 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 SO 2 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 SO 2 emissions reductions expected to result from ou r FIP will take place several years earlier than any significant SO 2 reductions under Entergy’ s alternative proposal. However, for purposes of comparing the long-term emissions reductions under the FIP and under the Enterg y 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 SO 2 emissions reductions due to controls on White Bluff Units 1 and 2 and Independence Units 1 and 2, we assumed an SO 2 emissions baseline that was determined by examining annual SO 2 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 Enter gy’s alternative proposal would, after 2027/2028, achieve slightly greater SO 2 reductions at White Bluff Units 1 and 2 than our FIP proposal, it would achieve substantially lower SO 2 reductions at Independence Units 1 and 2. Thus, considering the four units combined, we estimat e that our FIP proposal would achieve emissions reductions of 21,283 SO 2 tpy more than Entergy’s alterna tive 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 a lternative is fully realized in the period after 2027/2028. Entergy states only that its altern ative proposal would provide almost the same visibility benefit as our proposed FIP post-2027/2028. We conclude that not even this assertion is adequately supporte d, and that the long-term visib ility benefits of the Entergy alternative proposal would be sign ificantly smaller than those of the proposed and final FIP. As we explained above, Entergy assumes in its visibility improvement projections that SO 2 and NO X emissions from White Bluff Units 1 and 2 will be zero under the company’s alternative proposal. The assumption of zero SO 2 emissions from White Bluff after coal combustion ceases would be appropriate only if Entergy’s alternative proposal involves ac cepting a binding requirement to burn only natural gas or permanently s hut down after coal combustion ceases. 78 With respect to

NO X emissions from all four units of White Bluff and Independence, Entergy’s multi-unit strategy includes the same level of NO X control as our FIP proposal pr ior to the cess ation of coal

combustion at White Bluff in 2027/2028. Since Enter gy’s explanation of it s alternative proposal does not specify the operating conditions of Wh ite Bluff Units 1 and 2 when coal combustion ceases in 2027/2028, we find that the assumption of zero NO X emissions is also not adequately supported. However, even if we acc ept Entergy’s assumption that SO 2 and NO X emissions from

White Bluff will be zero after coal combustion ceas es and that its alternative proposal would thus achieve greater NO X reductions compared to our FIP propos al, given the dominance of visibility impact from sulfate compared to nitrate at th e affected Class I areas in Arkansas, the higher visibility impacts due to su lfate under the Entergy alternat ive proposal would more than outweigh any extra nitrate-related visibility be nefit. Entergy’s own CA Mx modeling shows that even assuming zero SO 2 and NO X emissions from White Bluff once it ceases coal combustion, its multi-unit alternative proposal would achieve le ss 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 Enter gy’s alternative proposal). Thus, we have determined that Entergy’s alternative proposal wo uld 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 En tergy’s photochemical m odeling of visibility benefits from the controls in our proposed FI P and Entergy’s alterna tive 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 permit ted to burn fuel oil after coal combustion ceases, it is not appropriate to assume that SO 2 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 SO 2 emission rate under the company’s proposed approach would be even higher than the SO 2 emission rate under our proposed FIP.68 very low because the units are equipped with elec trostatic precipitators (ESPs), we do not expect

that the additional PM emissions reductions from ceasing coal combustion would be considerable. Additionally, because PM emissions fr om White Bluff contribute very little to haze at Arkansas’ Class I areas, we do not believe th at the additional PM reductions that would be achieved would provide a si gnificant visibility bene fit at the Class I areas. 79 We also recognize that ceasing coal combustion at White Bluff Units 1 and 2 could re sult in greater nonair

environmental benefits and in more emission reductions of mercury and other hazardous air pollutants and CO 2 /CO 2e 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 sati sfy the requirements of the Regional Haze Rule. As discussed earlier in our response, we conc lude 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 unde r 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 de laying 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 co st to install dry FGD, we note that we have

revised our cost ca lculations of SO 2 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 Bl uff are estimated to cost $2,565/SO 2 ton removed at Unit 1 and $2,421/SO 2 ton removed at Unit 2. After revising our cost estimates for dry scrubbers on White Bluff, we continue to believe that dry sc rubber controls and LNB/SO FA controls are cost

effective at White Bluff Units 1 and 2 and would result in signif icant visibility improvement at

Arkansas’ Class I areas based on our CALPUFF modeling of the 98 th percentile visibility impacts from the facility. 80 Based on our consideration of th e five BART factors, we have determined that controls consistent with dry scrubber and LNB/SOFA in stallation 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 im pacts and visibility improvement of controls on Independence, we have determined that dry scrubbers and LNB/SO FA controls on Independence Units 1 and 2 are necessary to make reasonable pr ogress at Arkansas’ Class I areas. We have also revised our cost

calculations of SO 2 controls for these units in response to the comments received on our initial cost analysis. Based on our revised cost anal ysis, we have found th at dry scrubbers on Independence are estimated to cost $2,853/SO 2 ton removed at Unit 1 and $2,634/SO 2 ton removed at Unit 2. After revising our cost esti mates 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, an d 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 dr y scrubber and LNB/SOFA controls are cost effective. We also find that these controls on Independence woul d provide significant visibility improvement as projected by our CALPUFF m odeling that focuses on the 98 th percentile impacts from the facility. 81 Additionally, the CAMx photochemical mode ling submitted by Entergy shows that the contribution to visibility impairment due to ba seline emissions from th e 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 impairmen t at each Class I area and a large portion (approximately one-third) of the total contributi on 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 SO 2 , we note that

NO X emissions from the facility also have im pacts 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 NO X controls on Independence would provi de visibility improvement on this portion of the 20% worst days, a nd as such, are requiring both SO 2 and NO X controls under the reasonable progress requirements.

We do note that if Arkansas submits a regional h aze SIP revision to replace our FIP, the state has the discretion to consider an approach to addr ess the BART requirements for White Bluff that involves ceasing coal combustion at Units 1 and 2 by a date ce rtain, but an approvable SIP

revision must also include cons ideration and evaluation of DS I as a possible interim BART control option. With respect to Independence, a strategy that includes co ntrols for Independence

similar to the elements of Ente rgy’s alternative proposal that ar e specific to White Bluff (i.e.,

interim SO 2 controls, ceasing coal combustion in the near future, and NO X controls) would also have potential merit with re spect to addressing the reason able progress requirements for Independence Units 1 and 2. The state may consider submitting a SIP revision that includes such a strategy for Independen ce to replace our FIP.

With regard to the numeric RPGs we are finalizi ng, 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 visibili ty 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 inco rporated visibility improvements that would not occur until after 2018. After considering thes e 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 pr oposed. This approach is consiste nt 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 Pr ogress Goals Under the Regional Haze Program,” dated June 1, 2007.70 Section 169B(e)(1) of the CAA directed the Ad ministrator to promulga te regulations that “include[e] criteria for measuring ‘reasonable pr ogress’ toward the natio nal 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 stat e’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 comparis ons between the progress that will be achieved by the state’s long-term strategy and the URP, 86 and (2) providing a benchmark fo r assessing the adequacy of a state’s SIP in 5-year periodic reports. 87 Consequently, in our 2007 Reasonable Progress Guidance, we indicated that stat es could consider the “time necessary for compliance” factor by “adjust[ing] the RPG to reflect the degree of impr ovement 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 f our-factor analysis) and include d in the long-term strategy. In this instance, we are taking final action on the Arkansas Regional H aze FIP 9 years after the

state’s initial SIP submission was due. As a resu lt, only some of the control measures that we have determined are necessary to satisfy the BA RT 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 Gu idance and finalize RPGs that represent the visibility conditions anticipated on the 20% wo rst 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 SO 2 BART limit of 0.15 lb/MMBtu, that Flint

Creek and White Bluff would install low NO X burners to satisfy NO X BART, and that AECC Bailey and Entergy Lake Catherine would be s hut 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 Goal s 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 add itional information on the calculation of the RPGs.71 more stringent SO 2 emission limit of 0.06 lb/MMBtu at Flin t Creek and the in stallation of low

NO X burners at Independence in addition to Flint Creek and White Bluff, but also the continued operation of AECC Bailey and Entergy Lake Cath erine. 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 fou r-factor analysis, as requ ired by the CAA and the Regional Haze Rule. Without a four-factor analys is, 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 Independen ce plant are cost-effec tive and reasonable and therefore necessary to make reasonable progr ess. The visibility benefits of the SO 2 controls at Independence, along with benefits of the SO 2 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 a lternative 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 rega rding 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 NO X 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 determin e the impacts of other regulatory programs

and allow for better defined and more cost-effect ive decisions, especially considering there will be future opportunities to re-evaluate the RPGs and URPs.

[Entergy Mississippi Inc. (0168) p. 13; AE P-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 st ated that EPA failed to consider the full improvements in visibility at Class I areas th at will result from other emission reduction programs currently being implemen ted 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 NO X controls currently in the FIP. Im plementation 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 Arka nsas’s SIP providing additional benefits not quantified in the RPG analysis. Additionally, im plementation of the MATS rule and several other Clean Air Act programs, including CSAPR, the 1-hour SO 2 National Ambient Air Quality Standard (NAAQS), and the ozone NAAQS will, in many cases, also result in additional reductions in visibility-impairing pollutants be yond those relied upon when analyzing impacts at

Arkansas’ Class I Federal areas. 91 Time should be allowed for ev aluating the emission reductions and visibility improvement impacts resulti ng 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 impos ing costly controls in the firs t planning period is unwarranted in such a long term goal program and that the ob ligation to consider cost s is not only related to quantity but also timing. A much mo re prudent approach would be to allow time to determine the impacts of CSAPR, MATS, and other programs before requiring costly contro ls on a facility that will soon also need to reevaluate options re lated to the 111(d) program. Waiting until that program's requirements are better defined w ill allow for more cost-effective decisions.

AEP-SWEPCO stated that consid ering that the visibility impr ovements of these programs have not yet been quantified, and the gr adual progress anticipated in establishing such a long term goal, EPA should be patient and not take such ag gressive 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 issu es and the added visibility im provement associated with the controls proposed for the Independe nce facility do not indicate an ur gent 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 a dded in later planning periods, if needed.

[Conway Corporation et. al. (0172) p. 11-12 and EE AA (0173) p. 15] Conway Corporation et. al. and EEAA stated that in proposing to require th e 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 impr ovement 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 NO X 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 cu rrent emissions rates and those approved in Arkansas’s SIP, providing a dditional benefits not quantif ied 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 associ ated 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 th at even if the rule is stayed or vacated while EPA undertakes its cost analysis in compliance with the Court’s decision, MATS and its associ ated emission reductions will go forward by the end of the first planning period.73 Conway Corporation et. al. and EE AA stated that given that Arkansas’ Class I areas are ahead of the URP necessary to obtain the national visibi lity goal even before implementation of BART, EPA should allow more time for evaluating the em ission reductions and visibility improvement impacts resulting from these programs before requ iring installation of expensive controls that may not achieve perceptible visibility benefits.

[EEAA (0173) p. 15-16] EEAA stated th at in spite of the visibility benefits from other emission reduction programs (over and above currently do cumented visibility improvement), EPA is pushing forward with a proposal for additional cont rols under the guise of reasonable progress. EEAA disagrees with EPA’s conclusion that additi onal 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 f acility 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 Regiona l Haze Rule’s design for long-term gradual progress, EPA should be patient and should not ta ke such unreasonable an d aggressive action to impose costly controls that yield imperceptible visibility benefits.

Response: We disagree that EPA should delay impleme ntation of this FIP to allow time for evaluating the emission reductions and visibility improvement impacts resulting from other EPA programs. Congress added the visibility provisi ons in section 169A of the CAA in 1977; Congress later amended the Act in 1990 tasking EP A to carry out its regu latory 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 signi ficant portion of our FIP addres ses the requirements for BART. Given the statutory and regulator y requirements for BART, we cannot put off implementation of these measures to see what other improveme nts 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 expl ained elsewhere in this document, we have determined that the measures in the FIP applicab le 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 pr omulgate a FIP within 2 years of disapproving a SIP in whole or in part, unle ss the State corrects the deficiency and EPA approves the plan. There is no authority in the CAA for EPA to fu rther delay our action for the reasons provided by the commenter. The fact that we let two years el apse without fully approving a regional haze SIP

led a district court in Arkansas to order EP A to finalize a RH rulemaking by a date certain (August 31, 2016). 93

The Regional Haze Rule requires states to esti mate 2018 emission inventor ies as part of the planning process. EPA approved Arkansas’ estimat es 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 em issions inventories for 2018 in its SIP. As explained in our revi ew of the Arkansas Regional Ha ze SIP, CENRAP with assistance from Arkansas developed an emissions inve ntory for 2018 “by projec ting 2002 emissions and applying reductions expected from federal and state regulations affecting the emissions of the visibility-impairing pollutants NO X , PM, SO 2 , and VOCs.” EPA approved Arkansas’ 2018 emissions inventory in its fina l 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 ignor ing recent regulatory requirements, we agree that there have been a number of regulat ory changes over the years since the emission inventories for Arkansas and the surrounding st ates were developed. As noted above, we approved these inventories when we took act ion on Arkansas’ Regional Haze SIP as valid

estimations of 2018 emissions inventories. We note that Arkansas is re quired to update these inventories in its next regi onal haze SIP, due at this time in just over two years. 95 For the near term, we do not expect significant changes in em issions from Arkansas sources between now and 2018. More significantly, the comm enters’ suggestions that EPA should further delay the implementation of measures to improve visibili ty 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 ove r the planning period of the SIP. That Arkansas is meeting the glidepath, largely due to emissi on reductions in other states, does not support the conclusion that the most significant sources of visi bility 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 NO X to increase over the first planning period, notwith standing the reductions e xpected from federal regulations. Thus, for example, SO 2 emissions were expected to increase by 6,000 tons per

year. 96 In terms of changes in emissions inventorie s in Arkansas, we do not expect significant changes in emissions from Arkans as 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 NO X controls currently in the FIP is unclear. In determining that CSAPR provides for greater reasonable pr ogress than BART, EPA assessed th e 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 ye ars 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 Un ited 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 SO 2 and NO X reductions in many states; in Arkansas, however, the state is subject only to an ozone season NO X budget requirement. The commenters have presented no ev idence that CSAPR will result in any added benefit over and beyond the site-specific BART contro ls in the FIP at the Class I areas impacted by Arkansas, but if the commente rs’ point is that a program re quiring hundreds of thousands of

tons of reductions in SO 2 and NO X across a broad region will achieve greater visibility improvement than the modest BART NO X controls in the Arkansas FIP, then we would have to agree. To the extent the commenter is arguing that our revised reasona ble 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 th at 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 prop osed partial approval an d 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 peri od and our final action was published on March 12, 2012. 98 In our final action, we determined th at the Arkansas RH SIP does not meet certain elements of the Federal regional haze re quirements and partially approved and partially disapproved the Arkansas RH SIP. While we did receive advers e 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 reasonabl e 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 sign ificant additional visibility benefits or perceptible visibil ity benefits. We also address el sewhere in this section of the document comments contending that additional controls ar e not necessary at this time to make reasonable progress because Arka nsas’ 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 cont rols for Entergy Independence.

[ADEQ (0160) p. 8-13] ADEQ stated that EPA improperly performed the reasonable progress analysis by applying the reasona ble 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 numeri cal goals for reducing regional haze, called

97 76 FR 64186.

98 77 FR 14604.76 “reasonable progress goals.” This type of anal ysis 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 with in the scope of its lawful aut hority, “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 ‘o n a consideration of the

relevant factors.’” 101 In the proposed FIP, EPA has disreg arded 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 prim arily 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 (“reasonabl e progress factors”): (1) the co sts of compliance; (2) the time necessary for compliance; (3) the energy and non-air quality envir onmental 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 en sure 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 th e proposed FIP. Instead of utilizing the four reasonable progress factors in co njunction with the URP to set numerical goals measured in deciviews, EPA applies the reasonable progress fact ors in order to require emissions controls for Independence Plant Units 1 and 2, which it re fers to as a “reasonable progress source.” Effectively, EPA has applied the reasonable progre ss factors to the Independence Plant as if it were a BART analysis. Rather than consider ing the URP in conjunction with the reasonable progress factors, EPA completely dismisses the UR P, which Arkansas is on track to meet in the

99 See State of AR, ADEQ, State Implementa tion Plan Review for the Five-Y ear 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 th at “the URP does not establish a ‘safe harbor’ for the state in setting its progress goals.” 107

ADEQ stated that furthermore, EPA fails to expl ain how factors required to be considered in setting specific numerical targets, which are th emselves 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 fact ors set out in 40 C.F.R. § 5 1.308(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 we re 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 prog ress factor clearly marked, but this analysis does not explain how those factors were taken into consideration in select ing 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 reas onable 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 ha s failed to consider the “costs of compliance” with the RPGs in the proposed FIP. Although all of the reasonable prog ress factors are required to be considered in setting the RPGs, the Suprem e Court of the United Stat es 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 “app ropriate and necessary” as not including an analysis of costs in implementing the Mercur y and Air Toxics Standa rds (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 do llars 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 settin g 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 evalua te Entergy’s Independence Plant “because it is a signi ficant source of SO 2 and NO X ... even though Arkansas’s Class I areas and those outside of Arkansas most significantly imp acted 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 havi ng been installed to date. The additional control measures for the Entergy In dependence 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 mode ling for potential visibility impacts. 114 In doing so, EPA has ignored its own framework for establishing re asonable progress goals and requiring specific emissions controls for a point source. EPA should ha ve considered the four factors in 40 C.F.R. § 51.308(d)(1)(A) along with the URP as set fort h in 40 C.F.R. § 51.308(d)(1)(B) in setting

numerical RPGs.

ADEQ stated that in the Arkansas Regiona l 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 whethe r 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 canno t determine whether the RPGs presented by EPA are appropriate because EPA has failed to perf orm 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 s hould 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 Progr ess Goals (RPGs) for each Federal Class I area in the state to provide incremental visibility im provements 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_revie w-final-6-2-2015.pdf.

The Attorney General stated that 40 C.F.R. § 51. 308(d)(1) requires the Stat es to “establish goals (expressed in deciviews) that provide for reasona ble progress towards achie ving natural visibility conditions.” In setting a reas onable 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 facto rs 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 Im plementation 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 Cour t of Appeals held that EPA was bound to follow the same regulatory requirements as the St ate 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 demonstr ation of how those factors were applied. Then

EPA may determine that additional measures are nece ssary to meet the goals. The law clearly states that “reasonable progress goals...are not di rectly 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 (“I ndependence”). Independence is not subject to the BART requirements because it was not co nstructed between 1962 and 1977. Its construction commenced after this time period. EPA uses a “r easonable progress analysis for point sources” to shoehorn Independence into the use of emission controls wit hout a legal basis for doing so. This action is outside the scope of the Cl ean 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 us es 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 achie ve 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. It s discussion of those fact ors 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 Ac t 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 misunderstandi ng of the process for establishing RPGs. One

commenter contends that the la w 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 meas ures are necessary to meet th at 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 prog ress factors for the Inde pendence 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 envi ronmental 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 statutor y 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 consid eration in selecting the goal.

The statute and regulations are clear that in esta blishing the RPGs, states (or EPA in standing in the shoes of the state and promulgating a FIP) mu st conduct an analysis of the four statutory

factors to determine whether additional cont rols (i.e., beyond those required under BART and other “on the books” controls) are necessary to make reasonable pr ogress. These statutory factors are only relevant in the contex t of considering specific possibl e 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 afte r taking into account these fact ors -- 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 unde r 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 considerat ion of specific control measures for specific sources under th e reasonable progress requirements.

This approach to setting RPGs was understood a nd used by the states and the RPOs (including Arkansas and CENRAP), which took into acc ount the anticipated emi ssion reductions from specific measures adopted to improve visibility as well as from other CAA requirements in calculating 2018 emission inventor ies and then established RPGs based on the anticipated changes in emissions over the planning period of th e SIP. A description from last year by EPA of the design of the regional haze program and how st ates established reasonable progress goals provides a useful overview of how the program ha s 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 (PM 2.5 ) 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 thei r regional haze SIP. 64 FR at 35733. This is made clear in the haze regulations which prohibit states from adopting RPGs that represent less visibi lity 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 ha d or were expected to come into effect after the baseline period and that were anticipated to result in81 reductions of visibility impairing pollu tants. These regulations included NAAQS implementation measures as well as other CAA requirements,

such as mobile source rules or Ma ximum Achievable Control Technology (MACT) standards issued under se ction 112 of the CAA. . .

Thus, states took into account the an ticipated emission reductions from a wide range of measures in setti ng RPGs. To model the visibility conditions in 2018, states used projecte d 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 aff ecting 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 acc ount, as described above, anticipated reductions inemissions resulting from recent Federal rules addressing non-visibilityrelated requirements, as well as c onsent decrees, significant measures adopted by nearby states, and speci fic 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 ar gue that we performed “a BART analysis” for Independence. States and EPA have generally ta ken very similar approaches to analyzing BART and reasonable progress controls during the first planning period, as the relevant f actors to be considered overlap to a large degree: Compare sec tion 169A(g)(1) (“the costs of comp liance, the time necessary for compliance, the energy and nonair quality envi ronmental 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 visi bility which may reasonably be anticipated to result from the use of such tec hnology”). The type of s ource-specific analysis undertaken for Independence is a car eful and thorough analysis that by its nature tends to require cost-effective controls on only the largest contributo rs to visibility impairment. It is both logical

and rational and is based on consideration of the relevant st atutory factors.

The commenter’s suggestion that because the RP Gs 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 progre ss toward the national goal of natural visibility

conditions. While our FIP does cons ider and ultimately apply contro ls on an individual source basis to assure reasonable progres s, this is consistent with th e CAA, our regulations, and past EPA guidance. The four statutory fact ors under CAA Section 169A(g) and 40 CFR 51.308(d)(1)(i)(A) are directed to the listed possi ble features or cons equences 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 pr ogress analysis must consider the “compliance” time and costs for “potentially aff ected sources.” A state determines the rate of progress that is reasonable for a Class I area afte r taking into account the f our statutory factors-- as applied to specific sources or groups of sour ces – to determine what additional controls should be required in its regional haze SIP. Thus, indi vidual stationary sources may be subject to emission limits and source specific analysis wh en 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 elsewh ere 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 change s 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 th e 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 requi rements, 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 fact ors or require source-specific emission limits under the reasonable progress requirements.

Furthermore, if the CAA’s requirements were su ch that only sources subject to controls for

BART could be looked to for emission reductions to promote reasonable progr ess, 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 planni ng periods to build on past progress. Sourcespecific emission limitations, as pr omulgated in our FIP, are manife stly 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 Secti on 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 referen ce to “reasonable progress sources” in our FIP proposal, and states that this term does not app ear in the RH rule or related guidance. The

117 64 FR 35733.

118 See 51.308(d)(1)(v).83 commenter contends that we ci te no legal authority for identi fying and requiring emissions controls for “reasonable progress sources.” Where we used the term “reasonable progress sources” in our FIP proposal, we us ed 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 requ isite analysis to determine what controls are necessary to make reasonable progress by considering those sources and sour ce categories with the most significant impact on visibility impairme nt. We explained in our FIP proposal that our reasonable progress analysis focused on the poi nt source category since the other source categories each contribute a much smaller propor tion of the total light ex tinction 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 appr oximately 59% of the total light extinction. In comparison, area sources, which are the source cate gory with the next highest contribution to the total light extinction at each Class I area, contributed approx imately 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 reasona ble progress analysis to focus on the point source category.

We also note that the CENRAP CAMx modeling s hows that on most of the 20% worst days in 2002, total extinction is dominated by sulfat e 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 por tion 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 SO 2 and NO X to be key pollutants that contribute to visibility impairment at Arkans as’ Class I areas and considered both

SO 2 and NO X controls in our reason able 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 ar e reasonable in the first regional haze planning period, we examined the most recent SO 2 and NO X emissions inventories for point sources in

Arkansas. Our examination of the emissions invent ory 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 SO 2 and NO X point source emission in the state, contributing approximately 36.2% of the total SO 2 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 Sup port Document for CENRAP Emissions and Air Quality Modeling to Support Regional Haze State Implementation Plan s,” 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 Sup port Document for CENRAP Emissions and Air Quality Modeling to Support Regional Haze State Implementation Plan s,” 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 SO 2 tons out of total SO 2 point source emissions of 83,883 SO 2 tons, based on the 2011 NEI) and approximately 21.3% of the total NO X point source emission in the state (i.e., 13,411

NO X tons out of total NO X point source emissions of 62,984 NO X tons). 123

Our examination of the emissions inventory also revealed that other large point sources emitting

SO 2 and NO X are already being controll ed under the BART requirements (i.e., White Bluff and Flint Creek) and that further controls during this planning pe riod are not necessary for these sources. After White Bluff, Independence, and F lint Creek, the remaining point sources in the

state have much lower SO 2 and NO X emissions than these facilities. In other words, the magnitude of SO 2 and NO X emissions from point sources in Arkansas drops off considerably after the top 3 emitters. For example, the point source with the fourth highest SO 2 emissions (after White Buff, Independence, and Flint Cree k) is Future Fuel Chemical Company, which contributes approximately 4.1% of the total SO 2 point source emissions in the state (i.e., 3,420

SO 2 tons out of total SO 2 point source emissions of 83,883 SO 2 tons). The point source with the fourth highest NO X emissions is the Natural Gas Pi peline Company of America #308, which contributes approximately 5.1% of the total NO X point source emission in the state (i.e., 3,194

NO X tons out of total NO X point source emissions of 62,984 NO X 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 cont ributors 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 contro ls under reasonable progress. The claim that we arbitrarily singled out Independe nce and that we provided no expl anation as to why we did not evaluate other point sources under the reason able progress requireme nts is incorrect.

In one part of the comment, the commenter conte nds 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 c ontends 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 progre ss factors and we also di sagree 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 an alysis is inappropriate or insufficient because we applied the reasonable progres s factors to an indi vidual source (the Independence Plant), we discussed above why individual sources may be subj ect to controls and source specific analysis when establishing RPGs. With regard to our cons ideration 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 th rough the URP analysis is reasonable based upon the statutory fact ors, the state, or us in the case of a FIP, should identify th is 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 dete rmine that additional progress is reasonable based on the statutory fa ctors, that amount of progress should be adopted as the goal fo r the first long-term strategy. 125

That Arkansas’ Class I areas are below the URP g lidepath 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 possi bility 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 re flected in the URP is necessary to demonstrate reasonable progress. 126 Based on our analysis of the f our statutory factors, along with

consideration of the visi bility improvement of controls, we determined that there are reasonable controls available for Independen ce that would be cost-effective and would result in meaningful visibility benefit at Arkansas’ Class I areas. Because we have id entified that additional progress (beyond the amount reflected in the URP) is r easonable based on the statutory factors and our

consideration of the visi bility impacts, we are required to adopt that amount of progress under the reasonable progress requirements. It is for th is reason that we are requiring controls for Independence under the reasonabl e 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 FI P proposal explained in detail how we took the factors into consideration in evaluating cont rols under reason able 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 Inde pendence 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 spread sheet that contains information concerning ownership, location, boiler type, environmenta l controls, and other pertinent information. 128 The cost of compliance is a factor that is re quired for consideration under both a BART and a reasonable progress analysis. Due to the similaritie s in the facilities and the identical requirement

for consideration of the cost of controls unde r reasonable progress and BART, our use of the

total annualized costs of contro ls 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 fo r 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 ou r reasonable progress analysis, we took into

consideration the cost of contro ls 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 complian ce, energy and non-air quality environmental impacts of compliance, and the remaining useful li fe 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 visibil ity impacts from the Independence facility and the visibility benefit of controls using CALP UFF dispersion modeling. Based on our consideration of the four reasonable progress factors and th e modeled visibility improvemen t of controls, we determined

that reasonable controls for SO 2 and NO X 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 98 th percentile impacts from the source, and are therefore necessary to make reasonable progress. 129

After determining that reasonable controls ar e 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 th e revised RPGs is explained in detail in our FIP proposal and associated TSDs. 130 Therefore, comments allegi ng 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 sta ting that our proposed RPGs for the 20% worst days for Caney Creek and Upper Buffalo improperly incorporated visibility improvements that would not occu r until after 2018, we are providi ng revised RPGs that reflect anticipated visibility conditions at the end of the implementati on period in 2018 ra ther than the anticipated visibility conditions once the FIP ha s 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 re spects, 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 vari ous 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 SO 2 and NO X 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 Goal s 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 NO X controls at all, LNB/SOFA is the only option consistent with the reasonable progress requ irements. However, EPA has set up a false choice by failing to consider more stringent controls such as S CR. LNB/SOFA+SCR is the only option that fully

satisfies the NO X reasonable progress require ments at Independence.

Sierra Club stated that EPA declined to consid er SCR for Independence on the grounds that EPA had found that requiring SCR at White Bluff woul d lead to insufficient visibility benefits. 80 Fed. Reg. at 18,995; see also id. at 18,975. There are two primary fl aws in this argument. First, even if EPA can consider visibility improveme nt under reasonable progress, EPA has no rational basis for relying exclusively on the White Bluff an alysis given the material differences between White Bluff and Independence. I ndependence is closer to Hercul es-Glades and Mingo than is White Bluff. Reducing a certain amount of NO X at Independence may yield greater improvements in visibility at Hercules-Glade s and Mingo than reducing the same amount of

NO X 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 Independe nce 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 improveme nt 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 cons ider SCR for Independence Units 1 and 2 in its reasonable progress analysis.

Additionally, EPA claimed that b ecause 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 becau se “the incremental visibility benefit over LNB/SOFA+SNCR of up to 0.069 dv at a single Cla ss I area is relatively small considering the

incremental cost-effectiven ess of $6,717 per ton of NO X removed for Unit 1 and $5,736 per ton

of NO X 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 bene fits relative to SNCR, given that EPA is not proposing to select SNCR as a reasonable prog ress 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 ex amine the incremental costs and benefits of SCR, the proper comparison is be tween SCR and the technologies that EPA is actually proposing to require: LNB/SOFA.

Response: We disagree that in proposing the two c ontrol options for Independence Units 1 and 2 we set up “a false choice” by not eval uating and proposing more stringent NO X 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 re asonable justification for our decision to focus our reasonable progress analysis of NO X controls at Independence on LNB/SOFA.88 We explained in our propos al that in evaluating NO X controls under the BART requirements for White Bluff Units 1 and 2, we f ound that LNB/SOFA is much more cost-effective (lower $/ton) than SNCR or SCR, and that the additional visibi lity benefits that would be obtained with SNCR or SCR were not large enough to justify the additiona l cost of the more stringent controls for this planning period. 132 Therefore, we proposed to require NO X controls consistent with LNB/SOFA

for White Bluff Units 1 and 2 under the BART re quirements. 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 we re not large enough to justify

the additional cost of these controls at White Bl uff for this planning period, we had no reason not

to conclude the same for the Inde pendence facility. In considering NO X 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 NO X controls on Independence would likely have similar visibility benefits as for White Blu ff, and further supporte d our reasoning that the additional visibility benefits fr om SNCR and SCR controls on I ndependence would likely not be large enough to justify the additi onal cost of these controls for this planning period, just as was the case for White Bluff. Therefore, our reasonable progress evaluation of NO X 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 ar eas than SCR controls on White Bluff, we compare the visibility improvement due to the installation of LNB/SOFA at the Independence facility to the visi bility improvement due to those controls at White Bluff in the

Table below. We note that while LNB/SOFA co ntrols on Independence are predicted to have greater visibility benefits at Mi ngo than the same controls on White Bluff, the opposite is true at

Hercules-Glades.

Furthermore, we note that the baseline visibil ity impacts from Independence are greater at Caney Creek and Upper Buffalo than at Missouri’s Class I areas. 135 The predicted visibi lity benefits of LNB/SOFA controls on Indepe ndence 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 th e case for SNCR and SCR c ontrols. Therefore, we

132 80 FR at 18995.

133 To verify that the White Bluff and Independence Plants are sister facilities, we cons tructed 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 SO 2 and NO X 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 reasonin g for focusing our reasonable progress analysis

for NO X 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 in stallation of either SNCR or SCR cont rols at Independence were to yield greater visibility improvement at the Missouri Cl ass I areas than the same controls at White
Bluff, we note that this does not affect our re asonable progress determination. Our rationale for not evaluating the cost and visibility improveme nt of SNCR and SCR controls for Independence was not because we expected small visibility im provement due to these controls. It was because we didn’t anticipate that the level of additional visibility benefit of th e installation of these controls on Independence compared to less string ent controls would be large enough to justify the additional costs. We do not expect that the possibility of greater vi sibility benefits at

Missouri’s Class I areas from SN CR or SCR controls at Inde pendence compared to SNCR or

SCR controls at White Bluff would alter our conclusion on this matter. Further, because NO X is not a primary driver of regional haze at Arka nsas’ Class I areas on the 20% worst days, and Arkansas’ Class I areas are below the URP glidep ath, we find it reasonable to not require more stringent NO X 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 incremen tal cost effectivenes s of LNB/SOFA + SCR compared to LNB/SOFA + SNCR at White Bluff Unit 1 is $6,717/ton removed and the incremental visibility be nefit is 0.069 dv at the most impacted Class I area. We also found that90 the incremental cost effectiveness of LNB/SO FA + SCR compared to LNB/SOFA + SNCR at White Bluff Unit 2 is $5,736/ton removed and the in cremental 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 leve l of additional visibility benef it of SCR controls compared to SNCR is not large enough to justif y the incremental cost of the mo re stringent control. We also proposed to determine that the le vel of additional visibi lity 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 increm ental cost effectiveness and incremental visibility improvements, as the co mmenters state we should have done, we continue

to find that the level of additiona l visibility benefit of SCR contro ls 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 ra nging from 0.032 to 0.103 dv on a unit-basis at an

individual Class I area and incremental cumulati ve visibility benefits of 0.216 dv per unit across all 4 impacted Class I areas are not large enough to justify the additiona l cost of SCR on White Bluff for this planning period. Ba sed on our consideration of the five BART factors, we are finalizing our determination that NO X BART for White Bluff Units 1 and 2 are controls

consistent with LNB/SOFA.

We further address elsewhere in this document co mments 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 NO X 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 op tion that fully satisfies the reasonable progress requirements for NO X at Independence. Sierra Cl ub et. al. stated that its analysis of SCR controls on Independence Units 1 and 2 indi cates 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 remove d using the 2013 Cost Module. Stamper Report at 66. Sierra Club argue that these aver age cost-effectiveness valu es are well within the range that EPA has found reasonable in other reasonable progress determinations. See the Table

of cost-effectiveness values below. The incrementa l cost-effectiveness of SCR is also within the range of incremental cost-effec tiveness values that EPA has d eemed 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 co st-effectiveness of SCR is the d eciding factor in EPA’s decision, there is no basis for rejecting SCR, given that th e incremental cost-effectiveness is less than or equal to the incremental cost-e ffectiveness 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-e ffectiveness relative to averag e cost-effectiveness. Entergy could install SCR within 3 years, which is a r easonable 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 expe rt, 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 opera ting 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/SO FA+SCR to LNB/SOFA at Independence, the comparison weighs in favor of requiring SCR. Th e 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 ar eas (sum of the deciview benef it across the four Class I areas). Gray Report at 6. The comparable value is 0.43 d eciviews 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 contenti on that it can eliminate SCR from consideration at Independence for the sa me 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 incremen tal 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. Re g. at 5,040-41, and is within the range of

incremental cost-effectiveness for ot her controls that EPA has approved, see Stamper Report, Exs. 101, 104.

Sierra Club stated that in sum, the reasonable pr ogress factors, as well as visibility improvement, support finding that LNB/SOFA+S CR 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 th e visibility improvement from operation of LNB/SOFA+SCR at Independence Units 1 and 2, a nd therefore the long-term strategy should include SCR in order to meet the goals fo r Caney Creek and Upper Buffalo. Second, the reasonable progress goals for Hercules-Glade s and Mingo should refl ect the visibility improvement from operation of LNB/SOFA+SCR at Independence Units 1 and 2, and therefore the long-term strategy should incl ude 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 th an 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 Determinations 138

Facility Reasonable Progress

Control Cost, $/ton

Hawaii Electric Co., Kanoelehua Power Plant SO2 emissions cap 139 5587 Hawaii Electric Co., Puna Power Plant SO 2 emissions cap 5583 Hawaii Electric Co., Shipman Power Plant SO 2 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 NO X controls on Independence instead focused on LNB/SOFA. We ha ve 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 cont rols 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 SC R controls and dry FGD at Independ ence (on a facility-wide basis), but based on the information provided it does not app ear 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 SO 2 emissions cap] was derived from EPA’s analysis of the costs of switching these units to 1% sulfur fuel.” Therefore, the cost-eff ectiveness for the three Hawaii plants represents the cost to meet the SO 2 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 m odeled using baseline (i.e., uncontrolled) SO 2 emission levels, while the commenters’ modeled visi bility benefits of SCR at Independence were modeled using controlled SO 2 emission levels, the commenters’ comparison of visibility benefits from SCR at White Bluff to visibility benefits from SCR at Independen ce 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 facilit ies 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 be nefits 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 vi sibility benefits due to SCR at Independence are larger than that at White Bluff, or that th e incremental visibility benefits due to SCR at Independence (even when compared to LNB/SO FA) 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 benefi ts of LNB/SOFA. The commenters state that the incremental visibility benefit of SCR on the two units at Indepe ndence 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 LN B/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 SO 2 rather than the baseline SO 2 emission rate, so th ese numbers are not directly comparable to the visibility benefits of NO X controls at White Bl uff 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 SO 2 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 th e procedure we used in estimating baseline NO X emissions for our cost analysis of LNB/SOFA controls at Independence. The fact that the commenters can construct an alternative appr oach to our baseline calculation using 2001-2003 baseline emissions that results in higher cost-e ffectiveness values (i.e., lower $/ton) does not invalidate our approach. We calculated our baseline NO X 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 a ddress potential yearly variations in coal sulfur data, capacity usage, etc., and make the baseline more repr esentative of plant operations. Our Reasonable Progress Guidance notes the similarity between so me of the reasonable progress factors and the

BART factors contained in sec tion 51.308(e)(1)((ii)(A), and suggests that th e BART Guidelines be consulted regarding cost, energy and non-ai r quality environmental impacts, and the remaining useful life of the unit. We therefore relied on our BART Guidelines for assistance in interpreting those re asonable progress factors, as applic able. One of these areas is in the

calculation of the baseline emissions in determini ng 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 anal ysis for controls on White Bluff.

In analyzing the cost of LNB/SOFA + SCR c ontrols on Independence, the commenters assumed

a controlled NO X 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 NO X 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 inform ation 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 NO X emission rate of 0.04 lb/MMBtu on a 30 boiler-operating-day rolling average. We see no ev idence 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 sustaina ble at the Independence facility absent sitespecific engineering information. As the commente rs’ cost analysis is based on an assumed NO X emission rate of 0.04 lb/MMBtu fo r LNB/SOFA + SCR, we disagr ee with the cost analysis.

Due to the issues we discuss above concerning the commenters’ revised NO X baseline and NO X 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 c ontrols must be required for Independence Units 1 and 2 under the reasonable progress requirements for this planni ng period. We note that the commenters estimate

that the cost of LNB/SOFA + SCR controls on Independe nce is $3,570/ton at Unit 1 and $2,772/ton at Unit 2. The commenters also estimate th at 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 visi bility benefit of S CR on the two units at Independence (using the controlled SO 2 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 comme nters, even if we were to accept the commenter’s cost estimates, we would find that th e 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 di sagree that it demonstrates that SCR controls are necessary under the reasonable progress requirements for Independ ence 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 ef fectiveness and incremental cost effectiveness of controls we have required in other regional haze actions, we note th at in evaluating different co ntrol options for reasonable progress under the long term strategy, even if a partic ular control option is cost-effective or has a reasonable incremental cost-effectiveness, it may not be the most reasonable and appropri ate 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 progr ess analysis of NO X controls for Independence. We believe this is a reasonab le approach and that th e CAA, RH regulations, and our Reasonable Progress Guidance provide us with discretion to take such an approach in a reasonable progress analysis. As di scussed in our final rule and el sewhere in this document, we are finalizing NO X 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 Arka nsas’ impacts at Class I areas in Missouri, we disagree. In our proposed partial approval and partial disapprova l action on the Arkansas RH SIP, we stated that we agreed that additional emissions re ductions 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 reasonabl e 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 Independen ce in all Class I areas

located within 300 km of the Inde pendence Plant. The visibility improvement projected to take place at Hercules-Glades and Mingo due to contro ls at Independence did not affect our proposed decision for reasonable progress controls. We a pologize for any confusion that may have been caused by our modeling of the visibility im provement in Missouri’s Class I areas.

Comment: EPA should reject Option 2 under th e 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 cont rol options for the Independence plant: Option 1, which would require scrubber s 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 NO X controls, because it is inconsistent with the reasonable progress requirements. In contrast to Option 2, EPA’s proposed Option 1, which would require Independence Un its 1 and 2 to meet

143 Thus, we disagree that we “place[d] undue weight on incremental cost-e ffectiveness 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 e ffectiveness along with the other statut ory factors in our cost analysis for

NO X controls on White Bluff and in developing our cost analysis for NO X controls for Independence.

144 76 FR at 64215.

145 77 FR 14604.97 a NO X emission limit based on the use of LNB/SOFA, is cost-effective and consistent with each

of the four factors for evaluati ng 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 aver age 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 calc ulate the cost of LN B/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 pe r ton for Unit 2. Stamper Report at 66. Regardless of whether EPA uses the cost-effectiv eness figures from the proposed rule, or Ms. Stamper’s calculations, LNB/SOFA at Independen ce 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 Determinations 146

Facility Reasonable Progress

Control Cost, $/ton

Hawaii Electric Co., Kanoelehua Power Plant SO2 emissions cap 147 5587 Hawaii Electric Co., Puna Power Plant SO 2 emissions cap 5583 Hawaii Electric Co., Shipman Power Plant SO 2 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 SO 2 emissions cap] was derived from EPA’s analysis of the costs of switching these units to 1% sulfur fuel.” Therefore, the cost-eff ectiveness for the three Hawaii plants represents the cost to meet the SO 2 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 th e 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 qua lity 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 reasona ble progress measure the agency should adopt for controlling NO X emissions from Independence. LNB/ SOFA would improve visibility by 0.461 deciviews at Caney Creek and 0.248 deci views 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 eminen tly reasonable to require NO X controls at Independence, given that it currently has no NO X controls at all, is th e second-largest emitter of NO X in Arkansas, and EPA is proposing NO X controls for the first- and third-largest NO X emitters in the state. See 80

FR at 18991. EPA has not demonstrated that co nsideration of the four reasonable progress factors supports requiring no NO X controls, in light of the record evidence that cost-effective

NO X controls can be installed in a short period of time at Independence Units 1 and 2 with minimal environmental impacts. As EPA has not ar ticulated a rational basi s for disregarding the

evidence in the record that s upports Option 1, it would be arbitr ary and capricious for EPA to select Option 2 on this record.

Response: Although we disagree with the commenters’ co ntention that we erroneously declined to require LNB/SOFA + SCR at Independence Un its 1 and 2, we apprec iate 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 rulemaki ng and elsewhere in this document, we are finalizing Option 1 for Independence Units 1 and 2, which consists of requiring SO 2 controls

consistent with installati on of dry scrubbers and NO X controls consistent with installation of LNB/SOFA under the reasonable progress requirements.

Although it does not ultimately affect our final decision to require NO X controls consistent with LNB/SOFA, we disagree with the commenters’ c ontention that we underestimated the cost of LNB/SOFA at Independence and ad dress 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 cal culated by us in our cost analysis, and we acknowledge the information presented by the comm enters concerning the cost-effectiveness of reasonable progress determinations made in other regional haze actions.

We also agree that single source CALPUFF mode ling shows that meaningful reductions to the maximum 98th percentile visibility impact from the Independence facility are expected to be99 achieved through NO X controls. As discussed in our proposal, we conducted CALPUFF modeling of the baseline visibili ty impacts from Independence and the visibility benefit of

LNB/SOFA controls. 148 We found that LNB/SOFA controls on Independe nce 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 CA Mx source apportionment modeling conducted by Entergy and submitted to us during the comm ent period for our proposal shows that the contribution to visibility impairment due to ba seline emissions from th e 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 impairmen t at each Class I area and a large portion (approximately one-third) of the total contributi on 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 SO 2 , we note that

NO X emissions from the facility also have im pacts 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 NO X controls on Independence would provi de visibility improvement on this portion of the 20% worst days, a nd as such, we are requiring NO X controls consistent with LNB/SOFA under the reasonable progress requirements.

In response to comments stating that LNB/SOFA cont rols can be installed in less than a year, we are revising our proposed compliance date for NO X 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 issu es, we are finalizing an 18-month compliance

date for NO X controls for these sources.

3.b. Controls under reasonable progress/Arkans as’ Class I areas are below URP glidepath

Comment: EPA did not appropriately analyze wh ich sources, if any, should be controlled under the Reasonable Progress requirements.

[Entergy Arkansas Inc. (0166) p. 18] Entergy st ated that EPA’s justification for imposing SO 2 and NO X emission limits on Independence is not base d on rational policy, legal or environmental grounds and, as a result, it is arbitrary and capricious. EPA’s pr imary justification for proposing reasonable progress limits at Inde pendence is that “it would be unreasonable to ignore a source representing more than a third of the State’s SO 2 emissions and a significant portion of NO X point source emissions.” 80 FR at 18992. EPA fu rther supports its conc lusion that emission limits based on the installation of major control technology are justified based on a finding that the proposed controls at Indepe ndence are cost effective. 80 FR at 18994-97. However, the fact that a source, which is not subjec t to BART, may have significant SO 2 or NO X emissions, or that

it would be cost effective to control such emissions, is irre levant for reasonable progress

148 See our supplemental NO X 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, s hould 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 st ated that for reasonable progress purposes, EPA failed to undertake an appropr iate reasonable progress analys is, including the crucial first step of determining whether additional controls are, in fact, necessary for Arkansas to make reasonable progress. EPA targeted only Independen ce in its analysis and subsequent decision to impose SO 2 and NO X limitations on the two coal-fired un its at Independence. EPA’s singular attention on Independence for reas onable progress controls is unsubstantiated and is patently arbitrary and capricious. Despite identif ying the 10 largest point sources of SO 2 and NO X 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 thos e 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 ignor ing the other seven large point sources. 150

Entergy stated that by focusing solely on Indepe ndence, EPA’s reasonable progress analysis for the proposed Arkansas FIP abandons the analytical approach and determinative standards that guided previous reasonable progre ss analyses and determinations. In place of the criteria and procedures that EPA established in its own gui dance 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 Independen ce simply because it believes “it would be unreasonable to ignore” the faci lity. 80 Fed. Reg. at 18,992. EPA fa iled to consider any lesser level of controls, the relative costs of such c ontrols, the effectivene ss of the controls in improving visibility or the cost per deciview improvement associat ed with the proposed controls.

Entergy stated that EPA arbitr arily elected to propose contro ls for Independence that are unnecessary for Arkansas to demonstrate reasonab le progress, provide no perceptible visibility improvement and exceed the cost estimates doc umented for other sources under other approved plans where EPA declined to impose reasonable pr ogress controls. Further, EPA failed to follow its own guidance, which indicate s that “States should consider a broad array of sources and activities when deciding which sour ces 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) (Reas onable 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 anal yze 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/reaso nable_progress _guid07130 7.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 a nd is completely inconsistent with the detailed approach taken by EPA Region 6 in its promul gation 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., to tal emissions – 24-hour maximum annualized – divided by di stance to the Class I area) for each Texas point source and relevant Class I area to identify those poi nt 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 EP A’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 re sults “suggest that controlli ng a small number of sources will result in visibility benefits at both Class I ar eas, 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 M ontana Regional Haze FIP, 77 Fed. Reg. at 24,058-59; and Proposed North Dakota Regiona l Haze FIP, 76 Fed. Reg. at 58,624-26. By notable contrast, EPA’s Regi on 6 office did not perform any evaluation to identify any Arkansas point sources contributing to visibility impairment (or the scope of contri bution) 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 mode l, as it did in Arkansas. See Proposed Texas Regional Haze FIP, 79 Fed. Reg. at 74,877-78; Proposed Montana Re gional Haze FIP, 77 Fed. Reg. at 24,050; Proposed North Dakota Regional Haze FIP, 76 Fe d. Reg. at 58,635. EPA proceeded to complete the required four-factor reasona ble progress analysis in those other states only after narrowing the list of potential point sources. Propos ed 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 Region al Haze Rule requires that additional controls for proposed emission reductions, as iden tified 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 dict ates that if a point source’s contribution to visibility impairment is determined to be insi gnificant then add itional controls are not necessary to achieve reasonable

progress.102 [Entergy Mississippi Inc. (EMI) (0168) p. 4-5) EMI stated th at by focusing solely on the Independence Plant, EPA’s reasonable progress analysis for the Proposed Rule abandons the analytical approach and criteria that guid ed previous reasonable progress analyses and determinations. In place of the criteria and pro cedures that EPA utilized and applied in previous decisions to approve/disapprove regional haze SI Ps 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 igno re” the facility. In its f our-factor analysis, the agency further abandoned the standards and thres holds 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 impr ovements documented for other sources under other approved plans. EPA’s arbitrary evaluation proce ss for the Arkansas FIP not only distorts the goals and objectives of the regional haze rule bu t also is contrary to EPA’s own requirements for uniformity and regional consistency.

As an initial matter, EPA did not meet the Ac t’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 resu lt from BART” and other Clean Air Act programs “it may be all that is necessa ry 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 fr om any Arkansas point source, including the Independence Plant. The failure to determine visib ility impact is contrary to typical practice and is completely inconsistent with the detailed ap proach taken by Region 6 in its promulgation of the regional haze FIP for Texas, in which the ag ency conducted a refined multi-step process to identify those point sources re quiring further evaluation, quantif ying visibility impacts from those sources and arriving at a common brea kpoint in potential visibility improvement. 156 EPA proceeded to the required four-factor reasonable pr ogress 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 states 158 and because, as discussed above, the regional haze rule requires that additional controls for pr oposed emissions reductions, as stated in an implementation plan, must be needed to achieve reasonable progress. 159

By notable contrast, the same EPA Region di d not perform any eval uation to identify any Arkansas point sources contribu ting to visibility impairment (or measure the scope of any contribution) at the Upper Buffalo or Caney Cr eek class I Federal areas. Instead, the Agency made the simplistic evaluation that the Independence Plant was a large source of SO 2 and NO X

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); R easonable 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 so urce’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 ignor e” the facility. 160 This arbitrary approach turns the regional haze rule on its he ad 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 additi onal controls at the Independen ce Plant is that “it would be unreasonable to ignore a source representi ng more than a third of the State’s SO 2 emissions and a significant portion of NO X point source emissions.” 161 However, the fact that a source not otherwise subject to BART may have significant SO 2 or NO X emissions is irrelevant for reasonable progress purposes. This arbitrary appr oach to reasonable prog ress analysis (or lack thereof) is grossly inconsistent with the C AA, Regional Haze regulati ons and guidance, and EPA’s own prior efforts; the latter of which firs t 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 furt her the goal of the regional haze program and, moreover, is unnecessary to achieve reasonable progr ess 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 stat ed that EPA’s reasonable progress analysis for the Proposed Rule abandons the analytical a pproach and determinative criteria that guided previous analyses and determinations. In the place of the criteria a nd procedures that EPA utilized and applied in previous decisions to approve/disapprove re gional haze state implementation plans or promulgate regional haze federal implementatio n 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 faci lity. During its four-factor an alysis, the agency further abandoned the standards and thresholds that guide d previous determinations, choosing instead to propose additional controls for the Independence Plan t that are not cost-eff ective and fall short of the visibility improvements documented for othe r 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 commen ts on specific issues relating to the inconsistencies in the EPA’s proposed FIP. The commenters stated that reviewed individually, each issue evidences an arbitrary, un justified and inconsistent application of the regional haze regulations. Collectively, they de monstrate 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 ag ency to ensure that ac tions taken under the Clean Air Act: (1) “[a]re carried out fair ly 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 activitie s of other Regional Offices. 164

Conway Corporation et. al. a nd EEAA stated that in the pr oposed FIP, Region 6 officials

abandoned the standardized criteri a, procedures and policies prev iously 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 provide d when it rejected Arkansas’ SI P proposal in the first instance. 165

Conway Corporation et. al. a nd EEAA stated that as an in itial matter, in conducting its reasonable progress analysis, EPA failed to assess and document th e contribution to visibility impairment at any class I Federal area fr om any Arkansas point source, including the Independence Plant. The failure to determine visib ility impact is contrary to typical practice and is completely inconsistent with the detailed ap proach 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 requi ring further evaluation; 167 a photochemical modeling scenario utilizing source apportionment to quantify visibility impacts from the s ources identified in the Q/D analysis; 168 and, an extinction percentage threshold to arrive at a common br eakpoint in potential visibility improvement. 169 EPA proceeded to the required four-factor reasonable progress analysis only after narrowing the list of potentia l point sources. 170 No doubt, EPA pursued this process because it was the same process util ized previously by EPA and other states 171 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 c ontrast, in the proposed FIP, EPA’s Region 6 office did not perform any evalua tion to identify any Ar kansas’ point sources contributing to visibility impairment (or measur e the scope of any cont ribution) 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 SO 2 and NO X 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 unreas onable 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’ cont ention 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 repres enting more than a third of the state’s SO 2 emissions and a significant portion of NO X point source emissions, this is incorrect. While we did state in our FIP proposal th at it would be unreasonable to i gnore a source representing more

than a third of the state’s SO 2 emissions and a significant portion of NO X point source emissions,

the commenters took this statement out of c ontext. 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 th ose outside of Arkansas most significantly impacted by Arkansas sources are projected to meet the URP for the first planning peri od. This is because we believe that in determining whether reas onable progress is being achieved, it would be unreasonable to ignore a source representing more than

a third of the State’s SO 2 emissions and a si gnificant portion of

NO X 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 representi ng more than a third of the State’s SO 2 emissions and a significant portion of NO X point source emissions was our primary justification for looking more closely and evaluating the Independ ence plant in our reasonable pr ogress analysis. It was not, as the commenters contend, our justification fo r imposing controls on Independence. As we discussed in our FIP proposal, in our final rule, and el sewhere in this docu ment, our decision to require controls on Independence is based on our reasonable progress analys is, as required by the CAA and the Regional Haze Rule under section 51.308(d)(1).

We disagree with commenters c ontending that the fact that a non-BART source has significant

SO 2 or NO X emissions, or that it would be cost-effectiv e to control such emi ssions, is irrelevant in determining what sources to take a closer l ook 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 consid er in a reasonable progress analysis, meaning that consideration of the co st effectiveness of potential controls is not

irrelevant for reasonable progress purposes. As SO 2 and NO X are visibility impairing pollutants, significant SO 2 or NO X emissions from a source is generally an indication that there may be significant visibility impacts at ne arby Class I areas, and that inst allation 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 c onsideration under CAA section 169A(g)(1) or 40 CFR 51.308(d)(1)(i )(A), states and EPA have th e option of considering the projected visibility benefits of controls in determining if additional controls are necessary to make reasonable progress. Therefore, we find th at 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 su ch emissions is appropriate and relevant for reasonable progress purposes.

We disagree with commenters cont ending that we did not appropria tely analyze which sources, if any, should be controlled under th e reasonable progress requirement s. To the extent that the commenters contend that our proc ess 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 ar e not required to conduct photochemical modeling in a reasonable progress anal ysis. Our 2007 Reasonable Progre ss 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; how ever, 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 iden tifying source categories, specific point sources, or pollutants to

evaluate for additional controls under the r easonable progress requireme nts, 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 usua lly center around the ge neral premise of evaluating the biggest sources and/or the biggest impact ors on visibility. While the states or EPA have the discretion to consider visibility in a reasonable progress an alysis, photochemical mode ling is not required for purposes of conducting a reason able progress analysis.

Our FIP proposal provided a detailed explanatio n of how we determined what sources to

evaluate for controls und er reasonable progress, and we provi ded 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 pr oposal 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 s ources contribute 81.04 Mm

1 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 extincti on. In comparison, area sources, which are the source category with the next highest contributi on to the total light extinction at each Class I area, contribute approx imately 13.3% of the total light extinction at Caney Creek and 15.5% at Upper Buffalo. The rema ining source categories each contribute less than 6% of the total light extinction at each Cla ss I area. Therefore, we concluded that it was appropriate to focus our analys is on point sources. To the extent some commenters suggested

175 “Guidance for Setting Reasonable Progress Goal s Under the Regional Haze Program,” at 4-2.

176 See 80 FR at 18989.107 that our decision to focus our reasonable progr ess analysis on point s ources was unsubstantiated or arbitrary, this is inco rrect and not supported by the record for this action.

The CENRAP CAMx modeling shows that on mo st 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 th e total extinction at Upper Buffalo on 2 of the days that comprise the 20% wors t days in 2002 was due to nitrate. 178 The CENRAP CAMx modeling also shows that sulfate from point s ources was responsible for approximately 54.8% of the total visibility impairment at Upper Bu ffalo and 56.1% at Caney Creek on the 20% worst days in 2002. Nitrate from point sources was re sponsible for approximately 3% of the total visibility impairment at each Class I area on the 20% worst days in 2002. As such, although SO 2 emissions are the primary contributor to regional haze in Arkansas’ Class I areas on the 20% worst days, NO X emissions are also a key contributor. T hus, consistent with our 2007 Guidance for Setting Reasonable Progress Goal s Under the Regional Haze Program, 179 we found it appropriate to evaluate both SO 2 and NO X 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 ar e reasonable in the firs t regional haze planning period, we examined the most recent SO 2 and NO X emissions inventories for point sources in Arkansas (NEI 2011 v1). 180 We reasoned that examination of the emissions inventories is appropriate because significant SO 2 or NO X emissions from a source ar e generally an indication that it may be having significant visibility impact s at nearby Class I areas and that installation of controls may result in substantial emissions re ductions 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 pa rticular, our examination of the SO 2 and NO X emissions inventories for Arkansas’ point sources revealed that the number of poi nt sources that emit SO 2 and NO X emissions is relatively small. Furthermore, a very small portion of the point sources in the state is responsible for a la rge portion of the statewide SO 2 and NO X point source emissions. Specifically, White Bluff, Independence, and Flint Creek are collec tively responsible for approximately 84% of the SO 2 point source emissions and 55% of the NO X point source emissions in the state. Consequently, addressi ng these sources under the regional haze program will address a large proportion of the visibility impacts due to Arkansas point sources. We are requiring SO 2 and NO X controls for White Bluff and Flin t Creek under the BART requirements in this final action, which will substantially reduce emissions fr om these two facilities. The Independence Plant, which is not a subject-to-BART source, cont ributes 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 Implemen tation 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 Implemen tation 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 Un der the Regional Haze Program,” at 2-3 and 3-1.

180 80 FR at 18991.108 the total SO 2 point source emissions in the state (30,398 SO 2 tons out of total SO 2 point source emissions of 83,883 SO 2 tons, based on the 2011 NEI). 181 This source also contributes approximately 21.3% of the total NO X point source emission in the state (13,411 NO X tons out of

total NO X point source emissions of 62,984 NO X 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 sour ces in the State have

much lower SO 2 and NO X emissions than these facilities. In other words, the magnitude of SO 2 and NO X emissions from point sources in Arkansas drops off considerably after the top 3 emitters. We stated the following in our proposal:

The fourth largest SO 2 and NO X point sources in Arkansas are the Future Fuel Chemical Comp any, with emissions of 3,421 SO 2 tpy, and the Natural Gas Pipeline Company of America #308, with emissions of 3,194 NO X tpy (2011 NEI). In comparison to the emissions of the top three sour ces, 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 SO 2 emissions (after White Buff, Independence, and Flint Creek), co ntributes approximately 4.1% of the total SO 2 point source emissions in the state (3,420 SO 2 tons out of total SO 2 point source emissions of 83,883 SO 2 tons, based on the 2011 NEI). The Natura l Gas Pipeline Company of America #308, the point source with the fourth highest NO X emissions, contributes approximately 5.1% of the

total NO X point source emission in the state 3,194 NO X tons out of total NO X point source emissions of 62,984 NO X 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 ot her sources in Arkansas, for c ontrols under reasonable progress in this planning period. The comme nters’ 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 explanatio n as to why we did not evaluate other point sources under reasonable pr ogress is not supported by th e 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 specifi cally evaluated in the first planning period will become larger on a percentage basis. These sources will become th e largest impacting sources and should be considered for analysis under reasonable progress in future planning periods. The methodology we used here thus allows a109 Because our examination of the Arkansas emissions inventory revealed that the number of point

sources that emit SO 2 and NO X 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 SO 2 and NO X point source emissions, we concluded that other more e xhaustive analyses that we have performed in other regional haze actions were unnecessary to identify point source s 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 SO 2 and NO X emissions is very wide spread, an evaluation of the state’s emissions inventory al one was not sufficient to reveal the best potential candidates for

evaluation under reasonabl e progress. For this reason, we expl ained in our Texas Regional Haze FIP that due to the challenges presented by the geographic distribution a nd number of sources in Texas, the CAMx photochemical model was best suited for identifying sour ces to evaluate for reasonable progress controls. 184 We did not encounter these chal lenges 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 eval uate under reasonable progress, Entergy conducted CAMx sourceapportionment modeling and submitted it during th e 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 contra st 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, fo r our Arkansas FIP we had to start from square one in developing our analysis and determini ng what sources to evaluate under reasonable

progress.

We disagree with comments arguing that we “fai led 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 Ar kansas point sources because we did not conduct photochemical modeling, we discuss above and el sewhere in this document that we are not required to conduct photochemical modeling in a r easonable progress analys is. For consideration of the visibility impacts at the affected Class I areas and the visibility benefits of potential controls, we relied on the fo llowing: CENRAP CAMx source apportionment results, point source emission inventory data that initially iden tified the Independence facility as having the greatest potential to impact vi sibility 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 98 th percentile impacts from Independen ce and the visibili ty benefits of

consistent procedure to identify facilities for additional cont rol analysis in this and future planning periods and ensures continuing progress towards th e 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 Arka nsas point sources is incorrect.

We disagree that the controls we are requiring in our final ac tion for the Independence Plant do not further the goal of the regional haze progra m and we disagree that they are unnecessary to make reasonable progress during the first pla nning period. As discusse d in our proposal and throughout this final notice, based on our analysis of the four r easonable progress factors and our consideration of the baseline visibility im pacts from Independence and the visibility improvement of potential cont rols, we determined that SO 2 and NO X 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 commen ts claiming that before conducting a reasonable progress analysis we must first determine whet her 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 relativ e costs of such controls, and the visibility improvement of these controls, we note that for NO X we evaluated LNB/SOFA, which is a control technology that gene rally represents one of the lowest levels of NO X control. For SO 2 , we considered both wet and dry FGD. We di d not consider lesse r technologies for SO 2 since the four

factor evaluation demonstrated cost effective co ntrols. We address elsewhere in this document comments contending that we faile d to consider the cost per d eciview improvement associated with our proposed controls.

We address elsewhere in this document specific comments contending th at the controls we proposed for Independence fall short of the vi sibility 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 sp ecific comments contending that the SO 2 and NO X controls we proposed for Independence exceed th e cost estimates documented for other sources under other approved regional haze pl ans where we did not impose r easonable progress controls.

We address elsewhere in this document commen ts on specific issues relating to what the

commenters contend are “inconsistenc ies in the EPA’s proposed FIP.”

Comment: EPA’s proposed emissi on limits for Independence are not necessary to achieve reasonable progress since ADEQ has demonstrat ed that Caney Creek and Upper Buffalo will be below the glide path in 2018 and will m eet the 2018 RPGs established by Arkansas; this trend in visibility improvement is expected to continue beyond 2018.

185 We address comments contending that we inappropri ately 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 st ated 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 cont rols are “cost effective.”

Entergy stated that in a reasonable progress an alysis, 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 adde d); Reasonable Progress Gu idance at 4-1 (“Given the significant emissions reductions that we antici pate to result from BA RT” and other Clean Air Act programs “it may be all that is necessary to achieve reasonable progre ss 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 visibili ty 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; ra ther, 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 account ing for economic and technological constraints. The program is not designed to achieve the ultima te goal of eliminating visibility impairment immediately but, rather, over time. As EPA itsel f noted when establishing the Regional Haze Rule, which provides the states w ith a 64-year period to reach na tural visibility conditions at

Class I areas:

[a]dvancements in technology a nd 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 desi gned to require States, through the SIP process, to review the statut ory 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 th is extended period of time into account in providing guidance to the states on establishing thei r RPGs: “you should take into acc ount the fact that the long-term goal of no manmade impairment encompasses seve ral planning periods. It is reasonable for you to defer reductions to later plan ning periods in order to maintain a consistent glidepath toward the long term goal.” Reasonabl e 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 progre ss 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 th e planning period under consideration. 42

U.S.C. § 7491(b)(2) (requiring regi onal haze implementation plans to contain measures “necessary to make reasonable progress toward meeti ng the national goal”) (emphasis added).112 Only if further action is necessary for reasonable progress may EP A 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 he re. Arkansas’ Class I ar eas, 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 cl early that additional emissions reductions are not necessary to achieve reas onable 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 ofits lawful authority” and its decisionmaking process to be “logical and rational”). Noneth eless, EPA has proposed to require emissions limits at Independence Units 1 and 2 based on the installation of SO 2 and NO X controls, ostensibly to achiev e reasonable progress, and has offered two options for comment. Under Option 1, each coal-fired unit at Independ ence would be required to meet a rolling 30-day average SO 2 emission limit of 0.06 lb/MMBtu based on the installation and operation of dry FGD systems, and a rolling 30-day average NO X emission limit of 0.15 lb/MMBtu based on the installation and opera tion of LNB/SOFA. Id . at 18994, 18997. Under Option 2, the Independence coal-fired units would be required to meet only the SO 2 limit. Id . at 18994.

Entergy asserted that emission limits on Indepe ndence during at least th e first planning period are unnecessary to demonstrate reasonable prog ress, 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 projecte d 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 visibili ty degradation on the 20% best days will be achieved and that visibility ha s 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 pr ojected to meet the URP for the first planning period.” 80 FR at 18992. As a result of emission reduc tions achieved through regional and national programs, including MATS, CAIR, and CSAP R, future Clean Air Act programs such as implementation of the 1-hour SO 2 NAAQS, the revised ozone NAAQS and the Clean Power Plan, as well as the reductions for White Bluff a nd Independence that Entergy is proposing in its alternative proposal and the BART controls th at EPA has proposed for the other sources in Arkansas, there is every reason to project contin ued 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 Electric113 [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 Cla ss I Federal areas result ing from manmade air pollution. 188 The goal is not to simply reduce emi ssions 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 r easonable progress is being made while accounting for economic and technological constraints. The proposal for addi tional controls on Independence is not necessary to achieve reasonable progress because the Arka nsas Department of Environmental Quality (ADEQ) 5-Year Progress Report SIP revision demonstrates that both Caney Creek and Upper

Buffalo are and will be belo w 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 visibi lity impairment reduction goal of 3.88 dv and Upper Buffalo

achieved 66% of its 2018 visibi lity impairment reduction goal of 3.75 dv. Based on the 5-year rolling averages and projected data, both Cla ss 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 de gradation on the 20% best days (“B20”) will be achieved and that visibility ha s 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 addi tion to this undisputed eviden ce, EPA’s own analysis further counsels against imposing additi onal controls on the Independen ce 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 Arkans as’ 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 fo r only 3% of the total light ex tinction 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 SO 2 and NO X controls at the Independence Plant are warranted and reasonable.

The commenters asserted that EPA ultimately lack s evidence of a sufficient need to evaluate additional controls for Arkansas point sources and lacks a sufficient basis ( i.e. insignificant contribution to visibility impairme nt) to justify additional controls.

[AECC (0169) p. 2-5] AECC stated that in its reasonable progre ss analysis, EPA has proposed to require SO 2 and NO X 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 th e 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 “g lide path”) for the first planning period. 196 If Arkansas’ Class I areas - the Upper Buffalo Wilderness Ar ea and the Caney Creek Wilderness Area - are expected to meet the URP in th e first planning period, then evalua tions should be limited to units that are subject to BART. AECC stated that EP A 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 s hould 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 re spective 2018 RPGs. 198 For both of the Arkansas Class I areas, the most recent data fr om 2011 and the current five-year rolling average (2007-2011) show that visibility impairment is d ecreasing 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-Gla des Wilderness Area and the Mingo National Wildlife Refuge - have demonstrated vi sibility improvement between 2000 and 2011. 200

AECC stated that the emissions trends for Ar kansas EGUs are trended downward from 2000-

2011 201 and will likely continue to do so with several other federal environmental rules being implemented. The Clean Air Interstate Rule (CAIR) which limited SO 2 and NO X 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 Cro ss-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 cons idered “better than BART” for NO X , 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 Environmen tal 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 at tributable 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 whic h will have co-benefits of reducing particulate matter (PM) and other pollutants which will furthe r 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 NO X will be reduced across

the nation in order to meet the new standard. A reduction in nationwide NO X 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 projec t reasonable progress benefits fo r Independence. CALPUFF is a single-source puff model which will greatly overs tate the impacts of emissions and control

installation benefits when used for a reas onable progress analysis. When EPA evaluates Independence in future planning periods, EPA s hould use an appropriate model for reasonable progress analysis. Based on these facts, the Indepe ndence 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 comp liance with the federa l rules listed above.

[The Associations (0165) p. 5-9] The Associations stated that th ey have serious concerns about EPA’s overall approach to the regional haze progra m 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 th e 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 re port, 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 de creasing more rapidly than the glidepath and the RPG. Arkansas Department of Environmental Qu ality, State Implementation Plan Review for the Five-Year Regional Haze Progress Report (Rev ised May 2015) at 55-58. Nevertheless, EPA discards its key concessions, and ignores Arkans as’ data on reasonable progress, in favor of seeking costly controls on the Independence pl ant without any demonstration that additional emission reductions are necessary to m eet the RPGs for these Class I areas.

The Associations stated that under the Regi onal Haze program, states establish RPGs for reducing visibility impairments by a certain am ount of deciviews at Class I areas during each planning period. 40 C.F.R. § 51.308(d)(1). Th ese 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 Su preme 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 stay ed or vacated, AECC expects that the ru le 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 emissi on reductions anticipated from existing Clean Air Act programs as well as through BART. RPG Gu idance 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 cons tructed after August 7, 1977 are not subject to BART.

The Associations argued that emission reduc tions 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 requi re 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 anti cipate to result from BART” and other Clean Air Act programs “it may be all that is necessary to achieve reas onable progress in the first planning period for some States.”).

The Associations argued that a key flaw of th e 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-eligib le sources and other Clean Air Act programs,

“Arkansas Class I areas and those outside of Ar kansas most significantly impacted by Arkansas sources are projected to meet th e [Uniform Rate of Progress] for the first planning period.” 80 Fed. Reg. at 18,992. Under EPA’s RPG Guidance, th is 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 contro ls 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 explanatio n of “reasonableness,” however, has nothing to do with meeting Class I reasonabl e 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 th at it considers to be reasonable. Here, the entirety of EPA’s “reasonableness” explanation a ppears to be that the Independence plant is a relatively large source of emissions and that cont rols at the Independen ce 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 achi eving reasonable progress goa ls at either of the

Arkansas Class I areas for this planning period. Where Cl ass 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 contro l 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 stat ute 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) (strik ing down postal regulations related to the mailing of insurance offers because the “Pos tal Service ha[d] no congressionally delegated authority to exclude” certain types of mailings). The Clean Air Act simply does not give EPA or117 states the authority to impose emission reduc tions without linking t hose reductions to the necessity of meeting RPGs.

The Associations asserted that allowing EPA to im pose tens of millions of dollars of controls on BART-ineligible sources like the Independence plant, base d only on what it claims is “reasonable,” is not only economi cally 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 ca tegories, (2) that exis ted 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 contribut e 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 ru le, 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 bui lt 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 SO 2 emissions and a significant portion of NO X point source emissions.”). As implemented in the proposed rule, EPA has effectively adopted a presumption that at least some BART-ineligib le 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 a dopts this presumption w ithout first finding it necessary to impose additional emission reduction s to meet Class I reasonable progress goals. This necessity determination – finding additi onal emission reductions to meet reasonable progress goal – anchors the “rea sonableness” inquiry in the RP G Guidance. EPA claims that imposing tens of millions of dollars in new cont rols 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 “r easonableness” inquiry becomes a free-floating vehicle for EPA to issue pollu tion control edicts without any goal to accomplish. Imposing BART controls on the Independen ce plant without the need to m eet 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 th e 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 addr ess 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 ga in 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 th e very definition of arbitrary and capricious decision making.

204 42 U.S.C. § 7491.118 comprehensive visibility protec tion 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 desi gn the program to achieve the ultimate goal of eliminating visibility impairment immediately but, rather, ov er time. As EPA itself noted when establishing the Regional Haze Rule, which provides the stat es with a 64-year period to reach natural visibility conditions at Class I areas:

[a]dvancements in technology and ch anges in economic factors will likely provide opportunities for implementa tion of new cost-effective control measures to assure reasonable progre ss. 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 dete rmine appropriate changes to their strategies based on that review. 206

EEAA asserted that given the intent of the stat ute 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 mainta in and achieve reasonab le progress towards the national visibility goal. Here, wh ere visibility improvement at re levant 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 decad e, 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 becau se 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 Independenc e 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 ar e 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 ach ieve visibility improvement or for failure to meet the state’s URP goals. Rather, EPA primarily disapproved Ar kansas’ 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 reasona ble progress goals for visibility

205 64 Fed. Reg. 35714 (July 1, 1999), codi fied at 40 C.F.R. part 51, subpart P.

206 Id. at 35752.

207 State Implementation Plan Review for the Five-Year Re gional Haze Progress Report, Arkansas Department of Environmental Quality, Revised May 2015.119 for the first planning period and beyond. EPA ha s 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 rev eals that Arkansas is on track to achieve the visibility improvements contemplated by the Re gional 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 goa ls; it “requires only that a state establish reasonable progress, not the most reasonable progress.” 209

[Conway Corporation et. al. ( 0172) p. 11] Conway Corporatio n et. al. stated that EPA acknowledges that visibility impairment at Arka nsas’ 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 implemente d federal and state programs and

increased control efficien cies from EGU sources. 211 These results validate Arkansas’ original determination that existing stat e and federal programs were adequate to make reasonable progress toward natural visibility conditions.

[Domtar Supplemental Comments (0170) p. 2-3] Do mtar 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 obser vations 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 UR P glidepaths. EPA recognizes this fact in the proposed FIP at 80 FR at 18922. More over, 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 tr end 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 a ssessment results are ina ppropriate and would set an unlawful precedent. While Domtar is not di rectly affected by EPA’s reasonable progress evaluation proposal, it argues it is in directly affected through an in evitable increase in electric power prices. As such, Domtar is concerned with EPA’s conclusion in the proposed FIP. Despite the fact that visibility impr ovement in Arkansas’ Class I ar eas is ahead of schedule, EPA proposed emissions controls for SO 2 and possibly NO X on two non-BART affected units (at Entergy’s Independence facility) as part of its reasonable prog ress 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 comment ers stated that ADEQ’s Five Year Progress Report SIP revision show s that visibility at Arkansas’ Class I areas

is better than the URP and that controls fo r 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 th e first planning period, should only include BART

sources. One commenter notes that additional c ontrols for a non-BART source are especially unnecessary given the high cost.

Response: We disagree that we cannot evaluate or re quire 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 commen ters reference the CAA in support of the argument that controls under reasonable pr ogress 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 requir e regional haze SIPs to] contain such emission limits, schedules of compliance and other measures as may be necessary to make r easonable progress toward meeting the national goal... 212

These commenters interpret the term “reasonable pr ogress” to be defined as being on or below the URP glidepath, and that as l ong as a Class I area is on or be low 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 fo r compliance, (3) the en ergy and nonair quality environmental impacts of compliance, and (4) th e remaining useful life of any existing source subject to such requirements. The Regiona l Haze regulations under section 51.308(d)(1)(i)(A) also require considerat ion of these four statutory fact ors in establishing the RPGs:

(i) In establishing a reasonable prog ress 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 environm ental impacts of compliance, and the remaining useful life of any potentially affected sources, and include a demonstration showing how these factor s were taken into consideration in selecting the goal.

We commonly refer to the evalua tion of these four statutory fact ors 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 ma ke reasonable progress and the

establishment of the RPG must be based on th ese factors identified in CAA section 169A(g)(1) and the Regional Haze regulations un der 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 completi ng the requisite analysis of the four statutory

factors. It also should not be in terpreted to mean that a set of controls sufficient to achieve the URP is automatically sufficient for an approvabl e 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 rega rd to the Class I area’s positi on relative to the URP. Since an evaluation of the statutory factors is required regardless of the Cla ss I area’s position relative to the glidepath, this necessarily m eans that the CAA and the Regiona l Haze regulations envisioned that controls could be required under reasonabl e 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 reas onable 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 redu ctions that we anticipate to result from BART, the CAIR, a nd the implementation of other CAA programs, including the ozone and PM 2.5 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 Guid ance indicating that additional controls under reasonable progress can only be ev aluated or required if furthe r action beyond BART is needed to remain on or below the URP glidepath. Bei ng projected to meet the URP for 2018 does not

divest a state or EPA from its authority and obligation to con duct the four factor analysis required under CAA section 169A(g)(1) and se ction 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 es tablish a “safe harbor” for the state in setting its progress goals:

If the State determines that th e amount of pr ogress identified through the [URP] analysis is reas onable based upon the statutory factors, the State shou ld 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 determ ines that additional progress is reasonable based on the statutory factors, the State should adopt that amount of progress as its goal for the fi rst long-term

strategy. 215

Being projected to meet the URP for 2018 does not automatically mean that no additional controls beyond BART are requir ed under the reasonable progress requirements. The URP is an analytical requirement created by regulation to en sure that states consider the possibility of setting an ambitious reasonable progress goal. Its purpose is to complement, not usurp, the reasonable progress analysis. Base d on the analysis of the four statutory factors required under the CAA and Regional Haze regulati ons, a state or EPA in a FIP ma y determine that a greater or lesser amount of visibility improvement than wh at 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 Goal s 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 determ ine if additional controls are needed to make reasonable progress. Based on our analysis of the four statutory fact ors 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 ar e reasonable controls available for Independence that would be cost-effective and w ould result in meaningful visibility benefit at

Arkansas’ Class I areas. Because we have iden tified that additional progress (beyond the amount reflected in the URP) is reasonable based on our analysis of the four st atutory factors and our consideration of the visibility impacts from th e facility and the visibi lity improvement from controls, we are required to adopt that amount of progress as th e RPG for each Class I area in

Arkansas. It is for this reason that we ar e 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 b ecause 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 stat utory 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 st atutory factors when establishing

its RPGs. Based on an evaluation of the four statutory factors, states may determine that RPGs th at provide for a greater rate of visibility improvement than woul d 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 reiter ate 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 rela tive to the URP and that being below the glide path does not automatically mean that no controls are necessary under re asonable progress.

With regard to comments contending that we ar e ignoring data from ADEQ ’s Five Year Progress Report SIP revision, we note that Arkansas submitted the firs t 5-year Progress Report SIP revision in June 2015 and we are not including ou r 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 planni ng periods, and it has separate content and criteria for us to review. We are th erefore not obligated to consider or take action on the 5-year progress repor t at the same time we promul gate 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 Progres s 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, Ca ney 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 existi ng state and federal progr ams were adequate to make reasonable progress toward natural visibil ity 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 determinat ion 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 re quired under the CAA and section 51.308(d)(1). However, the State made its determination withou t conducting the four f actor analysis required under the CAA and the Regional Haze regulations, and we partially approved and partially disapproved the SIP in our March 12, 2012 fina l action on the Arkans as Regional Haze SIP. 220
That action included disapproval of Arkansas’ RPGs. As such, the State’s RPGs are not a

reflection of the controls nece ssary to make reasonable prog ress, and any arguments upholding or suggesting that the state’s RP Gs are appropriate or adequate are not germane to the proposed

action we solicited comments on and are out side 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 au thority 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 c ontrols 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, base d 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 affect ed 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 Re gional 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” c ontrols). Thus, the RPGs repres ent the best estimate of the degree of visibility improvement that will result in 2018 from cha nges in emissions inventories, changes driven by the particular set of control m easures the state has adop ted in its regional haze SIP or EPA in a regional haze FIP to address visib ility, as well as all other enforceable measures expected to reduce emissions over th e period of the SIP from 2002 to 2018. 222 But the RPGs

themselves are not enforceable. EPA cannot enfor ce 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 l ong-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 necessari ly 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 a nd obligation to conduct a reasonabl e 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 m eaningful visibility bene fit 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 th is is due to a large extent to emissions reductions taking place outsid e of Arkansas. As noted in our proposed partial approval and partial disapproval of the Arkans as RH SIP, the CENRAP 2018 projections

indicate that most of the decrea se in visibility impairment at Caney Creek and Upper Buffalo in 2018 is expected to be due to SO 2 emissions reductions from poi nt sources in other states:

Anticipated reductions of SO 4 emissions from point sources in Texas, the eastern United States, Indiana, a nd 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 SO 4 emissions from point sources in 2018, extinction due to point sources will still be the highest cont ributor 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 SO 4 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. Ev en with such large expected

reductions in SO 4 emissions from point sour ces 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 reducti ons from mobile sources. 224

We did not conduct photochemical modeling to determine the curr ent contribution from Arkansas and other states to visibility impa irment at Caney Creek and Upper Buffalo, but

223 76 FR at 64214.

224 76 FR at 64215.126 emissions data presented in ADEQ’s Fi ve Year Progress Report SIP revision 225 suggests that the recent observed improvement in visibility conditi ons at Arkansas’ Class I areas is likely due primarily to emissions reductions outside Arkans as. For example, Table 5.1 from ADEQ’s Five Year Progress Report SIP re vision shows that 2011 SO 2 emissions from Arkansas EGUs (73,629 tons) were higher than 2002 levels (70,759 tons) a nd 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 SO 2 emissions from all Arkansas point sources (EGU and non-EGU combined) were 84,870 tons, which is only slig htly 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 SO 2 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 NO X emissions from Arkansas point sources, as well as from all Arkansas source categories combined, were over tw ice 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 Cr eek, 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 redu ctions 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 visi bility improvement at Arkansas’ Cl ass 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 ne cessary. We note that the emissi ons data presented in ADEQ’s Five Year Progress Report SIP revision 230 show that there has been some reduction in NO X emissions from Arkansas EGUs between 2000 a nd 2011, but the data show that there has not been very much change in SO 2 emissions during this same time period. According to ADEQ’s Five Year Progress Report SIP revision, SO 2 emissions from Arkansas EGUs were 75,057 tpy in 2000 and 73,623 tpy in 2011, with not much variati on in the years in between. Therefore, we disagree that SO 2 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 at tributable to CSAPR” is unclear. In determining that CSAPR provides for greater reasonable pr ogress than BART, EPA assessed th e 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 Un ited 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 SO 2 and NO X reductions in many states; in Arkansas, however, the state is subject only to an ozone season NO X budget requirement. The commenters have presented no ev idence that CSAPR will result in any added benefit over and beyond the site-specific BART NO X controls in our Arkansas FIP at Arkansas’ Class I areas, but if the commente rs’ point is that a program re quiring hundreds of thousands of

tons of reductions in SO 2 and NO X across a broad region will achieve greater visibility improvement than the modest BART NO X controls in the Arkansas FIP, then we would have to agree. To the extent the commenter is argui ng 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 goa ls 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 a nd Upper Buffalo well beyond 2018 as a result of

emission reductions achieved thr ough other regional and national programs and that no controls are therefore necessary for the Independence plan t in this planning period, we discussed in a separate response to comment that the commente rs’ suggestions that EPA should further delay the implementation of measures to improve visi bility relies on the conclusion that there is a specific pre-determined rate of improvement th at constitutes reasonable progress. This is incorrect. As we discussed above, the determina tion of what constitutes reasonable progress is based on an analysis of the four statutory factors.

With regard to comments arguing that we shoul d 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 anth ropogenic visibility impairment in Federal Class I areas, we note that we agree that the regional haze progra m contemplates gradual visibility improvements over several planning periods. Those gradual im provements 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 th is action as being frontloading.

As we discuss elsewhere in this document and in our final rule, our cost analysis indicates that

the SO 2 and NO X controls we are requiring for Independe nce 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 addres s 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 eval uation of additional controls under a reasonable progress analysis that considered the four stat utory factors. As discu ssed in our proposal and throughout this final rule, based on the demonstr ations we developed pur suant 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 SO 2 and NO X 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 considerati on of the four statutory factors, we must requ ire those controls to make reas onable progress toward the national goal of natural visibility conditions . Therefore, we are requiring SO 2 and NO X controls for Independence Units 1 and 2 under the reasonable progress requirements.

We are requiring controls on Independence unde r the reasonable progress requirements, not under the BART requirements. CAA section 169 A 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 comp liance, (2) the time necessary for compliance, (3) the energy and nonair quality e nvironmental 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 factor s as a reasonable progress analysis. Congress also directed EPA to promulgate regulations requiring BART for a specific univer se of older sources, and again provided a set of statut ory factors States must consider : (1) the costs of compliance, (2) the energy and nonair quality environmen tal impacts of complian ce, (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 wh ich 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 th e reasonable progress analysis. Therefore, some commenters may mistakenly beli eve that we are somehow stre tching 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 factor s as well as the visibility improve ment of potential controls. Although visibility is not one of the f our mandatory factors explicitly listed for consideration under CAA section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), st ates and EPA have the option of considering the projected visibility benefits of controls in determining if th e controls are necessary to make reasonable progress.

We disagree that we are treati ng 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-e ffective.’” To the extent the commenters are suggesting that we are ignori ng 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 earli er in this response th at the analysis of the four statutory factors is a requi rement that applies regardless of a Class I area’s position on the glidepath. To the extent the commenters are sugg esting that we are ignorin g whether controls are needed to improve visibility because we did not conduct photochemical modeling in our analysis, we discuss elsewhere in this doc ument 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 visibi lity benefits of potentia l controls, we relied on the following: CENRAP CAMx source apportionm ent 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 Arka nsas sources not already controlled under the BART requirements, and the results of our CALPUFF modeling of the maximum or 98 th
percentile impacts from Independence and the vi sibility benefits of potential controls. 235
Therefore, we disagree with commenters contendi ng 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 th e CAA and section 51.308(d)(1)(i)(A) that must be considered in a reasonable progress analysis. Th erefore, we disagree with comm enters contending that it was inappropriate for us to consid er cost-effectiveness in our d ecision to require controls at Independence. Based on our consideration of the f our reasonable progress factors, as well as the baseline visibility impacts from Independen ce and the visibility improvement of potential controls, we determined that reasonable controls for SO 2 and NO X are available for Independence Units 1 and 2 that are cost eff ective and would result in a large amount of visibility improvement in Arkansas ’ Class I areas in terms of the 98 th percentile impacts from the source, and we are therefore requiring these co ntrols. 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 in appropriate 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 c ontend 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 su lfate from Arkansas poi nt sources will be responsible for only 3.58% of th e total light extinction at Ca ney Creek and 3.20% at Upper

Buffalo. As we discuss elsewhere in this docum ent, we disagree that these are small or insignificant visibility impacts. The commenters also contend that the Independence Plant’s

share of the total contribution fr om Arkansas point sources is ev en smaller than this and that controls on Independence are therefore not warran ted. We disagree that these visibility impacts are insignificant. As noted above, Entergy subm itted CAMx model results as part of their comments. The results of this modeling provid e additional support to ou r determination that Independence significantly impacts visibility at Arkansas’ Class I areas. The modeled contribution to visibility impairment due to ba seline emissions from th e Independence facility alone were approximately 1.3% of the total visibi lity impairment at each Arkansas Class I area. Considering that the CAMx photochemical mo deling takes into account the emissions of thousands of sources, both in Arkansas and outsi de of the state, we consider this to be a significant contribution to visibility impairmen t 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 sing le facility. Entergy’s CAMx modeling also shows that at Upper Buffalo, th e Independence facility contributes more to visibility impairment than all the subject-to-BART sources addre ssed 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 conditi ons) 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 Independe nce significantly impacts visibi lity, both in terms of maximum

235 We address comments contending that we inappropri ately used CALPUFF modeling to determine impacts and project visibility benefits from installing controls on Independence elsewhere in this document.130 visibility impairment and visibility impairm ent on the 20% worst days, and that emissions controls are expected to provide for meaningful visibility bene fits towards the goal of natural visibility conditions. We conc lude that both approaches, CALPUFF and CAMx, support the determination that the required contro ls on Independence are reasonable.

While the majority of the visibility impacts due to Independence on the 20% worst days are due

to SO 2 , we note that NO X emissions from the facility also have impacts on the 20% worst days. The CAMx source apportionment modeling submitted by Entergy showed that NO X emissions from Independence are responsible for 30-40% of th e 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 Visu al Environments (IMPROVE) monitoring data). We expect that installation of NO X controls on Independence will pr ovide visibility improvement on this portion of the 20% worst days and will al so provide meaningful visibility improvement

on the 98 th percentile day, as shown by the CALPU FF dispersion modeling. After carefully considering all comments submitted to us duri ng the comment period, we are finalizing both SO 2 and NO X controls for Independence Units 1 and 2 to make reasonable progress at Arkansas’ Class I areas (i.e., proposed Option 1), because both SO 2 and NO X are key pollutants contributing to visibility impairment, and because we have determined that these controls are cost effective and will provide for significant vi sibility benefits towards the goal of natural visibility conditions at Ar kansas’ Class I areas.

We disagree with comments contending that we inappropriately used CALPUFF modeling to determine impacts and project visibility benefi ts 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 vi sibility impairment due to anthropogenic emissions encompasses all days. Thus, states and EPA have the discretion to consider the visibility impacts of sources a nd the visibility benef it 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 gi ven facility has its largest impacts are not the same as the 20% of days with th e worst visibility overall, the faci lity’s impacts will still need to

be addressed for Arkansas’ Class I areas to ach ieve the national goal of natural visibility conditions. The Eighth Circuit previously a ddressed state and EPA use of CALPUFF for reasonable progress purposes. 236 We address comments conten ding that CALPUFF modeling overestimates the impacts of emissions and the visi bility benefits of cont rols elsewhere in this

document.

One commenter alleges that EPA “proposes to su pplant the State of Arkansas’ primary authority by imposing a proposed FIP” that requires controls under reasonabl e progress. In arguing that our FIP should not require controls under reasona ble progress, the commenter further states that the CAA provides states with disc retion in establishing RPGs and th at it requires only that a state establish reasonable progress, not the most reas onable progress. First, we point out that our proposed partial approval and par tial 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 act ion was published on March 12, 2012. 238 In our final action, we

determined that the Arkansas RH SIP does not m eet certain elements of the CAA and the Federal regional haze requirements and partially approve d and partially disapproved the Arkansas RH SIP. The portions that we disapproved include d Arkansas RPGs for Caney Creek and Upper

Buffalo because the state did not conduct a reas onable 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 r eceive 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, whenev er we disapprove a mandatory SIP submission in whole or in part, we are required to promul gate a FIP within two years unless we approve a SIP revision correcting the defici encies before promulgating a FI P. 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 Ar kansas’ primary authority by imposing a proposed FIP” is not supported by the facts. To the extent the comm enter is suggesting that the RPGs provided by Arkansas in its RH SIP are acceptable or appr opriate, such comment is not germane to the proposed action we solicited comments on a nd is outside the scope of this action.

Second, we agree that the CAA provides states with discre tion 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 discre tion as the state. Third, we note that the commenter’s statement that the CAA “requires on ly that a state establ ish reasonable progress, not the most reasonable progress” is taken from a court decision in North Dakota v. EPA , 730 F.3d 750, 768 (8 th Cir. 2013). We interpret the Court’s st atement 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 und er 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 c ontrols. We proposed, however, that neither additional controls nor a higher level of control on the source for which we proposed controls was appropriate, after appl ying the four reasonable progress fact ors. In other words, we did not propose the highest level of contro l (referred to by the Court as “most reasonable”). Based on the analysis that is required under the CAA and sec tion 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 pe riod since “EPA’s di sapproval 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.” Th ese commenters contend that EPA primarily disapproved Arkansas’ SIP because the underlying emissions reduction requirements were based on presumptive limits instead of on properly co nducted unit-specific BART evaluations. This statement is incorrect. Our March 12, 2012 part ial approval and partial disapproval of the

Arkansas RH SIP 239 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 disa pproved the state’s RPGs both because the RPGs did not reflect appropriate BART determinati ons 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 am ount of visibility improvement necessary to make reasonable progress. We discuss elsewher e 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 l ook 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 f our statutory factors a nd our consideration of the visibility impacts and visibility benefits of controls, we conclude that the SO 2 and NO X emission limitations we are establishing for Inde pendence Units 1 and 2 are necessary to make reasonable progress at Arkansas’ Class I areas for this planning period.

We disagree with commenters cont ending that we did not appropriate ly analyze which sources, if any, should be controlled under th e reasonable progress requirement s 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 addres s Arkansas’ impacts on Miss ouri’s Class I areas.

We address elsewhere in this document comments stating that our FIP should rely on CSAPR to satisfy the NO X BART requirement for Arkansas EGUs.

Comment: EPA has not demonstrated that it s proposed BART and Reasonable Progress controls are necessary for Arkansas to maintain reasonable progress and achieve the visibility goals of the CAA, especially in vi ew of the uncertainty that those controls will

result in actual visibi lity improvements.

[Nucor Steel-Arkansas and Nucor-Yamato Steel Company (0163) p. 16-19] Nucor stated that 42 USC §7491 requires that Regional Haze implem entation plans contain emission limits, compliance schedules and other measures, incl uding BART, “as may be necessary to make reasonable progress” toward meeting the CAA’s vi sibility 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 requi red by EPA’s proposed FIP. (Ex. 3, Arkansas Five Year RHR Progress Report, 2015; Ex. 5, ICF In ternational, “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 show n by the spreadsheet attached hereto as Ex. 6,133 of the 68 fossil-fuel electric generating units cl osest to Arkansas and the four Class I areas addressed in the proposed FIP, 17 units are sche duled 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, Ar kansas Five Year RH R Progress Report, 2015, p. 23-34.)

Nucor stated that EPA’s maximum modeled visib ility 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 tim es, 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 c ontrols 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 (9 th Cir., June 9, 2015).

As the Supreme Court recently held, federal admi nistrative agencies must engage in “reasoned decision making,” the agency’s “dec reed result must be within th e 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 “ab solutely 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 a nd future improvements in air quality in the areas surrounding these four Class I area s, and in view of the uncerta inty that EPA's proposed BART and Reasonable Progress controls will result in actual visibil ity 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 visibili ty 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 factor s into consideration in its BART and reasonable progress

determinations and to demonstrat e that these controls are indisp ensable. EPA has not explained

how it considered these and other relevant fact ors in reaching its de cision that its BART

determinations for Flint Creek and White Blu ff and its Reasonable Progress determination for Independence is “absolutely nece ssary” 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 re quires Regional Haze implementation plans to contain emission limits, compliance schedules an d 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 Pr ogress 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. Fu rther reductions in emissions

due to the effects of other re gulatory programs and developments will supplement Arkansas’ trend toward visibility improvement. As expl ained in section five of AEEC and AGC’s comments, the EPA’s maxi mum modeled visibility improvements for the affected units at White Bluff, Flint Creek and Independenc e are less than one deciview fo r 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 reas onably 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 BA RT and Reasonable Progress determinations are “indispensable;” EPA has not, and cannot, demonstr ate that the proposed controls constitute the only way Arkansas can achieve th e 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 comm ents asserting that recent monitoring data

demonstrate that Arkansas’ Class I areas are on track to meet th e 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 th at a state has satisfied its requirements under BART and reasonable progress.

Clean Air Act section 169A(b)(2) re quired us to promulgate regulat ions 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 complia nce, (2) the time necessary for compliance, (3) the energy and nonair quality environmental impacts of complian ce, (4) and the remaini ng 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 anticipa ted 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 th e 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 ot her “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 H aze 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 estab lishing the RPGs. The Arkansas RH SIP did not meet this statutory and regulatory requirement. In our March 12, 2 012, final action on the Arkansas RH SIP, we disapproved several of the State’s BART determ inations 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. Theref ore, 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 a nd conducting a four fact or reasonable progress analysis to determine if additional controls (beyond BART and other “on the books” controls) are necessary to make reasonable prog ress in Arkansas’ Class I areas.

The fact that Arkansas’ Class I area are achievi ng 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 a nd in our final rule, we conducted BART analyses for White Bluff and Flint Creek, as well as other Arkansas BART sources. In our BART an alyses, we considered the five statutory factors required under CAA s ection 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 othe r “on the books” contro ls) 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” reductio ns, are what we have determined are necessary to make reasonable pr ogress at Arkansas’ Clas s I areas, based on our analyses required under the CAA and the Regiona l Haze regulations. The discussion of how we considered the statutory factor s in establishing BART and reas onable progress controls is found in our proposal and in our fina l rule and further discussed elsewhere in this document.

The Regional Haze Rule provides that these emi ssion 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, alth ough visibility is not one of the four mandatory factors explicitly listed for consideration under CAA section 16 9A(g)(1) or 40 CFR 51.308(d) (1)(i)(A), states and EPA have the option of considering the projected visibility bene fits of controls in determining if the controls are necessary to make reasonable progress.

248 64 FR 35733.136 other control measures (including BART, r easonable progress, and other “on the books” controls). Thus, the RPGs represent the best estim ate of the degree of visi bility improvement that will result in 2018 from changes in emissions invent ories, 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 a ll 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 RP G does not necessarily demonstrate that a state has satisfied its requirements unde r BART and reasonable progress.

Further, as we discuss elsewher e in this document, we finalized our disapproval of Arkansas’ RPGs for Caney Creek and Upper Buffalo in a prev ious 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 act ion we solicited comments on and are outside the scope of this action.

One commenter states that EPA has not, and can not, 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 wa y Arkansas can fully meet the regional haze requirements in the CAA and our regulations. Th e CAA and the RH rule gives states and EPA (in the case of a FIP) wide latit ude in considering and weighing the statutory factors that must be considered under the requisit e analyses under section 51.308(e) in establishing BART and under section 51.308(d)(1) in establis hing controls under reasonable progress. Even though we are required to prepare our own analysis to do a FIP, this does not mean our an alysis and conclusions are precisely what Arkansas would itself c onclude in a SIP revision to meet the CAA requirements. In other words, the state could pot entially conduct analyses that fully satisfy the CAA and Regional Haze rule but arrive at a diffe rent, but nonetheless ap provable, 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 de velop 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 discu ssed in our proposal, in our fina l action, and elsewhere in this document, the emission limitations we are re quiring under the BART and the reasonable progress requirements in this FIP, along with other “on the book” reductio ns, are what we have determined are necessary to make reasonable pr ogress at Arkansas’ Clas s I areas, based on our analyses required under the CAA and the Regional Haze regulations.

We address elsewhere in this document commen ts suggesting or contending that we cannot establish controls under BART or reasonable pr ogress that result in visibility improvement less

than 1 dv. We also address elsewhere in this do cument comments contending that there is an overestimation of visibility impacts in the CALPU FF model and that there is uncertainty in the visibility improvement of the contro ls we are requiring in our FIP.

249 64 FR 35733.

250 80 FR at 18945.137 Comment: The EPA should not look beyond B ART 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 secti on 169A of the CAA require the st ates, 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 envi ronmental 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 progre ss towards achieving the national visibility goal, but instead calls for states to establish goals that provide for “reason able 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 m eet all established r easonable progress goals.” 252
ADEQ has assessed the current SIP elements a nd strategies and determined that, based upon relevant data ( i.e. , projected emissions and modeling resu lts), they are sufficient to enable

Arkansas and other states with Class I areas a ffected by emissions from Arkansas to meet all

established reasona ble progress goals. 253

EPA’s disapproval of the 2008 SIP was not due to lack of reasonabl e progress to achieve visibility improvement or for missing the Unifor m Rate of Progress (URP). It was disapproved primarily because the underlying emissions we re based on presumptive limits and no BART

evaluations had been conducted. The RPG and UR P in the 2008 SIP, and as supported in the 5- year update, should be accepted as presented by th e State. The actions required by EPA in the FIP to conduct BART analyses on ly serve to achieve greater emission reductions than in that analysis. Therefore, EPA should not look beyon d BART eligible units to achieve greater visibility improvements. EPA should not simply use the RH program as leverage to impose

emissions reductions that have lit tle benefit to the purpose of the rule to improve visibility. EPA should allow, and defer to, ADEQ to reeval uate the RPG and URP before imposing any additional specific emissions reductions.

EPA determined that it would be appropriate to evaluate th e Entergy Independence facility relative to reasonable progress obligations. We, however, disagree with EPA's conclusion that imposing emission controls on the Independence f acility is needed to meet the statutory requirements.

251 80 Fed. Reg. at 18989.

252 STATE OF ARKANSAS, Stat e Implementation Plan Review for the Five-Year Regional Haze Progress Report, Prepared by the Arkansas Department of Environmental Qu ality Air Division Planning Branch, April2014, Revised November 2014, p. 55 (hereinaft er "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 ar eas 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 therefor e not necessary.

With regard to the comment that our partial disa pproval of the Arkansas RH SIP was not due to lack of reasonable progress, we discuss elsewh ere in this document that our March 12, 2012 final

action 254 partially approving and partially disapp roving 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 st ate’s RPGs because the RPGs relied on BART determinations that did not meet the require ments of the CAA and the RH regulations and

because Arkansas failed to conduct a four-fact or analysis, as required by the CAA and the Regional Haze Rule. Without a four-factor analys is, 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. Therefor e, any arguments upholding the state’s RPGs or stating that we should accept those RPGs are out side the scope of this action.

The commenter contends that the requirement s in our FIP only serve to achieve greater

emissions reductions than in the Arkansas RH SIP. This is incorrect. Unde r section 110(c) of the Act, whenever we disapprove a mandatory SIP subm ission in whole or in pa rt, we are required to promulgate a FIP within 2 years unless we appr ove 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 establ ish emission limits in accordance with the CAA and the RH rule. We are requiring controls und er BART based on our analyses of the five statutory factors required under CAA section 169A(g)(2) and th e Regional Haze regulations under 40 CFR 51.308(e)(1). As discussed in our fina l rule, based on our an alysis of the four reasonable progress factors under CAA secti on 169A(g)(1) and 40 CFR 51.308(d)(1), and our

consideration of the visi bility improvement of potential co ntrols, we have determined that controls at the Independence plant are cost-effec tive, reasonable, and woul d result in meaningful visibility benefits at Arkansas’ Class I areas, and are therefore necessa ry 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 C AA for EPA to further delay our action for the reasons provided by the commen ter. We are operating under a court-ordered deadline to take final action to promulgate a FI P or approve a SI P 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 NO X BART emission limits for White Bluff, Flint Creek, and Indepe ndence, 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 pr oposed 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 reducti on 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 an alyzes. In the proposed rule, EP A 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, EP A properly proposes to find that the SO 2 and NO X BART requirements that EPA proposes for those units ar e “adequate for this fi rst planning period to

eliminate these sources from further consider ation of controls under the reasonable progress requirements for this first regional haze pl anning period.” 80 Fed. Re g. 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 SO 2 and NO X emissions from these two facilities.” Id . Relying on BART to satisfy reasonable progress is consiste nt 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 emi ssion reduction requirements are n eeded for these facilities in response to the reasonab le progress provisions.

Further, even if EPA were, in effect, to revise its proposed BART determ inations for White Bluff

Units 1 and 2 and Flint Creek Unit 1 by not promulgating the proposed NO X BART limits for those units, as recommended in Section II of UARG’s comments, both facilities would still satisfy all reasonable progress requirements fo r 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 duri ng the first planning period, and those emission reductions would have been sufficient to satisfy reasonable progress requirem ents for that period. EPA proposes SO 2 and NO X BART emission limits for White Bluff and Flint Creek that – in conjunction with other proposed control requirements – are signi ficantly more st ringent than necessary to meet the URPs, and, as discussed in Section II of UARG’s comments, the proposed

FIP’s NO X 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 NO X 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 pr ogress requirements.

Response: We address elsewhere in this document co mments contending that an evaluation under reasonable progress and that controls under reasonable progress are not necessary because140 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 20 18 does not necessarily de monstrate that a state has satisfied its requirements under BART and r easonable progress for the first planning period. Further, the fact that Arkansas’ Class I areas ar e projected to meet the State’s RPG and are below the 2018 URP glidepath, does not divest us from our authority and ob ligation to conduct NO X BART analyses for White Bluff and Flint Creek and determine appropriate controls under the BART requirements. Nor does it divest us fr om our authority and ob ligation to conduct a reasonable progress analysis to de termine if there are controls in addition to BART that are necessary to make reasonable pr ogress 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 NO X emission limits consistent with LNB/SOFA controls are BART for

White Bluff Units 1 and 2 and that NO X emission limits consistent with LNB/OFA controls are

BART for Flint Creek Unit 1. We also discuss in our final rule and else where in this document that based on our analysis of the four statutor y reasonable progress factors and our consideration of the visibility improvement of potentia l controls, we have determined that SO 2 and NO X controls for Independence would be cost-effectiv e and would result in meaningful visibility

benefits at Arkansas’ Class I ar eas, and therefore find that these are reasonable controls and are necessary to make reasonable prog ress. As such, we are requiring SO 2 and NO X controls for Independence Units 1 and 2 under the reasonable progress requirements.

We discuss elsewhere in this documen t that in our March 12, 2012 final action 257 on the Arkansas RH SIP, we disapproved the Stat e’s RPGs because the RPGs relied on BART determinations that did not meet the require ments of the CAA and the RH regulations and

because Arkansas failed to conduct the fou r-factor analysis required by the CAA and the Regional Haze Rule. Without a four-factor analys is, 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 di sapproving 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 reasona ble progress requirements for the first planning period, such argument is not germane to the pr oposed action we solicited comments on and is outside the scope of this action.

We appreciate the commenter’s support of our de cision not to require a dditional controls beyond BART for White Bluff and Caney Creek to sati sfy the reasonable pr ogress requirements.

We address elsewhere in this document sp ecific comments c ontending that our NO X BART limits for White Bluff, Flint Creek, and Inde pendence 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, SO 2 and

NO X emission limits to satisfy reasonable prog ress requirements for the Independence Power

Plant. Id. In the alternative, EPA pr oposes, as Option 2, only the SO 2 emission limits due to the vanishingly small extent of the putative “visib ility improvements” – amounting to “less than 0.003 dv” – that the proposed NO X emission limits for Independence would produce. Id . If EPA proceeds with these unjustified reasonable progress limits at all, it plainl y must reject Option 1 and instead adopt Option 2, as imposition of the proposed NO X emission limits would not be remotely defensible.

In any event, however, neither Option 1 nor Option 2 recognizes that, for SO 2 as well as for

NO X , these proposed reasonable progress emission limits are not compelled by the CAA or EPA’s rules and are unwarranted and improper unde r 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 pr ojected visibility improvements these limits would produce are very small and cannot justify th e 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 SO 2 and NO X controls for Independence are inappropriate and not compelled by the CAA or Regional Haze rule. We disagree that our proposed SO 2 and NO X controls on Independence are expected to produce “very small” visibility

benefits and that the costs are therefore not justified. We addr ess specific comments concerning

these issues elsewhere in this document. As di scussed in greater detail in our final rule and elsewhere in this document, we are finalizing both SO 2 and NO X 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-loadin g 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 Cl ean 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 regiona l 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 plan ning 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 re quirements for setting reasonable progress goals in terms of achieving a “uniform ra te of progress” toward the 2064 goal).

Delaying consideration of controls on Independe nce until the next plan ning period is a more reasonable approach that would allow for the consideration of updated information, such as control equipment characteristics and costs, emi ssions reductions attributab le to other regulatory and market drivers, and contemporaneous m onitoring and meteorological conditions, which would allow the coordination of these important investment and regulator y decisions with the implementation of other pending regulations. Finally, this appr oach would give states and regulated entities the op portunity to conduct integrated comp liance planning in ways that are consistent with provision of reliable and afford able electric power. EPA should withdraw its proposed controls for Independence 1 and 2.

As EPA and the states begin to implement th e next rounds of the regional haze program to

continue to make reasonable progress, EPA should allow stat es—through state environmental and electric utility regulators and in conjunction with power co mpanies—to consider the timing and scope of additional control act ivities, consistent with eff ective 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 investme nt decisions to be made over suitable planning

horizons. EPA also must take in to consideration progress alrea dy made through the installation of controls to satisfy BART requirements and ot her 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. Th ose gradual improvements are guided by the principle that controls found to be reasonable in a given planning peri od 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 fr ontloading. As we discuss in our final rule and throughout this document, our cost analysis indicates that the SO 2 and NO X controls we are requiring for Independence Units 1 and 2 are cost effective and well w ithin the range of co st of controls found to be reasonable by EPA and the states in othe r 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 po rtions of the State’s SIP submission. Pursuant to CAA section 169A(g)(1) and our Regional Ha ze regulations at 40 CFR section 51.308(d)(1),

we conducted an evaluation of additional contro ls under a reasonable progress analysis that considered the four statutory fact ors. As discussed in our propos al and throughout this final rule, based on the demonstrations we developed pur suant 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 SO 2 and NO X controls available for Independe nce that would result in consid erable visibility benefit at

Arkansas’ Class I areas. Under the CAA and the Re gional Haze regulations, if we determine that

additional controls are reasonable based on the consideration of th e four statutory factors, we must require those controls. Therefore, we are requiring SO 2 and NO X controls for Independence Units 1 and 2 under reasonable prog ress in this planning period.

The commenter has not presented any information that justifies the dismissal of controls for Independence that we have determined, pursuan t 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 ne xt 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 cons ider the timing and scope of additional control activities, consistent with eff ective 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 photochemic al 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 reas onable progress analysis and, as a result, has significantly over-estimated Independence’s cont ribution 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 Arka nsas’ 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 Indepe ndence 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 visibil ity 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 in dex 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 simila r 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 group ed with other like sources in to area source categories.” Id

. 264 The CAMx modeling was conducted by Trinity Consultants, Inc. Trinity’s Regional Haze Modeling Assessment144 the haze index has been consistently below th e URP in both Caney Creek and Upper Buffalo. Trinity Consultants, Inc. (“Trinity”) also perf ormed statistical analyses on the data from both Caney Creek and Upper Buffalo to statistical ly project the haze i ndex trend through 2018. 265
Using a Ranked Statistical Analysis, the haze inde x 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 a nd 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 Project ed 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 sta tistical 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 futu re 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 g lide 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), SO 2 and NO X 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 sour ces, which cause over 50% of the visibility impairment in Arkansas Class I areas, or from area and m obile 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 SO 2 emission budgets in the second phase, that sources

will be forced to make additional SO 2 and NO X reductions to comply with the 1-hour SO 2 NAAQS and the revised ozone NAAQS, and that the Phase 2 CAFE fuel economy standards drive further reductions from mobile sources, th e 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 elsewh ere in this document that the improvement in visibility

conditions in Arkansas’ Class I ar eas (including the fact that Ar kansas’ Class I areas are below the URP glidepath), as observed from IMPROVE monitor data, appear s to be in larg e part due to emissions reductions outside Arkansas. While we ag ree that point sources outside Arkansas have a significant visibility impact at Arkansas’ Clas s I areas, we discuss elsewhere in this document that most of the visibility improvement currentl y 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 ha ve 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 addr essing the reasonable progress and long term strategy requirements.

While we agree that Arkansas mobile and area s ources have visibility im pacts in Arkansas’ Class I areas, we disagree that Arkansas point s ources 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 Clas s 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 out side of the state) that contribu te 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 SO 2 and NO X point source emissions in the state, and are respon sible for approximately 84% of the SO 2 point source

emissions and 55% of the NO X point source emissions in the state. Independence alone is responsible for approximately 36% of the SO 2 point source emissions and 21% of the NO X point source emissions in the state. Therefore, we e xpect that addressing thes e 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 contributi on to visibility impairment due to emissions from the Independence facility alone are proj ected to be approximate ly 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 mo deling takes into account the emissions of thousands of sources, both in Arkansas and outsi de of the state, we consider this to be a significant contribution to visibility impairmen t 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 sing le facility. The CAMx modeling also showed that at Upper Buffalo, the Inde pendence facility’s cont ribution to visibility impairment is greater than the contribution from all of the subj ect-to-BART sources addressed in

this final action combined. In terms of decivi ews, 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 dete rmination that Independence significantly impacts visibility, both in terms of maximum visi bility 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 SO 2 , we note that NO X emissions from the facility also have impacts on the 20% worst days. The CAMx source apportionment modeling submitted by Entergy showed that NO X emissions from Independence are responsible for 30-40% of th e 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 NO X controls on Independence will provide visibility improvement on this portio n of the 20% worst days and will also provide meaningful visibility improvement on the 98 th percentile day, as shown by the CALPUFF dispersion modeling. After careful ly considering all comments submitted to us during the comment period, we are finalizing both SO 2 and NO X controls for Independence Units 1 and 2

because both SO 2 and NO X 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 st atistical analysis in gr eater detail elsewhere

in this document. We addre ss elsewhere in this document comments contending that we improperly relied on CALPUFF modeling in our r easonable 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 reasonabl e 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 re gulations require BART only as necessary to make reasonable148 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 a nd reasonable progress are defined to include consideration of cost, energy and non-air environmental impacts, a nd the remaining useful life of the source. Compare 42 U.S.C. § 7491(g)(1) with id. § 7491(g)(2). In practice, how ever, both analyses often involve the same factors, since states and EPA frequently consid er visibility improvement and existing controls when conducting reasonable prog ress analyses (which are required for BART), and in practice EPA considers the time n ecessary 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 BA RT analysis for Arkansas sources that

considers all of the elements EPA would be re quired 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 c ontrols as reasonable progress measures, not as BART, and thus commenters’ argument doe s not apply to the I ndependence controls.

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

3.c. Consistency

Comment: The cost-effectiveness of the SO 2 controls EPA proposed for the Independence

Plant far exceeds the cost-effectiveness standa rds 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 continue d into the required four -factor analysis. After failing to make the threshold determination of wh ether any emission reduc tions are necessary for the state to make reasonable prog ress at its Class I areas and th en making the unsubstantiated and unsupportable determination to target only the In dependence Plant, EPA applied dollar per ton cost-effectiveness estimates and visibility improve ment rates for the proposed controls that are out of line with the standards applied in othe r regional haze SIPs and FIPs. Specifically, EPA’s proposal attempts to justify a cost-effectivene ss of dry FGD at Independence Plant totaling $2,477/SO 2 ton removed for Unit 1 and $2,686/SO 2 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 analys is. For example, where states or EPA rely on a trading program, such as CSAPR, to satisfy the BART requirements, the BART anal ysis 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 review ed and approved by EPA for the Kentucky 271 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 ne gligible improvement in visibility that was specifically avoided in previous EPA actions. 274 Proposing such controls with such a low amount of visibility benefit also ignor es 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 th e required four-factor analysis. After maki ng the unsubstantiated and unsupportable determination to target only Independence, EPA applied different dollar per

ton cost-effectiveness thresholds fo r proposed controls at the plant, which are out of line with the standards applied in othe r regional haze SIPs and FIPs. Speci fically, 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 else where 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 Unit s 1 and 2. Based on this revision to our cost analysis, we find that dry FGD is estimated to cost $2,853/SO 2 ton removed at Unit 1 and $2,634/SO 2 ton removed. Although these cost estimates ar e slightly higher than we estimated in our proposal, we continue to find th ese controls to be cost effec tive and well within the range of cost of controls found to be reasonable by EP A and the States in other regional haze actions.

We disagree with the statement that our proposal to require SO 2 controls for Independence is inconsistent with our approvals of the Ke ntucky and North Carolina Regional Haze SIPs. Additionally, the factual c ontexts 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 Ke ntucky Regional Haze SIP, we approved the state’s use of a $2,000/SO 2 ton threshold. This is incorrect. In the preamble of our proposed approval of the Kentucky Regional Haze SI P, we discussed that the state identified 10

units for evaluation under reasonable progress, and that 9 of thes e 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 SO 2 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 SO 2 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 SO 2 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 complia nce for the reasonable progress assessment in this first regional haze SIP for the non-EGU Cent ury Aluminum, Kentucky concluded that it was not equitable to require non-EGUs to bear a greater economic burden th an 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 SO 2 reduced as a threshold for cost-effectiveness for that particular non-EGU source. Kentucky found that the cost effectiveness of the SO 2 control as suggested by the VISTAS control cost spreadsheet for potline s 1–4 at Century Aluminum is $14,207/ton of SO 2 removed. The State thus conclude d that, based on the high cost on a $/ton basis, there are no

cost-effective SO 2 reasonable progress controls available for the Century Aluminum units for the first implementation period. We proposed to appr ove Kentucky’s determination, but we also stated the following concerning our position on Kentucky’s use of a $2,000/SO 2 ton threshold:

Although the use of a specific thre shold for assessing costs means that a state may not fully consid er available emissions reduction

measures above its threshold th at would result in meaningful visibility improvement, EPA belie ves 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 meas ures that would have had a meaningful impact on visibi lity in its Class I area. 276

It is clear in our proposed a pproval that we were not appr oving or otherw ise advocating Kentucky’s use of a $2,000/SO 2 ton threshold in the reasonable progress analysis. On the contrary, we expressed concern th at the use of a specific threshold for assessing cost may result in a state not fully considering potential reasonable control measur es 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 affo rdable controls available above the $2,000/SO 2 ton threshold used by the state that provide meaningful visibility improvement at the Class I areas, we might have arrived at a di fferent decision concerni ng the approvability of Kentucky’s reasonable pr ogress analysis for SO 2

.

North Carolina took a similar approach to that of Kentucky in its SO 2 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 estimate d cost of compliance with its Clean Smokestacks Act, a law establishing a state-wide cap on SO 2 and NO X 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 th at North Carolina decided that for the limited purpose of evaluating the co st of compliance for non-EGUs in the SO 2 reasonable progress assessment for the first implementati on period, it was not equi table to require nonEGUs to bear a greater economic burden than E GUs for a given control strategy and therefore

also used a cost-effectiveness threshold for its non-EGUs. North Carolin a’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 SO 2 removed,” a statement which the commenters appear to have misinterpreted to mean that North Caroli na 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 c ontrols exceeded its threshold, North Carolina

concluded that there were no cost -effective reasonable progress SO 2 controls available for the first implementation period. We proposed to appr ove North Carolina’s determination, but we also stated the following concerning our posit ion on North Carolina’s use of a specific costeffectiveness threshold:

Although the use of a specific thre shold for assessing costs means that a state may not fully consid er available emissions reduction

measures above its threshold th at would result in meaningful visibility improvement, EPA belie ves 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 resu lt of using a specific cost effectiveness threshold, rejected potential reason able progress

measures that would have had a me aningful 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 otherw ise advocating North Carolina’s use of that specific cost-effectivene ss threshold in the reasonable progress analysis. Therefore, we disagree th at our requirement of SO 2 controls for Independence Units 1 and 2 under reasonable progress is inc onsistent with our actions on the Kentucky and North Carolina Regional Haze SIPs.

The commenter contends that the level of visi bility improvement projected to result from our proposed SO 2 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 acr oss the 20% worst days at Caney Creek and Upper Buffalo that we calculated would result fro m all the controls in our Arkansas FIP proposal in the context of light extinction due to all s ources in that time period and (2) the CALPUFF modeled visibility improvement due to contro ls on Independence Units 1 and 2 based on the maximum (98 th percentile) facility impacts using CA LPUFF dispersion modeling and natural visibility conditions as bac kground. 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 SO 2 controls

considered for the Ash Grove facil ity 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 CA LPUFF dispersion modeli ng (at the Class I area that showed the greatest improvement) for the SO 2 controls evaluated. 280 The commenter also refers to Oregon’s rejection in the Oregon RH SIP of new low-NO X burners with modified overfire air (NLNB/MOFA) plus SNCR for the PG E 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 comm enter refers to represents the change in the maximum 98th percentile impact over the m odeled 3-year meteorol ogical period using CALPUFF dispersion modeling at the Mt. Hood Wilderness Area. 282

In contrast, the visibility improvement projected to result from our proposed SO 2 controls for Independence, similarly based on the change in the maximum 98th percentile impact over the modeled 3-year meteorological period using CALPUFF dispersion mode ling (at the Arkansas Class I area that showed the grea test 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 visibili ty improvement expected from our proposed SO 2 controls on a per unit basis is significantly higher than the visi bility improvement that was projected to result from the SO 2 and NO X controls that were dismissed in the proposed actions for Montana and Oregon referenced by the co mmenter. The 0.19 dv and 0.21 dv improvement at Upper Buffalo and Caney Creek the commenter refe rs to is not the CALPUFF modeled visibility improvement of the maximum 98th percentile impact s from the facility. Instead, it represents the estimated improvement in the projected 2018 visibi lity 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 c ontrols in our FIP proposal. As we discuss in depth elsewhere in th is document, the RPGs are values that will be compared in a progress report to actual visibi lity conditions, and accordingly should represent the expected actual overall visibi lity conditions. CALPUFF modeled estimates of source impacts

and benefits of controls as di scussed above, have a di fferent purpose, which is to help guide

decisions on the control of individual sources.

The commenter also claims that our proposed co ntrols for Independence Units 1 and 2 “ignores EPA’s previous statement that improvements of le ss than 0.5 dv are ‘relatively small’ and are not reasonable justification for additional controls—e ven 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 pr ogress for Oregon point sources. However, the commenter is mischaracterizing ou r 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, ha ve emissions stacks located adjacent to each other, and th e two units have comparable SO 2 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 conc lusion that additional controls of non-BART point sources for reas onable progress purposes are not reasonable in the first planning period, because even though there are cost effective controls identified, visibil ity improvement is anticipated to be relatively small. 285

It is clear that the “0.5 dv” we mention in our proposed action on the Or egon RH SIP refers not to the visibility improvement that would result fr om installation of controls, but rather to the baseline visibility impacts of the point sources at the near by Class I areas. In comparison, we found that the baseline impacts from Independe nce (Units 1 and 2 co mbined) 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 cont rols on Independence Un its 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 Independen ce and the visibility improvement of potential controls, we have determined that SO 2 and NO X controls at Independence would be costeffective and would result in meaningful visibil ity benefits at Arkans as’ 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 sp ecific 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 co mments contending that we were arbitrary and capricious in determining what sources to evalua te under reasonable progress, that we “targeted” the Independence Plant, and that our decisi on to evaluate the Independence Plant was unsubstantiated and unsupported.

Comment: EPA’s evaluation and application of NO X 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 NO X controls at the Independence Plant also stands completely opposite its decision not to even evaluate similar controls for Texas’ poi nt sources despite simila r visibility conditions.

285 77 FR 30464.

286 See 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 NO X controls because modeling suggested that impacts from the sources were “p rimarily due to sulfate emissions” -- i.e. NO X emissions from those sources were not significa ntly impacting class I Federal Areas. 287 In Arkansas, EPA was even more explicit, stating th at “visibility impairment is not projected to be significantly impacted by nitrate on the 20% worst da ys at Caney Creek or Upper Buffalo.” 288 Incredibly, however, the agency evaluated and proposed NO X 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 NO X controls 290 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 regul ations strive for “standardiz[e d] 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 c onsistent as reasonably possible w ith activities of other Regional

Offices.” 293 In EPA’s Arkansas FIP proposal, Region 6 abandoned the standardized criteria, procedures and policies previous ly applied by the agency and, in the process, disregarded all notion of uniformity. Even worse, the EPA’s inconsis tent 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 pr oposal in the first instance. 294

[Entergy Arkansas Inc. (0166) p. 16, 17] Entergy stated that EPA’s decision to evaluate and

propose NO X controls at Independence stands comple tely opposite its decision not to even

evaluate NO X 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 fo r these EGU sources, as our mode ling 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 NO X limits on Independence is in explicable 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 SO 2 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 wh ere 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 Implementa tion 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 NO X , and almost not at all by Independence. Further, Arkansas has sufficien tly documented that those same Class I areas remain well ahead of the approved URP.

Entergy stated that reviewed i ndividually, the inconsistencies id entified 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 th at 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 fair ly 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 c onsistent as reasonably possible w ith 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 propos al 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 NO X controls at the Independence Plant also stands completely opposite its decision not to even evaluate similar controls for Texas’ point sources despite similar visibility conditio ns. EPA elected not to evaluate Texas point

sources for NO X controls because modeling suggested that impacts from the sources were “primarily due to sulfate emissions” -- i.e. NO X 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 signif icantly impacted by nitrate on the 20% worst days at Caney Creek or Upper Buffalo.” 296 Incredibly, however, the agency evaluated and proposed NO X 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 proj ection for anticipated

295 79 Fed. Reg. at 74,873 (“we are limiting our analyses to consideration of SO 2 controls for these EGU sources, as our modeling indicates that the impact s from these sources on the 20% wors t days are primarily due to sulfate emissions.”).

296 80 Fed. Reg. at 18994.

297 Id. at 18966.156 visibility improvement due to the NO X controls 298 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, illust rate the very fact-specific nature of

individual evaluations and deci sions 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 manne r, but the different facts—unique to each state and facility— inevitably lead to different outcomes. We agree that in our Texas FIP ac tion we noted that on the 20% worst days, the impacts from the EGUs we evaluated under re asonable progress were primarily due to sulfate emissions. We also agree that in our Arka nsas FIP proposal we acknowledged that the CENRAP modeling demonstrat es that sulfate is th e primary driver of regional haze in Arkansas’ Class I areas on th e 20% worst days. This does not mean that NO X is not a key pollutant contributing to regional ha ze impairment in both states. For instance, the CENRAP CAMx modeling shows that total extincti on at Caney Creek is do minated by nitrate on 4 of the days that comprise the 20% worst da ys 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 NO X controls under reasonable progress in both Texas and Arkansas. In our Texas FIP, we considered NO X controls under reasonable progress for the

Works No. 4 Glass Plant but ul timately did not require those controls based on the emission reductions already occurring at the facility, the anticipated lifetim e 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 contro ls 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 exis ting LNB for control of NO X emissions. This is in contrast to Independence, which is the second largest source of NO X point source emissions in Arkansas and is not currently equipped with any NO X controls. As such, Independence was a more compelling

candidate for evaluation of NO X controls in the first planning period than were the EGUs in

Texas that we evaluated for cont rols under reas onable progress.

As NO X is a visibility impairing pollutant and In dependence is responsible for a very large portion of the point source NO X emissions in the state (approximately 21.3%), 301 we determined

that it was reasonable to evaluate NO X controls under reasonable pr ogress in our Arkansas FIP proposal. We conducted CALPUFF modeling an d found that the Independence Plant has

298 Compare 79 Fed. Reg. at 9,360 (Arizona Proposed) (reject ing installation of selective catalytic reduction technology for reasonable progress wh ere 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 Implemen tation 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 NO X emissions based on the 98 th
percentile visibility impacts fr om 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 re asons, 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 Ente rgy submitted CAMx photochemical modeling during the public comment period showing that nitrate fr om 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 NO X controls at Independence, wh ich 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 statutor y factors and the visibility impr ovement available from controls,

we have determined that there are reasonable NO X controls available for Independence that are

cost effective and would result in considerab le visibility improvement. Therefore, we are requiring these controls.

We disagree that our decision to require NO X 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 re latively 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 pur poses of RP in this planning period. However, these units should be considered for additional NO X controls in future planning periods. 303

The “relatively high cost” of SCR controls we refer to in that statement is $6,829/ton NO X removed for Springerville Unit 1 and $6,085/ton NO X removed for Springerville Units 2. 304
Thus, our decision to not propose SCR at Spri ngerville Units 1 and 2 was not because we considered the visibility benefits to be too sma ll, as the commenter appears to believe. Instead, it was because we determined that, under these circ umstances, 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 lowe r ($401/ton removed for Unit 1 and $436/ton removed for Unit 2), and we determined that 0.459 dv visibility

302 Although the reasonab le progress provisions of the Regional H aze Rule place emphasis on the 20% worst days, the CAA goal of remedying visibility impairment due to an thropogenic 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 decision s, such as the days on which a given facility has its own largest (98 th percentile) impacts. Because Independence has significant 98 th 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 c ontrols. Therefore, we disagree that the NO X controls we proposed and are finalizing in this action for I ndependence Units 1 and 2 in any way contradict our action on the Arizona Regional Haze FIP.

We disagree that our proposed reasonable progress controls ar e 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 po licies applied by EPA in other regional haze actions with respect to the reasonable progress analysis.

We also address elsewhere in this document comm ents 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 ar ea 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 natu ral visibility conditions until well beyond the national goal of 2064.

[ADEQ (0160) p. 17-21] ADEQ stat ed that as pointed out in th e Five-Year Progress Report State SIP revision, Arkansas is making substantial prog ress in addressing regional haze in its Class I

areas and is on schedule to m eet 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 th at are more aggressive than that necessary to achieve the program’s goal, which is inconsis tent with surrounding st ates 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 Arka nsas may reach its own 2018 RPGs without additional control measures beyond those desc ribed 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 achie ve its 2018 RPG of 3.88 d eciviews 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 si mply unnecessary to achieve the goal of reaching background visibility conditions by 2064.

Despite Arkansas being on schedule to meet or beat the trajectory need ed to achieve background visibility conditions by 2064, EPA is proposing more stringent RPGs that would require unnecessary additional controls. Specifically, EP A is requiring additiona l controls on Entergy Independence Units 1 and 2. 311 EPA’s proposed RPGs are more a ggressive, 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 st ates that would allow those states to meet background visibility conditions well into the ne xt century. In Texas, EPA proposed RPGs that

would allow that state to achieve natural visibility conditions fo r the 20% worst days in Big Bend Wilderness Area in 194 years and in th e 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 bac kground 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 settin g 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 unreas onable and unnecessary to achieve “reasonable progress” towards reach ing 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 Regi onal 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 Implementati on Plans; State of California; Regional Haze State Implementation Plan and Interstate Transport Plan; Interference With Visibility Requirement, 76 FR 13944, at

13951160 visibility conditions by 2064. Notwithstanding th is 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 stat es that will not attain background visibility

conditions until well after 2064.

Despite Arkansas being on track to achiev e 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 appr oved 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 unneces sary controls on Entergy’s Independence Plant while allowing other states to ut ilize RPGs that will not attain background vi sibility conditions until hundreds of years after Arkansas will ac tually achieve background visibility without installing the controls required by the Proposed FIP. Since the Pr oposed FIP contains arbitrary and capricious revisions to Arkans as’s RPGs, despite the fact that Arkansas is already well on its way to compliance with the Regional Haze Rule a nd 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 esta blishing the RPGs, states (or EPA in standing in the state’s shoes in a FIP) must conduct an analysis of the f our 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” c ontrols) 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 Clas s I area is making reasonable progress and that the requirements under the CAA an d section 51.308(d)(1) ar e 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 obligati on to conduct a reasonable progress analysis, nor does it justify the dismissal of c ontrols 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 th at allow those states to meet background visibility conditions well into the next century. In Texas, EPA prop osed RPGs that a llow 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 Wich ita Mountains in 92 years. Id. EPA approved California’s RPGs even though many of its Class I areas will not r each 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 un til 2160, and in Ansel Adams Wilderness Area until 2200.

76 Fed.161 The preamble to the Regional Haze Rule 318 states the following with re gard to consideration of the URP glidepath:

If the State determines that the am ount of progress id entified 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 EP A may find, based on the required analysis of the four statutory factors alongside c onsideration of the visibility impr ovement of controls, that there are additional reasonable controls available that are cost effective and have meaningful visibility improvement, and are therefore necessary for reasona ble progress, even if the applicable Class I area is below the URP glidepath. On the other ha nd, there may be cases where the state or EPA find, based on the required analysis of the four statutory factor s alongside consideration of the visibility improvement of contro ls, 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 provi de for meaningful visibility improvement at Arkansas’ Class I areas. Theref ore, we must require these controls under reasonable progress and provi de RPGs that represent our best es timate of the degree of visibility improvement that will result in 2018 from the se t of control measures in our FIP to address visibility, as well as all other enforceable measur es 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 th e 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 ma nner, but the different facts— unique to each state and facility—i nevitably lead to different out comes. Thus, we disagree that our proposed Arkansas FIP and th e RPGs we are finalizing are in consistent with the RPGs we have established or approved in other regional ha ze actions where natural vi sibility conditions at the applicable Class I areas are projected to be achieved beyond 2064.

We address in greater detail comments rela ted to ADEQ’s Five Year Progress Report SIP

revision and recent IMPROVE monitor da ta 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 reas onable progress goals during the first planning period, it is “reasonable” to determine that no further emission reduc tions 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 ach ieve the [Reasonable Progress Goal] in the first planning period. [Nevada] r easonably concluded that the cost of

additional controls was not warra nted given projected emissions reductions from anthropogenic sources a nd 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 signif icant 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 go als for a Class I area were already being met. For Arkansas, however, EPA has completely reve rsed its prior position without any coherent explanation. EPA may not reverse its prior po licy 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 conces sion that the Arkansas Class I areas will meet their reasonable progress goals should end the inquiry absent so me significant concerns about the state being able to meet the Uniform Rate of Pr ogress 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 wh at is necessary to make reasonable progress, including whether additional c ontrols are necessary, must be made based on the required analyses under CAA section 169A(g)(1) and se ction 51.308(d)(1). We discuss extensively throughout this document that the fact that Arka nsas’ 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 obliga tion to conduct a reasona ble progress analysis.

We disagree with the commenter’s contention that our proposed requi rement of additional controls under reasonable progres s for Independence Units 1 and 2 is inconsistent with our approval of Nevada’s reasonable progress determ ination. The commenter’s contention that “For Nevada, EPA found that it was imminently reason able 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 deci sion 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 attribut es of regional haze at Jarbidge as well as the expected reductions in statewide emissions of SO X and NO X and BART controls on thre e facilities. The WRAP’s regional analysis indicates that h aze 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 demonstrati on that its RPG provides for reasonable progress in the first pl anning 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 ru le, in promulgating the SIP NDEP

considered the four factors in se tting 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 conclude d that the cost of additional controls was not warranted give n projected emissions reductions from anthropogenic sources and the fact that the majority of haze at Jarbidge is from natural a nd out-of-state sources. Moreover,

320 76 FR at 36465.164 NDEP noted in its comments that “o f 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 NO X and

SO 2 by 2018. The comments do not de monstrate that the State failed to consider reasonably the four factors, but the comments question whether the State s hould have done a more robust analysis. EPA has considered the comments and the comments have not provided any further spec ific facts that should have been considered in the State’s analys is 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 indicat ing 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 cont rols was not warranted given projected emissions reductions from anthropogenic s ources 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 prim ary driver of regional haze in Arkansas’ Class I areas, accounting for approximately 56% of the total visi bility impairment at Caney Creek and approximately 59% of the tota l visibility impairment at Upper Buffalo on the 20% worst days in 2002. We do note that the CE NRAP modeling for 2002 does indicate that for Caney Creek, the largest contributio ns 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 outs ide the State. However, we also make the important observation that the CENRAP 2018 mode ling 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 be tween 2002 and 2018. For example, anticipated reductions of sulfate from point sources in Texa s, the eastern United Stat es, 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 ea stern United States, Indi ana, 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 thes e other states, sulfate from Arka nsas point sources is actually expected to increase between 2002 and 2018. This distinguishes Arkansas from Nevada, where the expected reductions in Neva da’s statewide emissions of SO X and NO X , including BART controls on three facilities, was pa rt of our justification for agr eeing with Nevada that controls under reasonable progress are no t necessary. In the Nevada s ituation, the relevance of the observation that significant redu ctions 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 th at these technical fact s distinguish Arkansas’ Class I areas from the Jarbidge Wilderness Area.

We also make the observation that the citati on from our final action on the Nevada RH SIP explains that the RHR and EPA’s guidance affo rds 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 Arka nsas’ reasonable progress goals because Arkansas did not c onduct 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 th ey 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 contributo rs to visibility impairment, whic h 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 statut ory factors alongside consideration of the visibility improvement of controls, we determined that there are reasonable controls av ailable 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 re quire these controls under reasonable progress and

establish RPGs that reflect these additional controls as well as the BART cont rols that are part of our FIP. This comment, and our response to it, illustrate the very f act-specific nature of

individual evaluations and deci sions 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 manne r, 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 “concessi on that the Arkansas Class I areas will meet their reasonable progress goals.” This is inco rrect. On the contrary, we disapproved the RPGs established by Arkansas in our final action on the Arkansas RH SI P, published on March 12,

2012. 325 Therefore, the state established RPGs ar e not a reflection of the control measures necessary to make reasonable pr ogress. We also discuss elsewh ere 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 limitati ons and other control measures that apply to specific sources (including both BART and s ources controlled under reasonable progress). 327
Achieving or being projected to achieve the RPG does not necessa rily demonstrate that a state has satisfied the reasonable progr ess requirement. The state or EP A must complete the required four factor analysis to dete rmine 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 reas onable progress is inappropriat e, inconsistent and arbitrary, and that we inappropriately focused on Inde pendence in our reasonable progress analysis.

Comment: EPA must consider the four reasona ble 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 overarc hing requirement of the Clean Ai r Act’s haze provisions is for each state’s plan to include “emission limits, sche dules 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 cont rols, the time needed to install controls, energy and non-air quality environmental impacts of cont rols, 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 st ate with a Class I ar ea 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 stat e must demonstrate that achieving the URP is

unreasonable and that the alte rnative goal is reasonable. Id. § 51.308(d)(1)(ii). Moreover, each

state must consult with other states that contri bute 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 exempt s states from the required reasonable progress analysis merely because a Class I area is on the glidepath to achieving th e URP. To the contrary, EPA’s long-standing interpretation of the regional h aze 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 progre ss than the URP, a state must do so, as EPA explained in the 1999 regional haze rule:

If the State determines that the am ount of progress id entified 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 reasona ble 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 reason able progress goals and long-term strategy for Arkansas, “EPA ‘stands in the shoes of the defau lting State, and all of th e rights and duties that

would otherwise fall to the St ate 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 incomple te SIP, or submits a SI P that does not meet the statutory requirements, EPA is obligated to impl ement its own FIP to correct the deficiency in the SIP”).

Response: We generally agree with this comment w ith regard to our decision to evaluate Independence Units 1 and 2 under reasonable progre ss. We address elsewhere in this document more specific comments stating th at we must address in this FI P the requirements under section 51.308(d)(3) with regard to Cla ss I areas outside the state a ffected by Arkansas’ emissions.

Comment: EPA appropriately prioritized the I ndependence Power Plant in its Reasonable Progress Analysis, and EPA should require insta llation 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 MWeach. 80 Fed. Reg. at 18,992. It is the secondlargest point source of SO 2 and NO X emissions in Arkansas. Id. The plant is responsible for 36%

of SO 2 and 21% of NO X 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 neighbori ng states, such as Missouri, where it impairs visibility at the Hercules-G lades and Mingo Class I areas. Id.

The Independence plant lacks modern air pollutioncontrols, despite the availability of costeffective technologies that are widely used at other electric generating units. The plant has no scrubbers, and indeed has no pos t-combustion controls for SO 2 emissions. Id. at 18,992. Similarly, the plant has no post-combustion controls for NO X emissions. Id. EPA’s analysis indicates that installing scr ubbers and SCR at Independence Units 1 and 2 would be costeffective and would significantly improve visibili ty. In the reasonable progr ess analysis for other FIPs, EPA has prioritized point sources that ar e “upwind” of Class I areas, “have high SO 2 emissions and lack modern pollution c ontrols.” 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 SO 2 emissions (and high NO X emissions), and lacks modern pollution controls— EPA properly prioritized the Independence plan t for review during the reasonable progress analysis.168 In addition, the regional haze sc reening analysis used by fede ral land managers (FLMs)—who are responsible for protecting visibility in Class I areas—provides fu rther support for EPA’s decision to prioritize Independence. As disc ussed in more detail in the Gray Report, 328 FLMs rely on a screening methodology based on the potentia l 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 determinat ions regarding which emitting facilities will have an adverse impact on visibility. Gray Re port at 12-16. The FLMs c onsider a source located

more than 50 km from a Class I area to have a ne gligible 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 th e 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 comput ed 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 re commendation to requir e 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 w ith 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 scrubbe r and SCR controls at the Independence plant. Arkansas’s long-term st rategy should require Independence Units 1 and 2 to operate a scrubber and SCR to m eet 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 th e Independence Plant exce eds 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 reasona ble progress. While we generally agree with the nece ssity to evaluate Independen ce Units 1 and 2 under reasonable progress, and the need for SO 2 and NO X control on these units to make reasonable progress, we disagree that SCR or SNCR c ontrols are necessary. We addr ess comments arguing that we should require SCR or SNCR controls for Indepe ndence under reasonable progress elsewhere in

this document. We also discuss elsewhere in th is document that the purpose of our reasonable progress analysis is to addre ss the requirements under section 51.308(d)(1) and (d)(3) related to visibility impacts in Class I areas within the stat e. The purpose of the anal ysis 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 Inde pendence Units 1 and 2. There are no energy or non-air quality environmental impacts from a sc rubber that are signif icant 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 cons ideration of non-air quality environmental impacts of controls as does the reasonable pr ogress analysis, so EPA’ s conclusion in BART

determinations that scrubbers do not create e nvironmental impacts sufficient to negate their benefits should apply with equal fo rce in reasonable progress analyses. Compare 42 U.S.C. 7491(g)(1) (reasonable progress analys es shall consider “non-air quality environmental impacts of compliance”) with 42 U.S.C. § 7491(g)(2) (BART determ inations 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. Consid eration 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 th e record regarding the re maining useful life of the Independence plant that weighs in favor of any particular control.

If EPA were to consider visibi lity improvement, which is not a statutory factor for reasonable

progress, see 42 U.S.C. § 7491(g)(1), such considerat ion would support requiring a scrubber. Operating a dry scrubber at th e Independence plant would impr ove visibility by 0.938 deciviews at Caney Creek and 0.888 deciviews at Uppe r 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 factor s 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 cont rols, and controls can and should be installed earlier; the energy and non-air impacts are mini mal; and the remaining useful life does not cut against the controls. Moreover, th e visibility improvement from a dry or wet scrubber would be significant. Taken together, th e reasonable progress factors weigh in favor of requiring Independence Units 1 and 2 to install and opera te a scrubber in order to make reasonable progress at Caney Creek and U pper 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 em ission limits for Independence Units 1 and 2 can be achieved by SO 2 scrubber controls, we take no positi on 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 public ation of our April 8, 2015 proposal, we found that dry scrubbers on the Independence units would improve visibility by 1.096 dv at Caney170 Creek and 1.178 dv at Upper Buffalo. 329 Wet scrubbers on the In dependence units would improve visibility by 1.113 dv at Cane y 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 SO 2 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] Enter gy stated that in the proposed FIP, EPA’s reasonable progress analysis primarily focuses on poi nt 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 sole ly to Arkansas’ largest emitti ng point sources, and, specifically, to Independence. However, as demonstrated in Figures 3 and 4 below, Arkansas point sources are relatively insignificant cont ributors to visibility impairme nt in Caney Creek and Upper Buffalo compared to most of the other regi ons modeled by CENRAP and are not even the biggest source group contributor in Arkansas to visibility impa irment 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 Enterg y’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 ge ographic region and source category, so that the indi vidual contribution of each source category in each geographic region could be determined.171 “Regional Point Source Percentage of Total Ex tinction at Caney Creek Wilderness Area, W20 Group, 2002” (provided by Entergy as Figure 3 to AR020.0166)172 “Regional Point Source Percentage of Tota l 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, wh ich it provided, display the modeled percent contribution of elevated and low-level point s ources 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 sour ces in all geographic regions. Of a total point source contribution of 61.85% at Caney Creek in 2002, Arkansas’s poin t sources contributed only 2.87%, making Arkansas the eighth highest point source contributor. Similarly, of the 60.35% total point source contribut ion 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 Extincti on at Caney Creek Wilderness Area, W20 Group, 2002” (provided by Entergy as Figure 5 to AR020.0166)174 “Regional Percentage of Total Extincti on at Upper Buffalo Wilderness Area, W20 Group, 2002” (provided by Entergy as Figure 6 to AR020.0166)

At Caney Creek, Arkansas area sources cont ribute 3.75% of the overall extinction while Arkansas’ combined point source category (i.e., elev ated and low-level poin t 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 meaningf ully 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 ha ve a larger contribution to visi bility extinction at Caney Creek and Upper Buffalo. The commenter’s analysis of contributions to visibility impairment above focuses on visibility impairment in 2002. Howeve r, the projected 2018 contri butions to visibility impairment show large anticipated reductions in contributions from many areas outside of Arkansas. Arkansas point source s are projected to contribute more than 4% towards total175 visibility impairment at both Caney Creek a nd 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 stat e, we consider this to be a si gnificant contributi on 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 co mes from Arkansas area and mobile sources, not point sources. While we agree that Arkans as area sources do have a slightly greater percentage contribution than do Ar kansas 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 Arkans as point sources in our reasonable progress analysis. Additionally, we discuss in detail in ou r 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 Ar kansas’ 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 visibi lity impacts from the Independ ence 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 visibi lity 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 tota l contribution from all Arkansas point sources that can be addressed through installation of contro ls on two units at a single facility. Entergy’s CAMx modeling also shows that at Upper Buffal o, the Independence facility contributes more to visibility impairment than all the subject-to-BART sources addre ssed 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 conditi ons) 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 Indepe ndence facility significantly impact s 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 visibil ity 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 planni ng period will become larger on a percentage basis. These sources will become the largest im pacting sources and should be176 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 a nd ensures continuing progress towards the goal of natural visibility conditions.

Comment: Continued emissions reductions fr om out-of-state sources included in the CENRAP modeling will further Arkansas’ prog ress 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’ Clas s I areas will remain below the glidepath in the first planning period and well into the second ba sed on actual data; however , the analysis also demonstrates that, due to continued emissions re ductions 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 de creasing since the early 2000’s and that trend is expected to continue. Indeed, a number of sources in East Co ast 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 retirem ent will further improve visibility. The second phase of CSAPR, the 1-hour SO2 NAAQS and th e revised ozone NAAQS also will result in significant reductions in SO2 and NO X emissions from the largest point source contributors to Caney Creek and Upper Buffalo, which ar e 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 SO 2 Emissions” (provided by Entergy as Figure 7 to AR020.0166)178 National Emissions Inventory (NEI) Ai r Pollutant Emissions Trends Data NO X Emissions (provided by Entergy as Figure 8 to AR020.0166)

Entergy stated that according to EPA’s Reasona ble 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 redu ctions that we anticipate to result from BART, the CAIR, and the implementation of other CAA programs, including the ozone and PM 2.5 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 und ertake 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 th e commenter regarding emissions reductions179 from sources outside of Arkansas that impact visibility at Arkansas’ Class I areas. The

commenter contends that this tr end in emissions reductions from sources outside Arkansas will

continue into the future and will further Arkans as’ progress towards natural visibility conditions,

even without controls on Inde pendence. The commenter also poi nts to our Reasonable Progress Guidance as stating that it is important to acc ount for the emissions reduc tions 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 exte nt the commenter is s uggesting that Arkansas should be relieved of its obligati ons to address visibility impair ment 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 statutor y factors in addressing th e reasonable progress and long term strategy requirements. We discuss th is issue and also pr ovide a discussion of

Arkansas’ emissions trends from 2002 to 2011 elsewhere in this document.

Further, the commenters’ suggestions that EP A should delay the implementation of control measures for Independence that we have dete rmined are cost-effective and would result in meaningful visibility be nefit at Arkansas’ Class I areas, reli es on the conclusion that there is a specific pre-determined rate of improvement th at 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 an alysis under CAA section 169A(g)(1) and 40 CFR section 51.308(d)(1).

To the extent that the commenter is concerne d about whether our propos ed RPGs reflect the effects of the emission reductions from other regula tory requirements and s ources in other states, we believe this step of accounting for emi ssions 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 pr ojected reductions due to implementation of CAIR that states relied on in setting their RPGs. Under CAIR, point source

emissions of SO 2 were projected to increase in Arkans as. We recognize that in calculating proposed revised numeric RPGs for Arkansas’ Class I areas, we did not upda te the projections to take into account any changes in emissions re ductions anticipated to take place due to implementation of CSAPR and other CAA program s that were not already included in the 2018 CENRAP modeling projections. But the commente r has not provided any additional information to support any anticipated SO 2 reductions from Arkansas point sources in the near future to address any existing regulatory requiremen ts. 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 re ductions achieved through the FIP into quantitative RPGs, based on mode ling previously perfor med by the RPOs. This provides an estimate of the visibil ity 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, 31708180 projected 2018 visibility condi tions and RPGs established by Arkansas in its 2008 RH SIP. While there is limited precedent fo r 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 adju sted the 2018 RPGs provided by Arkansas by the amount of visibility benefit anti cipated from the difference in emissions reductions between the

estimates that went into the CENRAP modeli ng and those from our Arkansas FIP that are expected to take place by 2018. 336 We believe that this is a re liable 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 fo r estimating the revised RPGs is problematic because the RPGs are not directly enforceable, un like the emission limits that apply to specific sources under the regional haze requirements.

Comment: EPA’s Proposed FIP does not includ e 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), th e Regional Haze Rule requires states such as Arkansas to coordinate in various ways with Federal Land Ma nagers. For example, states are required to provide Federal Land Managers with notice of th e identified visibility impairment and an opportunity for consultation. 337 However, despite EPA requiring th is coordination, the actions of the Land Managers themselves ar e responsible for a di sproportionate 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 appr oved a Smoke Management Program that was developed, among other reasons, as a means of a ssuring that land managers throughout the State use specific techniques designed to ensure th at 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, pr escribed burning is a useful technique for various forest management purposes.

A Federal Land Manager is “the Secretary of th e department with authority over the Class I

areas.” 338 While several state agencies and private-s ector entities practice prescribed burning, the United States Forest Service (“ USFS”) is the largest practitio ner. The USFS uses prescribed burns from within the very Class I areas that are meant to be protecte d by the Regional Haze Rule. For example, in 2006 the USFS was responsib le 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 viola tion 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 pa rticipants including th e 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 Arka nsas were conducted w ithin the boundaries of designated National Forests. 341

There is currently no accepted regulatory proc edure for isolating the visibility impacts of prescribed burning from other anthropogenic so urces of haze. However, prescribed burns continue to be a significant source of the haze in the Class I areas that ar e meant to be protected by the Regional Haze program. As a result, th e actions of Federal Land Managers practicing prescribed burning should be given due consid eration. Therefore, EPA should withdraw the Proposed FIP, and any subsequent plan should incl ude 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 rega rding 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, includ ing smoke management techniques for agricultural and forestry management purposes. Secti on 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 ongoi ng air pollution control programs, including measures to address r easonably 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 li mitations and control measures; and

(G) The anticipated net effect on visi bility due to projected changes in point, area, and mobile source emissi ons 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 Arkans as RH SIP, we partially appr oved 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 a ppropriately consider emission limitations and schedules for compliance in developing its long-term stra tegy, which corresponds to the requirement under section 51.308(d)(3)(v)(C). Specifically, we found th at Arkansas did not follow the CAA and the Regional Haze Rule in establishing certain BA RT emission limits and did not complete a reasonable progress analysis to determine if a dditional controls were necessary in the first planning period. We also found that aside from th is element of the long-term strategy, remaining elements of the long term strategy in the Ar kansas RH SIP satisfied the requirements under section 51.308(d)(3)(v) for the fi rst planning period. This include s Arkansas’ consideration of agricultural and forestry smoke management techniques under section 51.308(d)(3)(v)(E). The purpose of our FIP is to addre ss the disapproved portions of the Arkansas RH SIP for the first implementation period. 343 Since we found in a previous fina l action that Arkansas adequately considered agricultural and forestry sm oke 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 addres ses 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 becaus e 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 so urce-based approach to setting reasonable progress goals inconsiste nt with the Clean Air Act. Reasona ble 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 impairme nt (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 cate gories of sources” that “may re asonably be anticipated to cause or contribute significantly to impairment of visi bility” 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 Impair ment (RAVI) provisions are applie d individually to “each major stationary source” meeting cer tain threshold criteria. ld. § 7491(b)(2)(A)(c). This distinction is carried over into EPA's regulations. For exam ple, under the Regional Haze Rule, SIPs that incorporate reasonable progress goals are in tended to address “reg ional 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 “v isibility 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 indi vidual sources. Consequently, EP A does not have the authority and should not have established a separate Reas onable Progress control ju st for Independence.

AEEC/AGC stated that in the Proposed FIP, th e EPA fails to explain how one could somehow use factors required to be cons idered 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 fo r “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 s ource-specific analysis in the determination of reasonable progress, the EPA lacks authority to es tablish separate Reason able Progress controls for the Independence plant; th erefore, 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 pr ogress by considering thos e sources and source categories with the most significant impact on visi bility impairment. We explained in our FIP proposal that our reasonable pr ogress analysis focused on the point source category since the other source categories each contribute a much sm aller 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 da ta that initially identified Wh ite Bluff, Flint Creek, and the Independence facility as having th e greatest potential to impact visibility at nearby Class I areas out of all Arkansas point s ources. Since we are requiring SO 2 and NO X 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 c ontrols under the reasonab le progress requirements for this planning period. As such, our evaluation of controls under reas onable progress focused on the Independence Plant. We discuss our approach to determine what sources to evaluate under reasonable progress in greater de tail in our proposal, in our fina l 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 re gulations, and past EPA guidance. The four statutory factors under CAA Section 169A(g) a nd 40 CFR 51.308(d)(1)(i)(A) are directed to the listed possi ble features or consequences of potential emission control

344 The Regional Haze Rule states that “[t]he reasonable progress goals estab lished 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 reas onable 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 afte r taking into account the f our statutory factors-- as applied to specific sources or groups of sour ces – to determine what additional controls should be required in its regional haze SIP. Thus, indi vidual stationary sources may be subject to emission limits and source specific analysis wh en determining whether additional controls are necessary to make r easonable progress.

The comment misinterprets the cited 10 th Circuit case. In that cas e, that court found that reasonable progress is not requir ed to be demonstrated on a source-by-source basis (or via “source-specific analysis”), but th is emphatically does not mean th at 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 establ ishing reasonable progress goals. When a State or EPA in a FIP conducts the requis ite analysis—whether it be gins it by analyzing sources individually or by anal yzing source categories—it should encompass the possibility of applying individual source controls, when they ar e 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 emi ssion control measure being nece ssary for reasonable progress, based on that source being responsible for a majo rity of the emissions from the category and there being a feasible and highly cost effective c ontrol, then it would be proper for the State (or EPA in a FIP) to focus its analysis on that so urce, including with a s ource-specific assessment.

To conclude otherwise vitiates th e 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. S ee CAA Section 169A(b)(2); 40 CFR 51.308(d)(1) and (3). Incidentally, the cited 10 th Circuit case had considered the claim that the State of New Mexico failed to conduct source-specific anal yses 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 im pacts 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 RP Gs 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 progre ss toward the national goal of natural visibility

conditions. We discuss elsewhere in this documen t that the numeric RPGs provided by the state or EPA represent the best estimate of the degr ee of visibility improveme nt that will result in185 2018 from changes in emissions inventories, cha nges driven by the partic ular set of control measures the state has adopted in its regional ha ze SIP or EPA in a regional haze FIP to address visibility, as well as all other enforceable measur es 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 antici pated 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 requi rements, 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 fact ors or require source-specific emission limits under the reasonable progress requirements.

The commenter states that we make referen ce 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 us ed 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 fi nalize 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 Qualit y 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 tr ibal governments with the following items on the agenda:

 Rulemaking activities including the proposal to delay of th e 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 vi sibility goals of the Regional Haze Rule are determined and calculated. These changes woul d 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 ha s 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 issui ng guidance to refocus the visibility tracking

metric and framework on the controllable frac tion 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 noti ce of availability of this dr aft 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 requir ed under CAA section 169A(g)(1) and 40 CFR 51.308(d)(1) to determine if addition al controls are necessary to make reasonable progress and to establish RPGs for the first planning peri od. The proposed rulemaking and draft guidance address the second and future implementation periods only, while th is 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 pr omulgation of our FIP to address the disapproved portions of the Arkansas RH SIP.

To the extent the commenter contends that the RG Ps in the Arkansas RH SIP are appropriate, we discuss elsewhere it this document why such comme nts are outside the scope of this rulemaking.

4. Specific BART Issues

4.a. Control Levels and Emission limits

Comment: EPA’s proposed SO 2 BART limit of 0.11 lb/MMBtu for Power Boiler 2 is too stringent, and its selection of emission baselin e information for the purpose of establishing

the SO 2 BART limit for Power Boil er No. 2 is inappropriate. [Domtar (0161) p. 6, 10-13] Domtar stated that table 43 on page 18979 of th e 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 NO X Emissions (lb/hr) SO 2 Emissions (lb/hr) PM 10 /PM F (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 SO 2 BART limit for Power Boiler 2. Instead of using data from the BART baseline period of 2001-2003 for calculating the BART SO 2 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 rese tting 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 pa st practices (Guideline s, at 39167). By analogy, in determining the BART limit for SO 2 , the percent reduction also s hould be applied to the past practice of Power Boiler 2 as re flected in the 2001-2003 timeframe. This approach is consistent with prior EPA BART determinations for pul p 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 SO 2 limit of 155 lb/hr for Power Boiler 2 is appropr iate under the BART fi ve factor analysis. EPA’s proposed limit of 0.11 lb/MMBTU is too string ent, is based on the use of an inappropriate baseline and assumes the existing control equipm ent can continuously opera te at the upper range of its capability (90% efficiency) over long peri ods of time, without supporting data or other

documentation.

Domtar stated that in the methodology to calcu late 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 baselin e years or lega lly appropriate. The variety of data sets EP A used is summarized below:

 Baseline SO 2 emissions of 2,078 TPY determined using 2001-2003 data for determining

tons of SO 2 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 y ears 2011-2013 to determine the BART limit

Domtar stated that EPA’ s selection of actual SO 2 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 invo lving 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 may188 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 ba seline information is appropriate if significant changes were made to the emission units or pe rmit conditions were imposed that prevent a unit from operating at the BART baseline emission valu e. However, this is not the case for Power

Boiler 2. The BART baseline information is re presentative of Power Boiler 2’s potential operations. The fact that the Ashdown Mill volu ntarily elects to operate at a lower SO 2 level is not relevant. Moreover, by not ut ilizing the BART baseline actual emission in establishing the proposed BART SO 2 limit, EPA penalizes the As hdown Mill for its voluntary SO 2 emission

reductions undertaken on its own initia tive since the BART baseline period.

Domtar stated that here, the Mill voluntarily reduced SO 2 emissions by over 40% since the BART baseline years. The Ashdown Mill was an early actor and voluntarily reduced SO 2 emissions prior to the proposed BART requirement s. Using the actual emission data from the BART baseline period of 2001-2003, gives the Mill cr edit for its early voluntary action. Also, using the earlier baseline appropria tely 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 ba seline year, EPA wrongly applied the maximum rated heat input capacity of 820 MMB TU/hr when it converted from a lb/hr limit

to a lb/MMBTU limit. This inaccurate met hodology of using emission data and maximum rated heat input to calcu late the proposed SO 2 BART limit is a significant concern.

Domtar stated that based on monthly SO 2 information for the 2011-2013 period, EPA estimated

that the SO 2 control efficiency for the scrubber on Po wer Boiler 2 to be approximately 69%. The scrubber is currently operated base d 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 SO 2 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 SO 2 control efficiency of 90%. However, there is no documentation s howing 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 SO 2 BART emission rate to use average SO 2 emissions from the 2001-2003 ba seline period as follows:

 Use the average SO 2 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 SO 2 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 very189 high control efficiency for a long-term limit; fo r purposes of this calculation, the Mill will use EPA’s assumed long-term control efficiency of 90%)

Based on this approach, the revised SO 2 limit for Power Boiler 2 is:

 No. 2 Power Boiler Average SO 2 Emissions

Baseline Year Average SO 2 (lb/hr)

2001 557.0

2002 475.0

2003 394.0 Average SO 2 Emission Rate (lb/hr) 475.3

 Calculating No. 2 Power Boiler BART SO 2 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 SO 2 emission rate in lb/hr for the 2001-2003 period is 475.3 lb SO 2 /hr. Using EPA’s assumption that the SO 2 control efficiency for the scrubber during the baseline period is approxima tely 69% and using the EPA assumed long-term scrubber removal efficiency of 90% equates to an SO 2 limit of 155 lb /hr. Thus, The Ashdown Mill requests EPA revise the proposed SO 2 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 SO 2 emission limit for No. 2 Power Boiler be expressed on a lb/hr basis. For EPA’s proposed limit, th e 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 representati ve 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 SO 2 BART limit is inappropriate and an inaccurate methodology which creates significant c oncerns. 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 e xpresses 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 ba sis, 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:

NO X and SO 2 emissions for each calendar day shall be determined by summing the hourly emissions measured in pounds of NO X or pounds of SO 2 . Each boiler operating da y of the 30-day rolling average for the power boiler sh all be determined by adding together the pounds of NO X or SO 2 from that day and the preceding 29 boiler operating days and dividing the total pounds of

NOx or SO 2 by the sum of the total nu mber of hours during the same 30 boiler operating day period. The result shall be the 30 boiler operating day rolli ng average in terms of lb/hr emissions of

NO X or SO 2 . If a valid NO X pounds per hour or SO 2 pounds per hour is not available for any hour for the power boiler, that NO X pounds per hour or SO 2 pounds per hour shall not be used in the calculation of the 30 boiler operati ng day rolling average for NO X or SO 2

.

[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 emissi ons 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 f easible and if they would be cost effective and provide meani ngful visibility benefit. This assessment first required us to determine the current control e fficiency of the scrubbers. Because our BART analysis involved determining the current contro l 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 SO 2 emissions from Power Boiler No. 2, mass of the fuel burned for each fuel type, and the per cent 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 curren t control efficiency of the ex isting scrubbers and our proposed

SO 2 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 SO 2 emission of 2,078 tpy we used to determine the tons of SO 2 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 shou ld use 2011-2013 data for purposes of calculating the cost effectiveness of our proposed control. We note that we are not revising th e cost estimate and calculation of the cost effectiveness of191 As discussed in detail in our pr oposal, 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 effi ciency. As discussed in our proposal, Domtar indicated that the scrubbers are currently operate d 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 permitt ed emission limits. The information the facility provided indicated that it would be possible to add more scrubbi ng solution to achieve greater

SO 2 removal than required to meet the boiler’s existing SO 2 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 maximu m 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 maximu m heat input rating is not representative of average (typical) boiler operating conditions. To address the commenter’s concern, we are finalizing an SO 2 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 SO 2 emission rate for the years 2011-2013 was 280.9 lb/hr. 353
This annual average SO 2 emission rate corresponds to the op eration 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. Applicati on 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 SO 2 emissions are currently lowe r than they were in the 2001- 2003 period, and that had we used 2001-2003 data to calculate the current control efficiency and

SO 2 BART emission limit, as the commenter reque sts, this would have resulted in a less stringent emission limit. However, as discussed above, the most reasonable approach is to use

SO 2 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 additiona l 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 appear s 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 calcula tion of an appropriate SO 2 BART emission limit. As Domtar is requesting an emission limit in terms of lb/hr, we are finalizing for SO 2 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 scru bbers at 90% control efficiency and addresses the

SO 2 BART requirement for Power Boiler No. 2.

We believe it reasonable to set the emissi on 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 SO 2 emission limit, the control efficiency from that period is irrelevant.

What is relevant are the current uncontrolled SO 2 emissions and the possible control efficiency of the existing scrubbers, which is what we cons idered 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 a nd scrubber pump upgrades to achi eve the lower level. We also note that the commenter did not provide additio nal information to support the claim that the existing scrubbers cannot consistent ly 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

SO 2 BART requirement for Power Boiler No. 2. We are finalizing an SO 2 emission limit of 91.5 lb/hr on a 30 boiler-opera ting-day rolling average.

As requested by the commenter, we are revising the regulato ry language at section 52.173 to

reflect that we ar e finalizing an SO 2 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 NO X 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 NO X emission limits proposed by Entergy for the units at White Bluff and Independence are based on the emissi on rate for LNB/SOFA of 0.15 lb/MMBtu that Entergy proposed in the Revised White Bluff BA RT 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 opera ted as base load units and sp ent 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 determin e which EGUs within its service territory are dispatched to operate and the operating load (M W) for each unit. Initially the MISO operating environment resulted in similar unit dispatch sc hedules for White Bluff and Independence, with all four units primarily dispat ched 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 lo w operating rates of less th an 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. Th ree of the four units have spent greater than 40% of their 2015 opera ting 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 coin cided 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 bot h White Bluff and Independence is significant with regard to NO X emissions as the LNB/SOFA sy stem 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 obt ain a guarantee of less than 0.15 lb/MMBtu for operating loads in th e range of 50-100% of unit capacity. 356 Since the available emission guarantee does no t cover unit operation at less th an 50% of capacity, Entergy requested a memorandum from Foster Wheeler re garding the impact of unit operation at less than 50% capacity on NO X emission rates. This memorandum is attached as Exhibit G to Entergy’s comments. Based on input from the LN B/SOFA vendor, Entergy does not believe that the proposed emission rate of 0.15 lb/MMBtu is consistently achieva ble under all operating

356 This range is referred to as th e “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 emissi ons guarantee to account
for fluctuations in NO X emissions from the units. Controlled NO X emissions fluctuate during normal boiler operation in response to a number of design/operating parameters including, but not necessarily limited to: inlet

NO X concentrations, boiler load, load ch anges, 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 peri od for the proposed limit, a unit which is frequently dispatched at less than 50% of cap acity 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 AD EQ 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 opera ting 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

NO X 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 un its 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 NO X emission rate (lb/ MMBtu basis) at operating rates of less than 50% of unit capacity, Entergy propos es a rolling 30-boiler operating day average emission rate of 1,342.5 lb NO X /hr at each coal-fired unit at White Bluff and Independence. In the alternativ e, if EPA believes that a lb/MMBtu limit is necessary for the units, Entergy proposes a bifurcated NO X 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 NO X /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 NO X /MMBtu, based on a rolling 30-boiler operating day average, to include only those hour s for which the unit was dispatched at 50% or gr eater of maximum capacity.

Entergy stated that this alte rnative approach would ensure that the units are operated in compliance with the LNB/SOFA design within th e control range of 50-100% of capacity while providing Entergy with flexibility in demonstr ating 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 NO X emission reductions.

Response: We acknowledge the information provided in the comment and in the attachments referenced by the commenter. We understand Enter gy’s concerns that becau se 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 cons istently meet our proposed NO X emission limit of 0.15 lb/MMBtu over a 30-boiler-operating-day period based on LN B/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 NO X 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 NO X control when the boiler is operated195 from 50 to 100% steam flow because the heat input across this range is sufficient to safely redirect a substantial por tion of combustion air through the overfire air registers. 357 This allows

the combustion zone airflow to be sub-stoichio metric and oxygen to be reduced to the point where much of the elemental nitrogen in the fu el and combustion air can pass through the boiler without oxidizing (i.e ., converting to NO X ). When a boiler is operated below the 50 to 100% capacity range, NO X concentrations on a lb/MMBtu basis can be elevated due to the lower heat input rating, even though the pounds of NO X 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 NO X 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 NO X 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 hou rs during which the unit was dispatched at 50% or greater of maximu m capacity, as requested by the commenter. Specifically, the 30 boiler-operating-day rolling av erage is to be calculated for each unit by the following procedure: (1) summing the total pounds of NO X emitted during the current boileroperating-day and the preceding 29 boiler-operati ng-days, including only emissions during hours when the unit was dispatched at 50% or greate r of maximum capacity; (2) summing the total heat input in MMBtu to the unit during the curren t boiler-operating-day and the preceding 29 boileroperating-days, including only the heat input during hours when th e unit was dispatched at 50% or greater of maximum capacity; a nd (3) dividing the total pounds of NO X 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 NO X emissions when the units are operated at 50% or greater of maximum capac ity, we are also establishing a limit in lb/hr to control NO X 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 comment er is too high to a ppropriately control

NO X 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 ven dor guarantee. The commenter did not explain how the 1,342.5 lb/hr limit was calculated, but it a ppears 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 capaci ties, considering that the limit was calculated based on the unit’s maximum heat input rating. Ho wever, such an emission limit would not be sufficiently protective or appropria te when the unit is operated at lower capacities when it is expected that NO X emissions on a mass basis would be lower compared to operation at high capacity. To address this concer n, we have calculated a new emission limit of 671 lb/hr that is based on 50% of the unit’s maximum heat input ra ting, and is applicable only when the unit is being operated at less than 50% of the unit’s maxi mum heat input rating. We calculated this limit by multiplying 0.15 lb/MMBtu by 50% of the maximu m heat input rating for each unit (i.e., 50% of 8,950 MMBtu/hr, or 4,475 MMBtu/hr). This lim it is on a rolling 3-hour average, where the average is to be calculated by including emissions only from th e hours during which the unit was operated at less than 50% of the unit’s maximu m heat input rating (i.e., hours when the heat

357 See Exhibit G to Entergy Ar kansas 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 ma ximum heat input rating

because there is no need for it sin ce the 0.15 lb/MMBtu limit will address NO X 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 NO X emission limit of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling average, where the average is to be calculated by incl uding only the hours during which the unit was dispatched at 50% or greater of maximum capac ity, as requested by the commenter. In addition, we are requiring White Bluff Units 1 and 2 a nd Independence Units 1 and 2 to each meet a NO X emission limit of 671 lb/hr on a ro lling 3-hour average that applie s 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 be ing able to meet the lb/MMBtu emission limit when the unit is being operated at lower capacities, and will also ensure that NO X emissions are appropriately controlled when the units are opera ted at higher capacities, as well as when they are operated at lower capacities.

Comment: EPA failed to consider all available control technologi es 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 BA RT 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 anal ysis 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 ava ilable retrofit technologies for White Bluff and Flint Creek. In addition, while EPA may have mode led 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 co mpared 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 SO 2 emissions. 360 EPA's own documents in support of the national Regional Haze Rule indicate that use of 0.7% low-sulfur coal reduces SO 2 emissions by

over 70%. 361 The U.S. Energy Information Administration states that low-sulfur coal may reduce

SO 2 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 regula tions. 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, F lint 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 si nce 2009 has been in the rang e of 0.25 – 0.30%; but the BART analyses relied on by EPA did not identify, much less evaluate th e use of low-sulfur coal as

BART. 364 In addition, although Entergy id entified DSI as an available control technology in its BART Five-Factor analysis, that control t echnology 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 contro l 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 di d not satisfy the requirements of the BART guidelines, and thus EPA's Proposed FIP shoul d be withdrawn. North Dakota v. EPA, 730 F.3d 750, 764 (8 th Cir. 2013) (EPA BART determination v acated 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 we re identified and evaluate d. Although EPA modeled numeric visibility improvements from the control techno logies that were eval uated using the CALPUFF model, EPA did not explain how it weighed those vi sibility impacts. At most, EPA stated for a particular numerical dv improvement that it wa s “considerable” or “significant,” however, EPA did not explain how it balanced t hose 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, att ached 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 Wh ite Bluff nor the Flint Creek five-factor analyses identifie d or considered low-sulfur coal as an available t echnology. 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 contro l technologies. Instead EPA appeared to simply determine whether a particular control technology was “cost-effective,” and then to ch oose 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 cert ain 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 CALPU FF model as discussed elsewhere in Nucor’s

comments.

Response: We disagree that the CAA or the RH re gulations require EP A to consider and evaluate every available re trofit technology in evaluati ng BART. The CAA requires the following in evaluating BART:

[I]n determining best available re trofit technology the State (or the Administrator in determining emission limitations which reflect such technology) shall take in to consideration the co sts of compliance, the energy and nonair quality environmen tal impacts of compliance, any existing pollution control technology in use at the source, the remaining useful life of the source, and the degr ee of improvement in visibility which may reasonably be anticipated to re sult 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 techno logy available, the costs of compliance, the energy and nonair quality environmen tal 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 regul ations require that every singl e 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 an alysis that reflects a comprehensive list of available technologies. It is no t necessary to list all permutations of

available control levels that exis t for a given tech nology— 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 Guidelin es provide the following:

If you find that a BART source has cont rols already in pl ace which are the most stringent controls available (not e 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 c onsists of the most stringent controls available, then there is no need to complete the remaining anal yses in this section (emphasis added). 369

As noted by the commenter, our FIP proposal di d rely on the BART anal yses provided by White

Bluff and Flint Creek. The BART analyses provided by White Bluff 370 and AEP Flint Creek 371
did identify DSI as an available control opti on. However, the remainder of each company’s analysis focused only on wet FGD and dry F GD. 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 e ffective control option. The companies themselves chose to eliminat e 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 consid er this less stringent control op tion in our analysis. We noted in our proposal that we concurred with the appr oach 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 SO 2 BART is an emission limit of 0.06 lb/MMBtu consistent with the installation of dry scrubbi ng technology, there was no need to evaluate DSI, which is a less stringent contro l option. This is consistent with the CAA, the Regional Haze Rule, and the BART Guidelines.

Additionally, the BART analysis provided by AEP Flint Creek stat ed that the retrofit controls

examined are limited to add-on controls that eliminate SO 2 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 SO 2 controls evaluated are limited to add-on controls that eliminate SO 2 after it is formed, as Units 1 and 2 currently use a low sulf ur fuel and thus would not achieve significant additional reductions through altern ative 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 Bluf f Steam Electric Station Redfield, Arkansas (AFIN 35– 00110),” dated October 2013, prepared by Trinity Consultant s 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 Southwes tern 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 Powe r 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 reflec ted in the baseline scenario for these units. Furthermore, while a facility can vo luntarily agree to switch to a di fferent type of coal to comply with BART requirements, we cannot dictate to faci lities which coal they should burn as a control

measure. 375 Therefore, we disagree with the claim th at our BART analysis is flawed because it

did not evaluate DSI or othe r 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 BA RT determination was not, as the commenter contends, because we did not consider every re trofit control technology av ailable in the BART analysis.

To the extent the commenter suggests that our Ar kansas 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. Th e commenter makes the al legation that in our Regional Haze FIP for Montana, we approve d the use of low sulfur coal as SO 2 BART for PPL Corette even though DSI was determined to cost $991/ton SO 2 and found to be cost-effective.

This is incorrect. In that ac tion, we stated the following:

We identified that three flue gas desulfurization (FGD or “scrubbing ‘) technologies as available control technologies for c onsideration at Corette. Two of these options, dry sorbent in jection (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-s witching options as Corette already burns very low-sulfur coal. 77 FR at 24043.

In our Montana RH FIP action we did not eval uate the use of low sulfur coal in the SO 2 BART evaluation for Corette. We evaluated two type s of dry scrubbing technologies and a wet scrubbing technology. In that acti on, we found the average cost-e ffectiveness of DSI at PPL Corette to be $3,940/SO 2 ton removed and not, as the commenter contends, $991/SO 2 ton
removed. 376 We also found LSD to have an average cost-effectiveness of $5,442/SO 2 ton removed and LSFO to have an average cost-effectiveness of $6,365/SO 2 ton removed. 377 We found that the visibility improvement at the Cl ass I area with the greatest improvement is

374 See “Revised BART Five Factor Analysis White Bluf f Steam Electric Station Redfield, Arkansas (AFIN 35– 00110),” at 5-1, dated October 2013, prepared by Trinity C onsultants 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 SO 2 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 sour ces currently burn fuel oil with a sulfur content greater than 0. 5%, compliance with the BA RT requirement will likely necessitate switching to

fuel oil with lower sulfur content. Howe ver, as discussed in our proposal, our SO 2 and PM BART determinations are based on a BART analysis provided by AECC Bailey and McClellan in which the so urces voluntarily accepted a

limit on the sulfur content of the fu el 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 agai nst the anticipated visibility impacts at Corette, but found that

the cost of SO 2 controls is not justified by the visibili ty improvement, and determined that BART

for SO 2 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 wa s 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 abov e, we believe that our analyses are still in accordance with the CAA, the RH rule, and our BART Guidelines. We also note that the SO 2 controls we evaluated for Flint Creek Unit 1 a nd White Bluff Units 1 and 2 were more costeffective (i.e., lower $/ton removed) and are expe cted to have greater visibility improvement compared to the SO 2 controls we evaluated for Corette in the Montana FIP proposal, which we ultimately determined were not BART. For exampl e, in our Arkansas FIP proposal we found that the average cost-effectiveness of NID at Flint Creek Unit 1 was $3,845/SO 2 ton removed, and that the visibility improvement at the Class I ar ea with the greatest improvement is expected to

be 0.615 dv. 380 As discussed in our final rule and el sewhere 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/SO 2 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 scrubbe rs are estimated to cost $2,421/SO 2 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. 382 The costs on a dollar per ton removed basis are lower and the pr ojected visibility improvement is higher for the controls we eval uated in our Arkansas FIP compared to the SO 2 controls we evaluated and determined were not BART for Corette in our Montana FIP action. Therefore, we see nothing in our Montana RH FIP th at 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 progr ess analysis. Specifically, the co mmenter contends that we did not explain how we weighed the visibility improveme nt of controls versus the cost and the other statutory factors. This is not true. Our FIP proposal discusse d in detail how we considered and weighed the statutory factors, a nd our rationale for determining wh at control option is BART. In particular, we carefully consider ed whether the visibility improve ment expected from controls

warranted the costs in terms of cost-effectiveness. When consid ering one control option versus the next most stringent option (i.e., wet scr ubbers 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 th ere 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 SO 2 emissions

reduction achievable with a NID scrubber. [Sierra Club et. al. (0171) p. 13-14] Sierra Club et.

al. stated that while th ey support EPA’s proposed SO 2 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 SO 2 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 re gulations, to determine BART, EPA must evaluate the highest control efficiency achievabl e by a particular technology. 42 U.S.C. § 7491(b)(2)(A) (requiring “ best available retrofit technol ogy”) (emphasis added); 40 C.F.R. Part 51, Appendix Y (“in analyzing th e technology you take in to account the most stringent emission control level that th e technology is capab le 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 technol ogy 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 retrof its at existing sources in the source category.”). As demonstrated in the att ached Stamper Report, AEP’s analysis (relied on by EPA) fails to consider the hi ghest control efficiency of a NI D scrubber. Several sources of

information demonstrate that EPA has not based its BART determination on the highest control efficiency for this technology, in cluding: industry experience and ve ndor guarantees that indicate

that NID scrubbers can achieve lower emi ssion limits than .06 lb/MMBtu; AEP’s own

discussions with vendors and its representations to the Arkans as Public Service Commission (“APSC”); and flaws in AEP’ s calculations of baseline SO 2 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 fr om recent 30-day average SO2 emission rates at

Flint Creek and 94.8% SO2 removal from the maxi mum annual average SO2 rate that occurred during 2001. Id . at 13. According to EPA, AEP’s “discuss ions with vendors” indicated an outlet

achievable SO 2 emission rate of 0.06 lb/MMBtu with NID technology, which reflects 92% SO 2 removal from 0.75 lb/MMBtu, the baseli ne 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 emi ssion 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 th at AEP represented to the APSC that NID technology can attain 98% removal:

[NID technology] can attain higher levels of SO 2 reduction, with vendor guarantee removal rates of 98% compared to maximum removal rates of 95% for [spray dryer absorbers] a nd other [dry FGD] technologies....The [dry FGD] system that is proposed for installation at Flint Creek will

remove 95% of the SO 2 in the flue gas to meet anticipated emission limits for the design basis fuel. 383

Moreover, AEP’s assumed SO 2 emission limit is inconsistent w ith its vendor’s guarantee that the

NID scrubber would meet a limit of 0.055 lb/M MBtu. Stamper Report at 8. Since such a guarantee is likely based on a short-term stack te st, rather than a 30-da y rolling average, the technology could likely achieve a lo wer limit over a longer-term period. Id

.

Finally, flaws in calc ulating baseline SO 2 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 SO 2 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 SO 2 emissions. See 40 C.F.R. Part 51, App. Y, § IV.D.4.c. Using this re vised 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 technol ogy 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 th e 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 string ent control level that the technology is capable of achieving should be considered. 385

We acknowledge the information provided in th e comment as well as in the referenced attachments regarding the level of control efficiency that has be en demonstrated and guaranteed by vendors for NID installation at other E GUs. We acknowledge that the lowest SO 2 emission guarantees for a NID system are 0.04 lb/MMBtu. Th e comment cites to proposed NIDs at Homer City 1 & 2 (2016), Indian River Unit 4 (2011), Br ayton 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 Po wer 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 f acilities and learned that only Indian River Unit 4 and Brayton Point Unit 3 are curr ently operating. We downloaded the SO 2 CEMS data for

these two facilities from CAMD, computed 30-day B OD averages, achieved SO 2 control efficiencies, and determined the maximum 30-day B ODs. This analysis is present in our final

docket. 386 Neither of these units is performing at a level of 98% SO 2 control or 0.04 lb/MMBtu.

Indian River Unit 4 has achieved only 86% SO 2 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/M MBtu. Brayton Point Unit 3 has achieved 94%

SO 2 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 SO 2 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 “pol ishing” scrubbers on circulating fluidized bed boilers, which are not similar boiler t ypes. As explained by the Guidance, similar sources with the control technology already in pl ace should be used to evaluate what level of control can be achieved at the source. Further, Flint Creek Unit 1 burns low sulfur wester n 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 Spurlo ck Unit 4 burns high sulfur bituminous coal and switchgrass. 389 The Guidance provides us with the di scretion to consider “special circumstances pertinent to the specific source unde r review.” In this case, we must consider the different coals being utilized by each respectiv e 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 availabl e to us demonstrating th at 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 pe rformance 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 perfor mance 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 SO 2 Averages.xlsx,” found in the docket for our rulemaking.

387 Burns & McDonnell, Indian River Unit 4, http://www.bu rnsmcd.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/pennener gy/2014/01/brayton-point- coal-fired-power-plantconfirmed-for-shut-down-by-2017.html.

389 http://www.ekpc.coop/pressreleases/2009%20press%20 releases/2009-04-01_Spurlock4_commercial_start.pdf205 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 SO 2 emission rate of 0.06 lb/MMBtu for NID.

There is no information available to us to subs tantiate 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 ope rating-day rolling aver age 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 a ttain 98% removal of SO 2 emissions, AEP communicat ed to us that the testimony before the Arkansas Public Serv ice 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 emi ssion rate and project ed unit performance. 391 AEP also explained that the outlet emission rate ev aluated 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 whethe r 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 ope rating-day rolling aver age 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 NO X controls at AEP Flint Creek Unit 1. [Sierra Club et. al. (0171) p. 15-16]

Sierra Club et. al. stated that EPA proposes that NO X BART for Flint Creek Unit 1 is an

emission limitation based on the installation of LN B/OFA. Such controls would cost-effectively achieve some emissions reductions and, as such, represent the minimum th at 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 di scusses 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 Repor t at 15-27. Ms. Stamper’s analysis shows that

these controls are even more efficient at NO X 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 gua rantees 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 Amer ican 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 NO X reductions achievable by these technologies. AEP analyzed SCR control efficiency alone (without LNB/OFA) to meet a NO X limit of 0.07 lb/MMBtu. This reflects 77% NO X removal efficiency from AEP’s assumed 0.31 lb/MMBtu baseline NO X emission rate. The

assumed 0.07 lb/MMBtu NO X emission limit does not reflect the maximum degree of NO X reduction achievable with this technology. Stamper Report at 16.

First, EPA’s analysis for both SCR and SNCR should have begun with the assumed NO X control rate achieved by LNB/OFA of .23 lb/MMBt u. Stamper Report at 15, 23. AEP could install SCR or SNCR concurrently with LNB/OFA a nd the combination of these controls improves their cost effectiveness. AEP’s analysis of SN CR 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 routinel y designed to achieve gr eater than 90% control and all major SCR catalyst vendors can guarantee at least 90% efficiency for SCRs burning coals with a wide range of proper ties, including from low sulfur Powder River Basin (“PRB”) subbituminous coal. Stamper Report at 16-19. Furthe r, permitting agencies have required lower

NO X limits than the 0.07 lb/MMBtu based on op eration 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 co ntrol” and imposed a

NO X 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 res ponse to comments document for its NO X BART finding for the San Juan Generating Station, EP A found significant support in act ual emissions data to support its finding that a 0.05 lb/MMBtu NO X limit was achievable on a 30-boiler operating day average basis, including a study that iden tified 25 units that are achieving NO X 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: Semino le Units 1 and 2 (ach ieving 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 (a chieving 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 em ission rate of 0.07 lb/MMBtu at Flint Creek, which reflects only 77% NO X removal across the SCR system, is inconsistent with the higher

levels of NO X 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% NO X control from the 0.23 lb/MMBtu emission rate expected with the LNB/OFA. Id . at 23.207 Response: We disagree with Sierra Cl ub’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, ener gy and nonair quality environmental impacts, pollution controls in us e 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 ha ve begun with the assumed NO X 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/MMB tu. We agree with the Sierra Club and Ms. Stamper on this point. For SNCR controls on Flin t 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 w ith another column added to include these

corrections:

Parameters/Costs Equation AEP SWEPCO EPA

Boiler design capacity, mmBtu/hr (Q B ) Q B 6324 6324

Total operating time (t op , hrs/yr) t op = CF total × 8760 hrs/yr 7752 7752

Total Capacity Factor (CF total ) CF total = CF plant × CF SNCR 0.92 0.92

Plant Capacity Factor (CF plant ) 2 0.92 0.92

SNCR Capacity Factor (CF SCNR ) 3 CF SNCR = t SNCR /365 1 1

Assumed NOx removal efficiency ( η NOx ) 4 35% 13.04%

Uncontrolled NOx rate (NOx in, lb/MMBtu) 5 0.33 0.23

Electricity Cost (Cost elect , $/kwh) 6 $0.05 $0.05

Water Cost (Cost water , $/gal) 7 $0.00362 $0.00362

Coal Cost (Cost coal , $/MMBtu) 8 $2.50 $2.50

Coal HHV (Btu/lb) 9 9,000 9,000

Cost of Ash Disposal (C ash , $/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 Index 11

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) × Q B × ((2375 MMBtu/hr/Q B )^0.577) × (0.66 +

0.85 η NOx ) × (CI 2011 /CI 1998 ) $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 $111,258
Inventory Capital (H) 12 H = Vol reagent (gal) × Cost reagent ($/gal) $76,102 $8,957

Cost reag , 50% Urea solution ($/gal) 13 1.54 1.54

Volume of Reagent Tank (Vol reagent (gal)) Vol reagent (gal) = q sol x days of reagent supply × 24 hr/day 49,417 5,817

Urea solution volumetric flow rate (q sol , gal/hr) 14 q sol = (m sol x 7.481 gal/ft 3 )/ ρ reagent 147.07 17.31

Mass flow rate of urea solution (m sol , lb/hr) 15 m sol = m reagent /C ureasol 1,395.84 164.30

Mass flow rate of reagent (m reagent , lb/hr) 16 m reagent = (NOx in x Q B x η NOx × NSR x

M
rea g en t )/(M NOx x SR T ) 697.92 82.15

Normalized Stoichiometric Ratio (NSR) NSR = ([2 × NOx in + 0.7] × η NOx )/NOx in 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 = q sol × Cost reag × t op $1,755,781 $206,662

Annual Electricity Cost (L) L = P × Cost elect × t op $58,064 $18,344

Power (P, kW) P = (0.47 × NOx in × NSR × Q B )/9.5 149.80 47.33

Annual Water Cost (M) M = q water × Cost water × t op $18,775 $2,210

Water flowrate for SNCR system (q wate r , gal/hr) 17 q water = (m sol / ρ water ) × [(C ureasolstore d /C ureasolin j ) - 1] 669.06 78.75

Annual Δ Coal Cost (N) N = Δ Coal × Cost coal × t op $109,558 $12,895

Additional coal required ( Δ Coal, MMBtu/hr) 18 Δ Coal = (Hv × m reagent × [(1/C ureasolinj ) - 1])/10 6 Btu/MMBtu 5.65 0.67

Annual Δ Ash Cost (O) O = ( Δ Ash × Cost ash × t op )/2000 lb/ton $1,643 $193

Additional ash generated ( Δ Ash , lb/hr) 19 Δ Ash = ( Δ Coal × ashproduct × 10 6 Btu/MMBtu)/HHV 47.11 5.54

Direct Annual Costs (DAC)/Variable O&M DAC = J + K + L + M + N + O $2,050,684 $325,551209 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 ha ve added another column with our corrections to (1) the assumed

NO X removal efficiency ( η NO X ), (2) the uncontrolled NO X rate (NOxin, lb/MMBtu), and (3) a recalculation of the capital rec overy 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-effectivene ss calculation as presente d in its BART analysis, 395 along with our

corrections. The first table is AEP SWEPCO’s co st-effectiveness calculati on. 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 ta ble, we carry those co rrections 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 6-3.210AEP SWEPCOControl TechnologyBaselineNOXEmissionRate (tpy)ControlledEmissionLevel(lb/MMBtu)ControlledEmission Rate(NOX tpy)AnnualEmissionsReductions(NOX tpy)Capital Cost($)AnnualCapitalCost ($.yr)AnnualFixedO&M($/yr)AnnualizedVariableO&M ($/yr)TotalAnnualCost ($/yr)AverageCostEffectiveness($/ton)IncrementalCostEffectiveness($/ton)LNB/OFA5,120.27 0.23 4,294.65 825.62 $16,000,000 $1,289,382 $240,000 $132,364 $1,454,621 $1,762 -LNB/OFA/SNCR5,120.27 0.20 3,771.82 1,348.45 $16,000,147 $1,398,940 $240,000 $133,033 $4,177,782 $3,098 $5,209AEP SWEPCO (tons reduced and total annl cost corrected)Control TechnologyBaselineNOXEmissionRate (tpy)ControlledEmissionLevel(lb/MMBtu)ControlledEmission Rate(NOX tpy)AnnualEmissionsReductions(NOX tpy)Capital Cost($)AnnualCapitalCost ($.yr)AnnualFixedO&M($/yr)AnnualizedVariableO&M ($/yr)TotalAnnualCost ($/yr)AverageCostEffectiveness($/ton)IncrementalCostEffectiveness($/ton)LNB/OFA5,120.27 0.23 3,798.91 1,321.36 $16,000,000 $1,289,382 $240,000 $132,364 $1,661,746 $437 -LNB/OFA/SNCR5,120.27 0.20 3,303.40 1,816.87 $23,124,235 $1,961,859 $240,000 $2,183,048 $4,384,908 $2,413 $5,496EPA (tons reduced, total annl costs, control level and control efficiency corrected)Control TechnologyBaselineNOXEmissionRate (tpy)ControlledEmissionLevel(lb/MMBtu)ControlledEmission Rate(NOX tpy)AnnualEmissionsReductions(NOX tpy)Capital Cost($)AnnualCapitalCost ($.yr)AnnualFixedO&M($/yr)AnnualizedVariableO&M ($/yr)TotalAnnualCost ($/yr)AverageCostEffectiveness($/ton)IncrementalCostEffectiveness($/ton)LNB/OFA5,120.27 0.23 3,798.91 1,321.36 $16,000,000 $1,289,382 $240,000 $132,364 $1,661,746 $1,258 -LNB/OFA/SNCR5,120.27 0.20 3,303.40 1,816.87 $21,683,091 $1,747,362 $240,000 $457,915 $2,445,277 $1,346 $1,581211 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 incrementa l cost effectiveness of SNCR + LNB/OFA over LNB/OFA alone is $1,581/ton. We re-apply the BART five factor s, 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 resulti ng 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 NO X control level of 0.04 lbs/MMBtu, using the IPM SCR cost algor ithms. Ms. Stamper makes a case that because her resulting $/ton figures are in line with ot her required SCR installations, the Flint Creek facility should similarly be requi red 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 applie d to the Flint Creek facility. However, we have reviewed the information Ms. Stamper presents a nd conclude, as we did in our New Mexico FIP, that it supports a 30 Boiler Operating Day (BOD) NO X average of 0.05 lbs/MMBtu for a SCR installation at the Flint Creek facility.

Second, as we indicate in Table 44 of our TS D 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/MMBtu 396 , we estimate that the resulting visi bility improvement at Caney Creek would be no higher than 0.26

dv. 397 Even accepting Ms. Stamper’s SCR cost an alysis of $3,511/ton (which would be higher were it revised using a controlled NO X rate of 0.05 lbs/MMBtu), we do not consider the relatively small visibility improvement to be worth the cost of th e SCR installation.

Therefore, we are requiring F lint Creek Unit 1 to meet an em ission limit of 0.23 lb/MMBtu on a 30 boiler-operating-day rolling average ba sed on LNB/OFA to comply with the NO X 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 SO 2 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 woul d also result in an increase in visibility benefit of only

4%.212 of 0.06 lb/MMBtu on a 30-day rolling average ba sed on the operation of a dry scrubber or another technology. 80 Fed. Re g. at 18,972-73. Entergy’s SO 2 BART analysis for White Bluff

evaluated the control e fficiencies of wet and dry scrubbers. Entergy di d not consider a NID technology dry scrubber. As demonstrated in Se ction I.A.1.b of the Sierra Club’s comments, both wet and dry scrubbers (including circulatin g dry scrubbers such as NID technology) can

achieve SO 2 removal levels in the 95- 99% range. Entergy should ha ve 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 ach ievable with this technology. Ms. Stamper’s cost analysis assumes a more-appropriate .04 lb/MMB tu limit for dry scrubbers, including a NID

scrubber.

Response: We agree that the Alstom NID circul ating dry scrubber is a promising SO 2 control option. However, as we discuss elsewhere in this document, the limited available SO 2 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 SO 2 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 proce dures discussed in these guidelines is the evaluation of multiple contro l technology alternatives which result in essentially equivalent emissions. It is not our intent to encourage evaluation of unnecessarily large number s of control alternatives for every emissions unit. Consequently, you should use judgment in deciding on

those alternatives for wh ich 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 th e less costly of these options. You should narrow the scope of the BART anal ysis in this way only if there is a negligible difference in emissi ons and energy and non-air quality environmental impacts between control alternatives. 398

As the BART analysis for White Bluff Units 1 a nd 2 evaluates semi-dry scrubbers and assumes a control efficiency of 0.06 lb/MMBtu, which is th e 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 theoreti cally capable of achieving the same or better SO 2 control efficiency as the SO 2 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 mainte nance costs, low power consumption, and high removal of hazardous pollutants for about the sa me 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, in cluding NID in our evaluation would not have changed our proposed SO 2 emission limits. We further addre ss the emissions limit achievable through the use of NID scrubbers elsewhere in this document.

Comment: EPA’s proposal did not e valuate the maximum degree of NO X emissions reductions achievable with LNB/SOFA pl us 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 NO X 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 re ductions is evaluated, SCR is BART for White Bluff. Entergy assumed that installation of S CR along with LNB/SOFA at White Bluff Units 1

and 2 could achieve an em ission rate of 0.055 lb/MMBt u. Stamper Report at 35. A NO X limit of

0.055 lb/MMBtu reflects a 63% NO X removal with SCR, with th e LNB/SOFA alone achieving a

NO X limit of 0.15 lb/MMBtu. Id . at 40. This assumption (which EPA relied on) unlawfully fails to reflect the maximum degree of NO X emissions reductions achiev able with this control

scenario. See 42 U.S.C. § 7491(b)(2)(A) (requiring “ best available retrof it technology”) (emphasis added).

As demonstrated in Section I.A.2.a of the Si erra Club et. al.’s comments, SCR systems are routinely designed, with vendor guarant ees, to achieve greater than 90% NO X removal. An emission limit of 0.04 lb/MMBtu at the White Bluff units, which reflects 73% removal from the

0.15 lb/MMBtu NO X rate achieved with the LNB/SOFA alon e, is easily achievable by pairing an SCR with LNB and SOFA. Stamper Report at 39-40.

Entergy’s air dispersion modeling (which EPA re lied 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 elsewh ere in the Sierra Club et. al.’s comments, Entergy

relied on the 2009-2011 NO X baseline which reflected the period of lowest NO X emission rates at White Bluff Units 1 and 2. Second, Entergy fail ed to evaluate LNB/SOFA plus SCR at an emission limit of 0.04 lb/MMBtu, which is readily achievable with these c ontrols. Accordingly, EPA should re-model the visibility benefits of th ese controls using more appropriate emissions reflective of baseline and post-control emissions.

Response: As we discuss in the section of this docume nt where we discuss co st 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) NO X average of 0.05 lbs/MMBtu for a SCR insta llation at the White Bluff facility. We disagree with Ms. Stamper that it suppor ts 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 corre ctions to Entergy’s NO X BART cost analyses, we did not criticize its

choice of a SCR NO X emission limit of 0.055 lbs/MMBtu. Entergy’s SCR NO X emission rate of214 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 peri od. Entergy confirms this on page 6-3 of its BART analysis. 400 Our New Mexico FIP decision to whic h Ms. Stamper cites, is based on a 30 BOD compliance period. As we discuss in our Ne w 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 al l 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/MMB tu average to be essentially equivalent to, or potentially more stringent than the 0.05 lb/MMBtu 30 BOD av erage we required in our New Mexico FIP, which forms the bulk of Ms. Stampe r’s support. Thus we (1) disagree with Ms. Stamper that SCR for White Bluff shoul d be evaluated on the basis of a NO X rate of 0.04 lbs/MMBtu, and (2) we believe Ente rgy’s use of a 30 day calendar NO X rate of 0.055 lb/MMBtu

in its evaluation of SCR was r easonable (although as discussed el sewhere, we had other issues with Entergy’s White Bluff BART analyses). Th is renders moot Ms. Stamper’s contention that Entergy’s air dispersion modeling (which we reli ed 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 NO X BART evaluation, Ms. Stamper al so argues that Entergy’s 2009-2011

baseline maximum 24-hour NO X emission rates of 3,001.4 lb/hr for Unit 1 and 3,527.4 lb/hr for Unit 2 were not appropriate for us e in the BART analysis becaus e they reflected the period of

lowest NO X emission rates for the units and therefor e “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 emission s from any given year or years, only that, as Ms. Stamper acknowledges, the “baseline emissions rate should represent a realistic depiction of anticipated annual emi ssions for the source.” 402 We believe it was reasona ble to select baseline

maximum 24-hour NO X emission rates that reflected the inst allation of controls and a change in operations after the neural network was installe d in 2006, which eliminates from consideration the highest NO X 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 as sessments for additional NO X controls

Comment: EPA was not required to consider DSI and low-sulfur coal as control options for White Bluff and Flint Creek because EPA prop osed 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 NO X 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 fluctu ations 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 th e 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. Specificall y, the BART Guidelines state:

If you find that a BART source has cont rols already in pl ace which are the most stringent controls available (not e 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 c onsists of the most stringent controls available, then there is no need to complete the remaining anal yses 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 St ation 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 anal yses 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 F lint 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 th at consists of the mo st stringent controls available,” and thus “there is no need to complete the remaini ng analyses in this section.” 40 C.F.R. Part 51, App. Y § (IV)(D)(1)(9). Under th e BART Guidelines, EPA was not required to analyze SO2 controls, such as lo w-sulfur coal and DSI, which ar e 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 t echnically infeasible technology for Power

Boiler No. 1. [Domtar (0161) p. 8-9] Domtar stated th at assuming EPA proceeds with BART for the Ashdown Mill, the Mill conceptua lly agrees with the proposed NO X 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 determinati on that for Power Boiler 1 the installation of FGR, LNB, Ultra Low NO X Burners (ULNB), OFA, Methane-de- NO X and SCR are technically

infeasible. EPA’s review of SNCR concludes that the technology is feasib le but the high costs on a dollar per ton of NO X removal basis 403 does not justify the pur ported small visibility improvement ranging from 0.061 dv to 0.136 dv at any single Class 1 ar ea. This level of “improvement,” if it even exists, would be impe rceptible 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 reasona bly anticipated to occur.

The Ashdown Mill disagrees with EPA’s determin ation that SNCR is a feasible technology for Power Boiler 1. We base our conclusion on a study 404 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 th e pulp and paper making operations, the boilers require co ntinuous adjustment of fuel fi ring 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 ta ke place. Since optimal furnace temperatures cannot be consistently maintained, th e urea injection needed for reducing NO X emissions will result in excess ammonia being present. This am monia will combine with chlorides and sulfides in the combustion gas producing increased corrosi on on downstream metal and heat surfaces. In addition, it is known that chlorides in the gas stre am will combine with ex cess ammonia to create condensable PM2.5 particles in the flue gas, th ereby increasing PM2.5 emissions. With respect to Power Boiler 1, SNCR is not a technically feasible control tec hnology, 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 NO X BART emission limit

of 207.4 lb/hr for Power Boiler No. 1.

We do not believe the commenter has provided su fficient information to demonstrate that SNCR is a technically infeasible control technology for Power Boile r No. 1. The BART Guidelines provide the following regarding the determination of technical feasibility:

“Control technologies are t echnically feasible if either (1) they have been installed and operated successf ully for the ty pe of source

under review under similar conditio ns, or (2) the technology could be applied to the source under review. Two key concepts are important in determining whethe r 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 NO X removed at 20% removal efficiency and $7,640 per

ton of NO X removed at 45% removal efficiency and $7,640 per ton of NO X removed at 32.5% removal efficiency.

404 International Applied Engineerin g, Inc. Observations of Charte red Steam Rates and Furnace Exit Gas Temperature.217 below, a technology is considered “available” if the source owner may obtain it through commercial ch annels, 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 applicab le is technically feasible. 405

The NSR permit for the Temple-Inland Kraft Liner board Mill, located in Orange County Texas, requires that the bark boiler inst all and operate SNCR to achieve a NO X emission limit of 0.166 lb/MMBtu based on a 30 day rolling average. Li ke 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 Temp le Inland Kraft and Power Boiler No. 1 at the Domtar Ashdown Mill. For example, similar to Do mtar’s Power Boiler No. 1, the bark boiler at Temple Inland Kraft is permitted to burn, among ot her fuel types, bark/wood biomass, natural gas, and tire-derived fuel. The Temple Inland Kr aft 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 be lieve that this type of technology meets the technical feasibility definition under the BART Guid elines for power boilers of this type. But we acknowledge Domtar’s concerns that because Po wer Boiler No. 1 is a high load swing boiler, there is uncertainty as to the level of NO X control that SNCR can achieve at this boiler on a longterm basis, including whether optimal furnace temp erature can be consistently maintained to achieve appreciable NO X control. Additional information specific to Power Boiler No. 1 would be necessary to support the claim that SNCR ope ration at this power bo iler would not achieve appreciable NO X emissions reductions on a long-term ba sis. However, we are finalizing our

determination that NO X BART for Power Boiler No. 1 is an emission limit of 207.4 lb/hr, which is a reflection of the boiler’s ope ration at the baseline emission rate and does not require SNCR installation. Therefore, th e 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 NO X control on Power Boiler 2 are not technically feasible. [Domtar (0155) p. 14-15] Domtar stat ed that it agrees with EPA’s

determination that MdN for NO X control is not technically feasible. The Ashdown Mill also agrees with EPA’s assessment the installati on of SNCR on Power Boiler 2 is not appropriate.

EPA concludes it is not a ppropriate due to the NO X 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 observat ions in a study conducted on Po wer Boiler 2 by International Applied Engineering 406 (see Appendix A to Domtar’s commen ts). The study concludes that with the large fluctuations in steam demand inhere nt in the pulp and paper making operations the boilers require continuous ad justment 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 usuall y 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 NO X emissions will either be too much or too little. When too little, NO X removal will be less than projected; when too much, excess ammonia slip will occur. The excess ammoni a 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 stre am will combine with ex cess 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 N o. 2. While we believe that SNCR may be a technically feasible control tec hnology for similar power boilers , as discussed in our proposal, we believe Domtar provided sufficient informati on to demonstrate that because of the wide variability in steam demand and wide range in furnace temperature observed at Power Boiler No. 2, the NO X 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 NO X 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 Ashdow n Mill is undergoing a major re-purposing project to realign the Mill’s ma nufacturing processes with the ch anging 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 flu ff 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 reconfigurati on 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 equipm ent and other Mill process systems. Most significantly for purposes of BART involvi ng 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, th e final state of Mill operations is anticipated to require changes in steam production from Powe r Boiler 1 and Power Boiler 2. In addition, the

407 80 FR 18986.219 Mill is also initiating other projects that will im prove process efficiencies and may also affect steam production needs. The machine conversio n portion of the re-purposing project is scheduled to start up in the thir d quarter of 2016. The next phase will be a shakedown period in 2017 where the Mill will obtain a greater underst anding of the fluff pul p production process and the Mill’s steam needs. Following this shakedow n, 2018 will be the first year of full production.

Key to understanding steam demand needs and corre spondingly the changes in the use of Power Boilers 1 and 2 is running the boilers through bot h the shakedown period and first full production year. This schedule allows the Mill to determin e the effects of seasonal weather changes (winter conditions) and the inherent va riability that occurs when operating (and learning) a new production process. The Mill needs to have sufficien t time to re-balance the Mill operations in its newly reconfigured state. Fo r that reason, data from 2017 and 2018, including the winter seasons, is essential for the Mill in making th e decision as to whethe r 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 ofthe 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 Clea n Air Act rules). In addition, both Power Boilers 1 and 2 share a common bark feed system. Changes in steam need s, changes in utilization or retirement of

Power Boilers 1 or 2 will affect these interrelated systems. As suming EPA proceeds in finalizing BART for the Ashdown Mill, a 5-year complia nce schedule for achieving the SO2 and NO X BART requirements for Power Boiler 2 is essential, given the integrated nature of the Mill and the complexities resulting fr om the re-purposing project.

For BART compliance plan purposes, the first un known that needs to be resolved (once the project is fully completed and operating duri ng 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 inte rmittently 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 boile r 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, change s involving the NCG gases, an inte gral 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 environmen tal obligations with the practical management, engineering and financial issues associated with this and th e Mill’s re-purposing project.220 It is against this backdrop that the Domt ar 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 SO 2 and NO X

 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 Po wer Boiler 2 should be defined as a Mill operating day

 Express the SO 2 BART limit for Power Boiler 1 in an al ternate form of lb/day instead of

lb/hr

 Modify the stack testing frequency fo r demonstrating compliance with the NO X BART limit for Power Boiler 1 to 5 years

 Adjust the SO 2 BART limit for Power Boiler 2 and expr ess in an alternate form of lb/hr

instead of lb/MMBTU

 Adjust the timeline for adopting a FIP to a llow ADEQ to develop and obtain approval of

a BART SIP for the Mill.

[0152-6] One public hearing commenter noted th at in late 2004, Domtar announced a major project that will convert a pape r 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 presen ted by the commenter regarding the repurposing project the Domtar Ashdown Mill is currently undergoing and how this may result in changes in steam needs, cha nges in utilization, or retireme nt of Power Boilers 1 and 2. We

address elsewhere in this document the comm enter’s detailed comments on each of the key

issues listed.

Comment: [Domtar (0161) p. 3-5] Domtar stated th at 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 Implem entation Plan (SIP). Dual regulation over Power Boilers 1 and 2 (key components of the M ill) 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 a ffect future Mill operations.

Assuming EPA proceeds with BART for the Ashdow n Mill, we believe EPA should work with ADEQ to convert EPA’s current FI P approval process into an a pproved 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 both221 Arkansas under the SIP and EPA under the FIP. Also, given the reques ted 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 Report 408 shows Arkansas as meeting or exceeding its glide path so additional time to deve lop a SIP will not affect Arkansas’ ability to meet its 2018 reasonable progress goals.

Response: As we note in our final rule, the State reta ins 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 th at 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 FI P 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 Admini strator disapproves a state implementation plan

submission “unless the State corre cts the deficiency, and the Admi nistrator approves the plan or plan revision, before the Administrator promul gates such Federal implementation plan.” Our partial approval and partial disapproval of th e Arkansas RH SIP was published in the Federal Register on March 12, 2012 and the ru le 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 C AA for EPA to further delay our action for the reasons provided by the commen ter. We are operating under a court-ordered deadline to take final action to promulgate a FI P or approve a SI P 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 in clude an alternate compliance option for

SO 2 BART for Power Boiler 1 in the event the bo iler is converted to na tural 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-configuratio n 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 SO 2 BART limit will be unnecessary along with the associated monitoring, recordkeeping and reporting requirements for the SO 2 BART limit. The Ashdown Mill is

408 State of Arkansas State Implementa tion Plan Review for the Five-Yea r 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 ru le an alternate compliance option that removes

all of SO 2 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 natu ral gas, an alternate compliance option needs to be developed to allo w compliance to be based on the use of AP-42 emission factors and fuel use records. Requirements for NO X testing need to be removed. If Power Boiler 1 is retired, there is no need to retain the NO X BART limit and the associated monitoring, recordkeeping and re porting requirements for the NO X BART limit. An alternate compliance option should address this retirement scenario as well.

Response: We proposed an SO 2 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 se parate comment. We prop osed to find that to demonstrate compliance with its SO 2 BART emission limit, the facility was required to use a site-specific curve equation (provided to us by the facility) to calculate the SO 2 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 SO 2 emissions from Power Boiler No. 1 when combusting fuel oil, the facility must assume that the SO 2 inlet is equal to the SO 2 being

emitted at the stack. 412 In our proposal we invited public comment specifically on the issue of whether our proposed method of demons trating compliance is appropriate.

We note that we became aware that Power Boiler N o. 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 SO 2 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 th e 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 curren tly 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 SO 2 emissions, render it appropria te to provide the facility with flexibility in demonstrating compliance with the SO 2 emission limit. Therefore, in addition to the method we proposed for demonstrating compliance with the SO 2 BART emission limit for Power Boiler No. 1, we are also finalizing one al ternative method for demonstrating compliance: the owner or operator may dem onstrate compliance with the SO 2 emission limit by switching Power Boiler No. 1 to burn only pipeline quality na tural 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

SO 2 BART emission limit, and the reporting and r ecordkeeping 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 reflec t this alternative method for demonstrating compliance.

We are finalizing our determination that NO X BART for Power Boiler No. 1 is an emission limit of 207.4 lb/hr. We proposed that to demonstrate compliance with this NO X BART emission limit, the facility was required to conduct annual stack testing. In response to a separate comment provided by Domtar, in our final FI P we are requiring stack testi ng every five years instead of annually to demonstrate compliance with the NO X BART emission limit. The repurposing project the mill is currently underg oing and the fact that the facil ity’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 NO X emission limit. Therefore, we are also providi ng one alternative method for dem onstrating compliance with the

NO X 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 NO X emission limit by calculating emissions usi ng AP-42 emission factors and fuel usage records. Under these circumstances, the faci lity would not be required to demonstrate compliance with the NO X BART emission limit for Power Bo iler No. 1 through stack testing. We are revising proposed section 52.173 to reflec t this alternative method for demonstrating compliance.

With regard to the request that we include a provision in our FIP that removes all SO 2 and NO X BART related requirements for Power Boiler 1 if th is boiler is permanently retired in the future, we noted above that the Regiona l Haze regulations define BART as an emission limitation based on the degree of reduction achieva ble through the application of th e best system of continuous emission reduction for each pollutant which is emitted by an existing stationary facility. The BART emission limits and applicable requirement s continue to apply re gardless if a BART

source is mothballed or reti red/shut down without bei ng dismantled, decommissioned, and having the air permit revoked. In the event that the BART so urce is permanently shut down, dismantled, decommissioned, and the permit revoked in the future, the process for removing the BART emission limits and applicable requirement s would necessarily involve a request by the company for partial FIP withdrawal or a SIP revision from the Stat e 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 re spect to the emission limits for the BART unit or revise the SIP if at some point in the future the company d ecides to permanently shut down, dismantle, and decommission the boiler and surrender th e air permit.

Further, we consider the conditi ons under which a unit is perman ently retired and the mechanism by which this is made enforceable to be critic al. Because the company has not decided if and when Power Boiler No. 1 will be permanently re tired or decided what the conditions of the retirement will be, we believe that it is reas onable and appropriate to wait until the company makes these decisions instead of including a pr ovision 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 in clude an alternative compliance option for

the SO 2 , NO X, 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 Boile r 2 is fuel switched to natural gas or retired as pa rt of the Domtar Ashdown Mill’s repurposing project, there is no

need to retain the SO 2 and PM BART limits and the associ ated monitoring, recordkeeping and reporting requirements for the SO 2 and PM BART limits. The Ashdown Mill requests that EPA

include in the BART FIP final rule an alternative compliance option which removes the SO 2 and

PM BART limits and the associated monitoring, recordkeeping and reporting requirements if the

boiler is fuel switched to natura l gas or permanently retired.

Additionally, if Power Bo iler 2 is fuel switched to natural gas as part of the Domtar Ashdown Mill’s repurposing project, the NO X BART requirements need to be modified to require compliance based on the use of AP42 emission fact ors and fuel use records. The requirement to operate and maintain a NO X CEM needs to be removed. If Power Boiler 2 is retired, the NO X BART requirements are unnecessary. The Ashdow n Mill requests EPA include alternate compliance options in the BART FIP final rule pr ovisions to address thes e potential scenarios.

Response: As discussed in our final rule and elsewher e in this document, we are finalizing an

SO 2 BART emission limit of 91.5 lb/hr and we are finalizing our determination that compliance

with the Boiler MACT PM standard as revise d satisfies the PM BART requirement for Power Boiler No. 2. We proposed to require the faci lity to demonstrate compliance with the SO 2 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 ar e finalizing these methods for demonstrating compliance with the SO 2 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 SO 2 and PM BART limits if the boiler is switched to natural gas, we do not have the authority to do this. The Regional H aze regulations define BART as an emission limitation based on the degree of reduction achievable through the applicati on 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 regard less if the unit is switched to natural gas. However, the repurpos ing 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 facili ty with flexibility in demons trating compliance with the SO 2 and

PM emission limits for Power Boiler No. 2. Theref ore, we are providing one alternative method for demonstrating compliance with the SO 2 and PM emission limits: the owner or operator may demonstrate compliance with these emission lim its 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 SO 2 and PM BART emission limits, and the related reporting and recordkeeping requirements wo uld be waived. Under these circumstances, the SO 2 and PM BART determinations for Po wer Boiler No. 2 would continue to apply but the facility would be able to dem onstrate 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 SO 2 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 NO X BART requirement. We proposed to require the f acility to demonstrate compliance with this

NO X emission limit using the existing CEMS, and we are finalizing this method for demonstrating compliance. However, the repurp osing project the mill is currently undergoing and the possibility of Power Boiler No. 2 bei ng converted to burn natural gas only render it appropriate to provide the facili ty with flexibility in demons trating compliance with the NO X emission limit. Therefore, we are providi ng one alternative method for demonstrating compliance with the NO X 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 applic able regulatory requirements, 416 the facility may demonstrate compliance with the NO X 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 NO X 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 SO 2 , NO X , 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 thro ugh 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 con tinue to apply regardle ss if a BART source is

mothballed or retired/shut dow n 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 fo r 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 re vision 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 dow n, dismantle, and decommission the boiler and surrender the air permit.

Further, we consider the conditi ons under which a unit is perman ently retired and the mechanism by which this is made enforceable to be critic al. Because the company has not decided if and when Power Boiler No. 2 will be permanently re tired or decided what the conditions of the retirement will be, we believe that it is reas onable and appropriate to wait until the company makes these decisions instead of including a pr ovision 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 exis ting CEMS is required under other applicable regulatory requirements, the most reasonable approach is to continue demonstrating compliance with the NO X BART emission limit using data from the CEMS.226 Comment: Domtar requests that the final FIP in clude a five year schedule for complying

with the SO 2 and NO X BART emission limits for Pow er Boiler 2 in light of the Mill’s repurposing project. [Domtar (0155) p. 13-14, 15] Domtar st ated that EPA proposes to require compliance with the SO 2 BART emission limit for Power Boiler 2 within 3 years of the effective

date of the final rule. EPA also proposes compliance with the NO X 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 effectiv e date of the final rule for the SO 2 and NO X BART requirements for Power Boiler 2 (assuming EPA deci des to proceed with BA RT for the Mill). It is anticipated that this Mill transformation pr oject 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 Boile r 2. Once the re-purposing and re-configuration of the Mill systems is complete and fully opera tional, the Mill will decide whether Power Boiler 2 will continue with full or intermittent operati on, if so, using what fuels, or will it be permanently retired. A 5-year schedule recognizes the interconnected opera tions of the Mill, in which changes to one system or component requires changes to other interconnected components. Given the Mill’s inte rconnected nature as well as the complex aspects of the repurposing project, a 5-year complian ce schedule for achieving the SO 2 BART and NO X BART requirements for Power Boiler 2 is essential.

As announced late last year, the Mill is conve rting a paper machine to produce fluff pulp. This transformation project is being driven by the co ntinued decline in the demand for paper products. Power 1 and Power Boiler 2 are part of the Mi ll’s steam generating components. The steam generating units are operated to produce steam that is needed for the ma nufacturing of pulp and paper products. Once the re-purposing and re-confi guration of the Mill systems is complete and fully operational, the Mill will decide whethe r Power Boiler 2 will continue with full or intermittent operation, if so, using what fuel s, 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. Si nce 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-p urposing 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 Cl ean Air Act rules) and both Po wer Boilers 1 and 2 share a common bark feed system. Changes in the utiliza tion or retirement of Power Boilers 1 or 2 will affect these interrelated systems. Significant tim e will be required to engineer new or modified systems, obtain environmental perm its 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 w ith 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 fi rst real indicator of227 what winter steam demands will be in the re-purposed state. For the purposes of selecting an appropriate BART compliance sc hedule and future Mill operati ons, 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 retir ing 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 de termining the ability of the existing SO 2 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 e fficiency on a long-term basis.

Response: We have reconsidered the SO 2 and NO X BART compliance dates for Power Boiler No. 2 in response to this comment. We understa nd the commenter’s concerns with respect to how the transformation and repurposing proj ect 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 ne wly 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 scen ario selected by the mill, which could include switching fuels, mothballing or retiring the boile rs, or continued operation and combustion of

solid fuels and installation of ai r 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 generall y 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 SO 2 and NO X BART emission limits no later than 5 years from th e effective date of this final rule and have amended the proposed regulatory text to reflect th is 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 la ter than 5 years after promulgation of this FIP.

4.d. Other Compliance Dates

Comment: Domtar requests that the compliance date for SO 2 and NO X 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 NO X BART limit

for Power Boiler 1 to be on the effective date of the final rule. Should EPA proceed with228 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. Th at will give the Mill additional time to prepare the complian ce records if there is a short period ( e.g ., 30 days) between when the rule is promulgated and the eff ective date, especially if the effective date of the final rule falls on a weekend or a holiday. In addition, if any conf usion 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 cha nges to definitions or other requirements that require the Ashdown to adjust recordkeeping systems.

Domtar stated that EPA is proposing compliance with the SO 2 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 effectiv e 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 defi nitions 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 co mpliance records especially if there is a short period between when the rule is pr omulgated and the effective date or if the effective date of the final rule falls on a weekend or a holiday. In add ition, 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 a dopts changes to definitions or requirements, which mandate adjustments to recordkeeping systems.

Response: We are finalizing a NO X BART emission limit of 207.4 lb /hr for Power Boiler No. 1, which is what we proposed. We proposed an SO 2 BART emission limit of 21.0 lb/hr for Power Boiler No. 1, and as discussed in our final rule and elsewhere in this do cument, 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 aforemen tioned BART emission limits for Power Boiler No. 1 is appropriate because it is a reasonable request th at will allow the owner or operator of the affected facility to prepare applicable complia nce records and adjust recordkeeping systems without unduly delaying compliance with the BA RT requirements. Therefore, we are revising the compliance dates we proposed for the SO 2 and NO X BART emission limits for Power Boiler No. 1 and the PM BART requirement for Power Bo iler 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 signifi cant cost. The utilities will pa ss 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 shoul d 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 pot entially 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 change s will be known. Facilities affected by these other requirements can plan holistic compliance strategi es 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 stra tegies and other significant regu latory 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 th e fact that Arkansas is more than meeting its “glide path” as discussed above.

Response: We acknowledge the commenter’s concerns rela ted to the potential increase in utility rates for Arkansas ratepayers as well as to pot ential requirements related to other CAA and EPA regulatory actions. We agree that multiple regulat ory actions are pending that will affect the power sector and that regulatory development s hould be coordinated when possible while still meeting the statutory and regul atory 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 timelin e for cost-effective control measures needed to meet the regional haze requirements.

The CAA and Regional Haze Rule require the inst allation and operation of BART, in particular, to be carried out expeditiously. The CAA defines the term “as e xpeditiously as practicable” to mean “as expeditiously as practicable but in no event later than five years after the date of230 approval of a [Regional H aze] plan revision . . . .” 417 Therefore, we do not have the authority to delay compliance dates across the board for all su bject-to-BART sources in Arkansas to allow time for greater certainty rega rding 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 installa tion and operation of a particular control technology, the states and EPA usually c onsider the amount of time it generally takes to install and operate that type of technology at si milar sources and the compliance dates that have been required for the installation and operation of the same type of control technology at similar sour ces in other regional haze actions, especial ly if there are no source-specific considerations or other special circumstances that would prevent the source from installing and operating the control technology with in the same amount of time. For example, where a particular control techno logy 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 prac ticable. Additionally, considering that most other states already have plans in place that fully address the regional haze requirements, it would be inequitable and contra ry 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 Arka nsas’ 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 deadline s 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 ra ised in other comments. We addr ess these comments in separate

responses.

We disagree that the BART c ontrols we proposed are unwarrant ed because of the “CALPUFF margin of error.” We address specific commen ts related to the CALP UFF margin of error

elsewhere in this document.

Comment: EPA should impose a shorter SO 2 BART compliance deadline for Flint Creek Unit 1 considering AEP is currently in the pr ocess 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 SO 2 BART determination is based on installation of a NID dry scrubber, EPA should impose a shorter complian ce deadline, as required by the Act. EPA’s proposed FIP requires Flint Creek Unit 1 to comply with the SO 2 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 expediti ously 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 th e regional haze plan. 40 C.F.R. §51.308(e)(1)(iv).

AEP could install a NID scrubber at Flint Creek much more expedi tiously 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 a nd operation at Flint Creek. 419 Further, it app ears 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 sc rubber with a May 2016 planned ope ration date, EPA’s five-year

SO 2 BART compliance deadline does not comply w ith the statutory requirement that BART controls be installed “as expeditiously as prac ticable,” 42 U.S.C. § 7491(b)(2)(A). Since AEP is installing the NID scrubber for MATS as we ll as BART compliance, EPA should require SO 2 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 inst allation of the NID system in 2016 in order to comply with 40 CFR Part 63, Subpart UUUUU - National Emission Standards for Hazard ous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Ge nerating Units, otherwise known as the Utility

MATS Rule. MATS establishes emission limits for three categories of pollu tants: mercury, acid gases (HCl and SO 2 ), and non-mercury hazardou s air pollutant (HAP) me tals. To address acid gases, an EGU must comply with an HCl emi ssion limit unless it is equipped with a wet or dry

FGD or DSI and an SO 2 CEMS, in which case it has the option of complying with an alternative

SO 2 emission limit. The applicable alternative SO 2 emission limit is 0.2 lb/MMBtu.

The commenter has made us aware that the Ar kansas PSC has determined that dry scrubber installation at Flint Creek is in the public intere st and that the installatio n 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 issu ed 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 requirement s 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 w ith 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 PS C is dated March 26, 2014, and stated that the FGD project includes the installa tion of an Alstom NID system to comply with MATS and in anticipation of the BART require ments. The report also stat ed 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 Recei ves Arkansas Commission Approval for Flint Creek Plant Project, at https://www.swepco.com/in fo/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 Re trofit 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/232 established design, procurement, and construction schedules to br ing the upgraded plant fully on line by May 29, 2016. The commenter provided the re port as an attachme nt 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 av ailable on the Arkansas PSC website is dated March 10, 2016, and covers the fourth qua rter 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 insta llation of the controls with the company, who confir med that installation of the NID controls was completed in June 2016, and that the plant is now operating with those

controls. 423

After carefully consider ing the information the commenter has brought to our attention, we no longer believe that a 5-year complia nce date is appropriate for the SO 2 BART controls we are requiring for Flint Creek. We agree with the commen ter 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 co mment period, as discussed above, indicates that Flint Creek intends to operate the NID sy stem to comply with the alternative SO 2 emission limit under the Utility MATS ru le. The applicable SO 2 emission limit is 0.2 lb/MMBtu. The SO 2 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 doc umentation the commenter provided, the company plans to use the same NID system to comply w ith MATS and to comply with the facility’s SO 2 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 inst alled to meet the 0.2 lb/MMBtu emission limit would need some upgrades in order to accommodat e 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 tim e to secure the additiona l scrubbing reagent that would be needed to comply with the SO 2 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 SO 2 BART requirement. We believe this is will provide sufficient time for the facility to be able to achieve the SO 2 BART requirement while still meeting the statutory mandate that BART controls be installed as expedi tiously as practicable.

Comment: EPA should impose a shorter NO X 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 NO X BART determination for Flint Creek is based on installation of LNB/OFA, in order to comply with its statutory mandate, EPA should establish a shor ter compliance deadline. EPA’s proposed FIP requires Flint Creek Unit 1 to comply with the NO X BART determination within three years

from the effective date of the rule. 80 Fe d. Reg. at 18,969. As noted above, compliance with BART is required as expeditiously as practi cable. 40 C.F.R. §51.308(e)(1)(iv). AEP has been planning for the installation of LNB/OFA and co nstruction 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 w ith a May 2016 planned operation date, EPA’s three-year NO X BART compliance deadline does not represent the expeditious implementation required by law. If EP A selects LNB/OFA only as BART NO X for Flint Creek, it should require a NO X BART compliance date of no later than May 2016. Id

.

If EPA selects SCR plus LNB/OFA as NO X BART for Flint Creek, EPA should establish a compliance date of May 2016 for LNB/OFA and within three years of the fi nal 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 repr esent expeditious implementation. Id

.

Response: We are finalizing our determination that NO X 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 operati on of LNB/OFA. The comme nter has not provided

sufficient information to corroborat e 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 NO X 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 submitte d by AEP/SWEPCO to the Arkansas PSC. 426 In that January 21, 2014 report, AE P/SWEPCO announces that cons truction 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 indica ting that the company planned to complete installation of a NID system a nd activated carbon injection by May 2016 to comply with the Utility MATS rule, there is no info rmation available to us corroborat ing 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 complia nce date we proposed) for LNB/OFA installation to allow time for planning, se lection of engineering and de sign professionals, vendors, contractors, permitting, start up and commi ssioning, 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 alrea dy underway and expected to be complete by May 2016. We address the company’s comments regardi ng 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 pu blic comment period are found in the docket associated with this rulemaking.

427 http://www.apscservices.inf o/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 th e appropriate compliance date for these NO X controls, we have also taken into co nsideration that we are finalizing NO X emission limits

consistent with the installation of LNB/OFA or LN B/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 In dependence 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 st ate, 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 m onths and at the same time supply adequate electricity to meet demand in the state. In light of these unique circumstance s, we find that it is appropriate to finalize an 18-m onth compliance date for Flint Creek Unit 1, White Bluff Units 1 and 2, Independence Units 1 and 2, to comply with the NO X emission limits required by this FIP. This compliance date provides the affected utilities sufficient tim e beyond typical LNB/OFA installation timeframes to install these controls and comply with their NO X 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 co mpliance date of SCR controls is moot.

Comment: EPA should impose a shorter NO X 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 NO X BART determination for White Bluff is based on installation of a S CR 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

NO X BART compliance date for SCR at White Bluff of no later than within three years of the final rule’s effective date, which would repres ent the expeditious implementation required by 42 U.S.C. § 7491(b)(2)(A). The NO X BART compliance date for LNB/SOFA should be eight

month’s from the final rule’s eff ective date. Stamper Report at 46.

Alternatively, if EPA finalizes its pro posal to require LNB/SOFA only as NO X 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 ex tended 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 NO X emission limit of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling average, where the average is to be calculated by incl uding only the hours during which the unit was dispatched at 50% or greater of maximum capac ity. In addition, we are requiring each unit to

meet a NO X emission limit of 671 lb/hr on a rolling 3-hour aver age 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 installa tion and operation of LNB/SO FA controls. In light

429 Based on data reported to us by th ese facilities. See http://ampd.epa.gov/ampd/.235 of the comment, we have reconsidered the compliance date for the NO X BART requirements for

White Bluff Units 1 and 2 and for the NO X controls under reasonable progress for Independence Units 1 and 2. Based on the supporting informati on provided by the commenter, we agree with the commenter that 6 – 8 months is the typica l installation timeframe for LNB/OFA controls. However, in determining the appropriate compliance date for these NO X controls, we have also taken into consideration that we are finalizing NO X emission limits that are consistent with the

installation of LNB/OFA or LNB/SOFA controls for a total of fi ve 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 thes e Arkansas units within the typical installation timeframe of 6 – 8 months and at the same tim e 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 NO X emission limits required by this FIP. This compliance date provides the affected u tilities sufficient time beyond typical LNB/OFA installation timeframes to install these controls and comply with their NO X emission limits, while safeguarding the continuity of Arkansas’ electricity supply.

We address elsewhere in this document specific comments cont ending 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 NO X BART requirement for Arkansas EGU’s and the requirement to in stall LNB/OFA at Flin t 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 NO X 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 unreas onable. The regional haze rule provides for compliance with BART as soon as practicable, bu t no later than 5 years. The time frame must allow for planning, selection of engineering and design professi onals, vendors, contractors, permitting, start up and commissioning, and coordi nating and scheduling unit outages. Further, EPA has allowed installation schedules up to 5 year s in other states and EPA should allow such a

time frame here.

Response: We are finalizing our determination that NO X 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 installe d within a 6-8 month tim eframe. We have also determined that the company has not provi ded any information regarding any special

430 Based on data reported to us by th ese 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 wi thin typical 3-year LNB/OFA installation timeframes. Although, as discusse d elsewhere in this document, we agree that LNB/OFA can typically be installed within a 6-8 month timef rame, in determining the appropriate compliance

date for these NO X controls, we have also taken into consideration that we are finalizing NO X 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 approximate ly 45% of the state’s 2015 heat input. 431 Because of the heavy reliance on these EGUs for el ectricity generation in the stat e, 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 finaliz e an 18-month compliance date fo r Flint Creek Unit 1, White Bluff Units 1 and 2, Independence Units 1 and 2, to comply with the NO X 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 NO X 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 s hould consider a boiler operating day to be any 24-hour period betw een 12:00 midnight and the following midnight during which any fuel is co mbusted at any time at the steam generating unit. This would allow 30 da y 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 boi lers. However, the Ashdown Mill boilers are not utility boilers; they are industr ial boilers. The Ashdown Mill defi nes a Mill operating day to be a 24-hour period between 6 a.m. and 6 a.m. the follo wing day. All of the Mill’s systems for Power Boiler 1 and Power Boiler 2 are programmed aro und this definition of a Mill operating day and to modify these systems requires a significant am ount of effort and requires the gathering and maintaining of multiple sets of records. A ssuming 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 th ese facilities. See http://ampd.epa.gov/ampd/.237 defined as a 24-hr period between 6 a.m. and 6 a.m. the fo llowing 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 th e definitions does not increase costs for the Mill, reduces confusion for the Mill operators, multip le sets of records will not be required and unnecessary changes to existing monitoring system s 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 bo iler operating day definition.

Response: After carefully considering the comment, we agree that Domtar’s request is reasonable and that it is appropr iate to harmonize the definitions of a boiler operating day and a Mill operating day to avoid any unnecessary modi fication or reprogrammi ng of Power Boilers 1 and 2. To accommodate Domtar’s request, for pu rposes 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 co mbusted at any time in the power boiler.” We are revising our final action to reflect this change.

Comment: Domtar requests changes to the re quirements for demonstrating compliance

with the NO X BART limit for Power Boiler 1. [Domtar (0161) p. 9-10] Domtar stated that proposed Section 52.173(19) (ii) requires complia nce with the BART NO X limit for Power

Boiler 1 be demonstrated with an annual stack test. We agree, in general, stack testing is an appropriate method for demonstrating complian ce. However, the proposed frequency of an

annual stack test is not appropriate. Historical NO X stack test data from 2001, 2002, 2003, 2004,

2005 and 2010 for Power Boiler 1 show the NO X emissions to be fairly consistent.

Domtar stated that based on the numerous previ ous stack tests, conducting stack tests annually is not warranted. Should EPA proceed with BART fo r the Ashdown Mill, the Mill is requesting the stack testing requirement be modified to require NO X stack testing every 5 years to demonstrate compliance with the BART NO X 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 SO 2 and NO X , that for each boiler operating day a 30-day rolling average determined by (i) adding together the pounds from that day of SO 2 and NO X and the preceding 29 boiler operating days and (ii) dividing the total pounds of SO 2 or NOx by the sum of the total number of hours during the same 30 boiler operating day pe riod. The reference to NO X in this section needs to be removed as compliance with the NO X limit is determined with stack testing. In addition, the discussion regarding SO 2 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 NO X stack testing conducted by Domtar for Power Boiler No. 1 demonstrate that NO X emissions have historically remained238 well below the NO X emission limit we are finalizing for the boiler. 432 Therefore, we agree with the company that it is appropriate to require st ack testing every 5 years instead of annually. In our final action we are requiring that the f acility demonstrate compliance with the NO X BART emission limit for Power Boiler No. 1 by conducting stack testing every fi ve 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 met hod for demonstrating compliance with the NO X 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 NO X 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 NO X BART emission limit for Power Boiler No. 1 through stack testing.

As compliance with the NO X BART emission limit is to be de termined through stack testing, we agree with the commenter that the reference to NO X in our proposed section 52.173(16)(iii) should be removed. We acknowledg e this error and ar e correcting this in our final action

.

Comment: Domtar requests that EPA’s proposed BART SO 2 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 As hdown Mill, the Mill conceptually agrees with the proposed

BART SO 2 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 Mi ll 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 th e 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 th e 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 SO 2 emissions for each day are determined by summing the hourly emissions measured in pounds of SO 2 . Calculating hourly SO 2 emissions using hourly fuel throughput info rmation is not a workable approach for Power Boiler 1 where the practi ce is to use monthly fuel th roughput information that is

reconciled at the end of each month. The Ashdow n Mill requests the requirement referencing summing of hourly SO 2 emission be removed. The Mill will track daily SO 2 emissions and requests the 30-day rolling averages for complian ce 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 va lues 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 NO X emission rate from Power Boiler No. 1 was 171.3 lb/hr, compared to the 207.4 lb/hr NO X emission limit we are finalizing.239 Response: After carefully considering this comment we have determined that Domtar’s request

for an SO 2 BART emission limit in terms of lb/day is reasonable. An emi ssion 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 SO 2 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 reasona ble 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 proce ss to be completed.

Comment: EPA should revise the requirements for demonstrating compliance with the SO 2 and NO X BART limits for Domtar Power Boiler 2. [Domtar (0161) p. 13, 15] Domtar stated that EPA is proposing complia nce with the proposed SO 2 and NO X 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 co mply with the CEMs quality assu rance procedures in 40 C.F.R.

Part 75. Since the Ashdown Mill is an industrial facility, the Mill is co mplying with the CEM requirements including the quality assurance requ irements 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 adeq uate and appropriate for use in SO 2 and NO X BART monitoring. No need exists for EPA to review and approve these existi ng 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 requireme nts including the quality assurance requirements

contained in 40 C.F.R. Part 60 instead of thos e contained in 40 C.F.R. Part 75. We acknowledge

this error and are correcting section 5 2.173 to reflect this.

Comment: EPA must clarify the PM BART requirements for Domtar Power Boiler 2 so these requirements are consistent with de finitions and requiremen ts 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 propos ed BART PM limit of 0.44 lb/MMBTU based on the MACT standard for the “biomass hybrid susp ension grate” sub-category contained in the

2013 Boiler MACT final rule. The Ashdown Mill also agrees with EPA’s a pproach 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 mon itoring, recordkeeping, reporting requirements for PM BART are consis tent with the monitoring, recordkeeping and reporting requirements under Boiler MACT. Deviati ng 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 scru bber pressure drop and the 30-day rolling average wet scrubber liquid flow ra te at or above the lowest on e-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 e ssentially proposing the same met hods for demonstrating compliance

with the Boiler MACT PM standard be used for demonstrating compliance with the PM BART emission limit. However, several of the definiti ons 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 de fines a 30-day rolling average to consist of 30 consecutive boiler operating days.

Examples of other inconsistencies between BA RT definitions/requirements and Boiler MACT

follow:

 During periods of startup and shutdown, Boile r 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 pe riods of startup and shutdown during which time comply only with the Table 3 work pr actices. 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 pe riods of operation in cluding periods of startup, shutdown, and malfunction. In additi on proposed BART requirements in Section 52.173(27) states: At all times, including pe riods of startup, s hutdown and malfunction, the owner or operator to the ex tent practical, maintain and operate the unit including air pollution control equipment in a manner c onsistent with good air pollution control practices for minimizing emissions. In contra st, Boiler MACT requirements allow certain air pollution control equi pment to startup up as expeditiously as possible.

 Boiler MACT is Section 63.7540((a)(1) states: Op erating limits must be confirmed or reestablished during performance tests. Un like 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 dr op 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 co nstitute a deviation of established operation limits listed in Table 4 of this subpart ex cept 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 Bo iler 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, mon itoring, recordkeeping, and reporting different from those the mill is already required to comp ly with under the Boiler MACT PM standard. In our proposal, our intent was to propose requireme nts for compliance demons tration, monitoring, recordkeeping, and reporting for the PM BART limit for Power Bo iler No. 2 that are consistent

with those under the Boiler MACT PM standa rd. However, the commenter has brought to our attention that only some of the compliance demonstration, monitoring, recordkeeping, and reporting requirements associated with the Boile r 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 w ith our PM BART determination for Power Boiler No.2. Therefore, to ensure clarity and consis tency, we are revising th e regulatory text found under 40 CFR section 52.173(c) that applies to Po wer Boiler No. 2 for PM BART to state that the mill shall rely on compliance with the Boil er MACT PM standard under 40 CFR Part 63 Subpart DDDDD as revised to satisfy the PM BA RT 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 th e PM BART requirement. We are not establishing a separate set of requirements for compliance demonstration, monitori ng, recordkeeping, and reporting (i.e., in addition to those already re quired under the Boiler MACT PM standard, as revised), that Power Boiler No. 2 is require d 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 McC lellan Generating Station Unit 1. [AECC (0169) p. 1-2] AECC stated that the EPA’s BART determination for SO 2 and particulate matter (PM)

emissions for these two units is to switch to a lo wer sulfur fuel oil. EPA’s BART determination

for NO X emissions is to maintain the existing NO X 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 SO 2 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” ove r a dry scrubber, and, therefore, EPA did not242 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 th e additional visibility benefits obtained as a result of the greater level of control wet scr ubbers 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 SO 2 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 S CR 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- NO X burners (LNB) with over-fire air (OFA). 435 Also, EPA believes that the addition of SCR cannot be justified due to a small visi bility improvement rela tive 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 s upport of our proposed NO X 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 pr oposed rule, EPA uses “a more streamlined approach to making BART determina tions” where baseline vi sibility 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 imp act of the White Bluff Auxiliary Boiler at the most-affected Class I area, “the visibility im provement that could be achieved through the installation and operatio n of controls would be negligible, su ch 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 SO 2 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 improveme nt at reasonable cost and, th erefore, that unit warrants streamlined BART analysis with respect to its SO 2 emissions. Id . at 18,979-80 & Tables 44 & 45; see id. at 18,980 (observing that “any vi sibility improvement that could be achieved as a

result of emissions reductions associated with the installation and operation of SO 2 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 Guide lines 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 si tuation, such as the distance of the source from a Class I area, the type a nd 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 exhaustiv e analysis of a source’s impact on visibility resulting from relatively mi nor emissions of a pollutant where it

is clear that controls would be cos tly 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 baseli ne visibility impacts” from that boiler’s PM emissions and the “potential for a very small amount of visibility improve ment” 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 c onsistent 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 pr oduce appreciable visibility impr ovement in relevant Class I

areas.

Response: We appreciate UARG’s support of the stre amlined approach we took for making

BART determinations for these sources.

Comment: The statutory factors support EP A’s determination that a scrubber is SO 2 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 Cr eek 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 significa nt visibility improvements at a ll four Class I areas that were considered (relying on 98th percentile im pacts): .615 dv (Caney Creek); 0.464 dv (Upper Buffalo); 0.414 (Mingo); and 0.345 dv (Hercule s-Glades). 80 Fed. Reg. at 18,966. These visibility improvements are signif icant and securing them is esse ntial to achieving the national244 visibility goal. Second, EPA appropr iately considered the existing SO 2 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 Repor t at 3. Third, EPA appropriate ly evaluated the energy and non-air quality environmental impacts of compli ance 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 th e cost-effectivene ss 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 lif e 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 dete rmining cost effectiveness of wet and dry scrubbers as many such control systems have b een operated for longer than 30 years. Stamper Report at 9.

Response: We appreciate the commenter’s supp ort of our determination that SO 2 BART for

Flint Creek Unit 1 is an emission limit th at is based on the use of a scrubber.

Comment: The statutory factors support EP A’s determination that scrubbers are SO 2 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 ef fectiveness—also support EPA’s

determination that a scrubber is SO 2 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 r easonably considered the degree of visibility improvement that is expected to result from th e use of a scrubber at White Bluff. Entergy’s modeling, on which EPA relies, indicates that th e installation of a dry scrubber at White Bluff Unit 1 would result in significant visibility impr ovements 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 0.62 0 (Mingo). 80 Fed. Reg. at 18,972. The modeled visibility improvements resulting from operati on of a dry scrubber at White Bluff Unit 2 are similarly significant though, with the exception of Upper Buffalo, sli ghtly less than the visibility improvement predicted for Unit 1. See id. Entergy’s modeling for a we t scrubber at White Bluff Units 1 and 2 shows similar visibility improvement s 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 improvement s are significant and securing them is essential to achieving th e national visibility goal. Sec ond, 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 evaluate d the energy and non-air quality environmental impacts of compliance and reasonably determined that no such impacts argued against selection

of a scrubber as SO 2 BART for White Bluff. See 80 Fed. Reg. 18,971-72. EPA noted that some energy impacts ( i.e. , the potential increased power requireme nts 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 re cord 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 peri od 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 supp ort of our determination that SO 2 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 Po wer Boiler 2, the averag e steaming rate is approximately 340,000 lb/hr.

Response: We acknowledge the comment and agree that th e description of heat input ratings in our proposed FIP at 80 FR at 18978- 79 refers to maximum heat inpu t rating. We also appreciate the correction provided by the commenter for th e average steaming rate for Power Boiler 1 and

Power Boiler 2. These errors did not aff ect 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 NO X limit for Power Boiler 2 of 345 lb/hr on a 30 boiler operating da y averaging basis. However, the preamble discussion on pages

18987-18988 discusses the installation of LNB and fu rther 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 NO X BART emission limit

for Power Boiler 2 of 345 lb/hr on a 30 boiler operating day averag ing basis. We are finalizing

this emission limit. While this limit was determined based on the NO X emission rate expected from the installation and operation of LNB at Po wer Boiler No. 2, we agree with the commenter that Domtar is not required to install LNB to comp ly with this emission limit. Domtar is free to choose any technology that meets the NO X limit we are establishing.

Comment: EPA should withdraw the BART emissi on limits for Bailey Unit 1 if the State submits to EPA a revised Regional Haze SIP co ntains a demonstration that the unit is not subject to BART. [UARG (0176) p. 7] UARG stated th at 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 withdr aw the proposed BART emission limits (or, if the Agency promulgates those lim its 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 demons tration that EPA acknowledges has already been made that that246 unit is not properly deemed subj ect to BART. EPA notes that re vised modeling conducted after EPA promulgated its 2012 final rule on the Arkans as SIP “shows visibility impacts from Bailey Unit 1 below 0.5 dv, which is the threshold used by Ar kansas to determine if a source is subject

to BART.” Id. EPA thus does not dispute that the newe r 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 comm it 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 promulga te 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 th e observation that the re vised modeling provided to us shows visibility impacts from Bailey Un it 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 th e 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 Re gional Haze regulations. We will take action on such SIP revision according to the statutory tim eframes 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 docume ntation to substantiate this. We will work with ADEQ during the SIP revision process to en sure the necessary supporting documentation is part of the SIP submittal.

Comment: EPA’s NO X 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 an alysis of the five stat utory BART factors: (1) the costs of compliance, (2) the energy and non- air quality environmental impacts of compliance, (3) existing pollution controls in us e at the source, (4) the remaini ng 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 fa ils to accurately consider non-environmental impacts, along with compliance costs and the de gree of visibility impr ovement. EPA incorrectly found that “there are not any ener gy or non-air quality environmenta l impacts associated with the operation of NO X controls at Entergy Lake Catherine Un it 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 thei r Lake Catherine Unit 4 NO X BART determination. Stamper Report at 53. Sargent & Lundy f ound, based on its BOOS testing, that Entergy would need to

437 80 FR 18949.

438 80 FR 18949.247 increase the firing rate of na tural gas by approximately 25% to operate the unit at the same capacity factor. Id at 54. Neither EPA nor Entergy recognize d the increased use of natural gas required for operation of BOOS in their Lake Catherine Unit 4 NO X BART analyses or analyzed the additional environmental impact s 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 NO X 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, othe r control options such as SCR typically have several associated impacts as well, including increased auxiliary power requirements, waste associated with catalyst replacement and dispos al, ammonia slip, and th e partial conversion of

SO 2 to sulfuric acid. As post combustion controls would result in increased power requirements to operate the control equi pment, we expect that this too may indirectly result in increased fossil fuel use to a certain extent. However, we belie ve that the scope of the collateral impacts

associated with the NO X control options we evaluated do not outweigh the benef its in terms of

NO X 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 operati on at Lake Catherine Unit 4 would make this option unacceptable. Thus, we continue to beli eve 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 th e commenter’s specific comments regarding consideration of compliance costs an d degree of visibility improvement.

5. Reliance on CSAPR Better than BART

Comment: EPA is acting arbitrarily and incons istently with its own past positions in requiring sources that are subject to the CSAPR to also control NO X emissions as BART.

[ADEQ (0160) p. 4-8] ADEQ stated that presentl y, Arkansas is subject to a Cross-State Air Pollution Rule Federal Implementation Plan (“CSAPR FIP”) for ozone-season NO X . Despite EPA’s own guidance stating that CSAPR makes greater reasona ble progress than BART for

ozone-season NO X

. 439 EPA makes no mention of CSAPR emi ssions controls in the Proposed FIP and requires BART for Electricity Generating Units (“EGUs”) that are subject to CSAPR. EPA should not require sources that ar e subject to the CSAPR FIP to al so 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 Provisi ons Governing Alternatives to Sour ce-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 th e Clean Air Interstate Rule (“CAIR”),

which was intended to address in terstate transport of air pollution as required by §110(a)(2)(D)

of the CAA. 440 The rule affected 28 states and the Di strict of Columbia and included a cap-andtrade program targeting SO 2 and NO X

. 441 The rule required 25 states, including Arkansas, to

reduce their state-wide emissions of NO X for the purposes of the 8-hour ozone National Ambient Air Quality Standard (“NAAQS”) by specifying ozone-season NO X emissions budgets. 442 The

emission limitations were intended to reduce or e liminate each state’s cont ributions 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. Howe ver, 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 ce rtain states to reduce annual SO 2 emissions, annual NO X emissions and ozone season NO X emissions to assist with othe r states’ attain ment of the 1997 ozone NAAQS, the 1997 fine particul ate matter with an aerodynamic diameter less than or equal to a nominal two and one-half (2.5) micrometer s (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 c oncluded. 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 st ates 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 al lowed to rely on EPA’s determination that CAIR makes greater reasonable progress than source-specific NO X controls. 449 In the final Transport rule, EPA demonstrated that CSAPR, which replaced CAIR, would ma ke greater reasonable progress toward national visibility goals than would BART. 450

440 See Rule to Reduce Interstate Transpor t of Fine Particulate Matter and Ozone (Clean Air Interstate Rule); Revisions to Acid Rain Program; Revisions to the NO X 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 require ments of the Regional Haze Rule, EPA found that the CSAPR trading program did not cause de gradation in any affected Class I area. 451 In addition, EPA found that CSAPR implementation combined with implementation of BART elsewhere achieved greater visibility improve ment 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 substi tute 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 NO X may rely on its determination that CSAPR makes greater reasonable progress than source-specific BART. EPA specifically noted that “[t]he states to wh ich 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 reasonab le progress than source-specific BART, EPA has nevertheless proposed NO X BART for certain units covered by CSAPR in the Proposed FIP.

ADEQ stated that the approach th at 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, Indi ana, 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 SO 2 and NO X

. 455

ADEQ stated that perhaps most noteworthy, EPA ha s proposed reliance on CSAPR in states that border Arkansas. The Texas-Oklahoma Regional H aze Plan does not require BART for sources that are subject to CSAPR. 456 In that plan, EPA reiterates it s position that “CSAPR, like CAIR, provides for greater reasonabl e progress towards the nati onal goal than would BART.” 457 EPA proposes replacing reliance on CAIR with reliance on the tradi ng programs of CSAPR as an

alternative to BART for SO 2 and NO X emissions from EGUs. 458

ADEQ stated that not only is EPA requiring sour ces subject to CSAPR to control emissions as BART in the Proposed FIP, but EPA has not ev en considered CSAPR as an option for making reasonable progress. Even if EPA ultimately reje cted 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/D EQ/Air/PublicNotices/Drafts/mspro.pdf

456 Approval and Promulgation of Impl ementation Plans; Texas and Oklahoma; Regional Haze State Implementation Plans; Interstate Transport State Im plementation Plan To Address Pollution Affecting Visibility and Regional Haze; Federal Implementation Plan for Regional Haze and Inters tate Transport of Pollution Affecting Visibility, 79 FR

74818.

457 79 FR 74818 at 74851.

458 79 FR 74818 at 74853 (the proposed [Texas-Oklah oma] FIP ... substitutes Texas' reliance on the Clean Air Interstate Rule (CAIR) to satisfy BART requirements at its EGUs with reliance on CA IR'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 positi on that CSAPR provides for greater reasonable progress than source-specific NO X , facilities subject to the CSAPR FIP should not also be required to install, operate, or maintain BART for NO X . In Arkansas, the following units should not be required to install the NO X BART proposed by EPA in the Proposed FIP because they are also subject to CSAPR for ozone-season NO X : (1) AEP Flint Creek Unit One; (2) Entergy White Bluff Unit One; (3) Entergy White Bluff Unit Tw o; 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 a ddition to CSAPR emissions controls for ozone

season NO X in any subsequently proposed plan.

[Entergy Arkansas Inc. (0166) p. 13] Entergy stat ed that NOx BART for all EGUs in Arkansas, including White Bluff, should be complian ce 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 a dopted this approach. Proposed Te xas Regional Haze FIP, 79 Fed. Reg. at 74,821; see also Proposed Pennsylvania SIP Appr oval, 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 NO X 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 w ith EPA’s proposed LNB/OFA controls for NO X for the

Flint Creek Power Plant. EPA issued a final rule allowing states that ar e subject to the CSAPR trading program for seasonal NO X to rely on the reductions ac hieved through that trading program to satisfy the regional haze program requirements for units subject to BART. 461

AEP-SWEPCO stated that EPA ha s an obligation to issue a FIP within 2 years of disapproving a SIP to correct identified deficiencies. In prep aring a FIP to address those deficiencies, EPA should select and propose options th at are in the best interests of all stakeholders. EPA makes no mention of CSAPR=BART in their pr oposed FIP. Although ADEQ did not propose CSAPR=BART in their submitted SIP, EPA should ha ve evaluated that alte rnative 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 th ere 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 Provi sions 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 ADEQ 462 as the primary option for compliance with NO X at the Flint Creek facility. The BART analysis for NO X 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 addres s that issue in the section of the FIP that discusses the Flint Creek facility.

AEP-SWEPCO stated that EPA has made clear th eir determination that CSAPR is “better than BART” in addressing NO X in ozone season only states. If CSAP R is indeed “better” than BART

for NO X , then EPA should have proposed the CSAPR tr ading program as an alternative to BART and selected that program in the regional haze FIP for addressing NO X emissions. Regardless of implementation of the Regional Haze Rule, CSAPR will be in effect in Arkansas and NO X emissions will be reduced accordingly. It is unn ecessary to also require site-specific NO X reduction controls which will result in reduced flexibility and increased costs without providing any additional visibility improvement s. 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

SO 2 and NO X emissions from EGUs in the regional haze plan for Texas.” 463 EPA also “... found that CSAPR, like CAIR, provides for greater r easonable progress towards the national goal than

would BART.” 464 The same approach should be allowed in Arkansas for NO X emissions. EPA

should establish CSAPR=BART for NO X and eliminate all site specific NO X 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 NO X trading program. EPA's own guidance states that CSAPR makes greater reasonable progress than BART for ozone season NO X . 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 NO X is allowed to rely on our determination that the Transport Rule makes gr eater reasonable progress than source-specific

BART for NO X . 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 me ntion of CSAPR compliance in EPA’s proposed Arkansas FIP, and yet EPA requires BART for EGUs that are su bject to CSAPR. All EGUs in Arkansas rated 25 megawatts or greater are subject to the seasonal NO X trading program under CSAPR; therefore, those EGUs should not be subj ect to additional BART controls for NO X . Specifically,

the NO X controls for the Flint Creek and White Blu ff 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: Revisi ons to Provisions Governing Alternatives to

462 BART Five Factor Analysis, Flint Cr eek 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, Limite d 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 SO 2 and/or NO X emissions from power plants. This determination is commonly referr ed to as CSAPR being “better-than-BART.” EPA also determined “that a state in the CSAPR regi on whose EGUs are subject to the requirements of the CSAPR trading program only for ozone season NO X is allowed to rely on our determination that CSAPR makes greater reason able progress than source-specific BART for

NO X .” 467 Arkansas is included in this determinatio n, therefore the state’s subject-to-BART EGUs were not required to perform a five factor analysis of NO X emissions. Beginning May 1, 2015, CSAPR is in effect and being implemented in Arkansas. ADEQ is currently reevaluating the

NO X emission limits that are in the disapproved SI P and considering appropriate revisions. EPA should have proposed the CSAPR trading program as an alternative to BA RT and selected that program in the Proposed Rule for addressing NO X emissions from Arkansas’ subject-to-BART sources, including AECC Bailey and McClellan plants, AEP/SWEPCO Flint Creek Plant and Entergy White Bluff and Lake Catherine 468 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 NO X emissions will be reduced accordingly. Thus, it is unnecessary to also require site-specific NO X 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 a lternative to BART for SO 2 and NO X emissions from electric generating units (“EGUs”) in the regional haze plan for Texas. 469 EPA also “found that CSAPR provides for greater reasonabl e progress towards the nati onal goal than would BART.” 470 The same approach should be allowed in Arkansas for NO X emissions, and EPA should establish

CSAPR=BART for NO X emissions and eliminate all site-specific NO X 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 determina tion that “CSAPR=BART” in which EPA has previously made clear its determination that CSAPR is “better than BART” in addressing NO X 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 w ould apply to several Arkansas

facilities—such as the Southwes tern Electric Power Company’s Flint Creek faci lity—should be an acceptable option since the proposed site-specific NO X 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 fo r Arkansas’ Class I areas wh ich 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 NO X and withdraw all site-specific NO X controls identified in the Arkansas FIP.

Response: Arkansas EGUs are subject to CSAPR for ozone season NO X , 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 NO X may rely on CSAPR to satisfy the NO X BART requirement for its EGUs. However, when standi ng in the shoes of a state and promulgating a FIP, EPA has the same discretion as the state to choose to either conduc t source-specific BART determinations or to rely on EPA’s 2012 finding th at CSAPR is better th an BART. Our decision to make source-specific NO X BART determinations for Arkansas is reasonable for multiple reasons: it is the approach Congr ess chose in the statute itself; 471 it is consistent with Arkansas'

earlier decision to condu ct source-specific NO X 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 re gulation 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 requ ire source-specific BART controls. 472 More specifically, in 2005 EPA revised the Regional Haze regulations to provide that a state s ubject 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 li eu of source-specific

BART. 475

In its 2008 regional haze SIP submittal, Arkansas decided to not rely on CAIR to satisfy the NO X BART requirement for its EGUs. 476 In our Regional Haze FIP propos al for Arkansas, we did not rely on CSAPR (the follow up rule to CAIR) to satisfy the NO X BART requirement for EGUs

because we chose to follow the sa me source-specific approach to NO X BART that Arkansas selected in its Regional Haze SIP submittal. In addition, litigation surrounding CSAPR was ongoing at the time that we issued our propos ed 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. Ci rcuit issued a July 2015 decision in EME Homer City Generation v. EPA 477 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 alterna tive 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 requiremen ts in the regional haze SIP, Arkansas is not included in

the EPA’s limited disa pproval 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 NO X and SO 2 emissions budgets. Arkansas’ ozone season NO X budget is not itself affected by the remand. However, the Court’s re mand of the affected states’ emissions budgets has implications for CSAPR better-than BA RT, since the demonstration underlying that rulemaking relied on the emission budgets of all st ates 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 acti ng 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 FI P is consistent with our final action on the Texas Regional Haze FIP. Although we proposed to rely on CSAPR to address the NO X BART requirements for EGUs in Texas, we did not finalize that portion of our proposed Texas FIP given the uncertainty arising from the rema nd 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 re vision, ADEQ may elect to rely on CSAPR to satisfy the NO X BART requirements for Arkansas’ EGUs instead of doing source-specific NO X BART determinations. Such an approach could be appropriate if, as we expect, the uncertainty created by the D.C. Circuit’s remand of the aff ected states’ emission budge ts 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 re asonable 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 BA RT 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 sec tion 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 NO X controls on Lake Catherine Unit 4 are within the CALPUFF model’s margin of error.

Comment: The NO X controls EPA evaluated for Lake Catherine Unit 4 cannot be justified as BART, and instead of imposing source-speci fic controls on Lake Catherine Unit 4 and the other EGUs in Arkansas, EPA shou ld find that CSAPR is better than NO X BART. [Entergy Arkansas Inc. (0166) p.53-54] Entergy stated that if EPA finalizes a determination that

478 https://www3.epa.gov/airtransport/C SAPR/pdfs/CSAPR_SO2_Remand_Memo.pdf

479 81 FR 296, at 302.

480 70 FR at 39143; see also 77 FR at 33653255 Lake Catherine Unit 4 should be subject to NO X BART controls, EPA should not impose sourcespecific NO X controls on Lake Catherine Unit 4 but should instead find that CSAPR is better

than NO X BART in Arkansas for all EGUs. Comp liance with CSAPR will ensure that NO X emissions from Arkansas’ EGUs are limited and will improve visibility in Arkansas’ Class I

areas.

Entergy stated that EPA also ha d evaluated controls other than BOOS for Lake Catherine Unit 4.

See 80 Fed. Reg. at 18,976-78. Similar to BOOS, how ever, these controls would result in imperceptible visibility improvements in Arka nsas’ Class I areas. Although Entergy did not evaluate the margin of error with respect to th e CALPUFF predicted visibility improvement from these other controls, EPA had rejected these controls as NO X BART for Lake Catherine Unit 4 based on costs and Entergy agrees with EPA’s de termination that these controls should not be

considered as NO X 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 installati on of LNB/SOFA and selective noncatalytic reduction (“SNCR”) or selective catalytic reduction (“ SCR”) cannot be justified as BART based on either average cost effectiv eness or incremental cost effectiveness. Id . Lake Catherine Unit 4 is a peaking unit and operated at only a two percent ca pacity factor in 2014. 481

The estimated incremental costs of instal lation 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 th ese controls would requi re a massive capital investment and significant opera tion and maintenance costs that are impracticable for a peaking

unit.

Response: We address elsewhere in this document w hy it would not be appropriate to make a determination to rely on CSAPR as an alternative to NO X BART for EGUs in Arkansas at this

time. As discussed elsewhere in this docum ent, we are finalizing source-specific NO X 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 Catherin e Unit 4. We disagree that BOOS would result in imperceptible visibility improvements in th e affected Class I areas and that we should therefore not require BOOS controls for NO X BART. We address elsewhere in this document comments on this issue, includi ng comments alleging that the proj ected visibility improvement

of NO X controls on Lake Catherine Unit 4 are within the CALPUFF model’s margin of error. As discussed in our proposal and else where in this document, BOOS c ontrols are expected to result in meaningful visibility improvement in the aff ected Class I areas and is very cost effective ($138/ton removed). Therefore, we are fina lizing our proposed determination that NO X BART for Lake Catherine Unit 4 for the natural ga s firing scenario is an emission limit of 0.22 lb/MMBtu on a 30 boiler-operating-day average cons istent 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 SO 2 emissions from Arkansas sources and regulates NO X emissions only during

the ozone season. [Sierra Club et. al. (0171) p. 46] Sie rra 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 fa ils for at least two reasons. Fi rst, Arkansas sources are not subject to SO 2 limits under CSAPR. See 77 Fed. Reg. 34,830, 34,845 (June 12, 2012). 482 Given

that CSAPR does not limit SO 2 emissions from any Arkansas sources, the commenters’ suggestion that CSAPR could represent th e best available te chnology for reducing SO 2 emissions is plainly incorrect.

CSAPR contains unit-level allocations for NO X emissions for several Arkansas sources for which EPA is proposing BART determinations. However, under CSAPR, Arkansas sources are subject to NO X emission limits only during the ozone season. 77 Fed. Reg. at 34,845. CSAPR

contains no annual NO X 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.”). Give n that CSAPR does not limit annual NO X emissions from Arkansas sources, CSAPR cannot satisfy the NO X BART requirements for annual emission

limits on Arkansas sources. EPA therefore act ed properly by not cons idering CSAPR as a potential control in the BART analysis for NO X emissions.

Response: We acknowledge the background information provided by the commenter. We agree that since Arkansas is not subject to CSAPR for SO 2 , Arkansas EGUs cannot rely on CSAPR to satisfy the SO 2 BART requirements. For the reasons disc ussed elsewhere in this document, we are finalizing source specific NO X BART determinations for Arkansas EGUs subject to BART instead of relying on CSAPR to satisfy the NO X BART requirement.

Comments disagreeing with our finding that CSAP R is “better-than-BART” for states subject to

CSAPR for ozone season NO X only (77 FR 33642) are outside th e scope of today’s rulemaking.

6. Cost

6.a. Cost Analyses and Cost Effectiveness Issues

Comment: EPA underestimated the costs of scr ubbers at White Bluff by basing its cost analysis on Entergy’s outdated cost estimate, eliminating le gitimate costs, using the IPM cost model, and revising Ent ergy’s assumed uncontrolled SO 2 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 Revi sed White Bluff BART Analysis, and presented its analysis of the cost s for scrubber installation at White Bluff in its SO 2 Cost TSD. However,

482 See also Unit Level Allocations Under the CSAPR FIPs After Tolling, available at http://www.epa.gov/crossstaterule/actions.html257 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 BA RT Analysis are signifi cantly 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 we re 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 scrubb ing 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. SO 2 Cost TSD, at 2. However, even with the updated cost information from Alstom, the informati on provided in the Revised White Bluff BART Analysis is now at least five y ears 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 signifi cantly 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 throughou t EPA’s analysis in the SO 2 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 cal culation 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 in cluded 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 co st analysis: costs for the reagent handling system; costs for the ductwork to supply the fl ue 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 downw ash effects; the costs associat ed with replacing the continuous emissions monitoring systems (CEMS) and associat ed recalibration and tes ting costs; and costs calculated as percentage s 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 ab sorber vessel could be eliminated but cited no basis for its assumption that two absorber ve ssels 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 Qu ality 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 co sts 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 in clude both direct assigned and allocated expenses. Allocated expenses represent overhead co sts associated with administrators, engineers and supervisors to the capital pr ojects for which they provide serv ices. Each function at Entergy charges its overhead costs to a “Capital Suspen se” project, which is then allocated to the appropriate capital project. Ca pital 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 to tal 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 SO 2 Cost TSD at 9. It was entirely proper for Entergy to include these co sts in its control tec hnology 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-estim ated the direct Operating a nd Maintenance (“O&M”) costs projected for the scrubbers by using its Integrated Planni ng 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 SO 2 Cost TSD at 14, Table 8. The IPM model includes several assumptions that fail to take into accoun t site-specific factors. S&L FIP Cost Report at 13-14. Accordingly, the IPM model is not consiste nt 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 SO 2 emission rate of 2.0 lb/MMBtu, which is in exces s of the sulfur level of the co als the units have historically burned. EPA criticized Entergy for this assu mption and revised the White Bluff baseline emission rates and projected post-control emission ra tes used for the cost effectiveness analysis.

See SO 2 Cost TSD at 12-14. However, it is proper, when conducting a BART cost analysis, to consider future fuel flexibility. The BART Guidelin es advise that “[t]he baseline emissions rate should represent a realistic depiction of anticip ated 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 antic ipated annual emissions are generally estimated based on annual emissions from a baseline period assu ming conditions of past practice, id . at 39,167-68, EPA has approved BART determinations that a ssume “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 woul d be necessary to reflect such a constraint in the cost of compliance, as it would force Entergy to cont inue purchasing higher-cost, low sulfur coal. Historically, Entergy has purchas ed lower sulfur coal than re quired 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, highe r sulfur coal would en able 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-speci fic O&M costs. S&L FIP Cost Report at 15.

Finally, although Entergy removed Allowance fo r Funds Used During Construction (AFUDC)

from the final Revised White Bl uff BART Analysis in response to comments from EPA on the Proposed White Bluff BART Analysis, Entergy di sagrees 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 construc tion, which could reach $30 million to $60 million during the 30-46 months of construction that woul d 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 co sts 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 AF UDC is not allowed by EPA’s

Control Cost Manual because “the CCM uses overnight costing methodology.” EPA Region 6

Comments on White Bluff BA RT Analysis, at 1 (Aug. 21, 2013) EPA Docket ID EPA-R06- OAR-2015-0189-0044. However, contrary to EPA’s a ssertion, the Control Cost Manual does not even address the use of the overnight methodol ogy 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 contro l costs, but instead is an explicit recognition of that category of costs.

EPA also has claimed that the U.S. Energy Info rmation 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]ta rting 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, Enterg y 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 anal yses. 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 scr ubbers at White Bluff should appropriately include

AFUDC.

[AECC (0169) p. 5-6] AECC stat ed that EPA based its White Bluff dry scrubber technology

estimates on costs associated with reports commissioned by Ente rgy 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 installi ng 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 constr uction 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 an alysis. EPA needs to re-evaluate the White Bluff

control cost estimates with th e 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 rem oval of certain costs from the co st analysis of our White Bluff scrubber cost analysis including owner’s costs and in terest incurred duri ng 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 descri bes a constant dollar approach that annualizes all capital costs and O&M costs ( on a constant-dollar basis) over th e useful life of the project.

In the Oklahoma rule EPA cited to an Ener gy 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 te rms of overnight costs.” However, this is a mischaracterization of the methodology the EIA uses to develop capita l costs for new power generation. The EIA document upon which EPA relied includes a clarif ying footnote that states: “Starting from overnight cost estimates, EIA’s electricity mode ling explicitly takes account of the time required to bring each generating technology online and the costs of financing cons truction in the period before a plant becomes operational.” Therefore, EI A cost evaluations take into account financing costs, including AFUDC, one of the line items EP A 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 contro ls equipment to be compared in a meaningful manner.” However, excluding financing costs will bias th e cost-effectiveness comparison toward the high capital options with extended c onstruction periods. Project fina ncing costs such as AFUDC may be minimal on projects that do not require signi ficant capital and with sh ort construction periods, but can be very significant on pr ojects with large capit al costs and extended construction periods. Excluding financing costs from the capital cost es timate results in the high-capital cost option appearing more cost-effective. Including financin g 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 anal ysis for a dry scrubber for the White Bluff facility on an outdated 2009 S&L analysis, “rather than using th e updated vendor pricing.” This is a misrepresentation of the fact s. Not disclosed by Entergy is th at 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 r ecent analysis available to us, th at it was used by Entergy itself, and has only been recently updated by Enter gy 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 th e 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 ma ny other consultants who perform control cost analyses) on numerous occasi ons. Again, had we had more updated cost information at the time we proposed our FIP, we w ould 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 cost s, stating such costs are allowed under “our” CUECost model, and our disallowa nce of AFUDC. Our use of the term, “overnight method” is merely a shorthand way of referring to the co sting methodology required by the Control Cost

Manual. The fact that the Cont rol Cost Manual itself does not us e that term does not obviate the need to adhere to that methodology. As we ha ve 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 co mments 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 “overn ight” methodology outlined in our Control Cost Manual. We were recently upheld in the Ninth Circuit 490 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 SO 2 baseline. As we discu ss 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 Ba sin coals, resulting in annual uncontrolled SO 2 emissions ranging from 0.46 lbs/MMBtu to 0.6 25 lbs/MMBtu, but designed its White Bluff scrubber systems assuming a coal with an uncontrolled SO 2 emission rate of 2.0 lbs/MMBtu.

This has ramifications for the scrubber cost e ffectiveness calculation, in which the annualized

cost of the controls are co mpared to the tons of SO 2 reduced from its SO 2 baseline. A scrubber capable of treating a higher sulfur coal is more expensive. Ente rgy 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 Wh ite Bluff and Independence Facilities, Arkansas Regional Haze Federal Implementation Plan (SO 2 Cost TSD).

489 See for instance our “Response to Technical Comments fo r Sections E through H of the Federal Register Notice for the Oklahoma Regional Haze and Visi bility Transport Federal Implementa tion 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 meth odology 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 SO 2 Cost TSD.262 capable of burning a coal with a higher sulfur content (assuming all regulatory requirements are otherwise met). However, unless this e xpense is balanced against the greater SO 2 removal capabilities of such a scr ubber, the cost effectivene ss calculation is skewed.

Nevertheless, Entergy continues to argue that it can legitimately introduce a mismatch between the cost of its scrubber systems and the SO 2 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 flexibilit y be considered “[t]he baseline emissions rate should represent a realistic depiction of an ticipated annual emissions for the source.”

The full quote which Entergy references above (which we reproduce in our SO 2 Cost TSD in the section referenced above) is actually: 492

The baseline emissions rate should repres ent a realistic depiction of anticipated annual emissions for the source. In gene ral, for the existing sources subject to BART, you will estimate the anticipated annual emissions based upon actual emissions from a baseline period. Wh en you project that future operating parameters (e.g., limited hours of operation or capacity utilizati on, 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 en forceable limitations. In the absence of enforceable limitations, you calculate base line 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 hi storical 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 th e above quote anticipates that future operations will cause the baseline to be lower, resulting in a correspondingly lower denominator in the $/ton

cost effectiveness calcul ation, thus resulting in the cost e ffectiveness seeming less attractive (higher), thus triggering the need for an enforceabl e mechanism to ensure the integrity of the cost

effectiveness calculation into th e future. The same principle a pplies 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 sulf ur coal, but the need to ensure the future integrity of the cost

effectiveness calculation nevertheless remains.

There are two obvious ways to addr ess this situation: either (1) this higher cost be balanced against its greater SO 2 reduction potential, or (2) that the scrubber system’s capability and cost be adjusted down to match the facility’s histor ical emissions. Lacking any information from Entergy regarding its preferences, we chose the la tter 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 cal culating 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 39167.263 2.0 lb/MMBtu case, and one base d on Entergy’s historical SO 2 emissions. We then applied these ratios to Entergy’s annualized cap ital costs and the sum of its dire ct 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 SO 2 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 ha ve approved BART determinations that assume “worst-case coal scenarios” and cites to our proposed North Dakot a 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 proposa l, Coal Creek Station had recently installed a coal drying system and in performing the BA RT 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 denominat or in the $/ton cost effectiveness determinant, result ing in the true cost effectiv eness of the technologies being considered being higher than what was evalua ted—the opposite of what Entergy is proposing here. In addition, the issue was la rgely moot in that we proposed approval of what the State of North Dakota had itself proposed as BART fo r Coal Creek—that the existing scrubbers be upgraded to 95% efficiency, arguably a very stringe nt level of control. In the Arizona proposal,

the Sundt Unit 4 was converted to burn coal in addition to natura l gas. Its annual SO 2 emissions varied greatly, as a result of years in which more or less natural gas was burned, presently a problem when selecting its SO 2 emission baseline. We therefore chose a year in which the Sundt Unit 4 burned predominantly coal to represent the SO 2 baseline, when evaluating it for SO 2 BART. This results in a r easonably conservative, “worst case” evaluation—again, not what Entergy is proposing here.

We address all of Entergy’s ot her comments, which are summar ies of its contractor S&L’s comments, in our responses to S&L’s comments.

Comment: Entergy objects to our calculatio n of O&M costs in ou r 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 Ma nual in developing its individual control technology co st estimates, in the supporting Cost TSD EPA stated that “we can compare Entergy’s O&M costs to those obt ained through the use of our IPM SDA cost

model.”

The IPM model and the Control Cost Manual pr ovide 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 pow er sector in the 48 contiguous states and the

District of Columbia. The model has been us ed by EPA to analyze impacts associated with proposed regulatory programs such as the Clean Ai r Interstate Rule (CAIR) and Mercury and Air Toxics Standard (MATS). The primary purpose of th e model is to provide fo recasts of least-cost capacity expansion, electricity dispatch and em ission control strategies for meeting energy demand and environmental, transmission, dispatch and reliability constraints. The model

includes cost modules for variou s air quality control technologi es, and S&L developed the cost264 algorithms used in the IPM model to estimate co sts associated with DSI, SDA, and wet FGD control systems. The IPM model is not referred to in either the Cont rol 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 pub lications, and do not take into c onsideration site-specific cost issues. The primary purpose of the IPM cost mo dules is to provide ge neric 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. Becau se of the limited number of site -specific inputs, the IPM cost algorithms provide order-of-magnitude control sy stem cost estimates, but they do not provide case-by-case project-specific cost estimates meet ing 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 cost s, the IPM model does not estimate sitespecific capital costs sufficiently upon wh ich 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 stoichiome try 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 ap ply site-specific temperatures;

 Reagent consumption also depends upon lime purity, which the IPM model assumes

to be 90% and cannot be modified to ma tch actual reagent supply information;

 The IPM model estimates water consumption ba sed on gas flow and fuel sulfur levels instead of performing site-specific calcul ations using actual fuel properties and operating conditions;

 Waste generation is a function of the assu med lime stoichiometry discussed above as

well as an assumed moisture content of 10% that cannot be modified to match vendor-supplied mass balances fo r specific applications; and265  The SDA flue gas pressure drop estimate included in the IPM model is an average value based on flue gas flow ra te and sulfur levels instea d 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 choi ce 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 potentia l project-specific site constraints that Entergy would incur to operate the FGD control systems EPA is proposing. In addition, using the IPM cost algor ithms 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 no t account for unit-specific design and operating parameters that can affect control system desi gn and costs, including operating costs. Second, the IPM cost equations do not take in to consideration site-specific c onditions 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 SO 2 emission

baseline used in its cost analysis and the assumed SO 2 inlet it assumed in the design of its scrubber. Entergy costed a scrubber capable of treating a SO 2 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 else where dictated a revisi on to Entergy’s cost estimate, we were left with no choice but to se ek 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 c ontractor 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 containe d 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 main tain and improve consistency, cost estimates should be based on the OAQPS Contro l Cost Manual, where possible.” 497 This statement is

footnoted to indicate: “You s hould include documentation for any additional information you used for cost calculations, in cluding any information supplie d 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 co sts, 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 estimati ng the costs of any of the SO 2 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 SO 2 ,” 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 direct ly, except through the overnight cost methodology and the other genera l principles containe d therein, which we followed. As a consequence, faced with having to perform cost analysis on an applicable control technology, we elected to use the on ly publically available current SO 2 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 presen t work is the general methodology chapter, Chapter 2: Cost Estimatio n: Concepts and Methodology. We did adopt the Control Cost Manual general cost methodology, th e 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 owne r’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 accep table tool to develop site specific capital or O&M cost estimates.” These models were develope d by Sargent & Lundy, under contract to us. 499 They were first published in 2010, 500 after the last Control Cost Ma nual 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 Co st Manual or the BART Guidelines. Regardless, the absence of a specific cite to a model in th e 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 Plans 502 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 (SO 2 ) 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 Guide lines for Best Available Re trofit 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 Ai r Markets Division contracted with engineering firm Sargent and Lundy to perform a complete bottom-up engineering reassessment of the cost and performance assumptions for SO 2 and nitrogen oxides NO X emission controls.” 506

This comment also confuses “the IPM model” a nd the cost models that are inputs to the IPM

model. The comment asserts that the IPM m odel and the Control Co st Manual provide two entirely different approaches to calculating c ontrol 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 syst em-wide impacts of ai r emissions policies on the U.S. electric power sector in the 48 contiguous states and the Di strict 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 co st inputs are not “multi-regional, dynamic, deterministic linear programming models” but rath er 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 onl y used the control tech nology cost models, not

the IPM model itself.

Accuracy of IPM Cost Algorithms fo r Site-Specific Costs Estimates

Entergy argues that the IPM model only provide s “generic order-of-magnitude costs,” implying they are not acceptable for unit-spec ific cost estimates for the indi vidual plants included in this rulemaking. We believe these cost models are ad equate 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 we t 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 Capac ity 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 a ddition, S&L included data from “Current Capital Cost and Cost-effectiveness of Power Plant Emissions Control Technologies” prepared by J. E. Cich anowicz 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 cons idered. 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 provi de a representative we t FGD cost basis.

The data was converted to 2012 dollars ba sed on the Chemical Engineering Plant Index (CEPI) data. Additional proprie tary S&L in-house data from 2007 to 2012

were included to confirm th e index validity. Finally, th e 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 project s 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 maintain ed 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 sp ecifics such as unit size, coal type, gross heat rate, retrofit f actor, and require unit specific i nputs 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 algorit hms is “not an appropriate choice for a unitspecific analysis consistent with BART guide lines” because: (1) it does not account for unitspecific design and operating parame ters 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 em ission 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 consider ation the technology available, the costs of compliance, the energy and non-air quality enviro nmental impacts of compliance, any pollution control equipment in use or in ex istence at the source, the remaini ng useful life of the source, and the degree of improvement in visibility....” 508 In this context, ca se-by-case refers to each pollutant at each emission unit. We applied the IPM cost models for SO 2 at each emission unit using unit-specific inputs. Thus, the “case-by-cas e” requirement of the definition of BART is satisfied. Second, we accounted for “unit-spec ific 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 pr ovide only “order of magnitude” control cost estimates. However, as the Cont rol Cost Manual explains, the so le input required for making an “order of magnitude” estimate is “the contro l system’s capacity (often measured by the

maximum volumetric flow rate of the gas passing th rough 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 wi dely reported in the literature. A quick look at the many inputs to the IPM cost models 511 demonstrates that they provide more accurate estimates than “order of magnitude.” The Cont rol 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 ru le 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: uni t size, retrofit factor, gross heat rate, SO 2 rate, type of coal, coal factor, SO 2 removal efficiency, auxiliary powe r cost, lime cost, waste disposal cost, makeup water cost, operating labor rate, eleva tion, interest rate, equi pment lifetime, and the

SO 2 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 F GD, SDA, and DSI cost algorithms discussed

herein For the reasons we desc ribe above, we disagr ee with S&L that our modifications to and use of the cost algorithms it ha s 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 subtra cts 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 th en 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 cost s, using fixed and variable O&M costs from a 2011 S&L cost summary as a surr ogate 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 estim ate. 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 si te-specific and there was a discrepancy between Entergy’s SO 2 emission baseline used in its cost analysis and the assumed SO 2 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 fi ve years in calculating baseline emissions for White Bluff and used an incorrect methodology that inflates SO 2 emissions reductions. [Entergy Arkansas Inc. (0166) p. 7- 8] EAI stated that the BART Gu idelines state that baseline emissions from existing sources “should represen t 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 th e anticipated annual emi ssions based upon actual emissions from a baseline period. Entergy orig inally had used the 2001 - 2003 baseline period.

See Revised White Bluff BART Anal ysis at 4-1. EPA looked at the five-year period between 2009 and 2013, SO 2 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 Wh ite Bluff. S&L FIP Cost Report at 3. There is no reasoned explanation for excluding two of th e five recent years’ of emissions data in calculating the baseline. EPA should use the averag e 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 identifie d the baseline emissions for White Bluff, EPA then apparently ignores the baseline emissi ons when estimating the SO 2 reductions that are achievable with the scrubbers. In an apparent attempt to inflate the emission reductions ach ievable at White Bluff through the installation of scrubbers, EPA identified the maximum monthly SO 2 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 contro lled 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 SO 2 reduced. Id . This methodology is patently incorrect. It assumes the

baseline emissions are based on maximum monthly averages, wh ich significantly overstates the annual averages actually used to calculate baseline emissions.

To correctly estimate the SO 2 emission reductions, EPA must mu ltiply 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 achievabl e 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 Whit e 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 co st 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 ina ppropriate for evaluating the cost effectiveness of dry scrubbers on White Bluff for regi onal haze purposes. To correct EPA’s deficiencies, Entergy commissioned a revise d dry FGD cost analysis from S&L that takes into account the current costs for dry scrubber in stallation 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 re ference herein). The 2015 S&L FGD Report also takes into account site-specific f actors at White Bluff that have an effect on costs. Finally, the study also uses the current SO 2 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 mu st 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 esti mated the costs to install dry scrubbers at White Bluff to be approximately $670 million. Re vised White Bluff BART Analysis, at 5-6, Table 5-3. The 2015 S&L FGD Report estimates that the total costs of dr y scrubbers at White
Bluff will be in excess of $1 billion. 2015 S&L F GD 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 e ffectiveness 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 magn itude 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 considerab le visibility improvement,” EPA rejected SO 2 BART limits based on switching to diesel b ecause EPA determined that diesel, with an average cost effectiveness of $7,145/ SO 2 ton removed, was not “cost-effective in view of the incremental visibility improvement.” 80 Fe d. 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 eff ectiveness of $6,525 per ton was excessive for NOx controls and did not constitute BART. Proposed North Dakota FI P, 76 Fed. Reg. at 58,630; Final North Dakota272 Regional Haze FIP, 77 Fed. Reg. 20,894, 20,896 (Apr. 6, 2012). And, in Montana, EPA

concluded that certain SO 2 controls with a cost effectiv eness of $5,442/ton and $6,365/ton were not cost effective. Proposed Mont ana 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 sorb ent injection was cost effective on a costper-ton basis, 77 Fed. Reg. at 24,047, EPA conclude d 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 co nsider the degree of anticipated visibility improvement. 42 U.S.C. § 7491(g)(2). Accordi ngly, 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 Ca ney 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 visibi lity improvements at Caney Creek and Upper Buffalo from the installation of dry FGD at Whit e 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 co st of installing dry sc rubbers at White Bluff to achieve these insignificant improvements, whet her 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 th is Proposed Rule. Accordi ngly, the installation of dry scrubbers cannot be considered BART for SO 2 at White Bluff.

Response: As we discuss in our responses to other comm ents that treat the i ssues 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 th at 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). He nce, Entergy’s comparison to our previous actions is not valid. When considered in conj unction with the significan t visibility benefits expected to occur from the installation of these scrubbers, we consider th e 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 allo wed 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 Bl uff SN-01, SN-02 and Flint Creek at a cost determined by the plant ope rators to be $2,913/ton SO 2 , $3,355/ton SO 2 , and $3,845/ton SO 2 , 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 Independenc e would be similar to the costs at White Bluff.

EPA claims that such additional costs, includ ing 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 expe rtise in power plant construction, public utility financing, or public ut ility cost recovery and rate regu lation; thus its cost estimates for White Bluff, Flint Creek and Independen ce are not entitled to deference. See, King v.

Burwell , 135 S. Ct. 2480 (2015) (where regulatory agency does not have exper tise in the field, its interpretations are not subject to deference.) The ultimate cost of EPA's BART and Reasonable Progress determinations to Entergy, AEP/SWEP CO, and AECC and its me mber cooperatives is limited, because they will be entitled by law to rec over 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 explici tly provide for cost recovery of AFUDC under an interim rate surcharge). Thus, for purposes of White Bluff, Flint Creek and Independ ence, which are public utility BART sources, the proper cost to be c onsidered 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 Commissi on Uniform System of Accounts, and is utilized by both the FERC and state regulatory commissions, includin g the Arkansas Public Service Commission to account for construction financing co sts 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 Reasona ble 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. Recen tly, 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 th ose 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 EP A in its BART and Reasonable Progress

determinations. Michigan v. EPA , 135 S. Ct. 2699 (2015) (unreasonabl e 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 SO 2 , 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 require d by the Proposed FIP. The ultimate cost of EPA’s BART and Reasonable Progress determin ations 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 recove r from Arkansas ratepayers. Since Arkansas law allows public utilities to recover these additional costs that the EP A failed to consider due to its arbitrary and capricious applicati on of the Cost Control Manual, th ese costs are relevant factors

that the EPA should have considered in its BART and Reasonable Progress determinations. 526
Further, since the EPA lacks speci al expertise in public utility financing and public utility cost recovery and rate regul ation, the EPA’s cost estimates for these utility-owned sources are not

521 EPA’s adjusted and proposed cost-effectiveness number s for White Bluff, Flint Creek and Independence exceed the upper limit of EPA's projected cost-effectiveness range of $400 – 2,000/ton SO 2 for EPA’s presumptive SO 2 BART limits in support of the national Regional Haze Rule . Exhibit 17 to Nucor’s co mments, 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 whic h 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 re levant factors when it rendered its BART and Reasonable Progress de terminations for the power pl ants affected by the Proposed FIP, the Proposed FIP is unreasonable, arbitrar y, and capricious, and the EPA should withdraw

it.

In rejecting and adjustin g Entergy’s cost calculations for Whit e 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 ba sed on uncontrolled SO 2 emissions of 2.0 lb/MMBtu, a level much higher

than the emission rate from White Bluff’s histor ical 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

SO 2 /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 inthe 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 annua l dollars without any inflation. AFUDC is an accounting method. Assets under construction do not provide service to current

customers and thus associated interest and allo wed return on equity are not charged to current customers. Instead, AFUDC capitalizes these costs a nd 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 wo rds, 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 cons tant dollar approach found in the Cost Manual and

should not be included in BART cost-effectivene ss 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 nint h circuit court of appeals. As explained in more detail by the

court:

The purpose of the cost analysis requir ed 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 r ealistic, rather than inflated in one

direction or another. Considerati on of AFUDC would not further this inquiry, as AFUDC is ultimately refl ective 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 agen cy 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 SO 2 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 attit udes, not of the hard costs of the equipment and construction, which s hould be consistent across sites. While AFUDC and similar concepts ar e relevant for sales and ratemaking, including them would undermine th e sort of “apples-to-apples” comparison that EPA asserts is ne cessary 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 peri od 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 th e 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 disc ussed 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 SO 2 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 SO 2 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]. Enter gy explained that Owne r’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 assist ance 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 dur ing construction

 Transmission interconnec tion (if applicable)

 Fuel interconnection (if applicable)

 Owner’s mobilization costs

 Owner’s project management and support staff

 Insurance advisor

 Labor relations consultant277  Tax consultant

 Financial advisor

 Legal advisor

 Market consultant

 Community relations/comm unity outreach program.

Entergy states that Owner’s Costs are real cost s that the owner will incur during the project and are typically included in cost estimates prepared fo r large air pollution contro l retrofit projects. In fact, U.S. EPA’s Coal Quality Environmenta l 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 fo r 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 Co st 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 Independe nce Plant is legally and factually flawed, as it inappropriately relies on the White Bluff cost analysis , for which EPA inappropriately eliminated legiti mate costs.

[Entergy Mississippi Inc. (0168) p. 10-11] EMI stat ed 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, alt hough it is a factor in deciding the level of control necessary to establish RP Gs. Second, EPA’s cost analysis fo r the proposed controls at the Independence Plant relies upon the control cost anal ysis for White Bluff, which is inappropriate. By simply relying on the White Bluff cost analys is 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, EP A’s Reasonable Progress Guidance requires that EPA (1) identify the emissi ons units to be contro lled; (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 suffici ently 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 underes timation 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 SO 2 Cost TSD were correct, EPA’s determination that th e 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; Conw ay Corporation et. al. (0172) p. 13, 14-15; and EEAA (0173) p. 6, 7-8] EMI, Conway Corporati on et. al., and EEAA stat ed that among other errors in the White Bluff analysis which EP A relied on to develop the Independence cost analysis, EPA improperly excluded from the cost calculation legitimate cost s 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; replaci ng 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 tw o 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 expe rtise in the design of FGD systems, offered no explanation for overriding the FGD supplier’s dete rmination 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 Wh ite Bluff Plant’s owners and their customers, therefore rendering EPA’s cost analysis clearly erroneous.

EPA also wrongly eliminated and/or failed to cons ider millions of dollars of owner’s costs such as capital suspense costs, operating and maintenan ce 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 co sts is contrary to EPA’s own guidance 534 and previously approved regional haze impl ementation 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 th e 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 contro l 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 determin ations 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 revise d its five-factor analysis of controls at White Bluff as requested by EPA staff in an effort to expedite consider ation of the analysis but expressly reserved the ability to

include AFUDC in future control cost anal yses. 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 a ssertions, the EPA Control Cost Manual does not preclude inclusion of AFUDC and, in fact, the calc ulation provided as an example in the Control Cost Manual specifically in cludes AFUDC as a variable. 537 The fact that the example “assumes” AFUDC is equal to zero does not reflect a de cision 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 Regul ation 101. Accordingly, the costs of controls for the subject-toBART sources should appropriately include AFUDC.

For all these reasons, EPA should reject the existi ng cost analysis for the proposed controls and conduct an appropriate and accurate estimate of the cost of contro ls 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 cont rols 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 Indepe ndence Plant are cost-effective is arbitrary and capricious and represents a clear error of judgment.

First, EPA’s cost analysis for the proposed c ontrols at Independence re lies upon the control cost analysis for White Bluff, see SO 2 Cost TSD at 16, which is inappr opriate. By simply relying on its White Bluff cost analysis w ithout undertaking a site -specific analysis for Independence, EPA did not follow the steps necessary to identify the costs of c ontrols for reasonable progress purposes. EPA’s Reasonable Progress Guidance re quires that EPA (1) identify the emissions units to be controlled; (2) iden tify the design parameters for the controls; and (3) develop cost estimates based upon those design paramete rs. 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 co sts for the installation of dry

scrubbers at White Blu ff. EPA inappropriately revised Ente rgy’s control cost analysis by eliminating the consideration of appropriate cost s. EPA’s cost estimates are artificially low because they fail to account for key consider ations. As discussed elsewhere in Entergy’s comments, EPA unjustifiably revised important as pects of Entergy’s Revised White Bluff BART Analysis, upon which the reasonab le progress controls cost anal ysis for Independence is based. At the least, EPA must re-eva luate 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 EP A’s estimate. Based on the 2015 S&L FGD Cost Estimate, and assuming a 30-year life for the dr y FGD systems at Independence and identical costs, this results in an average cost-eff ectiveness 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 impor tantly, the cost per deciview improvement that

537 See Control Cost Manual at 1-32, 2-44.280 would result from installing these controls is es timated 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 Cr eek and Upper Buffalo.

Entergy Arkansas Inc., p.43-44, (0021); Ente rgy 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 SO 2 removed for Independence Unit 1 and $2,286 per ton of SO 2 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-a pproved SIPs. The Kentucky Regional Haze SIP, 76 Fed. Reg. 78,194, 78,206 (Dec. 16, 2011), used $2,000 per ton SO 2 as a screening threshold for

cost-effectiveness based on CAIR. In the No rth 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 SO 2 removed ($/ton SO 2 ), and the average costs per utility system ranged from $1,231 to $1,375/ton SO 2 .” EPA’s estimated cost effectiveness of dry FGD at Independence is significantly higher than these thresholds, at $2,477/SO 2 ton removed for Unit 1 and $2,286/SO 2 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 co stly in the reasonab le 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 SO 2 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 alr eady meeting and exceeding the URP necessary to achieve the national visi bility goal. Despite these prior actions, EPA unreasonably concludes that the proposed contro ls at Independence are cost effective for reasonable progress purposes.

Finally, even if EPA’s cost an alysis as detailed in the SO 2 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 co sts 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 reasona ble progress for the Independence facility, as we describe in our proposal. 538 We also believe we were cons istent with our reasonable progress Guidance. We disagree that fo r the purposes of assess ing reasonable progress, we erred in using our scrubber cost analysis for the White Bluff f acility as a good starting point for assessing the

scrubber cost-effectiveness of th e Independence facility. As we note in more detail in our proposal, the White Bluff and Indepe ndence Plants are sister facilitie s 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 constr ucting a master spreadsheet that contains information concerni ng ownership, location, boil er type, environmental controls, and other pertinent info rmation. Based on the similarities between the two facilities, in our analysis of costs for cont rols on Independence we relied on the total annualized costs of controls we developed for White Bluff. Due to th e similarities in the f acilities and the identical requirement for consideration of cost of contro ls under reasonable prog ress and BART, using the

cost of controls from White Blu ff was a reasonable approach for estimating the cost of controls for Independence Units 1 and 2. Using control costs fr om similar (let alone si ster facilities, as in this case) as the basis to assess the cost of c ontrols is a common practi ce. We do note that in calculating the cost effectiveness of SO 2 controls for Independence Units 1 and 2, we used

baseline SO 2 emissions data specific to the Inde pendence units to estimate the annual SO 2 emissions reductions due to controls. Enter gy has submitted comments critiquing our White Bluff scrubber cost analysis, and has submitted a re vised White Bluff scrubber cost analysis. We incorporate Entergy’s revised White Bluff cost an alysis 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 inst alling 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 info rmation presented by Entergy to conclude that the

differences in scrubber costs between the White Bluff and Independence f acilities are outside the +/-30% accuracy required for study level estim ates, which are based on “rough sketches,” “preliminary sizes,” “approximate sizes,” “rough es timates,” 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 analys is, which we have revised based on Entergy’s comments. We address this issue, as well as ot her 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 re asonable progress costs that we ha ve deemed to be too high in

other instances. As an initial ma tter, cost is only one of four required factors that must be considered in determining reasonable progress fo r 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 on e of the four mandatory factors explicitly listed

for consideration under CAA s ection 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 demons tration 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 reasonabl e progress....”. Regardless, we have recently finalized reasonable progre ss and long-term strategy SO 2 emissions in our Texas and Oklahoma FIP based on scrubber retrofits, similar to thos e discussed herein, at co st-effectiveness figures above those for the Independence facility. 542

Regarding the Kentucky proposal cited by Entergy, we disagree that requiring SO 2 controls for Independence is inconsistent wi th 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/SO 2 ton removed for Unit 1 and $2,634/SO 2 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 inconsiste nt with our approvals of the Kentucky and North Carolina RH SIPs. The commen ter contends that in our proposed approval of the Kentucky RH SIP, we a pproved the state’s use of a $2,000/SO 2 ton threshold. This is incorrect. In the preamble of our proposed approv al 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 SO 2 controlled or reduced as a threshold for costeffectiveness for that particular non-EGU source. We stated the following regarding Kentucky’s

evaluation of the Centur y Aluminum facility:

The Century Aluminum facility in Hawe sville, Kentucky, has four potlines with 2002 base year emissions of 4,985 tons per year of SO 2 which were identified as having a significant contribution at the Mammoth Cave Class I area. VISTAS evaluated control options a nd 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 contro ls. The cost effectiveness of SO 2 control suggested by the VISTAS control cost spreadsheet for potlines 1– 4 at Century Aluminum is $14,207 per ton of SO 2 removed. Since the cost of compliance for the control option is over seven times greater than the Commonwealth’s costeffectiveness threshold [$2,000] for r easonable progress, KYDAQ concludes that

there are no cost-effective controls availa ble 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 su mmary. As we discuss in our final action, 81 FR 317, “We receive d 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 determina tion 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/SO 2 ton screening

threshold: 544

Although the use of a specific threshold for assessing costs means that a state may not fully consider available emissions re duction 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, EP A is placing great we ight on the fact

that there is no indication in the SIP subm ittal that Kentucky, as a result of using a specific cost effectiveness threshold, re jected potential re asonable progress measures that would have had a meaningful impact on visibility in its Class I area. EPA notes that given the emissions reduc tions resulting from CAIR, Kentucky’s BART determinations, and the measures in nearby states, the visibility improvements projected for the affected Cl ass 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 reason able progress determination for the Century Aluminum units, we were not approvi ng or otherwise advocati ng Kentucky’s use of a $2,000/SO 2 ton threshold in the reasonable progress analysis. On the contrary, we expressed concern that the use of a speci fic threshold for assessing cost may result in a state not fully considering potential reasonable control measur es 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 reas onable progress analysis. Furthermore, our statements in the proposal indicate that had th ere been evidence of contro ls available above the $2,000/SO 2 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 th e approvability of Kentucky’s reasonable progress analysis.

North Carolina took a similar approach as Kentuc ky 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 th ese 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 cont rol strategy. The f acility-by-facility costs for EGUs under CSA ranged from 912 to 1,922 dollars per ton of SO 2 removed ($/ton SO 2 ), and the average costs per utility system ranged from $1,231 to $1,375/ ton SO 2 . These costs were estimated using the capital costs from the

544 76 FR 78206.284 CSA 2006 compliance plans and the projecte d operating costs provided by Duke Energy and Progress Energy. These costs we re used as a guide in determining

cost effectiveness. 545

We proposed to approve North Carolina’s determ ination that there are no reasonable controls

available for sources in the state for the firs t 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 re duction measures above its threshold that would result in meaningful visibility improvement, EPA believes that the North Carolina SIP ensures reasonable progre ss. 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 pot ential 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 th reshold 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 progre ss determination, we were not approving or otherwise advocating North Carolina’s use of that specific sc reening 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 t oo 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 contro l cost evaluation discussed in the response to comment that Entergy cites would have replaced the existing dr y scrubber with a new wet scrubber. Thus, the basic facts between our Indepe ndence reasonable progress an alysis 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 quot e that Entergy partially reproduces is:

As stated in our proposal, while this value is within the range of cost effectiveness values that North Dakota, ot her states, and we have c onsidered reasonable in the BART context, it is not so low that we are prepared to disapprove the State’s

conclusion in the reasonab le progress context.

As can be seen from an examination of the fu ll quote, this statement in no way constitutes a blanket comparison of the accepta bility of BART co st-effectiveness to that of reasonable progress determinations.

Entergy further states that re-a pplying its revised White Bluff cost analysis to the Independence

545 77 FR 11870.

546 77 FR 38189.285 facility would result in a co st-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 determinati ons 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 th e cost of dry and wet scrubbers for White Bluff contained conservative assumptions and incl uded errors that inflated the cost of these

controls. [Sierra Club et. al. (0171) p. 19-21] Sierra Club et. al. st ated that EPA proposed that

SO 2 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 SO 2 removed for Unit 1 and $2,101 per ton of SO 2 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 SO 2 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 cont rols would not comply with BART. Stamper Report at 30-32. In fact, Ms. Stamper conducted he r own analyses of the proposed controls and concludes that the proposed cont rols are even more cost-effec tive than EPA considered, can achieve an emission rate of 0.04 lb/MMBtu, will provide greater visibili ty benefit, and are reasonable compared to costs bor ne by sources in other states. Id. As such, EPA should

determine that SO 2 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 Organi zations, Prepared by Victoria R. Stamper, August 5, 2015 (“Stamper Re port”), discusses several ways in which EPA and Entergy used conservative assumptions that inflated the cost of the controls EPA is proposing and concludes that thes e 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 analys is 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 burni ng coal with an uncontrolled SO 2 rate of 2.0 lb/MMBtu.

See 80 Fed. Reg. at 18,970. As EPA correc tly noted, actual uncontrolled SO 2 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. Pa rt 51, App. Y § (D)(4)(d)(1). As such, a lower

uncontrolled SO 2 rate than that assumed by Entergy is appropriate for BART evaluation.

Second, EPA found that Entergy included undocumen ted costs that, under EPA’s Cost Control Manual, are inappropriate and c ould constitute double counting. See 80 Fed. Reg. at 18,971. EPA should require that Entergy appropriately documen t 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 we t scrubber, a dry scrubbe r, and a NID scrubber

that reflect achievable emission rates. Ms. Stamper used the SO 2 control cost spreadsheets that EPA recently used in the Texas regional h aze rulemaking, which are based on Sargent & Lundy Integrated Planning Model (“IP M”) cost modules. Stamper Repor t at 30-32. EPA’s conservative

cost-effectiveness calculations and Ms. Stamper’s revised cost -effectiveness calculations both

demonstrate that EPA should base the SO 2 BART emission limit on installation of scrubbers:

Revised SO 2 Control Cost-Effectiveness Evaluation for

White Bluff Units 1 and 2 547

White Bluff

Unit SO 2 Control Total

Annualized

Costs Tons SO 2 Removed Cost

Effectiveness EPA’s Cost

Effectiveness 548

1 Wet FGD $38,113,408 18,569 tpy $2,053/ton $3,336/ton

1 NID TM 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 NID TM 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 estimat es, assuming actual uncontrolled SO 2 emissions during the 2001- 2003 baseline period—which are lower than th e 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 Sier ra Club et. al.’s comments (providing SO 2 BART costs from other states).

Response: We have reviewed the section of the Stampe r 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 st ates 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 di d not propose to correct, except for minor oversights (noted in our responses to Entergy’s comments) that do im pact our proposed BART determinations.

Ms. Stamper proposes that we should have required the installation of scru bbers in three years, citing to a letter to Senator Ca rper dated November 3, 2010, in which David Foerter, executive

director of the Institute of Cl ean Air Companies (ICAC), which stated that wet scrubbers could be installed in 36 months, dry scrubbing technol ogy could be installed in 24 months, and dry sorbent injection could be installed in 12 mont hs. Ms. Stamper also cites to a number of scrubber installations that are planning on comple ting 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 guara ntee 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 fo r 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 Independenc e facilities, more cost effective than dry scrubbers (SDA; we discuss NID below) and th at BART should have been based on a wet

scrubber control level of 0.04 lbs/MMBtu for th e White Bluff facility (Independence is not subject to BART). Our scrubber cost analyses wa s built off of the analyses supplied by Entergy,

and we determined that wet scrubbers were significantly less cost e ffective—again, in the specific cases of the White Bluff and Independenc e facilities for BART and reasonable progress respectively. The scrubber analysis that Ms. St amper performs, uses a m odified version of the IPM cost algorithms we used in our TX-OK FI P. Although we find the use of those algorithms perfectly adequate for cost anal ysis for both BART and reasonabl e progress, we disagree with

the SO 2 baseline Ms. Stamper uses, rendering her scr ubber cost analysis a nd 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 circul ating dry scrubber is a promising SO 2 control option. We reviewed NID in our preliminary work but ultimat ely decided not to eval uate it as a control because we had no relevant operating data and no me thod 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 (2016 550 ), 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 SO 2 CEMS data for these two facilities from CAMD, computed 30-day BOD averages, achieved SO 2 control efficiencies, and determ ined 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% SO 2 control or 0.04 lb/MMBtu.

Indian River Unit 4 has achieved only 86% SO 2 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% SO 2 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 SO 2 Averages.xlsx.”

552 Burns & McDonnell, Indian River Unit 4, http://www.bu rnsmcd.com/Resource_/Project/1302/ProjectPdf/IndianRiver-Unit-4.pdf.288 Point Unit 3 is scheduled for shutdown in 2017. 553 Further, these faciliti es 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, wh en 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, non e of them burn PRB coal. For example, Seward burns high sulfur waste coal; Gilbert Unit 3 bur ns 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 SO 2 control efficiency as the wet F GD scrubber retrofits that we eval uated, the facilities in question are free to choose NID or any other technol ogy 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. stat ed that EPA proposed that NO X BART for White Bluffs Units 1 and

2 is an emission limitation of 0.15 lb/MMBtu based on the installation of Low NO X Burners (LNB) and separated overfire air (“SOFA”) . 80 Fed. Reg. at 18974. EPA estimated that operation of LNB/SOFA would ha ve an average cost effectiveness of $350 and $340 per ton of

NO x removed for Unit 1 and Unit 2, respectively. Id. EPA’s proposal to require LNB/SOFA represents a cost-effective way to achieve some NO X 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, a nd 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-effectiven ess 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 NO x BART at White Bluff Un its 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 NO X 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 NO x 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/pennener gy/2014/01/brayton-point- coal-fired-power-plantconfirmed-for-shut-down-by-2017.html.

554 http://www.google.com/url?sa=t&r ct=j&q=&esrc=s&source=web&cd=8 &ved=0CFEQFjAHahUKEwifqrrXvc_H AhWFjw0KHQL9Cc8&url=http%3A%2F%2Fpennwell.websds.net%2F2013%2Fbangkok%2Fpga%2Fpapers%2FT2S4O1-paper.pdf&ei=GkXiVZ1GoWfNoL6p_gM&usg=AFQjCNFWrXl39kOm6Ya_4YnvwtYZItZDOQ&cad=rja

555 http://www.ekpc.coop/pressreleases/2009%20press%20 releases/2009-04-01_Spurlock4_commercial_start.pdf289 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 NO X BART in other states. Stamper Report at 40-42. Ms. Stamper’s revised cost analysis relies on baseline NO x emissions from 2012-2014. Entergy used a 2009-2011 baseline for its NO X BART analysis because the company had installed in 2006 a “n eural network system” and conducted “extensive boiler tuning” at White Bluff Units 1 and 2 that resulted, according to Entergy, in reduced NO X emission rates. 80 Fed. Reg.18,969. In fact, NO x emission rates have increased from the NO X 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 Ai r Markets Database, White Bluff Unit 1’s NO X rates have been steadily increasing since the neural network installa tion, whereas White Bluff

Unit 2’s NO x rates have oscillated higher and lower. See id.

The BART guidelines require th at the “baseline emission rate should represent a realistic depiction of anticipated annual emissions fo r the source.” 40 C.F.R. Part 51, Appendix Y, Section IV.D.4.c. Given the variability of NO x emission rates, Entergy’ s selection of a 2009- 2011 baseline period is not a realisti c depiction of anticipated annual NO x emissions from the White Bluff units. In fact, Ente rgy’s selection of the 2009-2011 tim eframe for a baseline period reflects the period of lo west annual average NO x 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 NO x emissions were the second lowest three-year period of NO X emissions after 2006, and more recent periods of NO x 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 installa tion of the neural network system.

Ms. Stamper’s revised estimates (and even Ente rgy’s unrevised estimates ) show that LNB/SOFA plus SCR and LNB/SOFA plus SNCR are both cost effective as NO x BART for

White Bluff:

Revised NO x Control Cost-Effectiveness Evaluation fo r White Bluff Units 1 and 2 to Reflect

a 2012-2014 Baseline and to Recalculate Cost s for SCR to Achieve a 0.04 lb/MMBtu

Emission Rate 556

White Bluff

Unit NOx

Control Total

Annualized

Costs Tons NOx

Removed Cost

Effectiveness EPA’s Cost

Effectiveness 557

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 NO X emissions during 2012 to 2014 results in greater NO X reductions and lower cost-effectiveness numbers for LNB/SOFA, LNB/SOFA plus SNCR, and LN B/SOFA plus SCR (when SCR costs are based on the August 2010 module). As discussed in Section I.A.2.b of Si erra Club’s comments, EPA and states have found that costs of SCR plus combustion contro ls 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 NO X emissions compared to all other NO X controls evaluated by EPA.

Ms. Stamper states that we have not pr oposed to require installation of low NO X burners and separated overfire air as expe ditiously as possible. Specifica lly, 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 NO X burners and SOFA can be

installed in much shorter timeframes.

Specifically, the Institute of Clean Air Comp anies (ICAC) has indicted that the typical

installation timeframe for low NO X burners would take between 6-8 months from bid evaluation through startup of the technology. Most of the co mponents can be installe d 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 EP A’s final regional haze rule for

Arkansas should be sufficient tim e for Entergy to install low NO X burners and SOFA at White Bluff Units 1 and 2, and thus reflects implementa tion 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 in stalled 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 mont hs. 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 th e Clifty Creek power plant al so 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 Stam per report that treats this issue in more detail and respond to both it and this comment here. We disagree with the Si erra Club’s apparent position that BART controls must be selected ba sed 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 us e at the source, remaining useful life, and visibility improvement. 558

In critiquing our NO X 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 emissi ons. 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 va lue 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 20 12-2014. However, the BART Guidelines do not require that the baseline us ed in the cost effectiveness an alysis be constructed from the highest emissions from any give n year or years, only that, as Ms. Stamper acknowledges, the “baseline emissions rate should represent a realis tic depiction of anticipated annual emissions for

the source.” 559 As a first matter, we believe it was reas onable to select a base line after the neural network was installed in 2006, which elimin ates from consideration the highest NO X 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 anticip ated 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 impact ed our proposed NOx BART determination. In contrast, this would have produced a baseline lo wer for Unit 2, increasing the cost-effectiveness calculation by 9.6%, making the NO X controls less attractive. Hen ce, we find that no change is necessary to the White Bluff NOx baseline.

Ms. Stamper goes on to select a revised NO X baseline based on a maximum three year NO X average emissions calculation and inputs that , along with a rejection of our acceptance of Entergy’s SCR NOx emission rate of 0.55 lbs/MM Btu in favor of a lower SCR outlet of 0.04 lbs/MMBtu, into a revised SCR cost anal ysis. She supports her 0.04 lbs/MMBtu NO X rate by

558 Summarized from Section 51.308(e)(1)(ii)(A).

559 70 FR 39167.292 pointing to a number of high pe rforming SCR installations, includ ing 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 FI P, that it supp orts a 30 Boiler Operating Day (BOD) NO X average of 0.05 lbs/MMBtu for a S CR 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 S CR operating at that level for extended periods of time, such that we would feel comfortable th at 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 NO X BART cost analyses, we did

not criticize its choice of a SCR NO X emission limit of 0.055 lb s/MMBtu. Entergy’s SCR NO X emission rate of 0.055 lbs/MMBtu was ba sed 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 di scuss in our New Mexico FIP, “[Use of a] BOD would ensure that, when an outage occurs, th e emissions following star tup 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 aver aging period because it does not overweigh emissions spikes as a 30 ca lendar day average can do during an extended outage. As a consequence, we considered En tergy’s 0.055 lb/MMBtu aver age to be essentially equivalent to, or potentially more stringe nt than the 0.05 lb/MMBtu 30 BOD average we required in our New Mexico FIP, which forms th e bulk of Ms. Stamper’s support. Thus we (1) disagree with Ms. Stamper that SCR for White Bluff should be evaluate d on the basis of a NO X rate of 0.04 lbs/MMBtu, and (2) we believe Entergy’s use of a 30 day calendar NO X rate of 0.055

in its evaluation of SCR was r easonable (although as discussed el sewhere, we had other issues with Entergy’s White Bl uff BART analyses).

Ms. Stamper goes on to incorporate her adjusted NO X baseline and a NO X emission rate of 0.4 lbs/MMBtu into a revised SCR cost analysis, us ing the IPM SCR Cost algorithms. Due to the

issues we discuss above concer ning her revised baseline and NO X 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 co st 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 cal culation) 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 determin ation or in finalizing BART in a FIP. As required by the CAA and reflected in Section 51.308(e )(1)(ii)(A), visibility improveme nt 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 fluctu ations 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 mu st 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 in cremental visibility improvement (over our NO X BART determination based on LNB/SOFA) that would result from the in stallation of SNCR or SCR at the White Bluff facility.

We agree with Ms. Stamper that the typical in stallation timeframe for LNB/SOFA is a shorter timeframe than the three years we proposed fo r 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 NO X BART emission limit. We are not re quiring SCR controls for White Bluff

and we discuss this elsewhere in this documen t. Because we are not requiring that SCRs be installed at the White Bluff facility, this commen t 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-est imates are actually conservative. [Sierra Club et. al. (0171) p. 31-33] Sierra Club et. al ., stated that the co sts of both a wet a nd 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 larg ely 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 th at a scrubber is cost-effective. See Stamper Report at 60- 62. Ms. Stamper used the Sargent & Lundy IPM co st modules for wet and dry scrubbers. She

concluded that EPA’s cost-effectiveness estimate s are conservative, give n 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 th at EPA should have evaluated a NID circulating dry scrubber, which has a higher removal efficiency than trad itional dry scrubbers for the same cost. Ms. Stamper calculated that a NID scrubber woul d cost $2,816 per ton for Unit 1 and $2,676 per ton

for Unit 2. Id. The costs that Ms. Stamper calculated fo r 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 SO 2 emissions rate of 0.04 lb/MMBtu , which is lower than the 0.06

lb/MMBtu rate that EPA assumed co uld 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 prog ress controls EPA has approved. For example, EPA approved as reasonab le progress measures Wyoming’s decision to require SCR at the Jim Bridger units after finding th at the costs would range from $2,258 to $2,961 per ton of NO
x removed and the visibility improve ment 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 prog ress measures at the Colorado Springs Nixon294 plant, after finding that the contro ls would cost $3,744 per ton of SO 2 removed (which is more than FGD would cost at Indepe ndence) and would improve visibi lity by 0.46 deciviews at the most impacted area (which is less improvement th an a scrubber at Inde pendence 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 progr ess determination for the Tolk units in Texas would require scrubbers that have co st-effectiveness values of $3,178 per ton and $2,998

per ton, see 79 Fed. Reg. at 74,876; scrubbers wo uld cost less per ton of SO 2 removed at the Independence units than at the Tolk units. More over, the visibility improvement from a scrubber at the Independence units exceeds the visibil ity 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 d eciviews at Guadalupe Mountains, the most impacted area).

Cost-Effectiveness of Final Reasonable Progress Determinations 563

Facility Reasonable Progress

Control Cost, $/ton

Hawaii Electric Co., Kanoelehua Power Plant SO 2 emissions cap 564 5,587 Hawaii Electric Co., Puna Power Plant SO 2 emissions cap 5,583 Hawaii Electric Co., Shipman Power Plant SO 2 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 SO 2 emissions cap] was derived from EPA’s analysis of the costs of switching these units to 1% sulfur fuel.” Therefore, the cost-effec tiveness for the three Hawaii plants repres ents the cost to meet the SO2 cap by switching to low-sulfur fuel.295 Response: We have reviewed the section of the Stam per report that treats this issue in more detail and respond to both it and this comment he re. 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 anal yses, that we should have required that scrubbers be installed in three years, and fu rther notes that the Independence facility will benefit fr om coordinated and shared engine ering design and FGD fabrication, economies of scale benefits with FGD suppliers, a nd 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 fo r a quicker installation of sc rubbers 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 sign ificant energy and non-air quality impacts of these controls, stating that auxilia ry power requirements were includ ed with the costs of controls and thus this non-air qual ity issue is reflected in the cost e ffectiveness numbers. Further, she

notes that these SO 2 controls are commonly utilized, and thus it is not expected that there would be any adverse energy or non-air quality impact s that would justify ex cluding 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 SO 2 control level of 0.04 lbs/MMBtu in our reasonable progress determination for the Indepe ndence 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 th e cost of wet scrubbers was reas onable, in light of their higher cost and the relatively low add itional improvement in visibility over dry scrubbers. Although visibility is not one of the f our mandatory factors explicitly listed for consideration under CAA section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), st ates or EPA have the option of considering

565 Although visibility is not one of the four mandatory f actors explicitly listed for consideration under CAA section 169A(g)(1) or 40 CFR 51.308( d)(1)(i)(A), states or EPA have the optio n of considering the projected visibility benefits of controls in determining if the cont rols are necessary to make reasonable progress.

566 Although visibility is not one of the four mandatory f actors explicitly listed for consideration under CAA section 169A(g)(1) or 40 CFR 51.308( d)(1)(i)(A), states or EPA have the optio n of considering the projected visibility benefits of controls in determining if the cont rols are necessary to make reasonable progress.296 the projected visibility benefits of controls in determining if th e controls are necessary to make reasonable progress. Therefore, in our reason able progress analysis for Independence, we considered the visibility benefits of controls alongsid e the four statutory f actors, 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 NI D in our reasonable progress of the Independence facility.

Comment: EPA should have evaluated S NCR 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 Cl ass I areas in Arkansas,” EPA found it was appropriate to eval uate NOx controls for reasona ble progress measures. 80 Fed. Reg. at 18,995. Due to the similarity between In dependence Units 1 and 2 and White Bluff Units 1 and 2, EPA applied the same costs for low NO x burners/SOFA that were developed for the White Bluff units, but determined cost effec tiveness of these controls based on the NOx

emissions reductions that would oc cur 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 an d 2 would not be worth the additional costs

either. Id

.

However, SCR along with low NOx burners/SOF A 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 we re cost effective. Thus, EPA should have

evaluated low NOx burners/SOFA + SCR as reas onable progress measures for the Independence units. Ms. Stamper presents her own co st analyses for LNB/SOFA/SCR.

Response: We have reviewed the section of the Stam per report that treats this issue in more detail and respond to both it and this comment he re. First, there is no requirement in the Regional Haze Rule that all pos sible 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 vi sibility improvement due to the installation of LNB/SOFA at the Independence f acility is of a similar magnitude to that of the White Bluff facility. We reasoned that because (1) the Inde pendence and White Bluff facilities were sister facilities and very similar, a nd (2) we found that the incremen tal costs of SNCR and SCR for

White Bluff were not worth the resulti ng 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 w ith 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 SO 2 scrubbers and LNB/SOFA.

Comment: EPA’s determination that SO 2 BART for AEP Flint Creek is a Novel Integrated Desulfurization (NID) dry scrubber is appropri ate, 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 determinati ons on an analysis of the five statutory BART factors: (1) the costs of compliance, (2) the en ergy 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) th e 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 SO 2 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 F lint Creek and to set a

limit on SO 2 emissions. AEP’s evaluation, which EPA relie d on in its proposal, shows that a NID scrubber is cost effective, would produce signif icant 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 SO 2 BART compliance and any less effective cont rols 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 SO 2 removed. See 80 Fed. Reg. 18,966-67. The attached St amper Report confirms EPA’s conclusion that the controls proposed in the FI P are cost-effective. Ms. Stamper conducted her own analyses of the proposed controls and conc ludes that the proposed co ntrols 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 wh ich 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 18,9 65). 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 achievabl e with a NID scrubber, Ms. Stamper revised AEP’s cost analyses using EPA’s SO 2 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 scrubbe rs. Based on Ms. Stamper’s revised costeffectiveness estimates, both a wet scrubber and a NID dry scrubber are hi ghly cost-effective as

SO 2 BART for Flint Creek:

Revised SO 2 Control Cost-Effectiveness Evalua tion for Flint Creek Unit 1 570

Flint Creek

Unit 1 SO 2 Control Total

Annualized

Costs Tons SO 2 Removed CostEffectiveness AEP’s CostEffectiveness 571 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 fo r both wet and NID scrubbers are significantly

lower than AEP’s cost estimates and the technol ogies are equally cost effective. Moreover, wet

and NID scrubbers can achieve an emission rate of 0.04 lb/MMB tu, 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 SO 2 BART emission limit

based on installation of scrubbers, as shown by SO 2 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 SO 2 BART determinations show that the costs of SO 2 controls to

570 Stamper Report at 11.

571 80 Fed. Reg. 18966, Table 26.299 meet BART at EGUs range fr om $1,571 to $7,309 per ton of SO 2 removed. 572 Wyoming, for example, found that a new dry scrubber and baghous e at Dave Johnston Unit 4 was cost effective at $5,028 per ton of SO 2 removed. 573 EPA proposed a FIP of reasonable progress measures based on switching to a lower sulfur fuel oil at the fu el oil-fired boilers at the Kanoelehua Hill Power Plant, the Puna Power Plant, and the Ship man Power Plant at a cost-effectiveness of approximately $5,600 per ton. 574 Colorado based its SO 2 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 SO 2 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 SO 2 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-eff ectiveness calculations of $2,498 (wet scrubber) and $2,405 (NID scrubber) per ton of SO 2 removed for Flint Creek are comparab le 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 SO 2 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 Stam per 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 subm itted 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 ar e reasonable compared to the costs ot her similar sources have had to bear to comply with region al 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-effectiven ess values. Therefore, we believe a wet scrubber and NID are more cost-effective (i.e., less dollars per ton of SO 2 removed) than estimated by AEP (see table above). However, we did not adjust the cost numbers and cost-effe ctiveness 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 estim ates were adjusted, yet the installatio n and operation of a wet scrubber is projected to result in minimal incremental visibility improvement over NID.300 cost-effectiveness values. Nevertheless, even di sregarding 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 co st analyses for wet a nd NID scrubbing, based on the IPM cost algorithms we used in our recent Te xas-Oklahoma FIP. In so doing, she applies the SDA cost algorithm to NID, citing to documentati on that indicates that NID may be 1-2% lower in cost to an SDA system. Ms. Stamper concl udes that AEP’s wet FGD and NID cost analyses (largely accepted by us) employed overly conserva tive 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. Stampe r 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 be nefit 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 ot her statutory factors. Visibility is one of the five statutory factors we are required to consider in a BART analysis. In a reasonable progress analysis, alt hough visibility is not one of the four mandatory factors explicitly listed for consideration under C AA section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), states or EPA have the option of considering the pr ojected visibility benef its of controls. In our reasonable progress analysis for Independence, we c hose to also consider vi sibility alongside the four reasonable pr ogress factors.

Ms. Stamper argues that both wet an d dry scrubbers are capable of ev en 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 th ese, we place the highest priority on the latter – actual monitoring data that dem onstrates that on similar units burning similar coals the control technology is capable of the level of control we are requiring. We belie ve it is important in making such an analysis to focus on the level of c ontrol, rather than on just the emission limit. We do not believe emission limits can be comp ared across units, unless similarity can be demonstrated, including the sulfur content of the coal being burn ed. We extensively analyzed the performance potential of wet scrubbe rs in our recent Texas-Oklahoma FIP. 582 We accounted for the many factors that could influence wet scrubber performance, in cluding principally, the type of coal burned and the sulfur level in that coal. We concl uded 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 Implem entation Plans; Interstate Visibility Transport State Implementation Plan to Address Pollutio n Affecting Visibility and Regional H aze; 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, a lthough 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 conclusi on. Therefore, because we have

concluded that in this instance the cost-effectiv eness of wet scrubbers is not justified by their relatively small additional visibility benefit, we disagree that SO 2 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 emi ssion 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 stat utory 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 y ears is appropriate for a scrubber cost analysis. We also agree

that our use of a 7% interest rate may be higher than the actu al cost that AEP may incur in financing the cost of a scrubber system that were we to adopt a lower in terest rate, the cost effectiveness of our proposed controls would beco me much more attractive (lower $/ton). For cost analyses related to government regulations, an appropriate ‘‘so cial’’ interest (discount) rate should be used, not the source’s actual rate of borrowing. OMB Circular A–4, providing Federal agencies guidance on developing regulato ry 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 st ates that a real discount rate of 7 percent should be used as a base-case fo r 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 da ta. It is a broad measur e that reflects the returns to real estate and small business capita l as well as corporate capital. It approximates the opportunity cost of capital , and it is the appropr iate discount rate whenever the main effect of a regulation is to displace or alter th e use of capital in the private sector.

The yearly updates to OMB Circular A-94 to wh ich the commenter references, are to Appendix C. However, as the letter that tr ansmits 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 co st-effectiveness analysis, as specified in the

Circular.” Note that the refere nce 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 alre ady begun on the Flint Creek NID system, and AEP will be using it to co mply with our MATS Rule, we should truncate the 5 years we have proposed for compliance to May, 2016, which by the public ation 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/f iles/omb/assets/omb/circulars/a004/a-4.pdf

584 https://www.whitehouse.gov/sites/de fault/files/omb/assets/a94/a094.pdf

585 https://www.whitehouse.gov/sites/defau lt/files/omb/memoranda/2015/m-15-05.pdf302 of our proposal that the Flin t Creek NID system installa tion 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 expediti ously as practicable. 42 U.S.C. § 7491(b)(2)(A). After carefully consider ing the information the commenter has brought to our attention, we believe that a five year compliance date is not appropriate for the SO 2 BART controls we are requiring for Flint Creek. Therefore, based on th e information that was made available to us during the comment period, we are finalizing a sh orter compliance date. As discussed in more detail in a separate response, we are finalizi ng an 18-month compliance date for the SO2 BART

emission limit for Flint Creek Unit 1.

Comment: Control scenarios that include S CR and SNCR are both cost-effective as NO X BART for Flint Creek Unit 1. [Sierra Club et. al. (0171) p. 17-18] Sierra Club et. al. stated that

for NO X , 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- NO X 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 NO X removed. EPA’s proposal to require LNB/OFA represents a cost-effective way to achieve some NO X emission reductions at Flint Creek and, therefore, is the absolute minimum th at EPA must require as selection of anything less stringent would be arbitr ary, 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, whic h Ms. Stamper explains in her report is far more cost-effective than EPA cal culated, would achieve lower emission rates and greater visibility benefits, and sa tisfies all of the BART standards. As such, we urge EPA to find

that NO X BART for the Flint Creek plant is an em ission rate of 0.04 lb/MMBtu based on the

installation of an SCR.

Sierra Club et. al. stated that the Stamper Report discusses seve ral ways in which EPA and AEP used very conservative assumptions that infl ated the cost of the SCRs and SNCRs as NO X BART options for Flint Creek. Ms. Stamper’s analysis s hows 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 re vised cost-effectiveness estimates (provided below) use a 30-year life.

To more properly evaluate the cost effectiveness of LNB/OF A plus SCR and LNB/OFA plus SNCR at Flint Creek, Ms. Stamper has provided re vised 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 es timate SCR costs in its evaluation of NO X 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 NO x Control Cost-Effectiveness Evalua tion for Flint Creek Unit 1 586

NO X Control Total

Annualized

Costs Tons NO X
Removed Cost

Effectiveness AEP’s Cost

Effectiveness 587 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, LN B/OFA plus SCR to meet a NO X limit of 0.04 lb/MMBtu is very cost effective (based on either version of the Sargent & Lundy SCR cost module). These NO X controls would also remove clos e to 700 tons per year more NO X than evaluated by AEP. As this analysis also shows, LNB/OFA plus SN CR 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 sour ces 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 NO X 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 effec tiveness 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 Apach e, Cholla, and Coronado power plants at costeffectiveness values ranging from $2,275 to $3,472 per ton of NO X 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 LN B/OFA ranging from $2,635 to $4,461 per ton of

NO x removed (2008 dollars) are reasona ble 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); s ee 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 cost s 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 rule makings that required SCR plus combustion controls on EGUs, EPA did not c onsider incremental cost-effectiveness numbers ranging from $1,903/ton to as high as $8,968/ton to be unreas onable 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 LN B/OFA are reasonable to justify requiring this combination of control technologies to meet the NO X BART requirements at Flint Creek.

Response: We have reviewed the section of the Stam per report that treats this issue in more detail and respond to both it and this comment here. We disagree with the Si erra Club’s apparent position that BART controls must be selected ba sed 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 us e at the source, remaining useful life, and visibility improvement. 593

We note that we provided comments to ADEQ 594 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 peri od in the evaluati on 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 amorti zation period in the cost analysis of SNCR. Any air pollution contro ls 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-eff ective (i.e., less dollars per ton removed) than estimated in AEP’s eval uation. 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 deci sion. [T]he incremental visibility benefit expected from the installation and operation of SNCR is too small to justify the cost of these controls co mpared to combustion controls alone. Therefore, we did not revise the am ortization period and the average cost

effectiveness calculations for SNCR.

Ms. Stamper also states that AEP overestimat ed the cost of SNCR because it based it on a

reduction of from 0.31 lbs/MMBtu to 0.2 lbs/MMBt u, 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 SW EPCO’s SNCR cost analysis with another column added to

include these corrections:306Parameters/Costs Equation AEP SWEPCOEPABoiler design capacity, mmBtu/hr (QB) QB6324 6324Total operating time (top, hrs/yr) top= CFtotal× 8760 hrs/yr 7752 7752Total Capacity Factor (CFtotal) CFtotal= CFplant× CFSNCR0.92 0.92Plant Capacity Factor (CFplant)20.92 0.92SNCR Capacity Factor (CFSCNR)3CFSNCR= tSNCR/365 1 1Assumed NOx removal efficiency (ηNOx)435%13.04%Uncontrolled NOx rate (NOxin,lb/MMBtu)50.330.23Electricity Cost (Costelect, $/kwh)6$0.05 $0.05Water Cost (Costwater, $/gal)7$0.00362 $0.00362Coal Cost (Costcoal, $/MMBtu)8$2.50 $2.50Coal HHV (Btu/lb)99,000 9,000Cost of Ash Disposal (Cash, $/ton)10$9.0 $9.0Capital recovery factor (CRF) CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate,a = equipment life0.09440.0806a. Equipment CRF, 20-yr life, 7% interestCost Index11a. 2011 Cost Index 585b. 1998 Cost Index 389.5Capital CostsDirect Capital Cost (A) DC ($) = ($950/MMBtu) × QB× ((2375MMBtu/hr/QB)^0.577) × (0.66 + 0.85ηNOx) ×(CI2011/CI1998)$5,007,199 $4,031,069Indirect Installation Costs ($)General Facilities 0.05 × A $250,360 $201,553Engineering and Home Office Fees 0.10 × A $500,720 $403,107Process Contingency 0.05 × A $250,360 $201,553Total Indirect Installation Costs (B) = General Facilities Cost + Engineering and Home OfficeFees + Process Contingency$1,001,440 $806,214Other Installation Costs ($)Project Contingency (C) C = 0.15 × (A + B) $901,296 $725,592.50Total Plant Cost (D) D = A + B + C $6,909,934 $5,562,876307Allowance for Funds During Construction (E) E = 0 (Assumed for SNCR) $0 $0Royalty Allowance (F) F = 0 (Assumed for SNCR) $0 $0Preproduction Cost (G) G = 0.02 × (D + E) $138,199 $111,258Inventory Capital (H)12H = Volreagent(gal) × Costreagent($/gal) $76,102 $8,957Costreag, 50% Urea solution ($/gal)131.54 1.54Volume of Reagent Tank (Volreagent(gal)) Volreagent(gal) = qsolx days of reagent supply × 24 hr/day 49,417 5,817Urea solution volumetric flow rate (qsol, gal/hr)14qsol= (msolx 7.481 gal/ft3)/ρreagent147.07 17.31Mass flow rate of urea solution (msol, lb/hr)15msol= mreagent/Cureasol1,395.84 164.30Mass flow rate of reagent (mreagent, lb/hr)16mreagent= (NOxinx QBxηNOx× NSR x Mreagent)/(MNOxxSRT)697.92 82.15Normalized Stoichiometric Ratio (NSR) NSR = ([2 × NOxin+ 0.7] ×ηNOx)/NOxin1.43 0.66Initial Catalyst and Chemicals (I) I = 0 (Assumed for SNCR due to no catalyst) $0 $0Total Capital Investment (TCI) (Capital Cost) TCI = D + E + F + G + H + I $7,124,235 $5,683,091Annual Costs ($)Annual Maintenance Cost (J) J = 0.015 × TCI $106,864 $85,246Annual Reagent Cost (K) K = qsol× Costreag× top$1,755,781 $206,662Annual Electricity Cost (L) L = P × Costelect× top$58,064 $18,344Power (P, kW) P = (0.47 × NOxin× NSR × QB)/9.5 149.80 47.33Annual Water Cost (M) M = qwater× Costwater× top$18,775 $2,210Water flowrate for SNCR system (qwater, gal/hr)17qwater= (msol/ρwater) × [(Cureasolstored/Cureasolinj) - 1] 669.06 78.75AnnualΔCoal Cost (N) N =ΔCoal × Costcoal× top$109,558 $12,895Additional coal required (ΔCoal, MMBtu/hr)18ΔCoal = (Hv × mreagent× [(1/Cureasolinj) - 1])/106Btu/MMBtu5.65 0.67AnnualΔAsh Cost (O) O = (ΔAsh × Costash× top)/2000 lb/ton $1,643 $193Additional ash generated (ΔAsh , lb/hr)19ΔAsh = (ΔCoal × ashproduct × 106Btu/MMBtu)/HHV 47.11 5.54Direct Annual Costs (DAC)/Variable O&M DAC = J + K +L + M + N + O $2,050,684$325,551Indirect Annual Costs (IDAC)/AnnualizedCapital CostIDAC = CFR × TCI $672,477 $457,980Total Annualized Costs (TAC) TAC = DAC + IDAC $2,723,162 $783,531TAC = DAC + IDAC $2,723,162308 Note in the above table, we ha ve added another column with our corrections to (1) the assumed NOx removal efficiency ( η NO X ), (2) the uncontrolled NOx rate (NO X in, lb/MMBtu), and (3) a recalculation of the capital recove ry 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-effectivene ss calculation as presente d in its BART analysis, 597 along with our

corrections. The first table is AEP SWEPCO’s cost-effectiveness calcu lation. 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 calculatio ns. In the third table, we ca rry 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 6-3.309AEP SWEPCOControlTechnologyBaselineNOxEmissionRate(tpy)ControlledEmissionLevel(lb/MMBtu)ControlledEmissionRate(NOx tpy)AnnualEmissionsReductions(NOx tpy)CapitalCost ($)AnnualCapitalCost($.yr)AnnualFixedO&M($/yr)AnnualizedVariableO&M($/yr)TotalAnnualCost($/yr)AverageCostEffectiveness($/ton)IncrementalCostEffectiveness($/ton)LNB/OFA5,120.27 0.23 4,294.65 825.62 $16,000,000 $1,289,382 $240,000 $132,364 $1,454,621 $1,762 -LNB/OFA/SNCR5,120.27 0.20 3,771.82 1,348.45 $16,000,147 $1,398,940 $240,000 $133,033 $4,177,782 $3,098 $5,209AEP SWEPCO (tons reduced and total annl cost corrected)ControlTechnologyBaselineNOxEmissionRate(tpy)ControlledEmissionLevel(lb/MMBtu)ControlledEmissionRate(NOx tpy)AnnualEmissionsReductions(NOx tpy)CapitalCost ($)AnnualCapitalCost($.yr)AnnualFixedO&M($/yr)AnnualizedVariableO&M($/yr)TotalAnnualCost($/yr)AverageCostEffectiveness($/ton)IncrementalCostEffectiveness($/ton)LNB/OFA5,120.27 0.23 3,798.91 1,321.36 $16,000,000 $1,289,382 $240,000 $132,364 $1,661,746 $437 -LNB/OFA/SNCR5,120.27 0.20 3,303.40 1,816.87 $23,124,235 $1,961,859 $240,000 $2,183,048 $4,384,908 $2,413 $5,496EPA (tons reduced, total annl costs, control level and control efficiency corrected)ControlTechnologyBaselineNOxEmissionRate(tpy)ControlledEmissionLevel(lb/MMBtu)ControlledEmissionRate(NOx tpy)AnnualEmissionsReductions(NOx tpy)CapitalCost ($)AnnualCapitalCost($.yr)AnnualFixedO&M($/yr)AnnualizedVariableO&M($/yr)TotalAnnualCost($/yr)AverageCostEffectiveness($/ton)IncrementalCostEffectiveness($/ton)LNB/OFA5,120.27 0.23 3,798.91 1,321.36 $16,000,000 $1,289,382 $240,000 $132,364 $1,661,746 $1,258 -LNB/OFA/SNCR5,120.27 0.20 3,303.40 1,816.87 $21,683,091 $1,747,362 $240,000 $457,915 $2,445,277 $1,346 $1,581310 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 incremen tal cost effectiveness of SNCR + LNB/OFA over LNB/OFA alone is $1,581/ton. We re-apply the BA RT five factors, with emphasis on cost and visibility improvement. The incremental visi bility improvement of SNCR + LNB/OFA over LNB/OFA alone is 0.033 dv at Caney Creek a nd 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 relativel y small at Caney Creek and to be very small in the remaining three affected Class I areas. 598 We conclude that despit e the improvement in the

cost-effectiveness of SNCR + LNB/OFA over LN B/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 re port 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 ar e in line with other required SCR installations, the Flint Creek facility should sim ilarly 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 leve l 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 info rmation Ms. Stamper presents and conclude, as we did in our New Mexico FIP, that it suppor ts a 30 Boiler Operating Day (BOD) NOx average

of 0.05 lbs/MMBtu for a SCR installati on at the Flint Creek facility.

Second, as we indicate in Table 44 of our TS D 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 Cr eek. We further note that AEP SWEPCO’s SCR cost analysis is almost completely undocum ented. 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 c ontrol level of 0.055 lb s/MMBtu rather than the modeled rate of

0.067 lbs/MMBtu 599 , we estimate that the resulting visibi lity improvement at Caney Creek would be no higher than 0.26 dv. 600 Based on this adjustment, the in cremental visibility improvement

of SCR + LNB/OFA over SN CR + LNB/OFA is 0.146 dv. Even accepting Ms. Stamper’s SCR cost analysis of $3,511/ton (which would be higher were it revise d using a controlled NO X rate of 0.05 lbs/MMBtu) and taki ng into consideration th e adjustments we have made to the cost analysis for SNCR + LNB/OFA, the incrementa l 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 woul d 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 incremen tal cost of the SCR installation.

Comment: EPA’s NO X 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 th at EPA proposed a FIP for Lake Catherine Unit 4 that requires an emission li mit of 0.22 lb/MMBtu on a 30 boiler operating-day rolling average based on the installation and opera tion of burners out of service (BOOS). 80 Fed. Reg. at 18,978. EPA conducted its own analysis of NO x 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 en ergy and non-air quality environmen tal impacts of compliance, (3) existing pollution controls in use at the source, (4) the remaining usef ul 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 visi bility 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 NO X burners, and over-fired ai r, 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 a ssociated with its selected control technology, and overstated the visibility benefits of each c ontrol scenario due to a reliance on Entergy’s flawed maximum daily average NO X emission rate. Therefore, EPA must do a new NO X BART analysis that corrects these flaws and consider s whether SCR represents the best system of

continuous emission reduction for NO X at Lake Catherine Unit 4.

EPA miscalculated the cost effectiveness for a ll control scenarios. While EPA disapproved and corrected some of Entergy’s inflated costs, EPA nonetheless significan tly underestimated the costs of BOOS in its FIP. As Ms. Stamper’s re port explained, installa tion 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 NO X BART analysis). EPA failed to include

these additional costs in its BOOS cost estimate . Including all of the cost s for BOOS installation and operation will make BOOS less cost effectiv e. In addition, EPA likely overestimated the

labor installation costs of low NO X burners, over-fired air, SNCRs, and SCRs in its FIP. As Ms. Stamper’s report noted, EPA likel y 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 al l of its cost-effectiveness analyses for NO X controls312 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 “s ignificantly 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 hist orically operated at le ss 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 NO X analysis, this unit had an average capacity factor of 21.2% based on heat input. Stam per 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) cap acity factor. Had EPA used a higher capacity factor, it would

have found an increase in the tons of NO X 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 NO X 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 le gally flawed. EPA must conduct a

new NO x BART analysis that corrects these flaws a nd considers whether SCR represents the best system of continuous emission reduction for NO X at Lake Catherine Unit 4. In doing so, we urge EPA to not place inappropriate weight on the incr emental 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-effectiven ess, in terms of dollars per ton removed [average cost effec tiveness], 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 th e 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 Sie rra Club et. al.’s comments.

Response: We have reviewed the section of the Stam per 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 NO X 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 emi ssion rate despite contra ry evidence, failed to consider the increased greenhouse gas emissions a ssociated with its selected control technology, and overstated the visibility benefits of each c ontrol scenario due to a reliance on Entergy’s flawed maximum daily average NO X 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 th e increase in greenhouse gas emissions that may occur as a result of a pot ential control strategy, as there is no basis for doing so in the Regional

Haze Rule. 602

Ms. Stamper states that we erre d in agreeing to the use of a 10% capacity factor in our cost calculations. She states that we previously noted that Unit 4 had previ ously operated at a 46% capacity factor in our 2011 proposal. 603 The language that Ms. Stampe r 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 th e operation of this un it to 10% capacity, the facility can legally be operated we ll above the 10% capac ity factor assumed by Entergy. Thus, any cost effectiveness analysis based on a 10% capacity factor is likely to significantly infl ate the cost per ton of cont rolling this unit. In support of the 10% capacity utilization factor, En tergy 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 th e 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 ei ther ‘‘(1) The ratio of a unit’s actual annual electric output (expre ssed 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 ra tio of a unit’s annua l 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 i nput or electric output. Nevertheless, Ms. Stamper states that she believes that we s hould have calculated the Lake Catherine Unit 4 capacity on the basis of operatin g time. In response, we investigated the correlation between heat input and operational time to NO X emissions for Lake Catherine Unit 4, reasoning that because our cost analyses was for NO X control, changes in capacity should correlate to changes in NO X

. 605 As the following graph indica tes, there is a good correlation between heat input and NO X , but no correlation betw een operational time and NO X 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 referen ce: 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 h ours in 2002 (64.5% utilization); 3,972 hours in 2003 (45.3% utilization); 1,534 hours in 2004 (17.5% utiliza tion); 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 capac ity should be based on ho urs operated per year,

and conclude that the historical ca pacity 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 Cath erine 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 responded 607 by pointing us to our BART Guide lines, which states that, “The baseline emissions rate should represent a realistic depiction of anticip ated annual emissions for the source.” 608 Our conclusion is that like an emission baseline, the assume d 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 emphasi s 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 ye ars results in a value of 6.8%. Thus, assuming a 10% capacity factor is conserva tive, and we disagree with Ms . Stamper that we erred in accepting Entergy’s assumption of a 10% capacity fact or 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 NO X emission reductions on Unit 4, if nece ssary, 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 re view of Arkansas’ next regional haze SIP.

Ms. Stamper alleges that the Sargent & Lundy documentation submitted by Entergy to support its analysis and cost calc ulations is not consistent with the BART analysis presented in Entergy’s 2013 revised BART analysis or with our propos ed 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 s ubstantiate these allega tions or why they are germane, so we are unable to assess them.

Ms. Stamper states that the NO X BART analysis for Lake Cath erine Unit 4, found in the May 2013 Sargent & Lundy report, includes an Estimate No. 31815A, for low NO X burners and separated overfire air at Lake Catherine Un it 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 SO 2 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 additiona l cost for Entergy la bor and loaders was already included in the Sargent & Lundy low NO X burner/SOFA estimate. Further, Entergy added the same am ount of $1,634,363 in Entergy employee labor and loaders to the Sargent & Lundy estimates for low NO X burners/SOFA plus SNCR and to the Sargent & Lundy costs for low NOx burners/OFA plus SCR.

The estimate Ms. Stamper cites, Estimate No. 31 815A, 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 co ver the labor and subcontract to install the LNB/OFA system, whereas the $1,634,363 Entergy a dded refers to its own employee labor and loaders. We therefore conclude that Ms. Stampe r has not demonstrated that the additional charge of $1,634,363 in Entergy employee labor and load ers was inappropriate for the LNB/OFA, SNCR, and SCR cost estimates.

Ms. Stamper states that it appear s that Entergy overstated the NO X reductions from BOOS at

Lake Catherine Unit 4. She states the En tergy 2013 revised report assumes lower NO X emission rates for BOOS than previously evaluated in the 2007 BART analysis for Lake Catherine, and Entergy’s 2013 revised BART analysis assumed a NO X rate of 0.22 lb/MMBtu with BOOS, despite the Sargent & Lundy an alysis of Lake Catherine Unit 4 found the achievable NO X 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 NO X 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 En tergy can meet its proposed NO X 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 Un it 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 NO X limit that it itself claims to be able to achieve. We therefore disagree with Ms. Stamper. Furthermore, as we di scuss elsewhere, the 0.22 lb/MMBtu emission limit refers to the 30-day BOD limit and the 0.24 lb/MMB tu emission rate is a short-term emission

rate based on a 50% reduction of th e 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 & Lu ndy stated that, to achi eve 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 Catherin e Steam Electric Station, May 2014. See pdf page 16.317 rates with BOOS, there would need to be an incr ease 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 a ttemperation 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 da ta 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 po ssible 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 si ze for the higher fuel flow rates. ETEC, Inc. has experience with several units sim ilar in design to Lake Catherine – Unit 4 that have been able to achieve full cap acity 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 bu rners would be opera ted “fuel rich”, lowering NO X formation. Using this approach would reduce NOx emissions at a small capital cost. The costs for BOOS w ith recovery of full unit capacity were based on vendor cost information for a prev ious project adjusted on a $/kW basis

to Lake Catherine – Unit 4 and escala ted 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, supe rheat and reheat attemperation sprays, tube metal temperatures and burner tilt positions for the new operating conditions. The expected NO X reduction would range from 40% at low load to 50% at full

load and NO X levels of 0.24 lb/MMBtu.

It appears to us that the cost s Ms. Stamper references for BH P 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 boi ler OEM or consultant would need to evaluate the existing fuel piping, superheat and reheat atte mperation 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 “a ny modifications to the boiler” costs

discussed above were not specifically applicable to Lake Ca therine 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 LN B/SOFA, LNB/SOFA/SNCR, and LNB/SOFA/SCR are likely lower than we have determined, and are al l within a range that ha s 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 increm ental cost-effectiveness as high as $30,000 to $57,000/ton. She states that we must correct th ese 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 31.318 achievable emission reductions from NO X controls and then redo the five factor NOx BART analysis for Lake Catherine. As we have discu ssed 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 CF R 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 ju stify their increased visibility benefit for the

Lake Catherine Unit 4 to meet BART. We a ddress 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 ma y 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 cost s 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 stat ed that the analysis EPA conducted for Independence included a cost analysis where EP A 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 thei r RH evaluations, EPA’s Cost Manual, does

not allow inclusion of all actual costs associated with retrofitting vari ous control technologies.

The Cost Manual results serve as a reasonable to ol 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 accu rately considering the whole cost impact. The Cost Manual is fundamental ly 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 so urces.”) relative to producing a value to be compared to actual $/ton by excluding real co sts 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 in stalled costs.

Response: We address specific criticisms concerni ng 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 re gional haze evaluations

numerous times that our Control Cost Manual do es not allow inclusion of all actual costs associated with retrofitting vari ous control technologies. We cannot find any specific reference to our making such a statement and we believ e AEP SWEPCO’s statement is inaccurate and misleading. Certain costs (e.g., AFUDC) are disallo wed (see our response to related comments),

but that does not invalidate the use of the Contro l 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 st ate 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 EP A Air Pollution Control Cost Manual. As

we describe in our Oklahoma final ac tion the CCM uses the “overnight” method

of cost estimation:

The Control Cost Manual us es 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 estim ated 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 overni ght 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 thei r returns using the principle of the time value of money ... The process through whic h future cash flows are translated into current dollars is called present value analysis. When the cash flows involve income and expenses, it is also comm only 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 intere st (discount) rate and then add them together.’’ Our proposed a pproach 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 Contro l 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 pr ogress cost evaluations as well, to ensure consistency in evaluating cost-effectivene ss calculations across BART and non-BART evaluations. Although the Contro l Cost Manual provides for specific methods for estimating capital costs in some instances, its use of the ove rnight method, the issue he re, is applicable to every control cost analysis. We also disagree with AEP SWEPCO’s statement that the Control Cost Manual is fundamentally flawed. AEP SWEP CO’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.320 does not directly address the controls needed to control air pollution at el ectrical generating units is based on an incomplete and misleading reprod uction of a quote. The full quote is actually: 616

This Manual provides up-to-date informa tion on point source and stationary area source air pollution controls for volatil e organic compounds (VOCs), particulate matter (PM), oxides of nitrogen (NOX) , and some acid gasses (primarily SO 2 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 contro ls 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 devi ces 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 resour ce for utilities. In

fact, many power plant permit applicati ons use the Manual to develop their costs. However, comparisons between u tilities and across the industry generally employ a process called “levelized cos ting” 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 es timating the cost of controls for power plants, which is why the BART Guidelines require its use, and w hy it has in fact been

used to do so in numerous instances.

Comment: EPA did not justify why it refused to take into account actu al costs of emission controls when evaluating BART. [UARG (0176) p. 8-9] UARG stat ed that the CAA and EPA’s BART rules require EPA to take actual costs of em ission 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 an d 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 interp retation of that methodology – is legally mandated. For instance, with respect to the White Bluff Plan t, 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 Contro l Cost Manual methodology.” 80 Fed. Reg. at 18,971;

see also id . at 18,973 (stating, in proposing to reject capital suspense co sts, that those costs “do not appear to be valid costs under the Contro l 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 duri ng construction” because such

616 Control Cost Manual, Sixth Edition, EPA/452/B- 02-001, January 2002. Section 1, page 1-3.321 costs are not, or “do not appear to be,” “valid costs under th e Control Cost Manual methodology” as construed by EPA).

The BART Guidelines make clear the nonbi nding 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 a ny information supplied by vendors that affects ... assumptions regarding purcha sed equipment costs, equipment life, replacement of major compone nts, and any other element of the calculation that differs from the Control Cost Manual

.

Id, at n.15 (emphasis added). Similarl y, 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 Co st Manual is “a ... refe rence 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 an alyses. 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. S ee 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 r eal capital costs a nd 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 a ddress specific line item cost comments in our responses to other more specific comments.

Comment: Economic and social fa ctors 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 CALPUF F model’s margin of error for Power Boiler 2,

there is the need for EPA to consider the adve rse 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 positio n 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).322 position means lost profits translating into lost jobs and significant adverse social consequences. The United States Supreme Court recognized thes e economic and social costs are a significant factor that must be considered before impos ing 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 d eciding whether regulati on is appropriate and necessary”). In addition, the D.C. Circuit Court explained in v acating 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 ha ve 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 paramo unt 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 requi re that when assessing BART, the state

or we must take into co nsideration five factors: 618

the technology available, the costs of compliance, the energy and nonair quality environmental impacts of compliance, a ny 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 anti cipated 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 ar e 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 fo r compliance with the CAA and the Regional Haze Rule requires the expenditure of capital, which ca rries with it the possibilit y of reduced profits. Domtar has not supplied any specific informati on that would cause us to conclude that compliance with BART would impact its continued viability. C onsequently, we see no reason to

conclude that we should ch ange our proposed BART de terminations 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 Corporat ion et. al. stated that EPA

failed to consider the cost-effectiveness of the cont rols relative to the visibility benefit that would result. EPA’s own guidance notes that for “ind ividual, 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 100.323 dollar-per-deciview calculation.” Reasonable Progress Guidance at 5-2. Here, EPA gave no

consideration to the doll ar-per-deciview resulting from instal ling scrubbers at Independence. If EPA had done so, it would rec ognize that the costs are ap proximately $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 requir e reasonable progress controls because of lack of cost-effectiveness, finding reasonable EPA’s explanati on that “cost of compliance is only one of the four statutory requiremen ts for reasonable progress analysis.”).

Ultimately, the insignificant level of projected vi sibility improvement does not justify the costs associated with adding a dry FGD, does not m eet the statutory RPG requirement for proper

consideration of the cost of controls, and is patently unreas onable, 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 C onway Corporation et. al. (0172) p. 10-11] EMI, AEP-SWEPCO, and Conway Corporation et. al . stated that the Inde pendence Plant is not a BART-eligible source and therefore, cost-eff ectiveness should be determined not only on the calculated $/ton cost, but also relative to the in stalled 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 NO X for the Independence Plant would resu lt 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 propos ed an option (Option 2) that did not include

the LNB/SOFA NO X controls. 623 EPA, however, did not recognize that the Indepe ndence Plant is subject to the Cross-State Air Pollution Rule (“CSAPR”) and that NO X reductions “better than BART” would already be achieved by participat ion in that program without specifically requiring emissions limits based on the installation of low NO X burners and separated overfire air as proposed in the FIP. For SO 2 emissions, EPA estimated improvements with dry FGD ranging from 1.045 to 1.178 dv with a cumulative be nefit 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 a ppropriate to use the cumulative values as a representation of the visi bility 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 dr y flue gas desulfurization (“F GD”). Therefore, EPA’s proposal does not meet the statutory RPG re quirement for proper consideration of the cost of controls and

so is not “reasonable.”

Response: See our response to another comment concer ning 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 visib ility is not one of the four mandatory factors explicitly listed for consideration under C AA section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), states or EPA have the option of considering the projected visibility bene fits of controls in determining if the controls are necessary to make reasonable progr ess. We disagree with Entergy that the projected visibility improvement does not justify the installation of controls at the Independence facility to meet reasonabl e progress. As we state in our TSD, 624 “The Entergy Independence Plant is not subject to BART, but its emissions were 30,398 SO 2 tpy and 13,411 NOx tpy based on the 2011 NEI. The Entergy Inde pendence Plant is the s econd largest source of

SO 2 and NOx point-source emissions in Arkansas , accounting for approximately 36% of the SO 2 point-source emissions and 21% of the NOx point-source emissions in the State. 625 As we discuss in detail elsewhere in this document, th e installation of the controls on Independence we are finalizing in this action will result in signif icant visibility benefits and meaningful progress towards the goal of natural visibility conditions.

We agree with Entergy that the Independence faci lity is not a BART-eligible source. However, Entergy cites to no justificati on 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 visibi lity improvement,” nor does Entergy provide specifics as to how this should be done. In addi tion, capital costs are alre ady considered, as they are an input (along with operati onal 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 NO X BART.

We disagree that the Regional H aze Rule requires that controls on a source or group of sources result in perceptible visi bility improvement and discuss that i ssue 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 appr oved 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 stat ed that EPA’s disregard for consistent reasonable progress review and analysis continued in to the statutory four-factor anal ysis. After making the arbitrary and capricious determination to target only the Independence Plant, EPA approved dollar per ton cost-effectiveness estimates and visibility improve ment rates for the proposed controls that are out of line with the standards applied in ot her regional haze SIPs and FIPs. EPA’s proposal attempts to justify a cost-effectiveness of dry FGD at the Independence Plant totaling $2,477/SO 2 ton removed for Unit 1 and $2,686/SO 2 ton removed at Unit 2. 626 However, this far exceeds the

624 See page 133 of our TSD. Based on 2011 data, En tergy’s White Bluff facility is the largest sources of SO 2 and NOx in the state, with slightly higher totals than the Independence facility.

625 The first and third largest sources of SO 2 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 Kentucky 627 and North

Carolina 628 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 neglig ible 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 im provements of less than 0.5 dv are “relatively small” and are not reasonable justification for ad ditional 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 progr ess analysis we also considered the visibility improvement of contro ls alongside the four st atutory factors. Although visibility is not one of the f our mandatory factors explicitly listed for consideration under CAA section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), st ates or EPA have the option of considering the projected visibility benefits of controls in determining if th e controls are necessary to make reasonable progress. In some cases, for reasonable progress determinations, we have calculated

cost-effectiveness values for cont rols that fall within a range we have previously found to be acceptable, but the visibility improvement was not la rge enough to consider as beneficial at this

time. 632 Thus, it is inappropriate to simply compar e cost-effectiveness values. Nevertheless, the Independence cost-effectiveness valu es fall squarely within a range of value we have previously found to be acceptable—again, even if the visibili ty benefits are not c onsidered—for the same types of controls. 633

We have responded to arguments that we have be en inconsistent with regards to our Kentucky and North Carolina actions, and comments concerni ng the estimated visibility benefits from all controls in our respons es 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% Wors t 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 deta il elsewhere in this document,

627 76 Fed. Reg. 78194, 78206 (Dec. 16, 2011) (approving the use of a $2,000 per ton SO 2 screening threshold).

628 77 Fed. Reg. 11858, 11870 (Feb. 28, 2012) (approving st ate’s decision not to implement additional controls for reasonable progress despite cost-effectiveness determinations ranging from $912 to $1,922 per ton of SO 2 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 dete rmination 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 direc tly comparable to the CALPUFF modeled improvement from controls cited to by the comm enter, due to differences in models, model inputs and metrics. The commenter does not pr ovide a direct comparison between the modeled visibility benefit of controls in Montana and Oregon to the CALP UFF modeled visi bility benefit of controls on the Independence facility and is in correct in their assertion that the benefits from controls at Independence are th e 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 la rger than the CALPUFF estimated visibility benefits of 0.18 dv for scrubbers at the Ash Grove facility in Mont ana or the 0.18 dv increm ental 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 becau se, for other states, EPA determined that “a predicted impact on a Class I area of 0.5 deciview ("dv") was "relatively sm all" 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 progr ess decision has been improperly taken out of context. The actua l passage that the commenter cites is:

All sources with a Q/d ratio of less th an 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 re gulations. Since the threshold is more conservative than the subject-to-BART thre shold, we believe that a Q/d value of 20 is reasonable for determining which poi nt 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 w ith Oregon's conclusion that additional controls of non-BART point sources fo r reasonable progress purposes are not reasonable in the first planning period, because even though there are cost effective controls identified, visibility im provement is anticipated to be relatively

small. 635

We therefore disagree with the commenter that our determination of contro ls 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 st ated that visibility modeling for the Bailey and McClellan facilities reveals that th e 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 th ree years of modeling

634 See Summary of Additional Modeling for Entergy Independence available in the docket for this action

635 77 FR 30464327 when burning natural gas. In contrast, the Bail ey 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 meteorologica l 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 uni ts are subject to BART and should be EPA’s primary focus for BART. Ms. Stamper presente d 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 grea test 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 th e Bailey and McClellan units to only burn natural gas was because of AE CC’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 th e BART Guidelines provide that it is not

EPA’s intent to direct sources to swit ch fuel forms. 80 Fed. Reg. at 18,953, 18,959. She concludes that if AECC is only conc erned with the need to burn fu el 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 ne cessarily 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. Natura l gas constitutes the majority of the heat input to these boilers. Not only would the cessation of burning fuel oil satisfy SO 2 BART, but it would also satisfy

BART for PM.

Ms. Stamper notes that in contrast, Entergy is wil ling 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 Cather ine plant, it can’t do the same at the Bailey and McClellan plants. EPA should impose such a rest riction 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 SO 2 and PM. If AECC needs the ability to burn fuel oil in the future, EP A could allow the plant to do so, but only after obtaining a BART determination for fu el oil, consistent w ith what it has proposed

as BART for Lake Catherine Unit 4. 80 Fed. Reg. at 19,002.

Relatedly, Ms. Stamper supports our propos ed determination that no additional NO X 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 sw itch fuel forms, such as from coal or fuel oil to gas (40 CFR part 51, Appendix Y, sec tion 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 f acilities include consideration of that fuel in their BART analyses, which is what we ha ve done. In addition, Lake Catherine Unit 4 voluntarily offered to accept a re striction on burning any fuel oil until BART determinations are made for the fuel oil firing scenario through ei ther promulgation of a FIP and/or through EPA approval of a SIP revision. Ther efore, we proposed to promulgate this restriction on Lake

Catherine Unit 4 in our FIP. On the other ha nd, AECC Bailey and McClellan did not offer to accept a restriction on burning fuel oil and we th erefore cannot impose such a restriction in our FIP. They did, however, offer to accept a restric tion on the sulfur content of the fuel burned and

our SO 2 and PM BART determinations for these two facilities is based on this voluntary acceptance. Therefore, we disagree that our treat ment of Lake Catherine Unit 4 is inconsistent with how we address AECC Bailey and McClellan in this FIP.

Comment: EPA incorrectly calculated ba seline emissions for White Bluff and Independence [S&L Entergy Report, page 2]. S&L objec ts to our approach of calculating a SO 2 baseline for the White Bluff and Independence fa cilities, 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 contrast ing our approach to calculating SO 2 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

Inde p endence 2 15,511 14,673 15,196 16,035 15,407

S&L concludes that in all cases, there is at leas t one other approach that would result in lower

baseline SO 2 emissions.

Response: We disagree with S&L that we erred in the procedure we used in estimating baseline

emissions for our BART and reason able progress scrubber upgrade co st analyses. The fact that S&L can construct alternative approaches to our ba seline calculation that result in lower values does not invalidate our BART and reasonable progr ess 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, th e results are all similar. In fact, for three out

of four units one of S&L’ s alternative approaches w ould have produced higher SO 2 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 state 636 :

How do I calculate baseline emissions?

1. The baseline emissions rate should repr esent a realistic depi ction of anticipated annual emissions for the source. In gene ral, 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 ope rating 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 u pon continuation of past practice.

Our Reasonable Progress Guidance notes the similar ity between some of th e reasonable progress

factors and the BART factors contained in S ection 51.308(e)(1)((ii)(A), and suggests that the BART Guidelines be consulted regarding co st, energy and non-air quality environmental impacts, and remaining useful life. We are th erefore relying on our BART Guidelines for assistance in interpreting those reas onable progress factors, as app licable. One of these areas is

in the calculation of the baseline emissi ons in determining cost effectiveness.

We believe the procedure we used is in comp liance with this language. We calculated our

baseline SO 2 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 vari ations in coal sulfur data, cap acity usage, etc., and make the baseline more representative of plant opera tions. 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 SO 2 emissions reductions for White Bluff and Independence [S&L Entergy Report, page 3]. S&L states that SO 2 emission reductions were estimated incorrectly by EPA for White Bluff a nd Independence. For each unit, EPA identified the maximum monthly SO 2 emission rate in the baseli ne 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 wa s then multiplied by the baseline emission

tons to determine the tons of SO 2 reduced. This methodology is in correct because it assumes the baseline emissions calculated in the previous section are based on ma ximum monthly averages,

636 70 FR 39167.

637 http://ampd.epa.gov/ampd/330 which are significantly higher than the annual aver ages actually used to calculate baseline emissions. The correct way to project the SO 2 emission reduction is to multiply the outlet emission rate of 0.06 lb/MMBtu by the average h eat input to the boiler (MMBtu/year) from the baseline period. For example, the average heat in put 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 SO 2 emission reductions of 14,264 tons per year, as compared to EPA’s 14,363. This method has been u tilized by S&L on previous BART analyses, and has been accepted previously by EPA. S&L pr esents its calculations below. We added the percent difference column:

Unit EPA Approach Using Maximum Monthly

SO 2 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

Inde p endence 1 12

, 912 12

, 607 2.4

Inde p endence 2 13

, 990 13

, 655 2.4

Response: We disagree with S&L that our methodology for calculating the SO 2 tons reduced

was incorrect for the White Bluff BART dete rminations and the Independence reasonable progress determinations. We began by selecti ng 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 th e 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 th e maximum monthly emissions from 2009-2013 and applied the aforementioned test to this figure to establish our control effi ciencies. This control efficiency was then applied to the SO 2 baseline. Using S&L’s pr oposed methodology of simply multiplying 0.06 by the average heat input to the bo iler 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 cap able of achieving the control emission rate on a monthly basis that involve a more detailed ex amination 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 w ould 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 woul d not have changed our proposed determinations

for either the White Bluff BART or Independence reasonable progr ess facilities. Lastly, as S&L has not provided any specific references to in stances 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 SO 2 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 SO 2 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 facili ties. As noted in the IPM dry FGD document, the 0.06 lb/MMBtu emission rate corresponds to the lowest available SO 2 emission guarantees from dry FGD suppliers. Compliance w ith a vendor’s guarant ee value is typically demonstrated during very short term testing conducted at ideal operating conditions. Vendor guarantees do not reflect controlled emission rate s that may be achievable on a consistent longterm basis as the unit operation varies from de sign 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 F GD 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 reagen t contact through the use of a fl uidized 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 EP A’s approach to estimating controlled SO 2 emission

rates is incorrect and based on a misunderstand ing of the actual performance and operation of dry FGD technology. By using this approac h, EPA is overestimating the tons of SO 2 removed and thus overstating the cost -effectiveness of the retrof it 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 fi nd 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 info rmation 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 represen ts 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 doi ng so does not consider the sulfur content of the coal.

Our conclusion that the White Bl uff 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 pub lished papers that cite to this capability. 640 As we state in our TSD, 641 we demonstrated in our Oklahoma FI P 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 w ith S&L that our proposed SO 2 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 Impl ementation 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

SO 2 removed and thus overstating the cost-effec tiveness 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 su btracted BOP costs because we believed the equipment to be included in Al stom’s scope. As desc ribed 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 Is land” supplied by the dry FGD vendor includes lime day bins, slakers, slurry transfer tanks, slur ry transfer pumps, slu rry storage tanks, and slurry feed pumps. The BOP system includes th e 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 bui lding, long-term storage silos, and a pneumatic conveying system to transfer the lime reagent fr om the long-term storage silos to the day bins,

which are within the dr y FGD vendor’s scope.

We agree with EPA’s comment that including th e NOx control equipment for Units 1 and 2 was an oversight and should not be incor porated into the Dry FGD estimates.

EPA mistakenly subtracted a total of $1,754,000 fr om 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 ba ghouse, 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 ac id 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 SO 2 concentrations in the controlled range with Dry FGD t echnology. The costs included in the original estimate to cover replacement of the existing equipment w ith new equipment rated for the lower SO 2 concentrations as well as the cost to calibrate and certify these monito rs including conducting a Relative Accuracy Test Audit (RATA) test. Base d 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/A333 EPA then adjusted additional cost items in the BO P estimate that were either percentages of the equipment, material, and labor costs or were rela ted 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 ite ms. In the table below, we correct EPA’s adjustments to remaining Entergy BOP cost s by employing EPA’s met hodology but reducing the percentage factors to the va lues indicated in Table 5. EP A 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 mi sconception as to the scope of work included in the BOP and Alstom estimates, they mistaken ly 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 retr ofit dry FGD systems at White Bluff.334Adjustment to Remaining Entergy BOP Costs (Total for Both Units)EPA Cost TSD Reductions CorrectedReductionsDESCRIPTIONEquipment Material Labor Total Equipment Material Labor TotalMOBILIZE/DEMOBILIZE @ 1%OF LABOR$0 $0 $0 $0 $0 $0 $0 $0MOBILIZE/DEMOBILIZE @ 1%OF LABOR$0 $0 $546,061 $546,061 $0 $0 $656,036 $656,036MOBILIZE/DEMOBILIZE @ 1%OF LABOR$0 $0 $0 $0 $0 $0 $0 $0COST DUE TO OVERTIME‐5‐10'S$0 $0 $7,970,183 $7,970,183 $0 $0 $9,575,359 $9,575,359COST DUE TO OVERTIME‐5‐10'S$0 $0 $0 $0 $0 $0 $0 $0PER DIEM‐@ $10 PER HOUR$0 $0 $7,888,659 $7,888,659 $0 $0 $9,477,416 $9,477,416PER DIEM‐@ $10 PER HOUR$0 $0 $0 $0 $0 $0 $0 $0SPARE PARTS @ 1% OFEQUIPMENT$0 $0 $0 $0 $0 $0 $0 $0SPARE PARTS @ 1% OFEQUIPMENT$327,060 $0 $0 $327,060 $400,318 $0 $0 $400,318FREIGHT @ 5% OF MATERIAL $0 $0 $0 $0 $0 $0 $0 $0FREIGHT @ 5% OF MATERIAL $0 $1,413,404 $0 $1,413,404 $0 $1,596,000 $0 $1,596,000GENERAL &ADMINISTRATIVE (G&A) @5% OF MATERIAL ANDLABOR$0 $0 $0 $0 $0 $0 $0 $0GENERAL &ADMINISTRATIVE (G&A)@5% OFMATERIAL ANDLABOR$0 $1,413,404 $2,417,281 $3,830,686 $0 $1,596,000 $2,904,116 $4,500,116GENERAL &ADMINISTRATIVE (G&A)$0 $0 $1,119,810 $1,119,810 $0 $0 $1,345,337 $1,345,337335@5% OF MATERIAL ANDLABORPROFIT @ 10% OF MATERIALAND LABOR$0 $0 $0 $0 $0 $0 $0 $0PROFIT @ 10% OF MATERIALAND LABOR$0 $2,826,809 $4,833,794 $7,660,602 $0 $3,192,000 $5,807,308 $8,999,308PROFIT @ 10% OF MATERIALAND LABOR$0 $0 $2,240,388 $2,240,388 $0 $0 $2,691,597 $2,691,597NON CONTRACTORINDIRECTS$0 $0 $0 $0 $0 $0 $0 $0ENGINEERING‐BOP$0 $0 $7,579,481 $7,579,481 $0 $0 $9,105,970 $9,105,970Totals $40,576,333 $48,347,457Reduction in Remaining BOPCosts$11,905,667 $4,134,543Excluded BOP Costs from Table 4$16,590,000TOTAL BOP Reduction$20,724,543Response: 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 Al stom 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 SO 2 scrubber, or were already covered as part of the Alstom quote. We re moved 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, whic h contains a 2015 White Bluff SDA cost estimate, for that

documentation.

First, Entergy states that its 2015 SDA cost esti mate 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 disc uss 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 sy stem BOP costs in its 2013 SDA co st 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 c hoice 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 th e 2009 Alstom quote was incorrect.

Entergy states it agrees with our exclusion of NO X controls from its BOP costs. However, it does not discuss our exclusion of $1,166,000 for boos ter 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-effec tiveness (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 SO 2 in the range that would result from the SDA control. Again, du e 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 pain t the chimney was jus tified 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 Whit e 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 escala te costs to the year 2013 resulted in severely underestimating the costs associat ed 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 we re 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 fo llowing formula, 550.8/521.9*$247,856,184 to obtain an estimated 2013 FGD cost of $261,581,119 for both un its. Rather than estimating escalation of Alstom’s pricing from 2010, S&L (on behalf of Entergy) requested upda ted 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 s ubstituted for supplier in formation better than comparing EPA’s escalation rate to the actual escalation rate indicate d 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

Avera g e Escalatio n 1.36% 4.7% p er y ea r

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 cost s, 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 re vised 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 analys is 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 esti mates for White Bluff: an early 2009 Sargent and Lundy (S&L) estimate with a total co ntractor 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 stat ed that unlike the S&L quote, the Alstom estimate was not itemized and only included a tota l price. Entergy used the 2009 Alstom price quote as the basis for its BART cost analysis for White Bl uff by increasing it by 10%, and scaling the S&L itemized cost to match the 110% ad justed Alstom total price. As we describe elsewhere in our response to comments, we criti qued 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 Alst om quotes, and with these corrections, we

were able to construct a reasona ble 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 esti mate, which it references in its comment, until after our proposal. Entergy’s 2015 report uses up dated 2013 pricing from Alstom as its basis. As we discuss in a previous comment, we revi ewed this 2015 cost analysis and found that it presents problems that prevent us from usi ng 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 an alysis. 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 th e 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. En tergy 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 significantl y different totals. For in stance, 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 cont ractor 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 another 646 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 Chemi cal Engineering Plant Co st 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, Ente rgy did so incorrectly and we corrected that

error. 648 We certainly prefer revi sed vendor quotations to escala ting 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 availa ble as in this case, we have no choice but to

escalate older cost estimates in order to bring the cost basi s to the present.

Entergy also apparently objects to any escalation technique that re sults 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 mate rials, 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, a lthough the Composite CE index usually increases from year to year, it does occasionally decrease, due to variou s broad economic factors, such as it did from 2008 to 2009, and again from 2011 to 2013. Thus, En tergy’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 i gnored 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 Ente rgy’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 disc uss 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 ap pears 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 analys is 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 co mment concerning our not usi ng its 2012 direct annual cost.

Comment: Entergy summarizes its objections to our escalation calcul ations in our White Bluff scrubber cost analysis. [S&L Entergy Report, page 12]. Continuing from its previous comment on escalation, Entergy pres ents the table below. Entergy states it summarizes how EPA incorrectly estimated escalation in its anal ysis 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 pr icing 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 revi sed costs shown in the table below. EPA’s

underestimation of cost escalati on carried through thei r 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 exclude d 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 I ndirect 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 prev ious comment, Entergy does not supply the 2013 Alstom quote which it references in its commen ts. 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 Ente rgy’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 Contingenc y (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 provi de either the 2009 or the 2013 Alstom quotes on which it states its cost estimates rel y. Thus, we have no ba sis to conclude that the costs Entergy presents in its 4.7% escalati on calculation even cove r the same scope of work. We find it perplexing that Entergy did not just supply the 2013 Alstom quote,

eliminate the usual disallowed cost it ems (AFUDC, escalatio n during construction, owner’s costs, etc.) and provide an updated co st analysis. Instead, its comments seem to342 be focused on attempting to shore up an older 201 3 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 Indi rect Costs (2012): “I n the Cost TSD, EPA incorrectly used the 2008 BOP Indirect Co sts 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 I ndirect 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 undoc umented and appeared to be captured elsewhere in its costs. As we explain in our TSD: 652

In addition to the BOP costs that we disc uss 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, start up and commissioning and are estimates provided by the contract or. Miscellaneous contractor labor is inclusive of legal s upport, owner’s insurance, S&L engineering costs, and Entergy’s environmental permitting costs.

No documentation of these costs was provide d. 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 Ad ministration” (Items 307.5 and 307.6) for a total of $6,355,000. These General and Ad ministrative and Non Contractor Indirects categories are broad in sc ope, unspecific in description, and undocumented. Together, they total $16,210,000. Lacking any documentation to the contrary, we must assume any wo rk associated with the support or

administration of the BOP items are cont ained within these cost items. We therefore propose to delete the additiona l BOP indirect cost item from the SDA

costs.

Entergy does not address this lack of documen tation 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 discu ss in our response to another comment, we did

not use those costs because En tergy incorrectly escalated th em 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 di sagrees with our exclusion of
these costs, 654 and we invited it to provide documentati on to the contrary. However, we cannot locate any documentation of these costs in its comments. Conseque ntly, 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 Tota l Contractor Costs and Contingency, we must similarly reject its escalation of its Ov erhead (2008) cost.

 Because the Administrative Charge s, Property Tax, and Insurance ar e 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 ou r 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

SO 2 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 conclu des, “[t]hus Entergy has costed SO 2 scrubber systems for the White Bluff facility that are overdesigned compar ed to its historical needs.” Based on this conclusion, EPA adjusts the cap ital 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 desi gn basis was to preserve fuel flexibility, but their conclusions that, “either (1) this highe r cost be balanced against its greater SO 2 reduction potential, or (2) that the scrubber system’s capab ility and cost be adju sted down to match the facility’s historical emissions,” are without basis and inconsistent with BART guidelines.

The SO 2 emission reduction calculation depends upon the baseline emissions, baseline heat input, and the required outlet emission rate (see Section 2.2 of our comments). SO 2 emission reduction does not depend on the fuel sulfur leve ls selected for FGD system design, neither the BART guidelines nor the CCM addre ss evaluating potential future SO 2 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 SO 2 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 polluti on control design be tied to historical operating trends. Therefore, EPA’s second conclusion that capital costs must be adjusted to match

historical emissions is ar bitrary and without basis.

Based on its erroneous conclusions , EPA selected a maximum monthl y fuel sulfur level of 0.68 lb/MMBtu as the design basis used to estimate th e capital costs. Entergy presents the figure below to illustrate why the use of White Bl uff’s maximum monthly fuel sulfur level is completely insufficient.

The ability to reduce SO 2 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 si zed 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 th e 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 wi th fuel limitations because we believe EPA345 selected the design basis due to a lack of experi ence 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 potenti al to fire fuels with higher su lfur levels, based on more recent information, Entergy now believes that they will not purchase fuels with sulf ur levels higher than 1.2 lb/MMBtu. The operating data shown in the a bove 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 incl uded a sensitivity analysis in S&L Report #012831. As discussed previously, we agree that it is appropriat e to base direct O&M cost

estimates on 0.68 lb/MMBtu fuel sulfur levels to represent average opera tional costs. However, EPA’s adjustment factor of 0.5823 applied to dire ct O&M costs severely underestimated these costs. In agreement with EPA’s sulfur basi s, 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 includi ng 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, resu lting in direct O&M co sts of $4,536,199 per unit being

included in its cost-effectiven ess calculation. This methodol ogy 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 a nnual 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 EP A should have applied the 0.9584 factor used to correct capital costs to the indirect annual co sts. EPA’s methodology unde restimated indirect O&M costs by $4,840,192 per unit.

Response: Entergy states that we correctly assume d 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 SO 2 reduction potential, or (2) that the sc rubber 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 explai ned our reasoning for this statement in our TSD, 655 including appropriate references to the BA RT Guidelines. As we noted in our TSD, “either (1) this higher cost be balanced against its greater SO 2 reduction potential, or (2) that the scrubber system’s capability and cost be adjust ed 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 bu rned, but continued to base the capabilities of the scrubber on its

historical SO 2 baseline. Thus, either Ente rgy’s annualized cost (the “$”) or its tons reduced (the “tons”) in the $/ton cost effectiveness calculati on are misrepresented. Our approach was to recalculate Entergy’s scrubber cost to bring its scrubber design in lin e with the historical coal it has burned. Entergy could have taken the altern ative 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 r easoning 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 th at capital costs must be adjusted to match

historical emissions is ar bitrary and without basis.

Entergy also states, “While we agree with EP A that direct O&M cost s be revised to 0.68 lb/MMBtu, this sulfur level is completely inad equate for the Dry FGD equipment design basis.” Entergy then presents the above SO 2 emissions plot as evidence of our error. We do not believe this statement accurately represents our appr oach. 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 certa in capital and operating costs of the 0.68 lbs/MMB tu case to the 2.0 lbs/MMBtu case. We then applied these ratios to Entergy’s own cost analysis (with th e corrections we discu ss 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 st ate so, but it appears that its SO 2 plot contains hourly SO 2 emissions data. Thus, Entergy appears to argue that its scrubber systems must be designed to treat every hourly fluctuation in SO 2 , 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 SO 2 limit. Our proposed limit is a 30 Boiler Operating Day (BOD) average. Thus, individual hourly SO 2 emissions are inconsequential. In fact, even daily SO 2 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 aver ages and the running 30 BOD average for White Bluff Unit 1. A plot of White Blu ff Unit 2 yields similar results. Th is plot illustrates two things: First, the maximum daily averages are signifi cantly below the maximum hourly averages Entergy presents in its plot. T hus the individual hourly data fl uctuations Entergy presents are inconsequential. Second, the running 30 BOD av erage indicates that our decision to fix the mismatch between Entergy’s scrubb er costs and its historical SO 2 baseline on the basis of a SO 2 inlet of 0.68 lbs/MMBtu is reasonable.

Entergy states that it has determined its assump tion 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 re agent. 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 operationa l 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 an d First Year Costs, per Unit

Units Design

0.68 lb SO 2 /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 fixe d 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 SO 2 /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 Independe nce SDA cost-effectiveness calculations would become even more attractive (lower $/ton).

Entergy then states that to illustrate the sma ll difference in capital co sts 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 co nclusion 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 co sts, which cover the fundamental design parameter of a scrubber—gas flow rate, were only changed by less than 5%. Thus, Enter gy’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, engineerin g 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 hist orically burned. Entergy argues that our O&M

factor of 0.5823 should not have be en applied to the indirect a nnual costs, including overhead, administrative charges, property tax and insura nce, all of which depend on capital cost. Therefore, argues Entergy, even if our capital cost scaling methodol ogy for capital cost is correct (which it does not believe is the case), then we should have applied th e 0.9584 factor used to correct capital costs to the indir ect 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 th e White Bluff and Independ ence 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 certai n aspects of conservativeness in our White Bluff cost analysis. [S&L Entergy Report, page 17]. EP A lists two assumptions it believes are

conservative in its Cost TSD. In one assu mption, EPA noted that amortization from the 2008 S&L cost analysis was 40 years, but they lowere d the remaining useful life to 30 years, which

increases the cost-effectiveness. EPA’s estimate is not conservative with re gard 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 S ection 3.9, the actual remaining lif e of these units is far below

what EPA assumed.

In the second assumption, EPA concludes that two absorber vessels are no t required and, thus, a 7% cost savings that could ha ve been realized was not appl ied. We do not believe EPA is qualified to design dry FGD systems, and theref ore 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 refere nce 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 ar bitrary 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 c oncluded 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 determin ations has no bearing on this. Ou r 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 equipm ent 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 contra ctor. 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 fr om 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 stat es, “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 ev aluation indicate any fu ture planned shutdown.” Therefore, EPA utilized 30-years as the rema ining useful life in its cost-effectiveness

calculations. As stated in Ente rgy’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 li fe 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 TS D that Entergy quotes, in order for us to incorporate a shorter scrubber li fe into the White Bluff SDA co st analysis, Entergy must be subject to a federally enforceab le document to shut down the un its in question. We have not

received such an enforceable document. We discu ss this issue in more detail elsewhere in this

document.

Comment: Entergy objects to our scr ubber cost analysis for Independence. [S&L Entergy Report, page 19]. EPA included Entergy’s Inde pendence Plant in its RPG analysis based on annual emissions from the facility. It is be yond 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 in clude Independence in its RPG analysis for Caney Creek and Upper Buffalo. Instead, our comments focus on the inconsistencies and erro rs included in EPA’s RPG analysis for the Independence station.

In EPA’s RPG analysis for SO 2 Controls, EPA concluded that the units at White Bluff and Independence Stations are similar enough to appl y “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 SO 2 emissions at Independence. This approach is flawed for several reasons. First, th is 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 annua lized costs. Second, applying the White Bluff annualized costs to Independence is inconsistent with EPA’s RP G guidance which requires cost estimates based on design parameters be developed for air pollution c ontrol systems.

To determine whether air pollution controls woul d 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 evaluatio n of: (a) costs of compliance; (b) time necessary for compliance; (c) energy and non-air impacts; and (d) the remaining useful life of th e 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. Furtherm ore, EPA’s use of aerial photos to indicate visual similarities between White Bluff and Independence ignores many site-specific fact ors 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 technol ogy 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 amoun t of skilled labor that would be required to construct four FGD system s in the same time period;

 EPA did not review plant operati ng data, such as flue gas temp eratures, which affect flue gas volume, potentially requiring differe nt equipment sizing for Independence;352  EPA did not review operating and maintenan ce 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 bedr ock that would impact foundation design or seismic design requirements;

 EPA did not assess other seismic design require ments such as seismic risk or magnitude of potential earthquakes to determine steel de sign 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 BA RT guidelines.” We note that, for EPA’s RPG analysis for Independence, EP A 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 SO 2 emissions at Independence station. EPA’s inherent assumption is that BART-level

SO 2 reductions are required at Independence to meet the RPGs, but it does not adequately support that assumption. EPA mode led visibility impacts of SO 2 reductions assuming FGD systems would be retrofitted at Independence, but they failed to conduct modeling using any other technology or methodology that c ould provide more cost-effective SO 2 reductions.

Finally, EPA also states in its RPG guidance docu ment that for, “individual, large scale sources, simple cost effectiveness estimates based on a dollar-per-t on calculation may not be as meaningful as a dollar-per-deciview calculation.” EPA’s CENRAP modeling showed that the cumulative benefit of installing a ll of the controls proposed in th e 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 SO 2 point source emissions and 29% of the point source NOX emissions in Arkansas, Ente rgy 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 retr ofitting dry FGD system s at Independence to estimate dollar-per-deciview as suggested in EP A’s RPG guidance document. The table below shows that retrofitting dry FGD systems at Inde pendence 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

$/ Δ dv $1,334,562,775 $1,525,214,600
Note: Entergy’s revised annual costs in the abov e 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 othe r responses to comments, we address Entergy’s objections to our White Bluff cost analysis, so th ey will not be repeated here. Entergy alleges that we failed to properly identify the design pa rameters for emission controls; and develop cost estimates based upon those design parameters. En tergy lists a number of areas it believes differentiates the White Bluff and Independence f acilities to the extent these differences would impact the Independence scrubber cost analysis.

We agree that there are likely differences betwee n 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 tang entially firing boilers having nameplate capacities of 900 MW and similar gross rati ngs. As we indicate above, all four

units burn coal from the Powder Ri ver Basin of Wyoming with similar characteristics. All four units employ co ld side electrostatic precipitators for particulate collection. Other pert inent characteristic s are similar.

We further presented satellite photographs to de monstrate that the layout of these facilities are extremely similar. We consequently expect that the differences En tergy 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 so le 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 pass ing through the system).” Such an estimate, for example, could be obtained from the cost re ported in dollars per me gawatt ($/MW) or dollars per million BTUs fired ($/MMBtu), metrics that are widely reported in the literature. The

Control Cost Manual indicates that “the cost s and estimating methodology in this Manual are directed toward the “study” estimate with a nomin al 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 woul d suggest that the differences between these two facilities are so significant they would impact this requir ed 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 Indepe ndence facility in our proposed Arkansas FIP under the reasonable progress secti on 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 contro l 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 ( $/ y ear )

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 ar e shown as a range based on a re maining useful life of 6 or 7

years.

In addition, the table below shows how EP A’s approach overstated the tons of SO 2 that would be removed by its FIP-imposed dry FGD and the adju stments S&L made to correct EPA’s mistakes.

Adjustments to EPA’s SO 2 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 SO 2 Emission

Reduction Calculation 14,264 14,353

Differential from EPA FIP -99 -868

EPA’s errors resulted in severe ly overstating the cost-effectiveness to retrofit dry FGD systems at White Bluff 1 and 2 (and then by extensi on in its reasonable progress analysis for Independence 1 and 2). The table below su mmarizes how EPA’s errors systematically

underestimated cost and overstated the cost-effectiv eness 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 SO 2 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 show n as a range based on a re maining useful life of 6 or 7 years.

With respect to EPA’s RPG analysis for SO 2 controls, EPA did not follow its own guidance document when conducting its four factor analys is of Independence. EPA failed to consider lower cost options that could reduce SO 2 emissions at Independence and instead concluded that BART-level controls were required to meet RP G. EPA did not prepare cost estimates based on design parameters for FGD system s retrofit at Independence, as required by their RPG guidance document. EPA did not conduct a dollar-per-deci view 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 appl ying annualized costs to projected visibility improvements the result is over $1.3 billion/ Δ dv for Caney Creek and over $1.5 billion/ Δ dv for Upper Buffalo, which is clea rly 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 comm ents. Below we summarize our determinations:

 Regarding the Corrected Baseline Emission Calculation and the Corrected SO 2 Emission
Reduction Calculation, we determined that Enter gy’s recalculations were not justified.

 Regarding the Corrected BOP Exclusions, we ha ve 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 Ex clusions and Corrected Escalation, we determined that Entergy’s recalc ulations were not justified.

 Regarding the Corrected Operating Cost, we agr eed with Entergy that it would have been more appropriate to apply the 0.9584 factor to the indirect annual costs and will356 incorporate that correction in our final SDA cost analysis for the White Bluff and Independence facilities.

 Regarding the Corrected Remaining Useful Li fe, 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 Bl uff and Independence SDA cost estimates are contained in the file, “White Bluff_R6 cost revisions2-revised.xl sx,” 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 ca lculations do not change our proposed findings for BART and reasonable progress for these units.

In addition, we have examined the effect of addi ng back in a number of the BOP and other costs we excluded (based on these costs being either di sallowed by the Control Cost Manual, or having lacked documentation from Entergy). This exerci se 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 r eagent 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 co sts 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 Cont rol Cost Manual, or are properly disallowed because they lack documenta tion from Entergy. We have presented this

information to indicate that these costs have a relatively minor effect on the final cost effectiveness. Although our fi nal decision regarding BART a nd 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-effec tiveness 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 Re port #012831.” We are unsure of the exact significance of this re port, as it appears it is primar ily used by Entergy to support its previous 2013 Cost estimate. We have addre ssed 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 Co st 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 co mments, 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, Enter gy does not provide this Alstom quote. Consequently, we have no way of verify ing Entergy’s 2015 cost calculations.

 The S&L Report #012831 uses an Engineeri ng, 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 so me disadvantages. These include the

fact that it can result in a higher contract price th an alternative contractual structures. This higher pr ice 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, wh ich did not use EPC contacts, and the corresponding higher fees associated wi th 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 stat es, “[t]he EPC Risk Fee is a premium included by the contractor which account s for the additional coordination and

665 Review Of EPA’s Cost Analysis For Arkansas Re gional Haze Proposed Federa l Implementation Plan, SL012913, Final July 14, 2015.

666 S&L Report #012831, page 1.358 management of the project as well as th e additional risk assumed by the contractor.” 667

The additional cost of an EPC contract fo r the White Bluff SDA cost analysis makes it difficult to compare the cost-effectiveness ($/to n) 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 a ppear 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 Contro l 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 installa tion 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, fa brication, and installation of the system. For example, a hundred ye ar flood may postpone delivery of materials, but their arrival at the j ob site is not a problem unique to a

retrofit situation.

S&L states this contingency was based on co st qualitative risk assessment (QRA) using Palisade Corporation's @RISK software. The co ntingency 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 pr ovided for any of these risks. It appears that a number of the inputs to this calcula tion 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 ot herwise risks to Entergy itself, and not S&L as the EPC contractor. For instance, one asse ssed 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 ca pital cost. Since Entergy is required to use a 7% interest rate in this calculation under the Control Cost Manual, assessing the risk of it incr easing is inappropriate. S&L a ppears to assess both the risks due to a longer compliance timeframe and a shorter compliance timeframe. Since we are not changing our proposed compliance timefra me 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 es calation 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 ch arge of $2,273,000 on owner’s costs, third party services, and contingency.

As described above, we have noted many probl ems with Entergy’s 2015 White Bluff SDA cost analysis, as contained in S&L Report #012831. We therefore cannot ac cept it. In instances like this, we often present our own co st analysis, eliminating the di sallowed 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 w ould 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. Visi bility Benefit

Comment: EPA should have evaluated the visi bility 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 th at EPA’s BART and Reasonable Progress

determinations are inconsistent with other EP A BART determinations, which would have been evident if EPA had evaluated visibility improve ments on a $/dv basis. When evaluated on that basis, the costs of EPA's Pr oposed 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 se mi-dry scrubber were excessive (even though EPA determined that both of those co ntrols were “cost-effective” on a $/ton SO 2 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 faile d to consider in its analysis of the energy and nonair quality enviro nmental impacts of compliance that must be
considered. All $/dv calculations for White Bluf f, 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- Effe ctiveness 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 w ith its Corette BART determination.

Comment: EPA is not required to consider the do llar per deciview cost of controls, and in any event, the dollar per deciview cost of cont rols 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 th e dollar per deciview metric. Furthermore, had EPA done so, Nucor contends that the dollar per deciview values for th e proposed controls are unreasonably high. Neither of Nucor’s arguments has merit.

First, EPA is not required to assess BART or reasonable progre ss 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 deci view value of controls. For BA RT 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 consideri ng costs in part by considering the costeffectiveness of controls, meas ured 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 us ing 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 requ ired to consider the dollar per deciview value of controls, the dollar per deciview values for th e proposed controls are comparable to other controls EPA has approved, given that EPA has approved SO 2 controls that cost as much as approximately $50 million per deciview. See Stamper Report, Ex. 6. As describe d elsewhere in the Sierra Club et. al.’s comments and in the Stamper Report, the costs and visibility be nefits of the proposed controls are comparable to the costs and bene fits 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 cons ider the $/dv metric, but take no position on its statement that the dollar per deci view values for the proposed controls are comparable to other controls we have previously appr oved. We disagree that the $/dv metric is more meaningful than

our use of the $/ton metric in c onjunction with our consideration of the visibility benefit from the361 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 co mparable 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 th e 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 BA RT 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 r ecommended 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 me tric as part of its proposed BART

determinations for either the Four Corner s Power Plant FIP in AZ, or the San Juan Generating Station FIP in NM. Generally speaking, while the metric can be useful if thoughtfully app lied, we view the use of the $/deciview metric as suggesting a level of precision in the calcu lation of visibility impacts that is not justified in many cases. While we did not use a $/deciview metric, we did, however, consider the visibil ity 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 do llar-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 guideline s 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 contro ls. Although visibility is not one of the four mandatory factors explicitly listed for consideration under CAA sectio n 169A(g)(1) or 40 CFR 51.3 08(d)(1)(i)(A), states or EPA have the option of considering the projected visibility be nefits 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 Fe deral Register Notice for the Oklahoma Regional Haze and Visibility Transport Federal Implem entation Plan, Docket No. EPA-R06-OAR-2010-0190, 12/13/2011, pdf 116.

672 70 FR 3916 7.362 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 explai ned why it did not use the dollar-perdeciview metric used by Oklahoma. "Gen erally speaking, while the metric can be useful if thoughtfully app lied, we view the use of the $/deciview metric as suggesting a level of precision in the calcu lation 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 devel oped "thresholds of acceptable costs per deciview improvement." Id. While the federal land managers have developed thresholds, these thresholds were appare ntly 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 caprici ous that the EPA chose not to use the dollar-per-deciview metric in evaluating BART options in creating the FIP. We

therefore also conclude th at any argument by the peti tioners 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 decivi ew 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 Mont ana proposal, which summarizes cost-effectiveness in $/ton, 674 and this quote concerning the Co rette facility from our Montana

final decision: 675

The BART Guidelines require that cost e ffectiveness be calcul ated in terms of annualized dollars per to n 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 e xplained 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 im provement 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 men tion 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 alternativ es" 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 cons ider the additional energy costs and water/land impacts of scrubber technology. Any costs associated with th ese energy and nonair quality environmental impacts of compliance were incl uded in our analysis. Thus we see no inconsistency with our Core tte BART determination.

Comment: EPA does not complete the analysis by giving a rational ex planation as to why the costs of the proposed controls were justified by the visibility improvement. [Arkansas Attorney General (0162) p. 4-6] Th e 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 im provements cited in the proposed FIP. EPA provides the cost calculations a nd it provides the visibility calc ulations; 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 exercise d 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 ar bitrary and capricious if ‘the agency fails to articulate a satisfactory explanation for its act ion, 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, w ithout a satisfactory expl anation 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. Cost s are an important factor in both determining appropriate BART controls and in setting reason able 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 cos tly for the State of Arkansas and its citizens.

In Michigan v. EPA , supra, the United States Supreme C ourt reiterated its support for sensible

consideration of cost with in a regulatory scheme:

676 80 Fed. Reg. 18944 (April 8, 2015).

677 Id.364 Consideration of cost re flects the understanding that reasonable regulation ordinarily requires paying attention to the advantages and the disadvantages of agency decisions. It also reflects the real ity that too much wasteful expenditure devoted to one problem may well mean cons iderably fewer resources available to deal effectively with other (per haps 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 ‘appr opriate’ to impose billions of dollars in economic costs in

return for a few dollars in hea lth or environmental benefits.” Id ., Slip Opinion at 7. EPA fails to explain its rationale from imposing significant costs upon Ar kansans 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 comment s from ADEQ and the parties affected by the proposed FIP.

Response: The commenter states that EPA failed to c onduct a rational cost-ben efit analysis and makes improper comparisons to suggest that our proposed costs do not justify the expected visibility benefits. These arguments are withou t 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 th e five statutory factors we must consider in a BART analysis under CAA sec tion 169A(g)(2) and 40 CFR 51.308(e)(1)(ii)(A). In our reasonable progress analysis, alongside the four statutory fact ors, we also considered the visibility improvement of controls. Although visib ility is not one of the four mandatory factors explicitly listed for consideration under C AA section 169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), states or EPA have the option of considering the projected visibility bene fits of controls in determining if the controls are necessary to make reasona ble 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 cost s 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 re duced ($/ton) basis. Our analys es conservatively estimated many individual cost parameters, resulting in higher cost estimates. We then validated the cost effectiveness of each control op tion 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 th at we were not requir ed to conduct a formal365 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 determini ng whether regulating haza rdous air pollutants was “necessary and appropriate.” Id. at 2706, 2711.

The proposal’s controls fall within the range of cost-effectiveness valu es established across a range of regional haze actions. The Ninth Circu it recently affirmed EPA’s costing method, see

Arizona , 2016 WL 722685 at **16-18, expl aining that “cross-facility comparisons of similar sources with regard to the cost-effectiveness of a given control option ai d in determining cost effectiveness at a specific s ource.” 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 sc rubber retrofits with cost effec tiveness 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 visibi lity improvement” metric has no basis in the CAA and EPA’s regulations and mischaracter izes visibility impr ovements in Class I

areas.

[Entergy Arkansas Inc. (0166) p.54-55; Ente rgy 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 “cu mulative visibility improvement” metric is arbitrary and capricious, and has no basis in law. In assessing the visibility improvements that are predicted to be achie ved 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 Cla ss I areas to support its proposed NOx BART

determination for Lake Catherine. 80 Fed. Re g. 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 cu mulative visibility improvement across the four affected Class I areas to support its proposed BART determinations and reasonable progress

determinations for the other aforementioned facil ities. It is improper for EPA to rely upon the cumulative visibility improvement across all a ffected Class I areas. BART and reasonable progress determinations instead should be base d 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 wh ether 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 indi vidual Class I area would experi ence 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 Ru le allows considerati on 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 c ontrols. For example, EPA appear s to have selected BOOS as NOx BART for Lake Catherine in part becau se 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 i ndividual 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 impr ovement, 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 visibil ity 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 deci view is the minimum change in visibility perceptible to a huma n observer. Deciviews cannot be di rectly 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, par ticles from one Class I area cannot contribute to or improve the light extinction at another Clas s 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 benef it from any visibility improvement that might be occurring at another Class I area. The cumulative me tric 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, therefor e, EPA has not justified that the predicted visibility improvements are “rea sonably 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 ow n regulations and is misleading. EPA's practice of summing up the predic ted 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 meaningl ess. For example, the cumulative visibility improvement metric frequently will be construc ted by summing up visibility improvements that may be perceptible for one or more Class I ar eas with visibility improvements that are not perceptible for one or more other Class I areas . The only purpose of th e cumulative visibility improvement indicator is to imply that faciliti es are having a large impact across numerous Class I areas, but this indicator can be deceptive if it includes imper ceptible visibility improvements

for some Class I areas. EPA should not use a cu mulative metric and should instead assess only the impacts of controls at i ndividual 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 visi bility improvement values at other Class I areas to arrive at a “cumulative visibility improvement.” 680 The “improvement” referenced in the

tables refers to “cumulative visibi lity benefits.” Similarly, in othe r tables, EPA adds the visibility impacts at individual Class I areas to a rrive at a “total visibility impact.” 681 The Proposed FIP, however, does not contain a discussion of the orig in or purpose of a “total visibility impact” metric, nor does it provide a sound scientific explan ation for either the “tot al visibility impact” metric or the “cumulative visibility improvement” metric.

Neither the Regional Haze Rule nor the EPA’s ow n guidelines provide a basis for a cumulative visibility metric or a total visi bility impact metric. Since the Re gional Haze Rule aims to improve visibility in individual Class I ar eas, adding slight improvements in visibility from separate areas together does not offer a useful method for m easuring overall visibi lity improvement. Many small incremental changes in perception in va rious locations do not create one large uniform incremental change in perception when aggregat ed. 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 l ack 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 Pr oposed 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 Cl ass I area to the visibi lity improvement values

at other Class I areas to arrive at a “cumulative visibility improvement. 683 This “improvement”

referenced in the tables refers to the “cumulativ e visibility benefits.” EPA does not discuss any purpose for calculating the “cumulative visibility be nefits” in the Proposed FIP. Similarly, EPA adds the visibility impacts at indi vidual 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” metr ic. 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 EP A 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. Us ing 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 toge ther slight improvements in visibility from separate areas is not a useful method for measuring overall incr eased visibility improvement. EPA’s chosen measurement of visibility impairment is a “deci view,” 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 a ny meaningful information related to progress toward reaching the ultimate goal of restoring background visibility cond itions at Class I areas.

It is grossly misleading to provide cumula tive numbers as a measurement of overall improvement when the incremental changes may onl y be slight, barely perceptible, and separated by large distances. The methodology behind these metr ics lacks any scientific basis. Due to the misleading nature of the cumulative visibility metr ic 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 Regiona l Haze Rule is to impr ove visibility in the nation’s national parks and wilder ness 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, su ch 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. § 51.301369 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 yiel d a less than one deciview improvement to visibility. The fraction of improveme nt will be imperceptible to the human eye. If a deciview is a measurement of perception of a landscape, it is e ssentially a snapshot in time. It is physically impossible for a person to look at the vistas of all class I Federa l areas at the same time. Thus, small, imperceptible changes in visibility ac ross the four class I Federal areas cannot be combined to manufacture a measure of perceptible im provement in visibility. It is, therefore, not logical then to aggregate the vi sibility improvements across all four class I Federal areas for each source, as is done in the proposed FIP. As suc h, one may question how the cost can be justified when visibility will notbe perceptibly improved.

EPA has invented the concept of “cumulative visibility impr ovement” 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 Retr ofit Technology (“BART”). CVI is a construct of the EPA that defies common sense and cannot be used to justif y 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 su ch will result in overall improvement. At best, this standard confuses the public and incorrectly represents th e actual visibility improvements

that will result from the chosen controls. At wors t, 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 consid er cumulative visibility improvement when promulgating a FIP. [Sierra Club et. al. (0171) p. 41-44] The Si erra 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 vi sibility 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 th e 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 th at 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 thos e areas for comparison purposes.” 79 Fed. Reg. at 5,120. There is nothin g inappropriate, much less anything unlawful, about considering the visibility improvement at mu ltiple 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 eviden ce in the record suggests that the BART and reasonable progress sources for which EPA proposed c ontrols impair visibility in at least four Class I areas, and that reducing pol lution from these sources would im prove 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 appro ach to other haze plans for EPA

to fail to consider the cumulativ e visibility improvement here. Th e legal requirement to consider cumulative visibility impacts is ro oted 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) (“Congr ess 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 area s which impairment results from manmade air pollution.”). EPA has interpreted the statutory goal of improving visi bility 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 th at the national goal of the program is to improve visibility at all Class I areas, it would be short-sight ed to limit the evaluation of the visibility benefits of a cont rol to only the most impacted Class I area.”); 77 Fed. Reg. 51,620, 51,631-32 (Aug. 24, 2012) (“EPA believes that it is impor tant to consider the visibility impact on multiple Class I areas. The goal of the visibility pr ogram 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 stat e indicated that the cumulative visibility improvement was significa nt. Similarly, when developing federal plans, EPA has considered cumulative visibility im provement 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 ha ve 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 categoric ally 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 bene fits, when such benefits are significant, it is not reasonable to ignore them altogether as ADEQ did.” Id.371 Similarly, EPA disapproved the stat e of New York’s determination as to the controls that are BART for SO2 pollution from the Danskammer po wer 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 explai ned its decision by noting that “[i]n making BART determinations, EPA also recomme nds the consideration of cumulative impacts and improvements that could occur at all of the Cl ass I areas a particular facility might impact.”

Id. EPA also disapproved several BART determinat ions 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 Cla ss 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 contro lling 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 neve r 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 explai ning the final regional haze plan for Montana, EPA noted that “[i]n our analysis of vi sibility impacts, we co nsidered the visibility improvement at all Class I areas with in 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 explaine d in the proposal, the EPA considered cumulative visibility impacts, as well as the other BART factors in reaching its BART

determination for this facilit y.”). 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 benefi ts 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, th e 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 de monstrate that EPA has approved plan s 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 so urces, 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 woul d improve visibility at all affected Class I areas. We believe that EPA is required to consid er the visibility improvement at all affected Class I areas as this approach gives meaning to th e 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 author ized 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 ot her 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 in tended 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 vi sibility metrics. Another appr oach 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 cumula tive 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 vi sibility 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 th e 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 effect s of the source. For other Class I areas in relatively close proximity to a BART-eligib le source, you may model a few strategic receptors to determine whether effects at thos e areas may be greater than at the nearest Class I area. For example, you might chose to lo cate 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 exp ected 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 a dditional analyses might be unwarranted. 690

This section of the BART Guidelin es 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 dur ation components of impairment,” emphasizing the flexibility in method and metrics that exists in assessing the net vi sibility improvement.

689 For example see 76 FR 52429

690 40 CFR 51 Appendix Y, IV.D.5373 In fully considering the visibility benefits an ticipated from the use of an available control technology as one of the factors in selection of BART, it is appropr iate to account for visibility

benefits across all affected Class I areas and th e BART guidelines provide the flexibility to do so. One approach as noted above is to qualita tively consider, for example, the frequency, magnitude, and duration of impairment at each a nd 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 note s the similarity between some of the reasonable progress factors a nd the BART factors contained in Section 51.308(e )(1)((ii)(A), and suggests that the BART Guidelines be cons ulted regarding cost, energy and non-air quality environmental impacts, and remaining useful life. We are therefor e relying on our BART Guidelines for assistance in interpreting thos e reasonable progress factors, as applicable. Also, similar to a BART analysis, we are also co nsidering the projected vi sibility benefit in our analysis following the BART gui delines and the use of CALPUFF. 692 We rely on the

BART Guidelines here and in ot her actions evaluating reasonable progress controls because they provide a reasonable and consiste nt approach regarding visibili ty modeling. This includes the flexibility in metrics that ex ists in assessing the net visibility improvement, and the use of cumulative visibility, along with visi bility impacts at individual Cl ass 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 mo re than one Class I area.

For each subject-to-BART source and the source ev aluated 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 imp rovement across the four Class I areas. The results show that some sources significantly imp act visibility at more than one Class I area,

emission reductions result in vi sibility benefits at all impact ed class I areas, and in some situations, the largest visibility benefits from c ontrols can occur at Class I areas other than the most impacted.

Therefore, consistent with the BART Guidelin es, and based upon these facts, we determined additional analyses were not on ly 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 conclude d that a quantitative an alysis 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 fr om the sources evaluated for BART and reasonable

progress.

691 Guidance for Setting Reasonable Progress Goals Un der 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 impr ovements from controls at multiple Class I areas. Given that the national goal of the pr ogram is to improve visibility at all Class I areas, it would be short-sighted to limit the evaluation of the visi bility benefits of a c ontrol to only the most impacted Class I area. We believe such informati on is useful in quantifyi ng the overall benefit of controls. As discussed in our pr oposal, we evaluated the statutor y 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 im provements that may be imperceptible elsewhere

in this section of the re sponse 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, wh ich 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 an d 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 vi sible to the naked eye, 694 achieving these slight reductions exceeds the scope of regulatory regime specifically designe d to address “the impa irment of visibility.”

The CAA only provides EPA with the authority to regulate the “impai rment 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 increm ental 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 disc ernable to the naked eye. Under both the plain language and dictionary definitions of “visibility,” the stat ute 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 “cap able 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 58,303.375 regulate haze below a single deciview, which woul d be invisible to the naked eye. Since the Proposed FIP will only achieve visibility improve ments 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-Yam ato Steel Company (0163) p. 12; and Arkansas Electric Energy Consumers Inc. and Ar kansas 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 h ealth based standard, and EPA may not require emissions reductions just for sake of doing so unde r 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 "d egree of improvement in visibility which may reasonably be anticipated to result from the us e of such technology." Id. §7491(g)(2) [emphasis supplied]. EPA may not require a source “to spe nd millions of dollars for new technology that will have no appreciable effect on haze in a ny 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 ev en when those technologies had no appreciable effect on visibili ty). Yet that is precisely what EPA has done here. Despite these limits on its authority, through the proposed FIP, th e EPA requires certain st ationary sources of

immense value to the State of Arkansas and its citizen s to install controls that will cost billions of dollars in order to achieve imperceptible visibility improvements.

Response: We disagree with commenters that the Re gional 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 visibilit y benefit may still be significant, as explained by the Regional Haze Rule: 701

Even though the visibility improvement fr om 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 co ntributions in the Cl ass 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 require ments 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 impa irment 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, 39129376 compliance, the energy and non-air quality enviro nmental 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 r easonably be anticipated to result from the use of such technology. 702

The CAA also requires that in determining r easonable 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 requirement s. Our Reasonable Progress Guidance 703 notes the similarity between some of the reasonable progress factor s and the BART factors contained in Section 51.308(e)(1)((ii)(A), and suggests th at the BART Guidelines be c onsulted regarding cost, energy and non-air quality environmental impacts, and remaining useful life. We are th erefore relying

on our BART Guidelines for assistance in inte rpreting those reasonable progress factors, as applicable, including visibility improvement ev en though it may not be perceptible from an individual source. Also, similar to a BART an alysis, we are also considering the projected visibility benefit in our an alysis of reasonable progress controls following the BART guidelines. 704 We rely on the BART Guidelines here a nd in other actions evaluating reasonable progress controls because they provide a reasonabl e and consistent approach regarding visibility modeling.

We accordingly disagree that selection of c ontrol measures under BART or for reasonable progress should be contingent upon perceptible visibility improve ment. As we stated in our previous rulemaking addressing the BART determinations in Oklahoma: 705

Given that sources are subject to BART based on a contribu tion 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 indivi dual source may not be perceptible, it should still be c onsidered because the contribu tion 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 re lative 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 reas onable progress analysis, we have not considered perceptib ility 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 visibi lity, and the fact that, in the aggregate, improvements from controls on multiple source s (either under BART or reasonable progress) will contribute to visibility progress towards th e 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 activitie s which are located across a broad geographic area. In this action, we found that the requi red cost-effective controls reduce visibility impairment from those BART sources that cont ribute or cause visibility impairment at nearby

Class I areas and result in meani ngful visibility benefits toward s the goal of natural visibility conditions. Similarly, we also found that the required cost-eff ective controls at the Entergy Independence facility reduce visibility impairme nt 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 ma de 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 en tirely possible that a source may be forced to spend millions of dollars for new technology that will have no appreci able 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 di d 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 contri bute to regional haze and therefore subject to

BART. 708 The approach in the Regional Haze Rule re quired a State to analyze “the degree of visibility improvement that would be achieved in each mandatory Class I Fede ral area as a result

of the emission reductions achievable from all sour ces 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 visi bility which may reasonably be anticipated to result from the use of such technology” factor infringed on states’ auth ority 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 e ach 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 cons trained 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 6378 because it found that we forced States to require BART controls without first assessing a source's particular contributi on to visibility impairment. This is no t the case with our action in Arkansas. In response to this court decision and to addres s 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; rath er, we considered all five BART factors fully, revea ling 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 visi bility improvement in a BART determination by using a regiona l, multi-source, group approach to assessing the visibility improvement factor, while assessi ng the other four statutory BART factors on a source-specific basis. Here, we did not give gr eater weight to our considerati on of visibility improvement or consider the visibility in a di fferent fashion from the other fa ctors. 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 Ar kansas. We must also consider the same factors that the State is mandated to consider by the CAA. The "deg ree 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 vi sibility 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 disc ussed above, we considered all the statutory factors, including the "degree of improvement in visibi lity which may reasonably be anticipated to result from the use of such [b est available retrofit] technology” in our BART

determinations. We do not cons ider perceptibility as a thresh old criterion for considering improvements in visibility to be meaningful. Failing to consider less-than-perceptible contributions to visibility impairment woul d 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 refl ects a misunderstanding of the nature of the Regional Haze problem. [Sierra Club et. al. (0171) p. 39-41] Th e Sierra Club et. al. stated that various commenters criticize the proposed FI P 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 approximate ly one deciview improvement at Caney Creek and Upper Buffalo. 80 Fed. Reg. at 18,994. Simila rly, if EPA had presented the improvement expected from both of the new scrubbers combin ed 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 re sulting 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 facilitie s is not linear so ca nnot be determined by simply summing the CALPUFF results for each i ndividual unit, but the combined improvement

from controls will exceed one deciview.

Not only is it appropriate to c onsider the combined visibility benefits from all of the SO 2 controls

at all of the controlle d sources, it is appropr iate to consider the combined benefit from both SO 2 and NO x controls. In the real world, the benefits from operating SO 2 and NO x controls are not experienced separately; actu al visibility conditions depe nd on the effects of both SO 2 and

NO x emissions on atmospheric chemistry. The vi sibility improvement from all the SO 2 and NO x controls EPA is proposing far exceeds one decivi ew. Thus, when all the controls are considered together, the proposed FIP will result in visibil ity improvement far greater than one deciview, and will be perceptible.

Moreover, it is factually incorr ect 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 thre shold of perception in all cases

for all scenes. The EPA believes that visibility changes of less than one deciview are likely to be per ceptible in some cases, especially where the scene being viewed is hi ghly sensitive to small amounts of pollution. 64 Fed. Reg. 35,714, 35,726 (July 1, 1999).

The comments regarding the perceptib ility 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 pr ogress” toward the goal of eliminating haze. 42 U.S.C. § 7491(a)(1), (b)(2). Congress defined re asonable progress to include consideration of four factors, id. § 7491(g)(1), but Congress did not dictat e the minimum amount of improvement that it would deem reasonable. Instead, Congre ss 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 at380 each source individually produce visibility improve ment 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 cause d 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 acro ss a broad geographic area.”). The regional haze regulations reflect EP A’s finding that the Congressional goal of eliminating haze can be achieved only by tackling the multitude of source s 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 visu ally perceptible visibility improvement, the commenters advance a position that is inconsiste nt with EPA’s long-standing interpretation of the regional haze rule. Commenters’ suggestion w ould also thwart Congress’s goal of ensuring progress toward the national visib ility 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 di scuss in response to comments above, the Regional Haze Rule does not require that contro ls on a source or group of sources result in perceptible visibility improvement. We also ag ree that in some cases required controls either individually or in combination wi th other required controls will re sult in perceptible visibility improvements at impacted Class I areas on some days.

Comment: The purported visibility improve ment that would result from the SO 2 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 improveme nt 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 co st for the Ashdown Mill. As noted in Nat’l Parks

Conservation Ass’n , it is arbitrary and capricious for EP A 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 to n removal basis the limit may app ear to be cost effective, the significant increase in annual operating expense will adversely affect the M ill‘s competitiveness in global markets and negatively affect its economic viability. Such a minor incremental381 visibility improvement, so small as to be insi gnificant and not perceivable to the human eye, does not justify the very high additional opera ting 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 cap abilities of the CALPUF F model and cannot be reasonably anticipated elsewhere in this se ction of the Response to Comments document. We address comments concerning the per ceptibility of visibility benefits in a separate response to comment above. In our analysis, we determin ed 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 em ission limit can be achieved by additional scrubber reagent in the existing scrubb er, which is cost-effect ive and results in a decrease in the visibility impacts from this source at the nearest Class I area.

We note that the commenter’s characte rization 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 rulema king as required under the law. 714

Comment: Some of EPA’s proposed BART det erminations are not justified based on the negligible projected visibility improvements. [UARG (0176) p. 4-7] UARG stated that EPA proposes BART determinations for certain facili ties that are based on EP A projected “visibility improvements” that are so minimal – indeed, hypot hetical, because they are below, and in most cases far below, the level of human perceptib ility – that they ca nnot support any BART requirement that entails installation and operati on 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 prope rly 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 thres hold for a source’s “causation” of visibility impairment at a Class I area and a 0.5-dv threshol d for a source’s “contri bution” to visibility impairment at a Class I area. Id . at 39,161. Indeed, in promulga ting the BART Guidelines, EPA stated that “for purposes of determining whic h sources are subject to BART, States should consider a 1.0 deciview change or more fr om 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 pe rceptibility 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 si gnificant costs that most of th ese BART determinations would impose, these proposed EPA actions are unreason able because they would not appreciably

714 “Concurring, Judge Berzon wrote separately to empha size 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 th ese specific circumstances.” Nat’l Parks Conservation

Ass’n vs. EPA382 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 SO 2 BART emission limit will result in visibi lity 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 ha s an average cost-effectiveness of $2,559 per ton of SO 2 removed. Id.

 SO 2 BART for McClellan Unit 1: EPA projects that its proposed SO 2 BART limit will result in visibility improvement ranging fr om 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 SO 2 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 – i ndeed, merely hypothetical – visibility improvements are insufficient to ju stify 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

 SO 2 BART for Domtar Ashdown Mill Power Boiler No. 2 : EPA projects that its proposed SO 2 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 SO 2 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 mi nuscule 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 hi gh 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  NO X BART for Domtar Ashdown Mill Power Boiler No. 2: EPA projects that its proposed NO X 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 av erage cost-effectivene ss of $1,951 per ton of

NO X 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 humanl y 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. Th e proposed FIP thus presents a result that Congress sought to preven t 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 propos ed 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 unjus tified proposed BART limits.

Response: We address comments concerning the perceptib ility of visibility improvements in a separate response to comments above. We disa gree with the commente r 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 sour ces that contribute to, as well as cause, such impairment.” 716

The commenter confuses the thresh old 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 impa irment 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 as sess the maximum total visibility impact from all BART units at a facility, typi cally based on CALPUFF modeling. If the impact from all the BART sources at a facility is above the thresh old, then each BART unit must be evaluated for controls, and theref ore 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 th at 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 c onsider along the cost of controls and other factors in informing

716 70 FR 39104, 39129384 the BART determination. For each of the required controls listed by the commenter, we

evaluated the cost of controls along with the anticipate d visibility benefit due to controls, the remaining useful life of the source, energy a nd non-air quality envir onmental impacts, and existing pollution control technology of all potential available c ontrols 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 a lluded to the possibility that, as is, the Rule may result in a situation wher e 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 else where, “Failing to consider less-t han-perceptible contributions to visibility impairment would ignore the CAA’s intent to have BART requirements apply to sources that contribute to, as we ll 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 th e 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 antici pated to cause or contri bute 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 achi eved 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 co nsider 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 w ith 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 c onstrained State authority, it did so because it found that we forced States to require BART contro ls without first assessing a source's particular contribution to visibility impairment. This is no t 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 co ncerns we finalized a revised Regional Haze Regulations and

Guidelines for Best Available Retrof it Technology (BART) Determinations. 725

With regard to the comment we properly rec ognize that the minuscule additional visibility improvement that could be achieved through installation and operati on 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 disagr ee that the same reasoning woul d apply. As we detail in our proposal, LNB/SOFA was determined to be ve ry 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 justifie d 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 co sts 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 Ar kansas Inc. stated that it acknowledges that, under the Regional Haze Rule, “the URP does not esta blish 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 addi tional 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 require s a consideration of the projected visibility benefit expect ed from the controls. Id . At 18,993.

EPA admits that it did not perform refined, mu lti-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 expens ive. 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 reasonab le progress benefits of installi ng 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 itsel f has recognized, CALPUFF is overly simplistic and greatly

overstates the effect of si ngle source emissions. BART Guidelines, 70 Fed. Reg. 39,104, 39,121 (July 6, 2005) (“there are other features of our recommended mode ling approach that are likely

to overstate the actual visibil ity effects of an individual sour ce. Most important, the simplified chemistry in the model tends to magnify the actua l 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 differe nt pollutants in the atmosphere than CAMx.

725 70 FR 39104.386 EPA has recognized that CAMx, a photochemical tran sport 3-dimensional grid model, is a more appropriate modeling tool for reasonable prog ress purposes. Proposed Texas Regional Haze FIP, 79 Fed. Reg. at 74,877-78. BART analyses assess th e impact of a single facility based on the maximum or 98th percentile impacts, regardle ss of whether the Class I area was actually experiencing high visibility impairment on a ny given day. Since CALPUFF does not conduct an analysis considering all the emissions from all pote ntial 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 incl uded 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, PM 2.5 , 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 scenari o... as part of a regional haze a ssessment usually necessitates the application of a chemical transport grid model.” Draft Modeling Guidance at 22. 726 Throughout the Draft Modeling Guidance, the discussion is fo cused on items specific to photochemical grid models such as CAMx, including emissions invent ories, supporting models, pre-processors, and applying a model to changes in visibility.

According to the Draft Guidance, “the emissi on sources included in the analysis must be comprehensive, including emissions from all so urce categories” (i.e., poi nt sources, non-point stationary sources, on-road and non- road mobile sources, fires, a nd biogenic sources) and “‘all’

sources of emissions.” Id . at 32, 36. A CAMx modeling anal ysis includes a comprehensive inventory, capturing each of thes e 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 emissi ons from a facility or source in question. This has been referred to by EPA as a “dirty background analysis.” CA LPUFF analyses conducted in support of BART

determinations do not consider the full inventor y of sources and thus do not account for other pollutants challenging and consuming precurs or 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 reflec t 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 th e 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/guida nce/guide/Draft_O3-PMRH_ Modeling_Guidance

‐ 2014.pdf

.387 models for assessing visibility impacts from a si ngle source or small group of sources. According to the Agency,

Chemical transport models ar e well suited for the purpose of estimating long-range impacts of s econdary pollutants, such as

PM 2.5 , that contribute to regiona l 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

PM 2.5 , 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 suppor ting 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 sy stem that treats emissions from all known anthropogenic and biogenic emissions sources with realistic chemical and physical

transformations should be utilized to estimate fu ture visibility conditions at a Class I area. The most appropriate tool that contains these qua lities is a photochemical grid model [such as CAMx].” Id. at 6. It further explains th at “the results from a BART determination or similar modeling using CALPUFF cannot be directly co mpared to estimated impacts of emissions controls from a single source on a reasonable progress goal.... La grangian puff models are not ideal for reasonable progress demonstrations sin ce 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 reas onable progress analysis and, as a result, significantly overestimated the Independence Plan t’s contribution to visibility impairment and the deciview improvement that would result from the installa tion and operation of emissions controls at the Independence Plant. 728 The visibility impairment at Ar kansas’ two Class I areas is caused overwhelmingly by point sources outside of the st ate, secondary organic aerosols - biogenic (“SOAB”), mobile sources, and Arkansas area sources 729 - 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 visi bility 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 sim ilar 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 group ed with other like sources in to 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 w ould 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 Plan t is misplaced and clea rly 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 singl e source emissions, does no t 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 va stly overstates the vi sibility 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 base d 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 c onsider 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 mode ling 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, a nd post-processing the mode l 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 re latively small change in the overall emissions patterns within the entire modeling domain. Th e only change within the entire model, which

includes the emissions from thousands of source s, 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 visibi lity 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 NO x 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 em ission "scaling" approach to de termine the effects of various

control scenarios for their evaluation of Texa s sources. For Arkansas, EPA Region 6 used the CENRAP 2018 base case projections as its starting point. For Texa s, EPA Region 6 also used the same CENRAP 2018 base case projections, but s upplemented it with a c ouple additional CAMx model runs (with updated emission levels), re presenting low and high control levels. The modeled species concentrations (contributions fr om 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 SO 2 and NOX emissions scaling approach that is currently be ing applied for the evaluation of the sources in Arkansas. EPA Region 6 did not run the CAMx model repeated ly to determine the visibility effects of controlling individual sources.

In Texas, the model results were used to de monstrate that the overall change in species concentrations was very nearly linearly proportio nal 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 redu ctions in sulfate and nitrate

concentrations at each of the Class I areas will be very near ly proportional to the SO2 and NOX concentration reductions. In other words, the em ission scaling approach has been shown to be mathematically sound and quite appropriate, especi ally considering the re sources that would be required to exercise CAMx separately for each control measure at each evaluated source.

Response: The commenters confuse the single source an alysis 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 m odeling following the same modeling protocol relied on for the BART analyses to assess the visib ility impacts and potential benefits of controls for the units at the Independence facility. For es timating 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, incl uding source apportionm ent results, and the projected emission inventories, and scaled the results as desc ribed in the TSD. While we acknowledge that this approach is not as refined an estimate as w ould 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 co mmenter 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 determinat ion 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 consider ation of the visibility be nefits, we relied on the results of our CALPUFF modeling, the CENRAP CAMx source apportionm ent results, and point source emission inventory data that initially iden tified the Independence facility as having the greatest potential to impact vi sibility 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 photoche mical grid models (such as CA Mx) in the future if modeling tools available were appropriate and EPA approved of the tec hnical 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 mode ls such as CALPUFF, CMAQ, REMSAD, and CAMx have all been usedfor 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 ev aluating specific Texas sources for reasonable progress. In 2006/7, EPA OAQPS and EPA Region 6 consulted with FLM representatives and approved Texas’ BART screeni ng 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 re quired to use CALPUFF in a BART determination as part of a SIP or FIP. The BART Guidelin e cited and referred to EPA’s Guideline on Air Quality Models (GAQM) 737 which includes provisions to ob tain approval through consultation with the reviewing authority. More over, we also note that in EP A’s document entitled Guidance on the Use of Models and Other Analyses for De monstrating 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 mode l should meet several general criteria for

it to be a candidate for consider ation. These general crite ria are consistent with the requirements of 40 CFR 51.112 and 40 CFR 51, Appe ndix W. Therefore, it is co rrect 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 visibi lity 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 tech niques 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 th eir use for SIP development in the future as they are adapted and demonstrated to be approp riate for single sour ce applications.”

736 See “Revised Draft Final Modeling Protocol, Screenin g Analysis of Potentially BART-Eligible Sources in Texas” Prepared for TCEQ by ENVIRON, Septembe r 27, 2006; “Modeling Guidan ce: Guidance for the Application of the CAMx Hybrid Photochemical Grid Mo del to Assess Visibility Impa cts 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 68218391 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 mode l visibility benefits as part of the reasonable progress analysis, and have used largely the same met hodology 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-effectiven ess as part of the four factor analysis and has

the benefit that it is immedi ately comparable to modeling us ed for BART determinations. Compared to a CAMx modeling exercise, CALPU FF modeling of one or more sources requires much less resources and time. However, the CA LPUFF 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 eval uating 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, pr ovide a complete representation of emissions, chemistry, transport, and deposition, while CA LPUFF treats a single source with simplified chemistry and parameterized physical processes. Furthermore, th e CAMx model can be used to evaluate a large number of indi vidual sources, and there are c oncerns 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 de termined 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 se lection 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 perf orm a final CAMx mode l scenario to obtain the new RPGs in our Texas action, and instead relied on a scaling anal ysis similar to the methodology used in this action to adjust the CE NRAP modeled RPG values based on the source apportionment data and emissions da ta 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 co ntrols based on scaling the anti cipated emission reductions and the source apportionment modeling. In Texas/Ok lahoma, source-specific source apportionment

data and emissions were utilized. In the othe r states, emissions and source-apportionment data on a state and source category level were utilized.

Consistent with the ex amples discussed above 740 , 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 progre ss evaluation, and that source was well within the recommended range for CALPUFF modeling of u nder 300km from the Class I areas of interest. In fact, three

738 For example see summary of the reas onable 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 Do cument, available at www.r egulations.gov, Document

ID: EPA-R06-OAR-2014-0754-0087.

740 For example see summary of the reas onable 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 screeni ng analysis focused on NOx and SO2 emissions from Arkansas point sources and our determinatio n 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 s ources subject to BART, we relied on CALPUFF modeling prepared by the faciliti es. 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 benef its across all facilities impacted by the proposed rulemaking. In some situations, the CALPUFF m odeled maximum or 98th percentile impacts of the facility may not coincide with the days th at make up the worst 20% monitored days at the Class I area. Therefore, the visibility be nefits modeled by CALPUFF are not directly comparable to the visibility benefits that woul d 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 signif icantly 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 i nventory revealed that a very small number of point sources are responsible for the majority of the point sour ce emissions of NOx and SO2 and therefore a very small number of point source s are responsible for the portion of visibility impairment due to Arkansas point sources on th e 20% worst days; and the Independence facility is one of the very largest emission sources a nd it is located relatively close (under 200 km) to three Class I areas. Therefore, we identified Independence as having th e greatest potential to impact visibility on the 20% worst days based on emissions and location and should be evaluated for reasonable progress controls. We determin ed that CALPUFF modeli ng 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-effectiv e controls. We then considered visibility benefits of the costeffective controls. We conducted CALPUFF mode ling to determine the level of visibility impacts and benefits anticipated by SO 2 and NOx controls at nearby impacted Class I areas, evaluating the 98 th percentile visibility impacts. 741

As we discuss elsewhere, Entergy submitted CAMx model results as part of their comments. The modeled contribution to visibility impair ment 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 natura l background conditions) is over 0.5 dv at the Arkansas Class I areas and even larger at the Cl ass 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 si gnificantly impacts visib ility, 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, suppor t 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 action393 The commenter cites the BART guidelines and as serts that EPA recogni zes 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 mode l 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 fre quently predicted lower nitrate concentrations compared to the CAMx photoc hemical grid model which has a much more rigorous treatment of photochemi cal reactions. EPA recognized th e 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 co nsider the less conservative 98th percentile primarily because the chemistry modules in th e CALPUFF model are simplified and likely to provide conservative (higher) re sults 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 limitation s of the CALPUFF model in the Preamble, EPA concluded that, for the specific purposes of the Regional Haze Rule's BART provisions, CALPUFF is suffi ciently 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-sour ce analysis to evaluate visibi lity impacts and benefits of

controls on an individual source with the analysis of overall visi bility conditions at a Class I area due to the complete emission control strategy for all sources develope d under the reasonable progress and long-term strategy requirements. The draft modeling guidanc e (as does the current guidance 746 ) discusses the projection of overall vi sibility conditions and the need for photochemical grid modeling to account for all em ission sources to model current visibility conditions and project future vi sibility conditions in response to the overall emission control

scenarios. The section of the modeling guidance on regional haze 747 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 featur es 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 othe r Analyses for Demonstra ting 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 evalua tes visibility impacts from a singlesource or a limited group of sources, it is not cap able of projecting overall visibility conditions

due to all sources and controls. Consistent with this draft gu idance 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 m odel results and adjusted them based on source apportionment and emissions data, to estimate the new RPGs fo r 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 im pacts 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 report 749 and assert that they support the conclusion that the use of CALPUFF for Independ ence was inappropriate. We disagree with the commenter. As we discuss above, we agree wi th 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 a ffect EPA's recommendation that States use CALPUFF to determine the applicab ility 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 m odels have evolved sufficiently and provide a credible platform for estimating potential visibi lity 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 fi nalized, CALPUFF or any other model can still be used for any non-BART analysis with the appropri ate 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 th e 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 contro l strategy analysis for single sources.”

749 Interagency Workgroup on Air Quality Modeling Phas e 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 ap propriate modeling techniques, such as photochemical transport models (which address limitations of models like CALPUFF [37] ), the EPA is proposing that theGuideline no longer contain language that requires the use of CALPUFF or another Lagrangian puff model for longrange transport assessments. Additionally, the EPA is prop osing to remove the CALPUFF modeling system as an EPA-preferred model for long-range transport due to concer ns 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 th at long-range transport assessments may be necessary in certain limited situations for PSD increment. For these situations, th e 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 report 752 discusses in detail the difference between the CALPUFF analysis typically followed under BART and the use of photochemical grid models for assessing reasonable progress an d overall visibility conditions . The report does not identify a preferred model for single-sour ce analysis but rather identifies the difference between the modeling approaches and cautions that the m odel 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 c onditions and improvement because they are only able to model a single or small group of sources . Accordingly, we utiliz ed CAMx model results to project overall future visibi lity conditions and establish the new RPGs in our reasonable progress demonstration. We us ed CALPUFF visibility modeli ng along with our evaluation of

the costs of controls to inform our decision on th e reasonableness of contro ls at the Independence facility. We also used CALPUFF visibility mode ling as only one factor to inform our decisions on BART for subject-to-BART facilities. We al so note that both the pro posed revisions and the IWAQM report were published after the proposed rule for Arkansas regional haze was published and well before the technical analysis a nd modeling were completed.

We address comments concerning th e contribution to visibility im pairment from Arkansas point sources and the benefit of controls on Indepe ndence 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 addre sses a significant portion of the visibility impairment due to Arkansas sources.

Comment: Use of CALPUFF modeling does not suppo rt 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 re liance on CALPUFF modeling results to make regulatory decisions in this case is not justif ied 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 overest imation is the failure to incorporate the puff splitting option within the CALPUF F 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 Phas e 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 typi cally 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 Ai r 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 accu racy 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 unde r similar circumstances has been previously

identified 755 and is described with specific referenc e 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 se veral well-known meteor ological phenomena and processes, and causes it to overe stimate visibility impacts by a fa ctor 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 obser vations of plume widths at long-range. 757 Among other things, this is due to the impact of plume tr ansport 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 igno red. 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 li kely 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 distorti on are a regular part of atmospheric behavior and cannot be neglected in re gulatory actions assessing the co st 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 contro l 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 captur ed 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 likel y 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 Cl ass I areas. Using the dates of the 98 th percentile visibility impacts, transport wind speeds were found to be generally less than 3 m/s. Thus, transport times for all plumes would have exce eded 10 hours and most transport times were 15- 24 hours. Thus, almost all plumes would have en countered an evening transition and overnight transport. The following tables demonstrate the distance in kilometers (km) and plume transport times for White Bluff, Flin t 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 In dependence 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 transpor t 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 underestima ting the effects during these overnight hours, which results in underestima ting plume widths by a factor of five to ten, and corresponding overestimations of plume concentr ations. This results in visibility impacts that398 are not accurate and should not be utilized to ma ke 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 b een 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 CALPU FF 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 signi ficant 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 appli cation 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 im pact greater than 2 to 3 deciviews meets the contribution threshold adopted by the States does notrequire the degree of cer tainty in the results of the model that might be required for othe r regulatory purposes.” 70 F.R. 39104, 39123; July 6, 2005; Regional Haze Regulations and Guidelin es for Best Available Retrofit Technology (BART) Determinations; Final Rule [emphasi s supplied]. For regulatory action such as evaluating the level of controls for a FIP, mu ch more realistic modeling should be used to determine visibility impacts. Fo r the Arkansas FIP, this should include at a minimum usage of the puff splitting option in CALPUFF. It shoul d also include an ev aluation 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 iner tial oscillations in the wind field. If at a minimum, the CALPUFF model results are overe stimated by a factor of 5, the maximum 98 th
percentile baseline visibility impact for White Bluff, Flint Creek, or Independence would be lowered to a level that removes any reasonabl e 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 pr ecise enough to reliably differentiate results

that are fractions of a deciview apart. In the proposed FIP, th e maximum visibility improvement reported for any single Class I area fo r 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 visib ility 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 de ciview change in haziness is a small but noticeable change in haziness under most circumstances when view ing 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 Atmos pheric Haze”, J. Air and Waste Manageme nt Assoc. 52: 1238, 1243, attached hereto as Exhibit 21 (“A 1- deciview change is never noticeable.”)399 significance of the modeled visibility improveme nts in the proposed FIP, EPA subjectively labels them as “considerable” (7 times), “si gnificant” (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 c onsiderable, significant or meaningful from a visibility standpoint, when these imp acts are not able to be perceived. 763

If adjusted to account for th e overestimation of the CALPUF F model and the distances and transport times involved in this case, the modele d visibility improvements would be even further below the 1dv perceptibility th reshold. As explained in Dr. McNider's report, based on the studies of observed plume width versus m odeled plume width, disp ersion 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 system atically overstates both the baseline visibility impacts of White Bluff, Flint Cr eek and Independence, and the vi sibility 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 m odel 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 repo rts, 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 predic tions of the tiny visibility benefits projected

from installation of additional controls. As i ndicated, EPA has not validated that the results within CALPUFF align with any real-world da ta or observations; however, the Hoffnagle and McNider reports demonstrate that at the distan ces 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 av ailable state-of-the-art modeling science. EPA's consideration of visibility im pacts 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, comb ined with the inability of the model to make

accurate determinations below the 1 deciview thres hold 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 anticipat ed 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 av ailable for predicting a single source’s contribution to visibility impairment. It is the only EPA-approved model for use in estimating single source pollutant concentra tions resulting from the long range transport of primary pollutants. In a ddition, it can also be used for some purposes, such as the visibility assessments addressed in to day’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 al so 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 fr om sources such that the differences in source configurat ions, sizes, emission rates, an d visibility impacts are wellreflected in the model results.

The use of CALPUFF in the context of the Regiona l 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 us ed 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 w ith 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 . . . CALP UFF 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, th e 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 BART 767 and claim that we state that CALPUFF is only a reasonable tool when im pacts exceed 2 to 3 deciviews. This is incorrect. The BART

Guidelines finalized in the 2005 Rule estab lish a maximum threshold of 0.5 deciviews for determining whether sources cause or contribut e 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 BART 768 and recommends the use of CALPUFF 769 to predict the visibility impacts from a single source at a Class I area to compare against this th reshold. The commenters fail to note that later

in that same section of the Rule we also disc uss the recommended use of CALPUFF to evaluate visibility benefits of cont rols. There we state:

“...we also recommend that the States use CALP UFF as a screening application in estimating the degree of visibility improveme nt that may reasonably be expected from controlling a single source in order to inform the BART de termination. As we noted in 2004, this estimate of visibility improvement doe s not by itself dictate the level of control a State would impose on a source; ‘‘the degr ee 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 togeth er 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 f acility based on CALPUFF modeling. If the impact from all the BART sources at a facility is a bove the threshold, then each BART unit must be evaluated for controls, and ther efore 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 un its, 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 vi sibility benefit would be one fact or to consider along the cost of

controls and other factors in in forming the BART determination.

With respect to our analysis of controls unde r reasonable progress, we rely on our Reasonable Progress Guidance. 771 Our Reasonable Progress Guidance note s the similarity between some of the reasonable progress 4 statutory factors and the BART 5 statutor y factors contained in the Act and repeated in the Guidance, and suggests that the BART Guid elines be consulted regarding cost, energy and non-air quality environmental im pacts, 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 ar e 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 matte r, 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 th e 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 Un der 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 conclu sions concerning CALP UFF model performance and assertions that model predic tions are overestimated by a factor of 5. We note that our regulations do not allow for the calib ration 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 examin ed all of EPA’s prior LRT model evaluation

efforts. These evaluation studies included th e 1986 8-Model Study (Car hart , et al., 1989), Rocky Mountain Acid Deposition Model A ssessment Project (Godowitch, 1989a, 1989b), IWAQM Phase I and II (EPA, 1998a, 1998b), an d the 2012 EPA LRT model evaluation study (ENIVRON, 2012a). 774 From this review, we drew the follo wing conclusions that are relevant to

commenters concerns:

1. The results of both the 1986 and 2012 EPA evalua tion efforts clearly identified that LRT model performance is highly sensitive to the quality of the me teorological inputs, meaning that LRT model performance w ill vary with the performance of the meteorological simulation used to supply mete orological information to the LRT model. Thus, in context, one cannot arbitrarily conclude that any modeling platform will consistently over-predict with every a pplication as LRT model performance is inextricably linked to prognostic me teorological model performance.

2. Carhart et al. (1989) conclude d that, in general, LRT models tend to underestimate the horizontal spreading of the plume at ground leve l resulting in too hi gh peak (centerline) concentrations when compared to the observa tions. 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 sp read of plumes will c onsistently result in over-prediction of ground level c oncentrations, resulting in hi gher bias and error scores.

This observation is consistent with th e findings of the EPA 2012 model study which

showed that the model CALPUFF underestimat ed 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. Ev aluation and Sensitivity Analyses Results of the MESOPUFF II Model with CAPTEX

Measurements. EPA-600/3-89-056. U.S. Environmental Protection Agency, Atmosphe ric 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 CALP UFF Modeling Results to Two Tracer Fi eld 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 Qua lity 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., EP A-454/R-12-003, Research Triangle Park, NC. https://www3.epa.gov/scram001/re ports/EPA-454_R-12-003.pdf403 monitor arcs (ENVIRON, 2012). This phenomenon was also observed in the original report published in 1998 as part of th e IWAQM Phase II process. CALPUFF underestimated lateral plume spread by as mu ch as 24% for the GP80 study and as much as 49% for SRL75 (EPA, 1998a). At great er distances, both the 1998 and 2012 studies showed that this phenomena reversed itself, w ith 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 Tra cer experiment (ETEX) results provided in the 2012 report also shows an underestimation of the late ral 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 disper sion is based upon Turner stabi lity classes or not. We do not disagree that some elements of scales of motion are potentia lly neglected by the CALMET/CALPUFF system. CALPUFF modeli ng utilizes CALMET to construct the meteorological inputs using surface and aloft mete orological observations and three-dimensional output from the MM5 prognostic numerical model. Performance evaluations of MM5 generated data sets against surface meteorological observati ons were completed for the datasets used to evaluate CENRAP BART sources, including th e 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 us e of upper air observat ions 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 cond itions that are input into the model, such as emissions and observed meteorological conditio ns 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 guida nce 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-p redict visibility impacts. For example, the 2012 ENVIRON report on Comparison of Single-Source Ai r 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 Syst em conference, Anderson et al. (2010) 777 found that the CALPUFF model frequently predicted lower nitr ate 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 re sults 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 si mplified chemistry could lead to model over predictions and thus be conser vative, 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 ov erly conservative and recommended the use of

the 98 th percentile value. While recognizing the limitations of the CALPUFF model in the Preamble of the Regional Haze Rule, EPA concl uded that, for the spec ific 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 inco rrect in not utilizing the puffsplitting option 780 and that this resulted in an overestim ation 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 Eu ropean Tracer experiment (ETEX). That sensitivity analysis determined that “the CALP UFF puff splitting sensitiv ity tests did not have any significant effect on CALP UFF 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 CALPU FF underestimated concentrations and the use of puff-splitting resu lted in higher co ncentrations.

Additionally, we ran the puff splitting feature in it s default configuration for the Four Corners Air Quality Task Fo rce CALPUFF dataset 782 modeling visibility impact s 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-split ting, visibility impacts (and thus concentrations) bot h increased and decreased ac ross 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 th eir 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 featur es 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 th at can further account for ve rtical wind shear effects across individual puffs when this is of specific concern. Di spersion 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.xls405 The analysis that appears in Table 1 of the Mc Nider analysis is flaw ed because surface wind speeds do not define puff transport. According the CALPUFF User’s Guide 784 , 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 contac t 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 im perceptible. We disagree and address this comment elsewhere where we discuss that per ceptibility is not a threshold criterion for considering improvements in vi sibility to be meaningful.

The commenter refers to the Hoffn agle report (Ex. 19 of Nucor co mments) to support claims that the CALPUFF model over-predicts concentratio ns. The Hoffnagle report claims that comparisons of CALPUFF modeled visibility im pacts to observed data demonstrates that CALPUFF over-predicts nitrate exti nction by a factor of 2 to 10, that the model is unreliable beyond 200km, and that the modeling is not suffici ently 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. Rega rding the use of CALPUFF beyond 200km, EPA concluded from the evaluation of the IWAQM ph ase 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 trans port distance was limited to less than 300km. 785

, 786
Furthermore, we note that all the large EGU sour ces 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 elsewh ere where we address co mments concerning the “margin of error” of the model and case st udy comparisons of CALPU FF 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 th e time we performed our analysis. 787 The Hoffnagle report discusses CALPUFF version 6.4 and alleges that that it is more scientifica lly 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 (Ver sion 5), Scire, et al., January 2000. Available at: http://www.src.com/calpuff/down load/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 co ntains 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 Re sponse to Comments for NM Regional Haze/Visibility Transport FIP, August 5, 2011. Available at: http s://www.regulations.gov/#!do cumentDetail;D=EPA-R06-OAR2010-0846-0127406 action to determine potential visibility impacts. The newer version(s) of CALPUFF have not

received the level of review re quired for use in regulatory acti ons subject to EPA approval and

consideration in a BART deci sion making process. Based on our review of the available

evidence we do not consider these newer versio ns 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 revisi ons to the Guideline on Air Quality Models (Appendix W). Proposed revisions to Appendix W discuss rem oving the requirement to use CALPUFF for long-range transport assessments and as a preferred model due to the need to provide flexibility in estimati ng single-source secondary polluta nt impacts and concerns about management and maintenance of the CALPUFF modeling code. 789 These proposed changes do

not affect EPA's recommendation that States us e CALPUFF to determine the applicability and level of BART in regional haze implementati on plans. The proposed changes also do not preclude the use of CALPUFF fo r any other non-BART analysis. The proposed changes to the Appendix W rule simply propose to remove CA LPUFF 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 jus tification as an “alternative model.”

Finally, the CAMx modeling provided by Entergy Ar kansas 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 di scuss 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 fr om the Independence facility at both Caney Creek and Upper Buffalo. For the White Bluff faci lity, 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 faci lity 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 98 th 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 (98 th percentile) is approximately 3.3 dv at Caney Creek and 2.3 dv at Upper Buffalo.

We address more general comments concer ning 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 ap propriate modeling techniques, such as photochemical transport models (which address limitations of models like CALPUFF [37] ), the EPA is proposing that theGuideline no longer contain language that requires the use of CALPUFF or another Lagrangian puff model for longrange transport assessments. Additionally, the EPA is prop osing to remove the CALPUFF modeling system as an EPA-preferred model for long-range transport due to concer ns 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 th at long-range transport assessments may be necessary in certain limited situations for PSD increment. For these situations, th e 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 st ated 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 tec hnology chosen by EPA fell within the model's margin of error, meaning such improvement cannot be “reas onably ... 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 betw een the facts found and the choice made.” 793 As a result, EPA acted in an arbitr ary and capricious manner by fail ing to provide an adequate explanation as to how the degr ee of visibility improvement c ould 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 determina tions. 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 po rtion of the Regional Haze Rule itself, it is arbitrary and capricious for EPA to force an emi ssions 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, 20 15 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 th e three Arkansas EGUs at any Class I area is

0.813 deciviews attributed to SO 2 controls at the Entergy White Bluff Unit I at Caney Creek, which is below the 1 deciview thre shold of visibility pe rception. Furthermore, EPA required the installation of low-NOx burners and over fire air at SWEPCO’s Flint Creek Unit, even though the highest modeled visibi lity improvement was 0.081 deciviews for NOx. Given the acknowledged over-prediction of the CA LPUFF model and its inaccuracy at these low levels, the actual visibility impact for the Stat e’s EGUs (and most likel y the other subject-toBART sources as well) would be much lower.

The CAA does not require visi bility improvements that canno t 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 provi de 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 th is 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 Circu it 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. Si nce 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 particul ar, 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 an ticipated 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 (9 th 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 th e 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 th e 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 statutor y prerequisite to procee ding 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 improve ment. 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 analys is 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 improve ment achieved by the imposition of BART on the Ashdown Mill. The report will be provided duri ng the reopened comment period.

Response: We disagree with the commenter's charac terization of the Ni nth Circuit decision regarding the “margin of error” of the CALPUFF model. The Ninth Circuit decision cited did not rule on any specific issue rela ted 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 ru lemaking as required under the law. 797

We discuss below in a separate response to comment in this section that the analysis performed by Trinity Consultants 798 that purports to calculate a “mar gin of error” of the CALPUFF modeling for the Arkansas BART sources (Domta r 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 improve ment that may be expected from available control technology” to inform BART and reasonable progress evalua tions. Whether or not the modeled visibility impacts or benefits lie below th is erroneous, calculated “margin of error” is immaterial to any assessment of whether or not the visibility impair ment or benefits from controls can reasonably be anticipated to occur. The noti on of a calculated “margin of erro r” 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 analy tical analysis” for every appli cation of the CALPUFF model to assess uncertainty in model results.

In response to the court’s finding in American Corn Growers Ass’n. v. EPA 799 that we failed to provide an option for BART evaluations on an individual source-by-source basis, we had to identify the appropriate analytic al tools to estimate single-source visibili ty impacts. The 2005

BART Guidelines recommended the use of CA LPUFF for assessing vi sibility (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 BA RT 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 ce rtain assumptions and uncertainties. 800 Evaluation of CALPUFF model performance for di spersion (no chemistry) to cas e studies using inert tracers has been performed. 801 It was concluded from these case st udies the CALPUFF dispersion model had performed in a reasonable manner, and ha d no apparent bias toward over or under prediction, so long as the transport di stance was limited to less than 300km. 802

, 803

In promulgating the 2005 BART guidelines, we responded to comments concerning the limitations and appropriateness of us ing CALPUFF. There we respond:

CALPUFF is the best modeling application av ailable for predicting a single source’s contribution to visibility impairment. It is the only EPA-approved model for use in estimating single source pollutant concentra tions resulting from the long range transport of primary pollutants. In a ddition, it can also be used for some purposes, such as the visibility assessments addressed in to day’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 al so 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 fr om sources such that the differences in source configurat ions, sizes, emission rates, an d 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 prim ary 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 determin ed the visibility resu lts 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 wa s 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 samp ling was available, such that the transport of the tracer pu ff as it passed the arc could be monitored. Differ ences on the order of 10 to 20 degrees were

found between the location of the simula ted and observed center of mass of th e tracer puff. Most of the simulated centerline concentration maxima along eac h 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 other411 We also recognized the uncertainty in the CALPUFF modeling results when we made the decision, in the final BART Guidelines, to recomm end 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 si mplified chemistry could lead to model over predictions and thus be conser vative, EPA decided to use the less conservative 98th percentile. 806
Examining the distribution of CA LPUFF modeled visibility impacts, it can be seen that the few

values at the extreme of the distribution ar e much higher than the rest of the values. 807 Therefore, in recognizing some of the limita tions of the CALPUFF model, we determined that use of the maximum modeled impact may be overly cons ervative and recommended the use of the 98 th
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 M odeling and Analysis System conference, Anderson et al. (2010) 809 found that the CALPUFF model fre quently predicted lower nitrate concentrations compared to the CAMx photoc hemical grid model which has a much more rigorous treatment of photochemical reacti ons. 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 98 th 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 featur es 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 Models412 The CALPUFF modeling following the BA RT guidelines and using the 98 th percentile value does not lend itself to model performance evalua tions of the type suggested by the commenters (see comments below concerning the “Margin of erro r” analysis), comparing measured visibility impairment at a specific time and place to modele d 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 emissions 811 , 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 em ission sources for the available ammonia. The goal of this modeling is to estimate the maximu m anticipated impact from the source in the vicinity of a Class I area (typical ly an area on the order of severa l hundred square miles or more), and not to provide an estimate of downwind concen trations or visibility conditions for a specific place at a specific time.

CALPUFF uses a pseudo-first-order chemical reaction mechanism to mo del 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 CALPUF F are appropriate for estimating a worst-case scenario for this particular sour ce and region. We note that small changes in emission levels will not significantly perturb the ava ilable 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 da ta, 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 inform ing decisions. The use of the 98 th percentile value and considering a minimum of thr ee 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 tr ansport of visibility impairing pollutants to a re ceptor 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 leve l of impact is a reliable assessm ent of the degree of visibility impacts and benefit from controls. Any uncerta inties in meteorological conditions that govern the transport and diffusion of pollutants are le ss 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 vi sibility impairment in a Class I area. Modeling of control scenarios is us ed 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 expect ed 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-contr olled 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 mo deling of these control sc enarios is done in a manner that holds all variables constant except for the emissions of the pollutant of interest. A relative reduction in visibility imp act 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 th e BART determination, but only one factor and is

considered on a relative basis to the baseline impact and the be nefits of other controls. The relative visibility benefit of all controls is weig hed along with the absolute and relative costs of controls, energy and non-air environmental impact s, 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 ra tes, and visibility impacts are well-reflected in the model

results.

CALPUFF visibility modeling, performed using the regulator y CALPUFF model version and following all applicable guidance and EPA/FLM r ecommendations, provides a consistent tool for comparison with the 0.5 dv subject-to-BAR T 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 a ssessing 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 complete d their BART analyses an d have either approved SIPs or FIPs in place, there is a large set of availa ble data on modeled vi sibility impacts and benefits, and how those model results were utilized to screen out sources a nd as part of the fivefactor analysis in making BART control de terminations 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 th e EPA’s willingness to reopen the comment period on the proposed BART requirements to a llow the Ashdown Mill to complete its very detailed and comprehensive analysis of CALP UFF’s model’s “margin of error.” Based on the report, the Ashdown Mill’s proposed BART requi rements will not resu lt in any reasonably anticipated improvements in visibility and shoul d 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 th e compliance period for five years.

In these supplemental comments, the Domt ar 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 co mments. We address Domtar’s July 15, 2015 comments elsewhere throughout this RTC doc ument. We address the specific comments provided in Domtar’s supplemen tal comments in the sections of the RTC document where we discuss modeling, cost, and reasonable progress an alysis issues. The “margin of analysis” evaluation submitted by Domtar is addressed in response to comments below.

Comment: EPA improperly uses CALPUFF to just ify emission reduction measures when the visibility improvements predicted by the CALPUFF model ar e within CALPUFF’s margin of error. [The Associations (0165) p. 9-10] The Asso ciations stated that in at least two instances, the proposed Arkansas federal impl ementation plan FIP imposes emission reduction measures through BART on the grounds that CA LPUFF 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 credib le 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 r easonably be anticipated to result from the use of such technology.” 42 U.S.C. § 74 91(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 wa s less than CALPUFF’s margin of error, and thus, EPA had no basis to belie ve that BART controls in that case could “reasonably be anticipa ted” to improve visibility. In the proposed rule, EPA imposes emission reduction requirements under BART in situatio ns where CALPUFF predicted very small visibility improvements without completing any s ite specific analyses to determine if these visibility improvements are within the margin of error. For example, EPA would require the

installation of low NOX burne rs and overfire air at Flint Creek Unit 1 even though the highest modeled visibility improvement was 0.081 dv. Base d 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 ma y be less than the margin of error. EPA needs to justify that the small visibility improve ment is “reasonably anti cipated”. The Clean Air Act does not require visibility improvements that cannot be reasonable an ticipated. Visibility improvements that are less than the margin of error are not “r easonably 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 ar eas 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 th reshold 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 re duction requirements on sources that, even if their emissions were much higher, would not even ri se 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 th ey do not even contribute to visibility impairments.415 Sensing that infinitesimal visibility improveme nts (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 Im provement” 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 coul d be believed. In this case, however, where each constituent modeled visibility im provement 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 improve ments that should individually be treated as zero, EPA arbitrarily attempts to create somethin g out of nothing (and even here the “something” is far below human perception). EPA should ab ide 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 cas e to avoid the decision’s holding by adding low confidence modeling results in order to artificia lly exaggerate the impact of emission reduction

measures.

Response: The commenter is mistaken regarding th e Ninth Circuit decision including the “margin of error” of the model. The Ninth Ci rcuit decision cited did not rule on any specific issue related to CALPUFF or the “margin of error” . Rather, the court rule d on a procedural error that EPA did not respond to the comment received regarding the CALPUFF ma rgin of error in its rulemaking as required under the law. We re spond to comments concerning the calculated “margin of error” of CALPUFF mode ling in a separate response.

The BART guidelines establish that a visibility impacts from a st ationary 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 deci views, it would be inconsistent to automatically rule out additiona l controls where the improvement in visibility may be less than 1.0 deciview or even 0.5 deciview s. A visibility improvement greater than 0.5 dv, as the commenter suggests, is not a requ irement 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 threshol d criterion for considering improvements in visibility.

We address comments concerning the use of cumula tive visibility in a separate response to

comment above.

Comment: Visibility improvement from contro ls on Lake Catherine Unit 4 cannot be reasonably anticipated due to the ma rgin 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 in stallation 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. 39161416 the proposed controls, EPA relied on the CA LPUFF dispersion modeling system without assessing the reliability of the model to pr edict 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 comp leted a quantitative analysis to ev aluate the margin of error in

the CALPUFF model for Lake Cather ine 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 Catherin e Unit 4, modeled using Post-BART emission rate and stack parameters.

Trinity calculated the average difference betw een modeled values obt ained using CALPUFF (including the CENRAP background) and IMPR OVE 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 W 20 days visibility for this anal ysis. Specifically the following comparisons were made:

 Modeled vs Measured W20 Days: The W 20 days based on IMPROVE measurements

were selected for each Class I area and co mpared 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 wh en IMPROVE measurements were taken. Modeled values were then compared to the IMPROVE measurements from the corresponding days.

 Measured and Modeled W20 Days: The W 20 days based on IMPROVE measurements were selected and compared with th e 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). (“CA LPUFF Margin of Error Report”),

which is attached as Exhibit H and is hereby incorporated by refe rence. 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 wh en compared with the IMPROVE measurements, which capture the impact of all other sources, in cluding Lake Catherine, on the Class I areas.

The proposed NOx BART controls for Lake Ca therine Unit 4 will result in visibility improvements that are even more inconseque ntial and cannot accurately be predicted by417 CALPUFF. Based on Trinity’s analysis, the min imum calculated margin of error for CALPUFF

for Lake Catherine Unit 4 is 0.93 dv. The CALPU FF 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 Cla ss I areas associated w ith 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 NO X 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 visi bility improvement associated with EPA’s proposed BART for Lake Catherine at Caney Creek and Upper Buffalo fall w ithin this margin of error. As such, the visibility improvements at ea ch of these Class I areas associated with the proposed BART cannot be reasonably anticipate d, as is required by the Clean Air Act. (42 U.S.C. 7491(g)(2).

Comment: Domtar’s Margin of Error Analysis de monstrates that the predicted visibility improvement from EPA’s proposed BART co ntrols 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 Cons ultants report enclosed with Domtar’s comments, the predicted visibility improvements associat ed 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 “reasonab ly 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 essentia l that EPA demonstrate that an y 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 th e proposed rule is projected to be in the millions and threatens the competitive position of the Ashdown Mill. The enclosed report by Trinity Consultants demonstr ates that EPA cannot show any “reasonably anticipated” improvements in visibility will result, and as su ch, 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 ma rgin of error for CALPUFF for the Ashdown Mill is 0.93 dv. The CALPUFF predicted visibi lity improvement associated with EPA’s proposed BART controls for the Ashdown Mill Po wer Boiler No. 2 at Caney Creek and Upper Buffalo fall within this margin of error. As such, the visibilit y improvements at each of these418 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 mode l’s predicted visibility impacts.

Response: The commenters mischaracterize the Ninth Ci rcuit decision regarding the “margin of error” of the model. The commenter suggests that the Court agreed that th e anticipated visibility benefits in that case were within the margin of e rror 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 ru lemaking 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 co mmenter’s analysis claiming to estimate the “margin of error”.

The Trinity analysis 815 purports to calculate a “margin of error” of the CALPUFF modeling for Lake Catherine. In general, the commenter’s analysis adds CALPU FF model results for a specific source or sources with CAMx model resu lts and compares this value to visibility

conditions derived from monitored data at each Cl ass 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 visib ility 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 spreadsh eets or detailed calculations to support this analysis, therefore we were unable to fully revi ew 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 ra te (equal to the maximum 24-hr emissions for baseline and estimated control-level emissions), assump tions of constant background ammonia, and simplified, limited chemistry. Modeling of a thre e 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 pr ovide an estimate of downwind concentrations or visibility conditions for a sp ecific place at a specific time.

In promulgating the BART guidelines we made the decision in the fina l BART Guideline to

recommend that the model be used to estimate th e 98th percentile visibil ity 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 empha size 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 th ese 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 m odel over predictions and thus be conservative,

EPA decided to use the less c onservative 98th percentile. 816 As a starting point, a BART-eligible source is identified as subject-to-BART and subject ed to a five-factor BART analysis only if it may reasonably be anticipated to cause or contribute to any impai rment 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 co mparing the modeled impact from baseline

emissions to the reduced modeled impact of the various contro l scenarios. This visibility analysis is only one factor of the BART determina tion 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 us eful life of the source, and the existing control equipment at the

source.

Our CALPUFF visibility modeli ng, performed using the regula tory CALPUFF model version and following all applicable guidance and EPA/FLM recommendations, showed significant visibility impacts due to the source and bene fits 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 ha s provided a consistent ba sis for determining if a source is anticipated to “cause” or “contribute” to visibi lity impairment at a Class I area and in assessing the degree of vi sibility benefit anticipated from co ntrols as one of the factors under

consideration in a 5-factor BART analysis. CALPUFF mode ling, 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 resu lts from two different models

The commenter’s analysis asserts that adding a “background” light ex tinction value derived from the 2002 CENRAP CAMx photochemical mode l 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 valu es. The commenter is incorrect because the CALPUFF modeling following the BA RT 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 th e baseline period. In additio n, 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 wi nd field based on prognostic data from the MM5 model which is then adjusted based on terrain an d land use data and then further adjusted based

on observational data. A model such as CALP UFF essentially holds constant a number of

factors in order to isolate the im pacts of a single source. It is extremely difficult in observational analyses to sufficiently control for all factors, in cluding 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 featur es 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 addr ess many of the issues that cause the comparison to not be a “like-kind” comp arison. We discuss below why the CAMx “background” value does not properl y 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 maximu m 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 emi ssion sources represent. As discussed by the commenter, CALPUFF is a “clean background analys is” because it only m odels emissions from one source. Therefore all of the ammonia presen t in the model is available to react to the

emissions from this one source. In a “dir ty 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 em issions from the source of interest to form visibility impairing particulate matter.

CAMx photochemical modeling using actual or typi cal emissions (which includes all emissions sources and has a more realistic representation of formation, transport, and removal processes of particulate matter that causes visibility de gradation) provides an estimate of downwind concentrations paired in space and time. Th e CENRAP 2002 CAMx mo deling utilized actual available emissions data, including hourly meas ured emissions data from EGUs and prognostic meteorological data from the MM5 model that went through extensive meteorological model performance analysis. 817 Ammonia concentrations are calcul ated based on emissions, transport, deposition, and chemistry. It is not appropriate to simply a dd predicted concentrations or visibility impacts from two very different models that rely on different model inputs (emissions and meteorological data), utilize different chem istry, and are used for different purposes. Furthermore, because the CENRAP CAMx modeli ng already contains emissions from the BART sources, simply adding the two model estimates re sults 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 avoi d double counting in this manner.

Fails to consider uncertainty in “background” value

The commenter’s analysis fails to consider a ny uncertainty in the CAMx derived “background”

value that is added to the CALP UFF modeled visibility impact. As demonstrated below, the “margin of error” calculated by the commente r is dominated by the under-prediction in the CAMx derived “background” value. The CE NRAP 2002 CAMx model results the commenter uses to estimate the “background” were compar ed 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 mode l selection and performance of the CAMx and CMAQ modeling performed. 819 In that review we summarized th e CENRAP model perfor mance 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 Inventor y Development for the Regional Haze Implementation Plan for the State of Arkansas availa ble at: http://www.regulations .gov/#!documentDetail;D=EPAR06-OAR-2008-0727-0013421 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 Cr eek, 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 underest imated and results in an under-prediction (- 33% bias) on total extinction. There is an overestimate of extinc tion (+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 resu lts in an under-predi ction (-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 tota l extinction at both Arkansas Class I areas was under-predicted by th e model. Therefore, the “background” value added by the commenter has uncertainty associat ed 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 commente r’s evaluation whether any of the difference

calculated between monitored and measured values are due to over or und er performance of the

CALPUFF modeled values.

As we noted earlier, the comment er did not provide any supporti ng spreadsheets or datasets, so

we are unable to review the individual calcu lations 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 disc usses 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 appo rtionment modeling does not provide any source-specific impact informati on that could be subtracted from the CENRAP modeling.

For the Lake Catherine analysis, the report st ates the following concerning background value

used:

In order to obtain an estimate of the imp act of other emission s ources (i.e., point, nonpoint, mobile, biogenic, etc.), Entergy obtained a background value from CAMx modeling completed for the Central Regiona l Air Planning Association (CENRAP) by ENVIRON using the CENRAP PM Source Apportionment Technology (PSAT) Tool. 820
The CENRAP's CAMx analysis was comp leted 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.mdb422 For the Domtar analysis, the report states the following concerning background value used:

In order to estimate the impact of ot her emission sources (i.e., point, non

‐ point, mobile, etc.), Domtar obtained a background value fr om the CAMx modeling completed for the Central Regional Air Planning Associat ion (CENRAP) by ENVIRON using the CENRAP PM Source Apportionment Technol ogy (PSAT) Tool.15 The CENRAP PSAT tool is determined by subtracting contributi on of all BART source (for scenario 1) or contribution of the Ashdown Mill (for scen ario 2 and 3) from the total CENRAP predicted concentrations. The CENRAP’s CAMx analysis was completed for actual emissions from 2002; therefore, the bac kground 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 modele d and observed data points for the Pre-BART

scenario 821 in some of the figures included in that report. We reviewed the 2002 Lake Catherine baseline modeling that was prep ared 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 th e commenter in their analysis. 823 We estimate that the “background” values that were added to th e CALPPUFF model result s are approximately 133.9 Mm-1 for Caney Creek and 124.7 Mm-1 for Uppe r 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 proj ected 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 th e 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 CENR AP CAMx photochemical modeling constitutes the majority of the modeled va lue (CALPUFF modeled impact pl us “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 Cane y Creek. The calculated “margin of error” is dominated by the difference betw een 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 impair ment 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” Pr epared by Trinity Consultants, August 2015

822 2002 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 action423 Following the commenter’s methodology, even if th e CALPUFF modeled values were increased by a factor of ten, the commenter’s estimated “mar gin of error” of the model would not change significantly. The table below summarizes the ch ange in margin of er ror 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 th e disconnect between the commenter’s estimated “margin of error” and any assessment of the CA LPUFF 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 tenf old actually results in a slight improvement

in what the commenters asserts is an indi cation 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 te n. We explain further below the over-prediction seen on the measured vs. modeled comparison.

Domtar impacts on Caney Creek. Modeled and observ ed 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 c onsideration 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 Catherin e Unit 4, modeled using Post-BART emission rate and stack parameters.

Because the commenters did not submit any spread sheets or supporting data, it is not clear how

CALPUFF results for all BART sources were combined for the first scenario. It is unclear how424 the inclusion of all BART sources would provi de useful information on the uncertainty of modeling the impact from a single source. The second scenario sti ll 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 visibil ity conditions in 2002 to a future scenario that would only result from the installation of additiona l controls. As such this scenario would not provide any useful information on the ability of th e model to reproduce past visibility conditions. The commenter provides no explanation to supp ort the selection of th ese scenarios or why analysis of any one scenario would be preferable to the other.

Flaws with the Modeled Versus Me asured 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 dur ing 2002 at Caney Creek and Upper Buffalo for the three scenarios described above. Speci fically, the commenter made the following comparisons:

 Modeled vs Measured W20 Days: Th e 20% Worst days based on IMPROVE

measurements were selected for each Cla ss 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 wh en IMPROVE measurements were taken. Modeled values were then compared to the IMPROVE measurements from the corresponding days.

 Measured and Modeled W20 Days: The W 20 days based on IMPROVE measurements were selected and compared with th e W20 days based on CALPUFF modeling disregarding temporal correlation.

We note that for all comparisons and calcula ted 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 comp arison 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 analys is is to predict the highest values (8 th 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 th at 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 em issions, constant background ammonia, and simplified chemistry) at a Class I area that is ty pically at least several hun dred square miles, and not to provide an estimate of downwind concentr ations or visibility conditions for a specific place and at a specific time. Nevertheless, the co mmenter attempts to do just that by examining425 the specific modeled values on those days with measured high visibility impairment during 2002. As can be seen by the CALPUFF mode l results used for this comparison, 824 the Domtar and Lake Catherine facilities do not have large m odeled impacts during the 20% worst days at the monitor. In fact for many of th ese days, there is no visibility impairment due to these sources as the transport patterns on these days do not carry em issions from these sources to the Class I area. As discussed elsewhere, the days that CA LPUFF 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 li ttle value in assessing the CALPUFF model’s ability to estimate the ma ximum 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 th e monitored data corresp onds 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 impair ment over the worst 20% days (as defined by the monitor) due to the visibility imp act from all sources. This mismatch between the set of days in the observations and the set of days estimat ed in the photochemical modeling “background” results in a “background” value that is much hi gher than the observational data set, and an overall over-prediction in the comparison. As ca n 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 visibi lity 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 Cather ine facilities. Those days with high CALPUFF modeled impacts are a different set of days that have different me teorological/transport conditions that are conducive to the chemistry a nd transport needed to cause visibility impacts

from Domtar or Lake Catherine to occur at th e 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 observati ons that occur under one set of meteorological conditions to a set of days with completely di fferent overall meteorological conditions.

Gives undue weight to values at extreme ta il of distribution of CALPUFF model results

As discussed above, the BART guidelines recommend the use of the 98 th percentile value as to not give undue weight to the extreme tail of the distribution of m odeled values. Since CALPUFF’s simplified chemistry could lead to m odel over predictions and thus be conservative, EPA decided to use the less conservative 98th pe rcentile. The commenter’s analysis utilizes

those values at the extreme end of the distribution that can signi ficantly impact their calculated average of the 20% worst days, despite EPA gui dance 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 Cane y 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 av eraging across a set of days of CALPUFF values, whether averaging the 20% wors t days as defined by the monitor or by the model, that includes some of th e values at the extreme end of the distribution (within the top 7 days) would be shifted towards possibly being ov erly conservative. Fo r 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 av oid 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 9147101316192225283134374043464952555861646770737679828588919497100Extinction(1/Mm) 

### CALPUFF ‐ Lake Catherine 2002 baseline ‐ top 100 days427 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, th e analysis performed does not constitute a proper model performa nce evaluation. Visibility impa irment is calculated based on the summation of extinction due to each visibility impairing pollutant. The concentration of each visibility impairing pollutant is either measur ed 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 guida nce, 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 m odel 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 analys is, the comparisons are limited to only 24 data points. Limitations in the avai lable monitored data (observati onal data is only available for every third day at one monitor) further limits the amount of availabl e data used in the commenter’s analysis for certain comparisons. Section 3.2.1 of the draft modeling guidance 827
provides a description of recommended metrics to be used in this type of evaluation. As we discuss in this guidance, it is important to incl ude 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 metric s, graphical displays of data allow for a fuller characterization of model performance. Ther efore, plots play a key role in any model performance evaluation. Our guida nce details a number of diffe rent plots that should be evaluated including scatter plots, bugle plots, a nd soccer plots. The commenter’s analysis does not provide an adequate analys is of the available data and improperly focuses on the total visibility impairment rather than the individu al 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 contri bute to visibility impairment and “the degree of visibility improvement that may be expected from ava ilable 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 “mar gin of error” is immateri al to any assessment of whether or not the visibility impairment or bene fits 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 Re gional 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 vi sibility impairment in a Class I area. Modeling of control scenarios is us ed to estimate the amount that this visibility impact can be

reduced due to a reduction in emissions. The mo deling of these control sc enarios is done in a manner that holds all variables constant except for the emissions of the pollutant of interest. A relative reduction in visibility imp act 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 weig hed along with the absolute and relative costs of controls, energy and non-air environmental impact s, 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 ra tes, and visibility impacts are well-reflected in the model

results.

Comment: Case study comparisons of CAL PUFF 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 discus sion of work performed by TRC Environmental Corporation. This work include s a June 2012 paper prepared by Gale Hoffnagle that discusses several case studies that compar ed 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 Mo ntana FIP, for its argument that EPA failed to explain why it could reasonably anticipate a visi bility 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 Stati on (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 cl ose as 90 km to the plant showed no change in either nitrate concentrations or visibility impact s subsequent to the closure of the plant. The measured visibility impairment at the Grand Ca nyon National Park during th e 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, Ente rgy Arkansas, Inc., Lake Catherine Plant” Prepared by Trinity Consultants, August 2015

829 Gale F. Hoffnagle, Accuracy of Visibility Protoc ol 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 vi sibility were not statistically significant.

Table 5-1. Mohave Visibility Im pairment – 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, th e CALPUFF results indicated th at visibility impairment caused by the Mohave Station was twice th e level detectable by the human eye. 19 The maximum CALPUFF predicted visibility impairment wa s 3.94 dv over 3 years, with a 98th percentile visibility impairment of 2.31 dv from the Moha ve Station. Based on the IMPROVE monitoring data, CALPUFF highly overestimated the visibili ty 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 Environmen tal Corporation, June 15, 2012

Response: The study by Terhorst and Berkman does not convince us that use of CALPUFF modeling is inappropriate or th at the modeled visibility imp acts and benefits should not be

considered as one of the f actors 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 aut hors state that Terhorst and Berkman’s data analysis actually validate EPA’s in terpretation 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 characteri zations” of Terhorst and Berkman, and that such

“careless claims invite mischievous citation in regulatory contex ts.” The commenter does not address or acknowledge the findi ngs of this rebuttal.

As also noted by the authors in their rebuttal, the compar ison 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 impa irment is based on a natural background approach, where the measured change in deciview impairment is a change relative to the degraded or dirty background conditi ons. 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 extin ction and the different deciview calculations are not directly comparable. Had the CALPUFF values been ad justed 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 98 th 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 addi tion, 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 so urces, to be able to is olate 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 wa s 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 mon itored 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 larg e power plant located between the Craig Station and Mt. Zirkel, the modeled impacts from the Cr aig Station alone were larger

than the monitored values for all sources comb ined, 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 m odeling following the BART guidelines approach is used to estimate the maximum visi bility impact from the source, modeling maximum emissions using simplified chemistry and an a ssumption of constant background ammonia over a period of three years. Since CALPUFF’s si mplified chemistry could lead to model over predictions and thus be cons ervative (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 downwi nd 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 re sults instead of the maximum modeled visibility impairment to addr ess the possibility of model over-predictions. We have also recognized the model’s sensi tivity to background ammonia concentrations,431 particularly in the arid regions of the We stern United States where ambient ammonia concentrations can be low. In developm ent of the Colorado BART modeling protocol 832 , the Colorado Department of Public Health and E nvironment investigated the sensitivity of CALPUFF modeling for the northwe stern portion of the state (w here 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 mode l 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 pref erentially reacts with sulfate. The ambient ammonia concentration is an input to the mode l. Accurate specificati on of this parameter is critical to the accurate estimation of pa rticulate nitrate concentrations. Based on a

review of available data , Langford et al. (1992) suggest that typical (w ithin a factor of 2) background values of ammonia are: 10 ppb fo r 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 w ith ambient temperature (variations of a factor of 3 or 4) and a strong dependen ce 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 ava ilable 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 Arkans as, the selected background amm onia value utilized in our analysis and agreed upon by CENRAP in devel oping their BART modeling protocol is 3 ppb. For some areas of Arkansas, this may be an unde rrepresentation of the amm onia levels due to the

numerous sources of ammonia emissions in the st ate, such as poultry a nd livestock operations. Therefore, the sensitivity of model results to the background a mmonia assumption is much less for CALPUFF modeling of Arkansas sources. Estimated impacts from sulfate emissions are less impacted by the simplified chemistry a nd ammonia assumptions used in the BART modeling than nitrate impacts.

Comparison of observed visibi lity versus modeled impacts

In evaluating the total visibility impacts, Hoffnag le 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 compar ison do not represent the impact from the source alone as claimed in the report and Hoffnagle’s c onclusion is incorrect. Hoffnagle compares the total impact, which includes an estimate of back ground 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 CALP UFF 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 significan t level of extinction, particularly for a relatively clean Class I ar ea 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 wh ere appreciable visibility impairment is measured (impairment greater than the 12.2 Mm-1 natu ral background level) the average modeled visibility impairment is less than half the averag e 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 extincti on due to Craig Station when the approximate background va lue is subtracted.

Observed Visibility Conditions at Mt. Zirkel compared to Mode led 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. Hoffna gle, 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 nitrat e 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 deciview s, delta deciviews due to the source and the % Nitrate contributing to the impairment (as shown in the ta ble 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 repor t. Based on the modeling data from the 2005 CDPHE analysis, we have calcula ted 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 8 th high. However, Hoofnagle calculates that the extin ction from nitrate alone is between 10 Mm -1 and 14

Mm -1 over the 25 highest modeled days 836 , 2 to 3 times higher than the actual maximum modeled extinction due to all pollutants. Hoffnagle inco rrectly 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, th erefore the change in extinction that results in a certain delta deciview is dependent on where on the deciview s cale you are. A delta deci view 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 th e 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 8 th highest modeled day. While the average monitore d nitrate extinct ion 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 2002 837 and exceeds 3 Mm -1 on 18 monitored days during 2001-2003 (greater than 5% of all monitored days). Recognizing the assumpti ons in the modeling that result in evaluating a worst case scenario, the sensitiv ity 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 duri ng these particular days wher e conditions were conducive to transporting the plume to the Class I area were lo wer, we would anticipate less nitrate formation than modeled using the assumed 1ppb.

835 BART CALPUFF Class I Federal Area Individual Sour ce 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 Day 1 Receptor

1 DV (Total)

1 DV (BKG)

1 Delta

DV 1 %_NO3

1 Total

extinction

2 BKG

extinction

2 Extinction

due to

source 2 Nitrate

extinction

due to

source 2

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 Cla ss 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 diffe rence between the modeled and

monitored results is that the CALPUFF model estim ates 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 (locat ed south of the Class I area) only measures visibility conditions at this one site. Given the North to South or ientation 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 sour ce was carried towards a portion

of the Class I area north of th e monitor’s location so that the maximum modeled impact from the source could be significant, while conditions at the monitor loca tion would be much cleaner. Hoffnagle acknowledges this possi bility but does not limit his an alysis 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 impact435 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 ex treme values in their analysis. Furthermore, model performance compared to meas urements at one fixed site under a specific set of conditions, does not invalidate the m odel for all applicati ons and conditions.

Comment: North Dakota SIP

In the development of the North Dakota Regiona l Haze SIP, the North Dakota Department of Health (NDDH) relie d on photochemical mode ling conducted by the Western Regional Air Partnership (WRAP) to determine the impact of sources located out side 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 stat e; however, NDDH utilized altern ate 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 measur ements of turbulence rather than the 1952 Pasquill

‐ Gifford diffusion confidents required by the EPA approach;

 Meteorological data from the National Cent er for Environmental Predictions (NCEP) Rapid Update Cycle (RUC) forecast model; and

 Use of hourly average ammonia concentrati ons instead of an annual average value.

The resulting CALPUFF values were then co mpared to IMPROVE monitoring data from

the South Unit at Theodore Roosevelt Na tional 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 ba sis that it included impacts from other sources rather than evaluating the impairment due to BA RT 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 a pplied 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/m 3 ) Predicted

(μg/m 3 )436 98 th Percentile 2.03 2.06

90 th 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 Regi onal 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 Environmen tal 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 Environmen tal 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 si ngle-source visibility impacts, whether or not the model performed we ll 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 satisfi ed for the use of North Dakota's hybrid modeling. Summarizing model results at one Class I area is not su fficient to demonstrate model performance. Furthermore, the commente r does not include model results for the other

Class I area that is included in North Dakota’s modeling, Lo stwood, where the hybrid modeling does not compare as favorably to the observe d results or the WRAP CMAQ modeling. In conclusion, the commenter does not provide suffici ent data to determine model performance of the hybrid modeling or support any of the non-defa ult modeling options employed in CALPUFF. We discuss more specific comments concerning puff splitting in a separate response to

comments.

We also disagree with the us e of the Ammonia Limit Met hod (ALM) in North Dakota’s modeling and note that it is incons istent with the nitrate repartit ioning approach that has been previously accepted by the FLMs and EPA. Th ere 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 propo sing 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 be ing modeled. Since ammonia levels from the local area were used by North Dakota, to do calculati ons in the modeling to consume ammonia from surrounding sources would unnaturally consume a mmonia that was actuall y 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 modele d 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 Sta tion, 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 va lues on 11 out of 22 of the worst 20% modeled days at the Theodore Roosevelt IMPROVE mon itoring 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 da ys. At the North Absaroka IMPROVE site, the impact from th e Colstrip Station was over predic ted on 9 out of 20 days of the worst 20% modeled days. At the Yellowsto ne IMPROVE site there are 10 days when the modeled extinction from the Colstrip Station ex ceeded the monitored values for the worst 20% modeled days.

Based on this analysis, PPL Montana, LLC, the operator and partial ow ner, challenged EPA’s BART rules, in part, on the basis that the maximum predic ted visibility improvement for Colstrip Units 1 and 2 was belo w the range of perceptibility and falls within the model’s margin of error, “meaning that such improvement cannot be r easonably anticipated as required

by the Act.” 26 The U.S. Court of Appeals for the Ni nth 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 cas e were within the margin of error of the model.

This is incorrect. The Ninth Circuit decision ci ted did not rule on any specific issue related to
CALPUFF. Rather, the court ru led on a procedural error th at 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 th an the actual model estimated value. In the

838 “Concurring, Judge Berzon wrote separately to empha size 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 th ese specific circumstances.” Nat’l Parks Conservation

Ass’n vs. EPA438 case of the Craig Station analysis, the incorrectly calculated nitrate extinction was 2 to 3 times larger than the total extinction estimated by th e model. The commente r’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 nitr ate extinction values for comparison with the

monitored values.

Furthermore, as discussed elsewhere, the an alysis examining the 20% worst modeled days

utilizes those values at the ex treme end of the distribution th at 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 in cluding these extreme values in their analysis.

The CALPUFF modeling following the BA RT guidelines and using the 98 th percentile value does not lend itself to model performance evalua tions 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 discussi on in response to comments on the “margin of error” analysis submitted by commenters). The BART modeling is a worst case assessment, utilizing maximum emissions 839 , assumptions of background amm onia 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 th e 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 vi sibility impairment in a Class I area. Modeling of control scenarios is us ed to estimate the amount that this visibility impact can be

reduced due to a reduction in emissions. The mo deling of these control sc enarios is done in a manner that holds all variables constant except for the emissions of the pollutant of interest. A relative reduction in visibility imp act due to a change in emissions is an indication that visibility benefits are reasonably an ticipated to occur.

Comment:

In 1998, the Interagency Workgroup on Air Qu ality Modeling (IWAQM) conducted a study using tracers to test the ability of CA LPUFF to match measured concentrations. 9 The study specifically involved non

‐ reacting tracers and focused on the m odel’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 expect ed 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-contr olled 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 conclude d 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 distan ces in excess of 200 km. We di sagree 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 r easonable manner, and had no apparent bias toward over or under prediction, so long as th e transport distance wa s limited to less than

300km. 841

, 842 Domtar Ashdown Mills is within 300km of Upper Buffalo. Our BART

determination was based on consider ation of the five-factors, incl uding the anticipated visibility benefit due to controls at all impacted Class I ar eas. The BART visibility analysis for Domtar includes assessment of visibility impacts and benef its 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 Models440 Comment: Regional Haze Modeling Asse ssment Report, Entergy Arkansas, Inc, Independence Plant [ Exhibit C to EAI Comments]. Entergy contracted with Trinity Consultants to perform regiona l haze modeling using CAMx and PSAT based on the modeling originally developed for CENRAP. This modeli ng 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 (p roposed controls in EPA’s FIP) and Entergy’s proposed control approach c onsisting of installed LNB/SO FA on Independence, and the

cessation of coal combustion at White Blu ff 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 fr om Entergy (see table below).

Unit Uncontrolled Baseline (tpy) Entergy’s Proposal Arkansas FIP

N

Ox SO2 N

Ox SO2 N

Ox 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 --- --- 41

45 14

53

WB

2 81

45 160

34 --- --- 40

60 14

76

LC

4 12

28 3.26 56

4 3.26 56

4 3.2

6

Source apportionment was used on the baseline m odeling scenario to assess the individual source contributions to visibility impairment.

Response: Results from Entergy’s CAMx modeling anal ysis 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 annu al emission levels and emissions during the baseline period of 2000-2004. Baseline modeled im pacts 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 emissi ons. We also note that the commenter mentions additional adjustments to stack locations and stac k parameters in the modeling inputs but did not provide any documentation on these adju stments 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 Inde pendence 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. stat ed 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 mode ling 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 demonstr ates 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 Arkans as point sources’ nitrate emissions to visibility impairment at Arkans as’ 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 Cane y Creek and 0.25% at Upper Buffalo. Id . The Independence

units’ share of emissions to this minimal contribu tion from Arkansas point sources to visibility impairment at Caney Creek and Upper Buffalo is even less.

Entergy’s CAMx modeling confirms that Independen ce’s contribution to visi bility impairment is insignificant in both Class I areas. Independence is projected to contri bute to only 0.119 dv of visibility impairment at Caney Cree k 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 Ar kansas sources. Also, the total haze index values442 visibility impairment, based on modeling, on th e W20 days in either Caney Creek or Upper Buffalo. Yet, based on such a miniscule contri bution and with no credib le explanation, EPA arbitrarily concludes that SO2 and NO X controls at Independence are warranted.

presented in the figures are based on Entergy’s CAMx mo del 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 assert ion that the contribu tion to visibility impairment from Entergy Independen ce 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 fo r 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 SO 2 and NOx point source emissions in Arkansas, accoun ting for approximately 36% of the SO 2 point-source emissions and 21% of the point so urce 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 SO 2 emissions from a single facili ty, the Independence facility. As we discuss in more detail elsewhere, given their contribution to visibility impairment on the 20% worst days, we consider both SO 2 and NO X to be key pollutants contributing to visibility impairment at Arkansas’ Class I areas. Ou r CALPUFF modeling eval uating the baseline 98 th
percentile impacts confirmed that the Independence facility was estim ated 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 anticipa ted visibility benefits from SO 2 and NO X 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 sour ce, for comparison purposes we note that the

844 80 FR 18991444 threshold used for visibility impacts to determ ine 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 commen ter’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 vi sibility 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 f unction 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 re sults 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 C ontribution to Total Vi sibility 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 st atement that the impact from the Independence facility is one half of one percent and is in fact, based on their own modeling and calculation, approximate ly 1.3% of the total visibility impairment at each Arkansas Class I area. Considering th at the CAMx photochemical mode ling 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 impa irment 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 sing le facility. The CAMx modeling also showed that at Upper Buffalo, the Inde pendence facility’s cont ribution to visibility impairment is greater than the contribution from all of the subj ect-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 visibi lity conditions. The deciview improvement based on the 2018 background conditions provides an es timate of the amount of benefit that can be anticipated in 2018 and the impact a control/emission reductio n may have on the established RPG for 2018. However, this estimate based on degraded or “dirty” background conditi ons 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 cond itions at the end of the planning period. 847

The need for consideration of visibility impacts a nd benefits relative to clean/natural conditions was explained in the preamble to the final BART Guidelines: 848

Using existing conditions as the baselin e 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. Th is 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 contributi on 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 St ates 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 visib ility impacts and benefits for sources examined for controls for reasonable progress. Accordingl y, the EPA has used cl ean background conditions in evaluating the benefits of controls on i ndividual reasonable pr ogress 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, an d 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, 2005446 disapproved reasonable pr ogress 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 decivi ew scale, the use of dirty bac kground conditions will result in

much lower values for deciview impacts than when using natu ral 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 assu med 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 exti nction value for this Class I area, the deciview

scale increment is 3.86 dv. In this example, the ‘clean bac kground’ 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 decivi ew” values, depending on whether projected conditions or natural background conditi ons 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 impr ovement 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 degrad ed 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 inputs 851 , CALPUFF visibility impacts are also calculated based on na tural 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 f acility are large or small; and (3) CAMx models all sources of emissions in the modeling domain, which includes all of the continental U.S., wh ereas CALPUFF only models the impact of emissions from one facility without explicit chemical interaction with other sources’ emissions.448 background approach (using annual averag e natural conditions background). 852 The results are

shown in the table below. 853

Entergy Arkansas 2018 CAMX Mode ling - Average Deciview Imp acts 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 im pacts greater than 0.5 dv at both Caney Creek and Upper Buffalo on aver age across the 20% worst days on a “clean” background basis based on CAMx modeling submitte d by the commenter. These CAMx model results for the average across the 20% worst days show that the Independen ce facility contributes significantly to visibility impairment on the 20% worst days and controls will result in meaningful visibility be nefit towards the goal of natural visi bility conditions. Furthermore, the maximum visibility impact on an individual day w ithin 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-w ide 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 visib ility benefits that would be anticipated on the 20% worst days.

Entergy Arkansas 2018 CAMX Mo deling- 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 calculate d using the following equation: Δ dv = 10 ln((b background + b

source )/ b background ), where b is extinction (Mm-1) and Δ dv is the delta-deciview visibility impact

. 853 See ” Entergy Arkansas CAMx - EPA calcs max and clean background.xlsx” available in the docket for this

action449 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 expect ed 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 em issions on visibility notes that their BART-type evaluation for NOx for the I ndependence 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 facili ty 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 SO 2 emissions for Independence Units 1 and 2, EPA estimated improvements with dry FGD ranging from 1.045 to 1.178 dv with a cumulative be nefit 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 a ppropriate to use the cumulative values as a representation of the visi bility benefit of adding controls since only the improvement at each particular Class I area coul d actually be recognized. Th is level of visibility improvement is virtually insignificant and does not justify the costs associ ated with adding a dry FGD and, therefore, does not meet the statutory RPG requirement fo r 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 ar e 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 impr ovement in visibility of nearly 0.5 dv to be insignificant or small for reasonable progress. In our proposed act ion, we noted that “The single source CALPUFF modeling shows that sizeab le 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 sign ificant 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% wors t days in 2002 is due to nitrate. 857 Both NOx and SO2 are key pollutants that contribute to visibility impair ment 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 thes e 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 re asonable progress controls for both pollutants. We recognized, however, that at this time, ev en though NOx emissions are a ke y pollutant, point source NOx

emissions are not the main contributors to visibi lity 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 em issions are a key pollutant to reaching the regional haze goals, and that the visibility benefits from NOx c ontrols 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 we re 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 fi nal 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 requireme nts is to improve visibility and make progress

towards natural conditions and NOx is a key pollutant impacting vi sibility 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 th e 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 fa ctors, we have determined that because NOx and SO2 are both key visibility impairing pollutants, for Indepe ndence 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 goa l. We have determined that it is appropriate to reduce NOx emissions and finalize Option 1. As to the co mment 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 improve ment 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 fo r BART controls, and that source with a 1.0 dv impact at a Class I area to “cause” visibility impa irment. Given that sources are subject to BART based on a contribution threshold of no great er than 0.5 deciviews and visibility impacts greater than 1.0 deciview are cons idered 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 18995451 be inconsistent to consider a potential improvement in visibility of greater than twice the BART threshold to be insignificant.

Furthermore, as discussed elsewhere, result s of Entergy Arkansas’ CAMx modeling with source apportionment provide additional s upport that the Independence facility has significant impacts on visibility at nearby Class I areas on th e 20% worst days and that controlling these units would re sult in significant visibility benefits towards the goal of natural visibility conditions.

We address comments concerning the considera tion of cumulative visi bility benefits and imperceptible visibility benefits elsewhere.

Comment: The CALPUFF modeling vastly oversta tes the potential visibility improvement from controls on Independence.

[Entergy Arkansas Inc. (0166) p.37-4; Enter gy Mississippi Inc. ( 0168) p. 8-10; Conway Corporation et. al. (0172) p. 8- 9; and EEAA (0173) p. 14-15] En tergy Arkansas Inc., Entergy Mississippi Inc., Conway Corpor ation et. al., and EEAA stated that EPA’s CALPUFF modeling

indicates that the SO 2 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 (A pr. 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 a nd Upper Buffalo, the W20 days show that the visibility impairment in 2018 will be approxima tely 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 proj ected to be responsible for only about 0.81 - 0.86 dv of impairment (23-24 dv x 3.6%). For nitrates, EPA proj ects 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 SO 2 and NOx emissions contri bute only a portion to the sulfate and nitrate percentages estimated from Arkansas point s ources. It would, therefore, be impossible for the SO 2 and NO X limits proposed for Independence to result in deciview improvements at Caney Creek and Upper Bu ffalo 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 em ission 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. stat ed that another illustration demonstrates why CALPUFF greatly overstates the benefits of overall visi bility benefits from proposed emission limits. In the Proposal, EPA proj ects the visibili ty benefits from the proposed

BART controls based on CALPUFF modeli ng. Based on CALPUFF, EPA’s proposed BART limits at White Bluff, Flint Creek Power Plant, Carl E. Bailey Gene rating Station, John L. McClellan Generating Station, Lake Catherine a nd Domtar Ashdown Power Boilers will result in452 projected combined visibility benefits of approximately 4.3 dv at Caney Creek. 860 See first figure below. Based on a statistical projecti on 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 gl ide path. The URP would not reach that haze level until approximately 2048. 861 Indeed, even if you ascribed th e 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, ad ding 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 Bu ffalo of 18.05 dv would keep Uppe r Buffalo below th e glide pa th 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 reasonabl e progress. As demonstrated in Figures 11 and 12, controls at Independence ca nnot be justified for reasonable progress based on the CALPUFF results, which predict an improvement of se veral deciviews solely from BART controls.

Response: As more fully explained above, the commen ter’s analysis fails to account for the fact that deciviews are a logarithmic function of extinction, that CALPUFF results are for the maximum impact (98 th 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 natura l 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 di rectly applied to th e total deciview impa irment. On the 20% worst days in 2018, sulfate from Arkansas point s ources is projected to c ontribute 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 c ontribute 0.29% of the total light extinction at Caney Creek and 0.25% at Upper Buffalo. 3.58% of the total exti nction in 2018 at Caney Creek is 3.073 Mm-1. Converting to deciviews, yields approxima tely 0.32 dv based on a “dirty” background 2018 projected visibility conditi ons and 0.92 dv based on a natural background approach.454 Second, 0.92 dv represents the estimated decivi ew 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 dir ectly comparable to the CALPUFF modeled 1.952 dv improvement from controls on both units at Inde pendence, due to differences in models, model inputs and metrics. CALPUFF modeling fo llowing the BART guidelines and recommended protocol, provides an estimate of the maximum (98 th 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 act ual 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 source s. A maximum value of 1.952 dv for visibility

benefits of controlli ng Independence based on CALPUFF modeli ng 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 visibil ity over the 73 days, or 24 monitored days with the worst visibility). Furthermore, the ma ximum value as modeled by CALPUFF is based on maximum 24-hr emissions which may be much highe r than the average emissions. As discussed in a separate response to comment above, CA Mx modeling using source apportionment provided by the commenter (Entergy) modeled a facility-w ide impact from Entergy Independence of 1.64 dv on the maximum day within the subset of da ys that make up the 20% worst days. The maximum modeled impact across the full 365 days m odeled 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 visibili ty benefit estimated by CALPUFF is not “impossible” and is in fact in line with the visibility impacts es timated using the CAMx model as supplied by the commenter.

Third, the commenter is incorrect in estimati ng a 4.3 dv improvement from all BART controls and using this value to adjust projected visibil ity 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 resu lt 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 comm enter’s description of the methodology used to estimate the total visibility benefits of BART controls, 862 the commenter simply added the

CALPUFF modeled deciview visib ility benefits for each control. These benefits represent the maximum (98 th percentile) visibility benefits at each source based on reduc tions to the maximum 24-hr emissions modeled over a period of three ye ars. The maximum benefits from controlling

one source cannot be added to the maximum bene fits 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 c ontrols at the same faci lity cannot be added as they may not occur on the same day. Furthe rmore, 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 fac ility 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 sp ecific controls. Furthermore, as discussed elsewhere, because deciviews ar e a logarithmic function of exti nction, they cannot be added as

the commenter does here. The CALPUFF modeled vi sibility 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 bene fit anticipated from all controls against 2018 vi sibility conditions in estimating the proposed RPGs for 2018. In

this calculation we estimated the benefit from a ll required controls to be 0.21 dv at Caney Creek and 0.19 dv at Upper Buffalo.

Comment: CALPUFF overstates the visibility im provement expected fr om EPA’s proposed controls on Independence. [Entergy Arkansas Inc. (0166) p.41-42] Entergy Arkansas Inc.

stated that EPA’s CALPUFF modeli ng greatly overstates the visibili ty benefits that would result from installing controls at I ndependence (as discussed elsewher e in Entergy’s comments) and should be disregarded. Further, when EPA us ed the CENRAP model (an appropriate multisource model) to assess overall visibility impair ment, 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 benef its 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 SO 2 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 c ontrols on Independen ce (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 discerni ble visibility improvements.

Not only does this demonstrate the illogic of relying on CALPUFF for reasonable progress, it

demonstrates that the realistic benefits resulti ng from installing controls at Independence will be inconsequential and will contribut e virtually nothing to visibility improvement at either Class I area. According to EPA, one deciview refl ects “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.”). Th us, 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 installatio n of controls at all of the pr oposed FIP sources would not be perceptible to the human eye. Likewise, a tota l 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 percep tibility of visibility improvements elsewhere in this document. There we explain th at in our visibility improvement analysis, we have not considered perceptibility as a thresh old criterion for considering improvements in visibility to be meaningful.

As we discuss in depth elsewher e, visibility improvements from controls must be evaluated on a “clean” background basis to fully as sess 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 va lue as of the end of the implementation period, i.e., the degree by which the RPGs would differ w ith and without the control being included in the LTS, as the commenter does here. We also di scuss elsewhere that the deciview scale is a logarithmic function of extinc tion and calculations to determ ine benefits or amount of contribution to visibility impairment must be based on extinction and then converted into deciviews. Nevertheless, the commenter’s es timated visibility benefits of 0.08 dv at Caney Creek and 0.07 dv at Upper Buffalo on average ac ross 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 appro ach for the 20% worst days. In our

response to a separate comment a bove, we discuss that due to the differences in models, model inputs, and metrics, the estimated visibility be nefits estimated from CAMx modeling cannot be directly compared to CALPUFF modeled visibi lity benefits. For one, CALPUFF modeling is used to estimate the maximum visibility be nefit 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 visibili ty 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 Independenc e facility at both Caney Creek and Upper Buffalo. In some situations, the CALPUFF mo deled 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 improvem ents 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 2457 With regard to the quote the commenter reproduc ed from the Eighth Circuit Court’s decision in

North Dakota v. EPA 865 , several environmental groups challenged a por tion of our final action on North Dakota’s regional haze SIP that ultim ately approved North Dakota’s reasonable progress determination for NOx controls for the Coyote Station. 866 The environmental groups objected to North Dakota’s decisi on to reject a control it had ev aluated, after having applied the four reasonable progress factors, and subsequently approving anot her NOx control as reasonable

progress.

We interpret the Court’s statement as meaning broa dly that just because a more stringent level of control could be technically feasib le in a particular instance, it does not mean it necessarily must be required under reasonable prog ress. We see no conflict with this determination and our proposed Arkansas FIP and requiring controls th at 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 di fferent conclusion had we conducted the analysis ourselves, but we ultimately determined thes e 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, stat ing in part that, “[e]ven if [the c ontrol in question] were perhaps the most reasonable technology available, the CAA re quires only that a stat e establish reasonable progress, not the most reasonable progress. In contrast, and as expl ained 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 th at 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 es tablished revised RPGs, since we have not received a revised SIP to correct the portions of the SIP submitta l we disapproved. We determined that cost

effective controls were in fact available that w ould 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 em issions have, and will continue to have, very little effect on visibility in a ny Class I area. EPA’s reasonable pr ogress 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, a nd nitrate from Arkansas point sources contributed 0.27% of the total light extinction at Caney Cr eek 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 co ntribute only a fraction of these small amounts.

Response: We disagree with the commenter’s assert ion 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 8 th 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 35732458 CENRAP modeling also pr ojects that Arkansas point sources will be responsible for 3.58% of the total light extinction at Cane y Creek and 3.20% at Upper Buffal o in 2018. As we discuss in our proposal, based on 2011 NEI data the Enterg y Independence Plant is the second largest

source of both SO 2 and NOx point source emissions in Arkansas, accounting for approximately

36% of the SO 2 point-source emissions and 21% of point-source NO X 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 projecte d benefits from controls for the projected 2018 visibility conditions, as well as the perceptibility of those bene fits 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 SO 2 emission rates will ensure

that the Class I areas achieve vi rtually 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 ba sed on a Ranked Statistical Analysis, to the deciview improvements projected for the followi ng 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 SO 2 emission rate at Independence (referred to as “ISES”); and (2) installation of EPA’s proposed FIP cont rols 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 propos al 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 SO 2 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 NO X 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 NO X rate is included as a
separate comment in this RTC document].459460 Response: We discuss the “ranked statistical an alysis” submitted by the commenter in the response to comments below in this section. We disagree with the comme nter 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 visi bility 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-t o-BART facilities with the exception of White Bluff. The m odeled FIP scenario also includes SO 2 and NOx controls at both Independence and White Bluff. The mode led Entergy proposal scenario includes the

elimination of emissions from White Bl uff, an approximate 15% reduction in SO 2 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 benefi t than the FIP controls at Arkansas’ Class I areas, most significantly at Upper Buffalo wh ere 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 Wh ite 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 emissi ons from Independence at nearby Class I areas in Missouri (not shown in the table) are also larger than the comb ined 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 afte r the cessation of coal-burning, and issues concerning the BART requirements for White Bluff in separate responses to comment elsewhere

in this document.

870 See “Entergy CAMx Results 2015-1124_FINAL.xls” submit ted with comments from Entergy Arkansas, Inc. and

available in the docket for this action

871 See “Entergy CAMx Results 2015-1124_FINAL.xls” submit ted 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 st atistical analysis (the “projected haze index” shown in the figures a bove, Entergy Arkansas Inc.’s submitted comments in figures 13 and 14) as the starting point for calc ulating 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 visi bility conditions based on past improvement and is not directly tied to any additional required emi ssion reductions in the next few years that would result in this future visibility improvement from current conditions to th is projected value in

2018.

7.g. Observed Visibility Improvements

Comment: Trinity Consultants Inc. (Trinity) was ta sked 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 a nd projected visibility figures below). This downward trend is consiste nt with the historical (2002 – 2011) trend in decreasing sulfur dioxide (SO2) emissions from tie r 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 I nventory (NEI) SO2 emissions from 2002, 2005, 2008, and 2011. Pursuant to the NEI emissions da ta, the SO2 emissions have significantly

decreased since 2005 to 2011 in all source categories, incl uding especially a more than 50% drop

due to fuel combustion from electric utilitie s and a 67% drop in the fuel combustion from

industrial sources. Based on the si gnificant downward trend in the observed data and the actual SO2 emissions data, the future haze index valu e 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 re gulations further curbing emissions.462 Based on the above, when looking at the obser ved values, the CENRAP model predicted regional haze value for 2018 is overly conservati ve 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 tr end predicted if an assessment occurred evaluating the observed values. Therefore, instead of using the CENR AP CAMx predicted 2018 haze index to understand the effect of the control options , a statistically derived projec ted haze index must be used.

In order to statistically calculate the future deciview haze index values using observed data instead of relying on the CENR AP modeling, two statistical analyses were performed and evaluated to determine the most appropriate anal ysis 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 an d 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 averag e of the 20% worst days for visibility was

872 Trinity’s report identifying why a sta tistical 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 peri od 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 glidepat h in 2018 (or even beyond) does not automatically

mean that no controls or evaluati on under reasonable progress is need ed in this planning period. The commenter presents SO 2 emissions data from 2002, 2005, 2008, and 2011 for states identified by the commenter as impacting visibili ty at the Arkansas Class I areas. This data shows significant emissions reductions over this time period and is consis tent 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 emi ssions do not exhibit the same downward trend as presented for the other states that impact visibi lity at the Arkansas Class I areas. The figure

below shows Arkansas SO 2 emissions from all source categories for 2004-2014. 874 More recent annual emissions from 2012-2014 are actually hi gher 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 ut ilities. To the extent that the commenters are suggesting that Arkansas should be relieved of it s regional haze obligations because other states’ emission reduction efforts have already result ed in significant visibility improvement at Arkansas’ Class I areas, this is incorrect. Rath er 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-data465 shoes, must consider the statut ory factors in addressing the long term strategy and reasonable progress requirements.

The commenter asserts that the CENRAP CA Mx predicted 2018 haze index is overly

conservative and that to understa nd the effect of the control op tions, a statistically derived projected haze index must be use d. We disagree with the comment er. The comments indicate a lack of understanding of how reas onable progress goals are establis hed, as well as the imports of the goals as opposed to the measures adopted to en sure 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 towa rds the goal of natural visibility conditions

. Accordingly, the RPGs must repres ent an estimate of the degree of visibility improvement that will result in a futu re 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 enfo rceable 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 ar e simply extrapolations of future visibility conditions based on observed reductions in visibility impairment in the past. Future visibility projections must be directly tie d to projections of future emi ssions, and anticipated reductions

875 64 FR 35733466 due to federal and state requirements. Curre nt 5-yr average (2010-2014) observed visibility conditions are 21.8 dv at Caney Cr eek and 21.6 dv at Upper Buffalo. 876 Any future improvements in overall visibili ty 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 anti cipated 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 201 8 projected by the commenter at Caney Creek in their statistical analysis. Furthermore, as di scussed above, any anticipated emission reductions

from sources in other states does not relieve Arkansas of its regiona l 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 impa irment. 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 a nd 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 i ndividual 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 proj ected 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 commente r does here. The RPGs are an analytical tool

the state and we use to evaluate whether the m easures 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 revise d RPGs are based upon) are not currently being achieved, we disagree that visibility at the Cl ass I areas has already improved beyond what we would require in our FIP and that our FIP is th erefore unjustified and unwarranted. The emission reductions required in this action will result in significant visibil ity improvements at the Class I areas beyond what is currently being achieved or observed. As discussed elsewhere, the commenter’s photochemical modeling analysis pr ovides an additional demonstration that the controls required in this action result in visibility benefits beyond current observed visibility conditions and serve to accelerate progre ss towards natural vi sibility conditions.

7.h. Reasonable Progress Goals

Comment: [ADEQ (0160) p. 15-16] EP A’s proposed RPGs are more stringent than Arkansas’s proposed RPGs in its 2008 Regional Haze State Im plementation 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 ar eas 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 Stat e-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 vi sibility conditions by 2064 and more stringent RPGs than those in Arkansas’s 2008 Regiona l Haze State Implementation Plan are not necessary. EPA should withdraw the Proposed FI P 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 SI P 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 demonstrat e that additional contro ls were not reasonable under 40 CFR 51.308(d)(1)(i)(A). Thus we disa pproved the RPGs Arkansas established for Caney Creek and Upper Buffalo. In our pr oposed rulemaking, we completed the reasonable progress analysis and establishe d revised RPGs, since we have not received a revised SIP to correct the portions of the SIP submittal we di sapproved. 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 SO 2 and its large potential to impact visibi lity 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 concer ning the visibility bene fits 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 wher e 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 facili ties and the Independence f acility 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 bene fits that provide for pr ogress towards the goal of natural visibility conditions. As we discuss be low in a separate response to comment, after considering comments received, we agree that th e 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 implemente d. We are finalizing RPGs that represent the visibility conditions anticipated on the 20% wo rst days at Caney Creek and Upper Buffalo by

2018.

879 77 FR 14604 at 18998, Table 67.

880 64 FR 35732468 We disagree with the commenter that the amount of visibility improvement due to our proposed FIP is “insignificant.” We address comments concerning the perceptib ility of visibility improvements in response to comments above. Th e 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 impl emented, the required controls to meet the BART requirements, as well as required contro ls on the Independence facility result in an approximate 2% improvement in overall visibi lity conditions projecte d by CENRAP at both Caney Creek and Upper Buffalo on the 20% worst da ys. Our technical record demonstrates that the required controls reduce impacts from thes e sources and result in meaningful visibility benefits towards the goal of natural visibility conditions. Th e required controls reduce the projected visibility impairment due to all Ar kansas 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 th e CENRAP projections already included an assumption of large emission reductions due to SO 2 BART at Flint Creek, as well as NO X 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 im properly 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 s ubstituted 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 mode ling in a manner adequate to develop “refined

numerical RPGs.” 884 EPA seems to acknowledge the infirm ity in its modeling by explaining its methodology as follows: “Development of refined nu merical RPGs for Arkansas’s Class I areas would require photochemical grid modeling of a mu ltistate area, involving thousands of emission sources, unlike the comparatively simple singl e-source CALPUFF modeling used for individual

BART assessments.” 885 EPA further explains th at “[d]eveloping all of th e necessary input files, running the photochemical model, and post-proce ssing 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 th at it is requiring an “update of the emission inventory for Arkansas and surr ounding states,” which would include the effects of all EPA and

881 2002 CENRAP modeled SO 2 emissions for Flint Creek were 11,165 tpy and 2018 CENRAP modeled SO 2 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 poi nt, 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 need ed, 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 th e 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 fo r the Proposed FIP was “comparatively simple single-source CALPUFF modeling used for individual BART assessments.” 890 EPA used this modeling only to justify additi onal emissions controls on Enter gy’s Independence Plant outlined in the reasonable progress an alysis and not in support of the proposed state-wide RPGs.

Given the substantial impact on Arkansas bus inesses and rate-payers that the potential differences in RPGs would make, ADEQ is tr oubled 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 es tablish “refined numerical RPGs.”

Response: We discuss our selection of the CALP UFF model for eval uating single-source visibility impacts in a separate response to comme nt above. In the respon se, 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 th eir comparison of approaches for establishing new RPGs between this action for Arka nsas and our previous action in Texas. For both Texas and Arkansas, we utilized the CE NRAP 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 pe rform a full photochemical modeling analysis to model all the required cont rols and project the future visibili ty 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

‐ 0087470 The primary difference between the two actions wa s that in evaluating th e 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 ke y differences that resulted

in the selection of different models was the numbe r of sources that needed to be analyzed (38 facilities in Texas compared to 1 facility in Ar kansas) 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 proposal 892 , “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 c hoose 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 ap propriate techniques, in accord ance 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 unsci entific. EPA used a ratio of emission rates from BART sources to Arkansas point sources to scale the modeled pred icted haze index. First, there is no evidence to prove that the CAMx pr edicted modeling results are linearly correlated with emission rates. In fact, the CAMx mode ling 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

PM 2.5 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 amm onia molecule reacts with SO 2 molecules to form sulfate before reacting with NO X molecules to form nitrate. If abundant SO 2 is present in the atmosphere, any

increase in NO X emissions will not result in a linear in crease in nitrate formation. As a result, there may not be any increase in the predicted regional haze. On the contrary, if abundant NO X molecules are present, then any reduction in SO 2 molecules will not result in a significant

reduction in haze as NO X will substitute the reduced SO 2 in the reaction. Second, a deciview is a logarithmic scale based on the concept that one deci view is the minimum cha nge 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 direc tly. Therefore, fractioni ng or scaling deciviews based on emission rates is illogical.

Comment: [EarthJustice/ Dr. Gray] In Texas, the mode l results were used to demonstrate that the overall change in species concentrations was ve ry nearly linearly proportional to the change

in emission levels for an indivi dual source (with very high linear correlation coefficients near 1.0). This strongly supports their use of the emission scaling a pproach for Arkansas. If the CAMx model were used to determine the imp act of emission controls on a single source in Arkansas (such as Independence), it is therefore expected that the modeled redu ctions in sulfate and nitrate

concentrations at each of the Class I areas will be very near ly 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 em ission scaling approach has been shown to be mathematically sound and quite appropriate, especi ally considering the re sources 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 lin ear relationship between emissions and deciviews and then commenting that this “fractioning or scaling of deciviews” is flawed because the relationship between light extinction and deci views is exponential. We properly developed a linear relationship between emissions and light ex tinction (inverse Megameters), not deciviews.

We agree with the commenters, that in general, the relationship between downwind concentrations and emissions can be complicat ed 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 re lied on the CENRAP’s 2018 CAMx modeling results, including source apportionment results, and the pr ojected emission inventories, and scaled the results as described in the TSD, si milar to what was done in our previous action in

Arizona and Texas. While we ac knowledge that this approach is not as refined an estimate as would be attained in performing a new photoche mical modeling run, it is based on scaling to adjust earlier photochemical modelin g 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 imp act the overall conclusions. Furthermore, in our technical analysis develope d to support our action on Texas re gional haze, we observed that for each facility and Class I area, the available m odeled 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 Mm

1 at Caney Creek and 1.8 Mm -1 at Upper Buffalo on the 20% worst days. As discussed elsewhere, Entergy Arkansas submitted additiona l 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 oversta ted: 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 c ontrol requirements that have comp liance 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 a nd 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

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‐ 0754

‐ 0007)

895 See Entergy CAMx Results 2015

‐ 1124_FINAL.xls472 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 th e 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 projectio ns 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 inaccura te and unsupportable.

In this regard, EPA fails to explain why (a) the Agency may permissibly use a concededly oversimplified and inaccurate shortcut met hodology for calculating RPGs in its FIP, on the grounds that EPA otherwise would have to c onduct time-consuming and complicated modeling,

see id. , but (b) Arkansas and other st ates apparently are held to a much higher standard for their RPG analyses, see id . In proposing and promulgating a FIP fo r Arkansas, EPA merely stands in the state’s shoes. Accordingly, if EPA may lawf ully comply with the CAA and the regional haze rules by conducting and relying on th is 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 belie ve 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 an alysis 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 fr om the approved portion of the 2008 Arkansas Regional Haze SIP and our FIP proposal. After co nsidering these comments, we agree that the RPGs should reflect anticipated vi sibility conditions at the end of the impl ementation period in 2018 rather than the anticipated visibility condi tions 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 Ad ministrator to promulga te regulations that “include[e] criteria for measuring ‘reasonable pr ogress’ toward the natio nal 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 stat e’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 coul d consider the “time necessary for compliance” factor by “adjust[ing] the RPG to reflect the degree of improvem ent 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 f our-factor analysis) and include d in the long-term strategy.

In this instance, we are taking final action on the Arkansas Regional H aze 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 BA RT 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 Gu idance and finalize RPGs that represent the visibility conditions anticipated on the 20% wo rst days at Caney Creek and Upper Buffalo by

2018. These RPGs are listed in the table below: 902

Reasonable Progress Goals for 2018 fo r 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 comple ted in 2006/2007, which assumed that Flint Creek would install scrubbers to meet the presumptive SO 2 BART limit of 0.15 lb/MMBtu, that

Flint Creek and White Bluff would install low NO X burners to satisfy NO X BART, and that AECC Bailey and Entergy Lake Ca therine would be shut down by 2018. In contrast, our RPGs reflect a more stringent SO 2 emission limit of 0.06 lb/MMBtu at Flint Creek and the installation

of low NO X burners at Independence in addition to F lint 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 Flin t Creek and Independence, but more emissions from AECC Bailey and Enter gy 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-fact or analysis, as required by the CAA and the Regional Haze Rule. Without a four-factor analys is, Arkansas was unable to determine whether control measures were necessary to make reasonable progress—t he 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 SO 2 controls at Independence, along

with benefits of the SO 2 BART controls at White Bluff, a nd 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 pr operly take these benefits into account when developing RPGs for 2028. 905

We disagree with the commenter that the propo sed 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 re fined 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 pr eviously performed by the CENRAP. 906 The proposed RPGs provided an estimate of the visibility bene fit of all the required controls compared to the 2018 visibility conditions projected by the state a nd established in their SIP that would result without the required controls. Our final RPGs , calculated using the same methodology, reflect the anticipated visibility condi tions at the end of the implementation period in 2018 and the visibility benefit from those controls required to be implem ented 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 implementa tion 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 improvement s 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 (a long with a consideration for what controls had already been implemented and what controls woul d 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 scali ng 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 prope rly 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 Cr eek 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 35732475 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 develo p the revised RPGs for Caney Creek and Upper Buffalo. [AECC (0169) p. 3-4] AECC st ated 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 RP Gs for the proposed Rule. 910 AECC stated that EP A 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 fo r Arkansas and the surrounding states; and

 Specialized and extensive computing hardware and expertise to deve lop input files, run the models, and post-process the model outputs. 911

AECC stated that EPA explains th at 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. CALPUF F is a single-source model used for individual BART assessments. A photochemical gr id 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 th at EPA used an inappropriate process to develop RPGs for the Arkansas Class I areas. EP A is using the results of this inappropriate analysis to subject the Independe nce plant to installation of controls. AECC believes that this is arbitrary on the part of EPA and the Independenc e 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 CA LPUFF 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 s ource apportionment modeling results and emission inventory data. As we stated in the proposed rulemaking, we did not perform additional photochemical modeling to directly mode l the new projected visibi lity goals due to the

time and resource demands associat ed with photochemical modeling.

7.i. Additional Modeling Comments

Comment: EPA should have used realist ic data for its visibility analysis [Nucor SteelArkansas and Nucor-Yamato Steel (0163) p.38-40] Nu cor 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 de piction 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 determina tions do not comply w ith this requirement. First, EPA’s use of the maximum 24-hour recorded emissions extrapolated across the three year analysis period significantly overestimates the vi sibility impacts from a facility. For example, from 2001 to 2003, Entergy Independence reported maximum 24-hour SO 2 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 aver age emissions from the facility are half of what is represented in the modeling analysis.

Additionally, EPA admits in the Regional Haze Re gulations and Guidelines for Best Available Retrofit Technology Determinations that modele d impacts are overstated. Specifically, EPA

states that “there are other features of our recommended modeling appro ach that are likely to overstate the actual visibility effects of an i ndividual 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 98 th percentile of modeled visibility values, which eliminates roughl y 7 days per year from the analysis. However, this approach has no rational or generally accepte d scientific basis as a way to “normalize” the emissions data. Using the same example for Ente rgy Independence, if the maximum 7 days of each year from 2001 to 2003 is eliminated for eac h 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 SO 2 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 s hould 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 SO 2 emissions. 914 Because use of low-sulfur coal is an acceptable pollution control technology, it wa s 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 (8 th 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 us ing annualized costs and annual emission reductions. Our costeffectiveness analysis for the BART units (devel oped 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 98 th 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 SO 2 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 emi ssion 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 note s the similarity between some of the reasonable progress factors a nd the BART factors contained in Section 51.308(e )(1)((ii)(A), and suggests that the BART Guidelines be cons ulted regarding cost, energy and non-air quality environmental impacts, and remaining useful life. We are therefor e relying on our BART Guidelines for assistance in interpreting thos e reasonable progress factors, as applicable. Also, similar to a BART analysis, we are also co nsidering the projected vi sibility benefit in our analysis following the BART guidelines. 917 We rely on the BART Guidelines here and in other actions evaluating reasonable progress controls b ecause 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 emi ssion rate from the 2001-2003 baseline period and modeled using 2001-2003 meteorologi cal data. The BART Guide lines also state that the

emissions estimates used in the models are inte nded 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 st art-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 us ed to estimate the 98t h percentile visibility impairment rather than the highest daily impact value as proposed. We made the decision to consider the less conservative 98th percentile pr imarily because the chemistry modules in the CALPUFF model are simplified and likely to pr ovide conservative (higher) results for peak impacts. Since CALPUFF’s simplified chemistry c ould lead to model over predictions and thus be conservative, EPA decided to use the less conservative 98th percentile. 919 Therefore, our modeling approach is consiste nt with the guidance and focuses on estimating the maximum potential visibility impacts th at 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 fr om the preamble to the final Regional Haze

Rule 920 discussing the use of the 98 th 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 ef fects of that source. B ecause of these features and the uncertainties associated with the model, we believe it is appr opriate 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 pe rcentile 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 contribu te to visibility impairment in a Class I area, while minimizing the likelihood that the highest modeled vi sibility impacts might be caused by unusual meteorology or conservative a ssumptions 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 th e 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 mete orology or conservative model assumptions) with eliminating the hi ghest emission rates and using the 8 th highest emission rate.

The commenter claims that the use of the 98 th 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 da ta from 2009-2011 rather

than the 2001-2003 baseline emissions for the eval uation 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 c ontent of coal and does not provide any information on shorter term emissi on rates or the maximum 24-hr emission rates during those years. This data also show s 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 th e 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 20 09-2011. Furthermore, th e recent utilization of lower-sulfur coal does not provide any assura nce 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 th e utilization of cheaper, higher-sulfur coal.

Consistent with the BART anal ysis 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

units479 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 NO X 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 in stallation 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] UA RG stated that EPA pr oposes reasonable progress requirements for the Independence Power Plant, wh ich is not subject to BART. EPA attempts to support its proposed reasonable progress determ ination for Independence with supplemental visibility modeling that EPA conducted after lear ning of an error in the Agency’s previous modeling. See Summary of Additional Modeling for En tergy Independence, Docket ID No. EPA- R06-OAR-2015-0189-0147, at 3 (Apr. 20, 2015). In conducting this supplemental modeling, EPA evaluated projecte d visibility improvements usi ng different baselines. For SO2, EPA evaluated visibility improvements agai nst a 2001-2003 baseline period (“BASE”) and against an alternative base line that included 2001 2003 SO 2 emissions and updated NOx emissions using 2011-2013 data (“BASE2”). See id . at 5 6. For NOx, EPA only evaluated visibility improvement s 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 resu lts using BASE and the NOx modeling results using BASE2, thereby s uggesting that those values are the ones on which EPA proposes to rely in this ru lemaking. 80 Fed. Reg. 24,872, 24,873 (May 1, 2015). EPA did not, however, provide any rationale fo r using an updated, 2011-2013 baseline for NOx modeling while retaining the 2001- 2003 baseline for evaluating vi sibility impacts of SO2 and SO2 reductions. If EPA intends to proceed to prom ulgate 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 a nd must allow a reasonabl e opportunity for public comment on that explanation and information.

Response: We disagree with the commenter's characteri zation of our action. For our visibility impact analysis of the Indepe ndence facility, we modeled usi ng 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, mo deled 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 woul d also be greater. In Appendix C of the TSD we explain the baseline emissions we identified for our analys is, using an updated baseline to evaluate NOx controls due to changes in opera tion 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 leve ls, particularly for unit 2 are much lower for the 2011-2013 time period than the 2001-2003 baseli ne, 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 th e model results. The supplemental modeling

corrected an error in th e modeled location of the facility due to a typograp hical error. All other model inputs and model scenarios were identi cal 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 modele d visibility impacts for SO2

control scenarios between the BA SE 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 action481 improvement at Hercules-Glade using BASE2 of 1.139 dv, a difference of 0.083 dv. 924 We

noted that these results are sim ilar and that either modeled scen ario supports our conclusion that visibility impacts from these units are large and th at controls will result in meaningful visibility benefits towards the goal of na tural visibility conditions. We disagree with the commenter and have provided opportunity for comment on all as pects of the modeling that we conducted including our additiona l modeling for the Inde pendence facility.

Comment: EPA’s NO X BART analysis for Lake Catherine Unit 4 did not adequately consider the visibility improvements from potential NO X 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 determinati ons on an analysis of the five statutory BART factors: (1) the costs of compliance, (2) the en ergy 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) th e 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 visi bility improvement from NO X controls, along with compliance costs and the non-environmental impacts of controls. [T he Sierra Club’s detail ed comments regarding consideration of compliance cost s 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 poten tial controls in several ways. EPA failed to provide sufficient documentation for the proposed achievable NO x limit of BOOS and, as a result, EPA likely overstated the visibility bene fits 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 f ound, 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 th e unit at the same capacity factor. Id . at 53-54. Sargent & Lundy never calculated what emission rate was achie vable with this additional natural gas usage.

Id . Then in 2015, EPA proposed an emission lim it of 0.22 lb/MMBtu on a 30 boiler operating day rolling average based on the installati on 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, En tergy 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 us ed averaging times to find this lower emission rate achievable than it is likely that Entergy di d not properly model short term NO x emissions for Lake Catherine. Stamper Report at 54.

In addition, EPA overestimated the visibility benefits of BOOS because it did not analyze

whether NO x 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 NO x emission rate. As described in Ms. Stamper’s report, Entergy inco rrectly determined the maximum daily rates for each control scenario, which resulted in appl ying 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

BASE2482 required by the proposed NO x rates for each control scenario. Id . at 55-57. As a result, Entergy understated the maximum daily NO x emission rates under each control scenario. This in turn overstated the visibility benef it from each control scenario.

Comments [Sierra Club Stamper Report]: Typically, the determination of the maximum 24-hour

emission rate for a control scenario is determin ed 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 un it achieved during the baseline pe riod 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 base line period is evaluate d. 3) Determine the percent reduction from the annual average or fr om the 30-day average NOx emission rate during the baseline period needed to achieve the pr oposed 30-day averaging limit for the proposed control scheme. 4) Apply that percent reduc tion to the maximum da ily NOx rate over the baseline period to predict ma ximum daily NOx emissions unde r 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 fo r 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 0.48 25 lb/MMBtu to the pr oposed 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 emissi ons under each control scenario. 210

However, the 0.4825 lb/MMBtu base line emission rate was not a l ong term average NOx rate at Lake Catherine Unit 4: instead, it was the ma ximum 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 comp aring it to proposed 30-day average emission

rates for each control scenario to determin e the percent removal, Entergy has greatly understated the maximum daily NOx emission rates under each control scenario (because Entergy’s approach overstates the percent reducti on from each control evaluated). As a result, Entergy’s modeling overstates the visibility be nefits with each contro l 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 ra te or, at most, the maximum 30-day average NOx rate during the baseli ne period, and then to evaluate the percent

reduction from that annual or 30- day average rate to achieve th e 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/MMBtu 212 , 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 ra te 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 recalcula te the projected maximum daily emission rates based on a 0.27

lb/MMBtu baseline and th e 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 Ba sed on Percent NOx Reduction from 30-Day Average NOx Baseline Rate, Rather than En tergy’s Maximum Daily NOx Baseline Rate

NOx Control

Scenario 30-Day Average NOx Rate,

lb/MMBtu Max Daily NOx Emissions, lb/hr Max Dail y NOx
Emissions Modeled by Entergy, lb/hr 214

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

SNC R 0.14 1,272.4 819.0

LNB/SOFA Plus SC R 0.03 272.7 175.5

As Table 15 demonstrates, the use of th e commonly-applied methodology for estimating maximum daily NOx emissions under each contro l scenario predicts significantly higher

maximum NOx emission rates for each contro l scenario, which means that Entergy’s modeling overstates the visibility be nefits for all controls evaluated.

For BOOS, it may not even be appropriate to assume an 18.5% re duction 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 lowe r 0.22 lb/MMBtu NOx limit with BOOS on a 30- day averaging basis based on the exp ected utilization rate of Unit 4. 218 It appears Entergy was assuming it could average in peak NOx ra tes with lower NOx rate s 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 modeli ng a lower NOx limit would overstate the visibility benefits of BOOS at Lake Catherin e Unit 4 by failing to reflect the max daily NOx

rate that would be emitte d at Unit 4 with BOOS.

EPA should carefully estimate the maximum daily emissions expected from the operation of BOOS (along with the increased fi ring rate) at Lake Catherine Un it 4 to ensure it is basing its BART determination on an accurate predicti on 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 BO OS 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 base line period and compared it to proposed 30-day average emission rates for each control scenar io to determine the percent removal.

The BART guidelines recommend the following a pproach in developing the modeled scenarios:

For each source, run the model, at pr econtrol 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). Calculat e 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. Fo r example, if the 24-hr precontrol emission rate is 100 lb/h r 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 previousl y, we rely on the BART Guidelin es 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 em ission rate was based on maximum actual 24-hr emission rate during the baseli ne period of 0.4825 lb/MMBtu. The modeled controlled emission rates were then estimated based on a percen tage reduction anticipated by each control technology, as identified in th e Sargeant and Lundy report 926 , 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 ra tes. We disagree that it is necessary to

remodel the baseline and control scenarios uti lizing a long-term emission rate.

Control % reduction

from baseline NOx emission rate (lb/MMBtu) NOx emission rate (lb/hr) 1

Baseline --- 0.4825 2456.4 2

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 th at the final BART analysis 927 prepared by the faci lity 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 analysis 928 prepared by the facility utilized th e 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 im pacted 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 r easonably be anticipated to result from the use of such technology. The visibility modeling is intended to give a re asonable best estimate of the visibility impacts from an evaluation of emissi on reductions. The visibility analysis is only one

of the factors in a BART determination. In th is 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 2013486 0.22 lb/MMBtu in our proposal, because we have dete rmined this emission rate to be achievable based on information supplied by the facility. In response to comme nts, 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 consider ation of the visibility impacts and benefits at the higher, short-term ra te does not change our determination that BOOS

is BART for this source. While the incrementa l visibility benefits ove r BOOS are larger by 0.06 dv, the total visibility be nefit of higher control levels is unchanged. As we discuss in the proposal 929 , the incremental costs for more effective controls above BOOS remain high. BOOS was estimated to cost $138/ton compared to $1,4 50/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 NO X 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. st ated that EPA’s Lake Catherine Unit 4 NO X BART analysis fails to accurately consider the degree of visibility improvement of controls, as well as the compliance costs and non-environmental impact s. 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 NO x BART analysis that corrects these flaws and considers whether SCR represen ts the best system of continuous emission

reduction for NO x at Lake Catherine Unit 4. In doing so, we urge EPA to give due consideration to the superior visibility bene fits of control scenarios that include SCRs and to not place inappropriate weight on the incr emental cost-benefit analysis in its revised BART analysis. When EPA corrects its BART analysis to addres s the flaws that Ms. Stamper identified, the agency will likely find that control scenarios th at include SCR are more cost-effective than EPA originally calculated and will provide for the grea test visibility benefits at Caney Creek and the other Class I areas. [Our respons es to comments regarding the co st-effectiveness and incremental

cost-effectiveness of NO X 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 NO x emission rate, its modeling of the SNCR contro l scenario does provide an approximation of SCR’s likely visibility benefits under correct modeling, as discu ssed in Ms. Stamper’s report. Stamper Report at 59. This means that the 98 th percentile visibility improvement at Caney Creek

would be at least 0.842 dv and th e cumulative benefit acr oss 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 NO x controls would come close to providing as much visibili ty improvement as the SCR control scenario at Lake Catherine Unit 4. We thus urge EPA to gi ve due consideration to these significant and superior visibility benefits in its revised Lake Catherine NO x BART analysis.

Response: We disagree with the commenter that we overestimated visibility benefits from SCR. We address comments concerning th e estimated visibility improvements from controls at Lake Catherine in the response to comments above . The BART determination is based on

929 80 FR 18978487 consideration of five factors, including the degree of improve ment 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 f actors in a BART determination. In the visibility analysis, we modeled the 24-hr maximum emission rate and percent reductions anticipated from available c ontrol technologies, following the BART guidelines, as discussed above. As we discuss in the proposal 930 , 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 visi bility benefits from SC R are not insignificant, we do not consider the cost per ton removed a nd the incremental costs of SCR to be costeffective. If the commenter were correct that we over-estimated the visi bility benefits of SCR this would serve only to only rein force 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 tw o previous time intervals (2001-2003 and 2011- 2013) and do not necessarily reflect future emi ssion levels (without controls). EPA should have used projected future year emissions with controls (baseline) and then comp ared that to a control

scenario with commensurate emission reducti ons 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 r ecent (or projected) emission levels for Independence. As EPA states (in their additional modeling report): “We note

that had we modeled a more r ecent baseline for SO2 emissions, the baseline visibility impacts would be greater and the visibility benefits m odeled from the control s cenarios would also be greater.”

EPA thus underestimated the differences between baseline (using either BASE or BASE2) and the various control scenarios (“visibility improve ment over baseline”). Ultimately, a more logical approach is for EPA to simply compare the vi sibility impacts between the different control

scenarios.

Examination of the modeling results shows th at the peak days are typically caused by a combination of high sulfate and high nitrate conc entration impacts, alt hough high sulfate impacts dominate the highest visibil ity impact days under the baseline emission scenarios. When significant SO2 emission reductions are applied ho wever (such as through the application of DFGD), the remaining peak days are domina ted by high nitrate even ts, 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 18978488 The combined control strategy consisting of LNB and DFGD results in th e largest visibility improvement of EPA’s modeled scenarios. The mode led 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, LN B, etc.) are compared, it is apparent that

the combined SO2 and NOX control scenario co nsisting of both LNB and DFGD achieves the best visibility outcomes in the four modele d Class I areas of the scenarios considered.

Response: We agree with the commenter that we likel y underestimated visibi lity benefits of controls at the Independence f acility using the 2001-2003 emissions baseline because recent SO2 emissions (and possibly projected future emissi ons) are higher than the modeled baseline

emissions from the 2001-2003 time frame. We acknow ledged this in our an alysis stating: “We

note that had we modeled a more recent baselin e for SO2 emissions, the baseline visibility impacts would be greater and the visibility be nefits modeled from the control scenarios would also be greater.” In our analysis, as document ed in our proposed rulemaking, we determined that modeled visibility impacts were large, visibility benefits from reductions in SO2 emissions from controls were significant, and c ontrols (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 propos ed installation of controls a nd would have reaffirmed this determination. We agree with the commenter that after significant projected SO2 emission reductions, the remaining visibility impact from th e source is still signifi cant (> 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 Independen ce 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 S CR at White Bluff woul d not achieve a large enough visibility improvement and therefore EP A need not consider SCR for Independence

either.

CALPUFF modeling following the EP A’s protocol and model inputs, was used to evaluate SCR

at an emission rate of 0.055 lb/M MBtu. The emission rate for SO 2 was assumed to be the 0.06

lb/MMBtu . The modeled emission rates for the SCR_DFGD scenar io 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 N OX 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 be low 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 Cl ass I areas) for each of the modeled emission scenarios (see Figures 1 and 2) is summ arized 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 NO X 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 98 th percentile delta dV would be 2.099 (relative to DFGD-only).

The cumulative visibility (del ta 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 cons ider sufficient to recommend SCR

over LNB/SOFA. The current modeling shows that S CR at Independence would achieve a much larger incremental visibility improveme nt 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 ap plied at Independence, then th e 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 doubl e the visibility impact (to 1.71).

EPA used the modeling results for SCR at White Bluff to discount the co nsideration 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 ob served that the larges t incremental visibility improvement over LNB/SOFA was 0.069 at Caney Cr eek. However, this was for a single unit
and also relative to SNCR, which was not proposed; the impact for the total facil ity (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 Cla ss I areas was modeled to be 0.43 (delta dV) for SCR relative to

LNB at White Bluff 9 , 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 Indepe ndence 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 Wh ite Bluff and Independence power plants. The current modeling shows that SCRs at Indepe ndence provide significant visibility benefit, including significant incremental visibility benefi t relative to less stri ngent controls, such as LNB. The cumulative visibility improvement fo r SCR at Independence relative to LNB is 0.743 deciview (“dV”), which is larg er than EPA assumed in faili ng to review this technology.

Moreover, EPA significantly unde rvalued the incremen tal visibility improvement between LNB

and SCRs at White Bluff. The cu mulative 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 Fina l 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 th e visibility benefit from controls we considered491 the total and incremental visibility benefit at e ach 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 in cremental cost of SCR over LNB/SOFA for unit 1 to be $7,338/ton and $6,611/ton for unit 2. The incremental visibi lity 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 pe r unit across all 4 imp acted Class I areas are not large enough to justify the additional cost of S CR 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 visi bility improvement due

to the installation of LNB/SOFA at the Independence facil ity is of a similar magnitude to that of the White Bluff facility. As explained in our pr oposed rule, we applied the total annualized LNB/SOFA cost developed by En tergy 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 facil ities 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 r eason not to conclude the same fo r 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 a nd compared the modeled visibility benefits of

SCR. The commenters modeled the combined visibi lity benefit of SCR controls and dry FGD at Independence (on a facility wide basis), but base d on the information provi ded it does not appear that they modeled or considered the visibility improvement of SCR controls alone, as was done

931 80 FR 18974492 for White Bluff. The commenter’s comparison of visibility benef it from SCR at White Bluff to visibility benefits at Independe nce is incorrect because the visi bility benefits due to SCR at White Bluff were modeled using baseline SO2 em ission 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 facilit ies would be similar, as demonstrated by the modeled visibility benefits for LNB/SOFA show n 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 S CR over SNCR as we did for White Bluff. Despite these differences, we have determined that th e additional visibility modeling submitted by the

commenter does not demonstrate th at 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) Visibilit y 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 benefi ts of LNB/SOFA. The ta ble below summarizes the results of our modeling for LNB/SOFA and the co mmenter’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 SCR 1 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 0.124493 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 incremen tal visibility benefit of SCR on both units over LNB/SOFA (using the reduced SO 2 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 a ddress comments concerning the commenter’s costestimates for SCR at Independence and White Blu ff in separate responses to comment.

Comment: EPA Used a Few Non-Default CALPUFF Modeling Options That, When

Returned to the Defaul t, Had No Material Impact on the Analysis.

Examination of EPA’s modeling files for Independence 11 revealed that the agency used a few non-default options. I reviewed th ese 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 divergen ce (dw/dz) is a measure of the change in the vertical wind speed (w) per meter of depth (the units of dw/d z 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 vert ically 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 sigm a-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 alwa ys 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. Shif ting a larger portion of the puff closer to the cen ter 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 resu lting 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 ar e lower, however overa ll it balances out

such that the 98 th percentile days (8 th 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 98 th
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 i nput 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 XSAMLE N 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 mo tion of each puff will be determined by the parameters at its center point lo cation which may not adequately represent the mo tion of a large puff that is stretched out over multiple meteorol ogical grid cells. Using the meteorology at a single location to represent the entire puff will increas e the uncertainty of the location of a portion of the puff’s mass. The differences in wi nd 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 tim e steps will likely be minimal (and unbiased).

The commenter evaluated CALPUFF results wi th both settings for XSAMLEN for 2001. The model results (see Ta ble 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 98 th percentile delta dV at each of the four modeled Class I areas (see Table 7). Using XSAMLEN=10 instead of the defau lt value resulted in a decrease in the

modeled cumulative visibility impact of less than 1 percent.

Table 7. 98 th Percentile Delta dV (2001)

98th Percentile delta dV (2001)

XSAMLEN = 1 XSAMLEN = 10

Cane y 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 98 th percentile delta dV impacts at the four Class I areas is small. Furthermore, it is expect ed that the differences in model results would be similar for

each of the modeled emission scen arios, so that the conclusions drawn when using the model

results to compare various emission control strate gies would not be changed at all.495 Response: We appreciate the sensitivity analysis pr ovided 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 th e CENRAP’s BART modeling protocol 932 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 98 th
percentile visibility impacts and vi sibility benefits of controls and would not have impacted our

control determinations based on consider ation of all the re levant 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 redu ctions the Agency proposes would not be achieved until well into the second planning pe riod. The Proposed FIP covers a planning period of 2008-2018. The major SO 2 emissions control technology that would have to be installed at Independence to meet the proposed SO 2 emission rate limitation ca nnot be designed, constructed and operational in le ss than five years. 933 Given the likely effective date of the FIP in 2016, SO 2 controls at Independence coul d not be installed and opera tional before sometime in 2021. 934

Adopting a reasonable progress goal for the firs t 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 comple tely failed to explai n why it is appropriate. Indeed, EPA will have multiple bites at this appl e – there are still four more planning periods during which the necessity of r easonable progress controls can be evaluated. Controls on Independence should not be considered until th ese 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 Reas onable 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 SO 2 controls at Independence by proposing that Independence meet the SO 2 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 contro ls at Independence.

934 The Proposed FIP provides for NO X emission limitations to be met three y ears after the effectiv e 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 ad dresses the requirements of the Regional Haze Program where a State’s SIP s ubmission 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 year s unless the State has corrected the deficiency by submitting a SIP revision and EPA has approve d 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 appli cable requirements.

The first planning period, ending in 2018, include s 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 fact ors set out in the CAA. Although States are required to establish RPGs for 2018 to provi de 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 Regiona l Haze Rule that controls to im prove visibility contained in a SIP must be fully implemented by the end of th e planning period. In particular, as discussed below, there is no requirement that long-te rm 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 irrespect ive of whether such cont rols can be put into place by 2018.

Congress declared that the “nat ional goal” of the Regional Haze program is “the prevention of any future, and the remedying of any existing, impa irment 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 regu lations requiring States to imp lement SIPs “to contain such emission, limits, schedules of compliance and ot her 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 year s) strategy for making r easonable progress toward meeting the national goal[.]” 936 Congress stated that “in dete rmining 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 in stall controls outside of the initial planning period in the long-term strategy, but rather, it re quires us to consider the time necessary for compliance when determining what constitute s “reasonable progress” toward the national goal. 938

We issued regulations including, in addition to BART requirement s, four “core requirements” including reasonable progress goals , calculations of baseline and na tural 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 statut ory 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 inclusio n of certain requirements to meet the RPGs without limiting planning authorit y to include other requirements to meet the national goal. Thus, there is no explicit statutor y or regulatory requirement to limit control options to the first planning period.

Further, EPA’s long-standing interpretation of th e Clean Air Act and its regulations explicitly provide for the type of post-planning period contro ls 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 prog ress,” as opposed to RPG, refers to the national goal, and as noted above , the regulation provides for flex ibility 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 cont rolled 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 th at could be controlled within the strategy period should be considered ...in establishing the SI P 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 with in 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 includi ng emission limits that li kely 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 th e Regional Haze Program (June 1, 2007), 5–2.

944 79 Fed. Reg. 74818, 74874.498 We also note that, due to sequencing of the SI P process, including subm ission, review, revisions, re-review, and FIP preparat ion, public notice and promulga tion, 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 require ments. 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 be nefit 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 th eir soonest opportunity, not delaye d, deferred or avoided for later planning periods at those times when other sour ces should be the focus of potential additional controls. Accordingly, we do not think th e 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-t erm 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 th e 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, resu lting 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. Furt her, 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 emi ssion control requirements and the structure of the RHR. As noted, the regional haze program contemplates gradual visibility improvements along a “glide path” that consid ers the 2064 goal, and does not requ ire immediate reductions that exceed making “reasonable progress.” See 64 Fed. Reg . at 35,721. Here, the proposed FIP is attempting to require controls for Independen ce units that EPA knows cannot be in place or effective within the first pl anning 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 pl ace or effective to meet a 2018 milestone is unreasonable and unjusti fied, especially considering th at impacted Class I areas are on track to meet upcoming reasonab le progress goals for visibility. Instead, these controls, if they will be necessary at all, shoul d 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 intermi ttent 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 re quirements 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 ru le sets out, deficiencies ar e 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 th e glidepath exceed “reasonable progress.” Assessing the measures necessary to achieve vi sibility improvement commensurate with the glidepath, as required by the Regional Haze Rule, ensures that States consider a relatively stringent suite of contro l measures in determining the approp riate measures to include in their regional haze SIPs. The glidepath, however, is an analytical requirement , and as explained in our prior disapproval of Arkans as’ 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 analys is of reasonable progress measures can or should be done.

We explained in our proposed ru le that we focused on the Entergy Independence Power Plant in our analysis of reasonable progres s measures “because it is one of most significant sources of

SO 2 and NOx, as it is the second largest point source for both SO 2 and NOx point source

emissions in the State.” 947 (The largest point source of SO 2 and NOx, the Entergy White Bluff Plant, is subject to the BART requirements). Given that it is our oblig ation to ensure that reasonable progress is made toward meeting th e national goal, it “woul d be unreasonable to ignore a source representing more than a third of the State’s SO 2 emissions and a significant portion of NOx point source emissions.” 948

We agree with EEI that the regional haze progra m contemplates gradual visibility improvements
over time. The measures in our FIP, as we ll as the other CAA programs, will provide improvements in visibility after 2018 and help to ensure that Class I ar eas continue to make reasonable progress in the second planning period. We do not consid er the emission limits that can be achieved by installation of scrubbers and combustion c ontrols we have proposed and

those we finalize in this action as being extensive or frontloading but instead repres ent a level of

control consistent with the reason able application of the four r easonable progress factors. As we have outlined in our proposal a nd 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 requireme nt for EPA to implement a FIP.

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

Comment: EPA has no legal basi s 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 SO 2 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 shutdown s 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 pr oposed 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 “S tates may conclude that contro l 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 en sure reasonable progress , but states conceivably

could conclude that nothing must be done. There is no provisi on setting a “floor” for reasonable

progress.

Response: White Bluff Units 1 and 2 are BART-eli gible sources that reasonably may be anticipated to cause or contribute to any impairment of visi bility 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 BA RT “unless the state demonstrat es that an emissions trading program or other alternative wi ll achieve greater reasonable towa rds natural conditions.” In several cases, after EPA has proposed or finalize d 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 wh ether the Entergy would be interested in an alternative path.

Entergy did provide comments tentatively sugg esting a possible multi-unit alternative to the proposed FIP that would have included em ission reductions at both White Bluff and Independence. 949 EPA could not complete an evaluation of an alternative pr oposal (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 measur es 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 alternativ e. Rather, EPA’s understanding is that under Entergy’s four-unit approach, the NO X control measures and lower SO 2 emission rate proposed for White Bluff would be

considered to constitute BART for White Bluff while the NOx control measures and lower SO 2 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 ha ze in a Class I area. In addition, the preventative component of th e national goal requires states to have a framework in place to address emissions growth. For these reasons, EPA c oncluded that all states must therefore submit regional haze SIPs. In explaini ng 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 regi onal 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 emi ssions reductions needed from individual States be developed and refined through mu ltistate 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 atta in 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 specifi cally 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 cons ultations 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 St ates 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 th at 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 Pr ogress 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 pr oposed 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 reas onable 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 Wilderne ss Area (“Upper Buffalo”) because, in EPA’s view, Arkansas “believed, incorrectly, that no additional analysis of potential reasonable progress measures was necessary because visibilit y 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 warra nted and, if they are, the nature and the degree of stringency of the required emission re ductions. 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 stat ed 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), EP A explains that the URP is the starting point for analysis and that the rule does not requir e assessing the reasonable progress criteria with respect to a potentially faster rate of pr ogress if the rate of progress represented by the URP is deemed to be reasonab le. 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 th e amount of pr ogress identified through the analysis is reasonable based upon the statutory factors, the State should identify this am ount of progress as its reasonable progress goal for the first long-term strategy, unless it determines that additional progre ss beyond this amount is also reasonable. If

the State determines that additi onal progress is reasonable based on the statutory factors, the Stat e 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 m easures that would be n eeded 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 progr ess that are more accelerated than the URP, particularly for the first planning period. EPA explaine d 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 easte rn United States ... the [emission] reductions from measures implementing the CAA requirements will provide the visibility improvement and emissions [reductions] needed for reasonable progress durin g the first regional haze implementation plan.”

Id. at 35,733; see also id. at 35,737 (“It is expected that for so me 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 improve ments 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 Progr ess Guidance that “[g]iven the significant

emissions reductions that we antici pate 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 am ount of emissions reduction is appropriate in setting the RPG, you should take into account the f act 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 reason able 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 UR P, this aspect of EPA’s proposed rule is arbitrary, capricious, a nd 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 [agenc y] acts pursuant to an erroneous view of law and, as a consequence, fails to exercise th e discretion delegated to it by Congress”).

Response: In 2012, EPA disapproved Arkansas’ reas onable 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 disapprova l of Arkansas’ SIP in this acti on. 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 pr ogress determination wa s 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 re levant 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 aut hority to require additional controls beyond

those needed to achieve the URP if such contro ls are considered reasonable based on a four factor analysis. See 51.308(d)(i)(A). As commen ter 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 EP A] should adopt that amount of pr ogress as its goal for the first long-term strategy.” 953

We disagree with the commenter’s general charac terization of the URP (o r “glidepath”) or the conclusion that EPA anticipated that emissions reductions from other CAA programs could be relied on without further analysis to ensure reason able 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 nationa l 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 su stained, would lead to attainment of the national goal in 60 years. EPA “concluded that it woul d be reasonable to es tablish 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 st ates 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 un reasonable. The commenter also cites to la nguage indicating EPA’s belief that future emission reductions resulting from the strate gies to ensure compliance with the NAAQS and other CAA programs might constitu te reasonable progress in some states. We note that in considering the appropriate r easonable 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 stat es, where other programs under the CAA have resulted in significant emission reductions, em issions from these three sources have not

953 64 FR at 35732.

954 64 Fed. Reg. at 35,732.505 substantively changed since the ba seline 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 th e 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 th at the final rule should find that reasonable progress requires th e Entergy Independence plant to meet an SO 2 emission limit of 0.04 based on the use of a scrubber. Two separate legal au thorities require this conclusion, and thus EPA has two independent grounds for requiring the Independence plant to install and operate a sc rubber under the reasonable progress provisions.

First, EPA should require a sc rubber under the reasonable prog ress 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 scrubbe r as part of the long-term st rategy that must include the emissions reductions necessary to meet the reason able progress goals for Class I areas in other states affected by the Indepe ndence plant’s emissions, namel y, 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 necessa ry 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 Cl ass I areas. 79 Fed. Reg. at 74,828-30. Arkansas was obligated to cons ult meaningfully with Missouri, id. § 51.308(d)(3)(i), which includes providing Missouri with the te chnical information necessary to determine whether the implementation of reasonable co ntrol measures in Arkansas would improve visibility in Miss ouri’s Class I areas.

Arkansas and Missouri consulted during the development of their respective plans. However, Arkansas neither considered nor proposed reas onable progress controls for the Independence plant. As a result, Arkansas did not provide Missouri with information on available future controls at Independence Un its 1 and 2. EPA disapproved Ar kansas’s reasonable progress analysis because it did not comply with applicable requirements.

The regulations required Arkansas to “document th e technical basis . . . on which the State is relying to determine its apportionment of emi ssion reduction obligations necessary for achieving reasonable progress in each mandatory Cl ass I Federal area it affects.” 40 C.F.R. 51.308(d)(3)(iii). “This documentation is necessary so that the interstate consultation process can506 proceed on an informed basis.” 80 Fed. Reg. at 74,829. Here, Arkansas failed to properly document its portion of reductions necessary to ac hieve 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 an alysis of reasonable pr ogress. Thus, Missouri developed its reasonable progre ss 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 th ere may be situations where “the [reasonable progress] goal itself is fl awed 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 adeq uate 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 provi de 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 deci views 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 al l of the four reasonable progress factors, the reasonable progress goals for Herc ules-Glades and Mingo must reflec t operation of a scrubber at the Independence plant. Reasonable progress go als for Hercules-Glades and Mingo that do not

reflect the reductions from a scrubbe r at Independence are not approvable; 955 for the same reason, an Arkansas plan that does not require a scr ubber at Independence is not approvable under 40 C.F.R. § 51.308(d)(3).

In sum, EPA has two separate legal bases for re quiring 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 sc rubber is a reasonable control measure at Independence Units 1 and 2 and thus the reasona ble 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 Mi ngo must reflect operation of a scrubber at both Independence units, and therefore Arkansas’s l ong-term strategy must require sc rubbers 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 Missour i 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 sectio n of the response to comments.

8.d. States have a leading role and dis cretion under the Regional Haze cooperative

federalism

Comment: The Regional Haze program is built on principles of cooperative federalism that require EPA to defer to stat es in developing SIPs. [Nucor Steel-Arkansas and Nucor-Yamato Steel (0163) p. 5-6, 9-12; and Ar kansas Electric Energy Consum ers 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 vi sibility at mandatory Class I Federal areas (“Class I areas”). Two of thes e 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 vi sibility 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 th e requirement in 40 C.F.R. § 51.308(g) that Arkansas provide periodic repo rts to the EPA evaluating its pr ogress towards the Reasonable Progress Goals (“RPGs”). The EPA prom ulgated the Proposed FIP on April 8, 2015. 957

Nucor and AEEC/AGC stated that EPA's disa pproval of the Arkansas Regional Haze SIP together with its decision to initiate this ru le-making and impose the proposed FIP far exceeds EPA's legal authority under the Clean Air Act. EPA's actions im properly transform the structure of the regional haze program from a state-driven program grounded in cooperative federalism to a centrally controlled, federally managed progr am with no meaningful role for the states, regulated entities, or in the case of electric publ ic utilities, the end users and consumers who ultimately will bear the brunt of and have to pa y for EPA's determinations. Nothing in the Clean Air Act or the administrative record supports EP A's determination that mandates the installation of over $2 billion in new emission controls on pu blic utility electric ge neration resources that have significant social and economic va lue 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 stat utory 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 FI P ignores those limits and timelines and would impose a plan that ignores the primary im plementation 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 Ac t, it gives EPA power to arbitrarily substitute its own judgment for that of a state at virt ually any stage of the implementation process.

As courts have recognized, the Clean Air Ac t was intended by Congress to be “a model of cooperative federalism.” Sierra Club v. Korles ki, 681 F.3d 342, 343 (6th Cir. 2012); Michigan v. EPA, 268 F.3d 1075, 1083 (D.C. Cir. 2001); Florid a Power & Light Co. v. Costle, 650 F.2d 579, 581 (5th Cir. 1981). Under this structure, Congress specifically f ound 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 cont rols within their borders." North Dakota v. EPA, 730 F.3d at 760-61. Thus, "states have br oad authority to determine the methods and particular control strategies they will use to achieve the statutory requi rements." BCCA Appeal Group v. EPA, 355 F.3d 817, 822 (5th Cir. 2003). Specifi cally, 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 cont rasting, narrow role to be played by EPA.”).

Nucor stated that rather than establishing st rict implementation requi rements, EPA's rule “requires States to determine the rate of progr ess for remedying existing impairment that is reasonable, taking into consideration the statut ory 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” a nd, in applying the required stat utory factors, the states “have flexibility in how to take into consideration these statutory fact ors 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 evaluati on is done adequately and the States provide a reasoned basis for their decision, EPA will de fer to the state.” 77 Fed. Reg. 40,150, 40,156 (July 6, 2012).

Nucor and AEEC/AGC stated that in the Propos ed FIP, EPA ignores these well-established principles of cooperative federalism , disregards the right of the St ate of Arkansas to make BART and Reasonable Progress decisions, and imposes a radically different implementation plan based on its own independent analysis. This over-reachi ng is contrary to the Clean Air Act and is unlawful. This hijacking of Arkansas’ primary au thority to implement th e 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 arbitraril y and capriciously, to make d ecisions based on sound reasoning, to take into account important and relevant factor s, 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 ac tion 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 characte rization of our action. Our action does accord with the CAA. Congress crafted the CAA to provi de 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 rec ognize that States have the primar y responsibility of drafting an implementation plan to address the requirement s of the regional haze program. We also recognize that we have the res ponsibility 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 coopera tive 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 th e 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 th e requirements of RH a nd 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 a nd 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 incl uded in the docket to this rulemaking action. To date, EPA ha s 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 Cong ress 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 nati onal parks and other scenic areas, Congress enacted the Clean Air Act’s regional haze provisions wi th 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 tr ansport 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 defi ciencies 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 w ould make incremental improvements over time. Section 169A requires EPA to “promulgate regulati ons 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 st rategy; and (3) implementation of BART for certain stationary sources. Through this program, each state charts a “Glidepath” towards natural visibility at the Class I area s within their borders by 2064. States then are provided significant flexibility in crafting the emission reductions nece ssary for meeting that Glidepath by assessing reasonable progress goa ls 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 goa ls, and the co-benefits of reducing visibility impairments through other Clean Air Act progr ams, 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 reasonabl e progress, not the most reason able progress.”). Reasonable progress goals for Class I areas ar e based on four factors: (1) “c osts of compliance;” (2) “the time necessary for compliance;” (3) “the ener gy 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 requ ired to be demonstrated on a source-by-source basis.”); RPG Guidance at 4-1 (“Given the signif icant 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 peri od for some States.”). Through th e state’s consideration of these factors, each Class I area need only make incremental progress th rough 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 exer cising their discretion re garding how they meet reasonable progress goals for the Class I areas with in their borders. Desp ite Congress’ intention for states to have primary responsibility in im plementing the program within their borders, EPA arbitrarily disapproved Arkansas’ Regional H aze 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 in stance in a disturbing tr end of EPA disregarding511 the considerable discreti on Congress assigned to states in th e 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 s hould 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 Congr ess assigned to states in the sy stem 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 resour ces working with its ne ighboring 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 fr om existing programs, emissi on reductions through BART, and several other emission reduction options to find the most efficient and affordable means of meeting federal requirements. As EPA has recognize d, at least at the outset of the Regional Haze program, Congress intended to “provide States co nsiderable discretion in establishing reasonable progress goals for improving visibi lity 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 addi tional control requirements”); id. at 5-1 (states “have flexibility

in how to take into consideration these statut ory factors and any othe r 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 ba sis for their decision, EPA will defer to the state” with respect to r easonable 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 ha ve a successful and dem onstrated track record in creating the real-world, m easured visibility improvement s Congress envisioned under the Regional Haze program. It is incr easingly troubling that EPA app ears eager to disapprove state implementation plans in order to substitute its own judgment on matters affecting not just technical details, but state regul atory and economic concerns. EPA’ s intrusion into these areas has frequently led to costly a nd unnecessary burdens on state indus tries 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 perc eived by the human eye. EPA’s pattern of second-guessing the re asoned decisions of expert state agencies is not only economically wasteful, but it cont ravenes 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 st ates in determining the best path of reasonable progress taking into account unique local circumstances to realiz e visibility improvements. EPA has failed to demonstrate any rational grounds to supplant its own judgment for Arkansas’ and, as described below, lacks the legal author ity to impose the proposed controls here.512 Response: Please see our above responses which a ddress 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 subm itted Arkansas regional haze SIP (and visibility transport SIP we disapproved in 2012) is in k eeping with Congressional intent on the roles prescribed for states and EPA under the Clean Ai r Act. As explained earlier, EPA reviewed Arkansas’ submitted regional haze and visibility In terstate 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 rulema king 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 tw o year clock by which EPA is required to act under the Clean Air Act to either approve a re vised SIP from Arkansas that corrects the deficiencies or promulgate a FIP. During the two-year pe riod, EPA met with Arkansas on revising the SIP. After the two years elapsed, EP A 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 proc eedings 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 Indepe ndence units also is justified by the statutory context of the regional haze program, which is designed to re spect 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 uni ts 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 fo r 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 rati onale 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 documen t. See our above responses concerning the

roles of states and EPA and the role of the UR P. Our proposed and final rules assessing the Arkansas regional haze SIP pr ovide additional background info rmation regarding our prior partial disapproval of sections of Arkansas ’ SIP addressing reasonable progress in which Arkansas did not conduct a four factor analys is as required under the RHR, 51.308(d)(1).76 FR 64186 (Oct. 17, 2011)(proposed rule); 77 FR 14604 (M arch 12,2012) (final rule).That action513 underwent notice and comment pursuant to the Ad ministrative Procedures Act and no party challenged the rulemaking within the required 60 days after the publicati on 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 im plementation of other CAA programs, BART, or forecasted levels of economic activity, a state (o r EPA) must provide a reasoned analysis to support its determination as to appropriate reason able 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 Arka nsas of SO2 and NOx –should be included in our FIP. We agree with the commenter that s ources 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 planni ng period. As EPA is issuing a FIP, we have considered the appropriateness of additional measures on Arkansas sources to ensure reasonable progress, and as explaine d elsewhere, reached the conclusion that SO 2 and

NO X control measures for Independence should be in cluded 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 St eel (0163) p. 13-16; Arkansas Electric Energy Consumers Inc. and Arkansas Gas Consum ers 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 Federa l implementation plan at any time within 2 years after the Administrator —

(A) Finds that a State has failed to make a re quired 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 su bmission in whole or in part, unless the State corrects the deficiency, and the Admini strator 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 Re gional Haze SIP on March 12, 2012 (77 Fed.Reg. 14604); however, EPA did not take a ny action to issue a FIP during th e 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 Pr oposed FIP after that time, EPA impermissibly ignores and does not give effect to the words “wit hin 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 becau se 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 S upreme Court reverse d. 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 in adequate, 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 impl ementing the Good Neighbor Provision.... However sensible (or not) th e 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 tim e” within the two-year limit.... Carving out an exception to the Act's precise deadlin es, as the D.C. Circuit did, “rewrites a decades-old statute whose pl ain text and structure esta blish a clear chronology of federal and State responsibilities.” The practical difficulties cited by the Court of Appeals do not justify departure from the Ac t'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 prim ary 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 implemen ting SIPs, States cannot wait indefinitely for

EPA to act on State submissions or to belatedl y issue FIPs; consequently , in section 7410(c)(1) Congress set a two year limit on EPA's ability to i ssue a FIP after a SIP disapproval. The State of Arkansas has given EPA assurances that it will co ntinue 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 an y 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 Cl ean Air Act does not release EPA from its statutory mandate to promulgate a FIP or approve a st ate SIP after the elapse of two years. Oklahoma v.

EPA , 723 F.3d 1201 (10 th Cir. 2013), cert. denied (U.S. May 27, 2014)(EPA’s authority to promulgate a FIP is not subject to a two y ear 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 promul gate a FIP or approve a SIP submittal addressing the disapproved portions of the Arkansas’ region al haze and visibility transport SIP by August
31, 2016.

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

Comment: EPA must address the requiremen ts of Executive Orders 12866 and 13211. [Entergy Arkansas Inc. (0166) p. 55- 56] Entergy Arkansas Inc. stat ed that EPA claims that the Proposal is not a “significan t regulatory action” under Execu tive Order 12866. 80 Fed. Reg. at 18,999. Entergy disagrees. The Proposal’s implemen tation cost to EAI alone of over $2 billion exceeds the $100 million threshold for economic signi ficance. “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 systematica lly 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 subjec t to Executive Order 12866, because the rule “only proposes source specific requirements for particular , identified facilities (s ix total).” 80 Fed. Reg. at 18,999. However, a count of the number of enti ties regulated under a rule is not indicative of the general applicabilityor the significance of the economic impacts of the rule. Requiring additional controls at power pl ants initiates a cascade of imp acts, including changes in the regional distribution of electricity and rates of thousands of electricity customers in multiple states. These far-reaching impacts merit classifyi ng the Proposed FIP as a regulation with general applicability and significant economic impact.

Entergy also disagrees with EPA’s conclusion th at the Agency is not required to assess the energy impacts of the Proposed FIP under Ex ecutive 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. Additi onally, 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, tran smittal letter to Hon. Ron Curry, EPA, Region VI Regional Administrator.516 Response: We disagree with the commenter’s inte rpretation of Executive Orders (“E.O.”) 12866 and 13211. E.O. 12866 defines “regulat ions” or “rules,” as “an agency statement of general applicability and future effect.” An “agency st atement of general applicability” refers to statements that apply to groups or classes of en tities, as opposed to a re gulation or rule which applies only to named entities. Our FIP is not, ther efore, a rule of genera l applicability because its requirements apply and are spec ifically tailored to six indivi dually identified facilities. Thus,

it is not a “rule” or “r egulation” 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 “s ignificant 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 cr iteria is therefore not require d. It should be noted that the agency action which was at the cente r 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 on ly conclusory speculations concerning energy impacts and grid reliability concerns with no data, we cannot speculat e 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 EP A asserts that its Pr oposed FIP is not a “significant regulator y action” within the meaning of Executive Order 12866 (“E.O. 12866”). 964
However, the proposed FIP would result in substa ntial and material costs being transferred onto Arkansas communities through increased electricity ra tes 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 wi th 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 regu latory 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 c opy 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 provi de 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 sign ificant regulatory action. 967 By issuance of E.O. 13563 on January 18, 2011, the sitting President reaffirmed “the prin ciples, structures, and definitions governing contemporary regulatory revi ew 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 envir onment, 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 anot her agency; (3) material ly alter the budgetary impact of entitlements, grants, user fees, or loan programs or the ri ghts and obligations of recipients thereof; or (4) raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principl es 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 passe d on to Arkansas consumers. Specifically, the following facilities owned by electr ic 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 Genera ting 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 Catherin e 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 consum ers of the electricity generated by these plants and generators. Under Arkansas law, a public utility such as thos e 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 fo r the recovery of cost s 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 adve rse impact that renders this action subject to requirements of E.O. 12866.

In addition, a significant regulat ory action under E.O. 12866 is cons idered a “significant energy action” and subject to yet furthe r 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 a dverse 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 “signifi cant energy action.” In order to comply with E.O. 13211, EPA is require d to submit to OIRA a “Statement of Energy Effects,” which describes the e ffects of certain regulatory acti ons 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 FI P is not subject to E.O. 13211 and E.O. 12866. The impacts of the Proposed FIP render it s ubject to both executiv e 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 “cos t of compliance” factor in relation to the RPGs, 974
EPA has not performed any analysis of the cost s of the overall impact of the Proposed FIP. Without EPA complying with the required ad ditional review by OIRA , there would be no oversight of the costs of the Proposed FIP at al l. Given the recent concerns by the Supreme Court

in Michigan v. EPA about the rationality of imposing billi ons 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 faile d to do so, ADEQ requests that EPA withdraw the Proposed FIP. 976

Response: Please see the above response in refe rence to E.O. 12866 and E.O. 13211.In the process of developing the FIP, we analyzed a ll the required factors, including the cost of compliance, at each source. Our detailed cost an alysis can be found elsewhere in the proposed rulemaking and in this document.

Comment: AECC stated there should be furth er federal review of the cost impacts of EPA’s proposed Rule. [AECC (0169) p. 6] AECC st ated that EPA states that the proposed Rule is not a “significant regu latory action” as define d 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 fi nal 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 revi ew prior to its issuance.

Additionally, in a recent decision involving costs of MATS, the U.S. Supreme Court recognized that costs of environmental regulation s 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 characteri zation 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 appr opriate and necessary finding under section 111 of the Clean Air Act. 135 S.Ct. 2699 (2015). The C ourt’s holding was based on its reading of the phrase “appropriate and necessary.” Even in th is context, however, the Court found that “a formal cost-benefit analysis in which each adva ntage 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 th e 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 cost s (and visibility benefits) of the measures in

the FIP.

8.g. EPA did not adequately consider relevant factors

Comment: EPA improperly failed to consider rele vant 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 ar e fully enforceable in federal court. See, e.g., Safe Air for Everyone v. Unite d States EPA, 488 F.3d 1088, 1091(9 th 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 Ea rlimart v. Warmerdam, 539 F.3d 1062, 1066 (9 th Cir. 2008); GenOn REMA, LLC v. EPA, 722 F.3d 513, 516 (3 rd Cir. 2013) (“If the EPA approves the SIPs, they become enforceable as federal law. ”); US Magnesium, LLC v. EPA, 690 F.3d 1157, 1159 (10 th 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 environmenta l agencies. See, e.g., United States v. Cinergy Corp., 623 F. 3d 455 (7 th Cir. 2015); Sierra Club v. Ga. Power Co., 443 F.3d 1346 (11 th Cir. 2006); United States v. General Motors Corp., 702 F.Supp. 133 (D.C. Tex. 1988).

Ark. Code Ann. §8-4-312 sets out seve ral factors that must be take n 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 es tablishing reasonable progress goals, 42 U.S.C. §7491(g)(1), the statute doe s 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 co nsidered. 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 determin ations for Flint Creek, White Bluff and Independence will cost over $2 Billion and will re sult in significant increases in electric and natural gas rates over most of th e State of Arkansas for residen tial, commercial, governmental, agricultural and industrial customers of Enter gy, 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 propor tion 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 certai nly pass those costs through to ratepayers, the proposed FIP will have a profound e ffect 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 beari ng the greatest burdens imposed by environmental pollution.” EPA, “Gui dance on Considering En vironmental Justice During the Development of Regulat ory Actions,” May 2015, at p. 2. 980 These same populations that EPA's EJ guidelines seek to protect woul d be adversely impacted by EPA's Proposed FIP. Arkansas is the second poorest state (49/50) with a median house hold income of $40,768. 981 It has the 4th highest percentage (ranke d 46/50) of poverty stricken residents. 982 The areas in Arkansas that White Bluff, Independence and F lint Creek serve have an average of 19.2% of residents living below the federal po verty level. Several counties in east Arkansas that are served by these facilities have more than 30% of thei r 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 in comes of over $50,000 sp ent 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 th eir budgets consumed by rising energy costs — 17% in 2012 compared to 10% in 2001. Mo st drastically, families making $10,000 to $30,000 spent 24% of their incomes on ener gy 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 in creases in electric rates that el ectricity providers would charge ratepayers in order to comply with EPA's pr oposed FIP will push more Arkansans deeper into

poverty.

There is an important relationship between ut ility rates, poverty a nd 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-cl ean-power-plan-may-do-more-harm-than-good/ Citing: http://www.americaspower.org/sites/default/f iles/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 conclude s 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 el ectric bills, leaving them less m oney for food, use of heating and air conditioning, paying health insurance premiu ms, buying medicine, transport to work, and to see their doctors. In forcing its proposed FIP ont o Arkansas, EPA has failed to consider whether it would harm thousands of Arkansans, wh ich 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, Independe nce, or Flint Creek resulting in local adverse economic impacts, the impact of such closures or curtailment on electric gr id 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 regula tion. Under EPA's BART guidance, EPA states that BART should not be so economically oner ous that it brings a facility

to the brink of shutdown or subs tantial 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 Cree k and Independence.

Under EPA's proposed Clean Power Plan, the possibl e impacts of the closur e or curtailment of fossil-fuel electric generating units like White Bl uff, 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 c onsider or take into account th e 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 territori es 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 im pacts in Arkansas. Not only are these factors “appropriate,” as indicated above they are “n ecessary” and required under Ark. Code Ann. §8-4- 312, EPA's own BART Guidelines, and its EJ Guid elines. “No regulation is ‘appropriate’ if it does significantly more harm than good.” Mi chigan v. EPA, 576 U.S. (2015). EPA should consider whether its proposed FIP “reflects th e reality that too much wasteful expenditure

986 See Exhibit 8 to Nucor’s comments, Klein, D., and Ke eney, R., "Mortality Reductions from Use of Low-Cost Coal-Fueled Power: An Analyti cal 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 fo r 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 f actor 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 consid erably fewer resources available to deal effectively with other (perhaps more seriou s) 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 properl y justified by EPA. EPA should have considered the economic impact of the Regional Haze Ru le 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 asse rtion 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 abov e 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 po llution. States are under an ob ligation to submit a Regional Haze SIP to EPA which complies with federal requi rements. 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 requ irements, EPA must step in and create a FIP to address the portions of the disappr oved the state’s plan which m eets all federal requirements.

Ark. Code Ann. §8-4-312 provides that “[i]n ex ercising their powers and responsibilities under this chapter, the Arkansas Department of Environm ental Quality and the Arkansas Pollution Control and Ecology Commission shall take into acc ount and give consideration to the following factors:...” (emphasis added). Arkansas has fail ed 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 factor s 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 Cont rol 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 th e federally-approved SIP. Ark. Code Ann. §8-4- 317 provides that “[i]n developi ng and implementing a state impl ementation plan, the Arkansas Department of Environmental Quality shall consid er and take into accoun t 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 sp irit and purpose of our Environmental Justice

Guidelines. The full sentence from which the comme nter quotes reads: “In particular, the U.S. Environmental Protection Agency has a re sponsibility under Executive Order 12898, Federal523 Actions to Address Environmental Justice in Mi nority Populations and Low-Income Populations to consider the impacts of our regulatory act ions on populations documented as frequently bearing the greatest burdens imposed by enviro nmental pollution.” Execu tive Order 12898 states that each Federal agency is re quired 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, po licies, and activities on minority populations and low-income populations in the Unit ed States and its territories a nd possessions, the District of Columbia, the Commonwealth of Puerto Rico, and the Commonwealth of the Mariana Islands.” Contrary to the commenter’s assertion, our act ion embodies the spirit in which the Executive

Order was written. The reduction in air pollution that will be attr ibuted 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 visibilit y 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 th e controls and the possibl e closure or curtailment of units, we note that controls achieving the level of control thatwe 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 gr id reliability concer ns in response to our proposed controls have not provided adequate documentation for th eir 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 unde r 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 th e controls required by th e FIP are cost-effective, worth the visibility reductions ach ieved, and consistent with expect ations 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 th e rule may cause units to close. [Sierra Club et. al. (0171) p. 44-45] Sierra Club et. al. stated that comments submitte d by other parties suggest that EPA is required to consider the potential closure of units as pa rt of considering the cost of controls. However, there is no evidence in the reco rd 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 othe r 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 cons istent with the BART Gu idelines’ instruction that EPA should rely upon the affordability provision onl y 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 allegedl y indicated that the co mpany 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 co st-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 th at 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 confidenti al 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 clos ures or curtailments.

8.h. Other

Comment: EPA arbitrarily chose the opti ons for emissions control for Entergy Independence Units 1 and 2. [ADEQ (0144) p. 22-23] ADEQ stated that EP A arbitrarily chose the two options it presented for emissions contro ls 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: Propos e No Additional Controls under Reasonable Progress”; “Option 2: Propose Only SO 2 Controls under Reasonable Progress”; and “Option 3: propose Both SO 2 and NO X 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-2015-0189525 “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 interpreti ng its own regulations, the law requires EPA to “cogently explain why it has exercise d its discretion in a given manner.” 994 Whether or not EPA ultimately chose to reject the opti on, it is legally obligated to cons ider and explain its decision to

or not to include it. The deci sion to provide ADEQ with a certain set of options prior to promulgation of the Proposed FIP and simply exci se one of those options from the Proposed FIP

without due consideration is arbitrary and capricious. EPA s hould withdraw the Proposed FIP and any subsequent plan that might include emi ssions controls for Entergy Independence Units 1 and 2 should include a proper consid eration of the available options.

Response: The document to which the commenter re fers, “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. Unde r Section 307(d)(3) of the Clean Air Act, the docket is required to include the factual da ta 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 underl ying the proposed rule. The briefing paper does not fall within any of these cate gories. We provided the proposed factual, technical, and legal basis for requiring controls at Independence to ensure reasonabl e progress in our proposed rule. In doing so, we have “cogently explain[ed]” th e 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 discre tion in deciding to require reas onable 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 Envir onmental Protection Agency (“EPA” or “Agency”) has acted in an arbitrary and capricious manner by proposing a FIP to address certain regiona l 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 de veloping 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 con cern 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 requ ires 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 regard ing the proposed Consent Decree in Sierra Club , the Attorney

General does not believe that five (5) months is an adequate ti me period for the EPA to fully analyze and respond to the public comments. Ag ain, 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 fu lly review all considerations will lead to an arbitrary and capricious decision. Such a decision w ill 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 challengi ng 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. Cons ent decrees establishing dates by which EPA must take action do not addre ss the content of final action by the Agency. In this case, as explained in more detail earl ier, 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 Arka nsas 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 ad equate time for EPA to address all comments and

to finalize a FIP. See Sam Coleman declar ation submitted under the mandatory duty suit (provided in our docket to this rulemaking). Th e proposed FIP, as explai ned 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 SI Ps 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 nationa l parks and wilderness ar eas 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 compli es with the applicable legal requirements, the Clean Air Act requires EPA to disapprove the st ate 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 stat e’s regional haze SIP complies with the Clean Air Act. 42 U.S.C. §§ 7410(c)(1), (k)(3), (l), 7491. EPA has broa d oversight authority over the regional haze program and is obligated to disappr ove 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 au thority to prevent recal citrant 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 “d isappointing state response[s] to air pollution concerns” and its recognition that “states e xperience[] 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 ap proval 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 Se ptember 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 disa pproving in part Arkans as’s regional haze and interstate transport SIP. 77 Fed. Reg. 14,603.

In the 2012 action, EPA approved Arkansas’s identif ication 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 ap proved 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 th at 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 partia lly 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 no t consider the four factors that states are528 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 deci sion by filing a petition for review in the appropriate Circuit Court of A ppeals. 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 a nd 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 expl ained 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 actio n; 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 addre ssed 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 Cl ub 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 contro l 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 im provements 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 e xplanation why the reasonable progress options available at Co lstrip 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 reasonabl e progress determinations in wh ich 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 co st 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 approve d or promulgated. These controls are also anticipated to re sult in comparable or greater visi bility benefits than controls in other regional haze actions. Below, we speci fically 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 ar e reasonable and cost effective controls and are required under reasonable progress. 996 In its SIP, Colorado determined th at the cost effectiveness of dry scrubbers on CSU Nixon Unit 1 would be $3,744/ton SO 2 removed and that the visibility improvement (delta dv for the maximum 98 th percentile impact) wa s projected to be 0.46 dv.

We approved Colorado’s determination that dry scrubbers are BART for SO 2 for CSU Martin

Drake Units 6 and 7. 997 The state determined that the cost effectiveness of dry scrubbers is $2,808/ton SO 2 removed for Unit 6 and $2,345/ton SO 2 removed for Unit 7. The state found that the visibility improvement (delta dv for the maximum 98 th percentile impact) is projected to be

0.25 dv for Unit 6 and 0.40 dv for Unit 7.

We also approved Colorado’s de termination that BART for NO X 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 NO X combustion controls under the reasonable progress requirements for Antel ope 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 th e Prong 4 requirement; EPA does not have authority to require controls at these sou rces 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 addressi ng interference with other stat es’ programs for visibility protection for the 2006 revised 24-hour PM 2.5 NAAQS. These comments are attached as Exhibit I and Entergy hereby incorpor ates 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 Secti on 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 so mething 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 PM 2.5 NAAQS: “Interference With Visibility” Requirement).

Arkansas emissions cause and contribute to visib ility 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 Tran sport SIP, 76 Fed. Reg. 64,186, 64,193, 64,215 (Oct. 17, 2011); Final Approval Regional Haze Intersta te Transport SIP, 77 Fed. Reg. 14604, 14623 (Mar. 12, 2012). Of these states, only Misso uri 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 prog ress 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 Ar kansas sources from inte rfering 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 inappropr iate for EPA to propose such a finding when the Agency has not yet finalized its regional h aze 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 significa nt changes could be made to the final FIP, because these changes are unforeseeable, and beca use Entergy has significant concerns that the final FIP may be legally and tech nically deficient, it is unreason able to request public comment on a proposal that the final FIP will satisfy Prong 4. This is a clear viola tion of EPA’s obligation531 under the Administrative Procedure Act to provid e adequate notice and o pportunity to comment on a proposed rule. 5 U.S.C. § 553. EPA should de fer 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 provisi on in 42 U.S.C. 7410(a)(2)(D)(i)(I I) prohibits interference with “measures” required to be included in another St ate’s implementation plan to protect visibility. EPA has not demonstrated that any of these sour ces in its Proposed FIP ar e interfering with any visibility control measure in any other state’s SI P. Nucor disagreed with EPA’s determination to disapprove the Arkansas interstate visibility tr ansport SIP provisions submitted to EPA on April 2, 2008 based on the same reasoning. 1000 In EPA’s 2011 proposed deci sion to disapprove that SIP submission, EPA stated that the Clean Air Act re quires states to prevent “sources in the state from emitting pollutants in amounts which will interfer e 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 st ates “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 vi sibility protection require ment is narrower and only protects against interference with specific measures, that is, actions included in another state's plan to achieve a visi bility goal. Reasonable progre ss 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 de monstrating that any of the sour ces 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 inte rstate visibility transport FIP is not based on

direct interference with a control measure in a nother state’s regional ha ze SIP (in contrast to interference with a regional haze related visibility goal), EPA’s interpretation is contrary to the clear and express language of Sec tion 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 interpre tation would impermissibly gi ve one state the power to control another state’s regional haze SIP decisions, in cluding its BART and Reasonable Progress

determinations.

Finally, even if the CAA's good neighbor visibil ity provision required a state SIP to contain

emission limits for sources that contribute to visi bility 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-R0 6-OAR-2008-0727 (w ithout exhibits), December 2011.532 protect visibility required to be included in a nother state’s SIP. EPA ha s 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 pr oviding that a Regional Haze SIP that requires emission reductions consistent with the assumpti ons the relevant RPO used to model the RPGs

for Class I areas in other states satisfies a stat e’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 th at a SIP for 8-hour ozone or PM 2.5 contains adequate provisions to prohibit emissions that interfere with visibility measures in other states. 1002

Arkansas chose to address th e interstate visibi lity transport requirement under section 110(a)(2)(D)(i)(II) for the 1997 8-hour ozone and 1997 PM 2.5 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 cu rrently include all of the emission reductions Arkansas agreed to achieve in its RPO process. Arkansas is a member state of CENRAP, the regional planni ng 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 reducti ons 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 pr ovide for all the emissions re ductions that Arkansas itself determined to be necessary to meet the inters tate 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 inte rfere with other states ’ visibility protection measures. Therefore, we disagree with the co mmenters’ argument that the Arkansas RH SIP

satisfies the interstate visibil ity transport requirem ent under section 110(a)( 2)(D)(i)(II) for the

1997 8-hour ozone and 1997 PM 2.5 NAAQS.

We disagree with Nucor’s conten tion that our interpretation is c ontrary 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 ou r interpretation would impermissibly give one state the power to control anothe r state’s regional haze SIP deci sions. However, the commenter’s

1001 Guidance on Infrastructure State Impl ementation 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 antici pates that a state may be requir ed to adjust its own emissions based on the impacts of those emissions on ot her 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, th ey do contemplate that a stat e may be required to prohibit

emissions that interfere with visibili ty in another state’s Class I areas.

As stated above, Arkansas electe d to address the inters tate visibility tran sport 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 re quirements of CAA secti on 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 re spect to visibility; however su ch a SIP could be sufficient. 1006 We also note that following our March 12, 2012, partia l 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 PM 2.5 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 obliga tions 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 re asonable progress goals are not “m easures.” In section 169A, the CAA gives clear direction that e ach state is to include in its SIP emission limits, schedules of compliance and other measures as may be nece ssary 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 Cl ass 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 requ irements 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, complia nce 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 re duction obligations agreed upon through that process. 1008

We consider it reasonable to cons ider the requirements of secti on 110(a)(2)(D)(i)(II) with respect to visibility in light of this requirement in th e 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 h aze 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 visi bility transport requirements but rather that these controls (adopted for other reas ons) are sufficient to ensure comp liance with the CAA’s visibility transport provisions (as well as the parallel region al haze requirements). Gi ven that the level of control that we have determined must be prov ided by our regional haze FI P 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 satisf y visibility transport requirements, we could have and would ha ve 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 th at since Missouri’s 5-Y ear Progress Report SIP

revision indicates that Missour i’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 modeli ng 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 PM 2.5 NAAQS. We have an obligation to promulgate a FIP to remedy this deficiency. Fu rther, as we explained above, we have not

determined that the contro ls required by our FIP are necessary to meet the visibility transport requirements but rather that these co ntrols (adopted for other reasons) are sufficient to ensure

1008 40 CFR 51.308(d)(3).535 compliance with the CAA’s visibility transport pr ovisions (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 Ha ze FIP together with th e approved portion of the Regional Haze SIP satisfy this requ irement for the 1997 8-hour ozone and PM 2.5 NAAQS.

We disagree that proposing our Arkansas Regional Haze FIP and Interstate Visibility Transport

FIP in the same action violated the Administrativ e Procedures Act resulting in our not providing adequate notice and opportunity to comment on the pr oposed 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) Regulati on 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 othe r 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 acti on. Our finalized FIP addresses the emissions from those subject to BART sour ces 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 wi th the portions of the Arkansas Regional Haze SIP we approved meets the requirements of s ection 110(a)(2)(D)(i)(II) that emissions from

Arkansas sources not interfere w ith 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 fi nalize our proposed findi ng that the approved portion of the Arkansas Regional Haze SIP and ou r Regional Haze FIP together will satisfy the interstate visibility transport requirement unde r section 110(a)(2)(D)( i)(II) for the 1997 8-hour

ozone and 1997 PM 2.5 NAAQS unless and until we finalize the Regional Haze FIP, based on the proposal, commenters were on suffi cient notice regarding whethe r section 110(a )(2)(D)(i)(II) is met. We note that we are finalizing our Regi onal 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.