92038 Federal Register / Vol. 89, No. 225 / Thursday, November 21, 2024 / Rules and Regulations 

1The August 11, 2022, SIP submission, with 

exception of the supporting modeling files and CBI, 

is included in the docket for this rulemaking. Due 

to size and compatibility limitations of the Federal 

Docket Management System, the supporting 

modeling files for Georgia’s Regional Haze Plan are 

instead available at the EPA Region 4 office. To 

request these files, please contact the person listed 

in this rulemaking under the section titled FOR

FURTHER INFORMATION CONTACT. 

2On November 1, 2023, Georgia supplemented its 

August 11, 2022, Haze Plan by submitting the final 

permits for each of the three sources selected for an 

emissions control analysis. This supplemental 

submission, received November 1, 2023, along with 

GA EPD’s November 17, 2023, clarification email, 

is included in the docket for this action. 

§ 165.T01–0404 Safety Zone; Hackensack 

River, Kearny and Secaucus, NJ. 

(a) Location. The following area is a 

safety zone: All the navigable waters of 

the Hackensack River between the New 

Jersey Turnpike/I–95 Fixed Bridge 

(River Mile 5.3) and 150 feet south of 

the existing Portal Bridge (River Mile 

5.0). 

(b) Definitions. As used in this 

section, designated representative 

means a Coast Guard Patrol 

Commander, including a Coast Guard 

coxswain, petty officer, or other officer 

operating a Coast Guard vessel and a 

Federal, State, and local officer 

designated by or assisting the Captain of 

the Port New York (COTP) in the 

enforcement of the safety zone. 

(c) Regulations. (1) Under the general 

safety zone regulations in subpart C of 

this part, you may not enter the safety 

zone described in paragraph (a) of this 

section unless authorized by the COTP 

or the COTP’s designated representative. 

(2) To seek permission to enter, 

contact the COTP or the COTP’s 

representative via VHF Channel 16 or by 

phone at (718) 354–4353 (Sector New 

York Command Center). Those in the 

safety zone must comply with all lawful 

orders or directions given to them by the 

COTP or the COTP’s designated 

representative. 

(d) Enforcement period. This section 

is effective from November 21, 2024, 

through December 31, 2025, but will 

only be enforced during periods when 

heavy lift operations at the new bridge 

are in progress. The Coast Guard will 

make notice of this safety zone via the 

Local Notice to Mariners and issue a 

Broadcast Notice to Mariners via marine 

channel 16 (VHF–FM) as soon as 

practicable. In addition, if the project is 

completed before December 31, 2025, 

enforcement of the safety zone will be 

suspended, and notice given via Local 

Notice to Mariners. 

Jonathan A. Andrechik, 

Captain, U.S. Coast Guard, Captain of the 

Port Sector New York. 

[FR Doc. 2024–27429 Filed 11–19–24; 4:15 pm] 

BILLING CODE 9110–04–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R04–OAR–2023–0220; FRL–10407– 

02–R4] 

Air Plan Approval; Georgia; Second 

Period Regional Haze Plan 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is approving the regional 

haze State Implementation Plan (SIP) 

revision submitted by Georgia 

Department of Natural Resources, 

Environmental Protection Division (GA 

EPD), dated August 11, 2022 (‘‘Haze 

Plan’’ or ‘‘2022 Plan’’), as satisfying 

applicable requirements under the 

Clean Air Act (CAA or Act) and EPA’s 

Regional Haze Rule (RHR) for the 

regional haze program’s second 

planning period. Georgia’s SIP 

submission addresses the requirement 

that states must periodically revise their 

long-term strategies (LTS) for making 

reasonable progress toward the national 

goal of preventing any future, and 

remedying any existing, anthropogenic 

impairment of visibility, including 

regional haze, in mandatory Class I 

Federal areas (hereinafter referred to as 

‘‘Class I areas’’). The SIP submission 

also addresses other applicable 

requirements for the second planning 

period of the regional haze program. 

EPA is taking this action pursuant to 

sections 110 and 169A of the Act. 

DATES: This rule is effective December 

23, 2024. 

ADDRESSES: EPA has established a 

docket for this action under Docket 

Identification No. EPA–R04–OAR– 

2023–0220. All documents in the docket 

are listed on the regulations.gov 

website. Although listed in the index, 

some information may not be publicly 

available, i.e., Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically through 

www.regulations.gov or in hard copy at 

the Air Regulatory Management Section, 

Air Planning and Implementation 

Branch, Air and Radiation Division, 

U.S. Environmental Protection Agency, 

Region 4, 61 Forsyth Street SW, Atlanta, 

Georgia 30303–8960. EPA requests that, 

if at all possible, you contact the person 

listed in the FOR FURTHER INFORMATION

CONTACT section to schedule your 

inspection. The Regional Office’s 

official hours of business are Monday 

through Friday, 8:30 a.m. to 4:30 p.m., 

excluding Federal holidays. 

FOR FURTHER INFORMATION CONTACT: 

Estelle Bae, Air Permitting Section, Air 

Planning and Implementation Branch, 

Air and Radiation Division, Region 4, 

U.S. Environmental Protection Agency, 

61 Forsyth Street SW, Atlanta, Georgia 

30303–8960. The telephone number is 

(404) 562–9143. Ms. Bae can also be 

reached via electronic mail at 

bae.estelle@epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. Background 

On August 11, 2022, GA EPD 

submitted a revision to its SIP to 

address regional haze for the second 

planning period.1 2 GA EPD made this 

SIP submission to satisfy the 

requirements of the CAA’s regional haze 

program pursuant to CAA sections 169A 

and 169B and 40 Code of Federal 

Regulations (CFR) 51.308. EPA has 

determined that the Georgia regional 

haze SIP submission for the second 

planning period meets the applicable 

statutory and regulatory requirements 

and is thus approving Georgia’s 

submission into its SIP. 

Through a notice of proposed 

rulemaking (NPRM), published on June 

3, 2024 (89 FR 47481), EPA proposed to 

approve Georgia’s Haze Plan as 

satisfying the regional haze 

requirements for the second planning 

period contained in the CAA and 40 

CFR 51.308. EPA described its rationale 

for proposing approval of the Haze Plan 

in the June 3, 2024, NPRM. Comments 

on the June 3, 2024, NPRM were due on 

or before July 3, 2024. EPA received two 

sets of comments on the NPRM. One set 

of comments received is not relevant to 

this action, and the other set of 

comments is addressed below. Both sets 

of comments are available in the docket 

for this action. 

II. Response to Comments 

In response to the NPRM, EPA 

received a comment letter signed by the 

National Parks Conservation 

Association (NPCA), Sierra Club, the 

Coalition to Protect America’s National 

Parks, and the Southern Environmental 

Law Center. Collectively, these groups 

will be referred to as the ‘‘Commenters.’’ 

In general, the Commenters state in their 

comment letter that Georgia, in its SIP 

submittal, and EPA, in its proposed 

approval of the SIP submittal, failed to 


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3Areas statutorily designated as mandatory Class 

I Federal areas consist of national parks exceeding 

6,000 acres, wilderness areas and national memorial 

parks exceeding 5,000 acres, and all international 

parks that were in existence on August 7, 1977. 

CAA 162(a). There are 156 mandatory Class I areas. 

The list of areas to which the requirements of the 

visibility protection program apply is in 40 CFR 

part 81, subpart D. 

4Exhibit 10 of the Conservation Groups’ 

comments contains the May 12, 2021, letter 

regarding the VISTAS regional haze modeling for 

the second planning period. 

5 ‘‘Modeling Guidance for Demonstrating Air 

Quality Goals for Ozone, PM2.5 and Regional Haze,’’ 

EPA 454/R–18–009, November 29, 2018, (hereafter 

‘‘2018 Modeling Guidance’’) is available at: https:// 

www.epa.gov/sites/default/files/2020-10/ 

documents/o3-pm-rh-modeling_guidance-2018.pdf. 

6The April 3, 2018, Quality Assurance Project 

Plan for the VISTAS II Regional Haze Project is 

located in Appendix A–1 of the Haze Plan. 

7See 2018 Modeling Guidance at p. 103. 

8 IMPROVE visibility monitoring data is available 

at: https://vista.cira.colostate.edu/Improve/. 

satisfy the requirements of the Act and 

the RHR. The Commenters thus request 

that EPA disapprove Georgia’s SIP 

revision. Summaries of the significant 

comments received from the 

Commenters and EPA’s responses to 

these comments are below. 

Comment 1: The Commenters state 

that in 2021 they informed the Visibility 

Improvement State and Tribal 

Association of the Southeast (VISTAS) 

and EPA via letter of ‘‘significant errors’’ 

in the visibility modeling conducted by 

VISTAS for the VISTAS states— 

including Georgia—and that EPA did 

not acknowledge these errors in the 

NPRM. These alleged errors are 

addressed in Comments 1.a through 1.c 

below. 

Comment 1a: The Commenters 

contend that the VISTAS modeling 

significantly underpredicted the 

contribution of sulfates to visibility 

impairment at Class I areas on the 20 

percent most impaired days and that 

this underprediction, while prevalent 

across all seasons, was largest during 

the summer months.3 The Commenters 

also assert that these errors resulted in 

the modeling not meeting VISTAS’ 

model performance goals and modeling 

acceptance criteria for a number of Class 

I areas. The Commenters further assert 

that although Georgia claims that it 

corrected for this underprediction 

through the use of relative response 

factors (RRFs), neither Georgia nor EPA 

assessed whether use of RRFs 

adequately corrected for errors in the 

modeling. 

Response 1.a: Regarding the 2021 

letter described by the Commenters,4

EPA disagrees with the Commenters 

that there are significant flaws in 

Georgia’s 2028 visibility modeling that 

resulted in excluding major sources of 

haze-forming pollution from evaluation 

via Four-Factor Analyses (FFAs) for the 

second planning period. As the 

Commenters state, Georgia relied upon 

the photochemical visibility modeling 

performed by VISTAS to project the 

impact of the State’s 2028 sulfur dioxide 

(SO2) and nitrogen oxide (NOX) 

emissions on visibility in both in-state 

and out-of-state Class I areas. VISTAS 

performed the modeling in accordance 

with the principles described within 

EPA’s ‘‘Modeling Guidance for 

Demonstrating Air Quality Goals for 

Ozone, PM2.5 and Regional Haze’’ (2018 

Modeling Guidance).5 In 2018, EPA 

approved 6 the Quality Assurance 

Project Plan prepared by VISTAS for 

performing the modeling and also 

reviewed and provided comments on 

the VISTAS Modeling Protocol. EPA 

also reviewed the VISTAS final 

modeling reports and data relied upon 

by Georgia and found them acceptable. 

The Commenters assert that, due to 

errors, the modeling failed to meet 

VISTAS’ model performance goals and 

modeling acceptance criteria for a 

number of Class I areas. Specifically, the 

Commenters assert that the VISTAS 

modeling significantly underpredicted 

the contribution of sulfate to visibility 

impairment on the 20 percent most 

impaired days and that the largest 

underprediction was during the summer 

months when visibility is most 

problematic at Class I areas. Figure 6– 

7 in Georgia’s Haze Plan shows the 

results of the normalized mean bias and 

normalized mean error statistical model 

performance tests for sulfates. 

Model bias and error, either high or 

low, is not uncommon in photochemical 

modeling analyses due to uncertainties 

in model inputs and the scientific 

model formulation, and the fact that all 

air quality models are simplified 

approximations of the complex 

phenomena of atmospheric chemistry, 

fate, and transport of pollutants. Section 

6.0 of EPA’s 2018 Modeling Guidance 

discusses uncertainties that may affect 

model results and provides 

recommendations to mitigate modeling 

bias and uncertainty. Georgia 

acknowledges that model performance 

is biased low on the 20 percent most 

impaired days and provided an 

explanation of why this modeling was 

appropriate for its regulatory 

determinations in the Haze Plan. 

Georgia references the 2018 Modeling 

Guidance, which states that it is not 

appropriate to use a ‘‘bright-line test’’ 

for distinguishing between adequate and 

inadequate photochemical model 

performance for a single performance 

test statistic. EPA’s 2018 Modeling 

Guidance instead recommends using a 

‘‘weight of evidence’’ approach for 

evaluating model performance 

holistically. 

As discussed in Section 5.2(d) of 

EPA’s ‘‘Guideline on Air Quality 

Models’’ contained in 40 CFR part 51, 

Appendix W, there are no specific levels 

of any model performance metric that 

indicate acceptable model performance. 

The decision regarding acceptability is 

heavily influenced by professional 

judgment of the reviewing authority, 

which is EPA in this case. Based upon 

the overall performance of the model for 

all pollutants affecting visibility, 

considered holistically, EPA agrees with 

Georgia’s conclusions that the modeling 

is acceptable for use in the regional haze 

SIP analyses, and the model bias was 

adequately explained by Georgia and 

therefore the source selection outcomes 

using the VISTAS’ methodology were 

reasonable. 

Just as importantly, Georgia took 

appropriate steps to correct for this 

model bias. The Haze Plan explains that 

the model is applied in a relative sense 

through the calculation of RRFs 

following the procedures in 2018 

Modeling Guidance for calculating 2028 

future year visibility impacts, which 

helps alleviate concerns about the low 

bias in the sulfate model predictions. As 

described in EPA’s 2018 Modeling 

Guidance, RRFs are ‘‘the fractional 

change in air quality concentrations that 

is simulated due to emissions changes 

between a base and a future year 

emissions scenario.’’ 7

EPA agrees with Georgia that applying 

the model in a relative sense using the 

RRFs is an important tool in alleviating 

the impacts of the sulfate modeling 

underpredictions in the 2011 baseline 

year on the model projections for the 

2028 future year. Section 4.1 of the 2018 

Modeling Guidance provides a detailed 

explanation of why EPA recommends 

photochemical modeling be applied in a 

relative sense and explains that 

problems posed by model bias are 

expected to be reduced when using the 

relative approach. Section 7.2.5.1 of 

Georgia’s Haze Plan explains the 

calculation of 2028 visibility estimates 

using the RRF approaches contained in 

EPA’s 2018 Modeling Guidance. Using 

the RRF approach with an average of 

five years of Interagency Monitoring of 

Protected Visual Environments 

(IMPROVE) 8 data on the 20 percent 

most impaired days and 20 percent 

clearest days along with the relative 

percent modeled change in all of the 

particulate matter (PM) species between 

2011 and 2028 reduces the influence of 


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9See ‘‘Timeline’’ for the VISTAS II Regional Haze 

Project at: https://www.metro4-sesarm.org/content/ 

vistas-regional-haze-project-intro. 

10See ‘‘Technical Support Document for EPA’s 

Updated 2028 Regional Haze Modeling’’ at: https:// 

www.epa.gov/visibility/technical-supportdocument-epas-updated-2028-regional-hazemodeling. 

11For more information on the NEI, see: https:// 

www.epa.gov/air-emissions-inventories/nationalemissions-inventory-nei. 

12See the January 29, 2018, email from EPA 

(Richard Wayland) regarding use of a 2011 base 

year by VISTAS for regional haze in the docket for 

this rulemaking. 

13The amount of progress that is ‘‘reasonable 

progress’’ is based on applying the four statutory 

factors in CAA section 169A(g)(1) in an evaluation 

of potential control options for sources of visibility 

impairing pollutants, which is referred to as a 

‘‘four-factor analysis.’’ 

14Out-of-state Class I areas affected by Georgia 

sources are: Florida, South Carolina, North 

Carolina, and Tennessee. Figures 2–8 and 2–9 of the 

Haze Plan provide the 2014–2018 IMPROVE data 

for the VISTAS Class I areas. 

the bias in sulfate-modeled (and other 

PM species) values in the 2011 baseline 

year. The 2028 visibility impairment 

projection is derived primarily from the 

five-year average of actual IMPROVE 

monitoring data in 2009–2013 that was 

then scaled in a relative sense by the 

modeling results. If the model was being 

applied in an absolute sense, the low 

bias in the sulfate modeled values 

would have a larger impact on the 2028 

visibility projections. For these reasons, 

Georgia’s use of RRFs adequately 

minimized the impacts of model bias, 

and therefore, Georgia’s source selection 

using the VISTAS’ methodology was 

reasonable. 

Comment 1.b: The Commenters also 

discuss several other alleged 

deficiencies with VISTAS’ modeling. 

They state that VISTAS relied on an 

‘‘outdated’’ 2011 baseline year for its 

2028 future year emissions projections 

and assumed that electric generating 

units (EGUs) would operate in the exact 

same manner in 2028 as they did in 

2011. Thus, the Commenters assert that 

this model assumption is incorrect 

because EGUs are likely to have 

different load utilization in 2028 than in 

2011. 

Response 1.b: Regarding the 

Commenters’ comments about Georgia’s 

use of a 2011 base emissions inventory 

year to project emissions out to 2028 

(the end of the second planning period), 

EPA finds the 2011 baseline year 

acceptable in this instance. Although it 

is always preferable to use the most 

recent information available for 

modeling, the 2011 baseline year 

inventory used by VISTAS was the 

latest region-wide inventory available at 

the time that Georgia’s SIP submittal 

was being developed during the VISTAS 

technical work, which took place from 

December 2017 to February 26, 2021.9

In EPA’s experience, coordination 

among states such as those in the 

VISTAS region takes time, and the 

modeling involved is time-consuming, 

highly technical, and resource intensive. 

The modeling generally requires 

hundreds of hours of time to gather the 

model input data (e.g., emissions, 

meteorology, land-use, etc.), prepare 

modeling protocols, perform the 

modeling, and analyze the results. The 

computational resources to run 

photochemical models are also very 

large. ‘‘Mainframe’’ clusters of a large 

number of computer processors are 

required to run the models, and even 

using these powerful computers, it takes 

weeks of computer run-time for a fullyear model simulation. Additionally, 

EPA’s newer 2016-based modeling 

platform only became available in 

September 2019, after VISTAS had 

already invested a considerable amount 

of time and money into the regional 

haze modeling analysis.10

EPA develops the National Emission 

Inventory (NEI) suitable for use in such 

models every three years.11 By design, 

the regional haze program requires 

states to spend significant time in the 

planning phase, and this generally 

necessitates the use of a baseline year 

that is substantially earlier than the date 

the state submits its SIP to EPA. Here, 

it is reasonable that Georgia utilized the 

2011 emissions inventory year on which 

to base the technical work for the 

following reasons. There is no RHR 

requirement regarding the baseline year 

for regional photochemical modeling 

(nor is photochemical modeling 

required). GA EPD justifies the use of 

this particular baseline year and states 

that the 2011 emissions inventory was 

the most recently available quality 

assured statewide emissions inventory 

when the VISTAS project began for the 

second planning period. Moreover, prior 

to using this data, GA EPD discussed the 

selection of this baseline year emissions 

inventory and received confirmation 

from EPA to use this emissions 

inventory.12 Given the aforementioned 

reasons, EPA finds the use of the 2011 

baseline year by VISTAS, and thus 

Georgia, reasonable. 

The 2011 emissions inventory was 

used to estimate emissions of visibility 

impairing pollutants in 2028 to develop 

the 2028 projections. VISTAS applied 

reductions expected from federal and 

state regulations to the visibility 

impairing pollutants NOX, PM, and SO2. 

Georgia’s 2028 emissions projections are 

based on the State’s technical analysis 

of the anticipated emissions rates and 

level of activity for EGUs, other point 

sources, non-point sources, on-road 

sources, and off-road sources based on 

their emissions in the 2011 base year, 

considering growth and additional 

emissions controls to be in place by 

2028. In addition, the VISTAS 

emissions inventory for 2028 accounts 

for post-2011 emission reductions from 

promulgated federal, state, local, and 

site-specific control programs. 

Although Georgia used the 2011 year 

as its emissions inventory base year, as 

required by the RHR at 40 CFR 

51.308(f)(2)(iii), Georgia also examined 

more recent emissions inventory 

information for SO2 and NOX for the 

years 2017, 2018, and 2019 and 

compared these emissions to the 2028 

emission projections that were used for 

modeling purposes in Section 7.6.5 and 

Tables 7–32 and 7–33 of its Haze Plan. 

This helps to ensure that the State 

adequately considered more recent 

emissions inventory information when 

developing its LTS. The technical 

information provided in the docket 

demonstrates that the emissions 

inventory in the Haze Plan adequately 

reflects projected 2028 conditions. 

Given the aforementioned reasons, EPA 

finds the use of the 2011 baseline year 

by VISTAS (and thus Georgia) 

reasonable. 

Comment 1.c: The Commenters state 

that VISTAS used ‘‘outdated’’ 

monitoring data for its 2028 future year 

projections that did not reflect an 

observed shift in nitrate contribution to 

visibility impairment in the 

southeastern United States in the recent 

past. Consequently, the Commenters 

assert that Georgia improperly excluded 

major sources of haze-forming pollution 

from FFAs.13

Response 1.c: Regarding the 

Commenters’ claims that the 2009–2013 

modeling base period did not reflect 

more recent changes in nitrate 

contributions, EPA discussed its views 

on this issue in detail in the NPRM. 

Nitrates are also discussed in Response 

3, below. EPA agrees that after the 

2009–2013 timeframe, nitrate impacts 

have become more significant on some 

of the 20 percent most impaired days, 

especially taking into account the 

significant decrease in SO2 emissions 

and measured sulfate concentrations as 

acknowledged in the NPRM. EPA 

nonetheless agrees with Georgia’s 

conclusion that for the second planning 

period, sulfates remain the dominant 

visibility impairing pollutant at the 

Class I areas affected by Georgia, and 

therefore, it is reasonable for Georgia to 

focus on SO2 emitting sources during 

this period.14


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15See 40 CFR 51.308(f)(2)(i). 

16As explained in the July 8, 2021, EPA 

memorandum containing ‘‘Clarifications Regarding 

Regional Haze State Implementation Plans for the 

Second Implementation Period’’ (‘‘2021 

Clarifications Memo’’), a reasonable source 

selection process ‘‘should be designed and 

conducted to ensure that source selection results in 

a set of pollutants and sources the evaluation of 

which has the potential to meaningfully reduce 

their contributions to visibility impairment.’’ See 

2021 Clarifications Memo at 3 available at: https:// 

www.epa.gov/system/files/documents/2021-07/ 

clarifications-regarding-regional-haze-stateimplementation-plans-for-the-secondimplementation-period.pdf. 17See 89 FR 47481, 47493 (June 3, 2024); see also 

Sections 2 and 2.1 of 2021 Clarifications Memo. 18The State’s use of a four percent AoI threshold 

for out-of-state sources is discussed below in 

Response 2.a. 19Both of these approaches (AoI and PSAT) are 

example methods in EPA’s August 20, 2019, 

guidance titled: ‘‘Guidance on Regional Haze State 

Implementation Plans for the Second 

Implementation Period’’ (‘‘2019 Guidance’’) which 

is available at: https://www.epa.gov/sites/default/ 

files/2019-08/documents/8-20-2019_-_regional_

haze_guidance_final_guidance.pdf. See subsection 

‘‘b) Estimating baseline visibility impacts for source 

selection’’ on pages 12–15 of the 2019 Guidance. 

PSAT is a type of photochemical modeling which 

is item 4 on page 13 of the 2019 Guidance. VISTAS’ 

AoI analyses involve items 1–3 on page 13 of the 

2019 Guidance. 

20No sources met Georgia’s Nitrate PSAT 

threshold of greater than or equal to one percent on 

the 20 percent most impaired days. 

Comment 2: The Commenters assert 

that Georgia’s source selection process 

was unreasonable and too restrictive, 

based, in part, on their concerns 

summarized in Comment 1. 

Additionally, the Commenters state that 

Georgia’s use of VISTAS’ multi-step 

source screening process using Area of 

Influence (AoI) and Particulate Matter 

Source Apportionment Technology 

(PSAT) analysis was unreasonable. They 

therefore contend that EPA’s proposal to 

approve the State’s source selection 

method is arbitrary and capricious. The 

Commenters’ specific comments on this 

topic are addressed in Comments 2.a 

through 2.f, below. 

Comment 2.a: The Commenters also 

claim that the State employed 

unreasonably high source selection 

thresholds for AoI, which were too 

restrictive and resulted in the 

identification of only five sources at that 

step. The Commenters assert that by 

using a percentage source selection 

threshold (for AoI and PSAT), the 

calculated threshold in absolute 

visibility impact terms was higher for 

Class I areas with the most severe 

visibility impairment. This in turn, they 

contend, meant that fewer sources were 

identified at the AoI step for Class I 

areas with the worst visibility 

impairment. The Commenters state that 

for the areas with the worst visibility 

impairment, more sources should be 

selected to make progress toward the 

natural visibility goal. In addition, the 

Commenters assert that neither Georgia 

nor EPA provide any justification for 

doubling the AoI threshold for out-ofstate sources compared to in-state 

sources. 

Response 2.a: Concerning the 

Commenters’ argument that the State’s 

source selection threshold is 

unreasonable, as explained in the 

NPRM, the RHR does not require states 

to consider controls for all sources, all 

source categories, or any or all sources 

in a particular source category. Nor does 

the RHR expressly specify criteria for 

minimum source selection thresholds. 

These flexibilities are, however, not 

unbounded. The RHR requires that 

‘‘[t]he State should consider evaluating 

major and minor stationary sources or 

groups of sources, mobile sources, and 

area sources. The State must include in 

its implementation plan a description of 

the criteria it used to determine which 

sources or groups of sources it evaluated 

and how the four factors were taken into 

consideration in selecting the measures 

for inclusion in its long-term 

strategy.’’ 15 In addition, the technical 

basis for source selection must also be 

documented, as required by 40 CFR 

51.308(f)(2)(iii). Thus, states must 

utilize a reasonable source selection 

methodology,16 and whatever choices 

states make regarding source selection 

should be reasonably explained.17

Georgia met these requirements. 

Specifically, Georgia discussed the 

criteria it used to determine which 

sources or groups of sources were 

evaluated by the State, including the use 

of AoI analysis, photochemical 

modeling (e.g., PSAT), and associated 

source selection thresholds for AoI and 

PSAT tagging in its Haze Plan. Georgia 

documented its use of these approaches 

in extensive detail within Section 7.5 of 

the Haze Plan and Appendices D–1 and 

D–2 of the Haze Plan (relating to AoI 

analysis) and Section 7.6 of the Haze 

Plan and Appendices E–1a, E–1b, E–2a, 

E–2b, E–2c, E–2d, E–2e, E–2f, E–3, E–4, 

E–5, E–6, E–7a, E–7b, and E–8 of the 

Haze Plan (relating to PSAT modeling). 

Georgia’s documentation adequately 

demonstrates why its source selection 

methodology—including the use of an 

AoI threshold of two percent 18 for instate sources for follow-up PSAT 

tagging, and a one percent PSAT 

threshold on a pollutant-by-pollutant 

basis for source selection—is 

reasonable. For the reasons stated in the 

NPRM (89 FR 47497), EPA finds that 

Georgia’s source selection methodology 

was reasonable and resulted in the 

selection of a reasonable set of sources 

contributing to visibility impairment at 

Class I areas affected by Georgia’s 

sources. The State’s methods for 

selecting sources for a control analysis 

and the State’s AoI and PSAT analyses 

identified sources in Georgia having the 

highest impact on visibility at Class I 

areas at the end of the second planning 

period and identified sources outside of 

Georgia having the largest impacts on 

visibility at Class I areas in the State. A 

specific source selection approach is not 

required by the RHR.19

The results of this methodology were 

reasonable as well. On the whole, SO2

emissions from the three in-state 

sources selected by Georgia for FFAs— 

Georgia Power Company’s Plant Bowen 

(‘‘Plant Bowen’’), International Paper’s 

Savannah Mill (‘‘IP-Savannah’’), and 

Brunswick Cellulose—are projected to 

impact visibility at Class I areas as 

described in Table 1 below.20

TABLE 1—SULFATE PSAT CONTRIBUTIONS (%) FOR PLANT BOWEN, IP-SAVANNAH, AND BRUNSWICK CELLULOSE AT

CLASS I AREAS ON 20% MOST IMPAIRED DAYS * 

Class I area ** Plant Bowen IPSavannah 

Brunswick 

Cellulose 

Cohutta National National Wilderness Area (Cohutta) (GA) ............................................................... 2.13 .................... ....................

Okefenokee National Wilderness Area (Okefenokee) (GA) ................................................................ 2.30 1.04 ....................

Wolf Island National Wilderness Area (Wolf Island) (GA) *** .............................................................. 2.33 1.54 1.76 

Chassahowitzka National Wilderness Area (FL) ................................................................................. 2.28 .................... ....................

St Marks National Wilderness Area (FL) ............................................................................................. 4.89 .................... ....................

Linville Gorge National Wilderness Area (NC) .................................................................................... 1.13 .................... ....................

Shining Rock National Wilderness Area (NC) ..................................................................................... 1.29 .................... ....................

Swanquarter National Wilderness Area (NC) ...................................................................................... 1.03 .................... ....................


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21These percentages were calculated by dividing 

the ‘‘GA’’ column by the ‘‘Projected 2028 20% Most 

Impaired Days Column’’ and multiplying by 100. 

TABLE 1—SULFATE PSAT CONTRIBUTIONS (%) FOR PLANT BOWEN, IP-SAVANNAH, AND BRUNSWICK CELLULOSE AT

CLASS I AREAS ON 20% MOST IMPAIRED DAYS *—Continued 

Class I area ** Plant Bowen IPSavannah 

Brunswick 

Cellulose 

Cape Romain National Wilderness Area (SC) .................................................................................... 3.53 1.28 ....................

Joyce Kilmer-Slickrock National Wilderness Area (TN and NC) ........................................................ 1.11 .................... ....................

* Note that fields in the above table left blank indicate that visibility impacts are below one percent. 

** The Class I areas listed in Table 1, above, are included because the Georgia facilities in this table have a sulfate PSAT contribution of one 

percent or more at one or more of these areas. 

*** Wolf Island has no IMPROVE monitor. Visibility at Wolf Island is assumed to be the same as the nearest Class I area monitor located at 

Okefenokee. 

Although these three sources are the 

largest contributors within Georgia to 

visibility impairment at Class I areas, 

Table 1 shows Sulfate PSAT visibility 

impacts from these sources range from 

approximately one to five percent at the 

selected Class I areas. This is due to the 

fact that most anthropogenic impacts to 

visibility at these Class I areas come 

from outside of Georgia. In fact, they 

primarily come from outside of the 

VISTAS states. This is illustrated in 

Table 7–4 of the Haze Plan, which 

provides the contributions from 2028 

SO2 and NOX emissions to visibility 

impairment from all source sectors for 

the 20 percent most impaired days in 

units of inverse megameters (Mm¥1). 

The entries in Table 2, below, show the 

contributions made from Georgia, all 

other VISTAS states, and other Regional 

Planning Organizations to Georgia’s 

Class I areas. 

TABLE 2—CONTRIBUTIONS OF 2028 SO2 AND NOX EMISSIONS FROM ALL SOURCE SECTORS TO VISIBILITY IMPAIRMENT

FOR THE 20 PERCENT MOST IMPAIRED DAYS FOR CLASS I AREAS IN GEORGIA

[Mm¥1] * 

Class I area ** 

Projected 2028 

impairment on 

20% most 

impaired days 

GA 

All other 

VISTAS 

states 

CENRAP 

region *** 

LADCO 

region *** 

MANE–VU 

region *** 

WRAP region within 

VISTAS modeling 

domain *** 

COHU ................................. 45.28 1.04 5.19 1.76 6.88 0.87 2.30 

OKEF ................................. 54.66 2.17 7.57 2.27 3.60 1.01 2.84 

WOLF ................................. 53.59 2.57 6.56 2.15 3.44 1.15 3.41 

* As noted in Georgia’s Haze Plan, the columns to the right of ‘‘Projected 2028 Impairment on 20% Most Impaired Days’’ do not add up to the 

values in the ‘‘Projected 2028 Impairment on 20% Most Impaired Days’’ column due to international emissions and boundary emissions. 

** ‘‘COHU’’ refers to Cohutta; ‘‘OKEF’’ refers to Okefenokee; and ‘‘WOLF’’ refers to Wolf Island. 

*** ‘‘CENRAP’’ refers to Central Regional Air Planning Association (which is associated with the Central States Air Resource Agencies 

(CENSARA)); ‘‘LADCO’’ refers to Lake Michigan Air Directors Consortium; ‘‘MANE–VU’’ refers to Mid-Atlantic/Northeast Visibility Union; ‘‘WRAP’’ 

refers to Western Regional Air Partnership. See also: https://www.epa.gov/visibility/visibility-regional-planning-organizations. 

Table 2, above, illustrates that 

Georgia’s in-state emissions account for 

a relatively small fraction of total 

visibility impairment at Georgia’s Class 

I areas. This fraction is approximately 

2.29 percent for Cohutta, 3.97 percent 

for Okefenokee, and 4.79 percent for 

Wolf Island.21

Likewise, the PSAT Tag Results 

spreadsheet in Appendix E–7A of the 

Haze Plan shows the visibility impacts 

on a facility-by-facility basis due to SO2

emissions. Specifically, Appendix E–7A 

shows the following SO2 visibility 

impacts to Georgia’s Class I areas on the 

20 percent most impaired days in units 

of Mm¥1. 

TABLE 3—SO2 VISIBILITY IMPACTS TO GEORGIA CLASS I AREAS ON THE 20 PERCENT MOST IMPAIRED DAYS

[Mm¥1] 

Class I area Plant Bowen 

contribution 

IP-Savannah 

contribution 

Brunswick 

Cellulose to 20% 

contribution 

Total of 

Georgia 

selected 

sources 

Georgia total 

contribution 

All sources 

(including 

out-of-state) 

contribution 

COHU ................................................. 0.282 0.038 0.002 0.322 0.803 15.6 

OKEF ................................................. 0.308 0.140 0.077 0.525 1.669 16.4 

WOLF ................................................. 0.302 0.200 0.228 0.458 2.124 16.2 

The above data in Table 3 further 

supports that Georgia’s source selection 

thresholds and source selection 

methodology were reasonable. 

Specifically, on the 20 percent most 

impaired days, Georgia’s selected instate sources are responsible for 

approximately 40 percent of Georgia’s 

total in-state SO2 visibility impairment 

at Cohutta, 31.5 percent of total in-state 

SO2 visibility impairment at 

Okefenokee, and 21.6 percent of total inVerDate Sep<11>2014 16:40 Nov 20, 2024 Jkt 265001 PO 00000 Frm 00016 Fmt 4700 Sfmt 4700 E:\FR\FM\21NOR1.SGM 21NOR1

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22These percentages were calculated by dividing 

the ‘‘Total of Selected Georgia Sources’’ column by 

the ‘‘Georgia Total Contribution’’ column and 

multiplying by 100. 23See Haze Plan Section 7.6. 24 40 CFR 51.308(f)(2)(ii). 

state SO2 visibility impairment at Wolf 

Island.22 States are not required by the 

RHR to select every source in the state, 

and the state selected the in-state 

sources with the largest visibility 

impacts on in-state and nearby Class I 

areas. The selection of the above sources 

captured sufficient visibility-impairing 

emissions to allow Georgia to ensure 

that FFAs conducted for this planning 

period had the potential to meaningfully 

reduce emissions (and thus, associated 

visibility impacts at Class I areas) from 

in-state sources. 

Table 3 also shows that most 

emissions of visibility-impairing 

sulfates that impact Georgia’s Class I 

areas on the 20 percent most impaired 

days are emitted from outside of 

Georgia. The same general pattern holds 

for the 20 percent least impaired days as 

well. Georgia does not have jurisdiction 

through its SIP to regulate sources 

outside of state boundaries. Georgia did, 

however, request FFAs from other states 

for an additional 14 facilities outside of 

Georgia through the interstate 

consultation process.23 The ‘‘regional’’ 

nature of the regional haze program 

necessarily requires Georgia to rely on 

reasonable progress made by other 

states, just as other states must rely on 

Georgia to make reasonable progress. 

The Commenters also argue that 

neither Georgia nor EPA provided 

justification for doubling the AoI 

threshold for out-of-state sources. In its 

Haze Plan, Georgia explained that use of 

an AoI contribution of four percent or 

more to tag sources for PSAT captures 

large sources outside of Georgia. When 

selecting out-of-state sources, 40 CFR 

51.308(f)(2)(ii) applies. 40 CFR 

51.308(f)(2)(ii) requires states to 

‘‘consult with those States that have 

emissions that are reasonably 

anticipated to contribute to visibility 

impairment in the mandatory Class I 

Federal area.’’ The use of the four 

percent AoI threshold allowed Georgia 

to identify ‘‘emissions that are 

reasonably anticipated to contribute to 

visibility impairment’’ 24 at Class I areas 

within Georgia that are emitted from 

out-of-state, and indeed, using this 

methodology combined with follow-up 

PSAT tagging and modeling, Georgia 

sought interstate consultation for 14 

such sources. 

Turning to the Commenters’ other 

source selection comments, they assert 

that by using a percentage threshold for 

AoI and PSAT, the calculated threshold 

in absolute visibility impact terms was 

higher for Class I areas with the most 

severe visibility impairment, which 

resulted in fewer sources being 

evaluated for reasonable progress for the 

most visibility-impaired Class I areas. 

Thus, the Commenters assert that the 

use of a percentage threshold was 

unreasonable. 

EPA disagrees. Regardless of whether 

a relative or absolute threshold is used, 

the number of sources selected depends 

on the chosen value of the threshold. A 

percentage threshold, rather than one 

using inverse megameters or deciviews, 

may capture more sources at areas with 

less visibility impairment or areas 

where no or few sources exceed an 

absolute visibility impairment 

threshold. When using an absolute 

value threshold instead of a percentage 

threshold, Class I areas with less 

visibility impairment might not have 

any sources selected at all that impact 

those areas. Thus, in general, the use of 

a percentage threshold is consistent 

with the requirement to make 

reasonable progress toward remedying 

visibility impairment in each Class I 

area. As noted above, states have 

flexibility to adopt any source selection 

methodology so long as the 

methodology is reasonable, and the 

states’ choices are reasonably explained. 

EPA finds that Georgia’s source 

selection method is reasonable and 

adequately explained for the reasons 

discussed above. 

Comment 2.b: The Commenters also 

state in their comments that VISTAS 

considered sulfate and nitrate separately 

in model analyses, which the 

Commenters allege does not align with 

how these pollutants actually function 

in the atmosphere. They state that 

sulfate and nitrate act in combination in 

the atmosphere, along with other haze 

precursors, to contribute to visibility 

impairment. As a result, they argue that 

VISTAS likely underestimated the 

overall visibility impact of individual 

sources in its PSAT analysis. 

Response 2.b: Regarding the 

Commenters’ assertion that VISTAS 

considered sulfate and nitrate separately 

in model analyses, which led to 

underestimating the visibility impacts 

in the PSAT analyses, EPA disagrees. In 

the AoI screening analysis, VISTAS 

used the combined sulfate plus nitrate 

values to select sources to tag for the 

refined PSAT source apportionment 

modeling analyses. Section 7.5.5 of the 

Haze Plan explains how Georgia used 

the results of the AoI analysis to select 

sources for further evaluation with 

PSAT. This section shows that facilities 

contributing more than two percent (instate) or four percent (out-of-state) of 

sulfate plus nitrate were selected for 

PSAT tagging. See Tables 7–8 through 

7–10 for the specific sources with 

sulfate plus nitrate values greater than 

Georgia’s AoI source selection 

thresholds. 

Also, contrary to the Commenters’ 

assertion, sulfates and nitrates were 

modeled together in the PSAT modeling 

with the other PM species that impact 

visibility (e.g., direct PM, organic 

carbon, elemental carbon, etc.). Section 

7.6.2 of Georgia’s Haze Plan summarizes 

the results of the PSAT modeling. This 

section states that: ‘‘The adjusted PSAT 

results were used to calculate the 

percent contribution of each tagged 

facility to the total sulfate and nitrate 

point source (EGU + non-EGU) 

contribution at each Class I area.’’ 

Tables 7–16 through 7–18 contain the 

specific PSAT results for each of 

Georgia’s Class I areas. It is true that 

Georgia considered the PSAT modeled 

results for sulfate and nitrate separately 

to compare against its selected one 

percent threshold to identify a 

reasonable number of sources for 

reasonable progress analyses. EPA 

agrees with the State that this approach 

is reasonable for the reasons discussed 

above and was adequately justified in 

the Haze Plan. 

Comment 2.c: The Commenters state 

that VISTAS used an outdated 2028 

emissions projection to ‘‘tag’’ sources. 

They note that although VISTAS 

documented that the initial 2028 

emission inventory projections were 

updated for the final modeling, the 

associated PSAT modeling did not use 

the final 2028 inventory. The 

Commenters state that VISTAS scaled 

predicted sulfate and nitrate to the 

corresponding changes in SO2 and NOX

emissions using a linear relationship 

between SO2 and NOX emissions and 

sulfate and nitrate concentrations. They 

argue that there is a non-linear 

relationship between emissions and 

sulfate/nitrate concentrations. These 

factors all are argued by the 

Commenters to have introduced errors 

into the VISTAS modeling. Moreover, 

the Commenters argue the PSAT tagging 

process was entirely unnecessary, as the 

AoI step would have already identified 

the sources that contributed to 

impairment at Class I areas. 

Response 2.c: VISTAS used the 

original 2028 emissions inventory to 

perform the PSAT modeling and the 

original PSAT results were linearly 

scaled to reflect the updated 2028 

emissions. Although linear scaling 

introduces some uncertainty to the final 

PSAT results, EPA agrees with VISTAS 

and Georgia that adjusting the results to 

account for VISTAS’ updated 2028 


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25 ‘‘Clarification on the Development of Modeled 

Emission Rates for Precursors (MERPs) as a Tier 1 

Demonstration Tool for Ozone and PM2.5 under the 

PSD Permitting Program,’’ April 30, 2024, 

Memorandum from Tyler Fox to Regional Office 

Modeling Contacts is available at: https://

www.epa.gov/sites/default/files/2020-09/ 

documents/epa-454_r-19-003.pdf. 

26See https://www.epa.gov/cmaq for further 

information on CMAQ. 

27See 40 CFR 51.308(f)(2)(i), (iii); 89 FR 47481, 

47493 (June 3, 2024); see also Sections 2 and 2.1 

of 2021 Clarifications Memo. 

28EPA’s 2019 Guidance, pages 12–14, describe 

components of Georgia’s AoI approach, including 

Q/d, trajectory analyses, residence time analyses, 

and source apportionment photochemical modeling 

(e.g., CAMx PSAT). 

29See e.g., 77 FR 1163 published February 27, 

2012, for a description of Georgia’s AoI approach 

in the first planning period. On May 4, 2018, EPA 

fully approved Georgia’s first period regional haze 

plan, effective June 4, 2018. See 83 FR 19637. 

30EPA’s regulations define ‘‘Federal Land 

Manager’’ as ‘‘the Secretary of the department with 

authority over the Federal Class I area (or the 

Secretary’s designee) or, with respect to RooseveltCampobello International Park, the Chairman of the 

Roosevelt-Campobello International Park 

Commission.’’ See 40 CFR 51.301. The U.S. 

National Park Service (NPS), U.S. Fish and Wildlife 

Service (FWS), and U.S. Forest Service (USFS) are 

collectively referred to as the ‘‘Federal Land 

Managers’’ or ‘‘FLMs’’ throughout this document. 

31Conservation Groups cite to the FLAG 

Guidance at 2024 Kordzi Report at pp. 7–10. 

32The Plume Visibility Model ‘‘PLUVUE’’ is used 

for estimating visual range reduction and 

atmospheric discoloration caused by plumes 

resulting from the emissions of particles, nitrogen 

oxides, and sulfur oxides from a single source. See 

‘‘PLUVUE II’’ at: https://www.epa.gov/scram/airquality-dispersion-modeling-alternative-models. 

The User’s Guide is available at: https://gaftp.

epa.gov/Air/aqmg/SCRAM/models/other/pluvueii/ 

PluvueUG.pdf. 

emissions inventory using linear scaling 

is a reasonable approach to account for 

VISTAS’ updated 2028 emissions 

projections and is a better approach 

than relying on the original PSAT 

modeling. Linear scaling of 

photochemical modeling results to 

account for changes in emissions is, in 

most cases, reasonable and is an 

accepted practice by EPA. As an 

example, EPA guidance recommends 

using EPA’s Modeled Emission Rates for 

Precursors (MERPs) for evaluating 

secondary particulate matter of 2.5 

micrometers or less in diameter (PM2.5) 

impacts in Prevention of Significant 

Deterioration (PSD) modeling analyses 

and allows for and recommends scaling 

of photochemical modeling results 

based on emissions.25 This guidance 

recommends an approach where the 

PM2.5 impacts are estimated using an 

archived national-scale photochemical 

modeling analysis, performed using 

Comprehensive Air Quality Model with 

Extensions (CAMx) and Community 

Multiscale Air Quality (CMAQ) 26

photochemical models, that uses 

hypothetical emissions sources, and 

then linearly scaling the photochemical 

modeling results using the ratio of the 

PSD project-specific source emissions to 

the modeled emissions from the 

hypothetical source (see Equation 1 on 

page 3 of the referenced April 30, 2024, 

MERPs memorandum). This approach is 

widely used and accepted by state air 

quality agencies and EPA to account for 

secondarily formed PM2.5 from 

precursor emissions (SO2 and NOX) for 

PSD modeling analyses. Since the 

VISTAS analyses used for regional haze 

modeling use linear scaling with CAMx 

and for the same PM2.5 precursors (SO2

and NOX) as the MERPs analyses, EPA 

finds the method of linear scaling of PM 

precursor emissions conducted by 

VISTAS to be acceptable practice. 

Regarding the Commenters’ assertion 

that the PSAT tagging process was 

unnecessary because the AoI step 

already identified the sources that 

contributed to impairment at Class I 

areas, EPA disagrees with the premise of 

this comment. The standard is not 

whether the state’s source selection 

approach is necessary or required, but 

rather, whether the approach is 

reasonable and is reasonably 

explained.27 The two-step process of 

screening with the AoI analysis and 

then applying the more refined PSAT 

source apportionment modeling to 

sources that met the initial AoI 

screening criteria is a sound technical 

approach for identifying sources to 

evaluate for reasonable progress. 

Elements of Georgia’s AoI approach are 

discussed in EPA’s 2019 Guidance as a 

viable method to assess sources’ 

visibility impacts to Class I areas.28

Georgia, along with many of the VISTAS 

states, also relied upon the AoI initial 

screening approach in its first planning 

period Haze Plan.29 VISTAS used the 

AoI analysis as an initial screening step 

because it is a much simpler and less 

resource intensive approach than using 

PSAT tagging to model hundreds to 

thousands of potential sources. The AoI 

screening approach identified a smaller 

subset of sources that could undergo 

refined analysis using PSAT modeling. 

EPA finds the two-step process of first 

screening with the AoI analysis 

followed by use of the more refined 

PSAT source apportionment modeling 

to sources is valid and reasonable. Also, 

as discussed above, states have 

discretion under the RHR regarding 

choice of source selection methodology. 

Georgia’s approach is acceptable for 

these reasons. 

Comment 2.d: The Conservation 

Groups note that Georgia relied on the 

PSAT modeling results for its multiple 

in-state sources that are located less 

than 50 kilometers (km) from a Class I 

areas and claim that PSAT modeling has 

been shown to be unreliable for sources 

that are within a short distance from a 

Class I area, referencing Federal Land 

Manager (FLM) 30 guidance that 

addresses regional grid models. The 

Commenters assert that this caused 

Georgia to improperly screen out 

sources. Specifically, the Commenters 

argue that the FLMs’ Air Quality Related 

Values Work Group (FLAG) Guidance 

indicates that photochemical grid 

models are not the preferred model for 

evaluating visibility impacts from 

sources less than 50 km from Class I 

areas and reference the use of direct 

plume impact models.31 According to 

the Conservation Groups, this guidance 

shows that regional grid models are not 

preferred for sources located close to 

Class I areas and that the grid size used 

by VISTAS is too small to produce 

accurate results for those sources. 

Response 2.d: The Commenters do not 

provide any specific model performance 

information demonstrating that the 

CAMx model nor the PSAT source 

apportionment tool have poor model 

performance for evaluating visibility 

impacts from sources located within 50 

km of any of the Class I areas located in 

Georgia. 

The Commenters take the FLMs’ 

FLAG guidance out of context. The 

FLAG reference to direct plume models 

(e.g., Plume Visibility Model) 32 is for 

evaluating visibility impacts under the 

New Source Review (NSR)/PSD 

permitting regulations and not for 

regional haze analyses. EPA’s regional 

haze regulations do not require 

evaluations of direct plume impacts 

separate from the photochemical 

modeling analyses used for regional 

haze visibility analyses. 

The Commenters assert that since the 

horizontal grid size used in the VISTAS 

CAMx modeling was 12 km, it is 

insufficient to resolve the details of 

emissions plumes from facilities within 

50 km of a Class I area and that the 

model performance degrades 

substantially at close-in distances. The 

general statement from the Commenters 

that model performance substantially 

degrades within 50 km is not supported 

by any specific evidence in the 

comments. Moreover, the Commenters’ 

position is belied by the fact that one of 

the three sources selected by Georgia— 

Brunswick Cellulose—is 27.9 km from 

the nearest Class I area (Wolf Island). 

EPA thus reaffirms that Georgia’s CAMx 

PSAT modeling was appropriate for 

selecting sources for reasonable progress 

analyses. 


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33This is explained in much greater detail in 

Section 7.5 of the Haze Plan. 

34 ‘‘Clarifications Regarding Regional Haze State 

Implementation Plans for the Second 

Implementation Period.’’ https://www.epa.gov/ 

system/files/documents/2021-07/clarificationsregarding-regional-haze-state-implementationplans-for-the-second-implementation-period.pdf. 

EPA Office of Air Quality Planning and Standards, 

Research Triangle Park (July 8, 2021). 

35The URP (also commonly referred to as the 

‘‘glidepath’’) is the linear rate of progress needed to 

attain natural visibility conditions, assuming a 

starting point of baseline visibility conditions in 

2004 and ending with natural conditions in 2064. 

The URP is used as a tracking metric to help States 

assess the amount of progress they are making 

toward the national visibility goal over time in each 

Class I area. See 40 CFR 51.308(f)(1)(vi). 

The Commenters separately argue that 

Georgia’s correlation analysis of the 

sulfate AoI versus PSAT presented in 

Section 7.6.3 of the Haze Plan is flawed. 

The Commenters in the Kordzi Report 

point out the scatter in the AoI/PSAT 

ratio data for distances less than 100 km 

in Figure 7–42 of the Georgia Haze Plan 

and argue this makes the State’s 

correlation conclusions invalid. Also, 

the Commenters refer to the scatter in 

the sulfate fractional bias values in 

Figure 7–43 in the Haze Plan and argue 

the AoI versus PSAT correlation is 

invalid. 

EPA disagrees. Georgia’s Figure 7–43 

has a coefficient of determination (R2) 

that appears to have a strong correlation, 

and the Commenters provided no new 

information that Georgia’s correlation 

results were flawed. While there is more 

scatter between the data points less than 

100 km from the Class I area, there is 

clearly a trend that the AoI values are 

much larger than the PSAT values 

within 100 km compared to the ratios 

for further distances. There is logic to 

this result due to the way the AoI metric 

is calculated using the Extinction 

Weighted Residence Times (EWRT) 

multiplied by the Emissions divided 

Distance (EWRTxQ/d). The EWRT is 

calculated using the frequency that 

winds (represented by Hybrid SingleParticle Lagrangian Integrated Trajectory 

(HYSPLIT) back trajectories) pass over a 

specific geographic area (represented by 

a modeling grid cell) on the path to the 

Class I area.33 For sources located less 

than 100 km from a Class I area, there 

is likely to be a higher frequency of the 

HYSPLIT back trajectories passing over 

the 12 km grid cell containing the 

source, thus the EWRT and AoI value 

will be larger. The CAMx PSAT 

modeling is a more refined 

photochemical modeling approach that 

calculates the atmospheric fate and 

transport of the PM precursors and their 

chemical reactions to form visibility 

impairing pollutants (e.g., ammonium 

sulfate). Therefore, compared to the AoI 

screening process, the refined PSAT 

technique is less likely to overestimate 

the visibility impacts for sources located 

within 100 km of the Class I area. 

Regarding the scatter of the data 

resulting in the AoI to PSAT fractional 

bias correlation, EPA acknowledges that 

there is scatter in the data which is 

reflected in the 0.72 R2 value shown in 

Figure 7–43 in the Haze Plan. However, 

this level of correlation is not 

uncommon in these types of modeling 

data analyses, and the results are 

reasonable. For these reasons, Georgia’s 

correlation approach is valid. 

The photochemical modeling 

employed by VISTAS and Georgia is the 

most refined methodology available for 

evaluating regional haze visibility 

impacts. Moreover, Georgia’s AoI 

screening process identified sources 

located within 50 km of its Class I areas, 

including the Brunswick Cellulose 

facility located approximately 30 km 

from Wolf Island that met the PSAT 

source selection criteria and underwent 

an FFA to evaluate reasonable progress. 

As discussed above, Georgia 

demonstrated in Section 7.6.3 of the 

Haze Plan that the AoI screening 

technique overestimates visibility 

impacts for sources located within 100 

km of a Class I area. Based upon this 

AoI overestimation, in Section 7.6.4 of 

the Haze Plan, Georgia explains why 

sources (with the exception of 

Brunswick Cellulose which is located 

27.9 km from Wolf Island) that are 

located less than 100 km from its Class 

I areas were not tagged for PSAT 

modeling and thus were not selected for 

FFAs. EPA finds that Georgia 

adequately justified why the other 

sources within 100 km of Class I areas 

were not selected for FFAs. 

Comment 2.e: The Commenters also 

note that EPA stated in guidance 34 that 

use of a source selection threshold that 

captures only a small portion of a state’s 

contribution to visibility impairment in 

Class I areas is more likely to be 

unreasonable. The Commenters assert 

that to ensure Georgia captured a 

meaningful portion of in-state sources, a 

different selection method with a lower 

threshold should have been used, such 

as a ‘‘Q/d’’ (emissions (Q) divided by 

distance to a Class I area (d)). The 

Commenters assert that utilizing this 

method with a threshold of five or lower 

might have resulted in up to 21 sources 

in Georgia being selected for an FFA. 

Response 2.e: Regarding the 

Commenters’ argument that the State 

should have adopted a different 

selection method (such as Q/d) with a 

lower threshold to select more sources, 

as discussed above, a state is not 

required to evaluate all sources of 

emissions in each planning period. 

Instead, a state may reasonably select a 

set of sources for an analysis of control 

measures. Selecting a set of sources for 

analysis of control measures in each 

planning period is also consistent with 

the RHR, which sets up an iterative 

planning process and anticipates that a 

state may not need to analyze control 

measures for all its sources in a given 

SIP revision. See 2019 Guidance at 9. 

Moreover, use of Q/d (which simply 

involves dividing the quantity of 

emissions by the distance to a Class I 

area) does not consider transport 

direction/pathway, dispersion and 

photochemical processes, or the 

particular days that have the most 

anthropogenic impairment due to all 

sources. 2019 Guidance at 13. Therefore, 

compared to photochemical modeling, 

using a simple Q/d technique as 

Commenters suggest would have 

resulted in a less accurate quantification 

of visibility impacts on Class I areas. As 

for the use of specific source selection 

thresholds (including Commenters’ 

suggested Q/d threshold of above five), 

as discussed in detail above, Georgia’s 

source selection methodology and 

thresholds were well documented and 

reasonable. 

Comment 2.f: The Commenters also 

assert that EPA’s position that Georgia’s 

source selection method is reasonable 

given the specific circumstances present 

in Georgia, including that Georgia is not 

contributing to visibility impairment at 

any Class I areas above the Uniform Rate 

of Progress (URP), is not a valid basis on 

which EPA can approve the State’s 

selection method.35 Specifically, the 

Commenters note that the glidepath 

(i.e., URP) is not a ‘‘Safe Harbor’’ to 

avoid requiring additional reasonable 

progress measures for Class I areas. 

Separately, the Commenters take issue 

with EPA’s statement in the NPRM that 

Georgia’s source selection methodology 

is also reasonable given the ‘‘specific 

circumstances present in Georgia’’ 

which precedes a factual recitation of 

the improvements in visibility since the 

2000–2004 baseline and Georgia’s lack 

of contribution to any Class I area above 

the URP. 

Response 2.f: EPA agrees that the URP 

is not a ‘‘safe harbor’’ to avoid requiring 

additional reasonable progress 

measures. However, being below the 

URP is relevant to whether a state needs 

to perform a ‘‘robust demonstration’’ 

based on the requirements in 40 CFR 

51.308(f)(3)(ii)(A) and 40 CFR 

51.308(f)(3)(ii)(B). Therefore, the factual 


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36 Georgia considered SO2 for FFAs conducted in 

the first planning period. 

information that all Georgia and nearby 

Class I areas are below the URP is 

needed to inform that requirement. 

Additionally, other information about 

measured progress towards natural 

conditions can be relevant in evaluating 

the source selection process and LTS. 

For example, significant improvements 

in visibility at impacted Class I areas 

since the beginning of the second 

planning period (starting in 2019) is 

relevant context to whether a state is 

making progress towards the national 

goal and how many additional sources 

needed to be analyzed in order to 

determine what is necessary for 

reasonable progress in the second 

planning period. Therefore, what 

progress the state has already achieved 

in the second planning period is a 

relevant factor that EPA may consider 

regarding the reasonableness of a state’s 

source selection thresholds. Even 

ignoring the fact that the visibility at 

Class I areas impacted by Georgia has 

greatly improved, EPA would still reach 

the same conclusion that Georgia’s 

source selection methodology and 

thresholds for this second planning 

period are reasonable for the reasons 

stated earlier in this Response. 

Comment 3: The Commenters assert 

that EPA incorrectly endorses Georgia’s 

decision to exclude consideration of 

NOX controls in any FFAs. They 

contend that VISTAS modeling did not 

accurately reflect the shift in the 20 

percent most impaired days and the 

corresponding increase in the 

contribution of nitrate to visibility 

impairment at Southeastern Class I areas 

such as Cohutta, especially in winter 

months and at coastal sites. The 

Commenters state that EPA’s 

expectation is that states will, at a 

minimum, consider both SO2 and NOX

in this planning period, and that there 

are multiple sources of significant NOX

emissions that Georgia should have 

analyzed for NOX controls. 

Response 3: EPA disagrees with this 

comment. The RHR does not prescribe 

which visibility impairing pollutants 

must be evaluated in the FFAs. EPA’s 

2019 Guidance on page 11 states: 

‘‘When selecting sources for analysis of 

control measures, a state may focus on 

the PM species that dominate visibility 

impairment at the Class I areas affected 

by emissions from the state and then 

select only sources with emissions of 

those dominant pollutants and their 

precursors.’’ Section 2.2 of EPA’s 2021 

Clarifications Memo recommends that 

states which do not evaluate SO2 and 

NOX in both source selection and 

control evaluations show why such 

consideration of these pollutants would 

be unreasonable, especially if the state 

considered both of these pollutants in 

the first planning period.36

Georgia followed these recommended 

approaches in the development of its 

Haze Plan. Georgia considered both SO2

emissions (via sulfate’s visibility 

impacts) and NOX emissions (via 

nitrate’s visibility impacts) in the source 

selection process. As part of the Haze 

Plan, GA EPD presented the results of 

PSAT modeling conducted by VISTAS 

to estimate the projected impact of 

statewide SO2 and NOX emissions 

across all emissions sectors in 2028 on 

total light extinction for the 20 percent 

most impaired days in all Class I areas 

in the VISTAS modeling domain. The 

modeling showed that SO2/sulfate 

visibility impacts from point sources 

were in general much larger than NOX/ 

nitrate impacts. Applying the modeling 

results to individual sources resulted in 

relatively large sulfate visibility impacts 

for a small number of in-state SO2

sources, but much smaller nitrate 

impacts from NOX emissions. Therefore, 

several sources were selected for SO2

control analysis determinations, but no 

sources in Georgia met the same source 

selection threshold for nitrate, and 

therefore Georgia did not select any 

sources for a NOX emissions control 

evaluation. Contrary to the Commenters’ 

assertion that Georgia made a 

‘‘decision’’ to exclude consideration of 

NOX controls in any FFA, it was 

Georgia’s objective application of its 

source selection process in combination 

with data and modeling showing that 

SO2 and not NOX is the dominant 

visibility impairing pollutant that 

resulted in Georgia selecting only 

sources for SO2 emissions control 

analyses. 

This approach was reasonable. 

IMPROVE monitoring data shows that 

ammonium sulfate remains the 

dominant visibility impairing pollutant 

at Georgia’s Class I areas as well as at 

those Class I areas outside of the State 

that are impacted by Georgia as 

discussed in Section 2.5.2 of the Haze 

Plan (particularly Figures 2–4 through 

2–6 for the 2009–2013 period and 

Figures 2–7 through 2–9 for the 2014– 

2018 period). Recent 2015–2019 

IMPROVE monitoring data cited within 

the Haze Plan identifies the relative 

contributions of PM species 

contributing to the total visibility 

impairment at the Georgia Class I areas, 

which are shown in Table 4, below. In 

spite of increased nitrate contributions 

on the 20 percent most impaired days in 

more recent years (as the Commenters 

note, often on winter days), as indicated 

in Table 4, ammonium nitrate 

contributions to regional haze at the 

State’s Class I areas remain relatively 

low at 8 to 15 percent of the total 

visibility impairment as compared to 

ammonium sulfate at 55 to 58 percent. 

TABLE 4—§2015–2019 SPECIATED IMPROVE MONITORING DATA FOR GEORGIA’S CLASS I AREAS

Ammonium 

sulfate 

(%) 

Ammonium 

nitrate 

(%) 

Organic 

carbon 

(%) 

Coarse 

mass 

(%) 

Elemental 

carbon 

(%) 

Fine 

sea salt 

(%) 

Fine 

soils 

(%) 

Cohutta ..................................................... 55 15 19 5 5 0 1 

Okefenokee .............................................. 58 8 19 6 5 2 1 

Wolf Island ............................................... 58 8 19 6 5 2 1 

Furthermore, in Tables 7–5 through 

7–7 of the Haze Plan, the State provided 

a calculation of the sulfate and nitrate 

EWRT used in the AoI analysis for 

Cohutta and Okefenokee for the 20 

percent most impaired days from 2011 

to 2016, demonstrating that the sulfate 

EWRT is significantly higher than the 

nitrate EWRT. This further supports the 

importance of focusing on SO2

emissions reductions for this planning 

period. 

The State’s rationale for focusing on 

SO2 controls in the FFAs is summarized 

in Georgia’s SIP submittal and the 

NPRM. See Haze Plan, Section 7.10; 89 

FR 47491, 47493–47494. EPA gave 

careful consideration to Georgia’s 

rationale and reaffirms that Georgia’s 

justification for not evaluating sources 

selected for SO2 emission control 


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analyses for a separate NOX emission 

control analysis is reasonably justified 

for this planning period. The trend of 

increasing nitrate contribution to 

visibility impairment as a total percent 

of all visibility impairment at Class I 

areas over time highlighted by the 

Commenters is something that will 

continue to be evaluated in future 

planning periods. If the data warrants 

further consideration of NOX/nitrate in 

future planning periods, EPA expects 

that Georgia will address potential NOX

controls in future regional haze SIP 

revisions. 

Comment 4: The Commenters assert 

that EPA ignores that Georgia 

unreasonably excluded sources from 

FFAs. The Commenters state that EPA 

must require Georgia to prepare FFAs 

for 16 additional EGU and non-EGU 

industrial sources identified by U.S. 

National Park Service (NPS) and the 

Commenters which have emissions that 

likely contribute to impairment in Class 

I areas in Georgia and other states. 

The Commenters describe four of 

these facilities in greater detail. These 

specific arguments are addressed in 

Comments 4.a through 4.c, below. 

Comment 4.a: Regarding Georgia 

Power—Plant Scherer (Plant Scherer), 

the Commenters state that this facility is 

not well controlled for NOX and that 

NOX emissions ‘‘can be cut in half at no 

capital cost whatsoever by simply 

requiring Georgia Power to operate its 

existing SCRs continuously throughout 

the year.’’ The Commenters also state 

that although the SO2 emission rate at 

each Plant Scherer unit is often very 

low, that at times the SO2 emission rates 

are as much as ten times higher, and 

that the current controls are not 

consistently achieving the level of 

control that they are capable of. 

Therefore, the Commenters assert that 

EPA must require Georgia to prepare an 

FFA for this facility. 

Response 4.a: As discussed in 

Response 2, Georgia’s source selection 

methodology was reasonable and was 

adequately documented in its Haze 

Plan. The fact that certain sources, 

including the 16 sources identified by 

the Commenters, were not selected for 

FFAs for either SO2 or NOX for this 

planning period is the result of the 

reasonable application of Georgia’s 

source selection process and source 

selection thresholds. In other words, if 

sources were selected by the State, they 

were selected because the data 

supported the selection of that source. 

The inverse is also true regarding 

sources that were not selected. As 

discussed in Response 3, NOX impacts 

were considered by the State, but no 

sources were selected for NOX controls 

(including these sources highlighted by 

the Commenters) because visibility 

impacts did not exceed the State’s 

source selection threshold. To the extent 

that the 16 sources identified by 

Commenters were not selected by 

Georgia, the Responses to Comments 2 

and 3 generally address why these 

sources were not selected and why EPA 

agrees with the State that it was 

reasonable for this planning period to 

not select these sources. To summarize, 

Georgia selected a sufficient number of 

sources under Georgia’s jurisdiction to 

ensure that sources responsible for the 

largest visibility impacts to Class I areas 

completed FFAs for this planning 

period. Georgia has discretion under the 

RHR to determine its source selection 

methodology and Georgia’s source 

selection process, and the sources that 

Georgia selected were reasonable and 

the Haze Plan complied with the CAA 

and RHR for this planning period. While 

Georgia could have used its discretion 

to select other sources in addition to 

those screened in during its source 

selection process, including some or all 

of the sources that the Commenters 

highlight, Georgia was not required to 

do so. 

Throughout the Commenters’ 

discussion of these 16 sources, however, 

the Commenters raise several additional 

points that have not yet been fully 

addressed in prior responses. Regarding 

the comment that Plant Scherer is not 

well-controlled for NOX, this was not a 

relevant consideration for Georgia’s 

source selection process. Plant Scherer 

did not meet Georgia’s two percent 

combined sulfate plus nitrate AoI 

threshold for visibility impacts and 

therefore was not selected for further 

PSAT analysis during the State’s initial 

screening process. Specifically, 

Georgia’s (through VISTAS’ modeling) 

AoI analysis found that Plant Scherer’s 

combined sulfate and nitrate impacts 

would be 0.79 percent for Cohutta, 0.71 

percent for Okefenokee, and 0.56 

percent for Wolf Island. See Haze Plan, 

Appendix E–7b. These numbers fell 

below Georgia’s two percent AoI 

threshold for visibility impacts, and 

therefore, the State did not consider this 

source for further PSAT analysis (or an 

FFA). By way of comparison, Georgia 

calculated Plant Bowen’s (another 

Georgia Power facility) combined nitrate 

and sulfate AoI impacts as 20.74 percent 

for Cohutta, 14.67 percent for 

Okefenokee, and 11.78 percent for Wolf 

Island, which is why Plant Bowen was 

considered for further PSAT tagging and 

was ultimately selected for an FFA for 

SO2, while Plant Scherer was not. EPA 

agrees with Georgia’s combined nitrate 

and sulfate AoI calculations and finds 

the State’s methodology and the results 

of this methodology reasonable. 

Regarding the Commenters’ comments 

that variability in the emissions at Plant 

Scherer warrant an emission limit of 

0.01 to 0.02 pound (lb)/million British 

thermal units (lb/MMBtu), as noted 

above, Georgia did not select Plant 

Scherer for an FFA because the 

visibility impacts from this source were 

well below Georgia’s source selection 

thresholds. As Plant Scherer was not 

selected for an FFA, consistent with the 

requirements under the RHR, Georgia 

does not have to address the limits at 

the source as suggested by the 

Commenters. 

Comment 4.b: Regarding Georgia 

Power—Plant Wansley (Plant Wansley), 

the Commenters state that while the 

facility has ceased to operate, nothing in 

the SIP submission prevents Plant 

Wansley from restarting operations with 

corresponding increases in emissions in 

the future. Separately, the Commenters 

express concerns that the 

documentation of the shutdown of Plant 

Wansley described in the NPRM does 

not adequately prevent Plant Wansley 

from restarting operations. The 

Commenters assert that this shutdown 

must be incorporated into the Haze 

Plan. 

Response 4.b: Even if EPA were to 

assume that Plant Wansley had not shut 

down, Georgia still would not have 

selected this source because the 

combined sulfate and nitrate AoI 

impacts based on VISTAS’ 2028 

projections for this facility, which 

project emissions without this 

shutdown, are 1.09 percent for Cohutta, 

0.67 percent for Okefenokee, and 0.77 

percent for Wolf Island, all of which are 

well below the State’s two percent AoI 

threshold. Therefore, even if the 

shutdown documentation for Plant 

Wansley was inadequate as asserted by 

the Commenters (which is not the case, 

as explained below), Georgia satisfied 

its RHR obligations under 40 CFR 

51.308(f)(2) and considered and 

reasonably explained the methodology 

by which it selected sources for FFAs 

that contribute to visibility impairment 

in Class I areas. 

However, Georgia did not just revoke 

the Part 70 operating permit for Plant 

Wansley as stated by the Commenters. 

Rather, Georgia’s December 28, 2022, 

letter to Georgia Power states that it 

revoked ‘‘all Georgia Air Quality 

Permits previously issued to this 

facility,’’ which would include both the 

facility’s preconstruction permits and 

the facility’s Part 70 permit that 

contains applicable requirements 

(including those originating from the 


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37 Georgia Rule 391–3–1–.03. ‘‘Permits. 

Amended’’ is available at: https://rules.sos.ga.gov/ 

GAC/391-3-1-.03. 

38See ‘‘Individual VISTAS Class I Areas Results’’ 

available at: https://www.metro4-sesarm.org/ 

content/task-5-area-influence-analysis. 

39 ‘‘Round one’’ and ‘‘Round two’’ refer to the first 

and second planning periods, respectively. 

40EPA’s ‘‘Air Pollution Control Cost Manual’’ is 

available at: https://www.epa.gov/economic-andcost-analysis-air-pollution-regulations/cost-reportsand-guidance-air-pollution. 

preconstruction permits). Restarting the 

facility—a concern raised by the 

Commenters—could not be 

accomplished without the submission of 

an application for a permit, as specified 

in Paragraph 391–3–1–.03 of the Georgia 

Rules for Air Quality Control 37 and 

issuance of an entirely new 

preconstruction permit, which would 

likely need to be a major source NSR 

permit. These major NSR permits 

generally require Best Available Control 

Technology for a PSD Permit or Lowest 

Achievable Emission Rate for a 

Nonattainment New Source Review 

permit. The Commenters appear to agree 

and state that ‘‘Any attempt to restart a 

boiler at Plant Wansley would require a 

new construction or major modification 

permit including either a prevention of 

significant deterioration (PSD) or new 

source review (NSR) analysis.’’ 

Comment 4.c: In regards to 

Transcontinental Gas Pipe Line Co., 

LLC, Compressor Station 120, the 

Commenters state that this facility 

emitted 2,283.57 tons of NOX in 2020 

and likely impacts 12 Class I areas, and 

that there are likely feasible and costeffective controls available to reduce 

this facility’s NOX emissions. Therefore, 

the Commenters assert that EPA must 

require Georgia to conduct an FFA of 

potential controls for Compressor 

Station 120. Regarding CEMEX 

Southeast, LLC, the Commenters state 

that this facility emits 1,424.37 tons per 

year (tpy) of NOX and 130.87 tpy of SO2

and likely impacts eight Class I areas, 

and that there are likely available 

controls that could reduce haze-forming 

emissions from CEMEX Southeast, LLC 

that Georgia failed to consider in its SIP 

revision. 

As for the 12 additional sources 

identified by the Commenters, all 12 of 

the listed sources have reported NOX

and/or SO2 emissions in the 2020 NEI 

and, according to the Commenters’ 

analysis, have a Q/d value above five for 

multiple Class I areas in the Southeast. 

For example, the Commenters state that 

Rome Linerboard Mill has a Q/d value 

of as high as 28.80 for Cohutta in 

Georgia and that NPS has noted in its 

consultation materials that the facility 

ranked third for haze contributions to 

VISTAS Class I areas based on 

cumulative AoI screening results and 

was in the top 80 percent of total AoI 

impact for five Class I areas. 

Additionally, Commenters assert that 

Georgia-Pacific Cedar Springs LLC is 

another paperboard mill that Georgia 

did not select but should have selected. 

The Commenters state that this facility 

emits 2,461.26 tpy of NOX and 338.2 tpy 

of SO2 and likely impacts 16 Class I 

areas. 

Response 4.c: For the same reasons as 

stated above in Responses 2 and 3 

regarding the adequacy of Georgia’s 

source selection methodology, EPA also 

disagrees that Georgia should have 

selected Transcontinental Gasoline 

Company LLC—Compressor Station 

120; CEMEX Southeast, LLC; Green 

Power Solutions; International Paper 

Co.—Temple Inland Rome Linerboard 

Mill (Temple-Inland—Rome Lumber 

Mill); Georgia Pacific Cedar Springs 

LLC; Interstate Paper LLC; Georgia 

Pacific Consumer Products LP— 

Savannah River Mill; Rayonier 

Performance Fibers LLC; PCA Valdosta 

Mill; C–E Minerals Plants 1, 2, and 6; 

Graphic Packaging Macon Mill; 

Weyerhaeuser NR Port Wentworth; 

Pinova, Inc.; and Thermal Ceramics. GA 

EPD identified and evaluated these 

sources as part of its AoI screening 

approach and did not select them for 

FFAs because they did not meet 

Georgia’s source selection thresholds.38

Comment 5: The Commenters assert 

that Georgia’s cost effectiveness 

analyses are arbitrary and that 

‘‘[a]lthough EPA acknowledges that 

Georgia relied on the Arkansas Excel 

document for its cost-effectiveness 

determinations, EPA does not address 

whether it was reasonable for Georgia to 

do so.’’ Additionally, they state that ‘‘to 

provide a reasoned basis for its 

decisions, Georgia must first establish a 

threshold, or explain and justify some 

other objective measure, for determining 

cost effectiveness that is in line with 

other states’ chosen measures and apply 

that threshold consistently across its 

Four-Factor Analyses.’’ 

According to the Commenters, there 

are three specific problems with 

Georgia’s reliance on the Arkansas Excel 

spreadsheet. First, the Commenters 

assert that this spreadsheet does not 

consider that Round one costeffectiveness measures were considered 

alongside visibility benefits and cite to 

EPA’s 2021 Clarifications Memo’s 

statement that ‘‘a state should not use 

visibility to summarily dismiss costeffective potential controls.’’ 39 Second, 

the Commenters state that they expect 

that with each successive planning 

period, the cost of controls should 

increase because the lowest cost 

emission reductions would have already 

been implemented, and therefore, the 

Commenters assert that relying on first 

planning period costs to guide second 

planning period costs is improper. 

Third, Commenters state that the 

‘‘Arkansas’ spreadsheet fails to include 

the high end of first round costeffectiveness values up to $10,000/ton.’’ 

In addition to this last point, the 

Commenters assert that ‘‘Arkansas 

wrongfully included [in its spreadsheet] 

some cost-effectiveness data that is too 

old to escalate according to EPA’s 

Control Cost Manual.’’ 

The Commenters instead suggest that 

Georgia should have adopted a firm cost 

threshold such that controls below the 

threshold would be selected and 

controls above the threshold would not 

be selected. Alternatively, the 

Commenters state that Georgia ‘‘should 

have explained or justified some other 

objective measure.’’ The Commenters 

also contend that EPA must reject 

Georgia’s use of this approach because 

it would be inconsistent with EPA’s 

reasoning in its proposal to partially 

disapprove Arizona’s SIP revision in 

which Arizona used a cost threshold of 

$6,500/ton. Finally, the Commenters 

state (in the Kordzi Report) that data 

from Florida River Power Plants 1 and 

2 are missing from this spreasheet and 

should have been included and 

considered. 

Response 5: There is no requirement 

in the CAA or the RHR for states to 

establish bright line cost effectiveness 

thresholds when evaluating control 

costs in FFAs. The CAA and the RHR 

instead require states to evaluate the 

costs of compliance, and EPA’s 2019 

Guidance recommends that states follow 

the recommendations in EPA’s ‘‘Air 

Pollution Control Cost Manual’’ 

(CCM) 40 to facilitate apples-to-apples 

comparisons of different controls 

options for the same source, and 

comparisons across different sources. 

2019 Guidance at 31. 

As described in Section 7.7 of the 

Haze Plan, for the cost of compliance 

factor, Georgia EPD did not set a specific 

cost per ton threshold, but rather 

analyzed each facility using the 

information in EPA’s CCM and 2019 

Guidance to determine whether a given 

control measure is cost-effective based 

on a number of factors, including the 

historical range of cost/ton values. The 

historical cost information was derived 

from an Excel spreadsheet assembled by 

Arkansas Department of Environmental 

Quality that compared the cost of 


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41 40 CFR 51.308(e)(1)(ii)(A): ‘‘. . . the State must 

take into consideration . . . 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.’’ 

42 Joe Kordzi, A Review of EPA’s Proposed 

Approval of the Georgia Regional Haze State 

Implementation Plan (June 2024) (hereinafter 

referred to as ‘‘Kordzi Report’’) included in the 

docket for this action as Exhibit 1 in the 

Conservation Group letter (July 3, 2024). 

compliance from the first planning 

period for SO2 and NOX in dollars per 

ton for various types of industrial 

emission units (e.g., EGU Boiler, 

Industrial Boiler, Kiln, Smelter, all NonEGU). The spreadsheet was updated 

with VISTAS data (Appendix G–4) and 

presents the maximum and minimum 

cost/ton and various statistical 

percentile values. While Georgia did not 

choose a bright-line cost effectiveness 

threshold, Georgia’s use of this 

spreadsheet was an objective measure 

by which Georgia determined the 

reasonableness of control costs for this 

second planning period. 

EPA acknowledges the Arkansas cost 

spreadsheet includes Best Available 

Retrofit Technology (BART) control 

determination costs that considered the 

visibility benefits of the controls 

pursuant to the CAA and RHR under 40 

CFR 51.308(e)(1)(ii)(A).41 However, this 

fact does not change EPA’s position that 

Georgia’s use of this spreadsheet was 

reasonable. First, Georgia did not 

consider visibility in making its control 

determinations for this planning period. 

Just as importantly, while EPA agrees in 

general with the Commenters that data 

from the first planning period is 

necessarily an imperfect yardstick by 

which to determine the reasonableness 

of control measures for this second 

planning period—in part because the 

first planning period included BART 

determinations whereas the second 

planning period does not—the 

information is nonetheless highly 

relevant. Moreover, Georgia did not set 

a cost threshold based on the low-end 

or mean (or median) cost of first 

planning period controls. In fact, all 

controls rejected by Georgia were more 

costly than the 98th percentile of all 

first planning periods costs. This also 

addresses the Commenters’ contention 

that with each planning period, control 

costs should increase. 

Finally, regarding the Commenters’ 

third concern with Georgia’s use of the 

Arkansas spreadsheet that the 

spreadsheet may include missing data, 

EPA has reviewed the concern raised in 

the Kordzi 42 report that the Florida 

Crystal River Power Plant Units 1 and 

2 determinations were excluded from 

this spreadsheet. According to the 

Kordzi Report cited by the Commenters, 

the Crystal River Power Plant Units 1 

and 2 determinations required the 

source to either (1) install dry flue gas 

desulfurization (FGD) and SCR at a costeffectiveness of $10,000/ton for SO2

BART and $8,224/ton for NOX BART or 

(2) retire by December 31, 2020. This is 

not accurate. While both options were 

considered in the Florida first planning 

period regional haze NPRM, the final 

rule selected only the shutdown option 

based upon the Florida Department of 

Environmental Protection’s decision to 

adopt this shutdown in a SIP 

supplement. See 78 FR 53,262 (August 

29, 2013). For this reason, there was no 

add-on control adopted, and therefore 

no cost to consider. Although EPA was 

not involved in the preparation of the 

Arkansas spreadsheet, this may explain 

why the Crystal River Power Plant 

facility was not included in the 

spreadsheet. In any event, EPA 

concludes that Georgia’s decision not to 

consider this facility was reasonable. 

Regarding the Commenters’ assertions 

that Georgia’s approach is unreasonable 

when compared to states such as 

Colorado and Nevada, which elected to 

set cost effectiveness thresholds of 

$10,000/ton of pollutant removed, and 

to Arizona, which elected to set a cost 

effectiveness threshold of $6,500/ton of 

pollutant removed, Georgia was not 

required by the CAA or RHR to adopt 

a similar bright-line cost effectiveness 

threshold. Moreover, the Commenters 

themselves do not suggest a specific 

bright-line threshold, let alone provide 

rationale to support such a threshold. 

Georgia applied its chosen methodology 

in a way that is reasonable by rejecting 

controls with cost-effectiveness values 

above the 98th percentile of first 

planning period costs. 

As for the Commenters’ position that 

approval of Georgia’s plan would be 

inconsistent with the rationale within 

EPA’s proposed disapproval of 

Arizona’s plan regarding the importance 

of adequate state justification, EPA 

disagrees. In EPA’s proposed 

disapproval of Arizona’s regional haze 

SIP, EPA stated that Arizona ‘‘did not 

provide an adequate justification for 

how this threshold resulted in a 

reasonable set of control measures,’’ and 

in several instances in the notice of 

proposed rulemaking, EPA noted that 

Arizona ignored its own threshold 

without justification. See 89 FR 47,429 

(May 31, 2024). That is quite different 

than Georgia, which did not use a 

bright-line threshold at all and instead 

consistently applied the statistical 

methods in the Arkansas spreadsheet to 

only reject control costs that exceed the 

98th percentile of first planning period 

costs identified within that spreadsheet. 

Comment 6: The Commenters assert 

that EPA shirks its duty to review 

Georgia’s source-specific FFAs. The 

Commenters state that EPA proposes to 

merely ‘‘rubber stamp’’ the State’s SIP 

submission, without engaging in any 

meaningful, independent, analysis of 

Georgia’s FFAs for the three facilities 

the State selected. Additionally, the 

Commenters assert that ‘‘[d]espite EPA’s 

stated expectations for this planning 

period, Georgia does not require any of 

the sources to adopt additional control 

measures to make reasonable progress.’’ 

Response 6: EPA’s proposed approval 

of Georgia’s Haze Plan is a proper 

exercise of EPA’s authority under the 

CAA. Congress crafted the CAA to 

provide for states to take the lead in 

developing implementation plans, but 

balanced that decision by requiring EPA 

to review the plans to determine 

whether a SIP meets the requirements of 

the CAA. When reviewing SIPs, EPA 

must consider not only whether the 

state considered the appropriate factors 

in making decisions, but acted 

reasonably in doing so. In undertaking 

such a review, EPA does not usurp the 

state’s authority but ensures that such 

authority is reasonably exercised. 

Contrary to the comment that the 

Agency ‘‘shirks’’ its CAA obligations, 

EPA has performed its duties with 

diligence. EPA carefully evaluated the 

Haze Plan and the associated record and 

engaged in a thorough analysis of each 

control option, including each of the 

underlying cost assumptions used in the 

calculations. Georgia conducted 

extensive technical work in support of 

its SIP submittal, and therefore, EPA 

independently evaluated each FFA, 

including costs, and compared each 

FFA’s control determination against the 

CCM. In the Technical Support 

Document (TSD) to the NPRM, EPA 

documented the cost assumptions that 

the State relied upon in its FFAs for 

transparency to the public. 

Each of the FFAs are discussed in 

more detail in the responses to 

comments that follow, but EPA notes 

that Georgia did adopt important control 

measures into the SIP as necessary for 

reasonable progress for the second 

planning period, including the coal 

burning prohibition at IP-Savannah. 

While that facility had voluntarily 

elected to stop burning coal at the No. 

13 Power Boiler, this prohibition was 

not federally enforceable and permanent 

until incorporated into the Georgia SIP. 

In the absence of placing this 

prohibition into the SIP, the facility 

could have lawfully restarted burning 

coal at any time, which is inconsistent 

with making reasonable progress under 

the CAA and RHR. EPA’s specific 


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43See Appendix G–1b, at p. 13 (noting that Plant 

Bowen switched to IB coal in 2014). 

44Facility and unit emissions and emissions rate 

data is from EPA’s CAMPD available at: https://

campd.epa.gov/. 

45The July 25, 2022, Stamper Report, ‘‘Review 

and Comments on Reasonable Progress Four-Factor 

Analyses Evaluated as Part of the Georgia Regional 

Haze Plan for the Second Implementation Period,’’ 

is included as Exhibit 2 of Appendix H–3a of the 

Haze Plan which is included in the docket for this 

action. 

46CAMPD data is available at: https://

campd.epa.gov/. 

analyses for each FFA are addressed in 

responses to comments below that 

address each of the three facilities 

selected by Georgia. 

Comment 7: The Commenters assert 

that ‘‘Plant Bowen’s SO2 emission rates 

have increased since round one of 

regional haze, which is contrary to the 

intent of the Regional Haze Program.’’ 

The Kordzi Report describes how, 

although Plant Bowen was reviewed for 

BART in the first round of regional haze 

planning, Georgia relied on the Clean 

Air Interstate Rule (CAIR) to satisfy 

BART for SO2 and NOX for EGUs and 

did not include any enforceable 

mechanism to ensure Plant Bowen’s 

emissions did not increase, citing to 

projected emissions from Plant Bowen 

and Q/d values. 

Response 7: Although the combined 

SO2 emission rates at Plant Bowen for 

Units 1–4 have increased since the first 

planning period as discussed below, 

focusing only on these emission rates 

from these units ignores the significant 

declines in total facility-wide SO2

emissions from this facility. EPA also 

does not agree with the Commenters 

that an increase in emission rates within 

permitted levels during the first 

planning period, on its own, is contrary 

to the intent of the regional haze 

program. 

In 2010, after wet scrubbers had been 

installed to control SO2 emissions at 

Plant Bowen’s four units, this facility’s 

annual average SO2 emission rates were 

approximately 0.068 lb/MMBtu based 

on Clean Air Markets Program Data 

(CAMPD) reviewed by EPA. In 2023, the 

annual average emission rate was 0.13 

lb/MMBtu. This increase was primarily 

due to a change in coal used at the 

facility from Central Appalachian 

bituminous coal (CAPP coal) to Illinois 

Basin coal (IB coal), with IB coal 

containing a higher sulfur content.43

These coal types are discussed in more 

detail in EPA’s responses to later 

comments regarding Plant Bowen’s FFA 

along with discussion as to why 

switching back to CAPP coal is not cost 

effective. 

While emission rates are an important 

consideration because FFAs generally 

yield emission controls that result in 

updated emission rates, in this instance, 

only considering emission rates as the 

Commenters propose would ignore an 

important aspect of the problem. Here, 

the total amount of SO2 emissions is 

also important. The first regional haze 

planning period spanned the period 

from 2000–2018, with SIPs due in 2007. 

Plant Bowen’s SO2 annual emissions in 

2007 were approximately 197,000 tpy 

prior to the installation of wet scrubbers 

to control SO2 emissions. Plant Bowen 

installed wet scrubbers between 2008 

and 2010 at Units 1 through 4. After 

these wet scrubbers were installed, 

Plant Bowen’s total facility-wide SO2

emissions dropped to approximately 

7,618 tpy in 2010, and in 2023, SO2 total 

emissions from Plant Bowen were 7,143 

tpy.44 EPA acknowledges that there is 

year-to-year variability in Plant Bowen’s 

emission rates and total emissions due 

to changes in demand for electricity, 

sulfur content of the fuel used at Plant 

Bowen, and scrubber efficiency. 

However, the general trend at this 

facility has been a significant reduction 

in total SO2 emissions during the first 

planning period. Contrary to the 

Commenters’ assertions, the fact that 

SO2 emission rates have varied to some 

extent at this facility during the first 

planning period is not contrary to the 

RHR. 

Comment 8: As a general matter, the 

Commenters contend that EPA did not 

scrutinize Georgia’s analysis of Plant 

Bowen and did not consider the 

comments submitted by the 

Commenters to Georgia, including the 

Stamper report.45 Specifically, the 

Commenters assert that Georgia greatly 

overstated the costs of switching back to 

lower sulfur CAPP coal for three 

primary reasons. 

Response 8: EPA disagrees with the 

Commenters. Regarding the 

Commenters’ assertion that EPA did not 

scrutinize the FFA or consider the 

Commenters’ state-level comments 

provided to Georgia, that is not correct. 

EPA evaluated Georgia’s entire SIP 

submittal, including the FFAs, the statelevel comments, and the State’s 

responses to those comments. 

Comment 8.a: First, the Commenters 

argue that Georgia’s assumption of an 

SO2 rate of 0.07 lb/MMBtu when 

burning CAPP coal was improper 

because Plant Bowen averaged 0.05 lb/ 

MMBtu or lower for many years when 

combusting CAPP coal. 

Response 8.a: The Commenters are 

incorrect. The data submitted by the 

Commenters in the Kordzi Report 

contains emission data for Plant Bowen 

Units 1 through 4 including for the 

years 2010 through 2014. As previously 

stated, Plant Bowen began to transition 

to IB coal in 2014. EPA was not able to 

reproduce the 0.05 lb/MMBtu average in 

the Kordzi Report. Based on the 

information submitted by the 

Commenters, the actual average SO2

emissions in lb/MMBtu across all four 

boilers from 2010–2013 is 0.065 lb/ 

MMBtu (i.e., prior to any switch to IB 

coal), not 0.05 lb/MMBtu as stated by 

the Commenters. The average for all 

four boilers from 2010 through 2014 is 

0.069 lb/MMBtu. These numbers are 

very close to the SO2 emission rate of 

0.07 lb/MMBtu assumed by Georgia if 

Plant Bowen were to switch to CAPP 

coal. EPA further confirmed these 

numbers by reviewing information from 

EPA’s CAMPD.46

Comment 8.b: Second, the 

Commenters argue that Georgia assumed 

in its analysis that CAPP coal has a 

higher sulfur content than most of the 

CAPP coal that Plant Bowen previously 

burned. 

Response 8.b: This is not correct 

based on the data provided by the 

Commenters. The statement cited by the 

Commenters in the Kordzi Report states 

that ‘‘Bowen’s estimate assumes a coal 

sulfur content of 1.1 percent. As shown 

above, this is slightly higher than most 

of the previous CAPP coal it burned.’’ 

However, taking a simple average of the 

sulfur content of all coal combusted 

across all four boilers contained within 

Table 2 of the Kordzi Report yields an 

average of 1.08 percent sulfur content 

for CAPP coal combusted from 2010– 

2013 and 1.19 percent for CAPP coal 

combusted from 2010–2014. Again, 

these numbers are very close to what 

Georgia relied upon for the Plant Bowen 

FFA, and EPA agrees with Georgia’s 

assumption regarding the sulfur content 

of CAPP coal given the averages 

discussed above. 

Comment 8.c: Third, the 

Commenters—and specifically the 

Kordzi Report provided as an 

attachment to the comments—state that 

based upon publicly available Energy 

Information Agency (EIA) Form 923 

data, railroad-transportable CAPP coal 

with a sulfur content of 1.05 percent or 

less is available to purchase from 

Kentucky, Virginia, and West Virginia at 

delivered prices (i.e., including both 

fuel costs and transportation costs) that 

are lower per MMBtu than what Plant 

Bowen currently pays for IB coal of a 

higher sulfur content. Based on this 

information, the Commenters argue that 

EPA must reject Georgia’s FFA for Plant 

Bowen. 


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47The affidavit is located in Appendix G–1b of 

the Haze Plan. 

Response 8.c: EPA also disagrees with 

the Commenters’ contention that Plant 

Bowen could purchase CAPP coal from 

mines in Kentucky, Virginia, and/or 

West Virginia at prices that are less 

expensive than the higher sulfur IB coal 

that Plant Bowen primarily relies upon. 

Table 4 within the Kordzi Report 

contains information obtained from EIA 

Form 923 for the year 2023, which 

includes coal production and sale 

information such as coal mine name, 

quantity sold, average heat content of 

the coal, average sulfur content of the 

coal, fuel cost in cents per MMBtu, total 

cost of each purchase of coal, and 

whether the purchase was pursuant to a 

contract or was made on the spot 

market. Based upon this data, the 

Kordzi Report tabulated the total cost of 

coal per MMBtu from mines that met 

the following criteria: the mines were 

only within Kentucky, Virginia, or West 

Virginia; the mines were capable of 

transporting coal by railroad; and the 

coal sold by the mine had sulfur content 

below 1.05 percent. Based upon this 

data, the Commenters conclude that the 

average cost of such coal is $4.89/ 

MMBtu. The Commenters also conclude 

that this is less expensive than the 

average cost of Plant Bowen’s coal 

purchases in 2023, which the 

Commenters assert is $5.33/MMBtu. 

First, EPA reviewed the unredacted 

fuel cost information contained in the 

technical appendix submitted by 

Georgia to EPA prior to publishing the 

NPRM, and EPA affirms that the 

information in that technical appendix 

supports the State’s and EPA’s 

conclusions that procuring CAPP coal 

would be significantly more costly than 

Plant Bowen’s current purchases of IB 

coal. Second, there is inadequate supply 

of coal fitting the type preferred by the 

Commenters to supply a facility as large 

as Plant Bowen. According to the EIA 

923 form data cited by the Commenters, 

in 2012, Plant Bowen purchased 

4,737,780 tons of coal. In that same year, 

32,145,400 tons of coal were sold 

meeting the criteria preferred by the 

Commenters (from Kentucky, Virginia, 

or West Virginia; no greater than 1.05 

percent sulfur content; and railroadtransportable). But in 2023, only 

4,900,885 tons of coal meeting the 

criteria preferred by Commenters were 

sold to all facilities combined. In other 

words, if Plant Bowen were to switch to 

CAPP coal, the demand for CAPP coal 

created by Plant Bowen alone would 

almost exceed the entire supply of such 

coal put into commerce in 2023. 

Comment 8.d: Additionally, the 

Commenters assert that Plant Bowen’s 

cost-effectiveness calculation contains 

an annual fuel cost of $86 million to 

switch to CAPP coal that is ‘‘completely 

undocumented.’’ Commenters argue that 

although Plant Bowen claimed this fuel 

cost as a trade secret and therefore 

submitted it to EPA as CBI, EPA is 

required to review this information and 

declare whether EPA finds that this 

information meets the documentation 

requirements contained in 40 CFR 

51.308(f)(2)(iii). The Commenters assert 

that some of the information may not be 

CBI, including certain fuel cost data, 

and that EPA must evaluate whether 

this information is CBI to provide the 

public with sufficient information to 

fully evaluate the proposal. 

Response 8.d: The costs for switching 

to CAPP coal were included in the Haze 

Plan under Appendix A and Appendix 

B to Appendix G–1b. Georgia Power 

submitted this cost information under a 

claim of business confidentiality and 

provided redacted versions of its 

proposed four factor analysis, including 

Appendix B to Appendix G–1b for 

public release. 

Under the CAA and EPA’s 

regulations, a company may assert a 

business confidentiality claim covering 

information furnished to EPA. See 40 

CFR 2.203(b). Once a claim is asserted, 

the Agency must consider the 

information to be confidential and must 

treat it accordingly unless the Agency 

finds in a CBI determination that the 

material is not CBI. See 40 CFR 2.205, 

2.301(g). Under 40 CFR 2.204(a), EPA is 

required to make a CBI determination 

when the Agency (1) learns that it is 

responsible for responding to a request 

under the Freedom of Information Act 

(FOIA) (5 U.S.C. 552) for the release of 

business information; (2) desires to 

determine whether business information 

in its possession is entitled to 

confidential treatment, even though no 

request for release of the information 

has been received; or (3) determines that 

it is likely that EPA eventually will be 

requested to disclose the information at 

some future date and thus will have to 

determine whether the information is 

entitled to confidential treatment. EPA’s 

regulations set forth the specific 

procedures that EPA must follow when 

making a CBI determination. 40 CFR 

2.204, 2.205, and 2.301(g). Under the 

regulations, EPA must provide the 

affected businesses with notice and, 

usually, an opportunity to comment on 

the impending CBI determination or 

release, including an opportunity to 

justify their CBI claims. See, e.g., 40 

CFR 2.204(e), 2.209(d), and 2.301(g)(2). 

Considering the nature of the comments 

regarding a switch to CAPP coal, the 

mechanism by which the Commenters 

requested that EPA make a CBI 

determination (i.e., via rulemaking 

comment instead of via FOIA), EPA’s 

review of the CBI information in 

evaluating the reasonableness of the 

FFA, and EPA’s refutation of the 

Commenters’ concerns regarding the 

costs of switching to CAPP coal, EPA is 

exercising its discretion under 40 CFR 

2.204(a) to not perform a CBI 

determination at this time. Therefore, 

EPA is obligated to protect the 

confidentiality of that information, 

which precludes the Agency from 

publicly posting this in the docket at 

regulations.gov. 

Plant Bowen submitted a signed 

affidavit 47 to substantiate its CBI claim 

and provided a public disclosure 

version of Technical Appendix A and 

Technical Appendix B to Appendix G– 

1b of the Haze Plan, with the CBI 

information redacted. As noted in the 

public disclosure materials, the redacted 

information consists of material 

including ‘‘2019 IRP Capacity Planning 

Documentation,’’ ‘‘Delivered Fuel Cost 

Estimates for PRB and CAPP Coals, 

‘‘CSX Transportation Contract 

Language,’’ ‘‘CSX Pricelist 

Inforormation,’’ and variable operating 

and maintenance costs for switching to 

CAPP coal such as including the costs 

from ‘‘hydrated lime adjustment,’’ 

‘‘ammonia adjustment,’’ ‘‘fuel additive 

adjustment,’’ and ‘‘activated carbon 

adjustment’’ as it relates to CAPP coal. 

Upon review of the assumptions and 

information contained in Appendix G 

used in the cost analyses, including the 

unredacted information, EPA finds the 

cost-effectiveness calculations for 

switching to CAPP coal to be 

appropriately documented and 

reasonable based on the available 

information, justifications, and support 

for each assumption used in the cost 

calculation. 

Comment 9: The Commenters state 

that in 2014, Plant Bowen switched 

from lower-sulfur CAPP coal to IB coal, 

which they state has a high sulfur 

content. The Commenters assert that 

Georgia greatly overstated the costs of 

switching to Powder River Basin (PRB) 

coal. Instead of requiring a switch to 

PRB coal, the Commenters contend that 

EPA accepted Georgia’s and Georgia 

Power’s claims at face value that such 

a switch would be cost prohibitive. The 

Commenters argue that Georgia Power’s 

cost analysis contains several problems 

that cause it to be overinflated. 

First, the Commenters argue that 

Georgia Power wants to earn a 6.04 

percent rate of return for electricity that 

it must purchase to make up for lost 

capacity. In referencing the Stamper 


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48See Section 4.4.1.1 on p. 15 of the Haze Plan 

in Appendix G–1b. 

49https://www.eia.gov/tools/faqs/

faq.php?id=101&t=3. 

50 Id. 

report, they contend that this cost 

should not be a capital expense but 

rather should be treated as an operating 

expense (such as fuel costs) that is not 

entitled to such returns. 

Second, the Commenters argue that 

Georgia does not make a fair comparison 

by assuming operating time will 

increase at the same time it will need to 

purchase $51 million worth of 

electricity to cover lost capacity. The 

Commenters contend that the FFA does 

not account for revenue from additional 

sales of electricity due to increased 

hours of operation. Additionally, the 

Commenters argue that the FFA already 

accounts for an increase in fuel costs in 

a different line item in the cost analysis, 

so they argue that Georgia Power is at 

least, in part, double counting the 

increased fuel usage of PRB coal. 

The Commenters state that even 

assuming the switch to PRB coal will 

decrease maximum hourly generating 

capacity, Georgia Power’s cost analysis 

appears to overstate the need (and cost) 

for replacement energy. The 

Commenters contend that based on 2019 

plantwide generation rates, Georgia 

Power would need to purchase only 

134,982 megawatt-hour (MWh) to make 

up for the switch to PRB coal. The 

Commenters cite to Table A2.2 of the 

FFA for the proposition that Georgia 

Power estimated that the switch ‘‘would 

require the purchase of approximately 

8,000,000 MWh of energy to replace the 

deficit’’ as a result of the assumption 

that the capacity penalty would apply 

during all hours of operation. In 

contrast, the Commenters provide an 

exhibit that they argue demonstrates 

that switching to PRB would only 

impact the peak hours of plant 

operation, which equates to 5.8 percent 

of the time according to the 

Commenters. Even assuming aboveaverage energy prices ($40/MWh), the 

Commenters assert that with the switch 

to PRB coal, the company would 

consequently need to only spend $5 

million annually, instead of Georgia 

Power’s assumed $51.7 million. 

The Commenters also assert that to 

the extent that Georgia Power suggests 

it needs to purchase or build 

replacement capacity to meet peak 

demands and reserve margin 

requirements, the FFA fails to provide 

the ‘‘robust’’ technical support for this 

position. As with the energy deficit 

discussed above, the Commenters 

contend that Georgia Power fails to 

establish that it actually has a projected 

capacity need in any such year. 

Additionally, the Commenters assert 

that Georgia Power fails to provide any 

documentation for current ‘‘market rate’’ 

or ‘‘cost of new construction.’’ As a 

result, the Commenters contend it is 

impossible to verify the needed capacity 

replacement and cost associated with 

switching to PRB. The Commenters state 

that EPA must review Georgia Power’s 

cost assumptions and confirm that the 

Company’s capacity penalty 

calculations are appropriate. 

The Commenters also state that 

Georgia refuses to make available for 

public review the calculations and 

supporting documentation for the cost 

analysis of switching to PRB coal. The 

Commenters assert that Georgia and 

EPA are obligated by the 

documentations requirements of 40 CFR 

51.308(f)(2)(iii) to review this 

information and declare whether they 

have found it acceptable, but neither 

Georgia nor EPA has indicated if they 

have reviewed the information and 

found it acceptable. The Commenters 

argue that a failure by EPA to make an 

independent determination as to 

whether this information satisfies the 

requirements for CBI violates the CAA 

and the RHR. 

Finally, the Commenters contend that 

Georgia’s calculated costs of $6,424/ton 

of SO2 reduced to switch to PRB coal is 

cost effective, and this cost-effectiveness 

value is lower than thresholds used by 

other states such as Colorado ($10,000/ 

ton), New Mexico ($7,000/ton), and 

Arizona ($6,500/ton). Moreover, the 

Commenters state that cost effectiveness 

should be lower to reflect that switching 

to PRB coal would result in 46 percent 

lower NOX emission rates without 

changing Plant Bowen’s use of NOX

controls. They argue that the NOX

reductions of switching to PRB coal 

would result in a cost-effectiveness of 

$4,749/ton of combined SO2 and NOX

removed. 

Response 9: EPA disagrees with the 

Commenters’ argument that EPA did not 

scrutinize GA EPD’s analysis of Plant 

Bowen and did not consider the public 

comments submitted at the state level. 

Regarding the Commenters’ argument 

that in 2014 Plant Bowen switched from 

lower-sulfur CAPP coal to IB coal which 

has a higher sulfur content, EPA 

acknowledges that the sulfur content for 

IB coal is higher and SO2 emissions 

have increased with the switch to IB 

coal. This switch is also discussed in 

Response 8. 

EPA disagrees with the Commenters’ 

argument that Georgia greatly overstated 

the costs of switching to 100 percent 

PRB coal. With a fuel switch to PRB 

coal, there would be a 27 percent 

facility derate based on the average heat 

content of PRB coal ((8,800 British 

thermal units per pound (Btu/lb)) in 

comparison to the current coal being 

used at Plant Bowen, which is IB coal 

with an average heat content of 12,002 

Btu/lb.48 This derate resulting from the 

reduced heat content of PRB coal would 

result in Plant Bowen having 27 percent 

less total electricity generation capacity. 

This is a real cost that Georgia was 

correct to account for in the FFA. 

Through a letter to GA EPD dated 

August 8, 2022, Georgia Power 

responded directly to similar comments 

submitted by the Commenters to GA 

EPD. This letter was included as part of 

Georgia’s submittal and is located 

within Appendix G–1e to the Haze Plan. 

Within that letter, Georgia Power 

explained that ‘‘[t]he capacity penalty 

costs in the Plant Bowen FFA 

represented the costs to replace the 

derated unit capacity to meet the reserve 

margin required in the Southern 

Company system.’’ Georgia Power also 

cited to the FFA, which notes that 

‘‘Plant Bowen Units 1–4 provide 

capacity value by supporting system 

reliability and by avoiding costs 

associated with replacement capacity 

that would be required to meet customer 

peak demands and reserve margin 

requirements in the absence of such 

Plant Bowen units. Without these units, 

Georgia Power would have to procure 

short-term and long-term replacement 

capacity in order to restore Georgia 

Power and the Southern Company 

system to a comparable level of 

reliability that the system currently 

holds.’’ 

The Commenters conflate two distinct 

electric generation concepts: capacity 

and generation. They are not the same. 

Nor are the financial costs and revenues 

associated with each the same. 

According to the EIA, ‘‘[e]lectricity 

generation capacity is the maximum 

electric output an electricity generator 

can produce under specific 

conditions.’’ 49 ‘‘Electricity net 

generation,’’ on the other hand, ‘‘is the 

amount of gross electricity generation a 

generator produces minus the electricity 

used to operate the power plant.’’ 50 It is 

this incorrect conflation of concepts that 

leads the Commenters to incorrectly 

conclude that Georgia Power could 

make up for any lost capacity at Plant 

Bowen by simply purchasing 134,982 

MWh of electricity annually. In general, 

the electrical grid can experience high 

periods of demand for short durations. 

This is known as ‘‘peak’’ electricity 

demand. To ensure reliability of the 

electrical grid, electric utilities must 

have sufficient capacity available to 


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51 Georgia Power ‘‘2023 Integrated Resource Plan 

Update,’’ at p. 1, available at: https://

georgiapower.com/content/dam/georgia-power/ 

pdfs/company-pdfs/2023-irp-update-maindocument.pdf. 

52 Id. at pp. 15–25. 

53 GA PSC Order Adopting Stipulated Agreement, 

at pp. 7–8, available at: https://psc.ga.gov/search/ 

facts-document/?documentId=218484. 

54 GA PSC Order Granting Certification of Plant 

Yates Units 8–10, available at: https://psc.ga.gov/ 

search/facts-document/?documentId=219790. 

55The Commenters also incorrectly note that 

Georgia Power is entitled to a 6.04 percent rate 

return. This 6.04 percent figure is identified in 

Table A1.2 as Georgia Power’s firm-specific interest 

rate as authorized by the Georgia Public Service 

Continued 

ensure that these peak loads can be met. 

The Commenters’ suggestion that 

Georgia Power could simply purchase 

134,982 MWh of generated electricity 

does not account for the need for 

Georgia Power to also have adequate 

capacity available for the grid, even at 

times of peak demand. Georgia Power 

refers to this concept as the ‘‘reserve 

margin’’ in its August 8, 2022, letter. 

EPA agrees with Georgia’s assessment 

that requiring PRB coal would result in 

a capacity derate, and that this capacity 

derate would impact electrical 

reliability by reducing peak available 

capacity to a sufficient extent that 

Georgia Power would have to ‘‘procure 

short-term and long-term replacement 

capacity.’’ Over the long-term, this 

would likely result in the need for 

Georgia Power to construct new 

generation capacity equivalent to the 

capacity derate, which would be a 

capital cost and not an operating 

expenditure. EPA thus does not agree 

with the Commenters that this capacity 

derate was mis-classified within the 

FFA as an operating expense. Plant 

Bowen Units 1 and 2 each have a 

maximum capacity of 724 megawatts 

(MW), and Units 3 and 4 have a 

maximum capacity of 892 MW. See 

Haze Plan Appendix G–1b, Note 1 to 

Table A2.2. Combined, these four units 

have a maximum capacity of 3,232 MW 

if combusting IB coal. A 27 percent 

derate of these units associated with a 

switch to PRB coal would reduce the 

maximum capacity of Plant Bowen to 

2,359 MW. The difference between 

these two numbers is 873 MW, which is 

the total capacity that Georgia Power 

would no longer have available to put 

onto the grid. 

Moreover, according to a recent IRP 

Update submitted by Georgia Power to 

the Georgia Public Service Commission 

(GA PSC), ‘‘the Company’s current 

projections reflect load growth of 6,600 

MW through the winter of 2030/2031, 

which is approximately 17 times greater 

than that previously forecasted.’’ 51 Due 

to this projected growth, Georgia Power 

requested that the GA PSC approve the 

construction of 1,400 MW of new 

generation capacity at Plant Yates, the 

authority to develop, own, and operate 

up to 1,000 MW of battery energy 

storage systems, the long term purchase 

of 750 MW of capacity from Mississippi 

Power through a power purchase 

agreement, and the long term purchase 

of 230 MW of capacity from Santa Rosa 

Energy Center through a power 

purchase agreement.52

On April 26, 2024, the GA PSC issued 

an order in which it took action on 

Georgia Power’s IRP Update filing. In 

that order, the GA PSC approved much 

of Georgia Power’s IRP Update filing, 

with certain modifications subject to a 

stipulation adopted by the GA PSC. 

Critically, within the GA PSC’s April 26, 

2024, order, the GA PSC stated the 

following as a finding of fact: 

Substantial empirical evidence shows that 

the load projected by the Company is indeed 

coming to Georgia. There is a large economic 

development pipeline made up of businesses 

seeking to locate in Georgia, and the 

Company has continued to see progress from 

large load customers included in its forecast, 

as well as accelerated customer load ramps 

and other tangible evidence of growth. The 

number of committed Georgia Power 

customers continues to increase. As of the 

2023 IRP Update filing, the Company had 

already been chosen to serve over 3,600 MW 

of load from the approximately 17,000 MW 

pipeline of economic development, nearly 

3,000 MW of which is already under 

construction. (Rebuttal Hearing Tr. 2031.) 

Since the 2023 IRP Update filing in October 

of 2023, the economic development pipeline 

has grown from 17,000 MW to 21,000 MW, 

and Georgia Power has been selected to serve 

an additional 2,602 MW. The large load 

customers included in the Company’s 

forecast are moving forward and making 

progress without material delay. The 

Stipulation will allow Georgia Power to 

reliably serve both its existing customers and 

the new ones.53

On August 29, 2024, the GA PSC took 

further action within this IRP Update 

docket by granting Georgia Power a 

certificate of convenience and public 

necessity for the construction of Plant 

Yates Units 8–10, and the PSC noted 

that ‘‘time is of the essence and the 

Commission declines to accept any 

further delay in putting these assets in 

place,’’ and ‘‘[i]n light of . . . the state 

of Georgia’s recent extraordinary 

economic growth, and its citizens and 

business’ pressing need for economical 

and reliable energy to meet this growth, 

the Commission agrees with the 

Company and Staff that certification of 

Plant Yates Units 8–10 is reasonable and 

appropriate.’’ 54 Plant Yates Units 8–10 

would provide Georgia Power with 

approximately 1,400 MW of additional 

generation capacity. 

These recent actions by the GA PSC 

are highly relevant to the Commenters’ 

assertions. Specifically, the Commenters 

argue that the Plant Bowen FFA’s 

conclusion is unsubstantiated regarding 

the need for Georgia Power to construct 

or otherwise acquire additional 

generation capacity to replace the 873 

MW of lost capacity if Plant Bowen 

were required to utilize lower sulfur, 

lower heat content PRB coal. Based on 

the recent factual findings of the GA 

PSC, which EPA acknowledges, EPA 

does not agree with the Commenters. 

While requiring Plant Bowen to switch 

to PRB coal would reduce SO2

emissions, it would do so at the expense 

of generation capacity, and the need to 

construct or procure new generation 

capacity was therefore properly 

considered within the FFA. EPA 

therefore agrees with Georgia’s 

conclusions that this capacity derate 

should be classified as a capital 

expenditure since it would result in the 

need to construct or procure access to 

new capital, i.e., 873 MW of generation 

capacity. EPA also agrees that the 

financial and energy costs associated 

with this capacity derate are not 

reasonable under the RHR. 40 CFR 

51.308(f)(2)(i). 

The CBI filings provided by Georgia 

Power as part of the Plant Bowen FFA 

further support EPA’s conclusion. 

Regarding the Commenters’ request that 

EPA determine whether these materials 

are in fact CBI, for the same reasons 

stated in Response 8, EPA is exercising 

its discretion to not make a formal CBI 

determination regarding the redacted 

materials contained within the Plant 

Bowen FFA at this time and disagrees 

with the Commenters’ assertion that 

EPA is required to make such a 

determination here. Nonetheless, 

throughout this rulemaking process, 

EPA has reviewed the unredacted 

indirect costs that GA EPD submitted in 

Technical Appendix B of Appendix G– 

1b of the Haze Plan (along with all other 

components of the Haze Plan). As 

requested by Commenters, EPA 

confirms that it reviewed this CBI 

information during the review of the 

Haze Plan and finds that it provides 

adequate technical justification in 

support of the submittal. Because the 

capacity derate would result in the need 

for Georgia Power to construct or 

procure new long-term generation 

capacity, EPA also agrees that Georgia 

Power would reasonably be entitled to 

a rate of return on this capital, which 

Georgia Power substantiated in its 

FFA.55


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Commission. This is not the same as the rate of 

return that Georgia Power is entitled to. The rate of 

return that Georgia Power is entitled to is identified 

in the same rate case cited to in support of Table 

A1.2. That rate of return (referred to by the Georgia 

Public Service Commission as ‘‘return on equity’’) 

is set forth in the Georgia Public Serivce 

Commission’s December 31, 2019, Short Order 

Adopting Settlement Agreement as Modified and 

ranges from 9.5 percent to 12.0 percent. This order 

is available at https://psc.ga.gov/search/factsdocument/?documentId=179339. 

The Commenters contend that there is 

a mismatch in assumptions in the FFA 

because the FFA assumes operating time 

will increase if combusting PRB coal at 

the same time as Plant Bowen would 

need to purchase $51 million worth of 

electric generating capacity to cover lost 

capacity due to the derate associated 

with reduced heat content of PRB coal. 

The Commenters are incorrect. The 

Plant Bowen FFA states that ‘‘the level 

of unit capacity derate does not impact 

the annual SO2 emissions reduction 

since the analysis assumes that the 2019 

baseline annual heat input is achievable 

at this derated unit capacity with an 

increased amount of operating time.’’ 

The FFA properly assumed an increase 

in operating time when comparing SO2

emissions if combusting PRB coal 

compared to IB coal because those 

emissions are based on projected 2028 

emissions. The 2028 emission 

projections, in turn, are based in part 

upon projections about the quantity of 

electricity that will actually be 

generated. The Plant Bowen FFA 

reasonably increased operating hours in 

2028 when modeling SO2 emissions if 

operating on PRB coal to ensure that the 

same quantity of electricity was 

generated in both the PRB scenario and 

the IB coal scenario. Again, the concept 

of total generation capacity of the plant 

that is available to provide load to the 

grid as needed is separate and distinct 

from electricity that is actually 

generated and placed onto the grid. EPA 

thus disagrees that there is a 

‘‘mismatch’’ in assumptions in the FFA. 

Regarding the comment that the cost 

of $6,424/ton of SO2 reduced associated 

with a switch to PRB coal is costeffective because it is lower than 

thresholds used by other states 

(Colorado—$10,000/ton, New Mexico— 

$7,000/ton, and Arizona—$6,500/ton), 

EPA disagrees. Flexibility afforded to 

states has long been a hallmark of the 

regional haze program. See, e.g., 82 FR 

3078, 3088 (January 10, 2017) (‘‘While 

these final revisions to the RHR 

continue to provide states with 

considerable flexibility in evaluating the 

four reasonable-progress factors, we 

expect states to exercise reasoned 

judgment when choosing which 

sources, groups of sources or source 

categories to analyze.’’); 2019 Guidance 

at p. 4 (‘‘States have discretion to 

balance these factors and considerations 

in determining what control measures 

are necessary to make reasonable 

progress.’’). Inherent in this flexibility is 

that different states may choose brightline cost effectiveness thresholds, and 

some may instead choose to adopt a 

different methodology to determine 

whether controls are cost effective (i.e., 

Georgia’s approach). For those states 

that do choose to use bright-line costeffectiveness thresholds, those 

thresholds may differ from state-to-state. 

Different states will take different 

approaches to comply with the RHR, 

and various methods of complying with 

the rule may be reasonable depending 

on a number of facts and circumstances 

(e.g., number of sources in the state; 

magnitude of emissions of visibility 

impairing pollutants from sources in the 

state; visibility impairment at impacted 

Class I areas). 

Due to this flexibility, EPA disagrees 

with the premise of the Commenters’ 

assertion, which appears to be that cost 

effectiveness thresholds in one state 

should be determinative of whether 

controls are cost-effective in another 

state. Taken to its logical conclusion, 

the Commenters’ position seems to be 

that EPA’s determinations regarding the 

approvability of bright-line costeffectiveness thresholds in states such 

as Colorado, New Mexico, and Arizona 

should serve to set a nationwide costeffectiveness floor. The RHR requires no 

such thing, and indeed, the Commenters 

cite to no legal authority for their 

position. 

As discussed in Response 5, Georgia 

relied on a spreadsheet of first planning 

period costs developed by Arkansas 

with input from other states and 

supplemented with VISTAS-specific 

data. Georgia determined based on that 

spreadsheet that a cost of $6,424/ton of 

SO2 removed, as determined for the 

2019 cost year, would exceed the 98th 

percentile of all costs incurred by 

sources to control emission in the first 

planning period. On this basis, Georgia 

determined that a cost of $6,424/ton of 

SO2 removed was not a reasonable cost 

of control. EPA reaffirms that Georgia’s 

conclusions were reasonable under the 

CAA and RHR. 

While the Commenters state that a 

switch to PRB coal would result in 46 

percent lower NOX emission rates and 

taking the NOX reductions into account 

would result in a cost-effectiveness of 

$4,749/ton for SO2 and NOX, combined, 

because the facility did not exceed 

Georgia’s AoI/PSAT threshold for NOX, 

Georgia did not conduct a control 

analysis for NOX due to its 

determination that SO2 is the dominant 

pollutant in this planning period for 

Class I areas impacted by Georgia 

sources. For the reasons discussed 

earlier in Response 3, EPA has 

concluded that Georgia’s approach is 

reasonable. As set forth in that response, 

PSAT source apportionment modeling 

clearly demonstrates that contributions 

from Georgia’s point source NOX

emissions are significantly below 

Georgia’s source selection thresholds. 

As stated in Tables 7–16, 7–17, and 7– 

18 of the Haze Plan, the modeled 

visibility impacts on a pollutant-bypollutant basis for Plant Bowen were as 

follows: 2.13 percent SO2 and 0.07 

percent NOX for Cohutta; 2.77 percent 

for SO2 and 0.01 percent for NOX for 

Okefenokee; and 2.35 percent for SO2

and 0.14 percent for NOX for Wolf 

Island, which results in SO2 visibility 

impacts approximately 17 times greater 

than NOX visibility impacts at each of 

the Georgia Class I areas. The nitrate 

impacts from this facility are far below 

Georgia’s source selection thresholds. 

As EPA has consistently stated, ‘‘When 

selecting sources for analysis of control 

measures, a state may focus on the PM 

species that dominate visibility 

impairment at the Class I areas affected 

by emissions from the state and then 

select only sources with emissions of 

those dominant pollutants and their 

precursors.’’ 2019 Guidance, at p. 11. 

Additional rationale can be found in the 

Response 3, which discusses the 

dominant nature of SO2 emissions in 

Georgia on visibility impairment at 

Class I areas compared to NOX

emissions. 

Comment 10: The Commenters assert 

that EPA must require Georgia to 

consider year-round operation of the 

Selective Catalytic Reduction (SCR) 

systems at each of Plant Bowen’s 

emissions units within the FFA. They 

state that ignoring NOX pollution and 

controls and EPA’s proposal to approve 

Georgia’s decision are not supported by 

the record. Instead, they argue EPA 

must require Georgia to evaluate options 

to reduce NOX emissions at Plant 

Bowen. The Commenters argue that 

although Plant Bowen is equipped with 

low NOX burners, separated overfire air, 

and SCR, Plant Bowen operates the SCR 

optimally only during ozone season, 

that they ‘‘severely underperform,’’ and 

that year-round operation of SCR could 

cut NOX emissions in half. The 

Commenters therefore state that EPA 

must require Georgia to evaluate readily 

implementable NOX controls, such as 

year-round SCR systems operation on a 

30-boiler operating day average NOX


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56Haze Plan, Appendix H–1b, NPS Regional Haze 

SIP feedback for Georgia EPD (June 22, 2022). 

emission limit of between 0.05 lb/ 

MMBtu and 0.07 lb/MMBtu. 

Response 10: EPA finds the 

Commenters’ assertions that EPA must 

require Georgia to analyze year-round 

operation of the SCR systems at Plant 

Bowen’s Units 1–4 unfounded because, 

as discussed in Response 3 and in the 

NPRM, EPA agrees with Georgia’s 

decision to focus on SO2 controls in this 

planning period given, among other 

things, IMPROVE monitoring data from 

the 2014–2018 and 2015–2019 five-year 

periods showing that ammonium sulfate 

is the dominant visibility impairing 

pollutant contributing to regional haze 

at the Class I areas impacted by Plant 

Bowen. As also discussed in Response 

9, the modeled visibility impacts on a 

pollutant-by-pollutant basis for Plant 

Bowen show that modeled visibility 

impacts from SO2 are 17 times higher 

compared to modeled visibility impacts 

from NOX in each of the Class I areas in 

Georgia. Based on these modeled 

visibility impacts, Plant Bowen did not 

meet Georgia’s source selection 

threshold for NOX due to low NOX

impacts. Therefore, EPA finds that 

Georgia appropriately focused on 

evaluating SO2 emissions controls only 

for Plant Bowen for this planning 

period. 

Comment 11: The Commenters 

contend that EPA cannot approve the 

incorporation of Plant Bowen’s Permit 

No. 4911–015–0011–V–04–3 (2023 

Permit Amendment) into Georgia’s SIP 

due to an unlawful startup, shutdown, 

and malfunction (SSM) exemption and 

emergency affirmative defense 

provisions in Plant Bowen’s 2019 title V 

renewal permit 4911–015–0011–V–04–0 

(2019 title V Permit) that could apply to 

the SO2 regional haze SO2 emission 

limit. The Commenters state the ‘‘Excess 

Emission’’ permit condition (i.e., 

Condition 8.14.4 of the 2019 title V 

permit) could allow Plant Bowen to 

exceed its regional haze SO2 limit 

contained in the 2023 Permit 

Amendment during SSM events. 

Additionally, the Commenters argue 

that Plant Bowen’s ‘‘emergency’’ 

affirmative defense provision (i.e., 

condition 8.13.2 of the 2019 title V 

permit) would allow Plant Bowen to 

argue an affirmative defense in any 

enforcement action brought for an 

alleged violation of the facility’s SO2

regional haze limit contained in the 

2023 permit amendment. Thus, the 

Commenters assert that EPA’s proposal 

to incorporate Plant Bowen’s 2023 

Permit Amendment into Georgia’s SIP 

violates the CAA and the RHR. 

Response 11: EPA disagrees with the 

Commenters. The Agency is 

incorporating the 2023 Permit 

Amendment into the Georgia SIP and is 

not incorporating into the SIP any 

portion of the 2019 title V Permit. 

Therefore, the provisions of the 2023 

Permit Amendment will be federally 

enforceable via the SIP as specifically 

provided for in that permit, which 

contains work practice requirements 

that apply during startup and shutdown. 

See 2023 Permit Amendment, Condition 

3.3.8. Additionally, Condition 8.14.4 of 

Plant Bowen’s 2019 title V Permit, 

referenced by the Commenters, is 

substantively the same as Georgia Rule 

391–3–1-.02(2)(a)7 of the State’s 

federally approved SIP. Because this 

rule is already in Georgia’s SIP and 

further because EPA is not adopting 

Condition 8.14.4 into the SIP in this 

action, the Commenters’ concerns are 

without merit. Likewise, Condition 

8.13.2 of Plant Bowen’s 2019 title V 

Permit, also referenced by the 

Commenters, is derived from Georgia 

Rule 391–3–1-.03(10)(d)7, which is a 

rule that is currently approved into 

Georgia’s title V rules. Specifically, that 

rule states that ‘‘40 CFR part 70.6(g) is 

hereby incorporated and adopted by 

reference.’’ On July 21, 2023, EPA 

removed 40 CFR 70.6(g) from the Code 

of Federal Regulations as ‘‘inconsistent 

with the EPA’s interpretation of the 

enforcement structure of the Clean Air 

Act.’’ Id. In accordance with the EPA’s 

July 21, 2023, rulemaking, Georgia is 

likewise required to remove this 

provision from the State’s title V rules. 

See 88 FR 47029. Upon removal of this 

rule from Georgia’s title V program, 

Georgia would then be obligated to 

remove conditions such as Plant 

Bowen’s Condition 8.13.2 from the 

facility’s title V permit. EPA also 

disagrees that the Condition 8.13.2 

would allow Plant Bowen to argue an 

affirmative defense in any enforcement 

action brought for an alleged violation 

of the facility’s SO2 regional haze limit 

contained in the 2023 permit 

amendment. Rather, an affirmative 

defense may only be argued for 

emergencies that meet the specific 

criteria of paragraphs a. though d. of 

Condition 8.13.2. 

Comment 12: The Commenters assert 

that EPA cannot approve Georgia’s FFA 

for Brunswick Cellulose and must 

require the facility to install costeffective controls. They state that due to 

the facility’s ‘‘significant’’ NOX

emissions, EPA must require Georgia to 

conduct an FFA for NOX controls. In 

addition, the Commenters argue that 

Georgia’s FFA, as it pertains to SO2

controls, is ‘‘riddled with errors that 

EPA neither acknowledges nor 

addresses.’’ 

The Commenters state that NPS found 

that Georgia did not follow EPA’s CCM 

in its analyses of wet scrubber and dry 

sorbent injection (DSI) controls for the 

No. 4 Power Boiler and No. 5 and 6 

Recovery Furnaces. The Commenters 

thus contend that to meet its regional 

haze requirements, as well as the 

requirement that EPA must act 

consistently across SIP actions, EPA 

must determine that these deviations 

from EPA’s CCM in its analyses of 

controls for Brunswick Cellulose violate 

the CAA and RHR. 

The Commenters also assert that 

Georgia inappropriately rejected a wet 

scrubber for the No. 4 Power Boiler. 

They contend that ‘‘based even on 

Georgia’s flawed analyses for 

Brunswick, a wet scrubber would likely 

reduce SO2 emissions from the No. 4 

Power Boiler by 141 tpy at a costeffectiveness of $10,330/ton of pollution 

reduced,’’ which they argue is within 

the range of cost thresholds adopted by 

other states. 

Response 12: Regarding the 

Commenters’ assertion that EPA cannot 

approve GA EPD’s FFA for Brunswick 

Cellulose and must require the facility 

to conduct NOX control analyses given 

its NOX emissions and to install costeffective controls for NOX, see Response 

2 and Response 3. In the Haze Plan, GA 

EPD evaluated Brunswick Cellulose’s 

contributions to visibility impairment at 

Class I areas and concluded that SO2

contributions to visibility impairment 

from this facility exceeded State’s AoI 

and PSAT screening thresholds and that 

NOX emissions did not exceed the 

State’s screening thresholds. Therefore, 

Brunswick Cellulose was selected for an 

SO2 FFA, but not for a NOX FFA. As 

discussed in Response 2 and Response 

3, Georgia’s approach was reasonable 

and complies with the RHR. 

Regarding the Commenters’ 

arguments that GA EPD’s FFA of SO2

controls for Brunswick Cellulose is 

‘‘riddled with errors’’ and not properly 

substantiated, the Commenters do not 

discuss any errors with any specificity. 

Instead, the Commenters cite to the 

NPS’s June 22, 2022, letter to GA EPD,56

in which NPS noted that ‘‘the indirect 

operating costs do not reflect the most 

recent CCM wet scrubber chapter 

methods.’’ The Commenters omit, 

however, that NPS also ‘‘agree[d] with 

several revisions made to the cost 

analyses.’’ While the Commenters focus 

on several concerns raised by NPS 

regarding Georgia’s rationale, the 

Commenters omit that in spite of these 

concerns, NPS agreed with Georgia’s 


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57See October 29, 2024, GA EPD email and 

attached file transmitting supplemental emissions 

information for the Brunswick Cellulose No. 6 

Recovery Furnace. 

58 Ga. Dept Nat. Res., Air Quality—Part 70 

Operating Permit, Brunswick Cellulose LLC, Permit 

No. 2631–127–0003–V–07–3 at 3 (Oct. 25, 2023), 

Document No. EPA–R04–OAR–2023–0220–0011 

(providing that Condition 6.2.52 ‘‘demonstrate[s] 

compliance with Condition 3.2.25’’) [hereinafter 

‘‘Brunswick Permit’’]. 

59Email from James Boylan, Chief, Air Prot. 

Branch, Ga. Env’t Prot. Div., to Estelle Bae, Air 

Permits Sec., Air Planning and Implementation 

Branch, Air and Radiation Div., Env’t Prot. Agency 

Region 4 (Apr. 15, 2024), Document No. EPA–R04– 

OAR–2023–0220–0109; Ga. Env’t Prot. Div., 

Response to EPA Regional Haze Questions at 1 

(April 14, 2024), Document No. EPA–R04–OAR– 

2023–0220–0110. 

ultimate conclusion that ‘‘[g]iven that 

the fuel switch is estimated to result in 

a cost savings (even at higher natural gas 

prices), the NPS reviewers concur that 

the incremental costs of selecting a 

scrubber system in lieu of a fuel switch 

are not justified from a cost standpoint.’’ 

Based on EPA’s evaluation of 

Brunswick Cellulose’s cost analyses, 

EPA noted several discrepancies, 

including the addition of property tax 

values to the total indirect operating 

costs. As alluded to in the NPS letter 

cited by the Commenters, these 

discrepancies were addressed prior to 

Georgia’s final SIP submittal. The State’s 

final SIP submittal to EPA included a 

revised cost calculation which was 

nearly identical to EPA’s calculations. 

In the Haze Plan, the State’s cost per ton 

calculation was marginally lower than 

EPA’s calculation due to EPA’s use of a 

lower 3.25 percent bank prime interest 

rate, as recommended by the CCM. 

Although EPA recognizes that GA EPD’s 

cost calculations produced slightly 

lower values compared to EPA’s own 

evaluation in accordance with the CCM, 

the differences in the total cost per ton 

of SO2 removed would not have 

changed the outcome of the FFA. In 

Appendix G–3 of the Haze Plan, GA 

EPD included documentation and 

explained the assumptions that the State 

used in the Brunswick Cellulose FFA, 

including the use of the current bank 

prime rate, a 30-year equipment life, 

and control efficiency assumptions used 

in the scrubber and DSI cost analyses. 

EPA thus does not agree with the 

Commenters that the FFA was not 

properly substantiated. 

The Commenters also argue that 

Georgia inappropriately rejected a costeffective control for the No. 4 Power 

Boiler ($10,330/ton of SO2 reduced for 

the installation of a wet scrubber), 

considering the cost-effectiveness is 

within the range of cost thresholds 

adopted by other states for the second 

planning period. Commenters raised a 

very similar argument regarding Plant 

Bowen, and for the same reasons that 

EPA disagreed with the Commenters’ 

position in Response 9 (regarding Plant 

Bowen), EPA disagrees here as well. 

Furthermore, the $10,330/ton value 

exceeds the highest state cost threshold 

identified by the Commenters ($10,000/ 

ton for Colorado). 

As discussed in Response 5, Georgia 

relied on a spreadsheet of first planning 

period costs developed by Arkansas 

with input from other states and 

supplemented with VISTAS-specific 

data. Georgia determined based on that 

spreadsheet that a cost of $10,330/ton of 

SO2 removed would exceed the 98th 

percentile of all costs incurred by 

sources to control emission in the first 

planning period. On this basis, Georgia 

determined that a cost of $10,330/ton of 

SO2 removed for the installation of a 

wet scrubber at Brunswick Cellulose 

was not a reasonable cost of control. 

Given that the State is not required to 

set a bright-line cost threshold by the 

RHR, the discretion afforded to the state 

to determine whether costs are 

reasonable, and the even-handed and 

consistent methodology applied by 

Georgia to determine whether control 

costs were reasonable for this planning 

period, EPA reaffirms that Georgia’s 

conclusions were reasonable under the 

CAA and RHR. 

Comment 13: The Commenters assert 

that, at a minimum, Brunswick 

Cellulose’s existing measures for the No. 

5 and 6 Recovery Furnaces are 

necessary for reasonable progress. The 

Commenters note that EPA has 

explained that a state can demonstrate 

that a source will continue 

implementing its existing measures 

such that they are not necessary for 

reasonable progress ‘‘based on data and 

information on: (1) The source’s past 

implementation of its existing measures 

and its historical emission rate, (2) the 

source’s projected emissions and 

emission rate, and (3) any enforceable 

emissions limits or other requirements 

related to the source’s existing 

measures.’’ The Commenters state that 

the expected emission ranges provided 

by Georgia for these furnaces are ‘‘very 

wide, with the top of the range being 

more than double the bottom.’’ 

Additionally, the Commenters state that 

nothing in the SIP revision 

demonstrates that emissions will remain 

the same at these units. The 

Commenters state that EPA explains 

that Georgia submitted a supplement to 

its SIP revision providing that the No. 

5 Recovery Furnace’s emissions 

fluctuated from 2016 to 2020 and argued 

that ‘‘the emission rate for the unit is 

within a consistent range limited by the 

Permit.’’ The Commenters therefore 

contend that EPA’s own justification for 

its determination underscores that 

existing permit limits for the facility are 

necessary to make reasonable progress. 

Response 13: EPA disagrees with the 

Commenters. EPA requested 

supplemental information from Georgia 

regarding emissions for the No. 5 

Recovery furnace, which has higher 

emissions than the No. 6 Recovery 

Furnace. Based on 2016 to 2020 

emissions data provided by Georgia to 

EPA that was cited in the NPRM and 

included in the docket, emissions at the 

No. 5 Recovery Furnace ranged from 

0.125 to 0.152 tons SO2/1,000 gallons of 

No. 6 fuel oil burned, demonstrating a 

reasonably consistent SO2 emission rate 

during this time period. The increase in 

total SO2 emissions discussed by the 

Commenters is attributable to increased 

fuel oil burned in the unit and is not 

attributable to an inconsistent emission 

rate. Based on 2016 to 2020 emissions 

data, SO2 emissions decreased from 21.7 

tpy in 2016 to 7.8 tpy in 2020. Because 

emissions remain consistent at the No. 

5 Recovery Furnace, EPA is not 

requiring Georgia to adopt existing 

measures for this emission unit into the 

SIP. This position is also consistent 

with EPA’s 2021 Clarifications Memo. 

See 2021 Clarifications Memo, at p. 9. 

Regarding the No. 6 Recovery Furnace, 

EPA likewise requested supplemental 

information from Georgia. This 

supplemental information is in the 

docket.57 While there is somewhat more 

variability in the emissions rate for this 

unit, the unit’s SO2 emissions are 

extremely low, and therefore existing 

measures at this unit are not necessary 

for reasonable progress. 

Comment 14: The Commenters assert 

that the Brunswick Cellulose permit that 

EPA proposes to incorporate into 

Georgia’s SIP does not include 

practically enforceable emission limits. 

More specifically, they argue the 

Brunswick Cellulose permit does not 

contain sufficient measures to ensure 

the facility complies with the 15 tpy 

SO2 limit for the No. 4 Power Boiler and 

the No. 6 fuel oil burning condition 

during adverse wood/bark conditions. 

The Commenters contend that the 

permit states that Brunswick Cellulose 

‘‘shall use emission factors’’ but does 

not specify what emission factors 

Brunswick Cellulose must use.58 The 

Commenters note that in an April 24, 

2024, email from GA EPD to EPA, GA 

EPD stated that Brunswick Cellulose 

will use an AP–42 emission factor of 

157 S lb/Mgal (where S is the fuel sulfur 

content by weight as a percentage per 

million gallons of fuel).59 However, the 

Commenters contend that AP–42 factors 


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60EPA, ‘‘Enforcement Alert: Reminder About 

Inappropriate Use of AP–42 Emission Factors,’’ 

Publication No. EPA 325–N–20–001 (Nov. 2020), 

available at: https://www.epa.gov/sites/default/files/ 

2021-01/documents/ap42-enforcementalert.pdf. 61Permit No. 2631–127–0003–V–07–3, Condition 

6.2.52, requires the source to use the emission 

factors and the records required by Condition 6.2.51 

to ensure compliance with the 15 tpy SO2 emission 

limit specified in Condition 3.2.25 for the No. 4 

Power Boiler. On April 15, 2024, GA EPD 

supplemented its August 11, 2022, Haze Plan by 

providing clarification on the specific emission 

factor that the source will use for calculating 

compliance with Condition 3.2.25. This April 15, 

2024, email containing the supplemental 

clarification is included in the docket for this 

action. 

62See, e.g., Discussion of interpretive letters in 

‘‘State Implementation Plans: Response to Petition 

for Rulemaking; Restatement and Update of EPA’s 

SSM Policy Applicable to SIPs; Findings of 

Substantial Inadequacy; and SIP Calls To Amend 

Provisions Applying to Excess Emissions During 

Periods of Startup, Shutdown and Malfunction,’’ 80 

FR 33840, 33884–89 (June 12, 2015). 

63On October 16, 2024, GA EPD provided a letter 

to EPA with an interpretation of the phrase ‘‘The 

Permittee shall use emissions factors’’ in Condition 

6.2.52. GA EPD stated in this letter that this phrase 

in Permit Condition 6.2.52 means that Brunswick 

Cellulose will use the same AP–42 emission factor 

as was used to calculate emissions for their permit 

application. The emission factor used by Brunswick 

Cellulose for No. 6 Fuel Oil in No. 4 Power Boiler 

(U700) is 157 S lb/Mgal, where S is the fuel content 

as a percentage. This emission factor was taken 

from Table 1.3–1 of AP–42. This October 16, 2024, 

letter containing the supplemental clarification of 

the emission factor is included in the docket for this 

rulemaking action. 

64 Intercontinental Terminals Company, LLC 

Pasadena Terminal, Title V Order No. VI–2023–13, 

at p. 15. 

65AP–42, Introduction, p. 9. 

66 Id. 

67See AP 42, Fifth Edition, Volume I Chapter 1: 

External Combustion Sources, 1.3: Fuel Oil 

Combustion, available at: https://www.epa.gov/ 

sites/default/files/2020-09/documents/1.3_fuel_oil_

combustion.pdf. 

68See EPA Reminder About Inappropriate Use of 

AP–42 Emission Factors, available at: https://

epa.gov/sites/default/files/2021-01/documents/ 

ap42-enforcementalert.pdf. 

do not reliably predict emissions and 

therefore are insufficient to determine 

compliance. The Commenters note that 

EPA has cautioned that the AP–42 

factors ‘‘are not likely to be accurate’’ 

and ‘‘[u]se of these factors as sourcespecific permit limits . . . is not 

recommended.’’ 60 The Commenters 

further argue that since neither EPA nor 

Georgia can rely on these AP–42 factors 

to establish or demonstrate compliance, 

the 15 tpy SO2 emission limit is not 

practically enforceable and EPA’s 

proposal to incorporate it into the SIP 

violates the CAA and the RHR. 

Response 14: EPA disagrees with the 

Commenters. GA EPD’s April 24, 2024, 

clarification email stated that the facility 

used the 157 S lb/Mgal emission factor 

contained within Table 1.3–1 of AP–42 

in its title V permit application.61 The 

use of interpretive letters to clarify 

ambiguity or perceived ambiguity in the 

provisions in a SIP submission is a 

permissible, and sometimes necessary, 

approach under the CAA.62 So long as 

the interpretive letters and EPA’s 

reliance on them is properly explained 

and documented, regulated entities, 

regulators, and the public can readily 

ascertain the existence of interpretive 

letters relied upon in EPA’s approval 

that would be useful to resolve any 

perceived ambiguity. By virtue of being 

part of the stated basis for EPA’s 

approval of that provision in a SIP 

submission, interpretive letters 

necessarily establish the correct 

interpretation of any arguably 

ambiguous SIP provision. In other 

words, the rulemaking record should 

reflect the shared state and EPA 

understanding of the meaning of a 

provision at issue at the time of the 

approval, which can then be referenced 

should any question about the provision 

arise in a future enforcement action. In 

this action, EPA is approving the 

Brunswick Cellulose emission limit and 

incorporating it into the SIP based on 

Georgia’s interpretation that the phrase 

‘‘shall use emissions factors’’ in 

Condition 6.2.52 means that the source 

shall use an emissions factor of 157 S 

lb/Mgal to calculate SO2 emissions from 

the unit for comparison with the 15 tpy 

emission limit.63 EPA will include an 

entry for this Brunswick Cellulose 

permit in the Georgia source-specific 

SIP table at 40 CFR 52.570(d) with text 

in the explanation column stating that 

‘‘shall use emissions factors’’ refers to 

the use of a 157 S lb/Mgal, from AP–42, 

Chapter 1, Section 1.3: Fuel Oil 

Combustion. For these reasons, EPA 

views the use of this emissions factor as 

a federally-enforceable requirement 

which renders the emission limit 

practically enforceable. 

As for the Commenters’ argument 

regarding the use of AP–42 as the basis 

for this emissions factor, the 

Commenters seem to suggest that AP–42 

emission factors can never be used in 

permitting. While AP–42 emission 

factors should be used with caution 

because source-specific data is always 

more reliable than industry-wide 

averages compiled in AP–42, EPA has 

consistently stated that ‘‘AP–42 

emission factors may be used to 

demonstrate compliance with emission 

limits in certain circumstances’’ and 

that ‘‘[w]hether and how a permit must 

account for uncertainty in AP–42 

emission factors (including the AP–42 

emission factor at issue here) is a factspecific decision, as with essentially all 

other decisions concerning compliance 

assurance.’’ 64

The Commenters do not raise any 

specific facts to suggest that the use of 

AP–42 emission factors here is 

inappropriate. Instead, they simply 

assert that EPA has ‘‘cautioned’’ against 

the use of such emission factors in 

permitting, and the Commenters then 

make a blanket statement that therefore 

such emission factors cannot be used in 

permitting at all. As applied here, the 

Commenters contend that the use of an 

AP–42 emission factor rendered the 15 

tpy emission limit practically 

unenforceable and therefore unlawful 

under the CAA and RHR. 

EPA disagrees. The AP–42 emission 

factor used by GA EPD, which is located 

in Table 1.3–1 of AP–42, is rated ‘‘A’’ 

by EPA, which is the best rating 

available and means that the test quality 

data used by EPA to develop this 

emission factor was ‘‘performed by a 

sound methodology and are reported in 

enough detail for adequate 

validation.’’ 65 An ‘‘A’’ rating also means 

that the ‘‘Factor is developed from Aand B-rated source test data taken from 

many randomly chosen facilities in the 

industry population. The source 

category population is sufficiently 

specific to minimize variability.’’ 66 The 

157 S lb/Mgal AP–42 emission factor, is 

a commonly used and appropriate 

representation of the SO2 emitted from 

a fuel-burning unit, as SO2 emissions 

are almost entirely dependent on the 

sulfur content of the fuel, conservatively 

assuming that 95 percent of the fuel 

sulfur is converted to SO2.67 Scenarios 

where EPA has raised concerns about 

the use of AP–42 emission factors 

generally involve scenarios such as 

synthetic minor permitting limits used 

to avoid major source permitting where 

the synthetic minor limit is near the 

major source threshold. For example, 

EPA is aware of many scenarios where 

permitting agencies have imposed 

emission limits of 249 tpy to avoid the 

250 tpy potential to emit major source 

PSD threshold in CAA 169(1). In such 

instances, precision in any emission 

factors used to develop the emission 

limit and to ensure compliance with the 

limit are essential because small errors 

in such emission factor relative to the 

source’s actual emission could result in 

a facility exceeding pertinent major 

source thresholds. As noted by 

Commenters, EPA issued a compliance 

alert to this effect in November of 

2020.68 The circumstances discussed in 

that compliance alert, however, are not 

present here because under the regional 

haze program, there is not a specific 

numeric threshold, such as a PSD major 

source threshold, that is applicable. 

Under the specific factual circumstances 


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present here, EPA finds that GA EPD’s 

use of this AP–42 emission factor was 

appropriate and that the Commenters’ 

concerns that deviations in Brunswick 

Cellulose’s actual emissions from those 

assumed in the emission factor are 

without merit. 

Comment 15: The Commenters assert 

that the most recently renewed 

Brunswick Cellulose title V permit 

(April 2023) is also affected by the same 

SSM exemption and affirmative defense 

provisions that were detailed above in 

the 2019 Plant Bowen title V permit. 

The Commenters contend that the 

Brunswick Cellulose SSM exemption 

also states that the exemption does not 

apply to ‘‘sources’’ subject to New 

Source Performance Standards 

requirements, and so, it is not clear 

whether that provision applies to 

Brunswick Cellulose’s 15 tpy limit for 

the No. 4 Power Boiler. However, the 

Commenters state if that provision 

applies to the 15 tpy limit, it renders the 

15 tpy limit unlawful and not 

practically enforceable for the same 

reasons raised by the Commenters 

regarding the identical permit 

conditions for Plant Bowen. The 

Commenters thus assert that EPA’s 

proposal to incorporate the 15 tpy limit 

into Georgia’s SIP violates the CAA and 

RHR. 

Response 15: EPA disagrees with the 

Commenters for the same reasons stated 

in Response 11. 

Comment 16: The Commenters assert 

that the Brunswick Cellulose title V 

permit that EPA would be adopting into 

Georgia’s SIP does not contain necessary 

reporting requirements, but instead only 

requires the facility to maintain 

documents ‘‘kept as part of the record’’ 

reflecting its fuel use and emission 

calculations. The Commenters note that 

the permit makes reference to a 

requirement that Brunswick Cellulose 

report its excess emissions, 

exceedances, or excursions in 

accordance with ‘‘the report required in 

Condition 6.1.4’’ of the permit. 

However, the Commenters state that the 

permit as included in EPA’s docket does 

not contain Condition 6.1.4., and thus, 

the Commenters argue that the 

provisions EPA proposes to incorporate 

into the SIP do not meet the 

requirements of the CAA or the RHR. 

Response 16: Permit condition 6.1.7, 

as incorporated, requires Brunswick 

Cellulose to report excess emissions, 

exceedances, or excursions from the 15 

tpy SO2 emission limit and fuel burning 

limitations in accordance with permit 

condition 6.1.4. Permit condition 6.1.4 

requires Brunswick Cellulose to submit 

a written report each quarter that 

contains any excess emissions, 

exceedances, or excursions, and any 

monitor malfunctions during each 

quarterly reporting period. If none of 

these occurred, Brunswick Cellulose 

must still submit a report stating that 

there were no excess emissions, 

exceedances, excursions, or monitor 

malfunctions during the quarterly 

reporting period. Condition 6.1.4. exists 

in a federally enforceable title V permit 

and is referenced in the reporting 

requirement in Condition 6.1.7 that is 

being approved into the SIP. 

Comment 17: The Commenters assert 

that EPA shirks its duty to review 

Georgia’s source-specific FFA for IPSavannah. The control measure at IPSavannah that Georgia determined is 

necessary to make reasonable progress is 

a requirement that the facility no longer 

burn coal at its No. 13 Power Boiler. The 

Commenters contend that EPA cannot 

approve Georgia’s reliance on the 

cessation of coal burning at the No. 13 

Power Boiler because it is not a new 

control and will not reduce IPSavannah’s emissions. The Commenters 

note that IP-Savannah ceased burning 

coal at the No. 13 Power Boiler in 2017, 

three years before the facility submitted 

its FFA to the State and five years before 

Georgia finalized its SIP revision, and 

contend that the measure is therefore 

neither ‘‘new’’ nor ‘‘additional.’’ The 

Commenters state that EPA’s conclusion 

that the control would achieve any 

emission reductions, let alone more 

reductions than other controls analyzed, 

is misleading at best. The Commenters 

contend that IP-Savannah’s baseline 

emissions for its control analysis used 

2018 and 2019 emissions and that 

because these years already accounted 

for the cessation of coal burning, EPA’s 

assertion that this control measure 

would achieve additional reductions in 

SO2 is ‘‘inappropriate double counting.’’ 

Nonetheless, the Commenters agree 

with EPA and GA EPD that this measure 

should be adopted into Georgia’s SIP, 

but the Commenters state that cessation 

of coal combustion at the No. 13 boiler 

should be classified as an existing 

measure. 

Response 17: EPA disagrees with the 

Commenters’ argue that IP-Savannah’s 

cessation of burning coal at the No. 13 

Power Boiler in 2017 is neither ‘‘new’’ 

nor ‘‘additional.’’ Although IP-Savannah 

stopped burning coal voluntarily in 

2017, IP-Savannah was still permitted to 

burn coal and the facility did not 

physically modify the No. 13 Power 

Boiler to remove the capability to burn 

coal. This restriction is a new control for 

regional haze purposes because 

incorporating it into Georgia’s SIP will 

result in the permanent cessation of coal 

combustion at the No. 13 Power Boiler. 

Without this incorporation into the SIP, 

the source could request a permit 

modification to begin combusting coal 

again, which would be inconsistent 

with the requirement to achieve 

reasonable progress under the CAA and 

RHR. The removal of coal as a fuel in 

the No. 13 Power Boiler will result in 

the permanent reduction of 

approximately 2,662 tpy of SO2

emissions reductions per year (see 

column ‘‘SO2 tpy Reductions’’ in Table 

7–35 of the Haze Plan). EPA finds that 

the selected control option is necessary 

for reasonable progress for the second 

period and is therefore adopting this 

measure into the SIP. In response to the 

Commenters’ assertion of the 

‘‘inappropriate double counting’’ of SO2

reductions, the characterization of the 

whether these are ‘‘additional’’ 

reductions is irrelevant. The cessation of 

coal burning is simply a measure that 

EPA is adding to the SIP and is a part 

of the LTS. 

Comment 18: Instead of the cessation 

of burning coal, the Commenters assert 

that EPA must require IP-Savannah to 

install cost-effective circulating dry 

scrubber (CDS) or DSI controls. The 

Commenters argue that Georgia’s 

analysis of these controls for the No. 13 

Power Boiler contain multiple errors 

and unsupported costs, which are 

detailed below. 

First, the Commenters contend that 

the facility’s 20-year ‘‘economic life’’ 

deviates from the CCM, where the 

remaining useful life for these controls 

is 30 years. Second, the Commenters 

contend that IP-Savannah provided only 

vague statements or justifications in 

support of its retrofit factor, that this 

retrofit factor was at the top of EPA’s 

recommended range, and that Georgia 

should have used an average retrofit 

factor of one when considering CDS and 

DSI controls. The Commenters also 

similarly contend that the capacity 

factor of 59 percent for the No. 13 Power 

Boiler is unsupported in the FFA, and 

that Georgia and EPA should have not 

accepted this number without further 

documentation. The Commenters state 

that information in the facilitysubmitted FFA indicates that the actual 

capacity factor is very likely much 

higher at 76.4 percent. The Commenters 

state that Georgia did not require or 

provide any documentation to support 

(1) IP-Savannah’s argument that it 

would have to expand its solid waste 

disposal site to accommodate CDS or 

DSI controls, or (2) the cost of 

expanding the waste disposal site. The 

Commenters contend that the facility’s 

claimed costs for waste disposal are not 

reliable, as the facility escalated the 

costs for expanding its disposal site 


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69See CAA 301(a)(2) and 40 CFR 56.5(a). 

from 2007 to 2021 dollars despite the 

fact that the CCM states that costs 

should not be escalated more than five 

years. 

The Commenters also assert that 

beyond the above-described alleged cost 

analysis errors for CDS and DSI, Georgia 

accepted an unreasonably low 90 

percent removal efficiency for CDS from 

the facility-submitted cost analysis. 

According to the Commenters, the CCM 

states that CDS systems can achieve at 

least 95 percent and possibly over 98 

percent removal efficiency. They further 

contend that Georgia acknowledged in 

the SIP revision that CDS systems can 

achieve 98 percent control in its 

response to comments, but the State still 

stated, without any support or 

explanation, that ‘‘it supports IPSavannah’s choice to use 90 percent as 

an appropriate efficiency factor.’’ 

Separately, the Commenters assert 

that Georgia accepted the same waste 

disposal cost for both CDS and DSI even 

though IP-Savannah’s calculated waste 

rate for CDS was significantly lower 

than that for DSI. Therefore, they argue 

that Georgia should have used a lower 

waste disposal cost in its analysis for 

CDS. In total, the Commenters contend 

that each of these alleged errors resulted 

in artificially inflated control costs for 

CDS and DSI and, therefore, artificially 

inflated cost-effectiveness values. The 

Commenters state that, according to the 

Stamper report attached to the 

Commenters’ comments, by correcting 

some of the noted errors identified by 

the Commenters in Georgia’s analysis, 

CDS and DSI are cost-effective controls 

at $3,790/ton and $5,920/ton of SO2

removed, respectively. 

Related to these points, the 

Commenters assert that Georgia violated 

the RHR’s requirement that it 

adequately document and support the 

technical basis for its control 

determinations, and that EPA does not 

acknowledge or address any of the many 

errors in Georgia’s control analyses. 

They also contend that in response to 

comments, Georgia admits that ‘‘the 

costs associated with [CDS and DSI] 

were not looked at in depth due to [the 

removal of coal burning] being an 

obvious path forward.’’ The 

Commenters contend that EPA’s 

argument that Georgia followed a 

reasonable cost analysis method and 

followed the CCM is unsupported. The 

Commenters state that in proposed 

rulemaking on the Arizona regional 

haze SIP, EPA proposes to conclude the 

FFAs for numerous sources were 

unreasonable because the State based its 

control determinations on, among other 

things, inappropriate emission rates for 

the controls analyzed and 

unsubstantiated deviations from the 

CCM. The Commenters therefore state 

that EPA must treat the errors in 

Georgia’s SIP revision consistently with 

how it has proposed to treat these same 

errors in Arizona’s SIP revision.69

Response 18: EPA disagrees with the 

Commenters’ argument that the Agency 

must require Georgia to ‘‘correct’’ its 

cost analyses, or ‘‘correct’’ those 

analyses itself, and require the 

installation of either CDS or DSI on the 

No. 13 Power Boiler at IP-Savannah to 

make reasonable progress. Georgia’s 

selection of cessation of coal 

combustion as a control met the 

requirements of the RHR and was 

consistent with EPA’s recommended 

process to select controls discussed in 

the 2019 Guidance and the 2021 

Clarifications Memo. Georgia was not 

required to select multiple controls for 

IP-Savannah’s No. 13 Power Boiler and 

applied its reasonable discretion to 

require IP-Savannah to implement the 

most cost-effective control. Moreover, 

even if assuming the Commenters’ 

technical arguments above regarding 

items such as retrofit factors, capacity 

factors, removal efficiency, and waste 

rate are accurate (EPA has not made a 

determination on those points), the cost 

of the other potential controls would 

still be positive, whereas cessation of 

coal combustion has a negative cost 

while still resulting in substantial 

permanent emission reductions. 

Because Georgia was not required to 

select multiple controls for the No. 13 

Power Boiler and further because EPA 

agrees with Georgia’s selection of 

cessation of coal combustion as 

reasonable for this planning period, the 

Commenters’ comments regarding other 

potential control options are without 

merit. 

EPA also disagrees with the 

Commenters’ argument that EPA did not 

evaluate the CDS and DSI in depth due 

to the removal of coal burning being an 

obvious path forward. EPA evaluated 

each assumption used in the cost 

analyses as part of the pre-hearing 

process and throughout the Haze Plan 

development process. 

Comment 19: The Commenters further 

assert that even using Georgia’s cost 

analyses, following the cessation of 

burning coal, CDS (removing 3,674 tpy 

of SO2 at a cost of $5,564/ton) and DSI 

(removing 2,653 tpy of SO2 at a cost of 

$6,245/ton) to control emissions from 

the No. 13 Power Boiler are cost 

effective because ‘‘[t]hese costs are well 

within the range of costs that other 

states have determined are cost effective 

for the second planning period.’’ The 

Commenters argue that EPA’s proposal 

to approve Georgia’s determination that 

these controls are not cost effective 

based on the State’s application of the 

Arkansas cost spreadsheet is arbitrary 

and capricious. 

Response 19: Commenters raised a 

very similar argument regarding Plant 

Bowen, and for the same reasons stated 

in Response 9 (regarding Plant Bowen), 

EPA disagrees here as well. As 

discussed in Response 5 and as noted by 

the Commenters, Georgia relied on a 

spreadsheet of first planning period 

costs developed by Arkansas with input 

from other states and supplemented 

with VISTAS-specific data. Georgia 

determined based on that spreadsheet 

that costs of $5,564/ton of SO2 removed 

for CDS and $6,245/ton of SO2 removed 

for DSI would exceed the 98th 

percentile of all costs incurred by 

sources to control emission in the first 

planning period. On this basis, Georgia 

determined that these were not 

reasonable costs to control emissions for 

this planning period. Given that the 

State provided a detailed 

documentation and justification, and is 

not required to set a bright-line cost 

threshold by the RHR, the discretion 

afforded to the State to determine 

whether costs are reasonable, the 

consistent methodology applied by 

Georgia to determine whether control 

costs were reasonable for this planning 

period, and the flexibility discussed in 

Response 9, EPA reaffirms that Georgia’s 

conclusions were reasonable under the 

CAA and RHR. 

Georgia selected the most costeffective control option for IP-Savannah, 

which is the permanent cessation of 

coal combustion at the No. 13 Power 

Boiler. The selection of this control is 

consistent with EPA’s recommended 

process to select controls as discussed 

in the 2019 Guidance and the 2021 

Clarifications Memo. The selection of 

the most cost-effective control is also 

consistent with Georgia’s approach to 

selection of controls. In short, Georgia 

was not required to select multiple 

controls for IP-Savannah’s No. 13 Power 

Boiler and applied its reasonable 

discretion to require IP-Savannah to 

implement the most cost-effective 

control. This approach is consistent 

with the CAA’s and RHR’s requirements 

that the state selects emission controls 

based upon four factors, including cost. 

See CAA section 169A(g)(1); 40 CFR 

51.308(f)(2)(i). 

Comment 20: The Commenters also 

assert that Georgia and EPA failed to 

consider other available controls to 

reduce IP-Savannah’s haze-forming 

emissions, namely packed bed 

scrubbers. The Commenters contend 


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70See https://www.epa.gov/sites/default/files/ 

2021-05/documents/wet_and_dry_scrubbers_

section_5_chapter_1_control_cost_manual_7th_

edition.pdf. 

71See Section 7.8.1. International Paper— 

Savannah Mill in the 2022 Plan. 

that packed bed scrubbers are a common 

SO2 control option for many industrial 

sources, including paperboard mills like 

IP-Savannah, and that these scrubbers 

are demonstrated to achieve up to 99.99 

percent control efficiency. The 

Commenters note that the CCM includes 

a module for assessing packed bed 

scrubber controls, and the Commenters 

conclude that while the record does not 

contain sufficient information to 

provide a cost analysis for these packed 

bed scrubbers, examples provided in the 

CCM indicate that packed bed scrubbers 

are likely a highly cost-effective control 

option for IP-Savannah. 

Response 20: EPA disagrees with the 

Commenters that GA EPD did not 

consider packed bed scrubbers in IPSavannah’s FFA. Packed tower 

scrubbers (also known as packed bed or 

packed column scrubbers) are a type of 

wet scrubber, and wet scrubbers were 

explicitly considered in IP-Savannah’s 

FFA and were rejected by GA EPD as 

not feasible due to the additional offsets 

to the facility’s water use and freshwater 

demand. See Haze Plan, Appendix G– 

2b, at p. 2–7 and 2–8. Thus, for the 

reasons stated in Responses 17 and 18, 

EPA disagrees. 

Packed tower scrubbers can achieve 

high removal efficiencies, handle high 

liquid rates, and have relatively lower 

water consumption requirements than 

other types of gas absorbers. However, 

packed towers may also have high 

system pressure drops, high clogging 

and fouling potential, and extensive 

maintenance costs due to the presence 

of packing materials. Installation, 

operation, and wastewater disposal 

costs may also be higher for packed bed 

scrubbers than for other absorbers.70 In 

addition to pump and fan power 

requirements and solvent costs, packed 

towers have operating costs associated 

with replacing damaged packing. 

Wet scrubbers such as packed tower 

scrubbers have water use and water 

discharge requirements that can make 

these controls not feasible in certain 

situations. According to GA EPD, 

treated wastewater from IP-Savannah is 

discharged to the Savannah River. IPSavannah’s 2019 National Pollutant 

Discharge Permit currently limits this 

facility’s wastewater discharge, and the 

facility has since committed to meet 

biologically based Ultimate Oxygen 

Demand limits which represent an 

approximately 85 percent reduction 

from its current permit limits. The 

facility is also limited on how much 

groundwater can be withdrawn, and its 

water withdrawal permit limits will be 

lower starting in 2025, which will cause 

any projects requiring additional water 

use to be offset by water-savings 

projects.71 Thus, a wet scrubber, which 

would represent 10 percent of the 

facility’s freshwater demand, was 

deemed not feasible by GA EPD. EPA 

agrees with GA EPD that adding a 

packed tower scrubber to control SO2

emissions from IP-Savannah would not 

be reasonable based upon Georgia’s 

technical determinations that this 

control is not feasible. Because this 

control is not feasible, neither GA EPD 

nor EPA performed a cost analysis for 

this control option. 

EPA disagrees that Georgia did not 

consider other available control options 

for reducing SO2. Georgia also evaluated 

the feasibility of a dry scrubber for the 

No. 13 Power Boiler. While a dry 

scrubber does not have the same 

additional needs for water as a wet 

scrubber, EPA agrees with Georgia’s 

determination that a dry scrubber was 

considered not technically feasible due 

to costs from the additional solid waste 

and wastewater generated and the 

expansion of the existing mill-owned 

landfill. 

Comment 21: The Commenters argue 

that IP-Savannah is a significant source 

of NOX pollution. The commenters 

contend that EPA must require Georgia 

to conduct an FFA for NOX controls on 

the facility’s emission units to ensure 

that the State requires a reasonable 

range of controls to make progress. 

Response 21: For the reasons stated in 

Response 2 and Response 3, EPA 

disagrees with the Commenters. In the 

Haze Plan, GA EPD evaluated IPSavannah’s contributions to visibility 

impairment at Class I areas and 

concluded that SO2 contributions to 

visibility impairment from this facility 

exceeded State’s AoI and PSAT 

screening thresholds and that NOX

contributions did not exceed the State’s 

screening thresholds. Therefore, IPSavannah was selected for an SO2 FFA 

but not for a NOX FFA. As discussed in 

Response 3, Georgia’s approach was 

reasonable and complies with the RHR. 

Comment 22: The Commenters assert 

that EPA ignores that the IP-Savannah 

title V permit that Georgia proposes to 

incorporate into its SIP does not include 

necessary reporting requirements. The 

Commenters argue that IP-Savannah’s 

permit, as reproduced in EPA’s docket, 

only includes provisions requiring the 

facility to ‘‘measure and record’’ 

information reflecting fuel use for the 

No. 13 Power Boiler. The permit makes 

reference to a requirement that IPSavannah report its excess emissions, 

exceedances, or excursions in 

accordance with ‘‘the report required in 

Condition 6.1.4’’ of the permit. 

However, the Commenters state that the 

permit does not contain Condition 6.1.4, 

and therefore the provisions EPA 

proposes to incorporate into the SIP do 

not include necessary reporting 

provisions and do not meet the 

requirements of the CAA or RHR. 

Response 22: Permit condition 6.1.7, 

as incorporated, requires IP-Savannah to 

report excess emissions, exceedances, or 

excursions in accordance with permit 

condition 6.1.4, as it relates to the 

burning of coal in the No. 13 Power 

Boiler. Permit condition 6.1.4 requires 

IP-Savannah to submit a written report 

each quarter that contains any excess 

emissions, exceedances, or excursions, 

and any monitor malfunctions during 

each quarterly reporting period. If none 

of these occurred, IP-Savannah must 

still submit a report stating that there 

were no excess emissions, exceedances, 

excursions, or monitor malfunctions 

during the quarterly reporting period. 

Condition 6.1.4 exists in a federally 

enforceable title V permit and is also 

referenced in the portions of the permit 

being approved into the SIP. 

Comment 23: The Commenters assert 

that EPA ignores that Georgia’s SIP does 

not address measures necessary to 

prevent future impairment as is required 

at Class I areas by the CAA and RHR. 

The Commenters contend that EPA has 

historically relied on new source 

permitting programs, ‘‘like the [PSD] 

and [NSR] programs,’’ to address the 

CAA’s prevention of future impairment 

mandate, but these programs ‘‘have 

changed dramatically over the decades.’’ 

The Commenters state that current PSD 

rules, as well as the nonattainment NSR 

rules, now exempt many modifications 

at existing major sources that were 

previously subject to PSD review. As a 

result, the Commenters state that the 

PSD and NSR rules do not provide as 

comprehensive Class I area visibility 

protections as they previously did. The 

Commenters thus contend that it is 

imperative that Georgia’s LTS include 

measures to prevent future visibility 

impairment from new sources, as well 

as new modifications at existing sources 

of haze pollution. 

More specifically, the Commenters 

assert that Georgia does not discuss 

anywhere in its SIP revision (1) the 

programs it has in place to address any 

potential future increases in emissions 

or (2) any pending air permit 

applications for sources that may 

contribute to future impairment at Class 


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72See 40 CFR 51.308; 64 FR 35714, July 1, 1999; 

and 82 FR 3078, January 10, 2017. 

73See ‘‘Guidance on Regional Haze State 

Implementation Plans for the Second 

Implementation Period’’ available at: www.epa.gov/ 

visibility/guidance-regional-haze-stateimplementation-plans-second-implementationperiod. EPA Office of Air Quality Planning and 

Standards, Research Triangle Park (August 20, 

2019). 

74See ‘‘Clarifications Regarding Regional Haze 

State Implementation Plans for the Second 

Implementation Period’’ available at: www.epa.gov/ 

system/files/documents/2021-07/clarificationsregarding-regional-haze-state-implementationplans-for-the-second-implementation-period.pdf. 

EPA Office of Air Quality Planning and Standards, 

Research Triangle Park (July 8, 2021). 

I areas in Georgia or other states. As an 

example, the Commenters state that 

Georgia is currently reviewing a permit 

application and draft permit from Twin 

Pines Minerals which proposes to locate 

a mine just three miles from 

Okefenokee. Although Twin Pines 

Minerals’ permit application indicates 

that the mine’s emissions would be 

relatively low, the Commenters state 

that the application is missing 

information on emission sources and 

potential emission levels. As a result, 

the Commenters state that it is nearly 

impossible for the public to determine 

exactly what kind of impact the 

proposed mine may have on air quality 

at Okefenokee. The Commenters state 

that the SIP revision does not address 

this facility, or any other proposed new 

sources or modifications. They assert 

that this underscores the need for the 

State to address measures to prevent 

future impairment to ensure that it is 

meeting the CAA’s natural visibility 

goal. Furthermore, they state that 

nowhere in EPA’s proposed approval 

does the Agency acknowledge or 

address the fact that Georgia’s SIP 

revision entirely omits any discussion of 

measures to prevent future impairment. 

Finally, they contend that EPA’s 

proposal to approve Georgia’s SIP is 

therefore arbitrary and capricious, in 

violation of the CAA and RHR. 

Response 23: Contrary to the 

Commenters’ assertions, there is no 

requirement in the CAA or for states’ 

second planning period regional haze 

plans to assess and/or adopt emission 

reduction measures into the SIP for 

hypothetical new emissions sources that 

do not yet exist (e.g., those which have 

not yet been constructed and/or are not 

yet in operation) to prevent future 

visibility impairment at Class I areas. 

Nor do the Commenters cite to legal 

authority suggesting that the CAA or 

RHR require this. Instead, the 

Commenters cite to CAA section 

169A(a)(1); 40 CFR 51.300(a), and 40 

CFR 51.308(f)(2)(iv)(B). 

None of these statutes and regulations 

support the Commenters’ assertions. 

CAA section 169A(a)(1) states the 

‘‘national goal’’ underlying the regional 

haze program ‘‘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.’’ In support of this goal, 

Congress required EPA to ‘‘promulgate 

regulations to assure (A) reasonable 

progress toward meeting the national 

goal specified in paragraph (1), and (B) 

compliance with the requirements of 

this section.’’ EPA has done so by 

promulgating the RHR, which the 

Commenters also cite to. 40 CFR 

51.300(a), cited by the Commenters, is 

entitled ‘‘Purpose and applicability’’ 

and restates the national goal from CAA 

section 169A(a)(1). This provision, 

while providing important context to 

the RHR, contains no independent 

requirements that states must meet and 

therefore does not support the 

Commenters’ position. 

The remaining citation to the RHR 

provided by the Commenters, 40 CFR 

51.308(f)(2)(iv)(B), similarly does not 

support the Commenters’ position. That 

provision states in full as follows: ‘‘The 

State must consider the following 

additional factors in developing its longterm strategy: Measures to mitigate the 

impacts of construction activities.’’ 

Contrary to the Commenters’ assertions, 

Georgia plainly addressed this 

requirement in its Haze Plan. See Haze 

Plan, at p. 221 (noting that ‘‘Measures to 

mitigate the impacts of construction 

activities’’ are addressed in Section 

7.9.2 of the Haze Plan); see also Haze 

Plan Section 7.9.2 (discussing ‘‘Dust and 

Fine Soil from Construction 

Activities’’). 

At bottom, the RHR addresses ‘‘the 

prevention of any future’’ visibility 

impairment by ensuring that reasonable 

progress measures are adopted into 

states’ SIPs. In this way, the RHR 

renders such measures permanent, 

which necessarily prevents future 

visibility impairment from those 

emission sources. Because neither the 

CAA nor RHR requires further measures 

to address future construction, the 

Commenters’ comments regarding the 

Twin Pines Minerals permit are 

acknowledged, but are not relevant. 

Comment 24: The Commenters argue 

that EPA’s proposal to approve 

Georgia’s RPGs violate the CAA and 

RHR. The Commenters maintain that in 

EPA’s SIP planning sequence, states first 

identify their LTS controls, which is 

followed by the development of RPGs. 

However, the Commenters contend that 

EPA fails to acknowledge that Georgia’s 

established RPGs for its three in-state 

Class I areas are based on VISTAS 

modeling results which were conducted 

in 2020. They comment this was 

completed before conducting FFAs or 

finalizing the State’s LTS controls in 

2022. Therefore, the Commenters assert 

that Georgia impermissibly reversed the 

SIP planning sequence and that 

Georgia’s RPGs are based on modeling 

results which do not meet the RHR 

requirement that RPGs must be based on 

enforceable SIP measures. The 

Commenters argue that Georgia’s 

response to comments ignored the 

problems raised regarding the RPGs and 

that Georgia’s response that the State’s 

RPGs ‘‘are representative of all known 

control measures necessary to make 

reasonable progress’’ is unfounded. 

Additionally, the Commenters assert 

that Georgia ‘‘cherry-picked’’ a 

statement from EPA’s 2019 Guidance in 

response to the concerns raised, i.e., 

EPA’s statement that states may conduct 

modeling to establish RPGs before ‘‘the 

outcome of some final state decisions on 

emission control measures [are] 

known.’’ The Commenters state Georgia 

ignored other parts of EPA’s 2019 

Guidance explaining that if a state 

conducted modeling for RPGs before 

finalizing LTS control determinations, 

the state must adjust its RPGs to 

reconcile the scenarios before the SIP 

revision with the RPGs is submitted. 

The Commenters argue that nothing in 

Georgia’s SIP revision or EPA’s proposal 

indicates that Georgia made adjustments 

to its RPGs after its FFA and finalizing 

its LTS, which the Commenters argue is 

contrary to EPA’s 2019 Guidance. Thus, 

the Commenters contend that EPA must 

not approve Georgia’s RPGs for its three 

Class I areas and must require that 

Georgia adjust those goals to properly 

reflect enforceable emission limitations 

adopted in the LTS portion of Georgia’s 

SIP. 

Response 24: EPA disagrees that 

Georgia’s RPGs must be disapproved on 

the basis that they do not reflect any 

new measures resulting from the three 

FFAs. EPA reiterates that the process for 

establishing RPGs for each Class I area 

is prescribed in the RHR and its 

amendments and discussed in related 

guidance.72 73 74 The RPGs established 

by the states with Class I areas are not 

directly enforceable but will be 

considered by the Administrator in 

evaluating the adequacy of the measures 

in the implementation plan in providing 

for reasonable progress towards 

achieving natural visibility conditions at 

that area. See 40 CFR 51.308(f)(3)(iii). 

As explained in footnote 34 of the 

NPRM of the Georgia Haze Plan, RPGs 

are intended to reflect the projected 

impacts of the measures all contributing 


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states include in their LTS. However, 

due to the timing of analyses, control 

determinations by other states, and 

other ongoing emissions changes, a 

particular state’s RPGs may not reflect 

all control measures and emissions 

reductions that are expected to occur by 

the end of the planning period. 

Because the air quality modeling to 

calculate RPGs is resource intensive and 

time consuming, EPA does not always 

expect the modeling to be repeated after 

a subsequent change in the content of a 

state’s own LTS or another state’s LTS 

that impacts the host state’s Class I 

area(s). 2019 Guidance at 47–48. 

Adjustment of the RPGs once 

modeling is completed to reflect new 

FFA outcomes is not required. However, 

the 2019 Guidance provides 

recommendations for addressing the 

timing of RPG calculations when states 

are developing their LTS on disparate 

schedules and for adjusting RPGs using 

a post-modeling approach. The outcome 

of a state’s source selection process and 

subsequent evaluation of technically 

feasible and cost-effective emissions 

controls as part of FFAs determine what 

constitutes the state’s LTS for that 

particular planning period. If a state’s 

source selection process and evaluation 

of technically feasible and cost-effective 

controls results in a LTS that includes 

the enforceable emissions limitations, 

compliance schedules and other 

measures that are necessary to make 

reasonable progress, then the 

requirements of the RHR are satisfied for 

that planning period. Any additional 

emissions reductions resulting from 

new FFA measures not included in the 

2028 RPGs serve to provide further 

assurance that the State’s Class I areas 

and those areas affected by the State’s 

sources will achieve their 2028 RPGs. 

Comment 25: The Commenters assert 

that EPA’s proposal to approve 

Georgia’s state-to-state consultations 

violates the CAA and RHR. They 

specifically mention EPA’s 2017 

amendments to the RHR stating ‘‘states 

must exchange their four factor analyses 

and the associated technical information 

that was developed in the course of 

devising their long-term strategies.’’ 

The Commenters contend that EPA 

treats the consultation process as a boxchecking exercise. Additionally, they 

argue that EPA’s proposal and TSD only 

recites what Georgia provided regarding 

its consultation, without conducting an 

independent analysis, and that EPA 

only mentioned that Georgia 

documented its consultation with other 

states. The Commenters assert that 

Georgia failed to independently assess 

whether additional controls on out-ofstate sources are needed to achieve 

reasonable progress. Therefore, both 

Georgia and EPA will need to 

independently evaluate all information 

in the record, as well as provide an 

explanation for their final 

determinations. 

The Commenters state that Georgia 

recognizes that sources from other states 

are projected to impact visibility in 

Georgia’s Class I areas, and the State 

requested FFAs from Florida, South 

Carolina, Kentucky, Tennessee, Ohio, 

Indiana, and Pennsylvania. However, 

the Commenters state that few of the 

out-of-state sources are adopting new 

control measures as a result of the FFAs. 

Furthermore, the Commenters assert 

that Georgia failed to critically evaluate 

whether additional controls are 

warranted from out-of-state sources to 

ensure reasonable progress. 

The Commenters assert that EPA must 

require that Pennsylvania optimize or 

upgrade controls at the Keystone 

Generating Station (Keystone Station). 

The Commenters state that the Keystone 

Station is not exempt from an FFA 

simply because it has systems (FGD and 

SCR) in place that meet the Mercury and 

Air Toxics Standards rule. Additionally, 

the Commenters contend that the 

scrubbers currently in place are 

underperforming and do not achieve at 

least 95 percent control efficiency, let 

alone the 98 percent control efficiency 

that a modern wet scrubber system is 

capable of continuously achieving. The 

Commenters state that of the control 

measures that Keystone Station did 

consider in FFA, running one more 

level of recycle pumps would be costeffective ($413/ton of NOX), and must be 

required. The Commenters argue that 

modern SCR systems have been shown 

to operate at an average monthly NOX

emission rate of 0.05 lb/MMBtu or 

lower, whereas the current SCR systems 

in Units 1 and 2 of the Keystone Station 

in 2019 have higher NOX emissions 

rates of 0.104 and 0.103 lb/MMBtu, 

respectively. In response to the 

Keystone Station’s assertion that 

optimization of the current SCR systems 

will be addressed in a future case-bycase NOX reasonably available control 

technology (RACT) analysis, the 

Commenters contend that a future 

RACT analysis is not an offramp from 

the regional haze requirements that 

apply now. Furthermore, the 

Commenters argue that the outcome of 

the RACT analysis will likely be 

different and less stringent because the 

analysis applies a different set of factors. 

Therefore, the Commenters assert that 

EPA must require Pennsylvania to direct 

the Keystone Station to evaluate 

additional cost-effective control 

measures, and the agency must ensure 

that the accuracy of cost-effectiveness 

arguments regarding the new controls 

are supported and documented. 

The Commenters also assert EPA must 

require that Ohio direct the Gavin 

Power Plant (Plant Gavin) to optimize or 

upgrade controls. The Commenters 

argue that Ohio failed to show that NOX

emissions from Plant Gavin are 

effectively controlled since the State did 

not show that an FFA for NOX control 

on the facility would be futile. 

Furthermore, the Commenters contend 

that nothing in the RHR itself permits 

the states to exclude sources from an 

FFA on the basis that they are 

‘‘effectively controlled.’’ Moreover, the 

Commenters argue that Plant Gavin’s 

FFA of SO2 controls contain errors, and 

that there are feasible and cost-effective 

controls available that can reduce SO2

emissions from the facility. The 

Commenters maintain that because 

Plant Gavin likely contributes to the 

impairment to both Georgia’s and Ohio’s 

Class I areas, EPA must require Ohio to 

perform an FFA of NOX controls and 

implement available and cost-effective 

SO2 controls for Plant Gavin. 

The Commenters further assert that 

EPA cannot approve Georgia’s 

consultation with Indiana. The 

Commenters state that Georgia disagreed 

with Indiana’s response to not require 

FFAs from its EGUs (including Gibston 

Station and AEP Rockport Generating 

Station), and Georgia’s consultation 

record is incomplete because ‘‘there is 

no record of the Indiana disagreement in 

the Georgia SIP.’’ If Georgia does 

disagree with Indiana, the Commenters 

argue that 51.308(f)(2)(ii)(C) would 

apply, which requires Georgia to 

‘‘describe the actions taken to resolve 

the disagreement’’ and EPA ‘‘take this 

information into account.’’ The 

Commenters assert that EPA cannot 

approve of Georgia’s state-to-state 

consultation because Georgia has not 

adequately documented its 

disagreement and resolution of the 

disagreement with Indiana, which the 

Commenters state is in violation of the 

CAA and the RHR. 

Response 25: 40 CFR 51.308(f)(2)(ii) 

provides that a ‘‘State must consult with 

those States that have emissions that are 

reasonably anticipated to contribute to 

visibility impairment in the mandatory 

Class I Federal area to develop 

coordinated emission management 

strategies containing the emission 

reductions necessary to make reasonable 

progress.’’ If the state disagrees, the state 

must describe the actions taken to 

resolve the disagreement (40 CFR 

51.308(f)(2)(ii)(C)). 


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75FWS, FS, and EPA representatives were also in 

attendance at the June 14, 2022, Georgia-NPS 

consultation meeting. 

Consultation may include efforts to reach 

agreement on the measures that each state 

will apply to its sources, or agreement on 

decision thresholds and other decision 

approaches, but it does not require such 

effort by any state and does not require that 

agreements be reached. If neither consulting 

state has sought an agreement about 

measures to be included in their SIP revision, 

neither state is required to include in its 

implementation plan the description 

mentioned in this requirement. However, if 

one state has formally asked another state to 

adopt a particular measure for a particular 

source, and the second state has not adopted 

that measure and also has not adopted an 

equivalent measure(s) as described in 40 CFR 

51.308(f)(2)(ii)(A), then both states are subject 

to this requirement to describe the actions 

taken to resolve the disagreement. This 

provision does not specify that any particular 

actions towards resolution be taken. If the 

two states submit SIP revisions that disagree 

on the controls in each state that are needed 

for reasonable progress, the RHR provides for 

EPA to consider the technical information 

and explanations presented by both states 

when considering whether to approve each 

state’s SIP. 

2019 Guidance, at p. 53. 

EPA’s review of Georgia’s interstate 

consultation process was hardly a box 

checking exercise, as EPA 

independently reviewed all of the 

consultation documentation provided 

by Georgia within its Haze Plan. Those 

materials are primarily contained in 

Appendix F of the Haze Plan, and EPA 

affirms that GA EPD properly complied 

with 40 CFR 51.308(f)(2)(ii) by 

consulting with Florida, South Carolina, 

Tennessee, Kentucky, Indiana, 

Pennsylvania, and Ohio and requesting 

FFAs for facilities located within those 

states with visibility impacts to Georgia 

Class I areas exceeding one percent for 

SO2 or NOX. Specifically, five facilities 

are located in Florida, one facility is 

located in Kentucky, two facilities are 

located in South Carolina, one facility is 

located in Tennessee, two facilities are 

located in Indiana, two facilities are 

located in Ohio, and one facility is 

located in Pennsylvania. Regarding 

Indiana specifically, Georgia 

documented communications between 

Georgia and Indiana in Appendix F–2b 

of the Haze Plan, and on pages 243–244 

of the Haze Plan narrative, Georgia 

indicated that Indiana ‘‘is not requiring 

4-factor analyses from its EGUs.’’ 

Georgia does not explicitly state its 

disagreement with Indiana, but based on 

the record, the states appear to disagree 

based on Georgia’s request for FFAs at 

Plant Gibson and AEP Rockport along 

with Georgia’s documentation within its 

Haze Plan that Indiana will not be 

preparing FFAs for these two facilities. 

As noted elsewhere in Georgia’s Haze 

Plan, AEP Rockport’s SO2 impact on 

visibility at Cohutta is 4.68 percent, and 

Plant Gibson’s SO2 impact on visibility 

at Cohutta is 2.31 percent. In accordance 

with 40 CFR 51.308(f)(2)(ii), Georgia has 

adequately documented its position and 

Indiana’s position, including in a letter 

VISTAS sent to Indiana on behalf of 

Georgia dated June 22, 2020, requesting 

FFAs for these facilities, as well in 

follow-up emails. See Haze Plan, 

Appendix F–2b. 

In regards to the Commenters’ 

contention that EPA must require 

controls at facilities outside of Georgia 

in this action on Georgia’s regional haze 

SIP, this action is not the appropriate 

forum to submit such comments. To the 

extent that Commenters have concerns 

about facilities outside of Georgia, such 

as those facilities in Pennsylvania, Ohio, 

and Indiana, any public comments 

related to out-of-state sources should be 

provided during the public comment 

periods regarding those states’ haze 

plans. Georgia lacks authority to 

regulate these out-of-state sources, and 

therefore EPA cannot require other 

states to implement control measures 

through the Georgia regional haze SIP. 

Comment 26: The Commenters assert 

that EPA must disapprove Georgia’s SIP 

because the State failed to engage in 

meaningful FLM consultation. The 

Commenters state that while Georgia 

did summarize and respond to the 

FLMs’ comments, it did not 

meaningfully consider or incorporate 

the suggestions into the SIP. The 

Commenters contend that ‘‘[c]ontrary to 

the CAA and RHR, Georgia treated the 

consultation as a box-checking exercise’’ 

and released the draft of the SIP revision 

for public comments only two days after 

it closed the formal consultation with 

FLMs. The Commenters argue that 

Georgia made only minor edits to the 

SIP based upon the FLMs’ comments 

and did not fully respond to the many 

concerns raised. Some concerns 

included screening thresholds that led 

to very few Georgia sources for analysis, 

exclusion of NOX from FFAs, lack of 

FFAs for multiple facilities (Plant 

Wansley, Plant Scherer, the Rome 

Linerboard Mill, Brunswick Cellulose, 

and IP-Savannah), concerns about the 

FFA for SO2 at Plant Bowen, and 

concerns about the VISTA modeling 

approach. Therefore, the Commenters 

assert that EPA must reject Georgia’s SIP 

revision on that basis that the State 

failed to meet the CAA’s and RHR’s 

requirement to ‘‘engage in meaningful 

FLM consultation.’’ Additionally, the 

Commenters argue that because EPA 

must disapprove of Georgia’s source 

selection method, FFA, and RPGs, the 

Agency must also disapprove of 

Georgia’s FLM consultation on the basis 

that the FLM consultation was based 

upon a SIP revision that did not meet 

the statutory and regulatory 

requirements of the CAA and RHR. 

Response 26: The FLMs play 

important roles in addressing visibility 

at Class I areas. 40 CFR 51.308(i)(3) 

requires states to include a description 

of how they address any comments 

provided by the FLMs. However, neither 

the CAA nor the RHR requires the state 

to agree with the FLM 

recommendations, nor do they specify 

the degree of consideration that must be 

given to those comments. Rather, 40 

CFR 51.308(i)(3) requires the State to 

‘‘include a description of how it 

addressed any comments provided by 

the Federal Land Managers.’’ 

Georgia complied with this 

requirement by documenting how it 

addressed the FLMs’ comments in 21 

pages of single-spaced responses to the 

FLMs’ comments contained within 

Appendix H–4a of its Haze Plan. The 

Commenters do not identify any specific 

FLM comments that Georgia did not 

respond to. EPA reviewed GA EPD’s 

responses and finds that they comply 

with the RHR requirement to describe 

how the state addressed comments 

provided by the FLMs. EPA thus 

disagrees with the Commenters that GA 

EPD did not fully respond to the FLMs’ 

comments. 

The timing of this consultation was 

also compliant with the RHR. FLM-State 

consultation must take place at least 60 

days prior to the state public comment 

period on any haze plan or plan revision 

pursuant to 40 CFR 51.308(i)(2). GA 

EPD complied this RHR requirement by 

initiating consultation with the FLMs on 

April 22, 2022, which was 62 days 

before the opening of the State’s public 

comment period on June 24, 2022. In 

addition, GA EPD met with NPS upon 

request on June 14, 2022, to discuss 

NPS’ feedback in more detail.75

Comment 27: The Commenters assert 

that EPA must consider the 

environmental justice (EJ) impacts of 

Georgia’s SIP revision. The Commenters 

state that EPA states it can ignore EJ 

implications of Georgia’s SIP revision, 

and that the Agency contravenes 

directives from the current presidential 

administration, as well as EPA’s 

commitments and action plans. The 

Commenters contend that EPA cannot 

argue to prioritize EJ while also 

disavowing any need to consider the 

disproportionate impacts of haze 

pollution sources in Georgia and its own 

actions on Georgia’s SIP revision. 


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76The ‘‘Executive Order on Revitalizing Our 

Nation’s Commitment to Environmental Justice for 

All’’ is available at: https://www.whitehouse.gov/ 

briefing-room/presidential-actions/2023/04/21/ 

executive-order-on-revitalizing-our-nationscommitment-to-environmental-justice-for-all/. 

77U.S. Env’t Prot. Agency, E.O. 13985 Equity 

Action Plan at 4–11 (Apr. 2022), see https://

www.epa.gov/system/files/documents/2022-04/epa

equityactionplanapril2022508.pdf. 

78EJScreen, an EJ screening and mapping tool, is 

available at: https://www.epa.gov/ejscreen. 

79See ‘‘EPA Legal Tools to Advance 

Environmental Justice’’, May 2022, available at: 

https://www.epa.gov/system/files/documents/2022- 

05/EJ%20Legal%20Tools%20May

%202022%20FINAL.pdf at 35–36. 

The Commenters assert that executive 

orders (EOs), as well as EPA’s own 

commitments and action plans direct 

the Agency to consider EJ implications. 

The Commenters state that EOs in place 

since 1994 require EPA to incorporate EJ 

as ‘‘part of its mission by identifying 

and addressing . . . disproportionately 

high and adverse human health or 

environmental effects of its program, 

policies, and activities,’’ which they 

argue to be applicable to regional haze 

SIP actions on minority populations and 

low-income populations. Additionally, 

the Commenters argue the directive to 

incorporate EJ into all of the Agency’s 

actions was reaffirmed by the Biden 

Administration in 2021 through back-toback EOs directed to federal agencies, 

including EPA, and again in 2023 when 

the Administration issued the 

‘‘Executive Order on Revitalizing Our 

Nation’s Commitment to Environmental 

Justice for All.’’ 76

The Commenters state that 

Administrator Regan recognized that 

EPA has a lead role in coordinating EJ 

efforts across the country and ‘‘urged all 

EPA offices to take ‘affirmative steps to 

incorporate environmental justice 

consideration into their work . . . in 

regulatory development processes and 

to consider regulatory options to 

maximize benefits to these 

communities,’ ’’ and the Commenters 

argue that EPA’s Equity Action Plan 77

issued in 2022 makes equity, EJ, and 

civil right a centerpiece of the agency’s 

regulatory work, which includes actions 

on regional haze SIPs. Furthermore, the 

Commenters assert that the 

determination of which sources to 

selected for an FFA and the reasonable 

progress measure to require for a source 

should incorporate EJ and equity into 

technical analyses, citing EPA’s 2019 

Guidance, which specifies that ‘‘[s]tates 

may also consider any beneficial non-air 

quality environmental impacts,’’ as well 

as the 2021 Clarification Memo issued 

by the Agency. 

The Commenters contend that EPA 

ignores the previously mentioned EOs, 

plans, and commitments when 

concluding that it is not required to 

consider EJ impacts of pollutants that 

contribute to regional haze from 

Georgia’s sources and actions on the SIP 

revision. The Commenters state that the 

same pollutants that affect visibility at 

national parks and wilderness areas also 

cause significant public health impacts, 

particularly those who live closest to the 

facilities. 

Drawing from EJScreen data,78 the 

Commenters state that emissions from 

sources of concern raised by NPS and 

the Commenters in their comments to 

Georgia are likely impacting areas 

characterized by higher percentages of 

low income and people of color. 

Specifically, within a 10-mile radius of 

Plant Bowen, the Commenters state that 

32 percent of the population are lowincome and 25 percent as people of 

color, with the community surround the 

plant in the 73rd percentile for the PM 

EJ Index and 67th percentile for ozone 

EJ Index when compared to the rest of 

the country. The Commenters state that 

analysis conducted by a Clean Air Task 

Force, based on 2019 emissions, shows 

that Plant Bowen’s emissions are 

responsible for ‘‘59 deaths, 7 hospital 

admissions, 13 asthma ER visits, 28 

heart attacks, 34 cases of acute 

bronchitis, 637 asthma attacks, and 3020 

lost work days each year.’’ The 

Commenters also highlight the 

community surrounding IP-Savannah, 

which they state is 37 percent lowincome and 59 percent people of color, 

as well as being in the 77th percentile 

for the PM EJ index when compared to 

the rest of the country. Additionally, the 

Commenters argue that the population 

surrounding the Rome Linerboard Mill, 

a facility that Georgia did not select or 

analyze in its SIP revision and EPA does 

not discuss in its proposal, is comprised 

of 44 percent low-income and 40 

percent people of color, and in the 82nd 

percentile for PM EJ index and 71st 

percentile for ozone EJ index. The 

Commenters contend that the sources 

from the facilities identified above are 

likely adversely impacting those 

communities and assert that EPA can 

and must hold Georgia accountable to 

consider EJ impacts of haze pollution 

from in-state sources, as well as analyze 

the potential disparate impacts of its 

action on Georgia’s SIP revision. 

Response 27: EPA disagrees with this 

comment but acknowledges the 

EJScreen information provided by the 

Commenters. The regional haze 

statutory provisions do not explicitly 

address considerations of EJ and neither 

do the regional haze regulatory 

requirements of the second planning 

period in 40 CFR 51.308(f), (g), and (i). 

However, the lack of explicit direction 

does not preclude a State’s SIP 

consideration of EJ in its SIP submittal. 

As explained in ‘‘EPA Legal Tools to 

Advance Environmental Justice,’’ 79 the 

CAA provides states with the discretion 

to consider EJ in developing rules and 

measures related to regional haze. While 

a state may consider EJ under the 

reasonable progress factors, neither the 

statute nor the regulation requires states 

to conduct an EJ analysis for EPA to 

approve a SIP submission. 

In this instance, Georgia elected not to 

consider EJ under the reasonable 

progress factors. In Appendix H of the 

Haze Plan, in response to an EJ 

comment received from the NPCA and 

Sierra Club, GA EPD states that the 

purpose of the RHR is to improve 

visibility in the Class I areas, not to look 

at health impacts from criteria 

pollutants in areas outside Class I areas, 

which is addressed through the 

implementation of the National 

Ambient Air Quality Standards. In 

addition, GA EPD notes that it has not 

identified any EJ communities living in 

any Class I areas whose visibility would 

be disproportionately impacted by GA 

EPD’s selection of reasonable progress 

controls. 

As discussed in the NPRM and in this 

notice of final rulemaking, EPA has 

evaluated Georgia’s SIP submission 

against the statutory and regulatory 

regional haze requirements and 

determined that it satisfies those 

minimum requirements. Furthermore, 

the CAA and applicable implementing 

regulations neither prohibit nor require 

such an evaluation of EJ with a regional 

haze SIP. 

III. Incorporation by Reference 

In this document, EPA is finalizing 

regulatory text that includes 

incorporation by reference. In 

accordance with requirements of 1 CFR 

51.5, and as discussed in Sections I and 

II of this preamble, EPA is finalizing the 

incorporation by reference into 

Georgia’s SIP GA EPD Permit No. 4911– 

015–0011–V–04–3 for Bowen SteamElectric Generating Plant (State effective 

September 6, 2023), GA EPD Permit No. 

2631–051–0007–V–04–1 for 

International Paper—Savannah (State 

effective October 20, 2023), and GA EPD 

Permit No. 2631–127–0003–V–07–3 for 

Brunswick Cellulose LLC (State 

effective October 25, 2023). EPA has 

made, and will continue to make, these 

materials generally available through 

www.regulations.gov and at the EPA 

Region 4 Office (please contact the 

person identified in the FOR FURTHER


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80 62 FR 27968 (May 22, 1997). 

INFORMATION CONTACT section of this 

preamble for more information). 

Therefore, these materials have been 

approved by EPA for inclusion in the 

SIP, have been incorporated by 

reference by EPA into that plan, are 

fully federally enforceable under 

sections 110 and 113 of the CAA as of 

the effective date of the final rulemaking 

of EPA’s approval, and will be 

incorporated by reference in the next 

update to the SIP compilation.80

IV. Final Action 

EPA is approving Georgia’s August 

11, 2022, SIP submission as satisfying 

the regional haze requirements for the 

second planning period contained in 40 

CFR 51.308(f). Thus, EPA is adopting 

into Georgia’s SIP GA EPD Permit No. 

4911–015–0011–V–04–3 for Bowen 

Steam-Electric Generating Plant, GA 

EPD Permit No. 2631–051–0007–V–04– 

1 for International Paper—Savannah, 

and GA EPD Permit No. 2631–127– 

0003–V–07–3 for Brunswick Cellulose 

LLC. 

V. Statutory and Executive Order 

Reviews 

Under the CAA, the Administrator is 

required to approve a SIP submission 

that complies with the provisions of the 

CAA and applicable Federal regulations. 

See 42 U.S.C. 7410(k); 40 CFR 52.02(a). 

Thus, in reviewing SIP submissions, 

EPA’s role is to approve state choices, 

provided that they meet the criteria of 

the CAA. Accordingly, this action 

merely approves state law as meeting 

Federal requirements and does not 

impose additional requirements beyond 

those imposed by state law. For that 

reason, this action: 

• Is not a significant regulatory action 

subject to review by the Office of 

Management and Budget under 

Executive Orders 12866 (58 FR 51735, 

October 4, 1993) and 14094 (88 FR 

21879, April 11, 2023); 

• Does not impose an information 

collection burden under the provisions 

of the Paperwork Reduction Act (44 

U.S.C. 3501 et seq.); 

• Is certified as not having a 

significant economic impact on a 

substantial number of small entities 

under the Regulatory Flexibility Act (5 

U.S.C. 601 et seq.); 

• Does not contain any unfunded 

mandate or significantly or uniquely 

affect small governments, as described 

in the Unfunded Mandates Reform Act 

of 1995 (Pub. L. 104–4); 

• Does not have federalism 

implications as specified in Executive 

Order 13132 (64 FR 43255, August 10, 

1999); 

• Is not subject to Executive Order 

13045 (62 FR 19885, April 23, 1997) 

because it approves a state program; 

• Is not a significant regulatory action 

subject to Executive Order 13211 (66 FR 

28355, May 22, 2001); and 

• Is not subject to requirements of 

section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (15 U.S.C. 272 note) because 

application of those requirements would 

be inconsistent with the CAA. 

In addition, the SIP is not approved 

to apply on any Indian reservation land 

or in any other area where EPA or an 

Indian tribe has demonstrated that a 

tribe has jurisdiction. In those areas of 

Indian country, the rulemaking does not 

have tribal implications and will not 

impose substantial direct costs on tribal 

governments or preempt tribal law as 

specified by E.O. 13175 (65 FR 67249, 

November 9, 2000). 

E.O. 12898 (Federal Actions to 

Address Environmental Justice in 

Minority Populations and Low-Income 

Populations (59 FR 7629, February 16, 

1994) directs Federal agencies to 

identify and address 

‘‘disproportionately high and adverse 

human health or environmental effects’’ 

of their actions on communities with EJ 

concerns to the greatest extent 

practicable and permitted by law. 

Executive Order 14096 (Revitalizing 

Our Nation’s Commitment to 

Environmental Justice for All, 88 FR 

25251, April 26, 2023) builds on and 

supplements E.O. 12898 and defines EJ 

as, among other things, the just 

treatment and meaningful involvement 

of all people, regardless of income, race, 

color, national origin, or Tribal 

affiliation, or disability in agency 

decision-making and other Federal 

activities that affect human health and 

the environment. 

Georgia EPD did not evaluate EJ 

considerations as part of its SIP 

submittal; the CAA and applicable 

implementing regulations neither 

prohibit nor require such an evaluation. 

EPA did not perform an EJ analysis and 

did not consider EJ in this action. Due 

to the nature of the action being taken 

here, this action is expected to have a 

neutral to positive impact on the air 

quality of the affected area. 

Consideration of EJ is not required as 

part of this action, and there is no 

information in the record inconsistent 

with the stated goal of E.O. 12898/14096 

of achieving EJ for communities with EJ 

concerns. 

This action is subject to the 

Congressional Review Act, and EPA will 

submit a rule report to each House of 

the Congress and to the Comptroller 

General of the United States. This action 

is not a ‘‘major rule’’ as defined by 5 

U.S.C. 804(2). 

Under section 307(b)(1) of the CAA, 

petitions for judicial review of this 

action must be filed in the United States 

Court of Appeals for the appropriate 

circuit by January 21, 2025. Filing a 

petition for reconsideration by the 

Administrator of this final rule does not 

affect the finality of this action for the 

purposes of judicial review nor does it 

extend the time within which a petition 

for judicial review may be filed, and 

shall not postpone the effectiveness of 

such rule or action. This action may not 

be challenged later in proceedings to 

enforce its requirements. (See section 

307(b)(2).) 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Incorporation by 

reference, Nitrogen dioxide, Particulate 

matter, Sulfur oxides. 

Dated: November 14, 2024. 

Cesar Zapata, 

Acting Regional Administrator, Region 4. 

For the reasons stated in the 

preamble, EPA amends 40 CFR part 52 

as follows: 

PART 52—APPROVAL AND 

PROMULGATION OF 

IMPLEMENTATION PLANS 

■ 1. The authority citation for part 52 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

Subpart L—Georgia 

■ 2. In § 52.570(d), amend ‘‘Table 2 to 

Paragraph (d)’’ by adding entries for 

‘‘Bowen Steam-Electric Generating 

Plant’’, ‘‘International Paper-Savannah’’, 

and ‘‘Brunswick Cellulose LLC’’ at the 

end of the table to read as follows: 

§ 52.570 Identification of plan. 

(d) * * * 


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92066 Federal Register / Vol. 89, No. 225 / Thursday, November 21, 2024 / Rules and Regulations 

TABLE 2 TO PARAGRAPH (d)—EPA-APPROVED GEORGIA SOURCE-SPECIFIC REQUIREMENTS

Name of source Permit No. 

State 

effective 

date 

EPA approval 

date Comments 

*******

Bowen Steam-Electric 

Generating Plant.

4911–015–0011–V–04–3 9/6/2023 11/21/2024, [Insert first 

page of Federal Register citation].

International Paper—Savannah.2631–051–0007–V–04–1 10/20/2023 11/21/2024, [Insert first 

page of Federal Register citation].

Brunswick Cellulose LLC .. 2631–127–0003–V–07–3 10/24/2023 11/21/2024, [Insert first 

page of Federal Register citation].

In Condition 6.2.52, the phrase ‘‘shall 

use emissions factors’’ means ‘‘shall 

use an emissions factor of 157 S lb/ 

Mgal.’’ 

■ 3. In § 52.570(e), amend the table by 

adding an entry for ‘‘Regional Haze 

Plan—Second Planning Period’’ at the 

end of the table to read as follows: 

(e) * * * 

EPA-APPROVED GEORGIA NON-REGULATORY PROVISIONS

Name of nonregulatory SIP provision 

Applicable 

geographic or 

nonattainment area 

State submittal 

date/effective 

date 

EPA approval date Explanation 

*******

Regional Haze Plan—Second Planning 

Period.

Georgia .................. 8/11/22 11/21/2024, [Insert first page of Federal 

Register citation].

[FR Doc. 2024–26977 Filed 11–20–24; 8:45 am] 

BILLING CODE 6560–50–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 272 

[EPA–R06–RCRA–2021–0330; FRL–9522– 

01–R6] 

Texas: Incorporation by Reference of 

State Hazardous Waste Management 

Program 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: This rule codifies in the 

regulations the prior approval of Texas’ 

hazardous waste management program 

and incorporates by reference 

authorized provisions of the State’s 

statutes and regulations. The 

Environmental Protection Agency (EPA) 

uses the regulations entitled ‘‘Approved 

State Hazardous Waste Management 

Programs’’ to provide notice of the 

authorization status of State programs 

and to incorporate by reference those 

provisions of the State statutes and 

regulations that are authorized and that 

EPA will enforce under the Solid Waste 

Disposal Act, commonly referred to as 

the Resource Conservation and 

Recovery Act (RCRA). The EPA 

previously provided notices and 

opportunity for comments on the 

Agency’s decisions to authorize the 

State of Texas program and the EPA is 

not now reopening the decisions, nor 

requesting comments, on the Texas 

authorizations as previously published 

in the Federal Register documents 

specified in Section I.C of this final rule 

document. 

DATES: This regulation is effective on 

December 23, 2024. The Director of the 

Federal Register approves this 

incorporation by reference as of 

December 23, 2024, in accordance with 

5 U.S.C. 552(a) and 1 CFR part 51. 

ADDRESSES: The EPA has established a 

docket for this action under Docket ID 

No. EPA–R06–RCRA–2021–0330. All 

documents in the docket are listed on 

the https://www.regulations.gov 

website. Although listed in the index, 

some information is not publicly 

available, e.g., Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, will be publicly 

available only in hard copy. Publicly 

available docket materials are available 

electronically through https://

www.regulations.gov. 

You can view and copy the 

documents that form the basis for this 

codification and associated publicly 

available materials from 8:30 a.m. to 

4:00 p.m., Monday through Friday, at 

the following location: EPA, Region 6, 

1201 Elm Street, Suite 500, Dallas, 

Texas 75270, phone number: (214) 665– 

8533. Interested persons wanting to 

examine these documents should make 

an appointment with the office. 

FOR FURTHER INFORMATION CONTACT: 

Alima Patterson, EPA Region 6 Regional 

Authorization/Codification Coordinator, 

RCRA Permits and Solid Waste Section 

(LCR–RP), Land, Chemicals and 

Redevelopment Division, EPA Region 6, 

1201 Elm Street, Suite 500, Dallas, 

Texas 75270, phone number: (214) 665– 

8533, Email address: patterson.alima@

epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. Incorporation by Reference 

A. What is codification? 

Codification is the process of placing 

a State’s statutes and regulations that 

comprise the State’s authorized 

hazardous waste management program 

into the Code of Federal Regulations 

(CFR). Section 3006(b) of RCRA, as 

amended, allows the EPA to authorize 

State hazardous waste management 

programs to operate in lieu of the 

Federal hazardous waste management 

regulatory program. The EPA codifies its 

authorization of State programs in 40 


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