Disapproval and Promulgation of Air Quality Implementation Plan; Nebraska; Regional Haze State Implementation Plan; Federal Implementation Plan for Regional Haze; Completion of Remand, 62691-62707 [2024-16697]

Agencies

• ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 89, Number 148 (Thursday, August 1, 2024)]
[Proposed Rules]
[Pages 62691-62707]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-16697]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R07-OAR-2024-0224; FRL-11566-01-R7]


Disapproval and Promulgation of Air Quality Implementation Plan; 
Nebraska; Regional Haze State Implementation Plan; Federal 
Implementation Plan for Regional Haze; Completion of Remand

AGENCY: Environmental Protection Agency.

ACTION: Proposed rule.

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SUMMARY: Pursuant to the Federal Clean Air Act (CAA or Act), the 
Environmental Protection Agency (EPA)

[[Page 62692]]

is proposing this action to address the voluntary remand of a portion 
of a final rulemaking published in the Federal Register on July 6, 
2012, addressing regional haze obligations for the first planning 
period in Nebraska. Specifically, we are revisiting and implementing a 
Federal Implementation Plan (FIP) applicable to the Gerald Gentleman 
Station, owned and operated by the Nebraska Public Power District 
(NPPD). In this action, the EPA is proposing a revised FIP that will 
limit sulfur dioxide (SO2) emissions at the Gerald Gentleman 
Station. The EPA proposes to determine that SO2 emission 
reductions are needed to make reasonable progress toward Congress' 
natural-visibility goal at Class I areas affected by visibility-
impairing emissions from Nebraska. This proposal addresses only the 
remanded portion of the Nebraska FIP.

DATES: Comments must be received on or before September 30, 2024. The 
EPA will hold an in-person public hearing in Nebraska and a separate 
virtual public hearing. For more information on the in-person and 
virtual public hearings, see SUPPLEMENTARY INFORMATION.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R07-
OAR-2024-0224, to the Federal eRulemaking Portal: https://www.regulations.gov. For additional submission methods, please contact 
the person identified in the FOR FURTHER INFORMATION CONTACT section.
    Docket: The docket for this action is available electronically at 
https://www.regulations.gov. Some information in the docket may not be 
publicly available via the online docket due to docket file size 
restrictions, or content (e.g., CBI). To request a copy of the files, 
please send a request via email to [email protected]. For questions 
about a document in the docket please contact individual listed in the 
FOR FURTHER INFORMATION CONTACT section.
    Confidential Business Information (CBI): Do not submit information 
containing CBI to the EPA through https://www.regulations.gov. To 
submit information claimed as CBI, please contact the individual listed 
in the FOR FURTHER INFORMATION CONTACT section. Clearly mark the part 
or all of the information that you claim to be CBI. In addition to one 
complete version of the comments that includes information claimed as 
CBI, you must submit a copy of the comments that does not contain the 
information claimed as CBI directly to the public docket through the 
procedures outlined in Instructions earlier. Information not marked as 
CBI will be included in the public docket and the EPA's electronic 
public docket without prior notice. Information marked as CBI will not 
be disclosed except in accordance with procedures set forth in 40 Code 
of Federal Regulations (CFR) part 2. For the full EPA public comment 
policy, information about CBI or multimedia submissions, and general 
guidance on making effective comments, please visit https://www2.epa.gov/dockets/commenting-epa-dockets.
    To pre-register to attend or speak at the virtual public hearing, 
please use the online registration form available at https://www.epa.gov/ne/state-nebraska or contact us via email at 
[email protected]. For more information on the virtual public 
hearing, see SUPPLEMENTARY INFORMATION.

FOR FURTHER INFORMATION CONTACT: Jed D. Wolkins, Environmental 
Protection Agency, Air Planning and Development Branch, 11201 Renner 
Boulevard, Lenexa, Kansas 66219; telephone number: (913) 551-7588; 
email address: [email protected].

SUPPLEMENTARY INFORMATION: Throughout this document ``we,'' ``us,'' or 
``our'' refer to the EPA.
    Virtual public hearing: The EPA is holding a virtual public hearing 
to provide interested parties the opportunity to present data, views, 
or arguments concerning the proposal. The virtual public hearing will 
be on September 3, 2024 at 1:00 p.m. Central Time (CT) and will 
conclude at 5:00 p.m. CT or 15 minutes after the last pre-registered 
presenter in attendance has presented if there are no additional 
presenters.
    The EPA will begin pre-registering speakers and attendees for the 
hearing upon publication of this document in the Federal Register. To 
pre-register to attend or speak at the virtual public hearing, please 
use the online registration form available at https://www.epa.gov/ne/state-nebraska or contact us via email at [email protected]. The last 
day to preregister to speak at the hearing will be August 26, 2024. The 
EPA will post a general agenda for the hearing that will list pre-
registered speakers in approximate order at https://www.epa.gov/ne/state-nebraska. Additionally, requests to speak will be taken on the 
day of the hearing as time allows.
    The EPA will make every effort to follow the schedule as closely as 
possible on the day of the hearing; however, please plan for the 
hearing to run either ahead of schedule or behind schedule. Each 
commenter will have approximately 3 to 5 minutes to provide oral 
testimony. The EPA encourages commenters to provide the EPA with a 
written copy of their oral testimony electronically by emailing it to 
[email protected]. The EPA may ask clarifying questions during the 
oral presentations but will not respond to the presentations at that 
time. Written statements and supporting information submitted during 
the comment period will be considered with the same weight as oral 
comments and supporting information presented at the virtual public 
hearing. A transcript of the virtual public hearing, as well as written 
copies of oral presentations submitted to the EPA, will be included in 
the docket for this action.
    The EPA is asking all hearing attendees to pre-register, even those 
who do not intend to speak. The EPA will send information on how to 
join the public hearing to pre-registered attendees and speakers. 
Please note that any updates made to any aspect of the hearing will be 
posted online at https://www.epa.gov/ne/state-nebraska. While the EPA 
expects the hearing to go forward as set forth above, please monitor 
our website or contact us via email at [email protected] to determine 
if there are any updates. The EPA does not intend to publish a document 
in the Federal Register announcing updates.
    If you require the services of a translator or a special 
accommodation such as audio description/closed captioning, please pre-
register for the hearing and describe your needs by August 8, 2024. The 
EPA may not be able to arrange accommodations without advance notice.

Table of Contents

I. Executive Summary
II. Background
    A. Regional Haze
    1. Determination of Baseline, Natural, and Current Visibility 
Conditions
    2. Reasonable Progress and Long-Term Strategy (LTS)
    3. Federal Land Manager (FLM) Consultation
    B. Previous Actions Related to Nebraska Regional Haze Long-Term 
Strategy Requirements for the First Planning Period
    C. Prior Litigation and EPA's Motion for Voluntary Remand
III. Overview of Proposed Action
IV. Legal Authority for This Action
V. EPA's Review of the 2012 Federal Implementation Plan on Remand
    A. Factor 1--The Costs of Compliance
    1. EPA's Evaluation of Costs for BART in the 2012 Proposed and 
Final Rule
    2. EPA's Updated Cost Evaluation
    B. Factor 2--The Time Necessary for Compliance
    C. Factor 3--The Energy and Non-Air Quality Environmental 
Impacts of Compliance

[[Page 62693]]

    D. Factor 4--The Remaining Useful Life of the Source
    E. Evaluation of Potential Visibility Impacts and Improvements
VI. Amending the FIP on Remand--Long-Term Strategy Determination for 
Gerald Gentleman Station
VII. The EPA's FLM Consultation
VIII. Proposed Action
IX. Environmental Justice Considerations
X. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 14094: Modernizing Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Coordination With Indian Tribal 
Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health and Safety Risks
    H. Executive Order 13211: Actions That Significantly Affect 
Energy Supply, Distribution or Use
    I. National Technology Transfer Advancement Act
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations and Executive Order 14096: Revitalizing Our Nation's 
Commitment to Environmental Justice for All

I. Executive Summary

    The CAA's visibility protection program was created in the 1977 CAA 
Amendments. In CAA section 169A, Congress declared a national goal to 
remedy any existing and prevent any future visibility impairment in 
certain national parks, such as Badlands in South Dakota and Rocky 
Mountain in Colorado, and national wilderness areas, such as the 
Wichita Mountains Wilderness in Oklahoma. Vistas in these areas 
(referred to as Class I areas) are often obscured by visibility 
impairment such as regional haze, which is caused by emissions from 
numerous sources located over a wide geographic area.
    In response to a Congressional directive to provide regulations to 
the states, the EPA promulgated regulations to address visibility 
impairment in 1999. These regulations, which are commonly referred to 
as the Regional Haze Rule, established an iterative process for 
achieving Congress's national goal by providing for multiple, 
approximately 10-year ``planning periods'' in which state air agencies 
must submit to the EPA plans that address sources of visibility-
impairing pollution in their states. The first state plans were due in 
2007 for the planning period that ended in 2018. The second state plans 
were due in 2021 for the period that ends in 2028. This proposal 
focuses on remaining obligations from the first planning period of the 
regional haze program.
    The CAA and Regional Haze Rule require states to submit a long-term 
strategy (LTS) that includes such measures as may be necessary to make 
reasonable progress toward the national visibility goal for each Class 
I area. A central element of the LTS for the first planning period 
state plans was the requirement for certain older stationary sources to 
install the Best Available Retrofit Technology (BART) for the purpose 
of eliminating or reducing visibility impairment within our nation's 
most treasured lands. The other central element of a state's LTS is the 
requirement to include any additional control measures that are 
necessary to make ``reasonable progress'' towards the national goal. To 
determine what control measures are necessary to make reasonable 
progress and therefore must be included in the LTS, the four statutory 
factors must be considered: (1) the costs of compliance, (2) the time 
necessary for compliance, (3) the energy and nonair quality 
environmental impacts of compliance, and (4) the remaining useful life 
of any existing source subject to such requirements. This statutory 
requirement is often referred to as a ``four-factor analysis.'' 
Additionally, when visibility-impairing emissions from multiple states 
impact the same national park or wilderness area, the Regional Haze 
Rule requires those states to coordinate and consult with one another 
to ensure that each state is making reasonable progress toward the 
national goal.
    Gerald Gentleman Station, located in western Nebraska, is one of 
the highest emitters of visibility-impairing pollutants, specifically 
SO2, in the nation. These emissions cause or contribute to 
visibility impairment in such iconic places as Wind Cave and Badlands 
National Parks in South Dakota and Rocky Mountain National Park in 
Colorado. To address this visibility impairment, Nebraska submitted its 
first regional haze state implementation plan (SIP) on July 13, 2011. 
Nebraska included a BART determination for SO2 emissions 
from the Gerald Gentleman Station. In July 2012, the EPA disapproved 
portions of the state's SIP, including the BART determination for 
Gerald Gentleman Station, finding significant flaws in several aspects 
of the state's analysis of potential emission control technologies. The 
EPA also disapproved the state's LTS for SO2 at Gerald 
Gentleman Station to the extent that it relied on the flawed BART 
determination. The EPA promulgated a FIP in place of the elements of 
the SIP that it disapproved. The EPA determined that BART for Gerald 
Gentleman Station was satisfied by the facility's participation in the 
Cross-State Air Pollution Rule (CSAPR) national trading program. The 
EPA further found that the gap left in the state's LTS by the EPA's 
partial disapproval were also satisfied by the CSAPR.
    The NPPD, who owns and operates the Gerald Gentlemen Station, and 
several environmental groups filed petitions for review of various 
aspects of the EPA's 2012 final action. The EPA sought and received a 
voluntary remand without vacatur to reconsider the portion of the final 
action relating to the LTS for SO2 at the Gerald Gentleman 
Station.\1\ After considering relevant facts, the EPA is proposing to 
amend its FIP.
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    \1\ The remainder of the 2012 final rule was upheld by the 
Eighth Circuit. Nebraska v. EPA, 812 F.3d 662 (8th Cir. 2016).
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    Nebraska remains one of the few states in the nation that does not 
have a complete first planning period regional haze plan in place to 
protect the national parks and wilderness areas impacted by its 
sources. With this action, the EPA is proposing a new FIP that will 
satisfy the regional haze statutory and regulatory requirements for the 
first planning period.

II. Background

A. Regional Haze

    Regional haze is visibility impairment that is produced by a 
multitude of sources and activities which are located across a broad 
geographic area. These sources and activities emit fine particulate 
matter (PM2.5) (e.g., sulfates, nitrates, organic carbon, 
elemental carbon, and soil dust) and its precursors (e.g., 
SO2, nitrogen oxides (NOX), and, in some cases, 
ammonia (NH3) and volatile organic compounds (VOCs)). Fine 
particle precursors react in the atmosphere to form PM2.5, 
which, in addition to direct sources of PM2.5, impairs 
visibility by scattering and absorbing light. Visibility impairment 
(i.e., light scattering) reduces the clarity, color, and visible 
distance that one can see.
    In section 169A of the 1977 Amendments to the CAA, Congress created 
a program for protecting visibility in the nation's national parks and 
wilderness areas. This section of the CAA establishes as a national 
goal the prevention of any future, and the remedying of any existing, 
anthropogenic (manmade) impairment of visibility in 156 national parks 
and wilderness areas designated as

[[Page 62694]]

mandatory Class I areas.\2\ Congress added section 169B to the CAA in 
1990 to address regional haze issues, and the EPA promulgated the 
Regional Haze Rule, codified at 40 CFR 51.308,\3\ on July 1, 1999.\4\ 
The Regional Haze Rule established a requirement for all states, the 
District of Columbia, and the Virgin Islands to submit a regional haze 
SIP.\5\ The primary purpose of the Regional Haze Rule is to outline the 
requirements for states to develop programs that assure reasonable 
progress toward meeting the national goal of preventing any future, and 
remedying any existing, impairment of visibility in mandatory Class I 
areas which impairment results from manmade air pollution.\6\
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    \2\ Areas designated as mandatory Class I 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. 42 U.S.C. 7472(a). In 
accordance with section 169A of the CAA, EPA, in consultation with 
the Department of Interior, promulgated a list of 156 areas where 
visibility is identified as an important value. 44 FR 69122 
(November 30, 1979). The extent of a mandatory Class I area includes 
subsequent changes in boundaries, such as park expansions. 42 U.S.C. 
7472(a). Although states and tribes may designate as Class I 
additional areas which they consider to have visibility as an 
important value, the requirements of the visibility program set 
forth in section 169A of the CAA apply only to ``mandatory Class I 
Federal areas.'' Each mandatory Class I Federal area is the 
responsibility of a ``Federal Land Manager.'' 42 U.S.C. 7602(i). 
When we use the term ``Class I area'' in this action, we mean a 
``mandatory Class I Federal area.''
    \3\ In addition to the generally applicable regional haze 
provisions at 40 CFR 51.308, the EPA also promulgated regulations 
specific to addressing regional haze visibility impairment in Class 
I areas on the Colorado Plateau at 40 CFR 51.309. The latter 
regulations are not relevant here.
    \4\ See 64 FR 35714 (July 1, 1999). On January 10, 2017, the EPA 
promulgated revisions to the Regional Haze Rule that apply for the 
second and subsequent implementation periods. See 82 FR 3078 (Jan. 
10, 2017).
    \5\ 40 CFR 51.300(b).
    \6\ Id. at 51.300(a).
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    To address regional haze visibility impairment, the Regional Haze 
Rule established an iterative planning process that requires states to 
periodically submit SIP revisions (each periodic revision referred to 
as a ``planning period'') to address regional haze visibility 
impairment at Class I areas.\7\ Under the CAA, each SIP submission must 
contain ``a long-term (ten to fifteen years) strategy for making 
reasonable progress toward meeting the national goal,'' and the initial 
round of SIP submissions also had to address the statutory requirement 
that certain older, larger sources of visibility-impairing pollutants 
install and operate BART.\8\ States' first regional haze SIPs were due 
by December 17, 2007, with subsequent SIP submissions containing 
revised long-term strategies originally due July 31, 2018, and every 
ten years thereafter.\9\
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    \7\ See 42 U.S.C. 7491(b)(2); 40 CFR 51.308 (b) and (f); see 
also 64 FR at 35768. The EPA established in the Regional Haze Rule 
that all states either have Class I areas within their borders or 
``contain sources whose emissions are reasonably anticipated to 
contribute to regional haze in a Class I area;'' therefore, all 
states must submit regional haze SIPs. See 64 FR at 35721. In 
addition to each of the 50 states, the EPA also concluded that the 
Virgin Islands and District of Columbia contain a Class I area and/
or contain sources whose emissions are reasonably anticipated to 
contribute regional haze in a Class I area. See 40 CFR 51.300(b) and 
(d)(3).
    \8\ See 42 U.S.C. 7491(b)(2)(A); 40 CFR 51.308 (d) and (e).
    \9\ See 40 CFR 51.308(b). The 2017 Regional Haze Rule revisions 
changed the second period SIP due date from July 31, 2018, to July 
31, 2021, and maintained the existing schedules for the subsequent 
implementation periods. See 40 CFR 51.308(f).
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1. Determination of Baseline, Natural, and Current Visibility 
Conditions
    The Regional Haze Rule establishes the deciview (dv) as the 
principal metric for measuring visibility.\10\ This visibility metric 
expresses uniform changes in the degree of haze in terms of common 
increments across the entire range of visibility conditions, from 
pristine to extremely hazy conditions. Visibility is also sometimes 
expressed in terms of the visual range or light extinction. Visual 
range is the greatest distance, in kilometers or miles, at which a dark 
object can just be distinguished against the sky. Light extinction, 
expressed in units of inverse megameters (Mm-1), is the 
amount of light lost as it travels over distance. The haze index, in 
units of dv, is calculated directly from the total light extinction. 
The dv is a useful measure for tracking progress in improving 
visibility because each dv change is approximately an equal incremental 
change in visibility perceived by the human eye. Most people can detect 
a change in visibility of one dv.\11\
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    \10\ See 64 FR 35714, 35725-27 (July 1, 1999).
    \11\ The preamble to the Regional Haze Rule provides additional 
details about the deciview. 64 FR at 35725.
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    The dv is used in expressing Reasonable Progress Goals (RPGs) 
(which are interim visibility goals towards meeting the national 
visibility goal), defining baseline, current, and natural conditions 
and tracking changes in visibility. The regional haze SIPs must contain 
measures that ensure ``reasonable progress'' toward the national goal 
of preventing and remedying visibility impairment in Class I areas 
caused by manmade air pollution by reducing anthropogenic emissions 
that cause regional haze.
    To track changes in visibility over time at each of the 156 Class I 
areas covered by the visibility program (40 CFR 81.401-437), and as 
part of the process for determining reasonable progress, states with 
Class I areas, must calculate the degree of existing visibility 
impairment at each Class I area at the time of each regional haze SIP 
submittal and periodically review progress every five years midway 
through each 10-year implementation period. To do this, the Regional 
Haze Rule requirements for the first planning period \12\ provide that 
states must determine the degree of impairment (in dv) for the average 
of the 20 percent least impaired (``best'') and 20 percent most 
impaired (``worst'') visibility days over a specified time period at 
each of their Class I areas. In addition, states must also develop an 
estimate of natural visibility conditions for the purpose of comparing 
progress toward the national goal. Natural visibility is determined by 
estimating the natural concentrations of pollutants that cause 
visibility impairment and then calculating total light extinction based 
on those estimates. The EPA provided guidance to states regarding how 
to calculate baseline, natural, and current visibility conditions in 
the first planning period.\13\
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    \12\ The applicable requirements of the Regional Haze Rule for 
the first planning period are found in 40 CFR 51.308(d).
    \13\ Guidance for Estimating Natural Visibility Conditions Under 
the Regional Haze Rule, September 2003, EPA-454/B-03-005, available 
at https://www3.epa.gov/ttn/naaqs/aqmguide/collection/cp2/20030901_oaqps_epa-454_b-03-005_estimating_natural%20_visibility_regional_haze.pdf (hereinafter 
referred to as ``our 2003 Natural Visibility Guidance''); and 
Guidance for Tracking Progress Under the Regional Haze Rule, EPA-
454/B-03-004, September 2003, available at https://www.epa.gov/sites/default/files/2021-03/documents/tracking.pdf (hereinafter 
referred to as our ``2003 Tracking Progress Guidance'').
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    For the regional haze SIPs for the first planning period, 
``baseline visibility conditions'' were the starting points for 
assessing ``current'' visibility impairment. Baseline visibility 
conditions represent the degree of visibility impairment for the 20 
percent least impaired days and 20 percent most impaired days for each 
calendar year from 2000 to 2004. Using monitoring data for 2000 through 
2004, states are required to calculate the average degree of visibility 
impairment for each Class I area on the 20 percent least and most 
impaired days, based on the average of annual values over the five-year 
period. The comparison of initial baseline visibility conditions to 
natural visibility conditions indicates the amount of improvement 
necessary to attain natural visibility, while the future comparison of 
baseline conditions to the then current conditions will indicate the 
amount of progress made. In general, the 2000-2004 baseline period is 
considered the starting point from

[[Page 62695]]

which improvement in visibility is measured in the first planning 
period.
2. Reasonable Progress and Long-Term Strategy (LTS)
    The vehicle for ensuring continuing progress towards achieving the 
natural visibility goal is the submission of a series of regional haze 
SIPs, including a LTS, from the states that have emissions expected to 
impact visibility in any Class I area. Additionally, states with Class 
I areas must establish two reasonable progress goals (RPGs) (i.e., one 
for the ``best'' and one for the ``worst'' days) for each Class I area 
within the state for each (approximately) 10-year planning period.\14\ 
The Regional Haze Rule does not mandate specific milestones or rates of 
progress, but instead calls for states to establish goals that provide 
for ``reasonable progress'' toward achieving natural visibility 
conditions. In establishing RPGs, states must provide for an 
improvement in visibility for the most impaired days over the 
(approximately) 10-year period of the SIP and ensure no degradation in 
visibility for the least impaired days over the same period.\15\
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    \14\ See 64 FR at 35730-37.
    \15\ Id.
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    Further, CAA section 169A(b)(2)(B) requires all states to include 
in their regional haze SIP a long-term (10-to-15-year) strategy for 
making reasonable progress towards the national goal. Consistent with 
this statutory obligation, 40 CFR 51.308(d)(3) requires all states 
(both downwind and upwind) to ``submit a long-term strategy that 
addresses regional haze visibility impairment for each mandatory Class 
I Federal area within the state and each mandatory Class I Federal area 
located outside the state which may be affected by emissions from the 
state.'' \16\ A state's LTS is therefore inextricably linked to the 
RPGs \17\ because it ``must include enforceable emission limitations, 
compliance schedules, and other measures as necessary to achieve the 
RPGs established by states having mandatory Class I Federal areas.\18\
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    \16\ 40 CFR 51.308(d)(3).
    \17\ 40 CFR 51.308(d)(1)
    \18\ 40 CFR 51.308(d)(3).
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    In establishing its LTS, a state must meet a number of 
requirements. First, as a corollary to Sec.  51.308(d)(1)(iv), when a 
state's emissions are reasonably anticipated to cause or contribute to 
visibility impairment in a Class I area located in another state, the 
Regional Haze Rule requires the downwind state to coordinate with the 
upwind states in order to develop coordinated emissions management 
strategies.\19\ The purpose of the consultation requirement is to 
ensure that the upwind states adopt control measures sufficient to 
address their apportionment of emission reductions necessary to achieve 
reasonable progress and that the downwind state's RPGs properly account 
for the visibility improvement that will result from the reasonable 
control measures identified and included in the upwind state's LTS.
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    \19\ 40 CFR 51.308(d)(3)(i).
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    Second, where multiple states contribute to visibility impairment 
in a Class I area, each state ``must demonstrate that it has included 
in its implementation plan all measures necessary to obtain its share 
of the emission reductions needed to meet the progress goal for the 
area.'' \20\ This requirement addresses situations where an upwind 
state agrees to achieve certain emission reductions during the 
consultation process, and downwind states rely upon those reductions 
when setting their RPGs, but the upwind state ultimately fails to 
include sufficient control measures in its LTS to ensure that the 
emission reductions will be achieved. In such a situation, the upwind 
state's LTS would not meet the statutory or regulatory requirements.
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    \20\ 40 CFR 51.308(d)(3)(ii).
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    Finally, each state ``must document the technical basis, including 
modeling, monitoring and emissions information on which the state is 
relying to determine its apportionment of emission reduction 
obligations necessary for achieving reasonable progress in each 
mandatory Class I area it affects.'' \21\ Section 169(A)(g)(1) of the 
CAA requires states to determine ``reasonable progress'' by considering 
the four statutory factors: (1) The costs of compliance; (2) the time 
necessary for compliance; (3) the energy and non-air quality 
environmental impacts of compliance; and (4) the remaining useful life 
of any potentially affected sources.\22\ Therefore, this provision 
requires states to consider downwind Class I areas when they develop 
the technical basis underlying their four-factor analysis to determine 
which control measures are necessary to make reasonable progress, and 
thus need to be a part of their LTS. The regulations further provide 
that, ``States may meet this requirement by relying on technical 
analyses developed by the regional planning organization and approved 
by all State participants.'' \23\ Thus, states have the option of 
meeting this requirement by relying on four-factor analyses and 
associated technical documentation prepared by a regional planning 
organization on behalf of its member states,\24\ to the extent that 
such analyses and documentation were conducted. In situations where a 
regional planning organization's analyses are limited, incomplete or do 
not adequately assess the four factors, however, then states must fill 
in any remaining gaps to meet this requirement. States should consider 
all types of anthropogenic sources of visibility impairment in 
developing their LTS, including stationary, minor, mobile, and area 
sources.\25\ At a minimum, states must describe how each of the 
following seven factors listed below are taken into account in 
developing their LTS: (1) Emission reductions due to ongoing air 
pollution control programs, including measures to address ``reasonably 
attributable visibility impairment'' (RAVI); (2) measures to mitigate 
the impacts of construction activities; (3) emissions limitations and 
schedules for compliance to achieve the RPG; (4) source retirement and 
replacement schedules; (5) smoke management techniques for agricultural 
and forestry management purposes including plans as currently exist 
within the state for these purposes; (6) enforceability of emissions 
limitations and control measures; (7) the anticipated net effect on 
visibility due to projected changes in point, area, and mobile source 
emissions over the period addressed by the LTS.\26\
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    \21\ 40 CFR 51.038(d)(3)(iii).
    \22\ 42. U.S.C. 7491(g)(1).
    \23\ 40 CFR 51.308(d)(3)(iii).
    \24\ See WildEarth Guardians v. EPA, 77 F.3d 919 at 944 (10th 
Cir. Oct. 21, 2014) (explaining that 40 CFR 51.308(d)(3)(iii) 
``permits a State conducting a reasonable-progress determination'' 
``to rely on [a regional planning organization's] four-factor 
analysis.'').
    \25\ 40 CFR 51.308(d)(3)(iv); See also 40 CFR 51.301.
    \26\ 40 CFR 51.308(d)(3)(v).
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3. Federal Land Manager (FLM) Consultation
    The Regional Haze Rule requires that a state, or the EPA if 
promulgating a FIP, consult with FLMs before adopting and submitting a 
required SIP or SIP revision or a required FIP or FIP revision. Under 
40 CFR 51.308(i)(2), a state, or the EPA if promulgating a FIP, must 
provide an opportunity for consultation no less than 60 days prior to 
holding any public hearing or other public comment opportunity on a SIP 
or SIP revision, or FIP or FIP revision, for regional haze. The EPA 
must include a description of how it addressed comments provided by the 
FLMs when considering a FIP or FIP revision.

[[Page 62696]]

B. Previous Actions Related to Nebraska's Regional Haze Long-Term 
Strategy for the First Planning Period

    On July 6, 2012, the EPA took final action on Nebraska's Regional 
Haze SIP for the first planning period.\27\ In that final action, the 
EPA partially approved and partially disapproved the state's SIP. The 
EPA disapproved the state's SO2 BART determinations for 
Gerald Gentleman Station Units 1 and 2 and the state's LTS, which had 
relied on the state's flawed BART determinations.\28\ The reasons for 
the EPA's disapproval are outlined in both the proposed rule and the 
final rule.\29\ In the same action, the EPA also promulgated a FIP to 
address the deficiencies in Nebraska's Regional Haze Plan. For those 
deficiencies associated with the state's SO2 control 
decisions for Gerald Gentleman Station Units 1 and 2, the EPA relied on 
the CSAPR to meet both the BART requirement and the LTS requirement to 
make reasonable progress.\30\ Specifically, the EPA relied on its 
finding in a separate national rulemaking that CSAPR provides for 
greater reasonable progress on average across all affected Class I 
areas than source-specific BART in those states covered by the CSAPR 
(the ``Better than BART Rule'').\31\ In that separate national 
rulemaking, the EPA revised the Regional Haze Rule to provide that 
states could choose to rely on the CSAPR as an alternative to BART. 
Consistent with this regulatory provision, the EPA relied on the CSAPR 
as an alternative to BART for SO2 emissions from the Gerald 
Gentleman Station. In addition, the EPA concluded in the FIP that 
reliance on the CSAPR would remedy the deficiency in Nebraska's LTS for 
SO2 at the Gerald Gentlemen Station.
---------------------------------------------------------------------------

    \27\ 77 FR 40149.
    \28\ The EPA approved rest of the Nebraska SIP including these 
elements of the LTS. See 77 FR 12770 (March 2, 2012) (proposed 
rule); 77 FR 40149 (July 6, 2012) (final rule).
    \29\ Id.
    \30\ Id.
    \31\ 77 FR 33642.
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C. Prior Litigation and EPA's Motion for Voluntary Remand

    Sierra Club, the NPCA, the State of Nebraska, and NPPD filed 
petitions for review challenging EPA's final action in the Eighth 
Circuit Court of Appeals.\32\ In response to arguments raised by the 
Sierra Club and NPCA during briefing on the petitions, the EPA moved 
for a voluntary remand without vacatur of the LTS portion of the FIP 
for Nebraska as it related to SO2 emissions from the Gerald 
Gentleman Station.\33\ The EPA explained in its motion that the 
Agency's rationale for declining to require additional SO2 
controls at the Gerald Gentleman Station as part of the LTS in its FIP 
was not fully or clearly explained. The EPA also stated that the 
explanation in the record could potentially be construed in a manner 
that was inconsistent with the EPA's interpretation of the relevant 
statutory requirements. As a result, the EPA determined that a remand 
was appropriate to afford the Agency an opportunity to amend or further 
explain its rationale for declining to require additional 
SO2 controls beyond the CSAPR in the LTS, more fully respond 
to comments submitted by the public, or to take further action if 
necessary. The Court granted the remand on March 19, 2015. On January 
19, 2017, the EPA Region 7 Administrator signed a proposed FIP that 
would have addressed the remanded portion of the Nebraska FIP for the 
first planning period. However, subsequent to the Administration 
change, the Office of Management and Budget published a memorandum 
requesting that any action that had been sent to the Federal Register, 
but had not yet published, be immediately withdrawn for review and 
approval by the new administration.\34\ After being withdrawn, no 
action was taken on the FIP. Therefore, the EPA now is proposing a 
similar, updated action to address the remanded portion of the Nebraska 
FIP for the first planning period.
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    \32\ NPPD dismissed its petition voluntarily but remained as an 
intervenor in the other petitions. See Order, Neb. Pub. Power Dist. 
v. EPA, No. 12-3061 (8th Cir. November 4, 2014).
    \33\ EPA's Motion for Partial Voluntary Remand, Nebraska. v. 
EPA, 812 F.3d 662 (8th Cir. 2015) (No.12-3084).
    \34\ 82 FR 8346.
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III. Overview of Proposed Action

    To address the voluntary remand, we are proposing to revise our FIP 
so that the LTS adequately addresses SO2 emissions from 
Gerald Gentlemen Station. Specifically, the EPA is proposing an 
SO2 emission limit of 0.06 lb/MMBtu on a 30-day rolling 
average basis for the Gerald Gentleman Station Unit 1 and Unit 2 to 
ensure that multiple Class I areas impacted by the Station's emissions 
can make reasonable progress toward Congress's natural-visibility goal. 
The EPA is also taking comment on the control options and limits 
analyzed in this action.

IV. Legal Authority for This Action

    The EPA has the authority to revisit its prior FIP actions on 
remand. As previously stated, the EPA moved for a partial voluntary 
remand of the FIP without admitting error. The Eighth Circuit granted 
the motion and remanded the action to the EPA on Marth 19, 2015. Thus, 
the EPA has an obligation to complete its action on remand.
    On remand, the EPA is taking this action pursuant to CAA sections 
110(c)(1), 110(k)(3), and 169A(b)(2). CAA section 169A(b)(2) requires 
states to revise their SIPs to contain such measures as may be 
necessary to make reasonable progress towards the national visibility 
goal. Additionally, CAA section 110(k)(3) authorizes the EPA to 
approve, disapprove, or partially approve and partially disapprove a 
SIP or SIP revision, and CAA section 110(c)(1) authorizes the EPA to 
promulgate a FIP where ``the Administrator . . . disapproves a state 
implementation plan submission in whole or in part.'' The EPA's 
authority to take such actions under the CAA necessarily provides it 
the inherent authority to revisit and amend such actions as necessary. 
See Trujillo v. Gen Elec. Co., 621 F.2d 1084, 1086 (10th Cir. 1980). It 
is well established that agencies have inherent authority to revisit 
past decisions and to revise, replace, or repeal a decision to the 
extent permitted by law and supported by a reasoned explanation. FCC v. 
Fox Television Stations, Inc., 556 U.S. 502, 515 (2009); Motor Vehicle 
Manufacturers Ass'n of the United States, Inc. v. State Farm Mutual 
Automobile Insurance Co., 463 U.S. 29, 42 (1983); see also Encino 
Motorcars, LLC v. Navarro, 579 U.S. 211, 221-22 (2016). Further, the 
Eighth Circuit granted the EPA's request for a voluntary remand, and 
this action responds to that remand.

V. EPA's Review of the 2012 Federal Implementation Plan on Remand

    In this action, the EPA is proposing to act on the remanded portion 
of our FIP as it relates to LTS requirements for SO2 for the 
Gerald Gentleman Station. Specifically, the EPA is supplementing the 
record with a four-factor analysis for SO2 at Gerald 
Gentleman Station. As a result of this analysis, the EPA is proposing a 
new FIP with a 0.06 lb/MMBtu emissions limit for SO2 as a 
part of Nebraska's LTS. In EPA's final 2012 action, the EPA relied on 
the implementation of the previously adopted CSAPR FIP for all Nebraska 
Electric Generating Units (EGUs) to satisfy the LTS requirements of the 
Regional Haze Rule for SO2, including for the Gerald 
Gentleman Station. At the time of the final action, the EPA did not 
further evaluate whether, with respect

[[Page 62697]]

to the Gerald Gentleman Station, the CSAPR was an appropriate and 
sufficient measure needed in its LTS for making reasonable progress 
towards natural visibility conditions at the Class I areas it impacts; 
that is, the Badlands, Wind Cave, and Rocky Mountain National Parks. 
The environmental petitioners pointed out this deficiency in their 
challenge of EPA's final action. The EPA agreed, and thus requested and 
was granted a remand.
    For the first planning period, Nebraska participated in the Central 
Regional Air Planning Association (CENRAP) and incorporated the CENRAP-
developed visibility modeling into their regional haze SIP. The SIP 
relied on the CENRAP modeling, which assumed SO2 controls at 
a rate of 0.15 lb/MMBtu at Gerald Gentleman Station.\35\ As explained 
in our 2012 final action on the Nebraska regional haze SIP, source-
specific CALPUFF modeling shows a significant visibility impact from 
Gerald Gentleman Station on South Dakota's Class I areas, Wind Cave and 
Badlands National Parks.\36\ The Colorado Department of Public Health 
and the Environment also commented on Nebraska's regional haze SIP, 
requesting that the state reconsider the question of whether the Gerald 
Gentleman Station should install SO2 controls, given Gerald 
Gentleman Station's CALPUFF modeled impacts on Rocky Mountain National 
Park.37 38 Nebraska consulted with both South Dakota and 
Colorado during the first planning period. Based on their BART 
determination, Nebraska did not require source-specific BART controls 
at Gerald Gentleman Station as part of their LTS in their regional haze 
SIP. As explained in our partial disapproval of the state's regional 
haze SIP, Nebraska did not include an adequate justification explaining 
why controls at the Gerald Gentleman Station were not included as part 
of the LTS, nor did Nebraska provide an adequate explanation or 
documentation of why their conclusions otherwise satisfied the 
requirements of 40 CFR 51.308(d)(3)(iii) to ``determine its 
apportionment of emission reduction obligations necessary for achieving 
reasonable progress.''
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    \35\ For comparison, the SO2 emission rate at Gerald 
Gentleman Station was about 0.58 lb/MMBtu during 2002, which was the 
period used as the baseline by Nebraska when it developed its SIP. 
In 2015 the emission rate was 0.57 lb/MMBtu. In 2022, the emission 
rate was 0.57 lb/MMBtu.
    \36\ 77 FR at 12776.
    \37\ 77 FR 12776-12777.
    \38\ Gerald Gentleman Station CALPUFF modeling visibility 
impacts were 1.15 deciview at Rocky Mountain. The source-specific 
CALPUFF modeling approach and results are provided in EPA's Analysis 
and Modeling TSD.
---------------------------------------------------------------------------

    In addition to the CALPUFF modeling used in its BART determination, 
Nebraska also used CENRAP CAMx photochemical source apportionment 
modeling to identify the pollutants (e.g., sulfates, nitrates) and 
source categories (e.g., elevated point EGUs) that most impact 
visibility at Class I areas located in surrounding states. A summary of 
the annual emissions used for Nebraska elevated point sources and 
Gerald Gentleman Station in the 2002 base year and 2018 future year 
CENRAP modeling is shown in table 1 of the Analysis and Modeling 
Technical Support Document (Analysis and Modeling TSD) for this action.
    The EPA reviewed both the 2018 CENRAP CAMx source 
apportionment modeling used by Nebraska and the Western Resources Air 
Partnership (WRAP) 2018 CAMx source apportionment used by 
South Dakota and Colorado to establish RPGs at their respective Class I 
areas. In setting their RPGs, both South Dakota and Colorado used the 
WRAP 2018 PRP18b modeling platform, which assumed an SO2 
control rate of 0.15 lb/MMBtu at Gerald Gentleman, which is similar to 
the 2018 CENRAP modeling. The modeled combined emissions at Gerald 
Gentleman Station Units 1 and 2 showed SO2 emissions 
decreasing from 32,152 ton per year (tpy) in 2002 to 8,732 tpy in 2018 
(with controls to achieve the 0.15 lb/MMBtu SO2 emission 
limit assumed to be in operation in 2018).\39\ This reduction of the 
CAMx modeled SO2 emissions at Gerald Gentleman 
Station helps lower the projected SO2-caused light 
extinction at Badlands National Park contributed by Nebraska elevated 
point sources from 0.98 Mm-1 in 2002 to 0.47 Mm-1 
in 2018. The decrease in the SO2 extinction at Badlands 
National Park from Nebraska elevated point sources is due to the 
decrease in modeled emissions from 2002 to 2018, and in particular the 
decrease in modeled SO2 emissions at Gerald Gentleman 
Station due to the assumption of the achievement of a 0.15 lb/MMBtu 
emission rate in 2018. The EPA therefore finds that the CAMx modeling 
performed by both CENRAP and WRAP shows that emissions from Gerald 
Gentleman Station contribute to visibility impairment at the Badlands 
Class I area in South Dakota.
---------------------------------------------------------------------------

    \39\ WRAP-RMC_2002-18_Modeling_Gerald_Gentleman.xlsx in the 
docket.
---------------------------------------------------------------------------

    In 2012, the EPA evaluated Nebraska's SIP and determined it did not 
appropriately address the LTS requirements of the Regional Haze Rule 
related to Gerald Gentleman Station. Although there were modeled 
visibility impacts and improvements from the installation of cost-
effective controls at Gerald Gentleman Station at Class I areas, 
Nebraska did not require any reduction in SO2 emissions from 
Gerald Gentleman Station. The EPA partially disapproved Nebraska's LTS 
based on the state's reliance on the deficient SO2 control 
determination for Gerald Gentleman Station. The EPA also promulgated a 
FIP in which we relied on the CSAPR to address this deficiency in 
Nebraska's SIP, but the EPA did not conduct a four factor analysis to 
evaluate whether additional controls beyond the CSAPR at Gerald 
Gentleman Station were required to ensure the SIP included all measures 
necessary to obtain Nebraska's share of the emission reductions needed 
to make reasonable progress towards the national goal at the Class I 
areas its emissions impact. Therefore, in order to provide a more 
thorough rationale on its LTS determination, the EPA requested and was 
granted a remand in order to provide a more robust explanation.
    To properly evaluate whether the CSAPR was sufficient to satisfy 
Nebraska's obligation to address the visibility impacts of their 
emissions at the Class I areas it affects, the EPA has reviewed the 
record from the proposed and final actions. The EPA has found that the 
reductions expected (and now observed) from the implementation of the 
CSAPR do not equate to the reductions presumed by the CENRAP and WRAP 
modeling that were found to be achievable at a reasonable cost by both 
Nebraska and the EPA. We are therefore proposing to conclude that the 
CSAPR budgets for Nebraska are inadequate to ensure reasonable progress 
at neighboring Class I areas.

[[Page 62698]]

    The EPA's determination in 2012 that the CSAPR provides for greater 
reasonable progress than BART was based on an assessment that the CSAPR 
would provide for greater visibility improvement, on average, across 
all affected Class I areas.\40\ In our assessment of the relative 
impacts of the CSAPR and BART on visibility, the EPA considered 
separately the average visibility improvement across the 60 Class I 
areas in the eastern portion of the CSAPR modeling domain and the 
average impact across all 140 Class I areas in the 48 contiguous states 
with sufficiently complete monitoring data to support our analysis.\41\ 
In both cases, the Agency concluded that the CSAPR would provide for 
greater reasonable progress than BART on a regional basis. Both 
assessments showed, however, that source-specific BART would provide 
for greater visibility improvement than participation in the CSAPR in a 
number of Class I areas west of the Mississippi River and east of the 
Rocky Mountains, including at the Wind Cave and Badlands National Parks 
in South Dakota.\42\
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    \40\ 77 FR 33642 (June 7, 2012).
    \41\ 76 FR 82219, 82225-82227 (December 30, 2011).
    \42\ 77 FR at 33650; TSD for CSAPR Better-than-BART found at 
https://www.regulations.gov/document?D=EPA-HQ-OAR-2011-0729-0014.
---------------------------------------------------------------------------

    That being said, as mentioned previously, in addition to the BART 
requirements, first planning period regional haze SIPs also have LTS 
requirements that are separate and apart from BART. The fact that a 
BART alternative provides for greater reasonable progress on average 
across a number of Class I areas in order to be considered a valid BART 
alternative, does not inherently mean that the same BART alternative 
can also be used, without additional explanation or analysis, to 
automatically satisfy the LTS requirements to ensure reasonable 
progress.\43\ As stated above, like the BART requirements laid out in 
CAA 169A(b)(2)(A) and 40 CFR 51.308(e), in order to show that a state's 
SIP is also making reasonable progress toward the national goal 
pursuant to CAA 169A(a)(1) & (b)(2)(B), it must also meet separate 
requirements outlined in 40 CFR 51.308(d). For example, each state must 
document the information upon which it is relying to determine its 
apportionment of emission reduction obligations necessary for achieving 
reasonable progress in each Class I area it affects, which includes 
considering the four statutory factors set forth in section 
169(A)(g)(1).\44\
---------------------------------------------------------------------------

    \43\ 70 FR 39104, 39143-144 (July 6, 2005).
    \44\ 40 CFR 51.308(d)(3)(iii); 42 U.S.C. 7491(g)(1).
---------------------------------------------------------------------------

    In assessing the impacts of the CSAPR on SO2 emissions 
from Nebraska, the CSAPR did not drive comparable SO2 
reductions at the Gerald Gentleman Station to those achievable from 
SO2 controls. Prior to the CSAPR, Gerald Gentleman Station 
had a five-year annual average SO2 emissions of 27,600 tons. 
After the CSAPR implementation on January 1, 2015, Gerald Gentleman 
Station has had annual SO2 emission ranging from 18,200 to 
27,700 tons with an annual average of 22,400 tons from 2015 to 
2022.\45\ In the most recent year (2022) of available data, Gerald 
Gentleman Station's facility-wide annual SO2 emissions were 
21,228 tons, which ranks 3rd nationally across electrical generating 
units. Currently, Nebraska receives 68,162 tons of SO2 
allowances under the CSAPR and 28,896 tons of SO2 allowances 
are given annually to Gerald Gentleman Station. Despite the CSAPR being 
a valid BART alternative to fulfill Nebraska's first planning period 
BART requirements, because of the amount of the CSAPR allowances 
provided to Nebraska, as it relates to its LTS requirements, the CSAPR 
has not resulted in any additional SO2 emissions reductions 
from Gerald Gentleman Station. Instead, the year-to-year variability 
seen in annual emissions is primarily driven by fluctuations in coal 
sulfur content and utilization. As an example, if Nebraska had 
implemented the 0.15 lb/MMBtu presumptive SO2 limit used in 
the CENRAP and WRAP modeling, as relied upon by other CENRAP and WRAP 
states, Gerald Gentleman Station would have had annual SO2 
emissions ranging from 5,500 to 8,300 tons.\46\ Given the lack of 
reductions required by the CSAPR in Nebraska coupled with the history 
outlined above regarding Nebraska's consultation with neighboring 
states, the EPA is proposing that it is inappropriate to rely on the 
CSAPR to ensure reasonable progress toward natural visibility without 
further consideration of appropriate SO2 control measures 
for Gerald Gentleman Station.
---------------------------------------------------------------------------

    \45\ Based on CAMD information. See the file ``CAMD 
SO2 annual emissions from GGS20152022.cvs'' in the docket 
for this action.
    \46\ Based on a conservative 70% reduction in emissions.
---------------------------------------------------------------------------

    Therefore, in this action, the EPA has provided an analysis of the 
LTS in accordance with 40 CFR 51.308(d) and the CAA 169A(b)(2)(B). This 
analysis includes a discussion of the four statutory factors outlined 
in CAA 169A(g)(1) to determine whether additional emission reduction 
measures are necessary at the Gerald Gentleman Station to fulfill the 
LTS requirements of the Regional Haze Rule to ensure reasonable 
progress towards the national goal.
    To complete the reasonable progress four-factor analysis the EPA 
must look at the following: the costs of compliance; the time necessary 
for compliance; the energy and non-air environmental impacts of 
compliance; and the remaining useful life of any potentially affected 
sources.\47\ The Guidance for Setting Reasonable Progress Goals under 
the Regional Haze Program \48\ notes the similarity between some of the 
reasonable progress factors and the BART factors contained in 40 CFR 
51.308(e)(1)(ii)(A),and suggests that the BART Guidelines be consulted 
regarding cost, energy and non-air quality environmental impacts, and 
remaining useful life. We are therefore relying on our BART Guidelines 
for assistance in quantifying and considering those reasonable progress 
factors, as applicable.
---------------------------------------------------------------------------

    \47\ 40 CFR 51.308(d)(1)(i); 42 U.S.C. 7491(g)(1).
    \48\ Guidance for Setting Reasonable Progress Goals Under the 
Regional Haze Program, June 1, 2007. The 2019 Guidance includes the 
June 1, 2007 in its list of other guidance and does not contradict 
it. While the 2019 Guidance discusses reasonable progress and the 
four-factor analysis, the EPA is using the June 1, 2007 Guidance 
since this is a first Planning Period action.
---------------------------------------------------------------------------

    Each of the elements of the four-factor analysis is discussed 
below.

A. Factor 1--The Costs of Compliance

1. EPA's Evaluation of Costs for BART in the 2012 Proposed and Final 
Rule
    In the 2012 proposed and final action, the EPA and Nebraska 
evaluated the cost of installation of wet FGD on Gerald Gentleman 
Station. Nebraska, in their SIP, concluded that these costs were 
reasonable on a cost per ton basis for both units combined ($2,726/
ton).\49\ Nebraska also evaluated controls at Gerald Gentleman Station 
on a dollars per dv basis.\50\ Nebraska determined that while costs on 
a dollar per ton basis

[[Page 62699]]

were reasonable, costs on a dollar per dv basis were not 
reasonable.\51\ Nebraska also saw water consumption of wet flue-gas 
desulfurization (FGD) controls as significant and concluded that 
because of this unique situation, wet FGD controls were unreasonable 
for Gerald Gentleman Station Units 1 and 2.\52\
---------------------------------------------------------------------------

    \49\ The Nebraska cost analysis was done using a dollar year 
prior to 2012. The state analysis and the prior EPA cost analysis 
were completed using a dollar year at least ten years earlier than 
the cost analysis in this document. Inflation has been factored into 
EPA's current cost analysis based on 2022 dollars.
    \50\ As explained in the final action in 2012, the BART 
Guidelines require the costs of controls to be evaluated on a dollar 
per ton basis. In their BART determinations, Nebraska used a 
threshold of $40 million/dv/year; in their review of the BART 
analysis for Gerald Gentleman Station, the EPA concluded that 
Nebraska had overestimated the cost of control and underestimated 
the control efficiency of scrubbers and ignored the cumulative 
visibility impacts of controls at Gerald Gentleman Station. If 
Nebraska had appropriately estimated the cost of control and 
considered cumulative benefits, scrubbers would have been found to 
be cost effective on a dollars per deciview basis under the 
threshold set by Nebraska. See 77 FR 40157.
    \51\ 77 FR 12770 at 12779.
    \52\ Id.
---------------------------------------------------------------------------

    The EPA agreed with Nebraska that the cost per ton for FGD was 
reasonable and that Nebraska's analysis showed significant visibility 
improvement both at Badlands National Park and on a cumulative 
basis.\53\ The EPA also found that Nebraska inappropriately ruled out 
dry sorbent injection (DSI), because the EPA found that costs were 
reasonable and visibility improvement was significant.\54\
---------------------------------------------------------------------------

    \53\ 77 FR 12770 at 12780.
    \54\ Id.
---------------------------------------------------------------------------

    The EPA also found that Nebraska made several errors in determining 
the cost of controls.\55\ The EPA determined that Nebraska made 
incorrect assumptions about Gerald Gentleman Station's SO2 
emissions and the capability of certain controls. Nebraska also 
deviated from the EPA's Cost Control Manual when evaluating costs.\56\ 
The EPA did our own evaluation in accordance with the Cost Control 
Manual and found that the cost per ton of SO2 controls 
ranged from $1,972 to $2,310 for each Gerald Gentleman Station 
unit.\57\ The EPA determined that the costs for control were reasonable 
and visibility improvement was significant and disapproved Nebraska's 
SO2 BART determination for Gerald Gentleman Station.\58\ The 
EPA's partial disapproval of Nebraska's SIP was upheld by the 8th 
Circuit and we are not reconsidering that decision in this proposed 
rulemaking.\59\ In 2011 and 2012, neither Nebraska in their SIP 
submission nor the EPA in its action analyzed whether any control 
measures beyond BART were necessary to make reasonable progress at the 
affected Class I areas and thus a part of Nebraska's LTS.
---------------------------------------------------------------------------

    \55\ Id.
    \56\ Id.
    \57\ Id. This analysis and determination were conducted 
consistent with previous actions where cost of control analyses were 
submitted with deviations from the Control Cost Manual. 77 FR 12770 
(March 2, 2012); 77 FR 40149 (July 6, 2012); 79 FR 74817 (December 
26, 2014); 81 FR 295 (January 5, 2016).
    \58\ Id.; 77 FR 40149.
    \59\ State of Nebraska v. EPA, 812 F.3d 662 (8th Cir. 2015).
---------------------------------------------------------------------------

2. EPA's Updated Cost Evaluation
    In this action, as the EPA reviewed the LTS requirements under the 
CAA and its regulations, the EPA evaluated the feasibility and costs of 
installing several types of SO2 control systems at Gerald 
Gentleman Station. Specifically, the EPA has analyzed costs for DSI, 
spray dry absorber (SDA), and wet FGD. We have looked at each of these 
control technologies at various control rates to determine which rate/
control scenarios are cost effective. The cost evaluation and 
methodologies are described in detail in the Cost Analysis Technical 
Support Document (Cost TSD), available in the docket of this proposed 
action.\60\
---------------------------------------------------------------------------

    \60\ The use of the IPM cost model is consistent with the other 
EPA Regional Haze actions and is based on reliable and accurate 
technical tools widely utilized by the EPA to assess control 
scenarios at electric generating units and other large sources.
---------------------------------------------------------------------------

    In developing cost estimates for the Gerald Gentleman Station 
units, we relied on the methodologies described in the EPA's Air 
Pollution Control Cost Manual (the Control Cost Manual, or Manual).\61\ 
To estimate the costs for SDA scrubbers and wet FGD scrubbers, we used 
the ``Air Pollution Control Cost Estimation Spreadsheet For Wet and Dry 
Scrubbers for Acid Gas Control'' 62 63 prepared by EPA's 
Office of Air Quality Planning and Standards (OAQPS) Air Economics 
Group following methods in the Cost Control Manual. The methodologies 
for wet FGD and SDA scrubbers are based on those from EPA's CAMPD 
Integrated Planning Model (IPM) Model Version 6. To estimate the cost 
for DSI, we used the 2023 version of the EPA's Retrofit Cost Analyzer 
(RCA),\64\ which is an Excel-based tool that can be used to estimate 
the cost of building and operating air pollution controls and also 
employs Version 6 of our IPM model. These cost algorithms calculate the 
Total Capital Investment (TCI) and Total Annual Direct and Indirect 
Annual Costs. They also calculate the annualized costs per ton of 
SO2 removed ($/ton).
---------------------------------------------------------------------------

    \61\ The EPA Air Pollution Control Cost Manual, Seventh Edition, 
April 2021, downloaded from https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution.
    \62\ IPM Model--Updates to Cost and Performance for APC 
Technologies, SDA FGD Cost Development Methodology, Final January 
2017, Project 13527-001, Eastern Research Group, Inc., Prepared by 
Sargent & Lundy. Downloaded from https://www.epa.gov/system/files/documents/2023-03/Attachment%205-2%20SDA%20FGD%20Cost%20Development%20Methodology.pdf and https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution.
    \63\ IPM Model--Updates to Cost and Performance for APC 
Technologies, Wet FGD Cost Development Methodology, Final January 
2017, Project 13527-001, Eastern Research Group, Inc., Prepared by 
Sargent & Lundy. Downloaded from https://www.epa.gov/system/files/documents/2023-03/Attachment%205-1%20Wet%20FGD%20Cost%20Development%20Methodology.pdf and https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution.
    \64\ IPM Model--Updates to Cost and Performance for APC 
Technologies, Dry Sorbent Injection for SO2/HCl Control 
Cost Development Methodology, Final March 2023, Project 13527-002, 
Eastern Research Group, Inc., Prepared by Sargent & Lundy. 
Downloaded from https://www.epa.gov/system/files/documents/2023-04/13527-002%20DSI%20Cost%20Methodology_Final_2023.pdf and https://www.epa.gov/power-sector-modeling/retrofit-cost-analyzer.
---------------------------------------------------------------------------

    The EPA evaluated the cost of DSI using the default RCA cost models 
based on 2021 dollars. In order to maintain consistency with other cost 
numbers presented in this proposal, we escalated these costs to the 
most recent year (2022) dollars.\65\ We used the RCA Tool \66\ to 
analyze the cost of DSI at Gerald Gentleman Station for SO2 
emission rates of 0.10 lb/MMBtu and 0.30 lb/MMBtu. We chose these rates 
based on documentation from the RCA tool. The tool does not recommend 
application of DSI for SO2 emission rates below 0.10 lb/
MMBtu without unit specific analysis, and we are absent site-specific 
information for Gerald Gentleman Station.\67\ As discussed in more 
detail in the Cost TSD (appendix A), we are not able to find 
information showing that any coal-fired units in the U.S. are currently 
achieving the 0.06 lb/MMBtu rate and 0.04 lb/MMBtu rate we reviewed for 
the other control options, with the use of DSI alone.
---------------------------------------------------------------------------

    \65\ Ibid., p.4: ``The data was converted to 2021 dollars based 
on an escalation factor of 2.5% based on the industry trends over 
the last ten years (2010-2020) excluding the current market 
conditions. To escalate prices from January 2021 to July 2022 costs, 
an escalation factor of 19.5% should be used, based on the Handy 
Whitman steam production plant index.''
    \66\
    \67\ IPM Model--Updates to Cost and Performance for APC 
Technologies, Dry Sorbent Injection for SO2/HCl Control 
Cost Development Methodology, Final March 2023, Project 13527-002, 
Eastern Research Group, Inc, Prepared by Sargent & Lundy, p.1-2.
---------------------------------------------------------------------------

    The corresponding DSI control efficiency rates at Gerald Gentleman 
Station Unit 1 for 0.30 lb/MMBtu and 0.10 lb/MMBtu was 52 and 84 
percent SO2 removal, while Unit 2 had corresponding control 
rates of 53 and 84 percent, respectively, for SO2 
removal.\68\ The slight difference in control efficiency at the 0.3 lb/
MMBtu rate is due to differences in the utilization of the two units 
over the time period analyzed (2018-2022). A summary of our DSI cost 
analysis is shown in table 1. We conclude DSI is cost-effective at

[[Page 62700]]

$2,491/ton and $2,486/ton for Unit 1 and Unit 2, respectively at the 
0.10 lb/MMBtu rate analyzed.\69\ We invite comment on the feasibility 
and cost-effectiveness of the control efficiencies and emission rate 
used for DSI at Gerald Gentleman Station, supported by evidence.
---------------------------------------------------------------------------

    \68\ The 52-53 percent rate for DSI was selected based on easily 
achieved known operating performance of installed DSI systems. The 
84 percent rate for DSI was selected based on the use of milled 
trona along with a baghouse. Both Gerald Gentleman Station units 
have baghouses installed.
    \69\ The EPA recently proposed a BART FIP for Texas that 
references past BART decisions, specifically that several controls 
were required by either the EPA or States as BART with average cost-
effectiveness values in the $4,200 to $5,100/ton range (escalated to 
2020 dollars). In 2022 dollars, this range is $5,700/ton to $7,000/
ton. See 88 FR 28918, 28963. For 2020 the CEPCI value is 596.2. For 
2022 the CEPCI value 816.0.

                                               Table 1--DSI Costs
----------------------------------------------------------------------------------------------------------------
                                                                      Removal     Controlled SO2    2022$ Cost
             Unit                            Control                efficiency       rate (lb/     effectiveness
                                                                       (90%)          MMBtu)          (/ton)
----------------------------------------------------------------------------------------------------------------
GERALD GENTLEMAN STATION Unit   DSI (milled trona)..............              52            0.30          $2,383
 1.                             w/BGH...........................              84            0.10          $2,491
GERALD GENTLEMAN STATION Unit   DSI (milled trona)..............              53            0.30          $2,362
 2.                             w/BGH...........................              84            0.10          $2,486
----------------------------------------------------------------------------------------------------------------

    As previously mentioned, we used the ``Air Pollution Control Cost 
Estimation Spreadsheet for Wet and Dry Scrubbers for Acid Gas 
Control,'' to estimate the cost of SDA scrubbers. This is an Excel-
based tool that can be used to estimate the costs for installing and 
operating scrubbers for reducing SO2 and acidic gas 
emissions from fossil fuel-fired combustion units and other industrial 
sources of acid gases.\70\ The size and costs of SDA scrubbers are 
based primarily on the size of the combustion unit and the sulfur 
content of the coal burned. The calculation methodologies used in the 
``Air Pollution Control Cost Estimation Spreadsheet for Wet and Dry 
Scrubbers for Acid Gas Control'' are consistent with those presented in 
the U.S. EPA's Air Pollution Control Cost Manual. The ``Air Pollution 
Control Cost Estimation Spreadsheet for Wet and Dry Scrubbers for Acid 
Gas Control'' employs version 6 of our IPM model.\71\ The cost models 
used in IPM version 6 were based on 2016 dollars. In performing the 
cost calculations in this action,\72\ we have escalated the costs to 
2022 dollars. The ``Air Pollution Control Cost Estimation Spreadsheet 
for Wet and Dry Scrubbers for Acid Gas Control'' allows the user to 
enter a different dollar-year for costs and the corresponding cost 
index if a different dollar-year is desired. Using this capability, we 
entered the 2022 Chemical Engineering Plant Cost Index (CEPCI) \73\ 
into the spreadsheet to estimate the cost of SDA scrubbers in 2022 
dollars.
---------------------------------------------------------------------------

    \70\ Air Pollution Control Cost Estimation Spreadsheet for Wet 
and Dry Scrubbers for Acid Gas Control, U.S. Environmental 
Protection Agency, Air Economics Group, Health and Environmental 
Impacts Division, Office of Air Quality Planning and Standards 
(January 2023), downloaded from https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution.
    \71\ Documentation for EPA's Power Sector Modeling Platform v6 
Using the Integrated Planning Model, dated March 2023. Documentation 
for v6 downloaded from https://www.epa.gov/power-sector-modeling/documentation-post-ira-2022-reference-case.
    \72\ Spreadsheets containing our cost calculations are located 
in our Docket.
    \73\ https://www.chemengonline.com/pci-home.
---------------------------------------------------------------------------

    We evaluated the cost of SDA using a control efficiency rate of 90 
and 91 percent SO2 removal at Gerald Gentleman Station Units 
1 and 2, corresponding to an SO2 emission rate of 0.06 lb/
MMBtu at both Units. The EPA analyzed the cost of SDA scrubbers using 
this removal rate and emission limit because the lowest available 
SO2 emission guarantees from original equipment 
manufacturers of SDA systems are 0.06 lb/MMBtu. A summary of our SDA 
scrubber cost analysis is shown in table 2. We conclude SDA scrubbers 
are cost-effective at $4,073/ton and $4,002/ton for Unit 1 and Unit 2, 
respectively at the 0.06 lb/MMBtu rate analyzed.\74\
---------------------------------------------------------------------------

    \74\ The EPA recently proposed a BART FIP for Texas that 
references past BART decisions, specifically that several controls 
were required by either the EPA or States as BART with average cost-
effectiveness values in the $4,200 to $5,100/ton range (escalated to 
2020 dollars). In 2022 dollars, this range is $5,700/ton to $7,000/
ton. See 88 FR 28918, 28963. For 2020 the CEPCI value is 596.2. For 
2022 the CEPCI value 816.0.

                                               Table 2--SDA Costs
----------------------------------------------------------------------------------------------------------------
                                                                                  Controlled SO2    2022$ Cost
             Unit                            Control                  Removal        Rate (lb/     effectiveness
                                                                  efficiency (%)      MMBtu)          (/ton)
----------------------------------------------------------------------------------------------------------------
GERALD GENTLEMAN STATION Unit   SDA.............................              90            0.06          $4,073
 1.
GERALD GENTLEMAN STATION Unit   SDA.............................              91            0.06           4,002
 2.
----------------------------------------------------------------------------------------------------------------

    The cost of a baghouse to collect the particles from the operation 
of the SDA scrubbers was not included in our cost estimate because 
Gerald Gentleman Station currently operates a baghouse on both units. 
The EPA invites comment on the feasibility and cost-effectiveness of a 
higher control efficiency, and lower emission rate, using dry scrubbing 
at Gerald Gentleman, supported by evidence.
    We also evaluated the cost of a wet FGD at Gerald Gentleman Station 
Units 1 and 2. The size and costs of wet FGD scrubbers are based 
primarily on the size of the combustion unit and the sulfur content of 
the coal burned. The wet FGD scrubber cost methodology includes cost 
algorithms for capital and operating cost for wastewater treatment 
consisting of chemical pretreatment, low hydraulic residence time 
biological reduction, and ultrafiltration to treat wastewater generated 
by the wet FGD system.\75\
---------------------------------------------------------------------------

    \75\ The methodologies had not been updated to incorporate the 
May 9, 2024 Steam Electric Power Generation Effluent Limitation 
Guidelines and Standards.
---------------------------------------------------------------------------

    Similar to our SDA analysis and approach, the cost models used in 
IPM version 6 were based on 2016 dollars and we escalated the costs to 
2022

[[Page 62701]]

dollars to estimate the cost of wet FGD scrubbers in 2022 dollars. As 
shown in table 3, the EPA used SO2 control efficiencies of 
90-91 percent and 94 percent corresponding to emission rates of 0.06 
and 0.04 lb/MMBtu, respectively.\76\ We conclude wet FGD are cost-
effective at $4,283/ton and $4,145/ton for Unit 1 at 90% and 94% 
SO2 removal rate (respectively) and $4,267/ton and $4,132/
ton for Unit 2 at 91% and 94% SO2 removal rate 
(respectively).
---------------------------------------------------------------------------

    \76\ The EPA analyzed the cost of wet scrubbers based on limits 
of 0.04 and at 0.06 lb/MMBtu. The first analysis at 0.04 lb/MMBtu 
evaluates wet FGD which is the lowest rate that vendors of the 
technology will guarantee. The IPM presumptive control model uses a 
removal efficiency of 98 percent. Because a 98 percent removal 
efficiency results in SO2 rates less than 0.04 lb/MMBtu 
for the Gerald Gentleman Station units, we limited the control 
efficiency in the cost algorithm to just under 94 percent to assure 
that NPPD can obtain a performance guarantee for the wet scrubber. 
The second analysis allows direct comparison to SDA at similar 
reduction efficiencies of 90- 91 percent.

                                             Table 3--Wet FGD Costs
----------------------------------------------------------------------------------------------------------------
                                                                                  Controlled SO2    2022$ Cost
             Unit                            Control                  Removal        Rate (lb/     effectiveness
                                                                  efficiency (%)      MMBtu)          (/ton)
----------------------------------------------------------------------------------------------------------------
GERALD GENTLEMAN STATION Unit   Wet FGD.........................              90            0.06          $4,283
 1.                                                                           94            0.04           4,145
GERALD GENTLEMAN STATION Unit   Wet FGD.........................              91            0.06           4,267
 2.                                                                           94            0.04           4,132
----------------------------------------------------------------------------------------------------------------

    We acknowledge that the remaining useful life affects the cost 
effectiveness estimates for the control technologies analyzed in this 
section. As discussed in more detail in appendix A of the TSD, 
available in the docket of this proposal, and in section IV.A.4. below, 
the EPA has used 30 years as the remaining useful life of the units and 
any new controls installed on them. The EPA believes that even if the 
remaining useful life of the units is as short as 20 years, the 
proposed control rate and associated control technologies are still 
cost effective.
    Based on our assessment, we are concluding that cost effective 
controls of SO2 are available using DSI, SDA scrubbers and 
wet FGD scrubbers.

B. Factor 2--The Time Necessary for Compliance

    The EPA believes five years is the appropriate time period for 
installation of wet FGD or SDA except where there are unusual 
circumstances. Five years for installation is consistent with our 
experience regarding FGD installations at power plants generally. In 
response to a section 114 information request, NPPD submitted several 
documents that demonstrate that between 2009 and 2014, NPPD considered 
installing wet FGD controls on Gerald Gentleman Station Units 1 and 
2.\77\ The engineering documents and requests for bids from this 
process included a timeline of five years from design to completion. 
The EPA believes this is an appropriate timeframe for installation of 
wet FGD controls at Gerald Gentleman Station. We believe that SDA could 
be installed within the same timeframe. DSI may be able to be installed 
in a time frame of two to three years. This is consistent with the 
previous EPA actions.\78\
---------------------------------------------------------------------------

    \77\ See NPPD CAA section 114 Response: NPPDRH114_0000892, 
NPPDRH114_0001321, NPPDRH114_0001584, NPPDRH114_0002059, 
NPPDRH114_0005017.
    \78\ See 76 FR 81729, 81758 (December 28, 2011) and 81 FR 66332, 
66416 (September 27, 2016), where we promulgated regional haze FIPs 
for Oklahoma and Arkansas, respectively. These FIPs required BART 
SO2 emission limits on coal-fired EGUs based on new 
scrubber retrofits with a compliance date of no later than five 
years from the effective date of the final rule. Also see 88 FR 
28918 (May 4, 2023), where we proposed BART SO2 emission 
limits with a compliance date not later than three years or DSI and 
five years for wet FDG.
---------------------------------------------------------------------------

C. Factor 3--The Energy and Non-Air Quality Environmental Impacts of 
Compliance

    The Guidance for Setting Reasonable Progress Goals under the 
Regional Haze Program advises, ``In assessing energy impacts, you may 
want to consider whether the energy requirements associated with a 
control technology result in energy penalties.'' ``To the extent that 
these considerations are quantifiable they should be included in the 
engineering analyses supporting compliance cost estimates'', and to 
consult the BART Guidelines.\79\ To analyze energy impacts, the BART 
Guidelines advise, ``You should examine the energy requirements of the 
control technology and determine whether the use of that technology 
results in energy penalties or benefits.'' \80\ As discussed above in 
our cost analyses for DSI, SDA, and wet FGD, our cost model allows for 
the cost of additional auxiliary power required for pollution controls 
to be included in the variable operating costs. The EPA chose to 
include this additional auxiliary power in all cases. Further, the cost 
of electricity is negligible compared to the capacity of Gerald 
Gentleman Station and the grid as a whole. For WFGD, the cost of 
electricity is approximately 1.25% of energy output. For SDA, the cost 
of electricity is approximately 1.32% of energy output. For DSI, the 
cost of electricity is 0.28% of energy output. Consequently, we believe 
that any energy impacts of compliance have been adequately considered 
in our analyses.
---------------------------------------------------------------------------

    \79\ Guidance for Setting Reasonable Progress Goals Under the 
Regional Haze Program, June 1, 2007, available at https://www3.epa.gov/ttn/naaqs/aqmguide/collection/cp2/20070601_wehrum_reasonable_progress_goals_reghaze.pdf.
    \80\ 70 FR 39168 (July 6, 2005).
---------------------------------------------------------------------------

    The Guidance for Setting Reasonable Progress Goals under the 
Regional Haze Program also advises the consideration of ``the effects 
of the waste stream that may be generated by a particular control 
technology, and/or other resource consumption rates such as water, 
water supply, and wastewater disposal. To the extent that these 
considerations are quantifiable, they should also be included in the 
analyses supporting compliance cost estimates'' and to also consult the 
BART Guidelines for additional guidance on applying this factor to 
stationary sources.\81\ Regarding the analysis of non-air quality 
environmental impacts, the BART Guidelines advise ``Such environmental 
impacts include solid or hazardous waste generation and discharges of 
polluted water from a control device. You should identify any 
significant or unusual environmental impacts associated with a control 
alternative that have the potential to affect the selection or 
elimination of a control alternative. Some control technologies may 
have potentially significant secondary environmental impacts. Scrubber 
effluent, for example, may affect water quality or land use. 
Alternatively, water availability may affect the feasibility

[[Page 62702]]

and costs of wet FGD. Other examples of secondary environmental impacts 
could include hazardous waste discharges, such as spent catalysts or 
contaminated carbon. Generally, these types of environmental concerns 
become important when sensitive site-specific receptors exist, or when 
the incremental emission reductions potential of the more stringent 
control is only marginally greater than the next most-effective option. 
However, the fact that a control device creates liquid and solid waste 
that must be disposed of does not necessarily argue against selection 
of that technology as BART, particularly if the control device has been 
applied to similar facilities elsewhere and the solid or liquid waste 
is similar to those other applications. On the other hand, where you or 
the source owner can show that unusual circumstances at the proposed 
facility create greater problems than experienced elsewhere, this may 
provide a basis for the elimination of that control alternative as 
BART.'' \82\
---------------------------------------------------------------------------

    \81\ Id.
    \82\ 70 FR 39169 (July 6, 2005).
---------------------------------------------------------------------------

    The SO2 control technologies the EPA considered in our 
analyses--DSI, SDA, and wet FGD--are in wide use in the coal-fired 
electricity generation industry. All three technologies would add spent 
reagent to the waste stream already generated by Gerald Gentleman 
Station, but do not present any unusual environmental waste impacts. In 
the case of DSI, the use of sodium-based sorbents makes fly ash 
unsaleable. The EPA has calculated that this would result in revenue 
loss of approximately $0.07/MWh ($1/ton fly ash estimate converted to 
$/MWh) and additional disposal costs of approximately $2/MWh. As 
discussed in our cost analyses for DSI, SDA, and wet FGD, our cost 
model includes waste disposal costs in the variable operating costs.
    Non-air environmental impacts may also take into account water use 
to operate to the SO2 controls evaluated, in particular wet 
FGD scrubbers. While the cost of incorporating a wastewater treatment 
facility at Gerald Gentleman Station is factored into our cost analysis 
for Wet FGD, we recognize water quality concerns associated with the 
waste stream for wet FGD as compared to the installation of SDA 
scrubbers and DSI. The wet FGD scrubber methodology includes cost 
algorithms for capital and operating cost for wastewater treatment 
consisting of chemical pretreatment, low hydraulic residence time 
biological reduction, and ultrafiltration to treat wastewater generated 
by the wet FGD system. The calculation methodologies used in the ``Air 
Pollution Control Cost Estimation Spreadsheet for Wet and Dry Scrubbers 
for Acid Gas Control,'' are those presented in the U.S. EPA's Air 
Pollution Control Cost Manual.
    The cost algorithm used in the ``Air Pollution Control Cost 
Estimation Spreadsheet for Wet and Dry Scrubbers for Acid Gas Control'' 
calculates the Total Capital Investment, Direct Annual Cost, and 
Indirect Annual Cost. The Total Capital Investment for wet FGD is a 
function of the absorber island capital costs, reagent preparation 
equipment costs, waste handling equipment costs, balance of plant 
costs, and wastewater treatment facility costs.
    Regarding water related impacts, we recognize that wet FGD requires 
additional amounts of water as compared to SDA and DSI. Furthermore, 
based on Effluent Limitation Guidelines (ELG), it is expected that all 
future wet FGD installations will require the facility to incorporate a 
wastewater treatment facility.\83\ While this cost is factored into our 
cost analysis, it also highlights water quality concerns associated 
with the waste stream for wet FGD as compared to the installation of 
dry scrubbers and DSI.
---------------------------------------------------------------------------

    \83\ IPM Model--Updates to Cost and Performance for APC 
Technologies, Wet FGD Cost Development Methodology, Final January 
2017, Project 13527-001, Eastern Research Group, Inc., Prepared by 
Sargent & Lundy, p. 1. This Model is prior to the May 9, 2024 Steam 
Electric Power Generation Effluent Limitation Guidelines and 
Standards.
---------------------------------------------------------------------------

    Gerald Gentleman Station is located in western Nebraska, a semi-
arid region dominated by agriculture. While we are aware of water 
availability concerns in the area surrounding Gerald Gentleman Station, 
we believe water resources are available to operate all control 
technologies evaluated in our cost analysis. This is based on 
Nebraska's Regional Haze SIP, the record for our previous actions on 
Nebraska's SIP, and information obtained from NPPD in 2017, which 
contain extensive information about water availability in the area of 
Gerald Gentleman Station. In our 2012 action, the EPA found that the 
cost of purchasing additional water at $234 per ton of SO2 
and that this cost was reasonable.\84\
---------------------------------------------------------------------------

    \84\ 77 FR 33642 (June 7, 2012). Note we are not using this 
number in our current cost analysis.
---------------------------------------------------------------------------

D. Factor 4--The Remaining Useful Life of the Source

    The Guidance for Setting Reasonable Progress Goals under the 
Regional Haze Program advises, ``If the remaining useful life of the 
source will clearly exceed'' the standard time period listed in the EPA 
Air Pollution Control Cost Manual, ``the remaining useful life factor 
has essentially no effect on control costs and on the reasonable 
progress determination process. Where the remaining useful life of the 
source is less than the time period for amortizing the costs of the 
retrofit control, you may wish to use this shorter time period in your 
cost calculations. For additional guidance on applying this factor to 
stationary sources, you may wish to consult the BART Guidelines''.\85\ 
Regarding the analysis of remaining useful life, the BART Guidelines 
advise ``The ``remaining useful life'' of a source, if it represents a 
relatively short time period, may affect the annualized costs of 
retrofit controls. For example, the methods for calculating annualized 
costs in EPA's OAQPS Control Cost Manual requires the use of a 
specified time period for amortization that varies based upon the type 
of control. If the remaining useful life will clearly exceed this time 
period, the remaining useful life essentially has no effect on control 
costs and on the BART determination process. Where the remaining useful 
life is less than the time period for amortizing costs, you should use 
the shorter time period in your cost calculations.'' \86\
---------------------------------------------------------------------------

    \85\ Guidance for Setting Reasonable Progress Goals Under the 
Regional Haze Program, June 1, 2007.
    \86\ 70 FR 39168 (July 6, 2005).
---------------------------------------------------------------------------

    In determining the cost of scrubbers in the original SIP 
submission, Nebraska did not provide a specific useful life for the 
Gerald Gentleman Station.\87\ NPPD also did not provide additional 
insight regarding the remaining useful life of the Gerald Gentleman 
Station in their section 114 response from 2016. Therefore, in line 
with the EPA's approach in prior actions,\88\ we used 30 years in the 
cost module of the IPM model when calculating costs for scrubber 
controls at the Gerald Gentleman Station in this action.
---------------------------------------------------------------------------

    \87\ ``The useful remaining life of Gerald Gentleman Station 
Units 1 and 2 is greater than 20 years under the current NPPD energy 
resource plan. Therefore, the remaining useful life has no impact on 
the annualized estimated control technology cost at this time.'' 
Nebraska Regional Haze SIP, section 10.6.4.9.
    \88\ See 76 FR 52388 (August 22, 2011); 76 FR 81728 (December 
28, 2011); Oklahoma v. EPA, 723 F.3d 1201 (July 19, 2013), cert. 
denied (U.S. May 27, 2014).
---------------------------------------------------------------------------

    Similarly, the EPA sees no reason to assume that a DSI system 
installation, which is a much less complex and costly (capital costs, 
as opposed to annualized costs) technology in comparison to a scrubber 
installation, should have a shorter lifetime. As with a wet FGD or SDA, 
we expect the boiler to be the limiting factor when considering the 
lifetime of a coal-fired power plant. The EPA has therefore

[[Page 62703]]

similarly assumed that the lifetime of a DSI system is 30 years.
    When considering the remaining useful life of a source, we must 
consider the useful life of any additional controls we could require 
and the remaining useful life of the source itself. All the examined 
control options have useful lives of 30 years, therefore, we propose to 
conclude that Units 1 and 2 have a remaining useful life of 30 years. 
In the NPPD 2023 Integrated Resource Plan, NPPD analyzed several 
continued operation scenarios. In the ``SD-05'' scenario, Gerald 
Gentleman Station continues to operate as is until at least 2050.\89\ 
While NPPD has indicated a possible shortening of its EGUs' lifespans, 
including Gerald Gentleman Station, NPPD has also indicated continued 
operation of Gerald Gentleman Station. Without a federally enforceable 
shutdown included in the SIP, the EPA must conclude that NPPD will 
continue operating Gerald Gentleman Station and must use the 30-year 
lifetime in the EPA cost analyses.
---------------------------------------------------------------------------

    \89\ See ``NPPD2023IntergratedResourcePlan.pdf'' in the docket 
for this action.
---------------------------------------------------------------------------

E. Evaluation of Potential Visibility Impacts and Improvements

    Although visibility is not a required element of the four-factor 
analysis, we reviewed the visibility information from the original 
Nebraska Regional Haze SIP record to verify the impacts of Gerald 
Gentleman Station on the nearest Class I areas of Badlands, Wind Cave, 
and Rocky Mountain National Parks. In addition, we provide an updated 
meteorological back-trajectory analysis on the 20% most impaired 
monitored days for the period from 2008 through 2021 at Badlands, Wind 
Cave and Rocky Mountain Class I areas in our Analysis and Modeling TSD, 
which is included in the docket. In this back-trajectory analysis, we 
run 72-hour HYSPLIT model back-trajectories originating at Class I area 
at three different height levels (100 meters, 500 meters and 1,000 
meters). We created composite HYSPLIT density plots for multi-year 
periods and the plots show a consistent pattern of the air mass over or 
near the location of Gerald Gentleman Station on the 20% most impaired 
days for the Badlands and Wind Cave Class I areas. We also generated 
daily back trajectory plots accompanied by plots of Gerald Gentleman 
Station SO2 emissions data and show that Gerald Gentleman 
Station was operating and emitting SO2 on, or leading up to, 
the most impaired days when back trajectories traveled near Gerald 
Gentleman Station.
    In summary, we confirmed the CENRAP and Nebraska CALPUFF modeling 
associated with Nebraska's first planning period SIP, and our updated 
back-trajectory analysis shows that Gerald Gentleman Station likely 
impacts the visibility at the affected Class I areas. Please see our 
Analysis and Modeling TSD for the detailed analysis linking emissions 
from Gerald Gentleman Station to visibility impairment at nearby Class 
I areas.
    Both the CENRAP and WRAP CAMx modeling and BART CALPUFF modeling 
relied upon in the Nebraska's first planning period SIP indicate a 
visibility improvement with the installation of SO2 controls 
at Gerald Gentleman Station. The projected 2018 modeling shows 
improvements in the visibility impairment contribution from Nebraska 
elevated sources at Badlands due to decreases in emissions from the 
SO2 BART controls assumed at Gerald Gentleman Station in the 
modeling. CALPUFF modeling with either wet FGD or DSI at a control rate 
of 0.15 lb/MMBtu produced significant visibility improvements at the 
two South Dakota Class I areas and Rocky Mountain National Park when 
averaged over the 2001-2003 modeling period. All control options with 
this level of control rate or lower will achieve significant emission 
reductions and visibility improvements, with lower control rates (i.e., 
below the modeled 0.15 lb/MMBtu) leading to greater visibility 
improvement.
    Therefore, although visibility is not a required element of the 
four-factor analysis, we propose to conclude there will be significant 
visibility benefit to the Class I areas as a result of installation of 
cost-effective SO2 controls at Gerald Gentleman Station.

VI. Amending the FIP on Remand--Long-Term Strategy Determination for 
Gerald Gentleman Station

    In light of the significant emission reductions achieved by a 0.06 
lb/MMBtu SO2 emission limit, leading to significant 
visibility improvements, the proven ability of both FGD and SDA to 
achieve a rate of 0.06 lb/MMBtu SO2 consistently over a long 
period of time, the controls being cost effective, the ability to 
reasonably obtain water to operate controls, the lower amount of 
wastewater generated, and the lack of certainty surrounding DSI being 
able to achieve the proposed limit at Gerald Gentlemen Station, to 
address the remand for LTS for SO2 at Gerald Gentleman 
Station, the EPA is proposing that Gerald Gentleman Station Unit 1 and 
Unit 2 meet an SO2 emission limit of 0.06 lb/MMBtu averaged 
over a rolling 30 boiler-operating-day period for each unit.\90\
---------------------------------------------------------------------------

    \90\ A boiler operating day is any 24-hour period between 12:00 
midnight and the following midnight during which any fuel is 
combusted at any time at the steam generating unit.
---------------------------------------------------------------------------

    Further, the EPA notes that all SO2 control technologies 
analyzed in this action are cost effective at all analyzed control 
percentages. While a 0.06 lb/MMBtu SO2 limit would achieve a 
high level of visibility improvement, the EPA nonetheless acknowledges 
that all the emission control technologies evaluated in this action 
will reduce SO2 emissions, thus resulting in improved 
visibility at the affected Class I areas.
    The EPA also notes that all the SO2 control technologies 
discussed in this action can be installed within 5 years and DSI can be 
installed as quickly as two years. Therefore, the time necessary for 
compliance for all emission rates can be considered equivalent and 
reasonable.
    In considering the relevant energy and nonair environmental 
concerns, the cost of electricity is negligible compared to the 
capacity of Gerald Gentleman Station and the grid as a whole, as 
included in our cost analysis. Additionally, more waste will be 
generated but not at a rate that would be considered unusual or 
unreasonable. The EPA notes that DSI and SDA generate less wastewater 
than wet FDG, for the same emission limit. Finally, while there is 
water scarcity in the region, NPPD has access to water to operate the 
controls and water costs are included in our cost analysis.
    The EPA also proposes to find that there are no permanent and 
enforceable limitations on the continued operation of Gerald Gentleman 
Station. The EPA is therefore proposing that the remaining useful life 
of the source is at least thirty years.
    Therefore, we also invite comment on all the control technologies 
and other emission limits analyzed within this action. The EPA is 
choosing to propose an SO2 emission limit of 0.06 lb/MMBtu 
based on multiple factors outlined at the beginning of this section. 
This limit was selected based on the operation of SDA. We find SDA can 
meet the 0.06 lb/MMBtu limit at a reasonable, cost-effective level and 
will result in large emissions reductions and visibility improvements 
with less water usage and wastewater than wet FGD. As discussed in more 
detail in the Cost TSD (Appendix A), we are not able to find 
information showing that any coal-fired units in the U.S. are currently 
meeting the 0.06 lb/MMBtu rate limit proposed in this action with the 
use of DSI alone.

[[Page 62704]]

Therefore, we do not have a sufficient basis to conclude that DSI can 
be used to meet a 0.06 lb/MMBtu limit at Gerald Gentleman Station. 
However, the EPA's analysis shows that NPPD can achieve this emission 
rate utilizing SDA or wet FGD technology, both of which are cost-
effective based on the EPA's analysis outlined throughout this action. 
Therefore, rather than proposing a specific control technology, the EPA 
believes it is appropriate to only propose an emission limit because it 
may be possible to meet the proposed limit with SDA or FGD. As stated 
above, we do not have sufficient information to determine whether DSI 
can meet this limit on a consistent, long-term basis. By proposing a 
limit only, the EPA is providing the source with greater flexibility to 
select the control technology that best meets its needs while also 
providing emissions reductions which will result in visibility benefits 
at the affected Class I areas.

VII. The EPA's FLM Consultation

    The EPA consulted with the FLMs (specifically, U.S. Fish and 
Wildlife Service, U.S. Forest Service, and the National Park Service) 
on April 23, 2024 to May 10, 2024. During the consultation we provided 
an overview of our proposed actions and drafts of our technical support 
documents. The FLMs signaled general support for our action.

VIII. Proposed Action

    Based on the EPA's review of the LTS requirements along with its 
analysis of the four statutory factors, the EPA proposes that NPPD 
Gerald Gentleman Station Unit 1 and Unit 2 each meet an emission limit 
of 0.06 lb/MMBtu averaged over a rolling 30 boiler-operating-day 
period. This emission limit would apply at all times, including periods 
of startup and shut down. We are also taking comment on the other 
control technologies and emissions limits analyzed in this action.

IX. Environmental Justice Considerations

    This section summarizes environmental justice data for areas that 
would be impacted by this proposed action and is intended for 
informational and transparency purposes only. Whereas, environmental 
justice data is not a key determinate for this action, the CAA and 
applicable implementing regulations neither prohibit nor require an 
evaluation of environmental justice. This action is perceived to have a 
positive benefit on environmental justice areas. The EPA defines 
environmental justice (EJ) as ``the fair treatment and meaningful 
involvement of all people regardless of race, color, national origin, 
or income with respect to the development, implementation, and 
enforcement of environmental laws, regulations, and policies.'' The EPA 
further defines the term fair treatment to mean that ``no group of 
people should bear a disproportionate burden of environmental harms and 
risks, including those resulting from the negative environmental 
consequences of industrial, governmental, and commercial operations or 
programs and policies.'' \91\ Recognizing the importance of these 
considerations to local communities, the EPA conducted an environmental 
justice screening analysis around the location of Gerald Gentleman 
Station to identify potential environmental stressors on these 
communities and the potential impacts of this action. However, the EPA 
is providing the information associated with this analysis for 
informational purposes only. The information provided herein is not a 
basis of the proposed action. The EPA conducted the screening analyses 
using EJScreen, an EJ mapping and screening tool that provides the EPA 
with a nationally consistent dataset and approach for combining various 
environmental and demographic indicators.\92\ The EJScreen tool 
presents these indicators at a Census block group (CBG) level or a 
larger user specified ``buffer'' area that covers multiple CBGs.\93\ An 
individual CBG is a cluster of contiguous blocks within the same census 
tract and generally contains between 600 and 3,000 people. EJScreen is 
not a tool for performing in depth risk analysis, but is instead a 
screening tool that provides an initial representation of indicators 
related to EJ and is subject to uncertainty in some underlying data 
(e.g., some environmental indicators are based on monitoring data which 
are not uniformly available; others are based on self-reported 
data).\94\ EJScreen environmental indicators help screen for locations 
where residents may experience a higher overall pollution burden than 
would be expected for a block group with the same total population in 
the U.S. These indicators of overall pollution burden include estimates 
of ambient particulate matter (PM2.5) and ozone 
concentration, a score for traffic proximity and volume, percentage of 
pre-1960 housing units (lead paint indicator), and scores for proximity 
to Superfund sites, risk management plan (RMP) sites, and hazardous 
waste facilities.\95\ EJScreen also provides information on demographic 
indicators, including percent low-income, communities of color, 
linguistic isolation, and less than high school education. The EPA 
prepared an EJScreen report covering a buffer area of approximately 6-
mile radius around Gerald Gentleman Station. From this report, no EJ 
indices were greater than the 80th national percentiles.\96\ The full, 
detailed EJScreen report is provided in the docket for this rulemaking. 
This action is proposing to promulgate a FIP to address LTS 
requirements that are not adequately satisfied by the Nebraska Regional 
Haze SIP. The proposed rule is proposing SO2 limits on 
Gerald Gentleman Station in Nebraska to fulfill regional haze program 
requirements. Exposure to SO2 is associated with significant 
public health effects. Short-term exposures to SO2 can harm 
the human respiratory system and make breathing difficult. People with 
asthma, particularly children, are sensitive to these effects of 
SO2.\97\ Therefore, we expect that these requirements for 
Gerald Gentleman Station in Nebraska, if finalized, and resulting 
emissions reductions will contribute to reduced environmental and 
health impacts on all populations impacted by emissions from these 
sources, including populations experiencing a higher overall pollution 
burden, people of color and low-income populations. There is nothing in 
the record which indicates that this proposed action, if finalized, 
would have disproportionately high or adverse human health or 
environmental effects

[[Page 62705]]

on communities with environmental justice concerns.
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    \91\ See https://www.epa.gov/environmentaljustice/learn-about-environmentaljustice.
    \92\ The EJSCREEN tool is available at https://www.epa.gov/ejscreen.
    \93\ See https://www.census.gov/programssurveys/geography/about/glossary.html.
    \94\ In addition, EJSCREEN relies on the five-year block group 
estimates from the U.S. Census American Community Survey. The 
advantage of using five-year over single-year estimates is increased 
statistical reliability of the data (i.e., lower sampling error), 
particularly for small geographic areas and population groups. For 
more information, see https://www.census.gov/content/dam/Census/library/publications/2020/acs/acs_general_handbook_2020.pdf.
    \95\ For additional information on environmental indicators and 
proximity scores in EJSCREEN, see ``EJSCREEN Environmental Justice 
Mapping and Screening Tool: EJSCREEN Technical Documentation,'' 
Chapter 3 and Appendix C (September 2019) at https://www.epa.gov/sites/default/files/2021-04/documents/ejscreen_technical_document.pdf.
    \96\ For a place at the 80th percentile nationwide, that means 
20% of the U.S. population has a higher value. The EPA identified 
the 80th percentile filter as an initial starting point for 
interpreting EJScreen results. The use of an initial filter promotes 
consistency for the EPA programs and regions when interpreting 
screening results.
    \97\ See https://www.epa.gov/so2-pollution/sulfur-dioxide-basics#effects.
---------------------------------------------------------------------------

X. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 14094: Modernizing Regulatory Review

    This action is exempt from review under Executive Order 12866, as 
amended by Executive Order 14094, because it is not a ``significant 
regulatory action'' under the terms of Executive Order 12866 \98\ and 
is therefore not subject to review under Executive Orders 12866 and 
14094.\99\ The proposed FIP only applies to one facility. It is 
therefore not a rule of general applicability.
---------------------------------------------------------------------------

    \98\ 58 FR 51735 (October 4, 1993).
    \99\ 88 FR 21879 (April 11, 2023).
---------------------------------------------------------------------------

B. Paperwork Reduction Act

    This proposed action does not impose an information collection 
burden under the provisions of the Paperwork Reduction Act because it 
is not a rule of general applicability and affects fewer than 10 
entities. See 5 CFR 1320(c).

C. Regulatory Flexibility Act

    I certify that this action will not have a significant impact on a 
substantial number of small entities. This proposed rule does not 
impose any requirements or create impacts on small entities. Nebraska 
Public Power District is not a small entity.

D. Unfunded Mandates Reform Act (UMRA)

    This action contains no Federal mandates under the provisions of 
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 
1531-1538 for state, local, or tribal governments or the private 
sector. The EPA has determined that Title II of UMRA does not apply to 
this proposed rule. In 2 U.S.C. 1502(1) all terms in Title II of UMRA 
have the meanings set forth in 2 U.S.C. 658, which further provides 
that the terms ``regulation'' and ``rule'' have the meanings set forth 
in 5 U.S.C. 601(2). Under 5 U.S.C. 601(2), ``the term `rule' does not 
include a rule of particular applicability relating to . . . 
facilities.'' Because this proposed rule is a rule of particular 
applicability relating to specific EGUs located at one named facility, 
the EPA has determined that it is not a ``rule'' for the purposes of 
Title II of UMRA.

E. Executive Order 13132: Federalism

    This action does not have Federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the national government and the states, or on the distribution of power 
and responsibilities among the various levels of government. This 
proposed rule does not impose significant economic costs on state or 
local governments. Thus, Executive Order 13132 does not apply to this 
proposed action. In the spirit of Executive Order 13132, and consistent 
with the EPA policy to promote communications between the EPA and state 
and local governments, the EPA specifically solicits comment on this 
proposed rule from state and local officials.

F. Executive Order 13175: Coordination With Indian Tribal Governments

    This action does not have tribal implications as specified in 
Executive Order 13175. This action applies to one facility in Nebraska 
and will affect Federal Class I areas in South Dakota and Colorado. 
This action does not apply on any Indian reservation land or any other 
areas where the EPA or an Indian tribe has demonstrated that a tribe 
has jurisdiction, or non-reservation areas of Indian county. Thus 
Executive Order 13175 does not apply to this action.

G. Executive Order 13045: Protection of Children From Environmental 
Health and Safety Risks

    Executive Order 13045: Protection from Environmental Health Risks 
and Safety Risks applies to any rule that: (1) is determined to be 
economically significant as defined under Executive Order 12866; and 
(2) concerns an environmental health or safety risk that we have reason 
to believe may have a disproportionate risk to children. Moreover, 
``regulation'' or ``rule'' is defined in Executive Order 12866 as ``an 
agency statement of general applicability and future effect.'' E.O. 
12866 does not define ``statement of general applicability'' but this 
term commonly refers to statements that apply to groups or classes, as 
opposed to statements which apply only to named entities. The proposed 
FIP, therefore, is not a rule of general applicability because its 
requirements apply and are tailored to only one individually identified 
facility. Thus it is not a ``rule'' or ``regulation'' within in the 
meaning of E.O. 12866. However, as this action will limit emissions of 
SO2, it will have a beneficial effect on children's health 
by reducing air pollution.

H. Executive Order 13211: Actions That Significantly Affect Energy 
Supply, Distribution or Use

    This proposed action is not subject to Executive Order 13211 
because it is not a significant regulatory action under Executive Order 
12866.

I. National Technology Transfer Advancement Act

    This proposed action involves technical standards. Section 12(d) of 
the National Technology Transfer and Advancement Act of 1995 
(``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note) directs the 
EPA to use voluntary consensus standards in its regulatory activities, 
unless to do so would be inconsistent with applicable law or otherwise 
impractical. Voluntary consensus standards are technical standards 
(e.g., materials specifications, test methods, sampling procedures, and 
business practices) that are developed or adopted by voluntary 
consensus standards bodies. NTTAA directs the EPA to provide Congress, 
through OMB, explanations when the Agency decides not to us available 
and applicable voluntary consensus standards. This proposed rule would 
require the affected facility to meet the applicable monitoring 
requirements of 40 CFR part 75. Part 75 already incorporates a number 
of voluntary consensus standards. Consistent with the Agency's 
Performance Based Measurement (PBMS), part 75 sets forth performance 
criteria that allow the use of alternative methods to the ones set 
forth in part 75. The PBMS approach is intended to be more flexible and 
cost-effective for the regulated community; it is also intended to 
encourage innovation in analytical technology and improved data 
quality. At this time, the EPA is not recommending any revisions to 
part 75; however, the EPA periodically revises the test procedures set 
forth in part 75. When the EPA revises the test procedures set forth in 
part 75 in the future, the EPA will address the use of any new 
voluntary consensus standards that are equivalent. Currently, even if a 
test procedure is not set forth in part 75, the EPA is not precluding 
the use of any method, whether it constitutes a voluntary consensus 
standard or not, as long as it meets the performance criteria 
specified; however any alternative methods must be approved through the 
petition process under 40 CFR 75.66 before they are used.

[[Page 62706]]

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations and 
Executive Order 14096: Revitalizing Our Nation's Commitment to 
Environmental Justice for All

    The EPA believes that the human health and environmental 
conditions, around Gerald Gentelman Station, that exist prior to this 
action do not result in disproportionate and adverse effects on 
communities with Environmental Justice concerns.
    The EPA believes that this action is not likely to result in new 
disproportionate and adverse effects on communities with environmental 
justice concerns. This proposed FIP limits emissions of SO2 
from one facility in Nebraska.
    The information supporting this Executive Order review is contained 
in Section IX Environmental Justice Considerations of this action and 
the file GGS6mileEJScreen Community Report.pdf in the docket for this 
action.
    The EPA believes the human health or environmental risk addressed 
by this proposed action will not have potential disproportionately high 
and adverse human health or environmental effects on communities with 
environmental justice concerns because it increases the level of 
environmental protection for all affected populations without having 
any disproportionately high and adverse human health or environmental 
effects on any population, including any communities with environmental 
justice concerns.

List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Incorporation by 
reference, Intergovernmental relations, Interstate transport of 
pollution, Nitrogen dioxide, Ozone, Particulate matter, Regional haze, 
Reporting and recordkeeping requirements, Sulfur oxides, Visibility.

Michael S. Regan,
Administrator.

    For the reasons stated in the preamble, the EPA proposes to amend 
40 CFR part 52 as set forth below:

PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS

0
1. The authority citation for part 52 continues to read as follows:

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

Subpart CC--Nebraska

0
2. Amend Sec.  52.1437 by revising paragraph (b) and adding paragraph 
(c) to read as follows:


Sec.  52.1437  Visibility protection.

* * * * *
    (b) Measures addressing partial disapproval associated with 
SO2. The deficiencies associated with the SO2 
BART determination for NPPD, Gerald Gentleman Station, Units 1 and 2 
identified in EPA's partial disapproval of the regional haze plan 
submitted by Nebraska on July 13, 2011, are satisfied by Sec.  52.1429. 
The deficiencies associated with the SO2 LTS addressing 
SO2 emissions for NPPD, Gerald Gentleman Station, Units 1 
and 2 identified in EPA's partial disapproval of the regional haze plan 
submitted by Nebraska on July 13, 2011, are satisfied by paragraph (c) 
of this section.
    (c) Requirements for Gerald Gentleman Station Units 1 and 2 
affecting visibility.
    (1) Applicability. The provisions of this section shall apply to 
each owner, operator, or successive owners or operators of the coal 
burning equipment designated as Gerald Gentleman Station Units 1 and 2.
    (2) Compliance dates. Compliance with the requirements of this 
section is required by 5 years from the effective date of this rule for 
Gerald Gentleman Station Units 1 and 2.
    (3) Definitions. All terms used in this part but not defined herein 
shall have the meaning given to them in the Clean Air Act and in parts 
51 and 60 of this title. For the purposes of this section:
    24-hour period means the period of time between 12:01 a.m. and 12 
midnight.
    Air pollution control equipment includes baghouses, particulate or 
gaseous scrubbers, sorbent injection systems, and any other apparatus 
utilized to control emissions of regulated air contaminants which would 
be emitted to the atmosphere.
    Boiler-operating-day means any 24-hour period between 12:00 
midnight and the following midnight during which any fuel is combusted 
at any time in a steam generating unit.
    Daily average means the arithmetic average of the hourly values 
measured in a 24-hour period.
    Heat input means heat derived from combustion of fuel in a unit and 
does not include the heat input from preheated combustion air, 
recirculated flue gases, or exhaust gases from other sources. Heat 
input shall be calculated in accordance with 40 CFR part 75.
    Owner or Operator means any person who owns, leases, operates, 
controls, or supervises any of the coal burning equipment designated in 
paragraph (a) of this section.
    Regional Administrator means the Regional Administrator of Region 7 
or his/her authorized representative.
    Unit means each individual coal-fired boiler covered under 
paragraph (a) of this section.
    (4) Emissions limitations. SO2 emission limit. The 
owner/operator of the units listed below shall not emit or cause to be 
emitted pollutants in excess of the following limitations in pounds per 
million British thermal units (lb/MMBtu) as averaged over a rolling 30 
boiler-operating-day period from the subject unit. Compliance with the 
requirements of this section is required as listed below. The sulfur 
dioxide (SO2) emission limit for each individual unit shall 
be as listed in the following table.

------------------------------------------------------------------------
                               SO2 Emission limit
             Unit                  (lbs/MMBtu)        Compliance date
------------------------------------------------------------------------
Gerald Gentleman Station Unit                0.06  Five years from
 1.                                                 effective date of
                                                    the final rule.
Gerald Gentleman Station Unit                0.06  Five years from
 2.                                                 effective date of
                                                    the final rule.
------------------------------------------------------------------------

    (5) Testing and monitoring.
    (i) No later than the compliance date of this regulation, the owner 
or operator shall install, calibrate, maintain and operate Continuous 
Emissions Monitoring Systems (CEMS) for SO2, diluent 
(%CO2 or %O2) and flow, for each unit listed in 
section (1) in accordance with 40 CFR 60.8 and 60.13 (e), (f), and (h), 
and appendix B of part 60. The owner or operator shall comply with the 
quality assurance procedures for CEMS found in 40 CFR part 75. The 
SO2, diluent, and flow CEMS data, expressed in units of the 
standard, shall be used to verify compliance for each unit.

[[Page 62707]]

    (ii) Continuous emissions monitoring shall apply during all periods 
of operation of the coal burning equipment including periods of 
startup, shutdown, and malfunction, except for CEMS breakdowns, 
repairs, calibration checks, and zero and span adjustments. Continuous 
monitoring systems for measuring SO2 and diluent gas shall 
complete a minimum of one cycle of operation (sampling, analyzing, and 
data recording) for each successive 15-minute period. Hourly averages 
shall be computed using at least one data point in each 15-minute 
quadrant of an hour. Notwithstanding this requirement, an hourly 
average may be computed from at least two data points separated by a 
minimum of 15 minutes (where the unit operates for more than one 
quadrant in an hour) if data are unavailable as a result of performance 
of calibration, quality assurance, preventative maintenance activities, 
or backups of data from data acquisition and handling system, and 
recertification events. When valid pounds per million Btu emission data 
are not obtained because of continuous monitoring system breakdowns, 
repairs, calibration checks or zero and span adjustments, emission data 
must be obtained by using other monitoring systems approved by the EPA 
to provide emission data for a minimum of 18 hours in each 24-hour 
period and at least 22 out of 30 successive boiler operating days.
    (6) Recordkeeping and reporting requirements. Unless otherwise 
stated all requests, reports, submittals, notifications and other 
communications to the Regional Administrator required by this section 
shall be submitted unless instructed otherwise to the Director, Air and 
Radiation Division, U.S. Environmental Protection Agency, Region 7, 
11201 Renner Boulevard, Lenexa, Kansas 66219. For each unit subject to 
the emissions limitation in this section and upon completion of CEMS as 
required in this section, the owner or operator shall comply with the 
following requirements:
    (i) The following information shall be reported to the Regional 
Administrator, EPA Region 7, and the Nebraska Department of Energy and 
the Environmental, for each boiler operating day. The report shall be 
submitted no later than 30 days following the end of each semi-annual 
calendar period (e.g., June 30, December 31).
    (ii) For each SO2 emission limit in paragraph (c)(1) of 
this section, comply with the notification, reporting, and 
recordkeeping requirements for CEMS compliance monitoring in 40 CFR 
60.7 (c) and (d).
    (iii) For each day, provide the total SO2 emitted that 
day by each emission unit covered under (c)(1). For any hours on any 
unit where data for hourly pounds or heat input is missing, identify 
the unit number and monitoring device that did not produce valid data 
that caused the missing hour.
    (iv) For the unit covered under (c)(2) and (d)(2), records 
sufficient to demonstrate that the fuel for the unit is pipeline 
natural gas.
    (v) Records for demonstrating compliance with the SO2 
and PM emission limitations in this section shall be maintained for at 
least five years.
    (A) Calendar date.
    (B) The average SO2 emission rates, in lb/MMBtu, for 
each 30 successive boiler operating day period, ending with the last 
30-day period in the semi-annual reporting period; reasons for non-
compliance with the emission standards; and, description of corrective 
actions taken.
    (C) Identification of the boiler operating days for which pollutant 
or diluent data have not been obtained by an approved method for at 
least 75 percent of the hours of operation of the facility; 
justification for not obtaining sufficient data; and description of 
corrective actions taken.
    (D) Identification of the ``F'' factor used for calculations, 
method of determination, and type of fuel combusted.
    (E) Identification of times when hourly averages have been obtained 
based on manual sampling methods.
    (F) Identification of the times when the pollutant concentration 
exceeded full span of the CEMS.
    (G) Description of any modifications to CEMS which could affect the 
ability of the CEMS to comply with Performance Specifications 2 or 3 of 
40 CFR 60.51, subpart Da.
    (7) Equipment operations. At all times, including periods of 
startup, shutdown, and malfunction, the owner or operator shall, to the 
extent practicable, maintain and operate the unit including the 
associated air pollution control equipment in a manner consistent with 
good air pollution control practices for minimizing emissions. 
Determination of whether acceptable operating and maintenance 
procedures are being used will be based on information available to the 
Regional Administrator which may include, but is not limited to, 
monitoring results, review of operating and maintenance procedures, and 
inspection of the unit.
    (8) Enforcement.
    (i) Notwithstanding any other provision in this implementation 
plan, any credible evidence or information relevant as to whether the 
unit would have been in compliance with applicable requirements if the 
appropriate performance or compliance test had been performed, can be 
used to establish whether or not the owner or operator has violated or 
is in violation of any standard or applicable implementation plan.
    (ii) Emissions in excess of the level of the applicable emission 
limit or requirement that occur due to startup, shutdown or malfunction 
shall constitute a violation of the applicable emission limit.

[FR Doc. 2024-16697 Filed 7-31-24; 8:45 am]
BILLING CODE 6560-50-P