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1 Visual range is the greatest distance, in 

kilometers or miles, at which a dark object can be 

viewed against the sky. 

2 64 FR 35715 (July 1, 1999). 

3An interactive ‘‘story map’’ depicting efforts and 

recent progress by EPA and states to improve 

visibility at national parks and wilderness areas 

may be visited at: http://arcg.is/29tAbS3. 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 52 and 97 

[EPA–R06–OAR–2016–0611; FRL–9969–07– 

Region 6] 

Promulgation of Air Quality 

Implementation Plans; State of Texas; 

Regional Haze and Interstate Visibility 

Transport Federal Implementation Plan 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: Pursuant to the Federal Clean 

Air Act (CAA or Act), the 

Environmental Protection Agency (EPA) 

is finalizing a partial approval of the 

2009 Texas Regional Haze State 

Implementation Plan (SIP) submission 

and a Federal Implementation Plan (FIP) 

for Texas to address certain outstanding 

requirements. Specifically, the EPA is 

finalizing determinations regarding best 

available retrofit technology (BART) for 

electric generating units (EGUs) in the 

State of Texas. To address the BART 

requirement for sulfur dioxide (SO2), the 

EPA is finalizing an alternative to BART 

that consists of an intrastate trading 

program addressing the SO2 emissions 

from certain EGUs. To address the 

BART requirement for oxides of 

nitrogen (NOX), we are finalizing our 

proposed determination that Texas’ 

participation in the Cross-State Air 

Pollution Rule’s (CSAPR) trading 

program for ozone-season NOX qualifies 

as an alternative to BART. We are 

approving Texas’ determination that its 

EGUs are not subject to BART for 

particulate matter (PM). Finally, we are 

disapproving portions of several SIP 

revisions submitted to satisfy the CAA 

requirement to address interstate 

visibility transport for six national 

ambient air quality standards (NAAQS): 

1997 8-hour ozone, 1997 fine particulate 

matter (PM2.5) (annual and 24-hour), 

2006 PM2.5 (24-hour), 2008 8-hour 

ozone, 2010 1-hour nitrogen dioxide 

(NO2) and 2010 1-hour SO2. We are 

finding that the BART alternatives to 

address SO2 and NOX BART at Texas’ 

EGUs meet the interstate visibility 

transport requirements for these 

NAAQS. 

DATES: This final rule is effective on 

November 16, 2017. 

ADDRESSES: The EPA has established a 

docket for this action under Docket ID 

No. EPA–R06–OAR–2016–0611. All 

documents in the docket are listed on 

the http://www.regulations.gov Web 

site. Although listed in the index, some 

information is not publicly available, 

e.g., Confidential Business Information 

(CBI) or other information whose 

disclosure is restricted by statute 

therefore is not posted to 

regulations.gov. Certain other material, 

such as copyrighted material, is not 

placed on the Internet and will be 

publicly available only in hard copy. 

Publicly available docket materials are 

available either electronically through 

http://www.regulations.gov or in hard 

copy at EPA Region 6, 1445 Ross 

Avenue, Suite 700, Dallas, Texas 75202– 

2733. 

FOR FURTHER INFORMATION CONTACT: 

Michael Feldman at Feldman.Michael@

epa.gov or 214–665–9793 

SUPPLEMENTARY INFORMATION: 

Throughout this document wherever 

‘‘we,’’ ‘‘us,’’ or ‘‘our’’ is used, we mean 

the EPA. 

Table of Contents 

I. Background 

A. Regional Haze 

B. Interstate Transport of Pollutants That 

Affect Visibility 

C. Previous Actions Related to Texas 

Regional Haze 

II. Our Proposed Actions 

A. Regional Haze 

B. Interstate Transport of Pollutants That 

Affect Visibility 

III. Summary of Our Final Decisions 

A. Regional Haze 

1. BART-Eligible Units 

2. Subject-to-BART Sources 

3. SO2 BART 

4. PM BART 

5. NOX BART 

B. Interstate Transport of Pollutants That 

Affect Visibility 

C. Reasonable Progress 

IV. Summary and Analysis of Major Issues 

Raised by Commenters 

A. Comments on Relying on CSAPR for 

SO2 BART or Developing an Intrastate 

SO2 Trading Program 

B. Comments on Source-Specific BART 

C. Comments on EPA’s Proposed SIP 

Disapprovals 

D. Legal Comments 

E. Comments on Identification of BARTEligible Sources 

F. Comments on PM BART 

G. Comments on EPA’s Source-Specific 

SO2 BART Cost Analyses 

H. Comments on EPA’s Modeling 

I. Comments on Affordability and Grid 

Reliability 

V. SO2 Trading Program and Its Implications 

for Interstate Visibility Transport, EGU 

BART, and Reasonable Progress 

A. Background on CSAPR as an Alternative 

to BART Concept 

B. Texas SO2 Trading Program 

1. Identification of Sources Participating in 

the Trading Program 

2. Texas SO2 Trading Program as a BART 

Alternative 

C. Specific Texas SO2 Trading Program 

Features 

VI. Final Action 

VII. Statutory and Executive Order Reviews 

I. Background 

A. Regional Haze 

Regional haze is visibility impairment 

that is produced by a multitude of 

sources and activities that are located 

across a broad geographic area and emit 

PM2.5 (e.g., sulfates, nitrates, organic 

carbon (OC), elemental carbon (EC), and 

soil dust), and its precursors (e.g., SO2, 

NOX, and, in some cases, ammonia 

(NH3) and volatile organic compounds 

(VOCs)). Fine particle precursors react 

in the atmosphere to form PM2.5, which 

impairs visibility by scattering and 

absorbing light. Visibility impairment 

reduces the clarity, color, and visible 

distance that can be seen. PM2.5 can also 

cause serious health effects and 

mortality in humans and contributes to 

environmental effects, such as acid 

deposition and eutrophication. 

Data from the existing visibility 

monitoring network, the ‘‘Interagency 

Monitoring of Protected Visual 

Environments’’ (IMPROVE) monitoring 

network, show that visibility 

impairment caused by air pollution 

occurs virtually all the time at most 

national parks and wilderness areas. In 

1999, the average visual range 1 in many 

Class I areas (i.e., national parks and 

memorial parks, wilderness areas, and 

international parks meeting certain size 

criteria) in the western United States 

was 100–150 kilometers, or about onehalf to two-thirds of the visual range 

that would exist without anthropogenic 

air pollution. In most of the eastern 

Class I areas of the United States, the 

average visual range was less than 30 

kilometers, or about one-fifth of the 

visual range that would exist under 

estimated natural conditions.2 CAA 

programs have reduced some hazecausing pollution, lessening some 

visibility impairment and resulting in 

partially improved average visual 

ranges.3

CAA requirements to address the 

problem of visibility impairment are 

continuing to be addressed and 

implemented. 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 


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4Areas designated as mandatory Class I Federal 

areas consist of National Parks exceeding 6,000 

acres, wilderness areas and national memorial parks 

exceeding 5,000 acres, and all international parks 

that were in existence on August 7, 1977. 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.’’ 

5 45 FR 80084 (Dec. 2, 1980). 

6 64 FR 35714 (July 1, 1999), codified at 40 CFR 

part 51, subpart P (Regional Haze Rule). 

7See 40 CFR 51.308(b). EPA’s regional haze 

regulations require subsequent updates to the 

regional haze SIPs. 40 CFR 51.308(g)–(i). 

8See 42 U.S.C. 7491(g)(7) (listing the set of 

‘‘major stationary sources’’ potentially subject-toBART). 

9CAIR required certain states, including Texas, to 

reduce emissions of SO2 and NOX that significantly 

contribute to downwind nonattainment of the 1997 

NAAQS for fine particulate matter and ozone. See 

70 FR 25152 (May 12, 2005). 

10See 70 FR 39104 (July 6, 2005). 

11See North Carolina v. EPA, 531 F.3d 896 (D.C. 

Cir. 2008), modified, 550 F.3d 1176 (D.C. Cir. 2008). 

12 76 FR 48207 (Aug. 8, 2011). 

13CSAPR was amended three times in 2011 and 

2012 to add five states to the seasonal NOX program 

and to increase certain state budgets. 76 FR 80760 

(December 27, 2011); 77 FR 10324 (February 21, 

2012); 77 FR 34830 (June 12, 2012). 

existing man-made impairment of 

visibility in 156 national parks and 

wilderness areas designated as 

mandatory Class I Federal areas.4 On 

December 2, 1980, EPA promulgated 

regulations to address visibility 

impairment in Class I areas that is 

‘‘reasonably attributable’’ to a single 

source or small group of sources, i.e., 

‘‘reasonably attributable visibility 

impairment.’’ 5 These regulations 

represented the first phase in addressing 

visibility impairment. EPA deferred 

action on regional haze that emanates 

from a variety of sources until 

monitoring, modeling, and scientific 

knowledge about the relationships 

between pollutants and visibility 

impairment were improved. 

Congress added section 169B to the 

CAA in 1990 to address regional haze 

issues, and we promulgated regulations 

addressing regional haze in 1999.6 The 

Regional Haze Rule revised the existing 

visibility regulations to integrate into 

the regulations provisions addressing 

regional haze impairment and 

established a comprehensive visibility 

protection program for Class I areas. The 

requirements for regional haze, found at 

40 CFR 51.308 and 51.309, are included 

in our visibility protection regulations at 

40 CFR 51.300–51.309. The requirement 

to submit a regional haze SIP applies to 

all 50 states, the District of Columbia, 

and the Virgin Islands. States were 

required to submit the first 

implementation plan addressing 

regional haze visibility impairment no 

later than December 17, 2007.7

Section 169A of the CAA directs 

states to evaluate the use of retrofit 

controls at certain larger, often undercontrolled, older stationary sources in 

order to address visibility impacts from 

these sources. Specifically, section 

169A(b)(2)(A) of the CAA requires states 

to revise their SIPs to contain such 

measures as may be necessary to make 

reasonable progress toward the natural 

visibility goal, including a requirement 

that certain categories of existing major 

stationary sources 8 built between 1962 

and 1977 procure, install and operate 

the ‘‘Best Available Retrofit 

Technology’’ (BART). Larger ‘‘fossil-fuel 

fired steam electric plants’’ are included 

among the BART source categories. 

Under the Regional Haze Rule, states are 

directed to conduct BART 

determinations for ‘‘BART-eligible’’ 

sources that may be anticipated to cause 

or contribute to any visibility 

impairment in a Class I area. The 

evaluation of BART for EGUs that are 

located at fossil-fuel-fired power plants 

having a generating capacity in excess of 

750 megawatts must follow the 

‘‘Guidelines for BART Determinations 

Under the Regional Haze Rule’’ at 

appendix Y to 40 CFR part 51 

(hereinafter referred to as the ‘‘BART 

Guidelines’’). Rather than requiring 

source-specific BART controls, states 

also have the flexibility to adopt an 

emissions trading program or alternative 

program as long as the alternative 

provides greater reasonable progress 

towards improving visibility than 

BART. 40 CFR 51.308(e)(2) specifies 

how a state must conduct the 

demonstration to show that an 

alternative program will achieve greater 

reasonable progress than the installation 

and operation of BART. 40 CFR 

51.308(e)(2)(i)(E) requires a 

determination under 40 CFR 51.308 

(e)(3) or otherwise based on the clear 

weight of evidence that the trading 

program or other alternative measure 

achieves greater reasonable progress 

than would be achieved through the 

installation and operation of BART at 

the covered sources. Specific criteria for 

determining if an alternative measure 

achieves greater reasonable progress 

than source-specific BART are set out in 

40 CFR 51.308(e)(3). Finally, 40 CFR 

51.308(e)(4) states that states 

participating in CSAPR need not require 

BART-eligible fossil fuel-fired steam 

electric plants to install, operate, and 

maintain BART for the pollutant 

covered by CSAPR. 

Under section 110(c) of the CAA, 

whenever we disapprove a mandatory 

SIP submission in whole or in part, we 

are required to promulgate a FIP within 

two years unless the state corrects the 

deficiency and we approve the new SIP 

submittal. 

B. Interstate Transport of Pollutants 

That Affect Visibility 

Section 110(a) of the CAA directs 

states to submit a SIP that provides for 

the implementation, maintenance, and 

enforcement of each NAAQS, which is 

commonly referred to as an 

infrastructure SIP. Among other things, 

CAA section 110(a)(2)(D)(i)(II) requires 

that SIPs contain adequate provisions to 

prohibit interference with measures 

required to protect visibility in other 

states. This is referred to as ‘‘interstate 

visibility transport.’’ SIPs addressing 

interstate visibility transport are due to 

the EPA within three years after the 

promulgation of a new or revised 

NAAQS (or within such shorter period 

as we may prescribe). A state’s failure to 

submit a complete, approvable SIP for 

interstate visibility transport creates an 

obligation for the EPA to promulgate a 

FIP to address this requirement. 

C. Previous Actions Related to Texas 

Regional Haze 

On March 31, 2009, Texas submitted 

a regional haze SIP to the EPA that 

included reliance on Texas’ 

participation in the Clean Air Interstate 

Rule (CAIR) as an alternative to BART 

for SO2 and NOX emissions from EGUs.9

This reliance was consistent with the 

EPA’s regulations at the time that Texas 

developed its regional haze plan,10 but 

at the time that Texas submitted this SIP 

to the EPA, the D.C. Circuit had 

remanded CAIR (without vacatur).11

The court left CAIR and our CAIR FIPs 

in place in order to ‘‘temporarily 

preserve the environmental values 

covered by CAIR’’ until we could, by 

rulemaking, replace CAIR consistent 

with the court’s opinion. The EPA 

promulgated CSAPR, a revised multistate trading program to replace CAIR, 

in 2011 12 (and revised it in 2012 13). 

CSAPR established FIP requirements for 

a number of states, including Texas, to 

address the states’ interstate transport 

obligation under CAA section 

110(a)(2)(D)(i)(I). CSAPR requires 

affected EGUs in these states to 


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14 77 FR 33641 (June 7, 2012). 

15 Id. 

16 79 FR 74818 (Dec. 16, 2014). 

17EME Homer City Generation, L.P. v. EPA, 795 

F.3d 118, 132 (D.C. Cir. 2015). 

18 81 FR 296 (Jan. 5, 2016). 

19Texas v. EPA, 829 F.3d 405 (5th Cir. 2016). 

20 81 FR 74504 (Oct. 26, 2016). 

21 81 FR 74504, 74524–25. 

22 81 FR 78954. 

23Texas continues to participate in CSAPR for 

ozone season NOX. See final action signed 

September 21, 2017 available at regulations.gov in 

Docket No. EPA–HQ–OAR–2016–0598. 

24 82 FR 912, 914–15 (Jan. 4, 2017). 

25 81 FR 74504 (Nov. 10, 2016). 

26 81 FR 78954. 

27 79 FR 74817, 74853–54 (Dec. 16, 2014). 

participate in the CSAPR trading 

programs and establishes emissions 

budgets that apply to the EGUs’ 

collective annual emissions of SO2 and 

NOX, as well as seasonal emissions of 

NOX. Following issuance of CSAPR, the 

EPA determined that CSAPR would 

achieve greater reasonable progress 

towards improving visibility than would 

source-specific BART in CSAPR 

states.14 We revised the Regional Haze 

Rule to allow states that participate in 

CSAPR to rely on participation in the 

trading programs in lieu of requiring 

EGUs in the state to install BART 

controls. 

In the same action that EPA 

determined that states could rely on 

CSAPR to address the BART 

requirements for EGUs, EPA issued a 

limited disapproval of a number of 

states’ regional haze SIPs, including the 

2009 SIP submittal from Texas, due to 

the states’ reliance on CAIR, which had 

been replaced by CSAPR.15 The EPA did 

not immediately promulgate a FIP to 

address the limited disapproval of 

Texas’ regional haze SIP in order to 

allow more time for the EPA to assess 

the remaining elements of the 2009 

Texas SIP submittal. In December 2014, 

we proposed an action to address the 

remaining regional haze obligations for 

Texas.16 In that action, we proposed, 

among other things, to rely on CSAPR 

to satisfy the NOX and SO2 BART 

requirements for Texas’ EGUs; we also 

proposed to approve the portions of the 

SIP addressing PM BART requirements 

for the state’s EGUs. Before that rule was 

finalized, however, the D.C. Circuit 

issued a decision on a number of 

challenges to CSAPR, denying most 

claims, but remanding the CSAPR 

emissions budgets of several states to 

the EPA for reconsideration, including 

the Phase 2 SO2 and seasonal NOX

budget for Texas.17 Due to potential 

impacts of the remanded budgets on the 

EPA’s 2012 determination that CSAPR 

would provide for greater reasonable 

progress than BART, we did not finalize 

our decision to rely on CSAPR to satisfy 

the SO2 and NOX BART requirements 

for Texas EGUs.18 Additionally, because 

our proposed action on the PM BART 

provisions for EGUs was dependent on 

how SO2 and NOX BART were satisfied, 

we did not take final action on the PM 

BART elements of Texas’ regional haze 

SIP. In January 2016, we finalized action 

on the remaining aspects of the 

December 2014 proposal. That 

rulemaking was challenged, however, 

and in December 2016, following the 

submittal of a request by the EPA for a 

voluntary remand of the parts of the rule 

under challenge, the Fifth Circuit Court 

of Appeals remanded the rule in its 

entirety.19

On October 26, 2016, the EPA 

finalized an update to CSAPR to address 

the interstate transport requirements of 

CAA section 110(a)(2)(D)(i)(I) with 

respect to the 2008 ozone NAAQS 

(CSAPR Update).20 The EPA also 

responded to the D.C. Circuit’s remand 

of certain CSAPR seasonal NOX budgets 

in that action. As to Texas, the EPA 

withdrew Texas’s seasonal NOX budget 

finalized in CSAPR to address the 1997 

ozone NAAQS. However, in that same 

action, the EPA promulgated a FIP with 

a revised seasonal NOX budget for Texas 

to address the 2008 ozone NAAQS.21

Accordingly, Texas remains subject to 

the CSAPR seasonal NOX requirements. 

On November 10, 2016, in response to 

the D.C. Circuit’s remand of Texas’s 

CSAPR SO2 budget, we proposed to 

withdraw the FIP provisions requiring 

EGUs in Texas to participate in the 

CSAPR trading programs for annual 

emissions of SO2 and NOX.22 We also 

proposed to reaffirm that CSAPR 

continues to provide for greater 

reasonable progress than BART 

following our actions taken to address 

the D.C. Circuit’s remand of several 

CSAPR emissions budgets. On 

September 21, 2017, we finalized the 

withdrawal of the FIP provisions for 

annual emissions of SO2 and NOX for 

EGUs in Texas 23 and affirmed our 

proposed finding that the EPA’s 2012 

analytical demonstration remains valid 

and that participation in CSAPR as it 

now exists meets the Regional Haze 

Rule’s criteria for an alternative to 

BART. 

II. Our Proposed Actions 

A. Regional Haze 

On January 4, 2017, we proposed a 

FIP to address the BART requirements 

for Texas’ EGUs. In that action, we 

proposed to replace Texas’ reliance on 

CAIR with reliance on CSAPR to 

address the NOX BART requirements for 

EGUs.24 This portion of our proposal 

was based on the CSAPR Update and 

our separate November 10, 2016 

proposed finding that the EPA’s actions 

in response to the D.C. Circuit’s remand 

would not adversely impact our 2012 

demonstration that participation in 

CSAPR meets the Regional Haze Rule’s 

criteria for alternatives to BART.25 We 

noted that we could not finalize this 

portion of our proposed FIP unless and 

until we finalized our proposed finding 

that the set of actions taken by the EPA 

in response to the D.C. Circuit’s remand 

of certain CSAPR budgets would not 

adversely impact our prior 

determination that CSAPR provides for 

greater reasonable progress than BART. 

As noted in section I.C, on September 

21, 2017, we finalized our proposed 

finding that EPA’s 2012 analytical 

demonstration remains valid and that 

participation in CSAPR as it now exists 

meets the Regional Haze Rule’s criteria 

for an alternative to BART. 

Also as noted in section I.C, as part of 

our November 10, 2016 proposed action 

in response to the D.C. Circuit’s remand 

of Texas’ SO2 CSAPR budget, we also 

proposed to withdraw the FIP 

provisions requiring EGUs in Texas to 

participate in the CSAPR trading 

programs for annual emissions of SO2

and NOX.26 In our January 4, 2017 

proposed action on BART requirements 

for Texas EGUs, we accordingly 

proposed that because Texas would no 

longer be participating in the CSAPR 

program for SO2, and thus would no 

longer be eligible to rely on 

participation in CSAPR as an alternative 

to source-specific EGU BART for SO2

under 40 CFR 51.308(e)(4), our regional 

haze FIP would need to include the 

identification of BART-eligible EGU 

sources, screening of sources to identify 

subject-to-BART sources, and source-bysource determinations of SO2 BART 

controls as appropriate. For those EGU 

sources we proposed to find subject to 

BART, we proposed to promulgate 

source-specific SO2 requirements. We 

also proposed to disapprove Texas’ 

BART determinations for PM from 

EGUs. In place of these determinations, 

we proposed to promulgate sourcespecific PM BART requirements for 

EGUs that we proposed to find subject 

to BART. Previously, we proposed to 

approve the EGU BART determinations 

for PM in the Texas regional haze SIP 

and this proposal has never been 

withdrawn.27 At that time, CSAPR was 

an appropriate alternative for SO2 and 

NOX BART for EGUs. The Texas 

Regional Haze SIP included a pollutantspecific screening analysis for PM to 


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28See discussion in Memorandum from Joseph 

Paisie to Kay Prince, ‘‘Regional Haze Regulations 

and Guidelines for Best Available Retrofit 

Technology (BART) Determinations,’’ July 19, 2006. 

29 81 FR 296 (Jan. 5, 2016). 

30Specifically, we previously disapproved the 

relevant portion of these Texas’ SIP submittals: 

April 4, 2008: 1997 8-hour Ozone, 1997 PM2.5 (24- 

hour and annual); May 1, 2008: 1997 8-hour Ozone, 

1997 PM2.5 (24-hour and annual); November 23, 

2009: 2006 24-hour PM2.5; December 7, 2012: 2010 

NO2; December 13, 2012: 2008 8-hour Ozone; May 

6, 2013: 2010 1-hour SO2 (Primary NAAQS). 79 FR 

74818, 74821; 81 FR 296, 302. 

31Texas v. EPA, 829 F.3d 405 (5th Cir. 2016). 

32EME Homer City Generation, L.P. v. EPA, 795 

F.3d 118, 133–34 (D.C. Cir. 2015) (holding that SIPs 

based on CAIR were unapprovable to fulfill good 

neighbor obligations). 

33 77 FR 33641, 33654 (June 7, 2012). 

34 79 FR 74817, 74823 (December 16, 2014) (‘‘We 

propose to replace Texas’ reliance on CAIR to 

satisfy the BART requirement for EGUs with 

reliance on CSAPR.’’). This part of the 2014 

proposal was not finalized in the action taken on 

January 5, 2016, that has since been remanded by 

the Fifth Circuit Court of Appeals. 81 FR 295. 

35Final action taken on January 5, 2016, that has 

since been remanded by the Fifth Circuit Court of 

Appeals. 81 FR 295. 

36 77 FR 33641 (June 7, 2012). 

37See Memorandum of Agreement Between the 

Texas Commission on Environmental Quality and 

the Environmental Protection Agency Regarding a 

State Implementation Plan to Address Certain 

Regional Haze and Interstate Visibility Transport 

Requirements Pursuant to Sections 110 and 169A 

of the Clean Air Act, Signed August 14, 2017. 

demonstrate that Texas EGUs were not 

subject to BART for PM. In a 2006 

guidance document,28 the EPA stated 

that pollutant-specific screening can be 

appropriate where a state is relying on 

a BART alternative to address both NOX

and SO2 BART. 

B. Interstate Transport of Pollutants 

That Affect Visibility 

In our January 5, 2016 final action 29

we disapproved the portion of Texas’ 

SIP revisions intended to address 

interstate visibility transport for six 

NAAQS, including the 1997 8-hour 

ozone and 1997 PM2.5.30 That 

rulemaking was challenged, however, 

and in December 2016, following the 

submittal of a request by the EPA for a 

voluntary remand of the parts of the rule 

under challenge, the Fifth Circuit Court 

of Appeals remanded the rule in its 

entirety without vacatur.31 In our 

January 4, 2017 proposed action we 

proposed to reconsider the basis of our 

prior disapproval of Texas’ SIP revisions 

addressing interstate visibility transport 

under CAA section 110(a)(2)(D)(i)(II) for 

six NAAQS. We proposed that Texas’ 

SIP submittals addressing interstate 

visibility transport for the six NAAQS 

were not approvable because they relied 

solely on Texas’ 2009 Regional Haze SIP 

to ensure that emissions from Texas did 

not interfere with required measures in 

other states. Texas’ Regional Haze SIP, 

in turn, relied on the implementation of 

CAIR as an alternative to EGU BART for 

SO2 and NOX.32 We proposed a FIP to 

fully address Texas’ interstate visibility 

transport obligations for: (1) 1997 8-hour 

ozone, (2) 1997 PM2.5 (annual and 24- 

hour), (3) 2006 PM2.5 (24-hour), (4) 2008 

8-hour ozone, (5) 2010 1-hour NO2 and 

(6) 2010 1-hour SO2. The proposed FIP 

was based on our finding that our 

proposed action to fully address the 

BART requirements for Texas EGUs was 

adequate to ensure that emissions from 

Texas do not interfere with measures to 

protect visibility in nearby states in 

accordance with CAA section 

110(a)(2)(D)(i)(II). 

III. Summary of Our Final Decisions 

A. Regional Haze 

When we finalized a limited 

disapproval of Texas’ 2009 regional 

haze SIP for its reliance on CAIR 

participation as a BART alternative, we 

did not immediately finalize a CSAPRbetter-than-BART FIP for Texas, as we 

had proposed for Texas and ultimately 

finalized for twelve other states. Instead 

of finalizing a CSAPR-better-than-BART 

FIP for Texas, the EPA acknowledged 

that we needed more time to assess the 

Texas regional haze SIP in regard to 

aspects other than its reliance on CAIR 

as an alternative to BART.33 As the EPA 

has continued to assess how best to 

address the regional haze obligations for 

Texas, Texas has not submitted a SIP 

revision to address the prior 

disapproval, so the EPA has a remaining 

obligation to address BART 

requirements for Texas EGUs. 

After assessing how we should 

address BART for Texas EGUs, we 

believe that our initial 2011 proposal, to 

treat Texas like other similarly situated 

CSAPR states, was an appropriate and 

regionally consistent approach. As 

discussed above, in 2014, we proposed 

that CSAPR would satisfy the NOX and 

SO2 BART requirements for Texas 

EGUs.34 However, we did not finalize 

this part of the 2014 proposal in the 

action taken on January 5, 2016.35 Given 

EPA’s response to the D.C. Circuit 

remand of certain CSAPR emission 

budgets, we can no longer rely on 

CSAPR for Texas’ SO2 BART 

requirements. Based on comments we 

received in response to our January 

2017 proposal, and giving particular 

weight to the views expressed by Texas, 

we are finalizing various determinations 

to ensure satisfaction of the BART 

requirement for EGUs in Texas. Of 

particular note, in making our final 

decision for the SO2 BART requirement 

for EGUs, we centered our focus on a 

timely comment letter received from the 

Texas Commission on Environmental 

Quality (TCEQ) and the Public Utility 

Commission of Texas (PUC). This 

comment urged us to consider as a 

BART alternative the concept of 

emission caps using CSAPR allocations. 

We also received similar comments 

from Luminant and American Electric 

Power (AEP). Based upon the 

comments, we are proceeding to address 

the SO2 BART requirement for EGUs 

under a BART alternative. The EPA 

finds that, because this BART 

alternative will result in SO2 emissions 

from Texas EGUs that will be similar to 

emissions anticipated under CSAPR, the 

alternative is an appropriate approach 

for addressing Texas’ SO2 BART 

obligations. 

Specifically, the BART alternative is 

justified ‘‘based on the clear weight of 

the evidence’’ that the alternative 

achieves greater reasonable progress 

than would be achieved through BART. 

See 40 CFR 51.308(e)(2)(i)(E). The 

program is designed to accomplish 

environmental and visibility results by 

achieving emission levels that will be 

the same as or better than the emission 

levels that would have been obtained by 

state participation in the interstate 

CSAPR program as finalized and 

amended in 2011 and 2012, which EPA 

first deemed to be better than BART for 

NOX and SO2 in a 2012 regulatory 

action.36 The TCEQ and EPA recently 

signed a memorandum of agreement 

(MOA) to work together to develop a SIP 

revision addressing interstate visibility 

transport requirements and BART 

requirements for EGUs with a BART 

alternative trading program starting 

from CSAPR as allowed under the 

Regional Haze Rule (40 CFR 

51.308(e)).37 Texas envisions that the 

FIP measures that serve to satisfy this 

BART requirement will be replaced by 

a future SIP submission following the 

approach described in the MOA that 

may be approved as meeting the 

requirements of the CAA and the 

Regional Haze Rule. EPA policy 

consistently favors that states will 

exercise their SIP authority to avoid 

need for promulgation and continued 

implementation of measures under FIP 

authority. In the absence of a SIP to 

address the SO2 BART requirement for 

Texas EGUs, however, EPA finds it 

necessary to address the requirement 

under its FIP authority, and the details 

of how this is addressed and the 

accompanying justification are further 

discussed below under Section III.A.3, 

‘‘SO2 BART.’’ 


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38 In this action, we did not consider VOCs and 

ammonia among visibility-impairing pollutants for 

several reasons, as discussed in the TSD. 

39 40 CFR 51.301. 

40 Dynegy purchased the Coleto Creek power 

plant from Engie in February, 2017. Note that 

Coleto Creek may still be listed as being owned by 

Engie in some of our supporting documentation 

which was prepared before that sale. 

The Regional Haze Rule requires that 

SIP or FIP measures be in place to 

ensure that BART is satisfied for all 

subject-to-BART EGUs and all hazecausing pollutants. For ease of 

summarization, we will detail the 

relevant final decisions for each of the 

haze-causing pollutants: PM, NOX, and 

SO2.38 In our final decisions today, the 

relevant BART requirement for all 

BART-eligible coal-fired units and a 

number of BART-eligible gas- or gas/fuel 

oil-fired units will be encompassed by 

BART alternatives for NOX and SO2

such that we do not deem it necessary 

to finalize subject-to-BART findings for 

these EGUs for these pollutants. The 

remaining BART-eligible EGUs not 

covered by the SO2 BART alternative 

have been determined to be not subject 

to BART based on the methodologies 

utilizing model plants and CALPUFF 

modeling as described in our proposed 

rule and BART Screening technical 

support document (TSD). Therefore, we 

are approving the portion of the Texas 

Regional Haze SIP that addresses the 

BART requirement for EGUs for PM, we 

are relying upon Texas EGUs’ continued 

participation in the CSAPR program to 

serve as a BART alternative for NOX, 

and we are promulgating an intrastate 

trading FIP to address the SO2 BART 

requirements for EGUs. 

1. BART-Eligible Units 

BART-eligible sources are those 

sources which have the potential to emit 

250 tons per year or more of a visibilityimpairing air pollutant, which were ‘‘in 

existence’’ on August 7, 1977 but not 

‘‘in operation’’ before August 7, 1962, 

and whose operations fall within one or 

more of 26 specifically listed source 

categories.39 As discussed in detail in 

our proposal and the BART FIP TSD, 

our analysis of BART-eligible EGUs 

started with the list of BART-eligible 

sources provided by TCEQ in the 2009 

Texas Regional Haze SIP. Based on 

additional information from potential 

BART-eligible sources and the U.S. 

Energy Information Administration 

(EIA), we converted Texas’ facilityspecific BART-eligible EGU list to a 

unit-specific BART-eligible EGU list, 

eliminated those units that have retired, 

and verified the BART-eligibility of each 

remaining unit. We noted in our 

proposal that Texas’ list omitted some 

sources that we had identified as BARTeligible. We are finalizing the 

identification of BART-eligible units as 

proposed. A ‘‘BART-eligible source’’ is 

the collection of BART-eligible units at 

a facility. Table 1 shows the list of EGUs 

in Texas that are BART-eligible: 

TABLE 1—SUMMARY OF BARTELIGIBLE UNITS

Facility Unit 

Barney M. Davis (Talen/Topaz) ...... 1. 

Big Brown (Luminant) ..................... 1. 

Big Brown (Luminant) ..................... 2. 

Cedar Bayou (NRG) ....................... CBY1. 

Cedar Bayou (NRG) ....................... CBY2. 

Coleto Creek (Dynegy 40) ................ 1. 

Dansby (City of Bryan) ................... 1. 

Decker Creek (Austin Energy) ........ 1. 

Decker Creek (Austin Energy) ........ 2. 

Fayette (LCRA) ............................... 1. 

Fayette (LCRA) ............................... 2. 

Graham (Luminant) ......................... 2. 

Greens Bayou (NRG) ..................... 5. 

Handley (Exelon) ............................ 3. 

Handley (Exelon) ............................ 4. 

Handley (Exelon) ............................ 5. 

Harrington Station (Xcel) ................ 061B. 

Harrington Station (Xcel) ................ 062B. 

J T Deely (CPS Energy) ................. 1. 

J T Deely (CPS Energy) ................. 2. 

Jones Station (Xcel) ........................ 151B. 

Jones Station (Xcel) ........................ 152B. 

Knox Lee Power Plant (AEP) ......... 5. 

Lake Hubbard (Luminant) ............... 1. 

Lake Hubbard (Luminant) ............... 2. 

Lewis Creek (Entergy) .................... 1. 

Lewis Creek (Entergy) .................... 2. 

Martin Lake (Luminant) ................... 1. 

Martin Lake (Luminant) ................... 2. 

Martin Lake (Luminant) ................... 3. 

Monticello (Luminant) ...................... 1. 

Monticello (Luminant) ...................... 2. 

Monticello (Luminant) ...................... 3. 

Newman (El Paso Electric) ............. 2. 

Newman (El Paso Electric) ............. 3. 

Newman (El Paso Electric) ............. 4. 

Nichols Station (Xcel) ..................... 143B. 

O W Sommers (CPS Energy) ......... 1. 

O W Sommers (CPS Energy) ......... 2. 

Plant X (Xcel) .................................. 4. 

Powerlane (City of Greenville) ........ ST1. 

Powerlane (City of Greenville) ........ ST2. 

Powerlane (City of Greenville) ........ ST3. 

R W Miller (Brazos Elec. Coop) ..... 1. 

R W Miller (Brazos Elec. Coop) ..... 2. 

R W Miller (Brazos Elec. Coop) ..... 3. 

Sabine (Entergy) ............................. 2. 

Sabine (Entergy) ............................. 3. 

Sabine (Entergy) ............................. 4. 

Sabine (Entergy) ............................. 5. 

Sim Gideon (LCRA) ........................ 1. 

Sim Gideon (LCRA) ........................ 2. 

Sim Gideon (LCRA) ........................ 3. 

Spencer (City of Garland) ............... 4. 

Spencer (City of Garland) ............... 5. 

Stryker Creek (Luminant) ................ ST2. 

Trinidad (Luminant) ......................... 6. 

Ty Cooke (City of Lubbock) ............ 1. 

Ty Cooke (City of Lubbock) ............ 2. 

V H Braunig (CPS Energy) ............. 1. 

V H Braunig (CPS Energy) ............. 2. 

TABLE 1—SUMMARY OF BARTELIGIBLE UNITS—Continued 

Facility Unit 

V H Braunig (CPS Energy) ............. 3. 

WA Parish (NRG) ........................... WAP4. 

WA Parish (NRG) ........................... WAP5. 

WA Parish (NRG) ........................... WAP6. 

Welsh Power Plant (AEP) ............... 1. 

Welsh Power Plant (AEP) ............... 2. 

Wilkes Power Plant (AEP) .............. 1. 

Wilkes Power Plant (AEP) .............. 2. 

Wilkes Power Plant (AEP) .............. 3. 

2. Subject-to-BART Sources 

As discussed elsewhere, it is 

unnecessary to finalize the subject-toBART determinations for BART-eligible 

sources that are covered by the BART 

alternatives for SO2 and NOX. The 

BART alternatives cover both BARTeligible and non-BART eligible sources. 

This combination provides for greater 

reasonable progress than source-specific 

BART. Even if a unit were individually 

found to not be subject to BART, its 

participation in the BART alternative 

contributes to the finding that the 

program provides greater reasonable 

progress than BART. We note that all 

BART-eligible EGUs in Texas are either 

covered by the BART alternative or have 

screened out of being subject to BART. 

The section below that discusses our 

final SO2 BART determination lists 

those units covered by the BART 

alternative program and identifies 

which of those units are BART-eligible. 

As discussed in section III.A.4 below, 

we are approving the portion of the 

2009 Texas Regional Haze SIP that 

determined that no PM BART 

determinations are needed for BARTeligible EGUs in Texas. 

For those BART-eligible EGUs that are 

not covered by the BART alternative for 

SO2, we are finalizing determinations 

that those EGUs are not subject-to-BART 

for NOX, SO2 and PM as proposed, 

based on the methodologies utilizing 

model plants and CALPUFF modeling 

as described in our proposed rule and 

BART Screening TSD. 

The following sources are determined 

to be BART-eligible, but not subject-toBART: 

TABLE 2—SOURCES DETERMINED TO

BE BART-ELIGIBLE BUT NOT SUBJECT-TO-BART FOR NOX, SO2, AND

PM 

Facility Units 

Barney M. Davis (Talen/ 

Topaz).

1. 

Cedar Bayou (NRG) .......... CBY1 & CBY2. 

Dansby (City of Bryan) ...... 1. 


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TABLE 2—SOURCES DETERMINED TO

BE BART-ELIGIBLE BUT NOT SUBJECT-TO-BART FOR NOX, SO2, AND

PM—Continued 

Facility Units 

Decker Creek (Austin Energy).1 & 2. 

Greens Bayou (NRG) ........ 5. 

Handley (Exelon) ............... 3, 4 & 5. 

Jones (Xcel) ....................... 151B & 152B. 

Knox Lee (AEP) ................. 5. 

Lake Hubbard (Luminant) .. 1 & 2. 

Lewis Creek (Entergy) ....... 1 & 2. 

Nichols Station (Xcel) ........ 143B. 

Plant X (Xcel) .................... 4. 

Powerlane (City of Greenville).ST1, ST2 & 

ST3. 

R W Miller (Brazos Elec. 

Coop).

1, 2 & 3. 

Sabine (Entergy) ................ 2, 3, 4 & 5. 

Sim Gideon (LCRA) ........... 1, 2 & 3. 

Spencer (City of Garland) 4 & 5. 

Trinidad (Luminant) ........... 6. 

Ty Cooke (City of Lubbock) 1 & 2. 

TABLE 2—SOURCES DETERMINED TO

BE BART-ELIGIBLE BUT NOT SUBJECT-TO-BART FOR NOX, SO2, AND

PM—Continued 

Facility Units 

V H Braunig (CPS Energy) 1, 2 & 3. 

3. SO2 BART 

The BART alternative will achieve 

SO2 emission levels that are 

functionally equivalent to those 

projected for Texas’ participation in the 

original CSAPR program. The BART 

alternative applies the CSAPR 

allowance allocations for SO2 to all 

BART-eligible coal-fired EGUs, several 

additional coal-fired EGUs, and several 

BART-eligible gas-fired and gas/fuel oilfired EGUs. In addition to being a 

sufficient alternative to BART, it secures 

reductions consistent with visibility 

transport requirements and is part of the 

long-term strategy to meet the 

reasonable progress requirements of the 

Regional Haze Rule. 

The combination of the source 

coverage for this program, the total 

allocations for EGUs covered by the 

program, and recent and foreseeable 

emissions from EGUs not covered by the 

program will result in future EGU 

emissions in Texas that are similar to 

the SO2 emission levels forecast in the 

2012 better-than-BART demonstration 

for Texas EGU emissions assuming 

CSAPR participation. In line with the 

comment from the TCEQ/PUC, we are 

finalizing a BART alternative that will 

encompass the SO2 BART requirements 

for coal-fired EGUs and a number of gasand gas/fuel oil-fired EGUs under a 

program that will include the sources in 

the following table. See Section V.B for 

a discussion on identification of 

participating sources. 

TABLE 3—TEXAS EGUS SUBJECT TO THE FIP SO2 TRADING PROGRAM

Owner/operator Units BART-eligible 

AEP ........................................................... Welsh Power Plant Unit 1 ......................................................................................... Yes. 

Welsh Power Plant Unit 2 ......................................................................................... Yes. 

Welsh Power Plant Unit 3 ......................................................................................... No. 

H W Pirkey Power Plant Unit 1 ................................................................................. No. 

Wilkes Unit 1 * ........................................................................................................... Yes. 

Wilkes Unit 2 * ........................................................................................................... Yes. 

Wilkes Unit 3 * ........................................................................................................... Yes. 

CPS Energy .............................................. JT Deely Unit 1 .......................................................................................................... Yes. 

JT Deely Unit 2 .......................................................................................................... Yes. 

Sommers Unit 1 * ....................................................................................................... Yes. 

Sommers Unit 2 * ....................................................................................................... Yes. 

Dynegy ...................................................... Coleto Creek Unit 1 ................................................................................................... Yes. 

LCRA ........................................................ Fayette/Sam Seymour Unit 1 .................................................................................... Yes. 

Fayette/Sam Seymour Unit 2 .................................................................................... Yes. 

Luminant ................................................... Big Brown Unit 1 ....................................................................................................... Yes. 

Big Brown Unit 2 ....................................................................................................... Yes. 

Martin Lake Unit 1 ..................................................................................................... Yes. 

Martin Lake Unit 2 ..................................................................................................... Yes. 

Martin Lake Unit 3 ..................................................................................................... Yes. 

Monticello Unit 1 ........................................................................................................ Yes. 

Monticello Unit 2 ........................................................................................................ Yes. 

Monticello Unit 3 ........................................................................................................ Yes. 

Sandow Unit 4 ........................................................................................................... No. 

Stryker ST2 * .............................................................................................................. Yes. 

Graham Unit 2 * ......................................................................................................... Yes. 

NRG .......................................................... Limestone Unit 1 ....................................................................................................... No. 

Limestone Unit 2 ....................................................................................................... No. 

WA Parish Unit WAP4 * ............................................................................................. Yes. 

WA Parish Unit WAP5 ............................................................................................... Yes. 

WA Parish Unit WAP6 ............................................................................................... Yes. 

WA Parish Unit WAP7 ............................................................................................... No. 

Xcel ........................................................... Tolk Station Unit 171B .............................................................................................. No. 

Tolk Station Unit 172B .............................................................................................. No. 

Harrington Unit 061B ................................................................................................. Yes. 

Harrington Unit 062B ................................................................................................. Yes. 

Harrington Unit 063B ................................................................................................. No. 

El Paso Electric ........................................ Newman Unit 2 * ........................................................................................................ Yes. 

Newman Unit 3 * ........................................................................................................ Yes. 

Newman Unit 4 * ........................................................................................................ Yes. 

* Gas-fired or gas/fuel oil-fired units. 


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41 In 2016, 218,291 tons of SO2 were emitted from 

sources included in the program and 27,446 tons 

from other EGUs (11.1%). 

42See CAIR 2018 emission projections of 

approximately 350,000 tons SO2 emitted from Texas 

EGUs compared to CAIR budget for Texas of 

225,000 tons. See section 10 of the 2009 Texas 

Regional Haze SIP. 

43See Memorandum of Agreement Between the 

Texas Commission on Environmental Quality and 

the Environmental Protection Agency Regarding a 

State Implementation Plan to Address Certain 

Regional Haze and Interstate Visibility Transport 

Requirements Pursuant to Sections 110 and 169A 

of the Clean Air Act, signed August 14, 2017. 

44 79 FR 74817, 74823 (December 16, 2014) (‘‘We 

propose to replace Texas’ reliance on CAIR to 

satisfy the BART requirement for EGUs with 

reliance on CSAPR.’’). This part of the 2014 

proposal was not finalized in the action taken on 

January 5, 2016, that has since been remanded by 

the Fifth Circuit Court of Appeals. 81 FR 295. 

45See final action signed September 21, 2017 

available at regulations.gov in Docket No. EPA–HQ– 

OAR–2016–0598. 46 82 FR 3078 (Jan. 10, 2017). 

This BART alternative includes all 

BART-eligible coal-fired units in Texas, 

additional coal-fired EGUs, and some 

additional BART-eligible gas and gas/ 

fuel oil-fired units. Moreover, we 

believe that the differences in source 

coverage between CSAPR and this 

BART alternative are either not 

significant or, in fact, work to 

demonstrate the relative stringency of 

the BART alternative as compared to 

CSAPR (See Section V of this preamble 

for detailed information). This relative 

stringency can be understood in 

reference to the following points: 

A. Covered sources under the BART 

alternative in this FIP represent 89%41

of all SO2 emissions from all Texas 

EGUs in 2016, and approximately 85% 

of CSAPR allocations for existing units 

in Texas. 

B. The remaining 11% (100 minus 89) 

of 2016 emissions from sources not 

covered by the BART alternative come 

from gas units that rarely burn fuel oil 

or coal-fired units that on average are 

better controlled for SO2 than the 

covered sources and generally are less 

relevant to visibility impairment. (A 

fuller discussion of this point is 

provided in Section V of this preamble.) 

As such, any shifting of generation to 

non-covered sources, as might occur if 

a covered source reduces its operation 

in order to remain within its SO2

emissions allowance allocation, would 

result in less emissions to generate the 

same amount of electricity. 

C. Furthermore, the non-inclusion of 

a large number of gas-fired units that 

rarely burn fuel oil reduces the amount 

of available allowances for units that 

would typically and collectively be 

expected to use only a fraction of 

CSAPR emissions allowances. Many of 

these sources typically emit at levels 

much lower than their allocation level. 

Sources not participating in the program 

may choose to opt in, thereby increasing 

the number of available allowances. 

This will serve to make the program 

more closely resemble CSAPR. 

D. The BART alternative does not 

allow purchasing of allowances from 

out-of-state sources. Emission 

projections under CAIR and CSAPR 

showed that Texas sources were 

anticipated to purchase allowances from 

out-of-state sources.42

Based on these points, and borrowing 

to the greatest extent possible from the 

rules and program design of CSAPR, but 

applying them for Texas only, we are 

proceeding with the commenters’, 

including the State of Texas’, suggested 

consideration for SO2 BART coverage 

for EGUs by means of a BART 

alternative under an intrastate trading 

program. As with any FIP, we also 

would welcome Texas submitting a 

future SIP, as discussed in the MOA, 

that meets the Regional Haze Rule and 

the Act’s requirements so as to enable 

future withdrawal of this FIP-based 

BART alternative.43

In 2014 we had originally proposed 

that CSAPR would satisfy the SO2 BART 

requirement for Texas EGUs.44

Although we never finalized that 

proposal, functionally, the final 

decision relies on substantially the same 

technical elements. In contrast to the 

2014 proposal, however, we are not 

finalizing this SO2 BART alternative as 

meeting the terms of 40 CFR 

51.308(e)(4), as amended, because that 

regulatory provision, by its terms, 

provides BART coverage for pollutants 

covered by the CSAPR trading program 

in the State but on September 21, 2017, 

EPA finalized its proposed action to 

remove Texas from the CSAPR SO2

trading program.45 Instead we are 

relying on the BART alternative option 

provided under 40 CFR 51.308(e)(2). 

The BART alternative being finalized 

today is supported by our determination 

that the clear weight of the evidence is 

that the trading program achieves 

greater reasonable progress than BART. 

The BART alternative is designed to 

achieve SO2 emission levels from Texas 

sources similar to the SO2 emission 

levels that would have been achieved 

under CSAPR. By a quantitative and 

qualitative assessment of the operation 

of the BART alternative, we are able to 

conclude that emission levels will be on 

average no greater than the emission 

levels from Texas EGUs that would have 

been realized from the SO2 trading 

program under CSAPR. (See Section V 

of this preamble for detailed 

information). Accordingly, by the 

measure of CSAPR better than BART, 

the SO2 BART FIP for Texas’ BARTeligible EGUs participating in the 

trading program will achieve greater 

reasonable progress than BART with 

respect to SO2. BART-eligible EGUs not 

participating in the program are 

demonstrated to not cause or contribute 

to visibility impairment, and we are 

finalizing our determination in this 

action that these units are not subject to 

BART. 

The Regional Haze Rule at 40 CFR 

51.308(e)(2)(iii) requires that the 

emission reductions from BART 

alternatives occur ‘‘during the period of 

the first long-term strategy for regional 

haze.’’ The SO2 BART alternative that 

EPA is finalizing here will be 

implemented beginning in January 

2019, and thus emission reductions 

needed to meet the allowance 

allocations must take place by the end 

of 2019. For the purpose of evaluating 

Texas’s BART alternative, the end of the 

first planning period of the first longterm strategy for Texas is 2021. This is 

a result of recent changes to the regional 

haze regulation, revising the 

requirement for states to submit 

revisions to their long-term strategy 

from 2018 to 2021.46 Therefore, the 

emission reductions from the Texas SO2

trading program will be realized prior to 

that date and within the period of 

Texas’ first long-term strategy for 

regional haze. 

In promulgating the regulatory terms 

and rules for implementing the BART 

alternative, we are mindful of the 

minimally required elements for a 

BART alternative emissions trading 

program that are specified in the 

provisions of 40 CFR 

51.308(e)(2)(vi)(A)–(L). In general, these 

types of provisions are foundational, in 

a generic sense, to the establishment of 

allowance markets. CSAPR is a 

prominent example of such an 

allowance market, and by transferring 

and generally incorporating program 

rules and terms from the well-tested 

provisions of CSAPR we have ensured 

that the BART alternative will conform 

in detail and coverage to the breadth of 

provisions that are needed for an 

emissions trading program covered by a 

cap (See Section V of this preamble for 

additional discussion). To the extent 

that Texas would submit a future SIP 

revision under its SIP authority to 

implement SO2 BART or an SO2 BART 

alternative for its EGUs as described in 

the MOA to meet the Regional Haze 

Rule and CAA requirements, it may look 

to the provisions promulgated under FIP 

authority or it may examine its 

flexibilities and the extent of its 


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47See discussion in Memorandum from Joseph 

Paisie to Kay Prince, ‘‘Regional Haze Regulations 

and Guidelines for Best Available Retrofit 

Technology (BART) Determinations,’’ July 19, 2006. 

48Stryker Creek is covered by CSAPR for NOX

and by the SO2 trading program but was not 

included in the 2009 Regional Haze SIP. How 

Stryker Creek is screened out for PM is discussed 

below. 

49EPA’s Proposal screened out Dansby, Greens 

Bayou, Handley, Lake Hubbard, Plant X, Powerlane, 

R W Miller, and Spencer using CALPUFF direct 

modeling and Model Plants. 50Environ Report—‘‘Final Report Screening 

Analysis of Potential BART-Eligible Sources in 

Texas’’, September 27, 2006; ‘‘Addendum 1—BART 

Exemption Screening Analysis’’, Draft December 6, 

2006; and ‘‘BARTmodelingparameters V2.csv’’. 51This is calculated by using the maximum daily 

PM10 daily emission rate, adding the maximum 

daily PM2.5 emission rate and then calculating the 

total emissions in tons per year if this max daily 

rate happened every day. 

52See ‘Coleto_Creek_Screen_analysis.xlsx.’ 

53See 79 FR 74817, 74848 (Dec. 16, 2014). 

54 81 FR 74504 (Oct. 16, 2016). 

55See final action signed September 21, 2017 

available at regulations.gov in Docket No. EPA–HQ– 

OAR–2016–0598. 

discretion regarding essential provisions 

detailed at 40 CFR 51.308(e)(2)(vi). 

4. PM BART 

In our January 2017 proposal, we 

proposed to disapprove Texas’ technical 

evaluation and determination that PM 

BART emission limits are not required 

for any of Texas’ EGUs. The Texas 

Regional Haze SIP included a pollutantspecific screening analysis for PM to 

demonstrate that Texas EGUs were not 

subject to BART for PM. This approach 

was consistent with a 2006 guidance 

document 47 in which the EPA stated 

that pollutant-specific screening can be 

appropriate where a state is relying on 

a BART alternative to address both NOX

and SO2 BART. Because we proposed to 

address SO2 BART on a source-specific 

basis, however, Texas’ pollutant-specific 

screening was not appropriate and we 

proposed source-specific PM BART 

emission limits consistent with existing 

practices and controls. In this final 

action, we are not finalizing sourcespecific SO2 BART determinations. 

Instead, for the majority of Texas’ 

BART-eligible EGUs, we are relying on 

BART alternatives for both SO2 and 

NOX emissions. Therefore, we now 

conclude that Texas’ pollutant-specific 

screening analysis was appropriate. All 

of the BART-eligible sources 

participating in the intrastate trading 

program have visibility impacts from 

PM alone below the subject-to-BART 

threshold of 0.5 deciviews (dv).48

Furthermore, the BART-eligible sources 

not participating in the intrastate 

trading program screened out of BART 

for all visibility impairing pollutants. As 

such, we are approving the portion of 

the Texas Regional Haze SIP that 

determined that PM BART emission 

limits are not required for any Texas 

EGUs. 

As we explained in the January 2017 

proposal, the Texas Regional Haze SIP 

did not evaluate PM impacts from all 

BART-eligible EGUs. We have evaluated 

and determined this omission does not 

affect Texas’ conclusion that no BARTeligible EGUs should be subject-toBART for PM emissions. In our 

proposal, we identified several facilities 

as BART-eligible that Texas did not 

identify as BART eligible in the Texas 

Regional Haze SIP. Specifically, we 

identified the following additional 

BART-eligible sources: Coleto Creek 

Unit 1 (Dynegy), Dansby Unit 1 (City of 

Bryan), Greens Bayou Unit 5 (NRG), 

Handley Units 3,4, and 5 (Excelon), 

Lake Hubbard Units 1 and 2 (Luminant), 

Plant X Unit 4 (Xcel), Powerlane Units 

ST1, ST2, and ST3 (City of Greenville), 

R W Miller Units 1, 2, and 3 (Brazos 

Elec.), Spencer Units 4 and 5 (City of 

Garland), and Stryker Creek Unit ST2 

(Luminant). In our proposal, we used 

CALPUFF modeling and a model-plant 

analysis and found that all of these 

facilities except Coleto Creek and 

Stryker Creek had impacts from NOX, 

SO2 and PM below the BART screening 

level.49 CALPUFF modeling showed 

that Stryker Creek Unit ST2 had a 

visibility impact of 0.786 dv from NOX, 

SO2 and PM. However, Stryker Creek 

Unit ST2 is now covered by a BART 

alternative for NOX and SO2, so we 

evaluated the visibility impact of 

Stryker Creek Unit ST2’s PM emissions 

alone. The CALPUFF modeling files and 

spreadsheets included in our proposal 

indicate that light extinction from PM 

(PMFine and PMCoarse) is less than 1% of 

total light extinction at all Class I areas. 

Therefore, because the visibility impact 

of PM emissions from Stryker Creek 

Unit ST2 would be a small fraction of 

0.786 dv (roughly 1%), the source is not 

subject to BART for PM under EPA’s 

2006 guidance. 

We also evaluated the potential 

visibility impact of PM emissions from 

Coleto Creek Unit 1 using the CAMx 

modeling that Texas used for PM BART 

screening of its EGU sources in its SIP.50

Specifically, we evaluated the modeling 

results for two facilities (LCRA Fayette 

and Sommers Deely) with stack 

parameters similar to Coleto Creek’s, but 

which are located closer to Class I Areas 

than Coleto Creek. Texas grouped the 

LCRA Fayette Facility in Group 2 of 

their PM screening modeling along with 

other sources and found that their 

maximum aggregate impacts at all Class 

I areas were less than 0.25 deciviews 

(dv). Texas also explicitly modeled the 

City Public Service Sommers Deely 

Facility’s PM impacts. Maximum 

impacts at all Class I areas from 

Sommers Deely were less than 0.32 dv. 

To extend these model results to Coleto 

Creek, we used the Q/D ratio where Q 

is the maximum annual PM emissions 51

and D is the distance to the nearest 

receptor of a Class I area. If the Q/D ratio 

of Coleto Creek is smaller than the ratios 

for the two modeling results (Fayette 

and Sommers Deely) then Coleto Creek 

impacts can be estimated as less than 

the impacts of these source(s) and thus 

be screened out. We evaluated the 

closest Class I Areas (Big Bend, 

Guadalupe Mountains, Carlsbad, 

Wichita Mountains, and Caney Creek) 

and the Q/D ratios were: Coleto Creek 

(0.59–0.86), Fayette (4.25–6.1), and 

Sommers Deely (6.0–10.05).52 The Q/D 

ratio for Fayette is 6 to 8 times larger 

than for Coleto Creek, while the Q/D 

ratio for Sommers Deely is 9 to 11.6 

times higher than for Coleto Creek. 

Therefore, if we were to model the PM 

impacts from Coleto Creek, they would 

be an order of magnitude smaller than 

the impacts from these facilities, which 

are well below the threshold of 0.5 dv. 

Therefore, Coleto Creek is not subject to 

BART for PM emissions. 

In finalizing an approval of Texas’ 

determinations regarding PM BART, we 

offer one additional note. We originally 

proposed to approve Texas’ screening 

approach in 2014,53 and our final action 

today essentially conforms to our 

technical evaluation in that proposal. 

5. NOX BART 

We are finalizing our proposed 

determination that Texas EGUs’ 

continued participation in the CSAPR 

program for interstate transport for 

ozone will serve as a BART alternative 

for NOX for EGUs in the State of Texas. 

Our action to address NOX BART for 

EGUs as it applies to Texas is based on 

two other recent rulemakings 

concerning CSAPR. The first is the 

rulemaking to update CSAPR to address 

interstate transport of ozone pollution 

with respect to the 2008 ozone NAAQS, 

which established a new ozone season 

budget for NOX emissions in Texas.54

The second is the determination that 

CSAPR continues to be a better than 

BART alternative, on a pollutant 

specific basis, for states that participate 

in the CSAPR program as it now 

exists.55 Because our FIP relies on 

CSAPR as a BART alternative for NOX

for Texas EGUs, we are not required in 

this action to promulgate source-specific 


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56As explained in our proposal, our ongoing 

authority and obligation to address the NOX BART 

requirement for Texas EGUs under CAA section 

110(c) traces to EPA’s limited disapproval of the 

2009 Texas Regional Haze SIP in 2012 due to the 

State’s reliance on the remanded and replaced CAIR 

as an alternative to NOX BART. See also EME 

Homer City Generation, L.P. v. EPA, 795 F.3d 118, 

133–34 (D.C. Cir. 2015) holding that SIPs based on 

CAIR were unapprovable to fulfill good neighbor 

obligations. 

57 82 FR 912, 916 (Jan. 4, 2017). 

58See ‘‘Guidance on Infrastructure State 

Implementation Plan (SIP) Elements under Clean 

Air Act Sections 110(a)(1) and (2)’’ included in the 

docket for this action. 

59See Id., at 33. 60See Id., at 34, and 76 FR 22036 (April 20, 2011) 

containing EPA’s approval of the visibility 

requirement of 110(a)(2)(D)(i)(II) based on a 

demonstration by Colorado that did not rely on the 

Colorado Regional Haze SIP. 

NOX BART determinations for those 

sources. 

We note that Texas may opt to use its 

SIP planning authority, as was noted in 

its 2009 Regional Haze SIP in a similar 

context, to address the NOX BART 

requirement for EGUs without relying 

on CSAPR. If Texas instead wishes to 

rely upon the CSAPR program to 

address the NOX BART requirement, it 

may submit a SIP revision to establish 

its reliance on the program to satisfy the 

requirement for NOX BART for EGUs. 

By using the SIP pathway, Texas would 

be exercising the primary responsibility 

for air pollution control that is 

embodied in the Act. See CAA section 

101(a)(3). Recognizing that the 2009 

Regional Haze SIP did not, by its terms, 

provide an approvable means to address 

the requirement, however, we are now 

required to exercise our FIP authority to 

address it.56 We are therefore finalizing 

the determination as proposed. 

B. Interstate Transport of Pollutants 

That Affect Visibility 

We are finalizing our proposal to 

disapprove Texas’ SIP revisions 

addressing interstate visibility transport 

under CAA section 110(a)(2)(D)(i)(II) for 

six NAAQS. As explained further in our 

proposal, Texas’ infrastructure SIPs for 

these six NAAQS relied on the 2009 

Regional Haze SIP, including its 

reliance on CAIR as an alternative to 

EGU BART for SO2 and NOX to meet the 

interstate visibility transport 

requirements.57 We are finalizing a FIP 

to fully address Texas’ interstate 

visibility transport obligations for the 

following six NAAQS: (1) 1997 8-hour 

ozone, (2) 1997 PM2.5 (annual and 24 

hour), (3) 2006 PM2.5 (24-hour), (4) 2008 

8-hour ozone, (5) 2010 1-hour NO2 and 

(6) 2010 1-hour SO2. 

An EPA guidance document (2013 

Guidance) on infrastructure SIP 

elements states that CAA section 

110(a)(2)(D)(i)(II)’s interstate visibility 

transport requirements can be satisfied 

by approved SIP provisions that the 

EPA has found to adequately address a 

state’s contribution to visibility 

impairment in other states.58 The EPA 

interprets interstate visibility transport 

to be pollutant-specific, such that the 

infrastructure SIP submission need only 

address the potential for interference 

with protection of visibility caused by 

the pollutant (including precursors) to 

which the new or revised NAAQS 

applies.59 The 2013 Guidance lays out 

two ways in which a state’s 

infrastructure SIP submittal may satisfy 

interstate visibility transport. One way 

is through a state’s confirmation in its 

infrastructure SIP submittal that it has 

an EPA approved regional haze SIP in 

place. In the absence of a fully approved 

regional haze SIP, a demonstration that 

emissions within a state’s jurisdiction 

do not interfere with other states’ plans 

to protect visibility meets this 

requirement. Such a demonstration 

should point to measures that limit 

visibility-impairing pollutants and 

ensure that the resulting reductions 

conform with any mutually agreed 

emission reductions under the relevant 

regional haze regional planning 

organization (RPO) process.60

To develop its 2009 Regional Haze 

SIP, TCEQ worked through its RPO, the 

Central Regional Air Planning 

Association (CENRAP), to develop 

strategies to address regional haze, 

which at that time were based on 

emissions reductions from CAIR. To 

help states in establishing reasonable 

progress goals for improving visibility in 

Class I areas, the CENRAP modeled 

future visibility conditions based on the 

mutually agreed emissions reductions 

from each state. The CENRAP states 

then relied on this modeling in setting 

their respective reasonable progress 

goals. 

This FIP is adequate to ensure that 

emissions from Texas do not interfere 

with measures to protect visibility in 

nearby states because the BART FIP 

emission reductions are consistent with 

the level of emissions reductions relied 

upon by other states during 

consultation. The 2009 Texas Regional 

Haze SIP relied on CAIR to meet SO2

and NOX BART requirements. Under 

CAIR, Texas EGU sources were 

projected to emit approximately 350,000 

tpy of SO2. As discussed elsewhere, 

Texas EGU emissions for sources 

covered by the trading program will be 

constrained by the number of available 

allowances. Average annual emissions 

for the covered sources will be less than 

or equal to 248,393 tons with some year 

to year variability constrained by the 

number of banked allowances and 

number of allowances that can be 

allocated in a control period from the 

supplemental pool. Sources not covered 

by the program emitted less than 27,500 

tons of SO2 in 2016 and are not 

projected to significantly increase from 

this level. Any new units would be 

required to be well controlled and 

similar to the existing units not covered 

by the program, they would not 

significantly increase total emissions of 

SO2. Additionally, this FIP relies on 

CSAPR as an alternative to EGU BART 

for NOX, which exceeds the emissions 

reductions relied upon by other states 

during consultation. As such, this BART 

FIP is sufficient to address the interstate 

visibility transport requirement under 

CAA section 110(a)(2)(D)(i)(II) for the 

six NAAQS. 

C. Reasonable Progress 

This final action is part of the longterm strategy for Texas and will 

contribute to making reasonable 

progress toward natural visibility 

conditions at Texas’ and downwind 

Class I areas. However, the EPA is not 

determining at this time that this final 

action fully resolves the EPA’s 

outstanding obligations with respect to 

reasonable progress that resulted from 

the Fifth Circuit’s remand of our 

reasonable progress FIP. We intend to 

take future action to address the Fifth 

Circuit’s remand. 

IV. Summary and Analysis of Major 

Issues Raised by Commenters 

We received both written and oral 

comments at the public hearings we 

held in Austin. We also received 

comments by the internet and the mail. 

The full text of comments received from 

these commenters, except what was 

claimed as CBI, is included in the 

publicly posted docket associated with 

this action at www.regulations.gov. The 

CBI cannot be posted to 

www.regulations.gov, but is part of the 

record of this action. We reviewed all 

public comments that we received on 

the proposed action. Below we provide 

a summary of certain comments and our 

responses. First, we provide a summary 

of all of the relevant technical 

comments we received and our 

responses to these comments. We do not 

consider some of the technical 

comments as relevant to the final action. 

For these comments we provide a brief 

summary of the comments and a 

discussion as to why they are not 

relevant. Second, we provide a 

summary below of the more significant 

legal comments with a summary of our 

responses. All of the legal comments we 

received that are relevant to our final 


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Federal Register / Vol. 82, No. 199 / Tuesday, October 17, 2017 / Rules and Regulations 48333 

61See final action signed September 21, 2017 

available at regulations.gov in Docket No. EPA–HQ– 

OAR–2016–0598. 

action are found in a separate 

document, titled the Legal Response To 

Comments (RTC) document. Therefore, 

if additional information is desired 

concerning how we addressed a 

particular legal comment, the reader 

should refer to the Legal RTC document. 

Third, we provide a summary of the 

more significant/relevant modeling 

related comments with a summary of 

our responses. The entirety of the 

modeling comments and our responses 

thereto are contained in a separate 

document titled the Modeling RTC 

document. 

A. Comments on Relying on CSAPR for 

SO2 BART or Developing an Intrastate 

SO2 Trading Program 

Comment: We received comments 

from TCEQ that our proposed SO2

controls for the coal-fired power plants 

represents more control than is 

necessary to satisfy BART. The EPA 

should consider an alternate control 

approach for these BART-affected units 

using source or system caps. Because 

the CSAPR level of control is better than 

BART, the EPA should have considered 

an equivalent control level in its BART 

analysis. For example, a potential 

alternative is the concept of systemwide emission caps using CSAPR 

allocations. A SO2 system-cap approach 

for BART would be based on 

establishing a cap on all the BART 

subject units under common ownership 

and control based on CSAPR allocations 

to those specific units. System-wide 

caps for these BART subject units based 

on CSAPR allocations would provide 

flexibility while actually being more 

stringent than CSAPR because the 

companies would not have the ability to 

trade allocations with non-BART 

facilities or with companies in other 

states. Furthermore, the EPA has 

approved system-cap approaches under 

the TCEQ’s Chapter 117 rules for NOX.

If such an approach using CSAPR 

allocations or some other similar 

variation can be demonstrated to be 

more stringent than CSAPR itself, then 

the EPA’s CSAPR-is-better-than-BART 

determination should satisfy some of 

the demonstration requirements for 

BART alternatives. Even if not based on 

CSAPR allocations, the EPA should 

consider a source-cap or system cap 

approach as an alternative to unit-byunit rate-based standards. Source and 

system cap strategies achieve equivalent 

reductions by setting mass-based limits 

(e.g., ton per day) for a group of units 

derived from rate-based standards and 

baseline levels of activity for the units. 

In this context, the rate-based standards 

used to set the caps would be the 

emission rates determined to represent 

BART. These types of cap approaches 

allow companies to consider a broader 

range of alternative strategies. Under a 

FIP with only unit-by-unit rate-based 

limits, as proposed by EPA, such an 

alternative strategy would not be 

allowed and EPA would have to revise 

its FIP to allow the company to pursue 

the alternative. A similar approach 

using system-caps would provide 

additional flexibility for companies. If 

the EPA is averse to creating a systemcap trading program for a single state, an 

alternative would be to allow for a state 

system-cap trading program that would 

allow companies to trade between 

systems once the EPA has approved the 

state program. 

We received a comment from 

American Electric Power (AEP) stating 

that in the proposed Texas BART FIP, 

EPA states that it encourages Texas to 

consider adopting SIP provisions that 

would allow EPA to fully approve the 

Regional Haze SIP with respect to 

Regional Haze and Interstate Visibility 

Transport. AEP also suggests that 

alternatively, Texas may also elect to 

satisfy its obligations by demonstrating 

an alternative. Although AEP views the 

most expeditious resolution for 

satisfying BART is finalization of 

CSAPR as a better-than-BART 

alternative, AEP would also welcome 

and support working with the State and 

EPA to develop a satisfactory BART 

compliance alternative. For example, 

AEP is open to consideration of a cap 

and trade program or other option for 

BART compliance. AEP is prepared to 

engage in such discussions as soon as 

possible. 

We also received a comment from 

Luminant stating that the EPA can and 

should address BART for Texas, not 

through EPA-mandated controls on 

individual units but through one of 

several available BART alternatives that 

will ensure equivalent or greater 

benefits at far less costs, as 

demonstrated by EPA’s own prior 

analyses of Texas EGUs’ emissions. 

Among those available alternatives is 

EPA’s original proposed BART plan for 

EGUs in Texas—reliance on Texas 

EGUs’ participation in the CSAPR 

annual SO2 and NOX trading programs 

as BART compliance. Since CSAPR 

became effective in 2015, SO2 emissions 

from Texas EGUs have declined 

substantially and are well below the 

levels that EPA previously determined 

are ‘‘better-than-BART.’’ EPA itself 

calculated ‘‘major visibility 

improvements at Class I areas in and 

around Texas’’ from the CSAPR-forBART alternative for Texas. The 

CSAPR-for-BART alternative remains 

the most expeditious and cost effective 

path for finalizing a BART solution for 

Texas EGUs. Indeed, EPA’s only lawful 

path forward to finalize a BART FIP for 

Texas by the current September 9, 2017 

deadline in EPA’s consent decree with 

Sierra Club is to finalize a CSAPR-forBART FIP for Texas EGUs, as EPA 

proposed to do in December 2014. That 

proposal was not withdrawn, remains a 

valid and defensible alternative, is 

supported by the record and prior EPA 

technical analyses, and has been fully 

vetted with substantial public review 

and comments. 

Response: Due to these comments 

requesting a BART alternative in lieu of 

source-specific EGU BART, we are 

finalizing an intrastate SO2 trading 

program as an alternative to source-bysource BART and to meet the interstate 

visibility transport requirements. This 

program will provide the commenters, 

and other owners of covered EGUs, with 

many of the benefits that they attributed 

to CSAPR. The premise in the comment 

that Texas EGUs are subject to CSAPR’s 

SO2 trading program is no longer true, 

given our recent action to remove Texas 

from that trading program.61 Hence, we 

cannot take the commenter’s 

recommended action of addressing SO2

BART through reliance on CSAPR. 

B. Comments on Source-Specific BART 

Comment: We received a number of 

comments in favor or against our 

proposals regarding BART-eligibility 

status, subject-to-BART status, and 

source-specific BART technologies and 

emission limits. Some were general and 

some were very specific. 

Response: Due to the comments we 

received requesting a BART alternative 

in lieu of source-specific BART 

determinations, we are finalizing an 

intrastate SO2 trading program as an 

alternative to source-by-source BART 

and to meet the interstate visibility 

transport requirements. As a 

consequence, we believe that it is not 

necessary to respond to comments 

concerning the merits of the proposed 

source-specific BART technologies and 

emission limits. Comments related to 

BART-eligibility status and subject-toBART status are addressed elsewhere in 

this preamble. 

C. Comments on EPA’s Proposed SIP 

Disapprovals 

Comment: The root of EPA’s flawed 

proposal is EPA’s departure from the 

cooperative federalism principles 

underlying the Clean Air Act. The State 

of Texas developed its regional haze SIP 


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48334 Federal Register / Vol. 82, No. 199 / Tuesday, October 17, 2017 / Rules and Regulations 

62See final action signed September 21, 2017 

available at regulations.gov in Docket No. EPA–HQ– 

OAR–2016–0598. 

63See Memorandum of Agreement Between the 

Texas Commission on Environmental Quality and 

the Environmental Protection Agency Regarding a 

State Implementation Plan to Address Certain 

Regional Haze and Interstate Visibility Transport 

Requirements Pursuant to Sections 110 and 169A 

of the Clean Air Act, Signed August 14, 2017. 

after years of work, technical analysis, 

and coordination with other States. For 

BART, Texas relied on the participation 

of Texas EGUs in CAIR and EPA’s 

determination that CAIR was betterthan-BART. EPA should have approved 

Texas’s SIP at the time because it 

complied with all statutory 

requirements and was supported by 

EPA’s own modeling. In no way does 

the Proposed Texas BART FIP—which 

starts over from scratch and creates an 

entirely new approach to BART for 

Texas EGUs—respect the State’s 

primary role under the statute. At a 

minimum, to more closely align with 

the State of Texas’s original choice to 

meet BART through a regional trading 

program, EPA should now finalize its 

prior proposal that CSAPR serve as a 

complete BART alternative for Texas 

EGUs. 

Response: Our action in 2012 to 

disapprove Texas’ 2009 SIP submission 

due to its reliance on CAIR is not the 

subject of this rulemaking and we do 

not address here the comment opposing 

that final action. We agree that CSAPR 

continues to be available on a pollutantspecific basis as a BART alternative for 

participating states for those pollutants 

subject to trading by CSAPR program 

participation; hence, we are finalizing a 

determination that CSAPR is better than 

BART for NOX at Texas EGUs. However, 

the premise in the comment that Texas 

EGUs are subject to CSAPR’s SO2

trading program is no longer true, given 

our recent action to remove them from 

that trading program.62 Hence, we 

cannot take the specific action 

recommended in this comment. Due to 

these comments requesting a BART 

alternative in lieu of source-specific 

EGU BART determinations, we are, 

however, finalizing a SO2 trading 

program as an alternative to source-bysource BART and as meeting the 

interstate visibility requirements. 

D. Legal Comments 

We received comments addressing 

EPA’s authority to promulgate a Federal 

Implementation Plan (FIP), the use of 

CSAPR as a better-than-BART 

alternative, cooperative federalism, 

deference to the State, the new 

Administration’s policies, Executive 

Orders, and litigation. These comments, 

and the response to comments, can be 

found in the document titled Legal RTC 

in the docket for this action. Below is a 

summary of some of the more 

significant comments we received. For a 

detailed review of all legal comments 

and responses, we refer the reader to 

this separate document. 

1. EPA’s Obligation and Authority To 

Promulgate a FIP 

Comment: Texas’ and industry’s 

challenge to CSAPR does not relieve 

EPA of its mandatory duty to issue a 

source-specific BART FIP for Texas. 

Although EPA would have permitted 

Texas to rely on CSAPR’s modest capand-trade program to avoid sourcespecific BART controls, Texas, 

Luminant, AEP, and Southwestern 

Public Service Company all chose to 

challenge CSAPR. They were ultimately 

successful in defeating EPA’s inclusion 

of Texas in the program for SO2 and 

ozone-season NOX. Ever since the D.C. 

Circuit remanded the Texas NOX and 

SO2 budgets to EPA in July 2015, Texas 

has been on notice that source-specific 

BART could well be necessary to meet 

its BART obligations. Yet Texas has not 

put forward either a new interstate 

transport SIP to replace CSAPR or a new 

BART SIP to address the Regional Haze 

Rule. 

Response: We agree that we have a 

mandatory duty to address the BART 

requirements for Texas EGUs but we do 

not agree that we must address these 

requirements through a FIP establishing 

source specific BART limits. We 

understand the comment to be 

referencing the court action, EME 

Homer City Generation v. EPA, 795 F.3d 

118 (D.C. Cir., July 28, 2015). At all 

times since the original submission of 

the 2009 Regional Haze SIP, Texas has 

been entitled to submit updated or new 

SIP revisions to address BART or 

interstate transport. A State is also 

entitled to submit a SIP that may be 

approved to replace a FIP after a FIP’s 

promulgation. When and whether Texas 

has been ‘‘on notice’’ regarding a 

potential need for source-specific BART 

is not material to the present need to 

address the EGU BART requirements 

through either a SIP or FIP. We do note 

that the 2009 Regional Haze SIP stated, 

‘‘The TCEQ will take appropriate action 

if CAIR is not replaced with a system 

that the US EPA considers to be 

equivalent to BART.’’ See 2009 SIP at 9– 

1. The 2009 SIP further acknowledged, 

‘‘Some EGUs may become subject to 

BART pending resolution of the CAIR at 

the federal level.’’ See 2009 SIP at 9–17. 

As circumstances now apply to Texas 

(and, as this comment suggests, may 

have been earlier projected), the State 

can take appropriate action to develop 

a SIP to address the EGU BART and 

interstate visibility transport 

requirements. The TCEQ and EPA 

recently signed a MOA to work together 

to develop a SIP revision addressing 

interstate visibility transport 

requirements and BART requirements 

for EGUs with a BART alternative 

trading program starting from CSAPR.63

However, without such a SIP, the Clean 

Air Act requires a promulgation of a FIP 

to address the outstanding BART and 

interstate transport requirements. 

Comment: Texas’s decision to not 

meet the BART requirements for its 

EGUs through voluntary participation in 

CSAPR does not relieve EPA of its 

mandatory duty to issue a sourcespecific BART FIP for Texas. Even if 

Texas were willing to voluntarily 

incorporate EPA’s invalidated CSAPR 

emission budgets into its SIP, the state 

cannot simply opt in and avoid sourcespecific BART. Because Texas cannot 

reverse course and adopt emissions 

budgets that it demonstrated were 

unnecessary, as a matter of law, and 

because the agency cannot achieve ‘‘all’’ 

of the CSAPR reductions by 2018 (the 

end of the first planning period), it 

cannot voluntarily adopt CSAPR. 

Response: We agree that we have a 

mandatory duty to address the BART 

requirement for Texas EGUs, but we do 

not agree that we must address it 

through a source-specific BART FIP. We 

understand this comment to refer to a 

hypothetical scenario based on the 

development and submission of a SIP by 

Texas providing for voluntary 

participation in CSAPR as a means of 

addressing the SO2 and/or NOX BART 

requirements for Texas EGUs. The 

possibility of such an option was 

detailed in a June 27, 2016 

memorandum entitled, ‘‘The U.S. 

Environmental Protection Agency’s Plan 

for Responding to the Remand of the 

Cross-State Air Pollution Rule Phase 2 

SO2 Budgets for Alabama, Georgia, 

South Carolina and Texas.’’ That 

memorandum was provided and 

available to Texas and other states. 

Several other states have pursued this 

option, but Texas has not, and it is not 

within the scope of our proposal. We are 

not opining on the operation of state law 

or otherwise responding to this 

comment. We address the issue of 

whether emission reductions from a 

BART alternative must be achieved by 

2018 in our response to another 

comment. 

Comment: EPA withdrawal of Texas 

from CSAPR does not relieve EPA of its 

mandatory duty to issue a sourcespecific BART FIP for Texas. After 


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64 82 FR 3078 (Jan. 10, 2017). 

having given Texas four months’ notice 

of its intent to fully withdraw the state 

from the CSAPR program, and made 

clear the implication that there would 

no longer be any doubt that Texas 

sources would need to comply with 

source-specific BART obligations, EPA 

formally issued its proposal to withdraw 

its federal plan to include Texas in the 

CSAPR emissions trading program one 

month before issuing the BART 

proposal. 81 FR 78954 (Nov. 10, 2016). 

EPA again made clear the situation: ‘‘[I]f 

and when this [CSAPR withdrawal] 

proposal is finalized, Texas will no 

longer be eligible to rely on CSAPR 

participation as an alternative to certain 

regional haze obligations including the 

determination and application of 

source-specific SO2 BART. Any such 

remaining obligations are not addressed 

in this proposed action and would be 

addressed through other state 

implementation plan (SIP) or FIP 

actions as appropriate.’’ Id. at 78,956. 

EPA has informed the U.S. District 

Court for the District of Columbia that 

it intends to finalize this proposal by 

October 31, 2017. 

After challenging the state’s inclusion 

in CSAPR for years, industry has done 

an about face in response to EPA’s 

Texas BART Proposal and now opposes 

EPA’s withdrawal of Texas from 

CSAPR. But EPA has gone on record 

that the agency does not currently have 

an analytical basis to support new 

CSAPR budgets for Texas. As EPA has 

noted, there was no such thing as a 

legally compliant CSAPR budget for 

Texas following the remand. Texas has 

had many years to submit a state SIP 

equivalent to CSAPR or other BART 

alternative to avoid source-specific 

BART, but Texas has taken no action to 

address its contribution to interstate 

pollution or regional haze. 

Response: We agree that we have a 

mandatory duty to address the BART 

requirement for Texas EGUs, but we do 

not agree that we must address it 

through a source-specific BART FIP. We 

also have a mandatory duty to address 

the interstate visibility transport 

requirements. 

Comment: We have strongly opposed 

the CSAPR-Better-than-BART rule since 

its inception. It is unlawful and 

unsupported by the scientific record. 

Legal challenges to EPA’s rule which 

purports to authorize reliance on 

CSAPR to satisfy BART are currently 

pending in the D.C. Circuit Court of 

Appeals. Until the D.C. Circuit rules on 

the validity of the CSAPR-Better-thanBART rule, neither EPA nor Texas 

should assume that CSAPR is an 

appropriate substitute for BART. 

Response: The legal and technical 

determinations of the CSAPR-Betterthan-BART rule are subject to judicial 

review under existing challenges and a 

separate administrative record, as 

indicated by the comment. Any 

challenges raised with regard to the 

present rulemaking and outside that 

litigation may be time-barred or directed 

to the wrong forum. As such, we do not 

believe that the incorporation of 

arguments from a brief filed with the 

D.C. Circuit concerning a separate 

regulatory determination warrants 

responses here, in this rulemaking, and 

that to offer responses here would 

suggest some basis for collateral, timebarred arguments that are out of the 

scope of this action. 

Comment: In addition to the legal 

uncertainty surrounding the national 

CSAPR-Better-than-BART rule, it is too 

late for Texas to rely on a BART 

alternative like CSAPR or any other 

program. Under EPA’s Regional Haze 

Rule, any BART alternative must 

include a ‘‘requirement that all 

necessary emission reductions take 

place during the period of the first longterm strategy for regional haze’’—i.e., no 

later than 2018. There are no plans in 

place, or even in development, for any 

federal or state program that would 

ensure the necessary reductions take 

place by the end of the first planning 

period in 2018. 

With the exception of a BART 

alternative approved for the Navajo 

Generating Station, which relied on the 

Tribal Authority Rule to provide 

additional flexibility, EPA has never 

proposed or approved a BART 

alternative that would allow the 

necessary emission reductions to be 

delayed past 2018. In Texas v. EPA, 829 

F.3d 405 (5th Cir. 2016), Texas and 

industry persuaded the Fifth Circuit of 

a likelihood that EPA could not require 

controls beyond the first planning 

period for reasonable progress. While 

neither the statute nor regulation 

precludes emission reductions relative 

to reasonable progress requirements to 

occur beyond the planning period 

deadline, the BART alternative 

requirements contain a provision 

directly on point. Accordingly, emission 

reductions under a BART alternative 

must be implemented by the end of the 

first planning period. 

Response: The Regional Haze Rule at 

40 CFR 51.308(e)(2)(iii) requires that the 

emission reductions from BART 

alternatives occur ‘‘during the period of 

the first long-term strategy for regional 

haze.’’ The SO2 BART alternative that 

EPA is finalizing here will be 

implemented beginning in January 

2019, and thus emission reductions 

needed to meet the allowance 

allocations must take place by the end 

of 2019. For the purpose of evaluating 

Texas’s BART alternative, the end of the 

first planning period of the first longterm strategy for Texas is 2021. This is 

a result of recent changes to the regional 

haze regulation, revising the 

requirement for states to submit 

revisions to their long-term strategy 

from 2018 to 2021.64 Therefore, the 

emission reductions from the Texas SO2

trading program will be realized prior to 

that date and within the period of 

Texas’ first long-term strategy for 

regional haze. Moreover, we expect that 

source owners in 2018 will already be 

taking steps, including appropriate 

source-level compliance planning (e.g., 

purchase contracts for coal), to be ready 

for the compliance year beginning on 

January 1, 2019. Adding to this, the 

State has already experienced 

reductions in SO2 emissions in response 

to market conditions and, to some 

extent, periods of compliance with 

CSAPR, including its allocations for 

SO2, when those measures were in effect 

or otherwise part of source owner 

planning considerations. 

We note that the BART alternative is 

projected to be implemented before any 

of the earlier-proposed compliance 

dates for source-specific SO2 BART for 

coal-fired units. 

The last year for which Texas EGUs 

must meet CSAPR requirements for SO2

is 2016. We considered and decided not 

to make the Texas SO2 trading program 

effective for 2017 because that would be 

unreasonably short notice to the affected 

EGUs in light of the late date in 2017 on 

which this action will become effective. 

We considered and decided not to make 

the program effective for 2018 because 

that also would be unreasonably short 

notice given that affected EGU owners 

should be allowed more than a few 

months to determine their strategy for 

compliance with the program in light of 

it having some features that are different 

from the CSAPR trading program they 

have been operating under until 

recently, for example the fact that they 

will no longer be able to purchase and 

use allowances from out-of-state EGUs. 

Comment: Adopting an emissions 

trading program for Texas that allows 

anywhere close to the tonnage of SO2

permitted by the emissions caps in 

CSAPR would also fail to meet the 

substantive requirements for a BART 

alternative. While the D.C. Circuit is 

considering whether CSAPR meets these 

substantive requirements in the CSAPRBetter-than-BART litigation, Texas’s 

situation is unique in that EPA has 


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65See 40 CFR 51.308(e)(2)(i)(C). 

actually completed a source-specific 

BART proposal that can be directly 

compared with the CSAPR program. 

Thus, even if the CSAPR-Better-thanBART rule is upheld as a national rule 

that EPA has the option of relying upon 

in certain states, and even if Texas were 

to join CSAPR or voluntarily adopt its 

budgets, it would be arbitrary for EPA 

to rely on CSAPR as a BART alternative 

without actually comparing the CSAPR 

or CSAPR-like program with its BART 

proposal. When comparing the two 

head-to-head, it is obvious as a practical 

matter that allowing Texas’s coal-fired 

power fleet to essentially continue 

emitting the same levels of SO2 as the 

status quo is not going to achieve 

equivalent visibility gains as the BART 

proposal would. As detailed in ‘‘EPA’s 

Fact Sheet for the Open House on EPA’s 

Clean Air Plan Proposal for Texas 

Regional Haze’’, the proposed BART 

limits are expected to reduce emissions 

of SO2 from 16 EGUs and would cut 

emissions from approximately 89 to 98 

percent—a reduction of over 194,000 

tons of SO2 every year. 

To satisfy the requirements for a 

BART ‘‘alternative,’’ an emissions 

trading program must make a technical 

demonstration that the trading program 

‘‘will achieve greater reasonable 

progress [towards natural visibility] 

than would have resulted from the 

installation and operation of BART at all 

sources subject to BART.’’ Id. 

§ 51.308(e)(2)(i). Under EPA’s 

regulations, if the distribution of 

emissions is different under an 

alternative program, a state ‘‘must 

conduct dispersion modeling’’ to 

determine differences in visibility 

between BART and the trading program 

for each impacted Class I area, for the 

worst and best 20 percent of days. The 

modeling only demonstrates ‘‘greater 

reasonable progress’’ if both of the 

following two criteria are met: (i) 

Visibility does not decline in any Class 

I area, and (ii) There is an overall 

improvement in visibility, determined 

by comparing the average differences 

between BART and the alternative over 

all affected Class I areas. Id. 

§ 51.308(e)(3). 

Response: The comment addresses the 

approvability of a hypothetical SIP 

offered to meet the requirements of 40 

CFR 51.308(e)(2). First, we do not agree 

with the premise of the comment that 

merely proposed determinations of 

BART in the context of a possible FIP 

set a stringency threshold for a 

demonstration set forth in a 

hypothetical SIP. Proposed 

determinations are only proposals and 

the facts put forth to support those 

proposals are themselves subject to 

correction via public comment and new 

information. Second, we also do not 

agree with any extension of the 

commenter’s assertion to a FIP. While 

the comment does not address all the 

pertinent requirements for a BART 

alternative, we have done so elsewhere 

in this preamble. For example, as 

allowed by the requirements for a BART 

alternative in § 51.308(e)(2)(i)(C), we are 

declining to conduct the analysis that 

would include making determinations 

of BART for each source subject to 

BART and we are instead exercising the 

exception allowed when the alternative 

measure ‘‘has been designed to meet a 

requirement other than BART (such as 

the core requirement to have a long-term 

strategy to achieve the reasonable 

progress goals established by States).’’ 65

Third, we disagree that 51.308(e)(3) 

applies to this action. Rather, we find 

justification for the BART alternative 

under the ‘‘clear weight of the 

evidence’’ that the trading program will 

provide greater reasonable progress than 

would be achieved through the 

installation and operation of BART at 

the covered sources. This means of 

validating a BART alternative, described 

by one Court as the ‘‘catch-all,’’ is 

permitted by 40 CFR 51.308(e)(2)(i)(E). 

We are allowed but not required to 

validate the BART alternative under the 

test set out in 40 CFR 51.308(e)(3). 

Although we are not applying that test 

here, we believe this intrastate trading 

program meets the intent of (e)(3). When 

promulgating the 2012 CSAPR-Betterthan-BART rule, the EPA relied on an 

analysis showing that CSAPR would 

result in greater reasonable progress 

than BART under the test in 40 CFR 

51.308(e)(3). In this action we are 

relying, in part, on that demonstration 

to show that the clear weight of 

evidence demonstrates that the SO2

Trading Program will provide for greater 

reasonable progress than BART in 

Texas. This is based on a showing that 

the emissions in Texas under the BART 

alternative will be on average no greater 

than the emission levels from Texas 

EGUs that was forecast in the 

demonstration for Texas EGU emissions 

assuming CSAPR participation. 

2. Statutory or Regulatory Text 

Comment: A state should be able to 

independently rely on EPA’s CSAPR-isbetter-than-BART determination if the 

state can demonstrate that a state-only 

program for EGUs is more stringent than 

CSAPR. While the TCEQ has not 

proposed any action to implement a 

Texas-only program for EGUs based in 

some way on CSAPR as a means of 

satisfying BART, and these comments in 

no way represent a commitment to 

propose such an action, the TCEQ 

should be able to rely on the EPA’s 

CSAPR-is-better-than-BART 

determination to satisfy certain aspects 

of the BART alternative provisions in 40 

CFR part 51, § 51.308(e)(2) if such a 

program can be demonstrated to be 

more stringent than CSAPR. 

Specifically, the state should be able to 

rely on the EPA’s determination that 

CSAPR resulted in greater reasonable 

progress than source-specific BART to 

satisfy the requirements of 

§ 51.308(e)(2)(i)(E) and (e)(3). 

We acknowledge that other 

requirements of § 51.308(e)(2) would 

still need to be satisfied, such as 

monitoring, recordkeeping, reporting, 

and provisions for emission trading 

programs. While the CSAPR option is 

specifically listed at § 51.308(e)(4), the 

EPA’s Regional Haze rules do not 

prohibit a state from relying on EPA’s 

modeling demonstration that CSAPR 

resulted in greater reasonable progress 

when using an alternative under 

§ 51.308(e)(2). If a state-only program is 

more stringent than CSAPR, for example 

a program based on CSAPR allocations 

but without interstate trading, requiring 

a state to conduct extensive modeling to 

demonstrate what the EPA has already 

demonstrated for a less stringent 

program is illogical and places an 

unnecessary and wasteful burden on 

states. 

Response: We agree with this 

comment. In response to this comment, 

our final FIP establishes an intrastate 

trading program that operates much like 

the CSAPR program did in Texas. This 

program is discussed in more detail 

elsewhere. 

3. EPA’s Reliance on CSAPR for NOX

BART 

Comment: Agree with EPA’s proposal 

regarding CSAPR as a BART alternative 

for NOX which is proposed for separate 

finalization. EPA could have followed 

the D.C. Circuit’s directive and updated 

NOX (and SO2) budgets for Texas. EPA 

could have but declined to do so. EPA 

notes that finalization of CSAPR as 

better-than-BART for NOX is contingent 

on a separate finalization that the D.C. 

Circuit remands would not adversely 

impact 2012 demonstrations. 

Uncertainty in this proposal does not 

seem to be an issue for NOX and EPA 

is again basing a proposal on an action 

yet to be finalized. 

Response: Whether we were in a 

position to provide updated annual NOX

and SO2 budgets for Texas is not 

relevant to this rulemaking. Because 

Texas EGUs are required to continue 


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participation in CSAPR for ozone 

transport, which involves NOX trading, 

we are determining that the NOX BART 

requirement for EGUs continues to be 

met through our determination that 

CSAPR is better than BART. 

We interpret the comment as 

supporting this action, even as it 

appears to criticize our reference to 

another proposed action, which has 

since been finalized, as part of the 

proposal for the NOX aspect of this 

action. Our proposed and finalized 

action for the NOX BART requirement 

addresses the Act’s requirements for 

Texas. This action and our recent action 

to remove Texas EGUs from CSAPR’s 

SO2 trading program are distinct 

actions, but we have provided 

appropriate transparency and notice 

regarding how the proposed actions 

relate and have given careful 

consideration to comments received that 

have bearing on each of the actions. 

Comment: EPA’s proposal is unlawful 

because it exempts sources from 

installing BART controls without going 

through the exemption process Congress 

prescribed. The visibility protection 

provisions of the Clean Air Act include 

a ‘‘requirement’’ that certain sources 

‘‘install, and operate’’ BART controls. 42 

U.S.C. 7491(b)(2)(A). Congress specified 

the standard by which sources could be 

exempted from the BART requirements, 

which is that the source is not 

reasonably anticipated to cause or 

contribute to a significant impairment of 

visibility in any Class I area. 

Appropriate federal land managers must 

concur with any proposed exemption. 

EPA has not demonstrated that any of 

the Texas EGUs subject to BART meet 

the standards for an exemption, nor has 

EPA obtained the concurrence of federal 

land managers. Therefore, EPA must 

require source-specific BART for each 

power plant subject to BART. 

Response: To the extent the comment 

is directed to the prior rules that 

determined and redetermined that 

CSAPR is better than BART and may be 

relied upon as an alternative to BART, 

we disagree that relying on CSAPR is in 

conflict with the CAA provision 

regarding exemptions from BART. In 

addition, the commenter’s objection 

does not properly pertain to this action, 

but instead to our past action that 

established 40 CFR 51.308(e)(4). We 

believe this comment to fall outside of 

the scope of our action here. To the 

extent the comment objects to BART 

alternatives generally, we also disagree. 

In addition, that objection does not 

properly pertain to this action, but 

instead to our past regulatory action that 

provided for BART alternatives. 

Comment: Even if EPA could use a 

BART alternative without going through 

the statutory exemption process, the 

CSAPR-Better-than-BART Rule was 

fatally flawed, and even if it were valid 

in 2012, is now woefully outdated. 

EPA’s regulations purport to allow the 

use of an alternative program in lieu of 

source-specific BART only if the 

alternative makes ‘‘greater reasonable 

progress’’ than would BART. 40 CFR 

51.308(e)(2). To demonstrate greater 

reasonable progress, a state or EPA must 

show that the alternative program does 

not cause visibility to decline in any 

Class I area and results in an overall 

improvement in visibility relative to 

BART at all affected Class I areas. Id. 

§ 51.308(e)(3)(i)–(ii). 

EPA compared CSAPR to BART in the 

Better-than-BART Rule by using CSAPR 

allocations that are more stringent than 

now required as well as by using 

presumptive BART limits that are less 

stringent than are actually required 

under the statute. Even under EPA’s 

skewed 2012 comparison, CSAPR 

achieves barely more visibility 

improvement than BART at Big Bend 

and Guadalupe Mountains. The NOX

emissions allowed under CSAPR from 

Texas EGUs are higher than would be 

allowed under BART. This was true 

even before EPA revised CSAPR to 

increase the emissions allocations for all 

Texas EGUs. 

If it were assumed that the CSAPRBetter-than-BART Rule were valid in 

2012, it is based on assumptions for 

both CSAPR and BART emissions 

which are now woefully outdated. The 

CSAPR-Better-than-BART Rule’s 

reliance on presumptive BART emission 

limits is now outdated, given that EPA 

has issued or approved source-specific 

BART determinations for dozens of 

sources since 2012. In particular, for 

Texas sources, EPA has proposed SO2

BART limits which are far below the 

presumptive BART limits EPA used in 

the Better-than-BART Rule. For units 

other than Martin Lake, EPA proposes 

SO2 BART limits of 0.04 to 0.06 lbs/ 

MMBtu, which are well below the 

presumptive SO2 BART limit of 0.15 

lbs/MMBtu; even at Martin Lake, EPA 

proposes limits of 0.11 to 0.12, which 

are still below presumptive BART for 

SO2. 

Similarly, the CSAPR-Better-thanBART Rule is based on a version of 

CSAPR that no longer exists. 

Accordingly, any conclusion that EPA 

made in the 2012 Better than BART rule 

regarding whether CSAPR achieves 

greater reasonable progress than BART 

is no longer valid. Since 2012, EPA has 

significantly changed the allocations 

and the compliance deadlines for 

CSAPR. Of particular relevance here, 

after 2012, EPA dramatically increased 

the CSAPR allocations for every covered 

EGU in Texas. EPA later withdrew the 

February 21, 2012 rule revision, but 

issued a new rule that included both the 

changes in the February 21, 2012 rule as 

well as additional changes to state 

budgets. 

By the time EPA finalized the Betterthan-BART-Rule in June 2012, EPA had 

changed the state emissions budgets by 

tens of thousands of tons, yet EPA 

proceeded to finalize the Better-thanBART Rule based solely on the 

emissions budgets in the original, 2011 

CSAPR rule. EPA also extended the 

compliance deadlines by three years, 

such that the phase 1 emissions budgets 

take effect in 2015–2016 and the phase 

2 emissions budgets take effect in 2017 

and beyond. Even more changes to 

CSAPR have occurred as a result of the 

D.C. Circuit’s decision in EME Homer 

City II Generation, including the 

proposed withdrawal of Texas from the 

annual NOX and SO2 trading programs. 

Given the large number of final BART 

determinations made since 2012, and 

the significant changes to CSAPR 

budgets since 2012, it is arbitrary and 

capricious to rely on the outdated 

assumptions about emissions which 

were made in the CSAPR-Better-thanBART Rule. 

Response: As we had proposed, our 

finalized determination that CSAPR 

participation will resolve NOX BART 

requirements for Texas EGUs is based 

on a separately proposed and finalized 

action. This comment falls outside of 

the scope of our action here. 

Comment: EPA’s November 2016 

‘‘Sensitivity Analysis’’ purports to 

update its CSAPR-Better-than-BART 

analysis to show that CSAPR still makes 

greater reasonable progress than BART. 

We agree with EPA that the 2016 

Sensitivity Analysis is not a proper legal 

basis for demonstrating that CSAPR 

makes greater reasonable progress than 

BART, because the 2016 analysis is 

merely a proposed rule. It would be 

unlawful to issue a final BART rule 

relying on CSAPR to satisfy the NOX

BART requirements in the absence of a 

final rule demonstrating that the CSAPR 

Update makes greater reasonable 

progress than BART. 

To demonstrate that CSAPR makes 

greater reasonable progress than BART, 

EPA must show that (1) visibility does 

not decline in any Class I area under 

CSAPR, and (2) there is an overall 

improvement in visibility, based on 

comparing the average differences 

between CSAPR and BART across all 

affected Class I areas. EPA’s analysis 

falls well short of making such a 


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demonstration, as we noted in our prior 

comments on EPA’s 2016 Sensitivity 

Analysis. 

EPA’s 2016 analysis is markedly 

different from the CSAPR-Better-thanBART Rule, which relied on 

quantitative modeling of electric power 

section emissions, using the Integrated 

Planning Model, and quantitative 

modeling of visibility at all affected 

Class I areas, using CAMx. Instead of 

updating that modeling, EPA’s 2016 

analysis consists of a back-of-theenvelope, qualitative discussion. This is 

wholly insufficient. There have been 

enormous changes in the electric power 

sector since EPA issued the Better-thanBART Rule in 2012, including changes 

in regulatory requirements (e.g., CSAPR 

revisions, NAAQS updates, etc.) and 

changes in unit operations caused by 

changes in fuel prices, demand, etc. 

Given that EPA believed in 2012 that it 

was necessary to conduct quantitative 

modeling of power sector emissions and 

the visibility impacts of such emissions, 

EPA must update that modeling in order 

to prove that CSAPR still makes greater 

reasonable progress than BART. 

EPA’s failure to update the modeling 

upon which it relied in the 2012 Better 

than BART Rule is even more arbitrary 

given EPA’s assumption, in the 2016 

Sensitivity Analysis, that no trading of 

CSAPR allowances would occur across 

state lines. The Sensitivity Analysis 

uses ‘‘emissions that would occur if the 

state budgets are increased as proposed 

assuming that all of the additional 

allowances are used by sources in the 

respective state (i.e., we did not remodel trading).’’ This assumption bears 

no relationship to reality, in which 

CSAPR—both the original rule, and the 

updated rule—expressly allows trading 

across state lines. EPA’s failure to create 

a realistic depiction of the geographic 

distribution of emissions under the 

updated CSAPR budgets dooms its 

Sensitivity Analysis, as EPA must 

demonstrate that visibility does not 

decline in any Class I area. Trading 

across state lines can increase emissions 

from particular sources, which in turn 

can degrade visibility at particular Class 

I areas. Having failed to consider how 

inter-state trading will affect the 

distribution of emissions under CSAPR, 

EPA cannot possibly show that visibility 

will not decline in any Class I area 

under CSAPR. 

Similarly, EPA failed to account for 

intra-state trading under CSAPR. Even 

assuming all changes in budgets would 

apply only within the affected state— 

that is, assuming interstate emissions 

trading did not change at all—EPA has 

not accounted for trading within the 

states. A 20% reduction in statewide 

emissions does not imply that each unit 

will reduce its emissions by 20%; 

indeed, some units could increase 

emissions while statewide emissions 

went down. EPA does not seem to have 

accounted for this in its analysis. Thus, 

even within EPA’s scenario whereby no 

changes to reflect current conditions 

need to be made, EPA’s ad hoc analysis 

fails to demonstrates that the ‘‘Betterthan-BART’’ test above would be met 

because EPA has failed to account for 

changes in emissions distribution based 

on the altered budgets. 

In addition, EPA cannot simply 

assume that the visibility improvement 

averaged across all Class I areas, 40 CFR 

51.308(e)(3)(ii), will still be better under 

the updated CSAPR than under BART. 

Without updated visibility modeling, 

EPA has no data to demonstrate that the 

second prong of the BART alternative 

test will be met in spite of the 

substantial changes in coverage and 

budgets under CSAPR. 

Response: In part, the comment makes 

the point that this final action cannot 

rely on another action that has only 

been proposed. We agree with this 

aspect of the comment, but this part of 

the comment is no longer relevant 

because the other action has now been 

finalized. As we had proposed, our 

finalized determination that CSAPR 

participation will resolve NOX BART 

requirements for Texas EGUs is based 

on a separately proposed and now 

finalized action. This comment in its 

discussion of the 2016 sensitivity 

analysis and other particulars raises 

issues that are addressed in the record 

for that separately finalized action. This 

comment falls outside of the scope of 

our action here. 

Comment: Under the updated version 

of CSAPR, Texas will not have 

allowances for annual NOX emissions. 

Instead, Texas will have a CSAPR 

budget for NOX for only the ozone 

season, which runs a few months each 

year. But BART is not a seasonal 

requirement; BART requires continuous 

operation of pollution controls. ‘‘The 

determination of BART must be based 

on an analysis of the best system of 

continuous emission control technology 

available and associated emission 

reductions achievable for each BARTeligible source that is subject to BART 

within the State.’’ It violates EPA’s 

regulations to use seasonal emissions 

reductions under CSAPR to satisfy the 

BART requirement to install and operate 

‘‘continuous emission control 

technology.’’ 

Response: We disagree with this 

comment, but also note that it should 

not be directed to this action but rather 

to the past rulemaking determination 

that provided BART coverage for 

pollutant trading under CSAPR as 

specified at 40 CFR 51.308(e)(4). In any 

event, the argument that BART must be 

based on ‘‘continuous’’ control does not 

transfer to the application and operation 

of a BART alternative. Sources that 

would operate under an annual trading 

program that provides tons per year 

allocations for a unit are not necessarily 

applying ‘‘continuous’’ controls either. 

In fact, they are also free to operate 

seasonally or with intermittent use of 

controls so long as they operate within 

the allocation or purchase allowances 

whenever emissions may exceed that 

allocation. We necessarily disagree that 

EPA regulations would bar seasonal 

emissions reductions to satisfy 

requirements for a BART alternative. 

4. Other CSAPR Comments 

Comment: The EPA should proceed to 

finalize CSAPR as a better-than-BART 

alternative not only as to NOX but also 

as to SO2. In the Texas Regional Haze 

SIP, Texas relied on EPA’s Regional 

Haze Rule that allows states to 

implement an alternative to BART as 

long as the alternative has been 

demonstrated to achieve greater 

reasonable progress toward the national 

visibility goal than BART. EPA made 

such a demonstration for CAIR and 

many states, including Texas, relied on 

CAIR’s cap and trade programs as a 

BART alternative for EGU emissions of 

SO2 and NOX in their SIP submittals. 

Following EPA’s demonstration in 2005 

that CAIR is better-than-BART and after 

Texas submitted the Regional Haze SIP, 

the D.C. Circuit Court remanded CAIR 

to EPA but ultimately did not vacate the 

CAIR rule. EPA approved certain States’ 

SIPs that implemented CAIR as a BART 

alternative, yet, EPA did not do so for 

Texas. 

CSAPR was issued to replace CAIR 

and because of EPA’s action on CAIR, 

EPA subsequently withdrew reliance on 

CAIR as a BART alternative and 

finalized the demonstration that 

compliance with CSAPR is better than 

application of BART. This action 

occurred after Texas had submitted its 

SIP. 

On December 16, 2014, EPA 

published a proposed FIP program to 

‘‘replace reliance on CAIR with reliance 

on the trading programs of CSAPR as an 

alternative to BART for SO2 and NOX

emissions for EGUs.’’ The CSAPR rule 

had been challenged in the D.C. Circuit 

and the court held that EPA had overcontrolled certain States’ budgets and 

remanded the CSAPR rule without 

vacatur for further revision by EPA. In 

January 2016, EPA did not finalize 

BART controls for EGUs, citing 


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uncertainty. EPA issued the CSAPR 

Update on October 24, 2016 but did not 

revise SO2 or NOX annual budgets for 

Texas. 

EPA’s Proposed FIP and the 

imposition of source-specific BART 

relies on the EPA’s proposed 

rulemaking for the withdrawal of Texas 

from the CSAPR Phase 2 trading budgets 

for SO2. In November 2016, EPA 

published a proposal to withdraw the 

FIP provisions that required affected 

EGUs to participate in Phase 2 of the 

CSAPR trading programs for annual 

emissions of SO2 and NOX purportedly 

to address a decision of the U.S. Court 

of Appeals for the District of Columbia 

Circuit that had remanded for further 

consideration the CSAPR Phase 2 SO2

budgets for Texas and other states. 

EPA’s proposed withdrawal of Texas 

from the Phase 2 CSAPR program for 

SO2 included a ‘‘sensitivity analysis’’ 

indicating that removal of Texas from 

the Phase 2 SO2 budget trading program 

(and including the removal of the 

Florida trading program) would not 

adversely impact the demonstration that 

CSAPR participation continued to 

qualify as an alternative to compliance 

with BART, in other states that were 

relying on CSAPR for BART 

compliance. 

EPA also noted that ‘‘[n]o changes to 

the Regional Haze Rule are proposed as 

part of the rulemaking.’’ Id. However, in 

support of this FIP proposal addressing 

Regional Haze, EPA notes that it, ‘‘had 

earlier proposed to rely on CSAPR 

participation to address these BARTrelated deficiencies in Texas’ SIP 

submittals referencing its December, 

2014 proposed FIP.’’ EPA did not 

address the D.C. Circuit Court’s remand 

as directed. 

The D.C. Circuit had remanded 

without vacatur the Phase 2 budgets in 

EME Homer City Generation, L.P. v. 

EPA, 795 F.3d 118 (D.C. Circuit 2015) 

and directed the EPA to reconsider the 

emission budgets and propose revised 

budgets. AEP said they did not support 

EPA’s proposal to withdraw Texas from 

CSAPR, stating that the EPA had 

provided insufficient justification and 

explanation for the proposal and had 

not considered the impact on the 

trading market. AEP noted that the court 

had specifically not vacated the Phase 2 

budgets due to concerns that such a 

decision would disrupt the trading 

markets. AEP also expressed concern 

that withdrawing Texas from CSAPR 

would impact the compliance strategies 

facilities have developed for compliance 

with BART, as BART eligible facilities 

had developed compliance strategies 

assuming BART compliance would be 

achieved through compliance with 

CSAPR. AEP said they supported the 

CSAPR trading programs because of 

their flexibility and administrative 

convenience, cost-effectiveness and the 

‘‘remarkable reductions that have 

occurred across the electric utility 

industry.’’ AEP also considered EPA’s 

analysis of the impact of sources in 

Texas on nonattainment areas in other 

states was inadequate and the 

explanation provided by EPA for its 

decision to change the initial 

determination was insufficient and 

potentially exposed Texas EGUs to 

future liability for the impact of PM2.5

emissions on Madison County and other 

upwind locations. AEP concluded their 

comments on 81 FR 78954 by 

recommending the EPA finalize CSAPR 

as a compliance alternative to BART for 

SO2 and revise the Phase 2 budgets, 

instead of withdrawing Texas from 

CSAPR. 

The D.C. Circuit requires EPA to 

propose acceptable budgets consistent 

and confirm that those budgets are a 

BART alternative and allow Texas to 

remain in the CSAPR trading program. 

Source specific controls, then, would no 

longer be necessary since CSAPR as a 

BART alternative would provide a more 

cost-effective, less burdensome and 

flexible program for compliance with 

Texas’ visibility obligations. 

By EPA’s reliance on the proposed 

withdrawal of Texas from the CSAPR 

trading program for SO2 as the basis for 

the proposed Texas BART FIP, EPA is 

illegally proposing BART controls on 

facilities premised on a proposed rule. 

Buttressing the proposed FIP on a 

proposed-not-yet-finalized rule is 

inconsistent with the APA. EPA seems 

concerned with uncertainty created by 

the remand yet, this action by EPA 

creates its own uncertainty with regard 

to whether the proposed withdrawal 

will be finalized as proposed. The APA 

requires that an agency provide notice 

and an opportunity to comment on 

proposed rules. 5 U.S.C. 553(c). An 

agency must be open to taking 

comments and responding to them. This 

necessarily requires that EPA must 

consider comments from the public 

before finalizing a proposed rule. In fact, 

the comment period for the proposed 

withdrawal of Texas from the SO2

CSAPR budgets ended after the date of 

the proposed BART FIP. Clearly, EPA 

gave itself no opportunity to consider 

public comment on the proposed 

withdrawal prior to relying on it as if it 

were final as proposed to justify the 

need for proposing source-specific 

BART. EPA’s actions demonstrate that it 

had no intention of accepting public 

comment and had already made up its 

mind that the proposal would be 

finalized as proposed, a direct 

contravention of the APA. 

Response: Several contentions 

provided by this commenter are relevant 

to the action withdrawing Texas from 

Phase 2 CSAPR program budget, but 

given the finalization of that action they 

are not relevant to this action. We are 

required to address the BART 

requirements for both pollutants under 

our CAA FIP authority, in the absence 

of an approvable SIP. We are finalizing 

our proposal that NOX BART is met by 

continued participation in CSAPR and 

we are finalizing a BART alternative to 

address the SO2 BART requirement. The 

BART alternative applies the CSAPR 

allowance allocations for SO2 to all 

BART-eligible coal-fired EGUs, several 

additional coal-fired EGUs, and several 

BART-eligible gas-fired and gas/fuel oilfired EGUs. In addition to being a 

sufficient alternative to BART, it secures 

reductions consistent with visibility 

transport requirements and is part of the 

long-term strategy to meet the 

reasonable progress requirements of the 

Regional Haze Rule. 

We do not agree with the commenter’s 

suggestion that we were not open to the 

consideration of comments in our 

proposed action or in any related 

actions in violation of the APA. 

Moreover, the assertion that EPA had 

made up its mind that any proposal 

would be finalized as proposed 

regardless of comments that might be 

offered is not correct. For efficiency and 

because of time constraints, our 

proposal for the NOX aspect of this 

action was based on a scenario of later 

finalization of the CSAPR remand 

response rule, but that does not mean 

that we did not fairly consider all 

comments on the CSAPR remand 

response rule or pre-decided the 

outcome of that rule. Our final decisions 

in this action reflect the final CSAPR 

remand rule, and consideration of 

comments on our proposal for this 

action. 

Comment: Recommend the CSAPR 

budgets be revised. Revising the CSAPR 

budgets is supported by actual SO2

emissions. The Texas EGU SO2 and NOX

emissions have steadily decreased and 

have fallen well below 2017 CSAPR 

budgets. These emissions are well below 

the original better-than-BART budgets 

for SO2. EPA’s determinations that 

CSAPR is better-than-BART is still valid 

and supported even if emissions were 

increased. 

We anticipate that EPA may respond 

that a September 9, 2017 Consent 

Decree deadline (derived from a case in 

which the EGUs were not party) did not 

permit time to consider comments 

before proposing the Texas BART FIP. 


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Clearly, the most expeditious approach 

would be for EPA to revise the invalid 

Phase 2 CSAPR budgets for Texas and 

propose that reliance on the revised 

budgets satisfies BART compliance. Any 

delays in addressing Texas’ BART 

obligations are the result of EPA not 

establishing an acceptable CAIR or 

CSAPR program, and EPA’s refusal to 

revise CSAPR Phase 2 budgets and not 

Texas’ failure to agree to accept invalid 

CSAPR budgets. In fact, the D.C. Circuit 

instructed EPA to act ‘‘promptly’’ in 

revising the budgets. 

Additionally, EPA’s attempt to 

comply with a court deadline does not 

justify noncompliance with the APA. 

With its current proposal (Texas BART 

FIP), EPA has done nothing but create 

further uncertainty and violate the APA. 

EPA could have requested an extension 

of the deadline to revise the budgets, but 

did not. Consistent with the 

Administration’s Executive Order on 

Reducing Regulation and Controlling 

Regulatory Costs, EPA could revise the 

CSAPR budgets adhere to CSAPR is 

better-than-BART, as they have in many 

other states, and remove two proposed 

regulations in doing so without the 

promulgation of another rule (proposed 

withdrawal of Texas from the CSAPR 

Phase 2 program and proposed sourcespecific BART for Texas source.) EPA 

should update the Phase 2 SO2 budgets 

as directed and post-haste proceed to 

finalize CSAPR as a better an alternative 

to the application of source-specific 

BART. 

Response: Texas declined to submit a 

SIP to voluntarily participate in CSAPR 

and we have addressed our remand 

obligations for Phase 2 SO2 budgets by 

ending Texas EGU participation in 

CSAPR for PM2.5 transport. We agree, 

however, that Texas sources can 

continue NOX BART coverage under 

CSAPR and we are finalizing a BART 

alternative for SO2 instead of 

establishing source-specific SO2 BART 

determinations for units at those 

sources. The BART alternative applies 

the CSAPR allowance allocations for 

SO2 to all BART-eligible coal-fired 

EGUs, several additional coal-fired 

EGUs, and several BART-eligible gasfired and gas/fuel oil-fired EGUs. In 

addition to being a sufficient alternative 

to BART, it secures reductions 

consistent with visibility transport 

requirements and is part of the longterm strategy to meet the reasonable 

progress requirements of the Regional 

Haze Rule. 

Comment: EPA is now proposing to 

require stringent emission control 

technology on units that have already 

met the BART obligations by 

participation in the regional trading 

programs, CAIR, and its replacement, 

CSAPR. In this proposal, EPA has 

effectively removed a cost-effective 

compliance mechanism which has been 

in place for the duration of the first 

planning period, with costs and 

reductions that far exceed the regulatory 

obligation, with limited or no benefit to 

visibility. Because it was only late last 

week that EPA made available the 

technical documents that it claims 

would support its action and EPA has 

yet to provide us with the specific 

modeling supporting the proposal that 

we requested several weeks ago, We 

have not yet had an opportunity to 

thoroughly evaluate EPA’s technical 

justification for the proposal. 

Response: Our proposal did not 

effectively remove CSAPR, and we 

disagree with the comment’s 

characterization of how and when 

CSAPR has been ‘‘in place.’’ Regardless, 

we agree with the premise of the 

comment that SO2 BART and NOX

BART for Texas EGUs can be addressed 

by the BART alternatives we rely on in 

our final action. We also disagree that 

our proposal would have provided 

limited or no benefit to visibility to the 

extent it suggests our final action is not 

providing visibility benefits. Visibility 

benefits are being secured and preserved 

into the future by the final FIP 

measures. 

Comment: Texas’ SO2 emissions are 

below the levels that EPA has found to 

be better-than-BART, and any 

reasonable assessment would conclude 

that trends of anticipated emissions in 

Texas will remain below those levels. 

EPA conducted two sensitivity analyses 

that both demonstrate that revised 

CSAPR emission levels for Texas are 

better-than-BART. We compared actual 

Texas EGU SO2 emissions in 2015 and 

2016 to the SO2 emission levels that 

EPA found are better-than-BART. In 

both cases, Texas’ actual emissions are 

well below the budgets that EPA has 

determined are better-than-BART. 

Response: We are finalizing a BART 

alternative that applies the CSAPR 

allowance allocations for SO2 to all 

BART-eligible coal-fired EGUs, several 

additional coal-fired EGUs, and several 

BART-eligible gas-fired and gas/fuel oilfired EGUs. In addition to being a 

sufficient alternative to BART, it secures 

reductions consistent with visibility 

transport requirements and is part of the 

long-term strategy to meet the 

reasonable progress requirements of the 

Regional Haze Rule. To the extent, the 

comment suggests that current and 

anticipated emissions alone are enough 

to satisfy requirements for BART or a 

BART alternative, we disagree. As a 

fundamental matter, emissions 

reductions must be enforceable to 

prevent undesired and unexpected 

increases in future years. Pointing to 

‘‘trends’’—i.e., unenforceable emissions 

levels without legal requirements 

against future increases—does not meet 

CAA requirements. 

Comment: EPA must promulgate or 

approve a BART alternative for Texas, 

and must not finalize the unlawful and 

cost-prohibitive proposed Texas BART 

FIP. EPA should not, and lawfully may 

not, finalize its Proposed Texas BART 

FIP. The Proposed Texas BART FIP— 

like the predecessor Reasonable 

Progress Rule that is stayed and was 

remanded by the Fifth Circuit for 

reconsideration—is fundamentally 

flawed, cost-prohibitive to implement, 

and contrary to reasoned decisionmaking. EPA should address BART for 

Texas—not through federally-mandated 

specific controls on individual units— 

but through one of several available 

BART alternatives that will achieve 

equivalent or greater benefits at far less 

costs, as demonstrated by EPA’s own 

prior modeling and sensitivity analyses. 

Among those available alternatives is 

EPA’s original proposed BART action 

for EGUs in Texas—reliance on Texas 

EGUs’ participation in CSAPR’s annual 

SO2 and NOX trading Programs as BART 

compliance. That alternative remains 

the most expeditious and defensible 

path for finalizing a BART solution for 

Texas EGUs, and it is fully supported by 

EPA’s previous CSAPR better-than 

BART modeling and sensitivity 

analyses. Indeed, EPA’s only lawful 

path forward to finalize a BART FIP for 

Texas by the current September 9, 2017 

deadline in EPA’s consent decree with 

Sierra Club is to finalize a CSAPR-forBART FIP for Texas EGUs, as EPA 

signed in December 2014. For the many 

reasons discussed in Section II of these 

comments, EPA would be acting 

unlawfully were it to finalize the 

Proposed Texas BART FIP as issued in 

December 2016. 

As an alternative to finalizing a 

CSAPR-for-BART FIP in September 

2017, EPA could seek an extension of 

the consent decree deadline and 

proceed to work cooperatively with the 

State of Texas and Texas EGU operators 

to develop and propose for comment a 

different BART alternative for Texas, as 

it has done in other states. Such an 

alternative could, for example, establish 

SO2 emission caps for Texas EGUs that 

are comparable to CSAPR budgets and 

would thus fall squarely within EPA’s 

previous CSAPR=BART demonstration 

and sensitivity analyses for Texas. EPA 

has frequently worked with states and 

stakeholders to develop workable BART 

alternatives for EGUs, and it should do 


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the same here with Texas and Texas 

stakeholders, including Luminant. 

Promulgation of a CSAPR-for-BART 

FIP is EPA’s only lawful option for 

meeting the September 9, 2017 consent 

decree deadline. If EPA believes that it 

must finalize a BART rule for Texas 

EGUs by September 2017, EPA’s only 

valid legal option is to finalize its 2014 

proposed CSAPR-for-BART FIP. In that 

proposal, EPA specifically stated that it 

was proposing ‘‘a FIP to replace reliance 

on CAIR with reliance on the trading 

programs of CSAPR as an alternative to 

BART for SO2 and NOX emissions from 

EGUs in the regional haze plan for 

Texas.’’ In support, EPA explained that 

it ‘‘determined that [1] CSAPR provides 

for greater reasonable progress towards 

the national goal than would BART and 

[2] Texas is included in CSAPR for NOX

and SO2.’’ The same is true today, and, 

indeed, recent emission trends and 

EPA’s sensitivity analyses for Texas 

confirm that CSAPR is and remains 

better-then-BART for Texas EGUs. Texas 

remains in the CSAPR annual programs 

for NOX and SO2, and EPA’s 

determination that CSAPR provides for 

greater reasonable progress than the 

installation of BART remains 

scientifically sound. EPA has 

determined that ‘‘[CSAPR] achieves 

greater reasonable progress towards the 

national goal of achieving natural 

visibility conditions than sourcespecific BART.’’ That conclusion 

remains valid today, and EPA has not 

undertaken any action to revise or 

rescind that rulemaking. In fact, the 

Eighth Circuit recently upheld EPA’s 

conclusion that CSAPR is better than 

BART, stating that ‘‘EPA’s explanation 

that the Transport Rule is better than 

source-specific BART is rational.’’ There 

is no legal or technical barrier to EPA 

finalizing its original proposal of 

CSAPR-for-BART for Texas EGUs, and, 

indeed, that is EPA’s only lawful 

current option if it were to meet the 

September 2017 deadline. 

EPA’s consent decree with Sierra Club 

does not prevent EPA from finalizing its 

original CSAPR-for-BART proposal in 

Texas. The consent decree that EPA 

entered into with Sierra Club was 

revised in December 2015 to provide 

two alternative deadlines for issuing a 

final rule that implements BART for 

Texas. First, the revised consent decree 

provides that by ‘‘[n]o later than 

December 9, 2016,’’ EPA was to 

promulgate a final BART FIP for Texas, 

unless EPA had approved Texas’s SIP or 

promulgated ‘‘a partial SIP’’ meeting the 

BART requirements under the regional 

haze program. Alternatively, the 

December 2016 deadline would be 

‘‘extended to September 9, 2017,’’ if 

EPA signed a new proposed rule for 

BART by December 9, 2016. EPA signed 

the Proposed Texas BART FIP on 

December 9, 2016, thereby triggering the 

extension in the consent decree. 

The consent decree, however, does 

not (and cannot) dictate the substance of 

EPA’s final BART rulemaking under the 

extended deadline of September 9, 

2017; the only prerequisite to invoking 

this extension is the signing of a 

proposal by December 9, 2016. EPA is 

not bound by the consent decree to 

finalize the terms of the current 

proposal or any similar source-specific 

BART rule; in fact, established 

principles of administrative law require 

EPA to remain open-minded during the 

rulemaking process. The consent decree 

merely established deadlines for EPA’s 

pending course of action. Accordingly, 

for purposes of meeting the upcoming 

deadline of September 9, 2017, EPA is 

not prohibited by the consent decree 

from reverting to its 2014 proposal to 

finalize CSAPR as a BART alternative 

for Texas EGUs. 

Response: We agree that the existence 

of the consent decree deadline does not 

dictate the substance of our action to 

address Clean Air Act requirements to 

meet the deadline. We disagree that our 

only possible lawful action for meeting 

the deadline is to impose a FIP based on 

CSAPR. 40 CFR 51.308(e) requires that 

states submit a SIP containing emission 

limitations that represent BART for 

BART eligible sources that may 

reasonably be anticipated to cause or 

contribute to any impairment of 

visibility in any mandatory Class I 

Federal area. Alternatively, 40 CFR 

51.308(e) allows states to establish an 

emissions trading program or other 

alternative as long as the trading 

program or other alternative will 

achieve greater reasonable progress 

toward natural visibility conditions than 

BART. Where a state has failed to 

submit a SIP by the applicable deadline 

or has submitted a SIP that has been 

disapproved by the EPA, the CAA 

authorizes and requires EPA to 

promulgate a FIP that meets the 

requirements of the applicable federal 

statutes and regulations. Thus, EPA has 

the authority to promulgate a FIP 

containing emission limits that 

represent BART for BART eligible 

sources that may reasonably be 

anticipated to cause or contribute to any 

impairment of visibility in any 

mandatory Class I Federal area. 

Alternatively, EPA may establish an 

emissions trading program or other 

alternative which will achieve greater 

reasonable progress than BART. We are 

meeting requirements with valid use of 

discretion where appropriate to finalize 

NOX BART as proposed, and to finalize 

a BART alternative with emission levels 

similar to CSAPR to address SO2 BART. 

We are not able to revive the 2014 

proposal to satisfy SO2 BART for Texas 

EGUs because remand obligations have 

led to the removal of SO2 trading 

requirements for Texas. We agree that 

this might have been a viable solution, 

but Texas declined to submit a SIP to 

voluntarily participate in CSAPR to 

fully preserve and accommodate this 

option. 

Comment: The Proposed Texas BART 

FIP is not only cost-prohibitive, it is not 

necessary to achieve the goals of the 

Regional Haze Program and satisfy the 

requirements of the CAA. EPA’s own 

prior modeling and analysis show that 

BART for these units is more than met 

by current SO2 emission levels from 

Texas EGUs, and the stringent 

additional limits in the Proposed Texas 

BART FIP are not necessary. 

EPA’s sensitivity analyses for Texas’s 

SO2 CSAPR budgets and recent 

emission trends in Texas demonstrate 

that CSAPR remains better-than-BART. 

EPA’s sensitivity analyses definitively 

confirm that EPA’s determination that 

CSAPR is better-than-BART in Texas 

remains scientifically sound. When EPA 

issued the final rule promulgating the 

CSAPR-for-BART provision in June 

2012, EPA confirmed that the upward 

adjustments to Texas’s budgets under 

CSAPR did not adversely impact 

visibility conditions in nearby Class I 

areas. EPA initially calculated visibility 

improvements for nearby Class I areas 

based on a SO2 budget for Texas of 

243,954 tons/year. Following EPA’s 

upward adjustments to the CSAPR 

budget due to errors in EPA’s initial 

calculation, EPA revised its visibility 

improvement estimates based on a SO2

budget of 294,471 tons/year. EPA’s 

methodology demonstrates the expected 

visibility improvement as a result of 

implementing the CSAPR is better-thanBART provision under the original 

budget and the revised budget. Even 

with an SO2 budget of nearly 300,000 

tons for Texas, visibility at these Class 

I areas was projected to improve (not 

degrade). 

Recent emissions data confirm EPA’s 

prior determination—i.e., that Texas’s 

emissions are well below the threshold 

that was previously determined to be 

better-than-BART. Implementation of 

CSAPR Phase 1 began in 2015, and 

implementation of Phase 2 began in 

2017. For 2015 and 2016—during 

CSAPR Phase 1—Texas maintained its 

annual emissions of SO2 and NOX well 

under the budgets established by EPA. 

The state-wide budget for annual SO2 in 

Texas is 294,471 tons, and the stateVerDate Sep<11>2014 18:01 Oct 16, 2017 Jkt 244001 PO 00000 Frm 00019 Fmt 4701 Sfmt 4700 E:\FR\FM\17OCR2.SGM 17OCR2

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wide budget for annual NOX in Texas is 

137,701 tons. These same budgets will 

apply during Phase 2, and there is no 

expectation that Texas EGUS will 

exceed these thresholds. In fact, EPA’s 

own data demonstrate that Texas has 

not exceeded, or even approached, its 

annual allowance allocations for either 

SO2 or NOX during Phase I of CSAPR. 

Emissions of SO2 from Texas EGUs were 

260,122 tons in 2015 and 244,233 tons 

in 2016. As for NOX, emissions from 

Texas EGUs were 107,921 tons in 2015 

and 106,625 tons in 2016. Once CSAPR 

became effective in Texas in 2015, SO2

emissions from Luminant’s coal-fired 

EGUs dropped dramatically and have 

trended downward. There is no reason 

to believe, and EPA presented no 

reason, that this trend will reverse—and 

certainly not to a degree that Texas EGU 

SO2 emissions would exceed CSAPR 

budgets or call into question EPA’s 

CSAPR better-than-BART 

demonstration. 

Texas has maintained its emissions 

well below the budgets established by 

CSAPR. The record establishes that 

BART for these units can be no more 

stringent than current emission levels, 

which are well below CSAPR budgets. 

In 2012, EPA concluded that ‘‘[CSAPR] 

achieves greater reasonable progress 

towards the national goal of achieving 

natural visibility conditions than 

source-specific BART.’’ EPA confirmed 

this determination in subsequent 

sensitivity analyses. So long as Texas’s 

emissions remain below the CSAPR 

budgets, the operation of Texas EGUs in 

such a manner will continue to be 

better-than-BART. 

Thus, the Proposed Texas BART FIP 

is based on a fundamental flaw by 

EPA—that BART for Texas EGUs must 

be ‘‘more emission reductions than 

projected under CAIR or CSAPR.’’ To 

the contrary, because Texas validly 

remains in the annual CSAPR programs 

for SO2 and NOX combined with the fact 

that Texas EGU SO2 emissions are well 

below the annual allocations, EPA has 

no valid basis to change course from its 

2014 proposal to finalize CSAPR for 

BART in Texas in order to impose more 

stringent source-specific BART controls. 

EPA should proceed to finalize a FIP for 

Texas that approves CSAPR as a BART 

alternative for Texas EGUs. 

Response: We agree that emissions 

similar to the CSAPR budgets would be 

better than BART and can be justified as 

a BART alternative. To the extent the 

comment suggests that merely pointing 

to current emissions level can satisfy the 

requirements of a BART alternative, we 

disagree. Those emissions levels must 

be made enforceable, and our final 

action accomplishes that. NOX BART for 

EGUs is addressed by continued 

participation in CSAPR program for 

ozone transport. With regard to SO2, the 

BART alternative is designed to achieve 

SO2 emission levels from Texas EGUs 

similar to the SO2 emission levels that 

would have been realized from the SO2

trading program under CSAPR. These 

measures will assure Texas’ recent 

reductions of SO2 and NOX will be 

maintained and improved upon in the 

future. 

Comment: The D.C. Circuit’s remand 

of CSAPR budgets does not create 

‘‘uncertainty’’ that prevents EPA from 

finalizing CSAPR-for-BART for Texas 

EGUs. EPA says that it did not finalize 

its initial CSAPR-for-BART proposal for 

Texas EGUs because it noted some 

‘‘uncertainty arising from the remand of 

Texas’ CSAPR budgets’’ by the D.C. 

Circuit. EPA made that claim in the 

now-stayed January 2016 Reasonable 

Progress Rule. That claim was wrong 

when it was made then, and it is clearly 

wrong now. There is no ‘‘uncertainty.’’ 

The D.C. Circuit’s remand does not 

prevent EPA from finalizing CSAPR as 

an SO2 BART alternative for Texas 

EGUs. 

First, EPA’s claim that there is an 

‘‘absence of CSAPR coverage for SO2’’ in 

Texas following the D.C. Circuit’s 

remand is simply wrong. Texas EGUs 

are and have been regulated by a BART 

equivalent trading program for the 

entirety of the first planning period to 

date—first through CAIR and, after 

CAIR’s replacement and up to the 

present day, through CSAPR. Texas 

EGUs are presently subject to CSAPR’s 

annual SO2 and NOX programs under 

the budgets remanded by the D.C. 

Circuit, which are budgets that EPA has 

confirmed as better-than-BART. EPA’s 

prior determination that CSAPR is 

better-than-BART for all states, 

including Texas, is scientifically sound 

and remains a binding part of EPA’s 

regulations. EPA may properly respond 

to the D.C. Circuit’s remand by revising 

Texas’s annual SO2 budget (as 

instructed by the D.C. Circuit) after it 

finalizes the proposed CSAPR-for-BART 

FIP for Texas. 

Second, regardless of when EPA 

responds to the D.C. Circuit’s remand, 

EPA’s own sensitivity analyses confirm 

that were EPA to properly respond to 

the remand by increasing Texas’s 

annual SO2 budgets so they do not overcontrol as instructed by the D.C. Circuit, 

those revised budgets would remain 

better-than-BART. EPA established a 

multi-step methodology to analyze 

whether increases in Texas’s SO2 annual 

budgets would change EPA’s CSAPR 

better-than-BART determination (which 

remains part of EPA’s binding 

regulations). First, EPA’s methodology 

for conducting a revised sensitivity 

analysis requires the identification of 

the Class I areas in and near Texas that 

that are most likely affected by Texas 

emissions. Second, EPA’s analysis then 

‘‘employ[s] [the] very conservative’’ 

assumption that ‘‘all of the visibility 

improvement’’ that EPA’s CSAPR betterthan-BART modeling predicted for these 

nine areas as a result of all CSAPR 

reductions from all covered states is 

‘‘solely due to [reductions] from Texas.’’ 

Third, with this conservative 

assumption, EPA then ‘‘proportionally 

reduce[s]’’ the modeled visibility 

improvements at these nine Class I areas 

based on the corrected higher SO2

budget for Texas. For example, if, in 

response to the D.C. Circuit’s remand, 

EPA were to adjust Texas’s budget to 

350,000 tons, CSAPR would still be 

better-than-BART for Texas and other 

states. Such an adjustment would be 

equivalent to a 57% reduction in the 

number of SO2 tons reduced compared 

to the original Texas CSAPR reductions 

that were modeled for EPA’s original 

CSAPR better-than-BART modeling. 

EPA’s methodology would thus reduce 

the visibility benefit accordingly by 

multiplying the visibility improvement 

at the Class I areas affected by Texas by 

a factor of 0.43. Thus, for example, the 

visibility improvement at Wichita 

Mountains from CSAPR, even after 

increasing Texas’s budget to 350,000 

tons, would be 0.688 deciview [1.6 

deciview × 0.43 = 0.688]. This 

methodology could be applied to other 

budgets as well. Visibility 

improvements at nine Class I areas in or 

around Texas result from the 

application of EPA’s sensitivity analysis 

of a hypothetical adjustment of Texas’s 

CSAPR SO2 budget to 350,000 tons per 

year. Thus, EPA’s own modeling shows 

that visibility at these Class I areas is 

projected to improve (not degrade) and 

that the BART requirements are met 

even if the CSAPR budgets are 

increased. 

Response: We have completed our 

response to the CSAPR remand by 

withdrawing Texas EGUs from CSAPR 

requirements for PM2.5 transport. We 

did not act to upward adjust Texas’ SO2

budget. Whether that was a proper 

response to the remand or whether 

upward adjustments would have 

preserved the analytic demonstration 

that CSAPR is better than BART are not 

issues of concern with the present 

finalized action. To the extent the 

comment asserts that CSAPR budgets 

can be used to support a better than 

BART alternative, we agree with the 

comment and this concept is part of the 


sradovich on DSK3GMQ082PROD with RULES2
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66See October 24, 2005 letter from Al Espinosa, 

Coleto Creek Power Station, #TX187–0023–0001, 

Docket Item No. EPA–R06–OAR–2016–0611–0023 

at p. 6. 

BART alternative and weight of the 

evidence that we deem to justify it. 

Comment: The proposed rule is 

legally dependent on other pending 

proposed rulemakings. EPA may not 

proceed with this action without first 

finalizing other proposed rules under 

the CAA on which this action is based. 

Since 2009, Texas EGUs have been 

subject to federal regulatory programs 

that have resulted in substantial 

reductions in the NOX and SO2

emissions that have been targeted by 

EPA as contributing to interstate 

transport and haze. In compliance with 

EPA rules and precedent, Texas relied 

on CAIR, and then its replacement 

CSAPR as achieving reductions in haze 

precursors from EGUs that are ‘‘better 

than BART’’ in its Texas Regional Haze 

SIP submittal. In the unlawful proposed 

rule, EPA rejects its prior position that 

Texas EGUs are exempt from BART due 

to participation in CSAPR. Yet, Texas 

EGUs continue to this day to be subject 

to CSAPR requirements for NOX and 

SO2. While EPA has proposed to 

withdraw CSAPR SO2 requirements for 

Texas EGUs, it has not yet done so and 

those EGUs remain subject to CSAPR 

allocations for both NOX and SO2 under 

federal and state laws and permits. 

Additionally, EPA’s proposal to 

withdraw the CSAPR FIP with respect 

to SO2 has been challenged in that 

rulemaking docket as unlawful and not 

in accordance with the court decision 

remanding that action to EPA. 

As a result, EPA may not proceed 

with the disapproval of Texas’ reliance 

on CSAPR as ‘‘better than BART’’ until 

such time that the proposal is legally 

finalized in compliance with the Court 

decision that remanded that rule to 

EPA. Once that rule is legally finalized, 

then Texas should be given an 

opportunity to address whether and 

how that affects the state’s regional haze 

program before a FIP is considered. 

Response: As was made clear by our 

proposal, we agree our rule is 

dependent on other proposed and now 

finalized rulemakings. Nothing in our 

proposal or final action prevents Texas 

from addressing the State’s regional 

haze program under its SIP planning 

authorities. Texas did not request that 

we withhold our action to withdraw 

CSAPR SO2 requirements for Texas 

EGUs, and it did not submit comments 

to oppose that action. We disagree that 

anything in the sequencing of actions 

would allow us to suspend our FIP 

obligations when there is no SIP to 

address the requirements. 

Comment: The effort to impose BART 

controls is the result of the proposed 

withdrawal of Texas from the CSAPR 

Phase 2 or annual trading program for 

SO2. Compliance with regional haze 

obligations for BART-eligible facilities 

in Texas has depended on CAIR-equal 

BART and CSAPR-equal BART and 

removing Texas from CSAPR results in 

significant disruption and costs to 

planned future compliance for these 

facilities. EPA seeks these excessive 

controls which will achieve limited 

visibility benefits. EPA should take the 

proper approach and follow the remand 

without vacatur of the D.C. Circuit, 

revise the trading budgets and then 

finalize CSAPR as compliance strategy 

for BART in lieu of this proposal. 

Response: We completed our response 

to the CSAPR remand in a separate 

action and refer Commenter there. We 

are finalizing a BART alternative for SO2

BART. 

E. Comments on the Identification of 

BART-Eligible Sources 

Comment: We received comment from 

the owners of Coleto Creek stating that 

in the Texas Regional Haze SIP, TCEQ 

determined that Coleto Creek Unit 1 was 

not a BART-eligible source, based on its 

interpretation and application of its SIPapproved regional haze rules at 30 TAC 

Chapter 116, Subchapter M. In 

implementing its rules, TCEQ prepared 

questionnaires that sought the 

information needed to render its BARTeligibility determinations.66 As a result 

of this TCEQ-led process, TCEQ 

determined that Coleto Creek Unit 1 was 

not BART-eligible because it was not 

built, and did not commence operation, 

until 1980, which is well after the 

August 7, 1977 applicability date. 

Coleto Creek Unit 1 has reasonably 

relied on the state’s eligibility 

determination in evaluating its 

obligations under the Regional Haze 

Rule program. EPA’s decision to reject 

TCEQ’s BART-eligibility determination 

for Coleto Creek Unit 1 under 30 TAC 

116.1500 is unsupported. 

Response: The commenter states that 

because Coleto Creek Unit 1 did not 

commence operations until 1980, it 

should be determined to be not BARTeligible, as was determined by the 

TCEQ. However, we believe the TCEQ 

erred in not listing Coleto Creek Unit 1 

as being BART-eligible. The date test for 

BART-eligibility is whether the units 

was ‘‘in existence on August 7, 1977,’’ 

and began operation after August 7, 

1962. The BART rule defines as ‘‘in 

existence on August 7, 1977’’ as follows 

(70 FR 39159): 

What does ‘‘in existence on August 7, 

1977’’ mean? 

2. The regional haze rule defines ‘‘in 

existence’’ to mean that: ‘‘the owner or 

operator has obtained all necessary 

preconstruction approvals or permits 

required by Federal, State, or local air 

pollution emissions and air quality laws 

or regulations and either has (1) begun, 

or caused to begin, a continuous 

program of physical on-site construction 

of the facility or (2) entered into binding 

agreements or contractual obligations, 

which cannot be canceled or modified 

without substantial loss to the owner or 

operator, to undertake a program of 

construction of the facility to be 

completed in a reasonable time.’’ 40 

CFR 51.301. 

The owner of Coleto Creek Unit 1 

provided information that onsite 

construction began prior to August 7, 

1977. Thus, Coleto Creek Unit 1 satisfies 

the above criteria as being ‘‘in existence 

on August 7, 1977.’’ Therefore, we 

disagree with the commenter and 

continue to find that Coleto Creek Unit 

1 is BART-eligible. The NOX BART 

requirement for Coleto Creek is met by 

relying on CSAPR as an alternative to 

EGU BART for NOX. The SO2 BART 

requirement is met by the intrastate 

trading program FIP that we are 

finalizing in this action and to which 

Coleto Creek will be subject. The PM 

BART requirement is met by our 

determination that the visibility impacts 

of PM emissions from Coleto Creek are 

too small to be considered to cause or 

contribute to visibility impairment at 

any Class I area and we determined the 

facility screens out and is not subject to 

PM BART. 

F. Comments on PM BART 

We previously proposed to 

disapprove the SIP’s subject-to-BART 

determinations for PM, on the grounds 

that the SIP had based these 

determinations on reliance on a BART 

alternative for SO2 and NOX and, as a 

result, considered only the contribution 

of PM emissions to visibility 

impairment, and to adopt sourcespecific PM emission limits to fill the 

SIP gap. In that context, we received 

several comments related to PM BART 

issues. Now, however, we have 

determined it is appropriate to adopt a 

BART alternative to address SO2 and 

NOX and therefore find Texas’ original 

SIP was correct in considering only the 

contribution of PM emissions. 

Considering only PM emissions, all 

sources considered in the Texas SIP 

were demonstrated to screen out of the 

need for source specific PM BART 

emission limits. 

Also, as explained above, we have 

identified additional sources as BARTeligible that were not considered in the 


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67Regional Haze Regulations and Guidelines for 

Best Available Retrofit Technology (BART) 

Determinations, Joseph Paisie, EPA Geographic 

Strategies Group, July 19, 2006. 

68Technical Support Document for the Texas 

Regional Haze BART Federal Implementation Plan, 

BART FIP TSD, Docket ID No. EPA–R06–OAR– 

2016–0611–004, page 26, footnote 39. 

69 Id, at 82. 

2009 Texas Regional Haze SIP. As 

discussed elsewhere, we have 

determined that the impact due to PM 

emissions from these additional sources 

are also below the BART screen level. 

Thus, the SIP’s determination that none 

of the BART-eligible EGUs are subjectto-BART for PM is correct and 

approvable. As a consequence, there is 

no SIP gap needing to be filled by a FIP. 

Because we are approving EGU PM 

BART screening determinations that 

result in no EGUs being subject to PM 

BART analysis, comments supporting or 

alleging errors in the details of our PM 

BART five-factor analysis and our 

proposed PM BART technology 

selections and emission limits are not 

relevant. We address in this section 

comments that are relevant to whether 

it is appropriate to approve the portion 

of this 2009 SIP submission and EPA’s 

analysis in our proposal that determined 

that no PM emission limits for Texas 

EGUs are needed to satisfy the BART 

requirement because the visibility 

impacts of PM emissions from BARTeligible EGUs do not cause or contribute 

to visibility impairment. The 

information in section III.A. on the 

history of our proposals regarding the 

EGU PM BART element of the 2009 

Texas SIP submission and EPA’s 

proposals is useful background for 

understanding the comments and our 

responses on this topic. 

Although we are not finalizing the 

MATS-based PM limits proposed as PM 

BART for the coal-fired EGUs, this 

regional haze action does not affect the 

existing MATS requirements for these 

units. We are also not finalizing the fuel 

oil sulfur percentage limits that we 

proposed for gas/fuel oil-fired EGUs; the 

same limits in existing permits for these 

sources are not affected by our action. 

Comments: AEP states that we 

provide no basis for not approving the 

TCEQ’s PM BART determination in 

2016 or logical support for our decision 

to proceed with modeling PM in the 

proposed Texas BART FIP. AEP believes 

that when a state is provided statutory 

deference in implementing the Regional 

Haze program, EPA must support its 

decision for not approving the state’s 

determination. While AEP also agrees 

that current PM requirements for 

sources complying with MATS are 

sufficient for meeting PM BART for 

Welsh Unit 1, it disagrees that PM 

BART is even warranted at all or that 

EPA has provided adequate basis for 

declaring that TCEQ’s screening 

analysis is no longer reliable. AEP says 

that buried in a footnote, EPA grasps at 

some claim of error that Texas’ PM 

BART determinations only looked at the 

impact of PM emissions on visibility, 

that Texas can only take this approach 

when the BART requirements of NOX

and SO2 are satisfied, and that Texas’ 

error of not identifying several PM 

BART eligible sources is grounds for 

disapproval. AEP believes this logic is 

unfounded and the situation is created 

by EPA’s piecemeal approach to 

rulemaking. AEP agrees with EPA’s 

conclusion that gas-fired units that 

occasionally burn fuel oil should have 

no further control. AEP will limit 

burning fuel oil with a sulfur content of 

0.7% as currently required by its permit. 

However, EPA has not provided 

sufficient reasons to be addressing PM 

BART. EPA should finalize its earlier 

proposal to approve Texas’ 

determination that sources in Texas are 

not subject to PM BART. 

The Lower Colorado River Authority 

disagrees with the disapproval of the 

Texas PM BART demonstration. 

The TCEQ and the Public Utilities 

Commission of Texas stated that our 

reliance on language in a guidance 

memo 67 to bar TCEQ from conducting 

pollutant-specific modeling to 

determining BART eligibility was 

incorrect. The TCEQ believes this memo 

did not state that the TCEQ’s pollutantspecific modeling is only appropriate 

when BART for other pollutants is 

satisfied with a BART alternative such 

as the CAIR or CSAPR. The TCEQ 

believes the memo states that such 

modeling may be appropriate where an 

alternative program is used for other 

pollutants. The TCEQ also believes we 

incorrectly claimed that its SIP 

acknowledges PM-only modeling is 

inappropriate where an alternative to 

BART is not employed.68

The TCEQ states that our CAMx 

modeling supports the conclusions from 

the screening modeling conducted by it 

that shows these same units did not 

meet the 0.5 deciview (dv) threshold.69

Furthermore, the TCEQ states that we 

found that for gas-fired units, PM 

emissions are ‘‘inherently low,’’ and 

that existing controls plus compliance 

with the MATS filterable PM limit of 

0.03 lb/MMBtu is already BART, further 

supporting its conclusion that there are 

no significant visibility impacts from 

PM emissions from these sources and 

BART controls for PM are unnecessary. 

Thus, the TCEQ reasons, a FIP for PM 

BART is unnecessary and the EPA 

should approve the screening modeling 

the TCEQ conducted, as we proposed to 

do in January 2015. 

Luminant provided comments similar 

to those above. Luminant added that it 

believes that Texas remains in CSAPR 

so there is no basis for us to deviate 

from our prior proposal to approve 

Texas’s PM BART determination. 

Luminant also stated that our reliance 

on a Ninth Circuit Court decision to 

support our rejection of pollutantspecific BART screening is incorrect 

because the case in point relied upon 

the BART de minimis exemption, which 

does not apply in this instance. 

Response: We are approving the EGU 

PM BART element of Texas’s 2009 SIP 

submittal. Under the combination of 

reliance on the CSAPR ozone-season 

NOX trading program to satisfy NOX

BART and reliance on the FIP’s 

intrastate trading program for SO2

emissions to satisfy SO2 BART, it is 

appropriate for determinations of 

whether a BART-eligible EGU is subject 

to BART for PM to be based only on the 

visibility impact of the source’s PM 

emissions. It is not necessary for us to 

respond to the comments stating that a 

PM-only analysis would be appropriate 

even if both SO2 and NOX were not 

addressed by trading programs. 

In particular, TCEQ’s comments are 

correct that the BART Guidelines do not 

prohibit pollutant-specific screening. 

The July 19, 2006 guidance memo states 

that EPA does not generally recommend 

a pollutant-specific screening approach, 

however, such a screening approach 

may be appropriate for PM in certain 

situations. The memo provides the 

situation of a state relying on CAIR for 

NOX and SO2 BART as an example 

where pollutant-specific screening for 

PM may be appropriate. We agree with 

TCEQ that the memo’s intention is not 

to limit PM-only analysis to SIPs that 

rely on CAIR. While we disagree with 

TCEQ’s position that a PM-only analysis 

is appropriate in a situation involving 

source-specific SO2 BART emission 

limits, the approaches promulgated here 

for SO2 and NOX BART are BART 

alternatives and are similar to the CAIR 

situation described in the memo. 

Therefore, we find that the pollutant 

specific PM screening approach in 

TCEQ’s original 2009 SIP submittal is 

appropriate and demonstrates that the 

sources covered by the BART alternative 

program for SO2 screen out of PM 

BART. For BART-eligible EGU sources 

not participating in the BART 

alternative program for SO2, all these 

sources screened out of BART for all 

visibility impairing pollutants utilizing 

model plants and CALPUFF modeling 

as described in our proposed rule and 


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BART Screening TSD. Therefore, we are 

approving the determination that no 

Texas EGUs are required to have sourcespecific PM emission limits in order for 

the BART requirement to be met. This 

approval is consistent with our 

December 2014 proposal for PM BART, 

in which EPA proposed to rely on 

Texas’ CSAPR participation for SO2 and 

NOX BART and to approve the SIP’s 

determinations regarding the need for 

PM emission limits. See 79 FR 74817, 

74848 (January 13, 2015). We are also 

determining that other sources that EPA 

identified in our December 2016 

proposal as BART-eligible that were not 

identified as BART eligible in TCEQ’s 

2009 Regional Haze SIP are also 

screened out from PM BART. 

Comment: The Sierra Club states that 

we should finalize our proposed 

disapproval of Texas’s PM BART 

determinations, which assumed that 

SO2 and NOX emissions contributing to 

PM formation would be regulated under 

CSAPR, see 82 FR at 935. Following the 

D.C. Circuit Court’s remand of CSAPR, 

SO2 emissions from Texas sources are 

no longer limited by CSAPR. The 

assumption underlying Texas’s PM 

BART determinations—that CSAPR 

would limit emissions of PM precursors 

from Texas sources—is now inaccurate; 

therefore, reasons the Sierra Club, we 

must disapprove the State’s PM BART 

determinations. 

Response: We note that the D.C. 

Circuit Court remanded the budget for 

Texas EGUs in the CSAPR trading 

program for SO2 without vacatur, so the 

commenter’s statement that Texas EGUs 

are no longer limited by CSAPR was not 

true at the time the comment was 

offered. It is true now as a result of our 

recent action to remove Texas EGUs 

from the annual SO2 and NOX trading 

programs. However, a large set of Texas 

EGUs will, under the final FIP, be 

subject to CSAPR for ozone-season NOX

and the intrastate trading program FIP 

for SO2. For these EGUs, the BART 

guidelines and our guidance allow for 

the subject-to-BART for PM 

determination to be based on only the 

impacts of PM emissions on visibility. 

For the BART-eligible EGUs that will 

not be required to participate in the 

FIP’s intrastate trading program, our 

analysis indicates that even when all 

three pollutants are included in the 

modeling, all of these sources affect 

visibility at surrounding Class I Areas 

by less than 0.5 dv, thus screening out 

of being subject to PM BART. 

Comment: EPA in its previous 

rulemaking on the reasonable progress 

measures for the Texas and Oklahoma 

regional haze plans initially proposed to 

accept Texas’ finding that no PM BART 

controls were necessary for EGUs 

‘‘based on a screening analysis of the 

visibility impacts from just PM 

emissions . . . .’’ In its current Texas 

BART rulemaking, EPA states that ‘‘[i]n 

connection with changed circumstances 

on how Texas EGUs are able to satisfy 

NOX and SO2 BART, we are now 

proposing to disapprove the portion of 

the Texas Regional Haze SIP that 

evaluated the PM BART requirements 

for EGUs.’’ The changed circumstances 

EPA refers to is the removal of Texas 

sources from the SO2 caps of the CSAPR 

rule. Unless a source is subject to a 

BART alternative or is otherwise 

determined to be exempt from BART for 

a particular pollutant, EPA’s regulations 

and BART guidelines do not generally 

provide for exemptions from a fivefactor BART analysis for a specific 

pollutant. Under EPA’s BART 

Guidelines and the definition of BART, 

once a source has been determined to be 

subject to BART, a five-factor BART 

analysis must be done for each pollutant 

pursuant to 40 CFR part 51, 51.301 and 

Appendix Y, section IV.A. So, EPA is 

correct that it must address BART for 

PM for the BART-subject sources in 

Texas. 

Response: The premise in the 

comment that EGUs in Texas will not be 

subject to a BART alternative for both 

NOX and SO2 is incorrect, given the 

content of this final action. 

Comment: Coleto Creek Unit 1 should 

not be subject to any FIP emission 

limits, because it should not be 

determined to be BART-eligible. 

Response: Texas’ 2009 SIP submission 

did not include Coleto Creek Unit 1 as 

a BART-eligible source and 

consequently the SIP did not present 

any analysis of whether it is subject-toBART, while we are determining in this 

action that Coleto Creek Unit 1 is BARTeligible. However, we evaluated the 

available modeling and other analyses 

and we have concluded that this 

information shows minimal impacts 

from PM from this particular BARTeligible source. Modeled PM impacts 

from Coleto Creek Unit 1 are expected 

to be much less than 0.32 delta 

deciviews (see Section III.4). 

Comment: Requiring the Stryker and 

Graham units to switch to ultra-lowsulfur diesel would significantly 

improve visibility. Requiring this 

switching at Stryker would improve 

visibility by more than 0.5 dv at Caney 

Creek, and switching to ultra-low-sulfur 

diesel at Graham would improve 

visibility by 0.85 dv at Wichita 

Mountains. 

Response: Insofar as this is a comment 

on our proposed source-specific FIP 

emission limits to address BART for 

PM, it is not necessary for us to respond 

because we are approving the SIP and 

not promulgating any such limits in this 

action. We note that the cited visibility 

benefits of switching to low-sulfur fuel 

reflect assumed reductions in both 

direct PM emissions and SO2 emissions 

from these two sources. The Stryker and 

Graham units are both covered by the 

intrastate trading program for SO2 and 

CSAPR for NOX, so it is appropriate that 

the subject-to-BART determination be 

made on the basis of the impacts of 

direct PM emissions alone. Those 

impacts are less than 0.5 dv. 

Comment: Texas identified 126 

sources as BART-eligible or potentially 

BART eligible. 

Yet Texas ultimately concluded that 

no BART-eligible source is subject to 

BART. Texas’s determination is based in 

part on the unsupported selection of 0.5 

dv as the threshold for contribution to 

visibility impairment. EPA must 

disapprove Texas’s determination as to 

the sources subject to BART. Texas 

adopted 0.5 dv as the threshold for 

‘‘contribution’’ to visibility impairment. 

Texas provided no justification for using 

a 0.5 dv threshold. There is no 

documentation in the record as to how 

or why Texas selected this threshold, 

and there is no legal support for such 

threshold. EPA’s BART Guidelines do 

not authorize states automatically to use 

a 0.5 dv contribution threshold. Instead, 

the BART Guidelines state only that 

‘‘any threshold that you use for 

determining whether a source 

‘contributes’ to visibility impairment 

should not be higher than 0.5 deciviews. 

In the next sentence, the Guidelines 

instruct each state that it ‘‘should 

consider the number of emissions 

sources affecting the Class I areas at 

issue and the magnitude of the 

individual sources’ impacts.’’ There is 

no evidence in the record that Texas 

ever conducted this analysis. 

Furthermore, the Guidelines conclude 

that ‘‘a larger number of sources causing 

impacts in a Class I area may warrant a 

lower contribution threshold.’’ As 

Texas’s list of 126 BART eligible sources 

indicates, a large number of sources 

impact the Class I areas in Texas and in 

neighboring states. Indeed, the subset of 

sources that screened out of BART 

based on individual modeling have a 

combined, baseline impact of nearly 10 

deciviews. Thus, the situation in Texas 

is exactly what EPA had in mind when 

it noted that a contribution threshold 

lower than 0.5 dv may be appropriate. 

Had Texas followed the BART 

Guidelines, it may well have selected a 

threshold lower than 0.5 dv. Using a 

lower contribution threshold would 

change Texas’s conclusion as to which 


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70This comment was submitted to a public 

docket (separate from the docket established for this 

action), in response to our December 2014 proposal 

(79 FR 74817, 74853–54 (Dec. 16, 2014)) to approve 

the subject-to-BART determinations in Texas’ 2009 

SIP submission and to disapprove the reasonable 

progress and some other elements of that SIP 

submission. See Docket Item No. EPA–R06–OAR– 

2014–0754–0067. We never took final action on PM 

BART, and did not respond to the comment. We are 

responding to it today because of its relevance to 

this final action. 

71USDA Forest Service, Guidance on the Use of 

the Mesoscale Model Interface Program (MMIF) for 

Air Quality Related Values Long Range Transport 

Modeling Assessments (Aug. 2016). 

sources are subject to BART because 

there are sources with a baseline impact 

just below 0.5 deciviews. EPA has a 

statutory responsibility to ensure that a 

SIP meets all applicable Clean Air Act 

requirements and is supported by the 

record. Here, Texas’s use of a 0.5 dv 

threshold has two fatal flaws: It is not 

based on the analysis prescribed by the 

BART Guidelines, and it is not 

supported by any analysis whatsoever 

in the record. Therefore, EPA must 

disapprove Texas’s conclusions that 

sources are not subject to BART, where 

Texas screened out sources because of a 

visibility impact below 0.5 deciviews.70

Response: EPA’s BART Guidelines 

allow states conducting source-bysource BART determinations to exempt 

sources with visibility impacts as high 

as 0.5 dv. While we agree that a state 

may choose to use a lower threshold, 

this should be based on consideration of 

not only the number of sources, but the 

proximity to the Class I area and the 

potential combined visibility impacts 

from a group of sources. States have the 

discretion within the CAA, Regional 

Haze Rule, and BART Guidelines to set 

an appropriate contribution threshold 

considering the number of emissions 

sources affecting the Class I areas at 

issue and the magnitude of the sources’ 

impacts. 

G. Comments on EPA’s Source-Specific 

SO2 BART Cost Analyses 

Comment: We received a large 

number of comments from the EGU 

owners covered under our proposal and 

environmental groups concerning 

various aspects of the SO2 BART cost 

analyses we performed for the coal-fired 

EGUs. These comments included both 

criticisms of and support for our basic 

approach, the tools we used, and 

various individual aspects of our cost 

analyses. We also received Confidential 

Business Information (CBI) comments 

from the owner of one of the EGUs 

covering the same areas. 

We also received comments from 

environmental groups stating that we 

should have required the gas-fired units 

that occasionally burn fuel oil to 

minimally switch to Ultra-Low-Sulfur 

Diesel (ULSD) in lieu of our proposed 

BART determination that these units be 

limited to 0.7% fuel oil by weight. 

These commenters argued that our 

estimate of the price per gallon for 

ULSD was too high and that in any case, 

the total annual cost to make the switch 

is very low. They also argue that 

requiring the Stryker and Graham units 

to switch to ultra-low-sulfur diesel 

would significantly improve visibility. 

Response: Due to the comments we 

received requesting a BART alternative 

in lieu of source-specific EGU BART 

determinations, we are finalizing a SO2

trading program as an alternative to 

source-by-source BART. As a 

consequence, we believe that comments 

concerning the SO2 BART cost analyses 

we performed on the coal-fired EGUs 

and these gas-fired units that 

occasionally burn fuel oil are no longer 

relevant. The trading program, by its 

nature, provides sources with flexibility 

in meeting the requirements. As a result, 

we expect compliance for sources to be 

extremely cost-effective. The program 

addresses both BART eligible and nonBART eligible EGUs. The combination 

addresses 89% of the emissions (based 

on 2016 annual emissions) that would 

have been addressed by CSAPR and, as 

a result, EGU emissions in Texas will be 

similar to emission levels anticipated in 

the CSAPR better than BART 

demonstration and will achieve greater 

reasonable progress than BART. 

H. Comments on EPA’s Modeling 

1. Modeling Related to Screening out 

BART-eligible sources based on 

CALPUFF Modeling and Model Plant 

analysis 

Comment: We received comments 

stating that we used an outdated version 

of CALPUFF and CALMET in our 

CALPUFF analyses and there are more 

recent EPA approved versions of 

CALPUFF and CALMET. The 

commenter indicated that there are 

more recent non-regulatory versions of 

CALPUFF (such as version 6.4) that 

include a number of technological 

improvements that could have been 

used. The commenter also indicated we 

did not follow USDA Forest Service 

Guidance that recommend using 

Mesocscale Model Interface Program 

(MMIF) for generating met fields for 

CALPUFF.71 The commenter concluded 

that EPA’s CALPUFF analysis was less 

reliable because of these issues. 

Response: For those BART-eligible 

EGUs that are not covered by the BART 

alternative for SO2, we are finalizing 

determinations that those EGUs are not 

subject-to-BART for NOX, SO2 and PM 

as proposed, based on the 

methodologies utilizing model plants 

and CALPUFF modeling as described in 

our proposed rule and BART Screening 

TSD. As mentioned in the BART 

screening TSD, we used versions 

(CALPUFF v5.8.4 and an existing 

CALMET data set that utilized CALMET 

v5.53a) that do not significantly differ 

from the current regulatory versions of 

CALPUFF (v5.8.5) and CALMET 

(v5.8.5). The current regulatory versions 

do include some additional bug fixes 

but the bugs that were fixed are not 

expected to significantly change the 

results for the modeling assessments we 

have done. The 2016 USDA Forest 

Service Guidance was not released until 

August of 2016 and no BART modeling 

was conducted by states and RPOs using 

MMIF. The USDA Forest Service 

Guidance is more germane for future SIP 

developments and any visibility 

analyses for other regulatory 

assessments in the future. 

In considering the comment that we 

should use a more recent version of 

CALPUFF (6.4) or an earlier version 

6.112, we considered the regulatory 

status of CALPUFF for visibility 

analyses and what analyses are needed 

to utilize an updated CALPUFF 

modeling system. The requirements of 

40 CFR 51.112 and 40 CFR part 51, 

Appendix W, Guideline on Air Quality 

Models (GAQM) and the BART 

Guidelines which refers to GAQM as the 

authority for using CALPUFF, provide 

the framework for determining the 

appropriate model platforms and 

versions and inputs to be used. Because 

of concern with CALPUFF’s treatment 

of chemical transformations, which 

affect AQRVs, EPA has not approved the 

chemistry of CALPUFF’s model as a 

‘‘preferred’’ model. The use of the 

regulatory version is approved for 

increment and NAAQS analysis of 

primary pollutants only. Currently, 

CALPUFF Version 5.8, is subject to the 

requirements of GAQM 3.0(b) and as a 

screening model, GAQM 4. CALPUFF 

Versions 6.112 and 6.4 have not been 

approved by EPA for even this limited 

purpose. The versions of CALPUFF, 

version 6.112 or 6.4, that the commenter 

recommended could be used to provide 

modeling analyses of BART eligible 

sources that have not gone through a 

full regulatory review in accordance 

with 40 CFR part 51 Appendix W 

Section 3.2.2. Furthermore, the 

currently available information does not 

support the approval of these versions 

of the CALPUFF model for use in 

making BART determinations. In 

addition, if these versions of the model 


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72 76 FR 52388, 52431–52434 (Aug. 22, 2011). 

73For example, see comment from Andrew Gray, 

Footnote 11, ‘‘For example, Texas used CALPUFF 

to perform BART modeling for Alcoa Inc, 

RN100221472 (nearest Class I area 490 km); 

Equistar Chemicals LP, RN 100542281 (nearest 

Class I area 517 km); ExxonMobil, RN102579307 

and RN102450756 (nearest Class I areas 526 and 

482 km, respectively); and Invista, RN104392626 

and RN102663671 (nearest Class I areas 472 and 

614 km, respectively). See February 25, 2009 Texas 

Regional Haze Plan, Chapter 9 at pages 9–9 through 

9–14, available at https://www.tceq.texas.gov/ 

airquality/sip/bart/haze_sip.html. South Dakota 

used CALPUFF for Big Stone’s BART 

determination, including its impact on multiple 

Class I areas further than 400 km away, including 

Isle Royale, which is more than 600 km away. See 

76 FR 76656. Nebraska relied on CALPUFF 

modeling to evaluate whether numerous power 

plants were subject to BART where the ‘‘Class I 

areas [were] located at distances of 300 to 600 

kilometers or more from’’ the sources. See Best 

Available Retrofit Technology Dispersion Modeling 

Protocol for Selected Nebraska Utilities, p. 3. EPA 

Docket ID No. EPA–R07–OAR–2012–0158–0008. 

EPA has approved reliance on these models.’’ 

74 79 FR 74818 (Dec. 16, 2014). 

75 81 FR 296 (Jan. 5, 2016). 

76We note that the Fifth Circuit Court of Appeals 

remanded the rule in its entirety. See Texas v. EPA, 

829 F.3d 405 (5th Cir. 2016). 

77See comments from Andrew Gray, n 11 (which 

is listed in its entirety earlier in this document) 

citing examples of modeled impacts from sources 

at distances greater than 300 km in Texas, Nebraska, 

and South Dakota. 

78We did iterative modeling with the model 

plants to model emissions at a level that would 

yield a value just under the screening level of 0.5 

Continued 

were acceptable for use, EPA would 

have to reconsider whether using the 

98th percentile impact for determining 

impairment was appropriate. Therefore, 

EPA does not believe the use of 

CALPUFF version 6.112 or 6.4 is 

appropriate for this rulemaking. We 

believe we have made the appropriate 

choice in using CALPUFF version 5.8. 

For further discussion, see our Modeling 

RTC and the response to comments in 

our previous New Mexico Final FIP in 

2011.72

Comment: We received a number of 

comments concerning the acceptable 

distances/range for which CALPUFF 

modeling results should be used for 

BART screening. A number of 

commenters indicated that EPA has 

repeatedly stated that 300 km should be 

the maximum distance for CALPUFF 

modeling results and even cited to some 

past actions (several FIPs—Arkansas, 

Oklahoma, Montana, and New Mexico) 

where EPA has indicated that 300 km 

was the general outer distance for 

CALPUFF. Commenters also raised past 

promulgation of CALPUFF in 2003 and 

IWAQM guidance/reports to support the 

claim that 300 km is the acceptable 

outer range of CALPUFF. TCEQ 

commented we should not use 

CALPUFF for distances beyond 400 km. 

Two commenters indicated that EPA 

had inappropriately reported CALPUFF 

results for distances of 412 km and 

436.1 km, well outside of 300 km. 

Another commenter indicated we 

included some model plants at 

distances greater than 400 km in our 

model plant screening analysis. 

Other commenters indicated that we 

should use the modeling results from 

CALPUFF for BART screening at ranges 

much greater than 400 km. They stated 

that CALPUFF over-predicts visibility 

impacts at distances greater than 300 

km; therefore, CALPUFF is an 

acceptable and conservative tool for 

screening BART sources at large 

distances from Class I areas. We 

received comments from several 

different companies (NRG, LCRA, 

Coleto Creek, and Luminant) that 

provided contractor (AECOM) analysis 

with opinions on the acceptable range of 

CALPUFF. AECOM’s report for LCRA 

included CALPUFF modeling results for 

14 Class I areas with distances out to 

more than 1000 km and asserted that 

TCEQ and EPA had utilized CALPUFF 

previously in screening out sources 

from being subject to a full BART 

analysis in the 2009 Texas regional haze 

SIP submission, our 2014 proposal, and 

our 2015 final action. Some comments 

were supportive of using CALPUFF 

results at distances of 400–1000 + km,73

while others opposed using CALPUFF 

beyond 300 km if the results did not 

screen a facility out of a full BART 

analysis. 

A number of commenters also raised 

concerns with the accuracy of the 

CALPUFF model and several 

uncertainty issues related to the 

CALPUFF model and results from the 

model. We also received the comment 

that CALPUFF’s regulatory status as a 

preferred model recently changed and 

that this change raises a question of 

whether CALPUFF should have been 

used for the Proposed Texas BART FIP. 

Response: As previously discussed 

and included in our record for our 

proposal we did use direct CALPUFF 

modeling results of facilities out to 432 

km for some very large EGU facilities 

(very large emissions from tall stacks). 

We also used CALPUFF for model 

plants for screening of sources beyond 

360 km to a Class I Area, but the actual 

distance to a Class I Area was 360 km 

or less for each of the model plants used 

for screening of sources. In our 2014 

proposed action 74 and the 2015 final 

action 75 on Texas regional haze we 

approved the use of CALPUFF to screen 

BART-eligible non-EGU sources at 

distances of 400 to 614 km for some 

sources. In those actions, we weighed 

the modeling results that were mostly 

well below 0.5 delta-dv with the 

potential uncertainty of CALPUFF 

results at these greater distances outside 

the typical range of CALPUFF in 

deciding how to use the results in 

screening of facilities. We disagree with 

the comment that it was inappropriate 

to rely on CALPUFF to screen BARTeligible EGU sources at ranges beyond 

400 km and that it would not be 

consistent with our past approval of the 

BART screening modeling included in 

the 2009 Texas Regional Haze SIP of 

non-EGU BART sources.76

It has been asserted by the 

commenters that CALPUFF 

overestimates visibility impacts at 

greater distances (greater than 300/400 

km) and therefore some commenters 

claimed that use of CALPUFF is 

conservative and acceptable for 

screening BART sources. We disagree 

with this comment. EPA has seen 

situations of both under-prediction and 

over-prediction at these greater 

distances. EPA has indicated 

historically that use of CALPUFF was 

generally acceptable at 300 km and for 

larger emissions sources with elevated 

stacks. We and FLM representatives 

have also allowed or supported the use 

of CALPUFF results beyond 400 km in 

some cases other than the Texas actions 

as pointed out by commenters.77 EPA 

has a higher confidence level with 

results within 300 km and when 

analysis of impacts at Class I areas 

within 300 km is sufficient to inform 

decisions on BART screening and BART 

determinations, we have often limited 

the use of CALPUFF results to within 

300 km as there are fewer questions 

about the suitability of the results. 

However, that does not preclude the use 

of model results for sources beyond the 

300 km range with some additional 

consideration of relevant issues such as 

stack height, size of emissions, etc. As 

one commenter pointed out, EPA and 

FLM representatives have utilized 

CALPUFF results in a number of 

different situations when the range was 

between 300–450 km. The model plants 

utilized in our model plant screening 

analysis were modeled at distances of 

300–360 km from the Class I area. In our 

model plant analysis, we found that in 

some situations there was a difference 

in whether or not a source screened out 

based on the distance between the 

model plant and the Class I area. Some 

initial model plant runs were done at 

distances of 201–300 km from a Class I 

Area and yielded higher Q/D ratios than 

the same model plant evaluation with 

the same modeled visibility impact at 

350–360 km (only 20% more than 300 

km).78 This difference and the lower Q/ 


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del-dv, typically a value around 0.49 del-dv. In 

these model distance sensitivity runs when we used 

the same number of sources and stack parameters 

but varied the emissions to yield 98th percentile 

max impacts of approximately 0.49 del-dv. We 

found that model plants at 350–360 km range had 

lower resulting Q/Ds than the same model plants 

at 300 km, thus sources more easily screened out 

using model plants at 350–360 km. 

79See our Screening of BART TSD.pdf (EPA-R06- 

OAR-2016-0611-0005.pdf); most sources had Q/D 

values on the order 30–50% of the critical Q/D from 

the model plant. 

80 Id. For example, Big Brown was 404 km from 

WIMO and the maximum impacts with NOX, SO2,

and PM was 4.265 del-dv (over 8 times the 0.5 deldv threshold). 

81For example, see Arkansas FIP, 81 FR 66332, 

66355- 66413 (Sept. 27, 2016) and the Response to 

Comments, Docket No. EPA–R06–OAR–2015–0189. 

82Am. Corn Growers Ass’n v. EPA, 291 F.3d 1 

(D.C. Cir. 2002). 

83 70 FR 39104, 39121 (July 6, 2005). 

84 ‘‘[M]ore recent series of comparisons has been 

completed for a new model, CALPUFF (Section 

A.3). Several of these field studies involved threeto-four hour releases of tracer gas sampled along 

arcs of receptors at distances greater than 50km 

downwind. In some cases, short-term concentration 

sampling was available, such that the transport of 

the tracer puff as it passed the arc could be 

monitored. Differences on the order of 10 to 20 

degrees were found between the location of the 

simulated and observed center of mass of the tracer 

puff. Most of the simulated centerline concentration 

maxima along each arc were within a factor of two 

of those observed.’’ 68 FR 18440, 18458 (April 15, 

2003), 2003 Revisions to Appendix W, Guideline on 

Air Quality Models. 

85 Interagency Workgroup on Air Quality 

Modeling (IWAQM) Phase 2 Summary Report and 

Recommendations for Modeling Long-Range 

Transport Impacts. Publication No. EPA–454/R–98– 

019. Office of Air Quality Planning & Standards, 

Research Triangle Park, NC. 1998. 

86 68 FR 18440, 18458 (Apr. 15, 2003). (2003 

Revisions to Appendix W, Guideline on Air Quality 

Models). 

87 70 FR 39104, 39121 (July 6, 2005). 

88 Id., at 39121. ‘‘Most important, the simplified 

chemistry in the model tends to magnify the actual 

visibility effects of that source. Because of these 

features and the uncertainties associated with the 

model, we believe it is appropriate to use the 98th 

percentile—a more robust approach that does not 

give undue weight to the extreme tail of the 

distribution.’’ 

89 68 FR 18440 (Apr. 15, 2003). 

D modeling for the model plant located 

at a greater distance from the Class I 

area indicated that using the model 

plant modeling at 300 km or less was 

overly conservative when we are 

evaluating facilities at distances of 360– 

600 km. Therefore, we chose the range 

that we thought was appropriate in the 

context of the distances of the sources 

being evaluated with that model plant. 

A distance of 300–360 km also fell 

within a range for which we have 

evaluated CALPUFF results a number of 

times and felt comfortable with using 

for large elevated point sources, and in 

most cases the comparison of Q/D ratios 

of the facility to model plant were not 

similar and the facility screened out 

with a significant safety margin.79

We note that we also had direct 

CALPUFF screening of some coal-fired 

plants out to 412 km with NOX, SO2, 

and PM in our proposal. The impacts of 

these facilities in the proposal screening 

modeling were typically very large and 

well above the 0.5 del-dv, so even 

considering that there are more 

uncertainties at distances greater than 

300 km the impacts were large enough 

that it was clear that these facilities 

would have impacts above the threshold 

based on impacts from the 3 

pollutants.80 The BART Guidelines 

indicate other models may be used on 

a case-by-case basis. CAMx is a 

photochemical modeling platform with 

a full chemistry mechanism that is also 

suited for assessing visibility impacts 

from single facilities/sources at longer 

distances where CALPUFF is more 

uncertain (such as distances much 

greater than 300 km). Texas and EPA 

have previously approved the use of 

CAMx for determining source impacts 

for BART screening purposes, and we 

also decided to supplement our 

CALPUFF analysis for some large coalfired sources with CAMx modeling. Our 

CAMx modeling of these coal-fired 

sources in the proposal further 

supported the magnitude of the assessed 

impacts were well above 0.5 del-dv 

(NOX, SO2, and PM) for these facilities 

that fell into the greater than 300 km 

range. We note that this screening 

modeling for these coal-fired facilities 

directly modeled with CALPUFF 

beyond 300 km and also modeled with 

CAMx is not pertinent to this final 

action since these coal-fired sources are 

participating in the SO2 trading program 

and we are not finalizing subject to 

BART determinations for these sources. 

Due to the comments we received 

requesting a BART alternative in lieu of 

source-specific EGU BART 

determinations, we are finalizing a SO2

trading program as an alternative to 

source-by-source BART. With the NOX

BART coverage from CSAPR, all the 

BART-eligible sources participating in 

the SO2 trading program only have PM 

emissions that have to be assessed for 

screening and potential subject to PM 

BART determinations. As discussed 

elsewhere, we are approving the 

determination in the 2009 Texas 

Regional Haze SIP that PM BART 

emission limits are not required for any 

Texas EGUs. 

We disagree with the commenter’s 

characterization of uncertainties raised 

that invalidate the CALPUFF modeling 

results. We respond to comments raised 

briefly here and in our Modeling RTC. 

We have also responded to a number of 

these issues in our past FIP actions.81

In response to the court’s 2002 finding 

in American Corn Growers Ass’n. v. 

EPA 82 that we failed to provide an 

option for BART evaluations on an 

individual source-by-source basis, we 

had to identify the appropriate 

analytical tools to estimate single-source 

visibility impacts. The 2005 BART 

Guidelines recommended the use of 

CALPUFF for assessing visibility 

(secondary chemical impacts) but noted 

that CALPUFF’s chemistry was fairly 

simple and the model has not been fully 

tested for secondary formation and thus 

is not fully approved for secondaryformed particulate. In the preamble of 

the final 2005 BART guidelines, we 

identify CALPUFF as the best available 

tool for analyzing the visibility effects of 

individual sources, but we also 

recognized that it is a model that 

includes certain assumptions and 

uncertainties.83 Evaluation of CALPUFF 

model performance for dispersion (no 

chemistry) to case studies using inert 

tracers has been performed.84 It was 

concluded from these case studies the 

CALPUFF dispersion model had 

performed in a reasonable manner, and 

had no apparent bias toward over or 

under prediction, so long as the 

transport distance was limited to less 

than 300km.85 86 As discussed above 

EPA has indicated historically that use 

of CALPUFF was generally acceptable at 

300 km and for larger emissions sources 

with elevated stacks we and FLM 

representatives have also allowed or 

supported the use of CALPUFF results 

beyond 400 km in some cases. 

In promulgating the 2005 BART 

guidelines, we responded to comments 

concerning the limitations and 

appropriateness of using CALPUFF.87 In 

the 2005 BART Guidelines the selection 

of the 98th percentile value rather than 

the maximum value was made to 

address concerns that the maximum 

may be overly conservative and address 

concerns with CALPUFF’s limitations.88

In the 2003 revisions to the Guideline 

on Air Quality Models, CALPUFF was 

added as an approved model for long 

range transport of primary pollutants. At 

that time, we considered approving 

CALPUFF for assessing the impact from 

secondary pollutants but determined 

that it was not appropriate in the 

context of a PSD review because the 

impact results could be used as the sole 

determinant in denying a permit.89

However, the use of CALPUFF in the 

context of the Regional Haze rule 

provides results that can be used in a 

relative manner and are only one factor 

in the overall BART determination. We 

determined the visibility results from 

CALPUFF could be used as one of the 


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90 70 FR 39104, 39123–24 (July 6, 2005). ‘‘We 

understand the concerns of commenters that the 

chemistry modules of the CALPUFF model are less 

advanced than some of the more recent atmospheric 

chemistry simulations. To date, no other modeling 

applications with updated chemistry have been 

approved by EPA to estimate single source 

pollutant concentrations from long range 

transport,’’ and in discussion of using other models 

with more advanced chemistry, ‘‘A discussion of 

the use of alternative models is given in the 

Guideline on Air Quality in appendix W, section 

3.2.’’ 

91For example, see Comparison of Single-Source 

Air Quality Assessment Techniques for Ozone, 

PM2.5, other Criteria Pollutants and AQRVs, 

ENVIRON, September 2012; and Anderson, B., K. 

Baker, R. Morris, C. Emery, A. Hawkins, E. Snyder 

‘‘Proof-of-Concept Evaluation of Use of 

Photochemical Grid Model Source Apportionment 

Techniques for Prevention of Significant 

Deterioration of Air Quality Analysis 

Requirements’’ Presentation for Community 

Modeling and Analysis System (CMAS) 2010. 

Annual Conference, (October 11–15, 2010) can be 

found at http://www.cmascenter.org/conference/ 

2010/agenda.cfm. 

92 82 FR 5182, 5196 (Jan. 17, 2017). ‘‘As detailed 

in the preamble of the proposed rule, it is important 

to note that the EPA’s final action to remove 

CALPUFF as a preferred appendix A model in this 

Guideline does not affect its use under the FLM’s 

guidance regarding AQRV assessments (FLAG 2010) 

nor any previous use of this model as part of 

regulatory modeling applications required under 

the CAA. Similarly, this final action does not affect 

the EPA’s recommendation [See 70 FR 39104, 

39122–23 (July 6, 2005)] that states use CALPUFF 

to determine the applicability and level of best 

available retrofit technology in regional haze 

implementation plans.’’ 

five factors in a BART evaluation and 

the impacts should be utilized 

somewhat in a relative sense because 

CALPUFF was not explicitly approved 

for full chemistry calculations.90 We 

note that since the BART Guidelines 

were finalized in 2005 there has been 

more modeling with CALPUFF for 

BART and PSD primary impact 

purposes and the general community 

has utilized CALPUFF in the 300–450 

km range many times (a number of 

examples were pointed out by a 

commenter) and EPA and FLM 

representatives have weighed the 

additional potential uncertainties with 

the magnitude of the modeled impacts 

in comparison to screening/impact 

thresholds on a case-by-case basis in 

approving the use of CALPUFF results 

at these extended ranges. 

We disagree with the commenter’s 

general statement that there is an 

acknowledged over-prediction of the 

CALPUFF model or an acknowledged 

inaccuracy at low impact levels, and 

that the actual visibility impacts from 

the BART sources are lower. The 

CALPUFF model can both under-predict 

and over-predict visibility impacts 

when compared to predicted visibility 

impacts from photochemical grid 

models. See our Modeling RTC for more 

detailed response.91

CALPUFF visibility modeling, 

performed using the regulatory 

CALPUFF model version and following 

all applicable guidance and EPA/FLM 

recommendations, provides a consistent 

tool for comparison with the 0.5 dv 

subject-to-BART threshold. The 

CALPUFF model, as recommended in 

the BART guidelines, has been used for 

almost every single-source BART 

analysis in the country and has 

provided a consistent basis for assessing 

the degree of visibility benefit 

anticipated from controls as one of the 

factors under consideration in a five 

factor BART analysis. Since almost all 

states have completed their BART 

analyses and have either approved SIPs 

or FIPs in place, there is a large set of 

available data on modeled visibility 

impacts and benefits for comparison 

with, and this data illuminates how 

those model results were utilized to 

screen out sources and as part of the 

five-factor analysis in making BART 

control determinations. 

The regulatory status of CALPUFF 

was changed in the recent revisions to 

the Guideline on Air Quality Models 

(GAQM) as far as the classification of 

CALPUFF as a preferred model for 

transport of pollutants for primary 

impacts, not impacts based on 

chemistry. The recent GAQM changes 

do not alter the original status of 

CALPUFF as discussed and approved 

for use in the 2005 BART guidelines. 

The GAQM changes indicated that the 

change in model preferred status had no 

impact on the use of CALPUFF for 

BART.92

Comment: We received comments 

stating that we used out-of-date and 

unrealistic emissions for some units, 

which artificially inflate the actual 

visibility impacts. The commenters state 

that the data used is unrealistic due to 

the 2000–2004 time period selected and 

also due to reporting errors to CAMD. 

Had more recent emissions been 

utilized in the screening analysis, these 

units would have been determined to 

not be subject to BART by the various 

screening methods applied by EPA. 

Commenters also state that a common 

sense reading of the Clean Air Act, 

BART regulations, and BART 

Guidelines indicate that the ‘‘subject to 

BART’’ analysis should be based on the 

most recently available emission data, 

which EPA’s subject-to-BART analysis 

does not use. Furthermore, the BART 

Guidelines do not specifically mandate 

the use of the 2000–2004 emission rates. 

Although the BART Guidelines 

recommend that for the purpose of 

screening BART-eligible sources, 

‘‘States use the 24-hour average actual 

emission rate from the highest emitting 

day of the metrological period 

modeled,’’ the BART Guidelines do not 

state that the time period analyzed must 

be restricted to 2000–2004. In fact, in 

the context of analyzing cost effective 

control options, the BART Guidelines 

recommend the use of emissions that 

are a ‘‘realistic depiction of anticipated 

annual emissions for the source.’’ 4 And 

‘‘[i]n the absence of enforceable 

limitations, you calculate baseline 

emissions based upon continuation of 

past practice.’’ 5 EPA must also use 

realistic emissions when determining 

whether a unit causes or contributes to 

visibility impairment for BART. The use 

of 15-year old NOX and SO2 data for 

purposes of evaluating this threshold 

question is illogical and arbitrary and 

capricious. 

We also received comments that 

doubling the annual emissions of PM 

was conservative and we should have 

potentially used maximum heat input to 

estimate PM emission rates for subject 

to BART modeling. We also received 

comments that the values we modeled 

based on CEM data may have included 

emission rates during upset conditions, 

thus the emission rates used may be 

larger than normal operations. 

Response: We note that, as discussed 

elsewhere, we are not making a subjectto-BART determination for those 

sources covered by the SO2 trading 

program. In our final rule, the relevant 

BART requirement for these 

participating units will be encompassed 

by BART alternatives for NOX and SO2

such that we do not deem it necessary 

to finalize subject-to-BART findings for 

these EGUs. In addition, we are 

approving the determination in the 2009 

TX RH SIP that none of these sources 

are subject to BART for PM. Therefore, 

comments concerning the emissions 

utilized in our subject to BART 

modeling for the sources participating 

in the SO2 trading program are no longer 

relevant. For those BART-eligible EGUs 

that are not covered by the BART 

alternative for SO2, we are finalizing 

determinations that those EGUs are not 

subject-to-BART for NOX, SO2 and PM 

as proposed, based on the 

methodologies utilizing model plants 

and CALPUFF modeling as described in 

our proposed rule and BART Screening 

TSD. 

We disagree with the commenter and 

believe using emissions from the 2000– 

2004 period is appropriate for 

determining if a source is subject to 

BART. Our analysis for facilities 

followed the BART Guidelines and was 

consistent with the BART analyses done 

for all BART-eligible sources. The BART 

Guidelines recommend that for the 


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93 40 CFR part 51 Appendix Y, Section III.A.2. 

94 40 CFR part 51 Appendix Y, Section III.A.3. 

purpose of screening BART-eligible 

sources, ‘‘States use the 24-hour average 

actual emission rate from the highest 

emitting day of the metrological period 

modeled’’ unless this rate reflects 

periods start-up, shutdown, or 

malfunction. The emissions estimates 

used in the models are intended to 

reflect steady-state operating conditions 

during periods of high capacity 

utilization. Consistent with this 

guidance, we utilized the 24-hr 

maximum emission rate from the 2000– 

2004 baseline period and modeled using 

2001–2003 meteorological data. We 

based our analysis on the CEM data 

from the baseline period 2000–2004 and 

removed what looked like questionably 

high values that did not occur often as 

they were potentially upset values. As 

discussed elsewhere we did review 

sources to determine if they installed 

controls during the baseline period and 

when that occurred we only looked at 

baseline emission data post controls. We 

received general comments that the 

values we used from CEM data might 

include upset values, but did not 

receive comments that indicated the 

values used were specifically upset 

values during the baseline period and 

should not be used. Facilities did not 

give us specific information to justify 

that the emission rates we used were not 

representative maximum 24-hour 

emission rates during the 2000–2004 

period, so EPA considers the emission 

rates used were acceptable for the BART 

screening process. 

We are not aware of any newly 

installed controls or limitations on 

emissions that have been put in place 

between the 2000–2004 baseline period 

and now for any of the BART-eligible 

sources not participating in the SO2

trading program that would affect the 

potential visibility impact from the 

source. Furthermore, because all these 

sources were shown to have visibility 

impacts less than the 0.5 dv threshold 

using the maximum 24-hr actual 

emissions during the 2000–2004, 

modeling of lower emissions due to any 

new controls or emissions limits would 

also result in the same determination. 

We were also not provided any specific 

information where additional emission 

reductions/controls had been installed 

and resulted in a short-term (24-hour) 

maximum emission rate significantly 

less than modeled at any of these units. 

The overall concern of the 

commenters was that the emissions 

used in the modeling resulted in some 

facilities being subject to a full BART 

analysis, but, as discussed elsewhere, 

we are not finalizing subject to BART 

determinations for the sources 

participating in the SO2 trading 

program. For the sources not 

participating in the trading program, 

they have been screened out with our 

baseline emissions modeling, so 

underlying concerns about emissions 

being high/non-representative would 

not result in any differences to the 

sources being screened out from a full 

BART analysis. 

Comment: We received comments 

that stated that the proposed PM BART 

demonstration by Texas only considered 

PM emissions because SO2 and NOX

emissions were to be controlled through 

an alternative BART program, CAIR. 

Following the same type of approach, 

EPA in this Proposed Rule finds that 

CSAPR for ozone season NOX is better 

than BART. However, for the screen 

modeling used in the development of 

this Proposed Rule, instead of setting 

the NOX emission rate consistent with 

CSAPR, EPA uses the maximum 24- 

hour NOX emission rates from the 2000– 

2004 time period. EPA ignores the 

continued application of CSAPR ozone 

season budgets that apply to EGUs in 

Texas. This methodology is inconsistent 

with past practices and overestimates 

cumulative conditions and facility 

impacts. Commenters also state that 

because NOX is to be controlled by 

CSAPR, NOX related haze impacts 

should not be considered in the 

screening analysis. 

Response: As discussed in our 

response to another comment, the 

emission rates used in the modeling 

should reflect maximum 24-hour 

emission rates from the baseline period. 

CSAPR for ozone season NOX is a 

seasonal NOX budget but does not 

effectively limit short-term emission 

rates such that a newer maximum 24- 

hour emission rate can be determined. 

Therefore, even if it were appropriate to 

consider any potential reductions due to 

CSAPR, it is not possible to accurately 

model any reductions/limits due to 

CSAPR on a short term basis. 

Furthermore, emissions from a unit can 

vary greatly over time as the CSAPR 

program allows sources to meet 

emission budgets in a given year by 

using banked allowances from previous 

years or by purchasing allowances from 

other sources within or outside of the 

State allowing emissions from the 

source to exceed their annual allocation 

level. We also note that we were not 

provided specific short-term emission 

rate limits from commenters that were 

based on the installation of new controls 

or other reductions that were permanent 

reductions to short-term emission rates. 

Our proposal did assess if emission 

controls were installed during the base 

period and we utilized the maximum 

short-term emission rate from the base 

period after the controls were installed 

where applicable. Regardless of this 

issue, the underlying concern of the 

commenters was whether their facility 

screened out of being subject to a full 

BART analysis. With CSAPR coverage 

for NOX and the SO2 intrastate trading 

program coverage for BART for all 

BART-eligible coal-fired EGUs, and 

several BART-eligible gas-fired and gas/ 

fuel oil-fired EGUs, all the BART 

eligible units screen out of a full BART 

analysis for the pollutants not covered 

by trading programs, thus the chief 

concern that the modeling based on 

2000–2004 maximum emissions and the 

inclusion of NOX contributed to a 

determination that the source was 

subject-to-BART, is no longer relevant. 

Concerning the inclusion of NOX

emissions in the screening analysis, 

EPA’s position is that the modeling 

must include both pollutants (NOX and 

SO2) since they both compete for 

ammonia. If we modeled only SO2, all 

of it would convert to ammonia sulfate 

(based on ammonia availability) and 

both baseline screening impacts for SO2

and visibility benefits from any control 

assessments would also be 

overestimated. The chemical interaction 

between pollutants and background 

species can lead to situations where the 

reduction of emissions of a pollutant 

can actually lead to an increase or 

inaccurate assessment of the visibility 

impairment, if both NOX and SO2 are 

not included in CALPUFF modeling. 

Therefore, to fully assess the visibility 

benefit anticipated from the use of 

controls, all pollutants should be 

modeled together. 

BART screening modeling would also 

include the PM emissions. BART 

screening is meant to be a conservative 

and inclusive test. We have always 

considered combined NOX, SO2, and 

PM impacts even if the facility had NOX

coverage or stringent NOX controls 

already installed. The BART guidelines 

state ‘‘You must look at SO2, NOX, and 

direct particulate matter (PM) emissions 

in determining whether sources cause or 

contribute to visibility impairment’’ 

unless emissions of these pollutants 

from the source are less than de 

minimis.93 The BART Guidelines then 

provide three modeling options to 

determine which sources and pollutants 

need to be subject to BART: 94 (1) 

Dispersion modeling to ‘‘determine an 

individual source’s impact on visibility 

as a result of its emissions of SO2, NOX

and direct PM emissions’’; (2) model 

plants to exempt individual sources 

with common characteristics as 


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95 40 CFR part 51 Appendix Y, Section IV.D.5 

(emphasis added). 

96EPA Memorandum from Joseph W. Paisie 

OAQPS to Kay Prince EPA Region 4, ‘‘Regional 

Haze Regulations and Guidelines for Best Available 

Retrofit Technology (BART) Determinations’’, July 

19, 2006. 

97 40 CFR part 51 Appendix Y, Section III.A.3. 

98See first example in 40 CFR part 51 Appendix 

Y, Section II.A.4. 

described in our BART Screening TSD; 

and (3) cumulative modeling on a 

pollutant by pollutant basis or for all 

visibility-impairing pollutants to show 

that no source in the State is subject to 

BART. The BART guidelines are clear 

that individual source modeling should 

evaluate impacts from NOX, SO2 and 

PM in determining if a source is subject 

to BART and the pollutant-specific 

analyses are directed as an option to 

screen out the impacts of all BART 

sources in the State for a specific 

pollutant such as VOC or PM (in the 

case of EGUs covered by trading 

programs for NOX and SO2). The BART 

Guidelines also state that in assessing 

the visibility benefits of controls 

‘‘modeling should be conducted for SO2,

NOX, and direct PM emissions (PM2.5

and/or PM10).’’ 95 In many cases a state 

may have only a handful of sources and 

impacts from more linear species (VOC 

or PM) may be so small that they make 

up a very small contribution (on the 

order of a 0–2% of the NOX and SO2

impacts) to the visibility impacts at a 

Class I Area, therefore it may be 

acceptable to screen out pollutants that 

have a minimal impact. This is not the 

situation with NOX, SO2 and PM 

emissions from EGUs in Texas where 

some EGUs’ PM modeled impacts were 

greater than 0.25 del-dv. EPA’s 2006 

memorandum on this is clear that you 

have to model both (NOX and SO2) 

because of technical and policy 

concerns, and also reiterated that 

pollutant specific analysis was for the 

limited situation of addressing PM 

when a large group of sources had 

BART coverage for the non-linear 

reacting pollutants (NOX and SO2) 

through a BART alternative.96 The 

BART Guidelines specifically indicate 

that NOX, SO2 and PM should be 

modeled together when modeling BART 

eligible units at one facility.97 This is 

similar to the BART eligibility test 

contemplated in the BART guidelines 

where if the emissions from the 

identified units at source exceed a 

potential to emit of 250 tons per year for 

any single visibility-impairing pollutant, 

the source is considered BART-eligible 

and may be subject to a BART review 

for all visibility impairing pollutants.98

As previously discussed the 

commenter’s primary concern with 

regard to the inclusion of NOX was that 

this may have contributed to facilities 

not screening out from a full BART 

analysis. Because, in the final rule, 

trading programs constitute BART 

alternatives for NOX and SO2, the 

facilities that were proposed as subject 

to BART now screen out for the 

pollutants not covered by a trading 

program. 

Comment: We received a comment 

from TCEQ that EPA should screen out 

the Newman facility based on CALPUFF 

modeling or use CAMx to appropriately 

screen Newman and determine its 

visibility impacts. We also received 

comments from the owner of Newman, 

EPEC, stating that the PM and SO2

BART limits for those gas-fired units 

that occasionally burn fuel oil, 

applicable to Newman 2 and 3, of a fuel 

oil sulfur content of 0.7% is acceptable, 

and that Newman 4 is restricted to burn 

only natural gas. EPEC has maintained 

on-site diesel fuel oil with a lesser 

sulfur content as emergency backup fuel 

for testing for preparedness purposes, 

and in the unlikely scenario of a natural 

gas curtailment event or other situation 

that may compromise the steady flow of 

the primary pipeline quality natural gas 

fuel supply. EPEC also notes that these 

units are only permitted to operate 876 

hours per year. 

Response: Based upon the comments 

we received requesting a BART 

alternative in lieu of source-specific 

EGU BART determinations, we are 

finalizing a SO2 trading program as an 

alternative to source-by-source BART. 

We are not finalizing subject-to-BART 

determinations for BART eligible 

sources covered by the BART alternative 

for SO2 and NOX. In our final rule, the 

relevant BART requirement for these 

participating units, including the BARTeligible Newman units, will be satisfied 

by BART alternatives for NOX and SO2

such that we do not deem it necessary 

to finalize subject-to-BART findings for 

these EGUs. In addition, we are 

approving a determination that none of 

these sources are subject to BART for 

PM. Therefore, we do not find it 

necessary to respond to the merits of 

comments concerning screening 

modeling for this source, because the 

outcome of that modeling is not 

dispositive to the source’s inclusion in 

the BART alternative or its allowance 

thereunder. See discussion above for 

assessment of previous CAMx PM 

screening (Texas 2009 RH SIP) where 

the Newman source was included in 

Group 2 with a number of other sources 

and screened out from being subject to 

BART for PM. 

Comment: We received comments 

that some of the stack parameters were 

incorrect at facilities in our CALPUFF 

and CAMx modeling. New stack height, 

diameter, velocity values were given for 

some units. 

Response: We reviewed the 

information provided and note that 

some facilities gave contradicting data 

within their comments. For those 

facilities for which we are relying on 

modeling to determine they are not 

subject to BART, we have evaluated 

potential changes where we may have 

had an inaccurate number in our 

proposal modeling. We have determined 

that the impacts from changes to stack 

parameters would be minimal and not 

change our current assessment and 

decisions. 

2. Modeling Related to Whether CoalFired Sources Are Subject to BART 

Comment: We received comments on 

the CALPUFF and CAMx modeling 

utilized to determine which coal-fired 

EGUs are subject to BART. These 

included comments concerning 

emissions inputs, the metrics used, the 

post-processing methodology, and the 

model performance. 

Response: Due to the comments we 

received requesting a BART alternative 

in lieu of source-specific EGU BART 

determinations, we are finalizing a SO2

trading program as an alternative to 

source-by-source BART. This trading 

program includes participation of all 

BART-eligible coal-fired EGUs such that 

we do not deem it necessary to finalize 

subject-to-BART findings for these EGUs 

except for PM emissions. As a 

consequence, we believe that it is not 

necessary to respond to the merits of 

comments concerning modeled baseline 

visibility impacts using CALPUFF or 

CAMx and determination of which coalfired sources are subject to BART. In 

this final action we are approving the 

determination in the Texas RH SIP that 

all EGU sources screen out of BART for 

PM. We are also finalizing the 

determination that all BART-eligible 

EGUs not participating in the trading 

program screen out of BART for NOX, 

SO2 and PM based on upon CALPUFF 

modeling (direct source and Model 

Plant). We address all comments 

pertinent to the use of CALPUFF (direct 

source and Model Plant) for BART 

screening for these sources in other 

responses to comments. We note that 

the comments expressing concerns 

about CALPUFF modeling were 

associated with facilities that did not 

screen out from a full subject to BART 

analysis. Since we have determined that 

no EGU sources are now subject to 

BART and a source-specific BART 

control analysis for pollutants not 

covered by a BART alternative, the 


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99 40 CFR part 51 Appendix Y, Section III.A.1. 

100See Docket Item No. EPA–R06–OAR–2016– 

0611–0070, p. 3. 

101 40 CFR 51.308(e)(4); see also generally 77 FR 

33641 (June 7, 2012). Legal challenges to the 

CSAPR-better-than-BART rule from conservation 

groups and other petitioners are pending. Utility Air 

specific concerns raised by commenters 

about being determined to be subject to 

a BART control analysis because of 

emissions inputs used, metrics used, 

etc. are not relevant to this final action. 

See the Modeling RTC document for the 

entirety of the modeling comments and 

our responses. 

Comment: The 0.5 dv threshold used 

by EPA in its proposed determinations 

based on CAMx modeling of what 

sources are subject to BART is too low, 

given the uncertainties in the CAMx 

modeling methods used to quantify the 

visibility impacts of sources. 

Response: In our proposed action, we 

utilized CAMx modeling to evaluate 

visibility impacts from BART-eligible 

sources that include BART eligible coalfired EGUs. Due to the comments we 

received requesting a BART alternative 

in lieu of source-specific EGU BART 

determinations, we are finalizing a SO2

trading program as an alternative to 

source-by-source BART. This trading 

program includes participation of all 

BART-eligible coal-fired EGUs such that 

we do not deem it necessary to finalize 

subject-to-BART findings for these 

sources except for PM emissions. 

In this final action the only CAMx 

modeling we are relying upon is CAMx 

modeling performed for TCEQ in 

screening of EGU emissions of PM that 

was included in TCEQ’s 2009 SIP. Our 

approval of the CAMx PM screening of 

EGUs is based on the original CENRAP 

modeling datasets, agreed modeling 

protocols and Texas’ use of the 0.5 deldv to screen sources as agreed upon by 

TCEQ in 2007. Any potential concerns 

with CAMx bias were considered in 

2007 and TCEQ, EPA and FLM 

representatives agreed to the approach 

of using 0.5 del-dv to screen groups of 

sources using CAMx modeling. We note 

that the BART guidelines specifically 

state that ‘‘as a general matter, any 

threshold that you use for determining 

whether a source ‘‘contributes’’ to 

visibility impairment should not be 

higher than 0.5 deciviews.’’ 99

Furthermore, our action on the PM 

BART determinations in the 2009 Texas 

SIP submittal would not be any different 

had we used a higher threshold since all 

sources screened out based on the use 

of the 0.5 dv threshold. Since we are not 

relying on the CAMx modeling we had 

performed for our proposal, any 

comments concerning the use of this 

modeling are not pertinent to this final 

action and it is not necessary to respond 

to the merits of those comments. 

3. Modeling Related to Visibility Benefit 

of Sources Subject-to-BART 

Comment: We received comments on 

the CALPUFF and CAMx modeling 

utilized to estimate the visibility 

benefits of controls. These included 

comments concerning the emissions 

inputs, the metrics used, the postprocessing methodology, and the model 

performance. 

Response: Based on the comments we 

received requesting a BART alternative 

in lieu of source-specific EGU BART 

determinations, we are finalizing a SO2

trading program as an alternative to 

source-by-source BART. This trading 

program includes participation of all 

BART-eligible coal-fired EGUs and a 

number of BART-eligible gas or gas/fuel 

oil-fired EGUs. It also includes a 

number of non-BART eligible EGUs. 

The combination of the source coverage 

for this program, the total allocations for 

EGUs covered by the program, and 

recent and foreseeable emissions from 

EGUs not covered by the program will 

result in future EGU emissions in Texas 

that are similar to the SO2 emission 

levels forecast in the 2012 better-thanBART demonstration for Texas EGU 

emissions assuming CSAPR 

participation. We are not finalizing our 

evaluation of whether individual 

sources are subject to BART. As a 

consequence, we believe that it is not 

necessary to respond to the merits of 

comments concerning source-specific 

visibility benefits of controls on these 

units, because we are not finalizing 

requirements based on those controls. 

I. Comments on Affordability and Grid 

Reliability 

Comment: We received comments 

from the State, EGU owners covered 

under our proposal and environmental 

groups concerning whether our proposal 

would cause EGUs to retire and thus 

cause grid reliability issues. These 

comments included both criticisms of 

and support for our proposed position. 

Texas, in particular, stated that recent 

ERCOT studies have raised concerns 

that several units in Texas will no 

longer be economically viable if 

required to install capital intensive 

controls. They also indicated that EPA’s 

IPM modeling supports this conclusion. 

Texas believed that if units shutdown 

with little notice it could cause 

reliability concerns. 

Response: EPA takes very seriously 

concerns about grid reliability. We are 

finalizing a SO2 trading program as an 

alternative to source-by-source BART. 

We believe the program we have 

designed will help address reliability 

concerns because it does not require 

installation of capital intensive controls 

and will provide much more flexibility 

to sources than the source by source 

compliance we proposed. In fact, 

aggregate emissions of the covered 

sources in 2016 were below the level 

called for by the trading program. In 

addition, the supplemental allowance 

pool is expected to provide additional 

flexibility to allow sources to run, if 

necessary, in an emergency. We believe 

that it is not necessary to respond on the 

merits to specific comments concerning 

the impacts to grid reliability related to 

the requirements of the proposed 

source-specific controls, because we are 

not finalizing those requirements. 

V. SO2 Trading Program and Its 

Implications for Interstate Visibility 

Transport, EGU BART, and Reasonable 

Progress 

The Regional Haze Rule provides each 

state with the flexibility to adopt an 

allowance trading program or other 

alternative measure instead of requiring 

source-specific BART controls, so long 

as the alternative measure is 

demonstrated to achieve greater 

reasonable progress than BART. As 

discussed in Section III.A.3 above, 

based principally on comments 

submitted by the State of Texas during 

the comment period urging us to 

consider as a BART alternative the 

concept of system-wide emission caps 

using CSAPR allocations as part of an 

intrastate trading program,100 we are 

acknowledging the State’s preference 

and exercising our authority to 

promulgate a BART alternative for SO2

for certain Texas EGUs. The 

combination of the source coverage for 

this program, the total allocations for 

EGUs covered by the program, and 

recent and foreseeable emissions from 

EGUs not covered by the program will 

result in future EGU emissions in Texas 

that are similar to what was forecast in 

the 2012 better than BART 

demonstration for Texas EGU emissions 

assuming CSAPR participation. 

A. Background on the CSAPR as an 

Alternative to BART Concept 

In 2012, the EPA amended the 

Regional Haze Rule to provide that 

participation by a state’s EGUs in a 

CSAPR trading program for a given 

pollutant—qualifies as a BART 

alternative for those EGUs for that 

pollutant.101 In promulgating this 


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Federal Register / Vol. 82, No. 199 / Tuesday, October 17, 2017 / Rules and Regulations 48353 

Regulatory Group v. EPA, No. 12–1342 (D.C. Cir. 

filed August 6, 2012). 

102See Technical Support Document for 

Demonstration of the Transport Rule as a BART 

Alternative, Docket ID No. EPA–HQ–OAR–2011– 

0729–0014 (December 2011) (2011 CSAPR/BART 

Technical Support Document), and memo entitled 

‘‘Sensitivity Analysis Accounting for Increases in 

Texas and Georgia Transport Rule State Emissions 

Budgets,’’ Docket ID No. EPA–HQ–OAR–2011– 

0729–0323 (May 29, 2012), both available in the 

docket for this action. 

103The EPA identified two possible sets of 

‘‘affected Class I areas’’ to consider for purposes of 

the study and found that implementation of CSAPR 

met the criteria for a BART alternative whichever 

set was considered. See 77 FR 33641, 33650 (June 

7, 2012). 

104For additional detail on the 2014 base case, 

see the CSAPR Final Rule Technical Support 

Document, available in the docket for this action. 

105CSAPR was amended three times in 2011 and 

2012 to add five states to the seasonal NOX program 

and to increase certain state budgets. 76 FR 80760 

(Dec. 27, 2011); 77 FR 10324 (Feb. 21, 2012); 77 FR 

34830 (June 12, 2012). The CSAPR-better-thanBART final rule reflected consideration of these 

changes to CSAPR. 

106Units that are subject to CSAPR but that do not 

receive allowance allocations as existing units are 

eligible for a new unit set aside (NUSA) allowance 

allocation. NUSA allowance allocations are a batch 

of emissions allowances that are reserved for new 

units that are regulated by the CSAPR, but weren’t 

included in the final rule allocations. The NUSA 

allowance allocations are removed from the original 

pool of regional allowances, and divided up 

amongst the new units, so as not to exceed the 

emissions cap set in the CSAPR. Each calendar 

year, EPA issues three pairs of preliminary and final 

notices of data availability (NODAs), which are 

determined and recorded in two ‘‘rounds’’ and are 

published in the Federal Register. In any year, if 

the NUSA for a given CSAPR state and program 

does not have enough new units after completion 

of the 2nd round, the remaining allowances are 

allocated to existing CSAPR-affected units. 

107See 40 CFR 97.710 for state SO2 Group 2 

trading budgets, new unit set-asides, Indian country 

new unit set-asides, and variability limits. 

108For the projected annual SO2 emissions from 

Texas EGUs See Technical Support Document for 

Demonstration of the Transport Rule as a BART 

Alternative, Docket ID No. EPA–HQ–OAR–2011– 

0729–0014 (December 2011) (2011 CSAPR/BART 

Technical Support Document), available in the 

docket for this action. at table 2–4. Certain CSAPR 

budgets were increased after promulgation of the 

CSAPR final rule (and the increases were addressed 

in the 2012 CSAPR/BART sensitivity analysis 

memo. See memo entitled ‘‘Sensitivity Analysis 

Accounting for Increases in Texas and Georgia 

Transport Rule State Emissions Budgets,’’ Docket ID 

No. EPA–HQ–OAR–2011–0729–0323 (May 29, 

2012), available in the docket for this action. The 

increase in the Texas SO2 budget was 50,517 tons 

which, when added to the Texas SO2 emissions 

projected in the CSAPR + BART-elsewhere scenario 

of 266,600 tons, yields total potential SO2 emissions 

from Texas EGUs of approximately 317,100 tons. 

109 81 FR 78954 (Nov. 10, 2016) and final action 

signed September 21, 2017 available at 

regulations.gov in Docket No. EPA–HQ–OAR– 

2016–0598. 

110See final action signed September 21, 2017 

available at regulations.gov in Docket No. EPA–HQ– 

OAR–2016–0598. 

CSAPR-better-than-BART rule (also 

referred to as ‘‘Transport Rule as a 

BART Alternative’’), the EPA relied on 

an analytic demonstration based on an 

air quality modeling study 102 showing 

that CSAPR implementation meets the 

Regional Haze Rule’s criteria for a 

demonstration of greater reasonable 

progress than BART. In the air quality 

modeling study conducted for the 2012 

analytic demonstration, the EPA 

projected visibility conditions in 

affected Class I areas 103 based on 2014 

emissions projections for two control 

scenarios and on the 2014 base case 

emissions projections.104 One control 

scenario represents ‘‘Nationwide BART’’ 

and the other represents ‘‘CSAPR + 

BART-elsewhere.’’ In the base case, 

neither BART controls nor the EGU SO2

and NOX emissions reductions 

attributable to CSAPR were reflected. To 

project emissions under CSAPR, the 

EPA assumed that the geographic scope 

and state emissions budgets for CSAPR 

would be implemented as finalized and 

amended in 2011 and 2012.105 The 

results of that analytic demonstration 

based on this air quality modeling 

passed the two-pronged test set forth at 

40 CFR 51.308(e)(3). The first prong 

ensures that the alternative program will 

not cause a decline in visibility at any 

affected Class I area. The second prong 

ensures that the alternative program 

results in improvements in average 

visibility across all affected Class I areas 

as compared to adopting source-specific 

BART. Together, these tests ensure that 

the alternative program provides for 

greater visibility improvement than 

would source-specific BART. 

For purposes of the 2012 analytic 

demonstration that CSAPR as finalized 

and amended in 2011 and 2012 

provides for greater reasonable progress 

than BART, the analysis included Texas 

EGUs as subject to CSAPR for SO2 and 

annual NOX (as well as ozone-season 

NOX). CSAPR’s emissions limitations 

are defined in terms of emissions 

‘‘budgets’’ for the collective emissions 

from affected EGUs in each covered 

state. Sources have the ability to 

purchase allowances from sources 

outside of the state, so total projected 

emissions for a state may, in some cases, 

exceed the state’s emission budget, but 

aggregate emissions from all sources in 

a state should remain lower than or 

equal to the state’s ‘‘assurance level.’’ 

The final emission budget under CSAPR 

for Texas was 294,471 tons per year for 

SO2, including 14,430 tons of 

allowances available in the new unit set 

aside.106 The State’s ‘‘assurance level’’ 

under CSAPR was 347,476 tons.107

Under CSAPR, the projected SO2

emissions from the affected Texas EGUs 

in the CSAPR + BART-elsewhere 

scenario were 266,600 tons per year. In 

a 2012 sensitivity analysis memo, EPA 

conducted a sensitivity analysis that 

confirmed that CSAPR would remain 

better-than-BART if Texas EGU 

emissions increased to approximately 

317,100 tons.108

As introduced in Section I.C, in the 

EPA’s final response to the D.C. 

Circuit’s remand of certain CSAPR 

budgets, we finalized the withdrawal of 

the requirements for Texas’ EGUs to 

participate in the annual SO2 and NOX

trading programs and also finalized our 

determination that the changes to the 

geographic scope of the CSAPR trading 

programs resulting from the remand 

response do not affect the continued 

validity of participation in CSAPR as a 

BART alternative. This determination 

that CSAPR remains a viable BART 

alternative despite changes in 

geographic scope resulting from EPA’s 

response to the CSAPR remand was 

based on a sensitivity analysis of the 

2012 analytic demonstration used to 

support the original CSAPR as betterthan-BART rulemaking. A full 

explanation of the sensitivity analysis is 

included in the remand response 

proposal and final rule.109

B. Texas SO2 Trading Program 

Texas is no longer in the CSAPR 

program for annual SO2 emissions and 

accordingly cannot rely on CSAPR as a 

BART alternative for SO2 under 

51.308(e)(4).110 Therefore, informed by 

the TCEQ comments, we are proceeding 

to address the SO2 BART requirement 

for coal-fired, some gas-fired, and some 

gas/fuel oil-fired units under a BART 

alternative, which we are justifying 

according to the demonstration 

requirements under 51.308(e)(2). 

1. Identification of Sources Participating 

in the Trading Program 

Under 51.308(e)(2), a State may opt to 

implement or require participation in an 

emissions trading program or other 

alternative measure rather than to 

require sources subject to BART to 

install, operate, and maintain BART. 

Such an emissions trading program or 

other alternative measure must achieve 

greater reasonable progress than would 

be achieved through the installation and 

operation of BART. At the same time, 

the Texas trading program should be 

designed so as not to interfere with the 

validity of existing SIPs in other states 

that have relied on reductions from 

sources in Texas. As discussed 

elsewhere, the Texas trading program is 

designed to provide the measures that 

are needed to address interstate 

visibility transport requirements for 

several NAAQS and to be part of the 

long-term strategy needed to meet the 

reasonable progress requirements of the 


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48354 Federal Register / Vol. 82, No. 199 / Tuesday, October 17, 2017 / Rules and Regulations 

111EPA is not determining at this time that this 

final action fully resolves the EPA’s outstanding 

obligations with respect to reasonable progress that 

resulted from the Fifth Circuit’s remand of our 

reasonable progress FIP. We intend to take future 

action to address the Fifth Circuit’s remand. 

112 Dynegy purchased the Coleto Creek power 

plant from Engie in February, 2017. Note that 

Coleto Creek may still be listed as being owned by 

Engie in some of our supporting documentation 

which was prepared before that sale. 

113See the BART FIP TSD, available in the docket 

for this action (Document Id: EPA–R06–OAR–2016– 

0611–0004), for evaluation of the performance of 

scrubbers on Fayette Units 1 and 2. 

114The annual average emission rate for 2016 for 

this unit was 0.01 lb/MMBtu. 

115Parish Units 5 and 6 are coal-fired BARTeligible units. Parish Unit 7 is not BART-eligible, 

but is a co-located coal-fired EGU. Unlike Parish 

Unit 8, these three units do not have an SO2

scrubber installed. 

116The annual average emission rate for 2016 for 

J K Spruce Units 1 and 2 was 0.03 lb/MMBtu and 

0.01 lb/MMBtu, respectively. The annual average 

emission rate for 2016 for J T Deely Units 1 and 2 

was 0.52 lb/MMBtu and 0.51 lb/MMBtu, 

respectively. 

Regional Haze Rule.111 To meet all of 

these goals, the trading program must 

not only be inclusive of all BARTeligible sources that are treated as 

satisfying the BART requirements 

through participation in a BART 

alternative, but must also include 

additional emission sources such that 

the trading program as a whole can be 

shown to both achieve greater 

reasonable progress than would be 

achieved through the installation and 

operation of BART, and achieve the 

emission reductions relied upon by 

other states during consultation and 

assumed by other states in their own 

regional haze SIPs, including their 

reasonable progress goals for their Class 

I areas. 

The identification of EGUs in the 

trading program necessarily begins with 

the list of BART-eligible EGUs for which 

we intend to address the BART 

requirements through a BART 

alternative. As discussed elsewhere, we 

determined that several BART-eligible 

gas-fired and gas/oil-fired EGUs are not 

subject-to-BART for NOX, SO2, and PM, 

therefore those BART-eligible sources 

are not included in the trading program. 

The table below lists those BARTeligible EGUs identified for 

participation in the trading program. 

TABLE 4—BART-ELIGIBLE EGUS PARTICIPATING IN THE TRADING PROGRAM

Facility Unit 

Big Brown (Luminant) ..................... 1. 

Big Brown (Luminant) ..................... 2. 

Coleto Creek (Dynegy 112) .............. 1. 

Fayette (LCRA) ............................... 1. 

Fayette (LCRA) ............................... 2. 

Graham (Luminant) ......................... 2. 

Harrington Station (Xcel) ................ 061B. 

Harrington Station (Xcel) ................ 062B. 

J T Deely (CPS Energy) ................. 1. 

J T Deely (CPS Energy) ................. 2. 

Martin Lake (Luminant) ................... 1. 

Martin Lake (Luminant) ................... 2. 

Martin Lake (Luminant) ................... 3. 

Monticello (Luminant) ...................... 1. 

Monticello (Luminant) ...................... 2. 

Monticello (Luminant) ...................... 3. 

Newman (El Paso Electric) ............. 2. 

Newman (El Paso Electric) ............. 3. 

Newman (El Paso Electric) ............. 4. 

O W Sommers (CPS Energy) ......... 1. 

O W Sommers (CPS Energy) ......... 2. 

TABLE 4—BART-ELIGIBLE EGUS PARTICIPATING IN THE TRADING PROGRAM—Continued 

Facility Unit 

Stryker Creek (Luminant) ................ ST2. 

WA Parish (NRG) ........................... WAP4. 

WA Parish (NRG) ........................... WAP5. 

WA Parish (NRG) ........................... WAP6. 

Welsh Power Plant (AEP) ............... 1. 

Welsh Power Plant (AEP) ............... 2. 

Wilkes Power Plant (AEP) .............. 1. 

Wilkes Power Plant (AEP) .............. 2. 

Wilkes Power Plant (AEP) .............. 3. 

For a BART alternative that includes 

an emissions trading program, the 

applicability provisions must be 

designed to prevent any significant 

potential shifting within the state of 

production and emissions from sources 

in the program to sources outside the 

program. Shifting would be logistically 

simplest among units in the same 

facility, because they are under common 

management and have access to the 

same transmission lines. In addition, 

since a coal-fired EGU to which 

electricity production could shift would 

have a relatively high SO2 emission rate 

(compared to a gas-fired EGU), such 

shifting could also shift substantive 

amounts of SO2 emissions. To prevent 

any significant shifting of generation 

and SO2 emissions from participating 

sources to non-participating sources 

within the same facility, coal-fired EGUs 

that are not BART-eligible but are colocated with BART-eligible EGUs have 

been included in the program. While 

Fayette Unit 3, WA Parish Unit 8 

(WAP8), and J K Spruce Units 1 and 2 

were identified as coal-fired units that 

are not BART-eligible but are co-located 

with BART-eligible EGUs, these units 

have scrubbers installed to control SO2

emissions such that a shift in generation 

from the participating units to these 

units would not result in a significant 

increase in emissions. Fayette Unit 3 

has a high performing scrubber similar 

to the scrubbers on Fayette Units 1 and 

2,113 and has a demonstrated ability to 

maintain SO2 emissions at or below 0.04 

lbs/MMBtu.114 We find that any shifting 

of generation from the participating 

units at the facility to Fayette Unit 3 

would result in an insignificant shift of 

emissions. The scrubber at Parish Unit 

8 maintains an emission rate four to five 

times lower than the emission rate of 

the other coal-fired units at the facility 

(Parish Units 5, 6, and 7) that are 

uncontrolled.115 Shifting of generation 

from the participating units at the Parish 

facility to Parish Unit 8 would result in 

a decrease in overall emissions from the 

source. Similarly, J K Spruce Units 1 

and 2 have high performing scrubbers 

and emit at emission rates much lower 

than the co-located BART-eligible coalfired units (J T Deely Units 1 and 2).116

In addition, because these units not 

covered by the program are on average 

better controlled for SO2 than the 

covered sources and emit far less SO2

per unit of energy produced, we 

conclude that in general, based on the 

current emission rates of the EGUs, 

should a portion of electricity 

generation shift to those units not 

covered by the program, the net result 

would be a decrease in overall SO2

emissions, as these non-participating 

units are on average much better 

controlled. Relative to current emission 

levels, should participating units 

increase their emissions rates and 

decrease generation to comply with 

their allocation, emissions from nonparticipating units may see a small 

increase. Therefore, we have not 

included Fayette Unit 3, WA Parish 

Unit 8 (WAP8), and J K Spruce Units 1 

and 2 in the trading program. The table 

below lists those coal-fired units that are 

co-located with BART-eligible units that 

have been identified for inclusion in the 

trading program. 

TABLE 5—COAL-FIRED EGUS CO-LOCATED WITH BART-ELIGIBLE EGUS

AND PARTICIPATING IN THE TRADING

PROGRAM

Facility Unit 

Harrington Station (Xcel) ................ 063B. 

WA Parish (NRG) ........................... WAP7. 

Welsh Power Plant (AEP) ............... 3. 

In addition to these sources, we also 

evaluated other EGUs for inclusion in 

the trading program based on their 

potential to impact visibility at Class I 

areas. Addressing emissions from 

sources with the largest potential to 

impact visibility is required to make 

progress towards the goal of natural 

visibility conditions and to address 

emissions that may otherwise interfere 


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117See 40 CFR part 51, App. Y, § III (How to 

Identify Sources ‘‘Subject to BART’’). 

118Federal Land Managers’ Air Quality Related 

Values Work Group (FLAG), Phase I Report— 

Revised (2010) Natural Resource Report NPS/ 

NRPC/NRR—2010/232, October 2010. Available at 

http://www.nature.nps.gov/air/Pubs/pdf/flag/FLAG

_2010.pdf. 

119We also note that TCEQ utilized a Q/D 

threshold of 5 in its analysis of reasonable progress 

sources in the 2009 Texas Regional Haze SIP. See 

Appendix 10–1. 

120See the TX RH FIP TSD that accompanied our 

December 2014 Proposed action 79 FR 74818 (Dec 

16, 2014) and 2009statesum_Q_D.xlsx available in 

the docket for that action. 

121 2016 annual SO2 emissions were only 138 tons 

compared to 11,931 tons in 2009. 

122 79 FR 74818 (Dec. 16, 2014). 

123San Miguel Electric Cooperative FGD Upgrade 

Program Update, URS Corporation, June 30, 2014. 

Available in the docket for our December 2014 

Proposed action, 79 FR 74818 (Dec 16, 2014) as 

‘‘TX166–008–066 San Miguel FGD Upgrade 

Program.’’ 

124A boiler operating day (BOD) 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. See 70 FR 

39172 (July 6, 2005). 

with measures required to protect 

visibility in other states. EPA, States, 

and RPOs have historically used a Q/D 

analysis to identify those facilities that 

have the potential to impact visibility at 

a Class I area based on their emissions 

and distance to the Class I area. Where, 

1. Q is the annual emissions in tons 

per year (tpy), and 

2. D is the nearest distance to a Class 

I Area in kilometers (km). 

We used a Q/D value of 10 as a 

threshold for identification of facilities 

that may impact air visibility at Class I 

areas and could be included in the 

trading program in order to meet the 

goals of achieving greater reasonable 

progress than BART and limiting 

visibility transport. We selected this 

value of 10 based on guidance contained 

in the BART Guidelines, which states: 

Based on our analyses, we believe that 

a State that has established 0.5 

deciviews as a contribution threshold 

could reasonably exempt from the 

BART review process sources that emit 

less than 500 tpy of NOX or SO2 (or 

combined NOX and SO2), as long as 

these sources are located more than 50 

kilometers from any Class I area; and 

sources that emit less than 1000 tpy of 

NOX or SO2 (or combined NOX and SO2) 

that are located more than 100 

kilometers from any Class I area.117

The approach described above 

corresponds to a Q/D threshold of 10. 

This approach has also been 

recommended by the Federal Land 

Managers’ Air Quality Related Values 

Work Group (FLAG) 118 as an initial 

screening test to determine if an 

analysis is required to evaluate the 

potential impact of a new or modified 

source on air quality related value 

(AQRV) at a Class I area. For this 

purpose, a Q/D value is calculated using 

the combined annual emissions in tons 

per year of (SO2, NOX, PM10, and 

sulfuric acid mist (H2SO4) divided by 

the distance to the Class I area in km. 

A Q/D value greater than 10 requires a 

Class I area AQRV analysis.119

We considered the results of an 

available Q/D analysis based on 2009 

emissions to identify facilities that may 

impact air visibility at Class I areas.120

The table below summarizes the results 

of that Q/D analysis for EGU sources in 

Texas with a Q/D value greater than 10 

with respect to the nearest Class I area 

to the source. 

TABLE 6—Q/D ANALYSIS FOR TEXAS

EGUS

[Q/D greater than 10, 2009 annual emissions] 

Facility Maximum Q/D 

H.W. Pirkey (AEP) ................ 35.8 

Big Brown (Luminant) ........... 182.9 

Sommers-Deely (CPS) ......... 56.9 

Coleto Creek (Dynegy) ......... 46.0 

Fayette (LCRA) ..................... 61.0 

Gibbons Creek (TMPA) ........ 30.8 

Harrington Station (XCEL) .... 107.8 

San Miguel ............................ 32.9 

Limestone (NRG) .................. 85.1 

Martin Lake (Luminant) ........ 367.4 

Monticello (Luminant) ........... 425.4 

Oklaunion (AEP) ................... 85.0 

Sandow (Luminant) .............. 63.0 

Tolk Station (XCEL) .............. 148.5 

Twin Oaks ............................. 14.2 

WA Parish (NRG) ................. 84.3 

Welsh (AEP) ......................... 230.1 

Based on the above Q/D analysis, we 

identified additional coal-fired EGUs for 

participation in the SO2 trading program 

due to their emissions, proximity to 

Class I areas, and potential to impact 

visibility at Class I areas. While Gibbons 

Creek is identified by the Q/D analysis, 

the facility does not include any BARTeligible EGUs and has installed very 

stringent controls such that current 

emissions are approximately 1% of 

what they were in 2009.121 Therefore, 

we do not consider Gibbons Creek to 

have significant potential to impact 

visibility at any Class I area and do not 

include it in the trading program. The 

Twin Oaks facility, consisting of two 

units, is also identified as having a Q/ 

D greater than 10. However, the Q/D for 

this facility is significantly lower than 

that of the other facilities, the facility 

does not include any BART-eligible 

EGUs, and the estimated Q/D for an 

individual unit would be less than 10. 

We do not consider the potential 

visibility impacts from these units to be 

significant relative to the other coalfired EGUs in Texas with Q/Ds much 

greater than 10 and do not include it in 

the trading program. The Oklaunion 

facility consists of one coal-fired unit 

that is not BART-eligible. Annual 

emissions of SO2 in 2016 from this 

source were 1,530 tons, less than 1% of 

the total annual emissions for EGUs in 

the state. We have determined that the 

most recent emissions from this facility 

are small relative to other non-BART 

units included in the program and we 

have not included Oklaunion in the 

trading program. Finally, San Miguel is 

identified as having a Q/D greater than 

10. The San Miguel facility consists of 

one coal-fired unit that is not BARTeligible. In our review of existing 

controls at the facility performed as part 

of our action to address the remaining 

regional haze obligations for Texas, we 

found that the San Miguel facility has 

upgraded its SO2 scrubber system to 

perform at the highest level (94% 

control efficiency) that can reasonably 

be expected based on the extremely high 

sulfur content of the coal being burned, 

and the technology currently 

available.122 Since completion of all 

scrubber upgrades,123 emissions from 

the facility on a 30-day boiler operating 

day 124 rolling average basis have 

remained below 0.6 lb/MMBtu and the 

2016 annual average emission rate was 

0.44 lb/MMBtu. Therefore, we have 

determined that the facility is well 

controlled and have not included San 

Miguel in the trading program. Other 

coal-fired EGUs in Texas that are not 

included in the trading program either 

had Q/D values less than 10 based on 

2009 emissions or were not yet 

operating in 2009. New units beginning 

operation after 2009 would be permitted 

and constructed using emission control 

technology determined under either 

BACT or LAER review, as applicable 

and we do not consider the potential 

visibility impacts from these units to be 

significant relative to those coal-fired 

EGUs participating in the program. See 

Table 10 and accompanying discussion 

in the section below for additional 

information on coal-fired EGUs not 

included in the trading program. The 

table below lists the additional units 

identified by the Q/D analysis described 

above as potentially significantly 

impacting visibility and are included in 

the trading program. We note that all of 

the other coal-fired units identified for 

inclusion in the trading program due to 

their BART-eligibility or by the fact that 

they are co-located with BART-eligible 

coal units would also be identified for 


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125EPA is not determining at this time that this 

final action fully resolves the EPA’s outstanding 

obligations with respect to reasonable progress that 

resulted from the Fifth Circuit’s remand of our 

reasonable progress FIP. We intend to take future 

action to address the Fifth Circuit’s remand. 

126See Table 3 above for list of participating units 

and identification of BART-eligible participating 

units. 

127Texas v. EPA, 829 F.3d 405 (5th Cir. 2016). 

inclusion in the trading program if the 

Q/D analysis were applied to them. 

TABLE 7—ADDITIONAL UNITS IDENTIFIED FOR INCLUSION IN THE TRADING

PROGRAM

Facility Unit 

H.W. Pirkey (AEP) .......................... 1. 

Limestone (NRG) ............................ 1. 

Limestone (NRG) ............................ 2. 

Sandow (Luminant) ......................... 4. 

Tolk (Xcel) ....................................... 171B. 

Tolk (Xcel) ....................................... 172B. 

As discussed in more detail below, 

the inclusion of all of these identified 

sources (Tables 4, 5, and 7 above) in an 

intrastate SO2 trading program will 

achieve emission levels that are similar 

to original projected participation by all 

Texas EGUs in the CSAPR program for 

trading of SO2 and achieve greater 

reasonable progress than BART. In 

addition to being a sufficient alternative 

to BART, the trading program secures 

reductions consistent with visibility 

transport requirements and is part of the 

long-term strategy to meet the 

reasonable progress requirements of the 

Regional Haze Rule.125 The combination 

of the source coverage for this program, 

the total allocations for EGUs covered 

by the program, and recent and 

foreseeable emissions from EGUs not 

covered by the program will result in 

future EGU emissions in Texas that on 

average will be no greater than what was 

forecast in the 2012 better-than-BART 

demonstration for Texas EGU emissions 

assuming CSAPR participation. 

2. Texas SO2 Trading Program as a 

BART Alternative 

40 CFR 51.308(e)(2) contains the 

required plan elements and analyses for 

an emissions trading program or 

alternative measure designed as a BART 

alternative. 

As discussed above, consistent with 

our proposal, we are finalizing our list 

of all BART-eligible sources, in Texas, 

which serves to satisfy 

§ 51.308(e)(2)(i)(A). 

This action includes a list of all EGUs 

covered by the trading program, 

satisfying the first requirement of 

§ 51.308(e)(2)(i)(B). All BART-eligible 

coal-fired units, some additional coalfired EGUs, and some BART-eligible 

gas-fired and oil-and-gas-fired units are 

covered by the alternative program.126

This coverage and our determinations 

that the BART-eligible gas-fired and oiland-gas-fired EGUs not covered by the 

program are not subject-to-BART for 

NOX, SO2 and PM satisfy the second 

requirement of § 51.308(e)(2)(i)(B). 

Regarding the requirements of 40 CFR 

51.308(e)(2)(i)(C), we are not making 

determinations of BART for each source 

subject to BART and covered by the 

program. The demonstration for a BART 

alternative does not need to include 

determinations of BART for each source 

subject to BART and covered by the 

program when the ‘‘alternative measure 

has been designed to meet a 

requirement other than BART.’’ The 

Texas trading program meets this 

condition, as discussed elsewhere, 

because it has been designed to meet 

multiple requirements other than BART. 

This BART alternative extends beyond 

all BART-eligible coal-fired units to 

include a number of additional coalfired EGUs, and some BART-eligible 

gas-fired and oil-and-gas-fired units, 

capturing the majority of emissions from 

EGUs in the State and is designed to 

provide the measures that are needed to 

address interstate visibility transport 

requirements for several NAAQS. This 

is because for all sources covered by the 

Texas SO2 trading program, those 

sources’ CSAPR allocations for SO2 are 

incorporated into this finalized BART 

alternative, and the BART FIP obtains 

more emission reductions of SO2 and 

NOX than the level of emissions 

reductions relied upon by other states 

during consultation and assumed by 

other states in their own regional haze 

SIPs including their reasonable progress 

goals for their Class I areas. This BART 

alternative, addressing emissions from 

both BART eligible and non-BART 

eligible sources, that in combination 

provides for greater reasonable progress 

than BART, is also designed to be part 

of the long-term strategy needed to meet 

the reasonable progress requirements of 

the Regional Haze Rule, which remain 

outstanding after the remand of our 

reasonable progress FIP by the Fifth 

Circuit Court of Appeals. Since the time 

of our January 4, 2017 proposal on 

BART, we note that the Fifth Circuit 

Court of Appeals has remanded without 

vacatur our prior action on the 2009 

Texas Regional Haze SIP and part of the 

Oklahoma Regional Haze SIP.127 We 

contemplate that future action on this 

remand, including action that may 

merge with new development of SIP 

revisions by the State of Texas as 

contemplated in its request for the SO2

BART alternative, will bring closure to 

the reasonable progress requirement. 

For these reasons, we find that it is not 

necessary for us to make determinations 

of BART for each source subject to 

BART and covered by the program. In 

this context, 51.308(e)(2)(i)(C) provides 

that we may ‘‘determine the best system 

of continuous emission control 

technology and associated emission 

reductions for similar types of sources 

within a source category based on both 

source-specific and category-wide 

information, as appropriate.’’ In this 

action, we are relying on the 

determinations of the best system of 

continuous emission control technology 

and associated emission reductions for 

EGUs as was used in our 2012 

determination that showed that CSAPR 

as finalized and amended in 2011 and 

2012 achieves more reasonable progress 

than BART. These determinations were 

based on category-wide information. 

Regarding the requirement of 40 CFR 

51.308(e)(2)(i)(D), our analysis is that 

the Texas trading program will 

effectively limit the aggregate annual 

SO2 emissions of the covered EGUs to 

be no higher than the sum of their 

allowances. As discussed elsewhere, the 

average total annual allowance 

allocation for covered sources is 238,393 

tons and an additional 10,000 tons for 

the Supplemental Allowance pool. In 

addition, while the Supplemental 

Allowance pool may grow over time as 

unused supplemental allowances 

remain available and allocations from 

retired units are placed in the 

supplemental pool, the total number of 

allowances that can be allocated in a 

control period from the supplemental 

pool is limited to a maximum 54,711 

tons plus the amount of any allowances 

placed in the pool that year from retired 

units and corrections. Therefore, annual 

average emissions for the covered 

sources will be less than or equal to 

248,393 tons with some year to year 

variability constrained by the number of 

banked allowances and number of 

allowances that can be allocated in a 

control period from the supplemental 

pool. The projected SO2 emission 

reduction that will be achieved by the 

program, relative to any selected 

historical baseline year, is therefore the 

difference between the aggregate 

historical baseline emissions of the 

covered units and the average total 

annual allocation. For example, the 

aggregate 2014 SO2 emissions of the 

covered EGUs were 309,296 tons per 

year, while the average total annual 

allocation for the covered EGUs is 


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128Texas sources were subject to CSAPR in 2015 

and 2016 but are no longer subject to CSAPR. We 

therefore select 2014 as the appropriate most recent 

year for this comparison. 

129We note that for other types of alternative 

programs that might be adopted under 40 CFR 

51.308(e)(2), the analysis of achievable emission 

reductions could be more complicated. For 

example, a program that involved economic 

incentives instead of allowances or that involved 

interstate allowance trading would present a more 

complex situation in which achievable emission 

reductions could not be calculated simply be 

comparing aggregate baseline emissions to aggregate 

allowances. 

130 81 FR 78954, 78962 (November 10, 2016) and 

final action signed September 21, 2017 available at 

regulations.gov in Docket No. EPA–HQ–OAR– 

2016–0598. 

248,393 tons/year.128 Therefore, 

compared to 2014 emissions, the Texas 

trading program is projected to achieve 

an average reduction of approximately 

60,903 tons per year.129 We note that the 

trading program allows additional 

sources to opt-in to the program. Should 

sources choose to opt-in in the future, 

the average total annual allocation could 

increase up to a maximum of 289,740. 

For comparison, the aggregate 2014 SO2

emissions of the covered EGUs 

including all potential opt-ins were 

343,425 tons per year. Therefore, 

compared to 2014 emissions, the Texas 

trading program including all potential 

opt-ins is projected to achieve an 

average reduction of approximately 

53,685 tons per year. 

Regarding the requirement of 40 CFR 

51.308(e)(2)(i)(E), the BART alternative 

being finalized today is supported by 

our determination that the clear weight 

of the evidence is that the trading 

program achieves greater reasonable 

progress than would be achieved 

through the installation and operation of 

BART at the covered sources. The 2012 

demonstration showed that CSAPR as 

finalized and amended in 2011 and 

2012 meets the Regional Haze Rule’s 

criteria for a demonstration of greater 

reasonable progress than BART. This 

2012 demonstration is the primary 

evidence that the Texas trading program 

achieves greater reasonable progress 

than BART. However, the states 

participating in CSAPR are now slightly 

different than the geographic scope of 

CSAPR assumed in the 2012 analytic 

demonstration. The changes to states 

participating in both CSAPR NOX

trading programs resulting from EPA’s 

response to the D.C. Circuit’s remand 

were found by us to have no adverse 

impact on the 2012 determination that 

CSAPR participation remains betterthan-BART.130 Regarding SO2 emissions 

from Texas, as detailed below, the 

BART alternative is projected to 

accomplish emission levels from Texas 

EGUs that are similar to the emission 

levels from Texas EGUs that would have 

been realized from the SO2 trading 

program under CSAPR. The changes to 

the geographic scope of the NOX CSAPR 

programs combined with the 

expectation that the Texas trading 

program will reduce the SO2 emissions 

of EGUs in Texas to levels similar to 

CSAPR-participation levels, despite 

slight differences in EGU participation 

between the two SO2 programs, lead to 

the finding here that post-remand 

CSAPR and the Texas BART alternative 

program are better-than-BART for Texas. 

The differences in Texas EGU 

participation in CSAPR and this BART 

alternative are either not significant or, 

in some cases, work to demonstrate the 

relative stringency of the BART 

alternative as compared to CSAPR. If 

Texas EGUs were still required to 

participate in CSAPR’s SO2 trading 

program, it would be plainly consistent 

with previous findings and approvals 

that CSAPR is an acceptable BART 

alternative. The Texas trading program 

will result in emissions from the 

covered EGUs and other EGUs in Texas 

that are no higher than if Texas EGUs 

were still required to participate in 

CSAPR’s SO2 trading program, and thus 

the clear weight of evidence is that the 

Texas trading program will provide 

more reasonable progress than BART. 

Still regarding 40 CFR 51.308(e)(2)(i)(E), 

we have considered the question of 

whether in applying this portion of the 

Regional Haze Rule we should take as 

the baseline the application of sourcespecific BART at the covered sources. 

We interpret the rule to not require that 

approach in this situation, given that 

51.308(e)(2)(i)(C) provides for an 

exception (which we are exercising) to 

the requirement for source-specific 

BART determinations for the covered 

sources. We are not making any sourcespecific BART determinations in this 

action, nor did Texas do so in its 2009 

SIP submission. 

Table 8 below identifies the 

participating units and their unit-level 

allocations under the Texas SO2 trading 

program. These allocations are the same 

as under CSAPR. 

TABLE 8—ALLOCATIONS FOR TEXAS EGUS SUBJECT TO THE FIP SO2 TRADING PROGRAM

Owner/operator Units Allocations 

(tpy) 

AEP ........................................................... Welsh Power Plant Unit 1 ............................................................................................ 6,496 

Welsh Power Plant Unit 2 ............................................................................................ 7,050 

Welsh Power Plant Unit 3 ............................................................................................ 7,208 

H W Pirkey Power Plant Unit 1 ................................................................................... 8,882 

Wilkes Unit 1 ................................................................................................................ 14

Wilkes Unit 2 ................................................................................................................ 2 

Wilkes Unit 3 ................................................................................................................ 3 

CPS Energy .............................................. JT Deely Unit 1 ............................................................................................................ 6,170 

JT Deely Unit 2 ............................................................................................................ 6,082 

Sommers Unit 1 ........................................................................................................... 55 

Sommers Unit 2 ........................................................................................................... 7 

Dynegy ...................................................... Coleto Creek Unit 1 ..................................................................................................... 9,057 

El Paso Electric ........................................ Newman Unit 2 ............................................................................................................ 1 

Newman Unit 3 ............................................................................................................ 1 

Newman Unit 4 ............................................................................................................ 2 

LCRA ........................................................ Fayette/Sam Seymour Unit 1 .......................................................................................

Fayette/Sam Seymour Unit 2 .......................................................................................

7,979 

8,019 

Luminant ................................................... Big Brown Unit 1 .......................................................................................................... 8,473 

Big Brown Unit 2 .......................................................................................................... 8,559

Martin Lake Unit 1 ........................................................................................................ 12,024 

Martin Lake Unit 2 ........................................................................................................ 11,580 

Martin Lake Unit 3 ........................................................................................................ 12,236 

Monticello Unit 1 .......................................................................................................... 8,598 


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131An Indian Country new unit set-aside is 

established for each state under the CSAPR that 

provides allowances for future new units locating in Indian Country. The Indian Country new unit 

set-aside for Texas is 294 tons. See 40 CFR 97.710. 

TABLE 8—ALLOCATIONS FOR TEXAS EGUS SUBJECT TO THE FIP SO2 TRADING PROGRAM—Continued 

Owner/operator Units Allocations 

(tpy) 

Monticello Unit 2 .......................................................................................................... 8,795 

Monticello Unit 3 .......................................................................................................... 12,216 

Sandow Unit 4 .............................................................................................................. 8,370 

Stryker ST2 .................................................................................................................. 145 

Graham Unit 2 .............................................................................................................. 226 

NRG .......................................................... Limestone Unit 1 .......................................................................................................... 12,081 

Limestone Unit 2 .......................................................................................................... 12,293 

WA Parish Unit WAP4 ................................................................................................. 3 

WA Parish Unit WAP5 ................................................................................................. 9,580 

WA Parish Unit WAP6 ................................................................................................. 8,900 

WA Parish Unit WAP7 ................................................................................................. 7,653 

Xcel ........................................................... Tolk Station Unit 171B ................................................................................................. 6,900 

Tolk Station Unit 172B ................................................................................................. 7,062 

Harrington Unit 061B ................................................................................................... 5,361 

Harrington Unit 062B ................................................................................................... 5,255 

Harrington Unit 063B ................................................................................................... 5,055 

Total ................................................... ....................................................................................................................................... 238,393 

The total annual allocation for all 

sources in the Texas SO2 trading 

program is 238,393 tons. In addition, a 

Supplemental Allowance pool initially 

holds an additional 10,000 tons for a 

maximum total annual allocation of 

248,393 tons. The Administrator may 

allocate a limited number of additional 

allowances from this pool to sources 

whose emissions exceed their annual 

allocation, pursuant to 40 CFR 97.912. 

Under CSAPR, the total allocations for 

all existing EGUs in Texas is 279,740 

tons, with a total of 294,471 tons 

including the new unit set aside of 

14,430 tons and the Indian country new 

unit set aside.131 As shown in Table 9 

below, the coverage of the Texas SO2

trading program represents 81% of the 

total CSAPR allocation for Texas and 

85% of the CSAPR allocations for 

existing units. The Supplemental 

Allowance pool contains an additional 

10,000 tons, compared to the new unit 

set aside (NUSA) allowance allocation 

under CSAPR of 14,430 tons. Examining 

2016 emissions, the EGUs covered by 

the program represent 89% of total 

Texas EGU emissions. 

TABLE 9—COMPARISON OF TEXAS SO2 TRADING PROGRAM ALLOCATIONS TO PREVIOUSLY APPLICABLE CSAPR 

ALLOCATIONS AND TO 2016 EMISSIONS

Annual allocations in the 

Texas Trading Program 

(tons per year) 

% of total 

previously applicable 

CSAPR 

allocations 

(294,471 tons per year) 

2016 emissions 

(tons per year) 

Texas SO2 Trading program sources ......................................... 238,393 81 218,291 

Total EGU emissions ................................................................... ........................................ ........................................ 245,737 

Supplemental Allowance pool ..................................................... 10,000 3.4 ........................................

Existing Sources not covered by trading program ...................... * 16 27,446 

* No allocation. 

The remaining 11% of the total 2016 

emissions due to sources not covered by 

the program come from coal-fired units 

that on average are better controlled for 

SO2 than the covered sources (26,795 

tons in 2016) and gas units that rarely 

burn fuel oil (651 tons in 2016). The 

table below lists these coal-fired units. 

The average annual emission rate for 

2016 is 0.50 lb/MMBTU for the coalfired units participating in the trading 

program compared to 0.12 lb/MMBTU 

for the coal-fired units not covered by 

the program. Therefore, we conclude 

that in general, based on the current 

emission rates of the EGUs, should a 

portion of electricity generation shift to 

units not covered by the program, the 

net result would be a decrease in overall 

SO2 emissions, as these nonparticipating units are on average much 

better controlled and emit far less SO2

per unit of energy produced. Relative to 

current emission levels, should 

participating units increase their 

emissions rates and decrease generation 

to comply with their allocation, 

emissions from non-participating units 

may see a small increase. 


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132We note the trading program does allow nonparticipating sources that previously had CSAPR 

allocations to opt-in to the trading program and 

receive an allocation equivalent to the CSAPR level 

allocation. Should some sources choose to opt-in to 

the program, the total number of allowances will 

increase by that amount. 

133For the projected annual SO2 emissions from 

Texas EGUs see Technical Support Document for 

Demonstration of the Transport Rule as a BART 

Alternative, Docket ID No. EPA–HQ–OAR–2011– 

0729–0014 (December 2011) (2011 CSAPR/BART 

Technical Support Document), available in the 

docket for this action, at table 2–4. Certain CSAPR 

budgets were increased after promulgation of the 

CSAPR final rule (and the increases were addressed 

in the 2012 CSAPR/BART sensitivity analysis 

memo), See memo titled ‘‘Sensitivity Analysis 

Accounting for Increases in Texas and Georgia 

Transport Rule State Emissions Budgets,’’ Docket ID 

No. EPA–HQ–OAR–2011–0729–0323 (May 29, 

2012), available in the docket for this action. The 

increase in the Texas SO2 budget was 50,517 tons 

which, when added to the Texas SO2 emissions 

projected in the CSAPR + BART-elsewhere scenario 

of 266,600 tons, yields total potential SO2 emissions 

from Texas EGUs of approximately 317,100 tons. 

TABLE 10—COAL-FIRED EGUS NOT COVERED BY THE TEXAS SO2 TRADING PROGRAM

Previously applicable 

CSAPR allocation 

(tons) 

2016 emissions 

(tons) 

2016 annual average 

emission rate 

(lb/MMBtu) 

Fayette/Sam Seymour Unit 3 ...................................................... 2,955 231 0.01 

Gibbons Creek Unit 1 .................................................................. 6,314 138 0.02 

JK Spruce Unit 1 ......................................................................... 4,133 467 0.03 

JK Spruce Unit 2 ......................................................................... 158 151 0.01 

Oak Grove Unit 1 ......................................................................... 1,665 3,334 0.11 

Oak Grove Unit 2 * ....................................................................... ........................................ 3,727 0.12 

Oklaunion Unit 1 .......................................................................... 4,386 1,530 0.11 

San Miguel Unit 1 ........................................................................ 6,271 6,815 0.44 

Sandow Station Unit 5A .............................................................. 773 1,117 0.11 

Sandow Station Unit 5B .............................................................. 725 1,146 0.10 

Sandy Creek Unit 1 * ................................................................... ........................................ 1,842 0.09 

Twin Oaks Unit 1 ......................................................................... 2,326 1,712 0.21 

Twin Oaks Unit 2 ......................................................................... 2,270 1,475 0.23 

WA Parish Unit WAP8 ................................................................. 4,071 3,112 0.16 

Total ...................................................................................... 36,047 26,795 ........................................

* Oak Grove Unit 2 and Sandy Creek Unit 1 received allocations from the new unit set aside under the CSAPR program. 

The exclusion of a large number of 

gas-fired units that occasionally burn 

fuel oil further limits allowances in the 

program as compared to CSAPR because 

CSAPR allocated these units allowances 

that are higher than their recent and 

current emissions. In 2016, these units 

emitted 651 tons of SO2, but received 

allowances for over 5,000 tons. By 

excluding these sources from the 

program, those unused allowances are 

not available for purchase by other 

EGUs. We note the trading program does 

allow non-participating sources that 

previously had CSAPR allocations to 

opt-in to the trading program and 

receive an allocation equivalent to the 

CSAPR level allocation. Should some 

sources choose to opt-in to the program, 

the total number of allowances will 

increase by that amount. This will serve 

to increase the percentage of CSAPR 

allowances represented by the Texas 

SO2 trading program and increase the 

portion of emissions covered by the 

program, more closely resembling the 

CSAPR program. 

Finally, the Texas SO2 trading 

program does not allow EGUs to 

purchase allowances from sources in 

other states. Under CSAPR, Texas EGUs 

were allowed to purchase allowances 

from other Group 2 states, a fact which 

could, and was projected to, result in an 

increase in annual allowances used in 

the State above the state budget. CSAPR 

also included a variability limit that was 

set at 18% of the State budget and an 

assurance level equal to the State’s 

budget plus variability limit. The 

assurance level for Texas was set at 

347,476 tons. The CSAPR assurance 

provisions are triggered if the State’s 

emissions for a year exceed the 

assurance level. These assurance 

provisions require some sources to 

surrender two additional allowances per 

ton beyond the amount equal to their 

actual emissions, depending on their 

emissions and annual allocation level. 

In effect, under CSAPR, EGUs in Texas 

could emit above the allocation if 

willing to pay the market price of 

allowances and the cost associated with 

each incremental ton of emissions could 

triple if in the aggregate they exceeded 

the assurance level. The Texas trading 

program will have 248,393 tons of 

allowances allocated every year, with no 

ability to purchase additional 

allowances from sources outside of the 

State, preventing an increase beyond 

that annual allocation.132 This includes 

an annual allocation of 10,000 

allowances to the Supplemental 

Allowance pool. The Supplemental 

Allowance pool may grow over time as 

unused supplemental allowances 

remain available and allocations from 

retired units are placed in the 

supplemental pool but the total number 

of allowances that can be allocated in a 

control period from in this 

supplemental pool is limited to a 

maximum 54,711 tons plus the amount 

of any allowances placed in the pool 

that year from retired units and 

corrections. The 54,711-ton value is 

equal to 10,000 tons annually allocated 

to the pool plus 18% of the total annual 

allocation for participating units, 

mirroring the variability limit from 

CSAPR. The total number of allowances 

that can be allocated in a single year is 

therefore 293,104, which is the sum of 

the 238,393 budget for existing units 

plus 54,711. Annual average emissions 

for the covered sources will be less than 

or equal to 248,393 tons with some year 

to year variability constrained by the 

number of banked allowances and 

allowances available to be allocated 

during a control period from the 

Supplemental Allowance pool. If 

additional units opt into the program, 

additional allowances will be available 

corresponding to the amounts that those 

units would have been allocated under 

CSAPR. The projected SO2 emissions 

from the affected Texas EGUs in the 

CSAPR + BART-elsewhere scenario 

were 266,600 tons per year. In a 2012 

sensitivity analysis memo, EPA 

conducted a sensitivity analysis that 

confirmed that CSAPR would remain 

better-than-BART if Texas EGU 

emissions increased to approximately 

317,100 tons.133 Under the Texas SO2

trading program, annual average EGU 

emissions are anticipated to remain well 

below 317,100 tons per year as annual 

allocations for participating units are 


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held at 248,393 tons per year. Sources 

not covered by the program emitted less 

than 27,500 tons of SO2 in 2016 and are 

not projected to significantly increase 

from this level. Any new units would be 

required to be well controlled and 

similar to the existing units not covered 

by the program, they would not 

significantly increase total emissions of 

SO2. Furthermore, as discussed above, 

any load shifting to these new nonparticipating units would be projected 

to result in a net decrease in emissions 

per unit of electricity generated and at 

most a small increase in total SO2

emissions compared to them not having 

been brought into operation. We note 

that total emissions of SO2 from all EGU 

sources in Texas in 2016 were 245,737 

tons. 

We also note that state-wide EGU 

emissions in Texas have decreased 

considerably since the 2002 baseline 

period, reflecting market changes and 

reductions due to requirements such as 

CAIR/CSAPR. In 2002, Texas EGU 

emissions were 560,860 tons of SO2

compared to emissions of 245,737 tons 

in 2016, a reduction of over 56%. The 

Texas SO2 trading program locks in the 

large majority of these reductions by 

limiting allocation of allowances to 

248,393 tons per year for participating 

sources. While the Texas program does 

not include all EGU sources in the State, 

as discussed above, the EGUs outside of 

the program contribute relatively little 

to the total state emissions and these 

units on average are better controlled for 

SO2 than the units subject to the Texas 

program. 

C. Specific Texas SO2 Trading Program 

Features 

The Texas SO2 Trading Program is an 

intrastate cap-and-trade program for 

listed covered sources in the State of 

Texas. The EPA is promulgating the 

Texas SO2 Trading Program under 40 

CFR 52.2312 and subpart FFFFF of part 

97. The State of Texas may choose to 

remain under the Texas SO2 Trading 

Program or replace it with an 

appropriate SIP. If the State of Texas is 

interested in pursuing delegation of the 

Texas SO2 Trading Program, the request 

would need to provide a demonstration 

of the State’s statutory authority to 

implement any delegated elements. 

The Texas SO2 Trading Program is 

modeled after the EPA’s CSAPR SO2

Group 2 Trading Program and satisfies 

the requirements of § 51.308(e)(2)(vi). 

Similar to the CSAPR SO2 Group 2 

Trading Program, the Texas SO2 Trading 

Program sets an SO2 emission budget for 

the State of Texas. Authorizations to 

emit SO2, known as allowances, are 

allocated to affected units. The Texas 

SO2 Trading Program provides 

flexibility to affected units and sources 

by allowing units and sources to 

determine their own compliance path; 

this includes adding or operating 

control technologies, upgrading or 

improving controls, switching fuels, and 

using allowances. Sources can buy and 

sell allowances and bank (save) 

allowances for future use as long as each 

source holds enough allowances to 

account for its emissions of SO2 by the 

end of the compliance period. 

Pursuant to the requirements of 

§ 51.308(e)(2)(vi)(A), the applicability of 

the Texas SO2 Trading Program is 

defined in 40 CFR 97.904. Section 

97.904(a) identifies the subject units, 

which include all BART-eligible coalfired EGUs, additional coal-fired EGUs, 

and several BART-eligible gas-fired and 

gas/fuel oil-fired EGUs, all of which 

were previously covered by the CSAPR 

SO2 Group 2 Trading Program. 

Additionally, under 40 CFR 97.904(b), 

the EPA is providing an opportunity for 

any other unit in the State of Texas that 

was subject to the CSAPR SO2 Group 2 

Trading Program to opt-in to the Texas 

SO2 Trading Program. We discuss in 

Section V.B above, how the 

applicability results in coverage of the 

Texas SO2 trading program representing 

81% of the total CSAPR allocation for 

Texas and 85% of the CSAPR 

allocations for existing units, and how 

potential shifts in generation would 

result in an insignificant change in 

emissions. The Texas SO2 Trading 

Program establishes the statewide SO2

budget for the subject units at 40 CFR 

97.910(a). This budget is equal to the 

allowances for each subject unit 

identified under §§ 97.904(a) and 

97.911(a). As units opt-in to the Texas 

SO2 Trading under § 97.904(b), the 

allowances for each of these units will 

equal their CSAPR SO2 Group 2 

allowances under § 97.911(b). 

Additionally, the EPA has established a 

Supplemental Allowance Pool with a 

budget of 10,000 tons of SO2 to provide 

compliance assistance to subject units 

and sources. Section 40 CFR 97.912 

establishes how allowances are 

allocated from the Supplemental 

Allowance Pool to sources (collections 

of participating units at a facility) that 

have reported total emissions for that 

control period exceeding the total 

amounts of allowances allocated to the 

participating units at the source for that 

control period (before any allocation 

from the Supplemental Allowance 

Pool). For any control period, the 

maximum supplemental allocation from 

the Supplemental Allowance Pool that a 

source may receive is the amount by 

which the total emissions reported for 

its participating units exceed the total 

allocations to its participating units 

(before any allocation from the 

Supplemental Allowance Pool). If the 

total amount of allowances available for 

allocation from the Supplemental 

Allowance Pool for a control period is 

less than the sum of these maximum 

allocations, sources will receive less 

than the maximum supplemental 

allocation from the Supplemental 

Allowance Pool, where the amount of 

supplemental allocations for each 

source is determined in proportion to 

the sources’ respective maximum 

allocations, with one exception. While 

all other sources required to participate 

in the trading program have flexibility 

to transfer allowances among multiple 

participating units under the same 

owner/operator when planning 

operations, Coleto Creek consists of only 

one coal-fired unit and is the only coalfired unit in Texas owned and operated 

by Dynegy. To provide this source 

additional flexibility, Coleto Creek will 

be allocated its maximum supplemental 

allocation from the Supplemental 

Allowance Pool as long as there are 

sufficient allowances in the 

Supplemental Allowance Pool available 

for allocation, and its actual allocation 

will not be reduced in proportion with 

any reductions made to the 

supplemental allocations to other 

sources. Section 97.921 establishes how 

the Administrator will record the 

allowances for the Texas SO2 Trading 

Program and ensures that the 

Administrator will not record more 

allowances than are available under the 

program consistent with 40 CFR 

51.308(e)(2)(vi)(B). The monitoring, 

recordkeeping, and reporting provisions 

for the Texas SO2 Trading Program at 40 

CFR 97.930–97.935 are consistent with 

those requirements in the CSAPR SO2

Group 2 Trading Program. The 

provisions in 40 CFR 97.930–97.935 

require the subject units to comply with 

the monitoring, recordkeeping, and 

reporting requirements for SO2

emissions in 40 CFR part 75; thereby 

satisfying the requirements of 

§ 51.308(e)(2)(vi)(C)–(E). The Texas SO2

Trading Program will be implemented 

by the EPA using the Allowance 

Management System. The use of the 

Allowance Management System will 

provide a consistent approach to 

implementation and tracking of 

allowances and emissions for the EPA, 

subject sources, and the public 

consistent with the requirements of 40 

CFR 51.308(e)(2)(vi)(F). Additionally, 

the EPA is promulgating requirements at 

40 CFR 97.913–97.918 for designated 


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and alternate designated representatives 

that satisfy the requirements of 40 CFR 

51.308(e)(2)(vi)(G) and are consistent 

with the EPA’s other trading programs 

under 40 CFR part 97. Allowance 

transfer provisions for the Texas SO2

Trading Program at 40 CFR 97.922 and 

97.923 provide procedures that allow 

timely transfer and recording of 

allowances; these provisions will 

minimize administrative barriers to the 

operation of the allowance market and 

ensure that such procedures apply 

uniformly to all sources and other 

potential participants in the allowance 

market, consistent with 40 CFR 

51.308(e)(2)(vi)(H). Compliance 

provisions for the Texas SO2 Trading 

Program at 40 CFR 97.924 prohibit a 

source from emitting a total tonnage of 

SO2 that exceeds the tonnage value of its 

SO2 allowance holdings as required by 

40 CFR 51.308(e)(2)(vi)(I). The Texas 

SO2 Trading Program includes 

automatic allowance surrender 

provisions at 40 CFR 97.924(d) that 

apply consistently from source to source 

and the tonnage value of the allowances 

deducted shall equal at least three times 

the tonnage of the excess emissions, 

consistent with the penalty provisions 

at 40 CFR 51.308(e)(2)(vi)(J). The Texas 

SO2 Trading Program provides for 

banking of allowances under 40 CFR 

97.926; Texas SO2 Trading Program 

allowances are valid for compliance in 

the control period of issuance or may be 

banked for future use, consistent with 

40 CFR 51.308(e)(2)(vi)(K). The EPA is 

promulgating the Texas SO2 Trading 

Program as a BART-alternative for 

Texas’ Regional Haze obligations. The 

CAA and EPA’s implementing 

regulations require periodic review of 

the state’s regional haze approach under 

40 CFR 51.308(g) to evaluate progress 

towards the reasonable progress goals 

for Class I areas located within the State 

and Class I areas located outside the 

State affected by emissions from within 

the State. Because the Texas SO2

Trading Program is a BART-alternative 

for Texas’ Regional Haze obligations, 

this program is required to be reviewed 

in each progress report. We anticipate 

this progress report will provide the 

information needed to assess program 

performance, as required by 40 CFR 

51.308(e)(2)(vi)(L). 

As previously discussed, the EPA 

modeled the Texas SO2 Trading 

Program after the EPA’s CSAPR SO2

Group 2 Trading Program. Relying on a 

trading program structure that is already 

in effect enables the EPA, the subject 

sources, and the public to benefit from 

the use of the Allowance Management 

System, forms, and monitoring, 

recordkeeping, and reporting 

requirements. However, there are a few 

features of the Texas SO2 Trading 

Program that are separate and unique 

from the EPA’s CSAPR. First, the 

program does not address new units that 

are built after the inception of the 

program; these units would be 

permitted and constructed using 

emission control technology determined 

under either BACT or LAER review, as 

applicable. Second, the Texas SO2

Trading Program provides that sources 

that were previously covered under the 

CSAPR SO2 Group 2 Trading Program, 

but are not subject to the requirements 

of subpart FFFFF of part 97 can opt-in 

to the Texas SO2 Trading Program at the 

allocation level established under 

CSAPR. Finally, the Texas SO2 Trading 

Program includes a Supplemental 

Allowance Pool to provide some 

compliance assistance to units whose 

emissions exceed their allocations. The 

amount of allocations to the 

Supplemental Allowance Pool each year 

is less than the portion of the Texas 

budget under the CSAPR SO2 Group 2 

Trading Program that would have been 

set aside each year for new units (and 

which would have been allocated to 

existing units to the extent not needed 

by new units). 

VI. Final Action 

A. Regional Haze 

We are finalizing our identification of 

BART-eligible EGUs. We are approving 

the portion of the Texas Regional Haze 

SIP that addresses the BART 

requirement for EGUs for PM. As 

discussed elsewhere in this preamble, 

we are replacing Texas’ reliance on 

CAIR with reliance on CSAPR to 

address the NOX BART requirements for 

EGUs. To address the SO2 BART 

requirements for EGUs, we are 

promulgating a FIP to replace Texas’ 

reliance on CAIR with reliance on an 

intrastate SO2 trading program for 

certain EGUs identified in Table 11 

below. This FIP is codified under 40 

CFR 52.2312 and subpart FFFFF of part 

97. We are finalizing our determination 

that BART-eligible EGUs not covered by 

the intrastate SO2 trading program are 

not subject-to-BART. This final action is 

also part of the long-term strategy to 

address the reasonable progress 

requirements for Texas EGUs, which 

remain outstanding after the remand of 

our reasonable progress FIP by the Fifth 

Circuit Court of Appeals. However, 

further assessment and analysis of the 

CAA’s reasonable progress factors will 

be needed before the Regional Haze 

Rule’s reasonable progress requirements 

will be fully addressed for Texas. 

TABLE 11—TEXAS EGUS SUBJECT TO THE FIP SO2 TRADING PROGRAM

Owner/operator Units 

AEP ......................................................................................................... Welsh Power Plant Units 1, 2, and 3. 

H W Pirkey Power Plant Unit 1. 

Wilkes Units 1 *, 2 *, and 3 *. 

CPS Energy ............................................................................................ JT Deely Units 1 and 2, Sommers Units 1 * and 2 *. 

Dynegy .................................................................................................... Coleto Creek Unit 1. 

LCRA ...................................................................................................... Fayette/Sam Seymour Units 1 and 2. 

Luminant ................................................................................................. Big Brown Units 1 and 2. 

Martin Lake Units 1, 2, and 3. 

Monticello Units 1, 2, and 3. 

Sandow Unit 4. 

Stryker ST2 *. 

Graham Unit 2 *. 

NRG ........................................................................................................ Limestone Units 1 and 2. 

WA Parish Units WAP4 *, WAP5, WAP6, WAP7. 

Xcel ......................................................................................................... Tolk Station Units 171B and 172B. 

Harrington Units 061B, 062B, and 063B. 

El Paso Electric ...................................................................................... Newman Units 2 *, 3 *, and 4 *. 

* Gas-fired or gas/fuel oil-fired units. 


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134 81 FR 296 (Jan. 5, 2016). 

135Specifically, we previously disapproved the 

relevant portion of these Texas’ SIP submittals: 

April 4, 2008: 1997 8-hour Ozone, 1997 PM2.5 (24- 

hour and annual); May 1, 2008: 1997 8-hour Ozone, 

1997 PM2.5 (24-hour and annual); November 23, 

2009: 2006 24-hour PM2.5; December 7, 2012: 2010 

NO2; December 13, 2012: 2008 8-hour Ozone; May 

6, 2013: 2010 1-hour SO2 (Primary NAAQS). 79 FR 

74818, 74821; 81 FR 296, 302. 

136Texas v. EPA, 829 F.3d 405 (5th Cir. 2016). 137 62 FR 19885 (Apr. 23, 1997). 

B. Interstate Visibility Transport 

In our January 5, 2016 final action 134

we disapproved the portion of Texas’ 

SIP revisions intended to address 

interstate visibility transport for six 

NAAQS, including the 1997 8-hour 

ozone and 1997 PM2.5.135 That 

rulemaking was challenged, however, 

and in December 2016, following the 

submittal of a request by the EPA for a 

voluntary remand of the parts of the rule 

under challenge, the Fifth Circuit Court 

of Appeals remanded the rule in its 

entirety without vacatur.136 In our 

January 4, 2017 proposed action we 

proposed to reconsider the basis of our 

prior disapproval of Texas’ SIP revisions 

addressing interstate visibility transport 

under CAA section 110(a)(2)(D)(i)(II) for 

six NAAQS. We have reconsidered the 

basis of our prior disapproval and are 

disapproving Texas’ SIP revisions 

addressing interstate visibility transport 

under CAA section 110(a)(2)(D)(i)(II) for 

six NAAQS. We are finalizing a FIP to 

fully address Texas’ interstate visibility 

transport obligations for the following 

six NAAQS: (1) 1997 8-hour ozone, (2) 

1997 PM2.5 (annual and 24 hour), (3) 

2006 PM2.5 (24-hour), (4) 2008 8-hour 

ozone, (5) 2010 1-hour NO2 and (6) 2010 

1-hour SO2. The BART FIP emission 

reductions are consistent with the level 

of emission reductions relied upon by 

other states during Regional Haze 

consultation, and it is therefore 

adequate to ensure that emissions from 

Texas do not interfere with measures to 

protect visibility in nearby states in 

accordance with CAA section 

110(a)(2)(D)(i)(II). 

VII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Overview, Executive Order 

13563: Improving Regulation and 

Regulatory Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is therefore not 

subject to review under Executive 

Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011). 

B. Executive Order 13771: Reducing 

Regulations and Controlling Regulatory 

Costs 

This action is not an Executive Order 

13771 regulatory action because this 

action is not significant under Executive 

Order 12866. 

C. Paperwork Reduction Act 

The Office of Management and Budget 

(OMB) has determined that this action 

imposes a collection burden that is 

subject to the Paperwork Reduction Act 

(PRA). An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. Therefore, the EPA will 

obtain a valid OMB control number 

unless OMB determines that these 

collection activities are covered under 

an existing information collection 

request (ICR) and associated OMB 

control number. If the EPA obtains a 

new OMB control number or amends an 

existing ICR with a valid OMB control 

number, the EPA will provide notice in 

the Federal Register as required by the 

PRA and the implementing regulations, 

with burden estimates, and, if 

necessary, publish a technical 

amendment to 40 CFR part 9 to display 

the new OMB control number for the 

information collection activities 

contained in this final rule. 

D. Regulatory Flexibility Act 

I certify that this action will not have 

a significant impact on a substantial 

number of small entities. In making this 

determination, the impact of concern is 

any significant adverse economic 

impact on small entities. An agency may 

certify that a rule will not have a 

significant economic impact on a 

substantial number of small entities if 

the rule relieves regulatory burden, has 

no net burden or otherwise has a 

positive economic effect on the small 

entities subject to the rule. This rule 

does not impose any requirements or 

create impacts on small entities. This 

FIP action under Section 110 of the 

CAA will not create any new 

requirement with which small entities 

must comply. Accordingly, it affords no 

opportunity for the EPA to fashion for 

small entities less burdensome 

compliance or reporting requirements or 

timetables or exemptions from all or 

part of the rule. The fact that the CAA 

prescribes that various consequences 

(e.g., emission limitations) may or will 

flow from this action does not mean that 

the EPA either can or must conduct a 

regulatory flexibility analysis for this 

action. We have therefore concluded 

that, this action will have no net 

regulatory burden for all directly 

regulated small entities. 

E. Unfunded Mandates Reform Act 

(UMRA) 

This action does not contain an 

unfunded mandate of $100 million or 

more as described in UMRA, 2 U.S.C. 

1531–1538, and does not significantly or 

uniquely affect small governments. 

F. 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. 

G. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This rule does not have tribal 

implications, as specified in Executive 

Order 13175. It will not have substantial 

direct effects on tribal governments. 

Thus, Executive Order 13175 does not 

apply to this rule. 

H. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 137 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 

effect on children. EPA interprets EO 

13045 as applying only to those 

regulatory actions that concern health or 

safety risks, such that the analysis 

required under Section 5–501 of the EO 

has the potential to influence the 

regulation. This action is not subject to 

Executive Order 13045 because it is not 

economically significant as defined in 

Executive Order 12866, and because the 

EPA does not believe the environmental 

health or safety risks addressed by this 

action present a disproportionate risk to 

children. This action is not subject to 

EO 13045 because it implements 

specific standards established by 

Congress in statutes. However, to the 

extent this rule will limit emissions of 

SO2, the rule will have a beneficial 

effect on children’s health by reducing 

air pollution. 


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I. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

J. National Technology Transfer and 

Advancement Act (NTTAA) 

This action involves technical 

standards. The EPA has decided to use 

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 System (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, EPA is not recommending 

any revisions to part 75; however, EPA 

periodically revises the test procedures 

set forth in part 75. When EPA revises 

the test procedures set forth in part 75 

in the future, 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, 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. 

K. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

The EPA believes that this action does 

not have disproportionately high and 

adverse human health or environmental 

effects on minority populations, lowincome populations and/or indigenous 

peoples, as specified in Executive Order 

12898 (59 FR 7629, February 16, 1994). 

We have determined that this rule will 

not have disproportionately high and 

adverse human health or environmental 

effects on minority or low-income 

populations 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 

minority or low-income population. The 

rule limits emissions of SO2 from 

certain facilities in Texas. 

L. Congressional Review Act (CRA) 

This rule is exempt from the CRA 

because it is a rule of particular 

applicability. 

List of Subjects 

40 CFR Part 52 

Environmental protection, Air 

pollution control, Best available retrofit 

technology, Incorporation by reference, 

Intergovernmental relations, Interstate 

transport of pollution, Nitrogen dioxide, 

Ozone, Particulate matter, Regional 

haze, Reporting and recordkeeping 

requirements, Sulfur dioxides, 

Visibility. 

40 CFR Part 97 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Intergovernmental 

relations, Nitrogen dioxide, Reporting 

and recordkeeping requirements, Sulfur 

dioxides. 

Dated: September 29, 2017. 

E. Scott Pruitt, 

Administrator. 

40 CFR parts 52 and 97 are amended 

as follows: 

PART 52—APPROVAL AND 

PROMULGATION OF 

IMPLEMENTATION PLANS 

■ 1. The authority citation for part 52 

continues to read as follows: 

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

Subpart SS—Texas 

■ 2. In § 52.2270, the second table in 

paragraph (e) is amended by adding the 

entry ‘‘Texas Regional Haze BART 

Requirement for EGUs for PM’’ at the 

end of the table to read as follows: 

§ 52.2270 Identification of plan. 

* * * * * 

(e) * * * 

EPA APPROVED NONREGULATORY PROVISIONS AND QUASI-REGULATORY MEASURES IN THE TEXAS SIP 

Name of SIP provision 

Applicable 

geographic or 

nonattainment 

area 

State submittal 

date/effective 

date 

EPA approval date Comments 

*******

Texas Regional Haze BART Requirement for 

EGUs for PM.

Statewide .................. 3/31/2009 10/17/2017, [insert Federal 

Register citation].

■ 3. Section 52.2304 is amended by 

adding paragraph (f) to read as follows: 

§ 52.2304 Visibility protection. 

* * * * * 

(f) Measures addressing disapproval 

associated with NOX and SO2. (1) The 

deficiencies associated with NOX

identified in EPA’s limited disapproval 

of the regional haze plan submitted by 

Texas on March 31, 2009, and EPA’s 

disapprovals in paragraph (d) of this 

section, are satisfied by § 52.2283(d). 

(2) The deficiencies associated with 

SO2 identified in EPA’s limited 

disapproval of the regional haze plan 

submitted by Texas on March 31, 2009, 

and EPA’s disapprovals in paragraph (d 

of this section), are satisfied by 

§ 52.2312. 

■ 4. Add § 52.2312 to subpart SS to read 

as follows: 

§ 52.2312 Requirements for the control of 

SO2 emissions to address in full or in part 

requirements related to BART, reasonable 

progress, and interstate visibility transport. 

(a) The Texas SO2 Trading Program 

provisions set forth in subpart FFFFF of 

part 97 of this chapter constitute the 

Federal Implementation Plan provisions 

fully addressing Texas’ obligations with 

respect to best available retrofit 

technology under section 169A of the 

Act and the deficiencies associated with 

EPA’s disapprovals in § 52.2304(d) and 

partially addressing Texas’ obligations 

with respect to reasonable progress 

under section 169A of the Act, as those 

obligations relate to emissions of sulfur 

dioxide (SO2) from electric generating 

units (EGUs). 

(b) The provisions of subpart FFFFF 

of part 97 of this chapter apply to 

sources in Texas but not sources in 

Indian country located within the 


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borders of Texas, with regard to 

emissions in 2019 and each subsequent 

year. 

PART 97—FEDERAL NOX BUDGET 

TRADING PROGRAM, CAIR NOX AND 

SO2 TRADING PROGRAMS, CSAPR 

NOX AND SO2 TRADING PROGRAMS, 

AND TEXAS SO2 TRADING PROGRAM 

■ 5. The authority citation for part 97 

continues to read as follows: 

Authority: 42 U.S.C. 7401, 7403, 7410, 

7426, 7601, and 7651, et seq. 

■ 6. Revise the part heading for part 97 

to read as set forth above. 

■ 7. Add subpart FFFFF consisting of 

§§ 97.901 through 97.935 to read as 

follows: 

Subpart FFFFF—Texas SO2 Trading 

Program 

Sec. 

97.901 Purpose. 

97.902 Definitions. 

97.903 Measurements, abbreviations, and 

acronyms. 

97.904 Applicability. 

97.905 Retired unit exemptions. 

97.906 General provisions. 

97.907 Computation of time. 

97.908 Administrative appeal procedures. 

97.909 [Reserved] 

97.910 Texas SO2 Trading Program and 

Supplemental Allowance Pool Budgets. 

97.911 Texas SO2 Trading Program 

allowance allocations. 

97.912 Texas SO2 Trading Program 

Supplemental Allowance Pool. 

97.913 Authorization of designated 

representative and alternate designated 

representative. 

97.914 Responsibilities of designated 

representative and alternate designated 

representative. 

97.915 Changing designated representative 

and alternate designated representative; 

changes in owners and operators; 

changes in units at the source. 

97.916 Certificate of representation. 

97.917 Objections concerning designated 

representative and alternate designated 

representative. 

97.918 Delegation by designated 

representative and alternate designated 

representative. 

97.919 [Reserved] 

97.920 Establishment of compliance 

accounts and general accounts. 

97.921 Recordation of Texas SO2 Trading 

Program allowance allocations. 

97.922 Submission of Texas SO2 Trading 

Program allowance transfers. 

97.923 Recordation of Texas SO2 Trading 

Program allowance transfers. 

97.924 Compliance with Texas SO2 Trading 

Program emissions limitations. 

97.925 [Reserved] 

97.926 Banking. 

97.927 Account error. 

97.928 Administrator’s action on 

submissions. 

97.929 [Reserved] 

97.930 General monitoring, recordkeeping, 

and reporting requirements. 

97.931 Initial monitoring system 

certification and recertification 

procedures. 

97.932 Monitoring system out-of-control 

periods. 

97.933 Notifications concerning 

monitoring. 

97.934 Recordkeeping and reporting. 

97.935 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

Subpart FFFFF—Texas SO2 Trading 

Program 

§ 97.901 Purpose. 

This subpart sets forth the general, 

designated representative, allowance, 

and monitoring provisions for the Texas 

SO2 Trading Program under sections 

110 and 169A of the Clean Air Act and 

40 CFR 52.2312, as a means of 

addressing Texas’ obligations with 

respect to BART, reasonable progress, 

and interstate visibility transport as 

those obligations relate to sulfur dioxide 

emissions from electricity generating 

units. 

§ 97.902 Definitions. 

The terms used in this subpart shall 

have the meanings set forth in this 

section as follows: 

Acid rain program means a multistate SO2 and NOX air pollution control 

and emission reduction program 

established by the Administrator under 

title IV of the Clean Air Act and parts 

72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Director of the Clean Air Markets 

Division (or its successor determined by 

the Administrator) of the United States 

Environmental Protection Agency, the 

Administrator’s duly authorized 

representative under this subpart. 

Allocate or allocation means, with 

regard to Texas SO2 Trading Program 

allowances, the determination by the 

Administrator, State, or permitting 

authority, in accordance with this 

subpart or any SIP revision submitted 

by the State approved by the 

Administrator, of the amount of such 

Texas SO2 Trading Program allowances 

to be initially credited, at no cost to the 

recipient, to a Texas SO2 Trading 

Program unit. 

Allowance management system 

means the system by which the 

Administrator records allocations, 

transfers, and deductions of Texas SO2

Trading Program allowances under the 

Texas SO2 Trading Program. Such 

allowances are allocated, recorded, 

held, transferred, or deducted only as 

whole allowances. 

Allowance management system 

account means an account in the 

Allowance Management System 

established by the Administrator for 

purposes of recording the allocation, 

holding, transfer, or deduction of Texas 

SO2 Trading Program allowances. 

Allowance transfer deadline means, 

for a control period in a given year, 

midnight of March 1 (if it is a business 

day), or midnight of the first business 

day thereafter (if March 1 is not a 

business day), immediately after such 

control period and is the deadline by 

which a Texas SO2 Trading Program 

allowance transfer must be submitted 

for recordation in a Texas SO2 Trading 

Program source’s compliance account in 

order to be available for use in 

complying with the source’s Texas SO2

Trading Program emissions limitation 

for such control period in accordance 

with §§ 97.906 and 97.924. 

Alternate designated representative 

means, for a Texas SO2 Trading Program 

source and each Texas SO2 Trading 

Program unit at the source, the natural 

person who is authorized by the owners 

and operators of the source and all such 

units at the source, in accordance with 

this subpart, to act on behalf of the 

designated representative in matters 

pertaining to the Texas SO2 Trading 

Program. If the Texas SO2 Trading 

Program source is also subject to the 

Acid Rain Program or CSAPR NOX

Ozone Season Group 2 Trading 

Program, then this natural person shall 

be the same natural person as the 

alternate designated representative as 

defined in the respective program. 

Authorized account representative 

means, for a general account, the natural 

person who is authorized, in accordance 

with this subpart, to transfer and 

otherwise dispose of Texas SO2 trading 

Program allowances held in the general 

account and, for a Texas SO2 Trading 

Program source’s compliance account, 

the designated representative of the 

source. 

Automated data acquisition and 

handling system or DAHS means the 

component of the continuous emission 

monitoring system, or other emissions 

monitoring system approved for use 

under this subpart, designed to interpret 

and convert individual output signals 

from pollutant concentration monitors, 

flow monitors, diluent gas monitors, 

and other component parts of the 

monitoring system to produce a 

continuous record of the measured 

parameters in the measurement units 

required by this subpart. 

Business day means a day that does 

not fall on a weekend or a federal 

holiday. 

Clean Air Act means the Clean Air 

Act, 42 U.S.C. 7401, et seq. 


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Coal means ‘‘coal’’ as defined in 

§ 72.2 of this chapter. 

Commence commercial operation 

means, with regard to a Texas SO2

Trading Program unit, to have begun to 

produce steam, gas, or other heated 

medium used to generate electricity for 

sale or use, including test generation. 

Common stack means a single flue 

through which emissions from 2 or 

more units are exhausted. 

Compliance account means an 

Allowance Management System 

account, established by the 

Administrator for a Texas SO2 Trading 

Program source under this subpart, in 

which any Texas SO2 Trading Program 

allowance allocations to the Texas SO2

Trading Program units at the source are 

recorded and in which are held any 

Texas SO2 Trading Program allowances 

available for use for a control period in 

a given year in complying with the 

source’s Texas SO2 Trading Program 

emissions limitation in accordance with 

§§ 97.906 and 97.924. 

Continuous emission monitoring 

system or CEMS means the equipment 

required under this subpart to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes and using an 

automated data acquisition and 

handling system (DAHS), a permanent 

record of SO2 emissions, stack gas 

volumetric flow rate, stack gas moisture 

content, and O2 or CO2 concentration (as 

applicable), in a manner consistent with 

part 75 of this chapter and §§ 97.930 

through 97.935. The following systems 

are the principal types of continuous 

emission monitoring systems: 

(1) A flow monitoring system, 

consisting of a stack flow rate monitor 

and an automated data acquisition and 

handling system and providing a 

permanent, continuous record of stack 

gas volumetric flow rate, in standard 

cubic feet per hour (scfh); 

(2) A SO2 monitoring system, 

consisting of a SO2 pollutant 

concentration monitor and an 

automated data acquisition and 

handling system and providing a 

permanent, continuous record of SO2

emissions, in parts per million (ppm); 

(3) A moisture monitoring system, as 

defined in § 75.11(b)(2) of this chapter 

and providing a permanent, continuous 

record of the stack gas moisture content, 

in percent H2O; 

(4) A CO2 monitoring system, 

consisting of a CO2 pollutant 

concentration monitor (or an O2 monitor 

plus suitable mathematical equations 

from which the CO2 concentration is 

derived) and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of CO2 emissions, in percent CO2; 

and 

(5) An O2 monitoring system, 

consisting of an O2 concentration 

monitor and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of O2, in percent O2. 

Control period means the period 

starting January 1 of a calendar year, 

except as provided in § 97.906(c)(3), and 

ending on December 31 of the same 

year, inclusive. 

CSAPR NOX Ozone Season Group 2 

Trading Program means a multi-state 

NOX air pollution control and emission 

reduction program established in 

accordance with subpart EEEEE of this 

part and § 52.38(b)(1), (b)(2)(i) and (iii), 

(b)(6) through (11), and (b)(13) of this 

chapter (including such a program that 

is revised in a SIP revision approved by 

the Administrator under § 52.38(b)(7) or 

(8) of this chapter or that is established 

in a SIP revision approved by the 

Administrator under § 52.38(b)(6) or (9) 

of this chapter), as a means of mitigating 

interstate transport of ozone and NOX.

Designated representative means, for 

a Texas SO2 Trading Program source 

and each Texas SO2 Trading Program 

unit at the source, the natural person 

who is authorized by the owners and 

operators of the source and all such 

units at the source, in accordance with 

this subpart, to represent and legally 

bind each owner and operator in matters 

pertaining to the Texas SO2 Trading 

Program. If the Texas SO2 Trading 

Program source is also subject to the 

Acid Rain Program or CSAPR NOX

Ozone Season Group 2 Trading 

Program, then this natural person shall 

be the same natural person as the 

designated representative as defined in 

the respective program. 

Emissions means air pollutants 

exhausted from a unit or source into the 

atmosphere, as measured, recorded, and 

reported to the Administrator by the 

designated representative, and as 

modified by the Administrator: 

(1) In accordance with this subpart; 

and 

(2) With regard to a period before the 

unit or source is required to measure, 

record, and report such air pollutants in 

accordance with this subpart, in 

accordance with part 75 of this chapter. 

Excess emissions means any ton of 

emissions from the Texas SO2 Trading 

Program units at a Texas SO2 Trading 

Program source during a control period 

in a given year that exceeds the Texas 

SO2 Trading Program emissions 

limitation for the source for such control 

period. 

Fossil fuel means natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material. 

Fossil-fuel-fired means, with regard to 

a unit, combusting any amount of fossil 

fuel in 2005 or any calendar year 

thereafter. 

General account means an Allowance 

Management System account, 

established under this subpart, which is 

not a compliance account. 

Generator means a device that 

produces electricity. 

Heat input means, for a unit for a 

specified period of unit operating time, 

the product (in mmBtu) of the gross 

calorific value of the fuel (in mmBtu/lb) 

fed into the unit multiplied by the fuel 

feed rate (in lb of fuel/time) and unit 

operating time, as measured, recorded, 

and reported to the Administrator by the 

designated representative and as 

modified by the Administrator in 

accordance with this subpart and 

excluding the heat derived from 

preheated combustion air, recirculated 

flue gases, or exhaust. 

Heat input rate means, for a unit, the 

quotient (in mmBtu/hr) of the amount of 

heat input for a specified period of unit 

operating time (in mmBtu) divided by 

unit operating time (in hr) or, for a unit 

and a specific fuel, the amount of heat 

input attributed to the fuel (in mmBtu) 

divided by the unit operating time (in 

hr) during which the unit combusts the 

fuel. 

Indian country means ‘‘Indian 

country’’ as defined in 18 U.S.C. 1151. 

Life-of-the-unit, firm power 

contractual arrangement means a unit 

participation power sales agreement 

under which a utility or industrial 

customer reserves, or is entitled to 

receive, a specified amount or 

percentage of nameplate capacity and 

associated energy generated by any 

specified unit and pays its proportional 

amount of such unit’s total costs, 

pursuant to a contract: 

(1) For the life of the unit; 

(2) For a cumulative term of no less 

than 30 years, including contracts that 

permit an election for early termination; 

or 

(3) For a period no less than 25 years 

or 70 percent of the economic useful life 

of the unit determined as of the time the 

unit is built, with option rights to 

purchase or release some portion of the 

nameplate capacity and associated 

energy generated by the unit at the end 

of the period. 

Monitoring system means any 

monitoring system that meets the 

requirements of this subpart, including 

a continuous emission monitoring 

system, an alternative monitoring 

system, or an excepted monitoring 

system under part 75 of this chapter. 


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Nameplate capacity means, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe, rounded to 

the nearest tenth) that the generator is 

capable of producing on a steady state 

basis and during continuous operation 

(when not restricted by seasonal or 

other deratings) as of such installation 

as specified by the manufacturer of the 

generator or, starting from the 

completion of any subsequent physical 

change in the generator resulting in an 

increase in the maximum electrical 

generating output that the generator is 

capable of producing on a steady state 

basis and during continuous operation 

(when not restricted by seasonal or 

other deratings), such increased 

maximum amount (in MWe, rounded to 

the nearest tenth) as of such completion 

as specified by the person conducting 

the physical change. 

Natural gas means ‘‘natural gas’’ as 

defined in § 72.2 of this chapter. 

Natural person means a human being, 

as opposed to a legal person, which may 

be a private (i.e., business entity or nongovernmental organization) or public 

(i.e., government) organization. 

Operate or operation means, with 

regard to a unit, to combust fuel. 

Operator means, for a Texas SO2

Trading Program source or a Texas SO2

Trading Program unit at a source 

respectively, any person who operates, 

controls, or supervises a Texas SO2

Trading Program unit at the source or 

the Texas SO2 Trading Program unit and 

shall include, but not be limited to, any 

holding company, utility system, or 

plant manager of such source or unit. 

Owner means, for a Texas SO2

Trading Program source or a Texas SO2

Trading Program unit at a source, any of 

the following persons: 

(1) Any holder of any portion of the 

legal or equitable title in a Texas SO2

Trading Program unit at the source or 

the Texas SO2 Trading Program unit; 

(2) Any holder of a leasehold interest 

in a Texas SO2 Trading Program unit at 

the source or the Texas SO2 Trading 

Program unit, provided that, unless 

expressly provided for in a leasehold 

agreement, ‘‘owner’’ shall not include a 

passive lessor, or a person who has an 

equitable interest through such lessor, 

whose rental payments are not based 

(either directly or indirectly) on the 

revenues or income from such Texas 

SO2 Trading Program unit; and 

(3) Any purchaser of power from a 

Texas SO2 Trading Program unit at the 

source or the Texas SO2 Trading 

Program unit under a life-of-the-unit, 

firm power contractual arrangement. 

Permanently retired means, with 

regard to a unit, a unit that is 

unavailable for service and that the 

unit’s owners and operators do not 

expect to return to service in the future. 

Permitting authority means 

‘‘permitting authority’’ as defined in 

§§ 70.2 and 71.2 of this chapter. 

Receive or receipt of means, when 

referring to the Administrator, to come 

into possession of a document, 

information, or correspondence 

(whether sent in hard copy or by 

authorized electronic transmission), as 

indicated in an official log, or by a 

notation made on the document, 

information, or correspondence, by the 

Administrator in the regular course of 

business. 

Recordation, record, or recorded 

means, with regard to Texas SO2

Trading Program allowances, the 

moving of Texas SO2 Trading Program 

allowances by the Administrator into, 

out of, or between Allowance 

Management System accounts, for 

purposes of allocation, transfer, or 

deduction. 

Reference method means any direct 

test method of sampling and analyzing 

for an air pollutant as specified in 

§ 75.22 of this chapter. 

Replacement, replace, or replaced 

means, with regard to a unit, the 

demolishing of a unit, or the permanent 

retirement and permanent disabling of a 

unit, and the construction of another 

unit (the replacement unit) to be used 

instead of the demolished or retired unit 

(the replaced unit). 

Serial number means, for a Texas SO2

Trading Program allowance, the unique 

identification number assigned to each 

Texas SO2 Trading Program allowance 

by the Administrator. 

Source means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. This definition 

does not change or otherwise affect the 

definition of ‘‘major source’’, ‘‘stationary 

source’’, or ‘‘source’’ as set forth and 

implemented in a title V operating 

permit program or any other program 

under the Clean Air Act. 

State means Texas. 

Submit or serve means to send or 

transmit a document, information, or 

correspondence to the person specified 

in accordance with the applicable 

regulation: 

(1) In person; 

(2) By United States Postal Service; or 

(3) By other means of dispatch or 

transmission and delivery; 

(4) Provided that compliance with any 

‘‘submission’’ or ‘‘service’’ deadline 

shall be determined by the date of 

dispatch, transmission, or mailing and 

not the date of receipt. 

Texas SO2 Trading Program means an 

SO2 air pollution control and emission 

reduction program established in 

accordance with this subpart and 40 

CFR 52.2312 (including such a program 

that is revised in a SIP revision 

approved by the Administrator), or 

established in a SIP revision approved 

by the Administrator, as a means of 

addressing the State’s obligations with 

respect to BART, reasonable progress, 

and interstate visibility transport as 

those obligations relate to emissions of 

SO2 from electricity generating units. 

Texas SO2 Trading Program 

allowance means a limited 

authorization issued and allocated by 

the Administrator under this subpart, or 

by a State or permitting authority under 

a SIP revision approved by the 

Administrator, to emit one ton of SO2

during a control period of the specified 

calendar year for which the 

authorization is allocated or of any 

calendar year thereafter under the Texas 

SO2 Trading Program. 

Texas SO2 Trading Program 

allowance deduction or deduct Texas 

SO2 Trading Program allowances means 

the permanent withdrawal of Texas SO2

Trading Program allowances by the 

Administrator from a compliance 

account (e.g., in order to account for 

compliance with the Texas SO2 Trading 

Program emissions limitation). 

Texas SO2 Trading Program 

allowances held or hold Texas SO2

Trading Program allowances means the 

Texas SO2 Trading Program allowances 

treated as included in an Allowance 

Management System account as of a 

specified point in time because at that 

time they: 

(1) Have been recorded by the 

Administrator in the account or 

transferred into the account by a 

correctly submitted, but not yet 

recorded, Texas SO2 Trading Program 

allowance transfer in accordance with 

this subpart; and 

(2) Have not been transferred out of 

the account by a correctly submitted, 

but not yet recorded, Texas SO2 Trading 

Program allowance transfer in 

accordance with this subpart. 

Texas SO2 Trading Program emissions 

limitation means, for a Texas SO2

Trading Program source, the tonnage of 

SO2 emissions authorized in a control 

period by the Texas SO2 Trading 

Program allowances available for 

deduction for the source under 

§ 97.924(a) for such control period. 

Texas SO2 Trading Program source 

means a source that includes one or 

more Texas SO2 Trading Program units. 

Texas SO2 Trading Program unit 

means a unit that is subject to the Texas 

SO2 Trading Program under § 97.904. 


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Unit means a stationary, fossil-fuelfired boiler, stationary, fossil-fuel-fired 

combustion turbine, or other stationary, 

fossil-fuel-fired combustion device. A 

unit that undergoes a physical change or 

is moved to a different location or 

source shall continue to be treated as 

the same unit. A unit (the replaced unit) 

that is replaced by another unit (the 

replacement unit) at the same or a 

different source shall continue to be 

treated as the same unit, and the 

replacement unit shall be treated as a 

separate unit. 

Unit operating day means, with 

regard to a unit, a calendar day in which 

the unit combusts any fuel. 

Unit operating hour or hour of unit 

operation means, with regard to a unit, 

an hour in which the unit combusts any 

fuel. 

§ 97.903 Measurements, abbreviations, 

and acronyms. 

Measurements, abbreviations, and 

acronyms used in this subpart are 

defined as follows: 

BART—best available retrofit 

technology 

Btu—British thermal unit 

CO2—carbon dioxide 

CSAPR—Cross-State Air Pollution Rule 

H2O—water 

hr—hour 

lb—pound 

mmBtu—million Btu 

MWe—megawatt electrical 

NOX—nitrogen oxides 

O2—oxygen 

ppm—parts per million 

scfh—standard cubic feet per hour 

SIP—State implementation plan 

SO2—sulfur dioxide 

§ 97.904 Applicability. 

(a) Each of the units in Texas listed in 

the table in § 97.911(a)(1) shall be a 

Texas SO2 Trading Program unit, and 

each source that includes one or more 

such units shall be a Texas SO2 Trading 

Program source, subject to the 

requirements of this subpart. 

(b) Opt-in provisions. (1) The 

provisions of paragraph (b) of this 

section apply to each unit in Texas that: 

(i) Is listed in the table entitled ‘‘Unit 

Level Allocations under the CSAPR FIPs 

after Tolling,’’ EPA–HQ–OAR–2009– 

0491–5028, available at 

www.regulations.gov; 

(ii) Is not a Texas SO2 Trading 

Program unit under paragraph (a) of this 

section; and 

(iii) Has not received a determination 

of non-applicability under 40 CFR 

97.404(c), 97.504(c), 97.704(c), or 

97.804(c). 

(2) The designated representative of a 

unit described in paragraph (b)(1) of this 

section may submit an opt-in 

application seeking authorization for the 

unit to participate in the Texas SO2

Trading Program, provided that the unit 

has operated in the calendar year 

preceding submission of the opt-in 

application. Opt-in applications must be 

submitted in a format specified by the 

Administrator no later than October 1 of 

the year preceding the first control 

period for which authorization to 

participate in the Texas SO2 Trading 

Program is sought. 

(3) The Administrator shall review 

applications for opt-in units and 

respond in writing to the designated 

representative within 30 business days. 

The Administrator will authorize the 

unit to participate in the Texas SO2

Trading Program if the provisions of 

paragraphs (b)(1) and (2) of this section 

are satisfied. 

(4) Following submission of an opt-in 

application and authorization in 

accordance with paragraphs (b)(2) and 

(3) of this section, the unit shall be a 

Texas SO2 Trading Program unit, and 

the source that includes the unit shall 

be a Texas SO2 Trading Program source, 

subject to the requirements of this 

subpart starting on the next January 1. 

The unit shall remain subject to the 

requirements of this subpart for the life 

of the source, with the exception for 

retired units under § 97.905. 

(5) Opt-in units shall receive 

allowance allocations as provided in 

§ 97.911(b). These allocations shall be 

recorded into a source’s compliance 

account per the recordation schedule in 

§ 97.921. 

(6) The Administrator will maintain a 

publicly accessible record of all units 

that become Texas SO2 Trading Program 

units under paragraph (b) of this section 

and of all allocations of allowances to 

such units. Such public access may be 

provided through posting of information 

on a Web site. 

§ 97.905 Retired unit exemptions. 

(a)(1) Any Texas SO2 Trading Program 

unit that is permanently retired shall be 

exempt from § 97.906(b) and (c)(1), 

§ 97.924, and §§ 97.930 through 97.935. 

(2) The exemption under paragraph 

(a)(1) of this section shall become 

effective the day on which the Texas 

SO2 Trading Program unit is 

permanently retired. Within 30 days of 

the unit’s permanent retirement, the 

designated representative shall submit a 

statement to the Administrator. The 

statement shall state, in a format 

prescribed by the Administrator, that 

the unit was permanently retired on a 

specified date and will comply with the 

requirements of paragraph (b) of this 

section. 

(b) Special provisions. (1) A unit 

exempt under paragraph (a) of this 

section shall not emit any SO2, starting 

on the date that the exemption takes 

effect. 

(2) For a period of 5 years from the 

date the records are created, the owners 

and operators of a unit exempt under 

paragraph (a) of this section shall retain, 

at the source that includes the unit, 

records demonstrating that the unit is 

permanently retired. The 5-year period 

for keeping records may be extended for 

cause, at any time before the end of the 

period, in writing by the Administrator. 

The owners and operators bear the 

burden of proof that the unit is 

permanently retired. 

(3) The owners and operators and, to 

the extent applicable, the designated 

representative of a unit exempt under 

paragraph (a) of this section shall 

comply with the requirements of the 

Texas SO2 Trading Program concerning 

all periods for which the exemption is 

not in effect, even if such requirements 

arise, or must be complied with, after 

the exemption takes effect. 

(4) A unit exempt under paragraph (a) 

of this section shall lose its exemption 

on the first date on which the unit 

resumes operation. A retired unit that 

resumes operation will not receive an 

allowance allocation under § 97.911. 

The unit may receive allowances from 

the Supplemental Allowance Pool 

pursuant to § 97.912. All other 

provisions of Subpart FFFFF regarding 

monitoring, reporting, recordkeeping 

and compliance will apply on the first 

date on which the unit resumes 

operation. 

§ 97.906 General provisions. 

(a) Designated representative 

requirements. The owners and operators 

shall comply with the requirement to 

have a designated representative, and 

may have an alternate designated 

representative, in accordance with 

§§ 97.913 through 97.918. 

(b) Emissions monitoring, reporting, 

and recordkeeping requirements. (1) 

The owners and operators, and the 

designated representative, of each Texas 

SO2 Trading Program source and each 

Texas SO2 Trading Program unit at the 

source shall comply with the 

monitoring, reporting, and 

recordkeeping requirements of §§ 97.930 

through 97.935. 

(2) The emissions data determined in 

accordance with §§ 97.930 through 

97.935 shall be used to calculate 

allocations of Texas SO2 Trading 

Program allowances under § 97.912 and 

to determine compliance with the Texas 

SO2 Trading Program emissions 

limitation under paragraph (c) of this 


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section, provided that, for each 

monitoring location from which mass 

emissions are reported, the mass 

emissions amount used in calculating 

such allocations and determining such 

compliance shall be the mass emissions 

amount for the monitoring location 

determined in accordance with 

§§ 97.930 through 97.935 and rounded 

to the nearest ton, with any fraction of 

a ton less than 0.50 being deemed to be 

zero and any fraction of a ton greater 

than or equal to 0.50 being deemed to 

be a whole ton. 

(c) SO2 emissions requirements—(1) 

Texas SO2 Trading Program emissions 

limitation. (i) As of the allowance 

transfer deadline for a control period in 

a given year, the owners and operators 

of each Texas SO2 Trading Program 

source and each Texas SO2 Trading 

Program unit at the source shall hold, in 

the source’s compliance account, Texas 

SO2 Trading Program allowances 

available for deduction for such control 

period under § 97.924(a) in an amount 

not less than the tons of total SO2

emissions for such control period from 

all Texas SO2 Trading Program units at 

the source. 

(ii) If total SO2 emissions during a 

control period in a given year from the 

Texas SO2 Trading Program units at a 

Texas SO2 Trading Program source are 

in excess of the Texas SO2 Trading 

Program emissions limitation set forth 

in paragraph (c)(1)(i) of this section, 

then: 

(A) The owners and operators of the 

source and each Texas SO2 Trading 

Program unit at the source shall hold 

the Texas SO2 Trading Program 

allowances required for deduction 

under § 97.924(d); and 

(B) The owners and operators of the 

source and each Texas SO2 Trading 

Program unit at the source shall pay any 

fine, penalty, or assessment or comply 

with any other remedy imposed, for the 

same violations, under the Clean Air 

Act, and each ton of such excess 

emissions and each day of such control 

period shall constitute a separate 

violation of this subpart and the Clean 

Air Act. 

(2) Compliance periods. A Texas SO2

Trading Program unit shall be subject to 

the requirements under paragraph (c)(1) 

of this section for the control period 

starting on the later of January 1, 2019 

or the deadline for meeting the unit’s 

monitor certification requirements 

under § 97.930(b) and for each control 

period thereafter. 

(3) Vintage of Texas SO2 Trading 

Program allowances held for 

compliance. (i) A Texas SO2 Trading 

Program allowance held for compliance 

with the requirements under paragraph 

(c)(1)(i) of this section for a control 

period in a given year must be a Texas 

SO2 Trading Program allowance that 

was allocated for such control period or 

a control period in a prior year. 

(ii) A Texas SO2 Trading Program 

allowance held for compliance with the 

requirements under paragraph 

(c)(1)(ii)(A) of this section for a control 

period in a given year must be a Texas 

SO2 Trading Program allowance that 

was allocated for a control period in a 

prior year or the control period in the 

given year or in the immediately 

following year. 

(4) Allowance Management System 

requirements. Each Texas SO2 Trading 

Program allowance shall be held in, 

deducted from, or transferred into, out 

of, or between Allowance Management 

System accounts in accordance with 

this subpart. 

(5) Limited authorization. A Texas 

SO2 Trading Program allowance is a 

limited authorization to emit one ton of 

SO2 during the control period in one 

year. Such authorization is limited in its 

use and duration as follows: 

(i) Such authorization shall only be 

used in accordance with the Texas SO2

Trading Program; and 

(ii) Notwithstanding any other 

provision of this subpart, the 

Administrator has the authority to 

terminate or limit the use and duration 

of such authorization to the extent the 

Administrator determines is necessary 

or appropriate to implement any 

provision of the Clean Air Act. 

(6) Property right. A Texas SO2

Trading Program allowance does not 

constitute a property right. 

(d) Title V permit requirements. (1) No 

title V permit revision shall be required 

for any allocation, holding, deduction, 

or transfer of Texas SO2 Trading 

Program allowances in accordance with 

this subpart. 

(2) A description of whether a unit is 

required to monitor and report SO2

emissions using a continuous emission 

monitoring system (under subpart B of 

part 75 of this chapter), an excepted 

monitoring system (under appendices D 

and E to part 75 of this chapter), a low 

mass emissions excepted monitoring 

methodology (under § 75.19 of this 

chapter), or an alternative monitoring 

system (under subpart E of part 75 of 

this chapter) in accordance with 

§§ 97.930 through 97.935 may be added 

to, or changed in, a title V permit using 

minor permit modification procedures 

in accordance with §§ 70.7(e)(2) and 

71.7(e)(1) of this chapter, provided that 

the requirements applicable to the 

described monitoring and reporting (as 

added or changed, respectively) are 

already incorporated in such permit. 

This paragraph explicitly provides that 

the addition of, or change to, a unit’s 

description as described in the prior 

sentence is eligible for minor permit 

modification procedures in accordance 

with §§ 70.7(e)(2)(i)(B) and 

71.7(e)(1)(i)(B) of this chapter. 

(e) Additional recordkeeping and 

reporting requirements. (1) Unless 

otherwise provided, the owners and 

operators of each Texas SO2 Trading 

Program source and each Texas SO2

Trading Program unit at the source shall 

keep on site at the source each of the 

following documents (in hardcopy or 

electronic format) for a period of 5 years 

from the date the document is created. 

This period may be extended for cause, 

at any time before the end of 5 years, in 

writing by the Administrator. 

(i) The certificate of representation 

under § 97.916 for the designated 

representative for the source and each 

Texas SO2 Trading Program unit at the 

source and all documents that 

demonstrate the truth of the statements 

in the certificate of representation; 

provided that the certificate and 

documents shall be retained on site at 

the source beyond such 5-year period 

until such certificate of representation 

and documents are superseded because 

of the submission of a new certificate of 

representation under § 97.916 changing 

the designated representative. 

(ii) All emissions monitoring 

information, in accordance with this 

subpart. 

(iii) Copies of all reports, compliance 

certifications, and other submissions 

and all records made or required under, 

or to demonstrate compliance with the 

requirements of, the Texas SO2 Trading 

Program. 

(2) The designated representative of a 

Texas SO2 Trading Program source and 

each Texas SO2 Trading Program unit at 

the source shall make all submissions 

required under the Texas SO2 Trading 

Program, except as provided in § 97.918. 

This requirement does not change, 

create an exemption from, or otherwise 

affect the responsible official 

submission requirements under a title V 

operating permit program in parts 70 

and 71 of this chapter. 

(f) Liability. (1) Any provision of the 

Texas SO2 Trading Program that applies 

to a Texas SO2 Trading Program source 

or the designated representative of a 

Texas SO2 Trading Program source shall 

also apply to the owners and operators 

of such source and of the Texas SO2

Trading Program units at the source. 

(2) Any provision of the Texas SO2

Trading Program that applies to a Texas 

SO2 Trading Program unit or the 

designated representative of a Texas SO2


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Trading Program unit shall also apply to 

the owners and operators of such unit. 

(g) Effect on other authorities. No 

provision of the Texas SO2 Trading 

Program or exemption under § 97.905 

shall be construed as exempting or 

excluding the owners and operators, 

and the designated representative, of a 

Texas SO2 Trading Program source or 

Texas SO2 Trading Program unit from 

compliance with any other provision of 

the applicable, approved State 

implementation plan, a federally 

enforceable permit, or the Clean Air Act. 

§ 97.907 Computation of time. 

(a) Unless otherwise stated, any time 

period scheduled, under the Texas SO2

Trading Program, to begin on the 

occurrence of an act or event shall begin 

on the day the act or event occurs. 

(b) Unless otherwise stated, any time 

period scheduled, under the Texas SO2

Trading Program, to begin before the 

occurrence of an act or event shall be 

computed so that the period ends the 

day before the act or event occurs. 

(c) Unless otherwise stated, if the final 

day of any time period, under the Texas 

SO2 Trading Program, is not a business 

day, the time period shall be extended 

to the next business day. 

§ 97.908 Administrative appeal 

procedures. 

The administrative appeal procedures 

for decisions of the Administrator under 

the Texas SO2 Trading Program are set 

forth in part 78 of this chapter. 

§ 97.909 [Reserved] 

§ 97.910 Texas SO2 Trading Program and 

Supplemental Allowance Pool Budgets. 

(a) The budgets for the Texas SO2

Trading Program and Supplemental 

Allowance Pool for the control periods 

in 2019 and thereafter are as follows: 

(1) The Texas SO2 Trading Program 

budget for the control period in 2019 

and each future control period is 

238,393 tons. 

(2) The Texas SO2 Trading Program 

Supplemental Allowance Pool budget 

for the control period in 2019 and each 

future control period is 10,000 tons. 

(b) [reserved] 

§ 97.911 Texas SO2 Trading Program 

allowance allocations. 

(a)(1) Except as provided in paragraph 

(a)(2) of this section, Texas SO2 Trading 

Program allowances from the Texas SO2

Trading Program budget will be 

allocated, for the control periods in 

2019 and each year thereafter, as 

provided in the following table: 

Texas SO2 trading program units ORIS code 

Texas SO2

trading 

program 

allocation 

Big Brown Unit 1 ...................................................................................................................................................... 3497 8,473 

Big Brown Unit 2 ...................................................................................................................................................... 3497 8,559 

Coleto Creek Unit 1 ................................................................................................................................................. 6178 9,057 

Fayette/Sam Seymour Unit 1 .................................................................................................................................. 6179 7,979 

Fayette/Sam Seymour Unit 2 .................................................................................................................................. 6179 8,019 

Graham Unit 2 ......................................................................................................................................................... 3490 226 

H W Pirkey Power Plant Unit 1 ............................................................................................................................... 7902 8,882 

Harrington Unit 061B ............................................................................................................................................... 6193 5,361 

Harrington Unit 062B ............................................................................................................................................... 6193 5,255 

Harrington Unit 063B ............................................................................................................................................... 6193 5,055 

JT Deely Unit 1 ........................................................................................................................................................ 6181 6,170 

JT Deely Unit 2 ........................................................................................................................................................ 6181 6,082 

Limestone Unit 1 ...................................................................................................................................................... 298 12,081 

Limestone Unit 2 ...................................................................................................................................................... 298 12,293 

Martin Lake Unit 1 ................................................................................................................................................... 6146 12,024 

Martin Lake Unit 2 ................................................................................................................................................... 6146 11,580 

Martin Lake Unit 3 ................................................................................................................................................... 6146 12,236 

Monticello Unit 1 ...................................................................................................................................................... 6147 8,598 

Monticello Unit 2 ...................................................................................................................................................... 6147 8,795 

Monticello Unit 3 ...................................................................................................................................................... 6147 12,216 

Newman Unit 2 ........................................................................................................................................................ 3456 1 

Newman Unit 3 ........................................................................................................................................................ 3456 1 

Newman Unit 4 ........................................................................................................................................................ 3456 2 

Sandow Unit 4 ......................................................................................................................................................... 6648 8,370 

Sommers Unit 1 ....................................................................................................................................................... 3611 55 

Sommers Unit 2 ....................................................................................................................................................... 3611 7 

Stryker Unit ST2 ...................................................................................................................................................... 3504 145 

Tolk Station Unit 171B ............................................................................................................................................. 6194 6,900 

Tolk Station Unit 172B ............................................................................................................................................. 6194 7,062 

WA Parish Unit WAP4 ............................................................................................................................................. 3470 3 

WA Parish Unit WAP5 ............................................................................................................................................. 3470 9,580 

WA Parish Unit WAP6 ............................................................................................................................................. 3470 8,900 

WA Parish Unit WAP7 ............................................................................................................................................. 3470 7,653 

Welsh Power Plant Unit 1 ....................................................................................................................................... 6139 6,496 

Welsh Power Plant Unit 2 ....................................................................................................................................... 6139 7,050 

Welsh Power Plant Unit 3 ....................................................................................................................................... 6139 7,208 

Wilkes Unit 1 ............................................................................................................................................................ 3478 14 

Wilkes Unit 2 ............................................................................................................................................................ 3478 2 

Wilkes Unit 3 ............................................................................................................................................................ 3478 3 

(2) Notwithstanding paragraph (a)(1) 

of this section, if a unit provided an 

allocation pursuant to the table in 

paragraph (a)(1) of this section does not 

operate, starting after 2018, during the 

control period in two consecutive years, 

such unit will not be allocated the Texas 

SO2 Trading Program allowances 

provided in paragraph (a)(1) of this 


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section for the unit for the control 

periods in the fifth year after the first 

such year and in each year after that 

fifth year. All Texas SO2 Trading 

Program allowances that would 

otherwise have been allocated to such 

unit will be allocated under the Texas 

Supplemental Allowance Pool under 40 

CFR 97.912. 

(b)(1) A unit that becomes a Texas 

SO2 Trading Program unit pursuant to 

§ 97.904(b) will receive an allocation of 

Texas SO2 Trading Program allowances 

equal to the SO2 allocation shown for 

the unit in the table referenced in 

§ 97.404(b)(1) (ignoring the years shown 

in the column headings in the table) for 

the control period in each year while 

the unit is a Texas SO2 Trading Program 

unit, provided that the unit has operated 

during the calendar year immediately 

preceding the year of each such control 

period. 

(2) If a unit that becomes a Texas SO2

Trading Program unit pursuant to 

§ 97.904(b) does not operate during a 

given calendar year, no Texas SO2

Trading Program allowances will be 

allocated to that unit for the control 

period in the following year or any 

subsequent year, nor will any 

allowances that would otherwise have 

been allocated to such unit under 

paragraph (b)(1) of this section be made 

available for use by any other unit under 

the Texas Supplemental Allowance Pool 

or otherwise. 

(c) Units incorrectly allocated Texas 

SO2 Trading Program allowances. (1) 

For each control period in 2019 and 

thereafter, if the Administrator 

determines that Texas SO2 Trading 

Program allowances were incorrectly 

allocated under paragraph (a) or (b) of 

this section, or under a provision of a 

SIP revision approved by the 

Administrator, then the Administrator 

will notify the designated representative 

of the recipient and will act in 

accordance with the procedures set 

forth in paragraphs (c)(2) through (5) of 

this section: 

(2) Except as provided in paragraph 

(c)(3) or (4) of this section, the 

Administrator will not record such 

Texas SO2 Trading Program allowances 

under § 97.921. 

(3) If the Administrator already 

recorded such Texas SO2 Trading 

Program allowances under § 97.921 and 

if the Administrator makes the 

determination under paragraph (c)(1) of 

this section before making deductions 

for the source that includes such 

recipient under § 97.924(b) for such 

control period, then the Administrator 

will deduct from the account in which 

such Texas SO2 Trading Program 

allowances were recorded an amount of 

Texas SO2 Trading Program allowances 

allocated for the same or a prior control 

period equal to the amount of such 

already recorded Texas SO2 Trading 

Program allowances. The authorized 

account representative shall ensure that 

there are sufficient Texas SO2 Trading 

Program allowances in such account for 

completion of the deduction. 

(4) If the Administrator already 

recorded such Texas SO2 Trading 

Program allowances under § 97.921 and 

if the Administrator makes the 

determination under paragraph (c)(1) of 

this section after making deductions for 

the source that includes such recipient 

under § 97.924(b) for such control 

period, then the Administrator will not 

make any deduction to take account of 

such already recorded Texas SO2

Trading Program allowances. 

(5) With regard to the Texas SO2

Trading Program allowances that are not 

recorded, or that are deducted as an 

incorrect allocation, in accordance with 

paragraphs (c)(2) and (3) of this section 

for a recipient under paragraph (a) of 

this section, the Administrator will 

transfer such Texas SO2 Trading 

Program allowances to the Texas 

Supplemental Allowance Pool under 40 

CFR 97.912. With regard to the Texas 

SO2 Trading Program allowances that 

are not recorded, or that are deducted as 

an incorrect allocation, in accordance 

with paragraphs (c)(2) and (3) of this 

section for a recipient under paragraph 

(b) of this section, the Administrator 

will retire such Texas SO2 Trading 

Program allowances. 

§ 97.912 Texas SO2 Trading Program 

Supplemental Allowance Pool. 

(a) For each control period in 2019 

and thereafter, the Administrator will 

allocate Texas SO2 Trading Program 

allowances from the Texas SO2 Trading 

Program Supplemental Allowance Pool 

as follows: 

(1) No later than February 15, 2020 

and each subsequent February 15, the 

Administrator will review all the 

quarterly SO2 emissions reports 

provided under § 97.934(d) for each 

Texas SO2 Trading Program unit for the 

previous control period. The 

Administrator will identify each Texas 

SO2 Trading Program source for which 

the total amount of emissions reported 

for the units at the source for that 

control period exceeds the total amount 

of allowances allocated to the units at 

the source for that control period under 

§ 97.911. 

(2) For each Texas SO2 Trading 

Program source identified under 

paragraph (a)(1) of this section, the 

Administrator will calculate the amount 

by which the total amount of reported 

emissions for that control period 

exceeds the total amount of allowances 

allocated for that control period under 

§ 97.911. 

(3)(i) For Coleto Creek (ORIS 6178), if 

the source is identified under paragraph 

(a)(1) of this section, the Administrator 

will allocate and record in the source’s 

compliance account an amount of 

allowances from the Supplemental 

Allowance Pool equal to the lesser of 

the amount calculated for the source 

under paragraph (a)(2) of this section or 

the total number of allowances in the 

Supplemental Allowance Pool available 

for allocation under paragraph (b) of this 

section. 

(ii) For any Texas SO2 Trading 

Program sources identified under 

paragraph (a)(1) of this section other 

than Coleto Creek (ORIS 6178), the 

Administrator will allocate and record 

allowances from the Supplemental 

Allowance Pool as follows: 

(A) If the total for all such sources of 

the amounts calculated under paragraph 

(a)(2) of this section is less than or equal 

to the total number of allowances in the 

Supplemental Allowance Pool available 

for allocation under paragraph (b) of this 

section that remain after any allocation 

under paragraph (a)(3)(i) of this section, 

then the Administrator will allocate and 

record in the compliance account for 

each such source an amount of 

allowances from the Supplemental 

Allowance Pool equal to the amount 

calculated for the source under 

paragraph (a)(2) of this section. 

(B) If the total for all such sources of 

the amounts calculated under paragraph 

(a)(2) of this section is greater than the 

total number of allowances in the 

Supplemental Allowance Pool available 

for allocation under paragraph (b) of this 

section that remain after any allocation 

under paragraph (a)(3)(i) of this section, 

then the Administrator will calculate 

each such source’s allocation of 

allowances from the Supplemental 

Allowance Pool by dividing the amount 

calculated under paragraph (a)(2) of this 

section for the source by the sum of the 

amounts calculated under paragraph 

(a)(2) of this section for all such sources, 

then multiplying by the number of 

allowances in the Supplemental 

Allowance Pool available for allocation 

under paragraph (b) of this section that 

remain after any allocation under 

paragraph (a)(3)(i) of this section and 

rounding to the nearest allowance. The 

Administrator will then record the 

calculated allocations of allowances in 

the applicable compliance accounts. 

(iii) Any unallocated allowances 

remaining in the Supplemental 

Allowance Pool after the allocations 

determined under paragraphs (a)(3)(i) 


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and (ii) of this section will be 

maintained in the Supplemental 

Allowance Pool. These allowances will 

be available for allocation by the 

Administrator in subsequent control 

periods to the extent consistent with 

paragraph (b) of this section. 

(4) The Administrator will notify the 

designated representative of each Texas 

SO2 Trading Program source when the 

allowances from the Supplemental 

Allowance Pool have been recorded. 

(b) The total amount of allowances in 

the Texas SO2 Trading Program 

Supplemental Allowance Pool available 

for allocation for a control period is 

equal to the sum of the Texas SO2

Trading Program Supplemental 

Allowance Pool budget under 

§ 97.910(a)(2), any allowances from 

retired units pursuant to § 97.911(a)(2) 

and from corrections pursuant to 

§ 97.911(c)(5), and any allowances 

maintained in the Supplemental 

Allowance Pool pursuant to paragraph 

(a)(3)(iii) of this section, but cannot 

exceed by more than 44,711 tons the 

sum of the budget provided under 

§ 97.910(a)(2) and any portion of the 

budget provided under § 97.910(a)(1) 

not otherwise allocated for that control 

period under § 97.911(a)(1). If the 

number of allowances in the 

Supplemental Allowance Pool exceeds 

this level then the Administrator may 

only allocate allowances up to this level 

for the control period. 

§ 97.913 Authorization of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.915, 

each Texas SO2 Trading Program source, 

including all Texas SO2 Trading 

Program units at the source, shall have 

one and only one designated 

representative, with regard to all matters 

under the Texas SO2 Trading Program. 

(1) The designated representative 

shall be selected by an agreement 

binding on the owners and operators of 

the source and all Texas SO2 Trading 

Program units at the source and shall act 

in accordance with the certification 

statement in § 97.916(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.916: 

(i) The designated representative shall 

be authorized and shall represent and, 

by his or her representations, actions, 

inactions, or submissions, legally bind 

each owner and operator of the source 

and each Texas SO2 Trading Program 

unit at the source in all matters 

pertaining to the Texas SO2 Trading 

Program, notwithstanding any 

agreement between the designated 

representative and such owners and 

operators; and 

(ii) The owners and operators of the 

source and each Texas SO2 Trading 

Program unit at the source shall be 

bound by any decision or order issued 

to the designated representative by the 

Administrator regarding the source or 

any such unit. 

(b) Except as provided under § 97.915, 

each Texas SO2 Trading Program source 

may have one and only one alternate 

designated representative, who may act 

on behalf of the designated 

representative. The agreement by which 

the alternate designated representative 

is selected shall include a procedure for 

authorizing the alternate designated 

representative to act in lieu of the 

designated representative. 

(1) The alternate designated 

representative shall be selected by an 

agreement binding on the owners and 

operators of the source and all Texas 

SO2 Trading Program units at the source 

and shall act in accordance with the 

certification statement in 

§ 97.916(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.916, 

(i) The alternate designated 

representative shall be authorized; 

(ii) Any representation, action, 

inaction, or submission by the alternate 

designated representative shall be 

deemed to be a representation, action, 

inaction, or submission by the 

designated representative; and 

(iii) The owners and operators of the 

source and each Texas SO2 Trading 

Program unit at the source shall be 

bound by any decision or order issued 

to the alternate designated 

representative by the Administrator 

regarding the source or any such unit. 

(c) Except in this section, § 97.902, 

and §§ 97.914 through 97.918, whenever 

the term ‘‘designated representative’’ is 

used in this subpart, the term shall be 

construed to include the designated 

representative or any alternate 

designated representative. 

§ 97.914 Responsibilities of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.918 

concerning delegation of authority to 

make submissions, each submission 

under the Texas SO2 Trading Program 

shall be made, signed, and certified by 

the designated representative or 

alternate designated representative for 

each Texas SO2 Trading Program source 

and Texas SO2 Trading Program unit for 

which the submission is made. Each 

such submission shall include the 

following certification statement by the 

designated representative or alternate 

designated representative: ‘‘I am 

authorized to make this submission on 

behalf of the owners and operators of 

the source or units for which the 

submission is made. I certify under 

penalty of law that I have personally 

examined, and am familiar with, the 

statements and information submitted 

in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(b) The Administrator will accept or 

act on a submission made for a Texas 

SO2 Trading Program source or a Texas 

SO2 Trading Program unit only if the 

submission has been made, signed, and 

certified in accordance with paragraph 

(a) of this section and § 97.918. 

§ 97.915 Changing designated 

representative and alternate designated 

representative; changes in owners and 

operators; changes in units at the source. 

(a) Changing designated 

representative. The designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 97.916. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous designated 

representative before the time and date 

when the Administrator receives the 

superseding certificate of representation 

shall be binding on the new designated 

representative and the owners and 

operators of the Texas SO2 Trading 

Program source and the Texas SO2

Trading Program units at the source. 

(b) Changing alternate designated 

representative. The alternate designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 97.916. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous alternate 

designated representative before the 

time and date when the Administrator 

receives the superseding certificate of 

representation shall be binding on the 

new alternate designated representative, 

the designated representative, and the 

owners and operators of the Texas SO2

Trading Program source and the Texas 


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SO2 Trading Program units at the 

source. 

(c) Changes in owners and operators. 

(1) In the event an owner or operator of 

a Texas SO2 Trading Program source or 

a Texas SO2 Trading Program unit at the 

source is not included in the list of 

owners and operators in the certificate 

of representation under § 97.916, such 

owner or operator shall be deemed to be 

subject to and bound by the certificate 

of representation, the representations, 

actions, inactions, and submissions of 

the designated representative and any 

alternate designated representative of 

the source or unit, and the decisions 

and orders of the Administrator, as if 

the owner or operator were included in 

such list. 

(2) Within 30 days after any change in 

the owners and operators of a Texas SO2

Trading Program source or a Texas SO2

Trading Program unit at the source, 

including the addition or removal of an 

owner or operator, the designated 

representative or any alternate 

designated representative shall submit a 

revision to the certificate of 

representation under § 97.916 amending 

the list of owners and operators to 

reflect the change. 

(d) Changes in units at the source. 

Within 30 days of any change in which 

units are located at a Texas SO2 Trading 

Program source (including the addition 

(see § 97.904(b)) or removal of a unit), 

the designated representative or any 

alternate designated representative shall 

submit a certificate of representation 

under § 97.916 amending the list of 

units to reflect the change. 

(1) If the change is the addition of a 

unit (see § 97.904(b)) that operated 

(other than for purposes of testing by the 

manufacturer before initial installation) 

before being located at the source, then 

the certificate of representation shall 

identify, in a format prescribed by the 

Administrator, the entity from whom 

the unit was purchased or otherwise 

obtained (including name, address, 

telephone number, and facsimile 

number (if any)), the date on which the 

unit was purchased or otherwise 

obtained, and the date on which the 

unit became located at the source. 

(2) If the change is the removal of a 

unit, then the certificate of 

representation shall identify, in a format 

prescribed by the Administrator, the 

entity to which the unit was sold or that 

otherwise obtained the unit (including 

name, address, telephone number, and 

facsimile number (if any)), the date on 

which the unit was sold or otherwise 

obtained, and the date on which the 

unit became no longer located at the 

source. 

§ 97.916 Certificate of representation. 

(a) A complete certificate of 

representation for a designated 

representative or an alternate designated 

representative shall include the 

following elements in a format 

prescribed by the Administrator: 

(1) Identification of the Texas SO2

Trading Program source, and each Texas 

SO2 Trading Program unit at the source, 

for which the certificate of 

representation is submitted, including 

source name, source category and 

NAICS code (or, in the absence of a 

NAICS code, an equivalent code), State, 

plant code, county, latitude and 

longitude, unit identification number 

and type, identification number and 

nameplate capacity (in MWe, rounded 

to the nearest tenth) of each generator 

served by each such unit, and actual 

date of commencement of commercial 

operation, and a statement of whether 

such source is located in Indian 

country. 

(2) The name, address, email address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the designated representative and any 

alternate designated representative. 

(3) A list of the owners and operators 

of the Texas SO2 Trading Program 

source and of each Texas SO2 Trading 

Program unit at the source. 

(4) The following certification 

statements by the designated 

representative and any alternate 

designated representative— 

(i) ‘‘I certify that I was selected as the 

designated representative or alternate 

designated representative, as applicable, 

by an agreement binding on the owners 

and operators of the source and each 

Texas SO2 Trading Program unit at the 

source.’’ 

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the 

Texas SO2 Trading Program on behalf of 

the owners and operators of the source 

and of each Texas SO2 Trading Program 

unit at the source and that each such 

owner and operator shall be fully bound 

by my representations, actions, 

inactions, or submissions and by any 

decision or order issued to me by the 

Administrator regarding the source or 

unit.’’ 

(iii) ‘‘Where there are multiple 

holders of a legal or equitable title to, or 

a leasehold interest in, a Texas SO2

Trading Program unit, or where a utility 

or industrial customer purchases power 

from a Texas SO2 Trading Program unit 

under a life-of-the-unit, firm power 

contractual arrangement, I certify that: I 

have given a written notice of my 

selection as the ‘designated 

representative’ or ‘alternate designated 

representative’, as applicable, and of the 

agreement by which I was selected to 

each owner and operator of the source 

and of each Texas SO2 Trading Program 

unit at the source; and Texas SO2

Trading Program allowances and 

proceeds of transactions involving 

Texas SO2 Trading Program allowances 

will be deemed to be held or distributed 

in proportion to each holder’s legal, 

equitable, leasehold, or contractual 

reservation or entitlement, except that, 

if such multiple holders have expressly 

provided for a different distribution of 

Texas SO2 Trading Program allowances 

by contract, Texas SO2 Trading Program 

allowances and proceeds of transactions 

involving Texas SO2 Trading Program 

allowances will be deemed to be held or 

distributed in accordance with the 

contract.’’ 

(5) The signature of the designated 

representative and any alternate 

designated representative and the dates 

signed. 

(b) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the certificate of 

representation shall not be submitted to 

the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

§ 97.917 Objections concerning 

designated representative and alternate 

designated representative. 

(a) Once a complete certificate of 

representation under § 97.916 has been 

submitted and received, the 

Administrator will rely on the certificate 

of representation unless and until a 

superseding complete certificate of 

representation under § 97.916 is 

received by the Administrator. 

(b) Except as provided in paragraph 

(a) of this section, no objection or other 

communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission, of a 

designated representative or alternate 

designated representative shall affect 

any representation, action, inaction, or 

submission of the designated 

representative or alternate designated 

representative or the finality of any 

decision or order by the Administrator 

under the Texas SO2 Trading Program. 

(c) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of any designated 

representative or alternate designated 

representative, including private legal 

disputes concerning the proceeds of 

Texas SO2 Trading Program allowance 

transfers. 


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§ 97.918 Delegation by designated 

representative and alternate designated 

representative. 

(a) A designated representative may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(b) An alternate designated 

representative may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(c) In order to delegate authority to a 

natural person to make an electronic 

submission to the Administrator in 

accordance with paragraph (a) or (b) of 

this section, the designated 

representative or alternate designated 

representative, as appropriate, must 

submit to the Administrator a notice of 

delegation, in a format prescribed by the 

Administrator, that includes the 

following elements: 

(1) The name, address, email address, 

telephone number, and facsimile 

transmission number (if any) of such 

designated representative or alternate 

designated representative; 

(2) The name, address, email address, 

telephone number, and facsimile 

transmission number (if any) of each 

such natural person (referred to in this 

section as an ‘‘agent’’); 

(3) For each such natural person, a list 

of the type or types of electronic 

submissions under paragraph (a) or (b) 

of this section for which authority is 

delegated to him or her; and 

(4) The following certification 

statements by such designated 

representative or alternate designated 

representative: 

(i) ‘‘I agree that any electronic 

submission to the Administrator that is 

made by an agent identified in this 

notice of delegation and of a type listed 

for such agent in this notice of 

delegation and that is made when I am 

a designated representative or alternate 

designated representative, as 

appropriate, and before this notice of 

delegation is superseded by another 

notice of delegation under 40 CFR 

97.918(d) shall be deemed to be an 

electronic submission by me.’’ 

(ii) ‘‘Until this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 97.918(d), I 

agree to maintain an email account and 

to notify the Administrator immediately 

of any change in my email address 

unless all delegation of authority by me 

under 40 CFR 97.918 is terminated.’’ 

(d) A notice of delegation submitted 

under paragraph (c) of this section shall 

be effective, with regard to the 

designated representative or alternate 

designated representative identified in 

such notice, upon receipt of such notice 

by the Administrator and until receipt 

by the Administrator of a superseding 

notice of delegation submitted by such 

designated representative or alternate 

designated representative, as 

appropriate. The superseding notice of 

delegation may replace any previously 

identified agent, add a new agent, or 

eliminate entirely any delegation of 

authority. 

(e) Any electronic submission covered 

by the certification in paragraph (c)(4)(i) 

of this section and made in accordance 

with a notice of delegation effective 

under paragraph (d) of this section shall 

be deemed to be an electronic 

submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

§ 97.919 [Reserved] 

§ 97.920 Establishment of compliance 

accounts and general accounts. 

(a) Compliance accounts. Upon 

receipt of a complete certificate of 

representation under § 97.916, the 

Administrator will establish a 

compliance account for the Texas SO2

Trading Program source for which the 

certificate of representation was 

submitted, unless the source already has 

a compliance account. The designated 

representative and any alternate 

designated representative of the source 

shall be the authorized account 

representative and the alternate 

authorized account representative 

respectively of the compliance account. 

(b) General accounts—(1) Application 

for general account. (i) Any person may 

apply to open a general account, for the 

purpose of holding and transferring 

Texas SO2 Trading Program allowances, 

by submitting to the Administrator a 

complete application for a general 

account. Such application shall 

designate one and only one authorized 

account representative and may 

designate one and only one alternate 

authorized account representative who 

may act on behalf of the authorized 

account representative. 

(A) The authorized account 

representative and alternate authorized 

account representative shall be selected 

by an agreement binding on the persons 

who have an ownership interest with 

respect to Texas SO2 Trading Program 

allowances held in the general account. 

(B) The agreement by which the 

alternate authorized account 

representative is selected shall include 

a procedure for authorizing the alternate 

authorized account representative to act 

in lieu of the authorized account 

representative. 

(ii) A complete application for a 

general account shall include the 

following elements in a format 

prescribed by the Administrator: 

(A) Name, mailing address, email 

address (if any), telephone number, and 

facsimile transmission number (if any) 

of the authorized account representative 

and any alternate authorized account 

representative; 

(B) An identifying name for the 

general account; 

(C) A list of all persons subject to a 

binding agreement for the authorized 

account representative and any alternate 

authorized account representative to 

represent their ownership interest with 

respect to the Texas SO2 Trading 

Program allowances held in the general 

account; 

(D) The following certification 

statement by the authorized account 

representative and any alternate 

authorized account representative: ‘‘I 

certify that I was selected as the 

authorized account representative or the 

alternate authorized account 

representative, as applicable, by an 

agreement that is binding on all persons 

who have an ownership interest with 

respect to Texas SO2 Trading Program 

allowances held in the general account. 

I certify that I have all the necessary 

authority to carry out my duties and 

responsibilities under the Texas SO2

Trading Program on behalf of such 

persons and that each such person shall 

be fully bound by my representations, 

actions, inactions, or submissions and 

by any decision or order issued to me 

by the Administrator regarding the 

general account.’’ 

(E) The signature of the authorized 

account representative and any alternate 

authorized account representative and 

the dates signed. 

(iii) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the application for a 

general account shall not be submitted 

to the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

(2) Authorization of authorized 

account representative and alternate 

authorized account representative. (i) 

Upon receipt by the Administrator of a 

complete application for a general 

account under paragraph (b)(1) of this 

section, the Administrator will establish 

a general account for the person or 

persons for whom the application is 

submitted, and upon and after such 

receipt by the Administrator: 


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(A) The authorized account 

representative of the general account 

shall be authorized and shall represent 

and, by his or her representations, 

actions, inactions, or submissions, 

legally bind each person who has an 

ownership interest with respect to Texas 

SO2 Trading Program allowances held 

in the general account in all matters 

pertaining to the Texas SO2 Trading 

Program, notwithstanding any 

agreement between the authorized 

account representative and such person. 

(B) Any alternate authorized account 

representative shall be authorized, and 

any representation, action, inaction, or 

submission by any alternate authorized 

account representative shall be deemed 

to be a representation, action, inaction, 

or submission by the authorized account 

representative. 

(C) Each person who has an 

ownership interest with respect to Texas 

SO2 Trading Program allowances held 

in the general account shall be bound by 

any decision or order issued to the 

authorized account representative or 

alternate authorized account 

representative by the Administrator 

regarding the general account. 

(ii) Except as provided in paragraph 

(b)(5) of this section concerning 

delegation of authority to make 

submissions, each submission 

concerning the general account shall be 

made, signed, and certified by the 

authorized account representative or 

any alternate authorized account 

representative for the persons having an 

ownership interest with respect to Texas 

SO2 Trading Program allowances held 

in the general account. Each such 

submission shall include the following 

certification statement by the authorized 

account representative or any alternate 

authorized account representative: ‘‘I 

am authorized to make this submission 

on behalf of the persons having an 

ownership interest with respect to the 

Texas SO2 Trading Program allowances 

held in the general account. I certify 

under penalty of law that I have 

personally examined, and am familiar 

with, the statements and information 

submitted in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(iii) Except in this section, whenever 

the term ‘‘authorized account 

representative’’ is used in this subpart, 

the term shall be construed to include 

the authorized account representative or 

any alternate authorized account 

representative. 

(3) Changing authorized account 

representative and alternate authorized 

account representative; changes in 

persons with ownership interest. (i) The 

authorized account representative of a 

general account may be changed at any 

time upon receipt by the Administrator 

of a superseding complete application 

for a general account under paragraph 

(b)(1) of this section. Notwithstanding 

any such change, all representations, 

actions, inactions, and submissions by 

the previous authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

authorized account representative and 

the persons with an ownership interest 

with respect to the Texas SO2 Trading 

Program allowances in the general 

account. 

(ii) The alternate authorized account 

representative of a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (b)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous alternate authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

alternate authorized account 

representative, the authorized account 

representative, and the persons with an 

ownership interest with respect to the 

Texas SO2 Trading Program allowances 

in the general account. 

(iii)(A) In the event a person having 

an ownership interest with respect to 

Texas SO2 Trading Program allowances 

in the general account is not included 

in the list of such persons in the 

application for a general account, such 

person shall be deemed to be subject to 

and bound by the application for a 

general account, the representation, 

actions, inactions, and submissions of 

the authorized account representative 

and any alternate authorized account 

representative of the account, and the 

decisions and orders of the 

Administrator, as if the person were 

included in such list. 

(B) Within 30 days after any change 

in the persons having an ownership 

interest with respect to Texas SO2

Trading Program allowances in the 

general account, including the addition 

or removal of a person, the authorized 

account representative or any alternate 

authorized account representative shall 

submit a revision to the application for 

a general account amending the list of 

persons having an ownership interest 

with respect to the Texas SO2 Trading 

Program allowances in the general 

account to include the change. 

(4) Objections concerning authorized 

account representative and alternate 

authorized account representative. (i) 

Once a complete application for a 

general account under paragraph (b)(1) 

of this section has been submitted and 

received, the Administrator will rely on 

the application unless and until a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section is received by the 

Administrator. 

(ii) Except as provided in paragraph 

(b)(4)(i) of this section, no objection or 

other communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission of the 

authorized account representative or 

any alternate authorized account 

representative of a general account shall 

affect any representation, action, 

inaction, or submission of the 

authorized account representative or 

any alternate authorized account 

representative or the finality of any 

decision or order by the Administrator 

under the Texas SO2 Trading Program. 

(iii) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative of a 

general account, including private legal 

disputes concerning the proceeds of 

Texas SO2 Trading Program allowance 

transfers. 

(5) Delegation by authorized account 

representative and alternate authorized 

account representative. (i) An 

authorized account representative of a 

general account may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(ii) An alternate authorized account 

representative of a general account may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(iii) In order to delegate authority to 

a natural person to make an electronic 

submission to the Administrator in 

accordance with paragraph (b)(5)(i) or 

(ii) of this section, the authorized 


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account representative or alternate 

authorized account representative, as 

appropriate, must submit to the 

Administrator a notice of delegation, in 

a format prescribed by the 

Administrator, that includes the 

following elements: 

(A) The name, address, email address, 

telephone number, and facsimile 

transmission number (if any) of such 

authorized account representative or 

alternate authorized account 

representative; 

(B) The name, address, email address, 

telephone number, and facsimile 

transmission number (if any) of each 

such natural person (referred to in this 

section as an ‘‘agent’’); 

(C) For each such natural person, a 

list of the type or types of electronic 

submissions under paragraph (b)(5)(i) or 

(ii) of this section for which authority is 

delegated to him or her; 

(D) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘I agree that any 

electronic submission to the 

Administrator that is made by an agent 

identified in this notice of delegation 

and of a type listed for such agent in 

this notice of delegation and that is 

made when I am an authorized account 

representative or alternate authorized 

account representative, as appropriate, 

and before this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 

97.920(b)(5)(iv) shall be deemed to be an 

electronic submission by me.’’; and 

(E) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘Until this 

notice of delegation is superseded by 

another notice of delegation under 40 

CFR 97.920(b)(5)(iv), I agree to maintain 

an email account and to notify the 

Administrator immediately of any 

change in my email address unless all 

delegation of authority by me under 40 

CFR 97.920(b)(5) is terminated.’’ 

(iv) A notice of delegation submitted 

under paragraph (b)(5)(iii) of this 

section shall be effective, with regard to 

the authorized account representative or 

alternate authorized account 

representative identified in such notice, 

upon receipt of such notice by the 

Administrator and until receipt by the 

Administrator of a superseding notice of 

delegation submitted by such 

authorized account representative or 

alternate authorized account 

representative, as appropriate. The 

superseding notice of delegation may 

replace any previously identified agent, 

add a new agent, or eliminate entirely 

any delegation of authority. 

(v) Any electronic submission covered 

by the certification in paragraph 

(b)(5)(iii)(D) of this section and made in 

accordance with a notice of delegation 

effective under paragraph (b)(5)(iv) of 

this section shall be deemed to be an 

electronic submission by the authorized 

account representative or alternate 

authorized account representative 

submitting such notice of delegation. 

(6) Closing a general account. (i) The 

authorized account representative or 

alternate authorized account 

representative of a general account may 

submit to the Administrator a request to 

close the account. Such request shall 

include a correctly submitted Texas SO2

Trading Program allowance transfer 

under § 97.922 for any Texas SO2

Trading Program allowances in the 

account to one or more other Allowance 

Management System accounts. 

(ii) If a general account has no Texas 

SO2 Trading Program allowance 

transfers to or from the account for a 12- 

month period or longer and does not 

contain any Texas SO2 Trading Program 

allowances, the Administrator may 

notify the authorized account 

representative for the account that the 

account will be closed after 30 days 

after the notice is sent. The account will 

be closed after the 30-day period unless, 

before the end of the 30-day period, the 

Administrator receives a correctly 

submitted Texas SO2 Trading Program 

allowance transfer under § 97.922 to the 

account or a statement submitted by the 

authorized account representative or 

alternate authorized account 

representative demonstrating to the 

satisfaction of the Administrator good 

cause as to why the account should not 

be closed. 

(c) Account identification. The 

Administrator will assign a unique 

identifying number to each account 

established under paragraph (a) or (b) of 

this section. 

(d) Responsibilities of authorized 

account representative and alternate 

authorized account representative. After 

the establishment of a compliance 

account or general account, the 

Administrator will accept or act on a 

submission pertaining to the account, 

including, but not limited to, 

submissions concerning the deduction 

or transfer of Texas SO2 Trading 

Program allowances in the account, only 

if the submission has been made, 

signed, and certified in accordance with 

§§ 97.914(a) and 97.918 or paragraphs 

(b)(2)(ii) and (b)(5) of this section. 

§ 97.921 Recordation of Texas SO2

Trading Program allowance allocations. 

(a) By November 1, 2018, the 

Administrator will record in each Texas 

SO2 Trading Program source’s 

compliance account the Texas SO2

Trading Program allowances allocated 

to the Texas SO2 Trading Program units 

at the source in accordance with 

§ 97.911(a) for the control periods in 

2019, 2020, 2021, and 2022. The 

Administrator may delay recordation of 

Texas SO2 Trading Program allowances 

for the specified control periods if the 

State of Texas submits a SIP revision 

before the recordation deadline. 

(b) By July 1, 2019 and July 1 of each 

year thereafter, the Administrator will 

record in each Texas SO2 Trading 

Program source’s compliance account 

the Texas SO2 Trading Program 

allowances allocated to the Texas SO2

Trading Program units at the source in 

accordance with § 97.911(a) for the 

control period in the fourth year after 

the year of the applicable recordation 

deadline under this paragraph. The 

Administrator may delay recordation of 

the Texas SO2 Trading Program 

allowances for the applicable control 

periods if the State of Texas submits a 

SIP revision by May 1 of the year of the 

applicable recordation deadline under 

this paragraph. 

(c) By February 15, 2020, and 

February 15 of each year thereafter, the 

Administrator will record in each Texas 

SO2 Trading Program source’s 

compliance account the allowances 

allocated from the Texas SO2 Trading 

Program Supplemental Allowance Pool 

in accordance with § 97.912 for the 

control period in the year of the 

applicable recordation deadline under 

this paragraph, . 

(d) By July 1, 2019 and July 1 of each 

year thereafter, the Administrator will 

record in each Texas SO2 Trading 

Program source’s compliance account 

the Texas SO2 Trading Program 

allowances allocated to the Texas SO2

Trading Program units at the source in 

accordance with § 97.911(b). 

(e) When recording the allocation of 

Texas SO2 Trading Program allowances 

to a Texas SO2 Trading Program unit in 

an Allowance Management System 

account, the Administrator will assign 

each Texas SO2 Trading Program 

allowance a unique identification 

number that will include digits 

identifying the year of the control 

period for which the Texas SO2 Trading 

Program allowance is allocated. 

§ 97.922 Submission of Texas SO2 Trading 

Program allowance transfers. 

(a) An authorized account 

representative seeking recordation of a 

Texas SO2 Trading Program allowance 

transfer shall submit the transfer to the 

Administrator. 


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(b) A Texas SO2 Trading Program 

allowance transfer shall be correctly 

submitted if: 

(1) The transfer includes the following 

elements, in a format prescribed by the 

Administrator: 

(i) The account numbers established 

by the Administrator for both the 

transferor and transferee accounts; 

(ii) The serial number of each Texas 

SO2 Trading Program allowance that is 

in the transferor account and is to be 

transferred; and 

(iii) The name and signature of the 

authorized account representative of the 

transferor account and the date signed; 

and 

(2) When the Administrator attempts 

to record the transfer, the transferor 

account includes each Texas SO2

Trading Program allowance identified 

by serial number in the transfer. 

§ 97.923 Recordation of Texas SO2

Trading Program allowance transfers. 

(a) Within 5 business days (except as 

provided in paragraph (b) of this 

section) of receiving a Texas SO2

Trading Program allowance transfer that 

is correctly submitted under § 97.922, 

the Administrator will record a Texas 

SO2 Trading Program allowance transfer 

by moving each Texas SO2 Trading 

Program allowance from the transferor 

account to the transferee account as 

specified in the transfer. 

(b) A Texas SO2 Trading Program 

allowance transfer to or from a 

compliance account that is submitted 

for recordation after the allowance 

transfer deadline for a control period 

and that includes any Texas SO2

Trading Program allowances allocated 

for any control period before such 

allowance transfer deadline will not be 

recorded until after the Administrator 

completes the deductions from such 

compliance account under § 97.924 for 

the control period immediately before 

such allowance transfer deadline. 

(c) Where a Texas SO2 Trading 

Program allowance transfer is not 

correctly submitted under § 97.922, the 

Administrator will not record such 

transfer. 

(d) Within 5 business days of 

recordation of a Texas SO2 Trading 

Program allowance transfer under 

paragraphs (a) and (b) of the section, the 

Administrator will notify the authorized 

account representatives of both the 

transferor and transferee accounts. 

(e) Within 10 business days of receipt 

of a Texas SO2 Trading Program 

allowance transfer that is not correctly 

submitted under § 97.922, the 

Administrator will notify the authorized 

account representatives of both accounts 

subject to the transfer of: 

(1) A decision not to record the 

transfer, and 

(2) The reasons for such nonrecordation. 

§ 97.924 Compliance with Texas SO2

Trading Program emissions limitations. 

(a) Availability for deduction for 

compliance. Texas SO2 Trading Program 

allowances are available to be deducted 

for compliance with a source’s Texas 

SO2 Trading Program emissions 

limitation for a control period in a given 

year only if the Texas SO2 Trading 

Program allowances: 

(1) Were allocated for such control 

period or a control period in a prior 

year; and 

(2) Are held in the source’s 

compliance account as of the allowance 

transfer deadline for such control 

period. 

(b) Deductions for compliance. After 

the recordation, in accordance with 

§ 97.923, of Texas SO2 Trading Program 

allowance transfers submitted by the 

allowance transfer deadline for a control 

period in a given year, the 

Administrator will deduct from each 

source’s compliance account Texas SO2

Trading Program allowances available 

under paragraph (a) of this section in 

order to determine whether the source 

meets the Texas SO2 Trading Program 

emissions limitation for such control 

period, as follows: 

(1) Until the amount of Texas SO2

Trading Program allowances deducted 

equals the number of tons of total SO2

emissions from all Texas SO2 Trading 

Program units at the source for such 

control period; or 

(2) If there are insufficient Texas SO2

Trading Program allowances to 

complete the deductions in paragraph 

(b)(1) of this section, until no more 

Texas SO2 Trading Program allowances 

available under paragraph (a) of this 

section remain in the compliance 

account. 

(c)(1) Identification of Texas SO2

Trading Program allowances by serial 

number. The authorized account 

representative for a source’s compliance 

account may request that specific Texas 

SO2 Trading Program allowances, 

identified by serial number, in the 

compliance account be deducted for 

emissions or excess emissions for a 

control period in a given year in 

accordance with paragraph (b) or (d) of 

this section. In order to be complete, 

such request shall be submitted to the 

Administrator by the allowance transfer 

deadline for such control period and 

include, in a format prescribed by the 

Administrator, the identification of the 

Texas SO2 Trading Program source and 

the appropriate serial numbers. 

(2) First-in, first-out. The 

Administrator will deduct Texas SO2

Trading Program allowances under 

paragraph (b) or (d) of this section from 

the source’s compliance account in 

accordance with a complete request 

under paragraph (c)(1) of this section or, 

in the absence of such request or in the 

case of identification of an insufficient 

amount of Texas SO2 Trading Program 

allowances in such request, on a first-in, 

first-out accounting basis in the 

following order: 

(i) Any Texas SO2 Trading Program 

allowances that were recorded in the 

compliance account pursuant to 

§ 97.921 and not transferred out of the 

compliance account, in the order of 

recordation; and then 

(ii) Any other Texas SO2 Trading 

Program allowances that were 

transferred to and recorded in the 

compliance account pursuant to this 

subpart, in the order of recordation. 

(d) Deductions for excess emissions. 

After making the deductions for 

compliance under paragraph (b) of this 

section for a control period in a year in 

which the Texas SO2 Trading Program 

source has excess emissions, the 

Administrator will deduct from the 

source’s compliance account an amount 

of Texas SO2 Trading Program 

allowances, allocated for a control 

period in a prior year or the control 

period in the year of the excess 

emissions or in the immediately 

following year, equal to three times the 

number of tons of the source’s excess 

emissions. 

(e) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraphs (b) and (d) of this section. 

§ 97.925 [Reserved] 

§ 97.926 Banking. 

(a) A Texas SO2 Trading Program 

allowance may be banked for future use 

or transfer in a compliance account or 

general account in accordance with 

paragraph (b) of this section. 

(b) Any Texas SO2 Trading Program 

allowance that is held in a compliance 

account or a general account will 

remain in such account unless and until 

the Texas SO2 Trading Program 

allowance is deducted or transferred 

under § 97.911(c), § 97.923, § 97.924, 

§ 97.927, or § 97.928. 

§ 97.927 Account error. 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any 

Allowance Management System 

account. Within 10 business days of 


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making such correction, the 

Administrator will notify the authorized 

account representative for the account. 

§ 97.928 Administrator’s action on 

submissions. 

(a) The Administrator may review and 

conduct independent audits concerning 

any submission under the Texas SO2

Trading Program and make appropriate 

adjustments of the information in the 

submission. 

(b) The Administrator may deduct 

Texas SO2 Trading Program allowances 

from or transfer Texas SO2 Trading 

Program allowances to a compliance 

account, based on the information in a 

submission, as adjusted under 

paragraph (a) of this section, and record 

such deductions and transfers. 

§ 97.929 [Reserved] 

§ 97.930 General monitoring, 

recordkeeping, and reporting requirements. 

The owners and operators, and to the 

extent applicable, the designated 

representative, of a Texas SO2 Trading 

Program unit, shall comply with the 

monitoring, recordkeeping, and 

reporting requirements as provided in 

this subpart and subparts F and G of 

part 75 of this chapter. For purposes of 

applying such requirements, the 

definitions in § 97.902 and in § 72.2 of 

this chapter shall apply, the terms 

‘‘affected unit,’’ ‘‘designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) in part 75 of this chapter shall 

be deemed to refer to the terms ‘‘Texas 

SO2 Trading Program unit,’’ ‘‘designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) respectively as defined in 

§ 97.902. The owner or operator of a 

unit that is not a Texas SO2 Trading 

Program unit but that is monitored 

under § 75.16(b)(2) of this chapter shall 

comply with the same monitoring, 

recordkeeping, and reporting 

requirements as a Texas SO2 Trading 

Program unit. 

(a) Requirements for installation, 

certification, and data accounting. The 

owner or operator of each Texas SO2

Trading Program unit shall: 

(1) Install all monitoring systems 

required under this subpart for 

monitoring SO2 mass emissions and 

individual unit heat input (including all 

systems required to monitor SO2

concentration, stack gas moisture 

content, stack gas flow rate, CO2 or O2

concentration, and fuel flow rate, as 

applicable, in accordance with §§ 75.11 

and 75.16 of this chapter); 

(2) Successfully complete all 

certification tests required under 

§ 97.931 and meet all other 

requirements of this subpart and part 75 

of this chapter applicable to the 

monitoring systems under paragraph 

(a)(1) of this section; and 

(3) Record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section. 

(b) Compliance deadlines. Except as 

provided in paragraph (e) of this 

section, the owner or operator of a Texas 

SO2 Trading Program unit shall meet the 

monitoring system certification and 

other requirements of paragraphs (a)(1) 

and (2) of this section on or before the 

later of the following dates and shall 

record, report, and quality-assure the 

data from the monitoring systems under 

paragraph (a)(1) of this section on and 

after: 

(1) For a Texas SO2 Trading Program 

unit under § 97.904(a), January 1, 2019; 

or 

(2) For a Texas SO2 Trading Program 

unit under § 97.904(b), January 1 of the 

first control period for which the unit is 

a Texas SO2 Trading Program unit. 

(3) The owner or operator of a Texas 

SO2 Trading Program unit for which 

construction of a new stack or flue or 

installation of add-on SO2 emission 

controls is completed after the 

applicable deadline under paragraph 

(b)(1) or (2) of this section shall meet the 

requirements of § 75.4(e)(1) through (4) 

of this chapter, except that: 

(i) Such requirements shall apply to 

the monitoring systems required under 

§ 97.930 through § 97.935, rather than 

the monitoring systems required under 

part 75 of this chapter; 

(ii) SO2 concentration, stack gas 

moisture content, stack gas volumetric 

flow rate, and O2 or CO2 concentration 

data shall be determined and reported, 

rather than the data listed in § 75.4(e)(2) 

of this chapter; and 

(iii) Any petition for another 

procedure under § 75.4(e)(2) of this 

chapter shall be submitted under 

§ 97.935, rather than § 75.66 of this 

chapter. 

(c) Reporting data. The owner or 

operator of a Texas SO2 Trading 

Program unit that does not meet the 

applicable compliance date set forth in 

paragraph (b) of this section for any 

monitoring system under paragraph 

(a)(1) of this section shall, for each such 

monitoring system, determine, record, 

and report maximum potential (or, as 

appropriate, minimum potential) values 

for SO2 concentration, stack gas flow 

rate, stack gas moisture content, fuel 

flow rate, and any other parameters 

required to determine SO2 mass 

emissions and heat input in accordance 

with § 75.31(b)(2) or (c)(3) of this 

chapter or section 2.4 of appendix D to 

part 75 of this chapter, as applicable. 

(d) Prohibitions. (1) No owner or 

operator of a Texas SO2 Trading 

Program unit shall use any alternative 

monitoring system, alternative reference 

method, or any other alternative to any 

requirement of this subpart without 

having obtained prior written approval 

in accordance with § 97.935. 

(2) No owner or operator of a Texas 

SO2 Trading Program unit shall operate 

the unit so as to discharge, or allow to 

be discharged, SO2 to the atmosphere 

without accounting for all such SO2 in 

accordance with the applicable 

provisions of this subpart and part 75 of 

this chapter. 

(3) No owner or operator of a Texas 

SO2 Trading Program unit shall disrupt 

the continuous emission monitoring 

system, any portion thereof, or any other 

approved emission monitoring method, 

and thereby avoid monitoring and 

recording SO2 mass discharged into the 

atmosphere or heat input, except for 

periods of recertification or periods 

when calibration, quality assurance 

testing, or maintenance is performed in 

accordance with the applicable 

provisions of this subpart and part 75 of 

this chapter. 

(4) No owner or operator of a Texas 

SO2 Trading Program unit shall retire or 

permanently discontinue use of the 

continuous emission monitoring system, 

any component thereof, or any other 

approved monitoring system under this 

subpart, except under any one of the 

following circumstances: 

(i) During the period that the unit is 

covered by an exemption under § 97.905 

that is in effect; 

(ii) The owner or operator is 

monitoring emissions from the unit with 

another certified monitoring system 

approved, in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter, by the 

Administrator for use at that unit that 

provides emission data for the same 

pollutant or parameter as the retired or 

discontinued monitoring system; or 

(iii) The designated representative 

submits notification of the date of 

certification testing of a replacement 

monitoring system for the retired or 

discontinued monitoring system in 

accordance with § 97.931(d)(3)(i). 

(e) Long-term cold storage. The owner 

or operator of a Texas SO2 Trading 

Program unit is subject to the applicable 

provisions of § 75.4(d) of this chapter 

concerning units in long-term cold 

storage. 

§ 97.931 Initial monitoring system 

certification and recertification procedures. 

(a) The owner or operator of a Texas 

SO2 Trading Program unit shall be 

exempt from the initial certification 


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requirements of this section for a 

monitoring system under § 97.930(a)(1) 

if the following conditions are met: 

(1) The monitoring system has been 

previously certified in accordance with 

part 75 of this chapter; and 

(2) The applicable quality-assurance 

and quality-control requirements of 

§ 75.21 of this chapter and appendices 

B and D to part 75 of this chapter are 

fully met for the certified monitoring 

system described in paragraph (a)(1) of 

this section. 

(b) The recertification provisions of 

this section shall apply to a monitoring 

system under § 97.930(a)(1) that is 

exempt from initial certification 

requirements under paragraph (a) of this 

section. 

(c) [Reserved] 

(d) Except as provided in paragraph 

(a) of this section, the owner or operator 

of a Texas SO2 Trading Program unit 

shall comply with the following initial 

certification and recertification 

procedures, for a continuous monitoring 

system (i.e., a continuous emission 

monitoring system and an excepted 

monitoring system under appendix D to 

part 75 of this chapter) under 

§ 97.930(a)(1). The owner or operator of 

a unit that qualifies to use the low mass 

emissions excepted monitoring 

methodology under § 75.19 of this 

chapter or that qualifies to use an 

alternative monitoring system under 

subpart E of part 75 of this chapter shall 

comply with the procedures in 

paragraph (e) or (f) of this section 

respectively. 

(1) Requirements for initial 

certification. The owner or operator 

shall ensure that each continuous 

monitoring system under § 97.930(a)(1) 

(including the automated data 

acquisition and handling system) 

successfully completes all of the initial 

certification testing required under 

§ 75.20 of this chapter by the applicable 

deadline in § 97.930(b). In addition, 

whenever the owner or operator installs 

a monitoring system to meet the 

requirements of this subpart in a 

location where no such monitoring 

system was previously installed, initial 

certification in accordance with § 75.20 

of this chapter is required. 

(2) Requirements for recertification. 

Whenever the owner or operator makes 

a replacement, modification, or change 

in any certified continuous emission 

monitoring system under § 97.930(a)(1) 

that may significantly affect the ability 

of the system to accurately measure or 

record SO2 mass emissions or heat input 

rate or to meet the quality-assurance and 

quality-control requirements of § 75.21 

of this chapter or appendix B to part 75 

of this chapter, the owner or operator 

shall recertify the monitoring system in 

accordance with § 75.20(b) of this 

chapter. Furthermore, whenever the 

owner or operator makes a replacement, 

modification, or change to the flue gas 

handling system or the unit’s operation 

that may significantly change the stack 

flow or concentration profile, the owner 

or operator shall recertify each 

continuous emission monitoring system 

whose accuracy is potentially affected 

by the change, in accordance with 

§ 75.20(b) of this chapter. Examples of 

changes to a continuous emission 

monitoring system that require 

recertification include replacement of 

the analyzer, complete replacement of 

an existing continuous emission 

monitoring system, or change in 

location or orientation of the sampling 

probe or site. Any fuel flowmeter system 

under § 97.930(a)(1) is subject to the 

recertification requirements in 

§ 75.20(g)(6) of this chapter. 

(3) Approval process for initial 

certification and recertification. For 

initial certification of a continuous 

monitoring system under § 97.930(a)(1), 

paragraphs (d)(3)(i) through (v) of this 

section apply. For recertifications of 

such monitoring systems, paragraphs 

(d)(3)(i) through (iv) of this section and 

the procedures in § 75.20(b)(5) and (g)(7) 

of this chapter (in lieu of the procedures 

in paragraph (d)(3)(v) of this section) 

apply, provided that in applying 

paragraphs (d)(3)(i) through (iv) of this 

section, the words ‘‘certification’’ and 

‘‘initial certification’’ are replaced by 

the word ‘‘recertification’’ and the word 

‘‘certified’’ is replaced by with the word 

‘‘recertified’’. 

(i) Notification of certification. The 

designated representative shall submit 

to the appropriate EPA Regional Office 

and the Administrator written notice of 

the dates of certification testing, in 

accordance with § 97.933. 

(ii) Certification application. The 

designated representative shall submit 

to the Administrator a certification 

application for each monitoring system. 

A complete certification application 

shall include the information specified 

in § 75.63 of this chapter. 

(iii) Provisional certification date. The 

provisional certification date for a 

monitoring system shall be determined 

in accordance with § 75.20(a)(3) of this 

chapter. A provisionally certified 

monitoring system may be used under 

the Texas SO2 Trading Program for a 

period not to exceed 120 days after 

receipt by the Administrator of the 

complete certification application for 

the monitoring system under paragraph 

(d)(3)(ii) of this section. Data measured 

and recorded by the provisionally 

certified monitoring system, in 

accordance with the requirements of 

part 75 of this chapter, will be 

considered valid quality-assured data 

(retroactive to the date and time of 

provisional certification), provided that 

the Administrator does not invalidate 

the provisional certification by issuing a 

notice of disapproval within 120 days of 

the date of receipt of the complete 

certification application by the 

Administrator. 

(iv) Certification application approval 

process. The Administrator will issue a 

written notice of approval or 

disapproval of the certification 

application to the owner or operator 

within 120 days of receipt of the 

complete certification application under 

paragraph (d)(3)(ii) of this section. In the 

event the Administrator does not issue 

such a notice within such 120-day 

period, each monitoring system that 

meets the applicable performance 

requirements of part 75 of this chapter 

and is included in the certification 

application will be deemed certified for 

use under the Texas SO2 Trading 

Program. 

(A) Approval notice. If the 

certification application is complete and 

shows that each monitoring system 

meets the applicable performance 

requirements of part 75 of this chapter, 

then the Administrator will issue a 

written notice of approval of the 

certification application within 120 

days of receipt. 

(B) Incomplete application notice. If 

the certification application is not 

complete, then the Administrator will 

issue a written notice of incompleteness 

that sets a reasonable date by which the 

designated representative must submit 

the additional information required to 

complete the certification application. If 

the designated representative does not 

comply with the notice of 

incompleteness by the specified date, 

then the Administrator may issue a 

notice of disapproval under paragraph 

(d)(3)(iv)(C) of this section. 

(C) Disapproval notice. If the 

certification application shows that any 

monitoring system does not meet the 

performance requirements of part 75 of 

this chapter or if the certification 

application is incomplete and the 

requirement for disapproval under 

paragraph (d)(3)(iv)(B) of this section is 

met, then the Administrator will issue a 

written notice of disapproval of the 

certification application. Upon issuance 

of such notice of disapproval, the 

provisional certification is invalidated 

by the Administrator and the data 

measured and recorded by each 

uncertified monitoring system shall not 

be considered valid quality-assured data 

beginning with the date and hour of 


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provisional certification (as defined 

under § 75.20(a)(3) of this chapter). 

(D) Audit decertification. The 

Administrator may issue a notice of 

disapproval of the certification status of 

a monitor in accordance with 

§ 97.932(b). 

(v) Procedures for loss of certification. 

If the Administrator issues a notice of 

disapproval of a certification 

application under paragraph 

(d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under 

paragraph (d)(3)(iv)(D) of this section, 

then: 

(A) The owner or operator shall 

substitute the following values, for each 

disapproved monitoring system, for 

each hour of unit operation during the 

period of invalid data specified under 

§ 75.20(a)(4)(iii), § 75.20(g)(7), or 

§ 75.21(e) of this chapter and continuing 

until the applicable date and hour 

specified under § 75.20(a)(5)(i) or (g)(7) 

of this chapter: 

(1) For a disapproved SO2 pollutant 

concentration monitor and disapproved 

flow monitor, respectively, the 

maximum potential concentration of 

SO2 and the maximum potential flow 

rate, as defined in sections 2.1.1.1 and 

2.1.4.1 of appendix A to part 75 of this 

chapter. 

(2) For a disapproved moisture 

monitoring system and disapproved 

diluent gas monitoring system, 

respectively, the minimum potential 

moisture percentage and either the 

maximum potential CO2 concentration 

or the minimum potential O2

concentration (as applicable), as defined 

in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 

appendix A to part 75 of this chapter. 

(3) For a disapproved fuel flowmeter 

system, the maximum potential fuel 

flow rate, as defined in section 2.4.2.1 

of appendix D to part 75 of this chapter. 

(B) The designated representative 

shall submit a notification of 

certification retest dates and a new 

certification application in accordance 

with paragraphs (d)(3)(i) and (ii) of this 

section. 

(C) The owner or operator shall repeat 

all certification tests or other 

requirements that were failed by the 

monitoring system, as indicated in the 

Administrator’s notice of disapproval, 

no later than 30 unit operating days 

after the date of issuance of the notice 

of disapproval. 

(e) The owner or operator of a unit 

qualified to use the low mass emissions 

(LME) excepted methodology under 

§ 75.19 of this chapter shall meet the 

applicable certification and 

recertification requirements in 

§§ 75.19(a)(2) and 75.20(h) of this 

chapter. If the owner or operator of such 

a unit elects to certify a fuel flowmeter 

system for heat input determination, the 

owner or operator shall also meet the 

certification and recertification 

requirements in § 75.20(g) of this 

chapter. 

(f) The designated representative of 

each unit for which the owner or 

operator intends to use an alternative 

monitoring system approved by the 

Administrator under subpart E of part 

75 of this chapter shall comply with the 

applicable notification and application 

procedures of § 75.20(f) of this chapter. 

§ 97.932 Monitoring system out-of-control 

periods. 

(a) General provisions. Whenever any 

monitoring system fails to meet the 

quality-assurance and quality-control 

requirements or data validation 

requirements of part 75 of this chapter, 

data shall be substituted using the 

applicable missing data procedures in 

subpart D or appendix D to part 75 of 

this chapter. 

(b) Audit decertification. Whenever 

both an audit of a monitoring system 

and a review of the initial certification 

or recertification application reveal that 

any monitoring system should not have 

been certified or recertified because it 

did not meet a particular performance 

specification or other requirement under 

§ 97.931 or the applicable provisions of 

part 75 of this chapter, both at the time 

of the initial certification or 

recertification application submission 

and at the time of the audit, the 

Administrator will issue a notice of 

disapproval of the certification status of 

such monitoring system. For the 

purposes of this paragraph, an audit 

shall be either a field audit or an audit 

of any information submitted to the 

Administrator or any State or permitting 

authority. By issuing the notice of 

disapproval, the Administrator revokes 

prospectively the certification status of 

the monitoring system. The data 

measured and recorded by the 

monitoring system shall not be 

considered valid quality-assured data 

from the date of issuance of the 

notification of the revoked certification 

status until the date and time that the 

owner or operator completes 

subsequently approved initial 

certification or recertification tests for 

the monitoring system. The owner or 

operator shall follow the applicable 

initial certification or recertification 

procedures in § 97.931 for each 

disapproved monitoring system. 

§ 97.933 Notifications concerning 

monitoring. 

The designated representative of a 

Texas SO2 Trading Program unit shall 

submit written notice to the 

Administrator in accordance with 

§ 75.61 of this chapter. 

§ 97.934 Recordkeeping and reporting. 

(a) General provisions. The designated 

representative of a Texas SO2 Trading 

Program unit shall comply with all 

recordkeeping and reporting 

requirements in paragraphs (b) through 

(e) of this section, the applicable 

recordkeeping and reporting 

requirements in subparts F and G of part 

75 of this chapter, and the requirements 

of § 97.914(a). 

(b) Monitoring plans. The owner or 

operator of a Texas SO2 Trading 

Program unit shall comply with the 

requirements of § 75.62 of this chapter. 

(c) Certification applications. The 

designated representative shall submit 

an application to the Administrator 

within 45 days after completing all 

initial certification or recertification 

tests required under § 97.931, including 

the information required under § 75.63 

of this chapter. 

(d) Quarterly reports. The designated 

representative shall submit quarterly 

reports, as follows: 

(1) The designated representative 

shall report the SO2 mass emissions data 

and heat input data for a Texas SO2

Trading Program unit, in an electronic 

quarterly report in a format prescribed 

by the Administrator, for each calendar 

quarter beginning with the later of: 

(i) The calendar quarter covering 

January 1, 2019 through March 31, 2019; 

or 

(ii) The calendar quarter 

corresponding to the earlier of the date 

of provisional certification or the 

applicable deadline for initial 

certification under § 97.930(b). 

(2) The designated representative 

shall submit each quarterly report to the 

Administrator within 30 days after the 

end of the calendar quarter covered by 

the report. Quarterly reports shall be 

submitted in the manner specified in 

§ 75.64 of this chapter. 

(3) For Texas SO2 Trading Program 

units that are also subject to the Acid 

Rain Program or CSAPR NOX Ozone 

Season Group 2 Trading Program, 

quarterly reports shall include the 

applicable data and information 

required by subparts F through H of part 

75 of this chapter as applicable, in 

addition to the SO2 mass emission data, 

heat input data, and other information 

required by this subpart. 

(4) The Administrator may review and 

conduct independent audits of any 

quarterly report in order to determine 

whether the quarterly report meets the 

requirements of this subpart and part 75 


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of this chapter, including the 

requirement to use substitute data. 

(i) The Administrator will notify the 

designated representative of any 

determination that the quarterly report 

fails to meet any such requirements and 

specify in such notification any 

corrections that the Administrator 

believes are necessary to make through 

resubmission of the quarterly report and 

a reasonable time period within which 

the designated representative must 

respond. Upon request by the 

designated representative, the 

Administrator may specify reasonable 

extensions of such time period. Within 

the time period (including any such 

extensions) specified by the 

Administrator, the designated 

representative shall resubmit the 

quarterly report with the corrections 

specified by the Administrator, except 

to the extent the designated 

representative provides information 

demonstrating that a specified 

correction is not necessary because the 

quarterly report already meets the 

requirements of this subpart and part 75 

of this chapter that are relevant to the 

specified correction. 

(ii) Any resubmission of a quarterly 

report shall meet the requirements 

applicable to the submission of a 

quarterly report under this subpart and 

part 75 of this chapter, except for the 

deadline set forth in paragraph (d)(2) of 

this section. 

(e) Compliance certification. The 

designated representative shall submit 

to the Administrator a compliance 

certification (in a format prescribed by 

the Administrator) in support of each 

quarterly report based on reasonable 

inquiry of those persons with primary 

responsibility for ensuring that all of the 

unit’s emissions are correctly and fully 

monitored. The certification shall state 

that: 

(1) The monitoring data submitted 

were recorded in accordance with the 

applicable requirements of this subpart 

and part 75 of this chapter, including 

the quality assurance procedures and 

specifications; and 

(2) For a unit with add-on SO2

emission controls and for all hours 

where SO2 data are substituted in 

accordance with § 75.34(a)(1) of this 

chapter, the add-on emission controls 

were operating within the range of 

parameters listed in the quality 

assurance/quality control program 

under appendix B to part 75 of this 

chapter and the substitute data values 

do not systematically underestimate SO2

emissions. 

§ 97.935 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

(a) The designated representative of a 

Texas SO2 Trading Program unit may 

submit a petition under § 75.66 of this 

chapter to the Administrator, requesting 

approval to apply an alternative to any 

requirement of §§ 97.930 through 

97.934. 

(b) A petition submitted under 

paragraph (a) of this section shall 

include sufficient information for the 

evaluation of the petition, including, at 

a minimum, the following information: 

(1) Identification of each unit and 

source covered by the petition; 

(2) A detailed explanation of why the 

proposed alternative is being suggested 

in lieu of the requirement; 

(3) A description and diagram of any 

equipment and procedures used in the 

proposed alternative; 

(4) A demonstration that the proposed 

alternative is consistent with the 

purposes of the requirement for which 

the alternative is proposed and with the 

purposes of this subpart and part 75 of 

this chapter and that any adverse effect 

of approving the alternative will be de 

minimis; and 

(5) Any other relevant information 

that the Administrator may require. 

(c) Use of an alternative to any 

requirement referenced in paragraph (a) 

of this section is in accordance with this 

subpart only to the extent that the 

petition is approved in writing by the 

Administrator and that such use is in 

accordance with such approval. 

[FR Doc. 2017–21947 Filed 10–16–17; 8:45 am] 

BILLING CODE 6560–50–P 


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