74818 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R06–OAR–2014–0754; FRL–9920–11– 

Region–6] 

Approval and Promulgation of 

Implementation Plans; Texas and 

Oklahoma; Regional Haze State 

Implementation Plans; Interstate 

Transport State Implementation Plan 

To Address Pollution Affecting 

Visibility and Regional Haze; Federal 

Implementation Plan for Regional Haze 

and Interstate Transport of Pollution 

Affecting Visibility 

AGENCY: Environmental Protection 

Agency. 

ACTION: Proposed rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is proposing to partially 

approve and partially disapprove a 

revision to the Texas State 

Implementation Plan (SIP) received 

from the State of Texas on March 31, 

2009, that addresses regional haze for 

the first planning period from 2008 

through 2018. This SIP revision was 

submitted to address the requirements 

of the Clean Air Act (CAA) and EPA’s 

rules that require states to prevent any 

future, and remedy any existing, 

manmade impairment of visibility to 

assure reasonable progress toward the 

national goal of achieving natural 

visibility conditions in Class I areas. 

The EPA is proposing to partially 

approve this SIP revision as meeting 

certain requirements of the regional 

haze program, including the majority of 

the requirement to procure and install 

the Best Available Retrofit Technology 

(BART) at certain categories of existing 

major stationary sources built between 

1962 and 1977. The EPA is also 

proposing to partially disapprove the 

SIP revision for not adequately 

addressing other requirements of the 

regional haze program related to 

reasonable progress, the long-term 

strategy, and the calculation of natural 

visibility conditions. The EPA is also 

proposing to disapprove SIP revisions 

submitted by Texas for the purpose of 

addressing the requirements of the CAA 

regarding interference with other states’ 

programs for visibility protection for the 

1997 fine particulate matter (PM2.5) 

National Ambient Air Quality Standards 

(NAAQS), the 1997 ozone NAAQS, the 

2006 PM2.5 NAAQS, the 2008 ozone 

NAAQS, the 2010 Nitrogen Dioxide 

(NO2) NAAQS, and the 2010 Sulfur 

Dioxide (SO2) NAAQS. 

Finally, the EPA is proposing to 

partially disapprove a revision to the 

Oklahoma SIP submitted in February 

19, 2010, that addresses regional haze 

for the first planning period. 

Specifically, EPA is proposing to 

disapprove Oklahoma’s Reasonable 

Progress Goals (RPGs) for the Wichita 

Mountains Class I area. 

The EPA is proposing a Federal 

Implementation Plan (FIP) for each 

Texas and Oklahoma to remedy certain 

deficiencies in the SIP. The proposed 

FIP would implement SO2 emission 

limits on fifteen Texas sources as part of 

a long-term strategy for making 

reasonable progress at three Class I areas 

in Texas and Oklahoma, sets new RPGs 

for the Big Bend, the Guadalupe 

Mountains, and Wichita Mountains 

Class I areas, and substitutes Texas’ 

reliance on the Clean Air Interstate Rule 

(CAIR) to satisfy BART requirements at 

its EGUs with reliance on CAIR’s 

successor, the Cross-State Air Pollution 

Rule (CSAPR). Our proposed FIP for 

Oklahoma does not establish any 

additional requirements on sources 

within Oklahoma. The EPA is taking 

this action under the CAA. 

Comments must be received on or 

before February 17, 2015. 

Public Hearings. EPA is holding open 

houses—for the purpose of providing 

additional information and informal 

discussion for our proposal, and public 

hearings—to accept oral comments into 

the record, as follows: 

Date: Tuesday, January 13, 2015. 

Time: Open House: 1:30 p.m.–3:30 p.m. 

Public hearing: 4:00 p.m.–8:00 p.m. 

(including short break). 

Location: Eastview Campus, Austin 

Community College, Building 8500, Room 

8500, 3401 Webberville Road, Austin, Texas 

78702. 

Date: Thursday, January 15, 2015. 

Time: Open House: 2:30 p.m.–4:30 p.m. 

Public hearing: 5:00 p.m.–7:00 p.m. 

Location: Metro Technology Centers, 

Springlake Campus, Business Conference 

Center Meeting, Room H, 1900 Springlake 

Drive, Oklahoma City, Oklahoma 73111. 

The public hearings will provide 

interested parties the opportunity to 

present information and opinions to 

EPA concerning our proposal. Interested 

parties may also submit written 

comments, as discussed in the proposal. 

Written statements and supporting 

information submitted during the 

comment period will be considered 

with the same weight as any oral 

comments and supporting information 

presented at the public hearing. We will 

not respond to comments during the 

public hearings. When we publish our 

final action, we will provide written 

responses to all significant oral and 

written comments received on our 

proposal. To provide opportunities for 

questions and discussion, we will hold 

an open house prior to each public 

hearing. During the open house, EPA 

staff will be available to informally 

answer questions on our proposed 

action. Any comments made to EPA 

staff during an open house must still be 

provided orally during one of the public 

hearings, or formally in writing within 

30 days after completion of the hearings, 

in order to be considered in the record. 

At the public hearings, the hearing 

officer may limit the time available for 

each commenter to address the proposal 

to three minutes or less if the hearing 

officer determines it to be appropriate. 

We will not be providing equipment for 

commenters to show overhead slides or 

make computerized slide presentations. 

Any person may provide written or oral 

comments and data pertaining to our 

proposal at the public hearings. 

Verbatim English language transcripts of 

the hearing and written statements will 

be included in the rulemaking docket. 

ADDRESSES: Submit your comments, 

identified by Docket No. EPA–R06– 

OAR–2014–0754, by one of the 

following methods: 

• Federal e-Rulemaking Portal: http:// 

www.regulations.gov. Follow the online 

instructions for submitting comments. 

• Email: R6_TXOKRegionalHaze@

epa.gov. 

• Mail: Mr. Guy Donaldson, Chief, 

Air Planning Section (6PD–L), 

Environmental Protection Agency, 1445 

Ross Avenue, Suite 1200, Dallas, Texas 

75202–2733. 

• Hand or Courier Delivery: Mr. Guy 

Donaldson, Chief, Air Planning Section 

(6PD–L), Environmental Protection 

Agency, 1445 Ross Avenue, Suite 1200, 

Dallas, Texas 75202–2733. Such 

deliveries are accepted only between the 

hours of 8 a.m. and 4 p.m. weekdays, 

and not on legal holidays. Special 

arrangements should be made for 

deliveries of boxed information. 

• Fax: Mr. Guy Donaldson, Chief, Air 

Planning Section (6PD–L), at fax 

number 214–665–7263. 

Instructions: Direct your comments to 

Docket No. EPA–R06–OAR–2014–0754. 

Our policy is that all comments received 

will be included in the public docket 

without change and may be made 

available online at www.regulations.gov, 

including any personal information 

provided, unless the comment includes 

information claimed to be Confidential 

Business Information (CBI) or other 

information whose disclosure is 

restricted by statute. Do not submit 

information that you consider to be CBI 

or otherwise protected through 

www.regulations.gov or email. The 

www.regulations.gov Web site is an 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74819 

‘‘anonymous access’’ system, which 

means we will not know your identity 

or contact information unless you 

provide it in the body of your comment. 

If you send an email comment directly 

to us without going through 

www.regulations.gov your email address 

will be automatically captured and 

included as part of the comment that is 

placed in the public docket and made 

available on the Internet. If you submit 

an electronic comment, we recommend 

that you include your name and other 

contact information in the body of your 

comment and with any disk or CD–ROM 

you submit. If we cannot read your 

comment due to technical difficulties 

and cannot contact you for clarification, 

we may not be able to consider your 

comment. Electronic files should avoid 

the use of special characters, any form 

of encryption, and be free of any defects 

or viruses. 

Docket: All documents in the docket 

are listed in the www.regulations.gov 

index. Although listed in the index, 

some information is not publicly 

available, e.g., CBI or other information 

whose disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, will be publicly 

available only in hard copy. Publicly 

available docket materials are available 

either electronically at 

www.regulations.gov or in hard copy at 

the Air Planning Section (6PD–L), 

Environmental Protection Agency, 1445 

Ross Avenue, Suite 700, Dallas, Texas 

75202–2733. The file will be made 

available by appointment for public 

inspection in the Region 6 FOIA Review 

Room between the hours of 8:30 a.m. 

and 4:30 p.m. weekdays except for legal 

holidays. Contact the person listed in 

the FOR FURTHER INFORMATION CONTACT

paragraph below or Mr. Bill Deese at 

214–665–7253 to make an appointment. 

If possible, please make the 

appointment at least two working days 

in advance of your visit. There will be 

a 15 cent per page fee for making 

photocopies of documents. On the day 

of the visit, please check in at our 

Region 6 reception area at 1445 Ross 

Avenue, Suite 700, Dallas, Texas. 

The Texas regional haze SIP is 

available online at: https://

www.tceq.texas.gov/airquality/sip/bart/

haze_sip.html. It is also available for 

public inspection during official 

business hours, by appointment, at the 

Texas Commission on Environmental 

Quality, Office of Air Quality, 12124 

Park 35 Circle, Austin, Texas 78753. 

The Oklahoma regional haze SIP is 

available online at: http://

www.deq.state.ok.us/AQDnew/

rulesandplanning/Regional_Haze/SIP/

index.htm. It is also available for public 

inspection during official business 

hours, by appointment, at the Oklahoma 

Department of Environmental Quality, 

Air Quality Division, 707 North 

Robinson Avenue, Oklahoma City, OK 

73102. 

FOR FURTHER INFORMATION CONTACT: Joe 

Kordzi, Air Planning Section (6PD–L), 

Environmental Protection Agency, 

Region 6, 1445 Ross Avenue, Suite 700, 

Dallas, Texas 75202–2733, telephone 

214–665–7186; fax number 214–665– 

7263; email address Kordzi.joe@epa.gov. 

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 Air Pollutants 

and Visibility Protection 

C. Our Prior Limited Disapproval of Texas’ 

Regional Haze Concerning CAIR 

II. Why are we acting on the Texas and 

Oklahoma Regional Haze SIPs 

simultaneously? 

III. Summary of Our Proposed Actions 

A. Texas 

B. Oklahoma 

IV. Discussion of the Regional Haze Rule 

Requirements as They Relate to Visibility 

Transport 

A. Introduction 

B. Statutory and Regulatory Background 

C. Our Interpretation of 40 CFR 

51.308(d)(1) and (d)(3) 

V. Our Analysis of and Proposed Action on 

the Texas Regional Haze SIP 

A. Affected Class I Areas 

B. Determination of Baseline, Natural, and 

Current Visibility Conditions 

1. Estimating Natural Visibility Conditions 

2. Estimating Baseline Visibility 

Conditions 

3. Natural Visibility Impairment 

4. Uniform Rate of Progress 

5. Reasonable Progress Goal Minimum 

C. Evaluation of Texas’ Reasonable 

Progress Goals 

1. Establishment of the Reasonable 

Progress Goals 

2. Texas’ Reasonable Progress Four Factor 

Analysis 

3. Our Analysis of Texas’ Reasonable 

Progress Four Factor Analysis 

4. Texas’ Assertion that Its Progress Goals 

Are Reasonable 

5. Reasonable Progress Consultation 

D. Evaluation of Texas’ BART 

Determinations 

1. Identification of BART-Eligible Sources 

2. Identification of Sources Subject to 

BART 

3. Texas’ BART Rule 

E. Long-Term Strategy 

1. Texas’ Long-Term Strategy Consultation 

2. Texas’ Share of Reductions in Other 

States’ Progress Goals 

3. Texas’ Technical Basis for Its Long-Term 

Strategy 

4. Texas’ Consideration of the Long-Term 

Strategy Factors 

F. Coordination of RAVI and Regional Haze 

Requirements 

G. Monitoring Strategy and Other SIP 

Requirements 

H. Federal Land Manager Consultation 

I. Periodic SIP Revisions and Five-Year 

Progress Reports 

J. Future Determination of the Adequacy of 

the Existing Implementation Plan 

VI. Our Analysis of and Proposed Action on 

the Remaining Parts of the Oklahoma 

Regional Haze SIP 

A. Previous Rulemakings on the Oklahoma 

Regional Haze SIP 

B. Evaluation of Oklahoma’s Reasonable 

Progress Goals 

1. Establishment of the Reasonable 

Progress Goals 

2. Reasonable Progress Consultation 

3. The Oklahoma’s Reasonable Progress 

‘‘Four Factor’’ Analysis 

4. Uniform Rate of Progress 

5. Reasonable Progress Goal Minimum 

6. Oklahoma’s Assertion That Its Progress 

Goals Are Reasonable 

7. Our Evaluation of Oklahoma’s 

Reasonable Progress Goals for the 

Wichita Mountains 

VII. Our Proposed Oklahoma and Texas 

Regional Haze FIPs 

A. Summary of Our Proposed Texas FIP 

B. Summary of Our Proposed Oklahoma 

FIP 

C. Technical Overview of Our Proposed 

Oklahoma and Texas FIPs 

D. Approach to Reasonable Progress and 

Long-Term Strategy 

1. Time Necessary for Compliance, and the 

Oklahoma and Texas RPGs 

2. Energy and Non-Air Quality 

Environmental Impacts of Compliance 

3. Remaining Useful Life 

4. Analysis of the PPG Flat Glass Plant 

E. Use of Confidential Business 

Information 

F. Reasonable Progress and Long-Term 

Strategy Scrubber and DSI Cost Results 

G. Reasonable Progress and Long-Term 

Strategy Scrubber Upgrade Cost Results 

H. Summary of the Modeled Benefits of 

Emission Controls 

1. Visibility Benefits of DSI, SDA, and Wet 

FGD 

2. Visibility Benefits of Scrubber Upgrades 

I. Proposed Reasonable Progress and LongTerm Strategy Determinations 

1. Proposed Reasonable Progress and LongTerm Strategy Determination for San 

Miguel 

2. Proposed Reasonable Progress and LongTerm Strategy Determination for Units 

Other Than San Miguel 

3. Proposed Reasonable Progress and LongTerm Strategy Determination for 

Scrubber Upgrades 

4. Proposed Reasonable Progress and LongTerm Strategy Determination for 

Scrubber Retrofits 

J. Treatment of Potential Error in Scrubber 

Upgrade Efficiency Calculations 

K. Proposed Natural Conditions for the 

Texas Class I Areas 

L. Calculation of Visibility Impairment for 

the Texas Class I Areas 

M. Uniform Rates of Progress and the 

Emission Reductions Needed To Achieve 

Them 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74820 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

1 Visual range is the greatest distance, in 

kilometers or miles, at which a dark object can be 

viewed against the sky. 

2Areas designated as mandatory Class I Federal 

areas (or Class I areas for short) 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. See CAA section 162(a) below. 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. See 44 FR 69122 

(November 30, 1979). The extent of a mandatory 

Class I area includes subsequent changes in 

boundaries, such as park expansions. CAA section 

162(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’’ (FLM). 

See CAA section 302(i). 

We use the term, ‘‘Class I Federal Area’’ and 

‘‘Class I Area’’ interchangeably throughout this 

document. 

3 64 FR 35714, 35715 (July 1, 1999). 

4 Id. 

5CAA section 169A(a)(1). 

6 Id. 

7 45 FR 80084 (December 2, 1980). 

8 64 FR 35714 (July 1, 1999), codified at 40 CFR 

part 51, subpart P. 9 76 FR 16168, 16172–75 (Mar. 22, 2011). 

10 40 CFR 51.308(b). 

11Proposal: 76 FR 16168 (March 22, 2011). Final: 

76 FR 81728 (December 28, 2011). 

12 64 FR 35714, 35735 (July 1, 1999). 

13CAA Section 110(a)(1). 

N. Reasonable Progress Goals and 

Demonstration 

VIII. Our Evaluation of the Texas 

Infrastructure SIP Submittals for 

Interstate Transport and Visibility 

Protection 

IX. Proposed Determination of Nationwide 

Scope and Effect 

X. Proposed Action 

A. Texas Regional Haze 

B. Oklahoma Regional Haze 

C. Interstate Transport of Air Pollution and 

Visibility Protection 

XI. 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 which are located 

across a broad geographic area and emit 

fine particles (PM2.5) (e.g., sulfates, 

nitrates, organic carbon, elemental 

carbon, and soil dust) and their 

precursors. Fine particle precursors 

react in the atmosphere to form PM2.5, 

which also impair visibility by 

scattering and absorbing light. Visibility 

impairment reduces the clarity, color, 

and visible distance that one can see. 

PM2.5 also can 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 park and wilderness areas. The 

average visual range 1 in many Class I 

Federal areas 2 (i.e., national parks and 

memorial parks, wilderness areas, and 

international parks meeting certain size 

criteria) in the western United States is 

100–150 kilometers, or about one-half to 

two-thirds of the visual range that 

would exist without anthropogenic air 

pollution.3 In most of the eastern Class 

I areas of the United States, the average 

visual range is less than 30 kilometers, 

or about one-fifth of the visual range 

that would exist under estimated 

natural conditions.4

In Section 169A of the 1977 

Amendments to the CAA, Congress 

created a program for protecting 

visibility in the nation’s national parks 

and wilderness areas. This section of the 

CAA establishes as a national goal the 

‘‘prevention of any future, and the 

remedying of any existing, impairment 

of visibility in mandatory Class I 

Federal areas which impairment results 

from man-made air pollution.’’ 5 The 

terms ‘‘impairment of visibility’’ and 

‘‘visibility impairment’’ are defined in 

the CAA to include a reduction in visual 

range and atmospheric discoloration.6

Section 169A(g)(6). In 1980, we 

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’’ (RAVI).7 These regulations 

represented the first phase in addressing 

visibility impairment. We 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 improved. 

Congress added Section 169B to the 

CAA in 1990 to address regional haze 

issues, and we promulgated regulations 

addressing regional haze in 1999.8 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 51.300–309. For a detailed 

description of those requirements, 

please refer to Section IV of our 

previous action on the Oklahoma 

regional haze SIP.9 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 SIP addressing 

regional haze visibility impairment for 

the first ten year planning period no 

later than December 17, 2007.10 States 

are required to submit subsequent SIPs 

every ten years leading up to 2064, 

when the national goal of a return to 

natural visibility at all Class I areas is 

scheduled to be realized. 

We have acted on all of the states’ 

regional haze SIPs for the first planning 

period except for the Texas regional 

haze SIP and certain portions of the 

Oklahoma regional haze SIP. Previously, 

we proposed a partial approval and 

partial disapproval of, and a FIP for 

portions of the Oklahoma SIP on March 

22, 2011. We finalized that action on 

December 28, 2011.11 However, for the 

reasons we explain below, we did not 

complete our review of Oklahoma’s 

regional haze SIP. Due to the special 

interrelationship of the visibility 

impairing transport of pollution 

between Texas and Oklahoma, we are 

proposing action on the remaining 

portions of the Oklahoma regional haze 

SIP and all portions of the Texas 

regional haze SIP simultaneously. 

B. Interstate Transport of Air Pollutants 

and Visibility Protection 

Section 110(a)(2)(D)(i)(II) of the CAA 

requires that states have a SIP, or submit 

a SIP revision, containing provisions 

prohibiting emissions from within a 

state from interfering with measures 

required to be included in the 

implementation plan for any other state 

under the provisions of Part C of the 

CAA protecting visibility. Because of 

the impacts on visibility from the 

interstate transport of pollutants, we 

interpret this ‘‘good neighbor’’ provision 

in Section 110 of CAA as requiring 

states to include in their SIPs measures 

to prohibit emissions that would 

interfere with the reasonable progress 

goals set to protect Class I areas in other 

states. This is consistent with the 

requirements in the regional haze 

program which explicitly require each 

state to address its share of the emission 

reductions needed to meet the 

reasonable progress goals for 

surrounding Class I areas.12

SIPs addressing the good neighbor 

provisions of Section 110(a)(2)(D)(i)(II) 

of the CAA are due to us within three 

years after the promulgation of a new or 

revised NAAQS (or within such shorter 

period as we may prescribe).13 In this 

action, we propose to take action on SIP 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74821 

14 70 FR 21147 (April 25, 2005). 

15 76 FR 81371 (December 28, 2011). 

16 70 FR 25162 (May 12, 2005). 17 70 FR 39104 (July 6, 2005). 18 40 CFR 51.308(e)(4) (Aug. 6, 2012). 19North Carolina v. EPA, 531 F3d 896; modified 

by 550 F.3d 1176 (D.C. Cir. 2008). 20 76 FR 48208 (Aug. 8, 2011). 21 77 FR 33642 (June 7, 2012). 

22 77 FR 33642, 33643. (June 7, 2012) 

23 76 FR 16168 (March 22, 2011). 

24 64 FR 35714, 35728 (July 1, 1999). 

25 64 FR 35735 (July 1, 1999). 

revisions addressing these good 

neighbor requirements that were 

submitted by Texas following 

promulgation of the following new or 

revised 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 NO2 and (6) 2010 1-hour 

SO2. 

In 2005, we made a finding that a 

number of states, including Texas, did 

not submit SIPs to address the interstate 

transport of air pollution and visibility 

protection for the 1997 ozone and PM2.5

NAAQS.14 Pursuant to Section 110(c)(1) 

of the CAA, this finding started a 24 

month time period for us to promulgate 

a FIP to address interstate transport of 

air pollution and visibility protection, 

unless a SIP was approved during that 

time period. 

While Texas did not make a timely 

SIP submittal to address the interstate 

transport of air pollution and visibility 

protection for the 1997 ozone and PM2.5

NAAQS, Texas later made SIP 

submittals for all new or revised 

NAAQS. Specifically, Texas made the 

following submittals for new or revised 

NAAQS that pertain to this action: 

• 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) 

We previously acted on portions of 

the April 4, 2008, and November 23, 

2009, Texas SIP submittals that 

addressed other ‘‘infrastructure’’ 

elements specified in CAA Section 

110(a)(2), necessary to implement, 

maintain, and enforce the 1997 8-hour 

ozone and 1997 and 2006 PM2.5

NAAQS.15 Texas’ submittals addressing 

transport for the ozone, PM2.5, NO2 and 

SO2 NAAQS may be accessed through 

the www.regulations.gov Web site 

(Docket No. EPA–R06–OAR–2014– 

0754). Texas indicated in the submittals 

that its regional haze SIP fulfilled its 

obligation for addressing emissions that 

would interfere with measures required 

to be included in the SIP for any other 

state to protect visibility. Because of our 

2005 finding that Texas did not make a 

timely SIP submission for the 1997 

ozone and PM2.5 NAAQS and the 

expiration of the 24-month FIP clock, 

we are obligated to either approve the 

SIP or, disapprove the SIP and 

promulgate a FIP to address interstate 

transport of air pollution and visibility 

protection for Texas emissions for the 

1997 ozone and PM2.5 NAAQS. We 

believe our proposal addresses this 

obligation. 

C. Our Prior Limited Disapproval of 

Texas’ Regional Haze SIP Concerning 

CAIR 

In 2005, we promulgated CAIR, which 

required 28 states and the District of 

Columbia to reduce emissions of SO2

and NOX that significantly contribute to, 

or interfere with maintenance of, the 

1997 NAAQS for ozone and PM2.5.16

Also in 2005, we determined that states 

could rely on CAIR to meet certain 

requirements of the Regional Haze 

Rule.17 In particular, we amended our 

regulations to provide that states 

participating in the CAIR cap-and-trade 

programs under 40 CFR part 96 

pursuant to an EPA-approved CAIR SIP 

or states that remain subject to a CAIR 

FIP in 40 CFR part 97 need not require 

affected BART-eligible EGUs to install, 

operate and maintain BART for 

emissions of SO2 and NOX.18 A number 

of states, including Texas, relied on 

CAIR in their regional haze SIPs as an 

alternative to BART for EGU emissions 

of SO2 and NOX and as an element of 

their long-term strategy. 

Following our determination in 2005 

that states could rely on CAIR in their 

regional haze SIPs, the D.C. Circuit 

Court of Appeals ruled on several 

petitions challenging CAIR and 

remanded CAIR to us.19 We issued a 

new rule in 2011 to replace CAIR.20 The 

Cross-State Air Pollution Rule (CSAPR), 

which replaced CAIR, also requires a 

number of states to improve air quality 

by reducing SO2 and NOX emissions 

that cross state lines and significantly 

contribute to ozone and/or fine 

particulate pollution in other states. We 

amended our regulations in 2012 to 

allow CSAPR to serve as an alternative 

to SO2 and NOX BART for EGUs in 

states in the CSAPR region.21 In that 

same rulemaking, we also finalized a 

limited disapproval of the regional haze 

SIPs of 14 states, including Texas. 

Although at the time that we completed 

our limited disapproval of these SIPs, 

CAIR remained in place pursuant to an 

order of the D.C. Circuit, we explained 

that as CAIR had been remanded, it 

remained in place temporarily. We also 

finalized FIPs replacing reliance on 

CAIR with reliance on CSAPR as an 

alternative to BART for several states 

but not for Texas.22 We more fully 

explained the basis for our limited 

disapproval in that rulemaking and are 

not taking comment on our limited 

disapproval of Texas’ regional haze SIP 

in this action. 

II. Why are we acting on the Texas and 

Oklahoma Regional Haze SIPs 

simultaneously? 

As we explained in our 2011 

proposed rulemaking on the Oklahoma 

regional haze SIP,23 we did not take 

action on Oklahoma’s RPGs for the 

Wichita Mountains at that time because 

we first had to evaluate and act upon 

the regional haze SIP submitted by 

Texas. To properly assess whether 

Oklahoma had satisfied the reasonable 

progress requirements of Section 

51.308(d)(1), which include the 

requirement to set RPGs that take into 

account the visibility improvement that 

will result from reasonable controls in 

upwind states, we concluded that we 

had to review and evaluate Texas’ 

regional haze SIP before proposing 

action on Oklahoma’s RPGs. 

In our Regional Haze Rule, we stated 

that ‘‘successful implementation of the 

regional haze program will involve longterm regional coordination among 

States,’’ and that ‘‘States will need to 

develop strategies in coordination with 

one another, taking into account the 

effect of emissions from one jurisdiction 

to air quality in another.’’ 24 We also 

noted that RPGs and Long-Term 

Strategies (long-term strategies) were 

intricately linked. The Regional Haze 

Rule requires each state submitting a 

long-term strategy to (1) consult with 

other states to develop coordinated 

emission strategies; (2) demonstrate that 

the SIP includes all measures necessary 

for the state to obtain its share of the 

emission reductions needed to meet the 

RPGs for the Class I areas it affects; (3) 

document the technical basis the state 

used to determine its apportionment of 

emission reduction obligations for the 

Class I areas it affects; (4) consider all 

anthropogenic sources of emissions; and 

(5) consider a list of seven other 

enumerated factors.25

As detailed within this proposal and 

within our Technical Support 

Documents (TSDs), the Texas and 

Oklahoma regional haze SIPs reveal that 

sources in Texas not only significantly 

impact visibility in the Wichita 

Mountains National Wildlife Refuge in 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74822 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

Oklahoma, but that the impacts from 

Texas point sources are shown to be 

several times greater than the impact 

from Oklahoma’s own point sources. 

Additionally, information in the 

Oklahoma Regional Haze SIP 

demonstrates that even if every source 

in Oklahoma were fully controlled, the 

Wichita Mountains would not meet the 

Uniform Rate of Progress (URP) in 2018 

absent additional emission reductions 

from upwind sources, principally Texas. 

As detailed in the Texas SIP, however, 

Texas determined that no additional 

controls at its sources were warranted 

during the first planning period to help 

achieve reasonable progress at the 

Wichita Mountains, and Oklahoma did 

not request any additional reductions 

from Texas. As a result, Oklahoma set 

RPGs for the Wichita Mountains that do 

not reflect any reasonable emission 

reductions from Texas beyond those 

that will be achieved by compliance 

with other requirements of the CAA. 

This situation demonstrates the 

difficulties states face when working to 

address air pollution problems that do 

not respect state borders. It also 

highlights the respective roles and 

responsibilities of upwind and 

downwind states in addressing visibility 

impairment in national parks and 

wilderness areas. In order to address 

these intricately intertwined issues 

between Oklahoma and Texas, it is 

appropriate to review them 

simultaneously. 

III. Summary of Our Proposed Actions 

A. Texas 

We propose to partially approve and 

partially disapprove the regional haze 

SIP that Texas submitted to us on March 

31, 2009, to meet the requirements of 

Section 308 of the Regional Haze Rule. 

Specifically, we propose to take action 

on Texas’ BART determinations, RPGs 

for the Big Bend and Guadalupe 

Mountains Class I areas, and long-term 

strategy for making reasonable progress 

at all Class I areas impacted by 

emissions from Texas sources. We are 

also proposing to take action on the 

requirements that support these major 

components of the state’s plan, 

including Texas’ calculations of 

baseline and natural visibility 

conditions, calculation of the URP, 

identification of anthropogenic sources 

of visibility impairment within the state, 

and Texas’ monitoring strategy. We take 

very seriously a decision to propose 

disapproval of provisions in Texas’ 

plan, as we believe that it is preferable 

that all emission control requirements 

needed to protect visibility be 

implemented through the Texas SIP. 

However, in order to approve the state’s 

plan, we must be able to find that the 

state’s plan is consistent with the 

requirements of the CAA. Our proposed 

actions are summarized as follows: 

BART: We propose to approve Texas’ 

determination of which sources in the 

state are BART-eligible. We also propose 

to approve Texas’ determination that 

none of the state’s BART-eligible nonEGUs are subject to the BART 

requirements because they are not 

reasonably anticipated to cause or 

contribute to visibility impairment in 

any Class I areas. We propose to 

approve the provisions in Texas’ BART 

rules at 30 Tex. Admin. Code (TAC) 

116.1500—116.1540, with the exception 

of 30 TAC 116.1510(d), which relies on 

CAIR. With respect to EGUs, we 

previously issued a limited disapproval 

of the Texas regional haze SIP due to 

Texas’ reliance on CAIR to satisfy the 

BART requirements. This action does 

not impact the limited disapproval. 

Reasonable Progress Goals: We 

propose to disapprove Texas’ RPGs for 

2018 on the 20-percent least impaired 

and 20-percent most impaired days for 

the Big Bend and Guadalupe Mountains 

Class I areas. We propose to find that 

the state has not demonstrated that its 

RPGs provide for reasonable progress 

towards meeting the national visibility 

goal. Specifically, we propose to find 

that Texas did not satisfy several of the 

requirements at Section 51.308(d)(1) 

with regard to setting RPGs, most 

notably the requirement to reasonably 

consider the four statutory reasonable 

progress factors and the requirement to 

adequately justify RPGs that are less 

stringent than the URP. 

Calculations of Baseline and Natural 

Visibility Conditions: We propose to 

approve Texas’ calculation of baseline 

visibility conditions at the Big Bend and 

Guadalupe Mountains Class I areas. We 

propose to disapprove Texas’ 

calculation of natural visibility 

conditions at these Class I areas. 

Because we propose to disapprove 

Texas’ calculation of natural visibility 

conditions, we must also propose to 

disapprove Texas’ calculation of the 

URP. 

Long-Term Strategy: We propose to 

disapprove Texas’ long-term strategy 

because it does not sufficiently address 

regional haze visibility impairment for 

all Class I areas impacted by Texas 

sources. Specifically, we propose to find 

that Texas did not satisfy several of the 

requirements of Section 51.308(d)(3) 

with regard to developing long-term 

strategies. We propose to find that 

Texas’ long-term strategy does not 

include all measures necessary to obtain 

the state’s share of emission reductions 

needed to make reasonable progress in 

the Wichita Mountains Class I area in 

Oklahoma. We also propose to find that 

the technical basis on which Texas 

relied to determine its apportionment of 

emission reduction obligations 

necessary for achieving reasonable 

progress in Wichita Mountains was 

inadequate. Finally, we propose to find 

that Texas did not adequately consider 

the emissions limitations and schedules 

for compliance needed to achieve 

reasonable progress in Big Bend, 

Guadalupe Mountains, or Wichita 

Mountains. We propose to find that 

Texas satisfied the remaining long-term 

strategy requirements, including the 

identification of anthropogenic sources 

of visibility impairment and the 

consideration of emission reductions 

due to ongoing air pollution control 

programs; measures to mitigate the 

impacts of construction activities; 

source retirement and replacement 

schedules; smoke management 

techniques; enforceability; and 

projected changes in emissions. 

Monitoring Strategy: We propose to 

approve Texas’ monitoring strategy. 

To remedy the deficiencies identified 

above, we propose a FIP for Texas that 

consists of a long-term strategy with SO2

emission limits for fifteen coal-fired 

EGUs that impact visibility in multiple 

Class I areas. We propose that these SO2

emission limits, listed below in Table 1, 

be met on a 30-boiler-operating-day 

rolling average. 

TABLE 1—PROPOSED 30-BOILEROPERATING-DAY SO2 EMISSION LIMITS

Unit 

Proposed SO2

emission limit 

(lbs/MMBtu) 

Scrubber Upgrades: 

Sandow 4 ...................... 0.20 

Martin Lake 1 ................ 0.12 

Martin Lake 2 ................ 0.12 

Martin Lake 3 ................ 0.11 

Monticello 3 ................... 0.06 

Limestone 2 ................... 0.08 

Limestone 1 ................... 0.08 

San Miguel* ................... 0.60 

Scrubber Retrofits: 

Big Brown 1 ................... 0.04 

Big Brown 2 ................... 0.04 

Monticello 1 ................... 0.04 

Monticello 2 ................... 0.04 

Coleto Creek 1 .............. 0.04 

Tolk 172B ...................... 0.06 

Tolk 171B ...................... 0.06 

* As we note elsewhere, we do not anticipate that San Miguel will have to install any 

additional control in order to comply with this 

emission limit. 

We propose to find that these 

emission limits will result in emission 

reductions that will achieve reasonable 

progress at Big Bend, the Guadalupe 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74823 

26As we explain later in our notice, San Miguel 

has already upgraded its scrubber and we are 

proposing that it maintain an emission rate 

consistent with recent monitoring data. 

27 42 U.S.C. Section 7410(a)(2)(D)(i)(II). 

28 Id. Section 7491(b)(2). 

29 Id. Section 7492. 

Mountains, and the Wichita Mountains. 

These emission limits reflect the degree 

of emission reduction that can be 

achieved by seven SO2 scrubber retrofits 

and seven SO2 scrubber upgrades,26 but 

we do not prescribe how the facilities 

must meet these emission limits. We 

determined that these emission limits 

are necessary to achieve reasonable 

progress based on our four-factor 

analysis, which demonstrates that the 

underlying controls are cost-effective 

and result in significant visibility 

improvement. We propose that those 

sources whose proposed emission limits 

can be achieved by installing scrubber 

retrofits must comply with the emission 

limits within five years of the effective 

date of our final rule. We propose that 

those sources whose emission limits can 

be achieved by conducting scrubber 

upgrades must comply with the 

emission limits within three years of the 

effective date of our final rule, except 

for San Miguel, for which we propose 

compliance within one year because 

that unit has been recently meeting our 

proposed emission limit. Our proposed 

FIP also includes new RPGs for Big 

Bend and Guadalupe Mountains that we 

believe reflect the visibility 

improvement that will result from the 

aforementioned SO2 emission limits, as 

well as new calculations of the natural 

visibility conditions for these Class I 

areas. 

We propose to replace Texas’ reliance 

on CAIR to satisfy the BART 

requirement for EGUs with reliance on 

CSAPR. 

Finally, we are also proposing to 

disapprove the portions of the 

infrastructure SIP revisions submitted 

by Texas to address the requirements of 

CAA Section 110(a)(2)(D)(i)(II) with 

respect to visibility. This provision of 

the CAA requires that each state’s SIP 

have adequate provisions to prohibit instate emissions from interfering with 

measures required to protect visibility 

in any other state. We refer to this and 

similar provisions pertaining to other 

states’ air quality as the ‘‘goodneighbor’’ requirements. We propose to 

disapprove portions of the Texas’ 

infrastructure SIP revisions addressing 

the ‘‘good-neighbor’’ visibility 

protection requirements for the 1997 

PM2.5 NAAQS, the 1997 ozone NAAQS, 

the 2006 PM2.5 NAAQS, the 2008 ozone 

NAAQS, the 2010 NO2 NAAQS, and the 

2010 SO2 NAAQS. We propose to find 

that the controls in our proposed FIP 

address the deficiencies in Texas’ 

regional haze SIP, in combination with 

the existing controls that Texas has 

relied upon in its regional haze SIP, will 

serve to prevent emissions from sources 

in Texas from interfering with measures 

required to protect visibility in other 

states. 

B. Oklahoma 

We propose to partially disapprove 

the regional haze SIP that Oklahoma 

submitted to us on February 19, 2010, 

to meet the requirements of Section 308 

of the Regional Haze Rule. Specifically, 

we propose to disapprove Oklahoma’s 

RPGs for 2018 on the 20-percent least 

impaired and 20-percent most impaired 

days for the Wichita Mountains Class I 

area. We propose to find that Oklahoma 

has not adequately demonstrated that its 

RPGs provide for reasonable progress 

towards meeting the national visibility 

goal. Specifically, we propose to find 

that Oklahoma did not satisfy several of 

the requirements at Section 51.308(d)(1) 

with regard to setting RPGs, including 

the requirement to adequately consult 

with other states that may reasonably be 

anticipated to cause or contribute to 

visibility impairment at the Wichita 

Mountains and the requirement to 

adequately justify RPGs that are less 

stringent than the URP. 

To remedy the deficiencies identified 

above, we propose a FIP for Oklahoma 

that includes revised RPGs for the 

Wichita Mountains that reflect the 

visibility improvement that will result 

from the SO2 emission limits in our 

long-term strategy for Texas included in 

our proposed FIP. Our proposed FIP for 

Oklahoma does not establish any 

additional requirements on sources 

within the state. 

IV. Discussion of the Regional Haze 

Rule Requirements as They Relate to 

Visibility Transport 

A. Introduction 

The Texas and Oklahoma regional 

haze SIPs reveal that sources in Texas 

not only impact visibility in the Wichita 

Mountains National Wildlife Refuge in 

Oklahoma, but that the impact from 

sources in Texas is several times greater 

than the impact from Oklahoma’s own 

sources. Additionally, the Oklahoma 

regional haze SIP demonstrates that, 

even if every source in Oklahoma were 

fully controlled, the Wichita Mountains 

would not meet the URP in 2018 absent 

additional emission reductions from 

upwind sources. Oklahoma and Texas 

discussed the significant contribution of 

sources in Texas to visibility 

impairment in Wichita Mountains 

during the interstate consultation 

process required by the Regional Haze 

Rule. Ultimately, however, Texas 

determined that no additional controls 

at its sources were warranted during the 

first planning period to help achieve 

reasonable progress at the Wichita 

Mountains, and Oklahoma did not 

request any additional reductions from 

Texas. As a result, Oklahoma set a 

reasonable progress goal for Wichita 

Mountains that does not achieve the 

URP and which does not reflect any 

emission reductions from Texas beyond 

those that will be achieved by 

compliance with other requirements of 

the CAA. During the notice-andcomment period on Oklahoma’s 

proposed SIP, several commenters 

criticized Oklahoma for not requesting 

additional reductions from Texas. They 

argued that without such reductions, 

Oklahoma would not make reasonable 

progress toward the national goal at the 

Wichita Mountains. In responding to 

these comments, Oklahoma 

acknowledged that sources in Texas had 

significant impacts on visibility in 

Wichita Mountains, but maintained that 

it did not have the regulatory authority 

to require emission reductions in other 

states. Oklahoma asserted that only 

Texas and the EPA could require such 

reductions. 

This situation demonstrates the 

difficulties states face when working to 

address air pollution problems that do 

not respect state borders. It also shows 

that some uncertainty exists as to the 

respective roles and responsibilities of 

upwind and downwind states in 

addressing visibility impairment in 

national parks and wilderness areas. 

Consequently, we believe that it is 

necessary at this time to provide 

clarification to the states on this issue, 

which hereafter will be referred to 

generally as the issue of ‘‘visibility 

transport.’’ Specifically, this section 

describes the regulatory requirements 

found at 40 CFR Sections 51.308(d)(1) 

and (d)(3), which pertain to RPGs, 

interstate consultation, and long-term 

strategies, and explains how these 

requirements apply in the visibilitytransport context. This section also 

explains how our interpretation of these 

requirements is consistent with the 

provisions of the CAA that seek to 

prevent interstate transport of visibilityimpairing pollutants,27 achieve 

reasonable progress toward the national 

goal,28 and address regional haze.29

B. Statutory and Regulatory Background 

Congress enacted Section 169A as 

part of the 1977 CAA Amendments, 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74824 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

30 Id. Section 7491(a)(1). 

31 Id. Section 7472(a). Although we often use the 

term, ‘‘Class I area’’ within this document, we 

mean, ‘‘Mandatory Class I Federal areas.’’ 

32 Id. Section 7491(a)(2). 

33 Id. 

34 ‘‘National Visibility Goal for Federal Class I 

Areas; Identification of Mandatory Class I Federal 

Areas Where Visibility Is an Important Value,’’ 44 

FR 69,122 (Nov. 30, 1979). 

35 42 U.S.C. Section 7491(b)(1). 

36 Id. Section 7491(b)(2). 

37 Id. 

38 Id. Section 7491(g)(1). 

39 Id. Section 7491(b)(2)(A). 

40 Id. Section 7491(g)(2). 

41 Id. Section 7491(b)(2)(B). 

42 42 U.S.C. Section 7410(a)(2)(D)(i)(II). 

43S. Rep. No. 95–127, at 41 (1977). 

44 ‘‘Visibility Protection for Class I Areas,’’ 45 FR 

34762 (May 22, 1980). 

45 45 FR 34763/3. 

46 Id. 

47 40 CFRCFR Section 51.301. 

48 45 FR 34763/3. 49 40 CFRCFR Section 51.301. 50 ‘‘Visibility Protection for Federal Class I 

Areas,’’ 45 FR 80084 (Dec. 2, 1980) (codified at 40 

CFR Sections 51.300–307). 51 Id. at 80086/1. 52See Id. at 80086/1 n.2 (‘‘We did not identify, 

nor did any commenters identify any State that did 

not contain a mandatory Class I Federal area, but 

which could contain a source the emissions from 

which could reasonably be anticipated to cause or 

contribute to any impairment of visibility in any 

mandatory Class 1 Federal area.’’). 

53 Id. at 80086/3. 

54 Id. at 80086/1. 

55 Id. at 80088/3. 

56 ‘‘State Implementation Plans for Visibility 

Long-Term Strategies, Integral Vistas, and Control 

Strategies,’’ 52 FR 45132 (Nov. 24, 1987). 

declaring as a national goal ‘‘the 

prevention of any future, and the 

remedying of any existing, impairment 

of visibility in mandatory Class I areas 

which impairment results from 

manmade air pollution.’’ 30 The term 

‘‘mandatory Class I Federal areas’’ refers 

to international parks, national 

wilderness areas and memorial parks 

that exceed 5,000 acres in size, and 

national parks that exceed 6,000 acres in 

size, which were in existence on August 

7, 1977.31 Congress directed the 

Secretary of the Interior, in consultation 

with the federal land managers to 

review all mandatory Class I Federal 

areas in the country and to identify 

those where visibility was an important 

value.32 Congress then directed us to 

confer with the Secretary of the Interior 

regarding the results of his review and 

to promulgate a final list of mandatory 

Class I Federal areas that would become 

subject to the protections of Section 

169A.33 On November 30, 1979, we 

finalized a list of 156 mandatory Class 

I Federal areas deserving of such 

protection.34

Congress also required us to issue 

regulations that would provide 

guidelines to the states on appropriate 

techniques and methods for identifying 

and measuring visibility impairment; 

modeling the extent to which manmade 

air pollution causes or contributes to 

such impairment; and preventing and 

remedying such pollution and 

impairment.35 In addition, Congress 

required our regulations to direct both 

states that contained mandatory Class I 

Federal areas, and states ‘‘the emissions 

from which may reasonably be 

anticipated to cause or contribute to any 

impairment of visibility in any such 

area,’’ to include three specific 

components in their SIPs.36

The first component consists of 

‘‘emission limitations, schedules of 

compliance and other measures as may 

be necessary to make reasonable 

progress toward meeting the national 

goal.’’ 37 In determining what 

constitutes ‘‘reasonable progress,’’ 

Congress directed states to take into 

consideration four statutory factors: (1) 

The costs of compliance, (2) the time 

necessary for compliance, (3) the energy 

and non-air quality impacts of 

compliance, and (4) the remaining 

useful life of any existing source subject 

to such requirements.38 The second 

component is a requirement that a 

specified group of older major stationary 

sources ‘‘procure, install, and operate, 

as expeditiously as practicable . . . the 

best available retrofit technology,’’ more 

commonly referred to as BART.39 Like 

the emission limitations required to 

make reasonable progress, the emission 

limitations representing BART must be 

determined by taking into consideration 

a list of statutory factors.40 Lastly, the 

third component consists of ‘‘a longterm (ten to fifteen years) strategy for 

making reasonable progress toward the 

national goal.’’ 41 This section focuses 

specifically on the first and third 

components: Reasonable progress and 

long-term strategies. 

In addition to enacting Section 169A, 

Congress also amended Section 110 of 

the CAA to require that all SIPs 

‘‘contain adequate provisions 

prohibiting . . . any source or other 

type of emissions activity within the 

State from emitting any air pollutant in 

amounts which will . . . interfere with 

measures required to be included in the 

applicable implementation plan for any 

other State . . . to protect visibility.’’ 42

A Senate Committee Report described 

this provision and similar requirements 

as being ‘‘intended to equalize the 

positions of the States with respect to 

interstate pollution by making a source 

at least as responsible for polluting 

another State as it would be for 

polluting its own State.’’ 43

To comply with Congress’s mandate, 

we issued a notice of proposed 

rulemaking titled, ‘‘Visibility Protection 

for Federal Class I Areas,’’ on May 22, 

1980.44 In that notice, we proposed a 

phased approach to combating visibility 

impairment.45 In the first phase, we 

intended to address visibility 

impairment attributable to ‘‘a single 

source or small group of sources,’’ such 

as plume blight, which could be 

identified using visual observation or 

other simple monitoring techniques.46

We referred to this type of visibility 

impairment as ‘‘reasonably attributable 

visibility impairment,’’ or RAVI.47

Then, once modeling and monitoring 

techniques had improved sufficiently, 

we intended to engage in a second 

phase of rulemaking to address the more 

complex problem of regional haze,48

which we defined as ‘‘visibility 

impairment that is caused by the 

emission of air pollutants from 

numerous sources located over a wide 

geographic area.’’ 49

We finalized our first phase of 

rulemaking on December 2, 1980.50

These regulations, hereafter referred to 

as the ‘‘RAVI Rule,’’ applied only to the 

36 states that contain mandatory Class 

I Federal areas.51 Notably, the RAVI 

Rule did not apply to upwind states, i.e., 

those states, ‘‘the emissions from which 

may reasonably be anticipated to cause 

or contribute to any impairment of 

visibility in any such area,’’ as required 

by Section 169A.52 Among other things, 

the RAVI Rule authorized the federal 

land managers to determine whether 

visibility impairment existed in any 

mandatory Class I Federal area.53 The 

RAVI Rule also required states to revise 

their SIPs to assure reasonable progress 

toward the national goal, to determine 

whether BART should be installed at 

sources causing visibility impairment 

certified by the federal land managers, 

and to implement long-term strategies 

for making reasonable progress.54

Ultimately, however, we concluded that 

‘‘[p]reliminary indications are that few, 

if any, existing stationary facilities will 

have to retrofit controls,’’ and that 

‘‘many of the basic elements of an 

acceptable [long-term] strategy already 

exist within the framework of other air 

pollution programs.’’ 55

Most states did not submit the SIP 

revisions required by the RAVI Rule. To 

resolve a lawsuit brought by 

environmental litigants, we 

promulgated FIPs for these states on 

November 24, 1987.56 Despite the fact 

that the federal land managers had 

certified that visibility impairment 

existed in nearly all mandatory Class I 

Federal areas, we ultimately determined 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74825 

57 Id. 

58 Vermont v. Thomas, 850 F.2d 99 (2d Cir. 1988). 

59 Id. at 101. 

60 Id. 

61 Id. 

62 ‘‘Approval and Promulgation of 

Implementation Plans; Vermont; Visibility in 

Federal Class I Areas; Lye Brook Wilderness,’’ 52 

FR 26973 (July 17, 1987). 

63 Vermont, 850 F.2d at 103–04. 

64 Id. at 104. 

65 Id. 

66 Maine v. Thomas, 690 F. Supp. 1106 (D. Maine 

1988). 

67The States were Connecticut, Maine, 

Massachusetts, New Jersey, New York, Rhode 

Island, and Vermont. 

68See 42 U.S.C. Section 7491(a)(4). 

69 Id. at 1108. 

70 Id. at 1109. 

71 Id. at 1112. 

72 Maine v. Thomas, 874 F.2d 883 (1st Cir. 1989). 

73 Id. at 885–86. 

74See, e.g., 136 Cong. Rec. 2608 (1990) (statement 

of Sen. Tim Wirth); 136 Cong. Rec. 2771 (1990) 

(statement of Rep. Ron Wyden); 136 Cong. Rec. 

2875 (statement of Sen. Brock Adams). 

75 42 U.S.C. Section 7492. 

76 Id. Section 7492(a)(1). 77 Id. 78 Id. Section 7492(c)(1). 79 Id. Section 7492(d). 80 Id. Section 7492(e)(1) & (2). 81 ‘‘Regional Haze Regulations,’’ 62 FR 41138 

(July 31, 1997). 82 Id. at 41139. 83 Id. at 41144–45. 

that neither BART nor any other 

controls were necessary to address the 

impairment because it was primarily in 

the form of regional haze and could not 

be attributed to a single source or small 

group of sources at that time.57

The following year, two decisions of 

the U.S. Courts of Appeal placed further 

emphasis on the fact that visibility 

impairment was largely a regional 

problem. The first case, Vermont v. 

Thomas,58 involved the State of 

Vermont’s challenge to our decision not 

to take action on aspects of Vermont’s 

SIP revision that were intended to 

address regional haze. In its SIP 

revision, Vermont had concluded that 

visibility impairment at the Lye Brook 

Wilderness Area was not caused by 

plume blight, but rather was comprised 

of regional haze caused primarily by 

sulfur dioxide emissions from out-ofstate sources.59 As such, only a 

reduction program that targeted those 

out-of-state sources could assure 

reasonable progress toward the national 

visibility goal. Vermont therefore 

proposed a long-term strategy that 

included a summertime ambient sulfate 

standard and a 48-state emission 

reduction plan.60 Vermont also 

requested that we disapprove and revise 

the SIPs of the upwind states that were 

contributing to regional haze in Lye 

Brook and require SIP revisions from 

those upwind states not currently 

subject to the RAVI Rule.61 We agreed 

with Vermont’s assessment of the 

visibility impairment at Lye Brook, but 

took no action on those parts of 

Vermont’s SIP revision aimed at 

controlling regional haze, explaining 

that they were outside the scope of the 

RAVI Rule.62

In its petition for review, Vermont 

argued that our decision not to act on 

the SIP revision in its entirety violated 

the CAA and the RAVI Rule.63 The 

Second Circuit upheld our 

interpretation, holding that Vermont’s 

proposed interstate measures were 

outside the scope of the RAVI Rule and 

thus were not subject to federal 

enforcement under the CAA. While the 

court sympathized with Vermont, 

recognizing ‘‘that without federal 

enforcement of Vermont’s plan, little, if 

any, progress will be made on regional 

haze at Lye Brook,’’ the court 

determined that, ‘‘until such time as a 

federal regional haze program is in 

place, Vermont may not impose its 

standards on upwind States.’’ 64 The 

court concluded its opinion by stating 

that it hoped EPA would act quickly to 

create a national program to address 

regional haze.65

The second case, Maine v. Thomas,66

involved a citizen suit brought by seven 

Northeastern states 67 and six 

environmental groups in which they 

sought to compel us to promulgate 

regulations addressing regional haze. 

The plaintiffs alleged that we had a 

nondiscretionary duty to issue 

regulations to achieve the national 

visibility goal by August 7, 1979,68 and 

that we had violated that duty because 

the RAVI Rule did not address regional 

haze and was therefore not a full 

response to the CAA’s directive.69 The 

district court rejected that argument, 

explaining that we had affirmatively 

chosen to take a phased approach to 

issuing visibility regulations when we 

promulgated the RAVI Rule.70 The 

district court therefore viewed the 

plaintiffs’ claim as a challenge to the 

RAVI Rule, which was not cognizable 

under the CAA’s citizen-suit provision. 

Therefore, the court dismissed the suit 

for lack of subject matter jurisdiction.71

On appeal, the First Circuit affirmed the 

district court’s judgment under largely 

the same reasoning.72 Like the Second 

Circuit, however, the court noted that 

EPA had long delayed in promulgating 

the promised rulemaking to address 

regional haze.73

Reacting to our delay in promulgating 

regulations to address regional haze and 

the courts’ decisions in Vermont and 

Maine,74 Congress enacted Section 169B 

of the CAA as part of the 1990 CAA 

Amendments.75 Congress designed 

Section 169B to provide regional 

solutions to what was, by definition, a 

regional problem. To address the 

technical limitations identified by us in 

the RAVI Rule, Congress required us to 

‘‘conduct research to identify and 

evaluate sources and source regions of 

both visibility impairment and regions 

that provide predominantly clean air in 

Class I areas.’’ 76 This research had to 

include an expansion of visibility 

monitoring in Class I areas, an 

assessment of the current sources of 

visibility-impairing pollution, the 

adaptation of regional air quality models 

for the assessment of visibility, and 

studies of the atmospheric chemistry 

and physics of visibility.77 Congress also 

provided us with the authority to 

establish visibility transport regions and 

commissions whenever we had reason 

to believe that ‘‘current or projected 

interstate transport of air pollutants 

from one or more States contributes 

significantly to visibility impairment in 

Class I areas located in the affected 

States.’’ 78 Once established, the 

visibility transport commissions and 

their member states were required to 

assess the available scientific and 

technical data regarding visibility 

impairment and to report back to us 

with recommendations regarding how 

existing statutory requirements for clean 

air corridors, new source review, and 

long-term strategies could be employed 

to reduce such impairment.79 Finally, 

Congress required us to carry out our 

overdue regulatory responsibilities 

under Section 169A, which had to 

include ‘‘criteria for measuring 

‘reasonable progress’ toward the 

national goal’’ and a requirement that 

states revise their SIPs within 12 

months.80

On July 31, 1997, we issued a notice 

of proposed rulemaking to revise the 

existing visibility regulations to address 

regional haze, commonly referred to as 

the ‘‘Regional Haze Rule.’’ 81 In that 

notice, we explained that ‘‘[t]he role of 

regional transport of fine particles in 

contributing to . . . regional haze 

impairment has been well documented 

by many researchers and recognized as 

a significant issue by many policy 

makers.’’ 82 Furthermore, we discussed 

how the studies required by the 1990 

CAA Amendments had revealed that, 

‘‘to varying degrees, emissions from 

each of the contiguous 48 States 

contribute to . . . visibility impairment 

in at least one mandatory Class I Federal 

area.’’ 83 Consequently, we proposed to 

expand the applicability of the visibility 

program to all states for the purpose of 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74826 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

84 Id. at 41144. 

85 Id. 

86 Id. at 41145. 

87 Id. at 41145–47. 

88As we note in the Regional Haze Rule (64 FR 

35725, July 1, 1999), the ‘‘deciview’’ or ‘‘dv’’ is an 

atmospheric haze index that expresses changes in 

visibility. This visibility metric expresses uniform 

changes in haziness in terms of common increments 

across the entire range of visibility conditions, from 

pristine to extremely hazy conditions. 

89 ‘‘Regional Haze Regulations,’’ 62 FR 41138 

(July 31, 1997) at 41446. 

90 Id. 

91 Id. 

92 Id. at 41147. 

93 Id. at 41153. 

94 Id. 

95 Id. 

96 Id. 

97 Id. at 41153–54. 

98 ‘‘Regional Haze Regulations,’’ 64 FR 35714 

(July 1, 1999). 

99 Id. at 35728. 

100 Id. at 35721. 

101 Id. at 35731. 

102 Id.; 40 CFR 51.308(d)(1). 

103 64 FR 35731 (July 1, 1999). 

104 64 FR 35731 (July 1, 1999); 40 CFR 

51.308(d)(1)(i)(A). 

105 64 FR 35731 (July 1, 1999). 

106 Id. at 35732; 40 CFR 51.308(d)(1)(i)(B). 

107 64 FR 35732 (July 1, 1999). 

108 Id.; 40 CFR 51.308(d)(1)(ii). 

109 64 FR 35732 (July 1, 1999); 40 CFR 

51.308(d)(1)(iv). 

addressing regional haze.84 We 

explained that this expansion of 

applicability was consistent with 

Section 169A(b)(2), which ‘‘requires 

States containing mandatory Class I 

Federal areas or having emissions which 

‘may reasonably be anticipated to cause 

or contribute to any impairment of 

visibility in any such area’ to revise 

their visibility SIPs in order to make 

reasonable progress toward the national 

visibility goal.’’ 85 We noted, however, 

that the expanded applicability of the 

visibility program should not be 

interpreted to mean that control 

strategies would be necessary in all 

cases. Instead, states should participate 

in regional air quality planning groups 

to establish and refine their relative 

contributions to regional haze, develop 

regional recommendations on state 

apportionment of emission reductions 

and control measure responsibilities, 

and identify existing SIP authorities or 

other proposed planning requirements 

necessary to address states’ 

contributions to visibility problems in 

other states.86

To satisfy Congress’s mandate that we 

establish criteria for measuring 

reasonable progress, we proposed to set 

presumptive ‘‘reasonable progress 

targets’’ for each Class I area.87 Under 

this framework, the reasonable progress 

targets would provide for perceptible 

improvement of at least 1.0 deciview 88

over a 10-year or 15-year period on the 

20-percent haziest days and allow no 

degradation from the baseline on the 20- 

percent clearest days.89 States could 

satisfy their reasonable progress 

obligations under Section 169A for a 

given Class I area by meeting the 

reasonable progress target for that 

area.90 States could also develop 

alternative targets so long as they 

justified those targets based on the four 

statutory factors.91 Finally, states would 

be required to provide a demonstration 

of reasonable progress every three years 

and revise their SIPs as necessary.92

To satisfy the CAA’s long-term 

strategy requirement, we proposed that 

states develop a procedure to determine 

natural and current visibility conditions 

for each Class I area for the 20-percent 

haziest and 20-percent clearest days.93

For Class I areas with existing 

anthropogenic impairment greater than 

1.0 deciview, states would be required 

to adopt measures, including BART and 

a combination of local and regional 

measures from non-BART sources, that 

would meet the reasonable progress 

targets over a three-year period.94 We 

also proposed that the long-term 

strategies explicitly address the 

contribution by each state needed to 

meet reasonable progress targets, 

explaining that ‘‘each State is ultimately 

responsible for determining its 

contribution to ensure reasonable 

progress in mandatory Class I areas 

affected by its emissions sources and 

implementing appropriate emissions 

control strategies.’’ 95 We further 

explained that it would consider this 

information, as well as any relevant 

regional planning analyses, in 

evaluating a state’s long-term strategy.96

Finally, we proposed requirements that 

would apply if a state did not meet its 

reasonable progress targets within a 

three-year period or when a state 

wished to develop alternative progress 

targets.97

We finalized the Regional Haze Rule 

on July 1, 1999.98 In the final rule, we 

reiterated that ‘‘[s]uccessful 

implementation of the regional haze 

program will involve long-term regional 

coordination among States,’’ and that 

‘‘States will need to develop strategies 

in coordination with one another, taking 

into account the effect of emissions from 

one jurisdiction to air quality in 

another.’’ 99 Consistent with the 

proposal, we concluded that all states 

had sources whose emissions were 

reasonably anticipated to cause or 

contribute to regional haze in at least 

one Class I area and therefore required 

all states to submit regional haze 

SIPs.100

In response to adverse comments, 

however, we also made significant 

changes to the proposal. We eliminated 

the requirement for presumptive 

reasonable progress targets of 1.0 

deciview.101 Instead, the final rule 

called upon states to establish 

‘‘reasonable progress goals,’’ or RPGs, 

for each Class I area.102 Like the 

reasonable progress targets, the RPGs 

had to be expressed in deciviews, 

provide for improvement on the 20- 

percent haziest days, and provide for no 

degradation on the 20-percent clearest 

days.103 Unlike the reasonable progress 

targets, however, the RPGs were to be 

set on a more flexible basis after 

consideration of the statutory factors.104

To provide greater equity between the 

RPGs set for the more impaired eastern 

states and the less impaired western 

states, we also introduced a new 

analytical requirement in the final 

rule.105 This requirement mandated 

that, for each Class I area, states (1) 

determine the amount of progress 

needed to reach natural background 

conditions in 60 years; (2) identify the 

URP, over that 60-year period; (3) 

identify the amount of progress that 

would result if the URP were achieved 

during the planning period; and (4) 

identify the emissions measures that 

would be needed to achieve that amount 

of progress and analyze whether the 

measures were reasonable based on the 

statutory factors.106 If a state found that 

the amount of progress necessary to 

achieve the URP (or some greater 

amount) was reasonable, then the final 

rule required the state to adopt that 

amount of progress as its RPG.107 If a 

state found that the amount of progress 

necessary to achieve the URP was 

unreasonable, however, then the state 

could set a less ambitious goal, but only 

after providing an analysis and rationale 

supporting its determination based on 

the statutory factors.108 Additionally, 

the final rule included a new 

requirement whereby states establishing 

RPGs had to consult with other states 

that were anticipated to contribute to 

visibility impairment in the Class I area 

under consideration and describe in 

their SIPs any actions taken to resolve 

disagreements over the apportionment 

of emission measures necessary to 

achieve the RPGs.109

In regard to the long-term strategy 

requirement, we explained that the 

RPGs and the long-term strategies were 

intricately linked. We interpreted the 

term ‘‘long-term strategy’’ as ‘‘the 

control measures that are needed to 

ensure reasonable progress, together 

with a demonstration that those 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74827 

110 64 FR 35734 (July 1, 1999). 

111 Id.; 40 CFR Section 51.308(f). 

112 64 FR 35735 (July 1, 1999); 40 CFR 

51.308(d)(3)(i). 

113 64 FR 35735 (July 1, 1999); 40 CFR 

51.308(d)(3)(ii). 

114 64 FR 35735 (July 1, 1999); 40 CFR 

51.308(d)(3)(iii). 

115 64 FR 35735 (July 1, 1999); 40 CFR 

51.308(d)(3)(iv). 

116 64 FR 35736–37 (July 1, 1999); 40 CFR 

51.308(d)(3)(v). 

117Am. Corn Growers v. EPA, 291 F.3d 1 (D.C. 

Cir. 2002). 

118 ‘‘Revisions to Regional Haze Rule to 

Incorporate Sulfur Dioxide Milestones and 

Backstop Emissions Trading Program for Nine 

Western States and Eligible Indian Tribes Within 

That Geographic Area,’’ 68 FR 33764 (June 5, 2003). 

119Ctr. for Energy & Econ. Dev. v. EPA, 298 F.3d 

653 (D.C. Cir. 2005). 

120 ‘‘Regional Haze Regulations and Guidelines 

for Best Available Retrofit Technology (BART) 

Determinations,’’ 70 FR 39104 (July 6, 2005). 

121See Id. at 39156–72 (codified at 40 CFR pt. 51, 

app. Y). 

122See Id. at 39156 (codified at 40 CFR 

51.308(e)(4)). 

123 ‘‘Regional Haze Regulations; Revisions to 

Provisions Governing Alternative to Source-Specific 

Best Available Retrofit Technology (BART) 

Determinations,’’ 71 FR 60612 (Oct. 13, 2006). 

124Util. Air Regulatory Grp. v. EPA, 471 F.3d 

1333 (D.C. Cir. 2006). 

125 ‘‘Regional Haze: Revisions to Provisions 

Governing Alternatives to Source-Specific Best 

Available Retrofit Technology (BART) 

Determinations, Limited SIP Disapprovals, and 

Federal Implementation Plans,’’ 77 FR 33641 (June 

7, 2012). 

126See, e.g., Nat’l Parks Conservation Ass’n v. 

EPA, No. 12–1480 (D.C. Cir. Dec. 17, 2012). 

127U.S. Envtl. Protection Agency, Additional 

Regional Haze Questions (Aug. 3, 2006). 

128 Id. at 10. 

129 Id. 

130 Id. at 11. 

131 Id. at 11–12. 

132 Id. at 12. 

133 Id. 

134 Id. 

135Office of Air Quality Planning & Standards, 

U.S. Envtl. Protection Agency, Guidance for Setting 

Reasonable Progress Goals Under the Regional Haze 

Program (June 1, 2007). 

136 Id. at 1–3. 

measures will provide for reasonable 

progress during the 10 to 15 year 

period.’’ 110 We abandoned our proposal 

to require states to update their longterm strategies every three years, 

providing instead for longer ten-year 

revisions.111 We also modified the 

requirements components of the longterm strategy. In brief, the final rule 

required each state submitting a longterm strategy to (1) consult with other 

states to develop coordinated emission 

management strategies,112 (2) 

demonstrate that the SIP includes all 

measures necessary for the state to 

obtain its share of the emission 

reductions needed to meet the RPGs for 

the Class I areas it affects,113 (3) 

document the technical basis the state 

used to determine its apportionment of 

emission reduction obligations for the 

Class I areas it affects,114 (4) consider all 

anthropogenic sources of emissions,115

and (5) consider a list of seven other 

enumerated factors.116

Since 1999, the Regional Haze Rule 

has been the subject of several revisions 

and legal challenges. Because none of 

these revisions or challenges impacted 

the regulatory provisions that are the 

focus of this section, each is discussed 

only in brief. In American Corn Growers 

v. EPA, the D.C. Circuit invalidated the 

Regional Haze Rule’s BART provisions 

because they required states to consider 

the visibility benefits of controls on a 

group-basis, rather than a sourcebasis.117 In 2003, we revised the 

Regional Haze Rule to incorporate 

provisions that would allow certain 

Western states and eligible Indian 

Tribes to implement alternative 

measures in lieu of BART.118 Shortly 

thereafter, in Center for Energy and 

Economic Development (CEED) v. EPA, 

the D.C. Circuit invalidated aspects of 

our 2003 revisions for using the same 

type of ‘‘group BART’’ approach that the 

court had forbade in American Corn 

Growers.119 In 2005, we revised the 

Regional Haze Rule a second time in 

order to remedy the defects with the 

Rule’s BART provisions that had been 

identified by the D.C. Circuit in 

American Corn Growers.120 In that same 

rulemaking, we promulgated the BART 

Guidelines to assist states in 

determining which sources are subject 

to BART and the appropriate level of 

control for such sources.121 Moreover, 

as noted above, we added a provision to 

the Regional Haze Rule that allowed 

certain Eastern states to rely on the 

CAIR in lieu of requiring BART at fossil 

fuel-fired EGUs.122 Then, in 2006, we 

revised the Regional Haze Rule a third 

time in order to remedy the defects with 

the Rule’s BART-alternative provisions 

that had been identified by the D.C. 

Circuit in CEED.123 A few months later, 

the D.C. Circuit upheld the 2005 

revisions in their entirety in Utility Air 

Regulatory Group v. EPA.124 The 2006 

revisions were never challenged. 

Finally, in 2012, we revised the 

Regional Haze Rule for a fourth time to 

replace the provision allowing Eastern 

states to rely on CAIR in lieu of BART 

with a provision allowing for reliance 

on CAIR’s successor, CSAPR.125

Challenges to the 2012 revisions are 

currently stayed and remain pending 

before the D.C. Circuit.126

During this same period, we also 

released several guidance documents 

pertaining to regional haze and visibility 

transport, some of which are helpful to 

the issues discussed in this section. In 

an August 3, 2006, document titled, 

‘‘Additional Regional Haze Questions,’’ 

we responded to questions submitted by 

states as they were developing their 

initial regional haze SIP submissions.127

Several states had questions regarding 

the interstate consultation process and 

the respective obligations of upwind 

and downwind states in setting RPGs 

and developing long-term strategies. For 

example, one state asked whether there 

was a protocol for resolving disputes 

between upwind and downwind states 

on apportionment and controls.128 In 

response, we encouraged the early 

identification of any potential disputes 

to allow all parties ample opportunity to 

address and document any 

disagreements.129 One state asked what 

would happen if a downwind state set 

a RPG that required an upwind state to 

make reductions that it would not 

make.130 We responded by stating, ‘‘If a 

State with a Class I area determines that 

a contributing State is not doing what is 

reasonable to meet the [RPG] set for the 

area, and has attempted to resolve this 

issue, the State with the Class I area 

should notify EPA and document this 

issue in its initial [regional haze] 

SIP.’’ 131 We explained that such 

problems should be brought to our 

attention as early in the process as 

possible.132 Finally, a third state asked 

whether a downwind state’s regional 

haze SIP could be disapproved because 

an upwind state was not doing all it 

could to meet the RPG for a downwind 

Class I area.133 We responded by 

reiterating the regulatory requirements 

and noting that, ‘‘If there is a 

disagreement among States as to what 

constitutes reasonable progress, the 

question of whether [a downwind 

State’s] or [an upwind State’s regional 

haze] SIP could be disapproved will 

depend on the specific[s] of the 

situation.’’ 134

On June 1, 2007, we released a second 

document to provide guidance to states 

on how to set their RPGs and how to 

decide those measures necessary to 

meet the goals.135 In the guidance, we 

provided a definition for the term 

‘‘reasonable progress goal,’’ explaining 

that RPGs are ‘‘interim goals that 

represent incremental visibility 

improvement over time toward the goal 

of natural background conditions and 

are developed in consultation with 

other affected States and Federal Land 

Managers.’’ 136 The guidance also 

reiterates that the long-term strategy and 

BART emission limitations are 

inherently linked to the RPGs: 

The long-term strategy is the compilation 

of ‘‘enforceable emissions limitations, 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74828 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

137 Id. at 1–4 (citing to 40 CFR 51.308(d)(3)). 

138See generally id. at 3–1 to 5–3. 

139 Id. at 2–4. 

140 42 U.S.C. Section 7410(a)(2)(D)(i) has four 

separate requirements or ‘‘prongs,’’ the last of 

which is that SIPs must address emissions that 

interfere with another State’s measures to protect 

visibility. 

141Office of Air Quality Planning & Standards, 

U.S. Envtl. Protection Agency, Guidance for State 

Implementation Plan (SIP) Submissions to Meet 

Current Outstanding Obligations Under Section 

110(a)(2)(D)(i) for the 8-Hour Ozone and PM2.5

National Ambient Air Quality Standards, at 9–10 

(Aug. 15, 2006). 

142Office of Air Quality Planning & Standards, 

U.S. Envtl. Protection Agency, Guidance on SIP 

Elements Required Under Sections 110(a)(1) and (2) 

for the 2006 24-Hour Fine Particle (PM2.5) National 

Ambient Air Quality Standards (NAAQS), at 5 

(Sept. 25, 2009). 

143Office of Air Quality Planning & Standards, 

U.S. Envtl. Protection Agency, Guidance on 

Infrastructure State Implementation Plan (SIP) 

Elements under Clean Air Act Sections 110(a)(1) 

and 110(a)(2) (Sept. 13, 2013). 

144 Id. at 33. 

145 Id. 

146 Id. at 34. 

147 Id. 

148 40 CFR 51.308(d)(1). 

149 Id. 51.308(d)(1)(i)(A). 

150 Id. n 51.308(d)(1)(iv). 

151 Id. 

152 Id. 

153 Id. 51.308(d)(3). 

154 Id. 

compliance schedules, and other measures as 

necessary to achieve the [RPGs],’’ and is the 

means through which the State ensures that 

its RPG will be met. BART emissions limits 

. . . are one set of measures that must be 

included in the SIP to ensure that an area 

makes reasonable progress toward the 

national goal, and the visibility improvement 

resulting from BART (or a BART alternative) 

is included in the development of the 

RPG.137

The majority of the guidance focuses 

on providing an overview of the process 

for developing RPGs, potential methods 

for identifying which source categories 

should be evaluated for controls, and 

suggestions for evaluating the four 

statutory factors with respect to 

potentially affected stationary 

sources.138 The guidance reiterates that 

the development of the RPG for each 

Class I area should be a collaborative 

process, but acknowledges that the 

Regional Haze Rule anticipated that 

states may not always agree on what 

measures would be reasonable or on the 

appropriateness of a given goal.139

Finally, in a series of three 

memoranda released in 2006, 2009, and 

2013, we provided guidance to the 

states regarding their obligations under 

Section 110(a)(2)(D)(i)(II) with respect to 

visibility transport, hereafter referred to 

as ‘‘prong 4.’’ 140 In the 2006 memo, we 

informed states that they could satisfy 

prong 4 for the 1997 8-hour ozone and 

PM2.5 NAAQS by making a simple SIP 

submission confirming that it was not 

possible at the time to assess whether 

there was any interference with 

measures in the SIPs of other states 

designed to protect visibility until the 

states submitted their regional haze SIPs 

the following year.141 In the 2009 

memo, we more plainly stated that 

states could satisfy prong 4 for the 2006 

24-hour PM2.5 NAAQS so long as they 

had fully approved regional haze 

SIPs.142 Most recently, in the 2013 

memo, we clarified states’ prong 4 

obligations with respect to the 2008 

ozone NAAQS, 2010 NO2 NAAQS, 2010 

SO2 NAAQS, and 2012 PM2.5

NAAQS.143 There, we reiterated that 

states could satisfy prong 4 by 

confirming that they had fully approved 

regional haze SIPs.144 We reasoned that 

a fully approved regional haze SIP 

necessarily would ensure that emissions 

from a state’s sources were not 

interfering with measures required to be 

included in other states’ SIPs to protect 

visibility.145 Alternatively, we 

explained that a state could satisfy its 

prong 4 obligations by including in its 

infrastructure SIP a demonstration that 

emissions within its jurisdiction do not 

cause interference.146 We clarified that 

such a submission would need to 

include measures to limit visibilityimpairing pollutants and ensure that the 

reductions were sufficient to comply 

with any mutually agreed upon RPGs 

for downwind Class I areas.147

C. Our Interpretation of 40 CFR 

51.308(d)(1) and (d)(3) 

With this background in mind, we 

turn now to the provisions of the 

Regional Haze Rule that implement the 

CAA’s reasonable progress and longterm strategy requirements in the 

visibility-transport context. Section 

51.308(d)(1) of the Regional Haze Rule 

requires states with Class I areas, i.e., 

downwind states, to ‘‘establish goals 

(expressed in deciviews) that provide 

for reasonable progress towards 

achieving natural visibility 

conditions.’’ 148 In establishing a RPG, a 

downwind state must consider the four 

statutory factors outlined in Section 

169A(g)(1) of the CAA—‘‘the costs of 

compliance, the time necessary for 

compliance, the energy and non-air 

quality environmental impacts of 

compliance, and the remaining useful 

life of any potentially affected 

sources.’’ 149 This requirement is 

commonly referred to as a four-factor 

analysis. States analyze the four factors 

to determine a reasonable set of control 

measures that will reduce visibilityimpairing emissions. The visibility 

improvement that will result from these 

emission reductions is then factored 

into the state’s RPGs. 

In addition to conducting a four-factor 

analysis to determine what control 

measures are reasonable for a 

downwind state’s own sources, the 

downwind state ‘‘must consult with 

those States which may reasonably be 

anticipated to cause or contribute to 

visibility impairment in the mandatory 

Class I Federal area,’’ 150 i.e., upwind 

states. The purpose of the consultation 

requirement is to ensure that the 

upwind states adopt control measures 

sufficient to address their 

apportionment of emission reductions 

necessary to achieve reasonable progress 

and that the downwind state’s RPGs 

properly account for the visibility 

improvement that will result from the 

reasonable control measures identified 

and included in the upwind state’s longterm strategy. Where a downwind state 

and an upwind state cannot agree on the 

proper apportionment of emission 

reductions necessary to achieve 

reasonable progress, however, the 

downwind state ‘‘must describe in its 

[SIP] submittal the actions taken to 

resolve the disagreement.’’ 151 This 

documentation is necessary so that we 

have sufficient information to evaluate 

the downwind state’s RPGs. Ultimately, 

we must decide, among other things, 

‘‘whether the State’s goal provides for 

reasonable progress towards natural 

visibility conditions,’’ 152 or whether the 

goal is inadequate due to an upwind 

state’s failure to include reasonable 

control measures in its long-term 

strategy. 

Section 51.308(d)(3) of the Regional 

Haze Rule requires all states (both 

downwind and upwind) to ‘‘submit a 

long-term strategy that addresses 

regional haze visibility impairment for 

each mandatory Class I Federal area 

within the State and for each mandatory 

Class I Federal area located outside the 

State which may be affected by 

emissions from the State.’’ 153 As 

explained previously, a state’s long-term 

strategy is inextricably linked to the 

RPGs because it ‘‘must include 

enforceable emission limitations, 

compliance schedules, and other 

measures as necessary to achieve the 

reasonable progress goals established by 

states having mandatory Class I Federal 

areas.’’ 154

In establishing its long-term strategy, 

a state must meet a number of 

requirements, three of which pertain to 

visibility transport. First, as a corollary 

to Section 51.308(d)(1)(iv), upwind 

states ‘‘must consult with [downwind] 

State(s) in order to develop coordinated 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74829 

155 Id. 51.308(d)(3)(i). 

156 Id. 51.308(d)(3)(ii). Similarly, ‘‘[i]f the State 

has participated in a regional planning process, the 

State must ensure it has included all measures 

needed to achieve its apportionment of emission 

reduction obligations agreed upon through that 

process.’’ Id. 

157 Id. 51.308(d)(3)(iii). 

158 42 U.S.C. Section 7491(g)(1). 

159 40 CFR 51.308(d)(3)(iii). 

160See WildEarth Guardians v. EPA, 2014 U.S. 

App. LEXIS 20145, at *55 (10th Cir. Oct. 21, 2014) 

(explaining that 40 CFR 51.308(d)(3)(iii) ‘‘permits a 

State conducting a reasonable-progress 

determination’’ ‘‘to rely on [a regional planning 

organization’s] four-factor analysis.’’). 

161Auer v. Robbins, 519 U.S. 452, 461 (1997). 

162Sec’y of Labor, Mine Safety & Health Admin. 

v. W. Fuels-Utah, 900 F.2d 318, 320 (D.C. Cir. 

1990). 

163 40 CFR 51.308(d). 

164 Id. 

165 42 U.S.C. Section 7491(a)(1). 

166 Id. Section 7491(b)(2). 

167 Id. Section 7491(g)(1). 

168See, e.g., Office of Air Quality Planning & 

Standards, U.S. Envtl. Protection Agency, Guidance 

on Infrastructure State Implementation Plan (SIP) 

Elements under Clean Air Act Sections 110(a)(1) 

and 110(a)(2) (Sept. 13, 2013). 

management strategies.’’ 155 Second, 

where multiple states cause or 

contribute to visibility impairment in a 

Class I area, each state ‘‘must 

demonstrate that it has included in its 

implementation plan all measures 

necessary to obtain its share of the 

emission reductions needed to meet the 

progress goal for the area.’’ 156 This 

requirement directly addresses 

situations where an upwind state agrees 

to achieve certain emission reductions 

during the consultation process, and 

downwind states rely upon those 

reductions when setting their RPGs, but 

the upwind state ultimately fails to 

include sufficient control measures in 

its long-term strategy to ensure that the 

emission reductions will be achieved. In 

such a situation, we must disapprove 

the upwind state’s long-term strategy. 

However, the regulations do not 

explicitly address situations where the 

control measures in an upwind state’s 

long-term strategy are sufficient to 

obtain its share of reductions needed to 

meet a RPG included in a downwind 

state’s SIP, but the goal itself is flawed 

precisely because the upwind state 

never proposed sufficient control 

measures to ensure reasonable progress 

in the first place. To prevent such 

situations, we interpret the term 

‘‘progress goal’’ in Section 

51.308(d)(3)(ii) as an approved or 

approvable progress goal. Consequently, 

where a RPG in a downwind state’s SIP 

does not account for adequate visibility 

improvement from an upwind state for 

this reason, we must disapprove both 

the downwind state’s goal and the 

upwind state’s long-term strategy. 

Finally, each state ‘‘must document 

the technical basis, including modeling, 

monitoring and emissions information, 

on which the State is relying to 

determine its apportionment of 

emission reduction obligations 

necessary for achieving reasonable 

progress in each mandatory Class I 

Federal area it affects.’’ 157 To reiterate, 

Section 169A(g)(1) of the CAA requires 

states to determine ‘‘reasonable 

progress’’ by considering the four 

statutory factors.158 Therefore, this 

provision requires states to consider 

both their own Class I areas and 

downwind Class I areas when they 

develop the technical basis underlying 

their four-factor analyses. This 

documentation is necessary so that the 

interstate consultation process can 

proceed on an informed basis and so 

that downwind states can properly 

assess whether any additional upwind 

emission reductions are necessary to 

achieve reasonable progress at their 

Class I areas. The regulations further 

provide that, ‘‘States may meet this 

requirement by relying on technical 

analyses developed by the regional 

planning organization and approved by 

all State participants.’’ 159 Thus, states 

have the option of meeting this 

requirement by relying on four-factor 

analyses and associated technical 

documentation prepared by a regional 

planning organization on behalf of its 

member states,160 to the extent that such 

analyses and documentation were 

conducted. In situations where a 

regional planning organization’s 

analyses are limited, incomplete or do 

not adequately assess the four factors, 

however, then states must fill in any 

remaining gaps to meet this 

requirement. 

Under Auer v. Robbins, 519 U.S. 452, 

461 (1997), an administrative agency is 

entitled to interpret its own regulations, 

and that interpretation will be entitled 

to judicial deference as long as the 

interpretation is not ‘‘plainly erroneous 

or inconsistent with the regulation.’’ 161

Moreover, as the D.C. Circuit has 

explained, ‘‘a regulation must be 

interpreted as to harmonize with and 

further and not to conflict with the 

objective of the statute it 

implements.’’ 162 We believe that our 

clarification of the requirements of 

Sections 51.308(d)(1) and (d)(3), as 

provided above, is reasonable, 

consistent with the overall framework of 

the Regional Haze Rule, and in harmony 

with the objectives of the CAA’s 

visibility provisions. 

First, we believe that our 

interpretation is consistent with the 

Regional Haze Rule as a whole. Section 

51.308(d) of the Regional Haze Rule, 

which subsumes all of the provisions 

discussed above, provides that states 

‘‘must address regional haze in each 

mandatory Class I Federal area located 

within the State and in each mandatory 

Class I Federal area located outside the 

State which may be affected by 

emissions from within the State.’’ 163

Our interpretation gives this ‘‘core 

requirement’’ 164 force by ensuring that 

downwind states account for all 

reasonable emission reductions when 

setting their RPGs and by ensuring that 

upwind states thoughtfully consider 

their impacts on neighboring Class I 

areas when conducting their four-factor 

analyses. 

Similarly, our interpretation 

harmonizes and furthers the goals of the 

CAA. Congress declared as a national 

goal ‘‘the prevention of any future, and 

the remedying of any existing, 

impairment of visibility’’ in all Class I 

areas.165 We believe it would be 

impossible to achieve this goal if 

upwind states did not have the same 

responsibility to address their visibilityimpairing emissions and achieve 

reasonable progress in downwind Class 

I areas as the downwind states 

themselves. Indeed, Section 169A(b)(2) 

explicitly required our implementing 

regulations to ‘‘require each applicable 

implementation plan . . . for a State the 

emissions from which may reasonably 

be anticipated to cause or contribute to 

any impairment of visibility in any such 

area [i.e., upwind States] to contain such 

emission limits, schedules of 

compliance and other measures as may 

be necessary to make reasonable 

progress toward meeting the national 

goal.’’ 166 As explained previously, the 

CAA requires states to determine what 

emission limits and other measures are 

necessary to make reasonable progress 

by considering the four statutory 

factors.167 Therefore, our interpretation 

of Section 51.308(d)(3)(ii) and (iii) 

ensures that the Regional Haze Rule 

requires what the CAA requires—that 

upwind states consider impacts at 

downwind Class I areas in their fourfactor analyses and, where appropriate, 

include emission limits and other 

measures to make reasonable progress at 

those Class I areas in their long-term 

strategies. 

Moreover, consistent with our 

guidance,168 our interpretation ensures 

that regional haze SIPs will be able to 

satisfy the CAA’s requirement that SIPs 

‘‘contain adequate provisions 

prohibiting . . . any source or other 

type of emissions activity within the 

State from emitting any air pollutant in 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74830 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

169 42 U.S.C. 7410(a)(2)(D)(i)(II). 

170S. Rep. No. 95–127, at 41 (1977). 

171See Vermont v. Thomas, 850 F.2d 99, 101 (2d 

Cir. 1988). 

172 Id. at 104. 

173 42 U.S.C. Section 7492(e)(1). 

174See, e.g., 136 Cong. Rec. 2608 (1990) 

(statement of Sen. Tim Wirth); 136 Cong. Rec. 2771 

(1990) (statement of Rep. Ron Wyden); 136 Cong. 

Rec. 2875 (statement of Sen. Brock Adams). 

175See U.S. Envtl. Protection Agency, Additional 

Regional Haze Questions, 10–12 (Aug. 3, 2006). 

176 Id. at 12. 

177 Guidance for Estimating Natural Visibility 

Conditions Under the Regional Haze Rule, EPA– 

454/B–03–005, September 2003. 

178Because this is the first regional haze planning 

period, baseline visibility conditions and current 

visibility conditions are the same. In future 

planning periods, we expect that baseline and 

current visibility conditions will be different due to 

reasonable progress being made and other changes 

in conditions. 

179Light extinction, in units of inverse 

megameters (Mm¥1), is the amount of light lost as 

it travels over one million meters. The haze index, 

in units of deciviews (dv), is calculated directly 

from the total light extinction, bext, as follows: HI 

= 10 ln(bext/10). 

180The IMPROVE program is a cooperative 

measurement effort governed by a steering 

committee composed of representatives from 

Federal agencies (including representatives from 

EPA and the federal land managers) and regional 

planning organizations. The IMPROVE monitoring 

program was established in 1985 to aid the creation 

amounts which will interfere with 

measures required to be included in the 

applicable implementation plan for any 

other State . . . to protect visibility.’’ 169

Congress intended this provision of the 

CAA to ‘‘equalize the positions of the 

States with respect to interstate 

pollution,’’ 170 and our interpretation 

accomplishes this goal by ensuring that 

downwind states can seek recourse from 

us if upwind states are not doing 

enough to address visibility transport. 

Finally, we believe that our 

interpretation is consistent with the 

long-standing recognition of Congress, 

the states, the courts, and us that 

regional haze is a regional problem that 

requires regional solutions. In 1987, the 

State of Vermont first envisioned a 

framework similar to the one ultimately 

adopted in the Regional Haze Rule by 

setting a goal sufficient to ensure 

reasonable progress (in that case, a 

summertime ambient sulfate standard) 

and requesting that we require upwind 

states to revise their SIPs to include 

measures that would provide the 

emission reductions necessary to meet 

that goal.171 The Second Circuit 

sympathized with Vermont’s plight 

despite upholding our inaction on 

Vermont’s SIP.172 Consequently, 

Congress enacted Section 169B of the 

CAA in 1990, which required us to issue 

new regulations to address regional 

haze.173 The Congressional record 

indicates that Congress was motivated 

in part by the dilemma of Vermont and 

other downwind states.174 After we 

promulgated the Regional Haze Rule in 

1999, states were acutely aware of the 

complexities of the visibility-transport 

problem, inquiring as to how disputes 

regarding the proper appropriation of 

emission reductions between downwind 

states and upwind states would be 

resolved.175 While we encouraged early 

collaboration among states in the hopes 

that such disputes would be minimized, 

we ultimately acknowledged that we 

might have to step in and disapprove 

either a downwind state or an upwind 

state’s SIP because it did not adequately 

address interstate visibility impacts.176

V. Our Analysis of and Proposed Action 

on the Texas Regional Haze SIP 

On March 31, 2009, we received a 

regional haze SIP revision from Texas. 

Prior to receiving Texas’ submittal, we 

reviewed a draft of the Texas regional 

haze SIP and submitted comments to 

the TCEQ in February 2008. Many of the 

issues we discuss below were originally 

identified in that document. This 

includes comments relating to ensuring 

that Texas include in its SIP all 

measures necessary to obtain its share of 

the emission reductions needed to meet 

the progress goals of Class I areas. 

Additionally, we met with the TCEQ on 

July 24, 2013, to further discuss Texas’ 

regional haze program and impacts from 

Texas sources on Class I areas. Provided 

below is a summary of our analysis of 

the various elements of Texas’ 

submission. For a more comprehensive 

analysis, please see our TX TSD, which 

is located in our docket to this 

rulemaking action. 

A. Affected Class I Areas 

In accordance with Section 51.308(d) 

of the Regional Haze Rule, the TCEQ 

identified two Class I areas within 

Texas: Big Bend National Park, in 

Brewster County, which borders the Rio 

Grande and Mexico, and the Guadalupe 

Mountains National Park in Culberson 

County, which borders New Mexico. 

The TCEQ is responsible for developing 

RPGs for these two Class I areas. The 

TCEQ also determined that emissions 

from sources in Texas impact visibility 

at a number of Class I areas outside of 

Texas. The Central Regional Air 

Planning Association (CENRAP) source 

apportionment modeling results, part of 

the state’s SIP, indicate that Texas 

emissions impact the visibility at a 

number of Class I areas in other states, 

including the Breton Wilderness Area in 

Louisiana, the Great Sand Dunes in 

Colorado, Caney Creek and the Upper 

Buffalo in Arkansas, the Wichita 

Mountains in Oklahoma, and several 

Class I areas in New Mexico. See the TX 

TSD for a summary of source 

apportionment modeling results for 

Class I areas in other states impacted by 

emissions from sources in Texas. 

B. Determination of Baseline, Natural, 

and Current Visibility Conditions 

As required by Sections 

51.308(d)(2)(i) and 51.308(d)(2)(iii) of 

the Regional Haze Rule, and in 

accordance with our 2003 Natural 

Visibility Guidance,177 the TCEQ 

calculated baseline/current 178 and 

natural visibility conditions for its two 

Class I areas, Big Bend and the 

Guadalupe Mountains, on the most 

impaired and least impaired days. 

1. Estimating Natural Visibility 

Conditions 

Natural background visibility, as 

defined in our 2003 Natural Visibility 

Guidance, is estimated by calculating 

the expected light extinction using 

default estimates of natural 

concentrations of fine particle 

components adjusted by site-specific 

estimates of humidity. This calculation 

uses the IMPROVE equation, which is a 

formula for estimating light extinction 

from the estimated natural 

concentrations of fine particle 

components (or from components 

measured by the IMPROVE monitors). 

This equation sums the light 

extinction 179 resulting from individual 

pollutants, such as sulfates and nitrates. 

Our guidance provides default natural 

conditions for the 20% worst and 20% 

best days for each Class I area based on 

the IMPROVE equation. As documented 

in our guidance, we allow states to use 

a ‘‘refined’’ approach or alternative 

approaches to the guidance defaults to 

estimate the values that characterize the 

natural visibility conditions of their 

Class I areas. Our guidance also states 

that states may wish to use a more 

refined approach to reduce uncertainty 

when baseline visibility is already near 

natural conditions or when there is 

marked seasonality. These alternative 

approaches can be implemented via 

alternative estimates of natural 

concentrations. One alternative 

approach is to develop and justify the 

use of alternative estimates of natural 

concentrations of fine particle 

components. Another option open to 

states is to use the ‘‘new IMPROVE 

equation’’ that was adopted for use by 

the IMPROVE Steering Committee in 

December 2005.180 The purpose of this 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74831 

of Federal and State implementation plans for the 

protection of visibility in Class I areas. One of the 

objectives of IMPROVE is to identify chemical 

species and emission sources responsible for 

existing anthropogenic visibility impairment. The 

IMPROVE program has also been a key participant 

in visibility-related research, including the 

advancement of monitoring instrumentation, 

analysis techniques, visibility modeling, policy 

formulation and source attribution field studies. 

181The science behind the revised IMPROVE 

equation is summarized in Appendix 5–1 of the 

Texas regional haze SIP and in numerous published 

papers. See for example: Hand, J.L., and Malm, 

W.C., 2006, Review of the IMPROVE Equation for 

Estimating Ambient Light Extinction Coefficients— 

Final Report. March 2006. Prepared for Interagency 

Monitoring of Protected Visual Environments 

(IMPROVE), Colorado State University, Cooperative 

Institute for Research in the Atmosphere, Fort 

Collins, Colorado, available at: http://

vista.cira.colostate.edu/improve/publications/

GrayLit/016_IMPROVEeqReview/

IMPROVEeqReview.htm and Pitchford, Marc., 2006, 

Natural Haze Levels II: Application of the New 

IMPROVE Algorithm to Natural Species 

Concentrations Estimates. Final Report of the 

Natural Haze Levels II Committee to the RPO 

Monitoring/Data Analysis Workgroup. September 

2006, available at http://vista.cira.colostate.edu/

improve/Publications/GrayLit/029_NaturalCondII/

naturalhazelevelsIIreport.ppt. 

182Pitchford, Marc, 2006, Natural Haze Levels II: 

Application of the New IMPROVE Algorithm to 

Natural Species Concentrations Estimates. Final 

Report of the Natural Haze Levels II Committee to 

the RPO Monitoring/Data Analysis Workgroup. 

September 2006, available at: http://

vista.cira.colostate.edu/improve/Publications/

GrayLit/029_NaturalCondII/

naturalhazelevelsIIreport.ppt. 

183The second version of the natural haze level 

II estimates based on the work of the Natural Haze 

Levels II Committee is available at: http://

vista.cira.colostate.edu/Docs/IMPROVE/Aerosol/

NaturalConditions/NaturalConditionsII_Format2_

v2.xls. 

refinement to the ‘‘old IMPROVE 

equation’’ was to provide more accurate 

estimates of the various factors that 

affect the calculation of light extinction. 

The new IMPROVE equation takes 

into account the most recent review of 

the science,181 and it accounts for the 

effect of particle size distribution on 

light extinction efficiency of sulfate 

(SO4), nitrate (NO3), and organic carbon. 

It also adjusts the mass multiplier for 

organic carbon (particulate organic 

matter) by increasing it from 1.4 to 1.8. 

New terms are added to the equation to 

account for light extinction by sea salt 

and light absorption by gaseous nitrogen 

dioxide. Site-specific values are used for 

Rayleigh scattering (scattering of light 

due to atmospheric gases) to account for 

the site-specific effects of elevation and 

temperature. Separate relative humidity 

enhancement factors are used for small 

and large size distributions of 

ammonium sulfate and ammonium 

nitrate and for sea salt. The terms for the 

remaining contributors, elemental 

carbon (light-absorbing carbon), fine 

soil, and coarse mass, do not change 

between the original and new IMPROVE 

equations. The default natural 

conditions in our 2003 guidance were 

updated by the Natural Haze Levels II 

Committee utilizing the new IMPROVE 

equation and included some 

refinements to the estimates for the PM 

components.182 183 These estimates are 

referred to as the ‘‘NCII’’ default natural 

visibility conditions. 

The TCEQ chose to derive a ‘‘refined’’ 

estimate of natural visibility conditions 

rather than using the default NCII 

values. In calculating natural visibility 

conditions, the TCEQ used the new 

IMPROVE equation and PM 

concentration estimates (i.e., the NCII 

values) for most components, but 

assumed that 100% of the fine soil and 

coarse mass concentrations in the 

baseline period should be attributed to 

natural causes and that the 

corresponding estimates in the NCII 

values should be replaced. The TCEQ 

noted there is some uncertainty with 

these calculations in the amount of 

natural fine and coarse mass 

assumption. The TCEQ also stated that, 

to the extent its assumption that 100% 

of coarse mass and fine soil is natural 

is an overestimate, it expects that its low 

organic carbon estimate will more than 

compensate for any errors in this 

assumption at this time. This issue is 

discussed in more detail in our TX TSD. 

For the 20% worst days, the TCEQ 

calculated natural visibility conditions 

for Big Bend and the Guadalupe 

Mountains of 10.09 dv and 12.26 dv, 

respectively. For the 20% best days, the 

TCEQ calculated that natural visibility 

conditions for Big Bend and the 

Guadalupe Mountains of 2.19 dv, and 

2.10 dv, respectively. 

In response to FLM comments, the 

TCEQ also performed an additional 

calculation for the 20% worst days, 

assuming only 80% of fine soil and 

course mass as natural, in order to 

demonstrate the sensitivity of its 

approach to this assumption. Under this 

approach, the TCEQ estimated natural 

conditions to be 9.2 dv for the 20% 

worst days at Big Bend, compared to 

10.09 dv using the assumption that 

100% of fine soil and course mass is 

natural, and 7.16 dv using the NCII 

method. For the Guadalupe Mountains, 

the TCEQ’s estimate was 11.0 dv under 

the 80% assumption, compared with 

12.26 dv under the 100% assumption 

and 6.65 dv using the NCII method. 

These values are summarized below: 

TABLE 2—TCEQ NATURAL VISIBILITY CALCULATIONS

Guadalupe Mountains Big Bend 

20% Worst 

days 

20% Best 

days 

20% Worst 

days 

20% Best 

days 

100% fine soil and coarse mass ..................................................................... 12.26 2.10 10.09 2.19 

80% fine soil and coarse mass ....................................................................... 11.0 (1) 9.2 (1) 

NCII default ...................................................................................................... 6.65 0.99 7.16 1.62 

1 Not calculated. 

Ultimately, the TCEQ stated that it 

was including the 80% assumption for 

illustration purposes only and based its 

calculations of natural conditions on 

assuming that 100% coarse mass and 

fine soil assumption are due to natural 

sources. 

We agree that dust storms and other 

blown dust from deserts are a significant 

contributor to visibility impairment at 

the Texas Class I areas that may not be 

captured accurately by our default 

method. However, we propose to find 

that the TCEQ has not adequately 

demonstrated that all coarse mass and 

fine soil measured in the baseline 

period can be attributed to 100% natural 

sources. Anthropogenic sources of 

coarse mass and fine soil in the baseline 

period could have included emissions 

associated with paved and unpaved 

roads, agricultural activity, and 

construction activities. We also note 

that the impact from dust at Big Bend 

is less certain than at Guadalupe 

Mountains and a different assumption 

may be appropriate in estimating 

natural conditions there. Given the 

significant uncertainty in the 

assumptions used in the Texas 

methodology and the demonstrated 

sensitivity to the assumption of 100% 

natural versus 80% soil and coarse mass 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74832 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

184The TCEQ determined that the fourth quarter 

of 2000 for Big Bend was not sufficiently complete 

for use in calculating a baseline average for 

regulatory purposes, as it had only ten complete 

days. 

185 Guidance for Tracking Progress Under the 

Regional Haze Rule, EPA–454/B–03–004, 

September 2003. 

from natural sources, we propose to 

disapprove Texas’ calculation of the 

natural visibility conditions for the Big 

Bend and Guadalupe Class I areas. 

In its regional haze SIP, the TCEQ 

stated that it will continue to evaluate 

data, modeling, and any other sources of 

information in order to further improve 

its estimates. Furthermore, the TCEQ 

plans to work with us and the federal 

land managers to improve natural 

conditions estimates for future regional 

haze SIP revisions. We encourage these 

efforts. 

As discussed elsewhere in this notice, 

we propose to rely on the NCII default 

values that were used for every other 

Class I area in the country for our 

proposed FIP to address this deficiency 

in the Texas regional haze SIP, but we 

solicit comment on the acceptability of 

alternate estimates in the range between 

the EPA default estimates and Texas’ 

estimates. The federal land managers 

commented during the development of 

the Texas regional haze SIP that an 

assumption of 80% would be more 

reasonable than an assumption of 100%. 

We note that with any of the 

methodologies for calculating natural 

conditions discussed above, Texas’ 

Class I areas are not projected to meet 

the URP in 2018 according to the 

CENRAP modeling and are not 

projected to meet the goal of natural 

visibility conditions by 2064. 

2. Estimating Baseline Visibility 

Conditions 

As required by Section 51.308(d)(2)(i) 

of the Regional Haze Rule, the TCEQ 

calculated baseline visibility conditions 

for Big Bend and the Guadalupe 

Mountains. The baseline condition 

calculation begins with the calculation 

of light extinction for each day with 

monitoring data, using the IMPROVE 

equation. As with the natural visibility 

conditions calculation, the TCEQ chose 

to use the new IMPROVE equation, as 

described above. 

The period for establishing baseline 

visibility conditions is 2000–2004, and 

baseline conditions must be calculated 

using available monitoring data, as 

required under Section 51.308(d)(2). 

The TCEQ averaged the data from 2001 

through 2004 for Big Bend 184 and 

calculated the baseline conditions at Big 

Bend to be 17.30 dv on the 20% worst 

days, and 5.78 dv on the 20% best days. 

In calculating the baseline conditions at 

the Guadalupe Mountains, the TCEQ 

averaged the visibility data for 2000– 

2004, and calculated the baseline 

conditions at the Guadalupe Mountains 

to be 17.19 dv on the 20% worst days, 

and 5.95 dv on the 20% best days. We 

have reviewed the TCEQ’s estimation of 

baseline visibility conditions at Big 

Bend and the Guadalupe Mountains and 

are proposing to find that the TCEQ has 

satisfied the requirements of Section 

51.308(d)(2)(i). 

3. Natural Visibility Impairment 

To address Section 

51.308(d)(2)(iv)(A), the TCEQ also 

calculated the number of dv by which 

baseline conditions exceed natural 

visibility conditions for the best and 

worst days at Big Bend and the 

Guadalupe Mountains. The natural 

visibility impairment is calculated by 

subtracting the natural visibility 

calculation from the baseline visibility 

calculation. This information is 

summarized below: 

TABLE 3—NATURAL VISIBILITY IMPAIRMENT

Class I area Baseline 

visibility 

Natural 

visibility 

Natural 

visibility 

impairment 

20% Worst Days ...................................... Big Bend ................................................................ 17.30 10.09 7.21 

Guadalupe Mts ...................................................... 17.19 12.26 4.93 

20% Best Days ........................................ Big Bend ................................................................ 5.78 2.19 3.59 

Guadalupe Mts ...................................................... 5.95 2.10 3.85 

We have reviewed the TCEQ’s 

estimates of the natural visibility 

impairment at Big Bend and the 

Guadalupe Mountains and we propose 

to disapprove these estimates because 

this calculation depends on the TCEQ’s 

calculations for natural visibility 

conditions, which we also propose to 

disapprove for the reasons discussed in 

the previous section. 

4. Uniform Rate of Progress 

Under Section 51.308(d)(1)(i)(B), as 

part of its RPGs determination, the 

TCEQ analyzed and determined the 

URP needed to reach natural visibility 

conditions by the year 2064. Also in 

establishing its RPGs, the TCEQ 

considered the uniform rate of 

improvement in visibility and the 

emission reduction measures needed to 

achieve this rate for the period covered 

by the SIP. In so doing, the TCEQ 

compared the baseline visibility 

conditions to the natural visibility 

conditions for Big Bend and the 

Guadalupe Mountains, and determined 

the URP needed to attain natural 

visibility conditions by 2064. The TCEQ 

constructed the URP consistent with the 

requirements of the Regional Haze Rule 

and our 2003 Tracking Progress 

Guidance 185 by plotting a straight 

graphical line from the baseline level of 

visibility impairment to the level of 

visibility conditions representing no 

anthropogenic impairment in 2064 for 

both Big Bend and the Guadalupe 

Mountains. 

Using the baseline visibility values 

and natural visibility values discussed 

above, the TCEQ calculated the URP for 

Big Bend to be 0.12 dv/year, and that for 

the Guadalupe Mountains to be 0.08 dv/ 

yr. This information is summarized 

below: 

TABLE 4—SUMMARY OF UNIFORM RATE OF PROGRESS

Visibility metric Big Bend Guadalupe Mts. 

Baseline Conditions ........................................... 17.30 dv ............................................................ 17.19 dv. 

Natural Visibility ................................................. 10.09 dv ............................................................ 12.26 dv. 

Total Improvement by 2064 .............................. 7.21 dv .............................................................. 4.93 dv. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74833 

186 ‘‘SIP Narrative comparison of changes from 

proposal to adoption’’ available at: http://

www.tceq.texas.gov/assets/public/implementation/

air/sip/haze/4HazeSIPcompare_rev.pdf 

187The TSD for CENRAP Emissions and Air 

Quality Modeling To Support Regional Haze State 

Implementation is found in Appendix 8.1 of the 

Texas regional haze SIP. 

188Reproduced from Tables 10–2 and 10–3 of the 

Texas regional haze SIP. 

TABLE 4—SUMMARY OF UNIFORM RATE OF PROGRESS—Continued 

Visibility metric Big Bend Guadalupe Mts. 

Uniform Rate of Progress .................................. 0.12 dv/year ...................................................... 0.08 dv/year. 

Improvement needed by 2018 .......................... 1.7 dv. ............................................................... 1.2 dv 

The TCEQ notes that the URP 

calculations above have some degree of 

uncertainty due to its assumptions in 

calculating the natural visibility. 

Based on the estimated cost and 

visibility benefit from NOX and SO2

controls identified during the TCEQ’s 

four-factor analysis described below in 

Section V.C.2, the TCEQ estimated the 

costs and emission reduction measures 

of SO2 and NOX required to enable the 

Guadalupe Mountains and Big Bend to 

achieve the URP. However, it appears 

that in estimating the emission 

reductions and costs to meet its URPs in 

Table 10–9 of the Texas Regional Haze 

SIP, the TCEQ used estimates of 

visibility benefits from an earlier draft of 

the Texas Regional Haze SIP. In that 

draft SIP, the TCEQ estimated the 

visibility benefit from a certain set of 

controls to be 0.05 dv at each Texas 

Class I area.186 Based on TCEQ’s final 

estimation of the visibility benefit from 

the TCEQ control set, we have updated 

the TCEQ’s calculations. See our TX 

TSD for more information. 

Errors in its calculation aside, we note 

that while the TCEQ has, in establishing 

its RPG, correctly followed the 

procedures for analyzing and 

determining the rate of progress needed 

to attain natural visibility conditions by 

the year 2064, we propose to find the 

TCEQ has calculated this rate of 

progress on the basis of, and compared 

baseline visibility conditions to, a 

flawed estimation of natural visibility 

conditions for the Big Bend and 

Guadalupe Mountains, as we describe 

above. Therefore, we propose to 

disapprove the TCEQs calculation of the 

URP needed to attain natural visibility 

conditions by 2064. In addition, as we 

discuss in Section V.C, we identify 

problems with the TCEQ’s reasonable 

progress four factor analysis, which the 

TCEQ partially relied upon in 

consideration of the emission reduction 

measures needed to achieve the natural 

visibility conditions. For these reasons, 

we must also propose disapproval of the 

TCEQ’s estimation of the emission 

reduction measures needed to achieve 

the URP for the period covered by the 

SIP, under Section 51.308(d)(1)(i)(B). 

5. Reasonable Progress Goal Minimum 

Under Section 51.308(d)(1)(vi), Texas 

may not adopt a RPG that represents 

less visibility improvement than is 

expected to result from implementation 

of other requirements of the CAA during 

the applicable planning period. 

The RPGs established by Texas are 

based on CENRAP 2018 modeling 

projections. The modeling projections 

conducted by CENRAP contain 

projections of the visibility conditions 

that are anticipated to be realized at 

each Class I area between the 2002 base 

year and the 2018 future year. These 

projections are based on the emission 

reductions resulting from federal and 

state control programs that are either 

currently in effect or with mandated 

future-year emission reduction 

schedules that predate 2018, including 

the long-term strategies of Texas, 

Oklahoma, and other states, and 

presumptive emission reductions 

expected to result from the submitted 

Oklahoma BART rule. Since CENRAP’s 

2018 modeling projections are based on 

local, state, and federal control 

programs that are either currently in 

effect or with mandated future-year 

emission reduction schedules, we 

believe that the TCEQ’s RPGs represent 

at least as much visibility improvement 

as is expected to result from 

implementation of other requirements of 

the CAA (i.e., requirements other than 

RH) during the applicable planning 

period. We therefore propose to approve 

Texas’ submission as meeting Section 

51.308(d)(1)(vi) because its RPGs for the 

Guadalupe Mountains and Big Bend do 

not represent less visibility 

improvement than is expected to result 

from the implementation of other 

requirements of the CAA during this 

planning period. 

C. Evaluation of Texas’ Reasonable 

Progress Goals 

As required by Section 51.308(d)(1) of 

the Regional Haze Rule, the TCEQ has 

established RPGs for its two Class I 

areas, Big Bend and the Guadalupe 

Mountains. These RPGs must provide 

for an improvement in visibility for the 

most impaired days over the period of 

the implementation plan and ensure no 

degradation in visibility for the least 

impaired days over the same planning 

period. 

1. Establishment of the Reasonable 

Progress Goals 

The TCEQ states that its RPGs are 

derived from the CENRAP modeling 187

and reflect emission reductions 

programs already in place, including 

CAIR and additional refinery SO2

reductions as a result of our refinery 

consent decrees. The TCEQ states that 

these RPGs assume that either CAIR will 

remain in place or will be replaced by 

a comparable program to reduce 

visibility impairing pollution from 

Electric Generating Units (EGUs) in 

Texas and in the eastern United States. 

The following tables 188 summarize the 

TCEQ RPGs: 

TABLE 5—TEXAS REASONABLE PROGRESS GOALS FOR 20% WORST DAYS

Class I area 

Baseline 

conditions 

(dv) 

Projected 

2018 visibility 

(RPG) 

(dv) 

Improvement 

projected by 

2018 using 

RPG 

(dv) 

Improvement 

by 2018 

at URP 

(dv) 

Date natural 

visibility 

attained at 

RPG rate 

Big Bend .............................................................................. 17.30 16.6 0.7 1.7 2155 

Guadalupe Mountains .......................................................... 17.19 16.3 0.9 1.2 2081 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74834 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

189 64 FR 35733 (July 1, 1999). 190 64 FR 35732 (July 1, 1999). 191Reproduced from Table 3 in Appendix 10–1 

of the Texas regional haze SIP. 

TABLE 6—TEXAS REASONABLE PROGRESS GOALS FOR 20% BEST DAYS

Class I area 

Baseline 

conditions 

(dv) 

Projected 

2018 visibility 

(RPG) 

(dv) 

Improvement 

by 2018 

(dv) 

Big Bend ...................................................................................................................................... 5.8 5.6 0.2 

Guadalupe Mountains .................................................................................................................. 5.9 5.7 0.2 

Based on the results of Texas’ 

required reasonable progress four-factor 

analysis (described in the following 

section), and the results of the CENRAP 

modeling and additional information 

developed by CENRAP, the TCEQ 

adopted the CENRAP modeled 2018 

visibility conditions as the RPGs for the 

Big Bend and Guadalupe Mountains 

Class I areas. The TCEQ established a 

RPG of 16.6 dv for Big Bend and 16.3 

dv for Guadalupe Mountains for the 

20% worst days for 2018. This 

represents a 0.7 dv and 0.9 dv 

improvement in visibility over the 

baseline conditions at Big Bend and 

Guadalupe Mountains, respectively. 

Although Texas’ RPGs do provide for 

some improvement in visibility for the 

most impaired days over the period of 

the SIP and ensure no degradation in 

visibility for the least impaired days 

over the same period, we believe the 

overall RPG goals that Texas established 

for its own Class I areas of Big Bend and 

Guadalupe Mountains do not provide 

for reasonable progress based on the 

four reasonable progress factors that a 

state is required to consider in selecting 

a RPG under (d)(1)(i)(A). For the reasons 

discussed below, we propose to find 

that the RPGs identified for the Texas 

Class I areas are not reasonable. We 

address our proposed finding regarding 

whether the Texas regional haze SIP 

satisfies the requirements under Section 

51.308(d)(1) to set RPGs below. 

2. Texas’ Reasonable Progress Four 

Factor Analysis 

In establishing a RPG for a Class I area 

located within a state, Texas is required 

by CAA Section 169A(g)(1) and Section 

51.308(d)(1)(i)(A) to ‘‘[c]onsider the 

costs of compliance, the time necessary 

for compliance, the energy and non-air 

quality environmental impacts of 

compliance, and the remaining useful 

life of any potentially affected sources, 

and include a demonstration showing 

how these factors were taken into 

consideration in selecting the goal.’’ 

This requirement is often referred to as 

the reasonable progress ‘‘four factor 

analysis.’’ In addition to this explicit 

statutory and regulatory requirement, 

the Regional Haze Rule also establishes 

an analytical requirement to ensure that 

Texas carefully consider the suite of 

emission reduction measures necessary 

to attain the URP. Under Section 

51.308(d)(1)(iii), the Regional Haze Rule 

provides that we will consider both 

Texas’ consideration of the four factors 

in Section 51.308(d)(1)(i)(A) and its 

analysis of the URP ‘‘[i]n determining 

whether the State’s goal for visibility 

improvement provides for reasonable 

progress.’’ As explained in the preamble 

to the Regional Haze Rule, the URP 

analysis was adopted to ensure that 

states use a common analytical 

framework and to provide an informed 

and equitable decision making process 

to ensure a transparent process that 

would, among other things, guarantee 

that the public would be provided with 

the information necessary to understand 

the emission reductions needed, the 

costs of such measures, and other 

factors associated with improvements in 

visibility.189 The preamble to the 

Regional Haze Rule 190 also states that 

the URP does not establish a ‘‘safe 

harbor’’ for the state in setting its 

progress goals: 

If the State determines that the amount of 

progress identified through the [URP] 

analysis is reasonable based upon the 

statutory factors, the State should identify 

this amount of progress as its reasonable 

progress goal for the first long-term strategy, 

unless it determines that additional progress 

beyond this amount is also reasonable. If the 

State determines that additional progress is 

reasonable based on the statutory factors, the 

State should adopt that amount of progress 

as its goal for the first long-term strategy. 

In establishing its RPGs for 2018 for 

the 20% worst days, the TCEQ relied on 

the improvements in visibility that are 

anticipated to result from federal, state, 

and local control programs. Based on 

the emission reductions from these 

measures, CENRAP modeled the 

projected visibility conditions 

anticipated at each Class I area in 2018 

and the TCEQ used these results to 

establish its RPGs. The TCEQ states it 

developed its RPGs after considering the 

regulatory factors required under 

Section 51.308(d)(1)(i)(A), discussed 

above. The TCEQ focused its control 

strategy analysis on point source 

emissions of SO2 and NOX, as the 

sources of these pollutants are the main 

anthropogenic pollutants that affect 

visibility at Class I areas in Texas. It 

examined visibility impairment at the 

Texas Class I areas and Class I areas in 

nearby states. The TCEQ stated that 

source apportionment modeling results, 

summarized in Chapter 11 of the Texas 

regional haze SIP, demonstrate that NOX

and SO2 are the main anthropogenic 

pollutants that affect visibility at the 

Class I areas in Texas and Class I areas 

in surrounding states. Source 

apportionment modeling also indicated 

that sulfur emissions that impact 

visibility are dominated by point 

sources, while impacts from NOX

emissions are more evenly distributed 

between area, mobile and point sources. 

The following table 191 summarizes the 

source category contributions from the 

2002 base case CENRAP source 

apportionment modeling for the five 

Class I areas whose visibility is most 

impacted by Texas emissions. In 

evaluating the emission inventory 

projections, Texas concluded that for 

SO2, point sources are responsible for 

over 90% of the projected 2018 

statewide emissions, and for NOX, point 

sources comprise over 45% of the 

projected statewide emissions. The 

TCEQ noted that NOX emissions are 

more evenly distributed among point, 

mobile, and area sources, and that states 

have very limited authority to reduce 

mobile source emissions and are already 

addressing road and non-road mobile 

emissions. The TCEQ noted the largest 

category of area source NOX is upstream 

oil and gas production, and it is taking 

all steps it has determined are 

reasonable at this time to control these 

sources as part of the Dallas-Fort Worth 

ozone SIP and is investing $4,000,000 in 

a grant program to assist with the 

retrofitting of gas-fired, rich burn 

compressor engines. The TCEQ also 

noted uncertainty in upstream oil and 

gas emission estimates. Therefore, the 

TCEQ reasoned that since point sources 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74835 

192Additional information and a copy of the 

AirControl NET software can be found at: http://

www.epa.gov/ttn/ecas/AirControlNET.htm 

193Lists of NOX and SO2 controls meeting cost 

thresholds ranging from $1,500/ton to $10,000/ton 

developed by Alpine Geophysics are available in 

the docket to this action (See spreadsheets titled 

‘‘nox_cost_ton__2_’’ and ‘‘so2_cost_ton’’) 

194Assessment of NOX Emission Reduction 

Strategies for Cement Kilns—Ellis County Final 

Report, TCEQ Contract No. 582–04–65589, Work 

Order No.05–06, Prepared by: ERG, Inc., 10200 

Alliance Road, Suite 190, Cincinnati, Ohio 45242– 

4716. Available at: http://www.tceq.state.tx.us/

assets/public/implementation/air/sip/agreements/

BSA/CEMENT_FINAL_REPORT_70514_final.pdf 

are the single largest pollution category 

for SO2 and NOX, it should concentrate 

its RPG strategy on analyzing controls 

for point sources. 

TABLE 7—PERCENTAGE SOURCE CATEGORY CONTRIBUTIONS TO SO4 AND NO3 AT THE FIVE CLASS I AREAS TEXAS

MOST IMPACTS

Big Bend Guadalupe Mountains 

Point Mobile Area Point Mobile Area 

SO4 ........................................................... 67.1 2.8 6.9 75.6 3.5 8.5 

NO3 .......................................................... 26.6 28.6 14.3 29.2 36.5 13.9 

Wichita Mountains Salt Creek White Mountain 

Point Mobile Area Point Mobile Area Point Mobile Area 

SO4 ............................................... 78.2 3.7 9.2 73.8 3.9 8.1 75.2 4.1 8.1 

NO3 .............................................. 28.1 44.7 13.4 35.8 29.9 17.1 27.9 40.3 12.0 

Having narrowed the scope of the 

control analysis to point sources of NOX

and SO2, the TCEQ developed a list of 

potential controls and costs associated 

with those controls to inform their four 

factor analysis. It used the control 

strategy analysis developed by CENRAP 

as the starting point for its analysis. 

CENRAP contracted with Alpine 

Geophysics to conduct an evaluation of 

possible additional point-source add-on 

controls for sources in CENRAP states. 

The Alpine Geophysics evaluation 

relied on AirControlNET,192 a database 

tool we released in 2006 to enable costbenefit analyses of potential emissions 

control measures and strategies. Alpine 

Geophysics prepared cost estimates for 

potential add-on controls for NOX and 

SO2 reductions in 2005 dollars for point 

sources in CENRAP states. The Iowa 

Department of Natural Resources and 

Kansas Department of Health and 

Environment staff developed Area-ofInfluence (AOI) data for each Class I 

area in every CENRAP member state, as 

well as distance calculations for each 

source to each Class I area for inclusion 

in the Alpine Geophysics analysis. 

Available SO2 and NOX control 

strategies in the AirControlNET dataset 

were applied to EGU and non-EGU 

sources to develop a master list of 

available incremental control strategies 

for the CENRAP states.193 The TCEQ 

reviewed this information for Texas 

sources and made changes based on 

additional information and past 

experience. The TCEQ also added some 

additional sources from source-types 

not included in the CENRAP 

AirControlNET dataset. This work 

resulted in a list of potential add-on 

controls for reducing SO2 and NOX at 

Texas point sources, an estimate of the 

costs associated with each control, and 

identification of the AOIs for each Class 

I area. 

The TCEQ states its analysis focused 

on moderate cost controls for sources it 

believed were likely to contribute to 

visibility impairment at Class I areas. In 

an effort to further narrow the list of 

potential controls, the TCEQ followed 

the screening process summarized 

below and as detailed in Section 10–1.3 

of Appendix 10–1 of the Texas regional 

haze SIP: 

• Identified controls at sources with 

potential control strategy costs greater 

than $2,700 per ton SO2 or NOX were 

initially screened out. 

• Remaining sources were reduced by 

eliminating the ones the TCEQ believed 

were so far away from any of the ten 

Class I areas, that any reduction in their 

emissions would likely not have a 

perceptible impact on visibility. 

• Remaining sources were further 

reduced by eliminating the ones for 

which a ratio of the estimated projected 

2018 base annual emissions (tons) of 

SO2 or NOX to distance (kilometers), to 

any Class I area, did not exceed five. 

• Any source with predicted 2018 

emissions less than 100 tons per year 

was excluded. 

Separate from the above described 

screening process, the TCEQ also 

excluded additional NOX controls on 

cement kilns from consideration, as it 

concluded it had already required all 

the measures it had determined 

reasonable to control NOX emissions 

from these sources in the latest DallasFort Worth ozone SIP revision. The 

TCEQ reasoned, based on a study 

performed for the Dallas-Fort Worth 

ozone SIP revision,194 that a 35 to 50% 

NOX control range was the most 

appropriate control level to address 

ozone formation. The TCEQ developed 

a source cap that required a reduction 

of approximately 9.69 tons per day (tpd) 

of NOX emissions from the cement kilns 

in Ellis County starting March 2009. 

The types of controls considered by 

the CENRAP study, based on industrial 

categories, are listed below: 

SO2 Control at 24 Facilities From 15 

Sites 

• Natural Gas Transmission—Flue Gas 

Desulfurization (FGD) 

• Crude Petroleum—Sulfur recovery 

and/or tail gas treatment 

• Inorganic chemical plants—coal 

washing and Spray Dryer Absorber 

(SDA) on boilers, increase efficiency 

of sulfuric acid plants 

• Electric Generating Units (EGU)—coal 

washing and FGD wet scrubbing 

• Carbon black—FGD 

NOX Control for 24 Facilities at 15 Sites 

• Natural Gas Transmission—Low 

NOX Burners (LNB), Selective Catalytic 

Reduction (SCR) + LNB 

• EGU—LNB with Close Coupled 

Over-Fired Air (LNC1), and with both 

LNC1 and Separated Over-Fired Air 

(LNC3) 

• Flat Glass—LNB, SCR 

• Paper Mills SNCR and Oxygen Trim 

(OT) with water injection 

• Chemical Plant Boiler—SCR 

The total cost of controls and the 

resulting emission reductions were 

calculated by summing up the 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74836 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

195Annualized costs are the total yearly costs, 

typically the sum of the yearly capital cost 

(amortized over the life of the control) and the 

yearly operational cost. In this instance, the TCEQ 

relied upon our AirControlNET model which for 

these types of controls typically assumed a 30 year 

control life. 

196Reproduced from Table 4 in Appendix 10–1 

of the Texas regional haze SIP. 197See Section 2.14 of the Technical Support 

Document for CENRAP Emissions and Air Quality 

Modeling to Support Regional Haze State 

Implementation Plans, September 12, 2007. 

198Q/D is the ratio of annual emissions over 

distance to a Class I area. 

199 ‘‘The results of the modeling were not 

intended to be prescriptive; instead, they were 

intended to be a starting point for control 

discussions that would require much greater 

refinement.’’ CENRAP TSD, page 2–37. 

200Table 5 in Appendix 10–1 of the Texas 

Regional Haze SIP. 

individual costs of those identified 

controls located within the AOI of Big 

Bend or the Guadalupe Mountains. The 

TCEQ also performed this calculation 

for eight additional Class I areas in other 

states impacted by Texas’ emissions: 

Breton Island, Caney Creek, Carlsbad 

Caverns, Salt Creek, Upper Buffalo, 

Wheeler Peak, White Mountain, and the 

Wichita Mountains. The annualized 

costs 195 that would result from the 

imposition of the above controls within 

each Class I area’s AOI are shown 

below. 

TABLE 8—ANNUALIZED COST OF CONTROLS FOR EACH CLASS I AREA

[Controls at facilities within each class I area’s AOI] 

Class I area NOX SO2

Big Bend ...................................................................................................................................................... $24,100,000 $215,900,000 

Breton Island ................................................................................................................................................ 27,000,000 231,000,000 

Caney Creek ................................................................................................................................................ 28,600,000 245,900,000 

Carlsbad Caverns ........................................................................................................................................ 24,100,000 255,500,000 

Guadalupe Mountains .................................................................................................................................. 33,800,000 254,900,000 

Salt Creek .................................................................................................................................................... 27,000,000 251,900,000 

Upper Buffalo ............................................................................................................................................... 24,100,000 233,800,000 

Wheeler Peak .............................................................................................................................................. 22,700,000 229,500,000 

White Mountains .......................................................................................................................................... 23,000,000 244,500,000 

Wichita Mountains ....................................................................................................................................... 28,100,000 269,500,000 

Many of these controls are in more 

than one AOI. The TCEQ reviewed the 

total cost of all state-wide point source 

controls identified by the process 

described above, as follows for 13 

facilities with SO2 controls and 15 

facilities with NOX controls. 

TABLE 9—TOTAL ESTIMATED COST OF TEXAS CONTROL SET 196

Pollutant Reduction 

(tpy) Estimated cost 

Sulfur Dioxide (SO2) .................................................................................................................................... 155,873 $270,800,000 

Nitrogen Oxides (NOX) ................................................................................................................................ 27,132 53,500,000 

Total Costs ........................................................................................................................................... .............................. $324,300,000 

The196 TCEQ used the results of the 

2018 CENRAP state-wide 

photochemical grid modeling analyses 

(that includes the 2018 modeling and a 

CENRAP control case modeling 

scenario) to estimate the visibility 

benefit that would result in 2018 from 

controlling those sources in Texas 

identified by it following the process 

described above. CENRAP developed a 

modeling scenario to estimate the 

effectiveness of a specific suite of 

controls on facilities in the CENRAP 

states. CENRAP based its control 

sensitivity analysis on a maximum 

estimated cost of $5,000 per ton of 

emissions of NOX or SO2 reduced 

estimated in the Alpine Geophysics 

report and evaluated only those point 

sources predicted to emit 100 tons or 

more of SO2 or NOX in the year 2018.197

Similar to the Texas analysis, CENRAP 

further refined the sources for analysis, 

considering controls only for those 

sources with emissions of NOX or SO2

greater than or equal to five tons per 

year per kilometer of distance to the 

nearest Class I area. This distanceweighing criterion limited the 

sensitivity evaluation to sources with 

the greatest likely influence on 

visibility. The CENRAP control 

sensitivity modeling run included 

emission reductions beyond CAIR and 

BART in the CENRAP states at all point 

sources where the cost-effectiveness and 

Q/D 198 criteria discussed above were 

met, and projected the resulting 

visibility conditions in 2018 at the 

CENRAP Class I areas. This modeling 

was developed as a starting point for 

discussion and development of refined 

analyses as needed.199

The TCEQ used the CENRAP control 

sensitivity analysis and the CENRAP 

2018 visibility projection modeling as 

the starting point for estimating the 

visibility benefit of implementing only 

the controls identified by it above for 

Texas point sources. The TCEQ used the 

results of this modeling analysis and the 

source apportionment modeling results 

to determine an ‘‘effectiveness ratio’’ for 

NOX and SO2 reductions, which it states 

provides an estimate of improvement in 

visibility for every ton of NOX and SO2

reduced in order to produce ‘‘an order 

of magnitude estimate of the likely 

visibility improvements resulting from 

the point source.’’ See Appendix 10–2 

and 10–4 of the Texas regional haze SIP 

and our TX TSD for additional 

information on the methodology Texas 

used to develop this estimate. 

The TCEQ summarizes the estimated 

visibility improvement that would 

result in 2018 from the imposition of all 

the above controls as follows 200: 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74837 

201Page 10–8 of the Texas Regional Haze SIP. 202Texas Regional Haze SIP, page 10–8. 

203Reproduced from Table 10–7 in the Texas 

Regional Haze SIP. 

TABLE 10—TCEQ PROJECTED VISIBILITY IMPROVEMENT TO SELECTED

CLASS I AREAS FROM THE IMPOSITION OF POTENTIAL CONTROLS

Class I area 

Visibility 

improvement 

(dv) 

Big Bend ......................... 0.16 

Breton Island .................. 0.05 

Caney Creek ................... 0.33 

Carlsbad Caverns ........... 0.22 

Guadalupe Mountains .... 0.22 

Salt Creek ....................... 0.18 

Upper Buffalo .................. 0.16 

Wheeler Peak ................. 0.04 

White Mountains ............. 0.24 

Wichita Mountains .......... 0.36 

After identification of potential 

controls for multiple sources, estimation 

of aggregate costs associated with those 

controls and estimation of the overall 

visibility improvement anticipated from 

implementation of those controls as 

described above, the TCEQ then 

weighed the four statutory factors in 

determining the reasonableness of 

additional controls and selecting the 

RPGs for Big Bend and Guadalupe 

Mountains. In general, the cost of 

compliance was the key factor 

considered by the TCEQ. It determined 

that the time necessary for compliance 

was not a critical factor for the 

determination of applicable additional 

controls for Texas sources. It stated that 

to the extent energy impacts are 

quantifiable for a particular control, 

they were included in its cost estimates. 

However, it stated that ‘‘including 

[energy and non-air quality 

environmental] impacts on a source-bysource basis would have added further 

weight against finding that the potential 

additional controls were reasonable to 

apply.’’ 201 The TCEQ also stated that for 

the purposes of initial analysis, no 

limited remaining useful life was 

assumed. The TCEQ describes the cost 

of compliance as a factor used to 

determine whether compliance costs for 

sources are reasonable compared to the 

emission reductions and visibility 

improvement they will achieve. The 

TCEQ weighed the four reasonable 

progress factors as follows: 

a. Cost of Compliance 

The TCEQ concluded that at a total 

estimated cost of over $300 million and 

(in its view) no perceptible visibility 

benefit, it was not reasonable to 

implement additional controls. All units 

in Texas that met the emissions over 

distance threshold were assessed. The 

TCEQ states it adopted its $2,700 cost 

threshold to limit the proposed controls 

group to cost-effective measures. 

Annualized cost values, and emission 

reductions based on proposed 

efficiencies listed in AirControlNET, 

were used. Modifications for Texas 

included the consideration of flue gas 

desulfurization for carbon black units. 

b. Time Necessary for Compliance 

The TCEQ determined that the time 

necessary for compliance was not a 

critical factor for the determination of 

applicable additional controls for its 

sources. It noted that in our CAIR 

regulatory impact statement, we 

estimated that approximately 30 months 

is required to design, build, and install 

SO2 scrubbing technology for a single 

EGU boiler. The TCEQ stated that the 

total time for a single facility to comply 

with one of the NOX caps would be 

about five years. It estimated that 

completion by 2018 would still be 

anticipated. For mobile sources, 

MOBILE and NONROAD model runs 

were completed for the 2018 emissions 

inventory. These model runs 

incorporated the degree of fleet and 

expected engine replacement prior to 

2018. The completion of other proposed 

controls were anticipated by 2018. 

c. Energy and Non-Air Quality 

Environmental Impacts of Compliance 

The TCEQ stated that to the extent 

energy impacts are quantifiable for a 

particular control, they were included 

in its cost estimates. However, it stated 

that ‘‘including [energy and non-air 

quality environmental] impacts on a 

source-by-source basis would have 

added further weight against finding 

that the potential additional controls 

were reasonable to apply. Source-bysource review of the non-air quality 

impacts of the potential controls would 

possibly have led to a different 

determination about the 

unreasonableness of the set of potential 

additional controls.’’ 202 The TCEQ 

noted that scrubbers, SCR systems, and 

Selective Non-Catalytic Reduction 

(SNCR) systems installed under the EGU 

control strategies would require 

electricity to operate fans and other 

ancillary equipment. However, it noted 

that estimates were given that the 

electricity and steam required by 

controls installed to meet SO2 and NOX

emission caps would be less than 1% of 

the total electricity and steam 

production of EGUs. TCEQ noted that 

Scrubbers, coal washing, and spray 

dryers would require additional 

safeguards for fuel handling and waste 

handling systems to avoid additional 

non-air environmental impacts such as 

increased effluents in waste water 

discharges and storm water runoff. The 

TCEQ expected that solid waste 

disposal and wastewater treatment costs 

would be less than five percent of the 

total operating costs of pollution control 

equipment. It noted that these factors 

would have to be considered specific to 

individual sources. 

d. Remaining Useful life 

The TCEQ noted that CENRAP 

considered the remaining useful life in 

modeling for mobile sources that 

assumes reduced emissions per vehicle 

mile traveled due to the turnover of the 

on-road mobile source fleet. It noted 

that for sources with a relatively short 

remaining useful life, this consideration 

would have weighed more heavily 

against a determination that controlling 

those sources would have been 

reasonable. The TCEQ believed that this 

factor was not critical for its sector 

analyses for the 2018 timeline and did 

not assume any limited useful 

equipment life. Only units that were 

scheduled for shutdown under 

enforceable decrees were eliminated 

from the 2018 inventory and further 

analysis. 

e. TCEQ Noted Uncertainty in Visibility 

Projections Due to CAIR 

The TCEQ noted that the majority of 

the emission reductions underlying the 

predicted visibility improvements in 

2018 resulting from controls already in 

effect or scheduled to become effective 

will result from the CAIR program in 

particular. The CAIR program allows 

interstate trading of allowances, and 

does not put specific emission limits on 

specific sources. Further, it notes that 

because emission allowances can be 

purchased by EGUs, visibility 

improvement may be less or more that 

that predicted by the CENRAP’s 

modeling. CENRAP used our Integrated 

Planning Model (IPM) to predict the 

emission reductions expected from 

CAIR in 2018. The TCEQ assumed that 

any replacement for CAIR will include 

interstate trading of emissions 

allowances. The TCEQ presents a 

comparison 203 of its baseline 2002 SO2

emissions, the CAIR budget for EGUs in 

2015 and the IPM predicted SO2

emissions for the 2018 planning year: 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74838 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

204Texas Regional Haze SIP, page 10–7. 

205Per Section 51.308(e)(5), ‘‘After a State has met 

the requirements for BART or implemented 

emissions trading program or other alternative 

measure that achieves more reasonable progress 

than the installation and operation of BART, BARTeligible sources will be subject to the requirements 

of paragraph (d) of this section in the same manner 

as other sources.’’ 

206See ‘‘Sensitivity Run Specifications for 

CENRAP Consultation,’’ available in the docket for 

this action. 

TABLE 11—COMPARISON OF TEXAS

2002 BASELINE SO2 EMISSIONS, 

2015 CAIR EGUS BUDGET AND

2018 IPM PREDICTED SO2 EMISSIONS

SO2 emissions 

Texas SO2

emissions 

(tpy) 

Current (2002 base case) .... 550,000 

EPA’s CAIR budget for 

Texas EGUs for 2015 ....... 225,000 

IPM projection CENRAP 

modeled for 2018 .............. 350,000 

The TCEQ notes that the IPM model 

analysis used by CENRAP predicts that 

by 2018 EGUs in Texas will purchase 

approximately 125,000 tpy of emissions 

allowances from out of state. This 

represents more than 50% of Texas’ 

total CAIR SO2 budget. The TCEQ states 

that it requested that key EGUs in Texas 

review and comment on the predictions 

of the IPM model. However, no EGU 

made an enforceable commitment to any 

particular pollution control strategy and 

preferred to retain the flexibility offered 

by the CAIR program. 

f. The TCEQ Reasonable Progress 

Conclusion 

The TCEQ’s assessment of reasonable 

progress rested primarily on its 

calculation of the total cost of the 

controls it analyzed versus the visibility 

benefits at the ten Class I areas it 

analyzed. It concluded, ‘‘At a total 

estimated cost exceeding $300 million 

and no perceptible visibility benefit, 

Texas has determined that it is not 

reasonable to implement additional 

controls at this time.’’ 204

Section 51.308(d)(1)(iii) requires that 

in determining whether the state’s goal 

for visibility improvement provides for 

reasonable progress towards natural 

visibility conditions, the Administrator 

will evaluate the demonstrations 

developed by the state pursuant to 

Sections 51.308(d)(1)(i) and (d)(1)(ii). 

We perform that evaluation beginning in 

the next section. 

3. Our Analysis of Texas’ Reasonable 

Progress Four Factor Analysis 

We agree with the TCEQ’s decision to 

focus the analysis of the four statutory 

factors on point sources, as the CENRAP 

modeling results and the TCEQ’s 

analysis in Chapter 11 and appendix 

10–1 of the Texas regional haze SIP 

indicate that the predominant 

anthropogenic pollutants that affects the 

state’s ability to meet the URP goals in 

2018 on the worst 20% days at the 

Texas Class I areas are largely due to 

sulfate and nitrate, primarily from point 

sources. We agree with the TCEQ’s 

assessment that the cost of compliance 

is the dominant factor, and its 

incorporation of the other factors into 

the cost, where applicable. We note, 

however, that because the TCEQ did not 

evaluate controls on a source-by-source 

basis, source–specific factors related to 

the evaluation of the reasonable 

progress four factor analysis could not 

be considered. We also agree with the 

TCEQ’s decision to consider visibility 

benefits in weighing the factors and to 

assist in its consideration of the cost of 

compliance. While visibility is not an 

explicitly listed factor to consider when 

determining whether additional controls 

are reasonable, the purpose of the fourfactor analysis is to determine what 

degree of progress toward natural 

visibility conditions is reasonable. 

Therefore, we believe it is appropriate to 

consider the projected visibility benefit 

of the controls when determining if 

cost-effective controls are warranted to 

make reasonable progress. However, the 

TCEQ did not discriminate between and 

analyze controls on those source(s) with 

the highest potential visibility benefit at 

each Class I area. We disagree with the 

set of potential controls identified by 

the TCEQ and how it analyzed and 

weighed the four reasonable progress 

factors in a number of key areas. 

a. The TCEQ’s Cost-Effectiveness 

Threshold Approach 

The TCEQ eliminated controls with 

an estimated cost-efficiency greater than 

$2,700/ton from any further analysis, 

regardless of their potential visibility 

benefits. Given the large number of 

sources and their large geographic 

distribution, some consideration of 

location and emissions data is needed 

before controls should have been 

eliminated from further analysis. The 

TCEQ supports its selection of this 

value with reference to ‘‘EPA estimated 

cost of implementing CAIR was up to 

$2,700/ton.’’ However, although we 

demonstrated that CAIR was acceptable 

in lieu of BART, CAIR was not designed 

as a reasonable progress strategy. A state 

should look beyond BART for 

additional reductions when developing 

its long-term strategy to achieve 

reasonable progress at its Class I 

areas.205 As a result of the application 

of this $2,700/ton threshold, potentially 

cost-effective controls were not 

evaluated at sources that may result in 

meaningful visibility benefits at 

Guadalupe Mountains or Big Bend. For 

example, potential SO2 controls for the 

Tolk Station were estimated in the 

Alpine Geophysics analysis to cost an 

average of approximately $3,100/ton 

and result in nearly 20,000 tpy reduced 

across the two units. Applying the 

$2,700/ton threshold, the TCEQ did not 

consider potential controls on any EGUs 

in West Texas to improve visibility at 

the two Class I areas located in West 

Texas despite the potential visibility 

benefits from controlling these large 

point sources. Sensitivity analysis 

performed by CENRAP suggests to us 

that a threshold in the range of $4,000/ 

ton to $5,000/ton would be reasonable 

for purposes of identifying potential 

cost-effective controls for further 

analysis.206

b. The TCEQ’s Weighing of the Four 

Factors for Individual Sources 

The TCEQ constructed a large 

potential control set consisting of a mix 

of large and small sources, located at 

various distances from Class I areas, 

with a large geographical distribution. 

Because of the variation in size, type, 

and location of these sources, the 

potential to impact visibility and 

potential benefit from controls at a given 

Class I area can vary greatly between the 

identified sources. This potential 

control set identified by the TCEQ 

included controls on some sources that 

would likely result in significant 

visibility benefits, but also included 

controls on many sources with much 

less anticipated visibility benefits. 

Because it only estimated the visibility 

benefit of all the controls together, the 

TCEQ was not able to assess the 

potential benefit of controlling 

individual sources with significant, and 

potentially cost-effective, visibility 

benefits. Also, we believe that 

individual benefits were masked by the 

inclusion of those controls with little 

visibility benefit that only served to 

increase the total cost figures. For 

example, the TCEQ identified SO2

controls at Big Brown to be 

approximately $1,500/ton, significantly 

less than its $2,700/ton threshold. These 

controls were estimated to achieve 

greater than 40,000 tpy SO2 emission 

reductions. Despite this evidence in the 

record of an identified cost-effective 

control that results in large emission 

reductions, and source apportionment 

modeling identifying large impacts from 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74839 

207As discussed later in this TSD, this study also 

looked at impacts from Texas sources on Class I 

areas in other States. 

208We occasionally present visibility in 

extinction, rather than deciviews (dv). Light 

extinction, in units of inverse megameters (Mm¥1), 

is the amount of light lost as it travels over one 

million meters. The haze index, in units of 

deciviews (dv), is calculated directly from the total 

light extinction, bext, as follows: HI = 10 ln(bext/ 

10). Extinction is an appropriate measure for the 

visibility impairment contribution from individual 

sources because it avoids the sensitivity of the 

logarithmic transformation for calculating 

deciviews to the overall level of visibility 

impairment including the impacts of other sources. 

209See Appendix 4–1: Summary of Consultation 

Calls. 

EGU sources in northeast Texas, the 

TCEQ did not separately evaluate the 

visibility benefit from the 

implementation of this control, or 

appropriately weigh the four reasonable 

progress factors in determining the 

reasonableness of this individual 

control. 

Because individual sources were not 

considered by the TCEQ, we found it is 

necessary to conduct an additional 

analysis to determine whether this 

approach materially affected the 

outcome of the TCEQ analysis. As we 

demonstrate in detail in our FIP TSD, by 

analyzing sources individually, we 

believe we have identified a small 

number of sources that are responsible 

for much of Texas’ collective visibility 

impact on the Texas’ Class I areas, 

which if controlled, would provide for 

visibility benefit at Texas’ Class I areas. 

That modeling is summarized below. 

Our preliminary modeling study 

identified those facilities with the 

largest impacts on the Texas Class I 

areas on the 20% worst days in 2018.207

This modeling includes the same 

projections the TCEQ used to account 

for predicted reductions due to CAIR. 

The projected impacts 208 in 2018 from 

the top ten facilities in Texas that 

impact visibility at Big Bend and the 

Guadalupe Mountains are summarized 

in Tables 12 and 13 below (see our FIP 

TSD for more details). Texas point 

sources combined are projected in 2018 

to contribute approximately 8% (3.56 

Mm¥1) to the total visibility impairment 

at Big Bend, and 9% (3.84 Mm¥1) to the 

total visibility impairment at Guadalupe 

Mountains. These results below show 

that some facilities can have large 

impacts on certain days and significant 

impacts on the 20% worst days, even 

including facilities like Big Brown 

which is more than 700 km from Big 

Bend and more than 800 km from the 

Guadalupe Mountains. We note that 

Texas decided to invite states to consult 

using the CENRAP Particulate Matter 

Source Apportionment Technology 

(PSAT) results and included states with 

> 0.5 inverse megameter impact (from 

all sources in the state) on one of Texas’ 

Class I areas.209 These results also 

suggest that controlling a small number 

of sources will result in visibility 

benefits at both Class I areas, and that 

rather than evaluating controls at all 

facilities identified by Texas combined, 

a subset of those facilities (and some 

additional facilities not identified) may 

be reasonable. 

TABLE 12—2018 PHASE 1 EPA SOURCE APPORTIONMENT MODELING RESULTS, TOP TEN FACILITIES IN TEXAS THAT

IMPACT VISIBILITY AT BIG BEND

Rank Facility name 

Extinction 

(Mm¥1) 20% 

worst days 

% Contribution 

to total visibility impairment 20% 

worst days 

Max extinction 

during 20% 

worst days 

1 ............................................. SOMMERS DEELY S ............................................................. 0.276 0.57 1.193 

2 ............................................. COLETO CREEK PL .............................................................. 0.216 0.44 0.937 

3 ............................................. BIG BROWN ........................................................................... 0.212 0.44 0.923 

4 ............................................. RELIANT ENERGY * ............................................................... 0.103 0.21 0.441 

5 ............................................. LIGNITE–FIRED P ** .............................................................. 0.101 0.21 0.428 

6 ............................................. MONTICELLO STM ................................................................ 0.096 0.20 0.413 

7 ............................................. W A PARISH STAT ................................................................ 0.090 0.18 0.385 

8 ............................................. BIG SPRING CARB ................................................................ 0.084 0.17 0.356 

9 ............................................. SANDOW STEAM EL ............................................................. 0.080 0.16 0.342 

10 ........................................... MARTIN LAKE ELE ................................................................ 0.080 0.16 0.342 

* This is the Limestone facility. 

** This is the San Miguel facility. 

TABLE 13—2018 PHASE 1 EPA SOURCE APPORTIONMENT MODELING RESULTS, TOP TEN FACILITIES IN TEXAS THAT

IMPACT VISIBILITY AT GUADALUPE MOUNTAINS

Rank Facility name 

Extinction 

(Mm¥1) 20% 

worst days 

% Contribution 

to total visibility impairment 20% 

worst days 

Max extinction 

during 20% 

worst days 

1 ............................................. TOLK STATION ...................................................................... 0.302 0.65 1.004 

2 ............................................. BIG BROWN ........................................................................... 0.235 0.50 0.809 

3 ............................................. BIG SPRING CARB ................................................................ 0.226 0.48 0.775 

4 ............................................. SOMMERS DEELY S ............................................................. 0.208 0.44 0.688 

5 ............................................. HARRINGTON STAT .............................................................. 0.184 0.39 0.606 

6 ............................................. MONTICELLO STM ................................................................ 0.114 0.24 0.391 

7 ............................................. WAHA PLANT ......................................................................... 0.113 0.24 0.387 

8 ............................................. RELIANT ENERGY * ............................................................... 0.111 0.24 0.372 

9 ............................................. MARTIN LAKE ELE ................................................................ 0.104 0.22 0.351 

10 ........................................... COLETO CREEK PL .............................................................. 0.066 0.14 0.227 

* This is the Limestone facility. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74840 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

210 70 FR 39137 (July 6, 2005). 

211See our cost-effectiveness calculations for 

retrofitting Big Brown and other Texas EGU with 

scrubbers in section VII.F. 

212 70 FR 39130 (July 6, 2005) 

213 76 FR 81739 (Dec. 28, 2011). 

c. The TCEQ’s Cost of Compliance 

Analysis Assumed Future CAIR 

Reductions as a Baseline 

We based our determination that 

CAIR was better than BART in part on 

a finding that CAIR resulted in an 

overall improvement in visibility 

determined by comparing the average 

differences over all affected Class I 

areas. We noted at the time that BART 

is one component of a long-term strategy 

to make reasonable progress, but it is 

not the only component. 210 Thus, when 

assessing reasonable progress, a state 

should look beyond BART for 

additional reductions when determining 

what long-term strategy will achieve 

reasonable progress at its Class I areas. 

A critical decision point in performing 

cost analysis for potential controls is the 

determination of an emission baseline. 

As we state above, the TCEQ projected 

that Texas EGUs would purchase 

approximately 125,000 tpy of emissions 

allowances from out of state. The TCEQ 

relied on the IPM predictions as 

discussed above to estimate 2018 

emission levels for EGUs. The TCEQ 

also notes that there is uncertainty in 

the size and distribution in emissions in 

the future projections. Nevertheless, the 

TCEQ utilized this future projection of 

2018 emissions as the starting point for 

its estimation of emission reductions 

and the associated costs of additional 

controls. 

For example, Big Brown Unit 1’s SO2

emissions in 2002 were 34,448 tpy. The 

IPM predictions that were incorporated 

into the 2018 emission level assume that 

a roughly 1/3 reduction in these 

emissions will occur in response to 

CAIR by switching to a coal with a 

lower sulfur content, resulting in a 2018 

SO2 emission level of 23,142 tpy. The 

TCEQ’s cost-effectiveness calculation 

for post-combustion controls on Big 

Brown Unit 1 was based on reducing 

that projected 2018 SO2 emission level 

of 23,142 tpy by 90%, resulting in a 

reduction of 20,828 tpy. This results in 

a cost of $32,766,310/yr, or a costeffectiveness calculation of $1,573/ton. 

However, the installation of a scrubber 

would allow Big Brown flexibility in 

fuel choice thus allowing the unit to 

continue to burn the higher average 

sulfur fuel it currently burns, instead of 

moving to the low sulfur coal predicted 

by IPM. 

Big Brown Unit 1 SO2 emissions in 

2012 were 32,100 tons. The issue of 

scrubber efficiency aside, a reduction of 

90% from these actual emission levels 

would result in an SO2 reduction in the 

range of 29,000 to 31,000 tpy. While the 

numerator ($) in the cost-effectiveness 

metric of $/ton will increase slightly 

beyond what was estimated by Alpine 

Geophysics due to an increased sulfur 

loading to the scrubber, the 

denominator (tons) would increase by 

roughly 50%, thus improving (lowering) 

the overall cost-effectiveness of 

controlling Big Brown Unit 1 

significantly.211 Estimates for scrubbers 

at Monticello are similarly impacted by 

the cost-methodology used by Texas in 

estimating cost-effectiveness on a costper-ton basis. 

We believe that in performing its 

control analysis, the TCEQ should have 

given greater consideration to the 

flexibility in the CAIR trading program 

and the resulting uncertainty in the 

projected emissions. In other words, the 

TCEQ could have recognized that 

implementation of reasonable controls 

under the Regional Haze Rule would 

likely not be in addition to anticipated 

reductions due to CAIR predicted by 

IPM, but would replace or complement 

any controls predicted by IPM. 

d. The TCEQ’s Assumptions of SO2

Control Efficiency of Scrubbers 

We note that the control efficiency of 

scrubbers evaluated by CENRAP and 

Texas, based on the data from 

AirControlNET, was assumed to be 

90%. As we discuss in detail in our FIP 

TSD, we establish that SO2 scrubbers are 

capable of achieving emission 

reductions of at least 95% for dry 

scrubbers and 98% for wet scrubbers. 

These additional reductions would 

further reduce the price on a $/ton basis 

and increase the visibility benefit 

anticipated due to controls. 

e. The TCEQ’s Evaluation of Potential 

Visibility Improvements 

In considering whether compliance 

costs for sources were reasonable, the 

TCEQ compared those costs to the 

emission reductions and visibility 

improvement those sources would 

achieve. While visibility is not an 

explicitly listed factor to consider when 

determining whether additional controls 

are reasonable, the purpose of the fourfactor analysis is to determine what 

degree of progress toward natural 

visibility conditions is reasonable. 

Therefore, we consider it appropriate to 

consider the projected visibility benefit 

of the controls when determining if the 

controls are needed to make reasonable 

progress. We discuss this in more detail 

in our FIP TSD. 

In evaluating and dismissing the 

estimated visibility benefit from the 

control set identified by the TCEQ, the 

TCEQ states that the estimated benefit is 

not perceptible (less than 1 dv) and that 

it is less than 0.5 dv, the threshold used 

under BART requirements used to 

determine if a facility contributes to 

visibility impairment. The 0.5 dv BART 

threshold referred to applies to the 

maximum anticipated visibility impact 

on a single day due to the short-term 

maximum actual baseline emissions 

from a single facility, compared to clean 

background conditions. The reasonable 

progress analysis presented by the 

TCEQ contemplates the visibility benefit 

anticipated for an average tpy emission 

reduction (as opposed to the impact 

from the total short-term maximum 

emissions from the sources) averaged 

across the 20% worst days, which 

would be anticipated to be significantly 

lower. See our FIP TSD for a detailed 

discussion of the different metrics and 

modeling typically used for BART and 

reasonable progress analyses. 

Furthermore, in a situation where the 

installation of BART may not result in 

a perceptible improvement in visibility, 

the visibility benefit may still be 

significant, as explained by the Regional 

Haze Rule: 212

Even though the visibility improvement 

from an individual source may not be 

perceptible, it should still be considered in 

setting BART because the contribution to 

haze may be significant relative to other 

source contributions in the Class I area. Thus, 

we disagree that the degree of improvement 

should be contingent upon perceptibility. 

As we stated in our Oklahoma final 

decision: 213

Given that sources are subject to BART 

based on a contribution threshold of no 

greater than 0.5 deciviews, it would be 

inconsistent to automatically rule out 

additional controls where the improvement 

in visibility may be less than 1.0 deciview or 

even 0.5 deciviews. A perceptible visibility 

improvement is not a requirement of the 

BART determination because visibility 

improvements that are not perceptible may 

still be determined to be significant. 

f. The TCEQ’s ‘‘Order of Magnitude 

Estimate’’ for Visibility Improvement 

The TCEQ produced an ‘‘order ofmagnitude estimate’’ of the visibility 

improvements resulting from the level 

of aggregate emission reductions that 

would result from its point source 

control strategy using PSAT results and 

effectiveness ratios. This methodology 

assumes that all emission reductions 

within a PSAT region have the same 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74841 

214See the FIP TSD. 

215We note that recent actual emissions at the 

facility are roughly twice as large as the 2018 

projected value. Based on 2002 emissions, the 

Q/D for Guadalupe Mountains for SO2 emissions is 

approximately 69. 

effectiveness in reducing visibility 

impairment. The estimated effectiveness 

factor applied equally to all emission 

reductions located in the East Texas 

source region, including Sommers Deely 

Spruce (440 km from Big Bend and 680 

km from Guadalupe Mountains) and 

Monticello (850 km from Big Bend and 

920 km from Guadalupe Mountains). 

Given the large difference in distances 

between these two facilities and the 

Class I areas, it is reasonable to expect 

that the effectiveness of emission 

reductions could vary greatly between 

the two. We propose to find that the 

TCEQ’s analysis is insufficient to 

determine the visibility benefit of 

controlling the source or subset of 

sources with the most effective controls 

for improving visibility conditions at a 

Class I area or a number of Class I areas 

and that the potential visibility benefits 

from controlling these sources may be 

significant. Our own source 

apportionment modeling has confirmed 

that individual sources within the 

CENRAP modeling PSAT regions had 

significantly different impacts, leading 

us to believe that TCEQ’s reliance on an 

aggregate analysis materially affected its 

conclusion that existing and scheduled 

controls would achieve reasonable 

progress.214

g. Upgrades to Existing Controls 

The CENRAP analysis and the 

additional analysis performed by the 

TCEQ did not consider the 

reasonableness of control upgrades or 

increased utilization of existing 

controls. We note that the 

AirControlNET database does not 

include general information for the cost 

and effectiveness of scrubber upgrades 

as the cost and reductions from these 

potential upgrades are typically very 

specific to the existing equipment and 

site-specific conditions. Many Texas 

EGU’s are equipped with older vintage 

scrubbers and/or have scrubber 

bypasses that divert a portion of the 

exhaust gas around the control 

equipment. In some cases, excess 

scrubbing capacity is simply not being 

utilized. Texas includes many of these 

sources with controls in the maps 

showing area of influence and ‘‘high 

priority’’ sources for other state’s Class 

I areas, as well as in the table of sources 

within the Class I areas AOI, in their 

correspondence with other states (see 

Appendix 4.3 of the TX regional haze 

SIP). However, Texas did not provide 

any analysis of the four factors on these 

partially controlled sources or include 

these sources in a Q/D analysis to 

identify those sources with the largest 

potential to impact visibility due to 

emissions and distance. There are a 

number of EGUs with existing controls 

with 2018 projected emissions large 

enough to have a Q/D many times 

greater than threshold (Q/D > 5) used by 

Texas. Furthermore, even with these 

existing controls, some of these EGUs 

are among the largest SO2 sources in the 

state. For example, the Martin Lake 

facility has a Q/D for Guadalupe 

Mountains (958 km away) greater than 

37 using the projected 2018 SO2

emissions.215 The 2018 projected 

emissions includes predicted emission 

reductions due to CAIR at many of these 

controlled facilities, suggesting some 

increase in control efficiency and/or 

burning fuels with a lower average 

sulfur content is already included in the 

2018 projections. Absent any additional 

analysis, however, it is not possible to 

determine whether additional 

reductions beyond those included in the 

2018 emission inventory for these 

facilities are cost-effective, result in 

visibility benefits at the Class I areas 

and are reasonable. For example, 

emissions at Martin Lake unit 1 in the 

CENRAP emission inventory are 

projected to decrease from 24,832 tpy in 

2002 to 11,351 tpy in 2018. As we 

discuss in our FIP TSD, based on coal 

data submitted to the U.S. Energy 

Information Administration, upgrading 

the existing scrubber to 95% control 

efficiency would result in an 

approximate emission reduction of an 

additional 7,000 tpy beyond those 

reductions projected to occur due to 

CAIR. Scrubber upgrades across all 

three Martin Lake units could result in 

emission reductions of approximately 

21,000 tpy beyond the level of control 

assumed in the 2018 projections. Given 

the size of these sources, the size of the 

impact from Texas emissions, and the 

source apportionment data indicating 

the large impact from SO2 emissions 

from EGUs, we believe it was 

unreasonable for Texas to not perform 

any analysis on these sources or request 

additional information from the 

facilities concerning potential upgrades. 

As documented in our FIP TSD, 

scrubber upgrades are often very costeffective on a cost per ton basis. Our 

analysis in the FIP TSD demonstrates 

that many of these older SO2 scrubbers 

can be cost-effectively upgraded. The 

importance of this omission becomes 

clear from our analysis that shows that 

for a cost-effectiveness of approximately 

$600/ton or less, over 100,000 tpy of 

SO2 emission reductions can be 

achieved from a small number of 

scrubber upgrades, resulting in costeffective visibility benefits at Texas 

Class I areas and Class I areas in other 

states. Thus, we propose to find that this 

omission by TCEQ materially affected 

the outcome of its four-factor analysis. 

See our FIP TSD for a detailed 

discussion of the visibility benefits 

anticipated from scrubber upgrades. 

h. Our Conclusion Regarding the 

TCEQ’s Analysis of the Four Reasonable 

Progress Factors 

For the reasons described above, we 

propose to disapprove Texas’ analysis of 

the reasonable progress factors under 

Section 51.308(d)(1)(i)(A). 

4. Texas’ Assertion That its Progress 

Goals Are Reasonable 

Section 51.308(d)(1)(ii) provides that 

for the period of the SIP, if Texas 

establishes a RPG that provides for a 

slower rate of improvement in visibility 

than the rate that would be needed to 

attain natural conditions by 2064, it 

must demonstrate based on the factors 

in Section 51.308(d)(1)(i)(A) that the 

rate of progress for the SIP to attain 

natural conditions by 2064 is not 

reasonable; and that the progress goal it 

adopted is reasonable. As part of its SIP 

assessment, Texas must provide to the 

public for review the number of years it 

would take to attain natural conditions 

if visibility improvement continues at 

the rate of progress it selected as 

reasonable. In determining whether the 

Texas’ goals for visibility improvement 

provide for reasonable progress towards 

natural visibility conditions, the 

Administrator will evaluate the 

demonstrations developed by it 

pursuant to Section 51.308(d)(1)(i) and 

(d)(1)(ii). 

a. The TCEQ’s Evaluation 

Texas’ RPGs for the 20% worst days 

establish a slower rate of progress than 

the URP for Big Bend and the 

Guadalupe Mountains. The TCEQ 

calculated that under the rate of 

progress selected as reasonable, natural 

visibility conditions (as calculated by 

Texas) would not be attained at Big 

Bend until 2155 and at the Guadalupe 

Mountains until 2081. In Appendix 10– 

3 of its regional haze SIP, the TCEQ 

includes calculations based on our 

default natural conditions, estimating 

attainment of natural visibility 

conditions at the Big Bend in 2215 and 

Guadalupe Mountains in 2167. 

The TCEQ believes the RPGs it 

established for Big Bend and the 

Guadalupe Mountains on the 20% worst 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74842 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

216Section 10.7 of the Texas Regional Haze SIP. 

days are reasonable, and that it is not 

reasonable to achieve the glide path in 

2018. In support of this conclusion, it 

included a discussion of the pollutant 

contributions and the sources of 

visibility impairment at these Class I 

areas (see Section 10.6. and Chapter 11 

of the Texas Regional Haze SIP and 

Table 14 below). In considering the four 

reasonable progress factors under 40 

CFR 51.308(d)(i)(A), as discussed in 

Section V.C.2, above, the TCEQ also 

took other factors into consideration in 

determining that it is not reasonable to 

achieve the glide paths in 2018 and that 

the RPGs adopted by the state are 

reasonable. The TCEQ indicated that the 

ability to meet the URP or make 

additional progress towards reaching 

natural visibility conditions is impeded 

primarily by the following: the 

significant contribution of emissions 

from Mexico and other international 

sources; the uncertainty in the effect of 

CAIR; and the poor cost-effectiveness of 

additional reasonable point source 

controls. 

The TCEQ noted that the CENRAP 

PSAT analysis indicates that 52% of the 

impairment at Big Bend and 25% of the 

impairment at Guadalupe Mountains is 

from Mexico and further south. 

Substantial reductions in emissions 

from outside the United States are 

needed to meet the goal of natural 

visibility at the Texas Class I areas. As 

discussed elsewhere in this notice, the 

TCEQ considered the URP and the 

emission reductions necessary to meet 

the URP in establishing the RPG. 

TABLE 14—CENRAP’S PSAT CONTRIBUTION TO VISIBILITY IN THE TEXAS CLASS I AREAS ON THE WORST 20% DAYS

Contribution by area Big Bend 

(%) 

Guadalupe 

Mountains 

(%) 

Texas ....................................................................................................................................................................... 24.8 34.8 

Mexico ...................................................................................................................................................................... 26.7 16.5 

Boundary Conditions ............................................................................................................................................... 25.7 8.7 

Other U.S. ................................................................................................................................................................ 11.9 18.9 

Miscellaneous .......................................................................................................................................................... 5.8 9.6 

Neighboring States .................................................................................................................................................. 5.1 11.5 

In addition, with respect to reductions 

at Texas sources, the TCEQ noted a 

wide range of measures and programs in 

place in Texas that result in emission 

reductions that often go beyond federal 

requirements. Chapter 11 and 

Appendices 11–2 (Federal and Texas 

Programs Related to On-Road and NonRoad Mobile Sources) and 11–3 (Major 

Point Source NOX Rules and Reductions 

Promulgated in Texas Since 2000) detail 

additional rules and programs that 

minimize emissions that can cause or 

contribute to local and regional 

visibility impairment. In Section 10.2 of 

the Texas regional haze SIP, the TCEQ 

identifies the following programs: 

• Opacity limits on grandfathered 

facilities; 

• Best Available Control Technology 

(BACT) requirements that typically go 

beyond EPA’s New Source Performance 

Standards (NSPS) for new and modified 

sources; 

• Extensive NOX emission limits on 

existing and new sources including 

major, minor and area sources including 

some on a statewide basis; 

• Texas Emission Reduction Program 

(TERP), which provides financial 

incentives to accelerate the 

implementation of new, cleaner diesel 

engine technologies in on-road and nonroad applications; and 

• Air Check Texas Repair and 

Replacement Assistance Program, which 

provides financial incentives for 

scrapping older gasoline-powered onroad vehicles. 

The TCEQ noted that the established 

RPGs reflect emission reduction 

programs already in place, including 

CAIR, additional refinery SO2

reductions as a result of refinery consent 

decrees, Texas ozone SIP revisions, and 

the Texas Clean Air Act. It noted that 

the majority of the emission reductions 

underlying the predicted visibility 

improvements are from the CAIR 

program or its eventual replacement. 

The TCEQ assumes that any 

replacement for CAIR will include 

interstate trading of emissions 

allowances and therefore there is 

uncertainty regarding how visibility will 

be improved at individual Class I areas. 

The TCEQ states that because emission 

allowances can be purchased by EGUs 

relatively close to the Texas Class I areas 

from EGUs far from the Texas Class I 

areas, the visibility improvement, may 

not be as great as predicted by the 

CENRAP’s modeling. Conversely, 

nearby EGUs may elect to control 

beyond their emission caps and sell 

emission allowances out of state, 

resulting in reduced emissions closer to 

the Texas Class I areas. 

The TCEQ concluded that ‘‘given the 

significant impact from international 

emissions, the uncertainty in the impact 

of CAIR, and the poor cost-effectiveness 

of additional, reasonable point source 

controls, the TCEQ has determined that 

additional controls for regional haze are 

not appropriate at this time.’’ 216

b. Our Evaluation 

We agree that there is uncertainty 

regarding the size and location of 

reductions at Texas EGUs due to 

implementation of CAIR/CSAPR. While 

reductions at certain facilities within 

Texas would result in improvements in 

visibility conditions at the Texas Class 

I areas or Class I areas in other states, 

similar reductions at other facilities may 

have no impact on visibility conditions 

at the Class I area. Furthermore, 

reductions that are seasonal in nature 

due to decreased operation during the 

fall and/or winter reduce annual 

emissions, contribute towards CAIR/

CSAPR compliance, but will not lead to 

improved visibility during the 20% 

worst days, which typically occur 

during the summer months. For 

example, in recent years the Monticello 

units have been shut down for several 

non-summer months, which has 

resulted in reduced annual emissions, 

while having no impact on summer time 

emissions or visibility impacts during 

the summer months. The CENRAP 

source apportionment results include 

the projected reductions due to CAIR 

compliance and show that even after 

these reductions, impacts from Texas 

points sources remain the most 

significant portion of the total visibility 

impairment with available controls at 

Big Bend and Guadalupe. Analysis of 

recent emissions from Texas EGUs 

shows that in many cases current 

emission levels are above those 

predicted in the 2018 CENRAP 

modeling. In fact, in the case of Martin 

Lake, current annual emissions are 

roughly twice those included in the 

2018 modeling, and we are not aware of 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74843 

217Available at: http://vista.cira.colostate.edu/

tss/ 

218Note that we discuss the difference between 

the natural visibility value calculated by New 

Mexico for Carlsbad Caverns and that calculated by 

Texas for the Guadalupe Mountains elsewhere in 

our proposal. 

any upcoming controls or changes in 

operation to suggest that future actual 

emissions will decrease to those 

predicted levels. 

We also agree with the TCEQ’s 

conclusion that it is not reasonable to 

meet the URP for the Texas Class I areas 

for this planning period. We agree with 

the TCEQ that emissions and transport 

from Mexico and other international 

sources will limit the rate of progress 

achievable on the 20% worst days and 

that efforts to meet the goal of natural 

visibility by 2064 would require further 

emission reductions not only within 

Texas, but also large emission 

reductions from international sources. 

We also note the more recent 

IMPROVE monitored data at the Big 

Bend and Guadalupe Mountains 

indicate that more progress than 

anticipated by the CENRAP modeling 

has occurred.217 The most recent fiveyear (2009–2013) average conditions for 

the 20% worst days is 16.3 dv at Big 

Bend and 15.3 dv at Guadalupe 

Mountains. This is below the level 

anticipated in the CENRAP projection 

for 2018 of 16.6 dv for Big Bend and 

16.3 dv for Guadalupe Mountains. We 

believe that this observed improvement 

from the baseline conditions is the 

result of meteorological conditions, 

reduction in the impacts from SO2

emissions, and a reduction in the 

impacts from coarse material. More 

recent emission inventory data shows 

reductions in emissions in most states 

beyond what was projected in the 2018 

modeling, including large reductions in 

emissions from the Eastern United 

States. Emissions from non-EGU Texas 

point sources are lower than have been 

projected in the modeling. We note that 

additional reductions are still needed to 

meet or exceed the URP goals for 2018 

as calculated by us in Section VII.M 

below. As discussed above, emission 

reductions at some of the sources that 

impact visibility the most are still above 

the emission level projected in the 

model and we believe that cost-effective 

controls are likely available at these 

sources. 

However, for the reasons we have 

discussed above, although we agree 

with the TCEQ that a rate of 

improvement necessary to attain natural 

visibility conditions by 2064 is not 

reasonable, we do not believe that the 

rate of improvement the TECQ has 

selected is reasonable, because we 

disagree with its four factor analysis and 

the analysis of emission measures 

needed to meet the URP. Therefore we 

propose to disapprove the TCEQ’s RPGs 

for Big Bend and the Guadalupe 

Mountains under Section 

51.308(d)(1)(ii). In so doing, we rely on 

the specific directive in Section 

51.308(d)(1)(iii): ‘‘In determining 

whether the State’s goal for visibility 

improvement provides for reasonable 

progress towards natural visibility 

conditions, the Administrator will 

evaluate the demonstrations developed 

by the State pursuant to paragraphs 

(d)(1)(i) and (d)(1)(ii) of this section.’’ 

We also propose to disapprove the 

Texas’ RPGs for the 20% best days. We 

propose to find that visibility on these 

days will be better than Texas projects, 

given additional controls in our 

proposed FIP. 

5. Reasonable Progress Consultation 

Pursuant to Section 51.308(d)(1)(iv), 

Texas consulted with other states which 

may reasonably be anticipated to cause 

or contribute to visibility impairment at 

its two Class I areas. In any situation in 

which Texas cannot agree with another 

such state or group of states that a goal 

provides for reasonable progress, Texas 

must describe in its submittal the 

actions taken to resolve the 

disagreement. In reviewing Texas’ SIP 

submittal, the Administrator will take 

this information into account in 

determining whether Texas’ goal for 

visibility improvement provides for 

reasonable progress towards natural 

visibility conditions. 

The TCEQ held three conference calls 

in July, 2007 to which Arkansas, 

Kansas, Louisiana, New Mexico, and 

Oklahoma were invited. The TCEQ used 

CENRAP generated products, such as 

regional photochemical modeling 

results and visibility projections, and 

source apportionment modeling to assist 

in identifying neighboring states’ 

contributions to the visibility 

impairment at its Class I areas. 

Specifically, the TCEQ used the results 

from the CENRAP particulate matter 

source apportionment technology 

(PSAT) modeling to determine that New 

Mexico, Oklahoma, Kansas, and 

Louisiana contribute to visibility 

impairment at the Texas Class I areas. 

The TCEQ invited those states with a 

> 0.5 inverse megameter impact on one 

of its Class I areas to its consultations. 

Other participants that attended one or 

more of the calls included CENRAP, us, 

and the federal land managers. The 

TCEQ invited tribes in all of the 

CENRAP states to the consultation calls, 

but no tribes participated in the 

consultation on Big Bend and 

Guadalupe Mountains. These calls are 

summarized in Appendix 4–1 of the 

Texas regional haze SIP. 

The first consultation call primarily 

addressed technical papers that 

discussed the natural conditions, the 

impacts of dust storms in Big Bend and 

the Guadalupe Mountains, our IPM 

emission projections, and the URP and 

RPGs for the Texas Class I areas. The 

second and third consultation calls 

consisted of discussions between the 

states and federal land managers 

regarding the dust storm technical 

papers. The TCEQ presented the URPs 

for its Class I areas, discussed controls 

that are in place in Texas, and its 

decision that no additional controls 

would be included in its regional haze 

SIP. The federal land managers 

suggested that the TCEQ revise the 

Prevention of Significant Deterioration 

(PSD) permit process to include FLM 

notification provisions. Texas 

committed to further consultations with 

the federal land managers to address 

their concerns about the Texas PSD 

program. 

The TCEQ discussed the CENRAP 

PSAT modeling results with the 

attendees. It noted that the BRAVO 

study indicated that for SO4, which has 

the largest visibility impact of all 

pollutants at Big Bend, approximately 

1⁄3 comes from Mexico, 1⁄3 from Texas, 

and 1⁄3 from the Midwest and South 

beyond Texas. It noted that these results 

are somewhat inconsistent with 

CENRAP PSAT modeling results, which 

indicate that slightly more than half of 

the visibility impairment at Big Bend 

comes from Mexico and other areas 

outside the U.S. 

New Mexico and the federal land 

managers discussed that despite the 

Guadalupe Mountains in Texas and 

Carlsbad Caverns in New Mexico 

sharing the same monitor, these Class I 

areas appeared to have significantly 

different calculated natural visibility 

values, individually prepared by the 

two states.218 The federal land managers 

and we both expressed a desire to 

review the TCEQ’s natural visibility 

calculation. 

The TCEQ concluded its 

consultations by noting that other states’ 

visibility impacts on Big Bend and the 

Guadalupe Mountains are relatively 

small. Texas sources are responsible for 

25% and 35% of the visibility 

impairment at Big Bend and the 

Guadalupe Mountains, respectively. 

Neighboring states combined contribute 

only 5% of the visibility impairment at 

Big Bend and 11.5% at the Guadalupe 

Mountains. As a result of these 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74844 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

219 64 FR 35736 (July 1, 1999). 

220The Texas BART Rule is present in Appendix 

9–2 of the Texas regional haze SIP. 

221 70 FR 39104 (July 6, 2005). 

222 70 FR 39158–39161 (July 6, 2005). 

consultations, the TCEQ did not request 

any additional reductions from other 

states. 

Citing the source apportionment 

results and results of the BRAVO study, 

in Section 11.3 of the Texas regional 

haze SIP, Texas requests in its SIP that 

we initiate and pursue federal efforts to 

reduce impacts from international 

transport. Due to large contributions 

from international sources, the TCEQ 

concludes it will be impossible to reach 

natural conditions without significant 

reductions in Mexico and other 

countries, in parallel with reductions 

within Texas and the rest of the United 

States. The TCEQ notes that Class I 

areas in other states will also benefit 

from reductions in emissions from 

international sources. We acknowledge 

that emissions from Mexico 

significantly impact the visibility at Big 

Bend and the Guadalupe Mountains. As 

we state in the Regional Haze Rule,219

‘‘the EPA does not expect States to 

restrict emissions from domestic sources 

to offset the impacts of international 

transport of pollution. We believe that 

States should evaluate the impacts of 

current and projected emissions from 

international sources in their regional 

haze programs, particularly in cases 

where it has already been well 

documented that such sources are 

important.’’ 

We reviewed the CENRAP PSAT data 

for the Texas Class I areas referred to 

during the consultation calls, as well as 

the technical papers discussed during 

those calls and the summary of the calls 

in Appendix 4–1 of Texas’ SIP 

submittal. Approximately half of the 

2002 visibility impairment at Big Bend 

is due to Mexico and other international 

sources captured in the modeled 

boundary conditions, one quarter of the 

impairment is due to Texas sources and 

the remaining quarter is due to all the 

remaining sources combined, with the 

largest contributions in this group from 

the Eastern United States (2.5%) and 

Louisiana (2.8%). Examining only 

contributions due to point sources in 

2002, Texas point sources contribute 

10% of the total visibility impairment at 

Big Bend and Mexico point sources 

contribute 16.9%. The largest impact 

from a nearby state is Louisiana at a 

little more than 2% contribution. All 

other nearby states contribute less than 

1% to the total visibility impairment at 

Big Bend. The source apportionment 

results for 2018 projections at Big Bend 

show similar levels of contribution with 

a slight decrease in Texas and Eastern 

United States contributions. Mexico and 

other international sources contribute 

approximately one quarter of the 

visibility impairment and Texas 

contributes about one third of the 

visibility impairment at the Guadalupe 

Mountains in 2002. The next largest 

contributing source regions are New 

Mexico (7.3%, 4.7% from natural 

sources), Kansas (3.3%), the Eastern 

United States (3.2%), Western United 

States (3.0%), and Oklahoma (2.5%). 

Examining only contributions due to 

point sources in 2002, Texas point 

sources contribute 8.7% of the total 

visibility impairment and Mexico point 

sources contribute 6.8%. The largest 

impact from a nearby state is New 

Mexico at a little more than 1% 

contribution. All other nearby states 

contribute less than 1% to the total 

visibility impairment at Guadalupe 

Mountains. The source apportionment 

results for 2018 projections at 

Guadalupe Mountains show similar 

levels of contribution with a slight 

decrease in eastern United States 

contributions. PSAT results show an 

overwhelming contribution from 

international sources and Texas sources 

and the technical papers shared by 

Texas suggest that dust storms 

significantly impact a number of the 

worst 20% days at these Class I areas. 

We find that the TCEQ appropriately 

identified those states with the largest 

impacts on Texas Class I areas and 

invited them for consultation. We agree 

with Texas’ determination that was not 

reasonable to request additional controls 

from other states at this time. Given the 

small contributions from individual 

nearby states, especially when only 

considering anthropogenic sources that 

can be easily controlled in comparison 

with the size of impacts from Texas 

sources and international sources, we 

find that it was reasonable for the TCEQ 

to have focused the analysis of 

additional controls on sources within 

Texas. We propose to find that Texas 

has satisfied the requirement under 

Section 51.308(d)(1)(iv) to consult with 

other states which may reasonably be 

anticipated to cause or contribute to 

visibility impairment at its two Class I 

areas. 

D. Evaluation of Texas’ BART 

Determinations 

As part of its strategy to address 

BART, the TCEQ adopted a BART rule 

on January 10, 2007, as 30 TAC Chapter 

116, Subchapter M.220 This rule 

identifies potentially affected sources as 

those belonging to one of 26 BART 

source industry categories; having a 

Potential to Emit (PTE) of 250 tpy or 

more of any visibility impairing 

pollutant; and not operating prior to 

August 7, 1962, and being in existence 

on August 7, 1977. It uses a value of 0.5 

dv as the visibility contribution 

threshold. It also incorporates the BART 

model plant and de minimis exemption 

criteria discussed below, and exempts 

EGUs that participate in CAIR from 

undergoing a BART review for NOX and 

SO2. It specifies that all non-exempt 

sources must undergo a BART review, 

according to the BART Guidelines. 

Lastly, it provides that BART controls 

must be installed and operational 

within 5 years following our approval of 

this SIP. We have reviewed the Texas 

BART rule and propose to approve it, 

with the exception of Texas’ reliance on 

CAIR to meet BART, as discussed in 

more detail in Section V.D.3. 

Texas exercised its option under 

Section 51.308(e)(4) (as it read at that 

time) that participation in CAIR is 

equivalent to BART. This exempted 

EGUs impacted by CAIR from a BART 

analysis for SO2 and NOX. As a result, 

the TCEQ did not evaluate BARTeligible EGUs that are included in CAIR 

for SO2 and NOX. This EGU BART 

exemption does not extend to 

particulate matter. As explained further 

in Section V.D.3, we earlier issued a 

limited disapproval of Texas’ regional 

haze SIP based on its reliance on CAIR. 

We are now 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. 

As discussed in more detail in our 

BART Rule,221 the BART evaluation 

process consists of three components: 

(1) An identification of all the BARTeligible sources, (2) an assessment of 

whether those BART-eligible sources are 

in fact subject to BART and (3) a 

determination of any BART controls. 

The TCEQ addressed these steps as 

follows: 

1. Identification of BART-Eligible 

Sources 

The first step of a BART evaluation is 

to identify all the BART-eligible sources 

within the state’s boundaries. The TCEQ 

identified the BART-eligible sources in 

Texas by utilizing the three eligibility 

criteria in the BART Guidelines 222 and 

our regulations (Section 51.301): (1) One 

or more emission units at the facility fit 

within one of the 26 categories listed in 

the BART Guidelines; (2) the emission 

unit(s) began operation on or after 

August 6, 1962, and was in existence on 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74845 

223 70 FR 39162 (July 6, 2005). 

224 70 FR 39163 (July 6, 2005). 

225Reproduced from Table 9–2 of the Texas 

regional haze SIP with additional sources later 

identified added. 

August 6, 1977; and (3) potential 

emissions of any visibility-impairing 

pollutant from subject units are 250 tons 

or more per year. 

The TCEQ did not have a 

comprehensive database of potential 

emissions from facilities, so it used 

annual emissions reporting with some 

adjustments. The TCEQ’s State of Texas 

Air Reporting System (STARS) database 

was used to determine which sources 

were potentially BART-eligible. In 

addition to NOX and SO2, the TCEQ also 

screened its database for sources of 

Volatile Organics (VOC) and coarse 

particulate matter (PM10) greater than 

200 tpy. The TCEQ used PM10 as a 

conservative value for direct PM2.5. 

However, because this database does not 

contain all information necessary to 

determine BART eligibility, the TCEQ 

also surveyed companies regarding their 

potential to emit and construction dates 

in order to complete the BART 

eligibility determination. In order to 

reduce the number of companies 

requiring clarification, the TCEQ chose 

to adopt a model plant analysis 

approach based on our model plants 223

in order to eliminate smaller sources of 

NOX and SO2 sources from being 

surveyed and potentially subject to 

BART. Regarding the use of the model 

plant approach, the BART Guidelines 

state:224

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 tons per year 

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 tons per year 

of NOX or SO2 (or combined NOX and SO2) 

that are located more than 100 kilometers 

from any Class I area. 

Since the STARS database includes 

reported actual emissions instead of 

potential to emit, the TCEQ added some 

conservatism to the inclusion of 

sources. The TCEQ modified its model 

plant approach and reduced the 

emission threshold to 375 tpy for 

sources greater than 50 km and 750 tpy 

for sources greater than 100 km to 

capture sources that might not have 

been above the BART Guideline’s 

emissions threshold, based only on their 

2002 emissions levels. 

As a result of the BART eligibility 

screening analysis, 254 sites/facilities 

(approximately 12% of the 2,165 

facilities in the Texas 2002 emissions 

inventory) were identified as being 

potentially BART-eligible based on their 

county’s minimum distance to Class I 

areas and their actual emissions. The 

TCEQ then sent surveys to these sites to 

request additional information in 

identifying construction or 

reconstruction dates and whether the 

potential to emit of potential BART 

eligible equipment exceeded the BART 

eligibility threshold of 250 tpy. As a 

result of the BART eligibility survey, the 

TCEQ determined that the following 

sites 225 numbered 1 through 120 were 

BART-eligible. During TCEQ’s review of 

BART eligible sources another 6 

facilities were identified as potentially 

BART eligible (numbered 121–126): 

TABLE 15—POTENTIAL BART-ELIGIBLE SOURCES BASED ON RESULTS OF TCEQ SURVEY

No. Account Source Regulated entity SIC 

1 ............... AC0017B Abitibi Consolidated Corp ....................................................................................................... RN100220110 2621 

2 ............... TG0044C AEP Texas .............................................................................................................................. RN101531226 4911 

3 ............... CD0013K AEP Texas Central Company ................................................................................................ RN102560687 4911 

4 ............... NE0024E AEP Texas Central Company ................................................................................................ RN100642040 4911 

5 ............... NE0026A AEP Texas Central Company ................................................................................................ RN100552181 4911 

6 ............... JI0030K AEP Texas North Company ................................................................................................... RN100215557 4911 

7 ............... CB0003M Alcoa Alumina & Chemicals ................................................................................................... RN100242577 2819 

8 ............... MM0001T Alcoa Inc ................................................................................................................................. RN100221472 3334 

9 ............... HT0011Q Alon USA Lp ........................................................................................................................... RN100250869 2911 

10 ............. ED0034O Ash Grove (Formerly North Texas Cement) .......................................................................... RN100225978 3241 

11 ............. HG0558G Atofina Chemicals Inc ............................................................................................................. RN100209444 2869 

12 ............. BL0021O BASF Corporation .................................................................................................................. RN100218049 2869 

13 ............. GB0001R BP Amoco Chemical Company .............................................................................................. RN102536307 2869 

14 ............. GB0004L BP Products North America In Texas .................................................................................... RN102535077 2911 

15 ............. GH0003Q Cabot Corporation .................................................................................................................. RN100221761 2895 

16 ............. BG0045E Capitol Cement Div Capitol .................................................................................................... RN100211507 3241 

17 ............. GH0004O Celanese Chemical ................................................................................................................ RN101996395 2869 

18 ............. MH0009H Celanese Limited .................................................................................................................... RN100258060 2869 

19 ............. ED0011D Chaparral Steel Midlothian ..................................................................................................... RN100216472 3312 

20 ............. BJ0001T Chemical Lime Ltd .................................................................................................................. RN100219856 3274 

21 ............. HG0310V Chevron Phillips Chemical ..................................................................................................... RN103919817 2869 

22 ............. BL0758C Chevron Phillips Chemical ..................................................................................................... RN100825249 2869 

23 ............. HW0013C Chevron Phillips Chemical Co ................................................................................................ RN102320850 2869 

24 ............. NE0027V Citgo Refining & Chemicals ................................................................................................... RN102555166 2911 

25 ............. BG0057U City Public Service ................................................................................................................. RN100217975 4911 

26 ............. BG0186I City Public Service ................................................................................................................. RN100217835 4911 

27 ............. HW0018P Conoco Phillips (Formerly Phillips 66) ................................................................................... RN102495884 2911 

28 ............. CR0020C Copano Processing LP ........................................................................................................... RN101271419 1321 

29 ............. AB0012W DCP (Formerly Duke Energy Field Services) ........................................................................ RN100218684 1321 

30 ............. HW0008S Degussa Engineered Carbons ............................................................................................... RN100209659 2895 

31 ............. HGA005E DOW ....................................................................................................................................... RN104150123 2869 

32 ............. HG0126Q DOW ....................................................................................................................................... RN100227016 2869 

33 ............. CI0022A Dynegy Midstream Services ................................................................................................... RN100222900 1321 

34 ............. HH0042M Eastman Chemical Company ................................................................................................. RN100219815 2869 

35 ............. HG0218K E.I. Dupont de Nemours & Co ............................................................................................... RN100225085 2869 

36 ............. OC0007J E.I. Dupont de Nemours & Co ............................................................................................... RN100542711 2869 

37 ............. EE0029T El Paso Electric Co ................................................................................................................ RN100211309 4911 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74846 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

TABLE 15—POTENTIAL BART-ELIGIBLE SOURCES BASED ON RESULTS OF TCEQ SURVEY—Continued 

No. Account Source Regulated entity SIC 

38 ............. TH0004D Electric Utility Dept ................................................................................................................. RN100219872 4911 

39 ............. CG0012C Enbridge Pipelines .................................................................................................................. RN102166964 1321 

40 ............. MQ0009F Entergy Gulf States Inc .......................................................................................................... RN100226877 4911 

41 ............. OC0013O Entergy Gulf States Inc .......................................................................................................... RN102513041 4911 

42 ............. BL0113I Equistar ................................................................................................................................... RN100218601 2869 

43 ............. BL0268B Equistar Chemicals LP ........................................................................................................... RN100237668 2821 

44 ............. HG0033B Equistar Chemicals LP ........................................................................................................... RN100542281 2869 

45 ............. HG0228H Exxon Chemical Co ................................................................................................................ RN102212925 2869 

46 ............. JE0065M Exxon Mobil Chemical Co ...................................................................................................... RN100211903 2821 

47 ............. HG0229F ExxonMobil Chemical Co ....................................................................................................... RN102574803 2869 

48 ............. HG0232Q ExxonMobil Corp .................................................................................................................... RN102579307 2911 

49 ............. JE0067I ExxonMobil Oil Corp ............................................................................................................... RN102450756 2911 

50 ............. NE0120H Flint Hills Resources ............................................................................................................... RN102534138 2911 

51 ............. NE0122D Flint Hills Resources LP ......................................................................................................... RN100235266 2911 

52 ............. JE0052V Huntsman Corporation ........................................................................................................... RN100219252 2869 

53 ............. JE0135Q Huntsman Petrochemical Corp .............................................................................................. RN100217389 2869 

54 ............. EB0057B Huntsman Polymers ............................................................................................................... RN101867554 2869 

55 ............. BL0002S INEOS Olefins & Polymers .................................................................................................... RN100238708 2869 

56 ............. CG0010G International Paper Co ........................................................................................................... RN100543115 2621 

57 ............. OCA002B Invista ..................................................................................................................................... RN104392626 2869 

58 ............. VC0008Q Invista (Formerly Du Pont De Nemours) ................................................................................ RN102663671 2869 

59 ............. WE0005G Laredo Power ......................................................................................................................... RN100213909 4911 

60 ............. MB0123F Lehigh Cement Company ....................................................................................................... RN100218254 3241 

61 ............. NE0025C Lon C Hill Power .................................................................................................................... RN100215979 4911 

62 ............. BC0015L Lower Colorado River Authority ............................................................................................. RN102038486 4911 

63 ............. FC0018G Lower Colorado River Authority ............................................................................................. RN100226844 4911 

64 ............. HG1575W Lyondell Chemical .................................................................................................................. RN100633650 2869 

65 ............. HG0048L Lyondell Citgo Refining .......................................................................................................... RN100218130 2911 

66 ............. GB0055R Marathon Ashland Petroleum ................................................................................................. RN100210608 2911 

67 ............. HH0019H NORIT Americas Inc .............................................................................................................. RN102609724 2819 

68 ............. GB0037T NRG Texas (Formerly Texas Genco LP) ............................................................................... RN101062826 4911 

69 ............. ED0051O Owens Corning ....................................................................................................................... RN100223585 3296 

70 ............. HG1451S Oxyvinyls LP ........................................................................................................................... RN102518065 2821 

71 ............. HG0175D Pasadena Refining ................................................................................................................. RN100716661 2911 

72 ............. JE0042B Premcor Refining Group ......................................................................................................... RN102584026 2911 

73 ............. MC0002H Regency Tilden Gas (Formerly Enbridge) ............................................................................. RN100216621 2819 

74 ............. HG0697O Rhodia Inc .............................................................................................................................. RN100220581 2819 

75 ............. HG0632T Rohm & Haas Texas .............................................................................................................. RN100223205 2869 

76 ............. HG0659W Shell Oil Co ............................................................................................................................ RN100211879 2911 

77 ............. HW0017R Sid Richardson Carbon .......................................................................................................... RN100222413 2895 

78 ............. HT0027B Sid Richardson Carbon Co .................................................................................................... RN100226026 2895 

79 ............. BL0038U Solutia Inc ............................................................................................................................... RN100238682 2869 

80 ............. TF0012D Southwestern Electric Power ................................................................................................. RN100213370 4911 

81 ............. GJ0043K Southwestern Electric Power ................................................................................................. RN102156916 4911 

82 ............. ME0006A Southwestern Electric Power ................................................................................................. RN100542596 4911 

83 ............. PG0040T Southwestern Public Service .................................................................................................. RN100224641 4911 

84 ............. PG0041R Southwestern Public Service .................................................................................................. RN100224849 4911 

85 ............. LN0081B Southwestern Public Service .................................................................................................. RN100224765 4911 

86 ............. JE0091L Sun Marine Terminal .............................................................................................................. RN100214626 4226 

87 ............. WN0042V Targa ...................................................................................................................................... RN102552387 1311 

88 ............. CY0019H Targa (Formerly Dynegy Midstream) ..................................................................................... RN102551785 1311 

89 ............. OC0019C Temple-Inland ......................................................................................................................... RN100214428 2621 

90 ............. CI0012D Texas Genco LP ..................................................................................................................... RN100825371 4911 

91 ............. FG0020V Texas Genco LP ..................................................................................................................... RN100888312 4911 

92 ............. HK0014M Texas Lehigh Cement Co ...................................................................................................... RN102597846 3241 

93 ............. HG0562P Texas Petrochemicals LP ....................................................................................................... RN100219526 2869 

94 ............. BL0082R The Dow Chemical Co ........................................................................................................... RN100225945 2869 

95 ............. JE0039N The Goodyear Tire And Rubber Co ....................................................................................... RN102561925 2822 

96 ............. NE0022I Ticona Polymers Inc ............................................................................................................... RN101625721 2869 

97 ............. JE0005H Total Petrochemicals .............................................................................................................. RN102457520 2911 

98 ............. ED0066B TXI Operations LP .................................................................................................................. RN100217199 3241 

99 ............. FI0020W TXU Big Brown Company LP ................................................................................................. RN101198059 4911 

100 ........... DB0251U TXU Electric Company ........................................................................................................... RN101559854 4911 

101 ........... FB0025U TXU Generation Company LP ............................................................................................... RN102285855 4911 

102 ........... HQ0012T TXU Generation Company LP ............................................................................................... RN100664812 4911 

103 ........... MB0116C TXU Generation Company LP ............................................................................................... RN102566494 4911 

104 ........... MM0023J TXU Generation Company LP ............................................................................................... RN102147881 4911 

105 ........... MO0014L TXU Generation Company LP ............................................................................................... RN102285848 4911 

106 ........... RL0020K TXU Generation Company LP ............................................................................................... RN102583093 4911 

107 ........... TA0352I TXU Generation Company LP ............................................................................................... RN100693308 4911 

108 ........... WC0028Q TXU Generation Company LP ............................................................................................... RN102183969 4911 

109 ........... YB0017V TXU Generation Company LP ............................................................................................... RN102563426 4911 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74847 

226Numbers 121–130 were not included in 

TCEQ’s initial list of 120 sources potentially subject 

to BART but were added during their review and 

development of the SIP. 

227 70 FR 39162–3 (July 6, 2005). 

228 70 FR 39162 (July 6, 2005). 

229See Tables 7–1 and 7–3 of the Texas regional 

haze SIP. Area sources comprise approximately 

94% of the total 2002 ammonia emissions, and 

approximately 93% of the total projected 2018 

ammonia emissions. 

230Note that our reference to CALPUFF 

encompasses the entire CALPUFF modeling system, 

which includes the CALMET, CALPUFF, and 

CALPOST models and other pre and post 

processors. The different versions of CALPUFF 

have corresponding versions of CALMET, 

CALPOST, etc. which may not be compatible with 

previous versions (e.g., the output from a newer 

version of CALMET may not be compatible with an 

older version of CALPUFF). The different versions 

of the CALPUFF modeling system are available 

from the model developer at http://www.src.com/

verio/download/download.htm. 

231 70 FR 39162 (July 6, 2005). 

232CAMx model code and user’s guide can be 

found at http://www.camx.com/download/

default.aspx.Model code used in our analysis is 

available with the modeling files. 

TABLE 15—POTENTIAL BART-ELIGIBLE SOURCES BASED ON RESULTS OF TCEQ SURVEY—Continued 

No. Account Source Regulated entity SIC 

110 ........... TF0013B TXU Generation Company LP ............................................................................................... RN102285921 4911 

111 ........... GB0076J Union Carbide Corp ................................................................................................................ RN100219351 2869 

112 ........... CB0028T Union Carbide Corporation ..................................................................................................... RN102181526 2869 

113 ........... HR0018T Valence Midstream Ltd ........................................................................................................... RN100213685 1321 

114 ........... GB0073P Valero Refining Co Texas ...................................................................................................... RN100238385 2911 

115 ........... NE0043A Valero Refining Company ...................................................................................................... RN100211663 2911 

116 ........... MR0008T Valero McKee ......................................................................................................................... RN100210517 2911 

117 ........... WH0014S Vetrotex Wichita Falls Plant ................................................................................................... RN100218601 3229 

118 ........... VC0003D Victoria Power ........................................................................................................................ RN100214980 4911 

119 ........... JB0016M Vintage Petroleum Inc ............................................................................................................ RN100214592 1311 

120 ........... JC0003K Westvaco ................................................................................................................................ RN102157609 2631 

121 226 ...... JE0343H BMC Holdings Inc ................................................................................................................... ..........

122 ........... AG0024G Pueblo Midstream Gas Corp .................................................................................................. ..........

123 ........... GBA007G INEOS ..................................................................................................................................... ..........

124 ........... HG0130C Valero Refining Texas LP ...................................................................................................... ..........

125 ........... JH0025O Johns Manville International ................................................................................................... ..........

126 ........... PE0024Q Regency Gas Services ........................................................................................................... ..........

We have reviewed the TCEQ’s 

development of their list of BARTeligible facilities (ultimately 126 

sources) and we propose to conclude 

that the TCEQ has adequately identified 

all sources that are BART eligible in the 

state. 

2. Identification of Sources Subject to 

BART 

The second step of the BART 

evaluation is to identify those BARTeligible sources that may reasonably be 

anticipated to cause or contribute to 

visibility impairment at any Class I area, 

i.e. those sources that are subject to 

BART. The BART Guidelines allow 

states to consider exempting some 

BART-eligible sources from further 

BART review because they may not 

reasonably be anticipated to cause or 

contribute to any visibility impairment 

in a Class I area. Sources that are not 

exempted by the state are required to 

conduct a full BART analysis and the 

state then makes a determination of 

what is BART for each of these subject 

to BART sources. 

a. Modeling Methodology 

Consistent with the BART Guidelines, 

the TCEQ chose to evaluate sources and 

determine if they were exempt from 

being subject to BART. When exempting 

sources from BART because they do not 

cause or contribute to visibility 

impairment in a Class I area, the BART 

Guidelines suggest three sub-options for 

determining that certain sources are not 

subject to BART: 227

• The use of model plants to exempt 

sources with common characteristics. 

• A cumulative modeling analysis to 

show that groups of sources are not 

subject to BART. 

• An individual source attribution 

approach. 

The TCEQ utilized all of these options 

to determine which sources were 

subject to BART. These BART 

exemption exercises are explained 

below. The BART Guidelines direct 

states to address SO2, NOX and direct 

PM (including both PM10 and PM2.5) 

emissions as visibility-impairing 

pollutants, and states must exercise 

their ‘‘best judgment to determine 

whether VOC or ammonia emissions 

from a source are likely to have an 

impact on visibility in an area.’’ 228

Ammonia (NH3) emissions in Texas are 

primarily due to area sources, such as 

livestock and fertilizer application.229

Because these are not point sources, 

they are not subject to BART. CENRAP 

modeling demonstrated that VOCs from 

anthropogenic sources are not 

significant visibility-impairing 

pollutants at the Guadalupe Mountains 

and Big Bend. The TCEQ further 

investigated VOC and direct PM impacts 

with the photochemical modeling as 

discussed below. We have reviewed this 

information and propose to agree with 

the TCEQ’s decision to address only 

SO2, NOX and PM as visibility impairing 

pollutants because VOC emissions from 

anthropogenic sources are not 

significant visibility-impairing 

pollutants at Class I areas in Texas and 

surrounding states and NH3 emissions 

in Texas are primarily due to area 

sources. 

The BART Guidelines provide that 

states may choose to use the 

CALPUFF 230 modeling system, or 

another appropriate model, to predict 

the visibility impacts from a single 

source on a Class I area and to therefore 

determine whether an individual source 

is anticipated to cause or contribute to 

impairment of visibility in Class I areas, 

i.e., ‘‘is subject to BART.’’ The 

Guidelines state that we believe 

CALPUFF is the best regulatory 

modeling application currently 

available for predicting a single source’s 

contribution to visibility impairment.231

The TCEQ consulted with us and FLM 

representatives and used both the 

Comprehensive Air Quality Model with 

extensions (CAMx) 232 and CALPUFF 

modeling systems to determine whether 

individual sources in Texas were 

subject to or exempt from BART. 

The BART Guidelines also 

recommend that states develop a 

modeling protocol for making 

individual source attributions, and 

suggest that states may choose to 

consult with us and their regional 

planning organization to address any 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74848 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

233CENRAP BART Modeling Guidelines, T. W. 

Tesche, D. E. McNally, and G. J. Schewe (Alpine 

Geophysics LLC), December 15, 2005, available at 

http://www.deq.state.ok.us/aqdnew/

RulesAndPlanning/Regional_Haze/SIP/

Appendices/index.htm. 

234 40 CFR part 51, Appendix W: Guideline on 

Air Quality Models Parts 8.3(d) and 8.3.1.2(d). 

235 70 FR 39104, 39161 (July 6, 2005). 

236Screening Analysis of Potentially BARTEligible Sources in Texas, and Final Report, 

Screening Analysis of Potential BART-Eligible 

Sources in Texas, located in Appendices 9–4 and 

9–5 of the Texas Regional Haze SIP, respectively. 

237See the CAMx modeling report, Addendum I, 

BART Exemption Screening Analysis, and 

Addendum II, BART Exemption Screening 

Analysis, located in Appendices 9–5 and 9–6 of the 

Texas Regional Haze SIP. 

issues prior to modeling. The CENRAP 

states, including Texas, developed the 

‘‘CENRAP BART Modeling 

Guidelines.’’ 233 Stakeholders, including 

EPA, FLM representatives, industrial 

sources, trade groups, and other 

interested parties, actively participated 

in the development and review of the 

CENRAP protocol. CENRAP provided 

readily available modeling data bases 

for use by states to conduct their 

analyses. We note that the original 

CALPUFF meteorological databases 

generated by CENRAP did not include 

observations as our guidance 

recommends,234 therefore sources were 

evaluated using the 1st High values 

instead of the 8th High values. The use 

of the 1st High modeling values was 

agreed to by us, representatives of the 

Federal Land Managers, and CENRAP 

stakeholders. We propose to find the 

chosen model and the general modeling 

methodology for the initial CALPUFF 

based screening modeling with CENRAP 

meteorological data acceptable. We 

further discuss both refined analyses 

using CALPUFF and CAMx modeling 

systems below. 

b. Contribution Threshold 

For states using modeling to 

determine the applicability of BART to 

single sources, the BART Guidelines 

note that the first step is to set a 

contribution threshold to assess whether 

the impact of a single source is 

sufficient to cause or contribute to 

visibility impairment at a Class I area. 

The BART Guidelines state that, ‘‘[a] 

single source that is responsible for a 1.0 

dv change or more should be considered 

to ‘cause’ visibility impairment.’’ 235 The 

BART Guidelines also state that ‘‘the 

appropriate threshold for determining 

whether a source contributes to 

visibility impairment’ may reasonably 

differ across States,’’ but, ‘‘[a]s a general 

matter, any threshold that you use for 

determining whether a source 

‘contributes’ to visibility impairment 

should not be higher than 0.5 dv.’’ 

Further, in setting a contribution 

threshold, states should ‘‘consider the 

number of emissions sources affecting 

the Class I areas at issue and the 

magnitude of the individual sources’ 

impacts. The Guidelines affirm that 

states are free to use a lower threshold 

if they conclude that the location of a 

large number of BART-eligible sources 

in proximity of a Class I area justifies 

this approach. Texas adopted a 

contribution threshold of 0.5 dv for 

determining which sources are subject 

to BART. For BART eligible EGUs that 

were originally covered by CAIR for 

NO2 and SO2, TCEQ used this threshold 

for PM impacts. For CALPUFF modeling 

that used the non-guideline CENRAP 

meteorological data and CAMx 

modeling we agreed to use the 1st High 

or maximum impact for evaluation with 

the threshold value. For the refined 

CALPUFF modeling that used 

meteorological data that did meet our 

guidelines we agreed with the use of the 

98th percentile value. We agree with 

Texas’ selection of this threshold value. 

The TCEQ first performed cumulative 

modeling analyses using the CAMx 

model. TCEQ’s CAMx modeling utilized 

the existing CENRAP photochemical 

modeling databases and CAMx 

modeling tools of Particulate Source 

Apportionment Tagging (PSAT) with 

Plume-in-Grid (PiG) treatment to assess 

contribution of groups of sources 

initially and later individual sources. As 

a result of this modeling, several BARTeligible sources were eliminated from 

further consideration due to their 

insignificant impacts on visibility at 

Class I areas. The remaining sources 

were required to perform source-specific 

screening modeling analyses using 

either the CALPUFF or the CAMx model 

setup developed by the TCEQ. TCEQ 

also utilized model plant approaches to 

screen out some sources. BART-eligible 

sources that were not eliminated due to 

any of the modeling analyses were then 

given the option of either reducing their 

emissions from their BART-eligible 

units using an enforceable mechanism, 

such as a permit, or performing a BART 

analysis. The following sections 

describe this process. 

c. Cumulative Modeling Using CAMx 

PSAT 

Due to the large number of sources the 

TCEQ initially conducted a cumulative 

modeling analysis to eliminate groups of 

sources from being subject to BART, as 

described in its CAMx modeling 

protocol and its CAMx modeling 

report.236 In addition to the cumulative 

CAMx modeling, the TCEQ developed 

its model plants based on the CAMx 

modeling results.237 CAMx also gave a 

more sophisticated way to evaluate VOC 

emissions from BART sources and 

determine if they needed to be 

evaluated further. The TCEQ also used 

the CAMx modeling and source 

grouping to assess the BART sources’ 

direct PM emissions impacts. It relied 

on CAIR coverage for NOX and SO2

emissions from EGUs subject to CAIR, 

so it only assessed impacts of VOCs and 

direct PM from these sources. 

The TCEQ’s CAMx modeling 

determined that visibility impacts at 

Class I areas due to all VOC emissions 

from BART eligible sources was well 

below the 0.5 dv threshold. The TCEQ 

CAMx modeling screened direct PM 

emissions from 37 EGUs using 

groupings and some individual source 

analyses. Of these, 35 of the 37 sources 

screened out from BART for direct PM 

emissions with the two remaining 

sources being from Account TF0012D— 

SWEPCO Welsh and Account 

TF0013B—TXU Monticello. The TCEQ 

also evaluated VOC emissions from nonEGU sources and screened out all but 

one non-EGU facility, the exception 

being Account CG0010G—International 

Paper facility. We have reviewed the 

TCEQ’s analysis as further discussed in 

our BART TSD, and we propose to 

concur with the TCEQ’s screening out of 

all BART sources from further screening 

or BART evaluation for VOC and direct 

PM emissions except for the 

International Paper, Monticello and 

Welsh accounts that were further 

evaluated for screening to be discussed 

later. 

The TCEQ also developed a Texas 

model plant for PM based on the 

previously discussed PM modeling for 

evaluation of two additional sources 

that were not in the original CAMx 

grouping modeling for PM. As further 

discussed in our BART TSD and the 

TCEQ’s regional haze SIP, two accounts 

were screened out from being subject to 

BART. They were Account CI0012D— 

Texas Genco LP and Account 

HW004D—Agrium. We have reviewed 

this analysis and propose to concur with 

TCEQ’s analysis and conclusion to 

screen out these two facilities from 

being subject to BART for their potential 

PM impacts. 

For SO2 and NOX BART screening, 

the TCEQ screened out many sources 

that were BART eligible and determined 

that they were eliminated from being 

subject to BART using either the 

cumulative CAMx modeling analyses or 

the Texas model plants approach based 

on sources in the CAMx groupings that 

screened out or using our model plants. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74849 

238The TCEQ CALPUFF modeling protocol, Best 

Available Retrofit Technology (BART) Modeling 

Protocol to Determine Sources Subject to BART in 

the State of Texas, and a summary report for each 

modeling demonstration are included in Appendix 

9–8 of the Texas regional haze SIP. 

239TCEQ’s CAMx modeling guideline, Guidance 

for the Application of the CAMx Hybrid 

Photochemical Grid Model to Assess Visibility 

Impacts of Texas BART Sources at Class I Areas is 

included in Appendix 9–8 of the Texas regional 

haze SIP. Both it and modeling summary reports for 

each modeling demonstration are included in the 

docket for this action. 

The 94 non-EGU sources were broken 

into groups of sources (initially 5–10 

sources per group approximately). 

Further analysis used the same sources 

and broke them into smaller groups for 

further evaluation and screening. From 

this second round of CAMx source 

grouping, the TCEQ developed model 

plants from the sources in the groups 

that screened out. The TCEQ’s model 

plant analyses is further discussed in 

our BART TSD and the Texas regional 

haze SIP submittal. 

If the technical analysis indicated a 

source was screened out, the TCEQ 

requested each source to certify that 

they agreed with the modeling analyses 

and data inputs (emissions, stack 

parameters, etc.). BART-eligible sources 

that were not eliminated from being 

subject to BART using these methods 

were required to conduct their own 

screening modeling analysis using 

either CALPUFF or CAMx modeling on 

an individual basis, using protocols 

developed by the TCEQ. As part of this 

analysis, the TCEQ also utilized our 

model plants and more facility specific 

information to screen out some 

facilities. Using these three techniques 

(CAMx grouping modeling, Texas model 

plants, and our model plants), the TCEQ 

screened out 72 facilities that were 

BART eligible based on their NOX and/ 

or SO2 emissions from being determined 

as subject to BART and a full five factor 

analysis. Table 17 below summarizes all 

the BART-eligible sources that were 

eliminated and how each source was 

eliminated. For sources eliminated from 

being subject to BART using the 

cumulative CAMx modeling analyses, 

CAMx based model plants and our 

model plants it is indicated in the 

column titled ‘‘Cum. Model CAMx’’. For 

full details see our BART TSD. We have 

reviewed the evaluation of facilities in 

TCEQ’s cumulative/grouping CAMx 

modeling analyses, the TCEQ’s Texas 

Model Plants analyses, and the TCEQ’s 

analyses using our Model Plants; and 

we propose to concur with the screening 

out from a full BART analysis of the 72 

facilities indicated in Table 17 under 

the column titled ‘‘Cum. Model CAMx’’ 

based on estimated/modeled impacts 

from NOX and SO2 from each facility. 

Many of the facilities not screened out 

by the TCEQ were further evaluated 

with individual facility impact 

modeling using either CALPUFF or 

CAMx. We discuss the TCEQ’s 

individual facility analysis in the 

following sections. 

d. Individual Source Apportionment 

Modeling Using CALPUFF 

As previously discussed CENRAP 

developed a CALPUFF modeling 

protocol and the meteorological 

modeling files (CALMET files) for 

conducting individual facility impact 

analysis from NOX and SO2 emissions. 

The CENRAP CALMET data set did not 

include observations, so CALPUFF 

modeling that used the CENRAP 

CALMET data had to use the 1st High 

value from the modeling instead of the 

8th High. TCEQ contacted the sources 

that did not previously screen out and 

gave them the option to do additional 

analysis with CALPUFF and/or CAMx. 

Facilities submitted individual source 

modeling protocols for their facilities 

and submitted them to TCEQ, us, and 

FLM representatives for review and 

comment. For the CALPUFF modeling, 

some sources used the CENRAP 

CALMET data and the 1st High metric 

for evaluation against the screening 

level of 0.5 del-dv (delta, or change in 

deciviews) and other sources developed 

CALMET with inclusion of 

meteorological observations data and 

used the 8th High modeling value 

instead. The TCEQ received and 

reviewed the additional individual 

source attribution modeling using the 

CALPUFF model.238 The 29 BARTeligible sources that were eliminated 

from being subject to BART based on 

CALPUFF modeling results are listed in 

the column labeled ‘‘CALPUFF’’ in 

Table 17, below. 

We have reviewed the modeling 

reports and files provided for these 29 

modeling efforts. Seventeen facilities 

screened out using the CENRAP NoObservation data set and followed the 

approved CENRAP protocol, including 

model setup/flags, post processing 

procedures, and accepted versions of 

the CALPUFF modeling suite at the 

time. Twelve facilities screened out 

using the refined CALMET data set 

using the CENSARA MM5 data and 

incorporating land and upper air 

meteorological data. From the 

discussion on PM screening above, there 

were three facilities that did not screen 

out (International Paper, TXU— 

Monticello, and AEP Welsh) which 

were evaluated in these model runs and 

these facilities were 3 of the 29 screened 

out here. We have reviewed the TCEQ’s 

individual source apportionment 

CALPUFF modeling analysis, and we 

propose to concur with TCEQ’s 

conclusion to screen these 29 sources 

from being subject to BART. 

e. Individual Source Apportionment 

Modeling Using CAMx 

Some facilities desired to do a single 

source analysis with CAMx. To 

standardize the modeling and 

evaluation, TCEQ developed ‘‘The 

CAMx modeling guideline, Guidance for 

the Application of the CAMx Hybrid 

Photochemical Hybrid Photochemical 

Grid Model to Assess Visibility Impacts 

of Texas BART Sources at Class I 

Areas,’’ as a standard protocol for 

refined single facility assessment with 

CAMx using the platform used for 

earlier screening modeling. The 

modeling emission inventory files were 

updated to the latest available at the 

time and the individual sources used 

their short-term allowable emission rate 

instead of the doubling of annual 

emissions to approximate short-term 

actuals. Six facilities conducted CAMx 

single facility screening analysis and all 

were less than 0.5 del-dv impacts based 

on the 1st High modeling value as 

agreed to in the Modeling Protocols at 

the time. The TCEQ included the 

modeling reports and the modeling 

protocol for this CAMx modeling of 

individual facility attribution.239 In 

Table 17 below, the column labeled 

‘‘Single Source CAMx’’ indicates the 

BART-eligible sources that were 

eliminated from being subject to BART 

based on individual facility attribution 

CAMx modeling results. 

These analyses used the maximum 

impact value on any day to compare 

against the 0.5 del-dv threshold. We 

have reviewed the modeling reports for 

these six facilities, and we propose to 

concur that the CAMx modeling and the 

evaluation was conducted in accordance 

with the modeling protocol approved by 

us at that time. When we approved the 

protocols, we did not consider the 

difference between CAMx and 

CALPUFF modeling and the natural 

conditions (‘‘clean’’) versus 2018 dirty 

background. In hindsight, we could 

have recommended using the ‘‘Clean’’ 

background approach in addition to the 

2018 based analysis as we are using in 

our FIP action discussed below. We note 

that all six of these facilities were 

included in the sources that we 

evaluated in our initial Q/D screening 

for our FIP analysis (which included all 

Texas sources in TCEQ’s emission 

database) as discussed below and all 

had a Q/D ratio to any Class I area that 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74850 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

240 70 FR 39162 (July 6, 2005). 

241 70 FR 39119 (July 6, 2005) 

242 70 FR 39157 (July 6, 2005). 243 70 FR 39161 (July 6, 2005). ‘‘Any de minimis 

values that you adopt may not be higher than the 

PSD applicability levels: 40 tons/yr for SO2 and 

NOX and 15 tons/yr for PM10. These de minimis 

levels may only be applied on a plant-wide basis. 

was less than 10 and were not further 

evaluated. Sources that had a ratio of 

less than 10 have a lower potential 

impact level in general. In light of our 

concurrence of the protocol and metrics 

to be used at the time of the Texas 

Regional Haze SIP development (2006– 

2007), we are not proposing to 

disapprove this aspect of TCEQ’s 

analysis. 

f. TCEQ-Granted BART Exemptions 

In addition to all the BART exemption 

modeling discussed above, the TCEQ 

also eliminated sources from being 

subject to BART based on further model 

plant analysis, using the BART 

Guideline approach.240 Sources that 

emitted less than 500 tons per year of 

NOX or SO2 (or combined NOX and 

SO2), located more than 50 kilometers 

from any Class I area; and sources that 

emitted less than 1,000 tons per year of 

NOX or SO2 (or combined NOX and SO2) 

located more than 100 kilometers from 

any Class I area were eliminated from 

being subject to BART, consistent with 

the BART Guidelines.241 The TCEQ also 

exempted a number of other sources for 

other reasons, including for having a 

PTE of less than 250 tons per year of any 

visibility impairing pollutant,242 not 

having any emitting units in any of the 

26 BART categories, unit shut downs, 

and de minimis levels of emissions.243

The results of the TCEQ’s granted 

exemptions are listed in column titled 

‘‘Exemption Requested’’ in Table 17 

below. We have reviewed the screening 

analysis for these 22 facilities and 

concur with the TCEQ screening them 

out from being subject to BART. 

Subsequent to the 2002 base year 

inventory, some BART-eligible sources 

reduced their permitted emissions and 

requested exemptions from the TCEQ. 

These nine sources did screen out/

obtain exemptions based on the limits 

and model plant approaches or reducing 

PTE below BART thresholds. See Table 

17 and the BART TSD for details. 

Documentation of the emission 

reductions is in the Texas regional haze 

SIP, Appendix 9–11: Documentation of 

Emission Reductions. The sources and 

the estimated reductions were also 

presented in our BART TSD and Table 

16 below. Reduction estimates are 

conservative because they are from the 

2002 actual emissions level to a new 

potential to emit level below the 2002 

actuals. Since facilities typically operate 

at less than their allowable emission 

rate on an annual basis we concur that 

the estimates of actual emission 

reductions for most of the sources is 

conservative. Capitol Cement shut down 

their BART units. 

TABLE 16—POST 2002 EMISSION REDUCTIONS AT TEXAS BART SOURCES

No. Regulated entity Source Account 

NOX Reduced 

from 

baseline 2002 

(tpy) 

SO2 Reduced 

from 

baseline 2002 

(tpy) 

PM Reduced 

from 

baseline 2002 

(tpy) 

1 ......... RN100211507 ..... CAPITOL CEMENT DIV .................... BG0045E ............. 1,328 1,193 100 

2 ......... RN100227016 ..... DOW .................................................. HG0126Q ............ 694 0 0 

3 ......... RN102450756 ..... EXXONMOBIL OIL ............................ JE0067I ............... 2.7 290 0 

4 ......... RN102609724 ..... NORIT AMERICAS INC .................... HH0019H ............. 16.6 +5.4 0 

5 ......... RN100216621 ..... REGENCY TILDEN GAS (FORMERLY ENBRIDGE PIPELINE).MC0002H ............ 2 2,276 0.2 

6 ......... RN102551785 ..... TARGA (FORMERLY DYNEGY MIDSTREAM SERVICES).CY0019H ............. 336 0.3 0.5 

7 ......... RN102561925 ..... THE GOODYEAR TIRE AND RUBBER CO.JE0039N .............. 89.1 +11.3 2.9 

8 ......... RN100213685 ..... VALENCE MIDSTREAM LTD ........... HR0018T ............. 247.1 2,743.5 5.6 

9 ......... RN100218601 ..... VETROTEX AMERICA ST. GOBAIN WH0014S ............ 62.6 16.4 59.0 

Total estimated reductions in PTE of haze emissions = 9,485.2 

tpy.

.............................. 2,778.1 6,535.9 168.2 

Following the conclusion of the BART 

exemption modeling, model plant 

analysis, and granted exemptions, all 

126 BART-eligible sources were found 

to be exempted from BART. 

g. Summary of Our Review of Texas’ 

BART Screening Analyses and 

Determinations 

The TCEQ analyzed 126 facilities that 

were potentially BART eligible or 

needed additional information to rule 

out their BART eligibility. We have 

reviewed the different modeling 

techniques that the TCEQ utilized in 

evaluating and screening out these 

sources and we propose to concur with 

the analysis. The TCEQ’s analysis was 

done in accordance with our 2005 

BART Guidelines, our modeling 

Guidelines on Air Quality Models (40 

CFR part 51 App. W), our and 

Interagency Work Group on Air Quality 

Monitoring’s (IWAQM) modeling 

guidance for CALPUFF and visibility 

analysis (several documents) and other 

pertinent modeling guidance. CALPUFF 

modeling was conducted pursuant to 

modeling protocols that were shared 

and reviewed by us and Federal Land 

Manager representatives and included 

the initial CENRAP modeling protocol, 

the TCEQ’s refined modeling protocol, 

and source specific modeling protocols. 

The TCEQ and six sources also 

performed modeling analyses with 

CAMx based on the TCEQ’s modeling 

protocols (initial TCEQ group/source 

modeling and refined single source 

protocols for six facilities). We initially 

had some concern in early 2007 that 

some sources may have screened out in 

the initial CAMx group modeling and 

model plant source screening in late 

2006 based on using the 98th percentile 

threshold rather than the threshold that 

was later agreed to in February 2007 of 

using the maximum (high 1st high 

instead of the. 8th high). As discussed 

and analyzed at the time (February 

2007) and detailed in our BART TSD, 

we think that the sources that screened 

out were analyzed in groups, and it is 

reasonable to conclude that no one 

source would have been above either 

threshold if refined modeling had been 

conducted. Subsequent screening using 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74851 

these sources and the model plant 

approach are also valid since each 

source would be below 0.5 del-dv based 

on the analysis as further discussed in 

our BART TSD. Therefore, we propose 

to concur with the sources that the 

TCEQ screened out using the model 

plant approaches. 

We also reviewed the results of the 

CALPUFF and CAMx single-source 

modeling, and we propose to concur 

with the screening of those facilities. We 

propose to concur with the TCEQ’s 

screening analysis overall and its 

conclusions as discussed above and in 

the BART TSD. The final list of all 

BART-eligible sources and the different 

screening techniques that provided the 

reason for not considering the source to 

be subject to BART for its VOC, direct 

PM, NOX and SO2 appears in the 

following table. 

TABLE 17—SUMMARY OF SCREENING ANALYSIS FOR EACH BART-ELIGIBLE FACILITY THAT WAS EVALUATED FOR IMPACTS

AT CLASS I AREAS AND REMOVED

[Screened out] 

Account Company BARTeligible 

Reason for removal 

Cum. model 

CAMx CAL-PUFF 

Single 

source 

CAMx 

Exemption 

requested 

1 ........ TG0044C ..... AEP TEXAS .................................................... y y .................... .................... ....................

2 ........ CD0013K ..... AEP TEXAS CENTRAL COMPANY—La 

Palma.

y y .................... .................... ....................

3 ........ NE0024E ..... AEP TEXAS CENTRAL COMPANY—Barney 

M Davis.

y y .................... .................... ....................

4 ........ NE0026A ..... AEP TEXAS CENTRAL COMPANY—Nueces 

Bay.

y y .................... .................... ....................

5 ........ JI0030K ....... AEP TEXAS NORTH COMPANY—W.T.U.- 

FT. PHANTOM.

y y .................... .................... ....................

6 ........ CB0003M .... ALCOA ALUMINA & CHEMICALS ................. y y .................... .................... ....................

7 ........ BL0002S ..... INEOS OLEFINS & POLYMERS .................... y y .................... .................... ....................

8 ........ HG0558G .... ATOFINA CHEMICALS INC ........................... y y .................... .................... ....................

9 ........ BL0021O ..... BASF CORPORATION ................................... y y .................... .................... ....................

10 ...... GB0001R .... BP AMOCO CHEMICAL COMPANY .............. y y .................... .................... ....................

11 ...... MH0009H .... CELANESE LIMITED ...................................... y y .................... .................... ....................

12 ...... ED0011D ..... CHAPARRAL STEEL MIDLOTHIAN .............. y y .................... .................... ....................

13 ...... BJ0001T ...... CHEMICAL LIME LTD .................................... y y .................... .................... ....................

14 ...... HG0310V .... CHEVRON PHILLIPS CHEMICAL ................. y y .................... .................... ....................

15 ...... HW0013C .... CHEVRON PHILLIPS CHEMICAL CO ........... y y .................... .................... ....................

16 ...... BG0057U .... CITY PUBLIC SERVICE—Sommers Deely 

Spruce.

y y .................... .................... ....................

17 ...... BG0186I ...... CITY PUBLIC SERVICE—V.H Brauning ........ y y .................... .................... ....................

18 ...... CR0020C .... COPANO PROCESSING LP .......................... y y .................... .................... ....................

19 ...... CI0022A ...... DYNEGY MIDSTREAM SERVICES ............... y y .................... .................... ....................

20 ...... WN0042V .... TARGA ............................................................ y y .................... .................... ....................

21 ...... HG0218K .... EI DUPONT .................................................... y y .................... .................... ....................

22 ...... EE0029T ..... EL PASO ELECTRIC CO ............................... y y .................... .................... ....................

23 ...... TH0004D ..... ELECTRIC UTILITY DEPT ............................. y y .................... .................... ....................

24 ...... MQ0009F .... ENTERGY GULF STATES INC—Lewis 

Creek.

y y .................... .................... ....................

25 ...... OC0013O .... ENTERGY GULF STATES INC—Sabine ....... y y .................... .................... ....................

26 ...... BL0113I ....... EQUISTAR ...................................................... y y .................... .................... ....................

27 ...... BL0268B ..... EQUISTAR CHEMICALS LP .......................... y y .................... .................... ....................

28 ...... HG0033B .... EQUISTAR CHEMICALS LP .......................... y .................... y y ....................

29 ...... HG0228H .... EXXON CHEMICAL CO ................................. y y .................... .................... ....................

30 ...... JE0065M ..... EXXON MOBIL CHEMICAL CO ..................... y y .................... .................... ....................

31 ...... HG0229F ..... EXXONMOBIL CHEMICAL CO ...................... y y .................... .................... ....................

32 ...... NE0122D ..... FLINT HILLS RESOURCES LP ..................... y y .................... .................... ....................

33 ...... JE0052V ..... HUNTSMAN CORPORATION ........................ y y .................... .................... ....................

34 ...... JE0135Q ..... HUNTSMAN PETROCHEMICAL CORP ........ y y .................... .................... ....................

35 ...... EB0057B ..... HUNTSMAN POLYMERS ............................... y .................... y .................... ....................

36 ...... GBA007G .... INEOS ............................................................. .................... .................... .................... .................... y 

37 ...... NE0120H ..... FLINT HILLS RESOURCES LP ..................... y y .................... .................... ....................

38 ...... WE0005G ... LAREDO POWER ........................................... y y .................... .................... ....................

39 ...... MB0123F ..... LEHIGH CEMENT COMPANY ....................... y y .................... .................... ....................

40 ...... NE0025C ..... LON C HILL POWER ..................................... y y .................... .................... ....................

41 ...... BC0015L ..... LOWER COLORADO RIVER Authority— 

Lower Colorado River.

y y .................... .................... ....................

42 ...... FC0018G ..... LOWER COLORADO RIVER AUTHORITY— 

Fayette.

y y .................... .................... ....................

43 ...... HG1575W ... LYONDELL CITGO REFINING ...................... y y .................... .................... y 

44 ...... HG1451S .... OXYVINYLS LP .............................................. y y .................... .................... ....................

45 ...... JE0042B ..... PREMCOR REFINING GROUP ..................... y y .................... .................... ....................

46 ...... HG0632T ..... ROHM & HAAS TEXAS .................................. y y .................... .................... ....................

47 ...... BL0038U ..... SOLUTIA INC ................................................. y y .................... .................... ....................

48 ...... GJ0043K ..... SOUTHWESTERN ELECTRIC POWER ........ y y .................... .................... ....................

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74852 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

TABLE 17—SUMMARY OF SCREENING ANALYSIS FOR EACH BART-ELIGIBLE FACILITY THAT WAS EVALUATED FOR IMPACTS

AT CLASS I AREAS AND REMOVED—Continued 

[Screened out] 

Account Company BARTeligible 

Reason for removal 

Cum. model 

CAMx CAL-PUFF 

Single 

source 

CAMx 

Exemption 

requested 

49 ...... ME0006A .... SOUTHWESTERN ELECTRIC POWER— 

Wilkes.

y y .................... .................... ....................

50 ...... PG0040T ..... SOUTHWESTERN PUBLIC SERVICE—Nichols.y y .................... .................... ....................

51 ...... PG0041R .... SOUTHWESTERN PUBLIC SERVICE—Harrington.y y .................... .................... ....................

52 ...... TF0012D ..... SOUTHWESTERN ELECTRIC POWER— 

Welsh.

y .................... .................... y ....................

53 ...... JE0091L ...... SUN MARINE TERMINAL .............................. y y .................... .................... ....................

54 ...... CI0012D ...... TEXAS GENCO LP—Cedar Bayou ................ y y .................... .................... ....................

55 ...... FG0020V ..... TEXAS GENCO LP—W A Parrish ................. y y .................... .................... ....................

56 ...... GB0037T ..... NRG Texas—PH Robinson ............................ y .................... y .................... ....................

57 ...... HG0562P .... TEXAS PETROCHEMICALS LP .................... y y .................... .................... ....................

58 ...... BL0082R ..... THE DOW CHEMICAL CO ............................. y y .................... .................... ....................

59 ...... NE0022I ...... TICONA POLYMERS INC .............................. y y .................... .................... ....................

60 ...... ED0066B ..... TXI OPERATIONS, L.P. ................................. y .................... y .................... ....................

61 ...... FI0020W ...... TXU BIG BROWN COMPANY LP .................. y y .................... .................... ....................

62 ...... DB0251U ..... TXU ELECTRIC COMPANY—North Lake 

Steam.

y y .................... .................... ....................

63 ...... FB0025U ..... TXU GENERATION COMPANY LP—Valley 

Steam.

y y .................... .................... ....................

64 ...... HQ0012T ..... TXU GENERATION COMPANY LP— 

Decordova.

y y .................... .................... ....................

65 ...... MB0116C .... TXU GENERATION COMPANY LP— 

Tradinghouse.

y y .................... .................... ....................

66 ...... MM0023J .... TXU GENERATION COMPANY LP—Sandow y y .................... .................... ....................

67 ...... MO0014L .... TXU GENERATION COMPANY LP—Morgan 

Creek.

y y .................... .................... ....................

68 ...... RL0020K ..... TXU GENERATION COMPANY LP—Martin 

Lake.

y y .................... .................... ....................

69 ...... TA0352I ...... TXU GENERATION COMPANY LP—Eagle 

Mtn.

y y .................... .................... ....................

70 ...... WC0028Q ... TXU GENERATION COMPANY LP—Permian Bsn.y y .................... .................... ....................

71 ...... YB0017V ..... TXU GENERATION COMPANY LP—Graham y y .................... .................... ....................

72 ...... TF0013B ..... TXU GENERATION COMPANY LP—Monticello.y .................... y .................... ....................

73 ...... GB0076J ..... UNION CARBIDE CORP ................................ y y .................... .................... ....................

74 ...... CB0028T ..... UNION CARBIDE CORPORATION ................ y y .................... .................... ....................

75 ...... GB0073P .... VALERO REFINING CO TEXAS .................... y y .................... .................... ....................

76 ...... VC0003D ..... VICTORIA POWER ........................................ y y .................... .................... ....................

77 ...... JB0016M ..... VINTAGE PETROLEUM, INC. ....................... y y .................... .................... ....................

78 ...... LN0081B ..... SOUTHWESTERN PUBLIC SERVICE ........... y y .................... .................... ....................

79 ...... AC0017B ..... ABITIBI CONSOLIDATED CORP ................... y .................... .................... .................... y

80 ...... MM0001T .... ALCOA INC ..................................................... y .................... y .................... ....................

81 ...... HT0011Q ..... ALON USA LP ................................................ y .................... y .................... ....................

82 ...... ED0034O .... ASH GROVE ................................................... y .................... y .................... ....................

83 ...... JE0343H ..... BMC HOLDINGS INC ..................................... .................... .................... .................... .................... y 

84 ...... GB0004L ..... BP PRODUCTS NORTH AMERICA IN 

TEXAS.

y .................... .................... y ....................

85 ...... GH0003Q .... CABOT CORPORATION ................................ y .................... y .................... ....................

86 ...... BG0045E .... CAPITOL CEMENT DIV CAPITOL ................. y .................... .................... .................... y 

87 ...... GH0004O .... CELANESE CHEMICAL ................................. y .................... .................... y ....................

88 ...... BL0758C ..... CHEVRON PHILLIPS CHEMICAL ................. y .................... .................... .................... y 

89 ...... NE0027V ..... CITGO REFINING & CHEMICALS ................. y .................... .................... y ....................

90 ...... HW0018P .... CONOCOPHILLIPS ........................................ y .................... y .................... ....................

91 ...... AB0012W .... DCP ................................................................. y .................... y .................... ....................

92 ...... HW0008S .... DEGUSSA ENGINEERED CARBONS ........... y .................... y .................... ....................

93 ...... MR0008T .... DIAMOND SHAMROCK REFINING ............... y .................... .................... .................... y 

94 ...... HGA005E .... DOW ............................................................... y .................... .................... y ....................

95 ...... HG0126Q .... DOW ............................................................... y .................... .................... .................... y 

96 ...... HH0042M .... EASTMAN CHEMICAL COMPANY ................ y .................... y .................... ....................

97 ...... OC0007J ..... EI DUPONT DENEMOURS & CO .................. y .................... .................... .................... y 

98 ...... MC0002H .... ENBRIDGE PIPELINE .................................... .................... .................... .................... .................... y 

99 ...... CG0012C .... ENBRIDGE PIPELINES .................................. y .................... .................... .................... y 

100 .... HG0232Q .... EXXONMOBIL CORP—Baytown ................... y .................... y .................... ....................

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74853 

244 77 FR 33642 (June 7, 2012). 

245Texas is subject to the requirements of the 

CSAPR trading program for both NOX and SO2. See 

76 FR 48208 (August 8, 2011). 246 77 FR 33654 (June 7, 2012). 

TABLE 17—SUMMARY OF SCREENING ANALYSIS FOR EACH BART-ELIGIBLE FACILITY THAT WAS EVALUATED FOR IMPACTS

AT CLASS I AREAS AND REMOVED—Continued 

[Screened out] 

Account Company BARTeligible 

Reason for removal 

Cum. model 

CAMx CAL-PUFF 

Single 

source 

CAMx 

Exemption 

requested 

101 .... JE0067I ....... EXXONMOBIL OIL CORP—Beaumont .......... y .................... y .................... ....................

102 .... CG0010G .... INTERNATIONAL PAPER CO ....................... y .................... y .................... ....................

103 .... OCA002B .... INVISTA .......................................................... y .................... y .................... ....................

104 .... VC0008Q .... INVISTA .......................................................... y .................... y .................... ....................

105 .... JH0025O ..... JOHNS MANVILLE INTERNATIONAL ........... .................... .................... .................... .................... y 

106 .... HG0048L ..... LYONDELL CITGO REFINING ...................... y .................... .................... y ....................

107 .... GB0055R .... MARATHON ASHLAND PETROLEUM .......... y .................... .................... .................... y 

108 .... HH0019H .... NORIT AMERICAS INC .................................. y .................... y .................... y 

109 .... ED0051O .... OWENS CORNING ........................................ y .................... .................... .................... ....................

110 .... HG0175D .... PASADENA REFINING .................................. y .................... y .................... ....................

111 .... AG0024G .... PUEBLO MIDSTREAM GAS CORP ............... .................... .................... .................... .................... y 

112 .... PE0024Q ..... REGENCY GAS SERVICES .......................... .................... .................... .................... .................... y 

113 .... HG0697O .... RHODIA, INC. ................................................. y .................... y .................... ....................

114 .... HG0659W ... SHELL OIL CO ............................................... y .................... y .................... ....................

115 .... HW0017R .... SID RICHARDSON CARBON ........................ y .................... y .................... ....................

116 .... HT0027B ..... SID RICHARDSON CARBON ........................ y .................... y .................... ....................

117 .... CY0019H ..... TARGA ............................................................ y .................... .................... .................... y 

118 .... OC0019C .... TEMPLE–INLAND ........................................... y .................... y .................... ....................

119 .... HK0014M .... TEXAS LEHIGH CEMENT CO ....................... y .................... y .................... ....................

120 .... JE0039N ..... THE GOODYEAR TIRE AND RUBBER CO .. y .................... y .................... y 

121 .... JE0005H ..... TOTAL PETROCHEMICALS .......................... y .................... y .................... ....................

122 .... HR0018T ..... VALENCE MIDSTREAM LTD ......................... y .................... y y y 

123 .... NE0043A ..... VALERO REFINING COMPANY .................... y .................... .................... .................... ....................

124 .... HG0130C .... VALERO REFINING TEXAS LP ..................... .................... .................... .................... .................... y 

125 .... WH0014S .... VETROTEX WICHITA FALLS PLANT ........... y .................... .................... .................... y 

126 .... JC0003K ..... WESTVACO .................................................... y .................... y .................... ....................

h. Subject to BART EGUs 

As explained above in Section I.C, in 

an earlier action, we issued a limited 

disapproval of the Texas regional haze 

SIP based on deficiencies arising from 

its reliance on CAIR to meet certain 

regional haze requirements.244 In the 

same rulemaking, we found that CSAPR, 

like CAIR, provides for greater 

reasonable progress towards the 

national goal than would BART. This 

finding applied only to EGUs in the 

states in the CSAPR region and only to 

the pollutants subject to the 

requirements of CSAPR.245 The docket 

for this earlier limited disapproval of 

Texas’ regional haze SIP may be found 

at Docket ID No. EPA–HQ–OAR–2011– 

0729. In that action, we did not 

disapprove the reasonable progress 

targets for 2018 that have been set by the 

states in their SIPs. The reasonable 

progress goals in the SIPs were set based 

on modeled projections of future 

conditions that were developed using 

the best available information at the 

time the analysis was done. Given the 

requirement in 40 CFR 51.308(d)(1)(vi) 

that states must take into account the 

visibility improvement that is expected 

to result from the implementation of 

other Clean Air Act requirements, states 

set their reasonable progress goals 

based, in part, on the emission 

reductions expected to be achieved by 

CAIR. As CAIR has now been remanded 

by the D.C. Circuit, the assumptions 

underlying the development of the 

reasonable progress targets have 

changed; however, because the overall 

EGU emission reductions from CSAPR 

are larger than the EGU emission 

reductions that would have been 

achieved by CAIR, we expect CSAPR to 

provide similar or greater benefits than 

CAIR. Given these considerations, we 

concluded not to disapprove the 

reasonable progress goals in any of the 

regional haze SIPs for their reliance on 

CAIR, including those for Texas. In this 

earlier action, we did not promulgate a 

FIP for Texas in order to allow more 

time for us to assess the Texas regional 

haze SIP submittal due to the variety 

and number of BART-eligible sources 

and the complexity of the SIP.246 At this 

time, we propose 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. 

Previously, CSAPR was stayed by the 

D.C. Circuit pending resolution of 

litigation. We moved to have that stay 

lifted in light of the Supreme Court 

decision. EME Homer City Generation, 

L.P. v. EPA, Case No. 11–1302, 

Document No. 1499505 (D.C. Cir. filed 

June 26, 2014). In our motion, we asked 

the Court to toll CSAPR’s compliance 

deadlines by three years, so that the 

Phase 1 emissions budgets apply in 

2015 and 2016 (instead of 2012 and 

2013), and the Phase 2 emissions 

budgets apply in 2017 and beyond 

(instead of 2014 and beyond). Under the 

tolled compliance deadline schedule 

proposed by us in its motion to lift the 

CSAPR stay, CAIR would sunset at the 

end of 2014 and be replaced by CSAPR 

beginning January 1, 2015. On October 

23, 2014, the D.C. Circuit granted our 

request to lift the legal stay on the 

implementation of CSAPR. Therefore, 

our proposed FIP to replace Texas’ 

reliance on CAIR with reliance CSAPR 

is consistent with the Court’s ruling. 

3. Texas’ BART Rule 

Texas also promulgated and 

submitted rule sections that add 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74854 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

247See Letter from Thomas Diggs, EPA, to Lola 

Brown, TCEQ (Sept. 22, 2006), attachment W–16 in 

the TCEQ’s March 19, 2009, SIP submittal. 

248 30 TAC 116.1510(d). 

249Section 51.308(d)(3)(i). 

250Section 51.308(d)(3)(ii). 

251Section 51.308(d)(3)(iii)–(iv). 

252Page 4–2 of the Texas Regional Haze SIP. 

253We assume the statement that modeling data 

indicates ‘‘no significant impact by Texas’’ on Class 

I areas in Arkansas and Oklahoma is an oversight 

in the Texas regional haze SIP. 

254See Table 1 of the TX TSD for a summary of 

CENRAP source apportionment modeling results for 

Class I areas in other States impacted by emissions 

from sources in Texas. 

engineering and control requirements 

for BART on certain affected sources. 

The full SIP submittal is available in the 

docket for this proposal at 

www.regulations.gov. Texas’ BART rules 

are codified at 30 TAC 116.1500– 

116.1540. The rules establish 

definitions, applicability, exemptions, 

BART, and exemption from BART. Our 

technical analysis of the provisions in 

Texas’ BART rules can be found in the 

TX and BART TSDs in the docket for 

this rulemaking. On September 22, 

2006, we provided substantive 

comments on Texas’ proposed BART 

rules.247 In its final adoption of the 

rules, the TCEQ adequately addressed 

all of our comments. However, at the 

time of our comments, CAIR had not yet 

been vacated by the D.C. Circuit. One 

provision in Texas’ BART rule, 30 TAC 

116.1510(d), provides an exemption 

from BART based on CAIR. Specifically, 

it states ‘‘BART-eligible electric 

generating units participating in the 

Clean Air Interstate Rule Trading 

Program are not subject to the 

requirements of Section 116.1520 or 

Section116.1530 of this title for NOX

and SO2.’’ 248 As discussed in Section 

I.C, we have already issued a limited 

disapproval of the Texas regional haze 

SIP for its reliance on CAIR. However, 

we determined that CSAPR provides for 

greater reasonable progress towards the 

national goal than would BART and 

Texas is included in CSAPR for NOX

and SO2. Therefore, our proposed FIP to 

replace reliance on CAIR with reliance 

on the trading programs of CSAPR as an 

alternative to BART includes a FIP to 

replace Texas’ reliance on CAIR in 30 

TAC 116.1510(d) with reliance on 

CSAPR. We propose to approve the 

remainder of the provisions in the Texas 

BART rules and Texas’ application of 

the BART rules regarding the 

identification of all BART eligible 

sources within the state and the 

screening of BART sources from full 

BART analysis. 

E. Long-Term Strategy 

Section 51.308(d)(3) provides that 

Texas’ long-term strategy include 

enforceable emissions limitations, 

compliance schedules, and other 

measures necessary to achieve the 

reasonable progress goals established by 

states having mandatory Class I areas. 

There are a number of requirements a 

state must meet when establishing its 

long-term strategy. These requirements 

include: (1) states must consult with 

downwind states to develop 

coordinated management strategies that 

address regional haze visibility 

impairment; 249 (2) where multiple 

states cause or contribute to visibility 

impairment in a Class I area, each state 

must demonstrate that it has put all 

measures necessary to obtain its share of 

emission reductions needed to meet the 

progress goal for the Class I area; 250 and 

(3) each state must provide and 

document the technical basis on which 

the state is relying to determine its share 

of emission reductions necessary to 

achieve reasonable progress for each 

Class I area it affects.251

1. Texas’ Long-Term Strategy 

Consultation 

Section 51.308(d)(3)(i) requires that 

where Texas has emissions that are 

reasonably anticipated to contribute to 

visibility impairment in any mandatory 

Class I area located in another state or 

states, it must consult with the other 

state(s) in order to develop coordinated 

emission management strategies. Texas 

must consult with any other state 

having emissions that are reasonably 

anticipated to contribute to visibility 

impairment in any mandatory Class I 

area within it. 

Regarding this requirement, the TCEQ 

makes the following statement in its 

SIP: 252

The TCEQ reviewed CENRAP modeling to 

assess which Class I areas in other States 

might be impacted by Texas’ emissions. 

Modeling indicated that Texas impacts 

Breton Wilderness Area in Louisiana, the 

Great Sand Dunes in Colorado, and several 

Class I sites in New Mexico. The TCEQ also 

consulted the adjacent States in which the 

modeling data indicated no significant 

impact by Texas, including Arkansas, 

Missouri, and Oklahoma.253

As we summarize below, CENRAP 

visibility modeling in fact demonstrates 

that Texas sources are responsible for a 

significant portion of the visibility 

impacts to Class I areas in a number of 

states on the worst 20% days for both 

2002 and 2018, including Arkansas and 

Oklahoma.254 Furthermore, as we 

discuss below, both Oklahoma and 

Texas mutually acknowledged that 

Texas sources significantly impact the 

visibility at the Wichita Mountains. 

Regardless, Texas participated in 

consultation calls with Arkansas, 

Missouri, and Oklahoma and through 

letters with Arkansas, Colorado, 

Louisiana, Missouri, and New Mexico. 

The TCEQ identified the significant 

point sources within each AOI and 

shared this information with nearby 

states during the consultation process 

(see Appendix 4–3 of the Texas regional 

haze SIP for consultation letters). 

Pursuant to this review and in 

response to comments from us and the 

federal land managers in March 2008, 

Texas wrote consultation letters to 

Arkansas, Missouri, Oklahoma, New 

Mexico, Louisiana, and Colorado to ask 

whether emission reductions projected 

in Texas by 2018 are sufficient to meet 

Texas’ apportionment of the impact 

reduction needed to meet the RPG for 

each Class I area in each state. 

The TCEQ also requested recipients of 

the letters to confirm they were not 

expecting any additional emission 

reductions from Texas sources. These 

letters and associated documents are 

included in Appendix 4–3 of the Texas 

Regional Haze SIP. Texas stated in the 

record that it had completed its 

consultation with Louisiana, Arkansas, 

Missouri, Oklahoma, and Colorado, and 

none of these states has asked it for 

further emission reductions to help the 

it meet its reasonable progress goals for 

its Class I area(s). Appendix 4–3 to the 

Texas regional haze SIP contains the 

official communications from these 

states to Texas. The following is a 

summary of the state-by-state review of 

Texas’ consultation under Section 

51.308(d)(3)(i): 

Colorado (Great Sand Dunes, Rocky 

Mountains) TCEQ sent Colorado a letter 

on March 25, 2008 with information of 

impacts of Texas sources on Colorado 

Class I areas. On June 19, 2008, 

Colorado responded in a letter in which 

it presented its own impact analyses 

and stated that Texas sources are below 

the criteria identified in the Colorado 

SIP (based on regional apportionment 

modeling used to develop the Colorado 

SIP, PSAT.). In a June 24, 2008, letter, 

Colorado’s Department of Public Health 

and Environment responded that no 

further emission reductions were 

requested of Texas at this time. 

Louisiana (Breton). On November 29, 

2007, the Louisiana Department of 

Environmental Quality (LDEQ) sent an 

email that stated it determined that 

emissions from Texas do not contribute 

to visibility impairment at Breton 

Wilderness Class I Area in Louisiana. 

LDEQ stated that it will continue to 

monitor all state and federal rules and 

control measures and will include the 

necessary emission factors in future 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74855 

255New Mexico Regional Haze SIP, Page 4 at: 

http://www.nmenv.state.nm.us/aqb/reghaz/

documents/Proposed_RH_SIP_309g_03312011.pdf. 

256See Appendix 4_3d of the Texas regional haze 

SIP for July 23, 2007, letter from ADEQ and MDNR 

to participants in the Central Class I Areas 

Consultation Process summarizing this series of 

consultation calls. 

modeling. TCEQ sent LDEQ a letter on 

March 25, 2008, with information of 

impacts of Texas sources on Breton. 

New Mexico: (Carlsbad Caverns, Salt 

Creek, White Mountain, Wheeler Peak). 

On August 8, 2008, TCEQ sent a letter 

to NMED. As of the date of the 

submission of the Texas regional haze 

SIP, New Mexico had not replied. New 

Mexico’s regional haze SIP provides 

additional clarification on its 

consultations. New Mexico 

acknowledges that the long-term 

strategies adopted by Colorado, Arizona, 

and Texas in their SIPs and approved by 

us will include emission reductions 

from a variety of sources that will 

reduce visibility impairment in New 

Mexico’s Class I areas.255

Missouri (Hercules-Glades, Mingo) 

and Arkansas (Caney Creek, Upper 

Buffalo). On August 26, 2007, Missouri 

and Arkansas invited states including 

Texas to a series of consultation calls 

concerning visibility at their four Class 

I areas. During these calls, a URP was 

developed for each Class I area in 

Arkansas and Missouri (Caney Creek 

and Upper Buffalo in Arkansas, and 

Hercules Glades and Mingo in 

Missouri). The participating states also 

determined that the projected 2018 

CENRAP modeling and other findings 

based on existing and proposed controls 

arising from local, state, and federal 

requirements indicated that the two 

Class I areas in Arkansas and the two 

Class I areas in Missouri are on the 

glidepath and are projected to meet the 

URP goals for the first implementation 

period ending in 2018. Arkansas 

Department of Environmental Quality 

(ADEQ) and Missouri Department of 

Natural Resources (MDNR) both 

determined that additional emission 

reductions from other states were not 

necessary to address visibility 

impairment at Caney Creek, Upper 

Buffalo, Hercules-Glades, and Mingo for 

the first implementation period ending 

in 2018, and all states participating in 

its consultations agreed with this.256

The TCEQ sent Missouri and Arkansas 

letters on March 25, 2008, with 

information of impacts of Texas sources 

on Missouri and Arkansas Class I areas. 

On April 21, 2008, Missouri responded 

with a letter that stated it had reviewed 

the TCEQ analysis and attachments and 

they provided results generally 

consistent with the CENRAP and 

Missouri modeling and data analysis 

used in developing its plan. Missouri 

indicated at this time, that emission 

reductions from Texas were adequate. In 

an April 21, 2008, letter, Missouri’s 

Department of Natural Resources 

responded that no further emission 

reductions were requested of Texas. 

Arkansas responded on June 10, 2008. It 

concurred with the CENRAP PSAT 

modeling assessment, and those results 

were used to set Arkansas’ RPGs for its 

2 Class I areas. Arkansas stated it was 

not depending on additional reductions 

at this time to meet its RPGs. In a June 

10, 2008, letter, the ADEQ responded 

that no further emission reductions 

were requested of Texas. 

Oklahoma (Wichita Mountains). The 

TCEQ attended Oklahoma’s three 

consultation calls held in August and 

September 2007. On August 3, 2007, 

ODEQ sent TCEQ a letter that noted the 

Wichita Mountains is not projected to 

be on its glide path and that, from ‘‘the 

work done through the CENRAP 

process, it is clear that Wichita 

Mountains suffers from significant 

anthropogenic impacts from Texas.’’ 

The letter requested that the ODEQ be 

able to comment on BACT 

determinations for Prevention of 

Significant Deterioration (PSD) sources 

that significantly impact the Wichita 

Mountains and requested that Class I 

impact reviews be required for all 

proposed PSD sources within 300 

kilometers of a Class I area. The letter 

cited several CAA visibility provisions 

related to PSD visibility requirements 

and the visibility transport requirement 

under Section 110 of the CAA. The 

ODEQ asked that the TCEQ ‘‘fully 

consider its comments’’ about 

applicable CAA provisions. In a 

response letter dated October 15, 2007, 

the TCEQ agreed that the modeling 

shows Texas to be a ‘‘significant source 

of visibility impairing pollution on the 

Wichita Mountains.’’ The TCEQ agreed 

to notify the ODEQ, along with the 

relevant FLM, whenever modeling 

indicates that a proposed source 

significantly impacts Wichita 

Mountains. The TCEQ also responded to 

the ODEQ’s PSD comments on potential 

impacts of new and modified sources. 

The TCEQ did not agree to the ODEQ’s 

300 kilometer PSD review request, and 

cited the need for us to adopt significant 

impact levels for Class I reviews so that 

there is a consistent approach to 

requiring Class I reviews. During the 

interim, the TCEQ committed to 

working with the federal land managers 

on mutually acceptable criteria for 

determining when a proposed PSD 

source should conduct a Class I review. 

The TCEQ also stated, in conjunction 

with work being done through CENRAP, 

that there will be significant reductions 

in the next few years and visibility at 

Wichita Mountains would improve as a 

result of those reductions. 

The TCEQ sent Oklahoma another 

consultation letter, dated March 25, 

2008. In that letter, the TCEQ provides 

a detailed assessment, based on 

CENRAP modeling, of the impact of 

Texas sources on the visibility at the 

Wichita Mountains. Specifically, the 

letter contained information related to 

the 2002 visibility impacts and the 2018 

projected visibility impacts from all 

source areas on the one Class I area in 

Oklahoma and the impacts apportioned 

to be from Texas’ sources. TCEQ 

indicated that CENRAP produced these 

results using particulate matter source 

apportionment technology (PSAT) 

modeling and relative response factors 

according to our regional haze modeling 

guidance. The data were from the 

August 27, 2007, version of the PSAT 

tool that Environ produced for CENRAP. 

The TCEQ also provided a table of 

sources of particular interest to Wichita 

Mountains, identified by the TCEQ due 

to their emissions and location within 

the AOI, developed as part of the 

CENRAP planning process. This table 

included 2002 and 2018 projected 

annual emissions from CENRAP, as well 

as the sources distance from Wichita 

Mountains. The TCEQ concluded by 

requesting ODEQ’s concurrence on that 

assessment, and, ‘‘that your State is not 

depending on any additional reductions 

from Texas sources in order to meet 

your reasonable progress goal(s).’’ 

On May 12, 2008, the ODEQ 

responded to that letter and concurred 

with the ‘‘information in that letter.’’ 

The ODEQ stated that it developed its 

RPG through CENRAP deliberation. It 

also stated that it does not anticipate 

reductions beyond those that Texas 

already planned to implement and upon 

which the CENRAP studies relied. 

However, the ODEQ stated that its RPG 

falls short of the uniform rate of 

improvement necessary to reach the 

default natural visibility conditions in 

2064. The ODEQ stated that reaching its 

progress goal requires constraints on 

emissions from new, modified, and 

existing sources. Referring back to its 

August 2007 letter, the ODEQ restated 

its request that the TCEQ perform an 

analysis of any new or modified PSD 

subject source within 300 km of the 

Wichita Mountains to conduct an 

analysis for its impact on the Wichita 

Mountains, following FLM guidance, as 

appropriate. It restated its request to 

review BACT determinations for 

proposed sources projected to 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74856 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

257We note, however, that we disapproved 

Arkansas’ RPGs because it did not perform an 

adequate four-factor analysis of their own sources 

and because we disapproved BART determinations 

in the State. See 76 FR 64186 (October 17, 2011). 

258See Tables 25 and 26 below and our TX TSD. 

significantly contribute to visibility 

impairment at the Wichita Mountains. 

The TCEQ committed to provide the 

ODEQ the opportunity to comment on 

control determinations for Texas 

facilities that having the potential to 

significantly impair visibility at the 

Wichita Mountains. The ODEQ asked to 

be informed of actual emission 

reductions achieved from CAIR. Please 

see our description of the TexasOklahoma consultations, based on the 

information in Oklahoma’s record, in 

our OK TSD and as summarized in 

Section VI.B.2, for additional 

consultation details. 

a. Our Review of Texas’ Long-Term 

Strategy State Consultation 

Section 51.308(d)(3)(i) requires that 

Texas consult with other states if its 

emissions are reasonably anticipated to 

contribute to visibility impairment at 

that state’s Class I area(s), and that 

Texas consult with other states if those 

states’ emissions are reasonably 

anticipated to contribute to visibility 

impairment at Big Bend and Guadalupe 

Mountains. The TCEQ’s consultations 

with other states that impact Texas 

Class I areas are described in Section 

V.C.5 above. 

During consultation, Colorado and 

Louisiana determined that Texas 

impacts on their Class I areas were not 

significant enough to warrant additional 

controls for this planning period. Based 

on the 2018 CENRAP projections, 

Missouri and Arkansas 257 established 

RPGs for their Class I areas that provide 

for a slightly greater rate of 

improvement in visibility than needed 

to attain the URP, and determined that 

the projected emission reductions 

included in the model were adequate, 

and that it was not reasonable to request 

additional controls from Texas at this 

time. We find these consultations 

acceptable. 

The CENRAP source apportionment 

modeling indicates that Texas 

emissions, particularly SO2 emissions 

from point sources, impact a number of 

Class I areas outside of Texas. Texas SO2

emissions are projected in 2018 to have 

the largest visibility impacts, in terms of 

both absolute contribution to extinction 

and percent contribution to total 

extinction, at the Wichita Mountains in 

Oklahoma.258 As we discuss above, both 

the ODEQ and the TCEQ agreed that 

sources in Texas significantly impact 

the visibility at the Wichita Mountains 

in Oklahoma, and that the impacts from 

point sources in Texas are several times 

greater than the impact from Oklahoma 

point sources. Furthermore, the ODEQ 

asserted in its consultations with the 

TCEQ, and elsewhere in its regional 

haze SIP, that it would not be able to 

reach natural visibility by 2064 without 

additional reductions from Texas 

sources. During consultations, the 

ODEQ specifically requested additional 

information on controls identified 

through the CENRAP process that were 

cost-effective and had the potential to 

result in visibility improvements due to 

their location and size. In addition, the 

ODEQ had information that other 

sources with existing controls still have 

a large potential to impact visibility and 

should be analyzed for control 

upgrades. 

Ultimately, however, Texas 

determined that no additional controls 

at its sources were warranted during the 

first planning period to help achieve 

reasonable progress at the Wichita 

Mountains, and Oklahoma did not 

specifically request any additional 

reductions from Texas sources. As a 

result, Oklahoma set RPGs for the 

Wichita Mountains that do not reflect 

any reasonable emission reductions 

from Texas beyond those that will be 

achieved by compliance with other 

requirements of the CAA. During the 

notice-and-comment period on 

Oklahoma’s proposed SIP, several 

commenters criticized Oklahoma for not 

requesting additional reductions from 

Texas. They argued that without such 

reductions, Oklahoma would not make 

reasonable progress toward the national 

goal at the Wichita Mountains. In 

responding to these comments, 

Oklahoma acknowledged that sources in 

Texas had significant impacts on 

visibility in the Wichita Mountains, but 

maintained that it did not have the 

regulatory authority to require emission 

reductions in other states. Oklahoma 

asserted that only Texas and we could 

require such reductions. We believe that 

the technical analysis developed by 

Texas did not provide the information 

necessary to identify reasonable 

reductions from its sources, and inform 

consultations in order to develop 

coordinated management strategies with 

Oklahoma. As a result, we believe that 

Texas did not incorporate those 

potential reasonable reductions into its 

long-term strategy and those reductions 

were not included in the reasonable 

progress goal established by Oklahoma 

for Wichita Mountains. Consequently, 

we propose to find that the TCEQ did 

not adequately address the requirement 

in Section 51.308(d)(3)(i) to ‘‘consult 

with the other State(s) in order to 

develop coordinated emission 

management strategies.’’ 

2. Texas’ Share of Reductions in Other 

States’ Progress Goals 

Section 51.308(d)(3)(ii) requires that if 

Texas emissions cause or contribute to 

impairment in another state’s Class I 

area, it must demonstrate that it has 

included in its regional haze SIP all 

measures necessary to obtain its share of 

the emission reductions needed to meet 

the progress goal for that Class I area. 

Section 51.308(d)(3)(ii) also requires 

that since Texas participated in a 

regional planning process, it must 

ensure it has included all measures 

needed to achieve its apportionment of 

emission reduction obligations agreed 

upon through that process. As we state 

in the Regional Haze Rule, Texas’ 

commitment to participate in CENRAP 

bind it to secure emission reductions 

agreed to as a result of that process, 

unless it proposes a separate or 

supplemental process and performs its 

consultations on the basis of that 

process. 

While the content of state SIPs cannot 

be dictated by a regional planning 

organization, the Regional Haze Rule 

contemplated that a coordinated 

regional effort would likely produce 

results the states would find beneficial 

in developing their regional haze SIPs. 

Any state choosing not to follow the 

recommendations of a regional body 

would have to provide a specific 

technical basis that its strategy 

nonetheless provides for reasonable 

progress based on the statutory factors 

and would be responsible for the 

content of that demonstration. The 

technical data prepared through the 

regional planning organization process 

is typically designed to inform the 

member states of their apportionment of 

the visibility impact at Class I areas, 

project future visibility conditions, and 

to provide high-level information on 

potential control strategies to inform 

consultations and the four-factor 

analysis necessary to establish RPGs. 

These analyses may require additional 

supplementation or refinement by the 

states in development of their regional 

haze SIPs to address impacts and 

potential controls of specific sources or 

source categories. 

Participation in a regional planning 

organization does not automatically 

satisfy a state’s obligation to 

‘‘demonstrate that it has included in its 

implementation plan all measures 

necessary to obtain its share of the 

emission reductions needed to meet the 

progress goal’’ for a Class I area. As 

mentioned in section IV above, the 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74857 

259 70 FR 39114 (July 6, 2005). 

260Technical Support Document for CENRAP 

Emissions and Air Quality Modeling to Support 

Regional Haze SIP, included as Appendix 8–1 of the 

Texas regional haze SIP. 

261See page 7–1 of the Texas Regional Haze SIP. 

262TOG is total organic gas, which includes total 

hydrocarbons. 

control measures in an upwind state’s 

long term strategy should be sufficient 

to obtain its share of reductions needed 

to meet an approved, or approvable, 

progress goal in a downwind state’s SIP. 

In this instance, the CENRAP technical 

analysis was sufficient to demonstrate 

that Texas as a whole, and particular 

source categories such as EGU point 

sources, had a significant impact on the 

visibility at the Wichita Mountains and 

other Class I areas. The analysis also 

estimated that large emission reductions 

could be achieved at some of these 

sources by implementing potentially 

cost-effective controls. The TCEQ 

recognized that some aspects of 

CENRAP’s technical analysis were 

limited and therefore attempted to 

supplement that analysis, which it used 

as the technical basis for both its 

reasonable progress and long-term 

strategy demonstrations, as we describe 

in Section V.C. As it states with regard 

to the development of its long-term 

strategy on page 10–4 of its regional 

haze SIP, ‘‘[t]he TCEQ used the control 

strategy analysis completed by the 

CENRAP as the starting point for the 

analysis of additional controls.’’ In fact, 

the TCEQ went beyond the CENRAP 

analysis by contemplating additional 

controls, applying a lower costeffectiveness threshold and estimating 

the visibility benefit from the identified 

control set. The TCEQ incorporated this 

supplemental analysis in the 

development of its RPG and its longterm strategy. It used this analysis to 

inform its decision not to control any 

additional sources, including those that 

impact the visibility at the Wichita 

Mountains and other Class I areas in 

other states. 

However, we believe the technical 

analysis developed by CENRAP and 

supplemented by the TCEQ did not 

provide the information needed to 

evaluate the reasonableness of controls 

on those sources with the largest 

potential to impact visibility at the 

Wichita Mountains. See Sections V.C.2 

and V.C.3, as well as the TX TSD for a 

detailed description and our review of 

the CENRAP and TCEQ analyses. We 

believe this information was critical for 

ODEQ to use in setting the RPG and 

critical for TCEQ when determining its 

fair share of reductions. 

We propose to find that Texas did not 

develop an adequate technical basis to 

inform consultations with Oklahoma 

and to identify reasonable reductions 

from its sources. As a result, we find 

that Texas did not incorporate those 

reasonable reductions into its long-term 

strategy. Texas’ ‘‘share of the emission 

reductions needed to meet the progress 

goal’’ for the Wichita Mountains was not 

properly established because of the 

inadequacies in its technical analyses, 

which compromised its consultations 

with Oklahoma. For these reasons we 

propose to find that TCEQ did not 

adequately meet the requirement in 

Section 51.308(d)(3)(ii). 

3. Texas’ Technical Basis for Its LongTerm Strategy 

Section 51.308(d)(3)(iii) requires that 

Texas document the technical basis, 

including modeling, monitoring and 

emissions information, on which it is 

relying to determine its apportionment 

of emission reduction obligations 

necessary for achieving reasonable 

progress in each mandatory Class I area 

it affects. It may meet this requirement 

by relying on technical analyses 

developed by the regional planning 

organization and approved by all state 

participants. Texas must identify the 

baseline emissions inventory on which 

its strategies are based. The baseline 

emissions inventory year is presumed to 

be the most recent year of the 

consolidated periodic emissions 

inventory. 

Section 51.308(d)(3)(iv) requires that 

Texas identify all anthropogenic sources 

of visibility impairment considered by it 

in developing its long-term strategy. 

Texas should consider major and minor 

stationary sources, mobile sources, and 

area sources. 

The TCEQ addressed the 

requirements of Sections 

51.308(d)(3)(iii)–(iv) mainly by relying 

on technical analyses developed by 

CENRAP and approved by all state 

participants, but it also performed an 

additional analysis building upon the 

work of the regional planning 

organization in order to evaluate 

additional controls, as described in 

Section V.C.2. The emissions inventory 

used in the regional haze technical 

analyses was developed by CENRAP 

with assistance from Texas. The 2018 

emissions inventory was developed by 

projecting 2002 emissions and applying 

reductions expected from federal and 

state regulations affecting the emissions 

of the visibility-impairing pollutants 

NOX, PM, SO2, and VOCs. By analogy, 

with regard to development of the longterm strategy, the BART Guidelines 

direct states to exercise judgment in 

deciding whether VOCs and NH3 impair 

visibility in their Class I area(s).259

CENRAP performed modeling 

sensitivity analyses, which 

demonstrated that anthropogenic 

emissions of VOC and NH3 do not 

significantly impair visibility in the 

CENRAP region. Therefore, Texas did 

not consider NH3 among visibilityimpairing pollutants and did not further 

evaluate NH3 and VOC emissions 

sources for potential controls under 

BART or reasonable progress. 

a. Texas’ 2002 Emission Inventory 

The TCEQ and CENRAP developed an 

emission inventory for five inventory 

source classifications: Point, area, nonroad and on-road mobile sources, and 

biogenic sources for the baseline year of 

2002. Texas’ 2002 emissions inventory 

provides estimates of annual emissions 

for haze producing pollutants by source 

category, based on information in 

Section 7.0 of Texas’ regional haze SIP. 

Methodologies used in developing the 

2002 emissions inventory are 

documented in Appendix 7–1 of the 

Texas regional haze SIP and the 

technical support document for the 

CENRAP emission inventory 

development.260 See our TX TSD and 

our CENRAP Modeling TSD for a 

summary and our review of how the 

2002 emissions inventory was 

constructed. The TCEQ noted concerns 

with the estimate of area source SO2

emissions included in the CENRAP 

emission inventory for 2002 and 2018, 

and stated that the 2002 emissions 

reported by TCEQ were 15,633 tpy for 

SO2 area sources. However, it states that 

the CENRAP’s modeled emissions are 

not expected to significantly impact 

visibility estimates for 2018 because of 

the relatively small contribution for 

these Texas sources on Class I areas.261

Texas’ 2002 emissions inventory is 

summarized in Tables 18 and 19: 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74858 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

263Appendix 7–2 of the Texas regional haze SIP: 

Integrated Planning Model Projections of Electric 

Generating Unit Emissions for the Regional Haze 

State Implementation Plan. 

264TOG is total organic gas, which includes total 

hydrocarbons. 

TABLE 18—TEXAS’ 2002 EMISSIONS INVENTORY

[Tons/year] 

CO NOX SO2 TOG 262 PM2.5 PM10 NH3

Area .............................. 908,407 280,811 111,853 1,163,549 347,490 1,552,824 380,057 

Point ............................. 498,467 600,725 821,961 207,695 46,789 80,947 2,609 

Non-road mobile .......... 1,210,158 242,551 21,828 148,952 15,089 15,556 56 

On-road mobile ............ 4,098,391 664,163 18,814 309,707 11,275 15,476 21,599 

Total ...................... 6,715,423 1,788,250 974,457 1,829,902 420,642 1,664,803 404,321 

TABLE 19—TEXAS’ 2002 BIOGENIC EMISSIONS INVENTORY

[Tons/year] 

NOX CO VOC 

Biogenic ......................................................................................................................................................... 184,896 755,941 4,033,760 

b. Texas’ 2018 Emission Inventory 

In general, the TCEQ used a 

combination of our Economic Growth 

Analysis System (EGAS 5), our mobile 

emissions factor model (MOBILE 6), our 

off-road emissions factor model 

(NONROAD), and the IPM for electric 

generating units.263 All control 

strategies expected to take effect prior to 

2018 are included in the projected 

emission inventory. See our TX TSD 

and our CENRAP Modeling TSD for a 

summary and our review of how the 

2018 emissions inventory was 

constructed. Texas’ 2018 emissions 

inventory is summarized in Table 20, 

based on information in Section 7.0 of 

the Texas regional haze SIP. 

TABLE 20—TEXAS’ 2018 EMISSIONS INVENTORY

CO NOX SO2 TOG 264 PM2.5 PM10 NH3

Area .............................. 899,497 274,663 114,138 1,420,681 354,712 1,557,089 562,379 

Point ............................. 542,128 525,174 625,068 283,290 80,577 121,733 6,790 

Non-Road ..................... 1,921,674 167,451 6,988 119,855 10,588 11,498 239 

On-Road ....................... 2,710,631 148,387 2,925 125,234 5,337 5,337 32,191 

Total ...................... 6,073,930 1,115,676 749,119 1,949,060 451,214 1,695,657 601,598 

Methodologies used in developing the 

2018 emissions inventory are 

documented in Appendix 7–1 of the 

Texas regional haze SIP and the 

technical support document for the 

CENRAP emission inventory 

development. CENRAP and the TCEQ 

used this and other states’ 2018 

emission inventories to construct 

visibility projection modeling for 2018. 

c. Visibility Projection Modeling 

Chapter 8 of the Texas regional haze 

SIP discuss the modeling methods and 

protocol used by the TCEQ and 

CENRAP in developing the assessment. 

Chapter 7 describes the baseline and 

2018 emission inventories used by the 

TCEQ. A detailed description and 

discussion of the model selection, 

modeling protocol, quality assurance, 

performance evaluation, emission 

inventory development and data used in 

the regional haze analysis can be found 

in our TX and CENRAP Modeling TSDs. 

A short summary is provided below: 

• CENRAP performed modeling for 

the regional haze long-term strategy for 

its member states, including Texas. The 

modeling analysis is a complex 

technical evaluation that began with 

selection of the modeling system. 

CENRAP used the following modeling 

system: 

• Meteorological Model: The 

Pennsylvania State University/National 

Center for Atmospheric Research (PSU/ 

NCAR) Mesoscale Meteorological Model 

(MM5) is a non-hydrostatic, prognostic 

meteorological model routinely used for 

urban-and regional-scale 

photochemical, PM2.5, and regional haze 

regulatory modeling studies. 

• Emissions Model: The Sparse 

Matrix Operator Kernel Emissions 

(SMOKE) modeling system generates 

hourly gridded speciated emission 

inputs of mobile, non-road mobile, area, 

point, fire and biogenic emission 

sources for photochemical grid models. 

• Air Quality Model: Our Models-3/

Community Multiscale Air Quality 

(CMAQ) modeling system is a 

photochemical grid model capable of 

addressing ozone, PM, visibility and 

acid deposition at a regional scale. The 

photochemical model selected for this 

study was CMAQ version 4.5. It was 

modified through CENRAP with a 

module for Secondary Organics 

Aerosols (SOA) in an open and 

transparent manner that was also 

subjected to outside peer review. The 

Comprehensive Air Quality Model with 

extensions (CAMx) Version 4.40 model, 

applied using similar options as used by 

CMAQ, was used as a secondary 

corroborative model. CAMx was also 

utilized with its Particulate Source 

Apportionment Technology (PSAT) tool 

to provide source apportionment of 

predicted nitrate and sulfate aerosol 

concentrations. 

d. Sources of Visibility Impairment in 

Big Bend National Park 

Tables 21 and 22 summarize the 

modeled contributions to total 

extinction at Big Bend for each source 

category and species for 2002 and 2018, 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74859 

265The species contributing to visibility 

extinction at Big Bend and Guadalupe Mountains, 

shown on Tables 21, 22, 23 and 24, are the 

following: Sulfate (SO4), nitrate (NO3), primary 

organic aerosols (POA), elemental carbon (EC), soil 

dust, and coarse mass (CM). These species’ 

precursors are SO2, NOX, and in some cases, NH3

and VOCs. 

respectively.265 Visibility impairment at 

Big Bend in 2002 on the worst 20% days 

is largely due to SO4 from point sources 

that contributes 17.7 Mm¥1 of the total 

extinction of 47.79 Mm¥1. The largest 

contributions of SO4 come from Texas 

(5.50 Mm¥1 from all source categories), 

boundary conditions outside the 

modeling domain (5.82 Mm¥1) and 

Mexico (8.28 Mm¥1). Overall, the 

largest source region contributions to 

visibility impairment in 2002 are from 

Mexico (12.75 Mm¥1), Texas (11.87 

Mm¥1), and outside the modeling 

domain (12.27 Mm¥1). 

In 2018, Texas, Mexico and sources 

outside the modeling domain are 

projected to continue to contribute the 

most to visibility impairment at Big 

Bend. The 2018 projection shows the 

total extinction at Big Bend for the worst 

20% days is estimated to be 44.06 

Mm¥1, a reduction of approximately 

8% from 2002 levels. Anticipated 

reductions of SO2 emissions primarily 

from point sources in Texas, the Eastern 

United States, Indiana, Illinois, Kansas, 

Alabama and Ohio will account for a 

decrease of 2.73 Mm¥1 in total light 

extinction (1.55 Mm¥1 decrease from 

Texas point sources). Even with these 

expected reductions in SO2 emissions 

from point sources in 2018, extinction 

due to point sources will continue to be 

the highest contributor to visibility 

impairment on the worst 20% days, 

accounting for over one third of the total 

extinction. Visibility impairment from 

all Texas sources will decrease by 1.90 

Mm¥1, primarily due to expected 

reductions from point sources. 

TABLE 21—PROJECTED LIGHT EXTINCTION FOR 20% WORST DAYS AT BIG BEND WILDERNESS AREA IN 2002 (MM¥1) 

Total 1 Point Natural On-road Non-road Area 

SO4 ........................................................... 26.10 17.70 0.02 0.28 0.45 1.82 

NO3 .......................................................... 2.05 0.55 0.33 0.36 0.23 0.30 

POA .......................................................... 5.81 0.10 0.08 0.04 0.09 0.83 

EC ............................................................ 2.12 0.01 0.03 0.10 0.32 0.45 

SOIL ......................................................... 2.54 0.28 1.14 0.01 0.00 1.00 

CM ............................................................ 7.03 0.02 5.52 0.00 0.07 1.23 

Sum ................................................... 47.79 18.66 7.12 0.80 1.16 5.63 

1Totals include contributions from boundary conditions and secondary organic matter but exclude contribution from Rayleigh scattering. 

TABLE 22—PROJECTED LIGHT EXTINCTION FOR 20% WORST DAYS AT BIG BEND WILDERNESS AREA IN 2018 (MM¥1) 

Total 1 Point Natural On-road Non-road Area 

SO4 ........................................................... 23.00 15.15 0.01 0.04 0.20 1.84 

NO3 .......................................................... 1.99 0.63 0.38 0.12 0.16 0.35 

POA .......................................................... 5.61 0.14 0.06 0.02 0.08 0.67 

EC ............................................................ 1.81 0.02 0.02 0.02 0.23 0.29 

SOIL ......................................................... 2.54 0.32 1.13 0.01 0.00 0.97 

CM ............................................................ 7.03 0.02 5.42 0.00 0.07 1.33 

Sum ................................................... 44.06 16.27 7.03 0.20 0.74 5.46 

1Totals include contributions from boundary conditions and secondary organic matter but exclude contribution from Rayleigh scattering. 

e. Sources of Visibility Impairment in 

Guadalupe Mountains National Park 

Tables 23 and 24 summarize the 

contributions to total extinction at 

Guadalupe Mountains for each source 

category and species for 2002 and 2018, 

respectively. Visibility impairment at 

Guadalupe Mountains in 2002 on the 

worst 20% days is largely due to SO4

from point sources and course material 

from natural and area sources. The 

largest contributions of SO4 come from 

Texas (4.28 Mm¥1 from all source 

categories), boundary conditions outside 

the modeling domain (1.90 Mm¥1) and 

Mexico (3.21 Mm¥1). Overall, the 

largest source region contributions to 

visibility impairment in 2002 are from 

Texas (16.62 Mm¥1), New Mexico (3.49 

Mm¥1), Mexico (7.90 Mm¥1), and 

source outside the modeling domain 

(4.16 Mm¥1). 

In 2018, sulfate and course material 

from Texas, Mexico, New Mexico and 

sources outside the modeling domain 

are projected to continue to contribute 

the most to visibility impairment at the 

Guadalupe Mountains. The 2018 

projection shows the total extinction at 

the Guadalupe Mountains for the worst 

20% days is estimated to be 44.32 

Mm¥1, a reduction of approximately 

7% from 2002 levels. Anticipated 

reductions of SO2 emissions primarily 

from point sources in Texas, the Eastern 

United States, Indiana, Alabama and 

Ohio will account for a decrease of 2.02 

Mm¥1 in total light extinction (0.68 

Mm¥1 decrease from Texas point 

sources). Even with these expected 

reductions in SO2 emissions from point 

sources in 2018, extinction due to point 

sources will still be a significant 

contributor to visibility impairment on 

the worst 20% days, accounting for over 

one fourth of the total extinction. 

Visibility impairment from all Texas 

sources will decrease by 1.29 Mm¥1, 

primarily due to expected reductions 

from point sources. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74860 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

266See Appendix E of the Technical Support 

Document for CENRAP Emissions and Air Quality 

Modeling to Support Regional Haze SIP, included as Appendix 8–1 of the Texas Regional Haze SIP 

for PSAT modeling results. 

TABLE 23—PROJECTED LIGHT EXTINCTION FOR 20% WORST DAYS AT GUADALUPE MOUNTAINS IN 2002 (MM¥1) 

Total 1 Point Natural On-road Non-road Area 

SO4 ........................................................... 15.94 12.10 0.02 0.22 0.33 1.36 

NO3 .......................................................... 3.67 1.09 0.40 0.79 0.55 0.52 

POA .......................................................... 2.75 0.24 0.19 0.10 0.16 1.61 

EC ............................................................ 1.19 0.01 0.04 0.15 0.34 0.51 

SOIL ......................................................... 4.37 0.41 1.29 0.02 0.00 2.41 

CM ............................................................ 16.04 0.19 7.75 0.02 0.39 6.60 

Sum ................................................... 47.80 14.05 9.68 1.31 1.76 13.00 

1Totals include contributions from boundary conditions and secondary organic matter but exclude contribution from Rayleigh scattering. 

TABLE 24—PROJECTED LIGHT EXTINCTION FOR 20% WORST DAYS AT UPPER GUADALUPE MOUNTAINS IN 2018 (MM¥1) 

Total 1 Point Natural On-road Non-road Area 

SO4 ........................................................... 13.65 10.11 0.02 0.03 0.10 1.40 

NO3 .......................................................... 3.32 1.18 0.44 0.27 0.37 0.65 

POA .......................................................... 2.38 0.29 0.15 0.05 0.13 1.30 

EC ............................................................ 0.86 0.02 0.04 0.04 0.23 0.37 

SOIL ......................................................... 4.37 0.51 1.29 0.02 0.00 2.31 

CM ............................................................ 16.02 0.20 7.69 0.03 0.38 6.65 

Sum ................................................... 44.32 12.31 9.62 0.43 1.22 12.68 

1Totals include contributions from boundary conditions and secondary organic matter but exclude contribution from Rayleigh scattering. 

f. Texas’ Contribution to Visibility 

Impairment in Class I Areas Outside the 

State 

CAMx PSAT results were also utilized 

to evaluate the impact of Texas emission 

sources in 2002 and 2018 on visibility 

impairment at Class I areas outside of 

the state. Texas sources are modeled to 

have contributions to the Class I areas 

in a number of nearby states. Tables 25 

and 26 summarize the contribution from 

Texas emissions of sulfate, nitrate and 

total visibility degradation at nearby 

states’ Class I areas for the 20% worst 

days in 2002 and 2018, as modeled by 

CENRAP and shown in Section 11.2 of 

the Texas regional haze SIP.266 The 

contributions from Texas sources on 

total visibility impairment decreases 

from 2002 to 2018 at all impacted Class 

I areas shown in the tables below. 

Texas’ impacts on other Class I areas in 

these nearby states are less than the 

impacts for the areas that are shown in 

the tables below for each state. 

TABLE 25—CONTRIBUTION FROM TEXAS EMISSIONS TO VISIBILITY IMPAIRMENT (MM¥1) AT CLASS I AREAS ON 20% 

WORST DAYS IN 2002 

Class I area State 

Sulfate Nitrate Total 

Texas Total, all 

source areas Texas Total, all source areas Texas Total, all source areas 

Salt Creek ............. New Mexico .......... 4.79 16.75 3.05 11.15 13.41 52.50 

White Mountain ..... New Mexico .......... 2.78 10.51 0.53 3.05 7.40 32.91 

Wheeler Peak ....... New Mexico .......... 0.76 5.27 0.22 1.64 1.85 21.96 

Wichita Mountains Oklahoma ............. 13.98 49.12 7.89 23.72 28.15 100.03 

Great Sand Dunes Colorado ............... 0.66 5.84 0.02 1.94 1.25 27.88 

Rocky Mountains .. Colorado ............... 0.30 7.69 0.08 5.17 0.58 32.13 

Caney Creek ......... Arkansas ............... 11.55 87.05 1.49 13.78 14.89 133.93 

Upper Buffalo ........ Arkansas ............... 4.41 83.18 0.27 13.30 5.19 131.79 

Hercules-Glades ... Missouri ................ 3.48 87.94 2.56 17.91 6.59 140.05 

Mingo .................... Missouri ................ 0.69 102.52 1.18 27.24 2.01 159.83 

Breton .................... Louisiana .............. 3.55 96.83 0.15 8.29 4.20 123.99 

TABLE 26—CONTRIBUTION FROM TEXAS EMISSIONS (MM¥1) TO VISIBILITY IMPAIRMENT AT CLASS I AREAS ON 20% 

WORST DAYS IN 2018 

Class I area State 

Sulfate Nitrate Total 

Texas Total, all 

source areas Texas Total, all source areas Texas Total, all source areas 

Salt Creek ............. New Mexico .......... 3.50 13.75 2.43 9.81 10.24 46.67 

White Mountain ..... New Mexico .......... 2.37 8.92 0.47 2.68 6.22 29.80 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74861 

267 40 CFR 51.308(d)(3)(iii). 

TABLE 26—CONTRIBUTION FROM TEXAS EMISSIONS (MM¥1) TO VISIBILITY IMPAIRMENT AT CLASS I AREAS ON 20% 

WORST DAYS IN 2018—Continued 

Class I area State 

Sulfate Nitrate Total 

Texas Total, all 

source areas Texas Total, all source areas Texas Total, all source areas 

Wheeler Peak ....... New Mexico .......... 0.79 5.00 0.19 1.48 1.59 20.80 

Wichita Mountains Oklahoma ............. 9.68 33.33 6.08 18.10 20.79 75.56 

Great Sand Dunes Colorado ............... 0.65 5.32 0.02 1.83 1.11 26.77 

Rocky Mountains .. Colorado ............... 0.30 6.52 0.06 4.28 0.51 29.41 

Caney Creek ......... Arkansas ............... 7.24 48.95 0.83 7.57 9.74 85.84 

Upper Buffalo ........ Arkansas ............... 2.74 45.38 0.18 9.22 3.38 86.16 

Hercules-Glades ... Missouri ................ 2.51 50.63 1.51 12.35 4.45 92.49 

Mingo .................... Missouri ................ 0.53 54.45 0.64 19.14 1.28 99.24 

Breton .................... Louisiana .............. 2.66 68.63 0.16 8.20 3.23 94.06 

We propose to find that the TCEQ’s 

2002 and 2018 emission inventories are 

acceptable and that Texas has satisfied 

the requirement of Section 

51.308(D)(3)(iv) regarding identifying all 

anthropogenic sources of visibility 

impairment considered by it in 

developing its long-term strategy, and 

that it considered major and minor 

stationary sources, mobile sources, and 

area sources. 

However, as we discuss in Section 

IV.C., given the plain language of the 

CAA, we believe Section 

51.308(d)(3)(iii) requires states to 

consider the four factors used in 

determining reasonable progress in 

developing the technical basis for both 

their own Class I areas and downwind 

Class I areas. This documentation is 

necessary so that the interstate 

consultation process can proceed on an 

informed basis, and so that downwind 

states can properly assess whether any 

additional upwind emission reductions 

are necessary to achieve reasonable 

progress at their Class I areas. Therefore, 

in determining its long-term strategy 

under Section 51.308(d)(3)(iii), we 

believe that Texas had an obligation to 

conduct an appropriate technical 

analysis, and demonstrate through that 

technical analysis (required under 

(d)(3)(ii)), that it provided its fair share 

of emission reductions to Oklahoma. In 

addition, we believe that Texas was 

required through consultation under 

Section 51.308(d)(3)(i) to provide a 

reasoned technical analysis, on which it 

based its long-term strategy, to 

Oklahoma. The regulations further 

provide that: 

The State must document the technical 

basis, including modeling, monitoring and 

emissions information, on which the State is 

relying to determine its apportionment of 

emission reduction obligations necessary for 

achieving reasonable progress in each 

mandatory Class I Federal area it affects. 

States may meet this requirement by relying 

on technical analyses developed by the 

regional planning organization and approved 

by all State participants.267

Thus, states may meet this 

requirement by relying on reasonable 

progress four-factor analyses and 

associated technical documentation 

prepared by a regional planning 

organization on behalf of its member 

states, to the extent that such analyses 

and documentation were conducted. If 

the technical analysis performed by the 

regional planning organization was 

missing, flawed, or incomplete, it could 

not be solely relied upon by a state 

when developing or documenting the 

technical basis of its long-term strategy. 

The technical data prepared through the 

regional planning organization process 

is typically designed to inform the 

member states of their apportionment of 

the visibility impact at Class I areas, 

project future visibility conditions, and 

to provide high-level information on 

potential control strategies to inform 

consultations and the four-factor 

analysis necessary to establish RPGs. 

These analyses may require additional 

refinements by the states in 

development of their regional haze SIPs 

to address impacts and potential 

controls of specific sources or source 

categories. As we discuss in Sections 

V.C., and V.E.2, the TCEQ recognized 

that some aspects of CENRAP’s 

technical analyses were limited because 

it supplemented that analysis with its 

own. It used this analysis to inform its 

decision not to control any additional 

sources, including those that impact the 

visibility at the Wichita Mountains and 

other Class I areas in other states. For 

the reasons discussed at length in 

Section V.C.2, we believe this analysis 

was inadequate and did not provide the 

information necessary to determine the 

reasonableness of controls at those 

sources in Texas that significantly 

impact visibility at the Wichita 

Mountains or other Class I areas. Based 

on CENRAP data and information 

shared during consultations, included 

in the record, the ODEQ and the TCEQ 

had evidence of some potential controls 

at certain EGUs in Northeast Texas that 

were estimated to be cost-effective even 

according to the TCEQ’s own cost 

threshold and would result in large 

emission reductions within the source 

type and region with the largest 

projected impacts at Wichita Mountains. 

The ODEQ and the TCEQ were also 

aware of additional large emission 

sources in Texas that should have been 

further evaluated for potential controls. 

Although both the ODEQ and the TCEQ 

had abundant evidence that Texas coal 

fired EGUs had a significant impact on 

the visibility at Oklahoma and Texas 

Class I areas, the development of this 

technical information by either party 

did not progress to the point where the 

impacts of individual sources could be 

determined or to the point where the 

information on cost-effective controls 

identified for some sources could be 

refined from a high level state. 

Consequently, we propose to find that 

Texas did not adequately address the 

requirements in Section 51.308(d)(3)(iii) 

to ‘‘document the technical basis, 

including modeling, monitoring and 

emissions information, on which the 

state is relying to determine its 

apportionment of emission reduction 

obligations necessary for achieving 

reasonable progress in each mandatory 

Class I Federal area it affects.’’ 

To determine whether additional 

controls were reasonable in Texas, we 

believed it necessary to undertake a 

cost/control and visibility analysis 

which is presented in our FIP TSD. In 

the FIP TSD, we provide detailed 

information concerning which sources 

within Texas are the largest contributors 

to the visibility degradation at the 

Wichita Mountains and at other Class I 

areas, and which sources we believe 

have cost-effective controls. For more 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74862 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

268Approved into the SIP on January 18, 1994, at 

59 FR 02532. 

information on our proposed FIP, please 

see section VII. 

4. Texas’ Consideration of the LongTerm Strategy Factors 

As required by Section 

51.308(d)(3)(v), Texas must consider, at 

a minimum, the following factors in 

developing its long-term strategy: 

(A) Emission reductions due to 

ongoing air pollution control programs, 

including measures to address RAVI; 

(B) Measures to mitigate the impacts 

of construction activities; 

(C) Emissions limitations and 

schedules for compliance to achieve the 

reasonable progress goal; 

(D) Source retirement and 

replacement schedules; 

(E) Smoke management techniques for 

agricultural and forestry management 

purposes including plans as currently 

exist within the state for these purposes; 

(F) Enforceability of emissions 

limitations and control measures; and 

(G) The anticipated net effect on 

visibility due to projected changes in 

point, area, and mobile source 

emissions over the period addressed by 

the long-term strategy. 

Texas’ long-term strategy incorporates 

emission reductions due to a number of 

ongoing air pollution control programs. 

This includes enforceable emissions 

limitations, compliance schedules, 

administrative orders, the issuance and 

enforcement of permits limiting 

emissions from all known major sources 

in Texas, state rules which specifically 

limit targeted emissions sources and 

categories, and several other ongoing air 

pollution control programs. The TCEQ 

has promulgated rules in order to 

administer these programs. These rules 

govern the TCEQ’s permitting process, 

including PSD and BACT requirements, 

and implementation of federal 

requirements. The TCEQ also has 

promulgated rules that limit emissions 

in order to comply with the NAAQS, 

which have ancillary benefits of 

visibility improvements. Other air 

pollution control programs, including 

federal mobile emissions programs, the 

Clean Air Interstate Rule, Maximum 

Achievable Control Technology, and 

Refinery Consent Decrees are 

implemented by TCEQ, have similar 

ancillary benefits of visibility 

improvements. 

Below we assess how the TCEQ 

addressed the long-term strategy factors 

in 40 CFR 51.308(d)(3)(v)(A)-(G). Please 

see our TX TSD for more information on 

how the TCEQ has addressed these 

factors. 

a. Reductions Due to Ongoing Air 

Pollution Programs 

The Texas long-term strategy 

incorporates emission reductions due to 

a number of ongoing air pollution 

control programs, which are 

summarized below. 

• The TCEQ implements CAIR. 

• The TCEQ implements a number of 

federal and state rules related to mobile 

source emissions. 

• The TCEQ implements some major 

point sources NOX rules, including 

Texas Senate Bill 7, which required 

emission reductions at EGUs built 

before Texas BACT emission control 

requirements went into effect in 1972, 

and NOX emission reductions related to 

ozone SIP revisions for the HoustonGalveston-Brazoria area, Beaumont-Port 

Arthur area, Austin, Northeast Texas, 

and East Texas. 

• A number of miscellaneous 

programs including SO2 reductions 

under our refinery consent decrees; the 

Texas Low Emissions Diesel Program; 

the Texas Emission Reduction Plan to 

reduce NOX and PM emissions by 

encouraging older road and non-road 

engine replacement; rules to control 

opacity and sulfur emissions, such as 30 

TAC Chapters 111 and 112; and BACT. 

The TCEQ states that the federal land 

managers for Big Bend and the 

Guadalupe Mountains, or other Class I 

areas that are impacted by emissions 

from Texas sources, have not identified 

any RAVI caused by Texas sources. 

Consequently, Texas does not have any 

measures in place or a requirement to 

implement RAVI. We propose that 

Texas has satisfied this requirement. 

b. Measures To Mitigate the Impacts of 

Construction Activities 

Section 51.308(d)(3)(v)(B) requires 

that Texas consider measures to mitigate 

the impacts of construction activities in 

developing its long-term strategy. The 

TCEQ notes that state Rule 30 TAC 

111.145, Construction and Demolition, 

requires precautions to control dust 

emissions from construction operations 

and other activities.268 It also notes that 

water pollution control requirements to 

prevent pollution from storm runoff and 

mud and dirt tracked from construction 

sites reduces the amount of fine soil 

material suspended in the air from 

traffic in these areas. The TCEQ 

determined that no additional measures 

were needed to mitigate the impacts of 

construction activities for purposes of 

visibility improvement, and we agree 

with this determination. We propose 

that Texas has satisfied this 

requirement. 

c. Emissions Limitations and Schedules 

for Compliance 

Section 51.308(d)(3)(v)(C) requires 

that in developing its long-term strategy, 

Texas consider emissions limitations 

and schedules of compliance to achieve 

the RPGs. No newly adopted source 

specific measures were identified to 

achieve the RPGs established by Texas. 

The TCEQ determined that 

implementation of existing and ongoing 

control measures are adequate to 

achieve the RPGs established by it and 

other CENRAP states. We propose to 

find that Texas has not satisfied this 

requirement, regarding emissions 

limitations and schedules for 

compliance to achieve the RPGs for Big 

Bend and the Guadalupe Mountains. 

Please see the technical discussion we 

present in Section V.C regarding the 

development of the Texas RPGs, as the 

TCEQ applied the same technical basis 

to the development of its long-term 

strategy. As with its RPGs, we propose 

to find this analysis is inadequate as it 

does not provide the information 

necessary to determine the 

reasonableness of controls at those 

sources in Texas that significantly 

impact visibility at the Wichita 

Mountains. 

d. Source Retirement and Replacement 

Schedules 

Section 51.308(d)(3)(v)(D) requires 

that Texas consider source retirement 

and replacement schedules in 

developing its long-term strategy. 

Retirement and replacement schedules 

were taken into account, to the extent 

possible, when developing inputs for 

the IPM that was used in the CENRAP 

modeling analysis. Units that the TCEQ 

knew were going to be shut down under 

enforceable actions at the time the 

modeling was performed were removed 

from the future year emission inventory. 

We propose that Texas has satisfied this 

requirement. 

e. Smoke Management Techniques 

Section 51.308(d)(3)(v)(E) requires 

that Texas consider smoke management 

techniques for agricultural and forestry 

management purposes in developing its 

long-term strategy. The TCEQ examined 

the data and modeling for the worst 

20% days at Big Bend and the 

Guadalupe Mountains and determined 

that smoke from agricultural burning 

and wildfires in Texas are not a large 

contributor to visibility impairment at 

these Class I areas. The TCEQ also 

determined that agricultural burning 

and wildfires in Texas are not 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74863 

269Approved into the SIP on April 28, 2009, at 

74 FR 19144. 

significant contributors to visibility 

impairment at Class I areas in nearby 

states. Because of the relatively low 

contribution of smoke from Texas to 

visibility impairment, Texas decided 

that certifying a smoke management 

plan as part of this SIP revision was 

unnecessary. The Texas Forest Service 

(TFS) coordinates fire and smoke 

management issues in Texas and has 

developed a voluntary plan under 

which all land managers in Texas, 

including the National Park Service, 

inform the TFS prior to performing 

prescribed burns. Texas also has an 

outdoor burning rule (30 TAC Chapter 

111, subchapter B) 269 that includes 

requirements for allowable prescribed 

burning. Texas counties also have the 

authority to prohibit open burning in 

times of drought. The TCEQ found that 

the current rules, policies, and plans 

(including smoke management plans of 

the NPS and other federal agencies) are 

adequate to meet the long-term strategy. 

We agree and propose that Texas has 

satisfied this requirement. 

f. Enforceability of emissions 

Limitations and Control Measures 

Section 51.308(d)(3)(v)(F) requires 

that Texas ensure the enforceability of 

emission limitations and control 

measures used to meet RPGs. The TCEQ 

has rules in place to ensure the 

enforceability of its emission 

limitations. This includes rules that 

govern TCEQ’s permitting process for 

major and minor sources, Prevention of 

Significant Deterioration (PSD) 

provisions, and BACT. The TCEQ has 

the authority to issue permits to all 

major and minor point sources in Texas, 

as they are currently defined at 30 TAC 

Ch. 116. Each permit must contain 

enforceable limitations on emissions of 

various defined pollutants, including 

those which cause or contribute to 

regional haze at the Texas Class I areas 

and Class I areas in other states. The 

TCEQ included information describing 

their legal authority and applicable laws 

in the submitted Texas regional haze 

SIP following the executive summary. 

We propose that Texas has satisfied this 

requirement. 

g. The Anticipated Net Effect on 

Visibility Due to Projected Changes in 

Emissions 

Section 51.308(d)(3)(v)(G) requires 

that in developing its long-term strategy, 

Texas consider the anticipated net effect 

on visibility due to projected changes in 

point, area, and mobile source 

emissions over the period addressed by 

the long-term strategy. In developing its 

regional haze SIP, the TCEQ relied on 

the CENRAP’s 2018 modeling 

projections. As described above, 

CENRAP used its 2002 emissions 

inventory as the starting point for its 

2018 emissions inventory. The 2018 

emissions inventory was designed to 

capture the anticipated changes in 

point, area, and mobile sources 

emissions over the period addressed by 

the long-term strategy. As we discuss in 

Section V.G, we propose to approve the 

TCEQ’s obligation to develop a 

statewide inventory of emissions, 

including future projected emissions. 

We believe that these projected changes 

in emissions were adequately 

implemented in CENRAP’s 2018 

modeling, and therefore propose to 

approve Texas’ submission under 

Section 51.308(d)(3)(v)(G). 

F. Coordination of RAVI and Regional 

Haze Requirements 

Under Section 51.308(d)(4), states are 

required to coordinate their RAVI longterm strategy and monitoring provisions 

with those for RH. Under our RAVI 

regulations, the RAVI portion of a state 

SIP must address any integral vistas 

identified by the federal land managers 

pursuant to 40 CFR 51.304. See 40 CFR 

51.302. An integral vista is defined in 40 

CFR 51.301 as a ‘‘view perceived from 

within the mandatory Class I Federal 

area of a specific landmark or panorama 

located outside the boundary of the 

mandatory Class I Federal area.’’ 

Visibility in any mandatory Class I area 

includes any integral vista associated 

with that area. The federal land 

managers for Big Bend and the 

Guadalupe Mountains have not 

identified any RAVI from Texas or other 

state sources. Also, the federal land 

managers for the Class I areas that 

Texas’ emissions impact in other states 

have not identified any RAVI caused by 

Texas sources. For these reasons, the 

TCEQ does not have any measures in 

place or a requirement to address RAVI. 

Thus, we propose to find that the Texas 

regional haze SIP has satisfied Section 

51.308(d)(4). We discuss the relevant 

monitoring provisions in the section 

that follows. 

G. Monitoring Strategy and Other SIP 

Requirements 

Section 51.308(d)(4) requires the SIP 

contain a monitoring strategy for 

measuring, characterizing, and reporting 

of regional haze visibility impairment 

that is representative of all mandatory 

Class I areas within the state. This 

monitoring strategy must be coordinated 

with the monitoring strategy required in 

Section 51.305 for RAVI. As Section 

51.308(d)(4) notes, compliance with this 

requirement may be met through 

participation in the IMPROVE network. 

Since the monitors used for the 

Guadalupe Mountains and Big Bend are 

IMPROVE monitors, we propose that the 

TCEQ has satisfied this requirement. 

Section 51.308(d)(4)(i) requires the 

establishment of any additional 

monitoring sites or equipment needed to 

assess whether RPGs to address regional 

haze for all mandatory Class I areas 

within the state are being achieved. We 

do not believe that additional 

monitoring, beyond the IMPROVE 

network monitors that are already in 

place, is necessary in order to assess 

Texas’ RPGs, and are therefore 

proposing to find that Texas has 

satisfied this requirement. 

Section 51.308(d)(4)(ii) requires that 

the TCEQ establish procedures by 

which monitoring data and other 

information are used in determining the 

contribution of emissions from within 

Texas to regional haze visibility 

impairment at mandatory Class I areas 

both within and outside the state. The 

monitors at Big Bend and the Guadalupe 

Mountains are operated through the 

IMPROVE monitoring program, which is 

national in scope, and other states have 

similar monitoring and data reporting 

procedures, ensuring a consistent and 

robust monitoring data collection 

system. As Section 51.308(d)(4) 

indicates, participation in the IMPROVE 

program constitutes compliance with 

this requirement. We are therefore 

proposing that the TCEQ has satisfied 

this requirement. 

Section 51.308(d)(4)(iv) requires that 

the SIP must provide for the reporting 

of all visibility monitoring data to the 

Administrator at least annually for each 

mandatory Class I area in the state. To 

the extent possible, Texas should report 

visibility monitoring data electronically. 

Section 51.308(d)(4)(vi) also requires 

that the TCEQ provide for other 

elements, including reporting, 

recordkeeping, and other measures, 

necessary to assess and report on 

visibility. We believe that Texas’ 

participation in the IMPROVE network 

ensures the monitoring data is reported 

at least annually and is easily 

accessible, and therefore we are 

therefore proposing to find that the 

TCEQ has satisfied this requirement. 

Section 51.308(d)(4)(v) requires that 

the TCEQ maintain a statewide 

inventory of emissions of pollutants that 

are reasonably anticipated to cause or 

contribute to visibility impairment in 

any mandatory Class I area. The 

inventory must include emissions for a 

baseline year, emissions for the most 

recent year for which data are available, 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74864 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

270Final action: 76 FR 81728 (December 28, 

2011). Proposal: 76 FR 16188 (March 22, 2011). 

271Approval of OK’s partial replacement for FIP: 

79 FR 12944 (March 7, 2014). Partial FIP 

withdrawal: 79 FR 12954 (March 7, 2014). 

272 76 FR 16177 (Mar. 22, 2011). 

273The TSD for CENRAP Emissions and Air 

Quality Modeling to Support Regional Haze State 

and estimates of future projected 

emissions. Texas must also include a 

commitment to update the inventory 

periodically. TCEQ provides a summary 

of the 2005 emission inventory in 

Appendix 7–1 of the Texas Regional 

Haze SIP. We discuss our review of the 

TCEQ’s 2002 and 2018 emission 

inventories above in Section V.E.3. The 

TCEQ has stated that it intends to 

update the Texas statewide emissions 

inventories periodically. We propose 

that this satisfies the requirement in 

Section 51.308(d)(4)(v). 

H. Federal Land Manager Consultation 

Both Big Bend and the Guadalupe 

Mountains are federally protected 

national parks for which the United 

States Department of the Interior, 

National Park Service is the FLM. 

Although the federal land managers are 

very active in participating in the 

regional planning organizations, the 

Regional Haze Rule grants the federal 

land managers a special role in the 

review of the regional haze SIPs. We 

view both the federal land managers and 

the state environmental agencies as our 

partners in the regional haze process. 

Section 51.308(i)(1) requires that by 

November 29, 1999, Texas must have 

identified in writing to the federal land 

managers the title of the official to 

which the federal land managers of Big 

Bend and the Guadalupe Mountains can 

submit any recommendations on the 

implementation of Section 51.308. We 

acknowledge that this section has been 

satisfied by all states via their 

communications with the federal land 

managers prior to this SIP action. 

Under Section 51.308(i)(2), Texas was 

obligated to provide the Park Service 

with an opportunity for consultation, in 

person and at least 60 days prior to 

holding a public hearing on its regional 

haze SIP. In practice, state 

environmental agencies have usually 

provided all federal land managers—the 

Forest Service, the Park Service, and the 

Fish and Wildlife Service, copies of 

their regional haze SIP, as the federal 

land managers collectively have 

reviewed these regional haze SIPs. The 

TCEQ followed this practice and sent its 

draft of this implementation plan 

revision to the federal land manager 

staff. The federal land managers were 

provided a comment period of from 

November 16, 2007, through January 16, 

2008. Their comments were provided to 

the public 30 days prior to the public 

hearing, which the federal land 

managers were notified of, and which 

occurred on February 19, 2008. 

Section 51.308(i)(3) requires that the 

TCEQ provide in its regional haze SIP 

a description of how it addressed any 

comments provided by the federal land 

managers. The TCEQ has provided that 

information in Appendix 2–2 of its 

regional haze SIP. 

Lastly, Section 51.308(i)(4) specifies 

the regional haze SIP must provide 

procedures for continuing consultation 

between the state and federal land 

managers on the implementation of the 

visibility protection program required 

by Section 51.308, including 

development and review of 

implementation plan revisions and 5- 

year progress reports, and on the 

implementation of other programs 

having the potential to contribute to 

impairment of visibility in the 

mandatory Class I areas. The TCEQ has 

acknowledged this requirement in its 

regional haze SIP. We are therefore 

proposing to find that the TCEQ has 

satisfied Section 51.308(i). 

I. Periodic SIP Revisions and Five-Year 

Progress Reports 

The TCEQ affirmed its commitment to 

complete certain items required in the 

future under our Regional Haze Rule. It 

acknowledged its requirement under 

Section 51.308(f), to revise and submit 

its regional haze SIP revision to us by 

July 31, 2018 and every ten years 

thereafter. It also acknowledged its 

requirement under Section 51.308(g), to 

submit a progress report in the form of 

a SIP revision every five years following 

this initial submittal of the Texas 

regional haze SIP. The TCEQ submitted 

the first five-year report in March 2014. 

We are not including our analysis of this 

SIP revision within this proposed 

action. 

J. Future Determination of the Adequacy 

of the Existing Implementation Plan 

Section 51.308(h) requires that Texas 

take one of the listed actions, as 

appropriate, at the same time it is 

required to submit any 5-year progress 

report to us in accordance with Section 

51.308(g). The TCEQ has committed in 

its SIP to take one of the actions listed 

under 51.308(h), depending on the 

findings of the five-year progress report. 

VI. Our Analysis of and Proposed 

Action on the Remaining Parts of the 

Oklahoma Regional Haze SIP 

A. Previous Rulemakings on the 

Oklahoma Regional Haze SIP 

In a previous rulemaking, we partially 

approved and partially disapproved 

portions of the Oklahoma regional haze 

SIP.270 We approved certain elements of 

the Oklahoma regional haze SIP, as 

follows: Identification of sources that 

are BART eligible and subject to BART; 

its determination of baseline and natural 

visibility conditions; its coordination of 

regional haze and RAVI; monitoring 

strategy and other implementation 

requirements; its coordination with 

states and federal land managers; and a 

number of the state’s NOX, SO2, and PM 

BART determinations. We disapproved 

Oklahoma’s submitted SO2 BART 

determinations for Units 4 and 5 of the 

OG&E Muskogee plant; Units 1 and 2 of 

the OG&E Sooner plant; and, Units 3 

and 4 of the AEP/PSO Northeastern 

plant. We also disapproved the longterm strategy in Oklahoma’s regional 

haze SIP because it did not include 

appropriate controls for these six 

sources. To remedy these deficiencies in 

the Oklahoma regional haze SIP, we 

concurrently promulgated a FIP that 

established SO2 BART emission limits 

for these six sources at three facilities in 

Oklahoma. We have subsequently 

withdrawn our FIP for two of the 

sources, following approval of 

Oklahoma’s SIP revision BART 

determinations for those two sources.271

We did not take action on whether 

Oklahoma satisfied the reasonable 

progress requirements of Section 

51.308(d)(1) in our earlier action. In that 

proposed action, we stated that to 

properly assess whether Oklahoma had 

satisfied these requirements, we must 

first evaluate and act upon the regional 

haze SIP revision submitted by the State 

of Texas.272 Our proposed action here, 

insomuch as it concerns Oklahoma’s 

obligations, is limited to our review of 

Oklahoma’s submission under Section 

51.308(d)(1). 

B. Evaluation of Oklahoma’s 

Reasonable Progress Goals 

As required by Section 51.308(d)(1) of 

the Regional Haze Rule, the ODEQ has 

established RPGs for its Class I area, the 

Wichita Mountains. These RPGs must 

provide for an improvement in visibility 

for the most impaired days over the 

period of the implementation plan and 

ensure no degradation in visibility for 

the least impaired days over the same 

period. 

1. Establishment of the Reasonable 

Progress Goals 

The RPGs established by ODEQ for 

the Wichita Mountains are derived from 

the CENRAP modeling of visibility 

conditions in 2018.273 The CENRAP 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74865 

Implementation is found in Appendix 4–2 of the 

Oklahoma Regional Haze SIP. 

274 76 FR 81728 (Dec. 28, 2011). 

275 79 FR 12944 (March 7, 2014). 

276 79 FR 12954 (March 7, 2014). 

277Section 51.308(d)(1)(iv). 278Copies of agendas and presentation materials 

are available in the docket for this action and at 

http://www.deq.state.ok.us/AQDnew/

rulesandplanning/Regional_Haze/SIP/

Consultation/index.htm. 

279These calls were recorded, referenced in OK’s 

regional haze SIP, and placed on ODEQ’s Web site. 

280Copies of these letters can be found in 

Appendix 10–1 of the Oklahoma regional haze SIP. 

modeling reflects emission reductions 

programs already in place from the 

implementation of the federal CAA and 

Oklahoma CAA, estimated reductions 

from the Oklahoma BART rule, and the 

estimated emission reductions 

identified in the long-term strategies of 

Oklahoma, Texas and other nearby 

states. The ODEQ adopted the results of 

the CENRAP modeling as the RPGs for 

the Oklahoma Class I area based on the 

results of its reasonable progress 

analysis and additional information 

developed by CENRAP or obtained 

through direct consultations with those 

states anticipated to impact visibility at 

Wichita Mountains. 

The ODEQ established a RPG of 21.47 

dv for the Wichita Mountains for 2018 

for the 20% worst days. This represents 

a 2.3 dv improvement in visibility over 

a baseline of 23.81 dv of visibility 

impairment. Based on the rate of 

progress represented by this RPG for the 

first planning period, the ODEQ 

calculated that the Wichita Mountains 

would attain natural visibility 

conditions in 2102. The ODEQ’s RPG for 

the 20% worst days is shown below, 

which is adapted from Tables IX–3 and 

IX–4 and Figure IX–1 of the Oklahoma 

Regional Haze SIP. 

TABLE 27—OKLAHOMA’S REASONABLE PROGRESS GOAL FOR THE 20% WORST DAYS

Class I area Baseline 

conditions 

Projected 

2018 visibility 

(RPG) 

Improvement 

projected by 

2018 using 

RPG 

Improvement 

by 2018 at 

URP 

Date natural 

visibility 

attained at 

RPG rate 

(dv) (dv) (dv) (dv) 

Wichita Mountains ................................................................ 23.81 21.47 2.33 3.80 2102 

ODEQ’s RPG for the 20% best days is 

shown below, which is adapted from 

Table IX–2 of the Oklahoma regional 

haze SIP. 

TABLE 28—OKLAHOMA’S REASONABLE PROGRESS GOAL FOR THE 20% BEST DAYS

Class I area 

Baseline 

conditions 

(dv) 

Projected 2018 

visibility (RPG) 

(dv) 

Improvement by 

2018 

(dv) 

Wichita Mountains ..................................................................................................... 9.78 9.23 0.55 

ODEQ’s RPGs for the Wichita 

Mountains are consistent with the 

minimum requirement of Section 

51.308(d)(1) that the RPGs provide for 

an improvement in visibility for the 

most impaired days over the period of 

the SIP and ensure no degradation in 

visibility for the least impaired days 

over the same period. For the reasons 

discussed below in more detail, 

however, we propose to disapprove 

Oklahoma’s RPGs for the Wichita 

Mountains. First, in our earlier action 

on the Oklahoma regional haze SIP, we 

disapproved the SO2 BART 

determinations for six EGUs at three 

power plants in Oklahoma and 

promulgated a FIP setting more 

stringent SO2 emission limits for these 

EGUs.274 Although we subsequently 

approved a SIP revision from Oklahoma 

addressing the BART requirements for 

two EGUs at one power plant,275 and 

removed the FIP requirements for this 

facility,276 our FIP and the revised 

Oklahoma SIP require greater reductions 

overall in emissions of SO2 than was 

assumed in setting the RPGs for the 

Wichita Mountains. Second, we are 

proposing to disapprove Oklahoma’s 

RPGs for the Wichita Mountains 

because they were based on an 

incomplete consultation with Texas 

under 51.308(d) (1)(iv) that resulted in 

inadequate reasonable progress towards 

the national visibility goal. 

2. Reasonable Progress Consultation 

In developing the RPGs for its Class 

I area, Oklahoma was required to 

consult with those states which may 

reasonably be anticipated to cause or 

contribute to visibility impairment at 

the Wichita Mountains.277 In any 

situation in which Oklahoma could not 

agree with another such state or group 

of states that a goal provides for 

reasonable progress, Oklahoma was 

required to describe in its submittal the 

actions taken to resolve the 

disagreement. In reviewing Oklahoma’s 

SIP submittal, the Administrator takes 

this information into account in 

determining whether Oklahoma’s goal 

for visibility improvement provides for 

reasonable progress towards natural 

visibility conditions. 

The ODEQ identified several states 

that were projected through visibility 

modeling to contribute more than 1 

Mm¥1 of light extinction at the Wichita 

Mountains in 2018 and invited these 

states to consult. It conducted four 

consultations.278 It directed its first 

consultation to the tribal leaders in 

Oklahoma and their environmental 

managers, on August 14, 2007. The 

ODEQ held the next three consultations 

as conference calls with representatives 

from CENRAP, EPA, the U.S. Fish and 

Wildlife Service, Arkansas, Iowa, 

Kansas, Louisiana, Minnesota, Missouri, 

Nebraska, and Texas.279 The ODEQ 

received written responses from the 

Arkansas Department of Environmental 

Quality, the TCEQ, and the Missouri 

Department of Natural Resources.280

The ODEQ sent a letter to the Iowa 

Department of Natural Resources as a 

follow up to the consultation calls for 

the Wichita Mountains. Below is a 

summary of Oklahoma’s consultations. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74866 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

281A copy of the presentation containing the 

information discussed by ODEQ is available in the 

docket for this action and at: http://

www.deq.state.ok.us/AQDnew/rulesandplanning/

Regional_Haze/RegionalHazeStatesConsultation1_

081607.ppt. 

282A spreadsheet with the list of potential 

controls shared with the States is available in the 

docket for this action and at: http://

www.deq.state.ok.us/AQDnew/rulesandplanning/

Regional_Haze/RegionalHazeStatesConsultation1_

081607_ControlAssumptions.xls. 

For additional detail on Oklahoma’s 

consultation, see the OK TSD. 

For the first call with the states, held 

on August 16, 2007, the ODEQ 

discussed the current modeling results, 

comparing the projected visibility 

conditions in 2018 to the 2018 URP 

goal.281 The ODEQ identified that the 

Wichita Mountains is projected in the 

2108 CENRAP modeling to be 1.5 dv 

short of its 3.8 dv reduction needed to 

meet the URP. It also discussed the 

primary anticipated causes of regional 

haze for the Wichita Mountains in 2018, 

based on modeling and monitored data. 

According to the ODEQ, high SO2

concentrations at the Wichita 

Mountains reflect long range transport 

from Texas and the eastern two-thirds of 

United States. The ODEQ identified that 

point sources are the most significant 

contributors to haze at the Wichita 

Mountains based on the source 

apportionment results from the 

CENRAP modeling, with the largest 

contributing point sources being Texas 

EGUs. 

The ODEQ used the AOI data 

developed for the Alpine Geophysics 

report and considered the PSAT 

modeling results to identify areas, 

pollutants and source types that 

contribute to visibility impairment at 

the Wichita Mountains. The ODEQ 

identified that SO2 emissions that 

impact visibility conditions at the 

Wichita Mountains generally originate 

from the south and east. The ODEQ 

identified sources within the Area of 

Influence of the Wichita Mountains 

with a ratio of annual emissions of NOX

or SO2 to distance (Q/D) greater than 5 

based on 2018 projected emissions. The 

ODEQ then used the Alpine Geophysics 

report developed for CENRAP (as 

described in more detail in Section 

V.C.2 above) to identify estimates of the 

costs of installing retrofit controls for 

these sources. The ODEQ applied a 

maximum cost threshold of $5,000/ton 

to the list of potential controls to 

eliminate controls that it considered too 

costly from additional analysis. The 

remaining sources were listed in the 

charts provided to the participants in 

the consultation process.282 For these 

sources, the ODEQ requested that the 

participating states provide any 

available information or comments 

relative to which listed sources are 

BART sources, planned expansions or 

installation of controls, feasibility of 

controls, cost of controls, and any 

modeling conducted that would 

indicate the sources’ levels of impact on 

the Wichita Mountains. It stated that it 

was not yet requesting reductions, but 

was merely soliciting additional 

information. 

For the August 30, 2007 meeting, the 

ODEQ focused on the method used to 

calculate natural conditions at the 

Wichita Mountains. The ODEQ also 

reviewed and discussed information it 

had received following its request for 

information regarding the sources of 

interest that it had identified. ODEQ 

also noted that it had received 

information from Arkansas, Iowa, 

Kansas, Louisiana, and Nebraska after 

the first call but that it still needed 

information from Texas, Missouri, and 

Minnesota. Texas indicated that 

although it had contacted its EGUs, 

none had provided information as to 

how they intended to comply with 

CAIR. Texas stated that it had not 

received any enforceable commitments 

for controls from any of its EGUs. For 

other listed Texas sources, TCEQ said it 

was seeing significant decreases in 

emissions from controls or programs 

that were already in place. According to 

Texas, in general, growth assumptions 

for non-EGU Texas sources were wrong. 

Total emissions for Texas point sources, 

it claimed, were steadily declining in 

spite of great economic growth. 

Louisiana stated that one of its sources, 

Rhodia, was under a Consent Decree 

and reducing its emissions. Minnesota 

and Missouri also offered to provide 

some additional information to 

Oklahoma regarding their sources. 

For the third and final consultation 

meeting on September 25, 2007, the 

ODEQ again followed up on the 

information request regarding the 

sources of interest that it had identified. 

Texas stated that there were no changes 

to its EGUs projections since very few 

of its EGUs had committed to controls 

in order to meet CAIR. Texas again 

stated that Texas point source 2018 

projections were unrealistic and that 

Texas point source emissions have 

historically been dropping even when 

the state has been growing substantially 

economically. The ODEQ stated that 

SO2 is 60% of the particulate issue with 

most of it coming from Texas, 

Louisiana, and other states all the way 

out to the east coast. The ODEQ finished 

the consultation call with a statement 

that it was considering the information 

provided from consultation and was 

using it in drafting its regional haze SIP. 

During the consultation process, 

Arkansas notified the ODEQ that it 

disagreed that its sources contribute 

significantly to visibility impairment at 

the Wichita Mountains. Missouri 

similarly informed the ODEQ that it 

considered current controls on Missouri 

sources to be sufficient. Later, the ODEQ 

also concluded based on modeled 

projections that Iowa would not 

contribute to visibility impairment at 

the Wichita Mountains in 2018 and 

informed Iowa that additional 

reductions were no longer requested. 

During the consultation process, 

Oklahoma and Texas exchanged letters 

regarding the Wichita Mountains. On 

August 3, 2007, the ODEQ sent a letter 

to the TCEQ in which it noted that 

despite significant planned reductions 

in SO2 and NOX emissions from sources 

in Oklahoma and Texas, the Wichita 

Mountains was not projected to meet 

the URP. The ODEQ further noted that 

the analyses by CENRAP had made clear 

that the Wichita Mountains suffer from 

significant anthropogenic impacts from 

Texas. The ODEQ requested that the 

TCEQ require new and modified PSD 

sources to conduct analyses of their 

impacts on visibility at the Wichita 

Mountains and that the ODEQ be given 

an opportunity to review and comment 

on BACT determinations for proposed 

projects likely to have a certain impact 

on visibility at the Wichita Mountains. 

In addition, the ODEQ requested that 

the evaluations of visibility impacts be 

extended from within 100 km of the 

Wichita Mountains to within 300 km of 

the Wichita Mountains in deference to 

FLM guidance. On October 15, 2007, the 

TCEQ sent a response to the ODEQ, 

agreeing that modeling showed 

emissions from Texas to be a significant 

source of visibility impairment at the 

Wichita Mountains. The TCEQ also 

noted, however, that significant 

reductions from Texas will be realized 

in the next several years. In response to 

the ODEQ’s specific request for the 

opportunity to comment on BACT for 

new and modified major sources, the 

TCEQ stated that it welcomed comment 

during the public review and comment 

period and would notify federal land 

managers and the ODEQ if modeling 

were to indicate that a proposed source 

might significantly impact the Wichita 

Mountains. In response to the ODEQ’s 

request that impact evaluations be 

extended to 300 km, the TCEQ stated 

that it was working with federal land 

managers on mutually acceptable 

criteria for determining when a 

proposed PSD source should conduct a 

Class I area review and would inform 

ODEQ on the outcome of these 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74867 

discussions. In addition, the TCEQ 

attached its draft RPG analysis for its 

two Class I areas, which included 

analyses the TCEQ used to determine 

that there are no reasonable costs of 

installing additional controls beyond 

CAIR to address Texas impacts at Big 

Bend National Park and the Guadalupe 

Mountains. 

Several months after this initial 

exchange of letter, the two states again 

exchanged letters. On March 25, 2008, 

following comments made by us and the 

federal land managers on Texas’ draft 

regional haze SIP, the TCEQ sent a letter 

to the ODEQ regarding emissions that 

affect the Wichita Mountains. The TCEQ 

provided a copy of the PSAT modeling 

results developed by CENRAP 

indicating the contribution for each 

source area to visibility impairment at 

the Wichita Mountains. The TCEQ 

stated in the letter that PSAT modeling 

indicated that the probable impacts of 

Texas sources at the Wichita Mountains 

will be reduced by 2018 due to expected 

emission reductions from current and 

planned controls. A list of sources that 

are within the area of interest and have 

an emissions over distance ratio equal to 

or greater than five (Q/D ≥5) was 

included with the letter, along with 

information on projected emissions and 

distance to Wichita Mountains for those 

sources. The TCEQ then requested 

concurrence from Oklahoma on this 

assessment and a verification that 

Oklahoma was not depending on any 

additional reductions from Texas 

sources in order to meet RPG for the 

Wichita Mountains. On May 12, 2008, 

the ODEQ sent a response to the TCEQ 

in which it noted that it concurred with 

the information the TCEQ had provided. 

The ODEQ stated that it had developed 

its RPG for the worst 20% days for the 

Wichita Mountains through the 

CENRAP deliberations and that its RPG 

did not anticipate emission reductions 

beyond those that Texas already 

planned to implement and upon which 

CENRAP modeling studies have relied. 

The letter also states that reaching the 

Wichita Mountains’ RPG requires 

constraints on emissions from new, 

modified, and existing sources. The 

letter then recaps the ODEQ’s initial 

request made in its August 3, 2007 

consultation letter that all sources 

within 300 km conduct an analyses of 

the impacts to the Wichita Mountains 

and that it be given the opportunity to 

comment on BACT for proposed sources 

projected to significantly contribute to 

visibility impairment at the Wichita 

Mountains. 

We reviewed the information 

developed by ODEQ and the 

participating states during the 

consultation process, as well as the 

CENRAP source apportionment 

modeling results and additional data 

developed by CENRAP and Alpine 

Geophysics. We propose to agree with 

the following conclusions made by the 

ODEQ in its consultations: 

• With all the reductions anticipated 

to occur in the contributing states, the 

CENRAP modeling projects that the 

Wichita Mountains will fall short of 

meeting the URP goal for this planning 

period. 

• NOX and SO2 are the primary 

causes of haze at the Wichita 

Mountains, with SO2 as the 

predominant cause of visibility 

impairment at the Wichita Mountains in 

2002 and 2018. 

• For this planning period, it is 

reasonable to not require additional 

controls for NOX sources, as NOX is not 

the predominant cause of visibility 

impairment at the Wichita Mountains in 

2002 or 2018. 

• Texas is a significant contributor to 

the visibility impairment at the Wichita 

Mountains. 

• Point sources are the most 

significant contributors to haze at the 

Wichita Mountains, and the largest 

contributing point sources are Texas 

EGUs. 

• Texas point sources identified 

during consultation by Oklahoma and 

other large sources within the AOI of 

Wichita Mountains are excellent 

candidates for additional analysis for 

potential controls. 

• Control cost data developed by 

Alpine Geophysics, and shared by 

Oklahoma during consultations, 

indicated potential SO2 controls were 

available for those Texas sources 

discussed during consultations at an 

average cost of less than $2,000/ton, and 

that for all but two of those identified 

Texas sources, potential controls are 

below the $2,700/ton threshold 

established by Texas in its analysis and 

development of its LTS. More 

specifically, for the largest of the 

identified sources, Alpine Geophysics 

estimated the cost of SO2 controls at the 

two units at Big Brown to be 

approximately $1,500/ton. They also 

projected that these controls would 

achieve greater than 40,000 tpy in SO2

emission reductions. Alpine Geophysics 

estimated the cost of SO2 controls at two 

units at Monticello to be approximately 

$1,850/ton. They also projected that 

these controls would achieve greater 

than 35,000 tpy in SO2 emission 

reductions. 

For this planning period, we propose 

to find that Oklahoma reasonably 

determined that additional SO2

reductions from Arkansas, Louisiana, 

Missouri, and Iowa were not necessary 

for reasonable progress. This proposed 

determination is based, in part, on our 

review of the CENRAP modelling 

showing the projected impact from 

sources in these states and the relative 

contributions from SO2 point sources in 

these states. See our OK TSD for 

additional discussion and presentation 

of CENRAP source apportionment 

results for impacts on Wichita 

Mountains. 

We agree with the ODEQ’s approach 

for identifying those states with sources 

that may impact visibility at the Wichita 

Mountains and its decision to invite 

those states to consult. Through the 

consultation process, the ODEQ was 

able to gain additional information 

regarding the potential impacts from 

nearby states. We do not agree, however, 

with the ODEQ’s approach to 

consultation to address impacts from 

emissions from Texas. At the time that 

Oklahoma was developing its SIP, it had 

(1) abundant information showing the 

impact of Texas sources on visibility at 

the Wichita Mountains, particularly 

from EGU sources in northeast Texas, 

and (2) evidence that cost-effective 

controls on these sources were likely 

available. Despite this information, the 

ODEQ neither requested that the TCEQ 

further investigate controls at these 

sources nor did it request additional 

reductions from Texas sources to 

address the impacts of emissions from 

these sources at the Wichita Mountains. 

The Regional Haze Rule requires states 

to use the consultation process under 

Sections 51.308(d)(1)(iv) in the 

development of RPGs to ensure that all 

states, including downwind states, take 

a hard look at what measures are 

necessary for ensuring reasonable 

progress towards improving and 

maintaining visibility at Class I areas. 

Lacking development of critical 

information during its consultations 

with Texas, we believe that Oklahoma 

did not have adequate information to 

reasonably establish its RPG for the 

Wichita Mountains, and, as explained 

below, should have requested that the 

TCEQ further investigate these sources 

or requested additional reductions from 

Texas sources to ensure that all 

reasonable measures to improve 

visibility were included in Texas’ LTS 

and incorporated into Oklahoma’s RPG 

for the Wichita Mountains. 

3. The Oklahoma’s Reasonable Progress 

‘‘Four Factor’’ Analysis 

In establishing RPGs for a Class I area, 

Oklahoma is required by CAA Section 

169A(g)(1) and Section 

51.308(d)(1)(i)(A) to ‘‘[c]onsider the 

costs of compliance, the time necessary 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74868 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

283 In our FIP (76 FR 81728), we disagreed with 

the ODEQ’s BART determinations for these three 

facilities (two units at each facility) and required a 

more stringent level of control. 

for compliance, the energy and non-air 

quality environmental impacts of 

compliance, and the remaining useful 

life of any potentially affected sources, 

and include a demonstration showing 

how these factors were taken into 

consideration in selecting the goal.’’ 

The ODEQ analyzed the largest 

sources of visibility impairing 

pollutants within Oklahoma, including 

sources of sulfur, nitrates, NH3, VOCs, 

and directly emitted coarse and fine 

particles. The ODEQ calculated that 

sulfurous pollutants contribute 

approximately 44% and nitrate bearing 

pollutants contribute approximately 

21% of the total light extinction (or 

visibility impairment) to the Wichita 

Mountains. The ODEQ also calculated 

that sources from all source categories 

combined within Oklahoma contribute 

only approximately 13% of the total 

pollutants that contribute to light 

extinction at the Wichita Mountains in 

the 2002 modeled base year. 

To evaluate any additional control 

measures necessary to demonstrate 

reasonable progress, the ODEQ initially 

relied on the same CENRAP analysis, 

including the Alpine Geophysics report 

commissioned by CENRAP, that the 

TCEQ relied upon, that we describe 

above in Section V.C. 

The CENRAP control case sensitivity 

evaluation projected that visibility at the 

Wichita Mountains would be improved 

by an additional 0.75 dv on the worst 

20% days over what the ODEQ projects 

as its RPG of 21.47 dv for 2018, if 

controls were implemented at the 

sources that met the combination of 

baseline emissions, potential for costeffective add-on controls, and location 

selected by CENRAP for the sensitivity 

analysis. The ODEQ pointed out that 

even if all controls contemplated in the 

CENRAP sensitivity evaluation were 

implemented, the Wichita Mountains 

would still fall significantly short of 

meeting the URP glide path for the 20% 

worst days in 2018, and ODEQ noted 

that most of the sources were located in 

Texas or other states outside of ODEQ’s 

jurisdiction. The ODEQ also stated that 

the control scenario presented in the 

Alpine Geophysics evaluation includes 

some already implemented, 

prohibitively costly, technically 

infeasible, or otherwise unreasonable 

controls. Following this analysis, the 

ODEQ examined additional controls for 

sources within Oklahoma, the full list of 

which we present in our OK TSD. 

In its analysis, the ODEQ considered 

the four statutory factors under Section 

51.308(d)(1)(i)(A) in its evaluation of the 

potential for additional controls. In 

summary, the ODEQ analyzed the cost 

of compliance by reviewing the cost 

information previously developed by 

CENRAP and made changes to the cost 

information based on its knowledge of 

the particular facilities and experience 

with implementing ozone reduction 

strategies. The ODEQ’s analysis focused 

on moderate cost controls for sources 

likely to contribute to visibility 

impairment at the Wichita Mountains. 

In considering the time necessary for 

compliance, the ODEQ determined that 

any such controls would have to be 

installed and in operation by 2018. It 

did not identify any detrimental non-air 

quality environmental impacts 

associated with any controls considered, 

and any energy impacts were factored 

into the cost of controls. In considering 

the remaining useful life of any 

potentially affected sources, the ODEQ 

stated that none of the sources 

considered for additional emission 

reductions had indicated plans to shut 

down. 

The ODEQ also evaluated the major 

sources of each visibility impairing 

pollutant within the state. In its 

analyses of additional SO2 control, it 

noted that the three largest sources of 

sulfur emissions in the state, OG&E 

Muskogee, OG&E Sooner, and AEP/PSO 

Northeastern, were subject to BART.283

The ODEQ also stated that sulfur 

controls at the Grand River Dam 

Authority (GRDA) would be costly and 

result in little visibility benefit given the 

location of the facility. Furthermore, the 

GRDA already utilized flue gas 

desulfurization. It noted that additional 

sulfur emission reductions were already 

required due to consent decrees on 

refineries. 

For NOX emissions, the ODEQ 

identified that three of the four largest 

NOX point sources and a number of 

smaller sources close to Wichita 

Mountains would be controlled under 

BART. Similar to its analysis for SO2, 

the ODEQ also stated that NOX controls 

at the GRDA would be costly and result 

in little visibility benefit given the 

location of the facility. The ODEQ 

determined that controls for other point 

and area sources, especially those 

associated with oil and gas activities, 

would be expensive and that violations 

would entail large costs to detect and 

enforce. The ODEQ stated that improved 

emission inventories in the future could 

help in developing state rules for area 

sources. In addition, the ODEQ stated 

that new oil and gas sources are covered 

by new source performance standards. 

Based on the above analysis of the 

four factors, the ODEQ concluded that 

retrofitting these identified point 

sources of NOX and SO2 would impose 

unreasonable costs for negligible 

visibility improvement. The ODEQ 

reasoned that most of the largest sources 

of SO2 and NOX were already being 

controlled through BART, consent 

decrees or other regulatory mechanisms; 

already had adequate controls in place; 

or are located too far from the Wichita 

Mountains, and therefore have too little 

visibility impact to justify the cost of 

additional controls. The ODEQ 

concluded that further emission 

reductions from such sources were 

unreasonable. It also stated that it would 

be unreasonable to require severe or 

over-control of Oklahoma sources to 

compensate for the contribution from 

Texas, other states, and foreign 

countries, especially considering that 

the vast majority of the visibility 

impairment at the Wichita Mountains 

originates from sources beyond the 

borders of Oklahoma. 

The ODEQ determined that the 

majority of VOC emissions are from 

biogenic sources. Anthropogenic 

sources of VOC are largely covered 

under federal mandates and have a 

small contribution to visibility 

impairment. Fine and coarse particulate 

emissions are also primarily due to 

natural sources such as dust storms and 

fires. The ODEQ noted that despite the 

prominence of agricultural burning and 

wildfires in the Oklahoma emissions 

inventory, it does not believe that these 

sources contribute significantly to 

regional haze at the Wichita Mountains 

or at any other Class I area. It pointed 

out that there are state regulations 

already in place (see the Oklahoma 

Administrative Code 252:100–13–7(4)) 

to address the burning of forestland, 

cropland, and rangeland. In addition, 

pursuant to the regional haze 

requirements at Section 

51.308(d)(3)(v)(E), the ODEQ considered 

smoke management techniques for 

purposes of agricultural and forestry 

management. The ODEQ stated that it 

believes that most emissions of fine and 

coarse PM originate from natural 

sources, and that even those originating 

in Oklahoma are beyond the regulatory 

purview of ODEQ. 

In establishing its RPGs for 2018 for 

the 20% worst days, the ODEQ relied on 

the improvements in visibility that were 

anticipated to result from federal and 

state control programs that were either 

currently in effect or with mandated 

future-year emission reduction 

schedules that predate 2018, including 

the long-term strategies of Oklahoma, 

Texas, and other states, and 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74869 

284Both GRDA Units 1 and 2 plan to install low 

NOX burners and overfire air in order to reduce 

NOX by construction permit No. 2009–179–C (M– 

2)(PSD). Unit 2 of the GRDA is fitted with a dry 

scrubber. We have recently became aware that Unit 

1 (which is not scrubbed) is scheduled to be retired 

or converted to natural gas and a third natural gas 

powered unit may be added under a draft permit 

evaluation. 

285 76 FR 81728 (Dec. 28, 2011). 

presumptive emission reductions 

expected to result from the submitted 

Oklahoma BART rule. Based on the 

emission reductions from these 

measures, CENRAP modeled the 

projected visibility conditions 

anticipated at each Class I area in the 

region in 2018, and the ODEQ used 

these results to establish its RPGs. 

We agree with the ODEQ’s decision to 

focus the analysis of the four statutory 

factors on point sources, as the CENRAP 

modeling results and ODEQ’s analysis 

in Section V.F of the Oklahoma regional 

haze SIP indicate that sulfate is the 

predominant pollutant that affects the 

state’s ability to meet the URP goals in 

2002 on the worst 20% days at the 

Wichita Mountains, and comes 

primarily from point sources. CENRAP 

modeling results also indicate that 

Oklahoma point sources contribute only 

3.25 Mm¥1 of the total 111.03 Mm¥1

visibility extinction at the Wichita 

Mountains in 2002 and only 2.95 

MmSO¥1 of the total 86.56 Mm¥1

projected for 2018. This modeling 

projection does not include the level of 

controls required under BART by the 

FIP and the revised SIP for the three 

largest sources of SO2 in the state. The 

ODEQ also considered sources of VOC 

emissions, coarse and fine PM 

emissions, mobile source emissions and 

area source emissions in its discussion 

and analysis of the four factors. 

There are large EGU sources of SO2

for which the ODEQ did not propose 

control, including the GRDA Units 1 

and 2,284 Muskogee Unit 6, and Hugo 

Unit 1. Oklahoma considered these 

sources for additional control under 

reasonable progress but ultimately for 

the reasons described above, declined to 

further control them. However, the total 

contribution from those sources not 

identified for control is only a fraction 

of the 1.23 Mm¥1 projected from all SO2

point sources, and none of the those 

sources are located such that we would 

anticipate significant visibility benefits 

at the Wichita Mountains on the 20% 

worst days should they be controlled. 

The 20% worst days at the Wichita 

Mountains are dominated by days 

impacted by emissions from sources in 

Texas. The largest impacts from sources 

in Oklahoma rarely occur on the 20% 

worst days as identified by the 

IMPROVE monitor data during the 

baseline period. For these reasons and 

others that we more fully explore in our 

OK TSD, we believe that Oklahoma has 

adequately controlled its own sources 

for reasonable progress to the extent 

necessary for this planning period. 

As the ODEQ notes in several places 

in its SIP, point sources in Texas 

account for a much greater portion of 

the visibility impact at the Wichita 

Mountains than Oklahoma point 

sources. Compared to the 1.23 Mm¥1

due to point source emissions of SO2 in 

Oklahoma discussed above, Texas point 

source emissions of SO2 are projected to 

contribute 7.83 Mm¥1 to the total 

extinction in 2018. We agree with the 

ODEQ’s statement regarding this 

situation: ‘‘The vast majority of 

visibility impairment at the Wichita 

Mountains comes from sources beyond 

the borders of the State of Oklahoma. 

The federal Regional Haze Rule in 40 

CFR 51.308(d)(3)(ii) does not require 

DEQ to compensate for the lack of 

control of emissions in Texas, other 

states, and foreign countries.’’ The 

Regional Haze Rule does not require a 

state to over control its own sources in 

order to compensate for under 

controlled sources from another state. 

However, the Regional Haze Rule does 

require, under Section 51.308(d)(1)(iv), 

that in developing its RPGs, Oklahoma 

consult with those states which may 

reasonably be anticipated to cause or 

contribute to visibility impairment at 

the Wichita Mountains to identify 

reasonable measures for improving 

visibility at its Class I area. 

4. Uniform Rate of Progress 

Section 51.308(d)(1)(i)(B) requires 

Oklahoma to analyze and determine the 

URP needed to attain natural visibility 

conditions by 2064. To calculate the 

URP, Oklahoma must compare baseline 

visibility conditions to natural visibility 

conditions at the Wichita Mountains 

and determine the uniform rate of 

visibility improvement (measured in 

deciviews) that would need to be 

maintained during each implementation 

period in order to attain natural 

visibility conditions by 2064. In 

establishing the RPG, Oklahoma must 

consider the URP and the emission 

reduction measures needed to achieve it 

for the period covered by the 

implementation plan. In a previous final 

rulemaking,285 we found that ODEQ 

appropriately calculated the URP for the 

Wichita Mountains. Therefore, the only 

portion of 40 CFR 51.308(d)(1)(i)(B) that 

we address is Oklahoma’s requirement 

to consider the emission reduction 

measures needed to achieve the URP 

when establishing the RPG for the 

Wichita Mountains. 

In establishing the RPGs for the 

Wichita Mountains, the ODEQ 

compared the baseline visibility 

conditions to the natural visibility 

conditions and determined the URP 

needed in order to attain natural 

visibility conditions by 2064. It 

calculated that the URP results as a 

visibility improvement of 3.80 dv for the 

period covered by this SIP revision 

submittal (up to and including 2018). 

The ODEQ noted that the CENRAP 

modeling results indicated that 

complete elimination of all 

anthropogenic emissions in Oklahoma 

are likely to be insufficient to meet the 

URP at the Wichita Mountains and that 

a majority of the visibility impairment at 

the Wichita Mountains comes from 

sources beyond Oklahoma’s borders. 

After considering the URP, the results 

of the CENRAP modeling and the four 

reasonable progress factors, the ODEQ 

determined that meeting the URP goal 

for 2018 was not reasonable. It then 

adopted the 2018 projected visibility 

conditions from the CENRAP 

photochemical modeling as the RPGs for 

the 20% best days and 20% worst days 

for the Wichita Mountains. 

TABLE 29—COMPARISON OF URP TO THE REASONABLE PROGRESS GOAL ON MOST IMPAIRED DAYS FOR THE WICHITA

MOUNTAINS

Extinction Deciview 

Natural Visibility Conditions ............................................................................................................................... 21.23 Mm¥1 ..... 7.53 dv. 

Baseline Visibility Conditions (2002–2004) ....................................................................................................... 108.15 Mm¥1 ... 23.81 dv. 

Improvement Needed to Reach Natural Conditions ......................................................................................... 86.91 Mm¥1 ..... 16.28 dv. 

Improvement by 2018 at Uniform Rate of Progress ......................................................................................... 34.18 Mm¥1 ..... 3.80 dv. 

Improvement by 2018 under Oklahoma’s RPG ................................................................................................ 22.52 Mm¥1 ..... 2.33 dv. 

Rate of Improvement from 2004–2018 under Oklahoma’s RPG (dv/year) ...................................................... ........................... 0.166 dv/year. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74870 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

286Available at: http://vista.cira.colostate.edu/

tss/. 287TCEQ comment letter to EPA on draft 

modeling platform dated June 24, 2014. ‘2018 EMP 

signed.pdf’. 

TABLE 29—COMPARISON OF URP TO THE REASONABLE PROGRESS GOAL ON MOST IMPAIRED DAYS FOR THE WICHITA

MOUNTAINS—Continued 

Extinction Deciview 

Shortfall between Oklahoma’s RPG and the URP (for this implementation period) ........................................ ........................... ¥1.47 dv. 

Improvement by 2064 Extrapolated from Oklahoma’s RPG ............................................................................. 68.38 Mm¥1 ..... 10.01 dv. 

Visibility in 2064 from Oklahoma’s RPG (extrapolated) .................................................................................... 39.76 Mm¥1 ..... 13.80 dv. 

Visibility in 2102 Extrapolated from Oklahoma’s RPG (natural visibility conditions achieved) ......................... 21.23 Mm¥1 ..... 7.53 dv. 

The ODEQ believes the RPGs it 

established for the Wichita Mountains 

are reasonable, and that it is not 

reasonable to achieve the URP in 2018. 

In support of this conclusion it included 

a discussion of the pollutant 

contributions and the sources of 

visibility impairment at the Wichita 

Mountains (see Sections IX.D and E of 

the Oklahoma regional haze SIP). The 

ODEQ also took several other factors 

into consideration in determining that it 

was not reasonable to achieve the glide 

path in 2018 and that the RPG adopted 

by it is reasonable. See our OK TSD for 

a summary of these factors and the 

CENRAP visibility modeling source 

apportionment results. 

We evaluated the analysis provided 

by the ODEQ along with the CENRAP 

modeling results, CENRAP emission 

inventories and other information in 

examining the RPGs established by 

ODEQ. Our review of the CENRAP 

emission inventory, modeling protocol 

and model results can be found in our 

CENRAP Modeling TSD. Below we 

present a summary of that evaluation: 

• The ODEQ demonstrated through 

the CENRAP control sensitivity 

modeling scenario discussed in Section 

V.C.2, above, that application of a wide 

suite of controls across CENRAP states 

determined to meet a cost-effective 

threshold of $5,000/ton and emissions 

in relation to location criteria, would 

also not be sufficient to meet the URP 

goal, falling approximately 0.71 dv 

deciview short of the goal. However, we 

note that this control sensitivity 

modeling also demonstrated that an 

additional improvement of 0.75 dv was 

achievable through implementation of 

the identified controls. Based on source 

apportionment data, a large portion of 

that improvement would likely result 

from implementation of identified 

controls in Texas. A 0.75 dv 

improvement represents nearly 33% 

additional improvement over the 2.3 dv 

improvement projected to occur 

between the baseline period and 2018 

due to all of the reductions included in 

the model from on the book controls, 

implementation of CAIR and 

assumptions of reductions due to BART. 

• Evidence in the record 

demonstrated that additional reductions 

at sources in Texas were likely feasible, 

result in visibility improvement, and be 

cost-effective, but the ODEQ did not 

pursue this with Texas. Consequently, 

we believe the ODEQ did not have 

sufficient information to adequately 

consider emission reductions for 

sources in Texas in establishing its 

RPGs and demonstrating that it is 

reasonable. 

• We believe the current approach to 

estimate natural conditions used by 

ODEQ follows our default methods and 

is acceptable to establish the 2064 goal, 

calculate the URP, and evaluate the 

RPGs established by Oklahoma. 

• We note the more recent IMPROVE 

monitored data at the Wichita 

Mountains indicates that more progress 

than anticipated by the CENRAP 

modeling has occurred.286 The most 

recent five-year (2009–2013) average 

conditions for the 20% worst days is 

21.2 dv. This is below the level 

anticipated in the CENRAP projection 

for 2018 of 21.5 dv. We believe that this 

observed improvement is the result of 

meteorological conditions, reduction in 

the impact from fires, and reduction in 

the impacts from SO2 emissions. More 

recent emission inventory data shows 

reductions in emissions in most states 

beyond what was projected in the 2018 

modeling, including large reductions in 

emissions from the Eastern United 

States. Emissions from non-EGU Texas 

point sources are lower than have been 

projected in the modeling. We note that 

additional reductions are still needed to 

meet or exceed the URP goal for 2018 

of 20.01 dv. As discussed above, 

emissions at some of the sources that 

impact visibility the most are still above 

the emission levels projected in the 

model and cost-effective controls are 

likely available at these sources. Based 

on information provided by the TCEQ, 

we do not expect large additional 

emission reductions of SO2 in Texas 

between 2013 and 2018 under federal 

programs and the SIP as submitted.287

Based on the above considerations, 

we propose to agree with the ODEQ’s 

demonstration that it is not reasonable 

to meet the URP for the Wichita 

Mountains for this planning period. We 

also agree with the ODEQ that emissions 

and transport from outside of Oklahoma 

will severely limit the rate of progress 

achievable at the Wichita Mountains on 

the 20% worst days. As the ODEQ itself 

(and we through our analysis detailed in 

the FIP TSD) have demonstrated, there 

are large visibility impacts at the 

Wichita Mountains from outside 

Oklahoma, the largest percentage 

coming from point sources in Texas. In 

addition, we believe the ODEQ has also 

demonstrated there is the likelihood of 

a sizeable visibility improvement from 

controlling a subset of these sources, 

with likely cost-effective controls. 

5. Reasonable Progress Goal Minimum 

Under Section 51.308(d)(1)(vi), 

Oklahoma may not adopt a RPG that 

represents less visibility improvement 

than is expected to result from 

implementation of other requirements of 

the CAA during the applicable planning 

period. 

The RPGs established by Oklahoma 

are based on CENRAP 2018 modeling 

projections. The modeling projections 

conducted by CENRAP contain 

projections of the visibility conditions 

that are anticipated to be realized at 

each Class I area between the 2002 base 

year and the 2018 future year. These 

projections are based on the emission 

reductions resulting from federal and 

state control programs that are either 

currently in effect or with mandated 

future-year emission reduction 

schedules that predate 2018, including 

the long-term strategies of Oklahoma, 

Texas, and other states, and 

presumptive emission reductions 

expected to result from the submitted 

Oklahoma BART rule. Since CENRAP’s 

2018 modeling projections are based on 

local, state, and federal control 

programs that are either currently in 

effect or with mandated future-year 

emission reduction schedules, we 

believe that the ODEQ’s RPGs represent 

at least as much visibility improvement 

as is expected to result from 

implementation of other requirements of 

the CAA (i.e., requirements other than 

regional haze) during the applicable 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74871 

288 76 FR 81728 (Dec. 28, 2011). 

289 In our August 21, 2013, proposed approval of 

Oklahoma’s June 20, 2013, regional haze SIP 

revision we proposed to find that the SO2 emission 

reductions associated with Oklahoma’s revised 

BART determination for Northeastern Units 3 and 

4, when combined with enforceable commitments 

from ODEQ, will be consistent with the levels of 

control assumed in the CENRAP modeling and 

relied on by other States as part of their reasonable 

progress demonstrations (78 FR 51586). 

planning period. We therefore propose 

to approve Oklahoma’s submission 

under Section 51.308(d)(1)(vi) that its 

RPG for the Wichita Mountains does not 

represent less visibility improvement 

than is expected to result from the 

implementation of other requirements of 

the CAA during this planning period. 

6. Oklahoma’s Assertion That Its 

Progress Goals Are Reasonable 

Section 51.308(d)(1)(ii) provides that 

for the period of the SIP, if Oklahoma 

establishes a RPG that provides for a 

slower rate of improvement in visibility 

than the rate that would be needed to 

attain natural conditions by 2064, it 

must demonstrate based on the factors 

in Section 51.308(d)(1)(i)(A) that the 

rate of progress for the SIP to attain 

natural conditions by 2064 is not 

reasonable; and that the progress goal it 

adopted is reasonable. As part of its SIP 

assessment, Oklahoma must provide to 

the public for review the number of 

years it would take to attain natural 

conditions if visibility improvement 

continues at the rate of progress it 

selected as reasonable. 

The ODEQ’s RPG for the 20% worst 

days establishes a slower rate of 

progress than the URP for the Wichita 

Mountains. As shown in Table IX–1 of 

the Oklahoma regional haze SIP, under 

the RPG adopted by ODEQ, it projected 

that natural visibility conditions will 

not be attained at the Wichita 

Mountains by 2064. ODEQ calculated 

that under the rate of progress selected 

by it as reasonable, it would attain 

natural visibility conditions at the 

Wichita Mountains in 2102. See Table 

29 above. 

In the Oklahoma Regional Haze SIP, 

the ODEQ states that the RPGs it 

established for the Wichita Mountains 

are reasonable and that it is not 

reasonable to achieve the URP in 2018. 

In support of this conclusion, it 

included a discussion of the pollutant 

contributions and the sources of 

visibility impairment at the Wichita 

Mountains (see Sections IX.D and E of 

the Oklahoma regional haze SIP). The 

ODEQ also took several other factors 

into consideration in determining that it 

was not reasonable to achieve the glide 

path in 2018 and that the RPG adopted 

by it is reasonable. See our OK TSD for 

a summary of these factors and the 

CENRAP visibility modeling source 

apportionment results. 

The ODEQ indicated that Oklahoma’s 

ability to meet the URP is impeded 

primarily by the following: the 

significant contribution of emissions 

from Texas and other areas outside the 

ODEQ’s jurisdiction; the uncertainty in 

the effect of CAIR; the economic and 

energy cost of additional controls on 

Oklahoma point sources; the lack of a 

quality-assured enhanced Oklahoma 

emissions inventory and ODEQ’s 

reluctance to target area sources for 

emissions controls until such an 

emissions inventory is developed; the 

ODEQ’s lack of jurisdiction over nonroad and on-road mobile sources; and, 

the limitations involved with utilizing 

the default EPA method to determine 

natural visibility conditions. See our OK 

TSD for a more complete summary of 

these factors. 

We evaluated the analysis provided 

by the ODEQ along with the CENRAP 

modeling results, CENRAP emission 

inventories and other information in 

examining the RPGs established by 

ODEQ. Our review of the CENRAP 

emission inventory, modeling protocol 

and model results can be found in our 

CENRAP Modeling TSD. 

7. Our Evaluation of Oklahoma’s 

Reasonable Progress Goals for the 

Wichita Mountains. 

In the sections above, we discuss how 

Oklahoma constructed its RPGs for the 

Wichita Mountains, how in doing so it 

consulted with Texas and other states, 

applied the four reasonable progress 

factors in evaluating sources within 

Oklahoma for additional controls in the 

development of that RPG, and 

calculated the URP for the Wichita 

Mountains. In this section we consider 

those efforts and present our evaluation 

of Oklahoma’s RPGs for the Wichita 

Mountains. 

We believe that with the exception of 

certain BART sources, Oklahoma 

appropriately concluded that no 

additional reasonable progress measures 

for Oklahoma sources were necessary 

during this first planning period. 

However, BART is a component of 

reasonable progress, and the RPGs 

selected by the ODEQ for the Wichita 

Mountains do not include the level of 

reductions necessary to meet the 

requirements under Section 51.308(e) 

for BART. In our December 28, 2011 

rulemaking, we disapproved the SO2

BART determinations for certain units 

and promulgated a BART FIP to impose 

controls for these units.288 Therefore, 

implementation of our SO2 BART FIP 

and the revised BART SIP for the AEP 

units is expected to result in greater 

reasonable progress than is anticipated 

in Oklahoma’s February 19, 2010, 

regional haze SIP submit.289

In addition, as required by Section 

51.308(d)(1)(iv), Oklahoma’s 

development of its RPGs must be 

informed by its consultations with other 

states. Oklahoma demonstrated that the 

unrealistic scenario of eliminating all 

Oklahoma sources would not be 

sufficient to meet the URP for 2018. It 

realized that efforts to meet the goal of 

natural visibility by 2064 would require 

further emission reductions from other 

states in the region. The CENRAP 

modeling, monitoring data and other 

technical analyses that informed 

consultations demonstrated that NOX

and SO2 are the primary causes of haze 

at the Wichita Mountains with SO2 from 

point sources being the predominant 

driver. It also showed that SO2 point 

sources in Texas were a significant 

contributor to the haze at the Wichita 

Mountains. Furthermore, the control 

and cost information developed by 

CENRAP and Alpine Geophysics 

showed that cost-effective controls on 

Texas sources were likely available, 

some with a cost-effectiveness on a $/

ton basis within TCEQ’s own 

benchmark. The Regional Haze Rule 

envisioned that a state would use the 

consultation processes under Sections 

51.308(d)(1)(iv) in the development of 

its RPGs, and 51.308(d)(3)(i) regarding 

the development of its long-term 

strategy, in identifying visibility 

impairing emissions that cross state 

boundaries, and in the coordination of 

strategies to reduce those emissions. 

However, despite this information in the 

record about the impact of Texas 

sources on the Wichita Mountains, the 

ODEQ did not request that the TCEQ 

further investigate these sources, nor 

did it request additional reductions 

from Texas sources to address this 

impact. As we discuss in Section V.E, 

we believe that the technical analysis 

developed by Texas did not provide the 

information necessary to identify 

reasonable reductions from its sources, 

and inform consultations in order to 

develop coordinated management 

strategies with Oklahoma. Therefore, 

due to this absence of the development 

of this critical information during 

consultations, we believe that Oklahoma 

did not have adequate information to 

establish its RPG for the Wichita 

Mountains, and should have requested 

that the TCEQ further investigate these 

sources or requested additional 

reductions from Texas sources to ensure 

that all reasonable measures to improve 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74872 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

290 64 FR 35732 (July 1, 1999). 

visibility were included in Texas’ LTS 

and incorporated into Oklahoma’s RPG 

for the Wichita Mountains. Thus, the 

basic intent of our consultation 

requirements was not realized. 

In addition to the explicit statutory 

requirement under Section 

51.308(d)(1)(ii) to consider the four 

reasonable progress factors, the Regional 

Haze Rule also establishes an analytical 

requirement to ensure that each state 

considers the emission reduction 

measures necessary to attain the URP. 

The Regional Haze Rule provides that 

we will evaluate Oklahoma’s 

consideration of the four factors in 

Section 51.308(d)(1)(i)(A), its analysis of 

the URP required under Section 

51.308(d)(1)(i)(B) and the demonstration 

developed pursuant to Section 

51.308(d)(1)(ii), ‘‘[i]n determining 

whether the State’s goal for visibility 

improvement provides for reasonable 

progress.’’ As explained in the preamble 

to the Regional Haze Rule, the URP 

analysis was adopted to ensure that 

states use a common analytical 

framework and to ensure an informed, 

equitable, and transparent decision 

making process that would, among other 

things, ensure that the public would be 

provided with the information 

necessary to understand the emission 

reductions needed, the costs of such 

measures, and other factors associated 

with improvements in visibility. We 

note that this analytical requirement is 

met only through consultation and is 

not restricted to the consideration of 

only those sources within the state with 

the impacted Class I area. As we stated 

in the Regional Haze Rule regarding this 

requirement: 290

In doing this analysis, the State must 

consult with other States which are 

anticipated to contribute to visibility 

impairment in the Class I area under 

consideration. Because haze is a regional 

problem, States are encouraged to work 

together to develop acceptable approaches for 

addressing visibility problems to which they 

jointly contribute. If a contributing State 

cannot agree with the State establishing the 

reasonable progress goal, the State setting the 

goal must describe the actions taken to 

resolve the disagreement. 

However, Oklahoma’s consultation 

was incomplete. While the analyses 

developed by CENRAP provide a great 

deal of information on contributions to 

visibility impairment and a set of 

potential available add-on controls and 

cost associated with those controls, the 

data was insufficient to fully assess the 

impacts and available emission 

reduction measures for Texas sources. 

Given the large contributions from 

sources in Texas and EGU point sources 

in particular, Oklahoma could not 

reasonably consider all the emission 

reductions needed to meet or approach 

the URP without considering emission 

reduction measures available for those 

sources in Texas that contribute the 

most to visibility impairment at Wichita 

Mountains. In summary, we propose to 

find the following: 

• Oklahoma has demonstrated that it 

is not reasonable to require additional 

emission reductions for its sources for 

this planning period. 

• BART is a component of developing 

the RPGs, and the RPGs are inadequate 

because BART controls were not 

adequately considered. We note this 

deficiency is addressed by our BART 

FIP and the revised Oklahoma SIP. 

• Oklahoma’s consultations with 

Texas were flawed, which prevented it 

from adequately developing its RPGs for 

the Wichita Mountains. 

• Also because Oklahoma’s 

consultations with Texas were flawed, 

Oklahoma did not consider the emission 

reduction measures necessary to achieve 

the URP for the Wichita Mountains and 

did not adequately demonstrate that the 

RPGs it established were reasonable 

based on the four statutory factors under 

51.308(d)(1)(ii). 

In consideration of these flaws, we 

propose to disapprove Oklahoma’s 

submission under Section 51.308(d)(1), 

except for those portions addressing 

Section 51.308(d)(1)(vi), which we 

propose to approve. 

VII. Our Proposed Oklahoma and 

Texas Regional Haze FIPs 

Below, we list all of the portions of 

Section 51.308 that we propose to find 

that Texas and Oklahoma did not meet, 

which we have discussed above, and 

more fully in our TX TSD and OK TSD 

documents. 

We propose to disapprove the parts of 

the Texas regional haze SIP addressing 

the following requirements: 

• Section 51.308(d)(1)(i)(A), regarding 

Texas’ reasonable progress four factor 

analysis. 

• Section 51.308(d)(1)(i)(B), regarding 

Texas’ calculation of the emission 

reductions needed to achieve the URPs 

for the Guadalupe Mountains and Big 

Bend. 

• Section 51.308(d)(1)(ii), regarding 

Texas’ RPGs for the Guadalupe 

Mountains and Big Bend. 

• Section 51.308(d)(2)(iii), regarding 

Texas’ calculation of the natural 

visibility conditions for the Guadalupe 

Mountains and Big Bend. 

• Section 51.308(d)(2)(iv)(A) 

regarding Texas’ calculation of natural 

visibility impairment. 

• Section 51.308(d)(3)(i) regarding 

Texas’ long-term strategy consultation. 

• Section 51.308(d)(3)(ii) regarding 

Texas securing its share of reductions in 

other states’ RPGs. 

• Section 51.308(d)(3)(iii) regarding 

Texas’ technical basis for its long-term 

strategy. 

• Section 51.308(d)(3)(v)(C), 

regarding Texas’ emissions limitations 

and schedules for compliance to achieve 

the RPGs for Big Bend and the 

Guadalupe Mountains. 

We propose to disapprove the RPGs 

for the Wichita Mountains set by 

Oklahoma in its regional haze SIP. In 

setting its RPG, we propose to find that 

Oklahoma generally did not meet the 

requirements of Section 51.308(d)(1) of 

the Oklahoma regional haze SIP, except 

for Section 51.308(d)(1)(vi). 

Below we present a summary of our 

proposed Texas and Oklahoma FIPs and 

why we believe these FIPs would cure 

the SIP deficiencies in those portions of 

the Texas and Oklahoma SIPs that we 

propose to disapprove, thereby 

satisfying our FIP obligation. Please see 

our FIP TSD and our Cost TSD for a full 

development of the technical basis of 

our FIPs. 

A. Summary of Our Proposed Texas FIP 

We believe our proposed FIP and its 

rationale as presented here provide the 

technical analysis that was lacking in 

Texas’ development of its RPGs for the 

Guadalupe Mountains and Big Bend, 

and in its consultations with Oklahoma 

for the development of the RPGs for the 

Wichita Mountains, as well as 

addressing its long-term strategy. As 

Texas did in the development of its SIP, 

we have also used the same analysis to 

address both tasks. We began our review 

of Texas’ conclusions with an initial 

analysis of all point sources in Texas 

and an assessment of the visibility 

impact from those sources with the 

greatest potential to contribute to 

visibility impairment. A refinement of 

this analysis resulted in our focus on a 

much smaller group of sources that 

essentially reduced down to an analysis 

of whether, in light of the balance 

between the cost of control and 

visibility benefits of control at each 

source, additional SO2 controls should 

be installed on each of certain large coal 

fired EGUs in Texas in order to improve 

the visibility at these Class I areas. We 

conducted our analysis using the four 

reasonable progress factors listed in 

Section 51.308(d)(1)(i)(A). We propose 

to find that this portion of our proposed 

Texas FIP would make whole our 

disapproval of those portions of the 

Texas SIP intended to meet: 

• Section 51.308(d)(1)(i)(A). 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74873 

• Section 51.308(d)(3)(i). 

• Section 51.308(d)(3)(ii). 

• Section 51.308(d)(3)(iii). 

• Section 51.308(d)(3)(v)(C). 

We also establish the natural visibility 

conditions for the Guadalupe Mountains 

and Big Bend. We then use those values 

and the analysis we have developed 

above to consider the emission 

reductions needed to achieve the URPs 

for the Guadalupe Mountains and Big 

Bend and establish their RPGs. We 

propose that these portions of our Texas 

FIP, developed below, make whole our 

disapproval of those portions of the 

Texas SIP intended to meet: 

• Section 51.308(d)(2)(iii). 

• Section 51.308(d)(2)(iv)(A). 

• Section 51.308(d)(1)(i)(B). 

• Section 51.308(d)(1)(ii). 

B. Summary of Our Proposed Oklahoma 

FIP 

We believe some of the same portions 

of our proposed Texas FIP would also 

largely address the portions of the 

Oklahoma regional haze SIP we are 

proposing to disapprove. We believe 

that Oklahoma’s incomplete 

consultation with Texas denied it the 

knowledge it needed—the visibility 

impacts of individual sources in Texas 

with the largest potential to impact the 

visibility at the Wichita Mountains and 

the extent to which cost-effective 

controls were available—in order to 

properly construct its RPG for the 

Wichita Mountains. As indicated in the 

record, both the ODEQ and the TCEQ 

acknowledged during the development 

of their respective regional haze SIPs 

that Texas point sources have a 

significant visibility impact at the 

Wichita Mountains and that costeffective controls were likely available 

for these sources. However, the ODEQ 

did not pursue the point in its 

consultations with the TCEQ under 

Section 51.308(d)(1)(iv). Our proposed 

Oklahoma FIP will address these 

deficiencies in the Oklahoma’s 

consultations by establishing new RPGs 

for the Wichita Mountains. These RPGs 

are based on our analysis of the 

proposed controls for Texas sources in 

our proposed Texas FIP. We do not 

believe that any further control 

measures for sources within Oklahoma 

are necessary to resolve the issues 

identified above in its SIP. 

C. Technical Overview of Our Proposed 

Oklahoma and Texas FIPs 

As discussed in our FIP TSD, we have 

determined that based on their visibility 

impacts, a smaller subset of the facilities 

that we have initially analyzed should 

be further evaluated to determine (1) if 

cost-effective controls are available and 

(2) considering their projected visibility 

benefits, which, if any controls should 

be proposed. With one exception, the 

PPG Flat Glass plant in Wichita Falls, 

all of the facilities in the smaller subset 

of Texas sources are coal fired power 

plants. While some of these coal fired 

power plants have scrubbers, all but one 

are partially bypassed. Also as 

discussed in that section, we are 

limiting our analyses to the 

consideration of SO2 controls for these 

EGU sources, as our modeling indicates 

that the impacts from these sources on 

the 20% worst days are primarily due to 

sulfate emissions. In our Cost TSD, we 

conduct a SO2 cost analyses for the 

following facilities and units: 

TABLE 30—SOURCES UNDERGOING REASONABLE PROGRESS AND LONG-TERM STRATEGY ANALYSES

Facility Units Currently scrubbed? Currently bypassed? 

Big Brown .................................................................................. 1, 2 No. 

Sandow 4 ................................................................................... 1 Yes ................................................ Yes. 

Monticello ................................................................................... 1, 2 No. 

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

Martin Lake ................................................................................ 1, 2, 3 Yes ................................................ Yes. 

Coleto Creek .............................................................................. 1 No. 

Limestone .................................................................................. 1, 2 Yes ................................................ Yes. 

San Miguel ................................................................................. 1 Yes ................................................ No. 

Tolk ............................................................................................ 1, 2 No. 

Welsh ......................................................................................... 1, 2, 3 No. 

W. A. Parish .............................................................................. 5, 6, 7 No. 

W. A. Parish .............................................................................. 8 Yes ................................................ Yes. 

In addition to these sources, we have 

examined the PPG Flat Glass Plant in 

Wichita Falls, Texas. This is the only 

non-EGU and the only source for which 

NOX controls are considered. For all of 

the sources we examined, visibility 

impacts were dominated by the impacts 

from SO2 emissions with the exception 

of the PPG Flat Glass Plant. Because of 

the proximity of this facility to Wichita 

Mountains, NOX and SO2 emissions 

from the facility were both responsible 

for the visibility impacts at Wichita 

Mountains. As discussed in more detail 

below, we evaluated these impacts and 

considered recent emissions and permit 

data in considering the potential need 

for additional controls for this facility. 

D. Approach to Reasonable Progress 

and Long-Term Strategy 

We are simultaneously conducting 

reasonable progress and long-term 

strategy analyses. These analyses 

address both (1) the requirements to 

consider the four reasonable progress 

factors for the Texas Class I areas, and 

(2) the technical basis required to 

develop the long-term strategy for the 

Texas Class I areas and the Wichita 

Mountains in Oklahoma. We use the 

‘‘four factor analysis’’ method outlined 

in 40 CFR 51.308(d)(1)(A) that states are 

directed to use in establishing a RPG: 

(1) Reasonable progress goals. For each 

mandatory Class I Federal area located 

within the State, the State must establish 

goals (expressed in deciviews) that provide 

for reasonable progress towards achieving 

natural visibility conditions. The reasonable 

progress goals must provide for an 

improvement in visibility for the most 

impaired days over the period of the 

implementation plan and ensure no 

degradation in visibility for the least 

impaired days over the same period. 

(i) In establishing a reasonable 

progress goal for any mandatory Class I 

Federal area within the State, the State 

must: 

(A) Consider the costs of compliance, the 

time necessary for compliance, the energy 

and non-air quality environmental impacts of 

compliance, and the remaining useful life of 

any potentially affected sources, and include 

a demonstration showing how these factors 

were taken into consideration in selecting the 

goal. 

To assist in interpreting these 

reasonable progress factors, we will rely 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74874 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

291 Guidance for Setting Reasonable Progress 

Goals Under the Regional Haze Program, June 1, 

2007. 

292For reasons we discuss in our FIP TSD, we 

believe that the Tolk facility may merit a special 

consideration of the energy and non-air quality 

environmental impacts of compliance. 

293See 79 FR 9353, footnote 137. We also 

finalized our proposal in 79 FR 52420, using this 

same reasoning. 

294 Guidance for Setting Reasonable Progress 

Goals Under the Regional Haze Program, June 1, 

2007. Page 19. 

295 70 FR 39168 (July 6, 2005). 

296 70 FR 39169 (July 6, 2005). 

on our reasonable progress Guidance.291

Our Reasonable Progress Guidance 

notes the similarity between some of the 

reasonable progress factors and the 

BART factors contained in Section 

51.308(e)(1)((ii)(A), and suggests that the 

BART Guidelines be consulted 

regarding cost, energy and non-air 

quality environmental impacts, and 

remaining useful life. We are therefore 

relying on our BART Guidelines for 

assistance in interpreting those 

reasonable progress factors, as 

applicable. 

We note that, with one exception,292

the issues relating to the evaluation of 

three of these factors: (1) Time necessary 

for compliance, (2) energy and non-air 

quality environmental impacts of 

compliance, and (3) remaining useful 

life, are common to all the units we are 

analyzing. Thus, we are analyzing these 

factors for all the units simultaneously. 

In analyzing the remaining factor, cost 

of compliance, we are including in our 

evaluation a consideration of any 

control technology that may already be 

installed at the facility. Also, similar to 

a BART analysis, we are also 

considering the projected visibility 

benefit in our analysis. As we state in 

our Arizona proposal: 293

While visibility is not an explicitly listed 

factor to consider when determining whether 

additional controls are reasonable, the 

purpose of the four-factor analysis is to 

determine what degree of progress toward 

natural visibility conditions is reasonable. 

Therefore, it is appropriate to consider the 

projected visibility benefit of the controls 

when determining if the controls are needed 

to make reasonable progress. 

For each unit, we are weighing the 

cost of compliance against the projected 

visibility benefit. 

1. Time Necessary for Compliance, and 

the Oklahoma and Texas RPGs 

We discuss the time necessary for 

compliance reasonable progress factor 

in our Reasonable Progress 

Guidance: 294

It may be appropriate for you to use this 

factor to adjust the RPG to reflect the degree 

of improvement in visibility achievable 

within the period of the first SIP if the time 

needed for full implementation of a control 

measure (or measures) will extend beyond 

2018. For example, if you anticipate that 

constraints on the availability of construction 

labor will preclude the installation of 

controls at all sources of a particular category 

by 2018, the visibility improvement 

anticipated from installation of controls at 

the percentage of sources that could be 

controlled within the strategy period should 

be considered in setting the RPG and in 

establishing the SIP requirements to meet the 

RPG. 

Due to delays in processing the Texas 

regional haze SIP and the remaining 

portion of the Oklahoma regional haze 

SIP, we cannot assume that the SO2

controls we are proposing will be 

installed and operational within this 

planning period, which ends in 2018. 

For instance, typical SO2 scrubber 

installations can take up to five years to 

plan, construct and bring to operational 

readiness. This would mean that any 

such controls that we may require in our 

final action may not be operational until 

after 2018. Therefore, although we are 

proposing revised RPGs for Oklahoma 

and Texas, we are proposing RPGs that 

only account for the scrubber upgrades 

included in this FIP anticipated to be 

completed by 2018. 

We request that Oklahoma and Texas 

consider the additional visibility 

improvements anticipated from any 

proposed FIP controls implemented 

after 2018 with the submission of their 

next regional haze SIPs due July 13, 

2018. 

2. Energy and Non-Air Quality 

Environmental Impacts of Compliance 

Regarding the analysis of energy 

impacts, the BART Guidelines advise, 

‘‘You should examine the energy 

requirements of the control technology 

and determine whether the use of that 

technology results in energy penalties or 

benefits.’’ 295 As discussed below in our 

cost analyses for Dry Sorbent Injection 

(DSI) and Spray Dryer Absorber (SDA) 

SO2 scrubbers, our cost model allows for 

the inclusion or exclusion of the cost of 

the additional auxiliary power required 

for the pollution controls we considered 

to be included in the variable operating 

costs. We chose to include this 

additional auxiliary power in all cases. 

Consequently, we believe that any 

energy impacts of compliance have been 

adequately considered in our analyses. 

Regarding the analysis of non-air 

quality environmental impacts, the 

BART Guidelines advise: 296

Such environmental impacts include solid 

or hazardous waste generation and 

discharges of polluted water from a control 

device. You should identify any significant 

or unusual environmental impacts associated 

with a control alternative that have the 

potential to affect the selection or elimination 

of a control alternative. Some control 

technologies may have potentially significant 

secondary environmental impacts. Scrubber 

effluent, for example, may affect water 

quality and land use. Alternatively, water 

availability may affect the feasibility and 

costs of wet scrubbers. Other examples of 

secondary environmental impacts could 

include hazardous waste discharges, such as 

spent catalysts or contaminated carbon. 

Generally, these types of environmental 

concerns become important when sensitive 

site-specific receptors exist or when the 

incremental emission reductions potential of 

the more stringent control is only marginally 

greater than the next most-effective option. 

However, the fact that a control device 

creates liquid and solid waste that must be 

disposed of does not necessarily argue 

against selection of that technology as BART, 

particularly if the control device has been 

applied to similar facilities elsewhere and the 

solid or liquid waste is similar to those other 

applications. On the other hand, where you 

or the source owner can show that unusual 

circumstances at the proposed facility create 

greater problems than experienced 

elsewhere, this may provide a basis for the 

elimination of that control alternative as 

BART. 

The SO2 control technologies we 

considered in our analysis—DSI and 

scrubbers—are in wide use in the coalfired electricity generation industry. 

Both technologies add spent reagent to 

the waste stream already generated by 

the facilities we analyzed, but do not 

present any unusual environmental 

impacts. As discussed below in our cost 

analyses for DSI and SDA SO2

scrubbers, our cost model includes 

waste disposal costs in the variable 

operating costs. Consequently, we 

believe that with one possible 

exception, any non-air quality 

environmental impacts have been 

adequately considered in our analyses. 

An examination of the aerial photo of 

the Tolk facility, which we present in 

our FIP TSD, does not reveal any 

obvious source of surface water. We 

therefore assume that well water is 

used. In light of this and its potential 

relationship to the energy and non-air 

quality environmental impacts of 

compliance, we limit our SO2 control 

analysis for Tolk to DSI and dry 

scrubbers. 

3. Remaining Useful Life 

Regarding the analysis of the 

remaining useful life, the BART 

Guidelines advise: 

The ‘‘remaining useful life’’ of a source, if 

it represents a relatively short time period, 

may affect the annualized costs of retrofit 

controls. For example, the methods for 

calculating annualized costs in EPA’s 

OAQPS Control Cost Manual require the use 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74875 

297Technical Support Document for the 

Oklahoma Regional Haze State Implementation 

Plan and Federal Implementation Plan. March 2011, 

p. 14. 

298http://corporate.ppg.com/Our-Company/

Worldwide-Operations/North-America/WichitaFalls. 

299Standard Permit Registration, PPG Industries, 

Inc., Wichita Falls Plant, Account No. WH–0040– 

R. Submitted by ENVIRON, dated October 11, 2007. 

300Permit Alteration, Permit Number: 898, Flat 

Glass Manufacturing Facility, Wichita Falls, 

Wichita County, Regulated Entity Number: 

RN102522950, Customer Reference Number: 

CN600124614, Account Number: WH–0040–R. 

301Permit Alteration, Permit Number: 898, Flat 

Glass Manufacturing Facility, Wichita Falls, 

Wichita County, Regulated Entity Number: 

RN102522950, Customer Reference Number: 

302TCEQ point source emission inventory. 

Downloaded from https://www.tceq.texas.gov/

airquality/point-source-ei/psei.html and available 

in the docket for this action. 

of a specified time period for amortization 

that varies based upon the type of control. If 

the remaining useful life will clearly exceed 

this time period, the remaining useful life has 

essentially no effect on control costs and on 

the BART determination process. Where the 

remaining useful life is less than the time 

period for amortizing costs, you should use 

this shorter time period in your cost 

calculations. 

In determining the cost of scrubbers 

in our prior Oklahoma FIP, we used a 

lifetime of 30 years. In so doing, we 

noted 297 that scrubber vendors indicate 

that the lifetime of a scrubber is equal 

to the lifetime of the boiler, which might 

easily be over 60 years. We also noted 

that many scrubbers that were installed 

between 1975 and 1986 are still in 

operation today (e.g., Coyote Station, 

H.L. Spurlock Unit 2, East Bend Unit 2, 

Laramie River Unit 3, Cholla 5, Basin 

Electric, Mitchell Unit 33, and all of the 

units in Table 30 that currently have 

scrubbers). Further, we noted that 

standard cost estimating handbooks and 

published papers report 30 years as a 

typical life for a scrubber and that many 

utilities routinely specify 30+ year 

lifetimes in requests for proposal and to 

evaluate proposals. We have used this 

30 year lifetime approach in prior 

actions and we therefore adopted the 

same scrubber lifetime in our present 

analysis. See 76 FR 52388 (Aug. 22. 

2011); 76 FR 81728 (Dec. 28, 2011); 

Oklahoma v. EPA, 723 F.3d 1201 (July 

19, 2013), cert. denied (U.S. May 27, 

2014). 

We see no reason to assume that a DSI 

system installation, which is a much 

less complex and costly (capital costs, 

as opposed to annualized costs) 

technology in comparison to a scrubber 

installation, should have a shorter 

lifetime. As with a scrubber, we expect 

the boiler to be the limiting factor when 

considering the lifetime of a coal-fired 

power plant. We have therefore 

similarly assumed that the lifetime of a 

DSI system is 30 years, as constrained 

by the boiler lifetime, as noted above. 

The BART Guidelines provide further 

clarification: 

Where this affects the BART 

determination, this date should be assured by 

a federally- or State-enforceable restriction 

preventing further operation. We recognize 

that there may be situations where a source 

operator intends to shut down a source by a 

given date, but wishes to retain the flexibility 

to continue operating beyond that date in the 

event, for example, that market conditions 

change. Where this is the case, your BART 

analysis may account for this, but it must 

maintain consistency with the statutory 

requirement to install BART within 5 years. 

Where the source chooses not to accept a 

federally enforceable condition requiring the 

source to shut down by a given date, it is 

necessary to determine whether a reduced 

time period for the remaining useful life 

changes the level of controls that would have 

been required as BART. 

As in a BART determination, we 

propose to adopt the same requirement 

regarding the need for a federally 

enforceable restriction for any DSI or 

scrubber remaining useful life of less 

than 30 years. 

4. Analysis of the PPG Flat Glass Plant 

The Wichita Falls PPG flat glass plant 

is located in Wichita Falls, Texas. The 

plant began operations in 1974.298 The 

facility produces flat glass on two 

production lines, each with its own 

natural gas furnace. A furnace typically 

lasts ten to twelve years until rebricking is required. In 2007, PPG 

applied to the TCEQ for a standard 

permit registration 299 in order to obtain 

authorization for the implementation of 

a low-NOX oxy-fuel injection conversion 

to its Melting Furnace No. 1. As a result 

of this upgrade, PPG calculated its NOX

emissions from Furnace No. 1 would 

decrease by approximately 1,996 tpy to 

894.25 tpy. PPG also further reduced 

their NOX emissions as a result of a fuel 

conservation project which occurred 

with the rebuilding of Furnace No. 2. 

This project lowered the NOX emissions 

of Furnace No. 2 from an allowable 

annual NOX limit of 3,236.82 tpy to 

2,947.49 tpy. These reductions were 

incorporated into a permit alteration.300

Table 31 below compares the 2018 

projected CENRAP emission inventory 

to the 2002 CENRAP emission 

inventory, the current permit limits for 

the two furnaces, and average actual 

annual emissions for the facility. We 

projected the visibility impact from this 

facility at the 2018 projected emission 

level to be 0.635 Mm¥1 at the Wichita 

Mountains (using source 

apportionment). Permit allowable 

emissions for NOX for the two furnaces 

are much lower than projected and 

modeled for 2018 and lower than the 

2002 emission level. The 2018 projected 

emissions for SO2 also exceed the 

permitted emissions for furnace No. 2. 

Average annual emissions are only 44% 

of the projected 2018 emissions for NOX

and 81% of the projected SO2

emissions. Therefore, we estimate that 

the current visibility impact due to the 

facility is significantly lower than the 

2018 projected value. We are proposing 

to find that the Wichita Falls PPG flat 

glass plant is adequately controlled to 

address visibility impacts from this 

facility for the first planning period. We 

encourage the State of Texas to revisit 

this issue when Furnace No. 2 is 

scheduled for its next re-bricking. 

TABLE 31—EMISSION COMPARISON FOR PPG FLAT GLASS PLANT

CENRAP 2002 emission 

inventory 

(tpy) 

CENRAP 2018 emission 

inventory 

(tpy) 

Permit allowable 301

(tpy) 

Average annual 

emissions 

(tpy, 2009–2012) 302

NOX SO2 NOX SO2 NOX SO2 NOX SO2

Furnace No. 1 .................. 2,694.5 48.0 4,526.8 80.7 894.3 180.3 .................... ....................

Furnace No. 2 .................. 2,495.2 279.7 4,191.9 470.0 2,947.5 350.4 .................... ....................

Furnace No. 1 and No. 2 5,189.7 327.7 8,718.8 550.6 3,841.7 530.7 .................... ....................

Facility total ...................... 5,317.0 371.0 8,929.0 623.0 .................... .................... 3,887.8 501.9 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74876 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

303 In this table, the capital cost is the total cost 

of constructing the facility. The annualized cost is 

the sum of the annualized capital cost and the 

annualized operational cost. See our Cost TSD for 

more information on how these costs were 

calculated. 

E. Use of Confidential Business 

Information 

Within our Cost TSD, we calculate the 

SO2 removal efficiencies for the 

underperforming scrubbers listed in 

Table 30, and present information that 

discusses how these scrubbers have 

been historically upgraded and what 

kinds of equipment revisions are 

typically required. In order to assess the 

potential range of options available to 

upgrade the scrubbers in the facilities 

listed in Table 30, we must have an 

understanding of what upgrades may 

have already been performed. Because 

most of this information is not available 

publicly, we requested it under 

authority granted to us under Section 

114(a) of the CAA. For each unit, we 

then conducted a cost analysis for 

eliminating any scrubber bypass and 

upgrading the units’ overall SO2

removal efficiency to at least 95%. As 

most of the information we received in 

response to our Section 114(a) requests 

was claimed as Confidential Business 

Information (CBI) under 40 CFR part 2, 

subpart B, we are limited in what we are 

able to publicly state in this analyses. 

Consequently, although our full cost 

analysis is available on a facility-byfacility basis for viewing by the 

companies who provided us with the 

CBI material, we can only provide a 

summary of it below. 

F. Reasonable Progress and Long-Term 

Strategy Scrubber and DSI Cost Results 

As we discuss in our Cost TSD, we 

evaluated each unit at its maximum 

recommended level of control, 

considering the type of SO2 control 

device: 

• We evaluated each unit at its 

maximum recommended DSI 

performance level, according to the IPM 

DSI documentation, assuming milled 

trona: 80% SO2 removal for an ESP 

installation and 90% SO2 removal for a 

baghouse installation. This level of 

control is within the range of control of 

SO2 scrubbers, and thus allows a better 

comparison of the costs of DSI and 

scrubbers. 

• However, we believe that the 

maximum performance level for DSI can 

only be determined after an onsite 

performance test. We believe it is useful 

to evaluate lesser levels of DSI control 

(and correspondingly lower costs). We 

therefore also evaluated all the units at 

a DSI SO2 control level of 50%, which 

we believe is likely achievable for any 

unit. 

• The SDA level of control was 

assumed to be a maximum of 95% not 

to go below 0.06 lbs/MMBtu. 

• The wet FGD level of control was 

assumed to be a maximum of 98% not 

to go below 0.04 lbs/MMBtu. 

Below, we present a summary of our 

DSI, SDA, and wet FGD cost analysis:303

TABLE 32—SUMMARY OF DSI, SDA, AND WET FGD COST ANALYSIS

Facility Unit Control 

Control 

level 

(%) 

SO2

Reduction 

(tpy) 

$/Ton 

reduced Capital cost Annualized cost 

Big Brown ............................................................ 1 DSI 50.0 15,334 $2,223 $19,096,000 $34,086,871 

DSI 90.0 27,600 2,996 33,357,000 82,684,241 

SDA 95.0 29,134 1,377 226,656,000 40,104,566 

Wet FGD 98.0 30,054 1,255 256,032,000 37,708,999 

2 DSI 50.0 15,407 2,201 19,035,000 33,909,822 

DSI 90.0 27,733 2,994 32,965,000 81,649,586 

SDA 95.0 29,273 1,373 229,544,000 40,185,893 

Wet FGD 97.9 30,169 1,257 259,141,000 37,909,708 

Monticello ............................................................. 1 DSI 50.0 8,933 2,728 17,137,000 24,364,819 

DSI 90.0 16,079 3,420 23,580,000 54,991,417 

SDA 95.0 16,972 2,012 224,262,000 34,154,932 

Wet FGD 97.0 17,328 1,937 250,804,000 33,558,169 

2 DSI 50.0 8,215 3,086 17,057,000 25,351,370 

DSI 90.0 14,786 3,845 23,468,000 56,850,489 

SDA 95.0 15,608 2,254 227,409,000 35,183,025 

Wet FGD 96.8 15,907 2,170 254,177,000 34,523,884 

Coleto Creek ........................................................ 1 DSI 50.0 8,030 2,792 15,888,000 22,416,218 

DSI 90.0 14,453 3,460 21,863,000 50,001,685 

SDA 93.5 15,012 2,356 240,408,000 35,366,916 

Wet FGD 95.7 15,361 2,278 262,435,000 34,996,979 

Tolk ...................................................................... 171B DSI 50.0 5,016 3,084 13,938,000 15,465,578 

DSI 90.0 9,028 3,592 19,179,000 32,426,429 

SDA 91.7 9,195 3,178 218,306,000 29,218,836 

Wet FGD 94.4 9,474 3,204 243,048,000 30,352,765 

172B DSI 50.0 5,517 2,828 13,873,000 15,600,155 

DSI 90.0 9,931 3,221 19,090,000 31,985,880 

SDA 90.8 10,015 2,998 226,957,000 30,022,609 

Wet FGD 93.8 10,355 3,019 252,559,000 31,257,301 

Welsh ................................................................... 1 DSI 50.0 4,042 3,718 14,888,000 15,026,538 

DSI 80.0 6,467 4,019 18,901,000 25,992,966 

SDA 88.7 7,169 3,489 201,549,000 25,009,785 

Wet FGD 92.5 7,474 3,508 221,282,000 26,216,294 

2 DSI 50.0 4,128 3,611 14,775,000 14,906,814 

DSI 80.0 6,605 3,879 18,758,000 25,622,166 

SDA 88.2 7,285 3,438 202,108,000 25,045,518 

Wet FGD 92.2 7,608 3,454 221,821,000 26,276,805 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74877 

TABLE 32—SUMMARY OF DSI, SDA, AND WET FGD COST ANALYSIS—Continued 

Facility Unit Control 

Control 

level 

(%) 

SO2

Reduction 

(tpy) 

$/Ton 

reduced Capital cost Annualized cost 

3 DSI 50.0 4,305 3,690 15,023,000 15,884,663 

DSI 80.0 6,887 3,998 19,071,000 27,531,831 

SDA 88.7 7,634 3,368 204,177,000 25,713,148 

Wet FGD 92.5 7,959 3,379 224,298,000 26,895,390 

W. A. Parish ......................................................... 5 DSI 50.0 7,079 2,559 15,227,000 18,111,990 

DSI 90.0 12,741 2,995 20,953,000 38,161,382 

SDA 92.5 13,095 2,441 240,112,000 31,970,651 

Wet FGD 95.0 13,449 2,389 260,195,000 32,124,808 

6 DSI 50.0 7,654 2,699 15,934,000 20,660,436 

DSI 90.0 13,776 3,229 21,924,000 44,478,086 

SDA 93.1 14,251 2,401 248,503,000 34,220,158 

Wet FGD 95.4 14,603 2,334 270,350,000 34,085,705 

7 DSI 50.0 6,168 2,805 14,641,000 17,301,527 

DSI 90.0 11,102 3,296 20,145,000 36,594,402 

SDA 92.7 11,432 2,559 211,443,000 29,250,022 

Wet FGD 95.1 11,733 2,542 233,698,000 29,821,127 

G. Reasonable Progress and Long-Term 

Strategy Scrubber Upgrade Cost Results 

In our Cost TSD, we analyze those 

units listed in Table 30 with an existing 

SO2 scrubber in order to determine if 

cost-effective scrubber upgrades are 

available. Because all of the scrubber 

systems we evaluate are wet scrubbers, 

we limit our analyses of scrubber 

upgrades to wet scrubbers. Below, we 

present a summary of the results of that 

analysis. 

With the exception of San Miguel, we 

are limited in what information we can 

include in this section, because in 

developing our scrubber cost estimates 

we used information that was claimed 

as CBI. This information was submitted 

in response to our Section 114(a) 

requests. We can therefore only present 

the following summary. With the 

exception of San Miguel, we propose to 

find that for all the units we analyzed: 

• The absorber system had either 

already been upgraded to perform at an 

SO2 removal efficiency of at least 95%, 

or it could be upgraded to perform at 

that level using proven equipment and 

techniques. 

• The SO2 scrubber bypass could be 

eliminated, and the additional flue gas 

could be treated by the absorber system 

with at least a 95% removal efficiency. 

• Additional modifications necessary 

to eliminate the bypass, such as adding 

fan capacity, upgrading the electrical 

distribution system, and conversion to a 

wet stack could be performed using 

proven equipment and techniques. 

• The additional SO2 emission 

reductions resulting from the scrubber 

upgrade are substantial, ranging from 

68% to 89% reduction from the current 

emission levels, and are cost-effective. 

A summary of our analyses is as 

follows: 

TABLE 33—SUMMARY OF SCRUBBER UPGRADE RESULTS

Unit 

2009–2013 

3-Year avg. SO2

emissions 

(eliminate max 

and min) 

(tons) 

SO2 Emissions at 

95% control 

(tons) 

SO2 Emission 

reduction due to 

scrubber upgrade 

(tons) 

SO2 Emission rate 

at 95% control 

(lbs/MMBtu) 

W. A. Parish WAP8 ................................................................. 2,586 836 1,750 0.04 

Monticello 3 .............................................................................. 13,857 1,571 12,286 0.06 

Sandow 4 ................................................................................. 22,289 4,625 17,664 0.20 

Martin Lake 1 ........................................................................... 24,495 3,706 20,789 0.12 

Martin Lake 2 ........................................................................... 21,580 3,664 17,917 0.12 

Martin Lake 3 ........................................................................... 19,940 3,542 16,389 0.11 

Limestone 1 ............................................................................. 10,913 2,466 8,446 0.08 

Limestone 2 ............................................................................. 11,946 2,615 9,331 0.08 

We calculated the cost-effectiveness 

for each of these units. Because those 

calculations depended on information 

claimed by the companies as CBI we 

cannot present it here, except to note 

that in all cases, the cost-effectiveness 

was less than $600/ton. We invite the 

facilities listed above to make 

arrangements with us to view the full 

cost analysis for their units. 

H. Summary of the Modeled Benefits of 

Emission Controls 

Prior to doing the control cost 

evaluations discussed in the sections 

above, we conducted several steps in 

support of our review which was 

ultimately used in our proposed FIP. We 

initially conducted a Q/D analysis on all 

facilities in Texas, using the distances to 

Class I areas in Texas and surrounding 

states. This Q/D analysis narrowed the 

list of over 1,600 facilities to 38 

facilities. We chose to use the CENRAP 

photochemical modeling platform with 

some minor upgrades to evaluate the 38 

facilities and determine if this smaller 

subset of sources, or individual sources, 

would yield visibility benefits worth 

considering for reasonable progress 

analysis. We chose to use the CAMx 

photochemical model instead of 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74878 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

CALPUFF for several reasons, 

including: 

• The large distances between sources 

and Class I areas are outside the typical 

range of CALPUFF. Because of the 

range, we were concerned that 

CALPUFF could overestimate impacts. 

• Using a photochemical model 

allowed us to assess improvements on 

the 20% worst and the 20% best days. 

• Using a photochemical model 

allowed us to use a more refined 

chemistry mechanism and use the same 

scientific tools used for reasonable 

progress analysis at Class I areas. 

• CAMx has both PSAT and PlumeIn-Grid capabilities, whereas the other 

available photochemical model CMAQ 

(Community Multi-scale Air Quality 

modeling system) did not have these 

tools. 

Full details of our Q/D and initial 

evaluation of 38 facilities with CAMx 

are discussed further in Appendix A of 

our FIP TSD. Based on the results of 

modeling the 38 facilities, we further 

narrowed the list to the smaller group of 

sources that we evaluated in a second 

round of CAMx modeling. Please see 

Appendix A of our FIP TSD, where we 

describe in detail the different modeling 

runs we conducted for our review, our 

methodology and selection of emission 

rates, our modeling results, and our 

final modeling analysis that we used to 

evaluate the benefits of the proposed 

controls and their associated emission 

decreases on visibility impairment 

values. We used modeling results from 

the initial modeling and a second round 

of modeling to estimate the benefits of 

emission reductions from controls/

control upgrades. Below we present a 

summary of our analysis and our 

proposed findings regarding the 

estimated visibility benefits of emission 

reductions based on the CAMx 

modeling results. 

Our modeling focused on calculating 

the extinction and visibility impacts and 

benefits at the Wichita Mountains, the 

Guadalupe Mountains, and Big Bend 

primarily, but also included analysis at 

a number of other Class I areas in states 

surrounding Texas. In so doing, we 

focused on the same sources listed in 

Table 30, above, that we did in our 

control cost evaluations. In evaluating 

the impacts and benefits of potential 

controls, we utilized a number of 

metrics, including change in deciviews 

in 2018 and natural conditions 

situations, change in extinction, change 

in percentage of total extinction, recent 

actuals vs. CENRAP 2018 projections, 

etc. For a full discussion of our review 

of all the modeling results, and factors 

that we considered in evaluating and 

weighing all the results, precedents, 

please see Appendix A of our FIP TSD. 

Below, we present the modeled 

visibility impacts based on their 

percentage extinction levels for the 20% 

worst days for the Wichita Mountains, 

Big Bend, and the Guadalupe 

Mountains: 

BILLING CODE 6560–50–P 


mstockstill on DSK4VPTVN1PROD with PROPOSALS2EP16DE14.000</GPH>
Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74879 


mstockstill on DSK4VPTVN1PROD with PROPOSALS2EP16DE14.001</GPH>

Figure 2. Extinction level and percent of total extinction at Big Bend for 20% worst 

days for the 9 facilities 

at 

I I I 

• 
74880 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

BILLING CODE 6560–50–C 

In Figures 1, 2, and 3, above, the 

visibility impacts from all of the units 

in Table 30 are represented, with the 

exception of San Miguel, for the reasons 

we discuss below in Section VII.I. In 

addition, the collective visibility impact 

from the remaining 29 sources which 

included San Miguel and 28 sources we 

elected not to include in our control 

cost analysis are also represented. As 

shown by Figure 1, a number of these 

facilities have significant visibility 

impacts at the Wichita Mountains. For 

instance, using actual emissions, Big 

Brown alone accounts for an impact 

equivalent to more than 1⁄3 of the total 

impact from point sources within the 

State of Oklahoma. Visibility impacts 

from these sources at Texas’ Class I 

areas are much more limited. 

In evaluating benefits of potential 

controls, we also considered estimated 

deciview improvements based on both a 

degraded 2018 background and a 

‘‘clean’’ background based on average 

annual natural conditions, as shown in 

the tables below. Because our analysis is 

based on a full photo-chemical grid 

model that includes modeling all 

emissions in the modeling domain, the 

model results are inherently a degraded 

background analysis and the results are 

impacted by emissions from other 

sources. To estimate the full benefit of 

reductions on a source we have 

estimated the ‘‘clean’’ background 

results based on the modeled extinction 

impact levels for each source and 

calculated the del-dv based on annual 

average natural conditions. A true 

‘‘clean’’ background model would not 

include interactions from emissions 

from other sources. Due to the inclusion 

of all these other sources at 2018 

estimated emission levels, the estimated 

impacts from a source (or from 

controlling a source) are less than the 

results that would be obtained using 

emission levels of sources that would 

exist when natural conditions are 

achieved. We note that CALPUFF based 

modeling simulates ‘clean’ background 

conditions with no other sources 

included than the source(s) being 

evaluated. See our FIP TSD for more 

discussion on this issue. The deciview 

improvement based on the 2018 

background conditions provides an 

estimate of the amount of benefit that 

can be anticipated in 2018 and the 

impact a control may have on the 

established RPG for 2018. However, this 

estimate based on degraded or ‘‘dirty’’ 

background conditions underestimates 

the visibility improvement that would 

be realized for the control options under 

consideration. Because of the non-linear 

nature of the deciview metric, as a Class 

I area becomes more polluted the 

visibility impairment from an 

individual source in terms of deciviews 

becomes geometrically less. Results 

based solely on a degraded background, 

will rarely if ever demonstrate an 

appreciable effect on incremental 

visibility improvement in a given area. 

Rather than providing for incremental 

improvements towards the goal of 


mstockstill on DSK4VPTVN1PROD with PROPOSALS2EP16DE14.002</GPH>
Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74881 

304 77 FR 20912 (Apr. 6, 2012). 305Our multiple CAMx runs yielded data on three 

or more levels of emissions (controlled and 

uncontrolled) on a number of facilities and based 

on the data a linear relationship between emission 

level and visibility impairment on a source specific 

basis is a reasonable analytical approach. See FIP 

TSD Appendix A for more details. 

natural visibility, degraded background 

results will serve to instead maintain 

those current degraded conditions. 

Therefore, the visibility benefit 

estimated based on natural or ‘‘clean’’ 

conditions is needed to assess the full 

benefit from potential controls. In our 

final decision for our North Dakota SIP 

and FIP,304 we explained this by noting: 

This is true because of the nonlinear nature 

of visibility impairment. In other words, as 

a Class I area becomes more polluted, any 

individual source’s contribution to changes 

in impairment becomes geometrically less. 

Therefore the more polluted the Class I area 

would become, the less control would seem 

to be needed from an individual source. 

The Eighth Circuit Court upheld this 

point in North Dakota v. EPA. 730 F.3d 

750, 766 (8th Cir. 2013). 

1. Visibility Benefits of DSI, SDA, and 

Wet FGD 

We evaluated the visibility benefits of 

DSI, for the thirteen units depicted in 

Table 30 that currently have no SO2

control. We evaluated all the units using 

the same control levels we employed in 

our control cost analyses. In summary, 

we evaluated these units at a DSI SO2

control level of 50%, which we believe 

is likely achievable for any unit. We also 

evaluated each unit at its maximum 

recommended DSI performance level, of 

80% SO2 removal for an ESP 

installation and 90% SO2 removal for a 

baghouse installation. As we note in 

Section VII.F, we believe these are 

maximum performance levels for DSI 

but we do not know whether a given 

unit is actually capable of achieving 

these DSI control levels. At the lower 

performance level we assumed, we 

conclude that the corresponding 

visibility benefits from DSI would also 

be close to half of the benefits from 

scrubbers resulting in the visibility 

benefits from scrubber retrofits being 

much more beneficial.305

We also evaluated the visibility 

benefits for scrubber retrofits (wet FGD 

and SDA) for these same units, 

assuming the same control levels 

corresponding to SDA and wet FGD that 

we used in our control cost analyses. 

The visibility benefits from DSI, SDA, 

and wet FGD are quantified specifically 

in Appendix A of our FIP TSD. Below, 

we present a summary of some of those 

visibility benefits: 

TABLE 34—AVERAGE CHANGE IN DECIVIEW LEVELS AT THE WICHITA MOUNTAINS FOR THE 20% WORST DAYS

Unit 

Visibility improvement 2018 background 

(Environ) 

Visibility improvement (average natural conditions) 

DSI Low DSI High SDA WFGD WFGD 

Upgrade 

DSI Low DSI High SDA WFGD WFGD 

Upgrade 

Big Brown 1 .............. 0.045 0.081 0.085 0.088 ................ 0.225 0.401 0.423 0.436 ................

Big Brown 2 .............. 0.045 0.081 0.086 0.088 ................ 0.226 0.403 0.425 0.438 ................

Coleto Creek 1 ......... 0.021 0.038 0.039 0.040 ................ 0.105 0.189 0.196 0.200 ................

Limestone 1 .............. ................ ................ ................ ................ 0.027 ................ ................ ................ ................ 0.135 

Limestone 2 .............. ................ ................ ................ ................ 0.030 ................ ................ ................ ................ 0.149 

Martin Lake 1 ........... ................ ................ ................ ................ 0.047 ................ ................ ................ ................ 0.234 

Martin Lake 2 ........... ................ ................ ................ ................ 0.040 ................ ................ ................ ................ 0.202 

Martin Lake 3 ........... ................ ................ ................ ................ 0.037 ................ ................ ................ ................ 0.185 

Monticello 1 .............. 0.026 0.047 0.050 0.051 ................ 0.132 0.236 0.249 0.254 ................

Monticello 2 .............. 0.024 0.043 0.046 0.047 ................ 0.121 0.217 0.229 0.233 ................

Monticello 3 .............. ................ ................ ................ ................ 0.036 ................ ................ ................ ................ 0.181 

Sandow 4 ................. ................ ................ ................ ................ 0.062 ................ ................ ................ ................ 0.312 

Tolk 171b ................. 0.004 0.006 0.006 0.007 ................ 0.018 0.032 0.033 0.034 ................

Tolk 172b ................. 0.004 0.007 0.007 0.007 ................ 0.020 0.035 0.036 0.037 ................

WA Parish 5 ............. 0.012 0.022 0.023 0.023 ................ 0.062 0.111 0.114 0.117 ................

WA Parish 6 ............. 0.013 0.024 0.025 0.025 ................ 0.067 0.120 0.124 0.127 ................

WA Parish 7 ............. 0.011 0.019 0.020 0.020 ................ 0.054 0.097 0.099 0.102 ................

WA Parish 8 ............. ................ ................ ................ ................ 0.003 ................ ................ ................ ................ 0.015 

Welsh 1 .................... 0.012 0.019 0.021 0.022 ................ 0.059 0.094 0.105 0.109 ................

Welsh 2 .................... 0.012 0.019 0.021 0.022 ................ 0.060 0.096 0.106 0.111 ................

Welsh 3 .................... 0.012 0.020 0.022 0.023 ................ 0.063 0.101 0.111 0.116 ................

TABLE 35—AVERAGE CHANGE IN DECIVIEW LEVELS AT BIG BEND FOR THE 20% WORST DAYS

Unit 

Visibility improvement 2018 background 

(Environ) 

Visibility improvement (average natural conditions) 

DSI low DSI high SDA WFGD WFGD 

upgrade 

DSI low DSI high SDA WFGD WFGD 

upgrade 

Big Brown 1 .............. 0.012 0.021 0.022 0.023 ................ 0.046 0.082 0.086 0.089 ................

Big Brown 2 .............. 0.012 0.021 0.022 0.023 ................ 0.046 0.082 0.087 0.089 ................

Coleto Creek 1 ......... 0.018 0.033 0.034 0.035 ................ 0.071 0.128 0.133 0.136 ................

Limestone 1 .............. ................ ................ ................ ................ 0.008 ................ ................ ................ ................ 0.033 

Limestone 2 .............. ................ ................ ................ ................ 0.009 ................ ................ ................ ................ 0.036 

Martin Lake 1 ........... ................ ................ ................ ................ 0.008 ................ ................ ................ ................ 0.030 

Martin Lake 2 ........... ................ ................ ................ ................ 0.007 ................ ................ ................ ................ 0.026 

Martin Lake 3 ........... ................ ................ ................ ................ 0.006 ................ ................ ................ ................ 0.023 

Monticello 1 .............. 0.003 0.005 0.005 0.006 ................ 0.011 0.020 0.021 0.022 ................

Monticello 2 .............. 0.003 0.005 0.005 0.005 ................ 0.010 0.018 0.019 0.020 ................

Monticello 3 .............. ................ ................ ................ ................ 0.004 ................ ................ ................ ................ 0.015 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74882 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

TABLE 35—AVERAGE CHANGE IN DECIVIEW LEVELS AT BIG BEND FOR THE 20% WORST DAYS—Continued 

Unit 

Visibility improvement 2018 background 

(Environ) 

Visibility improvement (average natural conditions) 

DSI low DSI high SDA WFGD WFGD 

upgrade 

DSI low DSI high SDA WFGD WFGD 

upgrade 

Sandow 4 ................. ................ ................ ................ ................ 0.026 ................ ................ ................ ................ 0.102 

Tolk 171b ................. 0.002 0.003 0.003 0.003 ................ 0.007 0.012 0.013 0.013 ................

Tolk 172b ................. 0.002 0.003 0.003 0.004 ................ 0.008 0.014 0.014 0.014 ................

WA Parish 5 ............. 0.007 0.013 0.013 0.014 ................ 0.028 0.051 0.052 0.054 ................

WA Parish 6 ............. 0.008 0.014 0.015 0.015 ................ 0.031 0.055 0.057 0.058 ................

WA Parish 7 ............. 0.006 0.011 0.012 0.012 ................ 0.025 0.044 0.046 0.047 ................

WA Parish 8 ............. ................ ................ ................ ................ 0.002 ................ ................ ................ ................ 0.007 

Welsh 1 .................... 0.001 0.002 0.002 0.002 ................ 0.005 0.008 0.008 0.009 ................

Welsh 2 .................... 0.001 0.002 0.002 0.002 ................ 0.005 0.008 0.009 0.009 ................

Welsh 3 .................... 0.001 0.002 0.002 0.002 ................ 0.005 0.008 0.009 0.009 ................

TABLE 36—AVERAGE CHANGE IN DECIVIEW LEVELS AT THE GUADALUPE MOUNTAINS FOR THE 20% WORST DAYS

Unit 

Visibility improvement 2018 background 

(Environ) 

Visibility improvement (average natural conditions) 

DSI Low DSI High SDA WFGD WFGD 

Upgrade 

DSI low DSI high SDA WFGD WFGD 

upgrade 

Big Brown 1 .............. 0.014 0.024 0.026 0.027 ................ 0.054 0.096 0.101 0.105 ................

Big Brown 2 .............. 0.014 0.025 0.026 0.027 ................ 0.054 0.097 0.102 0.105 ................

Coleto Creek 1 ......... 0.006 0.010 0.011 0.011 ................ 0.023 0.041 0.043 0.044 ................

Limestone 1 .............. ................ ................ ................ ................ 0.009 ................ ................ ................ ................ 0.037 

Limestone 2 .............. ................ ................ ................ ................ 0.010 ................ ................ ................ ................ 0.041 

Martin Lake 1 ........... ................ ................ ................ ................ 0.010 ................ ................ ................ ................ 0.041 

Martin Lake 2 ........... ................ ................ ................ ................ 0.009 ................ ................ ................ ................ 0.036 

Martin Lake 3 ........... ................ ................ ................ ................ 0.008 ................ ................ ................ ................ 0.033 

Monticello 1 .............. 0.004 0.006 0.007 0.007 ................ 0.014 0.025 0.027 0.027 ................

Monticello 2 .............. 0.003 0.006 0.006 0.006 ................ 0.013 0.023 0.024 0.025 ................

Monticello 3 .............. ................ ................ ................ ................ 0.005 ................ ................ ................ ................ 0.019 

Sandow 4 ................. ................ ................ ................ ................ 0.017 ................ ................ ................ ................ 0.069 

Tolk 171b ................. 0.012 0.022 0.022 0.023 ................ 0.048 0.085 0.087 0.090 ................

Tolk 172b ................. 0.013 0.024 0.024 0.025 ................ 0.052 0.094 0.095 0.098 ................

WA Parish 5 ............. 0.003 0.006 0.006 0.006 ................ 0.013 0.023 0.024 0.024 ................

WA Parish 6 ............. 0.004 0.006 0.007 0.007 ................ 0.014 0.025 0.026 0.027 ................

WA Parish 7 ............. 0.003 0.005 0.005 0.005 ................ 0.011 0.020 0.021 0.021 ................

WA Parish 8 ............. ................ ................ ................ ................ 0.001 ................ ................ ................ ................ 0.003 

Welsh 1 .................... 0.002 0.003 0.003 0.003 ................ 0.007 0.011 0.012 0.012 ................

Welsh 2 .................... 0.002 0.003 0.003 0.003 ................ 0.007 0.011 0.012 0.012 ................

Welsh 3 .................... 0.002 0.003 0.003 0.003 ................ 0.007 0.011 0.012 0.013 ................

The tables above show the estimated 

benefit (in deciviews) anticipated from 

the evaluated controls at each unit on 

the 20% worst days for each Class I 

area, considering both ‘‘dirty’’ 

background conditions projected in 

2018 modeling completed by Environ 

and the ‘‘clean’’ background conditions 

consistent with the estimated annual 

average natural conditions. We weighed 

these del-dv benefits, as well as 

extinction benefits and percentage of 

total extinction basis information, as 

further discussed in our TSD, in making 

our proposed findings about the benefits 

of potential controls. For brevity we are 

not including all the information that 

we considered which is discussed in 

FIP TSD Appendix A. Based on the 

information presented here and in our 

TSD materials, we propose to find that 

installing either wet FGD or SDA 

scrubbers on five of these units would 

yield significant visibility 

improvements at the Wichita 

Mountains. These five units are: Big 

Brown 1 and 2, Coleto Creek, and 

Monticello 1 and 2. We propose to find 

that scrubber installations on Big Brown 

1 and 2 would also yield significant 

benefits at both Guadalupe Mountains 

and Big Bend, and that a scrubber 

installation on the Coleto Creek unit 

would also yield significant visibility 

benefits at Big Bend. 

In comparison to the above five units, 

we propose to find that the visibility 

benefits from installing scrubbers on the 

W. A. Parish 5, 6, and 7 units; and 

Welsh 1, 2, and 3 units would not yield 

large enough visibility benefits to be 

considered at this time. 

We also evaluated the visibility 

benefits of installing scrubbers on Tolk 

units 171B and 172B, limiting our 

analysis to SDA. The visibility benefits 

of SDA scrubbers on the Tolk units are 

projected to occur mainly at the 

Guadalupe Mountains. We note that the 

deciview visibility benefits projected at 

the Guadalupe Mountains from controls 

on the Tolk units are smaller than those 

from scrubber upgrades at W. A. Parish 

or Welsh for impacts at the Wichita 

Mountains. However, when we 

evaluated other metrics, such as 

extinction benefit or percent of 

extinction benefits, we believe that the 

overall visibility benefit for installing 

scrubbers on the Tolk units was 

superior to either the W. A. Parish or the 

Welsh units. In particular, the Wichita 

Mountains has a much higher total 

extinction for the baseline and the 2018 

projection than the Guadalupe 

Mountains, so the relative improvement 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74883 

in extinction levels is higher when the 

Tolk units are controlled for the 

Guadalupe Mountains, than if the W. A. 

Parish or the Welsh units were 

controlled for the Wichita Mountains. 

Therefore, considering all the visibility 

benefits relative to the respective Class 

I areas, we propose to find that the 

visibility benefits from installation of 

dry scrubbers on the Tolk units would 

be significant and beneficial towards the 

goal of meeting natural visibility 

conditions at Guadalupe Mountains. 

2. Visibility Benefits of Scrubber 

Upgrades 

We also modeled the visibility 

benefits of those same units for which 

we conducted control cost analysis for 

upgrading their existing scrubbers. We 

assumed the same 95% control level we 

used in our control cost analyses. The 

visibility benefits from these scrubber 

upgrades are quantified specifically in 

Appendix A of our FIP TSD. Below, we 

present a summary of the del-dv 

visibility benefits. For the other 

visibility benefit results based on 

extinction and percentage of extinction 

see Appendix A of our FIP TSD. 

TABLE 37—DECIVIEW IMPROVEMENT AT CLASS I AREAS FOR SCRUBBER UPGRADES

Emission unit Control 

(%) 

SO2

Reduction 

(tpy) 

WIMO BIBE GUMO 

2018 avg. NC 2018 avg. NC 2018 avg. NC 

Limestone 1 ..................... 95 8,446 0.027 0.135 0.008 0.033 0.009 0.037 

Limestone 2 ..................... 95 9,331 0.030 0.149 0.009 0.036 0.010 0.041 

Martin Lake 1 ................... 95 20,789 0.047 0.234 0.008 0.030 0.010 0.041 

Martin Lake 2 ................... 95 17,917 0.040 0.202 0.007 0.026 0.009 0.036 

Martin Lake 3 ................... 95 16,389 0.037 0.185 0.006 0.023 0.008 0.033 

Monticello 3 ...................... 95 12,286 0.036 0.181 0.004 0.015 0.005 0.019 

Sandow 4 ......................... 95 17,664 0.062 0.312 0.026 0.102 0.017 0.069 

WA Parish 8 ..................... 95 1,750 0.003 0.015 0.002 0.007 0.001 0.003 

Our review of the impacts/benefits of 

scrubber upgrades on eight units at five 

facilities show that scrubber upgrades 

conducted at seven of the eight units 

would result in significant visibility 

improvements at the Wichita 

Mountains. These seven units are: 

Limestone 1 and 2; Martin Lake 1, 2, 

and 3; Monticello 3; and Sandow 4. We 

also project some visibility benefit at Big 

Bend, the Guadalupe Mountains and 

other Class I areas. We propose to find 

that the level of visibility improvement 

from a scrubber upgrade on W. A. Parish 

8 to be relatively small in comparison to 

the other units we evaluated, and not 

large enough to consider as beneficial at 

this time. 

I. Proposed Reasonable Progress and 

Long-Term Strategy Determinations 

Below, we present our proposed 

reasonable progress and long-term 

strategy determinations for our Texas 

and Oklahoma FIPs. This includes 

proposed determinations for those units 

with no SO2 controls for which we 

conducted DSI, SDA, and wet FGD cost 

analysis and visibility modeling. This 

also includes proposed determinations 

for those units already scrubbed to some 

degree, for which we conducted 

scrubber upgrade cost analysis and 

visibility modeling. Please see our FIP 

and Cost TSDs for more information. 

1. Proposed Reasonable Progress and 

Long-Term Strategy Determination for 

San Miguel 

We propose to find that the San 

Miguel facility has upgraded its SO2

scrubber system to perform at the 

reasonably highest level that can be 

expected (94% based on a 2009–2013 

average) based on the extremely high 

sulfur content of the coal being burned, 

and the technology currently available. 

We thus do not propose any further 

control. We propose to find that the San 

Miguel facility maintain a 30 Boiler 

Operating Day rolling average SO2

emission rate of 0.60 lbs/MMBtu based 

on the most recent actual emissions 

data. We believe that based on the 

scrubber upgrades it has recently 

performed and its demonstrated ability 

to maintain an emission rate below this 

value on a monthly basis from 

December 2013 to June 2014 that it can 

consistently achieve this emission level. 

See our Cost TSD for more details about 

our analysis of the scrubber upgrades 

that San Miguel has performed on its 

unit. We are specifically soliciting 

comments on this proposed emission 

limit and the potential need for a 

slightly higher limit to provide 

sufficient operational headroom to 

demonstrate compliance. 

2. Proposed Reasonable Progress and 

Long-Term Strategy Determination for 

Units Other Than San Miguel 

In Section VII.F, we present the 

results of our SO2 control cost analysis 

for those units listed in Table 30 with 

no SO2 control. In Section VII.G, we 

present the results of our control cost 

analysis for upgrading those units 

equipped with underperforming wet 

FGD scrubbers. In Section VII.H, we 

present the results of our modeled 

visibility benefits for these controls. We 

believe that we have provided the 

technical analysis that was lacking in 

Texas’ development of its RPGs for the 

Guadalupe Mountains and Big Bend, 

and in its consultations with Oklahoma 

for the development of the RPG for the 

Wichita Mountains. Further, we believe 

that our proposed control set, which we 

discuss below, developed through our 

reasonable progress four factor analysis, 

would ensure that Texas secures its 

share of the reductions needed for the 

RPGs of the Wichita Mountains, the 

Guadalupe Mountains, and Big Bend. 

Specifically, we propose to find that our 

technical analysis and control set makes 

whole our disapproval of: 

• Section 51.308(d)(1)(i)(A), regarding 

Texas’ reasonable progress four factor 

analysis. 

• Section 51.308(d)(1)(i)(B), regarding 

Texas’ calculation of the emission 

reductions needed to achieve the URPs 

for the Guadalupe Mountains and Big 

Bend. 

• Section 51.308(d)(1)(ii), regarding 

Texas’ RPGs for the Guadalupe 

Mountains and Big Bend. 

• Section 51.308(d)(3)(i) regarding 

Texas’ long-term strategy consultation. 

• Section 51.308(d)(3)(ii) regarding 

Texas securing its share of reductions in 

other states’ RPGs. 

• Section 51.308(d)(3)(iii) regarding 

Texas’ technical basis for its long-term 

strategy. 

• Section 51.308(d)(3)(v)(C), 

regarding Texas’ emissions limitations 

and schedules for compliance to achieve 

the RPGs for Big Bend and the 

Guadalupe Mountains. 

We also believe that this technical 

analysis and control set makes whole 

our proposed disapproval of 

Oklahoma’s submission under Section 

51.308(d)(1), except for Section 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74884 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

306As we discuss in section VII.D.2, we are only 

considering SDA in our cost/benefit analysis for 

Tolk due to a potential water issue that may have 

energy and non-air quality impact considerations. 307 70 FR 39172 (July 6, 2005). 

51.308(d)(1)(vi), which we propose to 

approve. We believe our technical 

analysis provides the information that 

Oklahoma should have had during its 

consultations with Texas in order to 

determine whether sources in Texas 

should have been controlled to improve 

the visibility at the Wichita Mountains. 

We believe our proposed control set 

would ensure that Texas’ share of the 

emission reductions are incorporated 

into Oklahoma’s RPGs. 

For all but one of the units we 

analyzed that currently have no SO2

controls, even at the lower level of 

control of 50%, the cost-effectiveness of 

DSI was worse (higher $/ton) than either 

SDA or wet FGD, even with the latter 

options offering much greater levels of 

control and visibility benefit. At the 

higher 80% or 90% level of control, the 

cost-effectiveness of DSI was worse than 

either SDA or wet FGD in all cases. 

Consequently, we are not proposing that 

DSI be installed at any unit. 

With the exception of Tolk,306 all of 

the scrubber retrofits were analyzed on 

the basis of both SDA and wet 

scrubbers. The SDA level of control was 

assumed to be a maximum of 95% not 

to go below 0.06 lbs/MMBtu. The wet 

FGD level of control was assumed to be 

a maximum of 98% not to go below 0.04 

lbs/MMBtu. As we discuss in our Cost 

TSD, the cost-effectiveness ($/ton) of 

wet FGD was better than SDA in all 

cases except for the Tolk and Welsh 

units, which burn Power River Basin 

(PRB) coal. However, even in those 

cases, the cost-effectiveness of wet FGD 

was only 0.5 to 0.8% greater than SDA. 

Given the greater visibility improvement 

of wet FGD over SDA, we propose to 

base our cost/benefit reasonable 

progress and long-term strategy 

determination on wet FGD, except for 

the Tolk units, due to their potential 

water issue. 

3. Proposed Reasonable Progress and 

Long-Term Strategy Determination for 

Scrubber Upgrades 

We propose to find that the costeffectiveness of the scrubber upgrades 

($600/ton or less) to be reasonable, and 

that on an individual basis, any 

reasonable amount of visibility 

improvement due to their installation 

justifies their cost. We believe this is the 

case for all of the scrubber upgrades 

except for the Parish 8 unit. Despite the 

same level of cost-effectiveness of the 

Parish 8 unit, we do not believe that the 

visibility benefits are large enough to 

justify the implementation of a scrubber 

upgrade on that unit. Therefore we 

propose that the scrubbers for the 

Sandow 4; Martin Lake 1, 2, 3; 

Monticello 3, and Limestone 1 and 2 

units be upgraded to perform at a 95% 

control level. This level of control 

corresponds to the emission limits listed 

in Table 38, below. 

4. Proposed Reasonable Progress and 

Long-Term Strategy Determination for 

Scrubber Retrofits 

The cost-effectiveness of the scrubber 

retrofits for the Welsh and Parish units 

are within a $/ton range that we have 

previously found to be cost-effective in 

BART determinations. However, we do 

not believe that their individual 

projected visibility improvements merit 

the installation of scrubbers at this time. 

We encourage the State of Texas to reevaluate this determination as part of its 

next regional haze SIP submittal. 

Similar to the scrubber upgrades, we 

believe the scrubber retrofits for the Big 

Brown units to be cost-effective and we 

find the projected visibility benefits 

from them to be significant. We 

therefore propose that the Big Brown 

units meet emission limits 

corresponding to this evaluation. Our 

proposed SO2 emission limits for the 

Big Brown units are shown in Table 38. 

In comparison to the Big Brown units, 

the cost-effectiveness of the scrubber 

retrofits for the Monticello, Coleto 

Creek, and Tolk units are less, although 

still well within the range that we have 

found acceptable for BART. Also, in 

comparison to the Big Brown units, the 

visibility improvements projected to 

occur due to the installation of the 

scrubber retrofits are less. For instance, 

as we discuss above in Section VII.H, 

the visibility benefits of SDA scrubbers 

on the Tolk units are projected to occur 

mainly at the Guadalupe Mountains. 

Those visibility benefits are smaller 

than the visibility benefits at Wichita 

Mountains from scrubber upgrades at 

W. A. Parish or Welsh, which we are not 

proposing to control. However, when 

we evaluated other metrics, such as 

extinction benefit or percent of 

extinction benefits, we concluded that 

the overall visibility benefit for 

installing scrubbers on the Tolk units 

was superior to either the W. A. Parish 

or the Welsh units. Thus, we consider 

these visibility benefits to be significant. 

Consequently, we propose that the 

Monticello, Coleto Creek, and Tolk units 

meet SO2 emission limits corresponding 

to this evaluation. Our proposed SO2

emission limits for these units are 

shown in Table 38. In recognition of 

their lesser cost/benefit ratio, we are 

specifically soliciting comments on the 

appropriateness of one or more of these 

scrubber retrofits. 

We propose that compliance be based 

on a 30 Boiler Operating Day (BOD) 

period. As the BART Guidelines direct, 

‘‘[y]ou should consider a boiler 

operating day to be any 24-hour period 

between 12:00 midnight and the 

following midnight during which any 

fuel is combusted at any time at the 

steam generating unit.’’307 To calculate 

a 30 day rolling average based on boiler 

operating day, the average of the last 30 

‘‘boiler operating days’’ is used. In other 

words, days are skipped when the unit 

is down, as for maintenance. This, in 

effect, provides a margin of safety by 

eliminating spikes that occur at the 

beginning and end of outages. Although 

we are not conducting BART 

determinations, our reasonable progress 

guidance notes the similarity between 

some of the reasonable progress factors 

and the BART factors contained in 

Section 51.308(e)(1)((ii)(A), and suggests 

that the BART Guidelines be consulted 

regarding cost, energy and non-air 

quality environmental impacts, and 

remaining useful life. We are therefore 

relying on our BART Guidelines for 

assistance in establishing the emission 

limit averaging period as well. 

TABLE 38—PROPOSED 30 BOILER

OPERATING DAY SO2 EMISSION LIMITS

Unit 

Proposed SO2

emission limit 

(lbs/MMBtu) 

Scrubber Upgrades: 

Sandow 4 ...................... 0.20 

Martin Lake 1 ................ 0.12 

Martin Lake 2 ................ 0.12 

Martin Lake 3 ................ 0.11 

Monticello 3 ................... 0,06 

Limestone 2 ................... 0.08 

Limestone 1 ................... 0.08 

San Miguel* ................... 0.60 

Scrubber Retrofits: 

Big Brown 1 ................... 0.04 

Big Brown 2 ................... 0.04 

Monticello 1 ................... 0.04 

Monticello 2 ................... 0.04 

Coleto Creek 1 .............. 0.04 

Tolk 172B ...................... 0.06 

Tolk 171B ...................... 0.06 

* As we note elsewhere, we do not anticipate that San Miguel will have to install any 

additional control in order to comply with this 

emission limit. 

J. Treatment of Potential Error in 

Scrubber Upgrade Efficiency 

Calculations 

In our Cost TSD, we discuss how we 

calculated the SO2 removal efficiency of 

the units we analyzed for scrubber 

upgrades. We note that due to a number 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74885 

308Regional Haze Rule Natural Level Estimates 

Using the Revised IMPROVE Aerosol Reconstructed 

Light Extinction Algorithm, Copeland, S. A., et al, 

Final Paper # 48, available in our docket.; NC II, or 

new IMPROVE natural visibility conditions are 

available at: http://vista.cira.colostate.edu/Docs/

IMPROVE/Aerosol/NaturalConditions/

NaturalConditionsII_Format2_v2.xls, for which we 

have filtered the data for Texas Class I areas and 

which is also available in our docket. 

of factors we could not accurately 

quantify, our calculations of scrubber 

efficiency may contain some error. 

Based on the results of our scrubber 

upgrade cost analysis, we do not believe 

that any reasonable error in calculating 

the true tons of SO2 removed affects our 

proposed decision to require emission 

reductions, as all of the scrubber 

upgrades we analyzed are cost-effective 

(low $/ton). In other words, were we to 

make reasonable adjustments in the tons 

removed to account for any potential 

error in our scrubber efficiency 

calculation, we would still propose to 

upgrade these SO2 scrubbers. We 

believe we have demonstrated that 

upgrading an underperforming SO2

scrubber is one of the most cost-effective 

pollution control upgrades a coal fired 

power plant can implement to improve 

the visibility at Class I areas. 

However, our proposed FIP does 

specify a SO2 emission limit that is 

based on 95% removal in all cases. This 

is below the upper end of what an 

upgraded wet SO2 scrubber can achieve, 

which is 98–99%, as we have noted in 

our Cost TSD. We believe that a 95% 

control assumption provides an 

adequate margin of error for any of the 

units for which we have proposed 

scrubber upgrades, such that they 

should be able to comfortably attain the 

emission limits we have proposed. 

However, for the operator of any unit 

that disagrees with us on this point, we 

propose the following: 

(1) The affected unit should comment 

why it believes it cannot attain the SO2

emission limit we have proposed, based 

on a scrubber upgrade that includes the 

kinds of improvements (e.g., elimination 

of bypass, wet stack conversion, 

installation of trays or rings, upgraded 

spray headers, upgraded ID fans, using 

all recycle pumps, etc.) typically 

included in a scrubber upgrade. 

(2) After considering those comments, 

and responding to all relevant 

comments in a final rulemaking action, 

should we still require a scrubber 

upgrade in our final decision making 

action we will provide the company the 

following option to seek a revised 

emission limit after taking the following 

steps: 

(a) Install a CEMS at the inlet to the 

scrubber. 

(b) Pre-approval of a scrubber upgrade plan 

conducted by a third party engineering firm 

that considers the kinds of improvements 

(e.g., elimination of bypass, wet stack 

conversion, installation of trays or rings, 

upgraded spray headers, upgraded ID fans, 

using all recycle pumps, etc.) typically 

performed during a scrubber upgrade. The 

goal of this plan will be to maximize the 

unit’s overall SO2 removal efficiency. 

(c) Installation of the scrubber upgrades. 

(d) Pre-approval of a performance testing 

plan, followed by the performance testing 

itself. 

(e) A pre-approved schedule for 2.a 

through 2.d. 

(f) Should we determine that a revision of 

the SO2 emission limit is appropriate, we 

will have to propose a modification to our 

decision making to do so. It should be noted 

that any proposal to modify the SO2 emission 

limit will be based largely on the 

performance testing and may result in a 

proposed increase or decrease of that value. 

K. Proposed Natural Conditions for the 

Texas Class I Areas 

As discussed in Section V.B.1, we 

propose to disapprove Texas’ 

calculation of the natural visibility 

conditions for the Big Bend and 

Guadalupe Class I areas under Section 

51.308(d)(2)(iii). The TCEQ used a 

refined approach to calculating the 

natural conditions for the Guadalupe 

Mountains and Big Bend. This 

approach, among other things, requires 

knowledge about the amount of coarse 

mass and soil that is attributable to 

natural sources. The TCEQ has provided 

data that supports the conclusion that a 

large portion of dust impacting visibility 

at its Class I areas is likely due to 

natural sources. We agree that dust 

storms and other blown dust from 

deserts are a significant contributor to 

visibility impairment at the Texas Class 

I areas that may not be captured 

accurately by our default method. 

However, we do not believe, as the 

TCEQ asserts, that all coarse mass and 

soil can be attributable to 100% natural 

sources. 

Although we believe that some coarse 

mass and soil should be attributable to 

natural sources, we do not have the 

information necessary to determine how 

much should be attributable to natural 

sources. We therefore acknowledge that 

like the TCEQ, we cannot accurately 

reset the natural conditions for the 

Guadalupe Mountains and Big Bend by 

using the TCEQ’s methodology, which 

depends on this information. In lieu of 

this, we propose to rely on the adjusted 

default estimates for the new IMPROVE 

equation from the Natural Conditions II 

committee,308 which was the starting 

point for the Texas natural visibility 

calculations, but solicit comment on the 

acceptability of alternate estimates in 

the range between our default estimates 

and the Texas estimates. We propose 

that the natural conditions for the 

Guadalupe Mountains and Big Bend be 

set as follows: 

TABLE 39—NATURAL CONDITIONS (NC 

II) FOR THE GUADALUPE MOUNTAINS

AND BIG BEND

Class 1 area 

20% Best 

days 

(dv) 

20% Worst 

days 

(dv) 

Guadalupe 

Mountains ...... 0.99 6.65 

Big Bend ........... 1.62 7.16 

We recommend that the State of Texas 

re-evaluate the natural conditions for its 

Class I areas in the next regional haze 

SIP. 

L. Calculation of Visibility Impairment 

for the Texas Class I Areas 

Using our proposed natural visibility 

conditions for the Guadalupe Mountains 

and Big Bend, we propose to reset the 

amount of natural visibility impairment 

for these Class I areas under Section 

51.308(d)(2)(iv)(A). We do this by 

modifying the table we present in our 

TX TSD. We replace Texas’ calculations 

of natural visibility for its Class I areas, 

with the adjusted default values (NC II), 

discussed above. We retain the baseline 

visibility values we proposed to 

approve, then recalculate the amount 

the baseline values exceed the natural 

visibility conditions. We propose that 

the natural visibility impairment for the 

Guadalupe Mountains and Big Bend be 

set as follows: 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74886 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

TABLE 40—REVISED VISIBILITY METRICS FOR THE CLASS I AREAS IN TEXAS

Class I area 

Haze index (deciviews) 

Most impaired Least 

impaired 

Estimate of Natural Visibility Conditions 

Big Bend .................................................................................................................................................................. 7.16 1.62 

Guadalupe Mountains .............................................................................................................................................. 6.65 0.99 

Baseline Visibility Conditions, 2000–2004 

Big Bend .................................................................................................................................................................. 17.30 5.78 

Guadalupe Mountains .............................................................................................................................................. 17.19 5.95 

Estimate of Extent Baseline Exceeds Natural Visibility Conditions 

Big Bend .................................................................................................................................................................. 10.14 4.16 

Guadalupe Mountains .............................................................................................................................................. 10.54 4.96 

M. Uniform Rates of Progress and the 

Emission Reductions Needed To 

Achieve Them 

Section 308(d)(1)(i)(B) requires that 

we analyze and determine the rates of 

progress needed to attain natural 

visibility conditions by the year 2064 

and consider the uniform rate of 

improvement in visibility and the 

emission reduction measures needed to 

achieve them. Below, we present the 

URPs for the 20% worst days for the 

Guadalupe Mountains and Big Bend, 

using the natural conditions we propose 

to establish above: 

TABLE 41—URP FOR BIG BEND

Baseline conditions 

(dv) 

Annual improvement 

needed to meet URP 

(dv) 

Visibility at 2018 

(dv) 

Improvement needed by 

2018 

(dv) 

Natural conditions at 2064 

(dv) 

17.30 0.17 14.93 2.37 7.16 

TABLE 42—URP FOR THE GUADALUPE MOUNTAINS

Baseline conditions 

(dv) 

Annual improvement 

needed to meet URP 

(dv) 

Visibility at 2018 

(dv) 

Improvement needed by 

2018 

(dv) 

Natural conditions at 2064 

(dv) 

17.19 0.18 14.73 2.46 6.65 

Please see our FIP TSD for graphical 

representations of these URPs. We 

propose to find that it is not reasonable 

to provide for rates of progress at 

Wichita Mountains, Big Bend, or 

Guadalupe Mountains that would attain 

natural visibility conditions by 2064 

(i.e., the URP). Our demonstration that 

a slower rate of progress is reasonable is 

based on the reasonable progress 

analyses performed by us and Texas that 

considered the four statutory reasonable 

progress factors, as described above. 

N. Reasonable Progress Goals and 

Demonstration 

We are quantifying proposed RPGs (in 

deciviews) for the 20-percent worst days 

in 2018. The proposed RPGs for 

Oklahoma’s Class I area, the Wichita 

Mountains, and Texas’ two Class I areas, 

Big Bend and the Guadalupe Mountains, 

account for the emission reductions 

from the reasonable progress control 

measures identified above in our 

proposed regional haze FIPs. The 

proposed RPGs reflect the results of our 

reasonable progress analysis of point 

sources as described in detail in our FIP 

TSD. These proposed RPGs are 

established based on an adjustment of 

the 2018 RPGs established by Texas and 

Oklahoma that were based on the 2018 

CENRAP modeling. We note that we do 

not anticipate implementation of the 

identified scrubber retrofits by the end 

of 2018. Therefore, we are only 

adjusting the RPGs established by the 

states to reflect the additional 

anticipated visibility benefit from the 

scrubber upgrades over the 2018 

projected visibility conditions. The 

tables below show the new adjusted 

RPGs as well as the additional 

improvement that is anticipated once all 

the scrubber retrofits have been 

implemented sometime after 2018. 

These new RPGs provide for an 

improvement in visibility on the worst 

days during this planning period. Table 

44 below estimates the RPG if all 

proposed controls were implemented by 

2018. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74887 

309Section II.A.3 of Appendix Y to Part 51— 

Guidelines for BART Determinations Under the 

Regional Haze Rule and 40 CFR 51.166(b)(i)(b). 

TABLE 43—PROPOSED RPGS FOR 20% WORST DAYS BASED ON PREDICTED BENEFIT OF SCRUBBER UPGRADES

BEYOND 2018 CENRAP PROJECTED VISIBILITY CONDITIONS. 

Baseline 

(dv) 

2018 CENRAP 

Projection 

(dv) 

Predicted additional benefit 

due only to 

FIP scrubber 

upgrades 

(dv) 

Proposed 

RPG 

(dv) 

Natural 

visibility 

Number of 

years needed 

to reach natural visibility 

Wichita Mountains .................................... 23.81 21.47 0.14 21.33 7.58 92 

Big Bend .................................................. 17.30 16.6 0.03 16.57 7.16 194 

Guadalupe Mountains .............................. 17.19 16.3 0.04 16.26 6.65 159 

TABLE 44—CALCULATED RPGS FOR 20% WORST DAYS BASED ON PREDICTED BENEFIT OF ALL PROPOSED CONTROLS

BEYOND 2018 CENRAP PROJECTED VISIBILITY CONDITIONS

Baseline 

(dv) 

2018 

CENRAP 

Projection 

(dv) 

Predicted additional benefit due only 

to FIP scrubber upgrades 

(dv) 

Additional 

benefit predicted due to 

FIP scrubber 

retrofits 

(dv) 

Total benefit 

from 

proposed 

controls 

RPG 

Assuming all 

controls in 

place by 

2018 

Natural 

visibility 

Number of 

years needed 

to reach 

natural 

visibility 

Wichita Mountains ............................. 23.81 21.47 0.14 0.30 0.45 21.03 7.58 82 

Big Bend ............................................ 17.3 16.6 0.03 0.09 0.12 16.48 7.16 173 

Guadalupe Mountains ....................... 17.19 16.3 0.04 0.12 0.15 16.14 6.65 141 

As discussed in more detail in the FIP 

TSD, current actual emissions for many 

of the units that we propose to control 

are higher than the projected CENRAP 

2018 emission rate. Therefore, the actual 

visibility impact due to emissions from 

these sources and the anticipated 

benefit from controls are larger than the 

benefits calculated above based on the 

2018 CENRAP projected visibility 

conditions. The table below summarizes 

the amount of visibility benefit we 

anticipate will occur from the 

implementation of our proposed FIP 

controls and the resulting emission 

reductions from the current actual 

average annual emissions. 

TABLE 45—ANTICIPATED VISIBILITY BENEFIT DUE TO EMISSION REDUCTIONS FROM ACTUAL EMISSION LEVELS

Predicted benefit 

due to FIP scrubber upgrades 

(dv) 

Benefit predicted 

due to FIP scrubber retrofits (dv) 

Total benefit 

from proposed 

controls (dv) 

Wichita Mountains ........................................................................................................... 0.28 0.33 0.62 

Big Bend .......................................................................................................................... 0.07 0.10 0.17 

Guadalupe Mountains ...................................................................................................... 0.07 0.12 0.20 

We propose to find that it is not 

reasonable to provide for rates of 

progress at the Wichita Mountains, Big 

Bend, or the Guadalupe Mountains that 

would attain natural visibility 

conditions by 2064 (i.e., the URP). Our 

demonstration that a slower rate of 

progress is reasonable is based on the 

reasonable progress analyses performed 

by us and the states that considered the 

four statutory reasonable progress 

factors, as described above. Although 

progress is slower than the URP, the 

proposed FIP would provide for RPGs 

that reflect an improved rate of progress 

and a shorter time period to reach 

natural visibility conditions at each of 

the Class I areas, compared with the 

RPGs established by Texas and 

Oklahoma in their regional haze SIPs. 

We have provided an estimate of the 

number of years needed to meet natural 

visibility conditions at the rate of 

progress proposed by us as reasonable. 

We have also estimated the RPG and the 

number of years to meet natural 

visibility conditions if all proposed 

controls were in place by 2018. We note 

that this does not take into account the 

visibility benefit from scrubber retrofits 

included in this proposed FIP that will 

be implemented after 2018. 

VIII. Our Evaluation of the Texas 

Infrastructure SIP Submittals for 

Interstate Transport and Visibility 

Protection 

To determine whether the CAA 

Section 110(a)(2)(D)(i) requirement for 

visibility protection is satisfied, the SIP 

must address the potential for 

interference with visibility protection 

caused by the pollutant (including 

precursors) to which the new or revised 

NAAQS applies. Pollutants which could 

interfere with visibility protection 

include: (1) SO2 (which is also a 

precursor for PM2.5), (2) nitrogen oxides 

(which includes NO2 and are precursors 

for ozone and PM2.5) and (3) particulate 

matter.309 An approved regional haze 

SIP that fully meets the regional haze 

requirements in 40 CFR 51.308 satisfies 

the requirement for visibility protection 

as it ensures that emissions from the 

state will not interfere with measures 

required to be included in other state 

SIPs to protect visibility. In the 

infrastructure SIP submittals for the 

ozone, PM2.5, NO2 and SO2 NAAQS 

Texas indicated that the Regional Haze 

SIP fulfilled its obligation for addressing 

emissions that would interfere with 

measures required to be included in the 

SIP for any other state to protect 

visibility. 

As we note above, we gave limited 

disapproval to the Texas Regional Haze 

SIP based on its reliance on CAIR. As 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74888 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

310 77 FR 33643 (June 7, 2012). 

311 42 U.S.C. Section 7607(b)(1). 

312Texas v. EPA, 2011 U.S. App. LEXIS 5654 at 

*15 (5th Cir. Feb. 14, 2011) (citing Admin. 

Conference of the U.S., Recommendations on 

Judicial Review Under the Clean Air Act, 41 FR 

56767, 56769 (Dec. 30, 1976) (Comments of G. 

William Frick)). 

313H.R. Rep. No. 95–294 at 323–24, reprinted in 

1977 U.S.C.C.A.N. 1402–03. 

explained in our limited disapproval of 

the Texas regional haze SIP, many states 

(including Texas) relied on the 

improvement in visibility expected to 

result from the implementation of CAIR 

in developing their long-term 

strategy.310 Texas relied on its own 

CAIR SIP as legal justification for these 

planned controls and did not include 

separate enforceable measures in its 

regional haze SIP to ensure these EGU 

reductions. As CAIR has been replaced 

by CSAPR, and CSAPR is going into 

effect in 2015, we propose to determine 

that Texas may not rely on its regional 

haze SIP to ensure that emissions from 

Texas do not interfere with the 

measures to protect visibility in nearby 

states. We propose to disapprove Texas’ 

SIP submittals for the 1997 PM2.5, 2006 

PM2.5, 1997 ozone, 2008 ozone, 2010 

NO2 and 2010 SO2 NAAQS, with 

respect to interstate transport of air 

pollution and visibility protection. 

CSAPR and our proposed FIP, which 

relies on emission reductions from the 

implementation of CSAPR in lieu of 

BART, addresses this deficiency in the 

Texas SIP. 

An additional reason for our proposed 

disapproval of the submittals for the 

1997 PM2.5, 2006 PM2.5 and 2010 SO2

NAAQS is our proposed conclusion that 

additional control of SO2 emissions in 

Texas is needed to prevent interference 

with measures required to be included 

in the Oklahoma SIP to protect 

visibility. Our proposed FIP addresses 

this deficiency in the Texas SIP. 

IX. Proposed Determination of 

Nationwide Scope and Effect 

Section 307(b)(1) of the CAA indicates 

which Federal Courts of Appeal have 

venue for petitions of review of final 

agency actions by the EPA under the 

CAA. This section provides, in part, that 

petitions for review must be filed in the 

U.S. Court of Appeals for the District of 

Columbia Circuit (i) when the agency 

action consists of ‘‘nationally applicable 

regulations promulgated, or final actions 

taken, by the Administrator’’ or (ii) 

when such action is locally or regionally 

applicable, if ‘‘such action is based on 

a determination of nationwide scope or 

effect and if in taking such action the 

Administrator finds and publishes that 

such action is based on such a 

determination.’’ 311

We propose to find and publish that 

this rule is based on a determination of 

nationwide scope and effect. The rule 

discusses our interpretation of multiple 

provisions of the Regional Haze Rule 

and explains how those provisions 

operate in the visibility-transport 

context. Our interpretation of our 

regulations is applicable to all states, 

not just Texas and Oklahoma. 

Consequently, our determination of 

nationwide scope and effect is 

‘‘consistent with the legislative history 

of the CAA, which evinces a clear 

congressional intent to ‘centralize 

review of ‘national’ SIP issues in the 

D.C. Circuit.’ ’’ 312 This determination is 

also appropriate because in the 1977 

CAA Amendments that revised CAA 

Section 307(b)(1), Congress noted that 

the Administrator’s determination that 

an action is of ‘‘nationwide scope or 

effect’’ would be appropriate for any 

action that has ‘‘scope or effect beyond 

a single judicial circuit.’’ 313 Here, the 

scope and effect of this rulemaking 

extends to two judicial circuits. 

Accordingly, we propose to determine 

that this is a rulemaking of nationwide 

scope or effect such that any petitions 

for review must be filed in the U.S. 

Court of Appeals for the District of 

Columbia Circuit. 

X. Proposed Action 

A listing of our proposed actions is 

provided below. 

A. Texas Regional Haze 

We propose to partially approve and 

partially disapprove a revision to the 

Texas SIP received from the State of 

Texas on March 31, 2009, that intended 

to address regional haze for the first 

planning period from 2008 through 

2018. This revision was intended to 

address the requirements of the CAA 

and our rules that require states to 

prevent any future, and remedy any 

existing, manmade impairment of 

visibility in mandatory Class I areas. We 

propose to approve a portion of this SIP 

revision as meeting certain requirements 

of the regional haze program and to 

disapprove portions addressing the 

requirements related to RP, the longterm strategy and the calculation of 

natural visibility conditions. We 

propose a FIP to implement SO2

emission limits on fifteen Texas sources, 

and to establish the natural visibility 

conditions at two Class I areas in Texas 

to address these issues. Specifically, we 

propose to disapprove the portions of 

the Texas regional haze SIP addressing 

the following regional haze rule 

requirements: 

• 51.308(d)(1)(i)(A) 

• 51.308(d)(1)(i)(B) 

• 51.308(d)(1)(ii) 

• 51.308(d)(2)(iii) 

• 51.308(d)(2)(iv)(A) 

• 51.308(d)(3)(i) 

• 51.308(d)(3)(ii) 

• 51.308(d)(3)(iii) 

• 51.308(d)(3)(v)(C) 

We propose a FIP to cure these defects 

in the Texas regional haze SIP. We 

propose to approve all other sections of 

the Texas regional haze SIP. 

With regard to Texas’ BART Rules, we 

propose a FIP to replace Texas’ reliance 

on CAIR in 30 TAC 116.1510(d) with 

reliance on CSAPR. We propose to 

approve the remainder of the provisions 

in Texas’ BART rules. 

Our proposed regional haze FIP relies 

on the already promulgated CSAPR FIP 

for Texas at 40 CFR 52.2283–84 to 

satisfy the BART requirement for SO2

and NOX emissions from EGUs. 

Our proposed FIP requires that the 

following SO2 emission limits be met on 

a 30 BOD period. 

TABLE 46—PROPOSED 30 BOILER

OPERATING DAY SO2 EMISSION LIMITS

Unit 

Proposed SO2

emission limit 

(lbs/MMBtu) 

Scrubber Upgrades: 

Sandow 4 .......................... 0.20 

Martin Lake 1 .................... 0.12 

Martin Lake 2 .................... 0.12 

Martin Lake 3 .................... 0.11 

Monticello 3 ....................... 0.06 

Limestone 2 ...................... 0.08 

Limestone 1 ...................... 0.08 

San Miguel * ...................... 0.60 

Scrubber Retrofits: 

Big Brown 1 ...................... 0.04 

Big Brown 2 ...................... 0.04 

Monticello 1 ....................... 0.04 

Monticello 2 ....................... 0.04 

Coleto Creek 1 .................. 0.04 

Tolk 172B .......................... 0.06 

Tolk 171B .......................... 0.06 

* As we note elsewhere, we do not anticipate that San Miguel will have to install any 

additional control in order to comply with this 

emission limit. 

We propose that compliance with 

these limits be within five years of the 

effective date of our final rule for Big 

Brown Units 1 and 2, Monticello Units 

1 and 2, Coleto Creek Unit 1, and Tolk 

Units 171B and 172B. Although this is 

not a BART action, this is the maximum 

amount of time allowed under the 

regional haze Rule for BART 

compliance. We based our cost analysis 

on the installation of wet FGD and SDA 

scrubbers for these units, and in the past 

we have typically required that scrubber 

retrofits under BART be operational 

within five years. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74889 

314 58 FR 51735 (October 4, 1993). 

315 76 FR 3821 (January 21, 2011). 

We propose that compliance with 

these limits be within three years of the 

effective date of our final rule for 

Sandow 4; Martin Lake Units 1, 2, and 

3; Monticello Unit 3; and Limestone 

Units 1 and 2. We believe that three 

years is appropriate for these units, as 

we based our cost analysis on upgrading 

the existing wet FGD scrubbers of these 

units, which we believe to be less 

complex and time consuming that the 

construction of a new scrubber. We 

solicit comments on alternative 

timeframes, of from two years up to five 

years from the effective date of our final 

rule. 

We propose that compliance with 

these limits be within one year for San 

Miguel. We believe that one year is 

appropriate for this unit because we 

based our analysis on scrubber upgrades 

that San Miguel has already performed, 

and because it has demonstrated its 

ability to meet this emission limit. We 

are specifically soliciting comments on 

this proposed emission limit and the 

potential need for a slightly higher limit 

to provide sufficient operational 

headroom to demonstrate compliance. 

Our proposed FIP also resets the 

natural conditions and the URPs for the 

Guadalupe Mountains and Big Bend 

Class I areas, and establishes new RPGs 

for the 20% worst days for these Class 

I areas. 

We propose that this FIP will fully 

satisfy the FIP obligation stemming from 

our proposed disapproval of portions of 

the Texas SIP. 

B. Oklahoma Regional Haze 

We are also proposing to partially 

disapprove a portion of a revision to the 

Oklahoma SIP submitted by the State of 

Oklahoma on February 19, 2010. 

Specifically, we propose to disapprove 

the portion of the Oklahoma regional 

haze SIP that addresses the 

requirements of Section 51.308(d)(1), 

except for Section 51.308(d)(1)(vi). 

We propose a FIP to reset Oklahoma’s 

RPGs based on our analysis conducted 

in support of our proposed Texas FIP. 

We propose to find that the same 

controls we have proposed above in our 

Texas FIP also serve to cure the defects 

in these sections of Oklahoma’s regional 

haze SIP as well, thus satisfying the FIP 

obligation stemming from our proposed 

disapproval of portions of the Oklahoma 

SIP. 

C. Interstate Transport of Air Pollution 

and Visibility Protection 

We propose to disapprove portions of 

Texas SIP submittals that address CAA 

provisions for prohibiting air pollutant 

emissions from interfering with 

measures required to protect visibility 

in any other state for the 1997 PM2.5, 

2006 PM2.5, 1997 ozone, 2008 ozone, 

2010 NO2 and 2010 SO2 NAAQS (CAA 

Section 110(a)(2)(D)(i)(II) and visibility 

protection). Specifically, we propose to 

disapprove portions of the following SIP 

submittals made by Texas for new or 

revised NAAQS: 

• 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) 

We propose to determine that our 

regional haze FIP will satisfy our FIP 

obligation for interstate transport of air 

pollution and visibility protection. 

XI. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This proposed action is not a 

‘‘significant regulatory action’’ under 

the terms of Executive Order 12866 314

and is therefore not subject to review 

under Executive Orders 12866 and 

13563.315 The proposed FIP applies to 

only eight facilities. It is therefore not a 

rule of general applicability. 

B. Paperwork Reduction Act 

This proposed action does not impose 

an information collection burden under 

the provisions of the Paperwork 

Reduction Act, 44 U.S.C. Section 3501 

et seq. Because it does not contain any 

information collection activities, the 

Paperwork Reduction Act does not 

apply. See 5 CFR 1320(c). 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to conduct 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements unless the 

agency certifies that the rule will not 

have a significant economic impact on 

a substantial number of small entities. 

Small entities include small businesses, 

small not-for-profit enterprises, and 

small governmental jurisdictions. For 

purposes of assessing the impacts of 

today’s rule on small entities, small 

entity is defined as: (1) a small business 

as defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201; (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of today’s proposed rule on 

small entities, 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 

proposed SIP action under Section 110 

of the CAA will not in-and-of itself 

create any new requirements on small 

entities but simply approves or 

disapproves certain state requirements 

for inclusion into the SIP. 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. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Pub. L. 

104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on state, local, 

and Tribal governments and the private 

sector. Under Section 202 of UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to state, local, 

and Tribal governments, in the 

aggregate, or to the private sector, of 

$100 million or more (adjusted for 

inflation) in any one year. Before 

promulgating an EPA rule for which a 

written statement is needed, Section 205 

of UMRA generally requires EPA to 

identify and consider a reasonable 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74890 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

316 65 FR 67249 (Nov. 9, 2000). 

317 62 FR 19885 (Apr. 23, 1997). 

318 66 FR 28355 (May 22, 2001). 319 59 FR 7629 (Feb. 16, 1994). 

number of regulatory alternatives and 

adopt the least costly, most costeffective, or least burdensome 

alternative that achieves the objectives 

of the rule. The provisions of Section 

205 of UMRA do not apply when they 

are inconsistent with applicable law. 

Moreover, Section 205 of UMRA allows 

EPA to adopt an alternative other than 

the least costly, most cost-effective, or 

least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including Tribal 

governments, it must have developed 

under Section 203 of UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

EPA has determined that Title II of 

UMRA does not apply to this proposed 

rule. In 2 U.S.C. Section 1502(1) all 

terms in Title II of UMRA have the 

meanings set forth in 2 U.S.C. Section 

658, which further provides that the 

terms ‘‘regulation’’ and ‘‘rule’’ have the 

meanings set forth in 5 U.S.C. Section 

601(2). Under 5 U.S.C. Section 601(2), 

‘‘the term ‘rule’ does not include a rule 

of particular applicability relating to 

. . . facilities.’’ Because this proposed 

rule is a rule of particular applicability 

relating to eight named facilities, EPA 

has determined that it is not a ‘‘rule’’ for 

the purposes of Title II of UMRA. 

E. Executive Order 13132, Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government. 

F. Executive Order 13175, Coordination 

with Indian Tribal Governments 

This proposed action does not have 

tribal implications, because the SIP 

submittals the EPA is proposing to 

approve or disapprove would not have 

a substantial direct effect on any Indian 

reservation land or in any other area 

where EPA or an Indian tribe has 

demonstrated that a tribe has 

jurisdiction. In those areas of Indian 

country, this proposed rule does not 

have tribal implications as specified by 

Executive Order 13175 316, nor will it 

impose substantial direct costs on tribal 

governments or preempt tribal law. 

Thus, Executive Order 13175 does not 

apply to this action. Consistent with the 

EPA policy the EPA nonetheless is 

offering consultation to tribes regarding 

this rulemaking action. The EPA will 

respond to relevant comments in the 

final rulemaking action. 

G. 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 317 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 proposed rule will limit 

emissions of SO2 the rule will have a 

beneficial effect on children’s health by 

reducing air pollution. 

H. Executive Order 13211, Actions That 

Significantly Affect Energy Supply, 

Distribution or Use 

This proposed action is not subject to 

Executive Order 13211 318 because it is 

not a significant regulatory action under 

Executive Order 12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12 of the National Technology 

Transfer and Advancement Act 

(NTTAA) of 1995 requires Federal 

agencies to evaluate existing technical 

standards when developing a new 

regulation. To comply with NTTAA, 

EPA must consider and use ‘‘voluntary 

consensus standards’’ (VCS) if available 

and applicable when developing 

programs and policies unless doing so 

would be inconsistent with applicable 

law or otherwise impractical. EPA 

believes that VCS are inapplicable to 

this action. Today’s action does not 

require the public to perform activities 

conducive to the use of VCS. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 319 establishes 

federal executive policy on 

environmental justice. Its main 

provision directs federal agencies, to the 

greatest extent practicable and 

permitted by law, to make 

environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. We 

have determined that this proposed 

rule, if finalized, 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. 

This proposed federal rule limits 

emissions of SO2 from eight facilities in 

Texas. 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Incorporation by 

reference, Intergovernmental relations, 

Nitrogen dioxide, Ozone, Particulate 

matter, Reporting and recordkeeping 

requirements, Sulfur dioxides, 

Visibility, Interstate transport of 

pollution, Regional haze, Best available 

control technology. 

Dated: November 24, 2014. 

Ron Curry, 

Regional Administrator, Region 6. 

Title 40, chapter I, of the Code of 

Federal Regulations is proposed to be 

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. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 74891 

■ 2. Part 52 is proposed to be amended 

by adding paragraph (d) in Section 

52.2284 and paragraphs (d) and (e) in 

Section 52.2304. 

The additions read as follows: 

Subpart SS—Texas 

§ 52.2284 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(d) Requirements for Martin Lake 

Units 1, 2, and 3; Monticello Units 1, 2, 

and 3, Limestone Units 1 and 2; Sandow 

Unit 4; Big Brown Units 1 and 2; Coleto 

Creek Unit 1; Tolk Units 1 and 2; and 

San Miguel affecting visibility. 

(1) Applicability. The provisions of 

this section shall apply to each owner 

or operator, or successive owners or 

operators, of the coal burning 

equipment designated as: Martin Lake 

Units 1, 2, and 3; Monticello Units 1, 2, 

and 3, Limestone Units 1 and 2; Sandow 

Unit 4; Big Brown Units 1 and 2; Coleto 

Creek Unit 1; Tolk Units 1 and 2; and 

San Miguel. 

(2) Compliance Dates. Compliance 

with the requirements of this section is 

required within 3 years of the effective 

date of this rule for Martin Lake Units 

1, 2, and 3; Monticello Unit 3, 

Limestone Units 1 and 2; and Sandow 

Unit 4. Compliance with the 

requirements of this section is required 

within 5 years of the effective date of 

this rule for Big Brown Units 1 and 2; 

Monticello Units 1 and 2; Coleto Creek 

Unit 1; and Tolk Units 1 and 2. 

Compliance with the requirements of 

this section is required within one year 

for San Miguel. These compliance dates 

apply unless otherwise indicated by 

compliance dates contained in specific 

provisions. 

(3) Definitions. All terms used in this 

part but not defined herein shall have 

the meaning given them in the Clean Air 

Act and in parts 51 and 60 of this title. 

For the purposes of this section: 

24-hour period means the period of 

time between 12:01 a.m. and 12 

midnight. 

Air pollution control equipment 

includes selective catalytic control 

units, baghouses, particulate or gaseous 

scrubbers, and any other apparatus 

utilized to control emissions of 

regulated air contaminants which would 

be emitted to the atmosphere. 

Boiler-operating-day means any 24- 

hour period between 12:00 midnight 

and the following midnight during 

which any fuel is combusted at any time 

at the steam generating unit. 

Daily average means the arithmetic 

average of the hourly values measured 

in a 24-hour period. 

Heat input means heat derived from 

combustion of fuel in a unit and does 

not include the heat input from 

preheated combustion air, recirculated 

flue gases, or exhaust gases from other 

sources. Heat input shall be calculated 

in accordance with 40 CFR part 75. 

Owner or Operator means any person 

who owns, leases, operates, controls, or 

supervises any of the coal burning 

equipment designated in paragraph (a). 

Regional Administrator means the 

Regional Administrator of EPA Region 6 

or his/her authorized representative. 

Unit means one of the coal fired 

boilers covered under paragraph (a) of 

this section. 

(4) Emissions Limitations. SO2

emission limit. The individual sulfur 

dioxide emission limit for a unit shall 

be as listed in the following table in 

pounds per million British thermal 

units (lb/MMBtu) as averaged over a 

rolling 30 boiler-operating-day period. 

Unit 

SO2 Emission 

limit 

(lbs/MMBtu) 

Sandow 4 .............................. 0.20 

Martin Lake 1 ........................ 0.12 

Martin Lake 2 ........................ 0.12 

Martin Lake 3 ........................ 0.11 

Monticello 3 .......................... 0.06 

Limestone 2 .......................... 0.08 

Limestone 1 .......................... 0.08 

Big Brown 1 .......................... 0.04 

Big Brown 2 .......................... 0.04 

Monticello 1 .......................... 0.04 

Monticello 2 .......................... 0.04 

Coleto Creek 1 ..................... 0.04 

Tolk 172B ............................. 0.06 

Tolk 171B ............................. 0.06 

San Miguel ............................ 0.60 

For each unit, SO2 emissions for each 

calendar day shall be determined by 

summing the hourly emissions 

measured in pounds of SO2. For each 

unit, heat input for each boileroperating-day shall be determined by 

adding together all hourly heat inputs, 

in millions of BTU. Each boileroperating-day of the thirty-day rolling 

average for a unit shall be determined 

by adding together the pounds of SO2

from that day and the preceding 29 

boiler-operating-days and dividing the 

total pounds of SO2 by the sum of the 

heat input during the same 30 boileroperating-day period. The result shall be 

the 30 boiler-operating-day rolling 

average in terms of lb/MMBtu emissions 

of SO2. If a valid SO2 pounds per hour 

or heat input is not available for any 

hour for a unit, that heat input and SO2

pounds per hour shall not be used in the 

calculation of the 30 boiler-operatingday rolling average for SO2. 

(5) Testing and monitoring. 

(i) No later than the compliance date 

of this regulation, the owner or operator 

shall install, calibrate, maintain and 

operate Continuous Emissions 

Monitoring Systems (CEMS) for SO2 on 

the units listed in Section (1) in 

accordance with 40 CFR 60.8 and 

60.13(e), (f), and (h), and Appendix B of 

Part 60. The owner or operator shall 

comply with the quality assurance 

procedures for CEMS found in 40 CFR 

part 75. Compliance with the emission 

limits for SO2 shall be determined by 

using data from a CEMS. 

(ii) Continuous emissions monitoring 

shall apply during all periods of 

operation of the coal burning 

equipment, including periods of startup, 

shutdown, and malfunction, except for 

CEMS breakdowns, repairs, calibration 

checks, and zero and span adjustments. 

Continuous monitoring systems for 

measuring SO2 and diluent gas shall 

complete a minimum of one cycle of 

operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. Hourly averages shall be 

computed using at least one data point 

in each fifteen minute quadrant of an 

hour. Notwithstanding this requirement, 

an hourly average may be computed 

from at least two data points separated 

by a minimum of 15 minutes (where the 

unit operates for more than one 

quadrant in an hour) if data are 

unavailable as a result of performance of 

calibration, quality assurance, 

preventive maintenance activities, or 

backups of data from data acquisition 

and handling system, and recertification 

events. When valid SO2 pounds per 

hour, or SO2 pounds per million Btu 

emission data are not obtained because 

of continuous monitoring system 

breakdowns, repairs, calibration checks, 

or zero and span adjustments, emission 

data must be obtained by using other 

monitoring systems approved by the 

EPA to provide emission data for a 

minimum of 18 hours in each 24 hour 

period and at least 22 out of 30 

successive boiler operating days. 

(6) Reporting and Recordkeeping 

Requirements. Unless otherwise stated 

all requests, reports, submittals, 

notifications, and other communications 

to the Regional Administrator required 

by this section shall be submitted, 

unless instructed otherwise, to the 

Director, Multimedia Planning and 

Permitting Division, U.S. Environmental 

Protection Agency, Region 6, to the 

attention of Mail Code: 6PD, at 1445 

Ross Avenue, Suite 1200, Dallas, Texas 

75202–2733. For each unit subject to the 

emissions limitation in this section and 

upon completion of the installation of 

CEMS as required in this section, the 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

74892 Federal Register / Vol. 79, No. 241 / Tuesday, December 16, 2014 / Proposed Rules 

owner or operator shall comply with the 

following requirements: 

(i) For each emissions limit in this 

section, comply with the notification, 

reporting, and recordkeeping 

requirements for CEMS compliance 

monitoring in 40 CFR 60.7(c) and (d). 

(ii) For each day, provide the total 

SO2 emitted that day by each emission 

unit. For any hours on any unit where 

data for hourly pounds or heat input is 

missing, identify the unit number and 

monitoring device that did not produce 

valid data that caused the missing hour. 

(7) Equipment Operations. At all 

times, including periods of startup, 

shutdown, and malfunction, the owner 

or operator shall, to the extent 

practicable, maintain and operate the 

unit including associated air pollution 

control equipment in a manner 

consistent with good air pollution 

control practices for minimizing 

emissions. Determination of whether 

acceptable operating and maintenance 

procedures are being used will be based 

on information available to the Regional 

Administrator which may include, but 

is not limited to, monitoring results, 

review of operating and maintenance 

procedures, and inspection of the unit. 

(8) Enforcement. 

(i) Notwithstanding any other 

provision in this implementation plan, 

any credible evidence or information 

relevant as to whether the unit would 

have been in compliance with 

applicable requirements if the 

appropriate performance or compliance 

test had been performed, can be used to 

establish whether or not the owner or 

operator has violated or is in violation 

of any standard or applicable emission 

limit in the plan. 

(ii) Emissions in excess of the level of 

the applicable emission limit or 

requirement that occur due to a 

malfunction shall constitute a violation 

of the applicable emission limit. 

* * * * * 

§ 52.2304 Visibility protection. 

* * * * * 

(d) Portions of SIPs addressing 

noninterference with measures required 

to protect visibility in any other state are 

disapproved for the 1997 PM2.5, 2006 

PM2.5, 1997 ozone, 2008 ozone, 2010 

NO2 and 2010 SO2 NAAQS. 

(e) Measures Addressing Disapproval 

Associated with NOX and SO2.

(1) The deficiencies associated with 

NOX identified in EPA’s disapproval of 

the regional haze plan submitted by 

Texas on March 31, 2009, are satisfied 

by Section 52.2283 

(2) The deficiencies associated with 

SO2 identified in EPA’s disapproval of 

the regional haze plan submitted by 

Texas on March 31, 2009, are satisfied 

by Section 52.2284. 

[FR Doc. 2014–28930 Filed 12–15–14; 8:45 am] 

BILLING CODE 6560–50–P 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2