Promulgation of Air Quality Implementation Plans; State of Texas; Regional Haze and Interstate Visibility Transport Federal Implementation Plan

Federal RegisterJan 4, 2017

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R06-OAR-2016-0611; FRL-9955-77-Region 6]

Promulgation of Air Quality Implementation Plans; State of Texas; Regional Haze and Interstate Visibility Transport Federal Implementation Plan

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Proposed rule.

SUMMARY:

Pursuant to the Federal Clean Air Act (CAA or Act), the Environmental Protection Agency (EPA) is proposing to promulgate a Federal Implementation Plan (FIP) in Texas to address the remaining outstanding requirements that are not satisfied by the Texas Regional Haze State Implementation Plan (SIP) submission. Specifically, the EPA proposes SO

limits on 29 Electric Generating Units (EGUs) located at 14 Texas facilities to fulfill requirements for the installation and operation of the Best Available Retrofit Technology (BART) for SO

. To address the requirement for NO

BART for Texas EGU sources, we are proposing a FIP that relies upon two other EPA rulemakings, one already final and one proposed, which together will establish that participation in the Cross-State Air Pollution Rule (CSAPR) continues to qualify as an alternative to NO

BART for EGUs in Texas. We also are proposing to disapprove the portion of the Texas Regional Haze SIP that addresses the BART requirement for EGUs for Particulate Matter (PM) and proposing a FIP with PM BART limits for EGUs at 29 EGUs located at 14 Texas facilities, based on existing practices and control capabilities. In addition, we propose to reconsider and re-propose disapproval of portions of several SIP revisions submitted to satisfy the requirement to address interstate visibility transport for six NAAQS and that the FIP emission limits we are proposing meet the interstate visibility transport requirements for these NAAQS.

DATES:

Comments:

Comments must be received on or before March 6, 2017. A public hearing will be held January 10, 2017. For additional logistical information regarding the public hearing please see the

SUPPLEMENTARY INFORMATION

section of this action.

ADDRESSES:

Submit your comments, identified by Docket No. EPA-R06-OAR-2016-0611, at

http://www.regulations.gov

or via email to

R6_TX-BART@epa.gov.

Follow the online instructions for submitting comments. Once submitted, comments cannot be edited or removed from

Regulations.gov

. The EPA may publish any comment received to its public docket. Do not submit electronically any information you consider to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Multimedia submissions (audio, video, etc.) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. The EPA will generally not consider comments or comment contents located outside of the primary submission (

i.e.

on the web, cloud, or other file sharing system). For additional submission methods, please contact Joe Kordzi, 214-665-7186,

Kordzi.joe@epa.gov.

For the full EPA public comment policy, information about CBI or multimedia submissions, and general guidance on making effective comments, please visit

http://www2.epa.gov/dockets/commenting-epa-dockets.

Docket:

The index to the docket for this action is available electronically at

http://www.regulations.gov

and in hard copy at the EPA Region 6, 1445 Ross Avenue, Suite 700, Dallas, Texas. While all documents in the docket are listed in the index, some information may be publicly available only at the hard copy location (

e.g.,

copyrighted material), and some may not be publicly available at either location (

e.g.,

CBI).

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.

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.

Public Hearing:

We are holding an information session, for the purpose of providing additional information and informal discussion for our proposal. We are also holding a public hearing to accept oral comments into the record:

Date:

Tuesday, January 10, 2017

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:

Joe C. Thompson Conference Center (on the University of Texas (UT) Campus), Room 3.102, 2405 Robert Dedman Drive, Austin, Texas 78712

Joe C. Thompson Conference Center parking is adjacent to the building in Lot 40, located at the intersection of East Dean Keeton Street and Red River Street. Additional parking is available at the Manor Garage, located at the intersection of Clyde Littlefield Drive and Robert Dedman Drive. If arranged in advance, the UT Parking Office will allow buses to park along Dedman Drive near the Manor Garage for a fee.

The public hearing will provide interested parties the opportunity to present information and opinions to us 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 hearing. 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 information session prior to the public hearing. During the information session, EPA staff will be available to informally answer questions on our proposed action. Any comments made to EPA staff during an information session must still be provided orally during the public hearing, 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.

Table of Contents

I. Background

II. Overview of Proposed Actions

A. Regional Haze

B. Interstate Transport of Pollutants That Affect Visibility

C. Our Authority To Promulgate a FIP

III. Our Proposed BART Analyses for SO

and PM

A. Identification of BART-Eligible Sources

B. Identification of Sources That are Subject to BART

1. Our use of the Standard BART Model Plant Exemption

2. Our Extension of the BART Model Plant Exemption

3. Our use of CALPUFF Modeling to Exempt Sources From Being Subject to BART

4. Our use of CAMx Modeling to Exempt Sources From Being Subject to BART

5. Summary of Sources That are Subject to BART

C. Our BART Five Factor Analyses

1. Steps 1 and 2: Technically Feasible SO

Retrofit Controls

a. Identification of Technically Feasible SO

Retrofit Control Technologies for Coal Fired Units

b. Identification of Technically Feasible SO

Retrofit Control Technologies for Gas-Fired Units That Burn Oil

c. Identification of Technically Feasible SO

Control Technologies for Scrubber Upgrades

2. Step 3: Evaluation of Control Effectiveness

a. Evaluation of SO

Control Effectiveness for Coal Fired Units

b. Evaluation of SO

Control Effectiveness for Gas Fired Units

3. Step 4: Evaluate Impacts and Document the Results for SO

a. Impact Analysis Part 1: Cost of Compliance for DSI, SDA, and Wet FGD

b. Impact Analysis Part 1: Cost of Compliance for Scrubber Upgrades

c. Impact Analysis Part 1: Cost of Compliance for Gas Units That Burn Oil

4. Impact Analysis Parts 2, 3, and 4: Energy and Non-air Quality Environmental Impacts, and Remaining Useful Life

5. Step 5: Evaluate Visibility Impacts

a. Visibility Benefits of DSI, SDA, and Wet FGD for Coal-fired Units

b. Visibility Benefits of Scrubber Upgrades for Coal-fired Units

c. Visibility Benefits of Fuel Oil Switching for Gas/Fuel Oil-Fired Units

6. BART Five Factor Analysis for PM

D. How, if at all, Do Issues of “Grid Reliability” Relate to the Proposed BART Determinations?

IV. Our Weighing of the Five BART Factors

A. SO

BART for Coal-fired Units With no SO

Controls

1. Big Brown 1 & 2

2. Monticello 1 & 2

3. Coleto Creek 1

4. Welsh 1

5. Harrington 061B & 062B

6. W A Parish WAP 5 & 6

7. J T Deely 1 & 2

B. SO

BART for Coal-fired Units With Underperforming Scrubbers

C. SO

BART for Gas-fired Units That Burn Oil

D. PM BART

V. Proposed Actions

A. Regional Haze

1. NO

BART

2. SO

BART for Coal-fired Units

3. Potential Process for Alternative Scrubber Upgrade Emission Limits

4. SO

BART for Gas-fired Units That Burn Oil

5. PM BART

B. Interstate Visibility Transport

VI. Statutory and Executive Order Reviews

I. Background

Regional haze is visibility impairment that is produced by a multitude of sources and activities that are located across a broad geographic area and emit fine particulates (PM

2.5

) (

e.g.,

sulfates, nitrates, Organic Carbon (OC), Elemental Carbon (EC), and soil dust), and their precursors (

e.g.,

Sulfur Dioxide (SO

), Nitrogen Oxides (NO

), and in some cases, ammonia (NH

) and Volatile Organic Compounds (VOCs)). Fine particle precursors react in the atmosphere to form PM

2.5

, which impairs visibility by scattering and absorbing light. Visibility impairment reduces the clarity, color, and visible distance that can be seen. PM

2.5

can also cause serious health effects and mortality in humans and contributes to environmental effects such as acid deposition and eutrophication.

Data from the existing visibility monitoring network, the “Interagency Monitoring of Protected Visual Environments” (IMPROVE) monitoring network, show that visibility impairment caused by air pollution occurs virtually all the time at most national parks and wilderness areas. In 1999, the average visual range

in many Class I areas (

i.e.,

national parks and memorial parks, wilderness areas, and international parks meeting certain size criteria) in the western United States was 100-150 kilometers, or about one-half to two-thirds of the visual range that would exist without anthropogenic air pollution. In most of the eastern Class I areas of the United States, the average visual range was less than 30 kilometers, or about one-fifth of the visual range that would exist under estimated natural conditions.

CAA programs have reduced some haze-causing pollution, lessening some visibility impairment and resulting in partially improved average visual ranges.

Visual range is the greatest distance, in kilometers or miles, at which a dark object can be viewed against the sky.

64 FR 35715 (July 1, 1999).

An interactive “story map” depicting efforts and recent progress by EPA and states to improve visibility at national parks and wilderness areas may be visited at:

http://arcg.is/29tAbS3.

CAA requirements to address the problem of visibility impairment are continuing to be addressed and implemented. In Section 169A of the 1977 Amendments to the CAA, Congress created a program for protecting visibility in the nation's national parks and wilderness areas. This section of the CAA establishes as a national goal the prevention of any future, and the remedying of any existing man-made impairment of visibility in 156 national parks and wilderness areas designated as mandatory Class I Federal areas.

On December 2, 1980, EPA promulgated regulations to address visibility impairment in Class I areas that is “reasonably attributable” to a single source or small group of sources,

i.e.,

“reasonably attributable visibility impairment.”

These regulations represented the first phase in addressing visibility impairment. EPA deferred action on regional haze that emanates from a variety of sources until monitoring, modeling, and scientific knowledge about the relationships between pollutants and visibility impairment were improved.

Areas designated as mandatory Class I Federal areas consist of National Parks exceeding 6000 acres, wilderness areas and national memorial parks exceeding 5000 acres, and all international parks that were in existence on August 7, 1977. 42 U.S.C. 7472(a). In accordance with section 169A of the CAA, EPA, in consultation with the Department of Interior, promulgated a list of 156 areas where visibility is identified as an important value. 44 FR 69122 (November 30, 1979). The extent of a mandatory Class I area includes subsequent changes in boundaries, such as park expansions. 42 U.S.C. 7472(a). Although states and tribes may designate as Class I additional areas which they consider to have visibility as an important value, the requirements of the visibility program set forth in section 169A of the CAA apply only to “mandatory Class I Federal areas.” Each mandatory Class I Federal area is the responsibility of a “Federal Land Manager.” 42 U.S.C. 7602(i). When we use the term “Class I area” in this action, we mean a “mandatory Class I Federal area.”

45 FR 80084 (December 2, 1980).

Congress added section 169B to the CAA in 1990 to address regional haze issues, and we promulgated regulations addressing regional haze in 1999.

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. The requirement to submit a regional haze SIP applies to all 50 states, the District of Columbia, and the Virgin Islands. States were required to submit the first implementation plan addressing regional haze visibility

impairment no later than December 17, 2007.

64 FR 35714 (July 1, 1999), codified at 40 CFR part 51, subpart P (Regional Haze Rule).

See 40 CFR 51.308(b). EPA's regional haze regulations require subsequent updates to the regional haze SIPs. 40 CFR 51.308(g)-(i).

Section 169A of the CAA directs states to evaluate the use of retrofit controls at certain larger, often under-controlled, older stationary sources in order to address visibility impacts from these sources. Specifically, section 169A(b)(2)(A) of the CAA requires states to revise their SIPs to contain such measures as may be necessary to make reasonable progress toward the natural visibility goal, including a requirement that certain categories of existing major stationary sources

built between 1962 and 1977 procure, install and operate the “Best Available Retrofit Technology” (BART). Larger “fossil-fuel fired steam electric plants” are included among the BART source categories. Under the Regional Haze Rule, states are directed to conduct BART determinations for “BART-eligible” sources that may be anticipated to cause or contribute to any visibility impairment in a Class I area. The evaluation of BART for Electric Generating Units (EGUs) that are located at fossil-fuel fired power plants having a generating capacity in excess of 750 megawatts must follow the “Guidelines for BART Determinations Under the Regional Haze Rule” at appendix Y to 40 CFR part 51 (hereinafter referred to as the “BART Guidelines”). Rather than requiring source-specific BART controls, states also have the flexibility to adopt an emissions trading program or alternative program as long as the alternative provides greater reasonable progress towards improving visibility than BART. To the extent a Regional Haze SIP does not meet CAA requirements to address BART, the CAA requires EPA to promulgate a FIP that makes the requisite determinations to ensure the BART requirement is satisfied, as applicable, for sources in the state.

See 42 U.S.C. 7491(g)(7) (listing the set of “major stationary sources” potentially subject-to-BART).

See, 42 U.S.C. 7491(b)(2)(A)(citing the potential need for BART as determined by “the Administrator in the case of a plan promulgated under section 7410(c) of this title”).

II. Overview of Proposed Actions

A. Regional Haze

On January 5, 2016, we took final action on nearly all portions of a Regional Haze SIP submittal submitted by the State of Texas on March 31, 2009.

In that final rule, we did not take action on the portion of the submittal that was intended to satisfy BART requirements for EGUs as mandated by 40 CFR 51.308(e). In an earlier, separate action, we issued a limited disapproval of the Texas Regional Haze SIP concerning EGU BART due to Texas' reliance on the Clean Air Interstate Rule (CAIR).

The EGU BART requirements for NO

and SO

remain unmet following the limited disapproval, and Texas has not submitted a revised SIP to address the deficiencies. While we previously proposed to approve the portion of the Regional Haze SIP that was intended to address whether EGUs in Texas must install and operate BART for PM,

that part of the proposed action was not finalized.

In connection with changed circumstances on how Texas EGUs are able to satisfy NO

and SO

BART, we are now proposing to disapprove the portion of the Texas Regional Haze SIP that evaluated the PM BART requirement for EGUs. The FIP we are proposing today addresses the EGU BART requirement and addresses these deficiencies in the Texas Regional Haze SIP.

81 FR 296 (January 5, 2016). A preliminary order of the Fifth Circuit Court of Appeals in Case No. 16-60118 was issued on July 15, 2016, and stayed the rule “in its entirety.” On December 2, 2016, the U.S. Department of Justice filed a motion for voluntary remand of the parts of the rule under challenge and consenting to continuation of the judicial stay for remanded parts of the rule. The motion also requested affirmance of the partial approvals of the Texas and Oklahoma SIPs and lifting of the stay as to those approvals. This motion is currently pending disposition.

The limited disapproval triggered the EPA's obligation to issue a FIP for Texas unless the State submitted an approvable SIP revision to correct the relevant deficiencies within 2 years of the final limited disapproval action. CAA section 110(c)(1); 77 FR 33641, 33654 (August 6, 2012).

79 FR 74817, 74851 (proposing to concur with screening analyses conducted by TCEQ including findings that no Texas EGUs are subject to BART for PM).

81 FR at 302 (January 5, 2016): “[W]e proposed to approve Texas' determination that for its EGUs no PM BART controls were appropriate, based on a screening analysis of the visibility impacts of from just PM emissions. . . ..we have. . . .decided not to finalize our proposed approval of Texas' PM BART determination [for EGUs].”

Texas' regional haze SIP relied on participation in CAIR as an alternative to meeting the source-specific BART requirements for SO

and NO

See

40 CFR 51.308(e)(4) (2006). At the time that Texas submitted its SIP to EPA, however, the D.C. Circuit had remanded CAIR (without vacatur).

See North Carolina

EPA,

531 F.3d 896 (D.C. Cir.),

modified,

550 F.3d 1176 (D.C. Cir. 2008). The court thereby left CAIR and CAIR FIPs in place in order to “temporarily preserve the environmental values covered by CAIR” until we could, by rulemaking, replace CAIR consistent with the court's opinion.

550 F.3d at 1178.

On August 8, 2011, we promulgated the Cross-State Air Pollution Rule (CSAPR), to replace CAIR.

In 2012, we issued a limited disapproval of the Texas regional haze SIP because of Texas' reliance on CAIR as an alternative to EGU BART for SO

and NO

We also determined that CSAPR would provide for greater reasonable progress than BART and amended the Regional Haze Rule to allow CSAPR participation as an alternative to source-specific SO

and NO

BART for EGUs.

CSAPR has been subject to extensive litigation, and on July 28, 2015, the D.C. Circuit issued a decision generally upholding CSAPR but remanding without vacating the CSAPR emissions budgets for a number of states in

EME Homer City Generation

EPA,

795 F.3d 118 (D.C. Cir.). Specifically, the court invalidated a number of the Phase 2 ozone-season NO

budgets and found that the SO

budgets for four states resulted in over-control for purposes of CAA section 110(a)(2)(D)(i)(I). The remand included Texas' ozone-season NO

budget and annual SO

budget.

76 FR 48208.

77 FR 33641.

While that rulemaking also promulgated FIPs for several states to replace reliance on CAIR with reliance on CSAPR as an alternative to BART, it did not include a FIP for Texas. 77 FR 33641, 33654.

We had earlier proposed to rely on CSAPR participation to address these BART-related deficiencies in Texas' SIP submittals.

Because of the uncertainty caused by the D.C. Circuit Court's partial remand, however, we determined that it was not appropriate to finalize our action. We are in the process of responding to the remand of these CSAPR budgets. On October 26, 2016, we finalized an update to the CSAPR rule that addresses the 1997 ozone NAAQS portion of the remand and the requirements of CAA section 110(a)(2)(D)(i)(I) for the 2008 ozone NAAQS.

This rule promulgated a new

FIP for Texas that replaced the CSAPR ozone season NO

emission budget designed to address the 1997 ozone NAAQS for the State with a revised budget designed to address the requirements of CAA section 110(a)(2)(D)(i)(I) for the 2008 ozone NAAQS. Then, on November 10, 2016, we proposed to withdraw the FIP provisions that require affected EGUs in Texas to participate in CSAPR for annual emissions of SO

and NO

with regard to emissions after 2016.

Withdrawal of these FIP requirements will address the D.C. Circuit's remand of the CSAPR Phase 2 SO

budget for Texas. This recently published proposed rule includes an assessment of the impacts of the set of actions that the EPA has taken or expects to take in response to the D.C. Circuit's remand on our 2012 demonstration that participation in CSAPR would provide for greater reasonable progress than BART.

79 FR 74817, 74823 (December 16, 2014).

“Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS.” 81 FR74504. The relevant portion of the remand pertained to the Phase 2 ozone season NO

emission budget designed to address the 1997 ozone NAAQS. In response to the remand, in this final rule the EPA removed the regulatory requirement for sources in Texas to comply with the phase 2 ozone season NO

budget calculated to address the 1997 ozone standard because we determined that no additional emission reductions from sources in Texas are necessary to address the State's obligation under 110(a)(2)(D)(i)(I) for the 1997 ozone NAAQS. However, because Texas is linked to downwind air quality problems with respect to the 2008 ozone NAAQS, we promulgated a new ozone season NO

emission budget to address that standard. 81 FR 74504, 74600-74601.

“Interstate Transport of Fine Particulate Matter: Revision of Federal Implementation Plan Requirements for Texas,” 81 FR 78954 (November 10, 2016). Although the court's decision specifically remanded only Texas' SO

budget, the court's rationale for remanding that budget also implicates Texas' annual NO

budget because the SO

and annual NO

budgets were developed through an integrated analysis and were promulgated to meet a common PM

2.5

transport obligation under CAA section 110(a)(2)(D)(i)(I).

In 2012, we determined that CSAPR is “better-than-BART” based on a comparison of projected visibility in scenarios representing CSAPR implementation and BART implementation, as well as a base case without CSAPR or BART, in relevant locations throughout the country. In the case of the remanded Phase 2 ozone-season NO

budgets, eight of the states with remanded budgets (including Texas) will continue to be subject to CSAPR to address ozone transport obligations with regard to the more stringent 2008 ozone NAAQS, and North Carolina and South Carolina, although no longer covered by CSAPR to address ozone transport obligations, will continue to be subject to CSAPR annual NO

requirements in order to address their PM

2.5

transport obligations. In considering the potential impact of the remand of Phase 2 budgets on the 2012 CSAPR-Better-than-BART analytic demonstration, we therefore believe that only two changes have potential relevance: The withdrawal of the FIP provisions subjecting Florida EGUs to CSAPR ozone-season NO

requirements that has already been finalized, and the withdrawal of FIP provisions subjecting Texas EGUs to CSAPR SO

and annual NO

requirements that is proposed separately. That proposed analysis supports the continued conclusion that CSAPR participation would achieve greater reasonable progress than BART for NO

despite the change in the treatment of Texas and Florida EGUs. Consequently, we have proposed that the Regional Haze Rule continues to authorize the use of CSAPR participation as a BART alternative for EGUs.

Finalization of that proposal would allow for Texas' regional haze program to rely on CSAPR ozone season control program participation as an alternative to source-specific EGU BART for NO

Based on that national proposal, we are now proposing a FIP to replace Texas' reliance on CAIR with reliance on CSAPR to address the NO

BART requirements for EGUs. Finalization of this portion of the FIP is contingent on our taking final action to find that CSAPR continues to be an appropriate alternative to source specific BART. However, finalization of the portion of our national proposal that would withdraw the FIP provisions for Texas for annual emissions of SO

and NO

described above would mean that Texas will no longer be eligible to rely on CSAPR participation as an alternative to source-specific EGU BART for SO

. As a result, we are proposing to promulgate a FIP that includes BART screening of sources and a source-by-source analysis for SO

BART and controls for this pollutant as appropriate. We are also unable to propose approval of the Texas Regional Haze SIP's PM BART evaluation, as previously proposed, as that demonstration made underlying assumptions that are no longer valid.

We instead propose to disapprove that portion of the SIP and, in place of it, promulgate source-specific PM BART requirements for EGUs that we have evaluated to be subject to BART in this proposed FIP.

81 FR at 78962-78964.

While we have proposed to remove Texas from CSAPR's annual NO

program, CSAPR is still an appropriate alternative to BART for NO

purposes because EGUs in Texas continue to be required to participate in CSAPR's ozone season NO

program.

We previously proposed approval of Texas' SIP for EGU PM BART on the premise that EGU BART for both SO

and NO

were covered by participation in CSAPR, which allowed Texas to conduct a screening analysis of the visibility impacts from PM emissions in isolation. However, modeling on a pollutant-specific basis for PM is appropriate only in the narrow circumstance where a state relies on a BART alternative to satisfy NO

and SO

BART. Due to the complexity and nonlinear nature of atmospheric chemistry and chemical transformation among pollutants, EPA has not recommended performing modeling on a pollutant-specific basis to determine whether a source is subject to BART, except in the unique situation described above. See discussion in Memorandum from Joseph Paisie to Kay Prince, “Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations,” July 19, 2006. More recently, the Ninth Circuit upheld EPA's disapproval of the Arizona regional haze SIP for including a pollutant-specific screening analysis for NO

Phoenix Cement Co.

EPA,

647 F. App'x 702, 705-06 (9th Cir. Mar. 31, 2016) (upholding EPA's interpretation that the “Regional Haze Rule [] require[s] a BART determination for any pollutant at a source that exceeds the de minimis threshold, once that source has been determined subject to BART.”). We did not finalize our proposed approval of Texas' EGU PM BART determination because of the uncertainty at that time concerning the CSAPR remand and whether Texas would continue to have CSAPR coverage for both NO

and SO

, 81 FR 296, 302, but that uncertainty has now been resolved.

We believe, however, it is preferable for states to assume primary responsibility for implementing the Regional Haze requirements as envisioned by the CAA. We will work with the State of Texas if it chooses to develop a SIP to meet these overdue Regional Haze requirements and replace or avoid a finalized FIP.

The FIP we are proposing includes BART control determinations for EGUs in Texas without previously approved BART determinations and associated compliance schedules and requirements for equipment maintenance, monitoring, testing, recordkeeping, and reporting for all affected sources and units. The EGU BART sources addressed in this FIP cause or contribute to visibility impairment at one or more Class I areas in Texas, Oklahoma, Arkansas, and New Mexico. The two Class I areas in Texas are Big Bend National Park and the Guadalupe Mountains National Park. The Class I area in Oklahoma is the Wichita Mountains National Wildlife Refuge. The two Class I areas in Arkansas are the Caney Creek Wilderness Area and the Upper Buffalo Wilderness Area. The closest impacted Class I areas in New Mexico are the Carlsbad Caverns National Park, Salt Creek Wilderness Area, and White Mountains Wilderness Area.

In order to remedy these deficiencies in the Texas SIP, we are proposing this FIP to establish the means by which the regional haze program for Texas will meet the BART requirements for SO

, NO

, and PM. We are proposing source-specific BART determinations for EGUs subject to BART for SO

and PM. We are proposing that NO

BART requirements for EGUs in Texas will be satisfied by a determination, proposed for separate finalization, that Texas' participation in CSAPR's ozone season control program is a permissible alternative to source-specific NO

BART.

Addressing the BART requirement for Texas EGUs, as proposed today, with cost-effective and readily available controls, will help ensure that progress

is made toward natural visibility conditions at Class I areas affected by Texas' sources. Please refer to our previous rulemaking on the Texas regional haze SIP for additional background regarding the CAA, regional haze, and our Regional Haze Rule.

81 FR 296. The public docket for this past rulemaking remains accessible under EPA Docket ID: EPA-R06-OAR-2014-0754 at

https://www.regulations.gov.

This proposed rulemaking has a separately established docket (EPA-R06-OAR-2016-0611). Our TSD contains a list of materials from EPA Docket ID: EPA-R06-OAR-2014-0754 that we incorporate by reference and consider to be part of this rulemaking record even as they are not necessarily re-uploaded to the newer docket.

B. Interstate Transport of Pollutants That Affect Visibility

Section 110(a) of the CAA directs states to submit a SIP that provides for the implementation, maintenance, and enforcement of each NAAQS, which is commonly referred to as an infrastructure SIP. Among other things, CAA 110(a)(2)(D)(i)(II) requires that SIPs contain adequate provisions to prohibit interference with measures required to protect visibility in other states. This requirement is referred to as “interstate visibility transport.” SIPs addressing interstate visibility transport are due to EPA within three years after the promulgation of a new or revised NAAQS (or within such shorter period as we may prescribe). A state's failure to submit a complete, approvable SIP for interstate visibility transport creates an obligation for EPA to promulgate a FIP to address this requirement.

CAA § 110(c)(1). Mandatory sanctions under CAA section 179 do not apply because the deficiencies are not with respect to a submission that is required under CAA title I part D. “Guidance on Infrastructure State Implementation Plan (SIP) Elements under Clean Air Act Sections 110(a)(1) and (2)” at pages 34-35 (September 13, 2013) [hereinafter 2013 i-SIP Guidance].

Previously, we issued a finding that Texas failed to submit a SIP revision to satisfy all four requirements of interstate transport under section 110(a)(2)(D)(i) of the CAA for the 1997 8-hour ozone and 1997 PM

2.5

NAAQS.

Texas later submitted a SIP revision to address interstate transport for these NAAQS. However, in our January 5, 2016 final action we disapproved the portion of Texas' SIP revisions intended to address interstate visibility transport for six NAAQS, including the 1997 8-hour ozone and 1997 PM

2.5

We concluded that to meet the requirements of interstate visibility transport: (1) Texas could not rely on its Regional Haze SIP, which relied heavily upon the remanded CAIR, to ensure that emissions from Texas do not interfere with measures to protect visibility in nearby states; and (2) additional control of SO

emissions in Texas were needed to prevent interference with measures required to be included in the Oklahoma SIP to protect visibility. However, in that action we did not finalize the portion of our proposed FIP addressing Texas' interstate visibility transport obligations because that portion of the proposed FIP would have partially relied on CSAPR to ensure the emissions from Texas' sources do not interfere with other states' visibility programs. Given the uncertainty that existed at the time arising from the D.C. Circuit's remand of Texas' CSAPR budgets (

EME Homer City Generation

EPA,

79 F.3d 118 (D.C. Cir.)), we concluded that it was not appropriate to finalize our proposed determination to rely on CSAPR as an alternative to SO

and NO

BART for EGUs in Texas in that action.

70 FR 21147 (April 25, 2005). The four components of interstate transport in Section 110(a)(2)(D)(i) are contained in two subsections. Section 110(a)(2)(D)(i)(I) addresses any emissions activity in one state that contributes significantly to nonattainment, or interferes with maintenance, of the NAAQS in another state. Section 110(a)(2)(D)(i)(II) requires SIPs to include provisions prohibiting any source or other type of emissions activity in one state from interfering with measures required of any other state to prevent significant deterioration of air quality or from interfering with measures required of any other state to protect visibility (referring to visibility in Class I areas). This proposal only addresses the fourth requirement concerning visibility.

Specifically, we previously disapproved the relevant portion of these Texas' SIP submittals: April 4, 2008: 1997 8-hour Ozone, 1997 PM

2.5

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

2.5

(24-hour and annual); November 23, 2009: 2006 24-hour PM

2.5

; December 7, 2012: 2010 NO

; December 13, 2012: 2008 8-hour Ozone; May 6, 2013: 2010 1-hour SO

(Primary NAAQS). 79 FR 74818, 74821; 81 FR 296, at 302.

81 FR 296, 301-2.

Our prior disapproval of interstate visibility transport for the six NAAQS is currently stayed by the Fifth Circuit.

We recognize that because our prior disapproval of the Texas SIP submittals addressing interstate visibility transport relied in part on our determinations of the measures needed in Texas to ensure reasonable progress in Oklahoma, the Fifth Circuit's stay of our previous action complicates next steps to ensure that the visibility requirements of CAA 110(a)(2)(D)(i)(II) are met. The Court's stay accordingly calls into question whether our past disapprovals for interstate visibility transport would stand. At the same time, we also note that we continue to have an obligation to issue a FIP for the 1997 8-hour ozone and 1997 PM

2.5

NAAQS as a result of our 2005 finding that Texas failed to timely submit SIPs to address the interstate transport visibility requirements. Given the uncertainties arising from the Fifth Circuit's stay of our prior disapproval, we are now proposing to reconsider the basis of our prior disapproval of Texas' SIP submittals addressing the interstate visibility transport requirement for all six NAAQS. We are now proposing to determine that Texas' SIP submittals addressing interstate visibility transport for the six NAAQS are not approvable because these submittals relied solely on Texas' Regional Haze SIP to ensure that emissions from Texas did not interfere with required measures in other states. Texas' Regional Haze SIP, in turn, relied on the implementation of CAIR as an alternative to EGU BART for SO

and NO

. Specifically, we are proposing disapproval of the following Texas SIP submittals insofar as they address the interstate visibility transport requirement: April 4, 2008: 1997 8-hour Ozone, 1997 PM

2.5

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

2.5

(24-hour and annual); November 23, 2009: 2006 24-hour PM

2.5

; December 7, 2012: 2010 NO

; December 13, 2012: 2008 8-hour Ozone; May 6, 2013: 2010 1-hour SO

(Primary NAAQS). Texas has not submitted a SIP revision to remove reliance on CAIR for Regional Haze or interstate visibility transport. As CAIR is no longer in effect and has been replaced by CSAPR, we are proposing to find that Texas' Regional Haze SIP does meet its interstate visibility transport obligations. As a result, the Texas SIPs to address interstate visibility transport for these six NAAQS continue to be unapprovable.

July 15, 2016 Order in

Texas

EPA

(Fifth Cir. Case No. 16-160118). The EPA's filed motion requesting voluntary partial remand and continuation of the judicial stay for remanded parts of the rule includes our prior disapproval of Texas' SIPs concerning interstate visibility transport. This motion is currently pending disposition.

We are proposing a FIP to cure the deficiencies in Texas' Regional Haze Program concerning EGU BART. This FIP will replace reliance on CAIR with reliance on CSAPR to meet the requirements for EGU BART for NO

in Texas. The FIP will also address Texas EGU BART for SO

and PM on a source-specific basis. With the absence of CSAPR coverage for SO

, we must reevaluate what is needed in Texas to address interstate visibility transport. Our proposed FIP to address Texas EGU BART achieves significant reductions of SO

, which exceed the reductions initially assumed for Texas under either CAIR or CSAPR. In addition, our proposed FIP achieves reductions at large sources of SO

emissions (

e.g.,

Monticello, Martin Lake and Big Brown), that have significant impacts on

Class I areas in nearby states. The BART FIP requires controls on many but not all of the sources that were controlled in our previous partial FIP for Texas Regional Haze. The EGU BART FIP also includes control requirements at some additional sources not controlled in our previous action on Texas Regional Haze.

We are proposing to find that our proposed EGU BART FIP is adequate to prevent interference with measures required to protect visibility in other states for the first planning period.

We, therefore, propose that the measures in our proposed FIP to address Texas EGU BART will fully address Texas' interstate visibility transport obligations for the six NAAQS (1997 8-hour ozone, 1997 PM

2.5,

2006 PM

2.5

, 2008 8-hour ozone, 2010 1-hour NO

, and 2010 1-hour SO

). We also propose that reliance on CSAPR for EGU NO

BART is appropriate to ensure NO

emissions from Texas EGUs do not interfere with other states' measures to protect visibility. We are proposing this action based on the reasoning that our BART FIP will achieve more emission reductions than projected under CAIR or CSAPR and the reductions are occurring at sources that have particularly large impacts on Class I areas outside of Texas. To the extent our previous final action concerning Texas Regional Haze is remanded by a Court or otherwise reconsidered in the future, we may revisit whether controls in the EGU BART FIP are adequate to address interstate visibility transport requirements. Nonetheless, we are here proposing that the proposed EGU BART FIP measures will be adequate to address interstate visibility transport based on current information. This proposal concerning the adequacy of the proposed FIP remedy does not depend on our earlier action on the Texas Regional Haze SIP or hinge on its disposition, nor does it foreclose that we may reexamine visibility transport concerns under potential scenarios where we have a responsibility to take new action.

This proposed FIP for interstate visibility transport is premised on the interpretation that this requirement can be addressed even when a Regional Haze SIP is not fully approved and the FIP does not purport to correct all Regional Haze SIP deficiencies.

See e.g.

76 FR 52388 (August 22, 2011); 76 FR 22036 (April 20, 2011); and 78 FR 14681 (March 7, 2013);

see also,

2013 i-SIP Guidance, at page 34 (stating that EPA may find it appropriate to supplement the i-SIP Guidance regarding the relationship between Regional Haze SIPs and interstate visibility transport for future planning periods).

See e.g.

78 FR 14681, 14685.

We encourage Texas to consider adopting additional SIP provisions that would allow the EPA to fully approve the Regional Haze SIP and thus to withdraw the FIP and approve Texas' SIP with respect to interstate visibility transport. Texas may also elect to satisfy interstate visibility transport by providing, as an alternative to relying on its Regional Haze SIP alone, a demonstration that emissions within its jurisdiction do not interfere with other states' plans to protect visibility.

2013 i-SIP Guidance, at pages 34-35.

C. Our Obligation To Promulgate a FIP

Under section 110(c) of the CAA, whenever we disapprove a mandatory SIP submission in whole or in part, we are required to promulgate a FIP within 2 years unless we approve a SIP revision correcting the deficiencies before promulgating a FIP. Specifically, CAA section 110(c) provides that the Administrator shall promulgate a FIP within 2 years after the Administrator disapproves a state implementation plan submission “unless the State corrects the deficiency, and the Administrator approves the plan or plan revision, before the Administrator promulgates such Federal implementation plan.”

The term “Federal implementation plan” is defined in Section 302(y) of the CAA in pertinent part as a plan promulgated by the Administrator to correct an inadequacy in a SIP.

EPA additionally has the authority to promulgate a FIP any time after finding that “a State has failed to make a required submission” of a SIP. CAA section 110(c)(1)(A); 42 U.S.C. 7410(c)(1)(a).

Beginning in 2012, following the limited disapproval of the Texas Regional Haze SIP, EPA had the authority and obligation to promulgate a FIP to address BART for Texas EGUs for NO

and SO

. In proposing to disapprove the Regional Haze SIP component that sought to address the PM BART requirement for Texas EGUs, we also have the obligation to promulgate a PM BART FIP to address the deficiency. Texas has not addressed the EGU BART disapproval, and that requirement is now significantly overdue.

We are accordingly empowered and required by the CAA to make determinations and promulgate a FIP to ensure the BART requirement for Texas EGUs is satisfied.

The Texas Regional Haze SIP stated, “The TCEQ will take appropriate action if CAIR is not replaced with a system that the US EPA considers to be equivalent to BART.” BART determinations were due in SIP submissions on December 17, 2007, 40 CFR 51.308(b), putting them on a timeline for controls by 2014 (considering the deadline for SIP action at CAA section 110(k)(2) and allowing five years for installation of BART controls). Additional delay of any amount is not appropriate and not consistent with the law.

Adding to this background, beginning with our January 5, 2016 disapproval of Texas SIP provisions regarding interstate visibility transport, we obtained the authority and obligation to promulgate a FIP to correct the deficiencies relating to that CAA requirement.

As with the BART requirement, we lack a SIP revision that would have any potential to correct the deficiency, necessitating that we now take action under FIP authority.

Additionally, we continue to have authority to issue a FIP to address interstate visibility transport for 1997 8-hour ozone and 1997 PM

2.5

due to our 2005 finding that Texas failed to submit SIPs to address interstate transport for these NAAQS under CAA section 110(a)(2)(D)(i). 70 FR 21147.

III. Our Proposed BART Analyses for SO

and PM

In our previous action,

we determined that due to the CSAPR remand, it was not appropriate at that time to rely on CSAPR as an alternative to SO

and NO

BART for EGUs in Texas. As a consequence, action to satisfy the overdue requirement to address BART for EGUs in the state of Texas was further delayed.

In this proposal, we are proposing that CSAPR, once fully revised to address the D.C. Circuit's remand, provides a basis for satisfying EGU BART obligations for NO

alone. It remains the case that we cannot rely on CSAPR as an alternative to SO

BART for Texas EGUs as further confirmed by our proposed action to remove Texas from the annual NO

and SO

control programs. Thus, we have the obligation to consider source-specific requirements for Texas EGUs consistent with the BART Guidelines for SO

BART.

See the discussion beginning on 81 FR 301 (January 5, 2016).

Id. at 346.

Because the component of the Texas Regional Haze SIP regarding the PM BART requirement for EGUs has not been acted on, we have the responsibility under CAA section 110(k) to evaluate the submission and take action to approve or disapprove it. The SIP determinations for PM were based on modeling that was conducted by examining visibility impairment due to PM emissions alone, based on the assumption that the state would be participating in CAIR for SO

and NO

and thereby having BART coverage for those pollutants. The Texas Regional Haze SIP had concluded that no PM BART controls for EGUs were appropriate, because modeling assessment of PM impacts alone showed their impacts to be too small to warrant control consideration. But Texas' screening analysis is no longer reliable or accurate because of the invalid assumption that source-by-source BART for either SO

or NO

would not be

required. In order to appropriately evaluate the BART requirements for EGUs, the visibility impacts from all pollutants must be studied, including PM emissions. Texas' PM BART analysis for EGUs does not do this.

Texas' Regional Haze SIP determined whether its sources should be subject to review for PM controls by only looking at the impact of PM emissions on visibility. This approach is only appropriate when a state satisfies the requirements for BART for SO

and NO

with an alternative measure. Additionally, as reflected in our TSD on the identification of BART-Eligible Sources, the Texas SIP neglected to identify several BART-eligible sources; this also shows error in the state's PM BART demonstration and conclusions, and it constitutes grounds for the proposed partial SIP disapproval for PM BART.

Accordingly, we are proposing to disapprove the portion of the Texas Regional Haze SIP that determined that all Texas EGUs screen out of the BART requirement for PM. The basis for the proposed disapproval is the SIP determination's assumption that EGUs would have coverage for SO

and NO

BART under an alternative measure.

Since that assumption is not valid, the technical determinations regarding PM BART cannot be approved. Following the directions of the BART Guidelines on how to identify sources “subject to BART,” we have looked at all visibility impairing pollutants from EGUs that are BART-eligible. Our proposed FIP therefore seeks to fill that regulatory gap by assessing BART for Texas EGUs for visibility impairing pollutants other than NO

i.e.,

and PM.

The requirements for “emissions trading programs or other alternative measures” that may be implemented rather than requiring BART are provided at 40 CFR 51.308(e)(2).

A. Identification of BART-Eligible Sources

The BART Guidelines set forth the steps for identifying whether the source is a BART-eligible source:

70 FR 39158 (July 6, 2005).

Step 1: Identify the emission units in the BART categories,

Step 2: Identify the start-up dates of those emission units, and

Step 3: Compare the potential emissions to the 250 ton/yr cutoff.

Following our 2016 final action on the March 31, 2009 Texas RH SIP, we began the process of generating additional technical information and analysis in order to address the above three steps in our BART-eligibility proposal. We started with Texas' facility-specific listing of BART-eligible EGU sources and removed sources we verified had retired. We then gathered additional information from (1) our authority under Section 114(a) of the CAA to request information from potential BART-eligible sources, and (2) the U.S. Energy Information Administration (EIA). We then converted Texas' facility-specific BART-eligible list to a unit-specific BART-eligible list and verified the BART-eligibility of each unit. The following is a list of units we propose have satisfied the above three steps and are BART-eligible:

See our BART FIP TSD for more information concerning how we selected the units we are proposing are BART-eligible and other details concerning our proposed BART determinations.

Table 1—Summary of BART-Eligibility Analysis

Facility

Unit

Barney M. Davis (Talen/Topaz)

Big Brown (Luminant)

Cedar Bayou (NRG)

CBY1.

Cedar Bayou (NRG)

CBY2.

Coleto Creek (Engie)

Dansby (City of Bryan)

Decker Creek (Austin Energy)

Fayette (LCRA)

Graham (Luminant)

Greens Bayou (NRG)

Handley (Exelon)

Harrington Station (Xcel)

061B.

Harrington Station (Xcel)

062B.

J T Deely (CPS Energy)

Jones Station (Xcel)

151B.

Jones Station (Xcel)

152B.

Knox Lee Power Plant (AEP)

Lake Hubbard (Luminant)

Lewis Creek (Entergy)

Martin Lake (Luminant)

Monticello (Luminant)

Newman (El Paso Electric)

Nichols Station (Xcel)

143B.

O W Sommers (CPS Energy)

Plant X (Xcel)

Powerlane (City of Greenville)

ST1.

Powerlane (City of Greenville)

ST2.

Powerlane (City of Greenville)

ST3.

R W Miller (Brazos Elec. Coop)

Sabine (Entergy)

Sim Gideon (LCRA)

Spencer (City of Garland)

Stryker Creek (Luminant)

ST2.

Trinidad (Luminant)

Ty Cooke (City of Lubbock)

V H Braunig (CPS Energy)

W A Parish (NRG)

WAP4.

W A Parish (NRG)

WAP5.

W A Parish (NRG)

WAP6.

Welsh Power Plant (AEP)

Wilkes Power Plant (AEP)

The final step in identifying a “BART-eligible source” is to use the information from the previous three steps to identify the collection of emissions units that comprise the BART-eligible source.

B. Identification of Sources That Are Subject to BART

Following our compilation of the BART-eligible sources in Texas, we examined whether these sources cause or contribute to visibility impairment in nearby Class I areas.

For those sources that are not reasonably anticipated to cause or contribute to any visibility impairment in a Class I area, a BART determination is not required. Those sources are determined to be not subject-to-BART. Sources that are reasonably anticipated to cause or contribute to any visibility impairment in a Class I area are determined to be subject-to-BART. For each source subject to BART, 40 CFR 51.308(e)(1)(ii)(A) requires that states (or EPA, in the case of a FIP) identify the level of control representing BART after considering the factors set out in CAA section 169A(g). The BART guidelines discuss several approaches available to exempt sources from the BART determination process, including modeling individual sources and the use of model plants. To determine which sources are anticipated to contribute to visibility impairment the BART guidelines state that CALPUFF or another appropriate model can be used to predict the visibility impacts from a single source at a Class I area. We employed a four-fold strategy in determining which units should or should not be subject to BART. A flowchart of the analysis along with a detailed discussion of the subject-to-BART screening analysis is provided in

the BART Screening TSD.

We summarize the methodology and results of this analysis here.

See 40 CFR part 51, Appendix Y, III, How to Identify Sources “Subject to BART”.

See our TSD, “Our Strategy for Assessing which Units are Subject to BART for the Texas Regional Haze BART Federal Implementation Plan (BART Screening TSD)” in our docket.

First, we examined whether any of the BART-eligible units should be eliminated from consideration based on the standard model plant exemptions described in the BART Guidelines.

Second, we created specific model plants between sources and nearby Class I areas and conducted CALPUFF modeling to evaluate a number of sources for exemption. Third, we performed stand-alone, source specific CALPUFF modeling on a number of units to determine if their visibility impacts were large enough to identify them as being subject to BART. Fourth, for those remaining units outside of the CALPUFF model's range, we contracted to have CAMx modeling performed to determine if their visibility impacts were large enough to merit their being subject to BART. These steps are further described below.

See the discussion beginning on 70 FR 39104, 39162 (July 6, 2005) [40 CFR part 51, App. Y].

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 preamble advises that, “for purposes of determining which sources are subject to BART, States should consider a 1.0 deciview change or more from an individual source to “cause” visibility impairment, and a change of 0.5 deciviews to “contribute” to impairment.”

It further advises that “States should have discretion to set an appropriate threshold depending on the facts of the situation,” 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,” and describes situations in which states may wish to exercise their discretion to set lower thresholds, mainly in situations in which a large number of BART-eligible sources within the State and in proximity to a Class I area justify this approach. We do not believe that the sources under consideration in this rule, most of which are not in close proximity to a Class I area, merit the consideration of a lesser contribution threshold. Therefore, our analysis employs a contribution threshold of 0.5 deciviews.

70 FR at 39118.

1. Our Use of the Standard BART Model Plant Exemption

As the BART Guidelines note:

[W]e 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 NO

or SO

(or combined NO

and SO

), 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 NO

or SO

(or combined NO

and SO

) that are located more than 100 kilometers from any Class I area. You do, however, have the option of showing other thresholds might also be appropriate given your specific circumstances.

70 FR at 39163 [40 CFR part 51, App. Y].

We applied the standard BART model plant exemption described above to the following facilities, exempting them from further analysis:

Table 2—Standard BART Model Plant Exempt Sources

Facility

Units

Dansby (City of Bryan)

Greens Bayou (NRG)

Nichols Station (Xcel)

143B.

Plant X (Xcel)

Powerlane (City of Greenville)

ST1, ST2 & ST3.

Spencer (City of Garland)

4 & 5.

Trinidad (Luminant)

Ty Cooke (City of Lubbock)

1 & 2.

2. Our Extension of the BART Model Plant Exemption

As the BART Guidelines note, the standard BART model plant exemption can be extended to values other than the 500 tons/50 km and 1,000 tons/100 km scenarios discussed in the previous section. The BART Guidelines explain that: “you may find based on representative plant analyses that certain types of sources are not reasonably anticipated to cause or contribute to visibility impairment. To do this, you may conduct your own modeling to establish emission levels and distances from Class I areas on which you can rely to exempt sources with those characteristics.”

70 FR at 39163 [40 CFR part 51, App. Y].

Modeling analyses of representative plants are used to reflect groupings of specific sources with important common characteristics. We conducted CALPUFF modeling to establish emission levels and distances from Class I areas on which we could rely to exempt sources with those characteristics. In this approach, a hypothetical facility (“model plant”) is located between a group of BART-eligible sources and a Class I area. Predominant wind patterns and elevation are considered in locating the model plant such that conditions that would be anticipated to transport pollution from the group of BART-eligible sources to the Class I area are consistent with conditions anticipated to transport pollution from the model plant to the Class I area. The visibility impacts from this model plant are modeled utilizing CALPUFF following the protocol described in the BART Screening TSD. Model plant emissions are adjusted such that the modeled visibility impact (maximum of 98th percentile values for 2001, 2002, and 2003) is below the screening threshold of 0.5 dv. For each model plant, theQ/d value is calculated as the annual emissions (combined NO

and SO

emissions) divided by distance to the Class I area (km) resulting in a critical Q/d value. The Q/d value for each BART-eligible source is calculated based on annual emissions based on the maximum actual 24-hr emission rate and distance to the Class I area and is then compared to the critical Q/d value. For a BART-eligible source with a lower Q/d value than the critical Q/d, it is reasonably anticipated that the visibility impact from the BART-eligible source is lower than the model plant and therefore below the screening threshold and not subject to BART. See the BART Screening TSD for additional discussion and source-specific information used in this model plant screening analysis. By this extension of the BART model plant exemption, we identified the following additional facilities that can be exempted from further analysis:

Table 3—Extended BART Model Plant Exempt Sources

Facility

Units

Barney M. Davis (Talen/Topaz)

Cedar Bayou (NRG)

CBY1 & CBY2.

Decker Creek (Austin

Energy)

1 & 2.

Lewis Creek (Entergy)

1 & 2.

Sabine (Entergy)

2, 3, 4 & 5.

Sim Gideon (LCRA)

1, 2 & 3.

V H Braunig (CPS Energy)

1, 2 & 3.

3. Our Use of CALPUFF Modeling To Exempt Sources From Being Subject to BART

Those sources that did not screen out using the model plant approach were modeled directly with CALPUFF if they were in a range of when CALPUFF has

been previously used. Historically CALPUFF has been used at distances up to approximately 400 km. The maximum 98th percentile impact from the modeled years (calculated based on annual average natural background conditions) was compared with the 0.5 dv screening threshold following the modeling protocol described in the BART screening TSD. The BART Guidelines recommend that states use the 24-hour average actual emission rate from the highest emitting day of the meteorological period modeled, unless this rate reflects periods of start-up, shutdown, or malfunction. The maximum 24-hour emission rate (lb/hr) for NO

and SO

from the 2000-2004 baseline period for each source was identified through a review of the daily emission data for each BART-eligible unit from EPA's Air Markets Program Data.

For some BART-eligible sources, evaluation of baseline emissions revealed evidence of the installation of NO

control technology during the baseline period. For those sources, the maximum emission rate was updated to reflect the identified maximum emission rate from the post-control portion of the baseline period. Because daily emissions are not available for PM, the annual average emission rate was doubled to approximate the 24-hr maximum emission rate for PM. See the BART Screening TSD for additional discussion and source-specific information used in the CALPUFF modeling for this portion of the screening analysis. With the use of CALPUFF modeling results, we identified the following additional facilities that can be exempted from further analysis:

http://ampd.epa.gov/ampd/.

Table 4—CALPUFF BART Exempt Sources

Facility

Units

Handley (Exelon)

3, 4 & 5.

Jones (Xcel)

151B & 152B.

Lake Hubbard (Luminant)

1 & 2.

Knox Lee (AEP)

R W Miller (Brazos Elec. Coop)

1, 2 & 3.

Based on these CALPUFF screening analyses using model plant approaches and direct modeling, the following gas

/fuel oil fired facilities did not screen out from being subject to BART: Newman, Stryker, Graham, and Wilkes. None of the coal fired facilities screened out in our CALPUFF modeling for the facilities within CALPUFF range.

When we use the term “gas,” we mean “pipeline quality natural gas.”

4. Our Use of CAMx Modeling To Exempt Sources From Being Subject to BART

Some of the BART-eligible sources in Texas are geographically distant from a Class I area, yet have high enough emissions that they may significantly impact visibility at Class I areas in Texas and surrounding states. However, the use of CALPUFF is not recommended for distances much greater than 300 km, and has typically not been used at distances more than approximately 400 km. To determine which sources are anticipated to contribute to visibility impairment the BART guidelines state that CALPUFF or another appropriate model can be used to predict the visibility impacts from a single source at a Class I area. CAMx provides a scientifically defensible platform for assessment of visibility impacts over a wide range of source-to-receptor distances. CAMx is also more suited than some other modeling approaches for evaluating the impacts of SO

, NO

, VOC and PM emissions as it has a more robust chemistry mechanism. The CAMx PM Source Apportionment Technology (PSAT) modeling was conducted for those BART-eligible sources that have large SO

emissions.

In 2006/2007, the TCEQ developed a modeling protocol and analysis using CAMx with the same Plume in Grid and PSAT techniques to evaluate visibility impacts from non-EGU BART sources, as well as to evaluate VOC and PM impacts from all BART-eligible sources to inform the 2009 Texas Regional Haze SIP.

51 52

This modeling protocol was reviewed by the TCEQ, EPA and FLM representatives specialized in air quality analyses and BART prior to performing the analysis and submission of their regional haze SIP. Our subject-to-BART screening modeling for EGU-sources using CAMx is consistent with the protocol developed and utilized by Texas in their regional haze SIP. We are using more recent model versions with updated science in our analysis.

CAMx results were also obtained and add to our basis of information for coal-fired facilities that have CALPUFF results.

See TX RH SIP Appendix 9-5, “Screening Analysis of Potential BART-Eligible Sources in Texas”; Revised Draft Final Modeling Protocol Screening Analysis of Potentially BART-Eligible Sources in Texas, Environ Sept. 27, 2006; and Guidance for the Application of the CAMx Hybrid Photochemical Grid Model to Assess Visibility Impacts of Texas BART Sources at Class I Areas, Environ December 13, 2007 all available in the docket for this action.

We approved Texas' subject-to-BART analysis for non-EGU sources which relied on this CAMx modeling in our January 5, 2016 rulemaking (81 FR 296).

Consistent with the BART guidelines and our CALPUFF modeling, for the selected BART-eligible sources we used the maximum actual 24-hr emission rates for NO

and SO

from the 2000-2004 baseline period from EPA's Air Markets Program Data

and modeled these emission rates as constant emission rates for the entire modeled year. For some of the modeled BART-eligible sources, evaluation of baseline emissions revealed evidence of installation of NO

control technology during the baseline period. For those sources the maximum emission rate was identified from the post-control portion of the baseline period. Because daily emissions are not available for PM, the annual average emission rate was doubled to approximate the 24-hr maximum emission rate for PM. A BART-eligible source that is shown not to contribute significantly to visibility impairment at any of the Class I areas using CAMx modeling may be excluded from further steps in the BART process. The maximum modeled impact for each source (calculated based on annual average natural background conditions) was compared to the 0.5 dv contribution threshold. See the BART Screening TSD for additional details on the CAMx modeling performed and the model inputs used. The table below summarizes the results of the CAMx screening analysis. As shown in the table below, all sources analyzed with CAMx modeling had impacts greater than 0.5 dv at one or more Class I areas. The most impacted Class I areas based on these results are Wichita Mountains National Wildlife Refuge in Oklahoma (WIMO), Caney Creek Wilderness Area in Arkansas (CACR), and Salt Creek Wilderness Area in New Mexico (SACR). CAMx modeled impacts at single locations for these sources (maximum impact day) ranged from 0.845 dv to 10.498 dv.

http://ampd.epa.gov/ampd/.

Table 5—CAMx BART Screening Source Analysis Results

BART-eligible source

Units

Most impacted Class I area

Maximum

delta-dv

Less than

0.5 dv?

Number of

modeled days

over 0.5 dv

Number of

modeled days

over 1.0 dv

Big Brown

1 & 2

WIMO

4.017

Coleto Creek

WIMO

0.845

Fayette Power

1 & 2

CACR

1.894

Harrington

061B & 062B

SACR

5.288

Martin Lake

1, 2, & 3

CACR

6.651

141

Monticello

1, 2, & 3

CACR

10.498

152

111

Calaveras

J T Deely 1 & 2, OW Sommers 1 & 2

WIMO

1.513

W A Parish

WAP4, WAP5 & WAP6

CACR

3.177

Welsh

1 & 2

CACR

4.576

Welsh unit 2 has recently shutdown. We note that baseline impacts from unit 1 alone are 2.343 dv at Caney Creek.

Number of days over 0.5 or 1.0 dv at the most impacted Class I area.

5. Summary of Sources that are Subject to BART

Based on the four methodologies described above, the BART-eligible sources in the table below have been determined to cause or contribute to visibility impairment at a nearby Class I area, and we therefore propose to find the sources are subject-to-BART. They are subject to review for visibility impairing pollutants other than NO

Foremost, they are subject to SO

BART, the visibility impairing pollutant that is the main contributor to the regional haze problem at Class I areas in Texas and neighboring states. The sources are also subject to review for source-specific BART requirements for PM.

The NO

BART requirement for these EGU sources is not addressed by source-specific limits in this proposal. According to our proposal, participation in CSAPR, in its updated form, would serve as a BART alternative, dispensing with the need for source-specific BART determinations and requirements for NO

Table 6—Summary: Sources That are Subject-to-BART

Facility

Units

Big Brown

1 & 2.

Coleto Creek

Fayette Power

1 & 2.

Harrington

061B & 062B.

Martin Lake

1, 2 & 3.

Monticello

1, 2 & 3.

Calaveras

J T Deely 1 & 2, O W Sommers 1 & 2.

W A Parish

WAP4, WAP5 & WAP6.

Welsh

1 & 2*.

Stryker

ST2.

Graham

Wilkes

1, 2 & 3.

Newman

2, 3 & 4.

* Welsh Unit 2 retired in April, 2016.

C. Our BART Five Factor Analyses

The purpose of the BART analysis is to identify and evaluate the best system of continuous emission reduction based on the BART Guidelines.

In determining BART, a state, or EPA when promulgating a FIP, must consider the five statutory factors in section 169A of the CAA: (1) The costs of compliance; (2) the energy and nonair quality environmental impacts of compliance; (3) any existing pollution control technology in use at the source; (4) the remaining useful life of the source; and (5) the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology. See also 40 CFR 51.308(e)(1)(ii)(A). This is commonly referred to as the “BART five factor analysis.” The BART Guidelines break the analyses of these requirements down into five steps:

See July 6, 2005 BART Guidelines, 40 CFR part 51, Regional Haze Regulations and Guidelines for Best Available Retrofit Technology Determinations.

70 FR 39104, 39164 (July 6, 2005) [40 CFR part 51, App. Y].

STEP 1—Identify All Available Retrofit Control Technologies,

STEP 2—Eliminate Technically Infeasible Options,

STEP 3—Evaluate Control Effectiveness of Remaining Control Technologies,

STEP 4—Evaluate Impacts and Document the Results, and

STEP 5—Evaluate Visibility Impacts.

The following sections treat these steps individually for SO

. We are combining these steps into one section in our assessment of PM BART that follows the SO

sections.

1. Steps 1 and 2: Technically Feasible SO

Retrofit Controls

The BART Guidelines state that in identifying all available retrofit control options,

[Y]ou must identify the most stringent option and a reasonable set of options for analysis that reflects a comprehensive list of available technologies. It is not necessary to list all permutations of available control levels that exist for a given technology—the list is complete if it includes the maximum level of control each technology is capable of achieving.

70 FR at 39164, fn 12 [40 CFR part 51, App. Y]

Adhering to this, we will identify a reasonable set of SO

control options, including those that cover the maximum level of control each technology is capable of achieving. In the course of that task, we will note whether any of these technologies are technically infeasible.

The subject-to-BART units identified in Table 6 can be organized into four broad categories, based on their fuel type and the potential types of SO

controls that could be retrofitted: (1) Coal-fired EGUs with no SO

scrubber, (2) coal-fired EGUs with underperforming SO

scrubbers, (3) gas-fired EGUs that do not burn oil, and (4) gas-fired EGUs that occasionally burn fuel oil. This classification is represented below:

Table 7—Subject to BART Fuel Types and Potential SO

BART Controls

Facility

Unit

Coal

no scrubber

Coal

underperforming

scrubber

Gas no oil

Gas burns oil

Big Brown (Luminant)

Coleto Creek (Engie)

Fayette (LCRA) *

Graham (Luminant)

Harrington Station (Xcel)

061B

Harrington Station (Xcel)

062B

J T Deely (CPS Energy)

Martin Lake (Luminant)

Monticello (Luminant)

Newman (El Paso Electric)

O W Sommers (CPS Energy)

Stryker Creek (Luminant)

ST2

W A Parish (NRG)

WAP4

W A Parish (NRG)

WAP5

W A Parish (NRG)

WAP6

Welsh Power Plant (AEP)

Wilkes Power Plant (AEP)

* The Fayette units have high performing wet Flue Gas Desulfurization scrubbers in place.

For the coal-fired EGUs without an existing scrubber, we have identified four potential control technologies: (1) Coal pretreatment, (2) Dry Sorbent Injection (DSI), (3) Spray Dryer Absorber (SDA), and (4) wet Flue Gas Desulfurization (FGD.) For the coal-fired EGUs with an existing underperforming scrubber we will examine whether that scrubber can be upgraded.

Gas-fired EGUs that do not burn oil have inherently very low SO

emissions and there are no known SO

controls that can be evaluated.

For gas-fired units that occasionally burn fuel oil, we will follow the BART Guidelines recommendations for oil-fired units: “For oil-fired units, regardless of size, you should evaluate limiting the sulfur content of the fuel oil burned to 1 percent or less by weight.”

In addition, we will also evaluate the potential for post combustion SO

controls for these units.

70 FR 39171 (July 6, 2005) [40 CFR 51, App. Y].

a. Identification of Technically Feasible SO

Retrofit Control Technologies for Coal-Fired Units

Available SO

control technologies for coal-fired EGUs consist of either pretreating the coal in order to improve its qualities, or treating the flue gas through the installation of either DSI or some type of scrubbing technology.

Coal Pretreatment

Coal pretreatment, or coal upgrading, has the potential to reduce emissions by reducing the amount of coal that must be burned in order to result in the same heat input to the boiler. Coal pretreatment broadly falls into two categories: coal washing and coal drying.

Coal washing is often described as preparation (for particular markets) or cleaning (by reducing the amount of mineral matter and/or sulphur in the product coal).

Washing operations are carried out mainly on bituminous and anthracitic coals, as the characteristics of subbituminous coals and lignite (brown coals) do not lend themselves to separation of mineral matter by this means, except in a few cases.

Coal is mechanically sized, then various washing techniques are employed, depending on the particle size, type of coal, and the desired level of preparation.

Following the coal washing, the coal is dewatered, and the waste streams are disposed.

Couch, G.R., “Coal Upgrading to Reduce CO

emissions,” CCC/67, October 2002, IEA Clean Coal Centre.

Ibid.

Various coal washing techniques are treated in detail in Chapter 4 of

Meeting Projected Coal Production Demands In The USA, Upstream Issues, Challenges, and Strategies,

The Virginia Center for Coal and Energy Research, Virginia Polytechnic Institute and State University, contracted for by the National Commission on Energy Policy, 2008.

Coal washing takes place offsite at large dedicated coal washing facilities, typically located near where the coal is mined. In addition, coal washing carries with it a number of problems:

• Coal washing is not typically performed on the types of coals used in the power plants under consideration, Powder River Basin (PRB) subbituminous and Texas lignites.

• Because coal washing is not typically conducted onsite of the power plant, it is viewed as a consideration in the selection of the coal, and not as an air pollution control.

• Coal washing poses significant energy and non-air quality considerations under section 51.308(e)(1)(ii)(A). For instance, it results in the use of large quantities of water,

and coal washing slurries are typically stored in impoundments, which can, and have, leaked.

“Water requirements for coal washing are quite variable, with estimates of roughly 20 to 40 gallons per ton of coal washed (1 to 2 gal per MMBtu) (Gleick, 1994; Lancet, 1993).” Energy Demands on Water Resources, Report to Congress on the Interdependency of Energy and Water, U.S. Department Of Energy, December 2006.

Committee on Coal Waste Impoundments, Committee on Earth Resources, Board on Earth Sciences and Resources, Division on Earth and Life Studies;

Coal Waste Impoundments, Risks, Responses, and Alternatives;

National Research Council; National Academy Press, 2002.

Because of these issues, we do not consider coal washing as a part of our reasonable set of options for analysis as BART SO

control technology.

In general, coal drying consists of reducing the moisture content of lower rank coals, thereby improving the heating value of the coal and so reducing the amount of coal that has to be combusted to achieve the same power, thus improving the efficiency of the boiler. In the process, certain pollutants are reduced as a result of (1) mechanical separation of mineralized sulfur (

e.g.,

and iron pyrite) and rocks, and (2) the unit burning less coal to make the same amount of power.

Coal drying can be performed onsite and so can be considered a potential BART control. Great River Energy has developed a patented process which is being successfully utilized at the Coal Creek facility and is potentially available for installation at other facilities.

This process utilizes excess waste heat to run trains of moving fluidized bed dryers. The process offers a number of co-benefits, such as general savings due to lower coal usage (

e.g.,

coal cost, ash disposal), less power required to run mills and ID fans, and lower maintenance on coal handling equipment air preheaters, etc.

DryFining

is the company's name for the process. It is described here:

http://www.powermag.com/improve-plant-efficiency-and-reduce-co2-emissions-when-firing-high-moisture-coals/.

Although we view this new patented technology for coal drying onsite as a promising path in the near future for generally improving boiler efficiency and obtaining some reduction in SO

, its analysis presents a number of difficulties. For instance, the degree of reduction in SO

is dependent on a number of factors. These include (1) the quality and quantity of the waste heat available at the unit, (2) the type of coal being dried (amount of bound sulfur,

i.e.,

pyrites, moisture content), and (3) the design of the boiler (

e.g.,

limits to steam temperatures, which can decrease due to the reduced flue gas flow through the convective pass of the boiler). We cannot assess many of these site-specific issues and we believe that requesting that the facilities in question do so would require detailed engineering analysis and extend our review time greatly. As a result of these issues, we do not further assess coal drying as part of our reasonable set of options for BART analysis. We expect that this technology may have matured enough such that it can be better assessed for the second planning period.

DSI

DSI is performed by injecting a dry reagent into the hot flue gas, which chemically reacts with SO

and other gases to form a solid product that is subsequently captured by the particulate control device. A blower delivers the sorbent from its storage silos through piping directly to the flue gas ducting via injection lances. The most commonly used sorbent is trona, a naturally occurring mineral primarily mined from the Green River Formation in Wyoming. Trona can also be processed into sodium bicarbonate, which is more reactive with SO

than trona, but more expensive. Hydrated lime is another potential sorbent but it is less frequently used and little data are available regarding its potential performance and cost. In general, trona is considered the most cost-effective of the sorbents for SO

removal. There are many examples of DSI being used on coal-fired EGUs to control SO

. However, DSI may not be technically feasible at every coal-fired EGU. For instance, Luminant states in its response to one of our Section 114(a) letters regarding its Big Brown and Monticello units:

Luminant's 6/17/14 response to EPA's 5/20/14 Section 114(a) request for information relating to the Big Brown, Martin Lake, Monticello, and Sandow generating stations.

Luminant commissioned the study of dry sorbent injection (“DSI”) at these units in 2011. These studies determined that a very high feed rate (in the range of 20-30%) was required to achieve modest SO

removal. Further, it was determined that other economic and operational factors make the use of DSI infeasible. For example, sorbent build-up was determined to cause degraded performance of the control equipment over time, as well as significant, repeat down time on a regular basis (

i.e.,

every few days) to remove the buildup. In addition to the high cost of the sorbent required, the disposal and transport of the used sorbent (a Texas Class 1 waste) would result in significant additional cost. Thus, the use of DSI was determined infeasible from both an operational and economic point of view, and further evaluation has been discontinued.

As a consequence of this statement, which is discussed more fully in the CBI material Luminant has submitted and in our TSD, we have concluded that DSI is not a feasible alternative for the Big Brown and Monticello facilities. For all unscrubbed, coal-fired BART-subject units other than the Big Brown and Monticello facilities, although individual installations may present technical difficulties or poor performance due to the suboptimization of one or more of the above factors, we believe that DSI is technically feasible and should be considered as a potential BART control.

Scrubbing Systems

In contrast to DSI, SO

scrubbing techniques utilize a large dedicated vessel in which the chemical reaction between the sorbent and SO

takes place either completely or in large part. Also in contrast to DSI systems, SO

scrubbers add water to the sorbent when introduced to the flue gas. The two predominant types of SO

scrubbing employed at coal-fired EGUs are wet FGD, and Spray Dry Absorber (SDA). More recently, Circulating Dry Scrubbers (CDS) have been introduced. The EIA reports the following types of flue gas desulfurization systems as being operational in the U.S. for 2015:

Table 8—EIA Reported Desulfurization Systems in 2015

Type

Number of

installations

Wet spray tower scrubber

296

Spray dryer absorber

269

Circulating dry scrubber

Packed tower wet scrubber

Venturi wet scrubber

Jet bubbling reactor

Tray tower wet scrubber

Mechanically aided wet scrubber.

DSI

106

Other

Unspecified

Total

854

Excluding the DSI installations, EIA lists 748 SO

scrubber installations in operation in 2015. Of these, 296 are listed as being spray type wet scrubbers, with an additional 42 listed as being

tray type wet scrubbers.

An additional 269 are listed as being spray dry absorber types. Consequently, spray type or tray type wet scrubbers (wet FGD) account for approximately 45% of all scrubber systems, and spray dry scrubbers (SDA) account for approximately 36% of all scrubber systems that were operational in the U.S. in 2015.

Trays are often employed in spray type wet scrubbers and EIA lists some of the wet spray tower systems as secondarily including trays.

We consider some of the other scrubber system types (

e.g.,

venturi and packed wet scrubber types) to be older, outdated technologies (that are not existing controls or factor into considerations regarding existing controls) and therefore will not be considered in our BART analysis. Jet bubbling reactors and circulating dry scrubbers are relatively new technologies, with limited installations, and little information is available with which to characterize them or their suitability as a retrofit control option. Therefore, they too will not be further considered as part of our reasonable set of options for analysis for BART controls.

In summary, wet FGD and SDA installations account for approximately 81% of all scrubber installations in the U.S. and as such constitute a reasonable set of SO

scrubber control options. The vast majority of the wet FGD and SDA installations utilize limestone and lime, respectively as reagents. In addition, these technologies cover the maximum level of SO

control available. As described above, these controls are in wide use and have been retrofitted to a variety of boiler types and plant configurations. We therefore see no technical infeasibility issues and believe that limestone wet FGD and lime SDA should be considered as potential BART controls for all of the unscrubbed coal-fired BART-eligible units.

b. Identification of Technically Feasible SO

Retrofit Control Technologies for Gas-Fired Units that Burn Oil

Reduction in Fuel Oil Sulfur

A number of the units we proposed in Table 6 as being subject to BART primarily fire gas, but have occasionally fired fuel oil in the past as reported by the EIA databases: EIA-767, EIA-906/920, and EIA-923,

which indicate the historic quantities of fuel oil burned and the type and sulfur content of that fuel oil. These units are identified below in Table 9:

EIA-767:

http://www.eia.gov/electricity/data/eia767/.

EIA-906/920 and EIA-923:

http://www.eia.gov/electricity/data/eia923/.

Table 9—Gas Units that Occasionally Burn Oil and are Subject to BART

Facility

Unit(s)

Gas turbine

Steam turbine

Graham (Luminant)

Newman (El Paso Electric)

2, 3

O W Sommers (CPS Energy)

1, 2

Stryker Creek (Luminant)

ST2

Wilkes Power Plant (AEP)

The BART Guidelines advise that for oil-fired units, regardless of size, limits on fuel oil sulfur content should be considered in the BART evaluation.

All of the subject units are limited by permit to burning oil with a sulfur content of no more than 0.7% sulfur by weight.

In analyzing the technical feasibility under BART of these facilities burning fuel oils of sulfur contents lower than historically burned, we investigated two issues: (1) Is lower sulfur fuel oil available and what is its cost, and (2) are there any technical issues in burning a lower sulfur fuel oil that could add to the cost of that oil? All of the units have either burned Distillate Fuel Oil (DFO) or have switched between DFO and Residual Fuel Oil (RFO), thus demonstrating the ability to burn DFOs of the type under consideration for SO

BART. We therefore conclude that lower sulfur DFOs are a technically feasible retrofit control option under BART. Lower sulfur DFOs carry no capital costs. Any cost increases relate to purchase price differences.

70 FR at 39171.

In addition, the Newman units 2 and 3 are restricted to burning fuel oil for no more than 10% of their annual operating time.

Scrubber Feasibility for Gas/Oil-Fired Boilers

We are aware of instances in which FGDs of various types have been installed or otherwise deemed feasible on a boiler that burns oil.

Consequently, we will consider the installation of various types of scrubbers to be technically feasible.

Crespi, M. “Design of the FLOWPAC WFGD System for the Amager Power Plant.” Power-Gen FGD Operating Experience, November 29, 2006, Orlando, FL.

Babcock and Wilcox. “Wet Flue Gas Desulfurization (FGD) Systems Advanced Multi-Pollutant Control Technology.” See Page 4: “We have also provided systems for heavy oil and Orimulsion fuels.”

DePriest, W; Gaikwad, R. “Economics of Lime and Limestone for Control of Sulfur Dioxide.” See page 7: “A CFB unit, in Austria, is on a 275 MW size oil-fired boiler burning 1.0-2.0% sulfur oil.”

c. Identification of Technically Feasible SO

Control Technologies for Scrubber Upgrades

In our recent Texas-Oklahoma FIP,

we presented a great deal of information that concluded that the existing scrubbers for a number of facilities could be very cost-effectively upgraded.

That information is included in this proposal.

It contains a comprehensive survey of available literature concerning the kinds of upgrades that have been performed by industry on scrubber systems similar to the ones installed on the units included in this proposal. We then reviewed all of the information we had at our disposal regarding the status of the existing scrubbers for each unit, including any upgrades the facility may have already installed. We finished by calculating the cost-effectiveness of scrubber upgrades, using the facility's own information, obtained as a result of our Section 114 collection efforts. The companies that supplied this information have asserted a Confidential Business Information (CBI) claim for much of it, as provided in 40 CFR 2.203(b). We therefore redacted any CBI information we utilize in our analyses, or otherwise disguised it so that it cannot be traced back to its specific source. Of the facilities we evaluated for scrubber upgrades in that action, Martin Lake Units 1, 2, and 3; and Monticello Unit 3 are subject to BART and are thus a part of this proposal.

81 FR 321.

See information presented in Sections 6 and 7 of the Cost TSD.

That information is included in our BART FIP TSD, Appendix B.

2. Step 3: Evaluation of SO

Control Effectiveness

In the following subsections, we evaluate the control levels each technically feasible technology is capable of achieving for the coal and gas units. In so doing, we consider the maximum level of control each technology is capable of delivering 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.”

To calculate a 30-day rolling average based on BOD, 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. In effect, this provides a margin of safety by eliminating spikes that occur at the beginning and end of outages.

70 FR 39103, 39172 (July 6, 2005), [40 CFR part 51, App. Y].

a. Evaluation of SO

Control Effectiveness for Coal Fired Units

Control Effectiveness of DSI

We lack the site-specific information, which we believe requires an individual performance test, in order to be able to accurately determine the maximum DSI SO

removal efficiency for the individual units listed in Table 7. We are aware that a number of the subject-to-BART coal-fired units have conducted such testing. However, although we have examined that testing, most of the facilities have claimed it as CBI and requested protection from public disclosure as provided by 40 CFR part 2.

However, we nevertheless must evaluate DSI as a viable, proven method of SO

control. We must do the same for SO

scrubbing, and in so doing, compare the visibility benefits and costs of each technology in order to inform our proposed BART determinations. We therefore propose the following methodology:

• We will evaluate each unit at its maximum recommended DSI performance level, according to the IPM DSI documentation,

assuming milled trona: 80% SO

removal for an ESP installation and 90% SO

removal for a baghouse installation. This level of control is within the range that can be achieved by SO

scrubbers, and thus allows a better comparison of the costs of DSI and scrubbers.

IPM Model—Updates to Cost and Performance for APC Technologies, Dry Sorbent Injection for SO

Control Cost Development Methodology, Final March 2013, Project 12847-002, Systems Research and Applications Corporation, Prepared by Sargent & Lundy, p. 7.

• However, (1) we do not know whether a given unit is actually capable of achieving these control levels and (2) we believe it is useful to evaluate lesser levels of DSI control (and correspondingly lower costs). We therefore also evaluate all the units at a DSI SO

control level of 50%, which we believe is likely achievable for most units.

• We invite comments on whether particular units have performed DSI testing and have concluded they cannot achieve a SO

reduction between 50% and 80/90%. Any data to support such a conclusion should be submitted along with those comments.

Control Effectiveness of Wet FGD and SDA

We have assumed a wet FGD level of control to be a maximum of 98% not to go below 0.04 lbs/MMBtu, in which case, we assume the percentage of control equal to 0.04 lbs/MMBtu. As we discuss later in this proposal, we will conduct our wet FGD control cost analysis using the wet FGD cost algorithms, as employed in version 5.13 of our IPM model.

The IPM wet FGD Documentation states: “The least squares curve fit of the data was defined as a “typical” wet FGD retrofit for removal of 98% of the inlet sulfur. It should be noted that the lowest available SO

emission guarantees, from the original equipment manufacturers of wet FGD systems, are 0.04 lb/MMBtu.” As we established in our Oklahoma FIP,

this level of control is achievable with wet FGD. This level of control was also employed in our recent Texas-Oklahoma FIP.

We received a comment challenging this level of control and we responded to that comment in our final action on our Texas-Oklahoma FIP and incorporate that response in this proposed action.

We continue to conclude that our proposed level of control for wet FGD is reasonable.

IPM Model—Updates to Cost and Performance for APC Technologies, Dry Sorbent Injection for SO

Control Cost Development Methodology, Final March 2013, Project 12847-002, Systems Research and Applications Corporation, Prepared by Sargent & Lundy. Documentation for v.5.13: Chapter 5: Emission Control Technologies, Attachment 5-5: DSI Cost Methodology, downloaded

https://www.epa.gov/sites/production/files/2015-08/documents/attachment_5-5_dsi_cost_methodology.pdf.

IPM Model—Updates to Cost and Performance for APC Technologies, SDA FGD Cost Development Methodology, Final March 2013, Project 12847-002, Systems Research and Applications Corporation, Prepared by Sargent & Lundy. Documentation for v. 5.13: Chapter 5: Emission Control Technologies, Attachment 5-2: SDA FGD Cost Methodology, downloaded from

https://www.epa.gov/sites/production/files/2015-08/documents/attachment_5-2_sda_fgd_cost_methodology_3.pdf.

IPM Model—Updates to Cost and Performance for APC Technologies, wet FGD Cost Development Methodology, Final March 2013, Project 12847-002, Systems Research and Applications Corporation, Prepared by Sargent & Lundy. Documentation for v.5.13: Chapter 5: Emission Control Technologies, Attachment 5-1: Wet FGD Cost Methodology, downloaded from

https://www.epa.gov/sites/production/files/2015-08/documents/attachment_5-1_wet_fgd_cost_methodology.pdf.

As discussed previously in our TSD for that action, control efficiencies reasonably achievable by dry scrubbing and wet scrubbing were determined to be 95% and 98% respectively. 76 FR 81742);

Oklahoma

EPA

, 723 F.3d 1201 (July 19, 2013), cert. denied (U.S. May 27, 2014).

81 FR 321.

That information is included in our BART FIP TSD, Appendix A.

As with our Oklahoma FIP, we have assumed a SDA level of control equal to 95%, unless that level of control would fall below an outlet SO

level of 0.06 lb/MMBtu, in which case, we assume the percentage of control equal to 0.06 lbs/MMBtu. See our response to comments in our previous Oklahoma FIP.

In that FIP, we finalized the same emission limit of 0.06 lbs/MMBtu on a 30 BOD average for 6 coal-fired EGUs. We justified those limits based on the same SDA technology, using a combination of industry publications and real world monitoring data. Much of that information is summarized in our response to a comment to that action

and in our TSD. We continue to conclude that our proposed level of control for SDA is reasonable.

76 FR 81728.

Response to Technical Comments for Sections E through H of the

Federal Register

Notice for the Oklahoma Regional Haze and Visibility Transport Federal Implementation Plan, Docket No. EPA-R06-OAR-2010-0190, 12/13/2011. See comment and response beginning on page 91.

b. Evaluation of SO

Control Effectiveness for Gas Fired Units

The control effectiveness of switching from a higher sulfur fuel oil to a lower sulfur fuel oil lies in the reduction in sulfur emissions. The emissions reduction depends on the percentage reduction from the sulfur contents of the fuel oil that forms the SO

baseline to the replacement fuel oil. Ultimately, the highest level of control would result from a switch from the highest percentage sulfur the units are permitted to burn, 0.7% to the lowest DFO available, ultra-low sulfur diesel, which has a sulfur content of 0.0015%. This would equate to a control effectiveness of 99.8%. Lesser levels of controls are also possible. We will evaluate a range of control effectiveness in switching to lower sulfur fuel oils in the next section.

Because we are unaware of any scrubber installations on oil fired units in the U.S., we have no information on their control effectiveness. However, we see no technical reason why the control effectiveness of FGDs installed on gas-fired units that occasionally burn fuel oil should not be equal to that of FGDs installed on coal-fired units.

3. Step 4: Evaluate Impacts and Document the Results for SO

The BART Guidelines offers the following with regard to how Step 4 should be conducted:

70 FR 39166.

After you identify the available and technically feasible control technology options, you are expected to conduct the following analyses when you make a BART determination:

Impact analysis part 1: Costs of compliance,

Impact analysis part 2: Energy impacts, and

Impact analysis part 3: Non-air quality environmental impacts.

Impact analysis part 4: Remaining useful life.

We evaluate the cost of compliance on a unit-by unit basis, because control cost analysis depends on specific factors that can vary from unit to unit. However, we generally evaluate the energy impacts, non-air quality impacts, and the remaining useful life for all the units in question together because in this instance there are no appreciable differences in these factors from unit to unit.

To the extent these factors inform the cost of controls, consistent with the BART Guidelines, they do inform our considerations on a unit-by-unit basis.

In developing our cost estimates for the units in Table 7, we rely on the methods and principles contained within the EPA Air Pollution Control Cost Manual (the Control Cost Manual, or Manual).

We proceed in our SO

costing analyses by examining the current SO

emissions and the level of SO

control, if any, for each of the units listed in Table 7. For the coal units without any SO

control, we calculate the cost of installing DSI, a SDA scrubber, and a wet FGD scrubber. For the gas units that burn oil, we evaluate the cost of switching to lower sulfur fuel oils and installing scrubbers.

EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/452/B-02-001, January 2002 available at

http://www.epa.gov/ttncatc1/dir1/c_allchs.pdf.

In order to estimate the costs for DSI, SDA scrubbers, and wet FGD scrubbers, we programmed the DSI, SDA and wet FGD cost algorithms, as employed in version 5.13 of our IPM model, referenced above, into three spreadsheets. These cost algorithms calculate the Total Project Cost (TPC), Fixed Operating and Maintenance (Fixed O&M) costs, and Variable Operating and Maintenance (Variable O&M) costs. We then performed DSI, SDA and wet FGD cost calculations for each unit listed in Table 7 that did not already have SO

control.

These cost models were based on costs escalated to 2012 dollars.

Because the IPM 5-13 cost algorithms were calculated in 2012 dollars, we have escalated them to 2016, using the annual Chemical Engineering Plant Cost Indices (CEPCI).

These spreadsheets are entitled, “DSI Cost IPM 5-13 TX BART.xlsx,” “SDA Cost IPM 5-13 TX BART.xlsx,” and “Wet FGD Cost IPM 5-13 TX BART.xlsx,” and are located in our Docket.

Ibid., p.1: “The data was converted to 2012 dollars based on the Chemical Engineering Plant Index (CEPI) data.”

a. Impact Analysis Part 1: Cost of Compliance for DSI, SDA, and Wet FGD

As we discuss above and in our Cost TSD, we evaluated each unit at its maximum recommended level of control, considering the type of SO

control device. Below, we present a summary of our DSI, SDA, and wet FGD cost analysis:

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.

Table 10—Summary of DSI, SDA, and Wet FGD Cost Analysis

Facility

Unit

Control

Control level

(%)

reduction

(tpy)

2016 Annualized

cost

2016 Cost

effectiveness

($/ton)

2016

Incremental

cost-

effectiveness

($/ton)

Big Brown

DSI

14,448

$29,468,587

$2,040

DSI

26,006

72,131,749

2,774

$3,691

SDA

27,453

35,297,532

1,286

−25,456

Wet FGD

28,320

33,673,102

1,189

−1,874

DSI

15,320

29,342,350

1,915

DSI

27,576

71,322,593

2,586

3,425

SDA

29,108

35,359,239

1,215

−23,475

Wet FGD

97.9

29,998

33,817,952

1,127

−1,732

Monticello

DSI

4,787

11,408,872

2,383

DSI

8,617

25,409,128

2,949

3,655

SDA

9,095

24,294,319

2,671

−2,332

Wet FGD

9,286

25,236,699

2,718

4,934

DSI

4,129

9,742,648

2,360

DSI

7,431

21,418,734

2,882

3,536

SDA

7,844

23,126,113

2,948

4,134

Wet FGD

96.8

7,995

24,233,133

3,031

7,331

Coleto Creek

DSI

7,376

16,246,169

2,203

DSI

13,277

34,841,379

2,624

3,151

SDA

92.4

13,632

29,445,018

2,160

−15,201

Wet FGD

94.9

14,005

29,786,106

2,127

914

Harrington

061B

DSI

2,477

9,187,608

3,710

DSI

3,962

16,073,779

4,057

4,637

SDA

90.2

4,466

17,455,679

3,909

2,742

062B

DSI

2,455

6,524,937

2,658

DSI

* 88.9

4,364

11,981,111

2,746

2,858

SDA

88.9

4,364

18,240,127

4,180

N/A

J T Deely

DSI

3,072

8,854,319

2,883

DSI

5,529

18,071,878

3,269

3,752

SDA

91.3

5,609

21,689,526

3,867

45,221

Wet FGD

94.2

5,787

22,555,395

3,898

4,864

DSI

3,222

9,865,798

3,062

DSI

5,800

20,229,233

3,488

4,020

SDA

91.3

5,884

21,812,518

3,707

18,849

Wet FGD

94.2

6,070

22,530,901

3,712

3,862

Welsh

DSI

3,343

8,963,761

3,469

DSI

* 87.2

5,832

23,090,408

3,960

5,676

SDA

87.2

5,832

22,697,048

3,892

N/A

Wet FGD

91.5

6,116

23,998,161

3,924

4,581

W.A. Parish

DSI

6,712

15,002,337

2,235

DSI

12,081

30,865,711

2,555

2,955

SDA

92.1

12,364

31,195,787

2,523

1,166

Wet FGD

94.7

12,717

30,735,030

2,417

−1,305

DSI

7,525

16,014,988

2,128

DSI

13,545

33,302,528

2,459

2,872

SDA

92.1

13,862

32,758,784

2,363

−1,715

Wet FGD

94.7

14,258

32,215,226

2,259

−1,373

* DSI control level limited to that of SDA.

b. Impact Analysis Part 1: Cost of Compliance for Scrubber Upgrades

In our BART FIP TSD, we analyze those units listed in Table 7 with an existing SO

scrubber in order to determine if cost-effective scrubber upgrades are available. Of our subject-to-BART units, Martin Lake Units 1, 2, 3; Monticello Unit 3, and Fayette Units 1 and 2 are currently equipped with wet FGDs. Of these, all but the Fayette units were analyzed for scrubber upgrades in our Texas-Oklahoma FIP. For all but the Fayette units, we propose to adopt the total annualized cost calculations used to make the cost-effectiveness calculations in our Texas-Oklahoma FIP in this action. We acknowledge that these costs could change slightly, due to changes in the costs of various materials and services. However, these costs were calculated in 2013 dollars. Escalating them to 2015 dollars would result in a reduction in cost, which we conservatively do not take into consideration.

The CEPCI for 2013 is 567.3 and that for 2015 is 556.3. Therefore, the costs would be multiplied by a factor of 556.8/567.3, which is approximately 0.98.

In our Texas-Oklahoma FIP action, after responding to comments we revised our proposed cost-effectiveness basis from where all scrubber upgrades were less than $600/ton, to where all scrubber upgrades ranged from between $368/ton to $910/ton.

As with our Texas-Oklahoma FIP, we are limited in what information we can include in this section, because we used information that was claimed as CBI. This information was submitted in response to our Section 114(a) requests. The following summary is based on information not claimed as CBI.

81 FR 318.

• The absorber system had either already been upgraded to perform at an SO

removal efficiency of at least 95%, or it could be upgraded to perform at that level using proven equipment and techniques.

• The SO

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 SO

emission reductions resulting from the scrubber upgrade are substantial, ranging from 68% to 89% reduction from the current emission levels, and are cost-effective.

We now update these calculations for 2011-2015 data.

The revised scrubber upgrade results for Martin Lake Units 1, 2, and 3; and Monticello Unit 3 are presented below in Table 11:

See Coal vs CEM data 2011-2015.xlsx.

Table 11—Summary of Updated Scrubber Upgrade Results

Unit

2011-2015

3-yr avg. SO

emissions

(eliminate max and min)

(tons)

emissions

at 95% control

(tons)

emissions

reduction due to scrubber

upgrade

(tons)

emission

rate at 95%

control

(lbs/MMBtu)

Monticello 3

8,136

1,180

6,956

0.05

Martin Lake 1

19,040

3,208

15,832

0.12

Martin Lake 2

17,973

3,393

14,580

0.12

Martin Lake 3

16,113

2,591

13,522

0.11

Total SO

Removed

50,890

As we note above, we updated 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 $1,156/ton or less. We invite the facilities listed above to make arrangements with us to view our complete updated cost analysis for their units.

The Fayette Units 1 and 2 are currently equipped with high performing wet FGDs. Both units have demonstrated the ability to maintain a SO

30 BOD average below 0.04 lbs/MMBtu for years at a time.

As we discuss above, we evaluate BART demonstrating that retrofit wet FGDs should be evaluated at 98% control not to go below 0.04 lbs/MMBtu. Because the Fayette units are performing below this level, we propose that no scrubber upgrades are necessary. We propose to find that the Fayette Units 1 and 2 maintain a 30 Boiler Operating Day rolling average SO

emission rate of 0.04 lbs/MMBtu based on the actual emissions data we present above. We believe that based on its demonstrated ability to maintain an emission rate below this value on a 30 BOD basis, it can consistently achieve this emission level.

See our BART FIP TSD for graphs of this data.

c. Impact Analysis Part 1: Cost of Compliance for Gas Units That Burn Oil

As we noted in Section III.C.1.b, a number of the units we proposed in Table 9 as being subject to BART primarily fire gas, but have occasionally fired fuel oil in the past as reported by the EIA. These units are limited by their permits to burning oil with a sulfur content of no more than 0.7% sulfur by weight. We proposed to consider both a reduction in fuel oil sulfur and SO

scrubbers as potential BART controls. Below we consider the cost of these potential controls.

Reduction in Fuel Oil Sulfur

In order to determine the cost of these facilities switching to lower sulfur content fuel oils, we sent the Graham, Newman, Stryker Creek, and the Wilkes facilities Section 114 letters requesting certain information.

We received very limited information in response to one of our questions concerning the present cost of the historic fuel oil burned, and the cost of various lower sulfur replacement fuel oils. Because of this, we were unable to compile facility-specific information on the cost of switching to lower sulfur fuel oils. Consequently, we considered the best available information by consulting more general information from the EIA, which reports the prices for various refinery petroleum products on a monthly and annual basis. Below is a summary of various distillate and residual fuel oil products for 2001 to 2015, averaged across the U.S.

Copies of these letters and the facilities' responses are in our docket. We inadvertently did not send the O W Sommers a letter.

EIA Refiner Petroleum Product Prices by Sales Type, available here:

http://www.eia.gov/dnav/pet/pet_pri_refoth_dcu_nus_a.htm; http://www.eia.gov/dnav/pet/pet_pri_spt_s1_a.htm.

Table 12—Selected EIA Reported Annual Refiner Petroleum Prices

Date

West Texas

intermediate

crude oil—Cushing

Oklahoma ($/bbl)

U.S. no. 2 diesel wholesale/resale

price by refiners

($/gallon)

U.S. no. 2 fuel oil

wholesale/resale

price by refiners

($/gallon)

U.S. no. 4 distillate

wholesale/resale

price by refiners

($/gallon)

2015

48.66

1.667

1.565

1.215

2014

93.17

2.812

2.741

2.333

2013

97.98

3.028

2.966

2.767

2012

94.05

3.109

3.031

2011

94.88

3.034

2.907

2.801

2010

79.48

2.214

2.147

2009

61.95

1.713

1.657

1.561

2008

99.67

2.994

2.745

2.157

2007

72.34

2.203

2.072

1.551

2006

66.05

2.012

1.834

1.395

2005

56.64

1.737

1.623

1.377

2004

41.51

1.187

1.125

1.033

2003

31.08

0.883

0.881

0.793

2002

26.18

0.724

0.694

0.663

2001

25.98

0.784

0.756

0.697

2000

30.38

0.898

0.886

0.778

Lacking facility-specific pricing information, for the purposes of calculating the cost of compliance, we make the following assumptions:

• No. 4 distillate is the type of fuel oil currently available that most closely approximates the types of fuel oil that were historically burned by the facilities. It is available in a range of sulfur up to the facilities' permitted maximum of 0.7% sulfur by weight or 7,000 ppm. We will use the cost of this fuel oil in constructing “business as usual” scenarios of the annual cost of fuel oil.

• No. 2 fuel oil is available at approximately 3,000 ppm, which roughly corresponds to the sulfur level present in No. 2 fuel oil prior to our implementation of the Ultra-Low-Sulfur Diesel (ULSD) regulations.

We will use the cost of this fuel oil in constructing a “medium control” annual cost of fuel oil.

69 FR 39073: “Both high sulfur No. 2-D and No. 2 fuel oil must contain no more than 5000 ppm sulfur,131 and currently [as of the date of our final rule, 6/29/04] averages 3000 ppm nationwide.”

• No. 2 diesel fuel corresponds to ULSD, with a sulfur content of 15 ppm. We will use the cost of this fuel oil in constructing a “high control” annual cost of fuel oil.

Having identified a reasonable set of historical and lower sulfur fuel oils, we turned to the matter of establishing SO

baselines. We would expect that regardless of the baseline selected, a cost-effectiveness calculation that simply depended on differing fuel oil costs and the resulting reductions in SO

, would result in the same value. In other words, the cost-effectiveness in $/ton is independent of the SO

baseline, since

in this case,

it is calculated on a unit basis—the increased cost in burning a unit of fuel divided by the increased reduction in the resulting

. While the above is true, reported data for these units does not match this expectation. This can be illustrated by examining selected EIA and emissions data for the Graham Unit 2:

Table 13—Graham Unit 2 Example Discordance in Fuel Oil Burned and Reported SO

Date

(month/year)

Quantity fuel oil burned

(bbls)

Reported SO

for month

(tons)

Reported EIA sulfur content

(wt %)

Mar-02

9,800

21.614

0.65

Feb-03

8,400

90.389

0.66

Jun-12

18,177

0.064

0.50

Jul-12

5,657

0.07

0.50

As can be seen from the above table, even though the reported sulfur content of the fuel oil in March 2002 and February 2003 was approximately the same, and the quantity burned was fairly close, the reported SO

emissions were significantly different. Similarly, although the amount of fuel oil burned in June 2012 was more than three times that burned in July 2012 (at the same sulfur content), the reported SO

emissions in June 2012 were less than that in July 2012. Also, although the fuel oil sulfur content in the 2012 examples was only slightly less than that in the 2002/2003 examples, and the amount of fuel oil burned was the same order of magnitude, the resulting reported SO

emissions in 2012 were three orders of magnitude less than that in 2002/2003. We conclude that either the values for the EIA fuel quantities, the EIA fuel oil sulfur contents, and/or the reported SO

emissions are in error. Further examination of the CAMD emissions data for Graham and Stryker revealed that the data contained a large amount of substitute data for SO

emissions and heat input during periods when the units burned fuel oil.

As a consequence of this discordance between the type and amount of fuel oil burned and the reported SO

emissions, we cannot rely on historical SO

emissions to construct a baseline, because a barrel of fuel oil with a given sulfur content does not result in a consistent reported SO

value over time. Instead, we will conduct our cost-effectiveness analysis on the basis of unit values of 1,000 barrels, using the following assumptions:

• Fuel oil costs will be based on the 2015 U.S. average prices as reported in Table 12 for No. 4 distillate at 0.7 wt. % (the permitted maximum for all units) as the current business as usual fuel, No. 2 fuel oil at 0.3 wt. % as the moderate control option, and No. 2 diesel at 0.0015% as the high control option.

• The emission factor for calculating the tons of sulfur emitted by the three fuel oils are taken from AP 42,

Compilation of Air Pollutant Emissions Factors.

The emission factor (lb/10

gal) used is 150 × S, where S = weight % sulfur, taken from AP 42, Fifth Edition, Volume 1, Chapter 1: External Sources, Section 1.3, Fuel Oil Combustion, available here:

https://www3.epa.gov/ttn/chief/ap42/ch01/index.html.

Boilers >100 Million Btu/hr, No. 4 oil fired.

Below is the result of that calculation:

Table 14—Cost Effectiveness of Switching to Lower Sulfur Fuel Oils

Level of control

Cost for 1,000 barrels

baseline

($/yr)

Tons reduced for 1,000

barrels

Cost

effectiveness for 1,000

barrels

($/ton)

Incremental

cost-

effectiveness

($/ton)

Business as usual (No. 4 distillate $1.215/gal)

$51,030

N/A

Moderate control (No. 2 fuel oil $1.565/gal)

65,730

1.26

11,218

High control (ULSD $1.667/gal)

70,014

2.20

8,627

−2,756

We suspect our price information for ULSD may be high, as the Wilkes facility indicated in its reply to our Section 114 request that its 8/12/16 contract for oil was for ULSD, which had an index price of $1.423/gallon. Assuming this price and retaining the same price for our business as usual No. 4 distillate fuel oil of $1.215/gallon, results in a cost-effectiveness of $3,970/ton—a significant improvement in cost-effectiveness. We invite the affected facilities to provide site-specific information for delivery of ULSD.

Scrubber Retrofits

Elsewhere in our proposal, we conclude that certain types of wet scrubbers were technically feasible as potential control options for gas boilers that occasionally burn oil, similar to the ones under BART review here. Were we to calculate the cost-effectiveness of a wet FGD, similar to those under consideration for the coal units undergoing BART review, we could expect that the capital and operating costs would be on the same order, as displayed in Table 10. It is a straightforward exercise to demonstrate that the installation of such a scrubber on any of the gas-fired units that occasionally burn oil would result in a very high cost-effectiveness value.

For instance, taking the smallest total annualized wet FGD cost in Table 10, corresponding to the Harrington Unit 0161B (approximately the same size as the Graham Unit 2), results in a value of $19,145,500. Assuming a 98% reduction from a baseline equal to the largest annual SO

emissions from any of the gas units, 1,287 tons/year (Graham Unit 2, 2001), results in a SO

reduction of 1,261 tons/year. The cost-effectiveness is then $15,183/ton, which is very high for a SO

scrubber. In addition, the annual SO

values for Graham Unit 2 from 2002 to 2015, and the annual SO

values for the remaining units, have always been an order of magnitude less than the 2001 Graham Unit 2 value. Although we have not modeled the visibility benefit of

installing SO

scrubbers on these units, the visibility benefit from scrubbers is estimated to be slightly less than the amount of benefit estimated from switching to ULSD.

For example, switching from 0.7% sulfur fuel oil to ULSD at 0.0015% sulfur results in a reduction in sulfur emissions of 99.8% compared to an estimated 98% reduction due to the use of a scrubber.

4. Impact Analysis Parts 2, 3, and 4: Energy and Non-air Quality Environmental Impacts, and Remaining Useful Life

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.”

As discussed above in our cost analyses for DSI, SDA, and wet FGD, 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.

70 FR 39103, 39168 (July 6, 2005), [40 CFR part 51, App. Y.].

Regarding the analysis of non-air quality environmental impacts, the BART Guidelines advise:

70 FR at 39169 (July 6, 2005), [40 CFR part 51, App. Y.].

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 emissions 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 SO

control technologies we considered in our analysis—DSI and scrubbers—are in wide use in the coal-fired 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 SO

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. We are aware that the Harrington facility has instituted a water recycling program and obtains some of its water from the City of Amarillo.

Due to potential non-air quality concerns, we limit our SO

control analysis for Harrington to DSI and dry scrubbers.

http://www.powermag.com/xcel-energys-harrington-generating-station-earns-powder-river-basin-coal-users-group-award/.

Regarding the remaining useful life, the BART Guidelines advise:

100

70 FR 39103, 39169, [40 CFR part 51, App. Y.].

You may decide to treat the requirement to consider the source's “remaining useful life” of the source for BART determinations as one element of the overall cost analysis. 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 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.

We are unaware that any of the facilities we have analyzed for BART have entered into an enforceable document to shut down the applicable units earlier than what would occur under our assumed 30-year operational life.

101

As we stated in our Oklahoma FIP,

102

we noted that scrubber vendors indicate that the lifetime of a scrubber is equal to the lifetime of the boiler, which might easily be well over 60 years. We identified specific scrubbers installed between 1975 and 1985 that were still in operation. Because a DSI system is relatively simple and reliable, we have no reason to conclude that its service life would be any less than what we typically use for scrubber cost analyses. Because none of the facilities involved have entered into enforceable documents to shut down the applicable units earlier, we will continue to use a 30-year equipment life for DSI, scrubber retrofits, and scrubber upgrades, as we believe that is proper.

101

We received a November 21, 2016 letter from the source owner regarding Parish Units 5 & 6. The letter, now added to the docket, explains the units have natural gas firing capabilities and expresses interest in obtaining flexibility to avoid BART or obtaining multiple options for complying with BART. While we acknowledge this interest, the letter does not provide or commit to any specifics in furtherance of the BART analysis that EPA is now required to conduct under the BART Guidelines.

102

Response to Technical Comments for Sections E. through H. of the

Federal Register

Notice for the Oklahoma Regional Haze and Visibility Transport Federal Implementation Plan, Docket No. EPA-R06-OAR-2010-0190, 12/13/2011. See discussion beginning on page 36.

5. Step 5: Evaluate Visibility Impacts

Please see the BART Modeling TSD, where we describe in detail the various modeling runs we conducted, our methodology and selection of emission rates, modeling results, and final modeling analysis that we used to evaluate the benefits of the proposed controls and their associated emission decreases on visibility impairment values. Below we present a summary of our analysis and our proposed findings regarding the estimated visibility benefits of emission reductions based on the CALPUFF and/or CAMx modeling results.

a. Visibility Benefits of DSI, SDA, and Wet FGD for Coal-Fired Units

We evaluated the visibility benefits of DSI, for the twelve units depicted in Tables 15 and 16 below that currently have no SO

control. We evaluated all the units using the control levels we employed in our control cost analyses. In summary, we evaluated these units at a DSI SO

control level of 50%, which we believe is likely achievable for any unit. At the lower performance level we assumed, we conclude that the corresponding visibility benefits from DSI in most cases would be close to half of the benefits from scrubbers resulting in the visibility benefits from scrubber retrofits being much more beneficial. 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. For those sources that are within 300 to 400 km of a Class

I area, we utilized CALPUFF and CAMx modeling to assess the visibility benefit of potential controls. For the remaining coal-fired sources (J T Deely, Coleto Creek, Fayette and W A Parish), only CAMx modeling was utilized as these sources are located at much greater distances to the nearest Class I areas. In evaluating the impacts and benefits of potential controls, we utilized a number of metrics, including change in deciviews and number of days impacted over 0.5 dv and 1.0 dv. Consistent with the BART Guidelines, the visibility impacts and benefits modeled in CALPUFF and CAMx are calculated as the change in deciviews compared against natural visibility conditions.

103

We note that the high control scenario modeling for Fayette units 1 and 2 demonstrate the benefit from existing high performing controls. As discussed elsewhere, we found that for these units no additional controls or upgrades were necessary. For a full discussion of our review of all the modeling results, and factors that we considered in evaluating and weighing all the results, see our BART Modeling TSD. Below, we present a summary of some of those visibility benefits at the Class I areas most impacted by each source:

103

40 CFR 51 Appendix Y, IV.D.5: “Calculate the model results for each receptor as the change in deciviews compared against natural visibility conditions.”

Table 15—Visibility Benefit of Retrofit Controls: Coal-Fired Units (CAMx Modeling)

Facility name

Emission unit

Class I area

Metric

Visibility impact

Baseline

DSI

(50%)

WFGD

(98%)

Visibility benefit

DSI

benefit

WFGD

benefit

Big Brown

Source (Unit 1 and 2)

WIMO

Max dv

4.017

2.249

0.474

1.768

3.542

Days >0.5 dv

Days >1.0 dv

CACR

Max dv

3.775

2.539

0.787

1.236

2.988

Days >0.5 dv

Days >1.0 dv

Unit 1

WIMO

Max dv

2.154

1.168

0.245

0.986

1.909

Days >0.5 dv

Days >1.0 dv

CACR

Max dv

2.016

1.327

0.409

0.688

1.606

Days >0.5 dv

Days >1.0 dv

Unit 2

WIMO

Max dv

2.175

1.181

0.235

0.994

1.940

Days >0.5 dv

Days >1.0 dv

CACR

Max dv

2.033

1.338

0.391

0.695

1.642

Days >0.5 dv

Days >1.0 dv

Monticello

Source (Unit 1, 2 and 3)

CACR

Max dv

10.498

6.121

2.079

4.377

8.419

Days >0.5 dv

152

107

124

Days >1.0 dv

111

103

WIMO

Max dv

5.736

2.769

0.774

2.968

4.962

Days >0.5 dv

Days >1.0 dv

Unit 1

CACR

Max dv

4.516

3.123

0.733

1.393

3.783

Days >0.5 dv

Days >1.0 dv

WIMO

Max dv

2.241

1.290

0.252

0.951

1.989

Days >0.5 dv

Days >1.0 dv

Unit 2

CACR

Max dv

4.487

3.065

0.563

1.422

3.924

Days >0.5 dv

Days >1.0 dv

WIMO

Max dv

2.189

1.252

0.186

0.937

2.003

Days >0.5 dv

Days >1.0 dv

Coleto Creek

Source (Unit 1)

WIMO

Max dv

0.845

0.526

0.176

0.318

0.668

Days >0.5 dv

Days >1.0 dv

CACR

Max dv

0.791

0.458

0.186

0.333

0.606

Days >0.5 dv

Days >1.0 dv

Harrington

Source (Unit 061B & 062B)

SACR

Max dv

5.288

4.287

3.235

1.001

2.053

Days >0.5 dv

Days >1.0 dv

WIMO

Max dv

4.928

4.362

3.798

0.565

1.130

Days >0.5 dv

Days >1.0 dv

Unit 061B

SACR

Max dv

2.908

2.322

1.738

0.586

1.170

Days >0.5 dv

Days >1.0 dv

WIMO

Max dv

2.708

2.382

2.065

0.326

0.643

Days >0.5 dv

Days >1.0 dv

Unit 062B

SACR

Max dv

2.998

2.373

1.719

0.625

1.279

Days >0.5 dv

Days >1.0 dv

WIMO

Max dv

2.770

2.407

2.046

0.363

0.723

Days >0.5 dv

Days >1.0 dv

J T Deely

Source (Sommers 1&2, J T Deely 1&2)

WIMO

Max dv

1.513

0.939

0.814

0.574

0.699

Days >0.5 dv

Days >1.0 dv

CACR

Max dv

1.423

1.155

0.905

0.268

0.518

Days >0.5 dv

Days >1.0 dv

J T Deely 1

WIMO

Max dv

0.757

0.449

0.270

0.307

0.487

Days >0.5 dv

Days >1.0 dv

BIBE

Max dv

0.652

0.373

0.069

0.279

0.583

Days >0.5 dv

Days >1.0 dv

J T Deely 2

WIMO

Max dv

0.632

0.387

0.334

0.245

0.298

Days >0.5 dv

Days >1.0 dv

CACR

Max dv

0.604

0.490

0.387

0.114

0.217

Days >0.5 dv

Days >1.0 dv

W.A. Parish

Source (WAP 4, 5, & 6)

CACR

Max dv

3.177

2.032

0.511

1.145

2.665

Days >0.5 dv

Days >1.0 dv

UPBU

Max dv

1.994

1.215

0.234

0.779

1.760

Days >0.5 dv

Days >1.0 dv

WAP 5

CACR

Max dv

1.698

1.052

0.180

0.646

1.518

Days >0.5 dv

Days >1.0 dv

UPBU

Max dv

1.038

0.613

0.094

0.424

0.943

Days >0.5 dv

Days >1.0 dv

WAP 6

CACR

Max dv

1.648

1.018

0.156

0.630

1.492

Days >0.5 dv

Days >1.0 dv

UPBU

Max dv

1.003

0.591

0.081

0.412

0.922

Days >0.5 dv

Days >1.0 dv

Welsh

Source (Unit 1 & 2)

CACR

Max dv

4.576

0.822

3.754

Days >0.5 dv

Days >1.0 dv

MING

Max dv

2.544

0.570

1.973

Days >0.5 dv

Days >1.0 dv

Unit 1

CACR

Max dv

2.343

1.659

0.822

0.684

1.521

Days >0.5 dv

Days >1.0 dv

MING

Max dv

1.150

0.886

0.570

0.264

0.579

Days >0.5 dv

Days >1.0 dv

Fayette

Source (Unit 1 & 2)

CACR

Max dv

1.894

0.903

0.991

Days >0.5 dv

Days >1.0 dv

WIMO

Max dv

1.175

0.580

0.595

Days >0.5 dv

Days >1.0 dv

Unit 1

CACR

Max dv

1.002

0.480

0.522

Days >0.5 dv

Days >1.0 dv

WIMO

Max dv

0.609

0.306

0.302

Days >0.5 dv

Days >1.0 dv

Unit 2

CACR

Max dv

0.974

0.441

0.534

Days >0.5 dv

Days >1.0 dv

WIMO

Max dv

0.598

0.282

0.316

Days >0.5 dv

Days >1.0 dv

Harrington high control scenario for both units is SDA at 95% reduction.

Welsh Unit 2 and Fayette Units 1 & 2 were not modeled at DSI level control. Welsh Unit 2 has shut down and Fayette units have WFGD (wet FGD) installed. Welsh source-wide modeling for high control includes a unit 2 shutdown.

Table 16—Visibility Benefit of Retrofit Controls: Coal-Fired Units (CALPUFF Modeling)

Facility name

Emission unit

Class I area

Metric

Visibility impact

Baseline

DSI

(50%)

WFGD

(98%)

Visibility benefit

DSI

benefit

WFGD

benefit

Big Brown

Source (Units 1 and 2)

WIMO

Max dv

4.27

2.54

0.43

1.73

3.83

Days >0.5 dv Avg.

67.33

43.33

2.67

24.00

64.67

Days >1.0 dv Avg.

42.00

21.00

1.00

41.00

CACR

Max dv

4.03

2.41

0.47

1.62

3.55

Days >0.5 dv Avg.

91.67

64.33

4.67

27.33

87.00

Days >1.0 dv Avg.

60.33

30.00

0.00

30.33

60.33

Monticello

Source (Unit 1, 2 and 3)

CACR

Max dv

6.57

3.68

1.70

2.89

4.87

Days >0.5 dv Avg.

143.67

115.00

62.33

28.67

81.33

Days >1.0 dv Avg.

113.00

66.33

23.67

46.67

89.33

UPBU

Max dv

3.45

1.77

0.77

1.68

2.68

Days >0.5 dv Avg.

103.00

61.00

13.67

42.00

89.33

Days >1.0 dv Avg.

39.33

16.67

2.67

22.67

36.67

WIMO

Max dv

3.23

1.60

0.54

1.63

2.70

Days >0.5 dv Avg.

60.00

34.67

6.00

25.33

54.00

Days >1.0 dv Avg.

39.33

16.67

0.67

22.67

38.67

Harrington

Source (Units 061B & 062B)

SACR

Max dv

1.06

0.86

0.61

0.20

0.45

Days >0.5 dv Avg.

21.00

15.33

6.33

5.67

14.67

Days >1.0 dv Avg.

6.67

3.00

0.67

3.67

6.00

WIMO

Max dv

1.29

0.97

0.55

0.32

0.74

Days >0.5 dv Avg.

26.00

15.33

8.67

10.67

17.33

Days >1.0 dv Avg.

9.00

4.67

1.33

4.33

7.67

Welsh

Source (Unit 1)

CACR

Max dv

1.44

1.12

0.72

0.32

0.72

Days >0.5 dv Avg.

50.33

32.67

12.33

17.67

Days >1.0 dv Avg.

15.33

8.00

2.33

7.33

13.00

UPBU

Max dv

0.76

0.49

0.22

0.27

0.54

Days >0.5 dv Avg.

12.00

4.67

0.33

7.33

11.67

Days >1.0 dv Avg.

0.67

0.00

0.67

WIMO

Max dv

0.56

0.33

0.15

0.23

0.41

Days >0.5 dv Avg.

7.33

2.67

0.33

4.67

7.00

Days >1.0 dv Avg.

1.33

0.33

0.00

1.00

1.33

Monticello's controlled level is a combination of scrubber upgrades and scrubber install in the facility impact modeling with CALPUFF.

Harrington high control scenario for both units is SDA at 95% reduction.

Welsh Unit 2 and Fayette Units 1 & 2 were not modeled at DSI level control. Welsh Unit 2 has shut down and Fayette units have WFGD installed. Welsh source-wide modeling for high control includes a unit 2 shutdown.

UPBU = Upper Buffalo Wilderness Area.

b. Visibility Benefits of Scrubber Upgrades for Coal-Fired Units

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. We also modeled a lower level control at 90%. The visibility benefits from these scrubber upgrades are quantified specifically in our BART Modeling TSD. Below, we present a summary of the del-dv visibility benefits and reduction in number of days impacted.

Table 17—Visibility Benefit of Scrubber Upgrades: Coal-Fired Units (CAMx Modeling)

Facility name

Emission unit

Class I area

Metric

Visibility impact

Baseline

(90%)

control

(95%)

control

Visibility benefit

(90%)

benefit

(95%)

benefit

Martin Lake

Source (Unit 1, 2 & 3)

CACR

Max dv

6.651

4.491

4.321

2.159

2.329

Days >0.5 dv

141

Days >1.0 dv

UPBU

Max dv

5.803

2.669

2.528

3.134

3.275

Days >0.5 dv

Days >1.0 dv

Unit 1

CACR

Max dv

2.633

1.550

1.468

1.083

1.165

Days >0.5 dv

Days >1.0 dv

UPBU

Max dv

2.254

0.867

0.805

1.387

1.449

Days >0.5 dv

Days >1.0 dv

Unit 2

CACR

Max dv

2.466

1.882

1.811

0.585

0.655

Days >0.5 dv

Days >1.0 dv

UPBU

Max dv

2.189

1.077

1.025

1.112

1.164

Days >0.5 dv

Days >1.0 dv

Unit 3

CACR

Max dv

2.755

1.682

1.609

1.074

1.146

Days >0.5 dv

Days >1.0 dv

UPBU

Max dv

2.368

0.942

0.890

1.425

1.478

Days >0.5 dv

Days >1.0 dv

Monticello

Source (Unit 1, 2 and 3)

CACR

Max dv

10.498

6.121

2.079

4.377

8.419

Days >0.5 dv

152

107

124

Days >1.0 dv

111

103

WIMO

Max dv

5.736

2.769

0.774

2.968

4.962

Days >0.5 dv

Days >1.0 dv

Unit 3

CACR

Max dv

4.632

0.905

0.914

3.728

3.719

Days >0.5 dv

Days >1.0 dv

WIMO

Max dv

2.282

0.462

0.364

1.820

1.918

Days >0.5 dv

Days >1.0 dv

Table 18—Visibility Benefit of Scrubber Upgrades: Coal-Fired Units (CALPUFF Modeling)

Facility name

Emission unit

Class I area

Metric

Visibility impact

Baseline

DSI

(50%)

WFGD

(98%)

Visibility benefit

DSI

benefit

WFGD

benefit

Martin Lake

Source (Units 1, 2 & 3)

CACR

Max dv

4.46

2.27

1.86

2.18

2.60

Days >0.5 dv Avg.

129.67

77.33

63.00

52.33

66.67

Days >1.0 dv Avg.

91.33

32.67

22.33

58.67

69.00

UPBU

Max dv

2.73

1.10

0.85

1.63

1.88

Days >0.5 dv Avg.

81.67

30.33

18.67

51.33

63.00

Days >1.0 dv Avg.

46.67

7.33

3.67

39.33

43.00

Monticello

Source (Unit 1, 2 and 3)

CACR

Max dv

6.57

3.68

1.70

2.89

4.87

Days >0.5 dv Avg.

143.67

115

62.33

28.67

81.33

Days >1.0 dv Avg.

113

66.33

23.67

46.67

89.33

UPBU

Max dv

3.45

1.77

0.765

1.68

2.68

Days >0.5 dv Avg.

103

13.67

89.33

Days >1.0 dv Avg.

39.33

16.67

2.67

22.67

36.67

WIMO

Max dv

3.23

1.60

0.54

1.63

2.70

Days >0.5 dv Avg.

34.67

25.33

Days >1.0 dv Avg.

39.33

16.67

0.67

22.67

38.67

Monticello's controlled level is a combination of scrubber upgrade on Unit 3 and scrubber retrofits on Units 1 and 2 in the facility impact modeling with CALPUFF.

c. Visibility Benefits of Fuel Oil Switching for Gas/Fuel Oil-Fired Units

We also modeled the visibility benefits of those gas/fuel oil-fired units for which we conducted control cost analysis for switching to lower sulfur fuels. We evaluated the visibility benefits of switching to fuel oils corresponding to ultra-low sulfur diesel at 0.0015% sulfur by weight and 0.3% sulfur by weight as we evaluated in our control cost analyses. The visibility benefits from these fuel switches are quantified specifically in our BART Modeling TSD. Below, we present a summary of the del-dv visibility benefits.

Table 19—Visibility Benefits From Lower Sulfur Fuel

Facility name

Emission unit

Baseline visibility impact from source

(most impacted Class I area)

Visibility benefit of 0.3% S fuel oil

Visibility benefit of 0.0015% S fuel oil

Stryker

ST2

CALPUFF 0.65% S: 0.786 dv @ CACR (Facility)

CALPUFF (0.3% S): 0.263 dv @ CACR (Facility)

CALPUFF: 0.522 dv @ CACR (Facility)

Graham

Unit 2

CALPUFF 0.69% S: 1.228 dv @ WIMO (Facility)

CALPUFF (0.3% S): 0.465 dv @ WIMO (Facility

CALPUFF: 0.851 dv @ WIMO (Facility)

Wilkes

Units 1, 2, 3

CALPUFF 0.43% S: 0.698 dv @ CACR (Facility)

CALPUFF (0.1% S): 0.029 dv @ CACR (Facility)

CALPUFF: 0.037 dv @ CACR (Facility)

Newman

Unit 2

N/A

Unit 3

N/A

Unit 4

N/A

Calaveras

Sommers

Unit 1

CAMx: 1.513 dv @ WIMO (Source); 0.106 dv @ CACR (Unit)

0.004 dv @ CACR

0.008 dv @ CACR

Sommers

Unit 2

CAMx: 1.513 dv @ WIMO (Source); 0.180 dv @ CACR (Unit)

0.023 @ CACR

0.047 @ CACR

Newman is on the edge of the CALMET and CALPUFF modeling grids for the database that were used in this action. Since the facility was near the edge, emissions of the facility's impacts could not be adequately modeled since some of the plumes could have gone out of the grid and not be adequately assessed if they come back into the grid and transport to impact a Class I area.

6. BART Analysis for PM

In our recent Texas-Oklahoma FIP, we initially proposed to approve Texas' determination that no PM BART controls were appropriate for its EGUs, based on a screening analysis of the visibility impacts from just PM emissions and the premise that EGU SO

and NO

were covered separately by participation in CSAPR (allowing consideration of PM emissions in isolation). Because of the CSAPR remand and resulting uncertainty regarding SO

and NO

BART for EGUs, we decided not to finalize our proposed approval of Texas' PM BART determination.

104

For reasons earlier stated we are proposing to disapprove the SIP determination regarding PM BART for EGUs. Following from that proposed disapproval, we are proposing a PM BART FIP for those Texas EGUs that are subject to BART.

104

81 FR 302 (January 5, 2016).

The BART Guidelines permit us to conduct a streamlined analysis of PM BART in two key ways. First, the Guidelines allow a streamlined analysis for PM sources subject to MACT standards. Unless there are new technologies subsequent to the MACT standards which would lead to cost-effective increases in the level of control, the Guidelines state it is permissible to rely on MACT standards for purposes of BART.

105

70 FR 39163-39164.

Second, with respect to gas-fired units, which have inherently low emissions of PM (as well as SO

), the Regional Haze Rule did not specifically envision new or additional controls or emissions reductions from the PM BART requirement. The BART guidelines preclude us from stating that PM emissions are

de minimis

when plant-wide emissions exceed 15 tons per years. While we must assign PM BART determinations to the gas-firing units, there are no practical add-on controls to consider for setting a more stringent PM BART emissions limit. The Guidelines state that if the most stringent controls are made federally enforceable for BART, then the otherwise required analyses leading up to the BART determination can be skipped.

106

70 FR 39165 (“. . . you may skip the remaining analyses in this section, including the visibility analysis . . .”)

With this background, we are providing our evaluation along with some supplementary information on the BART sources as divided into two categories: coal-fired EGUs, and gas-fired EGUs.

BART Analysis for PM for Coal-Fired Units

All of the coal-fired EGUs that are subject to BART are currently equipped with either Electrostatic Precipitators (ESPs) or baghouses, or both, as can be seen from Table 20:

Table 20—Current PM Controls for Coal-Fired Units Subject to BART

Facility name

Unit ID

Fuel type (primary)

control(s)

PM control(s)

Big Brown

Coal

Baghouse + Electrostatic Precipitator.

Big Brown

Coal

Baghouse + Electrostatic Precipitator.

Coleto Creek

Coal

Baghouse.

Harrington Station

061B

Coal

Electrostatic Precipitator.

Harrington Station

062B

Coal

Baghouse.

J T Deely

Coal

Baghouse.

J T Deely

Coal

Baghouse.

Martin Lake

Coal

Wet Limestone

Electrostatic Precipitator.

Martin Lake

Coal

Wet Limestone

Electrostatic Precipitator.

Martin Lake

Coal

Wet Limestone

Electrostatic Precipitator.

Monticello

Coal

Baghouse + Electrostatic Precipitator.

Monticello

Coal

Baghouse + Electrostatic Precipitator.

Monticello

Coal

Wet Limestone

Electrostatic Precipitator.

Fayette

Coal

Wet Limestone

Electrostatic Precipitator.

Fayette

Coal

Wet Limestone

Electrostatic Precipitator.

W A Parish

WAP5

Coal

Baghouse.

W A Parish

WAP6

Coal

Baghouse.

Welsh Power Plant

Coal

Baghouse (Began Nov 15, 2015) + Electrostatic Precipitator.

As an initial matter, we examine the control efficiencies of both baghouses and ESPs. We consider a baghouse, widely reported to be capable of 99.9% control of PM, to be the maximum level control for PM and so the units equipped with a baghouse will not be further analyzed for PM BART. The remaining units are fitted with ESPs.

The particulate matter control efficiency of ESPs varies somewhat with

the design, the resistivity of the particulate matter, and the maintenance of the ESP. We do not have any information on the control level efficiency of any of the ESPs for the units in question. However, reported control efficiencies for well-maintained ESPs typically range from greater than 99% to 99.9%.

107

We consider this pertinent in concluding that the potential additional particulate control that a baghouse can offer over an ESP is relatively minimal.

108

In other words, if we did obtain control information specific to the ESP units in question, we do not believe that additional information would lead us to a different conclusion.

107

EPA, “Air Pollution Control Technology Fact Sheet: Dry Electrostatic Precipitator (ESP)—Wire Plate Type,” EPA-452/F-03-028. Grieco, G., “Particulate Matter Control for Coal-fired Generating Units: Separating Perception from Fact,”

apcmag.net,

February, 2012. Moretti, A. L.; Jones, C. S., “Advanced Emissions Control Technologies for Coal-Fired Power Plants, Babcox and Wilcox Technical Paper BR-1886, Presented at Power-Gen Asia, Bangkok, Thailand, October 3-5, 2012.

108

We do not discount the potential health benefits this additional control can have for ambient PM. However, the regional haze program is only concerned with improving the visibility at Class I areas.

Nevertheless, w`e will examine the potential cost of retrofitting a typical 500 MW coal fired unit with a baghouse. Using our baghouse cost algorithms, as employed in version 5.13 of our IPM model,

109

and assuming a conservative air to cloth ratio of 6.0, results in a capital engineering and construction cost of $77,428,000.

110

Applied to the subject units, this cost assumes a retrofit factor of 1.0, and does not consider the demolition of the existing ESP, should it be required in order to make space for the baghouse.

109

IPM Model—Updates to Cost and Performance for APC Technologies, Particulate Control Cost Development Methodology, Final March 2013, Project 12847-002, Systems Research and Applications Corporation, Prepared by Sargent & Lundy. Documentation for v.5.13: Chapter 5: Emission Control Technologies, Attachment 5-7: PM Cost Methodology, downloaded from:

https://www.epa.gov/sites/production/files/2015-08/documents/attachment_5-7_pm_cost_methodology.pdf

110

Id.

See page 9.

We do not calculate the cost-effectiveness resulting from replacing an ESP with a baghouse. However, we expect that the tons of additional PM removed by a baghouse over an ESP to be very small, which would result in a very high cost-effectiveness figure. Also, we do not model the visibility benefit of replacing an ESP with a baghouse. However, our visibility impact modeling indicates that the baseline PM emissions of these units are very small, so we expect that the visibility improvement from replacing an ESP with a baghouse to be a small fraction of that. For instance, our CAMx baseline modeling shows that on a source-wide level, impacts from PM emissions on the maximum impacted days from each source at each Class I area was 3% of the total visibility impairment or less (calculated as percent of total extinction due to the source). Therefore additional PM controls are anticipated to result in very little visibility benefit on the maximum impacted days. Similarly, our CALPUFF modeling indicates that visibility impairment from PM is also a small fraction (typically only a few percent) of the total visibility impairment due to each source.

Adding to the above discussion, we are tasked to assign the enforceable emission limitations that constitute PM BART. We believe a stringent control level that would be met with existing or otherwise-required controls is a filterable PM limit of 0.03 lb/MMBtu for each of the coal-fired units subject to BART. We note that the Mercury and Air Toxics (MATS) Rule establishes an emission standard of 0.03 lb/MMBtu filterable PM (as a surrogate for toxic non-mercury metals) as representing Maximum Achievable Control Technology (MACT) for coal-fired EGUs.

111

This standard derives from the average emission limitation achieved by the best performing 12 percent of existing coal-fired EGUs, as based upon test data used in developing the MATS Rule. We are not familiar with any new technologies subsequent to this standard that could lead to any cost effective increases in the level of control; thus, consistent with the BART Guidelines, we are proposing to rely on this limit for purposes of PM BART for all of the coal-fired units as part of our

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