Promulgation of Air Quality Implementation Plans; State of Texas; Regional Haze and Interstate Visibility Transport Federal Implementation Plan, 912-950 [2016-30713]

Download as PDF 912 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 52 [EPA–R06–OAR–2016–0611; FRL–9955–77Region 6] Promulgation of Air Quality Implementation Plans; State of Texas; Regional Haze and Interstate Visibility Transport Federal Implementation Plan Environmental Protection Agency (EPA). ACTION: Proposed rule. AGENCY: 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 SO2 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 SO2. To address the requirement for NOX 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 NOX 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. SUMMARY: 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_ mstockstill on DSK3G9T082PROD with PROPOSALS2 DATES: VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 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/commentingepa-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 PO 00000 Frm 00002 Fmt 4701 Sfmt 4700 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 E:\FR\FM\04JAP2.SGM 04JAP2 mstockstill on DSK3G9T082PROD with PROPOSALS2 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules C. Our Authority To Promulgate a FIP III. Our Proposed BART Analyses for SO2 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 SO2 Retrofit Controls a. Identification of Technically Feasible SO2 Retrofit Control Technologies for Coal Fired Units b. Identification of Technically Feasible SO2 Retrofit Control Technologies for Gas-Fired Units That Burn Oil c. Identification of Technically Feasible SO2 Control Technologies for Scrubber Upgrades 2. Step 3: Evaluation of Control Effectiveness a. Evaluation of SO2 Control Effectiveness for Coal Fired Units b. Evaluation of SO2 Control Effectiveness for Gas Fired Units 3. Step 4: Evaluate Impacts and Document the Results for SO2 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. SO2 BART for Coal-fired Units With no SO2 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. SO2 BART for Coal-fired Units With Underperforming Scrubbers C. SO2 BART for Gas-fired Units That Burn Oil D. PM BART V. Proposed Actions A. Regional Haze 1. NOX BART 2. SO2 BART for Coal-fired Units VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 3. Potential Process for Alternative Scrubber Upgrade Emission Limits 4. SO2 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 (PM2.5) (e.g., sulfates, nitrates, Organic Carbon (OC), Elemental Carbon (EC), and soil dust), and their precursors (e.g., Sulfur Dioxide (SO2), Nitrogen Oxides (NOX), and in some cases, ammonia (NH3) and Volatile Organic Compounds (VOCs)). Fine particle precursors react in the atmosphere to form PM2.5, which impairs visibility by scattering and absorbing light. Visibility impairment reduces the clarity, color, and visible distance that can be seen. PM2.5 can also cause serious health effects and mortality in humans and contributes to environmental effects such as acid deposition and eutrophication. Data from the existing visibility monitoring network, the ‘‘Interagency Monitoring of Protected Visual Environments’’ (IMPROVE) monitoring network, show that visibility impairment caused by air pollution occurs virtually all the time at most national parks and wilderness areas. In 1999, the average visual range 1 in many Class I areas (i.e., national parks and memorial parks, wilderness areas, and international parks meeting certain size criteria) in the western United States was 100–150 kilometers, or about onehalf to two-thirds of the visual range that would exist without anthropogenic air pollution. In most of the eastern Class I areas of the United States, the average visual range was less than 30 kilometers, or about one-fifth of the visual range that would exist under estimated natural conditions.2 CAA programs have reduced some hazecausing pollution, lessening some visibility impairment and resulting in partially improved average visual ranges.3 CAA requirements to address the problem of visibility impairment are continuing to be addressed and implemented. In Section 169A of the 1977 Amendments to the CAA, 1 Visual range is the greatest distance, in kilometers or miles, at which a dark object can be viewed against the sky. 2 64 FR 35715 (July 1, 1999). 3 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. PO 00000 Frm 00003 Fmt 4701 Sfmt 4700 913 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.4 On December 2, 1980, EPA promulgated regulations to address visibility impairment in Class I areas that is ‘‘reasonably attributable’’ to a single source or small group of sources, i.e., ‘‘reasonably attributable visibility impairment.’’ 5 These regulations represented the first phase in addressing visibility impairment. EPA deferred action on regional haze that emanates from a variety of sources until monitoring, modeling, and scientific knowledge about the relationships between pollutants and visibility impairment were improved. Congress added section 169B to the CAA in 1990 to address regional haze issues, and we promulgated regulations addressing regional haze in 1999.6 The Regional Haze Rule revised the existing visibility regulations to integrate into the regulations provisions addressing regional haze impairment and established a comprehensive visibility protection program for Class I areas. The requirements for regional haze, found at 40 CFR 51.308 and 51.309, are included in our visibility protection regulations at 40 CFR 51.300–309. 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 4 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.’’ 5 45 FR 80084 (December 2, 1980). 6 64 FR 35714 (July 1, 1999), codified at 40 CFR part 51, subpart P (Regional Haze Rule). E:\FR\FM\04JAP2.SGM 04JAP2 914 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules impairment no later than December 17, 2007.7 Section 169A of the CAA directs states to evaluate the use of retrofit controls at certain larger, often undercontrolled, older stationary sources in order to address visibility impacts from these sources. Specifically, section 169A(b)(2)(A) of the CAA requires states to revise their SIPs to contain such measures as may be necessary to make reasonable progress toward the natural visibility goal, including a requirement that certain categories of existing major stationary sources 8 built between 1962 and 1977 procure, install and operate the ‘‘Best Available Retrofit Technology’’ (BART). Larger ‘‘fossil-fuel fired steam electric plants’’ are included among the BART source categories. Under the Regional Haze Rule, states are directed to conduct BART determinations for ‘‘BART-eligible’’ sources that may be anticipated to cause or contribute to any visibility impairment in a Class I area. The evaluation of BART for 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.9 II. Overview of Proposed Actions mstockstill on DSK3G9T082PROD with PROPOSALS2 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, 2009.10 In that final rule, we did not 7 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). 8 See 42 U.S.C. 7491(g)(7) (listing the set of ‘‘major stationary sources’’ potentially subject-toBART). 9 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’’). 10 81 FR 296 (January 5, 2016). A preliminary order of the Fifth Circuit Court of Appeals in Case VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 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).11 The EGU BART requirements for NOX and SO2 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,12 that part of the proposed action was not finalized.13 In connection with changed circumstances on how Texas EGUs are able to satisfy NOX and SO2 BART, we are now proposing to disapprove the portion of the Texas Regional Haze SIP that evaluated the PM BART requirement for EGUs. The FIP we are proposing today addresses the EGU BART requirement and addresses these deficiencies in the Texas Regional Haze SIP. Texas’ regional haze SIP relied on participation in CAIR as an alternative to meeting the source-specific BART requirements for SO2 and NOX. 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 v. 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 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. 11 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). 12 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). 13 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].’’ PO 00000 Frm 00004 Fmt 4701 Sfmt 4700 CAIR consistent with the court’s opinion.14 On August 8, 2011, we promulgated the Cross-State Air Pollution Rule (CSAPR), to replace CAIR.15 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 SO2 and NOX.16 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 sourcespecific SO2 and NOX BART for EGUs.17 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 v. EPA, 795 F.3d 118 (D.C. Cir.). Specifically, the court invalidated a number of the Phase 2 ozone-season NOX budgets and found that the SO2 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 NOX budget and annual SO2 budget. We had earlier proposed to rely on CSAPR participation to address these BART-related deficiencies in Texas’ SIP submittals.18 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.19 This rule promulgated a new 14 550 F.3d at 1178. FR 48208. 16 77 FR 33641. 17 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. 18 79 FR 74817, 74823 (December 16, 2014). 19 ‘‘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 NOX 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 NOX 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 NOX emission budget to address that standard. 81 FR 74504, 74600–74601. 15 76 E:\FR\FM\04JAP2.SGM 04JAP2 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules mstockstill on DSK3G9T082PROD with PROPOSALS2 FIP for Texas that replaced the CSAPR ozone season NOX 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 SO2 and NOX with regard to emissions after 2016.20 Withdrawal of these FIP requirements will address the D.C. Circuit’s remand of the CSAPR Phase 2 SO2 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. 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 ozoneseason NOX 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 NOX requirements in order to address their PM2.5 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 NOX requirements that has already been finalized, and the withdrawal of FIP provisions subjecting Texas EGUs to CSAPR SO2 and annual NOX requirements that is proposed 20 ‘‘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’ SO2 budget, the court’s rationale for remanding that budget also implicates Texas’ annual NOX budget because the SO2 and annual NOX budgets were developed through an integrated analysis and were promulgated to meet a common PM2.5 transport obligation under CAA section 110(a)(2)(D)(i)(I). VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 separately. That proposed analysis supports the continued conclusion that CSAPR participation would achieve greater reasonable progress than BART for NOX 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.21 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 NOX.22 Based on that national proposal, we are now proposing a FIP to replace Texas’ reliance on CAIR with reliance on CSAPR to address the NOX 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 SO2 and NOX 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 SO2. As a result, we are proposing to promulgate a FIP that includes BART screening of sources and a source-bysource analysis for SO2 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.23 21 81 FR at 78962–78964. we have proposed to remove Texas from CSAPR’s annual NOX program, CSAPR is still an appropriate alternative to BART for NOX purposes because EGUs in Texas continue to be required to participate in CSAPR’s ozone season NOX program. 23 We previously proposed approval of Texas’ SIP for EGU PM BART on the premise that EGU BART for both SO2 and NOX 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 NOX and SO2 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 pollutantspecific screening analysis for NOX. Phoenix Cement Co. v. EPA, 647 F. App’x 702, 705–06 (9th 22 While PO 00000 Frm 00005 Fmt 4701 Sfmt 4700 915 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. 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 SO2, NOX, and PM. We are proposing sourcespecific BART determinations for EGUs subject to BART for SO2 and PM. We are proposing that NOX 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 sourcespecific NOX BART. Addressing the BART requirement for Texas EGUs, as proposed today, with cost-effective and readily available controls, will help ensure that progress 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 NOX and SO2, 81 FR 296, 302, but that uncertainty has now been resolved. E:\FR\FM\04JAP2.SGM 04JAP2 916 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules 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.24 B. Interstate Transport of Pollutants That Affect Visibility mstockstill on DSK3G9T082PROD with PROPOSALS2 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.25 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 PM2.5 NAAQS.26 Texas later submitted a SIP revision to address interstate transport for these NAAQS. 24 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. 25 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]. 26 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. VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 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 PM2.5.27 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 SO2 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 v. 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 SO2 and NOX BART for EGUs in Texas in that action.28 Our prior disapproval of interstate visibility transport for the six NAAQS is currently stayed by the Fifth Circuit.29 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 27 Specifically, we previously disapproved the relevant portion of these Texas’ SIP submittals: April 4, 2008: 1997 8-hour Ozone, 1997 PM2.5 (24hour and annual); May 1, 2008: 1997 8-hour Ozone, 1997 PM2.5 (24-hour and annual); November 23, 2009: 2006 24-hour PM2.5; December 7, 2012: 2010 NO2; December 13, 2012: 2008 8-hour Ozone; May 6, 2013: 2010 1-hour SO2 (Primary NAAQS). 79 FR 74818, 74821; 81 FR 296, at 302. 28 81 FR 296, 301–2. 29 July 15, 2016 Order in Texas v. 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. PO 00000 Frm 00006 Fmt 4701 Sfmt 4700 to issue a FIP for the 1997 8-hour ozone and 1997 PM2.5 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 SO2 and NOX. 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 PM2.5 (24-hour and annual); May 1, 2008: 1997 8-hour Ozone, 1997 PM2.5 (24-hour and annual); November 23, 2009: 2006 24hour PM2.5; December 7, 2012: 2010 NO2; December 13, 2012: 2008 8-hour Ozone; May 6, 2013: 2010 1-hour SO2 (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. 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 NOX in Texas. The FIP will also address Texas EGU BART for SO2 and PM on a sourcespecific basis. With the absence of CSAPR coverage for SO2, 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 SO2, which exceed the reductions initially assumed for Texas under either CAIR or CSAPR. In addition, our proposed FIP achieves reductions at large sources of SO2 emissions (e.g., Monticello, Martin Lake and Big Brown), that have significant impacts on E:\FR\FM\04JAP2.SGM 04JAP2 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules 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.30 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 8hour ozone, 1997 PM2.5, 2006 PM2.5, 2008 8-hour ozone, 2010 1-hour NO2, and 2010 1-hour SO2). We also propose that reliance on CSAPR for EGU NOX BART is appropriate to ensure NOX 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.31 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.32 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.’’ 33 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. 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 NOX and SO2. 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.34 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. Adding to this background, beginning with our January 5, 2016 disapproval of Texas SIP provisions regarding 32 2013 i-SIP Guidance, at pages 34–35. 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). 34 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. mstockstill on DSK3G9T082PROD with PROPOSALS2 33 EPA 30 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). 31 See e.g. 78 FR 14681, 14685. VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 PO 00000 Frm 00007 Fmt 4701 Sfmt 4700 917 interstate visibility transport, we obtained the authority and obligation to promulgate a FIP to correct the deficiencies relating to that CAA requirement.35 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. III. Our Proposed BART Analyses for SO2 and PM In our previous action,36 we determined that due to the CSAPR remand, it was not appropriate at that time to rely on CSAPR as an alternative to SO2 and NOX 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.37 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 NOX alone. It remains the case that we cannot rely on CSAPR as an alternative to SO2 BART for Texas EGUs as further confirmed by our proposed action to remove Texas from the annual NOX and SO2 control programs. Thus, we have the obligation to consider sourcespecific requirements for Texas EGUs consistent with the BART Guidelines for SO2 BART. 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 SO2 and NOX 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 SO2 or NOX would not be 35 Additionally, we continue to have authority to issue a FIP to address interstate visibility transport for 1997 8-hour ozone and 1997 PM2.5 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. 36 See the discussion beginning on 81 FR 301 (January 5, 2016). 37 Id. at 346. E:\FR\FM\04JAP2.SGM 04JAP2 918 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules 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.38 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 SO2 and NOX BART under an alternative measure.39 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 NOX, i.e., SO2 and PM. A. Identification of BART-Eligible Sources The BART Guidelines set forth the steps for identifying whether the source is a BART-eligible source: 40 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. mstockstill on DSK3G9T082PROD with PROPOSALS2 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. 38 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 SO2 and NOX with an alternative measure. Additionally, as reflected in our TSD on the identification of BART-Eligible Sources, the Texas SIP neglected to identify several BARTeligible 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. 39 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). 40 70 FR 39158 (July 6, 2005). VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 Energy Information Administration (EIA). We then converted Texas’ facilityspecific BART-eligible list to a unitspecific 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: 41 TABLE 1—SUMMARY OF BARTELIGIBILITY ANALYSIS Facility Unit Barney M. Davis (Talen/Topaz) ........ Big Brown (Luminant) ........................ Big Brown (Luminant) ........................ Cedar Bayou (NRG) .......................... Cedar Bayou (NRG) .......................... Coleto Creek (Engie) ......................... Dansby (City of Bryan) ...................... Decker Creek (Austin Energy) .......... Decker Creek (Austin Energy) .......... Fayette (LCRA) ................................. Fayette (LCRA) ................................. Graham (Luminant) ........................... Greens Bayou (NRG) ........................ Handley (Exelon) ............................... Handley (Exelon) ............................... Handley (Exelon) ............................... Harrington Station (Xcel) ................... Harrington Station (Xcel) ................... J T Deely (CPS Energy) ................... J T Deely (CPS Energy) ................... Jones Station (Xcel) .......................... Jones Station (Xcel) .......................... Knox Lee Power Plant (AEP) ............ Lake Hubbard (Luminant) ................. Lake Hubbard (Luminant) ................. Lewis Creek (Entergy) ....................... Lewis Creek (Entergy) ....................... Martin Lake (Luminant) ..................... Martin Lake (Luminant) ..................... Martin Lake (Luminant) ..................... Monticello (Luminant) ........................ Monticello (Luminant) ........................ Monticello (Luminant) ........................ Newman (El Paso Electric) ............... Newman (El Paso Electric) ............... Newman (El Paso Electric) ............... Nichols Station (Xcel) ........................ O W Sommers (CPS Energy) ........... O W Sommers (CPS Energy) ........... Plant X (Xcel) .................................... Powerlane (City of Greenville) .......... Powerlane (City of Greenville) .......... Powerlane (City of Greenville) .......... R W Miller (Brazos Elec. Coop) ........ R W Miller (Brazos Elec. Coop) ........ R W Miller (Brazos Elec. Coop) ........ Sabine (Entergy) ............................... Sabine (Entergy) ............................... Sabine (Entergy) ............................... Sabine (Entergy) ............................... Sim Gideon (LCRA) .......................... Sim Gideon (LCRA) .......................... Sim Gideon (LCRA) .......................... Spencer (City of Garland) ................. Spencer (City of Garland) ................. Stryker Creek (Luminant) .................. 1. 1. 2. CBY1. CBY2. 1. 1. 1. 2. 1. 2. 2. 5. 3. 4. 5. 061B. 062B. 1. 2. 151B. 152B. 5. 1. 2. 1. 2. 1. 2. 3. 1. 2. 3. 2. 3. 4. 143B. 1. 2. 4. ST1. ST2. ST3. 1. 2. 3. 2. 3. 4. 5. 1. 2. 3. 4. 5. ST2. 41 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. PO 00000 Frm 00008 Fmt 4701 Sfmt 4700 TABLE 1—SUMMARY OF BARTELIGIBILITY ANALYSIS—Continued Facility Unit Trinidad (Luminant) ........................... Ty Cooke (City of Lubbock) .............. Ty Cooke (City of Lubbock) .............. V H Braunig (CPS Energy) ............... V H Braunig (CPS Energy) ............... V H Braunig (CPS Energy) ............... W A Parish (NRG) ............................. W A Parish (NRG) ............................. W A Parish (NRG) ............................. Welsh Power Plant (AEP) ................. Welsh Power Plant (AEP) ................. Wilkes Power Plant (AEP) ................ Wilkes Power Plant (AEP) ................ Wilkes Power Plant (AEP) ................ 6. 1. 2. 1. 2. 3. WAP4. WAP5. WAP6. 1. 2. 1. 2. 3. The final step in identifying a ‘‘BARTeligible 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.42 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-toBART screening analysis is provided in 42 See 40 CFR part 51, Appendix Y, III, How to Identify Sources ‘‘Subject to BART’’. E:\FR\FM\04JAP2.SGM 04JAP2 919 mstockstill on DSK3G9T082PROD with PROPOSALS2 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules the BART Screening TSD.43 We summarize the methodology and results of this analysis here. 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.44 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. 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.’’ 45 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 BARTeligible 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. 43 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. 44 See the discussion beginning on 70 FR 39104, 39162 (July 6, 2005) [40 CFR part 51, App. Y]. 45 70 FR at 39118. VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 Therefore, our analysis employs a contribution threshold of 0.5 deciviews. 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 NOX or SO2 (or combined NOX and SO2), as long as these sources are located more than 50 kilometers from any Class I area; and sources that emit less than 1000 tons per year of NOX or SO2 (or combined NOX and SO2) that are located more than 100 kilometers from any Class I area. You do, however, have the option of showing other thresholds might also be appropriate given your specific circumstances.46 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) ........ Plant X (Xcel) .................... Powerlane (City of Greenville). Spencer (City of Garland) Trinidad (Luminant) ........... Ty Cooke (City of Lubbock) 1. 5. 143B. 4. ST1, ST2 & ST3. 4 & 5. 6. 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.’’ 47 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 46 70 47 70 PO 00000 FR at 39163 [40 CFR part 51, App. Y]. FR at 39163 [40 CFR part 51, App. Y]. Frm 00009 Fmt 4701 Sfmt 4700 characteristics. In this approach, a hypothetical facility (‘‘model plant’’) is located between a group of BARTeligible 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 BARTeligible 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, the Q/d value is calculated as the annual emissions (combined NOX and SO2 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 Barney M. Davis (Talen/ Topaz). Cedar Bayou (NRG) .......... Decker Creek (Austin ........ Energy) .............................. Lewis Creek (Entergy) ....... Sabine (Entergy) ................ Sim Gideon (LCRA) ........... V H Braunig (CPS Energy) Units 1. CBY1 & CBY2. 1 & 2. 1 & 2. 2, 3, 4 & 5. 1, 2 & 3. 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 E:\FR\FM\04JAP2.SGM 04JAP2 920 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules 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 NOX and SO2 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.48 For some BART-eligible sources, evaluation of baseline emissions revealed evidence of the installation of NOX 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: TABLE 4—CALPUFF BART EXEMPT SOURCES Facility mstockstill on DSK3G9T082PROD with PROPOSALS2 Handley (Exelon) ............... Jones (Xcel) ....................... Lake Hubbard (Luminant) .. Knox Lee (AEP) ................. R W Miller (Brazos Elec. Coop). Units 3, 4 & 5. 151B & 152B. 1 & 2. 5. 1, 2 & 3. Based on these CALPUFF screening analyses using model plant approaches and direct modeling, the following 48 http://ampd.epa.gov/ampd/. VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 gas 49/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. 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-toreceptor distances. CAMx is also more suited than some other modeling approaches for evaluating the impacts of SO2, NOX, 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 SO2 emissions.50 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 nonEGU 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 49 When we use the term ‘‘gas,’’ we mean ‘‘pipeline quality natural gas.’’ 50 CAMx results were also obtained and add to our basis of information for coal-fired facilities that have CALPUFF results. 51 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. 52 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). PO 00000 Frm 00010 Fmt 4701 Sfmt 4700 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. 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 NOX and SO2 from the 2000– 2004 baseline period from EPA’s Air Markets Program Data 53 and modeled these emission rates as constant emission rates for the entire modeled year. For some of the modeled BARTeligible sources, evaluation of baseline emissions revealed evidence of installation of NOX 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. 53 http://ampd.epa.gov/ampd/. E:\FR\FM\04JAP2.SGM 04JAP2 921 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules TABLE 5—CAMX BART SCREENING SOURCE ANALYSIS RESULTS Most impacted Class I area BART-eligible source Units Big Brown ........................... Coleto Creek ...................... Fayette Power .................... Harrington ........................... Martin Lake ......................... Monticello ........................... Calaveras ........................... 1 & 2 ................................... 1 ......................................... 1 & 2 ................................... 061B & 062B ...................... 1, 2, & 3 ............................. 1, 2, & 3 ............................. J T Deely 1 & 2, OW Sommers 1 & 2. WAP4, WAP5 & WAP6 ...... 1 & 2 ................................... W A Parish ......................... Welsh 1 ............................... 1 Welsh WIMO WIMO CACR SACR CACR CACR WIMO Number of modeled days over 0.5 dv 2 Number of modeled days over 1.0 dv 2 .................. .................. .................. .................. .................. .................. .................. 65 9 26 13 141 152 47 33 0 9 5 99 111 6 No .................. No .................. 54 92 22 39 Maximum delta-dv ............. ............. ............. ............. ............. ............. ............. 4.017 0.845 1.894 5.288 6.651 10.498 1.513 CACR ............. CACR ............. 3.177 4.576 Less than 0.5 dv? No No No No No No No unit 2 has recently shutdown. We note that baseline impacts from unit 1 alone are 2.343 dv at Caney Creek. of days over 0.5 or 1.0 dv at the most impacted Class I area. 2 Number 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 NOX.54 Foremost, they are subject to SO2 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. TABLE 6—SUMMARY: SOURCES THAT ARE SUBJECT-TO-BART Facility Units Big Brown ........ Coleto Creek .... Fayette Power Harrington ........ Martin Lake ...... Monticello ......... Calaveras ......... W A Parish ...... Welsh ............... Stryker ............. Graham ............ Wilkes .............. Newman ........... The following sections treat these steps individually for SO2. We are combining these steps into one section in our assessment of PM BART that follows the SO2 sections. mstockstill on DSK3G9T082PROD with PROPOSALS2 54 The NO BART requirement for these EGU X 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 18:33 Jan 03, 2017 Jkt 241001 The purpose of the BART analysis is to identify and evaluate the best system of continuous emission reduction based on the BART Guidelines.55 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: 56 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. 1 & 2. 1. 1 & 2. 061B & 062B. 1, 2 & 3. 1, 2 & 3. J T Deely 1 & 2, O W Sommers 1 & 2. WAP4, WAP5 & WAP6. 1 & 2*. ST2. 2. 1, 2 & 3. 2, 3 & 4. * Welsh Unit 2 retired in April, 2016. VerDate Sep<11>2014 C. Our BART Five Factor Analyses need for source-specific BART determinations and requirements for NOX. 55 See July 6, 2005 BART Guidelines, 40 CFR part 51, Regional Haze Regulations and Guidelines for Best Available Retrofit Technology Determinations. PO 00000 Frm 00011 Fmt 4701 Sfmt 4700 1. Steps 1 and 2: Technically Feasible SO2 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.57 Adhering to this, we will identify a reasonable set of SO2 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 SO2 controls that could be retrofitted: (1) Coal-fired EGUs with no SO2 scrubber, (2) coal-fired EGUs with underperforming SO2 scrubbers, (3) gasfired EGUs that do not burn oil, and (4) gas-fired EGUs that occasionally burn fuel oil. This classification is represented below: 56 70 FR 39104, 39164 (July 6, 2005) [40 CFR part 51, App. Y]. 57 70 FR at 39164, fn 12 [40 CFR part 51, App. Y] E:\FR\FM\04JAP2.SGM 04JAP2 922 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules TABLE 7—SUBJECT TO BART FUEL TYPES AND POTENTIAL SO2 BART CONTROLS Facility Unit Coal no scrubber Coal underperforming scrubber Gas no oil Gas burns oil Big Brown (Luminant) ...................................................... Big Brown (Luminant) ...................................................... Coleto Creek (Engie) ....................................................... Fayette (LCRA) * .............................................................. Fayette (LCRA) * .............................................................. Graham (Luminant) .......................................................... Harrington Station (Xcel) ................................................. Harrington Station (Xcel) ................................................. J T Deely (CPS Energy) .................................................. J T Deely (CPS Energy) .................................................. Martin Lake (Luminant) .................................................... Martin Lake (Luminant) .................................................... Martin Lake (Luminant) .................................................... Monticello (Luminant) ...................................................... Monticello (Luminant) ...................................................... Monticello (Luminant) ...................................................... Newman (El Paso Electric) .............................................. Newman (El Paso Electric) .............................................. Newman (El Paso Electric) .............................................. O W Sommers (CPS Energy) ......................................... O W Sommers (CPS Energy) ......................................... Stryker Creek (Luminant) ................................................ W A Parish (NRG) ........................................................... W A Parish (NRG) ........................................................... W A Parish (NRG) ........................................................... Welsh Power Plant (AEP) ............................................... Wilkes Power Plant (AEP) ............................................... Wilkes Power Plant (AEP) ............................................... Wilkes Power Plant (AEP) ............................................... 1 ..................... 2 ..................... 1 ..................... 1 ..................... 2 ..................... 2 ..................... 061B .............. 062B .............. 1 ..................... 2 ..................... 1 ..................... 2 ..................... 3 ..................... 1 ..................... 2 ..................... 3 ..................... 2 ..................... 3 ..................... 4 ..................... 1 ..................... 2 ..................... ST2 ................ WAP4 ............. WAP5 ............. WAP6 ............. 1 ..................... 1 ..................... 2 ..................... 3 ..................... X X X ........................ ........................ ........................ X X X X ........................ ........................ ........................ X X ........................ ........................ ........................ ........................ ........................ ........................ ........................ ........................ X X X ........................ ........................ ........................ ........................... ........................... ........................... ........................... ........................... ........................... ........................... ........................... ........................... ........................... X X X ........................... ........................... X ........................... ........................... ........................... ........................... ........................... ........................... ........................... ........................... ........................... ........................... ........................... ........................... ........................... ........................ ........................ ........................ ........................ ........................ ........................ ........................ ........................ ........................ ........................ ........................ ........................ ........................ ........................ ........................ ........................ ........................ ........................ X ........................ ........................ ........................ X ........................ ........................ ........................ ........................ X X ........................ ........................ ........................ ........................ ........................ X ........................ ........................ ........................ ........................ ........................ ........................ ........................ ........................ ........................ ........................ X X ........................ X X X ........................ ........................ ........................ ........................ X ........................ ........................ mstockstill on DSK3G9T082PROD with PROPOSALS2 * 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 SO2 emissions and there are no known SO2 controls that can be evaluated. For gas-fired units that occasionally burn fuel oil, we will follow the BART Guidelines recommendations for oilfired 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.’’ 58 In addition, we will also evaluate the potential for post combustion SO2 controls for these units. 58 70 FR 39171 (July 6, 2005) [40 CFR 51, App. Y]. VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 a. Identification of Technically Feasible SO2 Retrofit Control Technologies for Coal-Fired Units Available SO2 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).59 Washing operations are carried out mainly on bituminous and anthracitic coals, as the characteristics 59 Couch, G.R., ‘‘Coal Upgrading to Reduce CO 2 emissions,’’ CCC/67, October 2002, IEA Clean Coal Centre. PO 00000 Frm 00012 Fmt 4701 Sfmt 4700 of subbituminous coals and lignite (brown coals) do not lend themselves to separation of mineral matter by this means, except in a few cases.60 Coal is mechanically sized, then various washing techniques are employed, depending on the particle size, type of coal, and the desired level of preparation.61 Following the coal washing, the coal is dewatered, and the waste streams are disposed. 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. 60 Ibid. 61 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. E:\FR\FM\04JAP2.SGM 04JAP2 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules mstockstill on DSK3G9T082PROD with PROPOSALS2 • 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,62 and coal washing slurries are typically stored in impoundments, which can, and have, leaked.63 Because of these issues, we do not consider coal washing as a part of our reasonable set of options for analysis as BART SO2 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.64 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. 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 SO2, its analysis presents a number of difficulties. For instance, the degree of 62 ‘‘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. 63 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. 64 DryFiningTM is the company’s name for the process. It is described here: http:// www.powermag.com/improve-plant-efficiency-andreduce-co2-emissions-when-firing-high-moisturecoals/. VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 reduction in SO2 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 SO2 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 SO2 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 SO2 removal. There are many examples of DSI being used on coal-fired EGUs to control SO2. 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: 65 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 SO2 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 65 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. PO 00000 Frm 00013 Fmt 4701 Sfmt 4700 923 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. SO2 Scrubbing Systems In contrast to DSI, SO2 scrubbing techniques utilize a large dedicated vessel in which the chemical reaction between the sorbent and SO2 takes place either completely or in large part. Also in contrast to DSI systems, SO2 scrubbers add water to the sorbent when introduced to the flue gas. The two predominant types of SO2 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 .... Spray dryer absorber ............ Circulating dry scrubber ....... Packed tower wet scrubber .. Venturi wet scrubber ............ Jet bubbling reactor .............. Tray tower wet scrubber ....... Mechanically aided wet scrubber. DSI ........................................ Other ..................................... Unspecified ........................... 296 269 50 6 48 31 42 Total ............................... 854 4 106 1 1 Excluding the DSI installations, EIA lists 748 SO2 scrubber installations in operation in 2015. Of these, 296 are listed as being spray type wet scrubbers, with an additional 42 listed as being E:\FR\FM\04JAP2.SGM 04JAP2 924 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules tray type wet scrubbers.66 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. 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 SO2 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 SO2 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 coalfired BART-eligible units. b. Identification of Technically Feasible SO2 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–923,67 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: 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) ....................................................................... O W Sommers (CPS Energy) ................................................................... Stryker Creek (Luminant) .......................................................................... Wilkes Power Plant (AEP) ........................................................................ 2 ...................................................... 2, 3 .................................................. 1, 2 .................................................. ST2 .................................................. 1 ...................................................... ........................ ........................ ........................ ........................ ........................ X X X X X mstockstill on DSK3G9T082PROD with PROPOSALS2 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.68 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.69 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 SO2 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 66 Trays are often employed in spray type wet scrubbers and EIA lists some of the wet spray tower systems as secondarily including trays. 67 EIA-767: http://www.eia.gov/electricity/data/ eia767/. EIA–906/920 and EIA–923: http:// www.eia.gov/electricity/data/eia923/. 68 70 FR at 39171. 69 In addition, the Newman units 2 and 3 are restricted to burning fuel oil for no more than 10% of their annual operating time. VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 cost increases relate to purchase price differences. SO2 Scrubber Feasibility for Gas/OilFired 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.70 Consequently, we will consider the installation of various types of scrubbers to be technically feasible. c. Identification of Technically Feasible SO2 Control Technologies for Scrubber Upgrades In our recent Texas-Oklahoma FIP,71 we presented a great deal of information that concluded that the existing scrubbers for a number of facilities could be very cost-effectively upgraded.72 That information is included in this proposal.73 It contains a comprehensive survey of available literature concerning the kinds of upgrades that have been performed by industry on scrubber systems similar to 70 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 MultiPollutant Control Technology.’’ See Page 4: ‘‘We have also provided systems for heavy oil and Orimulsion fuels.’’ PO 00000 Frm 00014 Fmt 4701 Sfmt 4700 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. 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.’’ 71 81 FR 321. 72 See information presented in Sections 6 and 7 of the Cost TSD. 73 That information is included in our BART FIP TSD, Appendix B. E:\FR\FM\04JAP2.SGM 04JAP2 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules 2. Step 3: Evaluation of SO2 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.’’ 74 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. a. Evaluation of SO2 Control Effectiveness for Coal Fired Units mstockstill on DSK3G9T082PROD with PROPOSALS2 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 SO2 removal efficiency for the individual units listed in Table 7. We are aware that a number of the subjectto-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 SO2 control. We must do the same for SO2 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,75 assuming milled trona: 80% SO2 removal for an ESP installation and 90% SO2 removal for a baghouse installation. This level of control is within the range that can be 74 70 FR 39103, 39172 (July 6, 2005), [40 CFR part 51, App. Y]. 75 IPM Model—Updates to Cost and Performance for APC Technologies, Dry Sorbent Injection for SO2 Control Cost Development Methodology, Final March 2013, Project 12847–002, Systems Research and Applications Corporation, Prepared by Sargent & Lundy, p. 7. VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 achieved by SO2 scrubbers, and thus allows a better comparison of the costs of DSI and scrubbers. • 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 SO2 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 SO2 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.76 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 SO2 emission guarantees, from the original equipment manufacturers of wet FGD systems, are 0.04 lb/MMBtu.’’ As we established in our Oklahoma 76 IPM Model—Updates to Cost and Performance for APC Technologies, Dry Sorbent Injection for SO2 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_55_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_52_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_51_wet_fgd_cost_methodology.pdf. PO 00000 Frm 00015 Fmt 4701 Sfmt 4700 925 FIP,77 this level of control is achievable with wet FGD. This level of control was also employed in our recent TexasOklahoma FIP.78 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.79 We continue to conclude that our proposed level of control for wet FGD is reasonable. 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 SO2 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.80 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 81 and in our TSD. We continue to conclude that our proposed level of control for SDA is reasonable. b. Evaluation of SO2 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 SO2 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. 77 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 v. EPA, 723 F.3d 1201 (July 19, 2013), cert. denied (U.S. May 27, 2014). 78 81 FR 321. 79 That information is included in our BART FIP TSD, Appendix A. 80 76 FR 81728. 81 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. E:\FR\FM\04JAP2.SGM 04JAP2 926 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules 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 gasfired 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 SO2 The BART Guidelines offers the following with regard to how Step 4 should be conducted: 82 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.83 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).84 We proceed in our SO2 costing analyses by examining the current SO2 emissions and the level of SO2 control, if any, for each of the units listed in Table 7. For the coal units without any SO2 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. 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 SO2 control.85 These cost models were based on costs escalated to 2012 dollars.86 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). 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 SO2 control device. Below, we present a summary of our DSI, SDA, and wet FGD cost analysis: 87 TABLE 10—SUMMARY OF DSI, SDA, AND WET FGD COST ANALYSIS Control level (%) Facility Unit Control Big Brown ........... 1 ......................... DSI ..................... DSI ..................... SDA .................... Wet FGD ............ DSI ..................... DSI ..................... SDA .................... Wet FGD ............ DSI ..................... DSI ..................... SDA .................... Wet FGD ............ DSI ..................... DSI ..................... SDA .................... Wet FGD ............ DSI ..................... DSI ..................... SDA .................... Wet FGD ............ DSI ..................... DSI ..................... SDA .................... DSI ..................... DSI ..................... SDA .................... DSI ..................... 2 ......................... Monticello ........... 1 ......................... 2 ......................... Coleto Creek ...... Harrington ........... 1 ......................... 061B ................... mstockstill on DSK3G9T082PROD with PROPOSALS2 062B ................... J T Deely ............ 1 ......................... 82 70 FR 39166. 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. 84 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. 83 To VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 SO2 reduction (tpy) 50 90 95 98 50 90 95 97.9 50 90 95 97 50 90 95 96.8 50 90 92.4 94.9 50 80 90.2 50 * 88.9 88.9 50 14,448 26,006 27,453 28,320 15,320 27,576 29,108 29,998 4,787 8,617 9,095 9,286 4,129 7,431 7,844 7,995 7,376 13,277 13,632 14,005 2,477 3,962 4,466 2,455 4,364 4,364 3,072 85 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. 86 Ibid., p.1: ‘‘The data was converted to 2012 dollars based on the Chemical Engineering Plant Index (CEPI) data.’’ PO 00000 Frm 00016 Fmt 4701 Sfmt 4700 2016 Annualized cost $29,468,587 72,131,749 35,297,532 33,673,102 29,342,350 71,322,593 35,359,239 33,817,952 11,408,872 25,409,128 24,294,319 25,236,699 9,742,648 21,418,734 23,126,113 24,233,133 16,246,169 34,841,379 29,445,018 29,786,106 9,187,608 16,073,779 17,455,679 6,524,937 11,981,111 18,240,127 8,854,319 2016 Cost effectiveness ($/ton) $2,040 2,774 1,286 1,189 1,915 2,586 1,215 1,127 2,383 2,949 2,671 2,718 2,360 2,882 2,948 3,031 2,203 2,624 2,160 2,127 3,710 4,057 3,909 2,658 2,746 4,180 2,883 2016 Incremental costeffectiveness ($/ton) $3,691 ¥25,456 ¥1,874 3,425 ¥23,475 ¥1,732 3,655 ¥2,332 4,934 3,536 4,134 7,331 3,151 ¥15,201 914 4,637 2,742 2,858 N/A 87 In this table, the capital cost is the total cost of constructing the facility. The annualized cost is the sum of the annualized capital cost and the annualized operational cost. See our Cost TSD for more information on how these costs were calculated. E:\FR\FM\04JAP2.SGM 04JAP2 927 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules TABLE 10—SUMMARY OF DSI, SDA, AND WET FGD COST ANALYSIS—Continued Facility Unit Control 2 ......................... Welsh .................. W.A. Parish ........ Control level (%) 1 ......................... 5 ......................... 6 ......................... ............................ DSI ..................... SDA .................... Wet FGD ............ DSI ..................... DSI ..................... SDA .................... Wet FGD ............ DSI ..................... DSI ..................... SDA .................... Wet FGD ............ DSI ..................... DSI ..................... SDA .................... Wet FGD ............ DSI ..................... DSI ..................... SDA .................... Wet FGD ............ SO2 reduction (tpy) 90 91.3 94.2 50 90 91.3 94.2 50 * 87.2 87.2 91.5 50 90 92.1 94.7 50 90 92.1 94.7 5,529 5,609 5,787 3,222 5,800 5,884 6,070 3,343 5,832 5,832 6,116 6,712 12,081 12,364 12,717 7,525 13,545 13,862 14,258 2016 Annualized cost 18,071,878 21,689,526 22,555,395 9,865,798 20,229,233 21,812,518 22,530,901 8,963,761 23,090,408 22,697,048 23,998,161 15,002,337 30,865,711 31,195,787 30,735,030 16,014,988 33,302,528 32,758,784 32,215,226 2016 Cost effectiveness ($/ton) 3,269 3,867 3,898 3,062 3,488 3,707 3,712 3,469 3,960 3,892 3,924 2,235 2,555 2,523 2,417 2,128 2,459 2,363 2,259 2016 Incremental costeffectiveness ($/ton) 3,752 45,221 4,864 4,020 18,849 3,862 5,676 N/A 4,581 2,955 1,166 ¥1,305 ........................ 2,872 ¥1,715 ¥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 SO2 scrubber in order to determine if cost-effective scrubber upgrades are available. Of our subjectto-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.88 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.89 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. • The absorber system had either already been upgraded to perform at an SO2 removal efficiency of at least 95%, or it could be upgraded to perform at that level using proven equipment and techniques. • The SO2 scrubber bypass could be eliminated, and the additional flue gas could be treated by the absorber system with at least a 95% removal efficiency. • Additional modifications necessary to eliminate the bypass, such as adding fan capacity, upgrading the electrical distribution system, and conversion to a wet stack could be performed using proven equipment and techniques. • The additional SO2 emission reductions resulting from the scrubber upgrade are substantial, ranging from 68% to 89% reduction from the current emission levels, and are cost-effective. We now update these calculations for 2011–2015 data.90 The revised scrubber upgrade results for Martin Lake Units 1, 2, and 3; and Monticello Unit 3 are presented below in Table 11: TABLE 11—SUMMARY OF UPDATED SCRUBBER UPGRADE RESULTS 2011–2015 3-yr avg. SO2 emissions (eliminate max and min) (tons) mstockstill on DSK3G9T082PROD with PROPOSALS2 Unit SO2 emissions at 95% control (tons) SO2 emissions reduction due to scrubber upgrade (tons) SO2 emission rate at 95% control (lbs/MMBtu) 8,136 19,040 17,973 16,113 1,180 3,208 3,393 2,591 6,956 15,832 14,580 13,522 0.05 0.12 0.12 0.11 Monticello 3 ...................................................................................................... Martin Lake 1 ................................................................................................... Martin Lake 2 ................................................................................................... Martin Lake 3 ................................................................................................... Total SO2 Removed ................................................................................. 88 The CEPCI for 2013 is 567.3 and that for 2015 is 556.3. Therefore, the costs would be multiplied VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 50,890 by a factor of 556.8/567.3, which is approximately 0.98. PO 00000 Frm 00017 Fmt 4701 Sfmt 4700 89 81 FR 318. Coal vs CEM data 2011–2015.xlsx. 90 See E:\FR\FM\04JAP2.SGM 04JAP2 928 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules 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 SO2 30 BOD average below 0.04 lbs/ MMBtu for years at a time.91 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 SO2 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. 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 SO2 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.92 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 facilityspecific 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.93 TABLE 12—SELECTED EIA REPORTED ANNUAL REFINER PETROLEUM PRICES West Texas intermediate crude oil—Cushing Oklahoma ($/bbl) Date mstockstill on DSK3G9T082PROD with PROPOSALS2 2015 2014 2013 2012 2011 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 ................................................................. ................................................................. ................................................................. ................................................................. ................................................................. ................................................................. ................................................................. ................................................................. ................................................................. ................................................................. ................................................................. ................................................................. ................................................................. ................................................................. ................................................................. ................................................................. 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. 91 See our BART FIP TSD for graphs of this data. of these letters and the facilities’ responses are in our docket. We inadvertently did not send the O W Sommers a letter. 92 Copies VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 U.S. no. 2 diesel wholesale/resale price by refiners ($/gallon) 48.66 93.17 97.98 94.05 94.88 79.48 61.95 99.67 72.34 66.05 56.64 41.51 31.08 26.18 25.98 30.38 1.667 2.812 3.028 3.109 3.034 2.214 1.713 2.994 2.203 2.012 1.737 1.187 0.883 0.724 0.784 0.898 • No. 2 fuel oil is available at approximately 3,000 ppm, which roughly corresponds to the sulfur level present in No. 2 fuel oil prior to our implementation of the Ultra-Low-Sulfur Diesel (ULSD) regulations.94 We will use the cost of this fuel oil in constructing a ‘‘medium control’’ annual cost of fuel oil. • No. 2 diesel fuel corresponds to ULSD, with a sulfur content of 15 ppm. We will use the cost of this fuel oil in constructing a ‘‘high control’’ annual cost of fuel oil. 93 EIA Refiner Petroleum Product Prices by Sales Type, available here: http://www.eia.gov/dnav/pet/ pet_pri_refoth_dcu_nus_a.htm; http://www.eia.gov/ dnav/pet/pet_pri_spt_s1_a.htm. PO 00000 Frm 00018 Fmt 4701 U.S. no. 2 fuel oil wholesale/resale price by refiners ($/gallon) Sfmt 4700 1.565 2.741 2.966 3.031 2.907 2.147 1.657 2.745 2.072 1.834 1.623 1.125 0.881 0.694 0.756 0.886 U.S. no. 4 distillate wholesale/resale price by refiners ($/gallon) 1.215 2.333 2.767 2.801 1.561 2.157 1.551 1.395 1.377 1.033 0.793 0.663 0.697 0.778 Having identified a reasonable set of historical and lower sulfur fuel oils, we turned to the matter of establishing SO2 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 SO2, would result in the same value. In other words, the cost-effectiveness in $/ ton is independent of the SO2 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 94 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.’’ E:\FR\FM\04JAP2.SGM 04JAP2 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules SO2. While the above is true, reported data for these units does not match this expectation. This can be illustrated by 929 examining selected EIA and emissions data for the Graham Unit 2: TABLE 13—GRAHAM UNIT 2 EXAMPLE DISCORDANCE IN FUEL OIL BURNED AND REPORTED SO2 Quantity fuel oil burned (bbls) Date (month/year) Mar-02 .......................................................................................................................................... Feb-03 .......................................................................................................................................... Jun-12 .......................................................................................................................................... Jul-12 ........................................................................................................................................... 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 SO2 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 SO2 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 SO2 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 SO2 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 SO2 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 SO2 emissions, we cannot rely on historical SO2 emissions to construct a baseline, because a barrel of fuel oil with a given sulfur content does not result in a consistent reported SO2 value over time. Reported SO2 for month (tons) 9,800 8,400 18,177 5,657 21.614 90.389 0.064 0.07 Reported EIA sulfur content (wt %) 0.65 0.66 0.50 0.50 Instead, we will conduct our costeffectiveness 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.95 Below is the result of that calculation: TABLE 14—COST EFFECTIVENESS OF SWITCHING TO LOWER SULFUR FUEL OILS Cost for 1,000 barrels baseline ($/yr) Level of control Tons reduced for 1,000 barrels $51,030 65,730 70,014 N/A 1.26 2.20 mstockstill on DSK3G9T082PROD with PROPOSALS2 Business as usual (No. 4 distillate $1.215/gal) ............................................... Moderate control (No. 2 fuel oil $1.565/gal) .................................................... High control (ULSD $1.667/gal) ....................................................................... 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 $3,970/ ton—a significant improvement in costeffectiveness. We invite the affected facilities to provide site-specific information for delivery of ULSD. Scrubber Retrofits Elsewhere in our proposal, we conclude that certain types of wet 95 The emission factor (lb/103 gal) used is 150 × S, where S = weight % sulfur, taken from AP 42, Fifth Edition, Volume 1, Chapter 1: External VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 Cost effectiveness for 1,000 barrels ($/ton) N/A 11,218 8,627 Incremental costeffectiveness ($/ton) ........................ ........................ ¥2,756 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 SO2 emissions from any of the gas units, 1,287 tons/year (Graham Unit 2, 2001), results in a SO2 reduction of 1,261 tons/year. The costeffectiveness is then $15,183/ton, which is very high for a SO2 scrubber. In addition, the annual SO2 values for Graham Unit 2 from 2002 to 2015, and the annual SO2 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 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. PO 00000 Frm 00019 Fmt 4701 Sfmt 4700 E:\FR\FM\04JAP2.SGM 04JAP2 930 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules installing SO2 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.96 mstockstill on DSK3G9T082PROD with PROPOSALS2 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.’’ 97 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. Regarding the analysis of non-air quality environmental impacts, the BART Guidelines advise: 98 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 mosteffective 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 96 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. 97 70 FR 39103, 39168 (July 6, 2005), [40 CFR part 51, App. Y.]. 98 70 FR at 39169 (July 6, 2005), [40 CFR part 51, App. Y.]. VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 unusual circumstances at the proposed facility create greater problems than experienced elsewhere, this may provide a basis for the elimination of that control alternative as BART. The SO2 control technologies we considered in our analysis—DSI and scrubbers—are in wide use in the coalfired electricity generation industry. Both technologies add spent reagent to the waste stream already generated by the facilities we analyzed, but do not present any unusual environmental impacts. As discussed below in our cost analyses for DSI and SDA SO2 scrubbers, our cost model includes waste disposal costs in the variable operating costs. Consequently, we believe that with one possible exception, any non-air quality environmental impacts have been adequately considered in our analyses. We are aware that the Harrington facility has instituted a water recycling program and obtains some of its water from the City of Amarillo.99 Due to potential non-air quality concerns, we limit our SO2 control analysis for Harrington to DSI and dry scrubbers. Regarding the remaining useful life, the BART Guidelines advise: 100 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 99 http://www.powermag.com/xcel-energysharrington-generating-station-earns-powder-riverbasin-coal-users-group-award/. 100 70 FR 39103, 39169, [40 CFR part 51, App. Y.]. 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 PO 00000 Frm 00020 Fmt 4701 Sfmt 4700 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. 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 SO2 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 SO2 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 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. E:\FR\FM\04JAP2.SGM 04JAP2 931 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules 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: TABLE 15—VISIBILITY BENEFIT OF RETROFIT CONTROLS: COAL-FIRED UNITS (CAMX MODELING) Visibility impact Facility name Emission unit Class I area Metric Baseline Big Brown ............. Source (Unit 1 and 2) ................. WIMO ................... CACR ................... Unit 1 ........................................... WIMO ................... CACR ................... Unit 2 ........................................... WIMO ................... CACR ................... Monticello ............. Source (Unit 1, 2 and 3) ............. CACR ................... WIMO ................... Unit 1 ........................................... CACR ................... WIMO ................... Unit 2 ........................................... CACR ................... WIMO ................... Coleto Creek ........ Source (Unit 1) ............................ WIMO ................... CACR ................... Harrington 1 ........... Source (Unit 061B & 062B) ........ SACR ................... WIMO ................... Unit 061B .................................... SACR ................... mstockstill on DSK3G9T082PROD with PROPOSALS2 WIMO ................... Unit 062B .................................... SACR ................... WIMO ................... 103 40 CFR 51 Appendix Y, IV.D.5: ‘‘Calculate the model results for each receptor as the change in VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ DSI (50%) 4.017 65 33 3.775 91 57 2.154 33 12 2.016 58 17 2.175 34 12 2.033 58 17 10.498 152 111 5.736 67 40 4.516 79 32 2.241 30 8 4.487 78 30 2.189 30 6 0.845 9 0 0.791 5 0 5.288 13 5 4.928 15 6 2.908 5 1 2.708 6 4 2.998 5 1 2.770 6 4 2.249 33 13 2.539 62 21 1.168 13 1 1.327 22 4 1.181 13 1 1.338 23 4 6.121 107 54 2.769 35 14 3.123 43 16 1.290 10 2 3.065 42 13 1.252 10 2 0.526 1 0 0.458 0 0 4.287 7 1 4.362 11 5 2.322 1 1 2.382 5 2 2.373 1 1 2.407 5 1 deciviews compared against natural visibility conditions.’’ PO 00000 Frm 00021 Fmt 4701 Sfmt 4700 E:\FR\FM\04JAP2.SGM 04JAP2 Visibility benefit WFGD (98%) 0.474 0 0 0.787 4 0 0.245 0 0 0.409 0 0 0.235 0 0 0.391 0 0 2.079 28 8 0.774 4 0 0.733 3 0 0.252 0 0 0.563 1 0 0.186 0 0 0.176 0 0 0.186 0 0 3.235 3 1 3.798 6 4 1.738 1 1 2.065 4 1 1.719 1 1 2.046 4 1 DSI benefit 1.768 32 20 1.236 29 36 0.986 20 11 0.688 36 13 0.994 21 11 0.695 35 13 4.377 45 57 2.968 32 26 1.393 36 16 0.951 20 6 1.422 36 17 0.937 20 4 0.318 8 0 0.333 5 0 1.001 6 4 0.565 4 1 0.586 4 0 0.326 1 2 0.625 4 0 0.363 1 3 WFGD benefit 3.542 65 33 2.988 87 57 1.909 33 12 1.606 58 17 1.940 34 12 1.642 58 17 8.419 124 103 4.962 63 40 3.783 76 32 1.989 30 8 3.924 77 30 2.003 30 6 0.668 9 0 0.606 5 0 2.053 10 4 1.130 9 2 1.170 4 0 0.643 2 3 1.279 4 0 0.723 2 3 932 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules TABLE 15—VISIBILITY BENEFIT OF RETROFIT CONTROLS: COAL-FIRED UNITS (CAMX MODELING)—Continued Visibility impact Facility name Emission unit Class I area Metric Baseline J T Deely .............. Source (Sommers Deely 1&2). 1&2, J T WIMO ................... CACR ................... J T Deely 1 ................................. WIMO ................... BIBE ..................... J T Deely 2 ................................. WIMO ................... CACR ................... W.A. Parish .......... Source (WAP 4, 5, & 6) .............. CACR ................... UPBU ................... WAP 5 ......................................... CACR ................... UPBU ................... WAP 6 ......................................... CACR ................... UPBU ................... Welsh 2 ................. Source (Unit 1 & 2) ..................... CACR ................... MING .................... Unit 1 ........................................... CACR ................... MING .................... Fayette 2 ............... Source (Unit 1 & 2) ..................... CACR ................... WIMO ................... Unit 1 ........................................... CACR ................... mstockstill on DSK3G9T082PROD with PROPOSALS2 WIMO ................... Unit 2 ........................................... CACR ................... WIMO ................... DSI (50%) Visibility benefit WFGD (98%) DSI benefit WFGD benefit Max dv ................. 1.513 0.939 0.814 0.574 0.699 Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ Max dv ................. Days >0.5 dv ........ Days >1.0 dv ........ 47 6 1.423 7 2 0.757 4 0 0.652 2 0 0.632 3 0 0.604 2 0 3.177 54 22 1.994 34 9 1.698 22 8 1.038 11 1 1.648 22 6 1.003 9 1 4.576 92 39 2.544 9 3 2.343 37 8 1.150 2 1 1.894 26 9 1.175 19 2 1.002 9 1 0.609 2 0 0.974 9 0 0.598 2 0 8 0 1.155 3 1 0.449 0 0 0.373 0 0 0.387 0 0 0.490 0 0 2.032 26 9 1.215 14 1 1.052 9 1 0.613 1 0 1.018 8 1 0.591 1 0 .................. .................. .................. .................. .................. .................. 1.659 18 3 0.886 1 0 .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. 1 0 0.905 2 0 0.270 0 0 0.069 0 0 0.334 0 0 0.387 0 0 0.511 1 0 0.234 0 0 0.180 0 0 0.094 0 0 0.156 0 0 0.081 0 0 0.822 3 0 0.570 1 0 0.822 3 0 0.570 1 0 0.903 2 0 0.580 1 0 0.480 0 0 0.306 0 0 0.441 0 0 0.282 0 0 39 6 0.268 4 1 0.307 4 0 0.279 2 0 0.245 3 0 0.114 2 0 1.145 28 13 0.779 20 8 0.646 13 7 0.424 10 1 0.630 14 5 0.412 8 1 .................. .................. .................. .................. .................. .................. 0.684 19 5 0.264 1 1 .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. .................. 46 6 0.518 5 2 0.487 4 0 0.583 2 0 0.298 3 0 0.217 2 0 2.665 53 22 1.760 34 9 1.518 22 8 0.943 11 1 1.492 22 6 0.922 9 1 3.754 89 39 1.973 8 3 1.521 34 8 0.579 1 1 0.991 24 9 0.595 18 2 0.522 9 1 0.302 2 0 0.534 9 0 0.316 2 0 1 Harrington high control scenario for both units is SDA at 95% reduction. 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. 2 Welsh VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 PO 00000 Frm 00022 Fmt 4701 Sfmt 4700 E:\FR\FM\04JAP2.SGM 04JAP2 933 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules TABLE 16—VISIBILITY BENEFIT OF RETROFIT CONTROLS: COAL-FIRED UNITS (CALPUFF MODELING) Visibility impact Facility name Emission unit Class I area Metric DSI (50%) Baseline Big Brown ................ Source (Units 1 and 2). WIMO ...................... CACR ...................... Monticello 1 .............. Source (Unit 1, 2 and 3). CACR ...................... UPBU 4 .................... WIMO ...................... Harrington 2 .............. Source (Units 061B & 062B). SACR ...................... WIMO ...................... Welsh 3 .................... Source (Unit 1) ........ CACR ...................... UPBU ...................... WIMO ...................... Visibility benefit WFGD (98%) DSI benefit WFGD benefit Max dv ..................... 4.27 2.54 0.43 1.73 3.83 Days >0.5 dv Avg. ... Days >1.0 dv Avg. ... Max dv ..................... Days >0.5 dv Avg. ... Days >1.0 dv Avg. ... Max dv ..................... 67.33 42.00 4.03 91.67 60.33 6.57 43.33 21.00 2.41 64.33 30.00 3.68 2.67 1.00 0.47 4.67 0.00 1.70 24.00 21 1.62 27.33 30.33 2.89 64.67 41.00 3.55 87.00 60.33 4.87 Days >0.5 dv Avg. ... Days >1.0 dv Avg. ... Max dv ..................... Days >0.5 dv Avg. ... Days >1.0 dv Avg. ... Max dv ..................... Days >0.5 dv Avg. ... Days >1.0 dv Avg. ... Max dv ..................... 143.67 113.00 3.45 103.00 39.33 3.23 60.00 39.33 1.06 115.00 66.33 1.77 61.00 16.67 1.60 34.67 16.67 0.86 62.33 23.67 0.77 13.67 2.67 0.54 6.00 0.67 0.61 28.67 46.67 1.68 42.00 22.67 1.63 25.33 22.67 0.20 81.33 89.33 2.68 89.33 36.67 2.70 54.00 38.67 0.45 Days >0.5 dv Avg. ... Days >1.0 dv Avg. ... Max dv ..................... Days >0.5 dv Avg. ... Days >1.0 dv Avg. ... Max dv ..................... Days >0.5 dv Avg. ... Days >1.0 dv Avg. ... Max dv ..................... Days >0.5 dv Avg. ... Days >1.0 dv Avg. ... Max dv ..................... Days >0.5 dv Avg. ... Days >1.0 dv Avg. ... 21.00 6.67 1.29 26.00 9.00 1.44 50.33 15.33 0.76 12.00 0.67 0.56 7.33 1.33 15.33 3.00 0.97 15.33 4.67 1.12 32.67 8.00 0.49 4.67 0.00 0.33 2.67 0.33 6.33 0.67 0.55 8.67 1.33 0.72 12.33 2.33 0.22 0.33 0.00 0.15 0.33 0.00 5.67 3.67 0.32 10.67 4.33 0.32 17.67 7.33 0.27 7.33 0.67 0.23 4.67 1.00 14.67 6.00 0.74 17.33 7.67 0.72 38 13.00 0.54 11.67 0.67 0.41 7.00 1.33 1 Monticello’s controlled level is a combination of scrubber upgrades and scrubber install in the facility impact modeling with CALPUFF. high control scenario for both units is SDA at 95% reduction. 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 sourcewide modeling for high control includes a unit 2 shutdown. 4 UPBU = Upper Buffalo Wilderness Area. 2 Harrington 3 Welsh 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) Visibility impact Facility name Emission unit Class I area Metric Baseline Martin Lake .............. Source (Unit 1, 2 & 3). CACR ...................... UPBU ...................... Unit 1 ....................... CACR ...................... mstockstill on DSK3G9T082PROD with PROPOSALS2 UPBU ...................... Unit 2 ....................... CACR ...................... UPBU ...................... Unit 3 ....................... CACR ...................... UPBU ...................... VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 PO 00000 (90%) control Visibility benefit (95%) control (90%) benefit (95%) benefit Max dv ..................... 6.651 4.491 4.321 2.159 2.329 Days >0.5 dv ........... Days >1.0 dv ........... Max dv ..................... Days >0.5 dv ........... Days >1.0 dv ........... Max dv ..................... Days >0.5 dv ........... Days >1.0 dv ........... Max dv ..................... Days >0.5 dv ........... Days >1.0 dv ........... Max dv ..................... Days >0.5 dv ........... Days >1.0 dv ........... Max dv ..................... Days >0.5 dv ........... Days >1.0 dv ........... Max dv ..................... Days >0.5 dv ........... Days >1.0 dv ........... Max dv ..................... Days >0.5 dv ........... 141 99 5.803 99 67 2.633 71 26 2.254 44 10 2.466 68 26 2.189 40 10 2.755 76 29 2.368 46 75 31 2.669 39 11 1.550 17 3 0.867 6 0 1.882 18 3 1.077 6 1 1.682 15 2 0.942 6 56 16 2.528 22 7 1.468 6 1 0.805 3 0 1.811 9 1 1.025 5 1 1.609 6 1 0.890 4 66 68 3.134 60 56 1.083 54 23 1.387 38 10 0.585 50 23 1.112 34 9 1.074 61 27 1.425 40 85 83 3.275 77 60 1.165 65 25 1.449 41 10 0.655 59 25 1.164 35 9 1.146 70 28 1.478 42 Frm 00023 Fmt 4701 Sfmt 4700 E:\FR\FM\04JAP2.SGM 04JAP2 934 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules TABLE 17—VISIBILITY BENEFIT OF SCRUBBER UPGRADES: COAL-FIRED UNITS (CAMX MODELING)—Continued Visibility impact Facility name Emission unit Class I area Metric (90%) control Baseline Monticello ................ Source (Unit 1, 2 and 3). CACR ...................... WIMO ...................... Unit 3 ....................... CACR ...................... WIMO ...................... Visibility benefit (95%) control (90%) benefit (95%) benefit Days >1.0 dv ........... Max dv ..................... 13 10.498 0 6.121 0 2.079 13 4.377 13 8.419 Days >0.5 dv ........... Days >1.0 dv ........... Max dv ..................... Days >0.5 dv ........... Days >1.0 dv ........... Max dv ..................... Days >0.5 dv ........... Days >1.0 dv ........... Max dv ..................... Days >0.5 dv ........... Days >1.0 dv ........... 152 111 5.736 67 40 4.632 79 32 2.282 31 7 107 54 2.769 35 14 0.905 5 0 0.462 0 0 28 8 0.774 4 0 0.914 5 0 0.364 0 0 45 57 2.968 32 26 3.728 74 32 1.820 31 7 124 103 4.962 63 40 3.719 74 32 1.918 31 7 TABLE 18—VISIBILITY BENEFIT OF SCRUBBER UPGRADES: COAL-FIRED UNITS (CALPUFF MODELING) Visibility impact Facility name Emission unit Class I area Metric Baseline Martin Lake Source (Units 1, 2 & 3). CACR ...................... UPBU ...................... Monticello 1 .............. Source (Unit 1, 2 and 3). CACR ...................... UPBU ...................... WIMO ...................... 1 Monticello’s DSI (50%) Visibility benefit WFGD (98%) DSI benefit WFGD benefit Max dv ..................... 4.46 2.27 1.86 2.18 2.60 Days >0.5 dv Avg. ... Days >1.0 dv Avg. ... Max dv ..................... Days >0.5 dv Avg. ... Days >1.0 dv Avg. ... Max dv ..................... 129.67 91.33 2.73 81.67 46.67 6.57 77.33 32.67 1.10 30.33 7.33 3.68 63.00 22.33 0.85 18.67 3.67 1.70 52.33 58.67 1.63 51.33 39.33 2.89 66.67 69.00 1.88 63.00 43.00 4.87 Days >0.5 dv Avg. ... Days >1.0 dv Avg. ... Max dv ..................... Days >0.5 dv Avg. ... Days >1.0 dv Avg. ... Max dv ..................... Days >0.5 dv Avg. ... Days >1.0 dv Avg. ... 143.67 113 3.45 103 39.33 3.23 60 39.33 115 66.33 1.77 61 16.67 1.60 34.67 16.67 62.33 23.67 0.765 13.67 2.67 0.54 6 0.67 28.67 46.67 1.68 42 22.67 1.63 25.33 22.67 81.33 89.33 2.68 89.33 36.67 2.70 54 38.67 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 Baseline visibility impact from source (most impacted Class I area) Emission unit ST2 ......................... Graham Unit 2 ...................... Wilkes Units 1, 2, 3 ............ Newman 1 mstockstill on DSK3G9T082PROD with PROPOSALS2 Stryker Unit 2 ...................... Unit 3 ...................... Unit 4 ...................... Sommers ................ Unit 1 ...................... Calaveras VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 Visibility benefit of 0.3% S fuel oil Visibility benefit of 0.0015% S fuel oil CALPUFF 0.65% S: 0.786 dv @ CACR (Facility). CALPUFF 0.69% S: 1.228 dv @ WIMO (Facility). CALPUFF 0.43% S: 0.698 dv @ CACR (Facility). N/A .......................................... N/A .......................................... N/A .......................................... CAMx: 1.513 dv @ WIMO (Source); 0.106 dv @ CACR (Unit). CALPUFF (0.3% S): 0.263 dv @ CACR (Facility). CALPUFF (0.3% S): 0.465 dv @ WIMO (Facility. CALPUFF (0.1% S): 0.029 dv @ CACR (Facility). N/A .......................................... N/A .......................................... N/A .......................................... 0.004 dv @ CACR .................. CALPUFF: 0.522 dv @ CACR (Facility) CALPUFF: 0.851 dv @ WIMO (Facility) CALPUFF: 0.037 dv @ CACR (Facility) N/A N/A N/A 0.008 dv @ CACR PO 00000 Frm 00024 Fmt 4701 Sfmt 4700 E:\FR\FM\04JAP2.SGM 04JAP2 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules 935 TABLE 19—VISIBILITY BENEFITS FROM LOWER SULFUR FUEL—Continued Facility name 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 CAMx: 1.513 dv @ WIMO (Source); 0.180 dv @ CACR (Unit). 0.023 @ CACR ....................... 0.047 @ CACR Emission unit Sommers ................ Unit 2 ...................... 1 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 SO2 and NOX were covered separately by participation in CSAPR (allowing consideration of PM emissions in isolation). Because of the CSAPR remand and resulting uncertainty regarding SO2 and NOX 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. 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 costeffective increases in the level of control, the Guidelines state it is permissible to rely on MACT standards for purposes of BART.105 Second, with respect to gas-fired units, which have inherently low emissions of PM (as well as SO2), 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 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 gasfired 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 mstockstill on DSK3G9T082PROD with PROPOSALS2 Big Brown ............................... Big Brown ............................... Coleto Creek .......................... Harrington Station .................. Harrington Station .................. J T Deely ................................ J T Deely ................................ Martin Lake ............................ Martin Lake ............................ Martin Lake ............................ Monticello ............................... Monticello ............................... Monticello ............................... Fayette ................................... Fayette ................................... W A Parish ............................. W A Parish ............................. Welsh Power Plant ................. Unit ID 1 2 1 061B 062B 1 2 1 2 3 1 2 3 1 2 WAP5 WAP6 1 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% 104 81 105 70 FR 302 (January 5, 2016). FR 39163–39164. VerDate Sep<11>2014 18:33 Jan 03, 2017 Fuel type (primary) Coal Coal Coal Coal Coal Coal Coal Coal Coal Coal Coal Coal Coal Coal Coal Coal Coal Coal ....................... ....................... ....................... ....................... ....................... ....................... ....................... ....................... ....................... ....................... ....................... ....................... ....................... ....................... ....................... ....................... ....................... ....................... SO2 control(s) PM control(s) ................................................ ................................................ ................................................ ................................................ ................................................ ................................................ ................................................ Wet Limestone ....................... Wet Limestone ....................... Wet Limestone ....................... ................................................ ................................................ Wet Limestone ....................... Wet Limestone ....................... Wet Limestone ....................... ................................................ ................................................ ................................................ Baghouse + Electrostatic Precipitator. Baghouse + Electrostatic Precipitator. Baghouse. Electrostatic Precipitator. Baghouse. Baghouse. Baghouse. Electrostatic Precipitator. Electrostatic Precipitator. Electrostatic Precipitator. Baghouse + Electrostatic Precipitator. Baghouse + Electrostatic Precipitator. Electrostatic Precipitator. Electrostatic Precipitator. Electrostatic Precipitator. Baghouse. Baghouse. Baghouse (Began Nov 15, 2015) + Electrostatic Precipitator. 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 106 70 FR 39165 (‘‘. . . you may skip the remaining analyses in this section, including the visibility analysis . . .’’) Jkt 241001 PO 00000 Frm 00025 Fmt 4701 Sfmt 4700 E:\FR\FM\04JAP2.SGM 04JAP2 936 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules mstockstill on DSK3G9T082PROD with PROPOSALS2 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. 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. We do not calculate the costeffectiveness 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 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. 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. VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 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 coalfired units as part of our FIP. We understand the coal-fired units covered by this proposal to be subject to MATS, but to the extent the units may be following alternate limits that differ from the surrogate PM limits found in MATS, we welcome comments on different, appropriately stringent limits reflective of current control capabilities.112 Because we anticipate that any limit we assign should be achieved by current control capabilities, we propose that compliance can be met at the effective date of the rule. To address periods of startups and shutdowns, we are further proposing that PM BART for these units will 111 77 FR 9304, 9450, 9458 (February 16, 2012) (codified at 40 CFR 60.42 Da(a), 60.50 Da(b)(1)); 40 CFR part 63 Subpart UUUUU—National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units. 112 The various limits are provided at 40 CFR part 63, subpart UUUUU, Table 2 (‘‘Emission Limits for Existing EGUs’’). PO 00000 Frm 00026 Fmt 4701 Sfmt 4700 additionally be met by following the work practice standards specified in 40 CFR part 63, subpart UUUUU, Table 3, and using the relevant definitions in 63.10042. We are proposing that the demonstration of compliance can be satisfied by the methods for demonstrating compliance with filterable PM limits that are specified in 40 CFR part 63, subpart UUUUU, Table 7. However, we would give consideration to commenter-submitted requests for alternate or additional methods of demonstrating compliance. BART Analysis for PM for Gas-Fired Units We note that PM emissions for the gas-only fired units that are subject to BART are inherently low.113 We therefore conclude that PM emissions from natural gas firing is so minimal that the installation of any additional PM controls on the unit would likely achieve very low emissions reductions and have minimal visibility benefits. As there are no appropriate add-on controls and the status quo reflects the most stringent controls, we are proposing to make the requirement to burn pipeline natural gas federally enforceable. We note that in addition to satisfying PM BART, this limitation will also serve to satisfy SO2 BART for these gas-fired units, as well as the fuel-oil units when they fire natural gas. We are proposing that PM and SO2 BART for gas firedunits will limit fuel to pipeline natural gas, as defined at 40 CFR 72.2. The available PM controls for gas units that also burn fuel oil are the same for the coal-fired units. We would expect similar costs for installing a baghouse on a typical gas-fired boiler that occasionally burns fuel oil. Again, our visibility impact modeling indicates that the baseline PM emissions of these units are very small, so we expect that the visibility improvement from the installation of a baghouse to be a small fraction on the order of 1–3% of the visibility impacts from the facility. We are confident that the cost of retrofitting the subject units with a baghouse would be extremely high compared to the visibility benefit for any of the units currently fitted with an ESP. We conclude that the cost of a baghouse does not justify the minimal expected improvement in visibility for these units. Accordingly, we are proposing that the fuel content limits for oil burning that we propose to meet SO2 BART will also satisfy PM BART. 113 AP 42, Fifth Edition, Volume 1, Chapter 1: External Sources, Section 1.4, Natural Gas Combustion, available here: https://www3.epa.gov/ ttn/chief/ap42/ch01/final/c01s04.pdf. E:\FR\FM\04JAP2.SGM 04JAP2 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules Lastly, should our assumptions regarding the frequency and type of fuel oil burned in these units significantly change, we expect that Texas will address such a change appropriately in its SIP, which we will review in the next planning period. D. How, if at all, do issues of ‘‘Grid Reliability’’ relate to the proposed BART determinations? mstockstill on DSK3G9T082PROD with PROPOSALS2 On July 15, 2016, a preliminary order of the Fifth Circuit Court of Appeals took the view that EPA’s TexasOklahoma FIP (81 FR 295, January 5, 2016) gave a ‘‘truncated discussion of grid reliability’’ and additionally stated that ‘‘the agency may not have fulfilled its statutory obligation to consider the energy impacts of the FIP.’’ The Court’s preliminary ruling made particular reference to ‘‘the explicit directive in the [CAA] that implementation plans ‘take[ ] into consideration . . . the energy . . . impacts of compliance,’ 42 U.S.C. 7491(g)(1).’’ 114 Because the BART requirement at issue in this proposal has similar language on energy impacts of compliance appearing at 42 U.S.C. 7491(g)(2), we wish to provide a clear explanation on how grid-related considerations for EGUs could bear on this proposal. First, the BART factor for energy impacts of compliance does not call for the examination of grid reliability considerations from alleged plans to shut down or retire a unit rather than comply with a more stringent emission limit or limits. The language instead calls for consideration of energy impacts from complying by installing retrofit controls on a source that continues in operation. In this regard, our proposal follows the required BART Guidelines for EGUs.115 The Guidelines explain that the energy impacts factor relates to the penalties and benefits that may be associated with the assessment of a control option, e.g., whether (for power penalties) the operation of add-on control technology subtracts from the productive yield of electricity from an EGU (what is sometimes termed an auxiliary or parasitic load).116 It is also 114 EPA Guidance on this statutory language specifically explains that energy impacts are a matter of whether ‘‘energy requirements associated with a control technology result in energy penalties.’’ U.S. EPA, Office of Air Quality Planning and Standards, ‘‘Guidance for Setting Reasonable Progress Goals under the Regional Haze Program,’’ (June 1, 2007 rev), at Page 5–2. 115 The promulgation of the Guidelines was required by 42 U.S.C. 7491(b)(1). Adherence to the Guidelines is mandatory for fossil-fuel fired generating power plants having total generating capacities ‘‘in excess of 750 megawatts.’’ 116 Other CAA provisions requiring consideration of ‘‘energy impacts’’ or ‘‘energy requirements of the VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 useful to note that the statutory text, while using the word ‘‘energy,’’ can apply to sources that do not produce energy or electricity. Thus, the statutory text regarding ‘‘energy impacts’’ of compliance with BART is not confined to the power generating industry and does not dictate that we study grid reliability issues. We have considered whether this topic has any separate relevance to our proposal. Various court filings, news accounts, and industry market reports suggest that some source operators for some Texas BART units may be contemplating unit retirements. The BART Guidelines directly address such scenarios under the ‘‘remaining useful life’’ factor: ‘‘there may be situations where a source operator intends to shut down a source . . . . but wishes to retain the flexibility to continue operating beyond that date in the event, for example, the market conditions change.’’ 117 The Guidelines advise that a source that is willing to assure a permanent stop in operations with a federally- or State-enforceable restriction preventing further operation may obtain a short remaining useful life for BART analysis purposes that could then factor in the overall cost analysis.118 As the Guidelines state, ‘‘Where the remaining useful life is less the than the time period for amortizing costs, you should use this shorter period in your cost calculations.’’ 119 We have no information on enforceable restrictions of this type for any of the units that we propose to be subject to BART. Absent that, we must assume that controls installed on the BART units will experience their full useful life. Affected sources are free to submit information as part of their comments containing appropriate enforceable documentation of shorter remaining useful lives. We note, however, that the Guidelines recognize there may be cases where the installation of controls, even when costeffective, would ‘‘affect the viability of control technology’’ are understood similarly. See, e.g., CAA section 169 (the 1977 ‘‘best available control technology’’ requirement with consideration of ‘‘energy . . . impacts’’); see also CAA section 108 (‘‘energy requirements . . . of the emission control technology; ‘‘energy . . . impact of such processes, procedures, and methods [to reduce or control air pollution’’); section 111 (‘‘taking into account . . . energy requirements’’ of an emission limitation), etc. 117 Id. at 39169–39170. 118 Similar to calculating a mortgage, remaining useful life is used in our cost-effectiveness analysis to calculate the annual cost of a particular control. The longer the remaining useful life, the smaller the total annualized cost, and the more cost-effective the control. 119 Id. at 39169. PO 00000 Frm 00027 Fmt 4701 Sfmt 4700 937 continued plant operations.’’ 120 Under the Guidelines, where there are ‘‘unusual circumstances,’’ we are permitted to take into consideration ‘‘the conditions of the plant and the economic effects of requiring the use of a control technology.’’ 121 If the effects are judged to have a ‘‘severe impact,’’ those effects can be considered in the selection process. In such cases, the Guidelines counsel that any determinations be made with an economic analysis with sufficient detail for public review on the ‘‘specific economic effects, parameters, and reasoning.’’ 122 It is recognized, by the language of the Guidelines, that any such review process may entail the use of sensitive business information that may be confidential. The ADDRESSES section of this proposal explains how to submit confidential information with comments, and when claims of confidential business information, or CBI, are asserted with respect to any information that is submitted, the EPA regulations at 40 CFR part 2, subpart BConfidentiality Business Information apply to protect it. All of that said, the Guidelines also advise that we may ‘‘consider whether other competing plants in the same industry have been required to install BART controls if this information is available.’’ 123 Because Texas EGUs are among the last to have SO2 BART determinations, this information is available. It is indeed the case that other similar EGUs have been required to install the same types of SO2 BART controls that we are proposing as very cost effective.124 We have considered the state of available information on whether the proposed controls could affect the viability of continued plant operations. On this point, we note that we are proposing BART determinations for several units where SO2 control requirements were separately promulgated as part of the TexasOklahoma FIP. These under-controlled EGU sources are: Big Brown 1 and 2; Monticello 1, 2 and 3; Martin Lake 1, 2 and 3; and Coleto Creek 1. In litigation over the reasonable progress FIP, various declarations were filed on the issues of alleged forced closures and alleged reliability impacts. These declarations have been compiled and added to the docket for this rulemaking. 120 70 FR 39103, 39171 (July 6, 2005), [40 CFR part 51, App. Y]. 121 Id. 122 70 FR at 39171. 123 Id. 124 See for instance, the EIA information we present elsewhere in this notice in which we summarize the hundreds of scrubber installations that have been performed on similar EGUs. E:\FR\FM\04JAP2.SGM 04JAP2 mstockstill on DSK3G9T082PROD with PROPOSALS2 938 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules Affairs (OIRA), Office of Management and Budget. This EGU BART proposal is not considered a significant regulatory action under Executive Order 12866, so the proposed action cannot be a ‘‘significant energy action’’ for purposes of Executive Order 13211 on that basis. This proposed action has also not been designated a significant energy action by the Administrator of OIRA, so Executive Order 13211 could not apply under that separate basis. With this proposal, there are no anticipated adverse effects on energy supply, distribution, or use that are meaningful or distinguishable from any other scenario where an EGU is expected to install cost-effective pollution controls required by the CAA. By our review, these declarations do not appropriately inform or substantiate source-specific allegations of ‘‘unusual circumstances’’ that may have a severe impact on plant operations, because they do not offer any site-specific information.125 Thus, we are unable to conclude that the proposed costeffective BART controls would severely impact plant operations. Generalized claims of possible retirements and discussions on attributes of the market design of the Electric Reliability Council of Texas (ERCOT) cannot inform the statutorily required, source-specific BART determinations. As a predicate to studying effects on transmission or reliability as ‘‘unusual circumstances,’’ we would require sitespecific information from any source that would wish for us to potentially consider ‘‘affordability of controls,’’ under the terms specified in the Guidelines. Source owners may submit information, including information claimed to be CBI, for our assessment and consideration to potentially support an economic analysis that might be used in the BART selection process. As suggested by the Guidelines, the information necessary to inform our judgment would likely entail sourcespecific information on ‘‘product prices, the market share, and the profitability of the source.’’ Consideration of such information does not dictate what will be selected as a ‘‘best’’ alternative under the Guidelines, but it will substantiate the likelihood of a retirement scenario that would then give the parameters for: A non-conjectural examination of grid reliability issues; judging the significance or insignificance of such issues; and assessing whether such issues could be avoided through appropriate transmission planning. In sum, unless we are able to substantiate an ‘‘affordability of controls’’ problem for any particular unit and substantiate that a particular unit retirement would not be happening anyway at about the same time, alleged grid reliability impacts are speculative and are not able to inform these required BART determinations. As a final note, we acknowledge Executive Order 13211 (‘‘Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, and Use’’). In cases where it does apply, agencies are ordered to prepare a Statement of Energy Effects for submission to the Administrator of the Office of Information and Regulatory IV. Our Weighing of the Five BART Factors Below we present our reasoning for proposing our BART determinations for 29 EGUs in Texas, based on our analysis and weighing of the Five BART Factors: (1) Proposed SO2 and PM BART determinations for 12 coal-fired units with no SO2 controls, (2) proposed BART SO2 and PM BART determinations for 6 coal-fired units with existing scrubbers, (3) proposed SO2 and PM BART determinations 7 gas-fired units that occasionally burn fuel oil, and (4) proposed PM BART determinations for 4 gas-fired units. In previous sections of this proposal, we have described how we assessed the five BART factors. In no case do we see any instance in which our assessment of energy impacts is a determining factor in assessing BART.126 Also, in no case do we see any instance in which our assessment of the remaining useful life is a determining factor in assessing BART. Should a facility indicate in comments to us that the remaining useful life is less than the 30 years we have assumed in our control cost analyses, and is willing to enter into an enforceable document to that effect, we will adjust our cost-effectiveness calculation accordingly in making our final decision. In two cases, Harrington units 061B and 062B, we have limited our SO2 control analysis for Harrington to DSI and dry scrubbers due to potential non-air quality concerns. In all other instances, we conclude that the cost of compliance, and the visibility benefits of controls are the controlling BART factors in our weighing of the five BART factors. In considering cost-effectiveness and visibility benefit, we do not eliminate 125 Certain statements in declarations from representatives of both Luminant and Coleto Creek, who are the source owners of these facilities, cited compliance planning efforts that would be consistent with continued plant operations. 126 In addition to our assessment of energy impacts, also see our discussion in Section III.D concerning our conclusion that energy impact considerations do not relate to potential electrical grid reliability issues. VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 PO 00000 Frm 00028 Fmt 4701 Sfmt 4700 any controls based solely on the magnitude of the cost-effectiveness value, nor do we use cost-effectiveness as the primary determining factor. Rather, we compare the costeffectiveness to the anticipated visibility benefit, and we take note of any additional considerations.127 Also, in judging the visibility benefit we do not simply examine the highest value for a given Class I area, or a group of Class I areas, but we also consider the cumulative visibility benefit for all affected Class I areas, the number of days in a calendar year in which we see significant improvements, and other factors.128 First, we note that all of the sources addressed in our proposed BART determinations have already been shown to cause or contribute to visibility impairment at a Class I area as a condition of being subject-to-BART as part of the BART screening analysis. This analysis eliminated any BARTeligible source that emits lower amounts of visibility impacting pollutants, or otherwise impacts any Class I area at less than 0.5 deciviews. In fact, all of the individual units that we are proposing for BART controls exceed 0.5 deciviews on a unit basis, with most exceeding 1.0 deciview impact on a unit basis. As a consequence, all of the units we are proposing for BART controls are among the largest emitters of visibility impacting pollutants in Texas. A number of these units (i.e., Big Brown, Martin Lake, Monticello, and Coleto Creek) were previously determined by us to require the same type and level of controls under the reasonable progress and long-term strategy provisions of the Regional Haze Rule that we are proposing here.129 Second, not discounting our approach of considering both cost-effectiveness and visibility benefit in unison, the costeffectiveness of all of the controls that form the basis of our proposed BART determinations are within a range found to be acceptable in other cases.130 As we 127 For instance, as we discuss later in Section IV.C why we believe that there are certain mitigating factors that should be considered when assessing BART for the gas-fired units that occasionally burn fuel oil. 128 See for example 70 39130: ‘‘comparison thresholds can be used in a number of ways in evaluating visibility improvement (e.g. the number of days or hours that the threshold was exceeded, a single threshold for determining whether a change in impacts is significant, a threshold representing an x percent change in improvement, etc.).’’ 129 See our recent Texas-Oklahoma FIP, 81 FR 321. 130 See for instance 79 FR 5048 (January 30, 2014): Jim Bridger BART determination of LNB/ SOFA + SCR on Units 1–4; 77 FR 18070 (March 26, 2012): EPA proposed approval of Colorado’s BART E:\FR\FM\04JAP2.SGM 04JAP2 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules stated in the BART Rule, ‘‘[a] reasonable range would be a range that is consistent with the range of cost effectiveness values used in other similar permit decisions over a period of time.’’ 131 A. SO2 BART for Coal-fired Units With No SO2 Controls As we have discussed in this proposal and in our TSD, we have assumed two DSI control levels corresponding to 50% control and either a maximum of 80% or 90% control, depending on the particulate matter control device in use.132 We did this to address the BART Guidelines directive that in evaluating technically feasible alternatives we ‘‘(1) [ensure we] express the degree of control using a metric that ensures an ‘‘apples to apples’’ comparison of emissions performance levels among options, and (2) [give] appropriate treatment and consideration of control techniques that can operate over a wide range of emission performance levels.’’ 133 In most cases, the costeffectiveness of the higher control level of DSI was higher than either SDA or wet FGD. This was not the case for Monticello Unit 2; Harrington Unit 062B; and J T Deely Units 1 and 2. However, these maximum DSI control levels are theoretical and we believe that any DSI control level above 50% must be confirmed by onsite testing before we could propose a BART control based on it. As is evident in comparing the 50% control level to the higher control level, the cost-effectiveness of DSI worsens (higher $/ton) as the control level increases, and the certainty of any unit attaining that control level decreases. We therefore regard the costeffectiveness values of the maximum DSI control levels as being useful in a basic comparison of cost-effectiveness between DSI and scrubbers, but we place much less weight on these values. We therefore conclude that given the uncertainty concerning the maximum control level of DSI, the greater control efficiency and resulting visibility benefit offered by scrubbers overrides any possible advantage DSI may hold in cost-effectiveness. Should the affected facilities provide site-specific information to us in their comments that conflicts with this assumption, we will incorporate it into our final decision on SO2 BART and potentially re-evaluate DSI. As we indicate elsewhere in our proposal, both SDA and wet FGD are mature technologies that are in wide use throughout the United States. We are not aware of any unusual circumstances that exist for any of the sources that would serve to indicate they should not be viewed similarly to these hundreds of previous scrubber retrofits. In comparing wet FGD versus SDA we note that in a number of cases the costeffectiveness of wet FGD is lower than the cost-effectiveness of SDA. In the remaining cases, we conclude that the incremental cost-effectiveness of wet FGD over SDA, which we review in Section III.C.3.a is reasonable, and the improved control and visibility benefit offered by wet FGD overrides the small penalty in cost-effectiveness FGD has in comparison to SDA. We propose that with the exception of the Harrington units, SO2 BART for all other coal-fired units should be based on the wet FGD control levels we have used in our BART analyses. We propose that SO2 BART for the Harrington units should be based on the SDA control levels we have used in our BART analyses. Below we discuss our consideration of the cost-effectiveness and anticipated visibility benefits of controls. See section III.C.5 for additional information on the anticipated visibility benefits from each level of control modeled. See the BART Modeling TSD for a complete 939 summary of our visibility benefit analysis of controls, including modeled benefits and impacts at all Class I areas included in the modeling analyses and additional metrics considered in the assessment of visibility benefits. CAMx model results shown in the tables below summarize the benefits from the recommended controls at the two Class I areas most impacted by the source or unit in the baseline modeling. The benefit is calculated as the difference between the maximum impact modeled for the baseline and the maximum impact level modeled under the control scenario. Also summarized are the cumulative benefit and the number of days impacted over 0.5 and 1.0 dv. Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and control scenario summed across the 15 Class I areas included in the CAMx modeling. The baseline total cumulative number of days over 0.5 (1.0) dv is calculated as the sum of the number of modeled days at each of the 15 Class I area impacted over the threshold in the baseline modeling. The reduction in number of days is calculated as the sum of the number of days over the chosen threshold across the 15 Class I areas included in the CAMx modeling for the baseline scenario subtracted by the number of days over the threshold for the control scenario. The CALPUFF cumulative model results only consider those Class I areas within the typical range of CALPUFF and not all 15 Class I areas included in the CAMx modeling. 1. Big Brown 1 & 2 In reviewing the Big Brown units, we conclude that the installation of wet FGD will result in very significant visibility benefits. We summarize some of these visibility benefits in the tables below: TABLE 21—WET FGD VISIBILITY BENEFITS AT BIG BROWN (CALPUFF) Improvement at Wichita Mountains (dv) Source Big Brown Units 1 & 2 ......................................................... Improvement at Caney Creek (dv) 3.83 Total cumulative visibility benefit (dv) 1 3.55 7.38 Cumulative reduction in number of days above 0.5 dv 2 151.67 mstockstill on DSK3G9T082PROD with PROPOSALS2 1 Cumulative Cumulative reduction in number of days above 1.0 dv 2 101.33 benefit is calculated as the difference in the maximum visibility impacts from the baseline and control scenario runs summed across the following Class I areas: Caney Creek and Wichita Mountains. 2 Using the three years (2001–2003) of CALPUFF modeling results an annual average of the number of days reduced was calculated. The Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across the following Class I areas for the baseline scenario subtracted by the number of days over the threshold for the control scenario: Caney Creek and Wichita Mountains. determination of SCR for Hayden Unit 2, later finalized at 77 FR 76871 (December 31, 2012). 131 70 FR 39168 (July 6, 2005). VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 132 Note for Harrington Unit 062B and Welsh 1, we further limited the maximum DSI control level to that of our calculated SDA control level. PO 00000 Frm 00029 Fmt 4701 Sfmt 4700 133 70 E:\FR\FM\04JAP2.SGM FR 39166 (July 6, 2005). 04JAP2 940 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules In evaluating Big Brown, we note there are two Class I areas within the typical range that CALPUFF has been used for assessing visibility impacts. Using the three years of 2001–2003 CALPUFF modeling results, we assessed the annual average number of days when the facility impacts were greater than 0.5 del-dv at each of the Class I areas and then summed this value for each of the Class I areas to yield an annual average cumulative value for total number of days impacts were above 0.5 del-dv at all Class I areas within typical CALPUFF range. The reduction in the number of days (annual average) was calculated as the cumulative value of the number of days over the 0.5 del-dv threshold across the Class I areas for the baseline scenario subtracted by the cumulative number of days over the threshold for the control scenario. For the two Class I areas that are within the range that CALPUFF is typically used, the 2001–2003 CALPUFF modeling results indicate that wet FGD on both units will eliminate 151.6 days annually (3 year average) when the facility has impacts greater than 0.5 delta deciview. The same analysis was also calculated using a 1.0 del-dv threshold and is reported in the table above. DSI operated at 50% control results in approximately half of the visibility benefits in terms of dv benefits at the most impacted Class I areas and about 1/3rd to half the cumulative benefits over the class I areas included in the modeling analysis. TABLE 22—WET FGD VISIBILITY BENEFITS AT BIG BROWN (CAMX) Improvement at Wichita Mountains (dv) Unit Big Brown 1 ......................................................................... Big Brown 2 ......................................................................... Source .................................................................................. Improvement at Caney Creek (dv) 1.909 1.940 3.542 Total cumulative visibility benefit (dv)1 1.606 1.642 2.988 Baseline total cumulative number of days over 0.5/1.0 dv 2 12.728 12.924 24.274 174/44 175/45 372/170 Reduction in number of days above 0.5/1.0 dv 3 174/44 175/45 362/170 1 Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and control scenario runs summed across 15 Class I areas included in the CAMx modeling. 2 Baseline Total Cumulative number of days over 0.5 (1.0) dv is calculated as the sum of the number of modeled days at each of the 15 Class I area impacted over the threshold. 3 Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across the 15 Class I areas included in the CAMx modeling for the baseline scenario subtracted by the number of days over the threshold for the control scenario. CAMx modeling results indicate that wet FGD will eliminate all days impacted over 1dv at all Class I areas on a unit and source-wide basis, and eliminate all but 10 days across the impacted Class I areas where the sourcewide impacts exceeds 0.5 dv. At the most impacted Class I area, wet FGD will on each unit result in visibility improvements of 1.9 dv on the most impacted day. DSI operated at 50% control results in approximately half of the wet FGD visibility benefits at the most impacted Class I areas and half of the cumulative benefits over the 15 class I areas included in the CAMx modeling. We also conclude that wet FGD is very cost-effective for both units at less than $1,200/ton and more cost-effective than DSI. Based on this consideration of the BART factors, we propose that SO2 BART for Big Brown Units 1 and 2 should be based on the installation of wet FGD at an emission limit of 0.04 lbs/MMBtu based on a 30 BOD. 2. Monticello 1 & 2 Similar to the Big Brown units, the installation of wet FGD at Monticello Units 1 and 2 will result in very significant visibility benefits. We summarize some of these visibility benefits in the tables below: TABLE 23—WET FGD VISIBILITY BENEFITS AT MONTICELLO (CALPUFF) Improvement at Caney Creek (dv) Source Monticello Units 1, 2 & 3 ..................................................... Improvement at Wichita Mountains (dv) 4.87 Total cumulative visibility benefit (dv) 1 2.70 10.25 Baseline total cumulative number of days over 0.5/1.0 dv 2 224.67 Cumulative reduction in number of days above 1.0 dv 2 164.67 mstockstill on DSK3G9T082PROD with PROPOSALS2 1 Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and control scenario runs summed across the following Class I areas: Caney Creek, Wichita Mountains, and Upper Buffalo. 2 Using the three years (2001–2003) of CALPUFF modeling results an annual average of the number of days reduced was calculated. The Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across the following Class I areas for the baseline scenario subtracted by the number of days over the threshold for the control scenario: Caney Creek, Wichita Mountains, and Upper Buffalo. In evaluating Monticello, we note there are three Class I areas within the typical range that CALPUFF has been used for assessing visibility impacts. Using the three years of 2001–2003 CALPUFF modeling results we assessed the annual average number of days when the facility impacts were greater than 0.5 del-dv at each of the Class I VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 areas and then summed this value for each of the Class I areas to yield an annual average cumulative value for total number of days impacts were above 0.5 del-dv at all Class I areas within typical CALPUFF range. The reduction in the number of days (annual average) was calculated as the cumulative value of the number of days PO 00000 Frm 00030 Fmt 4701 Sfmt 4700 over the 0.5 del-dv threshold across the Class I areas for the baseline scenario subtracted by the cumulative number of days over the threshold for the control scenario. For the three Class I areas that are within the range that CALPUFF is typically used, the 2001–2003 CALPUFF modeling results indicate wet FGD on both units will eliminate 224.6 E:\FR\FM\04JAP2.SGM 04JAP2 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules days annually (3 year average) when the facility has impacts greater than 0.5 delta deciview. The same analysis was also calculated using a 1.0 del-dv threshold and is reported in the table above. DSI operated at 50% control results in approximately half of the wet FGD visibility benefits at the most 941 impacted Class I area and half of the cumulative benefits. TABLE 24—WET FGD VISIBILITY BENEFITS AT MONTICELLO (CAMX) Improvement at Caney Creek (dv) Unit Monticello 1 .......................................................................... Monticello 2 .......................................................................... Source (including unit 3) ...................................................... Improvement at Wichita Mountains (dv) 3.783 3.924 8.419 Total cumulative visibility benefit (dv) 1 1.989 2.003 4.962 Baseline total cumulative number of days over 0.5/1.0 dv 2 12.708 13.025 31.553 197/67 192/57 520/293 Reduction in number of days above 0.5/1.0 dv 3 191/67 191/57 460/278 1 Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and control scenario runs summed across 15 Class I areas included in the CAMx modeling. 2 Baseline Total Cumulative number of days over 0.5 (1.0) dv is calculated as the sum of the number of modeled days at each of the 15 Class I area impacted over the threshold. 3 Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across the 15 Class I areas included in the CAMx modeling for the baseline scenario subtracted by the number of days over the threshold for the control scenario. CAMx modeling results indicate that wet FGD will eliminate all days impacted over 1 dv at all Class I areas on a unit basis, and eliminate all but 15 days across the impacted Class I areas where the source-wide impacts exceeds 1 dv. We note that source-wide modeled benefits include benefits of 95% control scrubber upgrade on Unit 3. At the most impacted Class I area, wet FGD on each unit will each result in visibility improvements of 3.8–3.9 dv on the most impacted day at Caney Creek and 2 dv visibility benefits at Wichita Mountains. DSI operated at 50% control results in less than half of the wet FGD visibility benefits at the most impacted Class I areas and half of the cumulative benefits over the 15 class I areas included in the modeling. The wet FGD cost-effectiveness of $2,718/ton and $3,031/ton are higher than those for Big Brown, but these figures remain well within a range that we have previously found to be acceptable for BART, and we consider the very significant visibility benefits that will result justify the cost of wet FGD at the Monticello Units 1 and 2. The 50% control DSI cost-effectiveness is slightly less than that for wet-FGD, but results in much less visibility benefits. Based on our consideration of the BART factors, we therefore propose that SO2 BART for Monticello Units 1 and 2 should be based on the installation of wet FGD at an emission limit of 0.04 lbs/MMBtu based on a 30 BOD. 3. Coleto Creek 1 In reviewing Coleto Creek Unit 1, we conclude that in comparison with the Monticello units, the installation of a wet FGD is more cost-effective and results in lesser, but still significant visibility benefits. We summarize some of these visibility benefits in the table below: TABLE 25—WET FGD VISIBILITY BENEFITS AT COLETO CREEK UNIT 1 (CAMX) Improvement at Wichita Mountains (dv) Unit Coleto Creek 1 ..................................................................... Improvement at Caney Creek (dv) 0.668 Total cumulative visibility benefit (dv) 1 0.606 5.233 Baseline total cumulative number of days over 0.5/1.0 dv 2 17/0 Reduction in number of days above 0.5/1.0 dv 3 17/0 mstockstill on DSK3G9T082PROD with PROPOSALS2 1 Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and control scenario runs summed across 15 Class I areas included in the CAMx modeling. 2 Baseline Total Cumulative number of days over 0.5 (1.0) dv is calculated as the sum of the number of modeled days at each of the 15 Class I area impacted over the threshold. 3 Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across the 15 Class I areas included in the CAMx modeling for the baseline scenario subtracted by the number of days over the threshold for the control scenario. CAMx modeling results indicate that wet FGD will eliminate all days impacted over 0.5 dv at all Class I areas. At the most impacted Class I area, wet FGD will result in visibility improvements of 0.6 or more on the most impacted days at both Caney Creek and the Wichita Mountains. In addition, seven other Class I areas are improved by amounts ranging from 0.356 to 0.531 dv on the maximum impacted days with wet FGD. DSI operated at 50% control VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 results in approximately half of the wet FGD visibility benefits at the most impacted Class I areas and half of the cumulative benefits over the 15 Class I areas included in the modeling. We also conclude that wet FGD is very cost-effective at $2,127/ton and well within a range that we have previously found to be acceptable and more cost-effective than DSI. We consider the significant visibility benefits that will result justify the cost PO 00000 Frm 00031 Fmt 4701 Sfmt 4700 of wet FGD at the Coleto Creek Unit 1. We therefore propose that SO2 BART for Coleto Creek Unit 1 should be based on the installation of wet FGD at an emission limit of 0.04 lbs/MMBtu based on a 30 BOD. 4. Welsh 1 In reviewing Welsh Unit 1, we conclude that the installation of a wet FGD will result in significant visibility E:\FR\FM\04JAP2.SGM 04JAP2 942 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules benefits. We summarize some of these visibility benefits in the tables below: TABLE 26—WET FGD VISIBILITY BENEFITS AT WELSH UNIT 1 (CALPUFF) Improvement at Caney Creek (dv) Source Welsh 1 ................................................................................ Improvement at Wichita Mtns. (dv) 0.72 Cumulative reduction in number of days above 0.5 dv 2 Total cumulative visibility benefit (dv) 1 0.41 1.66 56.67 Cumulative reduction in number of days above 1.0 dv 2 15 1 Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and control scenario runs summed across the following Class I areas: Caney Creek, Wichita Mountains, and Upper Buffalo. 2 Using the three years (2001–2003) of CALPUFF modeling results an annual average of the number of days reduced was calculated. The reduction in number of days is calculated as the sum of the number of days over the chosen threshold across the following Class I areas for the baseline scenario subtracted by the number of days over the threshold for the control scenario: Caney Creek, Wichita Mountains, and Upper Buffalo. In evaluating Welsh we note there are three Class I areas within the typical range that CALPUFF has been used for assessing visibility impacts. Using the three years of 2001–2003 CALPUFF modeling results we assessed the annual average number of days when the facility impacts were greater than 0.5 del-dv at each of the Class I areas and then summed this value for each of the Class I areas to yield an annual average cumulative value for total number of days impacts were above 0.5 del-dv at all Class I areas within typical CALPUFF range. The reduction in the number of days (annual average) was calculated as the cumulative value of the number of days over the 0.5 del-dv threshold across the Class I areas for the baseline scenario subtracted by the cumulative number of days over the threshold for the control scenario. For the three Class I areas that are within the range that CALPUFF is typically used, the 2001–2003 CALPUFF modeling results indicate wet FGD on both units will eliminate 56.67 days annually (3 year average) when the facility has impacts greater than 0.5 delta deciview. The same analysis was also calculated using a 1.0 del-dv threshold and is reported in the table above. CALPUFF modeling indicates that DSI operated at 50% results in approximately half the benefits of WGFD. TABLE 27—WET FGD VISIBILITY BENEFITS AT WELSH UNIT 1 (CAMX) Improvement at Caney Creek (dv) Unit Welsh 1 ................................................................................ Source (Welsh 1 & 2) .......................................................... Improvement at Mingo Wilderness (dv) 1.521 3.754 Total cumulative visibility benefit (dv) 1 0.579 1.973 4.683 13.179 Baseline total cumulative number of days over 0.5/1.0 dv 2 65/9 211/72 Reduction in number of days above 0.5/1.0 dv 3 60/9 206/72 mstockstill on DSK3G9T082PROD with PROPOSALS2 1 Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and control scenario runs summed across 15 Class I areas included in the CAMx modeling. 2 Baseline Total Cumulative number of days over 0.5 (1.0) dv is calculated as the sum of the number of modeled days at each of the 15 Class I area impacted over the threshold. 3 Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across the 15 Class I areas included in the CAMx modeling for the baseline scenario subtracted by the number of days over the threshold for the control scenario. CAMx modeling results indicate that wet FGD on unit 1 will eliminate all days impacted by the unit over 1 dv at all Class I areas and all but 5 days impacted over 0.5 dv. At the most impacted Class I area, wet FGD on unit 1 will result in visibility improvements of 1.521 dv on the most impacted days at Caney Creek. In addition to the visibility benefits at Caney Creek and Mingo, visibility benefits at two additional Class I areas exceed 0.5 dv. We note that source-wide benefits shown include the benefits from the shutdown of unit 2. In addition, cumulative benefits from wet FGD on VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 unit 1 over all 15 Class I areas exceeds 4.5 dv on the maximum impacted days. DSI operated at 50% control results in approximately half of the wet FGD visibility benefits at the most impacted Class I areas and half of the cumulative benefits over the 15 class I areas included in the modeling. We conclude that although at $3,824/ ton, the cost-effectiveness of wet FGD is higher than for other facilities, it remains within a range that we have previously found to be acceptable. We consider the significant visibility benefits that will result from the installation of wet FGD at Welsh Unit 1 PO 00000 Frm 00032 Fmt 4701 Sfmt 4700 to justify the cost. DSI at 50% control is slightly more cost-effective but results in much less visibility benefit. We therefore propose that SO2 BART for Welsh Unit 1 should be based on the installation of wet FGD at an emission limit of 0.04 lbs/MMBtu based on a 30 BOD. 5. Harrington 061B & 062B In reviewing Harrington, we conclude that the installation of SDA on Units 061B and 062B will result in significant visibility benefits. We summarize some of these visibility benefits in the tables below: E:\FR\FM\04JAP2.SGM 04JAP2 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules 943 TABLE 28—SDA VISIBILITY BENEFITS AT HARRINGTON (CALPUFF) Improvement at Salt Creek (dv) Source Harrington 061B & 062B ...................................................... Improvement at Wichita Mtns. (dv) 0.45 Total cumulative visibility benefit (dv) 1 0.74 2.56 Cumulative reduction in number of days above 0.5 dv 2 53.67 Cumulative reduction in number of days above 1.0 dv 2 26 1 Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and control scenario runs summed across the following Class I areas: Salt Creek, Wichita Mountains, Pecos, Carlsbad Caverns, and Wheeler Peak. 2 Using the three years (2001–2003) of CALPUFF modeling results an annual average of the number of days reduced was calculated. The reduction in number of days is calculated as the sum of the number of days over the chosen threshold across the following Class I areas for the baseline scenario subtracted by the number of days over the threshold for the control scenario: Salt Creek, Wichita Mountains, Pecos, Carlsbad Caverns, and Wheeler Peak. In evaluating Harrington we note there are five Class I areas within the typical range that CALPUFF has been used for assessing visibility impacts. Using the three years of 2001–2003 CALPUFF modeling results we assessed the annual average number of days when the facility impacts were greater than 0.5 del-dv at each of the Class I areas and then summed this value for each of the Class I areas to yield an annual average cumulative value for total number of days impacts were above 0.5 del-dv at all Class I areas within typical CALPUFF range. The reduction in the number of days (annual average) was calculated as the cumulative value of the number of days over the 0.5 del-dv threshold across the Class I areas for the baseline scenario subtracted by the cumulative number of days over the threshold for the control scenario. For the five Class I areas that are within the range that CALPUFF is typically used, the 2001–2003 CALPUFF modeling results indicate wet FGD on both units will eliminate 53.6 days annually (3 year average) when the facility has impacts greater than 0.5 delta deciview. The same analysis was also calculated using a 1.0 del-dv threshold and is reported in the table above. CALPUFF modeling indicates that DSI operated at 50% results in approximately half the benefits of WGFD. TABLE 29—SDA VISIBILITY BENEFITS AT HARRINGTON (CAMX) Improvement at Salt Creek (dv) Unit Harrington 061B ................................................................... Harrington 062B ................................................................... Source (061B & 0622B) ....................................................... Improvement at Wichita Mountains (dv) 1.170 1.279 2.053 Total cumulative visibility benefit (dv) 1 0.643 0.723 1.130 4.832 5.379 9.329 Baseline total cumulative number of days over 0.5/1.0 dv 2 17/5 17/5 51/17 Reduction in number of days above 0.5/1.0 dv 3 11/3 11/3 37/11 mstockstill on DSK3G9T082PROD with PROPOSALS2 1 Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and control scenario runs summed across 15 Class I areas included in the CAMx modeling. 2 Baseline Total Cumulative number of days over 0.5 (1.0) dv is calculated as the sum of the number of modeled days at each of the 15 Class I area impacted over the threshold. 3 Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across the 15 Class I areas included in the CAMx modeling for the baseline scenario subtracted by the number of days over the threshold for the control scenario. CAMx modeling results indicate SDA on these units will eliminate more than half of all days impacted by the units over 1 dv and 0.5 dv at all Class I areas. At the most impacted Class I areas, SDA on each unit will each result in visibility improvements of approximately 1.2 dv on the most impacted days at Salt Creek and 0.6–0.7 dv at Wichita Mountains, reducing the number of days impacted over 0.5 and 1.0 dv at these Class I areas. In addition, cumulative benefits from SDA on both units over all 15 Class I areas exceeds 9.3 dv on the maximum impacted days. VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 DSI operated at 50% control results in approximately half of the SDA visibility benefits at the most impacted Class I areas and half of the cumulative benefits over the 15 class I areas included in the modeling. We also conclude that SDA is costeffective at $3,904 for Unit 061B and $4,180/ton for Unit 062B and, remains within a range that we have previously found to be acceptable. In contrast to other units we have reviewed, the 50% control DSI cost-effectiveness is much less than that for SDA. However, given the additional large total cumulative visibility benefits that will result from PO 00000 Frm 00033 Fmt 4701 Sfmt 4700 the installation of SDA over DSI at 50% control, we consider SDA to justify the additional cost. We therefore propose that SO2 BART for Harrington Units 061B and 062B should be based on the installation of SDA at an emission limit of 0.06 lbs/MMBtu based on a 30 BOD. 6. W. A. Parish WAP 5 & 6 In reviewing W A Parish, we conclude that the installation of wet FGD on Units 5 and 6 will result in significant visibility benefits. We summarize some of these visibility benefits in the tables below: E:\FR\FM\04JAP2.SGM 04JAP2 944 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules TABLE 30—WET FGD VISIBILITY BENEFITS AT W A PARISH (CAMX) Improvement at Caney Creek (dv) Unit W A Parish 5 ........................................................................ W A Parish 6 ........................................................................ Source (WAP 4, 5 & 6) ........................................................ Improvement at Upper Buffalo (dv) 1.518 1.492 2.665 Total cumulative visibility benefit (dv) 1 0.943 0.922 1.760 Baseline total cumulative number of days over 0.5/1.0 dv 2 8.171 7.979 15.301 51/9 48/7 163/49 Reduction in number of days above 0.5/1.0 dv 3 51/9 48/7 162/49 1 Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and control scenario runs summed across 15 Class I areas included in the CAMx modeling. 2 Baseline Total Cumulative number of days over 0.5 (1.0) dv is calculated as the sum of the number of modeled days at each of the 15 Class I area impacted over the threshold. 3 Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across the 15 Class I areas included in the CAMx modeling for the baseline scenario subtracted by the number of days over the threshold for the control scenario. CAMx modeling results indicate that wet FGD on each of these units will eliminate all days impacted by each unit over 1 dv and 0.5 dv at all Class I areas. At the most impacted Class I areas, wet FGD on each unit will each result in visibility improvements of approximately 1.5 dv on the most impacted days at Caney Creek and 0.9 dv at Upper Buffalo. Nine Class I areas have modeled source-wide baseline impacts over 1 dv, and wet FGD on both units results in source-wide improvements of 1 dv or greater on the maximum impacted days at eight of these Class I areas. In addition, cumulative benefits from wet FGD on both units over all 15 Class I areas exceeds 15 dv on the maximum impacted days. DSI operated at 50% control results in approximately half of the wet FGD visibility benefits at the most impacted Class I areas and half of the cumulative benefits over the 15 class I areas included in the modeling. We note that source-wide modeling includes a small impact from WAP 4. This unit is gas-fired and was modeled at baseline emissions levels for both the baseline and control case scenarios. We conclude that wet FGD is costeffective at $2,417/ton for Unit 5 and $2,259/ton for Unit 6, and remains well within a range that we have previously found to be acceptable. DSI at 50% control is approximately the same cost- effectiveness but results in significantly less visibility benefit. We consider the cost of wet FGD at the W A Parish units to be justified by the significant visibility benefits that will result. We therefore propose that SO2 BART for W A Parish Units 5 and 6 should be based on the installation of wet FGD at an emission limit of 0.04 lbs/MMBtu based on a 30 BOD. 7. J T Deely 1 & 2 In reviewing J T Deely, we conclude that the installation of wet FGD on Units 1 and 2 will result in significant visibility benefits. We summarize some of these visibility benefits in the tables below: TABLE 31—WET FGD VISIBILITY BENEFITS AT J T DEELY (CAMX) Improvement at Wichita Mountains (dv) Unit J T Deely 1 .......................................................................... J T Deely 2 .......................................................................... Source (J T Deely 1 & 2, Sommers 1 & 2) ......................... Improvement at Caney Creek (dv) 0.487 0.298 0.699 Total cumulative visibility benefit (dv) 1 0.283 0.217 0.518 4.785 3.650 8.943 Baseline total cumulative number of days over 0.5/1.0 dv 2 10/0 7/0 89/13 Reduction in number of days above 0.5/1.0 dv 3 10/0 7/0 84/13 mstockstill on DSK3G9T082PROD with PROPOSALS2 1 Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and control scenario runs summed across 15 Class I areas included in the CAMx modeling. 2 Baseline Total Cumulative number of days over 0.5 (1.0) dv is calculated as the sum of the number of modeled days at each of the 15 Class I area impacted over the threshold. 3 Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across the 15 Class I areas included in the CAMx modeling for the baseline scenario subtracted by the number of days over the threshold for the control scenario. CAMx modeling results indicate wet FGD on each of these units will eliminate all days impacted by each unit over 0.5 dv at all Class I areas. At the most impacted Class I areas, wet FGD on each unit will each result in visibility improvements of 0.487 dv and 0.298 dv on the most impacted days at Wichita Mountains and 0.283 dv and 0.217 dv at Caney Creek. Larger visibility improvements on the most impacted days are anticipated at other Class I areas. Benefits from wet FGD on unit 1 are 0.583 dv at Big Bend, 0.511 dv at VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 Salt Creek, 0.449 dv at Guadalupe Mountains and Carlsbad Caverns, and 0.475 dv at White Mountains. Benefits from wet FGD on unit 2 are 0.583 dv at Big Bend, 0.441 dv at Salt Creek, 0.354 dv at Guadalupe Mountains and Carlsbad Caverns, and 0.375 dv at White Mountains. DSI operated at 50% control results in approximately half of the wet FGD visibility benefits at the most impacted Class I areas and half of the cumulative benefits over the 15 Class I areas included in the modeling. We note that source-wide modeling includes the PO 00000 Frm 00034 Fmt 4701 Sfmt 4700 impact from Sommers units 1 and 2, and as discussed in the BART Modeling TSD, control case scenarios for these units included benefits from switching to lower sulfur fuel oil. However, these modeled improvements are a small fraction of the total visibility benefits from controls at the source. We conclude that wet FGD is costeffective at $3,898/ton for Unit 1 and $3,712/ton for Unit 2, and remains within a range that we have previously found to be acceptable. We consider the cost of wet FGD at the J T Deely units E:\FR\FM\04JAP2.SGM 04JAP2 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules to be justified by the significant visibility benefits that will result at a number of impacted Class I areas. DSI at 50% control is slightly more costeffective but results in much less visibility benefit. We therefore propose that SO2 BART for J T Deely Units 1 and 2 should be based on the installation of wet FGD at an emission limit of 0.04 lbs/MMBtu based on a 30 BOD.134 B. SO2 BART for Coal-fired Units With Underperforming Scrubbers The BART Guidelines state that underperforming scrubber systems should be evaluated for upgrades.135 Other than upgrading the existing scrubbers, all of which are wet FGDs, there are no competing control technologies that could be considered 945 for these units. The CALPUFF modeling generated facility-wide impacts and the benefits of the scrubber upgrade on Monticello Unit 3 and the three Martin Lake facilities are included in Table 17 above. The following is a listing of each of the affected units along with the resulting CAMx modeled visibility benefits from upgrading their existing scrubbers: TABLE 32—VISIBILITY BENEFIT FOR COAL-FIRED UNITS WITH EXISTING SO2 CONTROLS (CAMX) Unit Improvement at most impacted (dv) Improvement at 2nd most impacted (dv) Monticello 3 .......................................................................... Martin Lake 1 ....................................................................... Martin Lake 2 ....................................................................... Martin Lake 3 ....................................................................... 3.719 ( CACR) 1.165 (CACR) 0.655 (CACR) 1.146 (CACR) 1.918 (WIMO) 1.449 (UPBU) 1.164 (UPBU) 1.478 (UPBU) As we state elsewhere in this proposal, because our cost-effectiveness calculations depend 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 conclude that in all cases, scrubber upgrades are very cost-effective and result in very significant visibility benefits, significantly reducing the impacts from these units and reducing the number of days that Class I areas are impacted over 1.0 dv and 0.5 dv. We propose that SO2 BART for all other coal-fired units with underperforming scrubbers should be based on the wet FGD upgrade control levels we have used in our BART analyses of them. mstockstill on DSK3G9T082PROD with PROPOSALS2 Total cumulative visibility benefit (dv) C. SO2 BART for Gas-Fired Units That Burn Oil In analyzing potential controls for those gas-fired units that occasionally burn fuel oil we considered scrubber retrofits and lower sulfur fuel oil. We concluded that the cost-effectiveness of scrubber retrofits for these units were likely very high, and not worth the potential visibility benefit. We also concluded that the costeffectiveness of switching to a No. 2 fuel oil with a sulfur content of 0.3% is $11,218/gallon, and the costeffectiveness of switching to ULSD with a sulfur content of 0.0015% is $8,627/ gallon. We further noted that one facility already had a contract in place for ULSD at a lower price than we 134 We have read reports that CPS Energy, is planning to retire J T Deely Units 1 and 2 by the end of 2018, but we have no enforceable documents to that effect. 135 70 FR 39171 (July 6, 2005). VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 11.940 7.575 6.199 7.863 Reduction in number of days above 0.5 dv at—— 200/66 160/41 150/41 173/47 Reduction in number of days above 1.0 dv at—— 188/66 151/40 134/39 163/46 assumed, which if used in our analysis would result in a cost effectiveness of $3,970/ton. Although the costeffectiveness of switching to a lower sulfur oil (assuming our price for ULSD of $1.667/gal) is higher than other controls that we have typically required under BART, we note certain mitigating factors. For instance, arguing against control, our calculated cost-effectiveness values are high in relation to other BART controls we have required in the past. Also, our visibility modeling necessarily utilized the maximum SO2 emissions over a 24-hour timeframe,136 resulting in the configuring of our visibility modeling to analyze the maximum short-term potential impacts that could occur when the unit burns fuel oil. However, as we discuss elsewhere in our proposal, these units are primarily gas-fired, and have only occasionally burned fuel oil. Their most recent practices appear to reinforce this trend. Arguing for control, unlike the wet FGD and SDA scrubbers we have costed in other sections of this TSD, which have large capital costs, we are unaware of any significant capital costs involved in switching fuels. This means the overall annual costs are relatively minor, if the units in question adhere to their historical usages. Also, because the units in question have only occasionally burned fuel oil, they have the option to avoid the cost of fuel switching entirely by not continuing to burn fuel oil and instead relying solely on their primary fuel of natural gas. Lastly, we note that the prevalence of ULSD in the fuel oil market is such that it appears to be gradually replacing most other No. 2 fuel oil applications.137 The preamble to the Regional Haze Rule counseled that a one percent sulfur content limitation on fuel oil should be considered as a ‘‘starting point,’’ 138 and the existing sulfur content limits are lower than one percent. Considering all of this information, we propose that SO2 BART for the gas-fired units that occasionally burn fuel oil should be no further control. In so doing, we acknowledge the data quality issues we have discussed concerning these units and we specifically request comments on all aspects of our proposed BART analysis for these units from all interested parties. Based on the comments we receive, we may either finalize our BART determinations for these units as proposed, or we may revise them without a re-proposal. 136 See the BART Guidelines at 70 FR 39162, July 6, 2005: ‘‘We 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 start-up, shutdown, or malfunction.’’ 137 http://www.eia.gov/todayinenergy/ detail.php?id=5890. http://blogs.platts.com/2014/ 05/07/heating-oil-new-york-sulfur/. http:// oilandenergyonline.com/challenges-to-thenortheast-supply-picture/. 138 70 FR at 39134. PO 00000 Frm 00035 Fmt 4701 Sfmt 4700 D. PM BART We propose to disapprove the portion of the Texas Regional Haze SIP that sought to address the BART requirement for EGUs for PM. We note that all of the coal-fired units are either currently fitted with a baghouse, an ESP and a polishing baghouse, or an ESP. We conclude that the cost of retrofitting the subject units with a baghouse would be extremely high compared to the visibility benefit for any of the units currently fitted with an ESP. E:\FR\FM\04JAP2.SGM 04JAP2 946 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules Consequently, we propose that PM BART for the coal-fired units is an emission limit of 0.030 lb/MMBtu along with work practice standards. We propose that PM and SO2 BART for the units that only fire gas be pipeline natural gas. We propose that PM and SO2 BART for those gas-fired units that occasionally burn fuel oil be the existing permitted fuel oil sulfur content of 0.7% sulfur by weight or pipeline natural gas. V. Proposed Actions A. Regional Haze We are proposing to disapprove the portion of the Texas Regional Haze SIP that sought to address the BART requirement for EGUs for PM. We are proposing to promulgate a FIP as described in this notice and summarized in this section to satisfy the remaining outstanding regional haze requirements that are unmet by the Texas’ regional haze SIP and that we did not take action on in our January 5, 2016 final action.139 Our proposed FIP includes SO2 and PM BART emission limits for sources in Texas to reduce emissions that contribute to regional haze in Texas’ two Class I areas and other nearby Class I areas and make reasonable progress for the first regional haze planning period for Texas’ two Class I areas. 1. NOX BART mstockstill on DSK3G9T082PROD with PROPOSALS2 As discussed elsewhere in this proposal, we are proposing a FIP to replace Texas’ reliance on CAIR with reliance on CSAPR to address the NOX BART requirements for EGUs. This portion of our proposal is based on: The recent update to the CSAPR rule; 140 and the EPA’s finalization of a separate proposed finding that the EPA’s actions in response to the D.C. Circuit’s remand would not adversely impact our 2012 demonstration that CSAPR is better than BART.141 We cannot finalize this portion of the proposed FIP unless and until the EPA finalizes the proposed finding that CSAPR continues to be better than BART because finalization of that proposal would allow for reliance on CSAPR participation as an alternative to source-specific EGU BART for NOX in Texas. 2. SO2 BART for Coal-Fired Units We propose that SO2 BART for the coal-fired units be the following SO2 emission limits to be met on a 30 Boiler Operating Day (BOD) period: 139 81 FR 296. FR 74504. 141 81 FR 78954. 140 81 VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 accurately quantify, our calculations of TABLE 33—PROPOSED SO2 BART EMISSIONS LIMITS FOR COAL-FIRED scrubber efficiency may contain some error. Based on the results of our UNITS Proposed SO2 emission limit (lbs/MMBtu) Unit Scrubber Upgrades Martin Lake 1 ................ Martin Lake 2 ................ Martin Lake 3 ................ Monticello 3 ................... Scrubber Retrofits Big Brown 1 ................... Big Brown 2 ................... Monticello 1 ................... Monticello 2 ................... Coleto Creek 1 .............. Fayette 1 ....................... Fayette 2 ....................... Harrington 061B ............ Harrington 062B ............ J T Deely 1 .................... J T Deely 2 .................... W A Parish 5 ................. W A Parish 6 ................. Welsh 1 ......................... 0.12 0.12 0.11 0.05 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.06 0.06 0.04 0.04 0.04 0.04 0.04 We propose that compliance with these limits be within five years of the effective date of our final rule for Big Brown Units 1 and 2; Monticello Units 1 and 2; Coleto Creek Unit 1; Harrington Units 061B and 062B; J T Deely Units 1 and 2; W A Parish Units 5 and 6; and Welsh Unit 1. This is the maximum amount of time allowed under the Regional Haze Rule for BART compliance. We based our cost analysis on the installation of wet FGD and SDA scrubbers for these units, and in the past we have typically required that scrubber retrofits under BART be operational within five years. We propose that compliance with these limits be within three years of the effective date of our final rule for Martin Lake Units 1, 2, and 3; and Monticello Unit 3. We believe that three years is appropriate for these units, as we based our cost analysis on upgrading the existing wet FGD scrubbers of these units, which we believe to be less complex and time consuming that the construction of a new scrubber. We propose that compliance with these limits be within one year for Fayette Units 1 and 2. We believe that one year is appropriate for these units because the Fayette units have already demonstrated their ability to meet these emission limits. 3. Potential Process for Alternative Scrubber Upgrade Emission Limits In our BART FIP TSD, we discuss how we calculated the SO2 removal efficiency of the units we analyzed for scrubber upgrades. We note that due to a number of factors we could not PO 00000 Frm 00036 Fmt 4701 Sfmt 4700 scrubber upgrade cost analysis, we do not believe that any reasonable error in calculating the true tons of SO2 removed affects our proposed decision to require emission reductions, as all of the scrubber upgrades we analyzed are costeffective (low $/ton). In other words, were we to make reasonable adjustments in the tons removed to account for any potential error in our scrubber efficiency calculation, we would still propose to upgrade these SO2 scrubbers. We believe we have demonstrated that upgrading an underperforming SO2 scrubber is one of the most cost-effective pollution control upgrades a coal fired power plant can implement to improve the visibility at Class I areas. However, our proposed FIP does specify a SO2 emission limit that is based on 95% removal in all cases. This is below the upper end of what an upgraded wet SO2 scrubber can achieve, which is 98–99%, as we have noted in our BART FIP TSD. We believe that a 95% control assumption provides an adequate margin of error for any of the units for which we have proposed scrubber upgrades, such that they should be able to comfortably attain the emission limits we have proposed. However, for the operator of any unit that disagrees with us on this point, we propose the following: (1) The affected unit should comment why it believes it cannot attain the SO2 emission limit we have proposed, based on a scrubber upgrade that includes the kinds of improvements (e.g., elimination of bypass, wet stack conversion, installation of trays or rings, upgraded spray headers, upgraded ID fans, using all recycle pumps, etc.) typically included in a scrubber upgrade. (2) After considering those comments, and responding to all relevant comments in a final rulemaking action, should we still require a scrubber upgrade in our final FIP we will provide the company the following option in the FIP to seek a revised emission limit after taking the following steps: (a) Install a CEMS at the inlet to the scrubber. (b) Pre-approval of a scrubber upgrade plan conducted by a third party engineering firm that considers the kinds of improvements (e.g., elimination of bypass, wet stack conversion, installation of trays or rings, upgraded spray headers, upgraded ID fans, using all recycle pumps, etc.) typically performed during a scrubber upgrade. The goal of this plan will be to maximize the unit’s overall SO2 removal efficiency. E:\FR\FM\04JAP2.SGM 04JAP2 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules (c) Installation of the scrubber upgrades. (d) Pre-approval of a performance testing plan, followed by the performance testing itself. (e) A pre-approved schedule for 2.a through 2.d. (f) Should we determine that a revision of the SO2 emission limit is appropriate, we will have to propose a modification to the BART FIP after it has been promulgated. It should be noted that any proposal to modify the SO2 emission limit will be based largely on the performance testing and may result in a proposed increase or decrease of that value. 4. SO2 BART for Gas-fired Units That Burn Oil We propose that SO2 BART for the following gas-fired units that occasionally burn fuel oil be the existing permit limits for the sulfur content of the fuel oil: TABLE 34—PROPOSED BART SO2 EMISSION LIMITS GAS UNITS THAT OCCASIONALLY BURN OIL Fuel Oil Sulfur Content (percent by weight) Facility Graham 2 .............................. Newman 2 * .......................... Newman 3 * .......................... O W Sommers 1 ................... O W Sommers 2 ................... Stryker Creek ST2 ................ Wilkes 1 ................................ 947 5. PM BART We propose that PM BART limits for the coal units, Big Brown Units 1 and 2; Monticello Units 1, 2, and 3; Martin Lake Units 1, 2, and 3; Coleto Creek Unit 1; J T Deely Units 1 and 2; W A Parish Units 5 and 6; Welsh Unit 1; Harrington Units 061B and 062B; and Fayette Units 1 and 2 are 0.030 lb/ MMBtu and work practice standards, which we present below: 0.7 0.7 0.7 0.7 0.7 0.7 0.7 * The Newman Units 2 and 3 are further limited to burning fuel oil for no more than 876 hours per year. TABLE 35—PM BART EMISSIONS STANDARDS AND WORK PRACTICE STANDARDS Unit Type PM BART Proposal Coal-Fired BART Units ............................................................................. Gas-Fired Only BART Units ..................................................................... Oil-Fired BART Units when not firing natural gas .................................... We propose that compliance with these emissions standards and work practice standards be the effective date of our final rule, as the affected facilities’ should already be meeting them. We propose that PM and SO2 BART for the units that only fire gas, Newman Unit 4; W A Parish Unit 4; and Wilkes Units 2 and 3 be pipeline natural gas. We propose that PM and SO2 BART for those gas-fired units that occasionally burn fuel oil, Newman Unit 2 and 3; O W Sommers Units 1 and 2; Stryker Creek Unit ST2; and Wilkes Unit 1 be the existing permitted fuel oil sulfur content of 0.7% sulfur by weight. mstockstill on DSK3G9T082PROD with PROPOSALS2 B. Interstate Visibility Transport We are proposing to disapprove Texas’ SIP revisions addressing interstate visibility transport under CAA section 110(a)(2)(D)(i)(II) for six NAAQS. We further are proposing a FIP to fully address Texas’ interstate visibility transport obligations for: (1) 1997 8-hour ozone, (2) 1997 PM2.5 (annual and 24 hour), (3) 2006 PM2.5 (24-hour), (4) 2008 8-hour ozone, (5) 2010 1-hour NO2 and (6) 2010 1-hour SO2. The proposed FIP is based on the finding that our proposed action to fully address the Texas Regional Haze BART program is adequate to ensure that emissions from Texas do not interfere with measures to protect visibility in VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 0.03 lb/MMBtu filterable PM Table 3 to Subpart UUUUU Pipeline quality natural gas Fuel Content not to exceed 0.7% sulfur by weight (also SO2 BART) nearby states in accordance with CAA section 110(a)(2)(D)(i)(II). VI. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Overview This proposed action is not a ‘‘significant regulatory action’’ under the terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is therefore not subject to review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011). The proposed FIP would not constitute a rule of general applicability, because it only proposes source specific requirements for particular, identified facilities (8 total). B. Paperwork Reduction Act This proposed action does not impose an information collection burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. Section 3501 et seq. Because it does not contain any information collection activities, the Paperwork Reduction Act does not apply. See 5 CFR 1320(c). C. Regulatory Flexibility Act The Regulatory Flexibility Act (RFA) generally requires an agency to conduct a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements unless the PO 00000 Frm 00037 Fmt 4701 Sfmt 4700 agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small not-for-profit enterprises, and small governmental jurisdictions. For purposes of assessing the impacts of today’s rule on small entities, small entity is defined as: (1) A small business as defined by the Small Business Administration’s (SBA) regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field. After considering the economic impacts of today’s proposed rule on small entities, I certify that this action will not have a significant impact on a substantial number of small entities. In making this determination, the impact of concern is any significant adverse economic impact on small entities. An agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, has no net burden or otherwise has a positive economic effect on the small entities subject to the rule. This rule does not impose any requirements or E:\FR\FM\04JAP2.SGM 04JAP2 948 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules mstockstill on DSK3G9T082PROD with PROPOSALS2 create impacts on small entities. This proposed FIP action under Section 110 of the CAA will not create any new requirement with which small entities must comply. This action, when finalized, will apply to 14 facilities owned by 8 companies, none of which are small entities. Accordingly, it affords no opportunity for the EPA to fashion for small entities less burdensome compliance or reporting requirements or timetables or exemptions from all or part of the rule. The fact that the CAA prescribes that various consequences (e.g., emission limitations) may or will flow from this action does not mean that the EPA either can or must conduct a regulatory flexibility analysis for this action. We have therefore concluded that, this action will have no net regulatory burden for all directly regulated small entities. D. Unfunded Mandates Reform Act Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104–4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on state, local, and Tribal governments and the private sector. Under Section 202 of UMRA, EPA generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with ‘‘Federal mandates’’ that may result in expenditures to state, local, and Tribal governments, in the aggregate, or to the private sector, of $100 million or more (adjusted for inflation) in any one year. Before promulgating an EPA rule for which a written statement is needed, Section 205 of UMRA generally requires EPA to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most costeffective, or least burdensome alternative that achieves the objectives of the rule. The provisions of Section 205 of UMRA do not apply when they are inconsistent with applicable law. Moreover, Section 205 of UMRA allows EPA to adopt an alternative other than the least costly, most cost-effective, or least burdensome alternative if the Administrator publishes with the final rule an explanation why that alternative was not adopted. Before EPA establishes any regulatory requirements that may significantly or uniquely affect small governments, including Tribal governments, it must have developed under Section 203 of UMRA a small government agency plan. The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 the development of EPA regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements. EPA has determined that Title II of UMRA does not apply to this proposed rule. In 2 U.S.C. Section 1502(1) all terms in Title II of UMRA have the meanings set forth in 2 U.S.C. Section 658, which further provides that the terms ‘‘regulation’’ and ‘‘rule’’ have the meanings set forth in 5 U.S.C. Section 601(2). Under 5 U.S.C. Section 601(2), ‘‘the term ‘rule’ does not include a rule of particular applicability relating to . . . facilities.’’ Because this proposed rule is a rule of particular applicability relating to 12 named facilities, EPA has determined that it is not a ‘‘rule’’ for the purposes of Title II of UMRA. E. Executive Order 13132: Federalism This proposed action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government. F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments This proposed rule does not have tribal implications, as specified in Executive Order 13175. It will not have substantial direct effects on tribal governments. Thus, Executive Order 13175 does not apply to this rule. G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks 142 applies to any rule that: (1) Is determined to be economically significant as defined under Executive Order 12866; and (2) concerns an environmental health or safety risk that we have reason to believe may have a disproportionate effect on children. EPA interprets EO 13045 as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under Section 5–501 of the EO has the potential to influence the regulation. This action is not subject to Executive Order 13045 because it is not economically significant as defined in Executive Order 12866, and because the EPA does not believe the environmental health or safety risks addressed by this 142 62 PO 00000 FR 19885 (Apr. 23, 1997). Frm 00038 Fmt 4701 Sfmt 4700 action present a disproportionate risk to children. This action is not subject to EO 13045 because it implements specific standards established by Congress in statutes. However, to the extent this proposed rule will limit emissions of SO2, NOX, and PM, the rule will have a beneficial effect on children’s health by reducing air pollution. H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use This proposed action is not subject to Executive Order 13211 (66 FR 28355 (May 22, 2001)), because it is not a significant regulatory action under Executive Order 12866. I. National Technology Transfer and Advancement Act Section 12 of the National Technology Transfer and Advancement Act (NTTAA) of 1995 requires Federal agencies to evaluate existing technical standards when developing a new regulation. To comply with NTTAA, EPA must consider and use ‘‘voluntary consensus standards’’ (VCS) if available and applicable when developing programs and policies unless doing so would be inconsistent with applicable law or otherwise impractical. EPA believes that VCS are inapplicable to this action. Today’s action does not require the public to perform activities conducive to the use of VCS. J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations Executive Order 12898 (59 FR 7629, February 16, 1994), establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States. We have determined that this proposed rule, if finalized, will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority or low-income population. E:\FR\FM\04JAP2.SGM 04JAP2 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules This proposed federal rule limits emissions of NOX, SO2, and PM from 14 facilities in Texas. List of Subjects in 40 CFR Part 52 Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Nitrogen dioxide, Ozone, Particulate matter, Reporting and recordkeeping requirements, Sulfur dioxides, Visibility, Interstate transport of pollution, Regional haze, Best available control technology. Dated: December 9, 2016. Ron Curry, Regional Administrator, Region 6. Title 40, chapter I, of the Code of Federal Regulations is proposed to be amended as follows: PART 52—APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS 1. The authority citation for part 52 continues to read as follows: ■ Authority: 42 U.S.C. 7401 et seq. Subpart SS—Texas 2. Section 52.2287 is added to read as follows: ■ § 52.2287 Best Available Retrofit Requirements (BART) for SO2 and Particulate Matter and Interstate pollutant transport provisions; What are the FIP requirements for visibility protection? (a) Applicability. The provisions of this section shall apply to each owner or operator, or successive owners or operators, of the coal or natural gas burning equipment designated below. (b) Definitions. All terms used in this part but not defined herein shall have the meaning given them in the CAA and in parts 51 and 60 of this title. For the purposes of this section: 24-hour period means the period of time between 12:01 a.m. and 12 midnight. Air pollution control equipment includes selective catalytic control units, baghouses, particulate or gaseous scrubbers, and any other apparatus utilized to control emissions of regulated air contaminants that would be emitted to the atmosphere. Boiler-operating-day means any 24hour period between 12:00 midnight and the following midnight during which any fuel is combusted at any time at the steam generating unit. Daily average means the arithmetic average of the hourly values measured in a 24-hour period. Heat input means heat derived from combustion of fuel in a unit and does not include the heat input from preheated combustion air, recirculated flue gases, or exhaust gases from other sources. Heat input shall be calculated in accordance with 40 CFR part 75. Owner or Operator means any person who owns, leases, operates, controls, or supervises any of the coal or natural gas burning equipment designated below. PM means particulate matter. Regional Administrator means the Regional Administrator of EPA Region 6 or his/her authorized representative. Unit means one of the natural gas, gas and/or fuel oil, or coal-fired units covered in this section. (c) Emissions limitations and compliance dates for SO2. The owner/ operator of the units listed below shall not emit or cause to be emitted pollutants in excess of the following limitations from the subject unit. Compliance with the requirements of this section is required as listed below unless otherwise indicated by compliance dates contained in specific provisions. Proposed SO2 emission limit (lbs/MMBtu) Unit mstockstill on DSK3G9T082PROD with PROPOSALS2 Martin Lake 1 ........................................................................................................................................................... Martin Lake 2 ........................................................................................................................................................... Martin Lake 3 ........................................................................................................................................................... Monticello 3 .............................................................................................................................................................. Big Brown 1 ............................................................................................................................................................. Big Brown 2 ............................................................................................................................................................. Monticello 1 .............................................................................................................................................................. Monticello 2 .............................................................................................................................................................. Coleto Creek 1 ......................................................................................................................................................... Fayette 1 .................................................................................................................................................................. Fayette 2 .................................................................................................................................................................. Harrington 061B ....................................................................................................................................................... Harrington 062B ....................................................................................................................................................... J T Deely 1 .............................................................................................................................................................. J T Deely 2 .............................................................................................................................................................. W A Parish 5 ........................................................................................................................................................... W A Parish 6 ........................................................................................................................................................... Welsh 1 .................................................................................................................................................................... (d) Emissions limitations and compliance dates for PM. The owner/ operator of the units listed below shall not emit or cause to be emitted pollutants in excess of the following limitations from the subject unit. Compliance with the requirements of this section is required as listed below unless otherwise indicated by VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 compliance dates contained in specific provisions. (1) Coal-Fired Units at Big Brown Units 1 and 2; Monticello Units 1, 2, and 3; Martin Lake Units 1, 2, and 3; Coleto Creek Unit 1; J T Deely Units 1 and 2; W A Parish Units 5 and 6; Welsh Unit 1; Harrington Units 061B and 062B; and Fayette Units 1 and 2. PO 00000 Frm 00039 Fmt 4701 Sfmt 4700 949 0.12 0.12 0.11 0.05 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.06 0.06 0.04 0.04 0.04 0.04 0.04 Compliance date (from the effective date of the final rule) (years) 3 3 3 3 5 5 5 5 5 1 1 5 5 5 5 5 5 5 (i) Normal operations: Filterable PM limit of 0.030 lb/MMBtu. (ii) Work practice standards specified in 40 CFR part 63, subpart UUUUU, Table 3, and using the relevant definitions in 63.10042. (2) Gas-Fired Units at Newman Unit 4; Wilkes Units 2 and 3; and W A Parish Unit 4 shall burn only pipeline natural gas, as defined in 40 CFR 72.1 E:\FR\FM\04JAP2.SGM 04JAP2 950 Federal Register / Vol. 82, No. 2 / Wednesday, January 4, 2017 / Proposed Rules mstockstill on DSK3G9T082PROD with PROPOSALS2 (3) Gas-fired units that also burn fuel oil at Graham Unit 2; Newman Units 2 and 3; O W Sommers Units 1 and 2; Stryker Creek Unit ST2; and Wilkes shall burn 0.7% sulfur content fuel or pipeline natural gas, as defined in 40 CFR 72.1. (4) Compliance for the units included in Section (d) shall be as of the effective date of the final rule. (e) Testing and monitoring. (1) No later than the compliance date of this regulation, the owner or operator shall install, calibrate, maintain and operate Continuous Emissions Monitoring Systems (CEMS) for SO2 on the units covered under paragraph (c) of this section. Compliance with the emission limits for SO2 shall be determined by using data from a CEMS. (2) Continuous emissions monitoring shall apply during all periods of operation of the coal or natural gas burning equipment, including periods of startup, shutdown, and malfunction, except for CEMS breakdowns, repairs, calibration checks, and zero and span adjustments. Continuous monitoring systems for measuring SO2 and diluent gas shall complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period. Hourly averages shall be computed using at least one data point in each fifteen minute quadrant of an hour. Notwithstanding this requirement, an hourly average may be computed from at least two data points separated by a minimum of 15 minutes (where the unit operates for more than one quadrant in an hour) if data are unavailable as a result of performance of calibration, quality assurance, preventive maintenance activities, or backups of data from data acquisition and handling system, and recertification events. When valid SO2 pounds per hour, or SO2 pounds per million Btu emission data are not obtained because of continuous monitoring system breakdowns, repairs, calibration checks, VerDate Sep<11>2014 18:33 Jan 03, 2017 Jkt 241001 or zero and span adjustments, emission data must be obtained by using other monitoring systems approved by the EPA to provide emission data for a minimum of 18 hours in each 24 hour period and at least 22 out of 30 successive boiler operating days. (3) Compliance with the PM emission limits for units in paragraph (d)(1) shall be demonstrated by the filterable PM methods specified in 40 CFR part 63, subpart UUUUU, Table 7. (f) Reporting and recordkeeping requirements. Unless otherwise stated all requests, reports, submittals, notifications, and other communications to the Regional Administrator required by this section shall be submitted, unless instructed otherwise, to the Director, Multimedia Division, U.S. Environmental Protection Agency, Region 6, to the attention of Mail Code: 6MM, at 1445 Ross Avenue, Suite 1200, Dallas, Texas 75202–2733. For each unit subject to the emissions limitation in this section and upon completion of the installation of CEMS as required in this section, the owner or operator shall comply with the following requirements: (1) For SO2 each emissions limit in this section, comply with the notification, reporting, and recordkeeping requirements for CEMS compliance monitoring in 40 CFR 60.7(c) and (d). (2) For each day, provide the total SO2 emitted that day by each emission unit. For any hours on any unit where data for hourly pounds or heat input is missing, identify the unit number and monitoring device that did not produce valid data that caused the missing hour. (3) Records for demonstrating compliance with the SO2 and PM emission limitations in this section shall be maintained for at least five years. (g) Equipment operations. At all times, including periods of startup, shutdown, and malfunction, the owner or operator shall, to the extent PO 00000 Frm 00040 Fmt 4701 Sfmt 9990 practicable, maintain and operate the unit including associated air pollution control equipment in a manner consistent with good air pollution control practices for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Regional Administrator which may include, but is not limited to, monitoring results, review of operating and maintenance procedures, and inspection of the unit. (h) Enforcement. (1) Notwithstanding any other provision in this implementation plan, any credible evidence or information relevant as to whether the unit would have been in compliance with applicable requirements if the appropriate performance or compliance test had been performed, can be used to establish whether or not the owner or operator has violated or is in violation of any standard or applicable emission limit in the plan. (2) Emissions in excess of the level of the applicable emission limit or requirement that occur due to a malfunction shall constitute a violation of the applicable emission limit. ■ 3. In § 52.2304, paragraph (f) is added to read as follows: § 52.2304 Visibility protection. * * * * * (f) Measures addressing disapproval associated with NOX, SO2, and PM. (1) The deficiencies associated with NOX identified in EPA’s disapproval of the regional haze plan submitted by Texas on March 31, 2009, are satisfied by Section 52.2283. (2) The deficiencies associated with SO2 and PM identified in EPA’s disapproval of the regional haze plan submitted by Texas on March 31, 2009, are satisfied by Section 52.2287. [FR Doc. 2016–30713 Filed 1–3–17; 8:45 am] BILLING CODE 6560–50–P E:\FR\FM\04JAP2.SGM 04JAP2

Agencies

[Federal Register Volume 82, Number 2 (Wednesday, January 4, 2017)]
[Proposed Rules]
[Pages 912-950]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-30713]



[[Page 911]]

Vol. 82

Wednesday,

No. 2

January 4, 2017

Part II





Environmental Protection Agency





-----------------------------------------------------------------------





40 CFR Part 52





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

Federal Register / Vol. 82 , No. 2 / Wednesday, January 4, 2017 / 
Proposed Rules

[[Page 912]]


-----------------------------------------------------------------------

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 SO2 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 SO2. To address the requirement for 
NOX 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 NOX 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

[[Page 913]]

    C. Our Authority To Promulgate a FIP
III. Our Proposed BART Analyses for SO2 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 SO2 Retrofit 
Controls
    a. Identification of Technically Feasible SO2 
Retrofit Control Technologies for Coal Fired Units
    b. Identification of Technically Feasible SO2 
Retrofit Control Technologies for Gas-Fired Units That Burn Oil
    c. Identification of Technically Feasible SO2 Control 
Technologies for Scrubber Upgrades
    2. Step 3: Evaluation of Control Effectiveness
    a. Evaluation of SO2 Control Effectiveness for Coal 
Fired Units
    b. Evaluation of SO2 Control Effectiveness for Gas 
Fired Units
    3. Step 4: Evaluate Impacts and Document the Results for 
SO2
    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. SO2 BART for Coal-fired Units With no 
SO2 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. SO2 BART for Coal-fired Units With Underperforming 
Scrubbers
    C. SO2 BART for Gas-fired Units That Burn Oil
    D. PM BART
V. Proposed Actions
    A. Regional Haze
    1. NOX BART
    2. SO2 BART for Coal-fired Units
    3. Potential Process for Alternative Scrubber Upgrade Emission 
Limits
    4. SO2 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 (PM2.5) (e.g., 
sulfates, nitrates, Organic Carbon (OC), Elemental Carbon (EC), and 
soil dust), and their precursors (e.g., Sulfur Dioxide 
(SO2), Nitrogen Oxides (NOX), and in some cases, 
ammonia (NH3) and Volatile Organic Compounds (VOCs)). Fine 
particle precursors react in the atmosphere to form PM2.5, 
which impairs visibility by scattering and absorbing light. Visibility 
impairment reduces the clarity, color, and visible distance that can be 
seen. PM2.5 can also cause serious health effects and 
mortality in humans and contributes to environmental effects such as 
acid deposition and eutrophication.
    Data from the existing visibility monitoring network, the 
``Interagency Monitoring of Protected Visual Environments'' (IMPROVE) 
monitoring network, show that visibility impairment caused by air 
pollution occurs virtually all the time at most national parks and 
wilderness areas. In 1999, the average visual range \1\ in many Class I 
areas (i.e., national parks and memorial parks, wilderness areas, and 
international parks meeting certain size criteria) in the western 
United States was 100-150 kilometers, or about 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.\2\ CAA programs have reduced some haze-causing pollution, 
lessening some visibility impairment and resulting in partially 
improved average visual ranges.\3\
---------------------------------------------------------------------------

    \1\ Visual range is the greatest distance, in kilometers or 
miles, at which a dark object can be viewed against the sky.
    \2\ 64 FR 35715 (July 1, 1999).
    \3\ 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.\4\ On December 2, 1980, EPA 
promulgated regulations to address visibility impairment in Class I 
areas that is ``reasonably attributable'' to a single source or small 
group of sources, i.e., ``reasonably attributable visibility 
impairment.'' \5\ These regulations represented the first phase in 
addressing visibility impairment. EPA deferred action on regional haze 
that emanates from a variety of sources until monitoring, modeling, and 
scientific knowledge about the relationships between pollutants and 
visibility impairment were improved.
---------------------------------------------------------------------------

    \4\ 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.''
    \5\ 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.\6\ The Regional Haze Rule revised the existing visibility 
regulations to integrate into the regulations provisions addressing 
regional haze impairment and established a comprehensive visibility 
protection program for Class I areas. The requirements for regional 
haze, found at 40 CFR 51.308 and 51.309, are included in our visibility 
protection regulations at 40 CFR 51.300-309. 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

[[Page 914]]

impairment no later than December 17, 2007.\7\
---------------------------------------------------------------------------

    \6\ 64 FR 35714 (July 1, 1999), codified at 40 CFR part 51, 
subpart P (Regional Haze Rule).
    \7\ 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 \8\ built between 1962 and 1977 procure, install and operate 
the ``Best Available Retrofit Technology'' (BART). Larger ``fossil-fuel 
fired steam electric plants'' are included among the BART source 
categories. Under the Regional Haze Rule, states are directed to 
conduct BART determinations for ``BART-eligible'' sources that may be 
anticipated to cause or contribute to any visibility impairment in a 
Class I area. The evaluation of BART for 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.\9\
---------------------------------------------------------------------------

    \8\ See 42 U.S.C. 7491(g)(7) (listing the set of ``major 
stationary sources'' potentially subject-to-BART).
    \9\ 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.\10\ 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).\11\ The EGU BART requirements for NOX and 
SO2 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,\12\ that part of the proposed action 
was not finalized.\13\ In connection with changed circumstances on how 
Texas EGUs are able to satisfy NOX and SO2 BART, 
we are now proposing to disapprove the portion of the Texas Regional 
Haze SIP that evaluated the PM BART requirement for EGUs. The FIP we 
are proposing today addresses the EGU BART requirement and addresses 
these deficiencies in the Texas Regional Haze SIP.
---------------------------------------------------------------------------

    \10\ 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.
    \11\ 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).
    \12\ 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).
    \13\ 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 
SO2 and NOX. 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 v. 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.\14\
---------------------------------------------------------------------------

    \14\ 550 F.3d at 1178.
---------------------------------------------------------------------------

    On August 8, 2011, we promulgated the Cross-State Air Pollution 
Rule (CSAPR), to replace CAIR.\15\ 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 SO2 and 
NOX.\16\ 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 
SO2 and NOX BART for EGUs.\17\ 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 v. EPA, 795 F.3d 118 (D.C. Cir.). Specifically, 
the court invalidated a number of the Phase 2 ozone-season 
NOX budgets and found that the SO2 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 
NOX budget and annual SO2 budget.
---------------------------------------------------------------------------

    \15\ 76 FR 48208.
    \16\ 77 FR 33641.
    \17\ 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.\18\ 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.\19\ This rule promulgated a new

[[Page 915]]

FIP for Texas that replaced the CSAPR ozone season NOX 
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 
SO2 and NOX with regard to emissions after 
2016.\20\ Withdrawal of these FIP requirements will address the D.C. 
Circuit's remand of the CSAPR Phase 2 SO2 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.
---------------------------------------------------------------------------

    \18\ 79 FR 74817, 74823 (December 16, 2014).
    \19\ ``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 NOX 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 NOX 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 NOX emission budget to 
address that standard. 81 FR 74504, 74600-74601.
    \20\ ``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' SO2 budget, the court's rationale 
for remanding that budget also implicates Texas' annual 
NOX budget because the SO2 and annual 
NOX budgets were developed through an integrated analysis 
and were promulgated to meet a common PM2.5 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 NOX 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 
NOX requirements in order to address their PM2.5 
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 NOX requirements that has 
already been finalized, and the withdrawal of FIP provisions subjecting 
Texas EGUs to CSAPR SO2 and annual NOX 
requirements that is proposed separately. That proposed analysis 
supports the continued conclusion that CSAPR participation would 
achieve greater reasonable progress than BART for NOX 
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.\21\ 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 
NOX.\22\ Based on that national proposal, we are now 
proposing a FIP to replace Texas' reliance on CAIR with reliance on 
CSAPR to address the NOX 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 SO2 and NOX 
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 SO2. As a result, we are proposing to promulgate a 
FIP that includes BART screening of sources and a source-by-source 
analysis for SO2 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.\23\ 
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.
---------------------------------------------------------------------------

    \21\ 81 FR at 78962-78964.
    \22\ While we have proposed to remove Texas from CSAPR's annual 
NOX program, CSAPR is still an appropriate alternative to 
BART for NOX purposes because EGUs in Texas continue to 
be required to participate in CSAPR's ozone season NOX 
program.
    \23\ We previously proposed approval of Texas' SIP for EGU PM 
BART on the premise that EGU BART for both SO2 and 
NOX 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 NOX and 
SO2 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 
NOX. Phoenix Cement Co. v. 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 
NOX and SO2, 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 SO2, 
NOX, and PM. We are proposing source-specific BART 
determinations for EGUs subject to BART for SO2 and PM. We 
are proposing that NOX 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 NOX 
BART.
    Addressing the BART requirement for Texas EGUs, as proposed today, 
with cost-effective and readily available controls, will help ensure 
that progress

[[Page 916]]

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.\24\
---------------------------------------------------------------------------

    \24\ 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.\25\
---------------------------------------------------------------------------

    \25\ CAA Sec.  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 
PM2.5 NAAQS.\26\ 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 PM2.5.\27\ 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 SO2 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 v. 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 SO2 and NOX 
BART for EGUs in Texas in that action.\28\
---------------------------------------------------------------------------

    \26\ 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.
    \27\ Specifically, we previously disapproved the relevant 
portion of these Texas' SIP submittals: April 4, 2008: 1997 8-hour 
Ozone, 1997 PM2.5 (24-hour and annual); May 1, 2008: 1997 
8-hour Ozone, 1997 PM2.5 (24-hour and annual); November 
23, 2009: 2006 24-hour PM2.5; December 7, 2012: 2010 
NO2; December 13, 2012: 2008 8-hour Ozone; May 6, 2013: 
2010 1-hour SO2 (Primary NAAQS). 79 FR 74818, 74821; 81 
FR 296, at 302.
    \28\ 81 FR 296, 301-2.
---------------------------------------------------------------------------

    Our prior disapproval of interstate visibility transport for the 
six NAAQS is currently stayed by the Fifth Circuit.\29\ 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 
PM2.5 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 
SO2 and NOX. 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 PM2.5 (24-hour and annual); May 1, 
2008: 1997 8-hour Ozone, 1997 PM2.5 (24-hour and annual); 
November 23, 2009: 2006 24-hour PM2.5; December 7, 2012: 
2010 NO2; December 13, 2012: 2008 8-hour Ozone; May 6, 2013: 
2010 1-hour SO2 (Primary NAAQS). 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.
---------------------------------------------------------------------------

    \29\ July 15, 2016 Order in Texas v. 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 
NOX in Texas. The FIP will also address Texas EGU BART for 
SO2 and PM on a source-specific basis. With the absence of 
CSAPR coverage for SO2, 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 
SO2, which exceed the reductions initially assumed for Texas 
under either CAIR or CSAPR. In addition, our proposed FIP achieves 
reductions at large sources of SO2 emissions (e.g., 
Monticello, Martin Lake and Big Brown), that have significant impacts 
on

[[Page 917]]

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.\30\ 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 PM2.5, 2006 
PM2.5, 2008 8-hour ozone, 2010 1-hour NO2, and 
2010 1-hour SO2). We also propose that reliance on CSAPR for 
EGU NOX BART is appropriate to ensure NOX 
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.\31\
---------------------------------------------------------------------------

    \30\ 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).
    \31\ 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.\32\
---------------------------------------------------------------------------

    \32\ 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.'' \33\ 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.
---------------------------------------------------------------------------

    \33\ 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 NOX and 
SO2. 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.\34\ 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.
---------------------------------------------------------------------------

    \34\ 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.\35\ 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.
---------------------------------------------------------------------------

    \35\ Additionally, we continue to have authority to issue a FIP 
to address interstate visibility transport for 1997 8-hour ozone and 
1997 PM2.5 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 SO2 and PM

    In our previous action,\36\ we determined that due to the CSAPR 
remand, it was not appropriate at that time to rely on CSAPR as an 
alternative to SO2 and NOX 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.\37\ 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 NOX alone. It remains the case that we 
cannot rely on CSAPR as an alternative to SO2 BART for Texas 
EGUs as further confirmed by our proposed action to remove Texas from 
the annual NOX and SO2 control programs. Thus, we 
have the obligation to consider source-specific requirements for Texas 
EGUs consistent with the BART Guidelines for SO2 BART.
---------------------------------------------------------------------------

    \36\ See the discussion beginning on 81 FR 301 (January 5, 
2016).
    \37\ 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 SO2 and 
NOX 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 
SO2 or NOX would not be

[[Page 918]]

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.\38\
---------------------------------------------------------------------------

    \38\ 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 
SO2 and NOX 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 
SO2 and NOX BART under an alternative 
measure.\39\ 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 NOX, i.e., SO2 
and PM.
---------------------------------------------------------------------------

    \39\ 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: \40\
---------------------------------------------------------------------------

    \40\ 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: 
\41\
---------------------------------------------------------------------------

    \41\ 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)................  1.
Big Brown (Luminant).........................  1.
Big Brown (Luminant).........................  2.
Cedar Bayou (NRG)............................  CBY1.
Cedar Bayou (NRG)............................  CBY2.
Coleto Creek (Engie).........................  1.
Dansby (City of Bryan).......................  1.
Decker Creek (Austin Energy).................  1.
Decker Creek (Austin Energy).................  2.
Fayette (LCRA)...............................  1.
Fayette (LCRA)...............................  2.
Graham (Luminant)............................  2.
Greens Bayou (NRG)...........................  5.
Handley (Exelon).............................  3.
Handley (Exelon).............................  4.
Handley (Exelon).............................  5.
Harrington Station (Xcel)....................  061B.
Harrington Station (Xcel)....................  062B.
J T Deely (CPS Energy).......................  1.
J T Deely (CPS Energy).......................  2.
Jones Station (Xcel).........................  151B.
Jones Station (Xcel).........................  152B.
Knox Lee Power Plant (AEP)...................  5.
Lake Hubbard (Luminant)......................  1.
Lake Hubbard (Luminant)......................  2.
Lewis Creek (Entergy)........................  1.
Lewis Creek (Entergy)........................  2.
Martin Lake (Luminant).......................  1.
Martin Lake (Luminant).......................  2.
Martin Lake (Luminant).......................  3.
Monticello (Luminant)........................  1.
Monticello (Luminant)........................  2.
Monticello (Luminant)........................  3.
Newman (El Paso Electric)....................  2.
Newman (El Paso Electric)....................  3.
Newman (El Paso Electric)....................  4.
Nichols Station (Xcel).......................  143B.
O W Sommers (CPS Energy).....................  1.
O W Sommers (CPS Energy).....................  2.
Plant X (Xcel)...............................  4.
Powerlane (City of Greenville)...............  ST1.
Powerlane (City of Greenville)...............  ST2.
Powerlane (City of Greenville)...............  ST3.
R W Miller (Brazos Elec. Coop)...............  1.
R W Miller (Brazos Elec. Coop)...............  2.
R W Miller (Brazos Elec. Coop)...............  3.
Sabine (Entergy).............................  2.
Sabine (Entergy).............................  3.
Sabine (Entergy).............................  4.
Sabine (Entergy).............................  5.
Sim Gideon (LCRA)............................  1.
Sim Gideon (LCRA)............................  2.
Sim Gideon (LCRA)............................  3.
Spencer (City of Garland)....................  4.
Spencer (City of Garland)....................  5.
Stryker Creek (Luminant).....................  ST2.
Trinidad (Luminant)..........................  6.
Ty Cooke (City of Lubbock)...................  1.
Ty Cooke (City of Lubbock)...................  2.
V H Braunig (CPS Energy).....................  1.
V H Braunig (CPS Energy).....................  2.
V H Braunig (CPS Energy).....................  3.
W A Parish (NRG).............................  WAP4.
W A Parish (NRG).............................  WAP5.
W A Parish (NRG).............................  WAP6.
Welsh Power Plant (AEP)......................  1.
Welsh Power Plant (AEP)......................  2.
Wilkes Power Plant (AEP).....................  1.
Wilkes Power Plant (AEP).....................  2.
Wilkes Power Plant (AEP).....................  3.
------------------------------------------------------------------------

    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.\42\ 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

[[Page 919]]

the BART Screening TSD.\43\ We summarize the methodology and results of 
this analysis here.
---------------------------------------------------------------------------

    \42\ See 40 CFR part 51, Appendix Y, III, How to Identify 
Sources ``Subject to BART''.
    \43\ 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.\44\ 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.
---------------------------------------------------------------------------

    \44\ 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.'' \45\ 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.
---------------------------------------------------------------------------

    \45\ 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 
NOX or SO2 (or combined NOX and 
SO2), as long as these sources are located more than 50 
kilometers from any Class I area; and sources that emit less than 
1000 tons per year of NOX or SO2 (or combined 
NOX and SO2) that are located more than 100 
kilometers from any Class I area. You do, however, have the option 
of showing other thresholds might also be appropriate given your 
specific circumstances.\46\
---------------------------------------------------------------------------

    \46\ 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).................  1.
Greens Bayou (NRG).....................  5.
Nichols Station (Xcel).................  143B.
Plant X (Xcel).........................  4.
Powerlane (City of Greenville).........  ST1, ST2 & ST3.
Spencer (City of Garland)..............  4 & 5.
Trinidad (Luminant)....................  6.
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.'' \47\
---------------------------------------------------------------------------

    \47\ 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, the Q/d value is calculated 
as the annual emissions (combined NOX and SO2 
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)..........  1.
Cedar Bayou (NRG)......................  CBY1 & CBY2.
Decker Creek (Austin...................  1 & 2.
Energy)................................
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

[[Page 920]]

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 
NOX and SO2 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.\48\ For some BART-eligible sources, evaluation of baseline 
emissions revealed evidence of the installation of NOX 
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:
---------------------------------------------------------------------------

    \48\ 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).........................  5.
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 \49\/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.
---------------------------------------------------------------------------

    \49\ 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 SO2, NOX, 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 SO2 emissions.\50\ 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.
---------------------------------------------------------------------------

    \50\ CAMx results were also obtained and add to our basis of 
information for coal-fired facilities that have CALPUFF results.
    \51\ 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.
    \52\ 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 NOX and SO2 from the 2000-2004 
baseline period from EPA's Air Markets Program Data \53\ 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 NOX 
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.
---------------------------------------------------------------------------

    \53\ http://ampd.epa.gov/ampd/.

[[Page 921]]



                                                  Table 5--CAMx BART Screening Source Analysis Results
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                             Number of       Number of
                                                          Most impacted Class I   Maximum  delta-                          modeled days    modeled days
       BART-eligible source                Units                   area                 dv          Less than  0.5 dv?      over 0.5 dv     over 1.0 dv
                                                                                                                                \2\             \2\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Big Brown........................  1 & 2...............  WIMO...................           4.017  No....................              65              33
Coleto Creek.....................  1...................  WIMO...................           0.845  No....................               9               0
Fayette Power....................  1 & 2...............  CACR...................           1.894  No....................              26               9
Harrington.......................  061B & 062B.........  SACR...................           5.288  No....................              13               5
Martin Lake......................  1, 2, & 3...........  CACR...................           6.651  No....................             141              99
Monticello.......................  1, 2, & 3...........  CACR...................          10.498  No....................             152             111
Calaveras........................  J T Deely 1 & 2, OW   WIMO...................           1.513  No....................              47               6
                                    Sommers 1 & 2.
W A Parish.......................  WAP4, WAP5 & WAP6...  CACR...................           3.177  No....................              54              22
Welsh \1\........................  1 & 2...............  CACR...................           4.576  No....................              92              39
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Welsh unit 2 has recently shutdown. We note that baseline impacts from unit 1 alone are 2.343 dv at Caney Creek.
\2\ 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 
NOX.\54\ Foremost, they are subject to SO2 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.
---------------------------------------------------------------------------

    \54\ The NOX 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 
NOX.

           Table 6--Summary: Sources That are Subject-to-BART
------------------------------------------------------------------------
             Facility                              Units
------------------------------------------------------------------------
Big Brown........................  1 & 2.
Coleto Creek.....................  1.
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...........................  2.
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.\55\ 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: \56\
---------------------------------------------------------------------------

    \55\ See July 6, 2005 BART Guidelines, 40 CFR part 51, Regional 
Haze Regulations and Guidelines for Best Available Retrofit 
Technology Determinations.

    \56\ 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 
SO2. We are combining these steps into one section in our 
assessment of PM BART that follows the SO2 sections.
1. Steps 1 and 2: Technically Feasible SO2 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.\57\
---------------------------------------------------------------------------

    \57\ 70 FR at 39164, fn 12 [40 CFR part 51, App. Y]

    Adhering to this, we will identify a reasonable set of 
SO2 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 SO2 controls that could be retrofitted: (1) Coal-
fired EGUs with no SO2 scrubber, (2) coal-fired EGUs with 
underperforming SO2 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:

[[Page 922]]



                                           Table 7--Subject to BART Fuel Types and Potential SO2 BART Controls
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                    Coal  underperforming
            Facility                       Unit              Coal no scrubber             scrubber                Gas no oil           Gas burns oil
--------------------------------------------------------------------------------------------------------------------------------------------------------
Big Brown (Luminant)............  1.....................  X.....................  ........................  .....................  .....................
Big Brown (Luminant)............  2.....................  X.....................  ........................  .....................  .....................
Coleto Creek (Engie)............  1.....................  X.....................  ........................  .....................  .....................
Fayette (LCRA) *................  1.....................  ......................  ........................  .....................  .....................
Fayette (LCRA) *................  2.....................  ......................  ........................  .....................  .....................
Graham (Luminant)...............  2.....................  ......................  ........................  .....................  X
Harrington Station (Xcel).......  061B..................  X.....................  ........................  .....................  .....................
Harrington Station (Xcel).......  062B..................  X.....................  ........................  .....................  .....................
J T Deely (CPS Energy)..........  1.....................  X.....................  ........................  .....................  .....................
J T Deely (CPS Energy)..........  2.....................  X.....................  ........................  .....................  .....................
Martin Lake (Luminant)..........  1.....................  ......................  X.......................  .....................  .....................
Martin Lake (Luminant)..........  2.....................  ......................  X.......................  .....................  .....................
Martin Lake (Luminant)..........  3.....................  ......................  X.......................  .....................  .....................
Monticello (Luminant)...........  1.....................  X.....................  ........................  .....................  .....................
Monticello (Luminant)...........  2.....................  X.....................  ........................  .....................  .....................
Monticello (Luminant)...........  3.....................  ......................  X.......................  .....................  .....................
Newman (El Paso Electric).......  2.....................  ......................  ........................  .....................  X
Newman (El Paso Electric).......  3.....................  ......................  ........................  .....................  X
Newman (El Paso Electric).......  4.....................  ......................  ........................  X....................  .....................
O W Sommers (CPS Energy)........  1.....................  ......................  ........................  .....................  X
O W Sommers (CPS Energy)........  2.....................  ......................  ........................  .....................  X
Stryker Creek (Luminant)........  ST2...................  ......................  ........................  .....................  X
W A Parish (NRG)................  WAP4..................  ......................  ........................  X....................  .....................
W A Parish (NRG)................  WAP5..................  X.....................  ........................  .....................  .....................
W A Parish (NRG)................  WAP6..................  X.....................  ........................  .....................  .....................
Welsh Power Plant (AEP).........  1.....................  X.....................  ........................  .....................  .....................
Wilkes Power Plant (AEP)........  1.....................  ......................  ........................  .....................  X
Wilkes Power Plant (AEP)........  2.....................  ......................  ........................  X....................  .....................
Wilkes Power Plant (AEP)........  3.....................  ......................  ........................  X....................  .....................
--------------------------------------------------------------------------------------------------------------------------------------------------------
* 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 
SO2 emissions and there are no known SO2 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.'' 
\58\ In addition, we will also evaluate the potential for post 
combustion SO2 controls for these units.
---------------------------------------------------------------------------

    \58\ 70 FR 39171 (July 6, 2005) [40 CFR 51, App. Y].
---------------------------------------------------------------------------

a. Identification of Technically Feasible SO2 Retrofit 
Control Technologies for Coal-Fired Units
    Available SO2 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).\59\ 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.\60\ 
Coal is mechanically sized, then various washing techniques are 
employed, depending on the particle size, type of coal, and the desired 
level of preparation.\61\ Following the coal washing, the coal is 
dewatered, and the waste streams are disposed.
---------------------------------------------------------------------------

    \59\ Couch, G.R., ``Coal Upgrading to Reduce CO2 
emissions,'' CCC/67, October 2002, IEA Clean Coal Centre.
    \60\ Ibid.
    \61\ 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.

[[Page 923]]

     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,\62\ and coal washing 
slurries are typically stored in impoundments, which can, and have, 
leaked.\63\
---------------------------------------------------------------------------

    \62\ ``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.
    \63\ 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 SO2 
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.\64\ 
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.
---------------------------------------------------------------------------

    \64\ DryFining\TM\ 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 SO2, its 
analysis presents a number of difficulties. For instance, the degree of 
reduction in SO2 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 SO2 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 
SO2 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 
SO2 removal. There are many examples of DSI being used on 
coal-fired EGUs to control SO2. 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: \65\
---------------------------------------------------------------------------

    \65\ 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 SO2 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.
SO2 Scrubbing Systems
    In contrast to DSI, SO2 scrubbing techniques utilize a 
large dedicated vessel in which the chemical reaction between the 
sorbent and SO2 takes place either completely or in large 
part. Also in contrast to DSI systems, SO2 scrubbers add 
water to the sorbent when introduced to the flue gas. The two 
predominant types of SO2 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
------------------------------------------------------------------------
                                                             Number of
                          Type                             installations
------------------------------------------------------------------------
Wet spray tower scrubber................................             296
Spray dryer absorber....................................             269
Circulating dry scrubber................................              50
Packed tower wet scrubber...............................               6
Venturi wet scrubber....................................              48
Jet bubbling reactor....................................              31
Tray tower wet scrubber.................................              42
Mechanically aided wet scrubber.                                       4
DSI.....................................................             106
Other...................................................               1
Unspecified.............................................               1
                                                         ---------------
    Total...............................................             854
------------------------------------------------------------------------

    Excluding the DSI installations, EIA lists 748 SO2 
scrubber installations in operation in 2015. Of these, 296 are listed 
as being spray type wet scrubbers, with an additional 42 listed as 
being

[[Page 924]]

tray type wet scrubbers.\66\ 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.
---------------------------------------------------------------------------

    \66\ 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 SO2 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 SO2 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 SO2 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,\67\ 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:
---------------------------------------------------------------------------

    \67\ 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)..................  2.....................  .........................  X
Newman (El Paso Electric)..........  2, 3..................  .........................  X
O W Sommers (CPS Energy)...........  1, 2..................  .........................  X
Stryker Creek (Luminant)...........  ST2...................  .........................  X
Wilkes Power Plant (AEP)...........  1.....................  .........................  X
----------------------------------------------------------------------------------------------------------------

    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.\68\ 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.\69\ 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 SO2 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.
---------------------------------------------------------------------------

    \68\ 70 FR at 39171.
    \69\ In addition, the Newman units 2 and 3 are restricted to 
burning fuel oil for no more than 10% of their annual operating 
time.
---------------------------------------------------------------------------

SO2 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.\70\ 
Consequently, we will consider the installation of various types of 
scrubbers to be technically feasible.
---------------------------------------------------------------------------

    \70\ 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 SO2 Control 
Technologies for Scrubber Upgrades
    In our recent Texas-Oklahoma FIP,\71\ we presented a great deal of 
information that concluded that the existing scrubbers for a number of 
facilities could be very cost-effectively upgraded.\72\ That 
information is included in this proposal.\73\ 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.
---------------------------------------------------------------------------

    \71\ 81 FR 321.
    \72\ See information presented in Sections 6 and 7 of the Cost 
TSD.
    \73\ That information is included in our BART FIP TSD, Appendix 
B.

---------------------------------------------------------------------------

[[Page 925]]

2. Step 3: Evaluation of SO2 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.'' \74\ 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.
---------------------------------------------------------------------------

    \74\ 70 FR 39103, 39172 (July 6, 2005), [40 CFR part 51, App. 
Y].
---------------------------------------------------------------------------

a. Evaluation of SO2 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 SO2 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 SO2 control. We must do the same for 
SO2 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,\75\ assuming 
milled trona: 80% SO2 removal for an ESP installation and 
90% SO2 removal for a baghouse installation. This level of 
control is within the range that can be achieved by SO2 
scrubbers, and thus allows a better comparison of the costs of DSI and 
scrubbers.
---------------------------------------------------------------------------

    \75\ IPM Model--Updates to Cost and Performance for APC 
Technologies, Dry Sorbent Injection for SO2 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 SO2 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 
SO2 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.\76\ 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 SO2 emission guarantees, from the original 
equipment manufacturers of wet FGD systems, are 0.04 lb/MMBtu.'' As we 
established in our Oklahoma FIP,\77\ this level of control is 
achievable with wet FGD. This level of control was also employed in our 
recent Texas-Oklahoma FIP.\78\ 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.\79\ We continue to conclude that our proposed level of 
control for wet FGD is reasonable.
---------------------------------------------------------------------------

    \76\ IPM Model--Updates to Cost and Performance for APC 
Technologies, Dry Sorbent Injection for SO2 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.
    \77\ 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 v. EPA, 723 F.3d 1201 (July 19, 2013), cert. denied 
(U.S. May 27, 2014).
    \78\ 81 FR 321.
    \79\ 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 
SO2 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.\80\ 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 \81\ and in our TSD. We continue to 
conclude that our proposed level of control for SDA is reasonable.
---------------------------------------------------------------------------

    \80\ 76 FR 81728.
    \81\ 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 SO2 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 SO2 
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.

[[Page 926]]

    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 SO2
    The BART Guidelines offers the following with regard to how Step 4 
should be conducted: \82\
---------------------------------------------------------------------------

    \82\ 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.\83\
---------------------------------------------------------------------------

    \83\ 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).\84\ We 
proceed in our SO2 costing analyses by examining the current 
SO2 emissions and the level of SO2 control, if 
any, for each of the units listed in Table 7. For the coal units 
without any SO2 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.
---------------------------------------------------------------------------

    \84\ 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 SO2 control.\85\ These cost models were 
based on costs escalated to 2012 dollars.\86\ 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).
---------------------------------------------------------------------------

    \85\ 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.
    \86\ 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 
SO2 control device. Below, we present a summary of our DSI, 
SDA, and wet FGD cost analysis: \87\
---------------------------------------------------------------------------

    \87\ 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                               2016
                                                                                           SO2 reduction       2016          2016 Cost      Incremental
            Facility                     Unit               Control        Control level       (tpy)        Annualized     effectiveness       cost-
                                                                                (%)                            cost           ($/ton)      effectiveness
                                                                                                                                              ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Big Brown.......................  1.................  DSI...............              50          14,448     $29,468,587          $2,040
                                                      DSI...............              90          26,006      72,131,749           2,774          $3,691
                                                      SDA...............              95          27,453      35,297,532           1,286         -25,456
                                                      Wet FGD...........              98          28,320      33,673,102           1,189          -1,874
                                  2.................  DSI...............              50          15,320      29,342,350           1,915
                                                      DSI...............              90          27,576      71,322,593           2,586           3,425
                                                      SDA...............              95          29,108      35,359,239           1,215         -23,475
                                                      Wet FGD...........            97.9          29,998      33,817,952           1,127          -1,732
Monticello......................  1.................  DSI...............              50           4,787      11,408,872           2,383
                                                      DSI...............              90           8,617      25,409,128           2,949           3,655
                                                      SDA...............              95           9,095      24,294,319           2,671          -2,332
                                                      Wet FGD...........              97           9,286      25,236,699           2,718           4,934
                                  2.................  DSI...............              50           4,129       9,742,648           2,360
                                                      DSI...............              90           7,431      21,418,734           2,882           3,536
                                                      SDA...............              95           7,844      23,126,113           2,948           4,134
                                                      Wet FGD...........            96.8           7,995      24,233,133           3,031           7,331
Coleto Creek....................  1.................  DSI...............              50           7,376      16,246,169           2,203
                                                      DSI...............              90          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...............              50           2,477       9,187,608           3,710
                                                      DSI...............              80           3,962      16,073,779           4,057           4,637
                                                      SDA...............            90.2           4,466      17,455,679           3,909           2,742
                                  062B..............  DSI...............              50           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.......................  1.................  DSI...............              50           3,072       8,854,319           2,883

[[Page 927]]

 
                                                      DSI...............              90           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
                                  2.................  DSI...............              50           3,222       9,865,798           3,062
                                                      DSI...............              90           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...........................  1.................  DSI...............              50           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.....................  5.................  DSI...............              50           6,712      15,002,337           2,235
                                                      DSI...............              90          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
                                  6.................  DSI...............              50           7,525      16,014,988           2,128  ..............
                                  ..................  DSI...............              90          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 SO2 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.\88\
---------------------------------------------------------------------------

    \88\ 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.\89\ 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.
---------------------------------------------------------------------------

    \89\ 81 FR 318.
---------------------------------------------------------------------------

     The absorber system had either already been upgraded to 
perform at an SO2 removal efficiency of at least 95%, or it 
could be upgraded to perform at that level using proven equipment and 
techniques.
     The SO2 scrubber bypass could be eliminated, 
and the additional flue gas could be treated by the absorber system 
with at least a 95% removal efficiency.
     Additional modifications necessary to eliminate the 
bypass, such as adding fan capacity, upgrading the electrical 
distribution system, and conversion to a wet stack could be performed 
using proven equipment and techniques.
     The additional SO2 emission reductions 
resulting from the scrubber upgrade are substantial, ranging from 68% 
to 89% reduction from the current emission levels, and are cost-
effective.
    We now update these calculations for 2011-2015 data.\90\ The 
revised scrubber upgrade results for Martin Lake Units 1, 2, and 3; and 
Monticello Unit 3 are presented below in Table 11:
---------------------------------------------------------------------------

    \90\ See Coal vs CEM data 2011-2015.xlsx.

                              Table 11--Summary of Updated Scrubber Upgrade Results
----------------------------------------------------------------------------------------------------------------
                                                  2011-2015 3-yr
                                                     avg. SO2      SO2 emissions   SO2 emissions   SO2 emission
                                                     emissions    at 95% control   reduction due    rate at 95%
                      Unit                        (eliminate max      (tons)        to scrubber   control  (lbs/
                                                     and min)                     upgrade (tons)      MMBtu)
                                                      (tons)
----------------------------------------------------------------------------------------------------------------
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 SO2 Removed...........................                                          50,890
----------------------------------------------------------------------------------------------------------------


[[Page 928]]

    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 SO2 30 BOD average below 0.04 lbs/MMBtu for years 
at a time.\91\ 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 SO2 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.
---------------------------------------------------------------------------

    \91\ 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 SO2 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.\92\ 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.\93\
---------------------------------------------------------------------------

    \92\ Copies of these letters and the facilities' responses are 
in our docket. We inadvertently did not send the O W Sommers a 
letter.
    \93\ 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                         U.S. no. 4
                                                                       West Texas         U.S. no. 2 diesel    U.S. no. 2 fuel oil       distillate
                              Date                                 intermediate  crude    wholesale/resale      wholesale/resale      wholesale/resale
                                                                      oil--Cushing        price by refiners     price by refiners     price by refiners
                                                                    Oklahoma ($/bbl)         ($/gallon)            ($/gallon)            ($/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.\94\ We will use the cost of this fuel oil in constructing 
a ``medium control'' annual cost of fuel oil.
---------------------------------------------------------------------------

    \94\ 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 SO2 
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 SO2, would result 
in the same value. In other words, the cost-effectiveness in $/ton is 
independent of the SO2 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

[[Page 929]]

SO2. 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 SO2
----------------------------------------------------------------------------------------------------------------
                                                                   Quantity fuel   Reported SO2    Reported EIA
                        Date (month/year)                           oil burned       for month    sulfur content
                                                                      (bbls)          (tons)          (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 SO2 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 SO2 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 SO2 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 SO2 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 
SO2 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 SO2 emissions, we cannot 
rely on historical SO2 emissions to construct a baseline, 
because a barrel of fuel oil with a given sulfur content does not 
result in a consistent reported SO2 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.\95\
---------------------------------------------------------------------------

    \95\ The emission factor (lb/10\3\ gal) used is 150 x 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
----------------------------------------------------------------------------------------------------------------
                                                                                       Cost
                                                  Cost for 1,000   Tons reduced    effectiveness    Incremental
                Level of control                      barrels        for 1,000       for 1,000         cost-
                                                   baseline  ($/      barrels      barrels  ($/    effectiveness
                                                        yr)                            ton)           ($/ton)
----------------------------------------------------------------------------------------------------------------
Business as usual (No. 4 distillate $1.215/gal).         $51,030             N/A             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 
SO2 emissions from any of the gas units, 1,287 tons/year 
(Graham Unit 2, 2001), results in a SO2 reduction of 1,261 
tons/year. The cost-effectiveness is then $15,183/ton, which is very 
high for a SO2 scrubber. In addition, the annual 
SO2 values for Graham Unit 2 from 2002 to 2015, and the 
annual SO2 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

[[Page 930]]

installing SO2 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.\96\
---------------------------------------------------------------------------

    \96\ 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.'' \97\ 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.
---------------------------------------------------------------------------

    \97\ 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: \98\
---------------------------------------------------------------------------

    \98\ 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 SO2 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 SO2 scrubbers, our cost 
model includes waste disposal costs in the variable operating costs. 
Consequently, we believe that with one possible exception, any non-air 
quality environmental impacts have been adequately considered in our 
analyses. We are aware that the Harrington facility has instituted a 
water recycling program and obtains some of its water from the City of 
Amarillo.\99\ Due to potential non-air quality concerns, we limit our 
SO2 control analysis for Harrington to DSI and dry 
scrubbers.
---------------------------------------------------------------------------

    \99\ 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\
---------------------------------------------------------------------------

    \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 
SO2 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 SO2 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

[[Page 931]]

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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                       Visibility impact            Visibility benefit
                                                                                             -----------------------------------------------------------
          Facility name              Emission unit       Class I area           Metric                                                DSI        WFGD
                                                                                               Baseline    DSI (50%)  WFGD (98%)    benefit     benefit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Big Brown.......................  Source (Unit 1 and  WIMO..............  Max dv............       4.017       2.249       0.474       1.768       3.542
                                   2).
                                                                          Days >0.5 dv......          65          33           0          32          65
                                                                          Days >1.0 dv......          33          13           0          20          33
                                                      CACR..............  Max dv............       3.775       2.539       0.787       1.236       2.988
                                                                          Days >0.5 dv......          91          62           4          29          87
                                                                          Days >1.0 dv......          57          21           0          36          57
                                  Unit 1............  WIMO..............  Max dv............       2.154       1.168       0.245       0.986       1.909
                                                                          Days >0.5 dv......          33          13           0          20          33
                                                                          Days >1.0 dv......          12           1           0          11          12
                                                      CACR..............  Max dv............       2.016       1.327       0.409       0.688       1.606
                                                                          Days >0.5 dv......          58          22           0          36          58
                                                                          Days >1.0 dv......          17           4           0          13          17
                                  Unit 2............  WIMO..............  Max dv............       2.175       1.181       0.235       0.994       1.940
                                                                          Days >0.5 dv......          34          13           0          21          34
                                                                          Days >1.0 dv......          12           1           0          11          12
                                                      CACR..............  Max dv............       2.033       1.338       0.391       0.695       1.642
                                                                          Days >0.5 dv......          58          23           0          35          58
                                                                          Days >1.0 dv......          17           4           0          13          17
Monticello......................  Source (Unit 1, 2   CACR..............  Max dv............      10.498       6.121       2.079       4.377       8.419
                                   and 3).
                                                                          Days >0.5 dv......         152         107          28          45         124
                                                                          Days >1.0 dv......         111          54           8          57         103
                                                      WIMO..............  Max dv............       5.736       2.769       0.774       2.968       4.962
                                                                          Days >0.5 dv......          67          35           4          32          63
                                                                          Days >1.0 dv......          40          14           0          26          40
                                  Unit 1............  CACR..............  Max dv............       4.516       3.123       0.733       1.393       3.783
                                                                          Days >0.5 dv......          79          43           3          36          76
                                                                          Days >1.0 dv......          32          16           0          16          32
                                                      WIMO..............  Max dv............       2.241       1.290       0.252       0.951       1.989
                                                                          Days >0.5 dv......          30          10           0          20          30
                                                                          Days >1.0 dv......           8           2           0           6           8
                                  Unit 2............  CACR..............  Max dv............       4.487       3.065       0.563       1.422       3.924
                                                                          Days >0.5 dv......          78          42           1          36          77
                                                                          Days >1.0 dv......          30          13           0          17          30
                                                      WIMO..............  Max dv............       2.189       1.252       0.186       0.937       2.003
                                                                          Days >0.5 dv......          30          10           0          20          30
                                                                          Days >1.0 dv......           6           2           0           4           6
Coleto Creek....................  Source (Unit 1)...  WIMO..............  Max dv............       0.845       0.526       0.176       0.318       0.668
                                                                          Days >0.5 dv......           9           1           0           8           9
                                                                          Days >1.0 dv......           0           0           0           0           0
                                                      CACR..............  Max dv............       0.791       0.458       0.186       0.333       0.606
                                                                          Days >0.5 dv......           5           0           0           5           5
                                                                          Days >1.0 dv......           0           0           0           0           0
Harrington \1\..................  Source (Unit 061B   SACR..............  Max dv............       5.288       4.287       3.235       1.001       2.053
                                   & 062B).
                                                                          Days >0.5 dv......          13           7           3           6          10
                                                                          Days >1.0 dv......           5           1           1           4           4
                                                      WIMO..............  Max dv............       4.928       4.362       3.798       0.565       1.130
                                                                          Days >0.5 dv......          15          11           6           4           9
                                                                          Days >1.0 dv......           6           5           4           1           2
                                  Unit 061B.........  SACR..............  Max dv............       2.908       2.322       1.738       0.586       1.170
                                                                          Days >0.5 dv......           5           1           1           4           4
                                                                          Days >1.0 dv......           1           1           1           0           0
                                                      WIMO..............  Max dv............       2.708       2.382       2.065       0.326       0.643
                                                                          Days >0.5 dv......           6           5           4           1           2
                                                                          Days >1.0 dv......           4           2           1           2           3
                                  Unit 062B.........  SACR..............  Max dv............       2.998       2.373       1.719       0.625       1.279
                                                                          Days >0.5 dv......           5           1           1           4           4
                                                                          Days >1.0 dv......           1           1           1           0           0
                                                      WIMO..............  Max dv............       2.770       2.407       2.046       0.363       0.723
                                                                          Days >0.5 dv......           6           5           4           1           2
                                                                          Days >1.0 dv......           4           1           1           3           3

[[Page 932]]

 
J T Deely.......................  Source (Sommers     WIMO..............  Max dv............       1.513       0.939       0.814       0.574       0.699
                                   1&2, J T Deely
                                   1&2).
                                                                          Days >0.5 dv......          47           8           1          39          46
                                                                          Days >1.0 dv......           6           0           0           6           6
                                                      CACR..............  Max dv............       1.423       1.155       0.905       0.268       0.518
                                                                          Days >0.5 dv......           7           3           2           4           5
                                                                          Days >1.0 dv......           2           1           0           1           2
                                  J T Deely 1.......  WIMO..............  Max dv............       0.757       0.449       0.270       0.307       0.487
                                                                          Days >0.5 dv......           4           0           0           4           4
                                                                          Days >1.0 dv......           0           0           0           0           0
                                                      BIBE..............  Max dv............       0.652       0.373       0.069       0.279       0.583
                                                                          Days >0.5 dv......           2           0           0           2           2
                                                                          Days >1.0 dv......           0           0           0           0           0
                                  J T Deely 2.......  WIMO..............  Max dv............       0.632       0.387       0.334       0.245       0.298
                                                                          Days >0.5 dv......           3           0           0           3           3
                                                                          Days >1.0 dv......           0           0           0           0           0
                                                      CACR..............  Max dv............       0.604       0.490       0.387       0.114       0.217
                                                                          Days >0.5 dv......           2           0           0           2           2
                                                                          Days >1.0 dv......           0           0           0           0           0
W.A. Parish.....................  Source (WAP 4, 5,   CACR..............  Max dv............       3.177       2.032       0.511       1.145       2.665
                                   & 6).
                                                                          Days >0.5 dv......          54          26           1          28          53
                                                                          Days >1.0 dv......          22           9           0          13          22
                                                      UPBU..............  Max dv............       1.994       1.215       0.234       0.779       1.760
                                                                          Days >0.5 dv......          34          14           0          20          34
                                                                          Days >1.0 dv......           9           1           0           8           9
                                  WAP 5.............  CACR..............  Max dv............       1.698       1.052       0.180       0.646       1.518
                                                                          Days >0.5 dv......          22           9           0          13          22
                                                                          Days >1.0 dv......           8           1           0           7           8
                                                      UPBU..............  Max dv............       1.038       0.613       0.094       0.424       0.943
                                                                          Days >0.5 dv......          11           1           0          10          11
                                                                          Days >1.0 dv......           1           0           0           1           1
                                  WAP 6.............  CACR..............  Max dv............       1.648       1.018       0.156       0.630       1.492
                                                                          Days >0.5 dv......          22           8           0          14          22
                                                                          Days >1.0 dv......           6           1           0           5           6
                                                      UPBU..............  Max dv............       1.003       0.591       0.081       0.412       0.922
                                                                          Days >0.5 dv......           9           1           0           8           9
                                                                          Days >1.0 dv......           1           0           0           1           1
Welsh \2\.......................  Source (Unit 1 &    CACR..............  Max dv............       4.576  ..........       0.822  ..........       3.754
                                   2).
                                                                          Days >0.5 dv......          92  ..........           3  ..........          89
                                                                          Days >1.0 dv......          39  ..........           0  ..........          39
                                                      MING..............  Max dv............       2.544  ..........       0.570  ..........       1.973
                                                                          Days >0.5 dv......           9  ..........           1  ..........           8
                                                                          Days >1.0 dv......           3  ..........           0  ..........           3
                                  Unit 1............  CACR..............  Max dv............       2.343       1.659       0.822       0.684       1.521
                                                                          Days >0.5 dv......          37          18           3          19          34
                                                                          Days >1.0 dv......           8           3           0           5           8
                                                      MING..............  Max dv............       1.150       0.886       0.570       0.264       0.579
                                                                          Days >0.5 dv......           2           1           1           1           1
                                                                          Days >1.0 dv......           1           0           0           1           1
Fayette \2\.....................  Source (Unit 1 &    CACR..............  Max dv............       1.894  ..........       0.903  ..........       0.991
                                   2).
                                                                          Days >0.5 dv......          26  ..........           2  ..........          24
                                                                          Days >1.0 dv......           9  ..........           0  ..........           9
                                                      WIMO..............  Max dv............       1.175  ..........       0.580  ..........       0.595
                                                                          Days >0.5 dv......          19  ..........           1  ..........          18
                                                                          Days >1.0 dv......           2  ..........           0  ..........           2
                                  Unit 1............  CACR..............  Max dv............       1.002  ..........       0.480  ..........       0.522
                                                                          Days >0.5 dv......           9  ..........           0  ..........           9
                                                                          Days >1.0 dv......           1  ..........           0  ..........           1
                                                      WIMO..............  Max dv............       0.609  ..........       0.306  ..........       0.302
                                                                          Days >0.5 dv......           2  ..........           0  ..........           2
                                                                          Days >1.0 dv......           0  ..........           0  ..........           0
                                  Unit 2............  CACR..............  Max dv............       0.974  ..........       0.441  ..........       0.534
                                                                          Days >0.5 dv......           9  ..........           0  ..........           9
                                                                          Days >1.0 dv......           0  ..........           0  ..........           0
                                                      WIMO..............  Max dv............       0.598  ..........       0.282  ..........       0.316
                                                                          Days >0.5 dv......           2  ..........           0  ..........           2
                                                                          Days >1.0 dv......           0  ..........           0  ..........           0
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Harrington high control scenario for both units is SDA at 95% reduction.
\2\ 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.


[[Page 933]]


                                 Table 16--Visibility Benefit of Retrofit Controls: Coal-Fired Units (CALPUFF Modeling)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                   Visibility impact               Visibility benefit
                                                                                        ----------------------------------------------------------------
         Facility name            Emission unit       Class I area          Metric                                                               WFGD
                                                                                           Baseline    DSI (50%)    WFGD (98%)  DSI benefit    benefit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Big Brown.....................  Source (Units 1    WIMO.............  Max dv...........         4.27         2.54         0.43         1.73         3.83
                                 and 2).
                                                                      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           21        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 \1\................  Source (Unit 1, 2  CACR.............  Max dv...........         6.57         3.68         1.70         2.89         4.87
                                 and 3).
                                                                      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 \4\.........  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 \2\................  Source (Units      SACR.............  Max dv...........         1.06         0.86         0.61         0.20         0.45
                                 061B & 062B).
                                                                      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 \3\.....................  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           38
                                                                      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         0.00         0.67         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
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Monticello's controlled level is a combination of scrubber upgrades and scrubber install in the facility impact modeling with CALPUFF.
\2\ Harrington high control scenario for both units is SDA at 95% reduction.
\3\ 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.
\4\ 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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                   Visibility impact               Visibility benefit
                                                                                        ----------------------------------------------------------------
         Facility name            Emission unit       Class I area          Metric                       (90%)        (95%)        (90%)        (95%)
                                                                                           Baseline     control      control      benefit      benefit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Martin Lake...................  Source (Unit 1, 2  CACR.............  Max dv...........        6.651        4.491        4.321        2.159        2.329
                                 & 3).
                                                                      Days >0.5 dv.....          141           75           56           66           85
                                                                      Days >1.0 dv.....           99           31           16           68           83
                                                   UPBU.............  Max dv...........        5.803        2.669        2.528        3.134        3.275
                                                                      Days >0.5 dv.....           99           39           22           60           77
                                                                      Days >1.0 dv.....           67           11            7           56           60
                                Unit 1...........  CACR.............  Max dv...........        2.633        1.550        1.468        1.083        1.165
                                                                      Days >0.5 dv.....           71           17            6           54           65
                                                                      Days >1.0 dv.....           26            3            1           23           25
                                                   UPBU.............  Max dv...........        2.254        0.867        0.805        1.387        1.449
                                                                      Days >0.5 dv.....           44            6            3           38           41
                                                                      Days >1.0 dv.....           10            0            0           10           10
                                Unit 2...........  CACR.............  Max dv...........        2.466        1.882        1.811        0.585        0.655
                                                                      Days >0.5 dv.....           68           18            9           50           59
                                                                      Days >1.0 dv.....           26            3            1           23           25
                                                   UPBU.............  Max dv...........        2.189        1.077        1.025        1.112        1.164
                                                                      Days >0.5 dv.....           40            6            5           34           35
                                                                      Days >1.0 dv.....           10            1            1            9            9
                                Unit 3...........  CACR.............  Max dv...........        2.755        1.682        1.609        1.074        1.146
                                                                      Days >0.5 dv.....           76           15            6           61           70
                                                                      Days >1.0 dv.....           29            2            1           27           28
                                                   UPBU.............  Max dv...........        2.368        0.942        0.890        1.425        1.478
                                                                      Days >0.5 dv.....           46            6            4           40           42

[[Page 934]]

 
                                                                      Days >1.0 dv.....           13            0            0           13           13
Monticello....................  Source (Unit 1, 2  CACR.............  Max dv...........       10.498        6.121        2.079        4.377        8.419
                                 and 3).
                                                                      Days >0.5 dv.....          152          107           28           45          124
                                                                      Days >1.0 dv.....          111           54            8           57          103
                                                   WIMO.............  Max dv...........        5.736        2.769        0.774        2.968        4.962
                                                                      Days >0.5 dv.....           67           35            4           32           63
                                                                      Days >1.0 dv.....           40           14            0           26           40
                                Unit 3...........  CACR.............  Max dv...........        4.632        0.905        0.914        3.728        3.719
                                                                      Days >0.5 dv.....           79            5            5           74           74
                                                                      Days >1.0 dv.....           32            0            0           32           32
                                                   WIMO.............  Max dv...........        2.282        0.462        0.364        1.820        1.918
                                                                      Days >0.5 dv.....           31            0            0           31           31
                                                                      Days >1.0 dv.....            7            0            0            7            7
--------------------------------------------------------------------------------------------------------------------------------------------------------


                                 Table 18--Visibility Benefit of Scrubber Upgrades: Coal-Fired Units (CALPUFF Modeling)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                   Visibility impact               Visibility benefit
                                                                                        ----------------------------------------------------------------
         Facility name            Emission unit       Class I area          Metric                                                               WFGD
                                                                                           Baseline    DSI (50%)    WFGD (98%)  DSI benefit    benefit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Martin Lake                     Source (Units 1,   CACR.............  Max dv...........         4.46         2.27         1.86         2.18         2.60
                                 2 & 3).
                                                                      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 \1\................  Source (Unit 1, 2  CACR.............  Max dv...........         6.57         3.68         1.70         2.89         4.87
                                 and 3).
                                                                      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           61        13.67           42        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        34.67            6        25.33           54
                                                                      Days >1.0 dv Avg.        39.33        16.67         0.67        22.67        38.67
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ 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
----------------------------------------------------------------------------------------------------------------
                                                           Baseline
                                                       visibility impact                      Visibility benefit
          Facility name              Emission unit     from source (most  Visibility benefit   of 0.0015% S fuel
                                                       impacted Class I   of 0.3% S fuel oil          oil
                                                             area)
----------------------------------------------------------------------------------------------------------------
Stryker                           ST2...............  CALPUFF 0.65% S:    CALPUFF (0.3% S):   CALPUFF: 0.522 dv
                                                       0.786 dv @ CACR     0.263 dv @ CACR     @ CACR (Facility)
                                                       (Facility).         (Facility).
Graham                            Unit 2............  CALPUFF 0.69% S:    CALPUFF (0.3% S):   CALPUFF: 0.851 dv
                                                       1.228 dv @ WIMO     0.465 dv @ WIMO     @ WIMO (Facility)
                                                       (Facility).         (Facility.
Wilkes                            Units 1, 2, 3.....  CALPUFF 0.43% S:    CALPUFF (0.1% S):   CALPUFF: 0.037 dv
                                                       0.698 dv @ CACR     0.029 dv @ CACR     @ CACR (Facility)
                                                       (Facility).         (Facility).
Newman \1\                        Unit 2............  N/A...............  N/A...............  N/A
                                  Unit 3............  N/A...............  N/A...............  N/A
                                  Unit 4............  N/A...............  N/A...............  N/A
Calaveras                         Sommers...........  CAMx: 1.513 dv @    0.004 dv @ CACR...  0.008 dv @ CACR
                                  Unit 1............   WIMO (Source);
                                                       0.106 dv @ CACR
                                                       (Unit).

[[Page 935]]

 
                                  Sommers...........  CAMx: 1.513 dv @    0.023 @ CACR......  0.047 @ CACR
                                  Unit 2............   WIMO (Source);
                                                       0.180 dv @ CACR
                                                       (Unit).
----------------------------------------------------------------------------------------------------------------
\1\ 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 SO2 and NOX 
were covered separately by participation in CSAPR (allowing 
consideration of PM emissions in isolation). Because of the CSAPR 
remand and resulting uncertainty regarding SO2 and 
NOX 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\
---------------------------------------------------------------------------

    \105\ 70 FR 39163-39164.
---------------------------------------------------------------------------

    Second, with respect to gas-fired units, which have inherently low 
emissions of PM (as well as SO2), 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\
---------------------------------------------------------------------------

    \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
----------------------------------------------------------------------------------------------------------------
                                                      Fuel type
         Facility name               Unit ID          (primary)        SO2 control(s)         PM control(s)
----------------------------------------------------------------------------------------------------------------
Big Brown......................               1  Coal..............  ..................  Baghouse +
                                                                                          Electrostatic
                                                                                          Precipitator.
Big Brown......................               2  Coal..............  ..................  Baghouse +
                                                                                          Electrostatic
                                                                                          Precipitator.
Coleto Creek...................               1  Coal..............  ..................  Baghouse.
Harrington Station.............            061B  Coal..............  ..................  Electrostatic
                                                                                          Precipitator.
Harrington Station.............            062B  Coal..............  ..................  Baghouse.
J T Deely......................               1  Coal..............  ..................  Baghouse.
J T Deely......................               2  Coal..............  ..................  Baghouse.
Martin Lake....................               1  Coal..............  Wet Limestone.....  Electrostatic
                                                                                          Precipitator.
Martin Lake....................               2  Coal..............  Wet Limestone.....  Electrostatic
                                                                                          Precipitator.
Martin Lake....................               3  Coal..............  Wet Limestone.....  Electrostatic
                                                                                          Precipitator.
Monticello.....................               1  Coal..............  ..................  Baghouse +
                                                                                          Electrostatic
                                                                                          Precipitator.
Monticello.....................               2  Coal..............  ..................  Baghouse +
                                                                                          Electrostatic
                                                                                          Precipitator.
Monticello.....................               3  Coal..............  Wet Limestone.....  Electrostatic
                                                                                          Precipitator.
Fayette........................               1  Coal..............  Wet Limestone.....  Electrostatic
                                                                                          Precipitator.
Fayette........................               2  Coal..............  Wet Limestone.....  Electrostatic
                                                                                          Precipitator.
W A Parish.....................            WAP5  Coal..............  ..................  Baghouse.
W A Parish.....................            WAP6  Coal..............  ..................  Baghouse.
Welsh Power Plant..............               1  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

[[Page 936]]

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 FIP. We understand the coal-fired units covered by 
this proposal to be subject to MATS, but to the extent the units may be 
following alternate limits that differ from the surrogate PM limits 
found in MATS, we welcome comments on different, appropriately 
stringent limits reflective of current control capabilities.\112\ 
Because we anticipate that any limit we assign should be achieved by 
current control capabilities, we propose that compliance can be met at 
the effective date of the rule. To address periods of startups and 
shutdowns, we are further proposing that PM BART for these units will 
additionally be met by following the work practice standards specified 
in 40 CFR part 63, subpart UUUUU, Table 3, and using the relevant 
definitions in 63.10042. We are proposing that the demonstration of 
compliance can be satisfied by the methods for demonstrating compliance 
with filterable PM limits that are specified in 40 CFR part 63, subpart 
UUUUU, Table 7. However, we would give consideration to commenter-
submitted requests for alternate or additional methods of demonstrating 
compliance.
---------------------------------------------------------------------------

    \111\ 77 FR 9304, 9450, 9458 (February 16, 2012) (codified at 40 
CFR 60.42 Da(a), 60.50 Da(b)(1)); 40 CFR part 63 Subpart UUUUU--
National Emission Standards for Hazardous Air Pollutants: Coal- and 
Oil-Fired Electric Utility Steam Generating Units.
    \112\ The various limits are provided at 40 CFR part 63, subpart 
UUUUU, Table 2 (``Emission Limits for Existing EGUs'').
---------------------------------------------------------------------------

BART Analysis for PM for Gas-Fired Units
    We note that PM emissions for the gas-only fired units that are 
subject to BART are inherently low.\113\ We therefore conclude that PM 
emissions from natural gas firing is so minimal that the installation 
of any additional PM controls on the unit would likely achieve very low 
emissions reductions and have minimal visibility benefits. As there are 
no appropriate add-on controls and the status quo reflects the most 
stringent controls, we are proposing to make the requirement to burn 
pipeline natural gas federally enforceable. We note that in addition to 
satisfying PM BART, this limitation will also serve to satisfy 
SO2 BART for these gas-fired units, as well as the fuel-oil 
units when they fire natural gas. We are proposing that PM and 
SO2 BART for gas fired-units will limit fuel to pipeline 
natural gas, as defined at 40 CFR 72.2.
---------------------------------------------------------------------------

    \113\ AP 42, Fifth Edition, Volume 1, Chapter 1: External 
Sources, Section 1.4, Natural Gas Combustion, available here: 
https://www3.epa.gov/ttn/chief/ap42/ch01/final/c01s04.pdf.
---------------------------------------------------------------------------

    The available PM controls for gas units that also burn fuel oil are 
the same for the coal-fired units. We would expect similar costs for 
installing a baghouse on a typical gas-fired boiler that occasionally 
burns fuel oil. Again, our visibility impact modeling indicates that 
the baseline PM emissions of these units are very small, so we expect 
that the visibility improvement from the installation of a baghouse to 
be a small fraction on the order of 1-3% of the visibility impacts from 
the facility. We are confident that the cost of retrofitting the 
subject units with a baghouse would be extremely high compared to the 
visibility benefit for any of the units currently fitted with an ESP. 
We conclude that the cost of a baghouse does not justify the minimal 
expected improvement in visibility for these units. Accordingly, we are 
proposing that the fuel content limits for oil burning that we propose 
to meet SO2 BART will also satisfy PM BART.

[[Page 937]]

    Lastly, should our assumptions regarding the frequency and type of 
fuel oil burned in these units significantly change, we expect that 
Texas will address such a change appropriately in its SIP, which we 
will review in the next planning period.

D. How, if at all, do issues of ``Grid Reliability'' relate to the 
proposed BART determinations?

    On July 15, 2016, a preliminary order of the Fifth Circuit Court of 
Appeals took the view that EPA's Texas-Oklahoma FIP (81 FR 295, January 
5, 2016) gave a ``truncated discussion of grid reliability'' and 
additionally stated that ``the agency may not have fulfilled its 
statutory obligation to consider the energy impacts of the FIP.'' The 
Court's preliminary ruling made particular reference to ``the explicit 
directive in the [CAA] that implementation plans `take[ ] into 
consideration . . . the energy . . . impacts of compliance,' 42 U.S.C. 
7491(g)(1).'' \114\ Because the BART requirement at issue in this 
proposal has similar language on energy impacts of compliance appearing 
at 42 U.S.C. 7491(g)(2), we wish to provide a clear explanation on how 
grid-related considerations for EGUs could bear on this proposal.
---------------------------------------------------------------------------

    \114\ EPA Guidance on this statutory language specifically 
explains that energy impacts are a matter of whether ``energy 
requirements associated with a control technology result in energy 
penalties.'' U.S. EPA, Office of Air Quality Planning and Standards, 
``Guidance for Setting Reasonable Progress Goals under the Regional 
Haze Program,'' (June 1, 2007 rev), at Page 5-2.
---------------------------------------------------------------------------

    First, the BART factor for energy impacts of compliance does not 
call for the examination of grid reliability considerations from 
alleged plans to shut down or retire a unit rather than comply with a 
more stringent emission limit or limits. The language instead calls for 
consideration of energy impacts from complying by installing retrofit 
controls on a source that continues in operation. In this regard, our 
proposal follows the required BART Guidelines for EGUs.\115\ The 
Guidelines explain that the energy impacts factor relates to the 
penalties and benefits that may be associated with the assessment of a 
control option, e.g., whether (for power penalties) the operation of 
add-on control technology subtracts from the productive yield of 
electricity from an EGU (what is sometimes termed an auxiliary or 
parasitic load).\116\ It is also useful to note that the statutory 
text, while using the word ``energy,'' can apply to sources that do not 
produce energy or electricity. Thus, the statutory text regarding 
``energy impacts'' of compliance with BART is not confined to the power 
generating industry and does not dictate that we study grid reliability 
issues.
---------------------------------------------------------------------------

    \115\ The promulgation of the Guidelines was required by 42 
U.S.C. 7491(b)(1). Adherence to the Guidelines is mandatory for 
fossil-fuel fired generating power plants having total generating 
capacities ``in excess of 750 megawatts.''
    \116\ Other CAA provisions requiring consideration of ``energy 
impacts'' or ``energy requirements of the control technology'' are 
understood similarly. See, e.g., CAA section 169 (the 1977 ``best 
available control technology'' requirement with consideration of 
``energy . . . impacts''); see also CAA section 108 (``energy 
requirements . . . of the emission control technology; ``energy . . 
. impact of such processes, procedures, and methods [to reduce or 
control air pollution''); section 111 (``taking into account . . . 
energy requirements'' of an emission limitation), etc.
---------------------------------------------------------------------------

    We have considered whether this topic has any separate relevance to 
our proposal. Various court filings, news accounts, and industry market 
reports suggest that some source operators for some Texas BART units 
may be contemplating unit retirements. The BART Guidelines directly 
address such scenarios under the ``remaining useful life'' factor: 
``there may be situations where a source operator intends to shut down 
a source . . . . but wishes to retain the flexibility to continue 
operating beyond that date in the event, for example, the market 
conditions change.'' \117\ The Guidelines advise that a source that is 
willing to assure a permanent stop in operations with a federally- or 
State-enforceable restriction preventing further operation may obtain a 
short remaining useful life for BART analysis purposes that could then 
factor in the overall cost analysis.\118\ As the Guidelines state, 
``Where the remaining useful life is less the than the time period for 
amortizing costs, you should use this shorter period in your cost 
calculations.'' \119\ We have no information on enforceable 
restrictions of this type for any of the units that we propose to be 
subject to BART. Absent that, we must assume that controls installed on 
the BART units will experience their full useful life. Affected sources 
are free to submit information as part of their comments containing 
appropriate enforceable documentation of shorter remaining useful 
lives.
---------------------------------------------------------------------------

    \117\ Id. at 39169-39170.
    \118\ Similar to calculating a mortgage, remaining useful life 
is used in our cost-effectiveness analysis to calculate the annual 
cost of a particular control. The longer the remaining useful life, 
the smaller the total annualized cost, and the more cost-effective 
the control.
    \119\ Id. at 39169.
---------------------------------------------------------------------------

    We note, however, that the Guidelines recognize there may be cases 
where the installation of controls, even when cost-effective, would 
``affect the viability of continued plant operations.'' \120\ Under the 
Guidelines, where there are ``unusual circumstances,'' we are permitted 
to take into consideration ``the conditions of the plant and the 
economic effects of requiring the use of a control technology.'' \121\ 
If the effects are judged to have a ``severe impact,'' those effects 
can be considered in the selection process. In such cases, the 
Guidelines counsel that any determinations be made with an economic 
analysis with sufficient detail for public review on the ``specific 
economic effects, parameters, and reasoning.'' \122\ It is recognized, 
by the language of the Guidelines, that any such review process may 
entail the use of sensitive business information that may be 
confidential. The ADDRESSES section of this proposal explains how to 
submit confidential information with comments, and when claims of 
confidential business information, or CBI, are asserted with respect to 
any information that is submitted, the EPA regulations at 40 CFR part 
2, subpart B-Confidentiality Business Information apply to protect it. 
All of that said, the Guidelines also advise that we may ``consider 
whether other competing plants in the same industry have been required 
to install BART controls if this information is available.'' \123\ 
Because Texas EGUs are among the last to have SO2 BART 
determinations, this information is available. It is indeed the case 
that other similar EGUs have been required to install the same types of 
SO2 BART controls that we are proposing as very cost 
effective.\124\
---------------------------------------------------------------------------

    \120\ 70 FR 39103, 39171 (July 6, 2005), [40 CFR part 51, App. 
Y].
    \121\ Id.
    \122\ 70 FR at 39171.
    \123\ Id.
    \124\ See for instance, the EIA information we present elsewhere 
in this notice in which we summarize the hundreds of scrubber 
installations that have been performed on similar EGUs.
---------------------------------------------------------------------------

    We have considered the state of available information on whether 
the proposed controls could affect the viability of continued plant 
operations. On this point, we note that we are proposing BART 
determinations for several units where SO2 control 
requirements were separately promulgated as part of the Texas-Oklahoma 
FIP. These under-controlled EGU sources are: Big Brown 1 and 2; 
Monticello 1, 2 and 3; Martin Lake 1, 2 and 3; and Coleto Creek 1. In 
litigation over the reasonable progress FIP, various declarations were 
filed on the issues of alleged forced closures and alleged reliability 
impacts. These declarations have been compiled and added to the docket 
for this rulemaking.

[[Page 938]]

By our review, these declarations do not appropriately inform or 
substantiate source-specific allegations of ``unusual circumstances'' 
that may have a severe impact on plant operations, because they do not 
offer any site-specific information.\125\ Thus, we are unable to 
conclude that the proposed cost-effective BART controls would severely 
impact plant operations. Generalized claims of possible retirements and 
discussions on attributes of the market design of the Electric 
Reliability Council of Texas (ERCOT) cannot inform the statutorily 
required, source-specific BART determinations.
---------------------------------------------------------------------------

    \125\ Certain statements in declarations from representatives of 
both Luminant and Coleto Creek, who are the source owners of these 
facilities, cited compliance planning efforts that would be 
consistent with continued plant operations.
---------------------------------------------------------------------------

    As a predicate to studying effects on transmission or reliability 
as ``unusual circumstances,'' we would require site-specific 
information from any source that would wish for us to potentially 
consider ``affordability of controls,'' under the terms specified in 
the Guidelines. Source owners may submit information, including 
information claimed to be CBI, for our assessment and consideration to 
potentially support an economic analysis that might be used in the BART 
selection process. As suggested by the Guidelines, the information 
necessary to inform our judgment would likely entail source-specific 
information on ``product prices, the market share, and the 
profitability of the source.'' Consideration of such information does 
not dictate what will be selected as a ``best'' alternative under the 
Guidelines, but it will substantiate the likelihood of a retirement 
scenario that would then give the parameters for: A non-conjectural 
examination of grid reliability issues; judging the significance or 
insignificance of such issues; and assessing whether such issues could 
be avoided through appropriate transmission planning. In sum, unless we 
are able to substantiate an ``affordability of controls'' problem for 
any particular unit and substantiate that a particular unit retirement 
would not be happening anyway at about the same time, alleged grid 
reliability impacts are speculative and are not able to inform these 
required BART determinations. As a final note, we acknowledge Executive 
Order 13211 (``Actions Concerning Regulations That Significantly Affect 
Energy Supply, Distribution, and Use''). In cases where it does apply, 
agencies are ordered to prepare a Statement of Energy Effects for 
submission to the Administrator of the Office of Information and 
Regulatory Affairs (OIRA), Office of Management and Budget. This EGU 
BART proposal is not considered a significant regulatory action under 
Executive Order 12866, so the proposed action cannot be a ``significant 
energy action'' for purposes of Executive Order 13211 on that basis. 
This proposed action has also not been designated a significant energy 
action by the Administrator of OIRA, so Executive Order 13211 could not 
apply under that separate basis. With this proposal, there are no 
anticipated adverse effects on energy supply, distribution, or use that 
are meaningful or distinguishable from any other scenario where an EGU 
is expected to install cost-effective pollution controls required by 
the CAA.

IV. Our Weighing of the Five BART Factors

    Below we present our reasoning for proposing our BART 
determinations for 29 EGUs in Texas, based on our analysis and weighing 
of the Five BART Factors: (1) Proposed SO2 and PM BART 
determinations for 12 coal-fired units with no SO2 controls, 
(2) proposed BART SO2 and PM BART determinations for 6 coal-
fired units with existing scrubbers, (3) proposed SO2 and PM 
BART determinations 7 gas-fired units that occasionally burn fuel oil, 
and (4) proposed PM BART determinations for 4 gas-fired units.
    In previous sections of this proposal, we have described how we 
assessed the five BART factors. In no case do we see any instance in 
which our assessment of energy impacts is a determining factor in 
assessing BART.\126\ Also, in no case do we see any instance in which 
our assessment of the remaining useful life is a determining factor in 
assessing BART. Should a facility indicate in comments to us that the 
remaining useful life is less than the 30 years we have assumed in our 
control cost analyses, and is willing to enter into an enforceable 
document to that effect, we will adjust our cost-effectiveness 
calculation accordingly in making our final decision. In two cases, 
Harrington units 061B and 062B, we have limited our SO2 
control analysis for Harrington to DSI and dry scrubbers due to 
potential non-air quality concerns. In all other instances, we conclude 
that the cost of compliance, and the visibility benefits of controls 
are the controlling BART factors in our weighing of the five BART 
factors.
---------------------------------------------------------------------------

    \126\ In addition to our assessment of energy impacts, also see 
our discussion in Section III.D concerning our conclusion that 
energy impact considerations do not relate to potential electrical 
grid reliability issues.
---------------------------------------------------------------------------

    In considering cost-effectiveness and visibility benefit, we do not 
eliminate any controls based solely on the magnitude of the cost-
effectiveness value, nor do we use cost-effectiveness as the primary 
determining factor. Rather, we compare the cost-effectiveness to the 
anticipated visibility benefit, and we take note of any additional 
considerations.\127\ Also, in judging the visibility benefit we do not 
simply examine the highest value for a given Class I area, or a group 
of Class I areas, but we also consider the cumulative visibility 
benefit for all affected Class I areas, the number of days in a 
calendar year in which we see significant improvements, and other 
factors.\128\
---------------------------------------------------------------------------

    \127\ For instance, as we discuss later in Section IV.C why we 
believe that there are certain mitigating factors that should be 
considered when assessing BART for the gas-fired units that 
occasionally burn fuel oil.
    \128\ See for example 70 39130: ``comparison thresholds can be 
used in a number of ways in evaluating visibility improvement (e.g. 
the number of days or hours that the threshold was exceeded, a 
single threshold for determining whether a change in impacts is 
significant, a threshold representing an x percent change in 
improvement, etc.).''
---------------------------------------------------------------------------

    First, we note that all of the sources addressed in our proposed 
BART determinations have already been shown to cause or contribute to 
visibility impairment at a Class I area as a condition of being 
subject-to-BART as part of the BART screening analysis. This analysis 
eliminated any BART-eligible source that emits lower amounts of 
visibility impacting pollutants, or otherwise impacts any Class I area 
at less than 0.5 deciviews. In fact, all of the individual units that 
we are proposing for BART controls exceed 0.5 deciviews on a unit 
basis, with most exceeding 1.0 deciview impact on a unit basis. As a 
consequence, all of the units we are proposing for BART controls are 
among the largest emitters of visibility impacting pollutants in Texas. 
A number of these units (i.e., Big Brown, Martin Lake, Monticello, and 
Coleto Creek) were previously determined by us to require the same type 
and level of controls under the reasonable progress and long-term 
strategy provisions of the Regional Haze Rule that we are proposing 
here.\129\
---------------------------------------------------------------------------

    \129\ See our recent Texas-Oklahoma FIP, 81 FR 321.
---------------------------------------------------------------------------

    Second, not discounting our approach of considering both cost-
effectiveness and visibility benefit in unison, the cost-effectiveness 
of all of the controls that form the basis of our proposed BART 
determinations are within a range found to be acceptable in other 
cases.\130\ As we

[[Page 939]]

stated in the BART Rule, ``[a] reasonable range would be a range that 
is consistent with the range of cost effectiveness values used in other 
similar permit decisions over a period of time.'' \131\
---------------------------------------------------------------------------

    \130\ See for instance 79 FR 5048 (January 30, 2014): Jim 
Bridger BART determination of LNB/SOFA + SCR on Units 1-4; 77 FR 
18070 (March 26, 2012): EPA proposed approval of Colorado's BART 
determination of SCR for Hayden Unit 2, later finalized at 77 FR 
76871 (December 31, 2012).
    \131\ 70 FR 39168 (July 6, 2005).
---------------------------------------------------------------------------

A. SO2 BART for Coal-fired Units With No SO2 
Controls

    As we have discussed in this proposal and in our TSD, we have 
assumed two DSI control levels corresponding to 50% control and either 
a maximum of 80% or 90% control, depending on the particulate matter 
control device in use.\132\ We did this to address the BART Guidelines 
directive that in evaluating technically feasible alternatives we ``(1) 
[ensure we] express the degree of control using a metric that ensures 
an ``apples to apples'' comparison of emissions performance levels 
among options, and (2) [give] appropriate treatment and consideration 
of control techniques that can operate over a wide range of emission 
performance levels.'' \133\ In most cases, the cost-effectiveness of 
the higher control level of DSI was higher than either SDA or wet FGD. 
This was not the case for Monticello Unit 2; Harrington Unit 062B; and 
J T Deely Units 1 and 2.
---------------------------------------------------------------------------

    \132\ Note for Harrington Unit 062B and Welsh 1, we further 
limited the maximum DSI control level to that of our calculated SDA 
control level.
    \133\ 70 FR 39166 (July 6, 2005).
---------------------------------------------------------------------------

    However, these maximum DSI control levels are theoretical and we 
believe that any DSI control level above 50% must be confirmed by 
onsite testing before we could propose a BART control based on it. As 
is evident in comparing the 50% control level to the higher control 
level, the cost-effectiveness of DSI worsens (higher $/ton) as the 
control level increases, and the certainty of any unit attaining that 
control level decreases. We therefore regard the cost-effectiveness 
values of the maximum DSI control levels as being useful in a basic 
comparison of cost-effectiveness between DSI and scrubbers, but we 
place much less weight on these values. We therefore conclude that 
given the uncertainty concerning the maximum control level of DSI, the 
greater control efficiency and resulting visibility benefit offered by 
scrubbers overrides any possible advantage DSI may hold in cost-
effectiveness. Should the affected facilities provide site-specific 
information to us in their comments that conflicts with this 
assumption, we will incorporate it into our final decision on 
SO2 BART and potentially re-evaluate DSI.
    As we indicate elsewhere in our proposal, both SDA and wet FGD are 
mature technologies that are in wide use throughout the United States. 
We are not aware of any unusual circumstances that exist for any of the 
sources that would serve to indicate they should not be viewed 
similarly to these hundreds of previous scrubber retrofits. In 
comparing wet FGD versus SDA we note that in a number of cases the 
cost-effectiveness of wet FGD is lower than the cost-effectiveness of 
SDA. In the remaining cases, we conclude that the incremental cost-
effectiveness of wet FGD over SDA, which we review in Section III.C.3.a 
is reasonable, and the improved control and visibility benefit offered 
by wet FGD overrides the small penalty in cost-effectiveness FGD has in 
comparison to SDA. We propose that with the exception of the Harrington 
units, SO2 BART for all other coal-fired units should be 
based on the wet FGD control levels we have used in our BART analyses. 
We propose that SO2 BART for the Harrington units should be 
based on the SDA control levels we have used in our BART analyses. 
Below we discuss our consideration of the cost-effectiveness and 
anticipated visibility benefits of controls. See section III.C.5 for 
additional information on the anticipated visibility benefits from each 
level of control modeled. See the BART Modeling TSD for a complete 
summary of our visibility benefit analysis of controls, including 
modeled benefits and impacts at all Class I areas included in the 
modeling analyses and additional metrics considered in the assessment 
of visibility benefits.
    CAMx model results shown in the tables below summarize the benefits 
from the recommended controls at the two Class I areas most impacted by 
the source or unit in the baseline modeling. The benefit is calculated 
as the difference between the maximum impact modeled for the baseline 
and the maximum impact level modeled under the control scenario. Also 
summarized are the cumulative benefit and the number of days impacted 
over 0.5 and 1.0 dv. Cumulative benefit is calculated as the difference 
in the maximum visibility impacts from the baseline and control 
scenario summed across the 15 Class I areas included in the CAMx 
modeling. The baseline total cumulative number of days over 0.5 (1.0) 
dv is calculated as the sum of the number of modeled days at each of 
the 15 Class I area impacted over the threshold in the baseline 
modeling. The reduction in number of days is calculated as the sum of 
the number of days over the chosen threshold across the 15 Class I 
areas included in the CAMx modeling for the baseline scenario 
subtracted by the number of days over the threshold for the control 
scenario. The CALPUFF cumulative model results only consider those 
Class I areas within the typical range of CALPUFF and not all 15 Class 
I areas included in the CAMx modeling.
1. Big Brown 1 & 2
    In reviewing the Big Brown units, we conclude that the installation 
of wet FGD will result in very significant visibility benefits. We 
summarize some of these visibility benefits in the tables below:

                          Table 21--Wet FGD Visibility Benefits at Big Brown (CALPUFF)
----------------------------------------------------------------------------------------------------------------
                                                                       Total        Cumulative      Cumulative
                                  Improvement at  Improvement at    cumulative     reduction in    reduction in
             Source                   Wichita       Caney Creek     visibility    number of days  number of days
                                     Mountains         (dv)        benefit  (dv)   above 0.5  dv   above 1.0  dv
                                       (dv)                             \1\             \2\             \2\
----------------------------------------------------------------------------------------------------------------
Big Brown Units 1 & 2...........            3.83            3.55            7.38          151.67          101.33
----------------------------------------------------------------------------------------------------------------
\1\ Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and
  control scenario runs summed across the following Class I areas: Caney Creek and Wichita Mountains.
\2\ Using the three years (2001-2003) of CALPUFF modeling results an annual average of the number of days
  reduced was calculated. The Reduction in number of days is calculated as the sum of the number of days over
  the chosen threshold across the following Class I areas for the baseline scenario subtracted by the number of
  days over the threshold for the control scenario: Caney Creek and Wichita Mountains.


[[Page 940]]

    In evaluating Big Brown, we note there are two Class I areas within 
the typical range that CALPUFF has been used for assessing visibility 
impacts. Using the three years of 2001-2003 CALPUFF modeling results, 
we assessed the annual average number of days when the facility impacts 
were greater than 0.5 del-dv at each of the Class I areas and then 
summed this value for each of the Class I areas to yield an annual 
average cumulative value for total number of days impacts were above 
0.5 del-dv at all Class I areas within typical CALPUFF range. The 
reduction in the number of days (annual average) was calculated as the 
cumulative value of the number of days over the 0.5 del-dv threshold 
across the Class I areas for the baseline scenario subtracted by the 
cumulative number of days over the threshold for the control scenario. 
For the two Class I areas that are within the range that CALPUFF is 
typically used, the 2001-2003 CALPUFF modeling results indicate that 
wet FGD on both units will eliminate 151.6 days annually (3 year 
average) when the facility has impacts greater than 0.5 delta deciview. 
The same analysis was also calculated using a 1.0 del-dv threshold and 
is reported in the table above. DSI operated at 50% control results in 
approximately half of the visibility benefits in terms of dv benefits 
at the most impacted Class I areas and about 1/3rd to half the 
cumulative benefits over the class I areas included in the modeling 
analysis.

                            Table 22--Wet FGD Visibility Benefits at Big Brown (CAMx)
----------------------------------------------------------------------------------------------------------------
                                                                       Total      Baseline total
                                  Improvement at  Improvement at    cumulative      cumulative     Reduction in
              Unit                    Wichita       Caney Creek     visibility    number of days  number of days
                                     Mountains         (dv)           benefit      over 0.5/1.0    above 0.5/1.0
                                       (dv)                           (dv)\1\         dv \2\          dv \3\
----------------------------------------------------------------------------------------------------------------
Big Brown 1.....................           1.909           1.606          12.728          174/44          174/44
Big Brown 2.....................           1.940           1.642          12.924          175/45          175/45
Source..........................           3.542           2.988          24.274         372/170         362/170
----------------------------------------------------------------------------------------------------------------
\1\ Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and
  control scenario runs summed across 15 Class I areas included in the CAMx modeling.
\2\ Baseline Total Cumulative number of days over 0.5 (1.0) dv is calculated as the sum of the number of modeled
  days at each of the 15 Class I area impacted over the threshold.
\3\ Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across
  the 15 Class I areas included in the CAMx modeling for the baseline scenario subtracted by the number of days
  over the threshold for the control scenario.

    CAMx modeling results indicate that wet FGD will eliminate all days 
impacted over 1dv at all Class I areas on a unit and source-wide basis, 
and eliminate all but 10 days across the impacted Class I areas where 
the source-wide impacts exceeds 0.5 dv. At the most impacted Class I 
area, wet FGD will on each unit result in visibility improvements of 
1.9 dv on the most impacted day. DSI operated at 50% control results in 
approximately half of the wet FGD visibility benefits at the most 
impacted Class I areas and half of the cumulative benefits over the 15 
class I areas included in the CAMx modeling.
    We also conclude that wet FGD is very cost-effective for both units 
at less than $1,200/ton and more cost-effective than DSI. Based on this 
consideration of the BART factors, we propose that SO2 BART 
for Big Brown Units 1 and 2 should be based on the installation of wet 
FGD at an emission limit of 0.04 lbs/MMBtu based on a 30 BOD.
2. Monticello 1 & 2
    Similar to the Big Brown units, the installation of wet FGD at 
Monticello Units 1 and 2 will result in very significant visibility 
benefits. We summarize some of these visibility benefits in the tables 
below:

                          Table 23--Wet FGD Visibility Benefits at Monticello (CALPUFF)
----------------------------------------------------------------------------------------------------------------
                                                                       Total      Baseline total    Cumulative
                                  Improvement at  Improvement at    cumulative      cumulative     reduction in
             Source                 Caney Creek       Wichita       visibility    number of days  number of days
                                       (dv)          Mountains     benefit  (dv)   over  0.5/1.0   above 1.0  dv
                                                       (dv)             \1\           dv \2\            \2\
----------------------------------------------------------------------------------------------------------------
Monticello Units 1, 2 & 3.......            4.87            2.70           10.25          224.67          164.67
----------------------------------------------------------------------------------------------------------------
\1\ Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and
  control scenario runs summed across the following Class I areas: Caney Creek, Wichita Mountains, and Upper
  Buffalo.
\2\ Using the three years (2001-2003) of CALPUFF modeling results an annual average of the number of days
  reduced was calculated. The Reduction in number of days is calculated as the sum of the number of days over
  the chosen threshold across the following Class I areas for the baseline scenario subtracted by the number of
  days over the threshold for the control scenario: Caney Creek, Wichita Mountains, and Upper Buffalo.

    In evaluating Monticello, we note there are three Class I areas 
within the typical range that CALPUFF has been used for assessing 
visibility impacts. Using the three years of 2001-2003 CALPUFF modeling 
results we assessed the annual average number of days when the facility 
impacts were greater than 0.5 del-dv at each of the Class I areas and 
then summed this value for each of the Class I areas to yield an annual 
average cumulative value for total number of days impacts were above 
0.5 del-dv at all Class I areas within typical CALPUFF range. The 
reduction in the number of days (annual average) was calculated as the 
cumulative value of the number of days over the 0.5 del-dv threshold 
across the Class I areas for the baseline scenario subtracted by the 
cumulative number of days over the threshold for the control scenario. 
For the three Class I areas that are within the range that CALPUFF is 
typically used, the 2001-2003 CALPUFF modeling results indicate wet FGD 
on both units will eliminate 224.6

[[Page 941]]

days annually (3 year average) when the facility has impacts greater 
than 0.5 delta deciview. The same analysis was also calculated using a 
1.0 del-dv threshold and is reported in the table above. DSI operated 
at 50% control results in approximately half of the wet FGD visibility 
benefits at the most impacted Class I area and half of the cumulative 
benefits.

                           Table 24--Wet FGD Visibility Benefits at Monticello (CAMx)
----------------------------------------------------------------------------------------------------------------
                                                                       Total      Baseline total
                                  Improvement at  Improvement at    cumulative      cumulative     Reduction in
              Unit                  Caney Creek       Wichita       visibility    number of days  number of days
                                       (dv)          Mountains     benefit  (dv)   over  0.5/1.0  above  0.5/1.0
                                                       (dv)             \1\           dv \2\           dv \3\
----------------------------------------------------------------------------------------------------------------
Monticello 1....................           3.783           1.989          12.708          197/67          191/67
Monticello 2....................           3.924           2.003          13.025          192/57          191/57
Source (including unit 3).......           8.419           4.962          31.553         520/293         460/278
----------------------------------------------------------------------------------------------------------------
\1\ Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and
  control scenario runs summed across 15 Class I areas included in the CAMx modeling.
\2\ Baseline Total Cumulative number of days over 0.5 (1.0) dv is calculated as the sum of the number of modeled
  days at each of the 15 Class I area impacted over the threshold.
\3\ Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across
  the 15 Class I areas included in the CAMx modeling for the baseline scenario subtracted by the number of days
  over the threshold for the control scenario.

    CAMx modeling results indicate that wet FGD will eliminate all days 
impacted over 1 dv at all Class I areas on a unit basis, and eliminate 
all but 15 days across the impacted Class I areas where the source-wide 
impacts exceeds 1 dv. We note that source-wide modeled benefits include 
benefits of 95% control scrubber upgrade on Unit 3. At the most 
impacted Class I area, wet FGD on each unit will each result in 
visibility improvements of 3.8-3.9 dv on the most impacted day at Caney 
Creek and 2 dv visibility benefits at Wichita Mountains. DSI operated 
at 50% control results in less than half of the wet FGD visibility 
benefits at the most impacted Class I areas and half of the cumulative 
benefits over the 15 class I areas included in the modeling.
    The wet FGD cost-effectiveness of $2,718/ton and $3,031/ton are 
higher than those for Big Brown, but these figures remain well within a 
range that we have previously found to be acceptable for BART, and we 
consider the very significant visibility benefits that will result 
justify the cost of wet FGD at the Monticello Units 1 and 2. The 50% 
control DSI cost-effectiveness is slightly less than that for wet-FGD, 
but results in much less visibility benefits. Based on our 
consideration of the BART factors, we therefore propose that 
SO2 BART for Monticello Units 1 and 2 should be based on the 
installation of wet FGD at an emission limit of 0.04 lbs/MMBtu based on 
a 30 BOD.
3. Coleto Creek 1
    In reviewing Coleto Creek Unit 1, we conclude that in comparison 
with the Monticello units, the installation of a wet FGD is more cost-
effective and results in lesser, but still significant visibility 
benefits. We summarize some of these visibility benefits in the table 
below:

                       Table 25--Wet FGD Visibility Benefits at Coleto Creek Unit 1 (CAMx)
----------------------------------------------------------------------------------------------------------------
                                                                       Total      Baseline total
                                  Improvement at  Improvement at    cumulative      cumulative     Reduction in
              Unit                    Wichita       Caney Creek     visibility    number of days  number of days
                                     Mountains         (dv)        benefit  (dv)   over 0.5/1.0    above 0.5/1.0
                                       (dv)                             \1\           dv \2\          dv \3\
----------------------------------------------------------------------------------------------------------------
Coleto Creek 1..................           0.668           0.606           5.233            17/0            17/0
----------------------------------------------------------------------------------------------------------------
\1\ Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and
  control scenario runs summed across 15 Class I areas included in the CAMx modeling.
\2\ Baseline Total Cumulative number of days over 0.5 (1.0) dv is calculated as the sum of the number of modeled
  days at each of the 15 Class I area impacted over the threshold.
\3\ Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across
  the 15 Class I areas included in the CAMx modeling for the baseline scenario subtracted by the number of days
  over the threshold for the control scenario.

    CAMx modeling results indicate that wet FGD will eliminate all days 
impacted over 0.5 dv at all Class I areas. At the most impacted Class I 
area, wet FGD will result in visibility improvements of 0.6 or more on 
the most impacted days at both Caney Creek and the Wichita Mountains. 
In addition, seven other Class I areas are improved by amounts ranging 
from 0.356 to 0.531 dv on the maximum impacted days with wet FGD. DSI 
operated at 50% control results in approximately half of the wet FGD 
visibility benefits at the most impacted Class I areas and half of the 
cumulative benefits over the 15 Class I areas included in the modeling.
    We also conclude that wet FGD is very cost-effective at $2,127/ton 
and well within a range that we have previously found to be acceptable 
and more cost-effective than DSI. We consider the significant 
visibility benefits that will result justify the cost of wet FGD at the 
Coleto Creek Unit 1. We therefore propose that SO2 BART for 
Coleto Creek Unit 1 should be based on the installation of wet FGD at 
an emission limit of 0.04 lbs/MMBtu based on a 30 BOD.
4. Welsh 1
    In reviewing Welsh Unit 1, we conclude that the installation of a 
wet FGD will result in significant visibility

[[Page 942]]

benefits. We summarize some of these visibility benefits in the tables 
below:

                         Table 26--Wet FGD Visibility Benefits at Welsh Unit 1 (CALPUFF)
----------------------------------------------------------------------------------------------------------------
                                                                       Total        Cumulative      Cumulative
                                  Improvement at  Improvement at    cumulative     reduction in    reduction in
             Source                 Caney Creek    Wichita Mtns.    visibility    number of days  number of days
                                       (dv)            (dv)        benefit (dv)    above 0.5 dv    above 1.0 dv
                                                                        \1\             \2\             \2\
----------------------------------------------------------------------------------------------------------------
Welsh 1.........................            0.72            0.41            1.66           56.67              15
----------------------------------------------------------------------------------------------------------------
\1\ Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and
  control scenario runs summed across the following Class I areas: Caney Creek, Wichita Mountains, and Upper
  Buffalo.
\2\ Using the three years (2001-2003) of CALPUFF modeling results an annual average of the number of days
  reduced was calculated. The reduction in number of days is calculated as the sum of the number of days over
  the chosen threshold across the following Class I areas for the baseline scenario subtracted by the number of
  days over the threshold for the control scenario: Caney Creek, Wichita Mountains, and Upper Buffalo.

    In evaluating Welsh we note there are three Class I areas within 
the typical range that CALPUFF has been used for assessing visibility 
impacts. Using the three years of 2001-2003 CALPUFF modeling results we 
assessed the annual average number of days when the facility impacts 
were greater than 0.5 del-dv at each of the Class I areas and then 
summed this value for each of the Class I areas to yield an annual 
average cumulative value for total number of days impacts were above 
0.5 del-dv at all Class I areas within typical CALPUFF range. The 
reduction in the number of days (annual average) was calculated as the 
cumulative value of the number of days over the 0.5 del-dv threshold 
across the Class I areas for the baseline scenario subtracted by the 
cumulative number of days over the threshold for the control scenario. 
For the three Class I areas that are within the range that CALPUFF is 
typically used, the 2001-2003 CALPUFF modeling results indicate wet FGD 
on both units will eliminate 56.67 days annually (3 year average) when 
the facility has impacts greater than 0.5 delta deciview. The same 
analysis was also calculated using a 1.0 del-dv threshold and is 
reported in the table above. CALPUFF modeling indicates that DSI 
operated at 50% results in approximately half the benefits of WGFD.

                          Table 27--Wet FGD Visibility Benefits at Welsh Unit 1 (CAMx)
----------------------------------------------------------------------------------------------------------------
                                                                       Total      Baseline total
                                  Improvement at  Improvement at    cumulative      cumulative     Reduction in
              Unit                  Caney Creek        Mingo        visibility    number of days  number of days
                                       (dv)         Wilderness     benefit  (dv)   over 0.5/1.0    above 0.5/1.0
                                                       (dv)             \1\           dv \2\          dv \3\
----------------------------------------------------------------------------------------------------------------
Welsh 1.........................           1.521           0.579           4.683            65/9            60/9
Source (Welsh 1 & 2)............           3.754           1.973          13.179          211/72          206/72
----------------------------------------------------------------------------------------------------------------
\1\ Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and
  control scenario runs summed across 15 Class I areas included in the CAMx modeling.
\2\ Baseline Total Cumulative number of days over 0.5 (1.0) dv is calculated as the sum of the number of modeled
  days at each of the 15 Class I area impacted over the threshold.
\3\ Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across
  the 15 Class I areas included in the CAMx modeling for the baseline scenario subtracted by the number of days
  over the threshold for the control scenario.

    CAMx modeling results indicate that wet FGD on unit 1 will 
eliminate all days impacted by the unit over 1 dv at all Class I areas 
and all but 5 days impacted over 0.5 dv. At the most impacted Class I 
area, wet FGD on unit 1 will result in visibility improvements of 1.521 
dv on the most impacted days at Caney Creek. In addition to the 
visibility benefits at Caney Creek and Mingo, visibility benefits at 
two additional Class I areas exceed 0.5 dv. We note that source-wide 
benefits shown include the benefits from the shutdown of unit 2. In 
addition, cumulative benefits from wet FGD on unit 1 over all 15 Class 
I areas exceeds 4.5 dv on the maximum impacted days. DSI operated at 
50% control results in approximately half of the wet FGD visibility 
benefits at the most impacted Class I areas and half of the cumulative 
benefits over the 15 class I areas included in the modeling.
    We conclude that although at $3,824/ton, the cost-effectiveness of 
wet FGD is higher than for other facilities, it remains within a range 
that we have previously found to be acceptable. We consider the 
significant visibility benefits that will result from the installation 
of wet FGD at Welsh Unit 1 to justify the cost. DSI at 50% control is 
slightly more cost-effective but results in much less visibility 
benefit. We therefore propose that SO2 BART for Welsh Unit 1 
should be based on the installation of wet FGD at an emission limit of 
0.04 lbs/MMBtu based on a 30 BOD.
5. Harrington 061B & 062B
    In reviewing Harrington, we conclude that the installation of SDA 
on Units 061B and 062B will result in significant visibility benefits. 
We summarize some of these visibility benefits in the tables below:

[[Page 943]]



                            Table 28--SDA Visibility Benefits at Harrington (CALPUFF)
----------------------------------------------------------------------------------------------------------------
                                                                       Total        Cumulative      Cumulative
                                  Improvement at  Improvement at    cumulative     reduction in    reduction in
             Source                 Salt Creek     Wichita Mtns.    visibility    number of days  number of days
                                       (dv)            (dv)        benefit  (dv)   above 0.5  dv   above 1.0  dv
                                                                        \1\             \2\             \2\
----------------------------------------------------------------------------------------------------------------
Harrington 061B & 062B..........            0.45            0.74            2.56           53.67              26
----------------------------------------------------------------------------------------------------------------
\1\ Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and
  control scenario runs summed across the following Class I areas: Salt Creek, Wichita Mountains, Pecos,
  Carlsbad Caverns, and Wheeler Peak.
\2\ Using the three years (2001-2003) of CALPUFF modeling results an annual average of the number of days
  reduced was calculated. The reduction in number of days is calculated as the sum of the number of days over
  the chosen threshold across the following Class I areas for the baseline scenario subtracted by the number of
  days over the threshold for the control scenario: Salt Creek, Wichita Mountains, Pecos, Carlsbad Caverns, and
  Wheeler Peak.

    In evaluating Harrington we note there are five Class I areas 
within the typical range that CALPUFF has been used for assessing 
visibility impacts. Using the three years of 2001-2003 CALPUFF modeling 
results we assessed the annual average number of days when the facility 
impacts were greater than 0.5 del-dv at each of the Class I areas and 
then summed this value for each of the Class I areas to yield an annual 
average cumulative value for total number of days impacts were above 
0.5 del-dv at all Class I areas within typical CALPUFF range. The 
reduction in the number of days (annual average) was calculated as the 
cumulative value of the number of days over the 0.5 del-dv threshold 
across the Class I areas for the baseline scenario subtracted by the 
cumulative number of days over the threshold for the control scenario. 
For the five Class I areas that are within the range that CALPUFF is 
typically used, the 2001-2003 CALPUFF modeling results indicate wet FGD 
on both units will eliminate 53.6 days annually (3 year average) when 
the facility has impacts greater than 0.5 delta deciview. The same 
analysis was also calculated using a 1.0 del-dv threshold and is 
reported in the table above. CALPUFF modeling indicates that DSI 
operated at 50% results in approximately half the benefits of WGFD.

                             Table 29--SDA Visibility Benefits at Harrington (CAMx)
----------------------------------------------------------------------------------------------------------------
                                                                       Total      Baseline total
                                  Improvement at  Improvement at    cumulative      cumulative     Reduction in
              Unit                  Salt Creek        Wichita       visibility    number of days  number of days
                                       (dv)       Mountains (dv)   benefit (dv)    over 0.5/1.0    above 0.5/1.0
                                                                        \1\           dv \2\          dv \3\
----------------------------------------------------------------------------------------------------------------
Harrington 061B.................           1.170           0.643           4.832            17/5            11/3
Harrington 062B.................           1.279           0.723           5.379            17/5            11/3
Source (061B & 0622B)...........           2.053           1.130           9.329           51/17           37/11
----------------------------------------------------------------------------------------------------------------
\1\ Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and
  control scenario runs summed across 15 Class I areas included in the CAMx modeling.
\2\ Baseline Total Cumulative number of days over 0.5 (1.0) dv is calculated as the sum of the number of modeled
  days at each of the 15 Class I area impacted over the threshold.
\3\ Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across
  the 15 Class I areas included in the CAMx modeling for the baseline scenario subtracted by the number of days
  over the threshold for the control scenario.

    CAMx modeling results indicate SDA on these units will eliminate 
more than half of all days impacted by the units over 1 dv and 0.5 dv 
at all Class I areas. At the most impacted Class I areas, SDA on each 
unit will each result in visibility improvements of approximately 1.2 
dv on the most impacted days at Salt Creek and 0.6-0.7 dv at Wichita 
Mountains, reducing the number of days impacted over 0.5 and 1.0 dv at 
these Class I areas. In addition, cumulative benefits from SDA on both 
units over all 15 Class I areas exceeds 9.3 dv on the maximum impacted 
days. DSI operated at 50% control results in approximately half of the 
SDA visibility benefits at the most impacted Class I areas and half of 
the cumulative benefits over the 15 class I areas included in the 
modeling.
    We also conclude that SDA is cost-effective at $3,904 for Unit 061B 
and $4,180/ton for Unit 062B and, remains within a range that we have 
previously found to be acceptable. In contrast to other units we have 
reviewed, the 50% control DSI cost-effectiveness is much less than that 
for SDA. However, given the additional large total cumulative 
visibility benefits that will result from the installation of SDA over 
DSI at 50% control, we consider SDA to justify the additional cost. We 
therefore propose that SO2 BART for Harrington Units 061B 
and 062B should be based on the installation of SDA at an emission 
limit of 0.06 lbs/MMBtu based on a 30 BOD.
6. W. A. Parish WAP 5 & 6
    In reviewing W A Parish, we conclude that the installation of wet 
FGD on Units 5 and 6 will result in significant visibility benefits. We 
summarize some of these visibility benefits in the tables below:

[[Page 944]]



                           Table 30--Wet FGD Visibility Benefits at W A Parish (CAMx)
----------------------------------------------------------------------------------------------------------------
                                                                       Total      Baseline total
                                  Improvement at  Improvement at    cumulative      cumulative     Reduction in
              Unit                  Caney Creek   Upper  Buffalo    visibility    number of days  number of days
                                       (dv)             (dv)       benefit  (dv)   over  0.5/1.0  above  0.5/1.0
                                                                        \1\           dv \2\           dv \3\
----------------------------------------------------------------------------------------------------------------
W A Parish 5....................           1.518           0.943           8.171            51/9            51/9
W A Parish 6....................           1.492           0.922           7.979            48/7            48/7
Source (WAP 4, 5 & 6)...........           2.665           1.760          15.301          163/49          162/49
----------------------------------------------------------------------------------------------------------------
\1\ Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and
  control scenario runs summed across 15 Class I areas included in the CAMx modeling.
\2\ Baseline Total Cumulative number of days over 0.5 (1.0) dv is calculated as the sum of the number of modeled
  days at each of the 15 Class I area impacted over the threshold.
\3\ Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across
  the 15 Class I areas included in the CAMx modeling for the baseline scenario subtracted by the number of days
  over the threshold for the control scenario.

    CAMx modeling results indicate that wet FGD on each of these units 
will eliminate all days impacted by each unit over 1 dv and 0.5 dv at 
all Class I areas. At the most impacted Class I areas, wet FGD on each 
unit will each result in visibility improvements of approximately 1.5 
dv on the most impacted days at Caney Creek and 0.9 dv at Upper 
Buffalo. Nine Class I areas have modeled source-wide baseline impacts 
over 1 dv, and wet FGD on both units results in source-wide 
improvements of 1 dv or greater on the maximum impacted days at eight 
of these Class I areas. In addition, cumulative benefits from wet FGD 
on both units over all 15 Class I areas exceeds 15 dv on the maximum 
impacted days. DSI operated at 50% control results in approximately 
half of the wet FGD visibility benefits at the most impacted Class I 
areas and half of the cumulative benefits over the 15 class I areas 
included in the modeling. We note that source-wide modeling includes a 
small impact from WAP 4. This unit is gas-fired and was modeled at 
baseline emissions levels for both the baseline and control case 
scenarios.
    We conclude that wet FGD is cost-effective at $2,417/ton for Unit 5 
and $2,259/ton for Unit 6, and remains well within a range that we have 
previously found to be acceptable. DSI at 50% control is approximately 
the same cost-effectiveness but results in significantly less 
visibility benefit. We consider the cost of wet FGD at the W A Parish 
units to be justified by the significant visibility benefits that will 
result. We therefore propose that SO2 BART for W A Parish 
Units 5 and 6 should be based on the installation of wet FGD at an 
emission limit of 0.04 lbs/MMBtu based on a 30 BOD.
7. J T Deely 1 & 2
    In reviewing J T Deely, we conclude that the installation of wet 
FGD on Units 1 and 2 will result in significant visibility benefits. We 
summarize some of these visibility benefits in the tables below:

                            Table 31--Wet FGD Visibility Benefits at J T Deely (CAMx)
----------------------------------------------------------------------------------------------------------------
                                                                       Total      Baseline total
                                  Improvement at  Improvement at    cumulative      cumulative     Reduction in
              Unit                    Wichita       Caney Creek     visibility    number of days  number of days
                                     Mountains         (dv)        benefit  (dv)   over  0.5/1.0   above 0.5/1.0
                                       (dv)                             \1\           dv \2\          dv \3\
----------------------------------------------------------------------------------------------------------------
J T Deely 1.....................           0.487           0.283           4.785            10/0            10/0
J T Deely 2.....................           0.298           0.217           3.650             7/0             7/0
Source (J T Deely 1 & 2, Sommers           0.699           0.518           8.943           89/13           84/13
 1 & 2).........................
----------------------------------------------------------------------------------------------------------------
\1\ Cumulative benefit is calculated as the difference in the maximum visibility impacts from the baseline and
  control scenario runs summed across 15 Class I areas included in the CAMx modeling.
\2\ Baseline Total Cumulative number of days over 0.5 (1.0) dv is calculated as the sum of the number of modeled
  days at each of the 15 Class I area impacted over the threshold.
\3\ Reduction in number of days is calculated as the sum of the number of days over the chosen threshold across
  the 15 Class I areas included in the CAMx modeling for the baseline scenario subtracted by the number of days
  over the threshold for the control scenario.

    CAMx modeling results indicate wet FGD on each of these units will 
eliminate all days impacted by each unit over 0.5 dv at all Class I 
areas. At the most impacted Class I areas, wet FGD on each unit will 
each result in visibility improvements of 0.487 dv and 0.298 dv on the 
most impacted days at Wichita Mountains and 0.283 dv and 0.217 dv at 
Caney Creek. Larger visibility improvements on the most impacted days 
are anticipated at other Class I areas. Benefits from wet FGD on unit 1 
are 0.583 dv at Big Bend, 0.511 dv at Salt Creek, 0.449 dv at Guadalupe 
Mountains and Carlsbad Caverns, and 0.475 dv at White Mountains. 
Benefits from wet FGD on unit 2 are 0.583 dv at Big Bend, 0.441 dv at 
Salt Creek, 0.354 dv at Guadalupe Mountains and Carlsbad Caverns, and 
0.375 dv at White Mountains. DSI operated at 50% control results in 
approximately half of the wet FGD visibility benefits at the most 
impacted Class I areas and half of the cumulative benefits over the 15 
Class I areas included in the modeling. We note that source-wide 
modeling includes the impact from Sommers units 1 and 2, and as 
discussed in the BART Modeling TSD, control case scenarios for these 
units included benefits from switching to lower sulfur fuel oil. 
However, these modeled improvements are a small fraction of the total 
visibility benefits from controls at the source.
    We conclude that wet FGD is cost-effective at $3,898/ton for Unit 1 
and $3,712/ton for Unit 2, and remains within a range that we have 
previously found to be acceptable. We consider the cost of wet FGD at 
the J T Deely units

[[Page 945]]

to be justified by the significant visibility benefits that will result 
at a number of impacted Class I areas. DSI at 50% control is slightly 
more cost-effective but results in much less visibility benefit. We 
therefore propose that SO2 BART for J T Deely Units 1 and 2 
should be based on the installation of wet FGD at an emission limit of 
0.04 lbs/MMBtu based on a 30 BOD.\134\
---------------------------------------------------------------------------

    \134\ We have read reports that CPS Energy, is planning to 
retire J T Deely Units 1 and 2 by the end of 2018, but we have no 
enforceable documents to that effect.
---------------------------------------------------------------------------

B. SO2 BART for Coal-fired Units With Underperforming 
Scrubbers

    The BART Guidelines state that underperforming scrubber systems 
should be evaluated for upgrades.\135\ Other than upgrading the 
existing scrubbers, all of which are wet FGDs, there are no competing 
control technologies that could be considered for these units. The 
CALPUFF modeling generated facility-wide impacts and the benefits of 
the scrubber upgrade on Monticello Unit 3 and the three Martin Lake 
facilities are included in Table 17 above. The following is a listing 
of each of the affected units along with the resulting CAMx modeled 
visibility benefits from upgrading their existing scrubbers:
---------------------------------------------------------------------------

    \135\ 70 FR 39171 (July 6, 2005).

               Table 32--Visibility Benefit for Coal-Fired Units With Existing SO2 Controls (CAMx)
----------------------------------------------------------------------------------------------------------------
                                                                       Total       Reduction in    Reduction in
                                  Improvement at  Improvement at    cumulative    number of days  number of days
              Unit                 most impacted     2nd most       visibility     above 0.5 dv    above 1.0 dv
                                       (dv)       impacted  (dv)   benefit  (dv)      at----          at----
----------------------------------------------------------------------------------------------------------------
Monticello 3....................   3.719 ( CACR)    1.918 (WIMO)          11.940          200/66          188/66
Martin Lake 1...................    1.165 (CACR)    1.449 (UPBU)           7.575          160/41          151/40
Martin Lake 2...................    0.655 (CACR)    1.164 (UPBU)           6.199          150/41          134/39
Martin Lake 3...................    1.146 (CACR)    1.478 (UPBU)           7.863          173/47          163/46
----------------------------------------------------------------------------------------------------------------

    As we state elsewhere in this proposal, because our cost-
effectiveness calculations depend 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 conclude that 
in all cases, scrubber upgrades are very cost-effective and result in 
very significant visibility benefits, significantly reducing the 
impacts from these units and reducing the number of days that Class I 
areas are impacted over 1.0 dv and 0.5 dv. We propose that 
SO2 BART for all other coal-fired units with underperforming 
scrubbers should be based on the wet FGD upgrade control levels we have 
used in our BART analyses of them.

C. SO2 BART for Gas-Fired Units That Burn Oil

    In analyzing potential controls for those gas-fired units that 
occasionally burn fuel oil we considered scrubber retrofits and lower 
sulfur fuel oil. We concluded that the cost-effectiveness of scrubber 
retrofits for these units were likely very high, and not worth the 
potential visibility benefit.
    We also concluded that the cost-effectiveness of switching to a No. 
2 fuel oil with a sulfur content of 0.3% is $11,218/gallon, and the 
cost-effectiveness of switching to ULSD with a sulfur content of 
0.0015% is $8,627/gallon. We further noted that one facility already 
had a contract in place for ULSD at a lower price than we assumed, 
which if used in our analysis would result in a cost effectiveness of 
$3,970/ton. Although the cost-effectiveness of switching to a lower 
sulfur oil (assuming our price for ULSD of $1.667/gal) is higher than 
other controls that we have typically required under BART, we note 
certain mitigating factors.
    For instance, arguing against control, our calculated cost-
effectiveness values are high in relation to other BART controls we 
have required in the past. Also, our visibility modeling necessarily 
utilized the maximum SO2 emissions over a 24-hour 
timeframe,\136\ resulting in the configuring of our visibility modeling 
to analyze the maximum short-term potential impacts that could occur 
when the unit burns fuel oil. However, as we discuss elsewhere in our 
proposal, these units are primarily gas-fired, and have only 
occasionally burned fuel oil. Their most recent practices appear to 
reinforce this trend.
---------------------------------------------------------------------------

    \136\ See the BART Guidelines at 70 FR 39162, July 6, 2005: ``We 
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 start-up, shutdown, or 
malfunction.''
---------------------------------------------------------------------------

    Arguing for control, unlike the wet FGD and SDA scrubbers we have 
costed in other sections of this TSD, which have large capital costs, 
we are unaware of any significant capital costs involved in switching 
fuels. This means the overall annual costs are relatively minor, if the 
units in question adhere to their historical usages. Also, because the 
units in question have only occasionally burned fuel oil, they have the 
option to avoid the cost of fuel switching entirely by not continuing 
to burn fuel oil and instead relying solely on their primary fuel of 
natural gas. Lastly, we note that the prevalence of ULSD in the fuel 
oil market is such that it appears to be gradually replacing most other 
No. 2 fuel oil applications.\137\
---------------------------------------------------------------------------

    \137\ http://www.eia.gov/todayinenergy/detail.php?id=5890. 
http://blogs.platts.com/2014/05/07/heating-oil-new-york-sulfur/. 
http://oilandenergyonline.com/challenges-to-the-northeast-supply-picture/.
---------------------------------------------------------------------------

    The preamble to the Regional Haze Rule counseled that a one percent 
sulfur content limitation on fuel oil should be considered as a 
``starting point,'' \138\ and the existing sulfur content limits are 
lower than one percent. Considering all of this information, we propose 
that SO2 BART for the gas-fired units that occasionally burn 
fuel oil should be no further control. In so doing, we acknowledge the 
data quality issues we have discussed concerning these units and we 
specifically request comments on all aspects of our proposed BART 
analysis for these units from all interested parties. Based on the 
comments we receive, we may either finalize our BART determinations for 
these units as proposed, or we may revise them without a re-proposal.
---------------------------------------------------------------------------

    \138\ 70 FR at 39134.
---------------------------------------------------------------------------

D. PM BART

    We propose to disapprove the portion of the Texas Regional Haze SIP 
that sought to address the BART requirement for EGUs for PM. We note 
that all of the coal-fired units are either currently fitted with a 
baghouse, an ESP and a polishing baghouse, or an ESP. We conclude that 
the cost of retrofitting the subject units with a baghouse would be 
extremely high compared to the visibility benefit for any of the units 
currently fitted with an ESP.

[[Page 946]]

Consequently, we propose that PM BART for the coal-fired units is an 
emission limit of 0.030 lb/MMBtu along with work practice standards. We 
propose that PM and SO2 BART for the units that only fire 
gas be pipeline natural gas. We propose that PM and SO2 BART 
for those gas-fired units that occasionally burn fuel oil be the 
existing permitted fuel oil sulfur content of 0.7% sulfur by weight or 
pipeline natural gas.

V. Proposed Actions

A. Regional Haze

    We are proposing to disapprove the portion of the Texas Regional 
Haze SIP that sought to address the BART requirement for EGUs for PM. 
We are proposing to promulgate a FIP as described in this notice and 
summarized in this section to satisfy the remaining outstanding 
regional haze requirements that are unmet by the Texas' regional haze 
SIP and that we did not take action on in our January 5, 2016 final 
action.\139\ Our proposed FIP includes SO2 and PM BART 
emission limits for sources in Texas to reduce emissions that 
contribute to regional haze in Texas' two Class I areas and other 
nearby Class I areas and make reasonable progress for the first 
regional haze planning period for Texas' two Class I areas.
---------------------------------------------------------------------------

    \139\ 81 FR 296.
---------------------------------------------------------------------------

1. NOX BART
    As discussed elsewhere in this proposal, we are proposing a FIP to 
replace Texas' reliance on CAIR with reliance on CSAPR to address the 
NOX BART requirements for EGUs. This portion of our proposal 
is based on: The recent update to the CSAPR rule; \140\ and the EPA's 
finalization of a separate proposed finding that the EPA's actions in 
response to the D.C. Circuit's remand would not adversely impact our 
2012 demonstration that CSAPR is better than BART.\141\ We cannot 
finalize this portion of the proposed FIP unless and until the EPA 
finalizes the proposed finding that CSAPR continues to be better than 
BART because finalization of that proposal would allow for reliance on 
CSAPR participation as an alternative to source-specific EGU BART for 
NOX in Texas.
---------------------------------------------------------------------------

    \140\ 81 FR 74504.
    \141\ 81 FR 78954.
---------------------------------------------------------------------------

2. SO2 BART for Coal-Fired Units
    We propose that SO2 BART for the coal-fired units be the 
following SO2 emission limits to be met on a 30 Boiler 
Operating Day (BOD) period:

    Table 33--Proposed SO2 BART Emissions Limits for Coal-fired Units
------------------------------------------------------------------------
                                                           Proposed SO2
                          Unit                            emission limit
                                                            (lbs/MMBtu)
------------------------------------------------------------------------
Scrubber Upgrades
    Martin Lake 1.......................................            0.12
    Martin Lake 2.......................................            0.12
    Martin Lake 3.......................................            0.11
    Monticello 3........................................            0.05
Scrubber Retrofits
    Big Brown 1.........................................            0.04
    Big Brown 2.........................................            0.04
    Monticello 1........................................            0.04
    Monticello 2........................................            0.04
    Coleto Creek 1......................................            0.04
    Fayette 1...........................................            0.04
    Fayette 2...........................................            0.04
    Harrington 061B.....................................            0.06
    Harrington 062B.....................................            0.06
    J T Deely 1.........................................            0.04
    J T Deely 2.........................................            0.04
    W A Parish 5........................................            0.04
    W A Parish 6........................................            0.04
    Welsh 1.............................................            0.04
------------------------------------------------------------------------

    We propose that compliance with these limits be within five years 
of the effective date of our final rule for Big Brown Units 1 and 2; 
Monticello Units 1 and 2; Coleto Creek Unit 1; Harrington Units 061B 
and 062B; J T Deely Units 1 and 2; W A Parish Units 5 and 6; and Welsh 
Unit 1. This is the maximum amount of time allowed under the Regional 
Haze Rule for BART compliance. We based our cost analysis on the 
installation of wet FGD and SDA scrubbers for these units, and in the 
past we have typically required that scrubber retrofits under BART be 
operational within five years.
    We propose that compliance with these limits be within three years 
of the effective date of our final rule for Martin Lake Units 1, 2, and 
3; and Monticello Unit 3. We believe that three years is appropriate 
for these units, as we based our cost analysis on upgrading the 
existing wet FGD scrubbers of these units, which we believe to be less 
complex and time consuming that the construction of a new scrubber.
    We propose that compliance with these limits be within one year for 
Fayette Units 1 and 2. We believe that one year is appropriate for 
these units because the Fayette units have already demonstrated their 
ability to meet these emission limits.
3. Potential Process for Alternative Scrubber Upgrade Emission Limits
    In our BART FIP TSD, we discuss how we calculated the 
SO2 removal efficiency of the units we analyzed for scrubber 
upgrades. We note that due to a number of factors we could not 
accurately quantify, our calculations of scrubber efficiency may 
contain some error. Based on the results of our scrubber upgrade cost 
analysis, we do not believe that any reasonable error in calculating 
the true tons of SO2 removed affects our proposed decision 
to require emission reductions, as all of the scrubber upgrades we 
analyzed are cost-effective (low $/ton). In other words, were we to 
make reasonable adjustments in the tons removed to account for any 
potential error in our scrubber efficiency calculation, we would still 
propose to upgrade these SO2 scrubbers. We believe we have 
demonstrated that upgrading an underperforming SO2 scrubber 
is one of the most cost-effective pollution control upgrades a coal 
fired power plant can implement to improve the visibility at Class I 
areas. However, our proposed FIP does specify a SO2 emission 
limit that is based on 95% removal in all cases. This is below the 
upper end of what an upgraded wet SO2 scrubber can achieve, 
which is 98-99%, as we have noted in our BART FIP TSD. We believe that 
a 95% control assumption provides an adequate margin of error for any 
of the units for which we have proposed scrubber upgrades, such that 
they should be able to comfortably attain the emission limits we have 
proposed. However, for the operator of any unit that disagrees with us 
on this point, we propose the following:
    (1) The affected unit should comment why it believes it cannot 
attain the SO2 emission limit we have proposed, based on a 
scrubber upgrade that includes the kinds of improvements (e.g., 
elimination of bypass, wet stack conversion, installation of trays or 
rings, upgraded spray headers, upgraded ID fans, using all recycle 
pumps, etc.) typically included in a scrubber upgrade.
    (2) After considering those comments, and responding to all 
relevant comments in a final rulemaking action, should we still require 
a scrubber upgrade in our final FIP we will provide the company the 
following option in the FIP to seek a revised emission limit after 
taking the following steps:
    (a) Install a CEMS at the inlet to the scrubber.
    (b) Pre-approval of a scrubber upgrade plan conducted by a third 
party engineering firm that considers the kinds of improvements (e.g., 
elimination of bypass, wet stack conversion, installation of trays or 
rings, upgraded spray headers, upgraded ID fans, using all recycle 
pumps, etc.) typically performed during a scrubber upgrade. The goal of 
this plan will be to maximize the unit's overall SO2 removal 
efficiency.

[[Page 947]]

    (c) Installation of the scrubber upgrades.
    (d) Pre-approval of a performance testing plan, followed by the 
performance testing itself.
    (e) A pre-approved schedule for 2.a through 2.d.
    (f) Should we determine that a revision of the SO2 
emission limit is appropriate, we will have to propose a modification 
to the BART FIP after it has been promulgated. It should be noted that 
any proposal to modify the SO2 emission limit will be based 
largely on the performance testing and may result in a proposed 
increase or decrease of that value.
4. SO2 BART for Gas-fired Units That Burn Oil
    We propose that SO2 BART for the following gas-fired 
units that occasionally burn fuel oil be the existing permit limits for 
the sulfur content of the fuel oil:

 Table 34--Proposed BART SO2 Emission Limits Gas Units That Occasionally
                                Burn Oil
------------------------------------------------------------------------
                                                             Fuel Oil
                                                          Sulfur Content
                        Facility                            (percent by
                                                              weight)
------------------------------------------------------------------------
Graham 2................................................             0.7
Newman 2 *..............................................             0.7
Newman 3 *..............................................             0.7
O W Sommers 1...........................................             0.7
O W Sommers 2...........................................             0.7
Stryker Creek ST2.......................................             0.7
Wilkes 1................................................             0.7
------------------------------------------------------------------------
* The Newman Units 2 and 3 are further limited to burning fuel oil for
  no more than 876 hours per year.

5. PM BART
    We propose that PM BART limits for the coal units, Big Brown Units 
1 and 2; Monticello Units 1, 2, and 3; Martin Lake Units 1, 2, and 3; 
Coleto Creek Unit 1; J T Deely Units 1 and 2; W A Parish Units 5 and 6; 
Welsh Unit 1; Harrington Units 061B and 062B; and Fayette Units 1 and 2 
are 0.030 lb/MMBtu and work practice standards, which we present below:

    Table 35--PM BART Emissions Standards and Work Practice Standards
------------------------------------------------------------------------
               Unit Type                         PM BART Proposal
------------------------------------------------------------------------
Coal-Fired BART Units..................  0.03 lb/MMBtu filterable PM
                                         Table 3 to Subpart UUUUU
Gas-Fired Only BART Units..............  Pipeline quality natural gas
Oil-Fired BART Units when not firing     Fuel Content not to exceed 0.7%
 natural gas.                             sulfur by weight (also SO2
                                          BART)
------------------------------------------------------------------------

    We propose that compliance with these emissions standards and work 
practice standards be the effective date of our final rule, as the 
affected facilities' should already be meeting them.
    We propose that PM and SO2 BART for the units that only 
fire gas, Newman Unit 4; W A Parish Unit 4; and Wilkes Units 2 and 3 be 
pipeline natural gas.
    We propose that PM and SO2 BART for those gas-fired 
units that occasionally burn fuel oil, Newman Unit 2 and 3; O W Sommers 
Units 1 and 2; Stryker Creek Unit ST2; and Wilkes Unit 1 be the 
existing permitted fuel oil sulfur content of 0.7% sulfur by weight.

B. Interstate Visibility Transport

    We are proposing to disapprove Texas' SIP revisions addressing 
interstate visibility transport under CAA section 110(a)(2)(D)(i)(II) 
for six NAAQS. We further are proposing a FIP to fully address Texas' 
interstate visibility transport obligations for: (1) 1997 8-hour ozone, 
(2) 1997 PM2.5 (annual and 24 hour), (3) 2006 
PM2.5 (24-hour), (4) 2008 8-hour ozone, (5) 2010 1-hour 
NO2 and (6) 2010 1-hour SO2. The proposed FIP is 
based on the finding that our proposed action to fully address the 
Texas Regional Haze BART program is adequate to ensure that emissions 
from Texas do not interfere with measures to protect visibility in 
nearby states in accordance with CAA section 110(a)(2)(D)(i)(II).

VI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Overview

    This proposed action is not a ``significant regulatory action'' 
under the terms of Executive Order 12866 (58 FR 51735, October 4, 1993) 
and is therefore not subject to review under Executive Orders 12866 and 
13563 (76 FR 3821, January 21, 2011). The proposed FIP would not 
constitute a rule of general applicability, because it only proposes 
source specific requirements for particular, identified facilities (8 
total).

B. Paperwork Reduction Act

    This proposed action does not impose an information collection 
burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 
Section 3501 et seq. Because it does not contain any information 
collection activities, the Paperwork Reduction Act does not apply. See 
5 CFR 1320(c).

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to conduct a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements unless the agency certifies 
that the rule will not have a significant economic impact on a 
substantial number of small entities. Small entities include small 
businesses, small not-for-profit enterprises, and small governmental 
jurisdictions. For purposes of assessing the impacts of today's rule on 
small entities, small entity is defined as: (1) A small business as 
defined by the Small Business Administration's (SBA) regulations at 13 
CFR 121.201; (2) a small governmental jurisdiction that is a government 
of a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-profit enterprise which is independently owned and operated 
and is not dominant in its field.
    After considering the economic impacts of today's proposed rule on 
small entities, I certify that this action will not have a significant 
impact on a substantial number of small entities. In making this 
determination, the impact of concern is any significant adverse 
economic impact on small entities. An agency may certify that a rule 
will not have a significant economic impact on a substantial number of 
small entities if the rule relieves regulatory burden, has no net 
burden or otherwise has a positive economic effect on the small 
entities subject to the rule. This rule does not impose any 
requirements or

[[Page 948]]

create impacts on small entities. This proposed FIP action under 
Section 110 of the CAA will not create any new requirement with which 
small entities must comply. This action, when finalized, will apply to 
14 facilities owned by 8 companies, none of which are small entities. 
Accordingly, it affords no opportunity for the EPA to fashion for small 
entities less burdensome compliance or reporting requirements or 
timetables or exemptions from all or part of the rule. The fact that 
the CAA prescribes that various consequences (e.g., emission 
limitations) may or will flow from this action does not mean that the 
EPA either can or must conduct a regulatory flexibility analysis for 
this action. We have therefore concluded that, this action will have no 
net regulatory burden for all directly regulated small entities.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on state, local, and Tribal 
governments and the private sector. Under Section 202 of UMRA, EPA 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to state, local, and Tribal governments, in 
the aggregate, or to the private sector, of $100 million or more 
(adjusted for inflation) in any one year. Before promulgating an EPA 
rule for which a written statement is needed, Section 205 of UMRA 
generally requires EPA to identify and consider a reasonable number of 
regulatory alternatives and adopt the least costly, most cost-
effective, or least burdensome alternative that achieves the objectives 
of the rule. The provisions of Section 205 of UMRA do not apply when 
they are inconsistent with applicable law. Moreover, Section 205 of 
UMRA allows EPA to adopt an alternative other than the least costly, 
most cost-effective, or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted. Before EPA establishes any regulatory 
requirements that may significantly or uniquely affect small 
governments, including Tribal governments, it must have developed under 
Section 203 of UMRA a small government agency plan. The plan must 
provide for notifying potentially affected small governments, enabling 
officials of affected small governments to have meaningful and timely 
input in the development of EPA regulatory proposals with significant 
Federal intergovernmental mandates, and informing, educating, and 
advising small governments on compliance with the regulatory 
requirements.
    EPA has determined that Title II of UMRA does not apply to this 
proposed rule. In 2 U.S.C. Section 1502(1) all terms in Title II of 
UMRA have the meanings set forth in 2 U.S.C. Section 658, which further 
provides that the terms ``regulation'' and ``rule'' have the meanings 
set forth in 5 U.S.C. Section 601(2). Under 5 U.S.C. Section 601(2), 
``the term `rule' does not include a rule of particular applicability 
relating to . . . facilities.'' Because this proposed rule is a rule of 
particular applicability relating to 12 named facilities, EPA has 
determined that it is not a ``rule'' for the purposes of Title II of 
UMRA.

E. Executive Order 13132: Federalism

    This proposed action does not have federalism implications. It will 
not have substantial direct effects on the states, on the relationship 
between the national government and the states, or on the distribution 
of power and responsibilities among the various levels of government.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This proposed rule does not have tribal implications, as specified 
in Executive Order 13175. It will not have substantial direct effects 
on tribal governments. Thus, Executive Order 13175 does not apply to 
this rule.

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

    Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks \142\ applies to any rule that: (1) Is 
determined to be economically significant as defined under Executive 
Order 12866; and (2) concerns an environmental health or safety risk 
that we have reason to believe may have a disproportionate effect on 
children. EPA interprets EO 13045 as applying only to those regulatory 
actions that concern health or safety risks, such that the analysis 
required under Section 5-501 of the EO has the potential to influence 
the regulation. This action is not subject to Executive Order 13045 
because it is not economically significant as defined in Executive 
Order 12866, and because the EPA does not believe the environmental 
health or safety risks addressed by this action present a 
disproportionate risk to children. This action is not subject to EO 
13045 because it implements specific standards established by Congress 
in statutes. However, to the extent this proposed rule will limit 
emissions of SO2, NOX, and PM, the rule will have 
a beneficial effect on children's health by reducing air pollution.
---------------------------------------------------------------------------

    \142\ 62 FR 19885 (Apr. 23, 1997).
---------------------------------------------------------------------------

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

    This proposed action is not subject to Executive Order 13211 (66 FR 
28355 (May 22, 2001)), because it is not a significant regulatory 
action under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12 of the National Technology Transfer and Advancement Act 
(NTTAA) of 1995 requires Federal agencies to evaluate existing 
technical standards when developing a new regulation. To comply with 
NTTAA, EPA must consider and use ``voluntary consensus standards'' 
(VCS) if available and applicable when developing programs and policies 
unless doing so would be inconsistent with applicable law or otherwise 
impractical. EPA believes that VCS are inapplicable to this action. 
Today's action does not require the public to perform activities 
conducive to the use of VCS.

J. Executive Order 12898: Federal Actions to Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994), establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States. We have determined that this proposed 
rule, if finalized, will not have disproportionately high and adverse 
human health or environmental effects on minority or low-income 
populations because it increases the level of environmental protection 
for all affected populations without having any disproportionately high 
and adverse human health or environmental effects on any population, 
including any minority or low-income population.

[[Page 949]]

This proposed federal rule limits emissions of NOX, 
SO2, and PM from 14 facilities in Texas.

List of Subjects in 40 CFR Part 52

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

    Dated: December 9, 2016.
Ron Curry,
Regional Administrator, Region 6.
    Title 40, chapter I, of the Code of Federal Regulations is proposed 
to be amended as follows:

PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS

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

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

Subpart SS--Texas

0
2. Section 52.2287 is added to read as follows:


Sec.  52.2287  Best Available Retrofit Requirements (BART) for 
SO2 and Particulate Matter and Interstate pollutant 
transport provisions; What are the FIP requirements for visibility 
protection?

    (a) Applicability. The provisions of this section shall apply to 
each owner or operator, or successive owners or operators, of the coal 
or natural gas burning equipment designated below.
    (b) Definitions. All terms used in this part but not defined herein 
shall have the meaning given them in the CAA and in parts 51 and 60 of 
this title. For the purposes of this section:
    24-hour period means the period of time between 12:01 a.m. and 12 
midnight.
    Air pollution control equipment includes selective catalytic 
control units, baghouses, particulate or gaseous scrubbers, and any 
other apparatus utilized to control emissions of regulated air 
contaminants that would be emitted to the atmosphere.
    Boiler-operating-day means any 24-hour period between 12:00 
midnight and the following midnight during which any fuel is combusted 
at any time at the steam generating unit.
    Daily average means the arithmetic average of the hourly values 
measured in a 24-hour period.
    Heat input means heat derived from combustion of fuel in a unit and 
does not include the heat input from preheated combustion air, 
recirculated flue gases, or exhaust gases from other sources. Heat 
input shall be calculated in accordance with 40 CFR part 75.
    Owner or Operator means any person who owns, leases, operates, 
controls, or supervises any of the coal or natural gas burning 
equipment designated below.
    PM means particulate matter.
    Regional Administrator means the Regional Administrator of EPA 
Region 6 or his/her authorized representative.
    Unit means one of the natural gas, gas and/or fuel oil, or coal-
fired units covered in this section.
    (c) Emissions limitations and compliance dates for SO2. 
The owner/operator of the units listed below shall not emit or cause to 
be emitted pollutants in excess of the following limitations from the 
subject unit. Compliance with the requirements of this section is 
required as listed below unless otherwise indicated by compliance dates 
contained in specific provisions.

------------------------------------------------------------------------
                                                            Compliance
                                           Proposed SO2   date (from the
                  Unit                    emission limit  effective date
                                            (lbs/MMBtu)    of the final
                                                           rule) (years)
------------------------------------------------------------------------
Martin Lake 1...........................            0.12               3
Martin Lake 2...........................            0.12               3
Martin Lake 3...........................            0.11               3
Monticello 3............................            0.05               3
Big Brown 1.............................            0.04               5
Big Brown 2.............................            0.04               5
Monticello 1............................            0.04               5
Monticello 2............................            0.04               5
Coleto Creek 1..........................            0.04               5
Fayette 1...............................            0.04               1
Fayette 2...............................            0.04               1
Harrington 061B.........................            0.06               5
Harrington 062B.........................            0.06               5
J T Deely 1.............................            0.04               5
J T Deely 2.............................            0.04               5
W A Parish 5............................            0.04               5
W A Parish 6............................            0.04               5
Welsh 1.................................            0.04               5
------------------------------------------------------------------------

    (d) Emissions limitations and compliance dates for PM. The owner/
operator of the units listed below shall not emit or cause to be 
emitted pollutants in excess of the following limitations from the 
subject unit. Compliance with the requirements of this section is 
required as listed below unless otherwise indicated by compliance dates 
contained in specific provisions.
    (1) Coal-Fired Units at Big Brown Units 1 and 2; Monticello Units 
1, 2, and 3; Martin Lake Units 1, 2, and 3; Coleto Creek Unit 1; J T 
Deely Units 1 and 2; W A Parish Units 5 and 6; Welsh Unit 1; Harrington 
Units 061B and 062B; and Fayette Units 1 and 2.
    (i) Normal operations: Filterable PM limit of 0.030 lb/MMBtu.
    (ii) Work practice standards specified in 40 CFR part 63, subpart 
UUUUU, Table 3, and using the relevant definitions in 63.10042.
    (2) Gas-Fired Units at Newman Unit 4; Wilkes Units 2 and 3; and W A 
Parish Unit 4 shall burn only pipeline natural gas, as defined in 40 
CFR 72.1

[[Page 950]]

    (3) Gas-fired units that also burn fuel oil at Graham Unit 2; 
Newman Units 2 and 3; O W Sommers Units 1 and 2; Stryker Creek Unit 
ST2; and Wilkes shall burn 0.7% sulfur content fuel or pipeline natural 
gas, as defined in 40 CFR 72.1.
    (4) Compliance for the units included in Section (d) shall be as of 
the effective date of the final rule.
    (e) Testing and monitoring. (1) No later than the compliance date 
of this regulation, the owner or operator shall install, calibrate, 
maintain and operate Continuous Emissions Monitoring Systems (CEMS) for 
SO2 on the units covered under paragraph (c) of this 
section. Compliance with the emission limits for SO2 shall 
be determined by using data from a CEMS.
    (2) Continuous emissions monitoring shall apply during all periods 
of operation of the coal or natural gas burning equipment, including 
periods of startup, shutdown, and malfunction, except for CEMS 
breakdowns, repairs, calibration checks, and zero and span adjustments. 
Continuous monitoring systems for measuring SO2 and diluent 
gas shall complete a minimum of one cycle of operation (sampling, 
analyzing, and data recording) for each successive 15-minute period. 
Hourly averages shall be computed using at least one data point in each 
fifteen minute quadrant of an hour. Notwithstanding this requirement, 
an hourly average may be computed from at least two data points 
separated by a minimum of 15 minutes (where the unit operates for more 
than one quadrant in an hour) if data are unavailable as a result of 
performance of calibration, quality assurance, preventive maintenance 
activities, or backups of data from data acquisition and handling 
system, and recertification events. When valid SO2 pounds 
per hour, or SO2 pounds per million Btu emission data are 
not obtained because of continuous monitoring system breakdowns, 
repairs, calibration checks, or zero and span adjustments, emission 
data must be obtained by using other monitoring systems approved by the 
EPA to provide emission data for a minimum of 18 hours in each 24 hour 
period and at least 22 out of 30 successive boiler operating days.
    (3) Compliance with the PM emission limits for units in paragraph 
(d)(1) shall be demonstrated by the filterable PM methods specified in 
40 CFR part 63, subpart UUUUU, Table 7.
    (f) Reporting and recordkeeping requirements. Unless otherwise 
stated all requests, reports, submittals, notifications, and other 
communications to the Regional Administrator required by this section 
shall be submitted, unless instructed otherwise, to the Director, 
Multimedia Division, U.S. Environmental Protection Agency, Region 6, to 
the attention of Mail Code: 6MM, at 1445 Ross Avenue, Suite 1200, 
Dallas, Texas 75202-2733. For each unit subject to the emissions 
limitation in this section and upon completion of the installation of 
CEMS as required in this section, the owner or operator shall comply 
with the following requirements:
    (1) For SO2 each emissions limit in this section, comply 
with the notification, reporting, and recordkeeping requirements for 
CEMS compliance monitoring in 40 CFR 60.7(c) and (d).
    (2) For each day, provide the total SO2 emitted that day 
by each emission unit. For any hours on any unit where data for hourly 
pounds or heat input is missing, identify the unit number and 
monitoring device that did not produce valid data that caused the 
missing hour.
    (3) Records for demonstrating compliance with the SO2 
and PM emission limitations in this section shall be maintained for at 
least five years.
    (g) Equipment operations. At all times, including periods of 
startup, shutdown, and malfunction, the owner or operator shall, to the 
extent practicable, maintain and operate the unit including associated 
air pollution control equipment in a manner consistent with good air 
pollution control practices for minimizing emissions. Determination of 
whether acceptable operating and maintenance procedures are being used 
will be based on information available to the Regional Administrator 
which may include, but is not limited to, monitoring results, review of 
operating and maintenance procedures, and inspection of the unit.
    (h) Enforcement. (1) Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the unit would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed, can be used to establish whether or not the owner or 
operator has violated or is in violation of any standard or applicable 
emission limit in the plan.
    (2) Emissions in excess of the level of the applicable emission 
limit or requirement that occur due to a malfunction shall constitute a 
violation of the applicable emission limit.

0
3. In Sec.  52.2304, paragraph (f) is added to read as follows:


Sec.  52.2304  Visibility protection.

* * * * *
    (f) Measures addressing disapproval associated with NOX, 
SO2, and PM. (1) The deficiencies associated with 
NOX identified in EPA's disapproval of the regional haze 
plan submitted by Texas on March 31, 2009, are satisfied by Section 
52.2283.
    (2) The deficiencies associated with SO2 and PM 
identified in EPA's disapproval of the regional haze plan submitted by 
Texas on March 31, 2009, are satisfied by Section 52.2287.

[FR Doc. 2016-30713 Filed 1-3-17; 8:45 am]
 BILLING CODE 6560-50-P