Federal Register Vol. 82, No.244,

We issued a notice of proposed rulemaking (NPRM) to amend 14 CFR part 39 by adding an AD that would apply to certain Gulfstream Aerospace Corporation (Gulfstream) Models G-1159A (GIII), G-IV, and GIV-X airplanes. The NPRM published in the Federal Register on September 22, 2017 (82 FR 44359). The NPRM was prompted by a report from Gulfstream that, during maintenance while replacing flap tracks on one of the affected airplanes, it was discovered that certain flap tracks were manufactured with the upper flange thickness less than design minimum and do not meet design load margins. The NPRM proposed to require replacing any defective flap track. We are issuing this AD to correct the unsafe condition on these products.

We gave the public the opportunity to participate in developing this final rule. The following presents the comment received on the NPRM and the FAA's response to the comment.

Gulfstream requested that the effective date be set in-line with the service information incorporated by referenced in the proposed AD.

Gulfstream stated that the compliance time specified in Gulfstream III Customer Bulletin Number 187, Gulfstream G450 Customer Bulletin Number 195, and Gulfstream IV Customer Bulletin Number 240, all dated June 28, 2017, which are the incorporated by reference documents listed in the proposed AD, is 12 months from the release date of the service information.

Gulfstream stated that if the AD becomes effective before January 18, 2018, the compliance time will be less than that allowed in the service information.

We do not agree that the possibility of this AD becoming effective before January 18, 2018, will result in a reduced compliance time than that allowed in the related service information. We infer that the commenter thinks a reduced compliance time would cause an undue burden on the owners/operators of the affected airplanes. This AD will not be effective until 35 days after publication in the Federal Register; therefore, we do not believe there will be any significant difference in the allowable compliance time for operators. We have not changed this AD based on this comment.

We reviewed the relevant data, considered the comment received, and determined that air safety and the public interest require adopting this final rule as proposed except for minor editorial changes. We have determined that these minor changes:

• Are consistent with the intent that was proposed in the NPRM for correcting the unsafe condition; and

• Do not add any additional burden upon the public than was already proposed in the NPRM.

We reviewed Gulfstream III Customer Bulletin Number 187, Gulfstream G450 Customer Bulletin Number 195, and Gulfstream IV Customer Bulletin Number 240, all dated June 28, 2017. The applicable model service information describes procedures for replacing any discrepant flap track C with an airworthy part. This service information is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in the ADDRESSES section.

We estimate that this AD affects 6 airplanes of U.S. registry.

We estimate the following costs to comply with this AD:

According to the manufacturer, some of the costs of this AD may be covered under warranty, thereby reducing the cost impact on affected individuals. We do not control warranty coverage for affected individuals. As a result, we have included all costs in our cost estimate.

Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. Subtitle VII: Aviation Programs, describes in more detail the scope of the Agency's authority.

We are issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, section 44701: “General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.

This AD is issued in accordance with authority delegated by the Executive Director, Aircraft Certification Service, as authorized by FAA Order 8000.51C. In accordance with that order, issuance of ADs is normally a function of the Compliance and Airworthiness Division, but during this transition period, the Executive Director has delegated the authority to issue ADs applicable to small airplanes and domestic business jet transport airplanes to the Director of the Policy and Innovation Division.

This AD will not have federalism implications under Executive Order 13132. This AD will not have a substantial direct effect 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.

For the reasons discussed above, I certify that this AD:

(1) Is not a “significant regulatory action” under Executive Order 12866,

(2) Is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979),

(3) Will not affect intrastate aviation in Alaska, and

(4) Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

Accordingly, under the authority delegated to me by the Administrator, the FAA amends 14 CFR part 39 as follows:

Electronic Availability

This document and additional information concerning OFAC are available from OFAC's website (www.treasury.gov/ofac).

On December 14, 2012, the President signed into law the Sergei Magnitsky Rule of Law Accountability Act of 2012, Public Law 112-208, title IV, 126 Stat. 1502 (2012) (the “Act”). The Act provides authority for the identification of and imposition of sanctions on certain persons related to the detention, abuse, and death of Sergei Magnitsky or responsible for certain gross violations of human rights in the Russian Federation.

Section 404(a) of the Act requires the President to submit to certain congressional committees a list of each person the President has determined meets certain criteria set forth in the Act. Section 406 of the Act requires the President, with certain exceptions, to exercise powers granted by the International Emergency Economic Powers Act (50 U.S.C. 1701 et seq.) to the extent necessary to freeze, and prohibit all transactions in, all property and interests in property that are in the United States, that come within the United States, or that are or come within the possession or control of any United States person of persons on the list required by Section 404(a) of the Act.

Section 404(a) of the Act sets out criteria for inclusion on the list, namely, certain persons who the President determines:

(1) Are responsible for the detention, abuse, or death of Sergei Magnitsky, participated in efforts to conceal the legal liability for the detention, abuse, or death of Sergei Magnitsky, financially benefitted from the detention, abuse, or death of Sergei Magnitsky, or were involved in the criminal conspiracy uncovered by Sergei Magnitsky;

(2) Are responsible for extrajudicial killings, torture, or other gross violations of internationally recognized human rights committed against individuals seeking: To expose illegal activity carried out by officials of the Government of the Russian Federation; or to obtain, exercise, defend, or promote internationally recognized human rights and freedoms, such as the freedoms of religion, expression, association, and assembly, and the rights to a fair trial and democratic elections, in Russia; or

(3) Acted as agents of or on behalf of a person in a matter relating to an activity described in paragraph (1) or (2).

Pursuant to Presidential Memorandum of April 5, 2013: Delegation of Functions Under Section 404 and 406 of Public Law 112-208 (78 FR 22761, April 16, 2013), the President delegated certain functions and authorities, including the functions and authorities set forth in section 404(a) of the Act, with respect to the determinations provided for therein, and section 406(a)(1) of the Act, with respect to the freezing, and prohibiting all transactions in, property, to the Secretary of the Treasury, in consultation with the Secretary of State.

Section 406(d) of the Act requires the Secretary of the Treasury to issue regulations, licenses, and orders as are necessary to carry out Section 406 of the Act. In furtherance of this requirement and the Presidential delegation of functions and authorities noted above, OFAC is promulgating the Magnitsky Act Sanctions Regulations, 31 CFR part 584 (the “Regulations”).

The Regulations implement targeted sanctions that are directed at persons determined to meet the criteria set forth above. The sanctions do not generally prohibit trade or the provision of banking or other financial services to the Russian Federation. Instead, the sanctions apply where the transaction or service in question involves property or interests in property that are blocked pursuant to these sanctions.

Subpart A of the Regulations clarifies the relation of this part to other laws and regulations. Subpart B of the Regulations implements the prohibitions contained in section 406 of the Act. See, e.g., §§ 584.201 and 584.205. Persons designated by or under the authority of the Secretary of the Treasury pursuant to the Magnitsky Act or otherwise subject to blocking pursuant to the Act are referred to throughout the Regulations as “persons whose property and interests in property are blocked pursuant to § 584.201(a).” The names of persons designated pursuant to the Act are published on OFAC's Specially Designated Nationals and Blocked Persons List, which is accessible via OFAC's website. Those names also are published in the Federal Register as they are added to the List.

Sections 584.202 and 584.203 of subpart B detail the effect of transfers of blocked property in violation of the Regulations and set forth the requirement to hold blocked funds, such as currency, bank deposits, or liquidated financial obligations, in interest-bearing blocked accounts. Section 584.204 of subpart B provides that all expenses incident to the maintenance of blocked physical property shall be the responsibility of the owners and operators of such property, and that such expenses shall not be met from blocked funds, unless otherwise authorized. The section further provides that blocked property may, in OFAC's discretion, be sold or liquidated and the net proceeds placed in a blocked interest-bearing account in the name of the owner of the property.

Section 584.205 of subpart B prohibits any transaction by a United States person or within the United States that evades or avoids, has the purpose of evading or avoiding, or attempts to violate any of the prohibitions set forth in this part, and any conspiracy formed to violate such prohibitions.

Section 584.206 of subpart B details transactions that are exempt from the prohibitions of the Regulations pursuant to sections 203(b)(1)-(4) of IEEPA (50 U.S.C. 1702(b)(1)-(4)). These exempt transactions relate to personal communications, donations of articles intended to be used to relieve human suffering, the importation and exportation of information or informational materials, and transactions ordinarily incident to travel.

Subpart C of the Regulations defines key terms used throughout the Regulations, and subpart D contains interpretive sections regarding the Regulations. Section 584.410 of subpart D explains that the property and interests in property of an entity are blocked if the entity is directly or indirectly owned, whether individually or in the aggregate, 50 percent or more by one or more persons whose property and interests in property are blocked, whether or not the entity itself is designated pursuant to the Act.

Transactions otherwise prohibited under the Regulations but found to be consistent with U.S. policy may be authorized by one of the general licenses contained in subpart E of the Regulations or by a specific license issued pursuant to the procedures described in subpart E of 31 CFR part 501. Subpart E of the Regulations also contains certain statements of specific licensing policy in addition to the general licenses. General licenses and statements of licensing policy relating to this part also may be available through the Magnitsky Sanctions page on OFAC's website: www.treasury.gov/ofac.

Subpart F of the Regulations refers to subpart C of part 501 for recordkeeping and reporting requirements. Subpart G of the Regulations describes the civil and criminal penalties applicable to violations of the Regulations, as well as the procedures governing the potential imposition of a civil monetary penalty or issuance of a Finding of Violation. Subpart G also refers to appendix A of part 501 for a more complete description of these procedures.

Subpart H of the Regulations refers to subpart E of part 501 for applicable provisions relating to administrative procedures and contains a delegation of authority by the Secretary of the Treasury. Subpart I of the Regulations sets forth a Paperwork Reduction Act notice.

Because the Regulations involve a foreign affairs function, the provisions of Executive Order 12866 and the Administrative Procedure Act (5 U.S.C. 553) requiring notice of proposed rulemaking, opportunity for public participation, and delay in effective date, as well as the provisions of Executive Order 13771, are inapplicable. Because no notice of proposed rulemaking is required for this rule, the Regulatory Flexibility Act (5 U.S.C. 601-612) does not apply.

The collections of information related to the Regulations are contained in 31 CFR part 501 (the “Reporting, Procedures and Penalties Regulations”). Pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. 3507), those collections of information have been approved by the Office of Management and Budget under control number 1505-0164. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid control number.

Throughout this document wherever “we,” “us,” or “our” is used, we mean the EPA.

Tropospheric ozone, commonly known as smog, is formed when VOCs and nitrogen oxides (NOX) react in the atmosphere in the presence of sunlight. Because of the harmful health effects of ozone, the EPA and state governments limit the amount of VOCs that can be released into the atmosphere. VOCs are those organic compounds of carbon (excluding carbon monoxide, carbon dioxide, carbonic acid, metallic carbides or carbonates, and ammonium carbonate) that form ozone through atmospheric photochemical reactions. Different VOCs have different levels of reactivity. That is, they do not react to form ozone at the same speed or do not form ozone to the same extent. Some VOCs react slowly or form less ozone; therefore, changes in their emissions have less and, in some cases, very limited effects on local or regional ozone pollution episodes. It has been the EPA's policy that organic compounds with a negligible level of reactivity should be excluded from the regulatory VOC definition so as to focus VOC control efforts on compounds that do significantly increase ozone concentrations. The EPA also believes that exempting such compounds creates an incentive for industry to use negligibly reactive compounds in place of more highly reactive compounds that are regulated as VOCs.

EPA periodically revises the list of negligibly reactive compounds to add or delete VOCs from regulation on the basis that these compounds make a negligible contribution to tropospheric ozone formation. Section 302(s) of the CAA specifies that the EPA has the authority to define the meaning of “VOC,” and hence what compounds shall be treated as VOCs for regulatory purposes. The policy of excluding negligibly reactive compounds from the VOC definition was first set forth in the “Recommended Policy on Control of Volatile Organic Compounds” (42 FR 35314, July 8, 1977) and was supplemented most recently with the “Interim Guidance on Control of Volatile Organic Compounds in Ozone State Implementation Plans” (Interim Guidance) (70 FR 54046, September 13, 2005). The EPA uses the reactivity of ethane as the threshold for determining whether a compound has negligible reactivity. Compounds that are less reactive than, or equally reactive to, ethane under certain assumed conditions may be deemed negligibly reactive and therefore suitable for exemption from the regulatory definition of VOC. Compounds that are more reactive than ethane continue to be considered VOCs for regulatory purposes and therefore are subject to control requirements. The selection of ethane as the threshold compound was based on a series of smog chamber experiments that underlay the 1977 policy.

The EPA lists compounds that it has determined to be negligibly reactive in its regulations as being excluded from the definition of VOC. (40 CFR 51.100(s)). The Arkansas submittal will update its SIP to be consistent with current EPA definitions to provide clarity and consistency for owners and operators of sources subject to ADEQ rules regarding VOC control.

The specific organic compounds that will be excluded from ADEQ's definition of VOC that is in the SIP with this revision include: trans-1,3,3,3-tetrafluoropropene; 2,3,3,3-tertrafluropropene; 1 HCF2OCF2H (HFE-134); HCF2OCF2OCF2H (HFE-236cal2); HCF2OCF2CF2OCF2H (HFE-338pcc13); HCF2OCF2OCF2CF2OCF2OCF2H (H-Galden 1040x or H-Galden ZT 130 (or 150 or 180)); 2 trans 1-chloro-3,3,3-trifluoroprop-1-ene; 3 and 2-amino-2-methyl-1-propanol.4

On March 24, 2017, ADEQ submitted SIP revisions to EPA for review and approval. A portion of the submitted revision update the definition of VOC found at the Arkansas Pollution Control & Ecology Commission's (Commission or APC&EC) Regulation No. 19, Regulations of the Arkansas Plan of Implementation for Air Pollution Control. Specifically, the revision adds trans-1,3,3,3-tetrafluoropropene; 2,3,3,3-tertrafluropropene; HCF2OCF2H (HFE-134); HCF2OCF2OCF2H (HFE-236cal2); HCF2OCF2CF2OCF2H (HFE-338pcc13); HCF2OCF2OCF2CF2OCF2OCF2H (H-Galden 1040x or H-Galden ZT 130 (or 150 or 180)); trans 1-chloro-3,3,3-trifluoroprop-1-ene; and 2-amino-2-methyl-1-propanol to the list of compounds excluded from the VOC definition on the basis that these compounds make a negligible contribution to the tropospheric ozone formation. These changes are consistent with EPA's definition of VOC at 40 CFR 51.100(s), section 110 of the CAA and meet the regulatory requirements pertaining to the SIPs.5 Pursuant to CAA section 110(I), the Administrator shall not approve a revision of a plan if the revisions would interfere with any applicable requirement concerning attainment and reasonable further progress (as defined in CAA section 171), or any other applicable requirement of the Act. The revision to Arkansas Regulation No. 19, Chapter 2: Definitions, is approvable under section 110(l) because it reflects changes to federal regulations based on findings that the aforementioned compounds are negligibly reactive.6

Pursuant to section 110 of the CAA, EPA is approving the revision to the Arkansas SIP updating the VOC definition. EPA has evaluated Arkansas' March 24, 2017, submittal and has determined that it meets the applicable requirements of the CAA and EPA regulations and consistent with EPA policy.

The EPA is publishing this rule without prior proposal because we view this as a non-controversial amendment and anticipate no adverse comments. However, in the proposed rules section of this Federal Register publication, we are publishing a separate document that will serve as the proposal to approve the SIP revision if relevant adverse comments are received. This rule will be effective on March 21, 2018 without further notice unless we receive relevant adverse comment by January 22, 2018. If we receive relevant adverse comments, we will publish a timely withdrawal in the Federal Register informing the public that the rule will not take effect. We will address all public comments in a subsequent final rule based on the proposed rule. We will not institute a second comment period on this action. Any parties interested in commenting must do so now. Please note that if we receive relevant adverse comment on an amendment, paragraph, or section of this rule and if that provision may be severed from the remainder of the rule, we may adopt as final those provisions of the rule that are not the subject of an adverse comment.

In this rule, the EPA is finalizing regulatory text that includes incorporation by reference. In accordance with the requirements of 1 CFR 51.5, the EPA is finalizing the incorporation by reference of the revisions to the Arkansas regulations as described in the Final Action section above. The EPA has made, and will continue to make, these materials generally available through www.regulations.gov and/or at the EPA Region 6 Office (please contact Ms. Nevine Salem for more information). Therefore, these materials have been approved by EPA for inclusion in the SIP, have been incorporated by reference by EPA into that plan, are fully federally enforceable under sections 110 and 113 of the CAA as of the effective date of the final rulemaking of EPA's approval, and will be incorporated by reference by the Director of the Federal Register in the next update to the SIP compilation (62 FR 27968, May 22, 1997).

Under the Clean Air Act, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the Clean Air Act. Accordingly, this action merely approves state law as meeting Federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this action:

• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);

• Is not an Executive Order 13771 (82 FR 9339, February 2, 2017) regulatory action because SIP approvals are exempted under Executive Order 12866;

• Does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.);

• Is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.);

• Does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);

• Does not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);

• Is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);

• Is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);

• Is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the CAA; and

• Does not provide EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible methods, under Executive Order 12898 (59 FR 7629, February 16, 1994).

In addition, the SIP is not approved to apply on any Indian reservation land or in any other area where EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the rule does not have tribal implications and will not impose substantial direct costs on tribal governments or preempt tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. The EPA will submit a report containing this rule and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication of the rule in the Federal Register. A major rule cannot take effect until 60 days after it is published in the Federal Register. This action is not a “major rule” as defined by 5 U.S.C. 804(2).

Under section 307(b)(1) of the CAA, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by February 20, 2018. Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this rule for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. This action may not be challenged later in proceedings to enforce its requirements. (See section 307(b)(2).)

Samuel Coleman was designated the Acting Regional Administrator on December 15, 2017 through the order of succession outlined in Regional Order R6-1110.13, a copy of which is included in the docket for this action.

40 CFR part 52 is amended as follows:

Throughout this document “we,” “us,” and “our” means the EPA.

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 adverse health effects and mortality in humans; it also contributes to environmental effects such as acid deposition and eutrophication.

Data from the existing visibility monitoring network, “Interagency Monitoring of Protected Visual Environments” (IMPROVE), shows that visibility impairment caused by air pollution occurs virtually all of the time at most national parks and wilderness areas. In 1999, the average visual range in many Class I areas (i.e., national parks and memorial parks, wilderness areas, and international parks meeting certain size criteria) in the western United States was 100-150 kilometers, or about one-half to two-thirds of the visual range that would exist without anthropogenic air pollution. In most of the eastern Class I areas of the United States, the average visual range was less than 30 kilometers, or about one-fifth of the visual range that would exist under estimated natural conditions. CAA programs have reduced some haze-causing pollution, lessening some visibility impairment and resulting in partially improved average visual ranges.

CAA requirements to address the problem of visibility impairment continue to be implemented. In Section 169A of the 1977 Amendments to the CAA, Congress created a program for protecting visibility in the nation's national parks and wilderness areas. This section of the CAA establishes as a national goal the prevention of any future, and the remedying of any existing, man-made impairment of visibility in 156 national parks and wilderness areas designated as mandatory Class I Federal areas. On December 2, 1980, the EPA promulgated regulations to address visibility impairment in Class I areas that is “reasonably attributable” to a single source or small group of sources, i.e., “reasonably attributable visibility impairment.” These regulations represented the first phase in addressing visibility impairment. The 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 the EPA promulgated regulations addressing regional haze in 1999. The Regional Haze Rule 1 revised the existing visibility regulations to add provisions addressing regional haze impairment and established a comprehensive visibility protection program for Class I areas. The requirements for regional haze are included in our visibility protection regulations at 40 CFR 51.300-309. The requirement to submit a regional haze SIP applies to all 50 states, the District of Columbia, and the Virgin Islands. States were required to submit the first implementation plan addressing regional haze visibility impairment no later than December 17, 2007.

Section 169A of the CAA directs states to evaluate the use of retrofit controls at certain larger, often under-controlled, older stationary sources in order to address visibility impacts from these sources. Specifically, section 169A(b)(2)(A) of the CAA requires states to revise their SIPs to contain such measures as may be necessary to make reasonable progress toward the natural visibility goal, including a requirement that certain categories of existing major stationary sources built between 1962 and 1977 procure, install and operate the “Best Available Retrofit Technology” (BART). Larger “fossil-fuel fired steam electric plants” are one of these 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 other alternative program as long as the alternative provides for greater progress towards improving visibility than BART.

On June 13, 2008, Louisiana submitted a SIP to address regional haze (“2008 Louisiana Regional Haze SIP” or “2008 SIP revision”). We acted on that submittal in two separate actions. Our first action was a limited disapproval 2 because of deficiencies in the state's regional haze SIP submittal arising from the remand by the U.S. Court of Appeals for the District of Columbia of the Clean Air Interstate Rule (CAIR). Our second action was a partial limited approval/partial disapproval 3 because the 2008 SIP revision met some but not all of the applicable requirements of the CAA and our regulations as set forth in sections 169A and 169B of the CAA and 40 CFR 51.300-308, but as a whole, the 2008 SIP revision strengthened the existing SIP. In that action we disapproved Louisiana's long-term strategy, finding that it was deficient given our finding that certain of Louisiana's BART determinations were not fully approvable.4 We found that Louisiana followed the requirements with regards to reasonable progress goals, but that the goals did not reflect appropriate emissions reductions for BART. We found that the long term strategy satisfied most requirements of 40 CFR 51.308(d)(3), but was deficient since it relied on BART determinations which we disapproved.

On August 11, 2016, Louisiana submitted a SIP revision to address the deficiencies related to BART for four non-EGU facilities: Sid Richardson, Phillips 66 Company—Alliance Refinery, Mosaic, and EcoServices, LLC. Based on the BART analysis and modeling provided by Sid Richardson, LDEQ concluded that the facility is not subject to BART because its model visibility impact was less than 0.5 deciviews (dv). We proposed to approve this determination. We also proposed approval of LDEQ's determination that the current controls installed and operating conditions at the Phillips 66 Company—Alliance Refinery subject to BART units constitute BART. The emission limits which reflect current controls and operating conditions at the facility for all subject to BART units are included in Administrative Order on Consent (AOC) No. AE-AOC-14-00211A between LDEQ and Phillips 66 in accordance with 40 CFR 51.308(e), and were provided in the August 11, 2016 SIP revision. We further proposed approval of LDEQ's determination that the current controls and operating conditions at the Mosaic facility constitute BART. The emission limits for Mosaic under current controls and operating conditions are included in AOC No. AE-AOC-14-00274A which was included in the August 11, 2016 SIP revision. Finally, we proposed approval of LDEQ's determination that the current controls and operating conditions at the EcoServices LLC facility constitute BART. The emission limits for EcoServices are included in AOC No. AE-AOC-14-00957 between LDEQ and EcoServices. We proposed to approve that August 11, 2016 revision in its entirety on October 27, 2016.5 We received no comments on our October 27, 2016 proposal and we are finalizing that approval here.

On February 10, 2017, Louisiana submitted a SIP revision intended to address the deficiencies related to BART for EGU sources. On May 19, 2017, we proposed to approve that revision, with the exception of the portion related to Entergy's Nelson facility. We proposed to approve the LDEQ determination that the BART-eligible units at the following facilities do not cause or contribute to visibility impairment and are not subject to BART: Terrebonne Parish Consolidated Government Houma Generating Station (Houma), Louisiana Energy and Power Authority Plaquemine Steam Plant (Plaquemine), Lafayette Utilities System Louis “Doc” Bonin Generating Station, Cleco Teche, Entergy Sterlington, NRG Big Cajun I, and NRG Big Cajun II. We also proposed to approve the LDEQ BART determinations for subject to BART units at the following facilities: Cleco's Brame Energy Center, and Entergy's Willow Glen, Little Gypsy, Ninemile Point, Waterford and Michoud facilities. We proposed to approve the AOCs for Brame, Willow Glen, Little Gypsy, and Ninemile Point. We are now finalizing our approval that BART has been addressed for these units.

We note that Entergy applied for a permit for Michoud, which included the decommissioning of the subject to BART Units 2 and 3, and the construction of new units. We proposed to approve the BART determination for Units 2 and 3 based on the draft permit indicating the units would no longer be operational. We expected the permit would be finalized before we took final action but it has not yet been finalized. We addressed this possibility by also proposing that LDEQ could submit another enforceable document to ensure that Units 2 and 3 cannot restart without a BART determination and emission limits, or otherwise demonstrate that the units have been decommissioned to the point that they cannot restart without obtaining a new NSR permit. LDEQ provided additional information from Entergy indicating that the units are in the process of being decommissioned, and are non-operational, as reflected in an email dated October 9, 2017, submitted by LDEQ to supplement its February 2017 SIP revision. We received no comments on our proposed approach for the Michoud BART units. As a result, we approving the SIP's finding that BART is addressed because the units are no longer in operation and are in the process of being decommissioned.

On June 20, 2017, LDEQ submitted a SIP revision for parallel processing related to Entergy's Nelson facility. On July 13, 2017, we proposed to approve this SIP revision along with the remaining portion of the February 2017 SIP revision that addressed BART for the Nelson facility. Specifically, we proposed to approve the LDEQ BART determinations for Nelson Units 6 and 4, and the Unit 4 auxiliary boiler, and the AOC that makes the emission limits that represent BART permanent and enforceable for the purposes of regional haze. We also solicited comment with respect to any information that would support or refute the costs in Entergy's evaluation of SO2 controls for Unit 6. On June 21, 2017, Entergy submitted a comment to LDEQ on its proposed SIP revision requesting a three-year compliance deadline to achieve the proposed SO2 BART limit for Nelson Unit 6. Entergy's letter explained that the company has coal contracts in place for the next three years, so the revised compliance date would provide the company sufficient time to transition to new mines with lower sulfur coal. Additionally, Entergy stated that it did not have the necessary equipment to blend varying fuel supplies. On August 24, 2017, we received a letter from LDEQ explaining their intent to revise the compliance date in the SIP revision for Nelson Unit 6 based on Entergy's comment letter. On September 26, 2017, we supplemented our proposed approval of the SO2 BART determination for Nelson by proposing to approve the three-year compliance date. On October 26, 2017, we received LDEQ's final SIP revision addressing Nelson, including a final AOC with emission limits and a SO2 compliance date three years from the effective date of the EPA's final approval of the SIP revision.

In 2005, the EPA promulgated CAIR, which required 28 states and the District of Columbia to reduce emissions of SO2 and NOX that significantly contribute to non-attainment or interfere with maintenance of the 1997 national ambient air quality standards (NAAQS) for fine particulates and/or 8-hour ozone in any downwind state.6 EPA demonstrated that CAIR would achieve greater reasonable progress toward the national visibility goal than would BART and determined that states participating in CAIR could rely on CAIR as an alternative to EGU BART for SO2 and NOX.7

Louisiana's 2008 Regional Haze SIP relied on participation in CAIR as an alternative to meeting the source-specific EGU BART requirements for SO2 and NOX.8 Shortly after Louisiana submitted its SIP to us, however, the D. C. Circuit remanded CAIR (without vacatur).9 The court thereby left CAIR and CAIR Federal Implementation Plans (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.10 In 2011, we promulgated the Cross-State Air Pollution Rule (CSAPR) to replace CAIR.11 While EGUs in Louisiana were required to participate in CAIR for both SO2 and NOX, Louisiana EGUs are only included in CSAPR for ozone-season NOX.12

In 2012, we issued a limited disapproval of Louisiana's and several other states' regional haze SIPs because of reliance on CAIR as an alternative to EGU BART for SO2 and/or NOX.13 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/or NOX BART for EGUs, on a pollutant-specific basis.14 Because Louisiana EGUs are included in CSAPR for NOX, Louisiana can rely on CSAPR to satisfy the EGU BART requirement for NOX.

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.15 On October 26, 2016, we finalized an update to CSAPR that addresses the 1997 ozone NAAQS portion of the remand as well as the CAA requirements addressing interstate transport for the 2008 ozone NAAQS.16 Additionally, three states, Alabama, Georgia, and South Carolina, have adopted or committed to adopt SIPs to replace the remanded FIPs and will continue their participation in the CSAPR program on a voluntary basis with the same budgets. On November 10, 2016, we proposed a rule intended to address the remainder of the court's remand as it relates to Texas.17 This separate proposed rule included an assessment of the impacts of the set of actions that the EPA had taken or expected to take in response to the D. C. Circuit's remand on our 2012 demonstration that participation in CSAPR provides for greater reasonable progress than BART. Based on that assessment, the EPA proposed that states may continue to rely on CSAPR as an alternative to BART on a pollutant-specific basis. On September 29, 2017, we finalized our proposed finding that the EPA's 2012 analytical demonstration remains valid and that participation in CSAPR, as it now exists, meets the Regional Haze Rule's criteria for an alternative to BART.18 LDEQ's February 2017 SIP revision relies on CSAPR as an alternative to BART for control of NOX from EGUs.

This action finalizes our proposed approval of the BART determinations for non-EGU facilities,19 our proposed approval of the BART determinations for EGU facilities,20 our proposed approval of the BART determination for Nelson Unit 6,21 our proposed approval of the reliance on CSAPR by EGUs for NOX BART requirements, and our proposed approval that the BART eligible sources 22 at the following facilities do not cause or contribute to visibility impairment and are not subject to BART: Terrebonne Parish Consolidated Government Houma Generating Station (Houma), Louisiana Energy and Power Authority Plaquemine Steam Plant (Plaquemine), Lafayette Utilities System Louis “Doc” Bonin Generating Station, Cleco Teche, Entergy Sterlington, NRG Big Cajun I, and NRG Big Cajun II. With the exception of the change in compliance date for Nelson Unit 6, we note that we are finalizing the proposed rules referenced above as proposed.23 A brief summary of the SIP submittal provisions being finalized is included below.

We are finalizing our approval of the Louisiana Regional Haze SIP as we have found it to meet the applicable provisions of the Act and EPA regulations and it is consistent with EPA guidance. We find that the core requirements for regional haze SIPs found in 40 CFR 51.308(d) such as: The requirement to establish reasonable progress goals, the requirement to determine the baseline and natural visibility conditions, and the requirement to submit a long-term strategy; the BART requirements for regional haze visibility impairment with respect to emissions of visibility impairing pollutants from non-EGUs and EGUs in 40 CFR 51.308(e); and the requirement for coordination with state and Federal Land Managers in 51.308(i) are met. This final action includes, among other things, the approval of the following: The determination that the emission limits reflected in the AOC between LDEQ and Phillips 66 meet the BART requirements, the determination that the sources listed in Tables 1, 2, and 3 below are not subject to BART, the determination that the sources listed in Table 4 below are subject to BART, the determination that the emission limits and operating conditions reflected in the AOC for Mosaic Fertilizer, LLC meet the BART requirements, the determination that the emission limits and operating conditions reflected in the AOC for EcoServices, LLC meet the BART requirements, the determination that emission limits and operating conditions listed in the AOC for Louisiana Generating, LLC meet the applicable BART requirements for Big Cajun II, the determination that the emission limits and operating conditions listed in the AOC for Cleco meet BART requirements for Cleco Brame Energy Center, and the determination that the emission limits and operating conditions in the AOCs for Entergy meet the applicable BART requirements for Waterford, Willow Glen, Ninemile, Little Gypsy, and Nelson. This final rule renders the limits and conditions included in the AOCs mentioned above federally enforceable. We are also finalizing approval of the three-year compliance date for Nelson Unit 6 in this final rule.24

Additionally, this final action fully approves the 2008, 2016, and the two 2017 SIP revisions as supplemented with respect to § 51.308(e), and addresses all deficiencies identified in our previous partial disapproval and partial limited approval of the 2008 SIP submission.25

We received comments from several commenters on our proposed approval of the BART determinations for EGU facilities,26 our proposed approval of the BART determination for Nelson Unit 6,27 and our proposed approval of LDEQ's revised SIP, which changed the effective date of the emission limits for Nelson Unit 6.28 We did not receive comments on our proposed approval of the BART determinations for the four subject to BART non-EGU facilities.29 Our response to the substantive comments are summarized in Section III. We note that we received a comment letter from Cleco Brame Energy Center on August 2, 2017. This comment letter was received outside of the applicable comment period.30 Additionally, the comments contained in the letter did not raise any issues with our proposal. They were submitted in response to issues raised by another commenter in a separate comment letter.31

We are approving the 2008, 2016, February 2017, and the October 2017 LA RH SIPs (as supplemented by the October 9, 2017 email 32 ) submitted by Louisiana as we have determined that they meet all of the regional haze SIP requirements, including the BART requirements in § 51.308(e). We have fully considered all significant comments on our proposed actions on the four RH SIP revision submittals as supplemented by the October 9, 2017 email, and have concluded that no changes are warranted.

We received written comments by the internet and the mail. The full text of comments received from these commenters is included in the publicly posted docket associated with this action at www.regulations.gov. We reviewed all public comments that we received on the proposed actions. Below, we provide a summary of certain comments and our responses. First, we provide a summary of the more significant/relevant modeling related comments with a summary of our responses. The entirety of the modeling comments and our responses thereto are contained in a separate document titled the Modeling RTC document. Second, we provide a summary of all of the relevant technical comments we received and our responses to these comments. Third, we provide a summary below of all of the relevant legal comments and our responses.

Comment: Cleco and Entergy assert that their BART-eligible sources were shown through their initial Comprehensive Air Quality Model with Extensions (CAMx) modeling analysis not to have significant impacts above the 0.5 dv threshold and are therefore, not subject to BART. After EPA's initial review of Entergy and Cleco's CAMx modeling 33 provided to EPA and LDEQ before LDEQ proposed its SIP, EPA provided additional guidance to LDEQ and Entergy/Cleco/Trinity. Even though the commenters disagreed with the technical basis of EPA's requests for revised modeling, in response to this guidance, revised modeling analyses 34 were completed for these sources and the commenters maintain that based on their revised modeling analyses, these units are not subject to BART. The commenters state that EPA's CAMx and CALPUFF modeling, which show that these sources are subject to BART, contain significant defects, making the modeling far less reliable than the initial CAMx modeling analyses submitted by Cleco and Entergy. They assert that CAMx modeling is clearly superior to CALPUFF modeling when there are relatively long distances between the modeled source and the Class I areas. The commenters state that the CAMx modeling protocol followed in their initial modeling analysis was proper, minimizes potential bias and shows that the BART-eligible units at Cleco Brame Energy Center and the Entergy Nelson, Waterford, Willow Glen, Ninemile Point, and Little Gypsy facilities have insignificant impacts at all Class I areas. Therefore, the commenters believe that all of these units should have been characterized as not subject to BART by LDEQ and EPA.

The commenters state that EPA should reconsider its evaluation of the submitted CAMx modeling, as the EPA's concerns about the accuracy of these modeling results are unfounded. Commenters provide additional specific comments addressing technical issues related to EPA's assessment of Cleco and Entergy's CAMx modeling analyses, refutes EPA's criticism in the proposed rule and TSD of this modeling, as well as comments concerning problems with EPA's own CAMx modeling methodology and performance evaluation. These specific comments also address deficiencies with the CALPUFF modeling system, including limitations on modeling at distances greater than 300km and the ability of the CALPUFF model to assess visibility impacts.

Response: We disagree with the comments, and we agree with LDEQ that the CALPUFF modeling following the reviewed protocol is an appropriate tool for evaluating visibility impacts and benefits to inform a BART determination. Relying on the CALPUFF modeling results submitted by Cleco 35 and Entergy,36 as well as EPA's review and additional CALPUFF modeling,37 included in the February 2017 and October 2017 SIP revisions, LDEQ concluded that the BART-eligible sources at Cleco Brame Energy Center and the Entergy Nelson, Waterford, Willow Glen, Ninemile Point, and Little Gypsy facilities have visibility impacts greater than 0.5 dv and are therefore subject to BART. We are finalizing our approval of LDEQ's subject to BART determinations for these EGU sources. Accordingly, LDEQ performed the required five-factor analyses and made BART determinations for these subject to BART sources. We agree with the commenters that CAMx provides a scientifically defendable platform for assessing visibility impacts over a wide range of source-to-receptor distances and 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. As we discuss below, we utilized CAMx to provide additional data and analysis for some large emission sources. However, CALPUFF is an appropriate tool for BART evaluations and remains the recommended model for BART.38 We are confident that CALPUFF distinguishes the relative contributions from sources such that the differences in source configurations, sizes, emission rates, and visibility impacts are well-reflected in the model results. We address specific comments concerning limitations on modeling distance and the ability of CALPUFF to assess visibility impacts from these sources in detail in the Modeling RTC. As discussed in the Modeling RTC document, EPA and FLM representatives have utilized CALPUFF results in a number of different situations when the range was between 300-450 km or more.39 We note that the Entergy Waterford, Willow Glen, Ninemile Point, and Little Gypsy facilities are located 217 km or less from the nearest Class I area. Therefore, the commenters concern regarding the use of CALPUFF modeling for distances greater than 300km is not relevant to the subject-to-BART determinations for these sources.

As we noted in our May 19, 2017 proposed action and CALPUFF Modeling TSD,40 the CALPUFF model is typically used for distances less than 300-400 km. Some of the BART-eligible sources in Louisiana are far away from Class I areas, yet have high enough emissions that they may significantly impact visibility at Class I areas in Louisiana and surrounding states. We performed additional modeling using CAMx to evaluate the visibility impacts and benefits of controls for the Entergy Nelson, Cleco Brame, and Big Cajun II sources to address possible concerns with utilizing CALPUFF to assess visibility impacts at Class I areas located far from these large emission sources. LDEQ included this modeling in Appendix F of the October 26, 2017 SIP revision.41 Our CAMx modeling supports the determination made by LDEQ that Entergy Nelson and Cleco Brame cause or contribute to visibility impairment at nearby Class I areas and are therefore subject to BART. Entergy Nelson has a maximum modeled impact of 2.22 dv at Caney Creek, with 31 days out of the 365 days modeled exceeding 0.5 dv, and 9 days exceeding 1.0 dv. Similarly, Cleco Brame has a maximum modeled impact of 2.833 dv at Caney Creek, with 30 days out of a maximum 365 days modeled exceeding 0.5 dv and 10 days exceeding 1.0 dv. We disagree with the commenters and find that our CAMx modeling is consistent with the BART Guidelines and a previous modeling protocol we developed for the use of CAMx modeling for BART screening for sources in Texas. 42 43 We respond to specific comments concerning our CAMx modeling, including model inputs, model performance, our modeling protocol and the use of direct model results in detail in the Modeling RTC document.

As we discuss in detail in our May 19, 2017 proposed action and CAMx Modeling TSD,44 the initial CAMx modeling, as well as the revised modeling submitted by Cleco and Entergy 45 was not conducted in accordance with the BART Guidelines and the previous modeling protocol developed for the use of CAMx modeling for BART screening for sources in Texas and does not properly assess the maximum baseline impacts. We disagree with the commenters and consider this CAMx modeling in the February 2017 LA RH SIP, Appendices B and D, to be invalid for supporting any determination of visibility impacts below 0.5 dv. As discussed in the CAMx Modeling TSD and in our Preliminary Review Response letter to Entergy and Cleco,46 the initial modeling deviated from the BART guidelines because it did not utilize emissions representative of maximum 24-hr actual emissions from the baseline period, did not evaluate the maximum modeled impact for all days, and did not calculate the deciview visibility impact based on a natural visibility background approach. We also review the revised modeling in detail in the CAMx Modeling TSD, identify a number of short comings in the revised approach, and conclude that it does not properly assess the maximum baseline impacts and is inconsistent with the BART Guidelines. We respond to specific comments concerning the CAMx modeling analyses developed by Trinity Consultants for Cleco and Entergy included in the February 2017 LA RH SIP at Appendices B and D in detail in the Modeling RTC.

Comment: NRG stated that it supports EPA's proposed approval of Louisiana's SIP revision, which determined that the Big Cajun II units are not subject to BART. NRG stated that Big Cajun II is not subject to BART, but even if it were, no further controls would be needed because the compliance actions NRG has taken for Mercury and Air Toxics Standards (MATS) and a consent decree,47 including installation of the existing dry sorbent injection (DSI) system, would be sufficient to meet BART. NRG asserted that, if the requirements set forth in the Consent Decree between Louisiana Generating 48 and EPA do not satisfy BART, Louisiana Generating's five-factor analysis, which used a baseline based on operation of the existing DSI and represents a realistic depiction of anticipated annual emissions, indicates that no further controls are cost-effective and Big Cajun II's current configuration and emission controls satisfies BART.

Response: We agree that Big Cajun II is not subject to BART. Prior to the submittal of the February 2017 Regional Haze SIP, the LDEQ and Louisiana Generating entered into an AOC that made the existing control requirements and maximum daily emission limits permanent and enforceable for BART. The AOC is included in Louisiana's February 2017 SIP revision. The modeling included in the February 10, 2017 SIP submittal (Appendix C) demonstrates that, with these existing controls and enforceable emission limits, Big Cajun II has modeled visibility impacts less than 0.5 dv at all impacted Class I areas, and therefore the facility is not subject to BART. We are finalizing our approval of Louisiana's determination in the SIP that the source is not subject to BART. Because the source was determined to not be subject to BART, LDEQ and EPA have made no determination of what controls, if any, would be necessary to satisfy BART had the source not screened out.

Comment: Cleco stated that it disagrees with the EPA that there is uncertainty in the cost-effectiveness of the enhanced DSI system for the Rodemacher 2 unit. Cleco stated that cost-effectiveness is calculated by adding annual operation and maintenance costs to the annualized capital cost of an option and then dividing by the reduction in annual emissions from a baseline period. Cleco asserted that, as the EPA acknowledged in its proposal, there are no capital costs associated with upgrading to an enhanced DSI system at Rodemacher 2. Rather, the only costs that Cleco will incur relate to additional reagent and associated waste disposal. Cleco stated that the cost of reagent that the company used in its five-factor analysis was based on actual contracts (currently in place) between the reagent supplier and Cleco. In addition, Cleco determined the reduction in emissions from the baseline period during actual unit testing. Therefore, Cleco believes that there is a high degree of certainty that the cost-effectiveness value for an enhanced DSI system is $967/ton.

Cleco also disagrees with the EPA that there is “uncertainty” with respect to the cost-effectiveness estimates for the dry scrubbing (Spray Dry Absorption or SDA) and wet scrubbing (wet Flue Gas Desulfurization, or wet FGD) options. The estimates were prepared for Cleco by the engineering firm Sargent & Lundy (S&L). S&L is a full-service engineering consulting firm providing expertise in all areas of power plant engineering and design. S&L has considerable experience with the federal and state environmental regulations affecting power plant operations, as well as the specification, evaluation selection, and implementation of emission control technologies for both gas and coal-fueled utility power facilities, including extensive experience with various FGD technologies. For example, since 2000, S&L has provided, or is currently providing, engineering services for the implementation of over 40 wet FGD projects, 30 dry FGD projects, and 25 DSI projects, all of which are technologies that were analyzed as part of the Five-Factor Analysis. As such, S&L is qualified to develop capital and O&M cost estimates for these control analyses.

Cost estimates for the Rodemacher 2 unit were prepared in accordance with the BART Guidelines and the methodology described in EPA's Control Cost Manual and represent study-level cost estimates. Capital costs for major equipment were developed using equipment costs for similarly sized units (adjusted for actual equipment sizing), site-specific balance-of plant (BOP) project-specific indirect cost factors. Where possible, default factors from EPA's Control Cost Manual were used to calculate indirect costs.

The capital cost estimates were provided to LDEQ and EPA for both the wet FGD and SDA options identifying the major cost categories, including civil work, concrete, steel, mechanical equipment, material handling, electrical, piping, controls and instrumentation. In addition, detailed cost effectiveness worksheets were provided to LDEQ and EPA identifying the variable O&M costs (e.g., reagent, waste disposal, auxiliary power and water), indirect operating costs (e.g., property taxes, insurance, and administrative services) and fixed O&M costs (e.g., operating personnel, maintenance material and labor) for both the SDA and wet FGD options. The indirect and fixed operating costs were based on factors provided in EPA's Control Cost Manual.

Cleco, however, agrees with EPA that the Total Capital Cost figure for the SDA option should be $378,318,000. The capital cost for the fabric filter and associated auxiliaries were inadvertently included twice in the Total Capital Cost figure line item. As such, the cost effectiveness for the SDA option should be $6,893/ton, not $8,589/ton. See attachment Cleco RPS2 S02 Worksheets_2010-2014 Baseline—Rev I. Regardless, the cost-effectiveness of the SDA and wet FGD options are significantly higher in comparison to the enhanced DSI option with minimal incremental visibility improvement. Cleco nevertheless agrees with LDEQ and EPA that an enhanced DSI system meets BART for the Rodemacher 2 unit.

Response: We agree that the cost effectiveness figures presented in Cleco's Five Factor Analysis included in the February 2017 LA RH SIP, Appendix B, are reasonable, as we stated in our April 2017 Technical Support Document (April 2017 TSD).49 “However, because DSI and a fabric filter baghouse are already installed and operational, the cost-effectiveness of Cleco's enhanced DSI is based only on the cost of the additional reagent and no additional capital costs are involved. Consequently, we believe that the uncertainty of Cleco's enhanced DSI cost-effectiveness figures is low and that Cleco's estimated cost-effectiveness of $967/ton is reasonable.” 50

We agree with Cleco's correction to the capital costs provided for SDA, and that the total capital cost figure based on Cleco's cost estimate should have been $378,318,000. The estimated cost effectiveness for SDA in their analysis is $6,893/ton, rather than $8,589/ton as stated in the Cleco cost analysis.51

As discussed in the April 2017 TSD, Cleco did not supply complete documentation for its cost analysis for SDA and wet FGD for Rodemacher 2, including details to support total direct cost and total capital cost figures. Based on our experience reviewing and conducting control cost analyses for many other similar types of facilities, Cleco's estimates appear high and without complete documentation, some uncertainty exists with respect to Cleco's cost-effectiveness estimates for SDA and wet FGD—$6,893/ton and $5,580/ton, respectively. For example, our estimated cost-effectiveness for similar equipment at Nelson Unit 6 is approximately $3000/ton.

We noted, however, that because DSI and a fabric filter baghouse are already installed and operational, the cost-effectiveness of Cleco's enhanced DSI is based only on the cost of the additional reagent and no additional capital costs are involved. In contrast to enhanced DSI, SDA and wet FGD, require the installation of controls and significant capital costs. We recognize the low cost effectiveness value of enhanced DSI. We also recognize the potentially high incremental costs of obtaining 0.1-0.2 dv of visibility improvement through SDA or wet FGD. Therefore, we are finalizing our approval of LDEQ's conclusion that enhanced DSI is SO2 BART for the Rodemacher 2, with a SO2 emission limit of 0.30 lbs/MMBtu on a 30 day rolling basis.

Comment: EPA's proposed determination [for Cleco's Brame Unit 2 (Rodemacher 2)] that enhanced DSI constitutes BART due to it being more cost-effective than FGD or scrubber given the small amount of additional visibility improvement that would be achieved with FGD or SDA is incorrect. EPA admitted it did not know the cost of scrubbers and therefore could not make the determination that scrubbers were not cost effective. Additionally, EPA recognized in its proposal that the costs submitted by Cleco were likely too high. EPA provided no discussion concerning the range of cost-effectiveness values for wet FGD that the agency would deem sufficient to justify the incremental visibility improvement relative to enhanced DSI. Nothing in the guidance, statute, or federal rules indicates that incremental costs should be dispositive in a BART determination. EPA must correct the State's mistakes and provide an accurate estimate of the costs and cost-effectiveness of controls, including enhanced DSI, dry FGD, and wet FGD.

Had EPA or Louisiana developed an accurate cost analysis, it is clear that either a wet or dry FGD at Rodemacher 2 would be well within the range of controls that EPA has previously determined are cost effective. First, with respect to dry FGD systems, it does not appear that Louisiana or EPA evaluated accurate removal efficiencies of various dry FGD systems, especially with the low sulfur coal that is used. SDAs can achieve emission rates lower than 0.06 lb/MMBtu and SO2 removal efficiencies greater than 95% control.52 Indeed, Louisiana failed entirely to evaluate dry FGD systems, such as circulating dry scrubbers (CDS) that are commonly used in the industry and vastly understated the removal efficiencies associated with those controls. The Alstom Novel Integrated Desulfurization system (NIDTM), has been selected as the most cost effective scrubber option when compared to other technologies in several recent evaluations. Second, with respect to the dry FGD systems that the State did evaluate, it significantly overstated the costs of such control technologies. Together, these errors significantly overstated the cost-effectiveness of dry FGD systems. When those errors are corrected the cost-effectiveness of dry FGD control technology is well within the range of costs that EPA has previously found reasonable.53 SDA at a controlled emission rate of 0.06 lb/MMBtu is estimated to be $2,908/ton. SDA or NIDTM CDS is estimated to be $2,808/ton with a controlled emission rate of 0.04 lb/MMBtu.

These supplemental cost analyses, using the same IPM cost spreadsheets used by EPA in its proposed Texas BART analysis,54 demonstrate that Louisiana's cost analyses for a dry FGD system are greatly overstated.

Louisiana's cost calculations for wet FGD controls at Rodemacher 2 are also erroneous. Contrary to Louisiana's evaluation, wet FGDs can achieve much lower SO2 emission rates than the 0.04 lb/MMBtu assumed by the State. Indeed, coupled with low sulfur Powder River Basin coal, new wet FGD scrubbers can achieve emission reductions greater than 95%, and are capable of achieving SO2 emission rates of 0.02 lb/MMBtu. Even assuming a 0.04 lb/MMBtu emission rate, an accurate cost effectiveness evaluation demonstrates that a wet FGD system could be installed for $2,947/ton of SO2 removed, which is well within the range of costs that EPA has found reasonable—most recently in the agency's proposed BART determinations for Texas. Moreover, BART controls have been approved that would lead to equal, or less, visibility improvement than achievable with wet or dry scrubbers at Rodemacher 2.

The commenter states that their supplemental cost analyses of either wet FGD or dry FGD at Brame Unit 2 (Rodemacher 2) show that the costs of either a wet or a dry FGD system are very reasonable, in that other similar sources have had to bear similar costs for pollution control to address BART and regional haze requirements. The incremental costs of installing a dry FGD or a wet FGD system at Brame Unit 2 compared to DSI plus a baghouse are very reasonable and thus should not be the basis for rejecting a dry or wet FGD system at Brame Unit 2. Considering the additional SO2 reductions and improved visibility benefits of installing the more effective controls of a dry or wet scrubber compared to DSI, EPA should have based its SO2 BART determination on either wet or dry FGD for Brame Unit 2.

Response: We agree with the comment that in some cases SDA and wet FGD may achieve lower emission rates than those evaluated. We evaluated the control capabilities of SDA and wet FGD in our action on Oklahoma BART.55 There we determined that reduction efficiencies of up to 95% or as low as 0.06 lb/MMBtu SO2 for dry scrubbers and 97%-98% removal efficiency or an outlet SO2 of 0.04 lb/MMBtu for wet scrubbers are appropriate levels for the BART evaluation for units when burning low sulfur coals.56 These limits are a reasonable estimate of potential control and we have consistently used these emission limits in our evaluation of controls for similar units in Texas and Arkansas.57 We disagree with the comment that the analysis in the February 2017 SIP is deficient because CDS was not evaluated. CDS is a variation on SDA with similar costs and reduction efficiency as the more widely used SDA design. As the commenters note, CDS annual costs are estimated to only be about 1-2% lower than the annual costs of an SDA.

We disagree with the comment concerning consideration of incremental costs. The BART Guidelines state that while the average costs (total annual cost/total annual emission reductions) for two control options each may be deemed to be reasonable, the incremental cost of the additional emission reductions to be achieved by option 2 may be very great. In such an instance, it may be inappropriate to choose option 2, based on its high incremental costs, even though its average cost may be considered reasonable.58 LDEQ reviewed all the available information and determined that the amount of visibility benefit achieved from SDA or wet FGD over enhanced DSI was not large enough to justify the additional cost of these controls at Rodemacher 2. EPA's regulations under the CAA “do not require uniformity between . . . actions in all circumstances and instead `allow for some variation' in actions taken in different regions.” 81 FR at 326 (quoting Amendments to Regional Consistency Requirements, 80 FR 50250, at 50258 (Aug. 19, 2015)). Some variation is to be expected because SIP actions are highly fact-dependent. The state weighed the factors considering all available information, in the February 10, 2017 SIP, and concluded that enhanced DSI is BART for this unit. The CAA allows EPA to review all the information in the SIP submittal and any other publicly available information to make its decision whether it agrees the state's determination meets the applicable requirements. After reviewing the relevant information, we determined that the State's SIP meets the requirements of the Act and the applicable regulations and guidance.

In our review of the cost estimates, we noted a lack of documentation and uncertainty in the Cleco cost-estimates for SDA and wet FGD. We noted, however, that because DSI and a fabric filter baghouse are already installed and operational, the cost-effectiveness of Cleco's enhanced DSI is based only on the cost of the additional reagent and no additional capital costs are involved. The cost-effectiveness of enhanced DSI was estimated to be $967/ton.59 In contrast to enhanced DSI, SDA and wet FGD require the installation of controls and significant capital costs. Cleco's cost-effectiveness estimates for SDA and wet FGD are $6,893/ton and $5,580/ton, respectively, while the commenter's estimate the costs of SDA, NIDTM CDS and wet FGD to be approximately $2,800/ton or greater.60 When the already sunk capital costs of the existing DSI system are removed, the incremental annual cost of enhanced DSI is estimated to be only $1,695,300/yr. Even accounting for the potential issues in Cleco's SDA and wet FGD cost analyses and considering the commenter's cost estimates, we are cognizant of the enhanced DSI's low cost-effectiveness, and the incremental costs of obtaining the additional 0.1-0.2 dv of visibility improvement that can be achieved by SDA, CDS or wet FGD over enhanced DSI are high. Therefore, we are finalizing our approval of LDEQ's conclusion that the amount of visibility benefit achieved from SDA or wet FGD over enhanced DSI was not large enough to justify the additional cost of these controls and enhanced DSI is SO2 BART for the Rodemacher 2, with a SO2 emission limit of 0.30 lbs/MMBtu on a 30 day rolling basis.

Comment: With respect to the analysis for the Rodemacher 2 unit, EPA stated the following concerning enhanced DSI:

82 FR 22936. On page 19 of the related TSD, EPA further stated:

Cleco disagrees that there is a “degree of uncertainty” concerning the potential SO2 control level of the current DSI system or the enhanced DSI system. Although the testing conducted was based on operating the system to determine removal of hydrogen chloride (HCl), the Rodemacher 2 unit operated a SO2 continuous emission monitoring system (CEMS) that gathered valid, real-time SO2 emissions data that demonstrated the achievable reductions. The data gathered by the SO2 CEMS is the same data submitted to EPA's Air Markets Program Data on a quarterly basis. Cleco, therefore, does not believe that a degree of uncertainty exists with respect to the SO2 control level.

As stated in the BART Five-Factor Analysis submitted to LDEQ,61 two performance tests were conducted at very high injection rates to determine the removal that could be achieved while operating the DSI system at close to the maximum design injection rate. The first test was performed at 12,000 lb/hr, which showed an average removal of 66% SO2 and the second test was conducted at 4,000 lb/hr, which showed an average removal of 63% SO2. Both tests were conducted at injection rates significantly higher than the current DSI rate of 1,500 lb/hr. Although the system is designed to inject up to 17,800 lb/hr of Trona, there would be close to no benefit in additional SO2 reduction since increasing the injection rate by 300% (from 4,000 lb/hr to 12,000 lb/hr) only provided an additional 3% SO2 reduction on average. Based on the foregoing, Cleco believes there is a high degree of certainty regarding the control levels achievable for the current DSI and enhanced DSI systems.

We also received comments from environmental groups 62 stating that Cleco evaluated two levels of control with DSI: DSI to meet an SO2 limit of 0.41 lb/MMBtu and “enhanced DSI” to meet an SO2 limit of 0.30 lb/MMBtu. These proposed limits were based on testing done on-site that Cleco conducted to determine the performance potential of enhanced DSI. However, Cleco did not submit the testing as part of the record for the BART determination. Further, the testing was not done to evaluate SO2 removal efficiency and was instead done to optimize hydrogen chloride control efficiency. Presumably, Cleco did not concurrently evaluate uncontrolled SO2 emissions, and thus the accuracy of the assumed SO2 removal efficiencies with DSI and enhanced DSI of 39% and 63% is questionable.

Further, Brame Unit 2 (Rodemacher 2) is already achieving the assumed “enhanced DSI” level of control of 0.30 lb/MMBtu SO2 rate with the current DSI operations which are being implemented to meet the MATS hydrogen chloride limit. Based on data in EPA's Air Markets Program Database, the average monthly SO2 emission rate at Brame Unit 2 was 0.26 lb/MMBtu from June 2015 through the first quarter of 2017. While there have been a few months with monthly SO2 emission rates in excess of 0.30 lb/MMBtu, the large majority of monthly SO2 emission rates at Brame Unit 2 have been at or well below 0.30 lb/MMBtu. Thus, there does not seem to be much if any enhancement needed to achieve 0.30 lb/MMBtu with DSI and a baghouse. Cleco should therefore have assumed a 0.30 lb/MMBtu SO2 limit, or even lower, as achievable with the currently operated DSI and baghouse. Given that the unit is already achieving a 0.30 lb/MMBtu level, it does appear likely any lower SO2 emission rates could be achieved with DSI “enhancements.”

Response: We agree with the commenter that the available testing data demonstrates that increasing the injection rate beyond 4,000 lb/hr (63% removal) results in minimal increased removal efficiency. As we discussed in our TSD and identified by the commenter above, because the DSI testing was not performed to examine optimization of SO2 removal and Cleco did not provide sufficient detail with regard to how the testing was conducted, we noted “some uncertainty” in the potential control levels for DSI and enhanced DSI. For example, it is unclear if the testing evaluated a range of fuel sulfur content or heat input rates. We therefore reviewed available emissions data from the unit from when the DSI became operational in March 2015 through the end of 2016 and found that based on that information 63 covering a range of actual operations, as well as the provided testing data, Louisiana's selection of 0.30 lbs/MMBtu on a rolling 30-day basis for SO2 is reasonable for an enhanced DSI system on the Rodemacher 2 unit.

We agree with the comment that recent emission data from June 2015 through the first quarter of 2017 demonstrates the ability to emit at or below 0.3 lb/MMBtu on a monthly basis. However, as also noted by the commenter, monthly emission rates with the current operation of the existing DSI system have also exceeded 0.3 lb/MMBtu at times during that same period. For example, the average monthly emission rate in December 2016 was 0.39 lb/MMBtu. The available testing data demonstrates that the unit is already equipped to operate the existing DSI and fabric filter at a range of injection rates, including the higher injection rates evaluated in the BART analysis, as “enhanced DSI.” In order to achieve the emission rate specified in Louisiana's BART determination of 0.30 lbs/MMBtu for SO2, made permanent and enforceable in the AOC, Cleco will have to operate the existing DSI system at higher injection rates to maintain future emissions below 0.3 lb/MMBtu on a rolling 30-day basis.

Comment: LDEQ commented that EPA's cost analysis did not alter its initial conclusion presented in its February 2017 RH SIP submittal that BART was “no further control.”

Response: In its October 2017 Regional Haze SIP submittal, LDEQ stated that, after a weighing of the five factors and after a review of both Entergy's and EPA's information, “BART is the emission limit of 0.6 lbs/MMBtu based on a 30 day rolling average as defined in the AOC . . . LDEQ believes, at present, that the use of lower sulfur coal presents the appropriate SO2 control based on consideration of economics, energy impacts, non-air quality environmental impacts, and impacts to visibility.” 64

Comment: Entergy supports the proposed limit for Nelson Unit 6 but disagrees that the Control Cost Manual disallows certain costs such as escalation during construction and owner's costs.65 These are actual costs that will be incurred during construction and that should have been included in the costs for each add-on control technology evaluated. Entergy also disagrees with EPA's reduction in the contingency factor from 25% to 10%. EPA has provided no justification for its use of 10% for the contingency factor, over than that it is “in the middle of the range employed in the Control Cost Manual.” 66 The costs that Entergy submitted in its BART Five-Factor Analysis for Nelson 67 are a more accurate estimate of the actual costs for controls at Nelson Unit 6 than the more generic costs that EPA assumed. However, even accepting EPA's cost calculations, the costs of installing SO2 controls are too high to constitute BART in light of the distance of Nelson from the nearest Class I areas and the minor visibility benefit expected to be achieved by such controls. Based on an evaluation of the five statutory factors required for a BART analysis, LDEQ appropriately concluded that low sulfur coal constitutes SO2 BART for Nelson 6. As Entergy concluded in the Nelson Five-Factor analysis, “no visibility improvement can reasonably be anticipated to result from the installation of [SO2] controls. Furthermore, the cost of each of the add-on [SO2] control options for Unit 6 is estimated as $3 billion or more per dv improvement.” 68

Response: We disagree with commenters' assertions that Allowance for Funds Used During Construction (AFUDC) should be incorporated into our cost analysis, as the practice of incorporating AFUDC is contradictory to the Cost Control Manual (CCM) methodology.69 The utility industry uses a method known as “levelized costing” to conduct its internal comparisons, which is different from the methods specified by the CCM. Utilities use “levelized costing” to allow them to recover project costs over a period of several years and, as a result, realize a reasonable return on their investment. The CCM uses an approach sometimes referred to as overnight costing, which treats the costs of a project as if the project were completed “overnight,” with no construction period and no interest accrual. Since assets under construction do not provide service to current customers, utilities cannot charge the interest and allowed return on equity associated with these assets to customers while under construction. Under the “levelized costing” methodology, AFUDC capitalizes the interest and return on equity that would accrue over the construction period and adds them to the rate base when construction is completed and the assets are used. Although it is included in capital costs, AFUDC primarily represents a tool for utilities to capture their cost of borrowing and return on equity during construction periods. AFUDC is not allowed as a capitalized cost associated with a pollution control device under CCM's overnight costing methodology and is specifically disallowed for SCRs (ie., set to zero) in the CCM.70 Therefore, in reviewing other BART determinations, EPA has consistently excluded AFUDC.71 EPA's position regarding exclusion of AFUDC has been upheld in the United States Ninth Circuit Court of Appeals.72

In the TSD we discuss Entergy's selection of contingency factor. There, we state that we are not aware of any characteristics of Nelson Unit 6 that would present any unusual difficulty distinguishing it from any other scrubber retrofit, and thus justifying a high estimate for contingency. The CCM uses contingency values ranging from 5 to 15%, depending upon the control device in question and the precise nature of the factors requiring contingency. Entergy has not provided any additional information to support the use of a contingency factor outside of this range. The CCM clarifies that a contingency factor should be reserved (and applied to) only those items that could incur a reasonable but unanticipated increase but are not directly related to the demolition, fabrication, and installation of the system. We used a contingency value of 10% for our analysis and adjustment of Entergy's costs, which lies in the middle of the range employed in the CCM. We believe this value is appropriate for mature technologies such as SDA and wet FGD.73

We disagree with the commenter's conclusion that no visibility improvement can reasonably be anticipated to result from the installation of SO2 controls and that visibility benefits of scrubbers cost $3 billion/dv or more. This conclusion and estimate in Entergy's Nelson Five-Factor analysis, is based on its CAMx modeling analysis. As we discuss in detail in the CAMx Modeling TSD and in our Modeling RTC document, we consider this submitted CAMx modeling to be invalid for supporting any determination of visibility impacts. The results of Entergy's CALPUFF modeling and EPA's CALPUFF and CAMx modeling assessing the visibility benefits of controls on this unit are included in Appendix D and F of the October 2017 LA RH SIP.

LDEQ reviewed all the available information including the modeling provided by EPA and determined “that additional visibility benefits may be available through the use of FGD.” The state, however, weighed the factors considering all available information contained in the SIP submittal, and concluded that “the use of lower sulfur coal presents the appropriate SO2 control based on consideration of economics, energy impacts, non-air quality environmental impacts, and impacts to visibility.”

We also note that we disagree with the use of the dollar per deciview metric as the only cost effectiveness metric in BART determinations. We discuss this in detail in our Response to Comments on our final action on Oklahoma Regional Haze.74 Our decision to not rely on a $/dv metric was reviewed and upheld in by the Tenth Circuit.75

Comment: The State makes the claim that a scrubber should be rejected because of the environmental impacts of waste generated by a scrubber. EPA reached the opposite conclusion, stating that FGD and DSI “do not present any significant or unusual environmental impacts.” Moreover, the State ignores that the cost to dispose of scrubber wastes is included in the cost model for a scrubber, as EPA points out. Allowing Nelson to emit 0.6 lb/MMBtu of SO2 is a ten-fold increase in the SO2 emissions rate relative to the 0.06 lb/MMBtu which a scrubber can achieve.76 In the name of considering environmental impacts, the State chose the option that will lead to the greatest amount of air pollution. This is not rational decision making, it runs counter to the statutory mandate for the haze program, and it is not approvable. We are unaware of any similar state or EPA decision for a haze SIP. EPA has cited no precedent for approving a State's selection of the least-effective pollution control on the basis that more effective pollution controls allegedly are worse for the environment.

In addition, the State fails to consider that a dry scrubber generates far less waste than a wet scrubber. And scrubber wastewater can be treated with available technologies to dramatically reduce environmental impacts. See 80 FR 67838 (Nov. 3, 2015). The State's rejection of a scrubber because of the auxiliary power needed to run a scrubber is without merit. All of the cost calculations for a scrubber reviewed by the State—both EPA's and Entergy's—included the energy cost to run the scrubber. Thus, the energy cost is not a separate consideration, and is not a separate basis for rejecting a scrubber. Just as we are aware of no example of EPA approving the rejection of a scrubber on the basis of scrubber wastes, we are not aware of any EPA decision approving the rejection of a scrubber because of the auxiliary power costs.

Response: We disagree with the commenter's characterization of the State's consideration of the energy and non-air quality environmental impacts. The consideration of these impacts is required as part of the BART determination. LDEQ stated in the October 2017 SIP:

LDEQ did not reject additional controls solely on the basis of the non-air quality environmental impacts or energy impacts associated with those controls. LDEQ identified the impacts associated with each control level as required, noting the difference between the lower sulfur coal option and additional add-on controls. LDEQ considered all of the available information, including EPA's analysis of the associated impacts and costs, and weighed all the factors in making the BART determination for Nelson Unit 6.

Comment: EPA cannot possibly have discharged its obligation to ensure that the State's BART determination is “reasonably moored to the Act's provisions,” Alaska Dep't of Envtl. Conservation, 540 U.S. at 485, because EPA claims it was “unable to verify any of the company's costs,” 82 FR at 32298, and could review only the “general description of the modeling protocol” that Entergy used. See Appendix F, CAMx Modeling TSD at 30. It is axiomatic that EPA cannot approve a plan where the agency is unable to review and verify the accuracy of the analysis on which the plan is based. See Motor Vehicle Mfrs. Ass'n of U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983) (“[T]he agency must examine the relevant data and articulate a satisfactory explanation for its action including a `rational connection between the facts found and the choice made.' ”) (emphasis added) (quoting Burlington Truck Lines v. United States, 371 U.S. 156, 168 (1962)).

Response: We disagree with the comment. While we noted in our proposal that we were unable to verify the company's costs and that we reviewed a general description of Entergy's modeling protocol, we also noted that we conducted our own independent cost analysis and CAMx modeling.78 EPA's cost and visibility analyses were included by LDEQ as a part of its October 2017 SIP submission (Appendix F) and were included in the information considered by the State in making its BART determination. LDEQ considered all the information contained in the SIP submittal, including information submitted by Entergy, EPA's review of that information, and EPA's additional analyses. As a result, LDEQ had adequate information upon which to base its determination.79

Comment: Neither the State nor EPA offered a rational basis for rejecting a scrubber and EPA did not offer a rational basis for approving the State's decision. The State did not explain why it rejected a control with cost-effectiveness and visibility improvement values which so many other states, and EPA, have found reasonable for BART determinations. And EPA has not explained how it can approve the rejection of a scrubber when the cost-effectiveness and visibility improvement values are within the range that EPA has found reasonable in so many other haze rulemakings. See generally 42 U.S.C. 7410(k)(3) (requiring EPA to review each SIP submission to ensure compliance with the Act), id. sec. 7410(l) (barring EPA approval of a SIP submission that interferes with any applicable requirement of the Act); Oklahoma v. EPA, 723 F.3d at 1208-09 (holding that “the statute mandates that the EPA must ensure SIPs comply with the statute” and upholding EPA's disapproval of the Oklahoma regional haze plan because Oklahoma “failed to follow the [BART] guidelines”).

EPA cannot approve the State's plan because EPA concluded that the analysis the State relied on is riddled with errors; approving such a plan is arbitrary and capricious. EPA identified multiple errors in Entergy's cost and visibility analyses—errors which Entergy and the State refused to correct, e.g., escalation during construction and owner's costs, a contingency of 25%, and the inability to verify any of the company's costs. EPA's submission of its own analyses to the State does not cure this defect since EPA's analysis is limited by the same lack of access to data from which the State's analysis suffers.

Response: As explained in previous responses, EPA reviewed the State's entire submission, including any attached appendices and supporting documentation, and any publicly available information as a whole in determining whether the State's submission is approvable. Though we identified errors in Entergy's cost and visibility analyses, EPA conducted its own cost and visibility analyses in accordance with the applicable regulations and guidelines. EPA's cost and visibility analyses are part of the SIP submission (Appendix F) and were included in the information considered by the State in making its BART determination. We do not believe that our modeling or cost analysis were limited by the lack of access to data. Our cost estimates rely on algorithms designed to use readily available data 80 that provide reasonable estimates of costs. Furthermore, we had all the data necessary to make estimates of visibility impairment. We only noted that there was limited access to documentation to explain the difference between our cost estimates and those provided by Entergy. As stated previously, LDEQ considered all the information contained in the SIP submittal. LDEQ reviewed this information as is evidenced by its SIP submission. LDEQ states, “LDEQ has weighed the five factors and after a review of both Entergy's and EPA's information. . .” 81 This indicates that the State reviewed the information it received from both Entergy and the EPA, and thus had adequate information upon which to base its determination. After reviewing the relevant information contained in LDEQ's SIP, we determined that the State's SIP meets the requirements of the Act and the applicable regulations and guidance.

Comment: Though EPA stated that the State “weighed the statutory factors,” 82 there is no evidence that the State weighed two of the statutory factors, the remaining useful life of the source and the existing controls in use at the source. BART must be based on a consideration of the five factors. The State's BART analysis appears in a single paragraph, which does not mention two of the five factors: The “remaining useful life of the source” and “existing pollution controls in use at the source,” 42 U.S.C. 7491(g)(2). The State's failure to consider existing pollution controls for SO2 emissions is significant, given that the State treats its BART determination of low-sulfur coal as requiring Nelson to do something new, despite evidence that Nelson is already using low-sulfur coal. As EPA acknowledged, the RS Nelson Plant has already been burning low sulfur Powder River Basin coal for many years.83

Similarly, it is important that states consider the “remaining useful life” factor. Cost calculations typically assume that costs will be recovered over the remaining useful life of a source. As a result, the remaining useful life is a key variable in cost analyses.

Whether Entergy or EPA considered these two factors is irrelevant legally, because the statute requires the State, not the plant owner, to determine BART. There is no evidence in the SIP that the State actually considered and relied on any analysis which Entergy or EPA may have conducted of the remaining useful life and existing pollution controls in use at the source. In particular, there is no passage in the State's SIP narrative in which the State discusses how it considered and weighed the remaining useful life and existing pollution controls in use at Nelson.84 EPA cannot approve a BART determination which fails to consider two factors, the remaining useful life and the existing controls in use at the source, which the statute requires states to consider.

Response: As explained in previous responses above, EPA reviews the final SIP document and any accompanying supplementary information or appendices that have been submitted by the State. In the October 2017 LA RH SIP at Appendix D, Entergy's BART analysis for Nelson unit 6 includes a description of existing control equipment at the unit 85 and a statement that remaining useful life does not impact the cost analysis.86 In our analysis, we conducted a five-factor analysis and addressed both remaining useful life and the existing controls in use at the source. As discussed in our draft Technical Support Document provided to LDEQ and included in its October 2017 LA RH SIP, Appendix F, in evaluating the cost of switching to lower sulfur coal to meet an emission limit of 0.6 lb/MMBtu, we began by noting that Entergy has purchased both higher and lower sulfur coals. To account for the existing use of low sulfur coal, we applied the premium 87 associated with purchasing only low sulfur coal to the fraction of higher sulfur coal purchased. In making their decision, the State evaluated all available information regarding the remaining useful life of the source and the existing controls in use at the source. LDEQ submitted the analyses conducted by EPA and Entergy as appendices to the LA RH SIP. As such, we took all the information contained in the LA RH SIP into account in making our determination to approve the State's SIP submittal.

Comment: The State unreasonably and unlawfully failed to consider the cost-effectiveness of controls in violation of the BART Guidelines. The State stated it selected low-sulfur coal over a scrubber even though additional visibility benefits may be achievable with the use of FGD because the lower sulfur coal option results in visibility benefits at a lower annual cost. The State's BART analysis violates the BART Guidelines by focusing the cost analysis solely on annual costs and by failing to consider cost-effectiveness at all. EPA's proposed approval fails to mention the applicable portions of EPA's own BART Guidelines and to discuss how the State's analysis is inconsistent with the Guidelines. In keeping with the statute, the regulations indicate that it is the total generating capacity of the plant—not any particular unit—that determines whether the BART Guidelines are mandatory.

Nelson began operation in 1960.88 Nelson Units 1 and 2 each have a nameplate capacity of approximately 114 MW, Unit 3 is 163 MW, Unit 4 is 592 MW, and Unit 6 is 615 MW. Although Units 1 and 2 have been spun off into a separate permit, the current Title V permit provides that the “facility capacity” is 1,204 MW.89 Given that Nelson's total capacity exceeds 750 MW, BART for Nelson must be determined in accordance with the BART Guidelines.90

The BART Guidelines recommend the use of cost-effectiveness “to assess the potential for achieving an objective in the most economical way.” The BART Guidelines specifically caution states not to consider annual costs without also considering cost-effectiveness. The SO2 BART determination violates the requirements in the BART Guidelines to consider cost-effectiveness of controls. Given that Nelson Unit 6 is located at a plant with a total generating capacity greater than 750 MW, the State is required to determine BART pursuant to the BART Guidelines—which the State failed to do, by failing to consider the cost-effectiveness of controls. The State should have followed the BART Guidelines and considered the cost-effectiveness of controls, which weigh in favor of selecting a scrubber as BART.

It is both irrational and contrary to the purpose of the haze provisions for the State to reject a very cost-effective control, a scrubber, on the ground that the annual cost is higher than the least-effective control, low-sulfur coal. If a state were permitted to reject more effective controls solely on the basis that annual costs are higher, then more effective controls would rarely, if ever, be required. If the State's rationale were approved by EPA, it would be difficult, if not impossible, to require the very pollution controls necessary to achieve the statutory mandate to eliminate haze pollution. The State's rationale must be rejected because it is incompatible with achieving the goal of the Clean Air Act to ultimately eliminate all human-caused haze pollution.

Response: We agree with the comment that the total capacity of the Nelson facility exceeds 750 MW and that the State was therefore required to determine BART pursuant to the BART Guidelines for this source. However, we disagree that LDEQ failed to consider cost-effectiveness. LDEQ included estimates of annual costs, cost-effectiveness, and incremental costs for the control options for Nelson Unit 6 in Appendices D and F of its SIP revision. LDEQ considered all information in the record, including all cost information provided by the EPA and Entergy. LDEQ weighed the five factors and concluded that “the use of lower sulfur coal presents the appropriate SO2 control based on consideration of economics, energy impacts, non-air quality environmental impacts, and impacts to visibility.” EPA has reviewed all the information in the SIP submittal and finds that the state's determination is approvable.

Comment: EPA's proposed approval of Entergy's 2012-2016 emissions baseline for the purposes of evaluating costs is arbitrary and contrary to law. As an initial matter, the cost analyses for other Louisiana BART sources, including Little Gypsy Unit 2, the Waterford units, and the Ninemile units, relied on a 2000-2004 emission baseline for the purposes of determining the cost effectiveness of controls. Neither Entergy nor EPA provide any reasoned explanation for treating Nelson differently. Instead, Entergy relied on an unenforceable, more recent operational profile in its BART analysis. Indeed, Entergy's BART analysis (and its conclusion that no additional controls are cost-effective) is based on baseline emissions from 2012-2014, during which Nelson 6 happened to be operating far less frequently than in earlier years.91 This is important because using a 2000-2004 baseline, a scrubber is even more cost-effective. The commenter estimates that a dry scrubber would cost $1,712 to $1,750 per ton and a wet scrubber would cost $1,728 to $1,748 using a 2000-2004 baseline. EPA's proposed approval of Entergy's emission baseline skews the cost analysis.

EPA has repeatedly concluded that states should determine BART using emissions data from 2000-2004. If projected operations will differ from past practice, and the state's BART determination is based on that emission baseline, the state “must make these parameters or assumptions into enforceable limitations” in the SIP itself. See 40 CFR part 51, App'x. Y § (IV)(D)(4)(d) LDEQ's proposed SIP contains no such enforceable limitation requiring Entergy to comply with 2012-2014 emissions, and is therefore unapprovable.

Response: We disagree with the comment regarding the use of baseline emissions in estimating annual costs and cost-effectiveness. Annual emissions used in evaluating cost effectiveness of controls are based on annual emissions representative of future anticipated annual emissions.92 The BART guidelines state that in the absence of enforceable limitations, baseline emissions should be based upon continuation of past practice.93 In many cases, in order to represent future anticipated annual emissions from the source EPA has used actual annual emissions from the most recent five-year period as being consistent with past practice for the purposes of the cost evaluation. EPA typically uses the most recent five years of annual emissions, eliminating the maximum and minimum annual emissions when evaluating cost impacts. For Nelson Unit 6, the cost analysis 94 developed by EPA and included in the October 2017 SIP submittal in appendix F, utilized a baseline based on average emissions from 2011 through 2015, excluding the maximum and minimum values. This analysis was later updated to using 2012-2016, excluding the maximum and minimum values. As stated in the Nelson Technical Assistance Document (Nelson TAD),95 EPA concluded that using the average annual emissions over the most recent five years, excluding the maximum and minimum years, was a reasonable compromise between simply selecting the maximum value from 2011-2015, or using the average of the values from 2011-2015. We discuss our review of the Entergy cost analysis for Nelson Unit 6 elsewhere in the response to comment section. The commenter is incorrect concerning the baseline used for cost analysis for Little Gypsy Unit 2, the Waterford units, and the Ninemile units. For the Waterford units, we utilized 2015 fuel oil prices and determined cost-effectiveness based on costs and tons reduced per 1,000 barrels of fuel burned. We also identified the highest annual emissions during the 2011-2015 period as part of our review of the BART determination for this source. For Little Gypsy and Ninemile, consideration of cost-effectiveness of controls was not necessary as the sources adopted the most stringent control level available. In addition, we note there are additional differences besides the choice of baseline emissions that we disagree with that resulted in lower estimated costs by the commenter than those estimated by EPA.96 We discuss the inputs we selected in our cost evaluation in the Nelson TSD.

Comment: The SIP is not approvable because it unlawfully fails to require at least presumptive BART for SO2 emissions as required by the BART Guidelines. For SO2, presumptive BART is an emission limit of 0.15 lb/MMBtu. 40 CFR part 51, App. Y § (IV)(E)(4) (“You must require 750 MW power plants to meet specific control levels for SO2 of either 95 percent control or 0.15 lbs/MMBtu, for each EGU greater than 200 MW that is currently uncontrolled unless you determine that an alternative control level is justified based on a careful consideration of the statutory factors.”). The State's BART determination for SO2 is an emission limit of 0.6 lb/MMBtu, which achieves nowhere near a 95% reduction in SO2 emissions and is four times higher than the presumptive BART rate of 0.15 lb/MMBtu. The State's failure to require at least the minimum emissions reductions mandated by the BART Guidelines violates the Clean Air Act requirement that BART be determined “pursuant to” the BART Guidelines for plants larger than 750 MW, 42 U.S.C. 7491(b)(2). EPA cannot approve a SIP which violates the Clean Air Act, and thus EPA must disapprove the SO2 BART determination Nelson Unit 6.

Response: We disagree with the comment that the State must require at least a level of control consistent with the presumptive limit for SO2 of either 95 percent control or 0.15 lbs/MMBtu. As identified by the commenter, the BART Guidelines state that the presumptive limit applies “unless you determine that an alternative control level is justified based on a careful consideration of the statutory factors.” LDEQ considered all information in the record, including all estimates of visibility benefits, annual costs, cost-effectiveness, and incremental cost provided by EPA and Entergy. The state weighed the factors and concluded that “the use of lower sulfur coal presents the appropriate SO2 control based on consideration of economics, energy impacts, non-air quality environmental impacts, and impacts to visibility.” EPA has reviewed all the information in the SIP submittal and finds that the state's determination meets the applicable requirements and therefore is approvable.

Comment: EPA's CALPUFF modeling shows that a scrubber would improve visibility by more than 1 deciview at Caney Creek, and slightly less than 1 deciview at Breton. Draft SIP, Appendix F at 41, Table 4-8. EPA's CAMx modeling indicated that a scrubber would improve visibility by 0.831 deciviews at Caney Creek and 0.663 deciviews at Upper Buffalo. 82 FR at 32299-300. These are significant amounts of visibility improvement, as indicated by the BART Guidelines instructions on determining which sources are subject to BART; the Guidelines state that a source which causes 1 deciview of impairment “causes” visibility impairment, and a source which leads to 0.5 deciviews of impairment “contributes” to impairment, 40 CFR part 51, App. Y § (III)(A)(1). This visibility improvement is well within the range of values for previous final BART determinations. In addition to being comparable to other BART determinations, the visibility improvement from a new scrubber is necessary as BART to move both affected Class I areas closer to natural visibility conditions.97

EPA's cost and visibility analyses only undermine the State's proposed BART determination, by demonstrating that the cost and visibility improvement from a scrubber are within the range of values which states and EPA routinely find to be reasonable, and on a case-specific basis, warranted as BART based on a five-factor analysis. EPA's own analysis concluded that the average cost-effectiveness is $2,706 per ton for SDA and $2,743 per ton for wet FGD. 82 FR at 32299. As the chart below indicates, these values are well within the range of average cost-effectiveness values for final BART determinations.98 EPA has not explained how it can approve the rejection of a scrubber when the cost-effectiveness and visibility improvement values are within the range that EPA has found reasonable in so many other haze rulemakings.

The commenter estimates the costs of a dry scrubber would cost $2,272 to $2,335 per ton and a wet scrubber would cost $2,328 to $2,361 per ton.99 And while the commenter states that it does not believe that incremental cost-effectiveness 100 should be a determining factor, it notes that EPA found that the incremental cost-effectiveness of a dry scrubber relative to DSI is $1,671. Both the average and incremental cost-effectiveness of a scrubber are well-within the range of cost-effectiveness values that states and EPA have found reasonable. See “Cost Effectiveness and Visibility in BART Determinations” spreadsheet (showing that many final BART determinations have an average cost-effectiveness exceeding $2,700 per ton of SO2 removed), Attached as Exhibit 5 (“Cost Effectiveness Spreadsheet”). Given the degree to which Nelson contributes to impairment at Class I areas, and the statutory mandate to restore natural conditions to these skies, the cost of a scrubber is justified as BART for this facility.

Response: The charts provided by the commenter give the ranges of cost-effectiveness and visibility benefits of controls identified by EPA and states in previous BART determinations for both NOX and SO2. However, these charts do not provide information on the visibility benefits, costs of controls, or incremental costs and benefits for technologies that were rejected in each of these determinations or in other situations where no additional controls were required to meet BART. Each BART determination is dependent on the specific situation and requires consideration of a number of factors including, the characteristics of the fuel burned at the source, the existing controls, the control efficiency of available control technologies, the remaining useful life, the costs and incremental costs of controls and the anticipated visibility benefit of each potential control. The Regional Haze Rule and BART Guidelines do not require the state to select as BART a more effective technology merely because it has visibility benefits or cost-effectiveness that fall within the range of previous cases, nor do they prohibit the state from choosing as BART a less effective technology measure that falls outside the range of previous cases. The state must consider all 5 statutory factors.

The Clean Air Act gave EPA the power to identify pollutants and set air quality standards. Congress gave states “the primary responsibility for implementing those standards.” Luminant Generation Co. v. EPA, 675 F.3d 917, 921 (5th Cir. 2012). (internal quotation marks omitted); see 42 U.S.C. 7407(a) (“Each State shall have the primary responsibility for assuring air quality within [its] entire geographic area.”); id. sec. 7401(a)(3) (“[A]ir pollution prevention . . . is the primary responsibility of States and local governments.”) The states have “wide discretion” in formulating SIPs. Union Elec. Co. v. EPA, 427 U.S. 246, 250 (1976). The Clean Air Act provides that EPA “shall approve” a SIP “if it meets the applicable requirements of this chapter.” 42 U.S.C. 7410(k)(3). EPA's regulations under the CAA “do not require uniformity between . . . actions in all circumstances and instead `allow for some variation' in actions taken in different regions.” 81 FR at 326 (quoting Amendments to Regional Consistency Requirements, 80 FR 50250, at 50258 (Aug. 19, 2015)). Some variation is to be expected because SIP actions are highly fact-dependent. Though we identified errors in Entergy's cost and visibility analyses, EPA conducted its own cost and visibility analyses in accordance with the applicable regulations and guidelines. EPA's cost and visibility analyses are part of the SIP submission (Appendix F) and were included in the information considered by the State in making their BART determination. LDEQ considered all information in the record, including all estimates of visibility benefits, annual costs, cost-effectiveness, and incremental cost provided by EPA and Entergy. The state weighed the factors considering all available information included in the SIP, and concluded that “the use of lower sulfur coal presents the appropriate SO2 control based on consideration of economics, energy impacts, non-air quality environmental impacts, and impacts to visibility.” EPA has reviewed all the information in the SIP submittal and finds that the state's determination is approvable.

Comment: EPA arbitrarily ignores the impact that errors in the cost and modeling analyses relied on by the State had on the State's BART determination. The State rejected a scrubber in favor of low-sulfur cost based on comparing the relative costs and visibility benefits of the two controls. Yet EPA found that the factors on which the State based its decision, cost and visibility benefits, are thoroughly inaccurate. EPA failed to explain how the Entergy analyses the State relied on can be incorrect, but the State's ultimate BART determination can be approvable.

Response: As explained in previous responses, EPA reviewed the State's entire submission, including any attached appendices and supporting documentation in determining whether the State's submission is approvable. EPA conducted its own cost and visibility analyses and submitted these analyses to the State for review in its determination. LDEQ reviewed this information as is evidenced by its SIP submission. LDEQ states, “LDEQ has weighed the five factors and after a review of both Entergy's and EPA's information . . .” This indicates that the State reviewed the information it received from both Entergy and the EPA in making its determination. After reviewing the relevant information contained in the State's SIP, we determined that the State's SIP is approvable.

Comment: The record indicates that EPA Region 6 has, on multiple occasions, expressed concerns with Entergy's modeling and cost analyses, as well as the Company's proposed baseline emission rates.101 Those documents—including Entergy's October 14, 2016 analysis, EPA's underlying March 16, 2016 Preliminary Review Response letter explaining its concerns with Entergy's modeling methodology, and any EPA response to Entergy's letter—do not appear to be included in the administrative record. Moreover, Louisiana's final BART analysis for Nelson does not address, let alone correct, many of the flaws EPA identified. As a result, the public has been deprived of information relevant to the legal and factual basis for Entergy's BART analysis, and is therefore unable to comment meaningfully on EPA's proposed approval of the BART analysis.

Response: The letters referenced by the commenter were made available by LDEQ on its website during its comment period. The final February 2017 SIP EPA received from LDEQ did not contain these letters as attachments, so they were inadvertently left out of the EPA docket, but they have since been placed in the docket. We note that the commenter cited to these letters in its comment, indicating that the commenter had the opportunity to review them. We also note that Entergy's response letter was included in the docket. This response letter included the questions raised by EPA in its initial letter verbatim.102 EPA did not rely on the Entergy's CAMx analysis in the October 2017 LA RH SIP, Appendix D, which is referred to by the commenter for our proposed approval of the State's SIP. While we found Entergy's modeling and methodology to be flawed, we also conducted our own CAMx modeling which LDEQ included in its SIP submission as an appendix.103

Comment: LDEQ stated it disagreed with EPA's use of the phrase “adopted and incorporated” when referring to the analysis provided to LDEQ by EPA. It stated that it places all documents and information submitted to it in connection with the development of the SIP in an administrative record. Such placement in the record does not indicate that LDEQ agrees with or has adopted positions, conclusions, or decisions, nor has incorporated them into the SIP revisions submitted to EPA. The final SIP document and any enforceable conditions included therein encompass the final decision by LDEQ.

Response: EPA recognizes that LDEQ independently reached the final determination presented in its Nelson RH SIP. We did not intend to imply that we substituted our own judgment for LDEQ's. When reviewing a SIP to determine whether it meets the applicable statutory and regulatory requirements, EPA considers the final SIP document as well as any accompanying supporting documents or appendices that have been submitted by the State. Reviewing the supporting documents and appendices assists EPA in determining how the State reached its final conclusion, and thus, helps determine whether the final conclusion meets the applicable statutory and regulatory requirements. We also note that in the SIP revision submitted to EPA in October 2017, LDEQ stated that the “. . . SIP is being revised to include the EPA information.” 104 This indicates that LDEQ considered the information provided by EPA when making its determination. It is thus appropriate for EPA to similarly rely on this information in our final rule.

Comment: LDEQ disagreed with the solicitation of comments on Entergy's cost per ton figure by EPA. LDEQ stated that it conducted its own public comment period and any comments submitted on this point are procedurally improper.

Response: While it is correct that LDEQ conducted its own public comment period, this does not relieve EPA of its duty under the Administrative Procedure Act to provide the public with notice of its proposed rulemaking and an opportunity to comment.

Comment: After finding that the Entergy analysis on which the State relies is unverifiable and unsupported by the facts before the agency—which demonstrate that a new scrubber would be both cost effective and significantly improve visibility—EPA inexplicably proposed to approve the State's BART determination. EPA's proposal is the quintessential example of an agency decision that is inconsistent with the evidence before the agency, and it would be arbitrary and capricious for EPA to finalize its proposal. See North Dakota v. EPA, 730 F.3d 750, 761 (8th Cir. 2013) (citing Ala. Dep't of Envtl. Conservation v EPA, 540 U.S. 461, 485, 490 (2004)) (EPA must ensure that the state's regional haze plan is “reasonably moored to the Act's provisions” and based on “reasoned analysis” of the facts).

Response: In our proposal we noted that we were unable to verify the cost analysis submitted by Entergy because it was based on a propriety database.105 However, as stated in our proposed rule, we developed our own BART analysis, including a control cost analysis, which was reviewed by LDEQ and submitted as an appendix to LDEQ's SIP submission 106 and considered in LDEQ's weighing of the five factors in reaching its determination regarding controls at Nelson. Thus, LDEQ included in its SIP and considered information adequate to provide a basis for its decision. As stated in a previous response, EPA reviews all information submitted by the State along with any other relevant publicly available information in determining whether its SIP submission is approvable, including any appendices or other supporting documentation.

Comment: The State also failed to consult with the Federal Land Managers regarding the proposed BART determination for Nelson Unit 6. This violates the statutory and regulatory requirements that each state consult with the Federal Land Managers prior to holding a public hearing on the SIP and that the State include in the public notice a summary of the Federal Land Managers' recommendations. EPA must disapprove the SIP submission based on the State's violation of the BART Guidelines and the consultation requirements. “Before holding the public hearing on the proposed revision of an applicable implementation plan to meet the requirements of this section, the State . . . shall consult in person with the appropriate Federal land manager or managers and shall include a summary of the conclusions and recommendations of the Federal land managers in the notice to the public.” 42 U.S.C. 7491(d). EPA may not approve a plan which violates applicable Clean Air Act requirements, and therefore EPA must disapprove the plan based solely on the State's violation of the consultation requirements.

Response: As evidenced by the letter sent to LDEQ by the Fish and Wildlife Service,107 LDEQ consulted with the appropriate Federal Land Mangers regarding its RH SIP submission. In its general comments, the Fish and Wildlife Service stated that more information was needed to determine the validity of LDEQ's conclusions and recommended that LDEQ include the information it relied upon in reaching its decision. In reference to Nelson, the Fish and Wildlife Service stated that it was aware that more information was available and that it would be interested in reviewing this information. Subsequently, LDEQ submitted an addendum to its SIP to include the analyses conducted by EPA. LDEQ provided the updated information, as requested, to the Fish and Wildlife Service via email on July 12, 2017.108

Comment: The only outcome consistent with EPA's findings in the record is for EPA to disapprove the State's analysis and issue a federal implementation plan for SO2 BART setting emission limits consistent with the operation of a new scrubber.

Response: As explained in previous responses, EPA reviewed the State's entire submission, including any attached appendices and supporting documentation, as a whole in determining whether the State's submission is approvable. After reviewing the relevant information, we determined that the State's SIP is approvable.109

Comment: The State expressly notes that in reaching its decision, it relied on Entergy's analysis.110 EPA has an independent obligation to ensure that the State's analysis complies with the Clean Air Act. See Ala. Dep't of Envtl. Conservation v. EPA, 540 U.S. at 485 (upholding EPA's interpretation of the Clean Air Act as authorizing EPA to “review permits to ensure that a State's BACT determination is reasonably moored to the Act's provisions”); North Dakota v. EPA, 730 F.3d at 761 (extending the holding of Alaska Dep't of Envtl. Conservation to EPA's role under the haze provisions of the Clean Air Act); Oklahoma v. EPA, 723 F.3d 1201, 1208 (10th Cir. 2013) (“Given that the statute mandates that the EPA must ensure SIPs comply with the statute, we fail to see how the EPA would be without the authority to review BART determinations for compliance with the guidelines.”)

Response: In its SIP, LDEQ states, “LDEQ has weighed the five factors and after a review of both Entergy's and EPA's information. . .” 111 This indicates that the State reviewed all the information it received from both Entergy and the EPA. As stated in a previous response, LDEQ indicated in its SIP that it was revising its previous submission to include the additional information provided by EPA. This further indicates that the State considered this information in its determination. While we did note the errors that were present in Entergy's analysis, we also stated that we conducted our own analysis in accordance with the applicable regulations and provisions of the Act, and provided this information to LDEQ.112 With the inclusion of the information from EPA, LDEQ had adequate information to make its decision.

Comment: EPA's proposal violates the procedural requirement of the Clean Air Act that EPA place in the public rulemaking docket the data on which the proposed rule relies. The Act requires that a proposed rule include a summary of the “factual data on which the proposed rule is based,” 42 U.S.C. 7607(d)(3)(A), and such “data . . . on which the proposed rule relies shall be included in the docket on the date of publication of the proposed rule.” Id. sec. 7607(d)(3). EPA proposed to approve the State's BART determination, which relies on Entergy's BART analyses. Therefore, EPA's proposed rule also relies on Entergy's BART analyses, yet factual data from Entergy's BART analyses are not included in the docket, namely, the proprietary database for calculating scrubber costs, 82 FR at 32298, and “model inputs, such as emissions or stack parameters” and “worksheets utilized for post-processing, or any of the actual CAMx modeling files.” Appendix F, CAMx Modeling TSD at 30. By failing to include this data in the rulemaking docket, EPA has violated 42 U.S.C. 7607(d)(3). See Kennecott Corp. v. EPA, 684 F.2d 1007, 1018 (D.C. Cir. 1982) (“If that argument be factually based, the financial analyses clearly form a basis for the regulations and should properly have been included in the docket. In all events, absence of those documents, or of comparable materials showing the nature and scope of its prior practice, makes impossible any meaningful comment on the merits of EPA's assertions.”). Entergy's consultant, Trinity, failed to provide fundamental information concerning its visibility modeling. “Trinity did not provide model inputs, such as emissions or stack parameters, or provide worksheets utilized for post-processing, or any of the actual CAMx modeling files so our review is limited only to general description [sic] of the modeling protocol provided in the various CAMx modeling reports provided by Entergy.” Draft SIP, Appendix F, CAMx Modeling TSD at 30.

Response: As stated in previous responses, EPA conducted its own cost and modeling analyses and submitted them to LDEQ for its consideration. LDEQ considered the information provided by EPA113 as well as that provided by Entergy 114 in making its final BART determination based upon weight of evidence. LDEQ stated in its February 2017 SIP submission that it did not have the expertise with which to review the summary of the CAMx modeling analysis provided by Entergy.115 LDEQ further stated in its June 2017 parallel processing proposed submission that it did not use the results of the CAMx modeling provided by Entergy to determine whether the units in question have satisfied the BART requirements.116 EPA reviewed the modeling inputs, approach and the model results that were available in Entergy's submitted analysis that were part of the LDEQ's June 2017 proposal. With this information, EPA was able to determine that the modeling was not consistent with the BART guidelines and should not be relied upon.117 Thus, the underlying information used to generate the CAMx modeling summary in Entergy's analysis is not required to be placed in the docket.118 After reviewing the relevant information, we determined that the State's SIP is approvable. All of the information EPA relied on its determination was made available in the docket during the comment period.

Comment: Louisiana's proposal unlawfully exempts sources from installing BART controls without going through the exemption process Congress prescribed. The visibility protection provisions of the Clean Air Act include a “requirement” that certain sources “install, and operate” BART controls. 42 U.S.C. 7491(b)(2)(A). Congress specified the standard by which sources could be exempted from the BART requirements, which is that the source is not “reasonably anticipated to cause or contribute to a significant impairment of visibility” in any Class I area. Id. sec. 7491(c)(1). Appropriate federal land managers must concur with any proposed exemption. Id. sec. 7491(c)(3). Neither EPA nor Louisiana has demonstrated that the Louisiana EGUs subject to BART meet the standards for an exemption. Nor has EPA or the state obtained the concurrence of federal land managers. Therefore, Louisiana must require source-specific BART for each power plant subject to BART.

Response: To the extent the comment is directed to the prior rules that determined and re-determined that CSAPR is better than BART and may be relied upon as an alternative to BART, we disagree that relying on CSAPR is in conflict with the CAA provision regarding exemptions from BART. In addition, the commenter's objection does not properly pertain to this action, but instead to our past action that established 40 CFR 51.308(e)(4). We believe this comment to fall outside of the scope of our action here. To the extent the comment objects to BART alternatives generally, we also disagree. In addition, that objection does not properly pertain to this action, but instead to our past regulatory action that provided for BART alternatives.

Comment: Even if Louisiana could meet a BART statutory exemption test, the state cannot rely on CSAPR because of flaws in the rule that purport to show that CSAPR makes more reasonable progress than BART (the “Better than BART” rule). EPA's regulations purport to allow the use of an alternative program in lieu of source-specific BART only if the alternative makes “greater reasonable progress” than would BART. 40 CFR 51.308(e)(2). To demonstrate greater reasonable progress, a state or EPA must show that the alternative program does not cause visibility to decline in any Class I area and results in an overall improvement in visibility relative to BART at all affected Class I areas. Id. § 51.308(e)(3)(i)-(ii). Here, EPA claims that its 2012 “Better than BART” rule demonstrated that CSAPR achieves greater reasonable progress than BART. See 77 FR 33642.

EPA compared CSAPR to BART in the Better than BART rule by using CSAPR allocations that are more stringent than now required as well as by using presumptive BART limits that are less stringent than required under the statute.119 These assumptions tilted the scales in favor of CSAPR. It would be arbitrary and capricious for EPA to rely on such an inaccurate, faulty comparison to conclude that CSAPR will achieve greater reasonable progress than will BART. Even under EPA's skewed comparison, CSAPR achieves barely more visibility improvement than BART at the Breton and Caney Creek National Wilderness Areas. If EPA had modeled accurate BART limits and up-to-date CSAPR allocations, then EPA would likely find that CSAPR would lead to less visibility improvement than BART.

As explained in detail in the attached briefing regarding the still-pending litigation challenging EPA's Better than BART rule, the Better than BART rule not only fails to meet the Clean Air Act's statutory requirements for a BART exemption but also fails to account for the geographic and temporal uncertainties in emissions reductions under CSAPR.120 We also submit and incorporate our February 28, 2011 comments and our supplemental March 27, 2012 comments on the Better than BART Rule, which are relevant to EPA's proposal to rely on CSAPR as a BART alternative.

Moreover, EPA's Better than BART determination fails to account for the inherent uncertainties in emissions reductions under CSAPR. BART is a technology that must be installed and operated year-round, and a corresponding emission limit that must also be met year-round. BART emissions limits must be met on a “continuous basis. ” See 42 U.S.C. 7602(k) (emphasis added). By contrast, CSAPR allows trading of emissions allowances between sources, including between sources in different states, rather than imposing a fixed emission limit for each source. EPA's assessment of CSAPR Better than BART does not and cannot assess the unknown impact of complex trading under CSAPR on the Class I areas affected by Louisiana sources.

EPA cannot lawfully rely on the Better than BART rule because the rule is based on a version of CSAPR that no longer exists. Accordingly, any conclusion that EPA made in the 2012 Better than BART rule regarding whether CSAPR achieves greater reasonable progress than BART is no longer valid. Since 2012, EPA has significantly changed the allocations and the compliance deadlines for CSAPR. Of particular relevance here, after 2012, EPA increased the total ozone season CSAPR allocations for every covered EGU in Louisiana. 77 FR 34830, 34835 (June 12, 2012). EPA also extended the compliance deadlines by three years, such that the phase 1 emissions budgets take effect in 2015-2016 and the phase 2 emissions budgets take effect in 2017 and beyond. 79 FR 71663 (Dec. 3, 2014).

In addition to EPA's increased emissions budgets and extended compliance timeline, the D.C. Circuit's decision in EME Homer City Generation v. EPA, 795 F.3d 118, 130-32 (D.C. Cir. 2015), which invalidated the SO2 or NOX emission budgets for thirteen states, has fundamentally undermined the rationale underlying EPA's Better than BART rule. Specifically, the Court invalidated the 2014 SO2 emission budgets for Alabama, Georgia, South Carolina, and Texas, and the 2014 NOX emission budgets for Florida, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Texas, Virginia, and West Virginia. Id. at 124. Of particular relevance here, the D.C. Circuit invalidated the CSAPR budgets for Texas, Alabama, and Georgia, which most impact visibility at Louisiana's Class I area. As explained in our initial brief in the still-pending challenge to the CSAPR Better than BART rule, the effect of Homer City is to pull the rug out from under EPA's BART exemption rule. This remains true even though some states have, in the wake of Homer City, opted in to CSAPR in lieu of issuing source-specific BART determinations. Texas, the state with the most SO2 emissions, has not opted in to CSAPR after the Homer City court remanded the CSAPR SO2 budgets for Texas, and therefore the CSAPR Better than BART Rule rests on facts which no longer exist. These assumptions underpinned EPA's finding that CSAPR was Better than BART. It would be arbitrary and capricious for EPA to now rely on the same assumptions, a blatantly inaccurate, outdated, faulty comparison to conclude that CSAPR will achieve greater reasonable progress than will BART. Even under EPA's skewed comparison, CSAPR barely achieved more visibility improvement than BART at the Breton and Caney Creek National Wilderness Areas. If EPA had modeled accurate BART limits and the modified CSAPR allocations as per the D.C. Circuit decision, then EPA would likely find that CSAPR would lead to less visibility improvement than BART.

Response: As we had proposed, our finalized determination that CSAPR participation will resolve NOX BART requirements for Louisiana EGUs is based on a separately proposed and finalized action. This comment falls outside of the scope of our action here.

Comment: Louisiana's reliance on CSAPR Better than BART is unlawful because the emissions reductions achieved by CSAPR in Louisiana are limited to five months of the year—the ozone season. Given that any controls that might be installed to meet CSAPR are not required to be operated year-round, CSAPR does nothing to protect the affected Class I areas during the remaining seven months of each year. In fact, as noted in EPA's Technical Support Document and in the National Park Service's comments on EPA's proposed disapproval of Louisiana's 2008 SIP, the adverse impacts of Louisiana NOX emissions on visibility are highest in the winter months—i.e., outside of the ozone season. Letter from Susan Johnson, Department of the Interior to Guy Donaldson, EPA Docket ID No. EPA-R06-OAR-2008-0510-0017, at 2 (Mar. 28, 2012), attached as Exhibit 4. Thus, NOX emissions reductions that are effective only during the ozone season will not address the visibility impact due to wintertime ammonium nitrate at Breton Island or other Class I areas in neighboring states.

Even within the five-month ozone season, CSAPR allows for temporal variability such that a facility could emit at high levels within a shorter time period, creating higher than anticipated visibility impacts. Because of the high degree of variability and flexibility, power plants may exercise options that would lead to little or no emission reductions. For example, a facility in Louisiana might purchase emission credits from a source beyond the air shed of the Class I area the Louisiana source impairs. Because CSAPR requirements only pertain to the Louisiana source for a fraction of the year, that source may be even more incentivized to purchase emission credits from elsewhere than a source in a fully covered CSAPR state. Thus, without knowing which Louisiana EGUs will reduce pollutants by what amounts under CSAPR, or when they will do so, and because these emissions reductions are applicable for less than half the year, Louisiana simply cannot know the impact of CSAPR upon Breton and other affected Class I areas.

For these reasons, reliance on CSAPR to satisfy the NOX BART requirements is unlawful. EPA should disapprove Louisiana's reliance on CSAPR to satisfy the NOX requirements, and issue a FIP with source-specific BART determinations for NOX.

Response: We disagree with this comment, but also note that it should not be directed to this action but rather to the past rulemaking determination that provided BART coverage for pollutant trading under CSAPR as specified at 40 CFR 51.308(e)(4). In any event, the argument that BART must be based on “continuous” control does not transfer to the application and operation of a BART alternative. Sources that would operate under an annual trading program that provides tons per year allocations for a unit are not necessarily applying “continuous” controls either. In fact, they are also free to operate seasonally or with intermittent use of controls so long as they operate within the allocation or purchase allowances whenever emissions may exceed that allocation. We necessarily disagree that EPA regulations would bar seasonal emissions reductions to satisfy requirements for a BART alternative.

Comment: Louisiana purports to satisfy the regulatory requirements for a BART alternative by relying on ozone-season budgets for NOX that no longer exist. To rely on CSAPR as an alternative to BART, Louisiana must demonstrate that the version of CSAPR that is now in effect, and will be in effect at the time of the final rule, makes greater reasonable progress than BART. Having failed to make that demonstration, Louisiana has not met its burden to show that CSAPR will achieve greater reasonable progress than source-specific BART. See 40 CFR 51.308(e)(2), (3). More troubling, Louisiana's reliance on the CSAPR “Better than BART” rule fails to account for, or even mention, the possibility that CSAPR or the “Better than BART” rule will not exist in any form when the SIP is finalized.

Response: As we had proposed, our finalized determination that CSAPR participation will resolve NOX BART requirements for Louisiana EGUs is based on a separately proposed and finalized action. On September 29, 2017, we affirmed our proposed finding that the EPA's 2012 analytical demonstration remains valid and that participation in CSAPR, as it now exists, meets the Regional Haze Rule's criteria for an alternative to BART.121 This comment falls outside of the scope of our action here.

Comment: EPA need not wait to finalize this element of the Proposed Rule until the Agency finalizes its proposed finding that CSAPR continues to be better than BART despite the removal of Texas from the annual NOX and SO2 trading programs.122 EPA has performed technical analyses supporting its conclusion that the ozone season NOX trading program remains “better than” BART despite the removal of Texas from the annual programs, which supports a final action in this rulemaking.123 Further, this Proposed Rule provides sufficient public notice and opportunity to comment on whether CSAPR participation appropriately satisfies NOX BART requirements for Louisiana EGUs. In light of this, EPA should determine in this rulemaking that participation in CSAPR satisfies BART for NOX emissions from Louisiana's EGUs. At the very least, EPA should finalize its proposal that CSAPR remains better than BART 124 in an expeditious manner, so that it can finalize this portion of the Proposed Rule.

Response: We have finalized our proposed rule finding that CSAPR continues to be better than BART despite the removal of Texas from the annual NOX and SO2 trading programs,125 so this comment is no longer relevant.

Comment: The proposal unlawfully fails either to approve a corrected long-term strategy or to issue a federal implementation plan (“FIP”) containing a proper long-term strategy as required by the CAA and federal regulations. Regardless of whether the previous version of the Regional Haze Rule or the Revised Regional Haze Rule governs this rulemaking, the requirements are the same: EPA is obligated to consider the four statutory factors to determine whether controls are needed at non-BART sources in order to make reasonable progress regardless of whether such measures are needed to attain reasonable progress goals or the uniform rate of progress. See 82 FR 3078, 3080, 3090-91 (Jan. 10, 2017); 79 FR 74818, 74828-30 (Dec. 16, 2014). EPA's proposal does not contain a reasonable progress analysis which considers these four factors for non-BART sources, such as Dolet Hills. The Revised Regional Haze Rule (82 FR 3078) explicitly brings the long-term strategy regulations in line with the statutory command to contain measures as necessary to make reasonable progress. Under the new requirements, “[t]he long-term strategy must include the enforceable emissions limitations, compliance schedules, and other measures that are necessary to make reasonable progress, as determined pursuant to (f)(2)(i) through (iv).”

EPA's proposal provides no evidence that the State submitted a revised submittal which “evaluate[d] and determine[d] the emission reductions measure that are necessary to make reasonable progress” by evaluating the four statutory factors. Nor is there any evidence of criteria the State used to evaluate which sources should be evaluated in the reasonable progress analysis, and how the four factors were considered. In comments we submitted to the State, we noted that under any reasonable criteria for screening sources, Dolet Hills should be evaluated under the long-term strategy requirements. See Letter from Joshua Smith, Sierra Club to Vivian Aucoin, Louisiana Department of Environmental Quality at 7-11 (Dec. 14, 2016), attached as Exhibit 5. Cleco Power's lignite-fired Dolet Hills Power Station is one of the largest sources of visibility-impairing SO2 and NOX emissions in Louisiana. States and EPA routinely use a Q/D analysis as an initial screening method for determining which sources should be analyzed using the four factors. Using this approach, EPA, the states, and federal land managers generally conduct modeling for any source that has a Q divided by D threshold of 10 or more. Using Dolet Hills's average annual SO2 and NOX emissions from 2000-2016, Dolet Hills easily meets the Q/D threshold for additional modeling based on impacts to Breton National Wilderness Area and Caney Creek National Wilderness Area. For example, the Q/D for Dolet Hills based on annual SO2 emissions (17,907 tpy) and distance to Breton (500 km) would be 35.8.

Based on the Q/D analysis, EPA was required to issue a FIP applying the four factors to Dolet Hills to determine whether additional emissions reductions are necessary at Dolet Hills to make reasonable progress. EPA's failure to do so violates the statute and the implementing regulations. The Stamper Report also provides a rough estimate of what such a four-factor analysis would look like for Dolet Hills for SO2. First, there is ample support for requiring reasonable progress controls at Dolet Hills within a reasonable amount of time—no more than five years—just as EPA did for similar sources in the Texas reasonable progress FIP. Second, as EPA has recognized, the SO2 control technologies of wet and dry FGD systems are widely used at coal-fired power plants all over the United States, and any energy and non-air quality environmental impacts of these controls are vastly outweighed by the benefits of significant reductions of air pollutants. Third, the Dolet Hills Power Plant began operation in 1986, and Cleco Power has indicated that the expected lifetime of the unit is sixty years. In any event, because there is no enforceable requirement or deadline for retirement, EPA must assume that the remaining useful life of the plant is 30 years—i.e., the life of the SO2 pollution controls evaluated.

Finally, it is clear that a new wet FGD system at Dolet Hills would be cost effective. Assuming a 98% SO2 removal efficiency, or a 0. 04 lb/MMBtu SO2 emission rate, and applying EPA's standard cost assumptions (i.e., a 7% interest rate; 30-year life, etc.), the cost of a new wet FGD scrubber at Dolet Hills would be approximately $1,710/ton, which is well within EPA's range of reasonable BART costs. Moreover, emissions from the lignite-fired Dolet Hills power plant are currently responsible for significant visibility impairment at a number of Class I areas, including a more than 1.0 deciview (“dv”) baseline impact at Caney Creek. Gray Report at 6, Table 5. The modeling also demonstrates that installation of SO2 controls at Dolet Hills, such as a replacement wet FGD system, would dramatically improve the visibility at all modeled Class I areas. Indeed, the installation of a wet FGD scrubber at Dolet Hills would improve visibility at Caney Creek by 0.799 dv, relative to baseline 2000-2004 emissions. Moreover, a wet FGD system would result in almost a 0.5 dv improvement at Breton Island in Louisiana, and more than 0.5 dv improvement at Wichita Mountains and the Upper Buffalo. Overall cumulative delta dv impacts across six Class I areas would be reduced from 4.23 to 0.93—a cumulative improvement of 3.30 dv.

In sum, the installation of a new WFGD system at Dolet Hills would be well within the range of costs that EPA has deemed reasonable and cost effective. Moreover, the installation of a new wet FGD system a Dolet Hills would result in a significant and noticeable change in visibility on the peak impact days at several Class I areas. Consequently, EPA must evaluate whether additional emission reductions at Dolet Hills are necessary to ensure reasonable progress toward the national goal.

Response: In 2012, we proposed to find that Louisiana's Long Term Strategy (LTS) for the first planning period was deficient given our proposed finding that certain of Louisiana's BART determinations were not fully approvable. “In general, the State followed the requirements of 40 CFR 51.308(d)(1), but these goals do not reflect appropriate emissions reductions from BART.” 126 We finalized that action, which specifically disapproved the State's LTS, but only insofar as it relied on deficient BART determinations.127 With this final action, we are approving all of LDEQ's SIP submittals, including the ones submitted after the 2008 SIP submittal, which have cured the deficiencies in the 2008 SIP revision submittal as identified in our 2012 action that related to BART, thus correcting the deficiencies in the LTS portion of the SIP as well. We note that the Regional Haze Rule requires states to submit periodic comprehensive SIP revisions that will continue to assess measures needed to achieve reasonable progress; the next SIP revision is due in 2021. We also note that the Revised Regional Haze Rule referenced by the commenter makes changes to the requirements that states have to meet for the second and subsequent implementation periods, but the revised rule is not applicable to this SIP submittal.128

Comment: The three-year compliance date for Nelson Unit 6 does not meet the Clean Air Act requirement that BART controls be installed as expeditiously as practicable. There is no specific technical or economic evidence in the record to support a three-year compliance date. The record indicates that Entergy is likely meeting the 0.6 lbs/MMBtu limit now. On September 28, 2017, Entergy's counsel wrote to EPA that “You asked whether the Nelson plant currently is meeting an emission rate of 0.6 lbs/MMBtu. The answer is that Nelson 6 generally is emitting at levels below that level, with periodic exceptions when the sulfur content is higher.” 129 In addition, Entergy's reported monthly emissions data over the last several years clearly indicate that “Entergy has been able to consistently purchase coal with a sulfur content that would enable the Nelson Unit to comply with the 0.60 lbs./MMBtu level.” 130

Even if Nelson is not currently meeting the proposed SO2 limit, Entergy's counsel represented to EPA that Nelson could meet the 0.6 lbs/MMBtu limit in 2018 and 2019 if the limit was an annual average rather than a 30-day rolling average.131 In the same message, Entergy's counsel stated that Nelson could meet the 0.6 lbs/MMBtu limit, with a 30-day rolling average, “for 2020.” 132 EPA's stated rationale for the deadline extension—that Entergy needs three years to comply—is contradicted by Entergy's statement that it could meet a 30-day rolling average of 0.6 lbs/MMBtu beginning in 2020. Entergy represents that it would “be difficult for Nelson to assure compliance with an emission limit of 0.6 lbs/MMBtu before 2020.” 133 Entergy stated that it was unable to blend fuel, yet this is contradicted by the record. The Company has been “consistently” purchasing low-sulfur coal and “blending them in its feed stream for a number of years.” 134 Entergy did not explain what equipment it had on site, what equipment it believes would be necessary to blend coal, and how much the necessary equipment would cost.

Additionally, Entergy could accept penalties for cancelling portions of its 2018 and 2019 contracts. Entergy did not provide any information about the penalties of cancelling the contract. It would have been able to submit this information to EPA and claim it as confidential business information. Neither the State nor EPA considered any other alternatives to extending the compliance deadline by three years. There is no evidence in the record for this amendment that the State or EPA considered the costs for Entergy to purchase the low-sulfur coal and fuel blending equipment necessary to meet the compliance deadline before 2020. Nor is there any evidence that the State or EPA considered alternatives such as lengthening the averaging time for the 0.6 lbs/MMBtu limit for 2018 and 2019. Inexplicably, no consideration was given to the proposal that Entergy itself made: An annual limit for 2018 and 2019, followed by a 30-day rolling average for 2020.

Response: In a letter dated October 26, 2017 135 sent to LDEQ and EPA during the respective comment periods, Entergy stated that though it had recently been receiving lower sulfur coal, the sulfur content can vary greatly since its current contract limits the sulfur coal delivered to 1.2 lbs/MMBtu. Entergy further stated that it does not have the equipment necessary to blend fuel which limits its ability to manage variable fuel supplies. Thus, it would not be able to consistently meet the 0.6 lbs/MMBtu emission limit that has been determined to be BART prior to the expiration of its current contracts. BART is required to be installed and operational as expeditiously as practicable, but in no event later than five years after the approval of the SIP. The State took the circumstances at Entergy into account and determined that a compliance period of three years met this requirement. Under the company's current contract, the company could potentially receive coal that violates the limit. Therefore, it is reasonable for company to have time to enter into new contracts with new specifications. Further, the commenter raises the possibility of an annual limit that would be in place sooner. Annual limits, however, are generally not considered appropriate for BART which targets improvements on the days of maximum impact from the source. EPA has reviewed all the information in the SIP submittal and finds that the state has made a reasoned determination that meets the applicable requirements and therefore is approvable.

We are approving revisions to the Louisiana SIP submitted on June 13, 2008, August 11, 2016, February 10, 2017, and October 26, 2017, as supplemented October 9, 2017, as meeting the regional haze requirements for the first planning period. This action includes the finding that the submittals meet the applicable regional haze requirements as set forth in sections 169A and 169B of the CAA and 40 CFR 51.300-308. The EPA is approving the SIP submittals with the supplemental information as meeting the following: The core requirements for regional haze SIPs found in 40 CFR 51.308(d) such as the requirement to establish reasonable progress goals, the requirement to determine the baseline and natural visibility conditions, and the requirement to submit a long-term strategy; the BART requirements for regional haze visibility impairment with respect to emissions of visibility impairing pollutants from non-EGUs and EGUs in 40 CFR 51.308(e); and the requirement for coordination with state and Federal Land Managers in § 51.308(i). For the BART requirements, we are approving LDEQ's determination that the BART-eligible sources at the following facilities do not cause or contribute to visibility impairment and are not subject to BART: Terrebonne Parish Consolidated Government Houma Generating Station (Houma), Louisiana Energy and Power Authority Plaquemine Steam Plant (Plaquemine), Lafayette Utilities System Louis “Doc” Bonin Generating Station, Cleco Teche, Entergy Sterlington, NRG Big Cajun I, and NRG Big Cajun II. We are also approving LDEQ's reliance on CSAPR to meet the NOX BART requirement for EGUs. We are approving the following Agreed Orders on Consent that make the source-specific BART emission limits enforceable for the subject to BART units at the following facilities:

In this rule, the EPA is finalizing regulatory text that includes incorporation by reference. In accordance with the requirements of 1 CFR 51.5, the EPA is finalizing the incorporation by reference of the revisions to the Louisiana regulations as described in the Final Action section above. The EPA has made, and will continue to make, these materials generally available through www.regulations.gov and at the EPA Region 6 Office (please contact Ms. Jennifer Huser for more information). Therefore, these materials have been approved by EPA for inclusion in the SIP, have been incorporated by reference by EPA into that plan, are fully federally enforceable under sections 110 and 113 of the CAA as of the effective date of the final rulemaking of EPA's approval, and will be incorporated by reference by the Director of the Federal Register in the next update to the SIP compilation (62 FR 27968, May 22, 1997).

Under the Clean Air Act, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, the EPA's role is to approve state choices, provided that they meet the criteria of the Clean Air Act. Accordingly, this action merely approves state law as meeting Federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this action:

• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);

• Is not an Executive Order 13771 (82 FR 9339, February 2, 2017) regulatory action because SIP approvals are exempted under Executive Order 12866;

• Does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.);

• Is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.);

• Does not contain any unfunded mandate or significantly or uniquely affect small governments, described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);

• Does not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);

• Is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);

• Is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);

• Is not subject to requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the CAA; and

• Does not provide EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible methods, under Executive Order 12898 (59 FR 7629, February 16, 1994).

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. EPA will submit a report containing this action and other required information to the U. S. Senate, the U. S. House of Representatives, and the Comptroller General of the United States prior to publication of the rule in the Federal Register. A major rule cannot take effect until 60 days after it is published in the Federal Register. This action is not a “major rule” as defined by 5 U.S.C. 804(2).

Under section 307(b)(1) of the Clean Air Act, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by February 20, 2018. Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this action for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. This action may not be challenged later in proceedings to enforce its requirements. (See section 307(b)(2).)

40 CFR part 52 is amended as follows:

Throughout this document whenever “we,” “us,” or “our” is used, we mean EPA. This supplementary information section is arranged as follows:

States are required to submit a progress report in the form of a SIP revision every five years that evaluates progress towards the RPGs for each mandatory Class I Federal area within the state and in each mandatory Class I Federal area outside the state which may be affected by emissions from within the state. See 40 CFR 51.308(g). In addition, the provisions under 40 CFR 51.308(h) require states to submit, at the same time as the 40 CFR 51.308(g) progress report, a determination of the adequacy of the state's existing regional haze SIP. The first progress report SIP is due five years after submittal of the initial regional haze SIP.

On October 16, 2017 (82 FR 48030), EPA published a notice of proposed rulemaking (NPR) proposing approval of Ohio's March 11, 2016 Regional Haze Five-Year Progress Report SIP revision on the basis that it satisfies the requirements of 40 CFR 51.308(g) and (h).

The specific details of Ohio's March 11, 2016 SIP revision and the rationale for EPA's approval are discussed in the NPR and will not be restated here. EPA received one comment agreeing with EPA's assessment of Ohio's March 11, 2016 Regional Haze Five-Year Progress Report.

EPA is approving Ohio's March 11, 2016 Regional Haze Five-Year Progress Report SIP submittal as meeting the requirements of 40 CFR 51.308(g) and (h).

Under the Clean Air Act, the Administrator is required to approve a SIP submission that complies with the provisions of the Clean Air Act and applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the Clean Air Act. Accordingly, this action merely approves state law as meeting Federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this action:

• Is not a significant regulatory action subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);

• Is not an Executive Order 13771 (82 FR 9339, February 2, 2017) regulatory action because SIP approvals are exempted under Executive Order 12866;

• Does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.);

• Is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.);

• Does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);

• Does not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);

• Is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);

• Is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);

• Is not subject to requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the Clean Air Act; and

• Does not provide EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible methods, under Executive Order 12898 (59 FR 7629, February 16, 1994).

In addition, the SIP is not approved to apply on any Indian reservation land or in any other area where EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the rule does not have tribal implications and will not impose substantial direct costs on tribal governments or preempt tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. EPA will submit a report containing this action and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication of the rule in the Federal Register. A major rule cannot take effect until 60 days after it is published in the Federal Register. This action is not a “major rule” as defined by 5 U.S.C. 804(2).

Under section 307(b)(1) of the Clean Air Act, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by February 20, 2018. Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this action for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. This action may not be challenged later in proceedings to enforce its requirements. (See section 307(b)(2)).

40 CFR part 52 is amended as follows:

In the direct final rule, EPA stated that if adverse comments were submitted by December 4, 2017, the rule would be withdrawn and not take effect. EPA received an adverse comment prior to the close of the comment period and, therefore, is withdrawing the direct final rule. EPA will address the comment in a subsequent final action based upon the proposed action also published on November 2, 2017 (82 FR 50853). EPA will not institute a second comment period on this action.

In the direct final rule, EPA stated that if adverse comments were submitted by December 7, 2017, the rule would be withdrawn and not take effect. EPA received an adverse comment prior to the close of the comment period and, therefore, is withdrawing the direct final rule. EPA will address the comment in a subsequent final action based upon the proposed action also published on November 7, 2017 (82 FR 51594). EPA will not institute a second comment period on this action.

Throughout this document “we,” “us,” and “our” means the EPA.

On July 10, 2015 the Texas Commission on Environmental Quality (TCEQ) submitted rule revisions to their 30 TAC, Chapter 115 “Control of Air Pollution from Volatile Organic Compounds” and a demonstration that RACT requirements are met in the DFW NAA for inclusion into the Texas SIP. The background for this action is discussed in detail in our October 5, 2017 proposal, 82 FR 46450. In that document we proposed to approve the submitted TAC Chapter 115 SIP revisions into the SIP because these revisions will assist the DFW area reach attainment under the 2008 8-Hour O3 NAAQS by reducing VOC emissions for affected sources in the DFW area. We also proposed approval of all revisions for the amended, repealed, and new sections of Chapter 115 that were submitted for inclusion into the SIP. Additionally, the EPA proposed determining the TCEQ rules included in these revisions would meet the CAA § 182(b) RACT requirements for the 2008 O3 NAAQS in the DFW NAA. We also proposed approval of the RACT demonstration, including the negative declarations for certain RACT categories of emission sources provided by the TCEQ. We did not receive any comments regarding our proposal.

We are approving the revisions to 30 TAC Chapter 115 submitted to the EPA on July 10, 2015, for inclusion into the Texas SIP. We are also approving the DFW RACT demonstration submitted by the TCEQ. For complete details of the SIP revisions we are approving please see the proposal to this action and the accompanying Technical Support Document included in the public docket for this rule. This action is being taken under section 110 of the Act.

In this rule, the EPA is finalizing regulatory text that includes incorporation by reference. In accordance with requirements of 1 CFR 51.5, the EPA is finalizing the incorporation by reference of the revisions to the Texas regulations as described in the Final Action section above. The EPA has made, and will continue to make, these materials generally available through www.regulations.gov and/or at the EPA Region 6 Office (please contact Robert Todd for more information). Therefore, these materials have been approved by EPA for inclusion in the SIP, have been incorporated by reference by EPA into that plan, are fully federally enforceable under sections 110 and 113 of the CAA as of the effective date of the final rulemaking of EPA's approval, and will be incorporated by reference by the Director of the Federal Register in the next update to the SIP compilation (62 FR 27968, May 22, 1997).

Under the Clean Air Act, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, the EPA's role is to approve state choices, provided that they meet the criteria of the Clean Air Act. Accordingly, this action merely approves state law as meeting Federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this action:

• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);

• Is not an Executive Order 13771 (82 FR 9339, February 2, 2017) regulatory action because SIP approvals are exempted under Executive Order 12866;

• Does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.);

• Is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.);

• Does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);

• Does not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);

• Is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);

• Is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);

• Is not subject to requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the CAA; and

• Does not provide EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible methods, under Executive Order 12898 (59 FR 7629, February 16, 1994).

In addition, the SIP is not approved to apply on any Indian reservation land or in any other area where EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the rule does not have tribal implications and will not impose substantial direct costs on tribal governments or preempt tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. EPA will submit a report containing this action and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication of the rule in the Federal Register. A major rule cannot take effect until 60 days after it is published in the Federal Register. This action is not a “major rule” as defined by 5 U.S.C. 804(2).

Under section 307(b)(1) of the Clean Air Act, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by February 20, 2018. Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this action for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. This action may not be challenged later in proceedings to enforce its requirements. (See section 307(b)(2).)

40 CFR part 52 is amended as follows:

A. What decisions has EPA made in this rule?

On July 14, 2017, Arizona applied to EPA for final authorization of changes to the State hazardous waste program. EPA concludes that Arizona's application to revise its authorized program meets all statutory and regulatory requirements established by RCRA, as set forth in RCRA sec. 3006(b), 42 U.S.C. 6926(b), and 40 CFR part 271. Therefore, EPA grants Arizona final authorization to operate as part of its hazardous waste program the changes listed below in Section E of this document, as further described in the authorization application.

Arizona has responsibility for permitting treatment, storage, and disposal facilities within its borders (except in Indian country) and for carrying out the aspects of the RCRA program described in its revised program application, subject to the limitations of the Hazardous and Solid Waste Amendments of 1984 (HSWA).

The effect of this decision is that the changes described in Arizona's authorization application will become part of the authorized State hazardous waste program, and therefore will be federally enforceable. Arizona will continue to have primary enforcement authority and responsibility for its State hazardous waste program. EPA retains its authorities under RCRA secs. 3007, 3008, 3013, and 7003, including its authority to:

• Conduct inspections, and require monitoring, tests, analyses or reports;

• Enforce RCRA requirements, including authorized state program requirements, and suspend or revoke permits; and

• Take enforcement actions regardless of whether the state has taken its own actions.

This action does not impose additional requirements on the regulated community because the regulations for which Arizona is being authorized by today's action are already effective, and are not changed by today's action.

A single comment in support of the action and no adverse comments were received during the public comment period.

Arizona initially received final authorization on November 20, 1985, to implement its base hazardous waste management program. Arizona received authorization for revisions to its program on August 6, 1991 (56 FR 37290 effective October 7, 1991), July 13, 1992 (57 FR 30905 effective September 11, 1992), November 23, 1992 (57 FR 54932 effective January 22, 1993), October 27, 1993 (58 FR 57745 effective December 27, 1993), July 18, 1995 (60 FR 36731 effective June 12, 1995), March 7, 1997 (62 FR 10464 effective May 6, 1997), October 28, 1998 (63 FR 57605-57608 effective December 28, 1998), and March 17, 2004 (69 FR 12544 effective March 17, 2004), originally published on October 27, 2000 (65 FR 64369).

Arizona submitted a final complete program revision application to EPA dated July 14, 2017, seeking authorization of changes to its hazardous waste program that correspond to certain federal rules promulgated between May 26, 1998, and July 28, 2006 (also known as RCRA Cluster VIII (Checklist 167D only), Cluster IX (Checklists 169 and 173-180) and Clusters X through XVII). EPA has determined that Arizona's hazardous waste program revisions are equivalent to, consistent with, and no less stringent than the federal program, and therefore satisfy all the requirements necessary to qualify for final authorization. Accordingly, EPA grants Arizona final authorization for the following program changes:

Arizona adopts by reference the federal RCRA regulations in effect January 29, 2007, at Arizona Administrative Code (AAC) Title 18, Chapter 8, Article 2 (AAC R18-8-260 through 280 effective September 30, 2016). The federal requirements for which the State is being authorized are listed in the table below, noting the Arizona Administrative Register (AAR) volume and page and the AAC implementing rule sections. EPA is excluding Checklist 204 Performance Track from authorization because the program has been discontinued. An asterisk (*) after a checklist number indicates a rule that is optional for state adoption.

The BLM published the Resource Management Planning Rule (Planning 2.0 Rule) on December 12, 2016 (81 FR 89580). The rule became effective on January 11, 2017. On February 7, 2017, the United States House of Representatives passed a resolution of disapproval (H.J. Res. 44) of the Planning 2.0 Rule under the CRA, 5 U.S.C. 801 et seq. The Senate then passed a resolution of disapproval (S.J. Res. 15) on March 7, 2017 (Cong. Rec. p. S1686-S1687). President Trump then signed the resolution into law as Public Law Number 115-12 on March 27, 2017. Therefore, under the terms of the CRA, the BLM Planning 2.0 Rule shall be “treated as though such rule had never taken effect.” 5 U.S.C. 801(f).

However, because the CRA does not include direction regarding the removal, by the Office of the Federal Register or otherwise, of the voided language from the Code of Federal Regulations (CFR) the BLM must publish this document to effect the removal of the voided text. This document will enable the Office of the Federal Register to effectuate congressional intent to remove the voided text of the Planning 2.0 Rule as if it had never taken effect, and restore the previous language and prior state of the CFR.

This action is not an exercise of the Department's rulemaking authority under the Administrative Procedure Act, because the Department is not “formulating, amending, or repealing a rule” under 5 U.S.C. 551(5). Rather, the Department is effectuating changes to the CFR to reflect what congressional action has already accomplished—namely, the nullification of any changes purported to have been made to the CFR by the Planning 2.0 Rule and the reversion to the regulatory text in effect immediately prior to January 11, 2017, the effective date of the Planning 2.0 Rule. Accordingly, the Department is not soliciting comments on this action. Moreover, this action is not a final agency action subject to judicial review.

This document announces that, on December 4, 2017, OMB approved, for a period of three years, the information collection requirements contained in the Commission's Report and Order, FCC 16-169, published at 82 FR 7699, January 23, 2017. The OMB Control Number is 3060-1248. The Commission publishes this notification as an announcement of the approval date of those requirements. If you have any comments on the burden estimates listed below, or how the Commission can improve the collections and reduce any burdens caused thereby, please contact Cathy Williams, Federal Communications Commission, Room 1-C823, 445 12th Street SW, Washington, DC 20554. Please include the OMB Control Number, 3060-1248, in your correspondence. The Commission will also accept your comments via the internet if you send them to [email protected].

To request materials in accessible formats for people with disabilities (Braille, large print, electronic files, audio format), send an email to [email protected] or call the Consumer and Governmental Affairs Bureau at (202) 418-0530 (voice), (844) 432-2275 (videophone), or (202) 418-0432 (TTY).

As required by the Paperwork Reduction Act of 1995 (44 U.S.C. 3507), the FCC is notifying the public that it received OMB approval on December 4, 2017, for the information collection requirements concerning real-time text (RTT) outreach guidelines, TTY waiver notice conditions, and a requirement for waiver recipients to file reports every six months that are contained in the Commission's Report and Order, FCC 16-169, published at 82 FR 7699, January 23, 2017.

Under 5 CFR part 1320, an agency may not conduct or sponsor a collection of information unless it displays a current, valid OMB Control Number.

No person shall be subject to any penalty for failing to comply with a collection of information subject to the Paperwork Reduction Act that does not display a current, valid OMB Control Number. The OMB Control Number is 3060-1248.

The foregoing notice is required by the Paperwork Reduction Act of 1995, Public Law 104-13, October 1, 1995, and 44 U.S.C. 3507.

The total annual reporting burdens and costs for the respondents are as follows:

OMB Control Number: 3060-1248.

OMB Approval Date: December 4, 2017.

OMB Expiration Date: December 31, 2020.

Title: Transition from TTY to Real-Time Text Technology, CG Docket No. 16-145 and GN Docket No. 15-178.

Form Number: N/A.

Type of Review: New collection.

Respondents: Business or other for-profit.

Number of Respondents and Responses: 967 respondents; 5,557 responses.

Estimated Time per Response: 0.2 hours (12 minutes) to 60 hours.

Frequency of Response: Annual, ongoing, one-time, and semiannual reporting requirements; Recordkeeping requirement.

Obligation to Respond: Required to obtain or retain benefit. The statutory authority can be found at sections 4(i), 225, 255, 301, 303(r), 316, 403, 715, and 716 of the Communications Act of 1934, as amended, and section 106 of the Twenty-First Century Communications and Video Accessibility Act of 2010, 47 U.S.C. 154(i), 225, 255, 301, 303(r), 316, 403, 615c, 616, 617; Public Law 111-260, § 106, 124 Stat. 2751, 2763 (2010).

Total Annual Burden: 127,360 hours.

Total Annual Cost: No cost.

Nature and Extent of Confidentiality: There is no need for confidentiality with this collection of information.

Privacy Impact Assessment: This information collection does not affect individuals or households; therefore, the Privacy Act is not impacted.

Needs and Uses: TTY technology provides the primary means for people with disabilities to send and receive text communications over the public switched telephone network (PSTN). Changes to communications networks, particularly ongoing technology transitions from circuit switched to IP-based networks and from copper to wireless and fiber infrastructure, have affected the quality and utility of TTY technology, prompting discussions on transitioning to an alternative advanced communications technology for text communications. Accordingly, on December 16, 2016, the Commission released the Report and Order, amending its rules that govern the obligations of wireless service providers and manufacturers to support TTY technology to permit such providers and manufacturers to provide support for RTT over wireless IP-based networks to facilitate an effective and seamless transition to RTT in lieu of continuing to support TTY technology.

In the Report and Order, the Commission adopted measures requiring the following:

(a) RTT outreach guidelines. Each wireless provider and manufacturer that voluntarily transitions from TTY technology to RTT over wireless IP-based networks and services is encouraged to develop consumer and education efforts that include (1) the development and dissemination of educational materials that contain information pertinent to the nature, purpose, and timelines of the RTT transition; (2) internet postings, in an accessible format, of information about the TTY to RTT transition on the websites of covered entities; (3) the creation of a telephone hotline and an online interactive and accessible service that can answer consumer questions about RTT; and (4) appropriate training of staff to effectively respond to consumer questions. All consumer outreach and education should be provided in accessible formats including, but not limited to, large print, Braille, videos in American Sign Language that are captioned and video described, emails to consumers who have opted to receive notices in this manner, and printed materials. Service providers and manufacturers are also encouraged to coordinate with consumer, public safety, and industry stakeholders to develop and distribute education and outreach materials. The information will inform consumers of alternative accessible technology available to replace TTY technology that may no longer be available to consumers through their provider or on their devices.

(b) TTY waiver notice conditions. Each wireless provider that receives a waiver of the requirement to support TTY technology over wireless IP-based networks and services must apprise its customers, through effective and accessible channels of communication, that (1) until TTY is sunset, TTY technology will not be supported for calls to 911 services over IP-based wireless services, and (2) there are alternative PSTN-based and IP-based accessibility solutions for people with disabilities to reach 911 services. These notices must be developed in coordination with PSAPs and national consumer organizations, and include a listing of text-based alternatives to 911, including, but not limited to, TTY capability over the PSTN, various forms of PSTN-based and IP-based TRS, and text-to-911 (where available). The notices will inform consumers of the loss of the use of TTY for completing 911 calls over the provider's network and alternative services that may be used.

(c) Six-month reports. Once every six months, each wireless provider that requests and receives a waiver of the requirement to support TTY technology must file a report with the Commission and inform its customers regarding its progress toward and the status of the availability of new IP-based accessibility solutions. Such reports must include (1) information on the interoperability of the provider's selected accessibility solution with the technologies deployed or to be deployed by other carriers and service providers, (2) the backward compatibility of such solution with TTYs, (3) a showing of the provider's efforts to ensure delivery of 911 calls to the appropriate PSAP, (4) a description of any obstacles incurred towards achieving interoperability and steps taken to overcome such obstacles, and (5) an estimated timetable for the deployment of accessibility solutions. The information will inform consumers of the progress towards the availability of alternative accessible means to replace TTY. The Commission will evaluate the reports to determine whether any changes to the waivers are warranted and whether there are any impediments to progress that the Commission may be in a position to resolve.

The shrimp fishery in the Gulf is managed under the FMP. The FMP was prepared by the Council and implemented through regulations at 50 CFR part 622 under the authority of the Magnuson-Stevens Fishery Conservation and Management Act (Magnuson-Stevens Act).

This document also designates the unidentified tables in § 622.55 to bring the section into compliance with the requirements of 1 CFR 8.1 and 8.2 and with the Office of the Federal Register's Document Drafting Handbook (https://www.archives.gov/files/federal-register/write/handbook/ddh.pdf) section 7.4. On August 22, 2017, NMFS published a notice of availability for Amendment 17B and requested public comment (82 FR 39733). On October 4, 2017, NMFS published a proposed rule for Amendment 17B and requested public comment (82 FR 46205). The proposed rule and Amendment 17B outline the rationale for the action contained in this final rule. A summary of the management measures described in Amendment 17B and implemented by this final rule is provided below.

From 2003 to 2006, the Gulf shrimp fishery experienced significant economic losses, primarily as a result of high fuel costs and reduced prices caused by competition with imports. These economic losses contributed to a reduction in the number of vessels in the fishery, and consequently, a reduction of commercial effort. During that time, commercial vessels in the Gulf shrimp fishery were required to have an open-access permit. In 2006, to prevent overcapitalizing the fishery when it became profitable again, the Council established a 10-year freeze on the issuance of new shrimp permits and created a limited access Federal Gulf shrimp moratorium permit (moratorium permit)(71 FR 56039, September 26, 2006). In 2016, the Council extended the duration of the Gulf shrimp moratorium permit program for another 10 years through Amendment 17A to the FMP (81 FR 47733, July 22, 2016).

During the development of Amendment 17A, the Council identified several other issues with the Gulf shrimp fishery that it wanted addressed. First, MSY and OY are defined individually for the three penaeid shrimp species and for royal red shrimp. Second, the number of moratorium permits has continued to decline, and the Council is concerned that the decline in total permits will continue indefinitely. Finally, transit through Federal waters (Gulf EEZ) with shrimp on board currently requires a Federal moratorium permit, which limits the ability of a state-registered vessel to navigate in certain areas of the Gulf while engaged in shrimping. Amendment 17B was developed to address these issues through revisions to management reference points and the Gulf shrimp permit program, while maintaining catch efficiency, economic efficiency, and stability in the fishery.

This final rule allows for the creation of a Federal Gulf shrimp reserve pool permit when certain conditions are met, and allows non-federally permitted Gulf shrimp vessels to transit through the Gulf EEZ.

Currently, moratorium permits are valid for 1 year and are required to be renewed annually. If the permit is not renewed within 1 year of its expiration date, the permit is no longer renewable and is terminated. A terminated permit cannot be reissued by NMFS and is lost to the fishery.

As of December 31, 2016, 1,441 moratorium permits were valid or renewable. Since the start of the permit moratorium, a total of 493 moratorium permits have been terminated. As described in Amendment 17B, when the number of valid or renewable moratorium permits reaches 1,072, then any moratorium permits that are not renewed within 1 year of expiration would be converted to Gulf shrimp reserve pool permits. This number is based on the predicted number of active permitted vessels needed to attain aggregate OY in the offshore fishery. As explained further below, the aggregate OY accounts for relatively high catch per unit effort (CPUE) and landings, while reducing the risk of exceeding sea turtle and juvenile red snapper bycatch. Any Gulf shrimp reserve pool permit that is created would not be issued until eligibility requirements are developed by the Council and implemented through subsequent rulemaking.

Currently, to possess Gulf shrimp in the Gulf EEZ, a vessel must have been issued a moratorium permit. In the Gulf, there are some areas where state-only licensed shrimpers would like to transit with shrimp on board from state waters through Federal waters to return to state waters and port. However, because these state-licensed shrimping vessels do not possess a Federal moratorium permit, they cannot legally transit through the Gulf EEZ while possessing shrimp. This results in some of these vessels spending increased time at sea and incurring additional fuel costs because of longer transit times.

This final rule allows a vessel possessing Gulf shrimp to transit the Gulf EEZ without a valid moratorium permit if fishing gear is appropriately stowed. Transit is defined as non-stop progression through the area; fishing gear appropriately stowed means trawl doors and nets must be out of the water and the bag straps must be removed from the net. This transit exemption is expected to reduce the time at sea required for some shrimpers, while allowing enforcement to easily determine that the gear is not being used for fishing.

Amendment 17B specifies the aggregate MSY and aggregate OY for the Federal Gulf shrimp fishery, and determines a minimum number of moratorium permits in the fishery.

After extending the duration of the Gulf shrimp moratorium permit program for another 10 years, and recognizing that the moratorium results in a passive loss of permits from the fishery, the Council decided to determine an appropriate minimum number of moratorium permits. Although the Council previously specified species specific MSYs and OYs for penaeid shrimp, the shrimp permit is not species specific. Therefore, the Council established an aggregate MSY and OY for the Federal Gulf shrimp fishery to facilitate the decision on the minimum number of moratorium permits.

Amendment 17B establishes aggregate MSY for the Federal Gulf shrimp fishery at 112,531,374 lb (51,043,373 kg), tail weight. Amendment 17B also establishes aggregate OY for the Gulf shrimp fishery equal to 85,761,596 lb (38,900,806 kg), tail weight, which is the aggregate MSY reduced for the ecological, social, and economic factors described above.

As noted above, as of December 31, 2016, 1,441 moratorium permits were valid or renewable, and, at the current rate of termination, the minimum threshold number of permits selected by the Council, 1,072 permits, will be reached in 24 years. This minimum threshold number of valid or renewable moratorium permits is based on the predicted number of active permitted vessels needed to achieve aggregate OY in the offshore fishery. Neither this final rule nor Amendment 17B actively removes any moratorium permits. The minimum threshold is only for purposes of monitoring changes in fishery participation and determining whether additional management measures should be established.

As specified in Amendment 17B, when the number of moratorium permits declines to 1,175, the Council will form a panel to review details of the reserve permit pool and other options for management. The panel will consist of the Council's Shrimp Advisory Panel (AP) members, Science and Statistical Committee (SSC) members, NMFS, and Council staff. This panel could make recommendations about how to utilize a Gulf shrimp vessel permit reserve pool. The development of additional details for the pool permits will occur through a plan amendment or framework action, as appropriate, at a later date, when additional available information about the status of the Gulf shrimp fishery may be available.

In addition to the measures described in Amendment 17B, this final rule revises the coordinates for the Tortugas shrimp sanctuary in the Gulf that were established in the original Shrimp FMP; and clarifies the regulations for the harvest and possession of wild live rock in Gulf Federal waters, as established in the FMP for Coral and Coral Reefs of the Gulf of Mexico (Coral FMP).

The original FMP established the Tortugas shrimp sanctuary on May 20, 1981, which was implemented with cooperation from of the state of Florida (46 FR 27489, May 20, 1981), and which is currently defined at 50 CFR 622.55(c)(1). Since that time, there have been numerous advances in geographical positioning systems that describe the physical locations (such as lights) used to define the boundary of the Tortugas shrimp sanctuary. NMFS and the state of Florida have determined that several positions for the points defining the boundary of the sanctuary are no longer consistent with the most recent published coordinates in Federal navigation references and current positioning systems, such as Global Positioning Systems. For example, Point N (Coon Key Light) is currently described as being located at 25°52′9″ north latitude and 81°37′9″ west longitude. However, using current technology that is reflected in recent U.S. navigational publications, NMFS and the state of Florida have noted that this point is actually located at 25°52′54″ north latitude and 81°37′56″ west longitude. Therefore, this final rule revises the positions for Points N, F, G, H, and P to reflect current technology, for consistency with the current U.S. Coast Guard Light List, the U.S. Coast Pilot, and the state of Florida regulations, and for consistency in units of position. For consistency, Florida is also updating these positions. Only these technical corrections for the coordinates are being made to the language of the regulations; this final rule does not make any substantive changes in the regulations specific to the management measures for the Tortugas shrimp sanctuary.

This final rule also revises the prohibited species regulations for wild live rock, as established in the Coral FMP. In 1994, the final rule implementing Amendment 2 to the Coral FMP established a prohibition on the harvest and possession of wild live rock in the Gulf EEZ to begin on January 1, 1997 (59 FR 66776, December 28, 1994). The following year, the final rule implementing Amendment 3 to the Coral FMP established an annual quota for wild live rock from the Gulf EEZ to apply before the prohibition would take effect (60 FR 56533, November 9, 1995). The prohibition on harvest beginning in 1997 and the quota were originally codified at 50 CFR 638.26(c) and (d), and the quota provision included prohibitions on harvest and possession and on sale and purchase when a quota closure occurs. When NMFS reorganized the 50 CFR part 622 regulations in 1996, the prohibition on harvest and possession and the quota provisions were moved to 50 CFR 622.42(b)(2) and 622.43(a)(2)(ii) (61 FR 34930, July 3, 1996). In 1999, NMFS issued a final rule for a Technical Amendment to its regulations in 50 CFR part 622 in order to revise a variety of regulations for clarity, consistency in terms, and the removal of outdated regulations (64 FR 59125, November 2, 1999). Because the harvest of wild live rock in the Gulf was discontinued at the end of 1996, the final rule for the Technical Amendment removed several provisions related to harvest, including the quota and the associated prohibitions on harvest and possession and on sale and purchase, when a quota closure occurs. That final rule also added a general restriction on sale and purchase of wild live rock from the Gulf EEZ, which remains in effect today. However, NMFS recently became aware that the rule inadvertently failed to also add the general restriction on the harvest and possession of wild live rock in or from the Gulf EEZ. In this final rule, NMFS corrects this error by adding the Gulf EEZ wild live rock prohibition at § 622.73(c).

This final rule revises several table designations that are revised through Amendatory instruction 3 in the codified text. These table designations have been updated in this final rule based on updated formatting guidance provided by the Office of the Federal Register. No changes to the content in the referenced tables themselves was made in this final rule different from that in the proposed rule. In § 622.55, the table designations for paragraphs (d) and (e) use different numbers than those that were included in the proposed rule; specifically, this final rule uses numbers 1, 2 and 3 instead of numbers 3, 4 and 5, respectively, in the paragraph (d) table names, and the number 4 instead of the number 6 in the paragraph (e) table name.

NMFS received seven comments on the notice of availability and proposed rule for Amendment 17B from the public and a Federal agency. Several commenters supported the transit provision for shrimp vessels not possessing a Federal moratorium permit. A Federal agency submitted a comment stating it had no comment on Amendment 17B or the proposed rule. NMFS' responses to comments that specifically relate to the actions contained in Amendment 17B and the proposed rule are summarized below.

Comment 1: A minimum threshold number of moratorium permits should not be established because there is no need to keep unused permits available to the fishery.

Response: NMFS disagrees. The Council established the minimum threshold to provide a clear benchmark for monitoring changes in fishery participation. Since the implementation of the Federal Gulf shrimp permit moratorium in Amendment 13 to the FMP in 2006, (71 FR 56039, September 26, 2006), the fishery has experienced a passive decline in valid and renewable moratorium permits. While the permit moratorium has been successful in reducing overcapitalization and increasing CPUE in the fishery, the Council is concerned the decline in permits could continue indefinitely.

National Standard 1 of the Magnuson-Stevens Act requires that fishery management plans prevent overfishing while achieving, on a continuing basis, the OY from each fishery. In March 2016, the Council convened a working group to recommend an appropriate aggregate MSY and aggregate OY for the Gulf shrimp fishery in Federal waters. The working group recommended an aggregate MSY and also determined that there were four important factors to consider when establishing aggregate OY: Landings, CPUE, sea turtle bycatch threshold, and juvenile red snapper bycatch. The working group concluded that the predicted effort and associated landings in 2009 balanced all of these criteria relative to observed levels in other years. The minimum threshold is based on the predicted number of active permitted vessels needed to attain this aggregate OY. Evaluating changes in fishery participation using this threshold will help the Council determine whether additional management measures are necessary in the future to continue to achieve OY on a continuing basis, consistent with National Standard 1.

Comment 2: If the Council and NMFS have determined that the Gulf shrimp fishery needs more effort to achieve OY, and therefore more available moratorium vessel permits, NMFS should distribute any reserve pool permits through an auction or drawing, or sell them at the current market price.

Response: The Council and NMFS have not decided that additional moratorium vessels permits are necessary. Amendment 17B requires only that the Council form a review panel when the number of valid or renewable shrimp moratorium permits reaches 1,175, and that when the number of valid or renewable moratorium permits reaches 1,072, any moratorium permits that are not renewed within 1 year of expiration be converted to Gulf shrimp reserve pool permits. The panel would consist of the Council's Shrimp AP members, SSC members, NMFS, and Council staff. The panel would review the details of a permit pool and other management options, and provide recommendations to the Council on issuance of any reserve pool permits or how else to utilize reserve pool permits. The Council would then decide the specific details of any future actions with respect to reserve pool permits, after the opportunity for public comment consistent with both the Magnuson-Stevens Act and Administrative Procedure Act.

The Regional Administrator, Southeast Region, NMFS, has determined that this final rule is consistent with Amendment 17B, the FMP, the Magnuson-Stevens Act, and other applicable law.

This final rule has been determined to be not significant for purposes of Executive Order 12866.

The Magnuson-Stevens Act provides the legal basis for this rule. No duplicative, overlapping, or conflicting Federal rules have been identified. In addition, no new reporting and record-keeping requirements are introduced by this rule. Accordingly, the Paperwork Reduction Act does not apply to this rule. A description of this rule, why it is being implemented, and the purposes of this rule are contained in the preamble and in the SUMMARY section of the preamble. The objectives of this rule are to establish the appropriate metrics to manage the shrimp fishery, maintain increases in catch efficiency, maintain landings at or near aggregate OY, promote economic efficiency and stability in the fishery, provide flexibility for state registered shrimp vessels, protect federally managed Gulf shrimp stocks, correct coordinates for the Tortugas sanctuary in the Federal regulations so they are consistent with published coordinates in Federal navigation references and current positioning systems, and correct the regulations to clarify that harvest and possession of wild live rock in or from the Gulf EEZ is prohibited.

The Chief Counsel for Regulation of the Department of Commerce certified to the Chief Counsel for Advocacy of the Small Business Administration (SBA) during the proposed rule stage that this rule, if adopted, would not have a significant economic impact on a substantial number of small entities. NMFS did not receive any comments from SBA's Office of Advocacy or the public regarding the economic analysis of Amendment 17B or the certification in the proposed rule. No changes to this rule were made in response to public comments. The factual basis for the certification was published in the proposed rule and is not repeated here. Because this final rule is not expected to have a significant economic impact on a substantial number of small entities, a final regulatory flexibility analysis is not required and none has been prepared.

For the reasons set out in the preamble, 50 CFR part 622 is amended as follows:

The February 7, 2017, final rule (82 FR 9634) set groundfish harvest specifications for 2017-18 (overfishing limits, acceptable biological catches, and annual catch limits (ACLs)) and established management measures designed to keep catch within the ACLs. As part of that final rule, consistent with the Council's recommendations and described in the preamble to that rule, NMFS implemented Amendment 27 to the PCGFMP. This action makes corrections to the implementing regulations for two components of Amendment 27: (1) Reclassification of big skate from an ecosystem component species to “in the fishery” and (2) the update of several sections of the PCGFMP to reflect that canary rockfish and petrale sole were declared rebuilt. This action makes corrections in certain provisions of the recreational groundfish retention regulations in effect in waters off California and the groundfish retention regulations in the limited entry fixed gear and open access fisheries, as amended in the February 7, 2017, final rule to reflect the rebuilt status of canary rockfish and petrale sole. In addition, this action makes two minor, technical corrections to the regulations implementing the 2017-18 harvest specifications by correcting the unit of weight used to set the sablefish cumulative limit for Tier 2 of the limited entry fixed gear sablefish fishery, and by correcting a typographical error in the season dates for the Mendocino Management Area recreational fisheries.

The February 7, 2017, final rule made several changes necessary to reclassify big skate from an ecosystem component species to “in the fishery,” however, one necessary change was mistakenly omitted. In 50 CFR 660.11, the definition of “groundfish” includes a separate listing of the species included in the ecosystem component. Big skate was mistakenly not removed from that ecosystem component definition. Big skate was correctly listed in the definition under the skates category within the definition of “groundfish,” at 50 CFR 660.11, Groundfish (2) Skates. This rule will remove big skate from the ecosystem component category under the definition of “groundfish,” at 50 CFR 660.11, Groundfish (10) Ecosystem component species.

NMFS is making three corrections to groundfish recreational fishery regulations in effect off of California. As noted above, one of the components of Amendment 27 was to amend the PCGFMP to reflect that canary rockfish and petrale sole were declared rebuilt. As a result of the rebuilt status of the canary rockfish and petrale sole fisheries, the State of California relaxed some of its restrictions on retention in the recreational fisheries. As noted in the proposed rule and the February 7, 2017, final rule, NMFS intended the federal regulations to be consistent with the changes in the California state restrictions. However, while the February 7, 2017, final rule correctly updated the federal regulations to remove the prohibition on retention of canary rockfish for the Washington state recreational fisheries, the final rule mistakenly did not remove the prohibition on retention of canary rockfish for recreational fisheries off of California and the Cowcod Conservation Area (50 CFR 660.360(c)(3)(i)(B)). This inadvertent omission is inconsistent with the Council's intent in making its recommendation for the 2017-18 harvest specifications and management measures. Therefore, this correcting action will update § 660.360(c)(3)(i)(B) to reflect the rebuilt status of canary rockfish.

Additionally, in the preamble to the proposed rule (81 FR 75266, 75282; Oct. 28, 2016), NMFS noted that the rule would remove petrale sole and starry flounder from the California recreational season and depth restrictions, which are management measures to reduce regulatory discards. This change allows anglers to retain petrale sole and starry flounder year round without depth constraint. The February 7, 2017, final rule correctly revised § 660.360(c)(3) to note the exception for petrale sole and starry flounder. However, paragraphs (c)(3)(i)(B), (c)(3)(i)(C), and (c)(3)(iv) of § 660.360 were not similarly revised. Consistent with the revisions already made to paragraph (c)(3), this correcting action revises paragraphs, (c)(3)(i)(B), (c)(3)(i)(C), and (c)(3)(iv) of § 660.360 to exempt petrale sole and starry flounder from the season and depth restrictions for recreational fisheries off of California.

Finally, NMFS is correcting the season dates for the Mendocino Management Area under § 660.360(c)(3)(ii)(A)(2). The final rule incorrectly stated that the season is open “May 1 through October December 31,” but correctly stated that the season is closed January 1 through April 30. This rule will correct the mistake by deleting the extra word “October” so that the correct open season is reflected in the language, “May 1 through December 31.”

As a result of canary rockfish being rebuilt, NMFS relaxed some of the restrictions on retention in the limited entry fixed gear and open access fisheries. However, the February 7, 2017, final rule, as it pertained to the groundfish limited entry fixed gear fishery ((50 CFR 660.230(a)) and to the open access fishery (50 CFR 660.330(a)), mistakenly did not update the federal regulations to remove the prohibition on retention of canary rockfish, even though NMFS set trip limits for canary rockfish in the limited entry fixed gear fishery in Table 2 to Part 660, Subpart E, and in the open access fishery in Table 3 to Part 660, Subpart F. This was inconsistent with the Council's intent in its recommendation of the 2017-18 harvest specifications and management measures. This rule will update both § 660.230(a) and § 660.330(a) to reflect the rebuilt status of canary rockfish.

The February 7, 2017, final rule included the cumulative limits for each of the three tiers of the limited entry fixed gear sablefish primary fishery for both 2017 and 2018. Inadvertently, the cumulative limit for Tier 2 in 2017 was expressed in metric tons instead of in pounds. The final rule read “20,509 mt” (9,303 kg) instead of “20,509 lbs”, which is the true equivalent of 9,303 kg. This rule corrects this error by stating that the Tier 2 cumulative limit for 2017 is “20,509 lbs (9,303 kg)” in 50 CFR 660.231(b)(3)(i).

The Assistant Administrator (AA) for Fisheries, NOAA, finds that pursuant to 5 U.S.C. 553(b)(B), there is good cause to waive prior notice and an opportunity for public comment on this action, as notice and comment are unnecessary and would be contrary to the public interest. This correcting action is consistent with harvest specification and management measures recommended by the Council and described in the preambles to the proposed rule (81 FR 75266; Oct. 28, 2016) and final rule (81 FR 9634; Feb. 7, 2017) implementing Amendment 27 to the PCGFMP. Because the corrections included in this rule are consistent with actions on which NMFS has already requested and considered public comments, further notice and opportunity for public comment on this action is unnecessary. It would be contrary to the public interest to delay implementation of the minor corrections in this rule, because this correcting action will reduce confusion caused by unintentional technical errors, some of which also appear to create inconsistency between state and federal regulations. For the reasons above, the AA also finds good cause under 5 U.S.C. 553(d)(3) to waive the 30-day delay in effectiveness and makes this rule effective immediately upon publication. This rule is exempt from the procedures of the Regulatory Flexibility Act (RFA) because the rule is issued without opportunity for prior notice and opportunity for public comment. Therefore, RFA analysis is not required and none has been prepared.

For the reasons set out in the preamble, 50 CFR part 660 is corrected by making the following correcting amendments: