This final rule, pursuant to 5 U.S.C. 553, amends regulations issued to carry out a marketing order as defined in 7 CFR 900.2(j). This final rule is issued under Marketing Agreement and Order No. 986, (7 CFR part 986), regulating the handling of pecans grown in the states of Alabama, Arkansas, Arizona, California, Florida, Georgia, Kansas, Louisiana, Missouri, Mississippi, North Carolina, New Mexico, Oklahoma, South Carolina, and Texas. Part 986 (referred to as the “Order”) is effective under the Agricultural Marketing Agreement Act of 1937, as amended (7 U.S.C. 601-674), hereinafter referred to as the “Act.” The Council locally administers the Order and is comprised of growers and handlers of pecans operating within the production area, and one accumulator and one public member.

The Department of Agriculture (USDA) is issuing this final rule in conformance with Executive Orders 13563 and 13175. This action falls within a category of regulatory actions that the Office of Management and Budget (OMB) has exempted from Executive Order 12866 review. Additionally, because this rule does not meet the definition of a significant regulatory action it does not trigger the requirements contained in Executive Order 13771. See OMB's Memorandum titled “Interim Guidance Implementing Section 2 of the Executive Order of January 30, 2017, titled `Reducing Regulation and Controlling Regulatory Costs' ” (February 2, 2017).

This rule has been reviewed under Executive Order 12988, Civil Justice Reform. This rule is not intended to have retroactive effect.

The Act provides that administrative proceedings must be exhausted before parties may file suit in court. Under section 608c(15)(A) of the Act, any handler subject to an order may file with USDA a petition stating that the order, any provision of the order, or any obligation imposed in connection with the order is not in accordance with law and request a modification of the order or to be exempted therefrom. A handler is afforded the opportunity for a hearing on the petition. After the hearing, USDA would rule on the petition. The Act provides that the district court of the United States in any district in which the handler is an inhabitant, or has his or her principal place of business, has jurisdiction to review USDA's ruling on the petition, provided an action is filed not later than 20 days after the date of the entry of the ruling.

This final rule revises the reporting requirements under the Order. This action requires all pecan handlers to report to the Council the average handler price paid and average shelled pecan yield as part of its existing year-end report. The Council will use this information to provide statistical reports to the industry and meet requirements under the Order. This action was unanimously recommended by the Council at its January 24, 2017, meeting and affirmed at its April 17, 2018, meeting.

Section 986.76 provides the authority to collect reports on the quantity of pecans handled and other pertinent information as specified by the Council. Section 986.78 provides, with the approval of the Secretary, authority for the Council to collect other reports and information from handlers needed to perform its duties. Section 986.175 specifies that handlers shall submit a year-end report to the Council that includes the amount of shelled and inshell pecans in inventory, total inventory calculated on an inshell basis, total weight and type of domestic pecans handled for the fiscal year, and information on assessments owed, paid, or due.

This rule revises § 986.175 to require that additional information be included in the year-end report. These revisions require handlers to report the average price paid by handler and average yield of shelled pecans as part of the existing year-end report.

At its January 24, 2018, and April 17, 2018, meetings, the Council reviewed the reporting requirements under the Order and determined there were additional data that would be beneficial to collect and summarize for the industry on an annual basis. Specifically, the Council recommended adding two additional items to be reported as part of the annual year-end reporting requirement, average price paid by handlers and shelled pecan yield.

While the National Agricultural Statistics Service (NASS) reports average grower prices, this reporting change will provide information regarding a handler's overall cost of acquiring pecans. Some handlers buy directly from growers, but many buy from other handlers or import pecans. Understanding the cost of pecans being handled is key information in determining the value of the overall crop and subsequent impacts on the market for pecans the following season. During the meetings, members noted that collecting the average price paid would also be necessary to complete the marketing policy report required under the Order. The marketing policy, as required by § 986.65, must include projected prices for the upcoming fiscal year, which would be influenced by handler costs. Further, the Council believes providing this information would improve the information available to the pecan industry. In particular, the Council feels this information may give growers better information that can be used in making business decisions. The Council recommended adding this reporting requirement as there is currently no comprehensive source for handler cost information.

The Council also discussed asking handlers to provide information regarding the weight of shelled pecans handled. During the formal rulemaking hearing to promulgate the Order, a witness testified regarding a conversion rate of multiplying the shelled weight by two to calculate inshell weight. That conversion rate was incorporated into the Order. Using this conversion, the weight of shelled pecans is approximately 50 percent of the inshell weight. This proportion is referred to as the “shell-out” or shelled pecan yield. However, there are natural variations in pecans and yield can vary depending on the thickness of the shells of different varieties and can also vary from year to year. These fluctuations make it challenging to accurately convert the total inshell volume harvested into shelled pounds, or shelled pounds into their inshell equivalent to provide an accurate estimate of overall supply.

As with the handler price paid, there is currently no central industry source for information on shelled pecan yield. The Council believes collecting this data will allow them to provide the industry with an updated annual average of this yield, which could be an indicator of quality, and over time provide a series of data on shelled pecan yield that would allow them to determine if changes to the current conversion rate are needed.

Following the recommendation of the proposed changes made at the January 24, 2018 meeting, some members had questions about the specific data that would be collected. Based on these questions, the Council made some adjustments to the proposed form to clarify that handlers would report the average price paid for all inshell pecans purchased during the fiscal year, regardless of how the pecans are handled, including pecans from outside the production area. For the purposes of this form, the terms crop year and fiscal year are synonymous. The Council reviewed the revised reporting form at its April 17, 2018, meeting and affirmed that the new language met their original intent.

The Council believes these revised reporting requirements are necessary to provide accurate reports to the industry regarding average price paid, yield for shelled pecans, and to meet requirements under the Order. The industry will use this information to complement the information provided by NASS in the development of its marketing policy and to collect accurate data to determine if the definition of weight in § 986.43 needs to be amended.

Pursuant to requirements set forth in the Regulatory Flexibility Act (RFA) (5 U.S.C. 601-612), the Agricultural Marketing Service (AMS) has considered the economic impact of this action on small entities. Accordingly, AMS has prepared this final regulatory flexibility analysis.

The purpose of the RFA is to fit regulatory actions to the scale of businesses subject to such actions in order that small businesses will not be unduly or disproportionately burdened. Marketing orders issued pursuant to the Act, and rules issued thereunder, are unique in that they are brought about through group action of essentially small entities acting on their own behalf.

There are approximately 2,500 growers of pecans in the production area and approximately 250 handlers subject to regulation under the Order. Small agricultural growers are defined by the Small Business Administration as those having annual receipts less than $750,000, and small agricultural service firms are defined as those whose annual receipts are less than $7,500,000 (13 CFR 121.201).

According to information from NASS, the average grower price for pecans during the 2016-2017 season was $2.59 per pound and 269 million pounds were utilized. The value for pecans that year totaled $697 million ($2.59 per pound multiplied by 269 million pounds). Taking the total value of production for pecans and dividing it by the total number of pecan growers provides an average return per grower of $278,684. Using the average price and utilization information, and assuming a normal distribution among growers, the majority of growers receive less than $750,000 annually.

Evidence presented at the formal rulemaking hearing indicates an average handler margin of $0.58 per pound. Adding this margin to the average grower price of $2.59 per pound of inshell pecans results in an estimated handler price of $3.17 per pound. With a total 2017 production of 269 million pounds, the total value of production in 2017 was $853 million ($3.17 per pound multiplied by 269 million pounds). Taking the total value of production for pecans and dividing it by the total number of pecan handlers provides an average return per handler of $3.4 million. Using this estimated price, the utilization volume, number of handlers, and assuming a normal distribution among handlers, the majority of handlers have annual receipts of less than $7,500,000. Thus, the majority of growers and handlers regulated under the Order may be classified as small entities.

This final rule revises the reporting requirements in § 986.175. This action requires all pecan handlers to report to the Council the average handler price paid and average shelled pecan yield as part of its existing year-end report. This information will be used by the Council to provide statistical reports to the industry and meet requirements under the Order. The authority for this action is provided in §§ 986.76 and 986.78.

It is not anticipated that this action will impose additional costs on handlers or growers, regardless of size. Council members, including those representing small businesses, indicated the average handler price paid and the average shelled pecan yield information is already recorded and maintained by handlers as a part of their daily business and the information should be readily accessible. Consequently, any additional costs associated with this change would be minimal and apply equally to all handlers.

This action should also help the industry by providing additional data on pecans handled. This information will help with marketing and planning for the industry, as well as provide important information in preparing the annual marketing policy required by the Order. This change will also assist with the development of a dataset to determine if the conversion rate for shelled to inshell pecans needs to be revised. The benefits of this rule are expected to be equally available to all pecan growers and handlers, regardless of their size.

The Council discussed other alternatives to this action, including making no changes to the current reporting requirements. However, having the information on handler price paid and shelled pecan yield will provide important information for the industry.

Another alternative considered was to create a new report for the collection of this information. However, the industry recently implemented a series of monthly reports that increased the reporting burden on handlers. Rather than add to the burden by creating a new report, the Council believed it would be more efficient to ask handlers for this information as part of the existing year-end reporting requirement. Therefore, the alternatives were rejected.

In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), the Order's information collection requirements have been previously approved by OMB and assigned OMB No. 0581-0291 “Federal Marketing Order for Pecans.” This final rule will require changes to the Council's existing APC Form 7. However, the changes are minor and the currently approved burden for the form will not be altered by the changes to the form. The revised form has been submitted to OMB for approval.

As with all Federal marketing order programs, reports and forms are periodically reviewed to reduce information requirements and duplication by industry and public sector agencies. As noted in the initial regulatory flexibility analysis, USDA has not identified any relevant Federal rules that duplicate, overlap, or conflict with this rule. Further, no public comments were received regarding the initial regulatory flexibility analysis.

AMS is committed to complying with the E-Government Act, to promote the use of the internet and other information technologies to provide increased opportunities for citizen access to Government information and services, and for other purposes.

The Council's meetings were widely publicized throughout the pecan industry and all interested persons were invited to attend the meetings and participate in Council deliberations on all issues. The Council's meetings held on January 24, 2018, and April 17, 2018, were also public meetings and all entities, both large and small, were able to express views on this issue.

A proposed rule concerning this action was published in the Federal Register on October 9, 2018, (83 FR 50531). Copies of the rule were sent via email to Council members and known pecan handlers. The rule was also made available through the internet by USDA and the Office of the Federal Register . A 30-day comment period ending November 8, 2018, was provided to allow interested persons to respond to the proposal. No comments were received. Accordingly, no changes will be made to the rule as proposed.

A small business guide on complying with fruit, vegetable, and specialty crop marketing agreements and orders may be viewed at: http://www.ams.usda.gov/rules-regulations/moa/small-businesses . Any questions about the compliance guide should be sent to Richard Lower at the previously-mentioned address in the FOR FURTHER INFORMATION CONTACT section.

After consideration of all relevant matter presented, including the information and recommendation submitted by the Council and other available information, it is hereby found that this rule, as hereinafter set forth, will tend to effectuate the declared policy of the Act.

For the reasons set forth in the preamble, 7 CFR part 986 is amended as follows:

The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the United States Code. 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. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it supports the removal of Class E airspace extending upward from 700 feet above the surface at Chase Field Industrial Airport, Beeville-Chase Field, TX.

The FAA published a notice of proposed rulemaking in the Federal Register (83 FR 55306; November 5, 2018) for Docket No. FAA-2018-0917 to remove Class E airspace extending upward from 700 feet above the surface at Chase Field Industrial Airport, Beeville-Chase Field, TX. Interested parties were invited to participate in this rulemaking effort by submitting written comments on the proposal to the FAA. No comments were received.

Class E airspace designations are published in paragraphs 6005 of FAA Order 7400.11C, dated August 13, 2018, and effective September 15, 2018, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designations listed in this document will be published subsequently in the Order.

This document amends FAA Order 7400.11C, Airspace Designations and Reporting Points, dated August 13, 2018, and effective September 15, 2018. FAA Order 7400.11C is publicly available as listed in the ADDRESSES section of this document. FAA Order 7400.11C lists Class A, B, C, D, and E airspace areas, air traffic service routes, and reporting points.

This amendment to Title 14 Code of Federal Regulations (14 CFR) part 71 removes the Class E airspace extending upward from 700 feet above the surface at Chase Field Industrial Airport, Beeville-Chase Field, TX.

This action due to the cancellation of the instrument procedures at the airport making the airspace no longer necessary.

The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current, is non-controversial and unlikely to result in adverse or negative comments. It, therefore: (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); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. Since this is a routine matter that only affects air traffic procedures and air navigation, it is certified that this rule, when promulgated, does not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

The FAA has determined that this action qualifies for categorical exclusion under the National Environmental Policy Act in accordance with FAA Order 1050.1F, “Environmental Impacts: Policies and Procedures,” paragraph 5-6.5.a. This airspace action is not expected to cause any potentially significant environmental impacts, and no extraordinary circumstances exist that warrant preparation of an environmental assessment.

In consideration of the foregoing, the Federal Aviation Administration amends 14 CFR part 71 as follows:

The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the United States Code. 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. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it establishes Class E airspace extending upward from 700 feet above the surface at Williston Basin International, Williston, ND, to support IFR operations at the airport.

On November 5, 2018, the FAA published a notice of proposed rulemaking in the Federal Register (83 FR 55310 for Docket No. FAA-2018-0250, a notice of proposed rulemaking (NPRM) to establish Class E airspace extending upward from 700 feet above the surface at Williston Basin International Airport, Williston, ND. Controlled airspace is necessary to accommodate new standard instrument approach procedures developed at Williston Basin International Airport, for the safety and management of instrument flight rules (IFR) operations. No comments were received.

Class E airspace designations are published in paragraph 6005 of FAA Order 7400.11C, dated August 13, 2018, and effective September 15, 2018, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designations listed in this document will be published subsequently in the Order.

This document amends FAA Order 7400.11C, Airspace Designations and Reporting Points, dated August 13, 2018, and effective September 15, 2018. FAA Order 7400.11C is publicly available as listed in the ADDRESSES section of this document. FAA Order 7400.11C lists Class A, B, C, D, and E airspace areas, air traffic service routes, and reporting points.

The FAA amends Title 14, Code of Federal Regulations (14 CFR) part 71 by:

Establishing Class E airspace area extending upward from 700 feet above the surface to within a 6.7-mile radius of Williston Basin International Airport, Williston, ND, to accommodate new standard instrument approach procedures. This action would enhance safety and the management of IFR operations at the airport.

The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current, is non-controversial and unlikely to result in adverse or negative comments. It, therefore: (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); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. Since this is a routine matter that only affects air traffic procedures and air navigation, it is certified that this rule, when promulgated, does not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

The FAA has determined that this action qualifies for categorical exclusion under the National Environmental Policy Act in accordance with FAA Order 1050.1F, “Environmental Impacts: Policies and Procedures,” paragraph 5-6.5.a. This airspace action is not expected to cause any potentially significant environmental impacts, and no extraordinary circumstances exist that warrant preparation of an environmental assessment.

In consideration of the foregoing, the Federal Aviation Administration amends 14 CFR part 71 as follows:

The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the United States Code. 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. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it establishes Class E airspace extending upward from 700 feet above the surface at Farington Field Airport, Auburn, NE, to support IFR operations at the airport.

On December 17, 2018, the FAA published a notice of proposed rulemaking in the Federal Register (83 FR 64490) for Docket No. FAA-2018-0974, to establish Class E airspace extending upward from 700 feet above the surface at Farington Field Airport, Auburn, NE. Interested parties were invited to participate in this rulemaking effort by submitting written comments on the proposal to the FAA. One comment was received. The comment was not germane to the proposed rule change.

This document amends FAA Order 7400.11C, Airspace Designations and Reporting Points, dated August 13, 2018, and effective September 15, 2018. FAA Order 7400.11C is publicly available as listed in the ADDRESSES section of this document. FAA Order 7400.11C lists Class A, B, C, D, and E airspace areas, air traffic service routes, and reporting points.

This amendment to Title 14 Code of Federal Regulations (14 CFR) part 71 establishes Class E airspace extending upward from 700 feet above the surface within a 6.4-mile radius of Farington Field Airport, Auburn, NE, to accommodate new standard instrument approach procedures developed for the airport, for the safety and management of instrument flight rules (IFR) operations.

The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current, is non-controversial and unlikely to result in adverse or negative comments. It, therefore: (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); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. Since this is a routine matter that only affects air traffic procedures and air navigation, it is certified that this rule, when promulgated, does not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

The FAA has determined that this action qualifies for categorical exclusion under the National Environmental Policy Act in accordance with FAA Order 1050.1F, “Environmental Impacts: Policies and Procedures,” paragraph 5-6.5.a. This airspace action is not expected to cause any potentially significant environmental impacts, and no extraordinary circumstances exist that warrant preparation of an environmental assessment.

In consideration of the foregoing, the Federal Aviation Administration amends 14 CFR part 71 as follows:

The Federal Civil Penalties Inflation Adjustment Act of 1990, as amended by the Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015 (collectively, “the Act”), codified at 28 U.S.C. 2461 note (LEXIS through Pub. L. 115-90, approved 12/8/17), requires Federal agencies to adjust their civil monetary penalty (CMP) rates for inflation every year.

In accordance with sections 4 and 5 of the Act, the annual CMP inflation adjustment for 2019 is based on the percent change in the Consumer Price Index for all Urban Consumers (CPI-U) between October 2017 and October 2018. The CPI-U for October 2017 was 246.663, and for October 2018 was 252.885, for an increase of 2.522%. In accordance with section 5(a) of the Act, the new maximum CMP rates must be rounded to the nearest whole dollar. In accordance with section 6 of the Act, the new maximum penalty rates will apply only to CMPs, including those which are associated with violations predating the increase, that are assessed after the date the increase takes effect.

ONRR assesses CMPs under the Federal Oil and Gas Royalty Management Act, 30 U.S.C. 1719, and our regulations at 30 CFR part 1241. We calculate and assess CMPs per violation, at the applicable rate, for each day such violation continues.

This final rule increases the maximum CMP rates for each of the four categories of violations identified in 30 U.S.C. 1719(a)-(d) and 30 CFR part 1241. The following list identifies the existing ONRR regulations containing CMP rates and shows those rates before and after this increase.

Executive Order (E.O.) 12866 provides that the Office of Information and Regulatory Affairs (OIRA) in OMB will review all significant rules. OIRA has determined that this rule is not significant.

E.O. 13563 reaffirms the principles of E.O. 12866, while calling for improvements in the Nation's regulatory system to promote predictability, to reduce uncertainty, and to use the best, most innovative, and least burdensome tools for achieving regulatory ends. E.O. 13563 directs agencies to consider regulatory approaches that reduce burdens and maintain flexibility and freedom of choice for the public where these approaches are relevant, feasible, and consistent with regulatory objectives. E.O. 13563 emphasizes further that regulations must be based on the best available science and that the rulemaking process must allow for public participation and an open exchange of ideas. We developed this rule in a manner consistent with these requirements.

This rule will not have a significant economic effect on a substantial number of small entities under the Regulatory Flexibility Act (RFA, 5 U.S.C. 601 et seq. ) because the rule only makes adjustments for inflation. The Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015 requires agencies to adjust civil penalties with an annual inflation adjustment. Therefore, the RFA does not apply to this rulemaking.

This rule is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. This rule:

a. Does not have an annual effect on the economy of $100 million or more.

b. Will not cause a major increase in costs or prices for consumers; individual industries; Federal, State, local government agencies; or geographic regions.

c. Does not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of United States-based enterprises to compete with foreign-based enterprises.

This rule does not impose an unfunded mandate on State, local, or Tribal governments or the private sector of more than $100 million per year. This rule does not have a significant or unique effect on State, local, or Tribal governments or the private sector. Therefore, we are not required to provide a statement containing the information that the Unfunded Mandates Reform Act (2 U.S.C. 1531 et seq. ) requires because this rule is not an unfunded mandate.

This rule does not result in a taking of private property or otherwise have taking implications under E.O. 12630. Therefore, this rule does not require a takings implication assessment.

Under the criteria in section 1 of E.O. 13132, this rule does not have sufficient Federalism implications to warrant the preparation of a Federalism summary impact statement. Therefore, this rule does not require a Federalism summary impact statement.

This rule complies with the requirements of E.O. 12988. Specifically, this rule:

a. Meets the criteria of section 3(a), which requires that we review all regulations to eliminate errors and ambiguity and to write them to minimize litigation.

b. Meets the criteria of section 3(b)(2), which requires that we write all regulations in clear language using clear legal standards.

The Department strives to strengthen its government-to-dash;government relationship with the Indian Tribes through a commitment to consultation with the Indian Tribes and recognition of their right to self-governance and Tribal sovereignty. Under the Department's consultation policy and the criteria in E.O. 13175, we evaluated this rule and determined that it will have no substantial direct effects on Federally-recognized Indian Tribes and does not require consultation.

This rule:

(a) Does not contain any new information collection requirements.

(b) Does not require a submission to OMB under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. ). See 5 CFR 1320.4(a)(2).

This rule does not constitute a major Federal action significantly affecting the quality of the human environment. We are not required to provide a detailed statement under NEPA because this rule qualifies for categorical exclusion under 43 CFR 46.210(i) in that this rule is “. . . of an administrative, financial, legal, technical, or procedural nature . * * *” We also have determined that this rule is not involved in any of the extraordinary circumstances listed in 43 CFR 46.215 that would require further analysis under NEPA.

This rule is not a significant energy action under the definition in E.O. 13211 and, therefore, does not require a Statement of Energy Effects.

We are required by E.O. 12866 (section 1(b)(12)), E.O. 12988 (section 3(b)(1)(B)), and E.O. 13563 (section 1(a)), and by the Presidential Memorandum of June 1, 1998, to write all rules in plain language. This means that each rule we publish must:

(a) Be logically organized.

(b) Use the active voice to address readers directly.

(c) Use common, everyday words and clear language rather than jargon.

(d) Be divided into short sections and sentences.

(e) Use lists and tables wherever possible.

If you feel that we have not met these requirements, send your comments to Luis.Aguilar@onrr.gov. Your comments should be as specific as possible. For example, you should tell us the numbers of the sections or paragraphs that you find unclear, which sections or sentences are too long, the sections where you feel lists or tables would be useful, etc.

The Act requires agencies to publish annual inflation adjustments by no later than January 15 of each year, notwithstanding section 553 of the Administrative Procedure Act (APA) (5 U.S.C. 553). OMB has interpreted this direction to mean that the usual APA public procedure for rulemaking—which includes public notice of a proposed rule, an opportunity for public comment, and a delay in the effective date of a final rule—is not required when agencies issue regulations to implement the annual adjustments to civil penalties that the Act requires. Accordingly, we are issuing the 2019 annual adjustments as a final rule without prior notice or an opportunity for comment and with an effective date immediately upon publication in the Federal Register .

Section 553(b) of the Administrative Procedure Act (APA) provides that, when an agency for good cause finds that “notice and public procedure . . . are impracticable, unnecessary, or contrary to the public interest,” the agency may issue a rule without providing notice and an opportunity for prior public comment. Under section 553(b), ONRR finds that there is good cause to promulgate this rule without first providing for public comment. ONRR is promulgating this final rule to implement the statutory directive in the Act, which requires agencies to publish a final rule and to update the civil penalty amounts by applying a specified formula. We have no discretion to vary the amount of the adjustment to reflect any views or suggestions provided by commenters. Accordingly, it would serve no purpose to provide an opportunity for public comment on this rule prior to promulgation. Thus, providing for notice and public comment is unnecessary.

Furthermore, ONRR finds under section 553(d)(3) of the APA that good cause exists to make this direct final rule effective immediately upon publication in the Federal Register . In the Act, Congress expressly required Federal agencies to publish annual inflation adjustments to civil penalties in the Federal Register no later than January 15 of every year, notwithstanding section 553 of the APA. Under the statutory framework and OMB guidance, the new penalty levels are to take effect immediately upon publication. Moreover, an effective date after January 15 would delay application of the new penalty levels, contrary to Congress's intent.

For the reasons discussed in the preamble, ONRR amends 30 CFR part 1241 as set forth below:

The Coast Guard is issuing this final rule wthout prior notice and opportunity to comment pursuant to authority under section 4(a) of the Administrative Procedure Act (APA) (5 U.S.C. 553(b)). This provision authorizes an agency to issuse a rule without prior notice and opportunity to comment when the agency for good cause finds that those procedures are “impracticable, unnecessary, or contrary to the public interest.” Under 5 U.S.C. 553(b), the Coast Guard finds that good cause exists for not publishing a notice of proposed rulemaking (NPRM) with respect to this rule because the New York City Highway Bridge, that once required draw operations in 33 CFR 117.795(b), was replaced with a fixed bridge in December 2017. It is unnecessary to publish a NPRM because this regulatory action does not purport to place any restrictions on mariners but rather removes a restriction that has no further use or value.

We are issuing this rule under 5 U.S.C. 553(d)(3). The Coast Guard finds that good cause exists for making this rule effective in less than 30 days after publication in the Federal Register . The bridge has been a fixed bridge for 12 months and this rule merely requires an administrative change to the Federal Register , in order to omit a regulatory requirement that is no longer applicable or necessary. The modification has already taken place and the removal of the regulation will not affect mariners currently operating on this waterway. Therefore, a delayed effective date is unnecessary.

The Coast Guard is issuing this rule under authority 33 U.S.C. 499.

The New York City Higwahy Bridge across Mill Basin, mile 0.8 was removed and replaced with a fixed bridge in December 2017. It has come to the attention of the Coast Guard that the governing regulation for this drawbridge was never removed subsequent to the completion of the fixed bridge that replaced it. The elimination of this drawbridge necessitates the removal of the drawbridge operation regulation, 33 CFR 117.795(b), that pertains to the former drawbridge.

The purpose of this rule is to remove the section 33 CFR 117.795(b), that refers to the New York City Highway Bridge at mile 0.8, from the Code of Federal Regulations since it governs a bridge that is no longer able to be opened.

The Coast Guard is changing the regulation in 33 CFR 117.795(b) by removing restrictions and the regulatory burden related to the draw operations for this bridge that is no longer a drawbridge. The change removes the section 33 CFR 117.795(b) of the regulation governing the New York City Highway Bridge since the bridge has been replaced with a fixed bridge. This Final Rule seeks to update the Code of Federal Regulations by removing language that governs the operation of the New York City Highway Bridge, which in fact is no longer a drawbridge. This change does not affect nor does it alter the operating schedules in 33 CFR 117.795 that govern the remaining active drawbridges on Jamaica Bay and connecting waterways.

We developed this rule after considering numerous statutes and Executive Orders related to rulemaking. Below we summarize our analyses based on a number of these statutes and Executive Orders, and we discuss First Amendment rights of protesters.

Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits. Executive Order 13771 directs agencies to control regulatory costs through a budgeting process. This rule has not been designated a “significant regulatory action,” under Executive Order 12866. Accordingly, it has not been reviewed by the Office of Management and Budget (OMB) and pursuant to OMB guidance it is exempt from the requirements of Executive Order 13771.

This regulatory action determination is based on the fact that the bridge was replaced by a fixed bridge and no longer operates as a drawbridge. The removal of the operating schedule from 33 CFR part 117 subpart B will have no effect on the movement of waterway or land traffic.

The Regulatory Flexibility Act of 1980 (RFA), 5 U.S.C. 601-612, as amended, requires federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. The Coast Guard certifies under 5 U.S.C. 605(b) that this rule will not have a significant economic impact on a substantial number of small entities.

For the reasons stated in section IV.A above this final rule would not have a significant economic impact on any vessel owner or operator.

Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we want to assist small entities in understanding this rule. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the FOR FURTHER INFORMATION CONTACT , above.

Small businesses may send comments on the actions of Federal employees who enforce, or otherwise determine compliance with, Federal regulations to the Small Business and Agriculture Regulatory Enforcement Ombudsman and the Regional Small Business Regulatory Fairness Boards. The Ombudsman evaluates these actions annually and rates each agency's responsiveness to small business. If you wish to comment on actions by employees of the Coast Guard, call 1-888-REG-FAIR (1-888-734-3247). The Coast Guard will not retaliate against small entities that question or complain about this rule or any policy or action of the Coast Guard.

This rule calls for no new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).

A rule has implications for federalism under Executive Order 13132, Federalism, if it has 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. We have analyzed this rule under that Order and have determined that it is consistent with the fundamental federalism principles and preemption requirements described in Executive Order 13132.

Also, this rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it does not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes.

The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this rule will not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.

We have analyzed this rule under Department of Homeland Security Management Directive 023-01 and Commandant Instruction M16475.lD, which guides the Coast Guard in complying with the National Environmental Policy Act of 1969 (NEPA)(42 U.S.C. 4321-4370f), and have made a determination that this action is one of a category of actions which do not individually or cumulatively have a significant effect on the human environment. This rule simply promulgates the operating regulations or procedures for drawbridges. This action is categorically excluded from further review, under figure 2-1, paragraph (32)(e), of the Instruction.

A preliminary Record of Environmental Consideration and a Memorandum for the Record are not required for this rule.

The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to contact the person listed in the For Further Information Contact section to coordinate protest activities so that your message can be received without jeopardizing the safety or security of people, places or vessels.

Bridges.

For the reasons discussed in the preamble, the Coast Guard amends 33 CFR part 117 as follows:

On November 26, 2018, the North Carolina Department of Transportation (NCDOT) provided the Coast Guard with details concerning the demolition of the old Herbert C. Bonner Bridge. Demolition will not follow a set schedule due to sea conditions, equipment needs, and vessel navigation considerations. In addition, demolition will take place in two locations at once due to equipment types and demolition methods. NCDOT has determined that a moving safety zone is needed in Oregon Inlet within 100 yards of active demolition work and demolition equipment. In response, on December 18, 2018, the Coast Guard published a notice of proposed rulemaking (NPRM) titled Safety Zone; Oregon Inlet, Dare County, NC (83 FR 64771). There, we stated why we issued the NPRM, and invited comments on our proposed regulatory action related to the demolition of the old Herbert C. Bonner Bridge. During the comment period that ended January 17, 2019, we received no comments. However, during the comment period, NCDOT requested a new effective period from the beginning of March through March 30, 2020, instead of between February 1, 2019, and February 29, 2020, as proposed in the NPRM.

Under 5 U.S.C. 553(d)(3), the Coast Guard finds that good cause exists for making this rule effective less than 30 days after publication in the Federal Register . Delaying the effective date of this rule would be impracticable and contrary to the public interest because immediate action is needed protect persons, vessels, and the marine environment on the navigable waters of Oregon Inlet during the demolition of the old Herbert C. Bonner Bridge in Dare County, NC.

The Coast Guard is issuing this rule under authority in 33 U.S.C. 1231. The COTP North Carolina has determined that potential safety hazards associated with the demolition of the old Herbert C. Bonner Bridge would be a concern for anyone transiting Oregon Inlet. The purpose of this rule is to protect persons, vessels, and the marine environment in Oregon Inlet during the demolition of the old Herbert C. Bonner Bridge.

As noted above, we received no comments on our NPRM published December 18, 2018. There is a minor change in the regulatory text of this rule from the proposed rule, shifting the demolition period start and end dates back by one month. The demolition will occur from the beginning of March through March 30, 2020, instead of between February 1, 2019, and February 29, 2020.

This rule establishes a moving safety zone to be enforced during active demolition work from March 4, 2019, through March 30, 2020. Demolition will not follow a set schedule due to changing sea conditions, equipment needs, and vessel navigation considerations. In addition, demolition will take place in two locations at once due to equipment types and demolition methods, the exact times of activation will be announced via Broadcast Notices to Mariners at least 48 hours prior to enforcement. The moving safety zone will include all navigable waters within 100 yards of active demolition work and demolition equipment in Oregon Inlet along the old Herbert C. Bonner Bridge, which follows a line beginning at approximate position 35°46′47″ N, 75°32′41″ W, then southeast to 35°46′37″ N, 75°32′33″ W then southeast to 35°46′09″ N, 75°31′59″ W, then southeast to 35°46′03″ N, 75°31′51″ W, then southeast to 35°460′1″ N, 75°31′40″ W. (NAD 1983). This zone is intended to protect persons, vessels, and the marine environment on the navigable waters in Oregon Inlet during the demolition of the old Herbert C. Bonner Bridge. No vessel or person will be permitted to enter the safety zone during the designated times. There will be alternative navigation options for vessel traffic when a moving safety zone that covers all or part of the navigation channel is being enforced.

We developed this rule after considering numerous statutes and Executive orders related to rulemaking. Below we summarize our analyses based on a number of these statutes and Executive orders, and we discuss First Amendment rights of protestors.

Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits. Executive Order 13771 directs agencies to control regulatory costs through a budgeting process. This rule has not been designated a “significant regulatory action,” under Executive Order 12866. Accordingly, this rule has not been reviewed by the Office of Management and Budget (OMB), and pursuant to OMB guidance it is exempt from the requirements of Executive Order 13771.

This regulatory action determination is based on the size, location, and duration of the safety zone. Vessel traffic will not be allowed to enter or transit portions of Oregon Inlet during active demolition work, to be conducted from March 4, 2019, through March 30, 2020. The specific enforcement times for active demolition work will be broadcast at least 48 hours in advance and vessels will be able to transit Oregon Inlet at all other times. The Coast Guard will issue a Local Notice to Mariners and transmit a Broadcast Notice to Mariners via VHF-FM marine channel 16 regarding the safety zone. There will be alternative navigation options for vessel traffic when a moving safety zone covers all or part of the navigation channel. Vessel traffic in this portion of Oregon Inlet will fluctuate between high, medium, and low depending on the time of the year. This rule does not allow vessels to request permission to enter the moving safety zone covering the active demolition areas within Oregon Inlet during the designated times.

The Regulatory Flexibility Act of 1980, 5 U.S.C. 601-612, as amended, requires Federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. The Coast Guard received no comments from the Small Business Administration on this rulemaking. The Coast Guard certifies under 5 U.S.C. 605(b) that this rule will not have a significant economic impact on a substantial number of small entities.

While some owners or operators of vessels intending to transit the safety zone may be small entities, for the reasons stated in section V.A above, this rule will not have a significant economic impact on any vessel owner or operator.

Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we want to assist small entities in understanding this rule. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the FOR FURTHER INFORMATION CONTACT section.

Small businesses may send comments on the actions of Federal employees who enforce, or otherwise determine compliance with, Federal regulations to the Small Business and Agriculture Regulatory Enforcement Ombudsman and the Regional Small Business Regulatory Fairness Boards. The Ombudsman evaluates these actions annually and rates each agency's responsiveness to small business. If you wish to comment on actions by employees of the Coast Guard, call 1-888-REG-FAIR (1-888-734-3247). The Coast Guard will not retaliate against small entities that question or complain about this rule or any policy or action of the Coast Guard.

This rule will not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).

A rule has implications for federalism under Executive Order 13132, Federalism, if it has 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. We have analyzed this rule under that Order and have determined that it is consistent with the fundamental federalism principles and preemption requirements described in Executive Order 13132.

Also, this rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it does not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes. If you believe this rule has implications for federalism or Indian tribes, please contact the person listed in the FOR FURTHER INFORMATION CONTACT section.

The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this rule will not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.

We have analyzed this rule under Department of Homeland Security Directive 023-01 and Commandant Instruction M16475.1D, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (42 U.S.C. 4321-4370f), and have determined that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This rule involves a 100-yard radius moving safety zone lasting from March 4, 2019, through March 30, 2020, that will prohibit entry into a portion of Oregon Inlet for bridge demolition. It is categorically excluded from further review under paragraph L60(a) of Appendix A, Table 1 of DHS Instruction Manual 023-01-001-01, Rev. 01. A Record of Environmental Consideration supporting this determination is available in the docket where indicated under ADDRESSES .

The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to contact the person listed in the FOR FURTHER INFORMATION CONTACT section to coordinate protest activities so that your message can be received without jeopardizing the safety or security of people, places or vessels.

For the reasons discussed in the preamble, the Coast Guard amends 33 CFR part 165 as follows:

This section provides an overview of the action, including a summary of the amendments and their estimated impacts as well as information concerning potentially affected entities and statutory authority.

Section II provides a summary of the proposal for this action, including background information. In section III, EPA summarizes and responds to comments received on the proposal. EPA's final action is set forth in section IV, and section V discusses the estimated impacts of the amendments. Section VI addresses reviews required under various statutes and executive orders as well as determinations concerning applicable rulemaking and judicial review provisions.

On September 27, 2018, EPA published in the Federal Register a proposal  1 to amend the existing NO X SIP Call regulations  2 to allow states to amend their SIPs, for NO X SIP Call purposes only, to establish emissions monitoring requirements for certain units other than requirements to monitor according to 40 CFR part 75. This action finalizes the amendment generally as proposed, with minor further revisions discussed in section IV of this document. Ultimately, such alternate monitoring requirements could be made available to sources through states' revisions to their SIPs, with consequent potential reductions in some units' monitoring costs. The group of units affected under the SIPs adopted to meet the NO X SIP Call comprises both existing and new electricity generating units (EGUs) as well as certain other existing and new industrial units (non-EGUs). Within this overall group, the set of existing units potentially affected by the amendment includes approximately 285 non-EGU boilers and combustion turbines and approximately 30 EGUs—specifically, combustion turbines that are considered large EGUs for NO X SIP Call purposes and that are not required to monitor according to part 75 under other programs such as the Acid Rain Program or a Cross-State Air Pollution Rule (CSAPR) trading program. States, not EPA, will decide whether to revise the monitoring requirements in their SIPs as allowed under this amendment, and EPA lacks complete information on the remaining monitoring requirements that the sources would face if a state decides to make such revisions, leaving considerable uncertainty regarding the amount of monitoring cost reductions that may occur. However, using information from comments and assumptions concerning the sources' remaining monitoring requirements, EPA estimates annual monitoring cost reductions from this action in the range of $1.2 million to $3.3 million. Because this action is not expected to cause any change in emissions or air quality, the monitoring cost reductions will constitute net benefits from the action.

In addition, EPA is eliminating several obsolete provisions of the NO X SIP Call regulations that no longer have any substantive effect on the regulatory requirements faced by states or sources and is making clarifying amendments—all of which EPA considers non-substantive—to the remaining regulations. The additional amendments also include updates to several cross-references in the CSAPR regulations that refer to an obsolete provision of the NO X SIP Call regulations. The specific additional amendments discussed in the proposal are identified in section II.C. of this document, and the amendments are being finalized generally as proposed, with minor further revisions discussed in section IV of this document.

This action does not apply directly to any emissions sources but instead amends existing regulatory requirements applicable to the SIPs of Alabama, Connecticut, Delaware, Illinois, Indiana, Kentucky, Maryland, Massachusetts, Michigan, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Rhode Island, South Carolina, Tennessee, Virginia, West Virginia, and the District of Columbia. If an affected jurisdiction chooses to revise its SIP in response to these amendments, sources in the jurisdiction could be indirectly affected if they are subject to emissions monitoring requirements for purposes of the NO X SIP Call and are not independently subject to comparable requirements under another program such as the Acid Rain Program or a CSAPR trading program. Generally, the types of sources that could be indirectly affected are fossil fuel-fired boilers and stationary combustion turbines with heat input capacities over 250 million British thermal units per hour (mmBtu/hr) or serving electricity generators with capacities over 25 megawatts (MW). Sources meeting these criteria operate in a variety of industries, including but not limited to the following:

Statutory authority for this action is provided by Clean Air Act (CAA) sections 110 and 301, 42 U.S.C. 7410 and 7601, which also provided statutory authority for issuance of the existing NO X SIP Call regulations that EPA is amending in this action. 3

This section summarizes the proposal for this action. Section II.A. repeats some of the background information from the proposal. Section II.B. addresses the proposed amendment to the NO X SIP Call's emissions monitoring requirements, reiterating the proposed rationale and summarizing the proposal's discussion of projected impacts. Sections II.C. and II.D. summarize the remaining proposed amendments and describe the public comment process.

Under the CAA, EPA establishes and periodically revises national ambient air quality standards (NAAQS) for certain pollutants, including ground-level ozone, while states have primary responsibility for attaining the NAAQS through the adoption of emission control measures in their SIPs. Under CAA section 110(a)(2)(D)(i)(I), 42 U.S.C. 7410(a)(2)(D)(i)(I), often called the “good neighbor” provision, each state is required to include provisions in its SIP prohibiting emissions that “will . . . contribute significantly to nonattainment in, or interfere with maintenance by, any other State with respect to any [NAAQS].” In 1998, EPA issued the NO X SIP Call (the Rule) identifying good neighbor obligations with respect to the 1979 1-hour ozone NAAQS and calling for SIP revisions to address those obligations. 4 The Rule's regulatory text was codified at 40 CFR 51.121, addressing the required SIP revisions, and 40 CFR 51.122, addressing states' periodic reporting requirements. As implemented, the Rule required 20 states and the District of Columbia  5 to revise their SIPs to reduce their sources' emissions of NO X , an ozone precursor, during the May-September “ozone season” starting in 2004.

To implement the NO X SIP Call's emissions reduction requirements, EPA promulgated a “budget” for the statewide seasonal NO X emissions from each covered state. Each state's emissions budget was calculated as the state's projected 2007 pre-control or “baseline” emissions inventory minus the state's required emissions reduction. The Rule did not mandate that states follow any particular approach for achieving their required emissions reductions. Instead, states retained wide discretion regarding which sources in their states to control and what control measures to employ. Each state was simply required to demonstrate that whatever control measures it chose to include in its SIP revision would be sufficient to ensure that projected 2007 statewide seasonal NO X emissions from its sources would not exceed its emissions budget.

Besides the general flexibility given to states regarding the choices of sources and control measures, the NO X SIP Call included additional provisions designed to increase compliance flexibility. Most notably, the Rule allowed states to adopt interstate emission allowance trading programs as control measures to accomplish some or all of the required emissions reductions. EPA also provided a model rule for an EPA-administered interstate trading program—the NO X Budget Trading Program (NBTP)—that would meet all the Rule's SIP approval criteria for a trading program for two types of sources: Fossil fuel-fired EGU boilers and combustion turbines serving electricity generators with capacity ratings greater than 25 MW (large EGUs), and fossil fuel-fired non-EGU boilers and combustion turbines with heat input ratings greater than 250 mmBtu/hr (large non-EGU boilers and turbines).

While generally oriented toward providing states and sources with compliance flexibility, the NO X SIP Call also included two conditional provisions that would become mandatory SIP requirements for large EGUs and large non-EGU boilers and turbines if states chose to include any emission control measures for these types of sources in their SIP revisions. First, under § 51.121(f)(2), any control measures imposed on these types of sources would be required to include enforceable limits on the sources' seasonal NO X mass emissions. These limits could take several forms, including either limits on individual sources or collective limits on the group of all such sources in a state. Second, under § 51.121(i)(4), these sources would be required to monitor and report their seasonal NO X mass emissions according to the provisions of 40 CFR part 75. 6 One way a state could meet these two SIP requirements was to adopt the NBTP, because the NBTP included provisions addressing both requirements and was expressly designed as a potential control measure for these types of sources.

All the jurisdictions subject to the NO X SIP Call as implemented ultimately chose to adopt the NBTP for large EGUs and large non-EGU boilers and turbines as part of their required SIP revisions. By adopting control measures applicable to large EGUs and large non-EGU boilers and turbines into their SIPs, all the affected jurisdictions triggered the obligations for their SIPs to include enforceable mass emissions limits and part 75 monitoring requirements for these types of sources. These requirements have remained in effect despite the discontinuation of the NBTP following the 2008 ozone season. 7

The NBTP was implemented starting in 2003 for sources in several northeastern states and in 2004 for sources in most of the remaining NO X SIP Call states. Missouri sources joined the NBTP in 2007, and EPA continued to administer the NBTP through the 2008 ozone season. Since the 2008 ozone season, EPA has replaced the NBTP with a series of three similar interstate emission allowance trading programs designed to address eastern states' good neighbor obligations with respect to ozone NAAQS more recent than the 1979 1-hour ozone NAAQS. The NBTP's three successor seasonal NO X trading programs were established under the Clean Air Interstate Rule (CAIR), 8 which was remanded to EPA for replacement;  9 the original CSAPR, 10 which replaced CAIR; and most recently the CSAPR Update. 11 The seasonal NO X trading programs established under CAIR and the original CSAPR were both designed to address the 1997 8-hour ozone NAAQS, while the trading program established under the CSAPR Update was designed to address the 2008 8-hour ozone NAAQS. The CAIR seasonal NO X trading program operated from 2009 through 2014, the original CSAPR seasonal NO X trading program started operating in 2015, 12 and the CSAPR Update trading program started operating in 2017.

For purposes of this action, the most important difference between the NBTP and its successor seasonal NO X trading programs concerns the types of sources participating in the various programs. As discussed above, the NBTP was designed to cover both large EGUs and large non-EGU boilers and turbines. In contrast, by default the three successor trading programs have covered only units considered EGUs under those programs, which generally means all units that would be classified as NO X SIP Call large EGUs as well as a small subset of the units that would be classified as NO X SIP Call large non-EGU boilers and turbines. 13 Under the CAIR seasonal NO X trading program, most NO X SIP Call states exercised an option to expand program applicability to include all their NO X SIP Call large non-EGU boilers and turbines, but the option was eliminated under the original CSAPR seasonal NO X trading program and no state has exercised the restored option made available under the CSAPR Update trading program. Consequently, at present most NO X SIP Call large non-EGU boilers and turbines do not participate in a successor trading program to the NBTP.

The second relevant difference between the NBTP and its successor trading programs concerns the various programs' geographic areas of coverage. At present, EGUs in fourteen NO X SIP Call states participate in the CSAPR Update trading program. 14 EGUs in the remaining seven NO X SIP Call jurisdictions do not currently participate in a successor trading program to the NBTP, although most such units are subject to other EPA programs with comparable part 75 monitoring requirements. 15

In the CAIR rulemaking, EPA amended the NO X SIP Call regulations both to provide that the NBTP would be discontinued upon implementation of the CAIR seasonal NO X trading program and to require states to adopt replacement control measures into their SIPs to ensure continued achievement of the portions of their NO X SIP Call emissions reduction requirements that had been met through the NBTP. 16 As noted above, notwithstanding the discontinuation of the NBTP, the NO X SIP Call's requirements for enforceable mass emissions limits and part 75 monitoring have continued to apply to large EGUs and large non-EGU boilers and turbines in all affected states. Since the CAIR rulemaking, EPA has worked with NO X SIP Call states individually to assist them in revising their SIPs to meet these ongoing NO X SIP Call requirements, whether through use of the NBTP's successor trading programs (to the extent those options have been available) or through other replacement control measures.

Under CAA section 107(d)(3)(E), 42 U.S.C. 7407(d)(3)(E), redesignation of an area to attainment of a NAAQS requires a determination that the improvement in air quality is due to “permanent and enforceable” emissions reductions. At least 140 EPA final actions redesignating areas in 20 states to attainment with an ozone NAAQS or a fine particulate matter (PM 2.5 ) NAAQS—because NO X is a precursor to PM 2.5 as well as ozone—have relied in part on the NO X SIP Call's emissions reductions. 17 In this action, to avoid any possible argument that amendments to the NO X SIP Call might result in a lessening of permanence and enforceability that could threaten continued reliance on the Rule's emissions reductions to support other actions, EPA is not substantively amending the Rule's key provisions supporting these attributes. These key provisions include the statewide emissions budgets and general enforceability and monitoring requirements as well as the requirements for enforceable limits on seasonal NO X mass emissions from large EGUs and large non-EGU boilers and turbines. 18 As discussed in section II.B. of this document, EPA believes that under current circumstances, the amendment to allow states to establish alternate monitoring requirements for large EGUs and large non-EGU boilers and turbines does not undermine assurance that the Rule's required emissions reductions will continue to be achieved and therefore does not pose a risk to the permanence and enforceability of the emissions reductions.

The only substantive amendment to the NO X SIP Call regulations proposed for this action concerns emissions monitoring requirements. Under 40 CFR 51.121(i)(4) of the regulations as originally promulgated, where a state's SIP revision contains control measures for large EGUs or large non-EGU boilers and turbines, the SIP must also require part 75 monitoring for these types of sources. As discussed in section II.A. of this document, all NO X SIP Call states triggered this requirement by including control measures in their SIPs for these types of sources, and the requirement has remained in effect despite the discontinuation of the NBTP after the 2008 ozone season. For this action, EPA proposed to amend the provision at § 51.121(i)(4) to make the inclusion of part 75 monitoring requirements for these sources in SIPs optional rather than mandatory for NO X SIP Call purposes. 19 The SIPs would still need to include some form of emissions monitoring requirements for these types of sources, consistent with the Rule's general enforceability and monitoring requirements at § 51.121(f)(1) and (i)(1), respectively, but states would no longer be required to satisfy these general Rule requirements specifically through the adoption of part 75 monitoring requirements. EPA noted that finalization of this proposed amendment would not in itself eliminate part 75 monitoring requirements for any sources but would enable EPA to approve SIP submittals replacing these requirements for NO X SIP Call purposes with other forms of monitoring requirements.

In the proposal, EPA discussed the following rationale for the proposed amendment to emissions monitoring requirements. 20 The condition that SIPs must include part 75 monitoring requirements was established based on determinations that, first, a requirement for mass emissions limits for large EGUs and large non-EGU boilers and turbines was feasible and provided the greatest assurance that the NO X SIP Call's required emissions reductions would be achieved, and second, part 75 monitoring was a feasible and cost-effective way to ensure compliance with the mass emissions limits for these sources. 21 (Part 75 monitoring requirements were also established independently as an essential element of the now-discontinued NBTP, which like EPA's other emission allowance trading programs could function only with timely reporting of consistent, quality-assured mass emissions data by all participating units.) To ensure that the NO X SIP Call's emissions reductions can continue to be relied on as permanent and enforceable for purposes of other actions, EPA did not propose to amend the Rule's existing requirements regarding enforceable mass emissions limits for these sources. However, EPA proposed the view that under current circumstances, allowing states to establish alternate monitoring requirements for large EGUs and large non-EGU boilers and turbines would not pose a risk to the permanence and enforceability of the Rule's emissions reductions.

The first relevant current circumstance EPA discussed was the substantial margins by which all NO X SIP Call states are now complying with the portions of their statewide emissions budgets assigned to large EGUs and large non-EGU boilers and turbines. As shown in Table 1 of the proposal, which is reproduced without change as Table 1 of this document, in 2017, seasonal NO X emissions from sources that would have been subject to the NBTP across the region covered by the NO X SIP Call were approximately 200,000 tons, which is less than 40% of the sum of the relevant portions of the statewide final NO X budgets. Table 1 also shows that no state's reported emissions exceeded 71% of the relevant portion of its budget. 22 As noted by EPA, these comparisons demonstrate that the Rule's required emissions reductions would continue to be achieved even with substantial increases in emissions from current levels. EPA also observed that the possibility of such large increases in emissions is remote because of requirements under other state and Federal environmental programs  23 and changes to the fleet of affected sources since 2008. 24

The second relevant current circumstance EPA discussed was that even with the proposed amendment, part 75 monitoring requirements would remain in effect for most NO X SIP Call large EGUs pursuant to other regulatory requirements, including the Acid Rain Program and the CSAPR trading programs, and these large EGUs are responsible for most of the collective emissions of NO X SIP Call large EGUs and large non-EGU boilers and turbines. Table 1 shows the portions of the reported seasonal NO X emissions for each state reported by units that would continue to be subject to part 75 monitoring requirements even if the proposed amendments are finalized and all states choose to revise their SIPs. 25 As indicated in the table, the sources that would continue to report under part 75 account for over 90% of the overall emissions. If a state chooses to revise its SIP to no longer require part 75 monitoring for some sources, then under § 51.121(f)(1) and (i)(1)—which EPA did not propose to amend—the SIP would still have to include provisions requiring all large EGUs and large non-EGU boilers and turbines subject to control measures for purposes of the NO X SIP Call to submit other forms of information on their seasonal NO X emissions sufficient to ensure compliance with the control measures. EPA stated the belief that in the context of the substantial compliance margins discussed above, and given the continued availability of part 75 monitoring data from sources responsible for most of the relevant emissions, emissions data from the remaining sources submitted pursuant to other forms of monitoring requirements can provide sufficient assurance that the Rule's overall required emissions reductions will continue to be achieved.

In the proposal's discussion of projected impacts, 26 EPA stated the expectation that the proposed amendments, if finalized, would have no impact on emissions or air quality because no changes would be made to any of the NO X SIP Call's existing regulatory requirements related to statewide emissions budgets or enforceable mass emissions limits for large EGUs and large non-EGU boilers and turbines.

With respect to cost impacts, EPA expressed the expectation that, if the proposed amendment to monitoring requirements is finalized, at least some states would revise their SIPs to establish alternate monitoring requirements and at least some sources would experience reductions in monitoring costs. EPA indicated that there were approximately 310 existing large EGUs and large non-EGU boilers and turbines in NO X SIP Call states that could potentially be affected by the proposed amendment to monitoring requirements if all affected states were to revise their SIPs. The discussion also indicated how many of these units used each of the principal monitoring methodologies allowed under part 75 according to the monitoring plans submitted for the units. Specifically, EPA noted that approximately 90 units used monitoring methodologies involving continuous emissions monitoring systems (CEMS) to measure both stack gas flow rate and the concentrations of certain gases in the effluent gas stream, approximately 140 units used methodologies involving gas concentration CEMS but not stack gas flow rate CEMS, and approximately 80 units used non-CEMS methodologies. The proposal noted that it was not possible to predict the amount of the monitoring cost reductions that might eventually result from finalization of the proposed monitoring amendment because states, not EPA, would decide whether to revise the monitoring requirements in their SIPs and because EPA lacks information on the remaining monitoring requirements that sources would face. However, EPA qualitatively discussed how alternate monitoring requirements could result in reduced costs for units currently using the various part 75 monitoring methodologies. For example, some units that currently use part 75 monitoring methodologies involving the use of stack gas flow rate CEMS might be allowed to discontinue use of those CEMS, some units that currently use part 75 monitoring methodologies involving the use of gas concentration CEMS might be allowed to discontinue use of those CEMS, and some units continuing to use one or both types of CEMS might be allowed to perform less extensive data reporting or less comprehensive quality-assurance testing. EPA expressed the expectation that units currently using non-CEMS methodologies under part 75 would experience little or no reduction in monitoring costs as a result of the proposed monitoring amendment.

In addition to the proposed amendment to the NO X SIP Call's monitoring requirements discussed in section II.B. of this document, EPA proposed to make several further amendments to the Rule's regulatory text at 40 CFR 51.121 and 51.122 to remove obsolete provisions and clarify the remaining provisions. The proposed revisions also included updates to several cross-references in the CSAPR regulations at 40 CFR 52.38 that refer to an obsolete provision of the NO X SIP Call regulations. Although EPA proposed to remove or modify numerous provisions of the NO X SIP Call regulations, 27 the proposal explained that the additional amendments were not intended to substantively alter any currently effective regulatory requirements. Briefly, EPA proposed to:

• Rescind and remove the stayed and superseded findings of good neighbor obligations with respect to the 1997 8-hour ozone NAAQS at § 51.121(a)(2), remove § 51.121(q) staying the now-rescinded findings, and remove obsolete related language in § 51.121(c)(1) and (2);

• Clarify the expression of Phase I and existing final emissions reduction requirements by removing the table of required incremental Phase II emissions reduction amounts at § 51.121(e)(3), adding a column of Phase I budget amounts to the existing table of final budget amounts in § 51.121(e)(2)(i), revising the definitions of “Phase I SIP submission” and “Phase II SIP submission” at § 51.121(a)(3)(i) and (ii), and making related revisions at § 51.121(b)(1) introductory text and (b)(1)(i);

• Remove § 51.121(e)(4), which governs the former compliance supplement pool;

• Remove § 51.121(e)(5), which sets forth a one-time process for revising the emissions inventories and budgets published as part of the original Rule;

• Remove § 51.121(g)(2)(ii), which contains an obsolete table of baseline emissions inventory information originally intended to help states prepare their required SIP revisions;

• Remove § 51.121(p) and (b)(2), which authorize the use of the former NBTP and other potential interstate trading programs, respectively, as compliance options;

• Make clarifying revisions to § 51.121(r)(2), which sets forth the post-NBTP transition requirements;

• Remove § 51.121(d)(1), which contains obsolete deadlines for Phase I and Phase II SIP submissions, and § 51.121(d)(2), which contains obsolete or duplicative procedural provisions concerning the completeness and format of SIP submissions;

• Remove or update obsolete cross-references in the NO X SIP Call regulations at §§ 51.121(b)(1)(i), (g)(2)(i) and (r)(1) and (2) and 51.122(c)(1)(ii) and in the CSAPR regulations at § 52.38(b)(8)(ii), (b)(8)(iii)(A)( 2 ), (b)(9)(ii), and (b)(9)(iii)(A)( 2 ); and

• Make clarifying editorial revisions to § 51.121 heading, (b)(1)(ii), (e)(2)(ii)(B) and (E), (f)(2)(i)(B), (f)(2)(ii), (h), (i)(2),(3), and (5), (l)(1) and (2), (m), (n), and (o).

These proposed further amendments as well as EPA's supporting rationales are fully discussed in the proposal. 28 The discussions in the proposal are incorporated herein and are not summarized further in this document except as necessary to respond to comments in sections III.B. through III.D of this document.

In the proposal, EPA requested comment on the proposed amendment to revise the provision at 40 CFR 51.121(i)(4) to allow states to establish monitoring requirements for large EGUs and large non-EGU boilers and turbines in their SIPs other than part 75 monitoring requirements. With respect to the remaining proposed amendments, EPA made clear that the amendments were not intended to substantively alter existing regulatory requirements and consequently requested comment solely on whether the provisions proposed for removal as obsolete in fact are obsolete and on whether the proposed clarifications in fact achieve clarification. EPA did not reopen for comment any provisions of the existing NO X SIP Call regulations except the provisions that were proposed to be amended as discussed in the proposal  29 and did not reopen or request comment on amending any other existing regulations. The proposal also provided information on how to request a public hearing. No public hearing was held because none was requested, and the public comment period closed on October 29, 2018.

Commenters on the proposal included states, source owners, industry associations, environmental organizations, and persons commenting as individuals. The comments are available in the docket for this action. In this section, EPA summarizes and responds to the comments regarding the proposed amendments, including requests for clarification. Sections III.A through III.D. address the proposed amendments to the NO X SIP Call's provisions concerning emissions monitoring requirements, emissions reduction requirements, the baseline emissions inventory table, and post-NBTP transition requirements, respectively.

With respect to the proposed amendments not addressed in sections III.A. through III.D., EPA received no adverse comments or requests for clarification. One commenter stated no objection to or supported most of these amendments individually, and additional commenters expressed general support for all the amendments removing obsolete provisions or all the amendments clarifying the remaining regulations. EPA thanks the commenters for these comments, which are not discussed further in this document.

Some commenters also submitted comments on topics other than the NO X SIP Call regulations. These comments are outside the scope of the proposal and are not discussed further in this document.

Comment: Most commenters supported the proposed amendment to the NO X SIP Call's monitoring requirements. These commenters generally expressed the view that requirements to perform part 75 monitoring solely for purposes of the NO X SIP Call are no longer necessary to ensure states' compliance with the Rule's emissions reduction requirements. Most of these commenters also generally indicated that allowing the use of alternate monitoring requirements would result in reduced monitoring costs for some sources.

Response: EPA agrees with these comments' support for the proposed amendment to the Rule's monitoring requirements.

Comment: Some commenters, while generally supporting the proposed monitoring amendment, stated that EPA should also make further amendments to the NO X SIP Call's monitoring provisions to authorize particular forms of alternate monitoring requirements. Specifically, two commenters requested an amendment providing that, if a demonstration is made that emissions from a state's large non-EGU boilers and turbines “will not exceed the [emissions] budget . . . established” for such sources, then those sources would be allowed to determine reported NO X emissions according to a methodology based on the use of emission factors—that is, factors approved as estimates of the quantity of NO X emitted per unit of fuel combusted—and information on fuel consumption. Another commenter requested an amendment to authorize methodologies involving the use of gas concentration CEMS installed and operated in accordance with the provisions of 40 CFR part 60 in addition to the monitoring methodology preferred by the two previously mentioned commenters. Another commenter, without expressing a preference for a particular form of alternate monitoring requirements, recommended that EPA issue model rule language for alternate monitoring requirements that would be approvable in SIP revisions.

Most commenters supporting the proposed monitoring amendment did not request that EPA make further amendments to identify particular permissible alternate monitoring requirements or issue model rule language. One of these commenters specifically recommended that EPA defer to states' choices regarding alternate monitoring requirements to the maximum extent allowable.

Response: EPA disagrees with the comments seeking further amendments to identify specifically permissible alternate monitoring requirements or issue model rule language and agrees with the comments supporting the monitoring amendment as proposed without such further amendments. Upon finalization of the proposed amendment to the NO X SIP Call regulations making the inclusion of part 75 monitoring requirements in SIPs optional rather than mandatory, states would have the flexibility to establish their own preferred forms of monitoring requirements for NO X SIP Call purposes, subject to the existing general provisions at § 51.121(i) introductory text and (i)(1) concerning SIP monitoring requirements—provisions that EPA did not propose to amend. Under the general monitoring provisions, which closely parallel the longstanding provisions concerning SIP source surveillance requirements at 40 CFR 51.210 and 51.211, each SIP revision must provide for monitoring the status of compliance with any control measures adopted to achieve the NO X SIP Call's emissions reduction requirements, and the monitoring must be sufficient to determine whether sources are in compliance with the control measures. Nothing in these general monitoring provisions precludes the commenters' preferred forms of monitoring requirements where such requirements are shown to be sufficient to meet these criteria. Thus, the further amendments suggested by the commenters are unnecessary, because where a state agrees that the commenters' preferred forms of monitoring requirements are appropriate, the state may obtain approval of those requirements simply by submitting a SIP revision that adopts those requirements and demonstrating that the revision satisfies the general monitoring provisions and does not conflict with any other applicable CAA requirement. 30 For the same reasons that EPA considers it reasonable under current circumstances to make part 75 monitoring optional rather than mandatory for NO X SIP Call purposes (as discussed in section II.B. of this document), EPA also considers it reasonable to defer to states' choices regarding alternate monitoring requirements for NO X SIP Call purposes to the extent consistent with the general monitoring provisions at § 51.121(i) introductory text and (i)(1).

In addition, EPA believes that inclusion of the suggested further amendments would not be particularly useful in providing certainty of the approvability of any specific state regulation implementing the commenters' preferred forms of monitoring requirements. Notwithstanding any endorsement of a particular overall monitoring approach that EPA might include in the regulations, given the need to satisfy the NO X SIP Call's general monitoring provisions just discussed, EPA would still need to individually review the specific alternate monitoring requirements in each SIP revision to support a determination that the monitoring is sufficient to ensure compliance with the NO X SIP Call's emissions reduction requirements. For example, EPA would need to consider whether each regulation contains adequate provisions to avoid gaps in required monitoring and whether a regulation following an emission factor approach employs emission factors that are designed to avoid any bias toward understatement of emissions. Approval of each SIP revision would also be subject to notice-and-comment procedures. While in theory EPA could provide greater certainty of the approvability of certain forms of alternate monitoring requirements by issuing model rule language, EPA believes issuance of such language in this instance is neither necessary nor consistent with EPA's general intent of deferring to states' preferences regarding alternate monitoring requirements for NO X SIP Call purposes.

Comment: One commenter stated that amending the NO X SIP Call regulations to allow sources that currently monitor using CEMS to switch to alternate monitoring methods would be inconsistent with CAA section 110(l), 42 U.S.C. 7410(l), known as the “anti-backsliding” provision, which prohibits EPA from approving any implementation plan revision that would interfere with any applicable requirement under the CAA. The commenter stated that effective and accurate emissions monitoring is needed to protect against backsliding and that allowing sources to use monitoring approaches less effective than CEMS monitoring would be inconsistent with section 110(l) because it would deprive communities and regulators of timely or reliable emissions information needed to identify possible violations of emissions standards and to facilitate enforcement actions.

Response: EPA disagrees with this comment. As a preliminary matter, EPA notes that CAA section 110(l) applies to EPA actions determining to approve implementation plan revisions, not other EPA actions that might affect the matters that are required to be addressed through such implementation plan revisions. Thus, this action to amend the NO X SIP Call regulations is not subject to section 110(l). At the same time, no Agency-issued regulation can negate or otherwise modify the Congressionally-established prohibition in section 110(l) against approval of implementation plan revisions that would permit backsliding. For this reason, notwithstanding the content of any amendment to the NO X SIP Call regulations finalized in this action, approval of any SIP submissions made in response to such an amendment will necessarily still be subject to anti-backsliding requirements under section 110(l).

Substantively, the proposed amendment to monitoring requirements is not inconsistent with the purpose of section 110(l) because there is no reason to expect that a SIP submission seeking only to revise monitoring requirements for NO X SIP Call purposes would result in increased emissions or otherwise interfere with any other CAA requirement, in light of the criteria for approval of such a SIP submission. That is, the amendments proposed for this action make no changes to the NO X SIP Call's existing regulatory requirements related to statewide emissions budgets or enforceable mass emissions limits for large EGUs and large non-EGU boilers and turbines. As discussed in response to a previous comment, under § 51.121(i) introductory text and (i)(1) any alternate monitoring requirements approved into a SIP for NO X SIP Call purposes must be sufficient to determine whether the state's sources are in compliance with the control measures adopted to meet the Rule's emissions requirements. Given continued implementation of SIP requirements governing the unchanged amounts of allowable emissions, accompanied by replacement monitoring requirements sufficient to ensure compliance with the unchanged emissions requirements, a SIP revision adopted in response to the proposed amendments would not be expected to result in increases in emissions that could interfere with other statutory or regulatory requirements.

The commenter's suggestion that CEMS emissions data provided pursuant to NO X SIP Call requirements is necessary to provide emissions information to identify violations of and enforce other emissions standards is outside the scope of the proposal. The NO X SIP Call's monitoring requirements were promulgated to provide monitoring information sufficient to ensure compliance with the control measures adopted to achieve the Rule's emissions reduction requirements. 31 Monitoring requirements to ensure compliance with other emissions requirements are generally established as part of the regulations that establish each specific emissions requirement or through monitoring-focused regulations such as the source surveillance regulations at 40 CFR part 51, subpart K, or the compliance assurance monitoring regulations at 40 CFR part 64. Any concerns about the adequacy of the monitoring requirements established under other regulations would be properly raised as comments in the actions promulgating those regulations or as requests for new rulemaking, not as comments on this action addressing monitoring requirements under the NO X SIP Call regulations. In the proposal for this action, EPA did not propose to alter any monitoring requirements under any regulations other than the NO X SIP Call regulations.

Comment: One commenter stated that amending the NO X SIP Call regulations to allow sources that currently monitor using CEMS to switch to alternate monitoring methods would be inconsistent with CAA section 504(b), 42 U.S.C. 7661c(b), which authorizes EPA to prescribe monitoring requirements for the operating permits that certain sources are required to obtain pursuant to CAA title V. The commenter cited a portion of the provision stating that “continuous emissions monitoring need not be required if alternative methods are available that provide sufficiently reliable and timely information for determining compliance” and stated that because CEMS monitoring is the most reliable and timely monitoring method for determining compliance with NO X emissions limits, it would be unreasonable and inconsistent with section 504(b) for EPA to allow sources which already have CEMS equipment installed to use less reliable and timely monitoring approaches.

Response: EPA disagrees with this comment. While CAA section 504(b) provides EPA with authority to prescribe monitoring requirements for title V operating permits, it does not require EPA to exercise that authority in any particular situation and hence does not impose any statutory requirement applicable to this action. Further, even accepting for purposes of argument the comment's premise that the conditions that would apply to an exercise of EPA's authority under section 504(b) should also apply to EPA's establishment of monitoring requirements for NO X SIP Call purposes, the proposed monitoring amendment is neither unreasonable nor inconsistent with those conditions. As noted in the comment, section 504(b) explicitly provides that EPA need not exercise its authority under the section so as to require CEMS in circumstances where alternate monitoring methods sufficient to determine compliance are available. In the proposal, EPA presented recent emissions data and expressed the view that, given the current substantial margins by which the sets of large EGUs and large non-EGU boilers and turbines in all NO X SIP Call states are complying with the relevant portions of the statewide emissions budgets as well as the fact that most of the relevant emissions will continue to be monitored according to part 75 under other programs, monitoring of the remaining emissions using non-part 75 approaches can now provide sufficient assurance that the Rule's required emissions reductions will continue to be achieved. 32 The commenter does not challenge EPA's assessment. EPA's rationale for proposing the amendment closely parallels and is fully consistent with the conditions set forth in section 504(b) for the possible establishment of monitoring requirements other than CEMS monitoring requirements.

Moreover, neither of the commenter's stated reasons for suggesting that it would be unreasonable or inconsistent with section 504(b) for EPA to allow the use of non-CEMS approaches is compelling. The first stated reason—that CEMS-based monitoring approaches would provide the most reliable and timely information for determining compliance with NO X emission limits—is itself inconsistent with the statutory text which, as just discussed, explicitly indicates the potential acceptability of non-CEMS monitoring approaches that provide sufficient reliability and timeliness of information for determining compliance. The second stated reason—that the sources in question already have CEMS equipment installed—is incorrect for some of the sources potentially affected by the monitoring amendment and materially incomplete for all of them. The set of large EGUs and large non-EGU boilers and turbines subject to the NO X SIP Call's ongoing requirements discussed in this document includes both existing and new units. Some new units that would need to install CEMS equipment if required to monitor under part 75 might not need to install some or all of that CEMS equipment if part 75 monitoring were not required for NO X SIP Call purposes. Further, as discussed in the proposal, even for a source that already has CEMS equipment installed, the source's ongoing operating costs to monitor using the installed CEMS equipment could be higher than the source's ongoing operating costs if the source were to switch to a non-CEMS monitoring approach. 33 Besides the factor of whether non-CEMS monitoring approaches that provide sufficiently reliable and timely information for determining compliance are available, the text of section 504(b) does not specify or limit other factors that EPA may consider when applying its authority under the section. Thus, it is neither unreasonable nor inconsistent with section 504(b) for EPA to consider the likelihood that some sources would incur lower monitoring costs if allowed to use non-CEMS monitoring approaches for NO X SIP Call purposes.

Comment: One commenter summarized several provisions of CAA section 110(a), 42 U.S.C. 7410(a), concluding with the interpretation that “a bedrock requirement for any implementation plan is for emissions monitoring requisite to ensure attainment and maintenance of the NAAQS.” The commenter further stated that the current network of ambient air quality monitors is “not robust enough to adequately assess levels of [ozone and particulate matter] in ambient air” and cited a study concerning satellite-based measurements of ambient air quality. The commenter concluded that “[g]iven this level of under-assessment of pollution problems and dramatic[ ] undercounting of nonattainment issues,” the proposed amendment to allow states to establish alternate emissions monitoring requirements “is wholly inconsistent with the Clean Air Act's requirements.”

Response: EPA disagrees that the proposed amendment to the NO X SIP Call regulations would be inconsistent with the statutory requirements under CAA section 110(a). The comment conflates the statutory provision authorizing EPA to prescribe emissions monitoring requirements for individual sources under CAA section 110(a)(2)(F) with the general requirement for ambient air quality monitoring under CAA section 110(a)(2)(B). Contrary to the commenter's interpretation of CAA section 110(a), the data used to determine whether air quality in a given area meets the ozone or PM 2.5 NAAQS are the data obtained through the ambient air quality monitoring network, not the data obtained through source emissions monitoring. Similarly, assessments of whether the emission control measures in effect are collectively sufficient to ensure attainment and maintenance of those NAAQS are made using monitored ambient air quality data or projected ambient air quality data (which necessarily reflect projected, not monitored, source emissions data). The amendments proposed for this action would not alter any regulatory requirements concerning ambient air quality monitoring, and comments on this topic are outside the scope of the proposal.

As discussed in response to a previous comment, the originally intended purpose served by the emissions monitoring requirements under the NO X SIP Call was to ensure compliance with the control measures adopted to achieve the Rule's emissions reduction requirements, not to ensure attainment and maintenance of the NAAQS. Amendment of the NO X SIP Call as proposed for this action would not alter the provisions at § 51.121(i) introductory text and (i)(1) that set forth the ongoing general requirement for SIPs to include emissions monitoring sufficient for this purpose. The amendment would simply expand the options available to states for addressing the ongoing general requirement by eliminating the additional specific requirement at § 51.121(i)(4) for part 75 monitoring by large EGUs and large non-EGU boilers and turbines. Like the NO X SIP Call's initial monitoring requirements, the Rule's monitoring requirements as amended would be fully consistent with CAA section 110(a)(2)(F), which authorizes EPA to prescribe emissions monitoring and reporting SIP requirements that may include requirements for “correlation of such [emissions] reports by the State agency with any emission limitations or standards” established under the CAA.

Comment: One commenter discussed the data EPA presented in the proposal regarding recent emissions reported by the sources that would have been subject to the former NBTP. While not disputing EPA's assessment that the data show that the sources in all states subject to the NO X SIP Call are currently complying with the assigned portions of their respective statewide budgets by substantial margins, the commenter asserted that EPA's reliance on the data to support the proposed amendment to the Rule's monitoring requirements is misguided. The commenter questioned the relevance of EPA's assessment that non-part 75 monitoring by the sources not subject to part 75 monitoring requirements under other programs could now provide assurance of continued compliance with the NO X SIP Call's emissions reduction requirements, suggesting that EPA should instead consider emissions targets more stringent than the Rule's existing budgets.

With regard to EPA's assessment that the substantial majority of emissions from large EGUs and large non-EGU boilers and turbines would continue to be monitored according to part 75 under other programs, the commenter observed that in certain states, the emissions from the subset of large EGUs and large non-EGU boilers and turbines potentially affected by the proposed monitoring amendment can be significant relative to the emissions from the remaining large EGUs and large non-EGU boilers and turbines that must continue to monitor their emissions under part 75 for other programs. Based on this observation, the commenter concluded that, in these states, allowing the potentially affected sources to monitor using non-CEMS methodologies “will notably degrade the overall NO X emissions data” from the sets of large EGUs and large non-EGU boilers and turbines in the states. The commenter also stated that the total amount of seasonal NO X emissions from the potentially affected sources—approximately 15,000 tons in the 2017 ozone season—is “not trivial,” but is significant in an absolute sense regardless of its relation to the amount of emissions from the sources that would still be subject to part 75 monitoring requirements under other programs. Noting that annual emissions of 100 tons can trigger classification of certain types of new or modified sources as “major sources” under other CAA programs, the commenter suggested that allowing sources that collectively produce 15,000 tons of seasonal NO X emissions to stop using CEMS is comparable to excusing as many as 360 major sources from requirements to use NO X CEMS under other programs.

Response: EPA continues to believe that the emissions data presented in the proposal provide compelling support for the proposed amendment to the NO X SIP Call's emissions monitoring requirements. EPA disagrees with the commenter's suggestion that in evaluating possible changes to monitoring requirements under the NO X SIP Call, rather than assessing whether alternate forms of monitoring would be sufficient to ensure compliance with the Rule's existing emissions reduction requirements, EPA should instead consider whether the alternate monitoring requirements would be sufficient to ensure compliance with more stringent emissions targets. As discussed in response to a previous comment, the Rule's monitoring requirements were established to provide monitoring information sufficient to ensure compliance with the control measures adopted to achieve the Rule's required emissions reductions, and monitoring requirements to ensure compliance with other emissions requirements are established in other regulations. Comments concerning whether the Rule's existing emissions reductions requirements are sufficiently stringent are outside the scope of the proposal. EPA did not propose to substantively alter any regulatory requirements other than the NO X SIP Call's monitoring requirements.

With regard to the commenter's observations concerning the relative magnitudes of the respective total amounts of emissions from sources potentially affected by the proposed monitoring amendment and other sources in certain states, EPA acknowledges that emissions from the potentially affected sources comprise larger shares of the total emissions from large EGUs and large non-EGU boilers and turbines in some states than others but disagrees with the suggestion that this fact should foreclose the possibility of allowing monitoring flexibility for NO X SIP Call purposes. According to the recent emissions data presented in the proposal  34 and reproduced in Table 1 in section II.B. of this document, for six of the states identified in the comment—Alabama, Maryland, New Jersey, New York, South Carolina, and Tennessee—the total amount of emissions from the state's potentially affected sources was from 19% to 30% of the total amount of emissions from the state's remaining large EGUs and large non-EGU boilers and turbines, and for the last identified state—Delaware—the emissions from the state's potentially affected sources exceeded the emissions from the state's remaining large EGUs and large non-EGU boilers and turbines. However, even accepting the commenter's premise that allowing the potentially affected sources in these states to switch from CEMS methodologies to non-CEMS methodologies would reduce the accuracy of the total reported amounts of emissions from large EGUs and large non-EGU boilers and turbines, EPA believes that the compliance margins in these states are large enough that there would still be sufficient assurance that the NO X SIP Call's emissions reduction requirements would continue to be achieved. In each of these states (as well as all the other states subject to the NO X SIP Call), the emissions data in Table 1 indicate that, assuming no increase in the total emissions from the sources in the state that would continue to be subject to part 75 monitoring under other programs, the total emissions from the state's potentially affected sources could increase at least eightfold without causing the total emissions from the state's large EGUs and large non-EGU boilers and turbines to exceed the relevant portion of the statewide emissions budget. 35 Thus, again assuming no increase in the total emissions from the sources in the state that would continue to be subject to part 75 monitoring under other programs, even if the total reported emissions data for the set of potentially affected sources in a state in some future ozone season were to understate the true emissions data because of less accurate measurements made using non-CEMS methodologies, in order for the total reported emissions data to incorrectly indicate compliance for the state when the true emissions data would indicate non-compliance, the cumulative measurement errors causing understatement of the true data—that is, the differences between the reported emissions data values and the true emissions data values for each source—would have to be several times larger than the reported data values. 36 The commenter does not suggest, and EPA does not believe, that the accuracy of non-CEMS monitoring approaches would be so poor as to allow such a scenario to occur. Moreover, if the commenter believes that the specific alternate monitoring approaches included in a particular state's SIP revision submitted for EPA's approval would provide insufficiently accurate data to ensure continued compliance with the control measures adopted in the state's SIP for NO X SIP Call purposes, the notice-and-comment process for approval of the SIP revision would provide an opportunity for the commenter to raise that concern.

With regard to the commenter's observations concerning the significance of the total seasonal NO X emissions from the potentially affected sources in an absolute sense, EPA agrees that a 15,000-ton quantity of seasonal NO X emissions is “not [a] trivial” amount but disagrees with the suggestion that this fact should foreclose the possibility of allowing monitoring flexibility for NO X SIP Call purposes. The proposed amendments would not alter any of the Rule's regulatory requirements concerning permissible amounts of emissions and would not eliminate the requirement for SIPs to provide for monitoring of the emissions from all large EGUs and large non-EGU boilers and turbines sufficient to ensure continued compliance with the Rule's emissions reduction requirements. Nor does EPA agree that allowing non-CEMS monitoring approaches to be used for purposes of demonstrating compliance with control measures adopted under the NO X SIP Call is comparable to excusing major sources from requirements to monitor using CEMS for other purposes. The amendments proposed for this action are based on EPA's assessment, specific to this action, that under current circumstances monitoring information from some sources other than part 75 monitoring information can now provide sufficient assurance that the NO X SIP Call's required emissions reductions will continue to be achieved. Where any source is required to monitor using CEMS for another purpose under regulations other than the NO X SIP Call regulations, the amendments proposed for this action would not affect those requirements.

Comment: One commenter contended that allowing alternate monitoring requirements will lead to increased emissions. The commenter observed that EPA did not know which specific sources might ultimately be allowed to use alternate monitoring methods. According to the commenter, EPA had suggested in the proposal that the potential for increases in pollution resulting from alternate monitoring requirements is merely uncertain, because EPA would not itself relax the requirements but would leave that decision to the states, and the commenter stated it is arbitrary and capricious for EPA to rely on such a claim of uncertainty to avoid assessing the impacts of increased pollution. The commenter contended that EPA had suggested in the proposal that “systemwide NO X emissions are low enough that if there are increases in pollution attainment and maintenance [of the NAAQS] might not be threatened.” The commenter also discussed ozone pollution and the harms it causes to human health and the environment, citing several EPA documents.

Response: EPA does not dispute the commenter's summary of the harms caused by ozone pollution or the correct observation that EPA does not know which specific sources might ultimately be allowed to use alternate monitoring methods (because states, not EPA, will decide whether to revise their SIPs). Otherwise, EPA disagrees with these comments. Relative to part 75 monitoring approaches, non-part 75 monitoring approaches may be expected to provide less detailed monitoring data and require less rigorous quality assurance, with a consequently greater possibility that the total NO X emissions amount reported by a source for a given ozone season might understate or overstate the source's actual total emissions for that ozone season to some degree. However, there is no reason to expect any approved non-part 75 monitoring methodology either to be systematically biased toward understatement of emissions or to create any incentive leading to increased emissions. EPA was clear in the proposal that no changes to emissions or air quality are expected because no changes are being made to the NO X SIP Call's emissions requirements. 37 The commenter effectively equates allowing alternate monitoring methods with relaxing emissions requirements, providing no rationale or evidence to support the contention that in the absence of any change in either emissions requirements or the general requirement to monitor emissions, possible changes in just the allowed methods for emissions monitoring under the NO X SIP Call will lead to increased emissions. EPA continues to believe it is reasonable to assume that under current circumstances where sources are already complying with the NO X SIP Call's emissions requirements by substantial margins, substitution of one monitoring method for another monitoring method, in the absence of any change in the Rule's emissions requirements, will not cause sources to change their behavior in a way that would affect emissions levels. Moreover, in the event that a particular state's SIP submission were to include a poorly designed alternate monitoring requirement that could lead to systematic understatement of emissions, the SIP approval process—including notice-and-comment procedures—would provide a further safeguard against the possibility of alternate monitoring requirements insufficient to ensure compliance with the Rule's emissions requirements. The commenter appears to incorrectly assume that the amendment in this action would by itself end all EPA oversight of monitoring requirements for NO X SIP Call purposes and fails to acknowledge the additional safeguard afforded by the SIP approval process.

The commenter's claims regarding suggestions that EPA purportedly made about the supposed possibility of increased emissions misrepresent the proposal. Contrary to the comments, nowhere in the proposal did EPA indicate “uncertainty” as to whether the proposed amendments would lead to increased pollution. Rather, as just discussed, EPA explicitly stated that the proposed amendments are expected to have no impact on emissions or air quality. The fact that states, rather than EPA, will decide whether to revise their SIPs to establish alternate monitoring requirements was cited in the proposal as a basis for uncertainty with regard to the potential amount of reductions in monitoring costs, not as a basis for uncertainty with regard to supposed potential increases in emissions. 38 Likewise, nowhere in the proposal did EPA make any suggestion regarding the relationship of supposed potential increases in emissions to the likelihood of attainment or maintenance of any NAAQS. Rather, as an illustration of the magnitude of states' recent margins of compliance with the NO X SIP Call's emissions reduction requirements, EPA stated only that such compliance would continue to be achieved even if emissions were to increase substantially from current levels, and then proceeded to explain why such increases in emissions in fact are unlikely to occur. 39

Comment: One commenter suggested that the proposal did not address relevant differences among the states and source types that could be affected by the proposed monitoring amendment. The commenter stated that the proposal failed to identify which sources affected under the NO X SIP Call do not participate in any CSAPR trading program. Noting that several NO X SIP Call states are outside the region covered by the various CSAPR trading programs, the commenter asserted that EPA had failed to explain “why sources in some areas should be allowed to monitor less and pollute more,” and that “EPA is thus effectively proposing to end continuous NO X monitoring for an entire geographic area without discussing the ensuing implications.” Noting that the NO X SIP Call applies to both EGUs and non-EGUs while the CSAPR trading programs generally apply only to EGUs, the commenter further asserted that EPA did not “coherently address the distinction between the types of sources” (emphasis in original) covered by the NO X SIP Call and the CSAPR trading programs. Repeating the contention that allowing alternate monitoring methods will lead to increased emissions, the commenter suggested that EPA should have evaluated the impacts on regional ozone transport problems of allowing alternate monitoring methods for some states and source types but not others.

Response: EPA disagrees with these comments. Contrary to the commenter's suggestion, the proposal explicitly discussed differences among NO X SIP Call states concerning whether each state's EGUs are covered by a CSAPR trading program, noting that EGUs in Connecticut, Delaware, Massachusetts, Rhode Island, and the District of Columbia do not participate in any CSAPR trading programs. 40 Likewise, the commenter's assertion that the proposed monitoring amendment would “end continuous NO X monitoring for an entire geographic region” is directly contradicted by information in the proposal: First, by the explanation that most of the EGUs in the five non-CSAPR states will remain subject to part 75 monitoring requirements under the Acid Rain Program;  41 second, by the explanation that most of the emissions from the set of large EGUs and large non-EGU boilers and turbines affected under the NO X SIP Call come from large EGUs that would continue to monitor their emissions according to part 75 under either the Acid Rain Program or a CSAPR trading program;  42 and third, by the data showing quantitatively that out of the total set of sources subject to the NO X SIP Call in the five non-CSAPR states, the subset of sources that would continue to be subject to part 75 monitoring requirements under other programs has produced most of the recent emissions. 43

Contrary to the commenter's assertion that the proposal failed to address the distinction between EGUs and non-EGUs, the proposal explicitly discussed the fact that unlike most EGUs, most non-EGUs affected under the NO X SIP Call do not participate in a CSAPR trading program or face part 75 monitoring requirements under other programs. 44 The proposal also explicitly noted that although some of the sources potentially affected by the proposed monitoring amendment are large EGUs not subject to the Acid Rain Program or a CSAPR trading program, most of the potentially affected sources are large non-EGU boilers and turbines. 45 The proposal presented recent state-specific emissions data broken out according to whether the emissions came from sources that would continue to be subject to part 75 requirements under other programs or instead came from sources potentially affected by the proposed amendment. 46 The proposal did not further break out the total recent emissions from potentially affected sources into the respective portions from EGUs and non-EGUs because EPA did not see any relevance in whether the NO X emissions that might be monitored for NO X SIP Call purposes using methods other than part 75 come from EGUs or from non-EGUs. The commenter has not suggested any reasons why further subcategorization of the emissions information provided in the proposal might be relevant to an evaluation of the proposed monitoring amendment. Nevertheless, to address the comment, EPA notes that large non-EGU boilers and turbines were collectively responsible for 14,860 tons of the total 15,084 tons of seasonal NO X emissions shown in Table 1 for all units potentially affected by the proposed monitoring amendment, or 98.5% of the total, while large EGUs not required to monitor according to part 75 under the Acid Rain Program or a CSAPR trading program were collectively responsible for 224 tons, or 1.5% of the total. 47

The comments suggesting that EPA should have evaluated the impacts on regional ozone transport problems of allowing alternate monitoring methods for some states and source types but not others reflect the commenter's unsupported assumption that allowing alternate monitoring methods is equivalent to relaxing emissions requirements. EPA has already rebutted the commenter's assumption in response to a previous comment. Because there is no reason to expect any increase in emissions from the proposed monitoring amendment, there is no reason to evaluate any impacts on regional ozone transport problems of any supposed potential increase in emissions.

Comment: One commenter stated that EPA has not “identif[ied] any need to weaken emission monitoring requirements” (emphasis in original), has not identified specific complaints from sources regarding the costs of operating monitoring equipment that has already been installed, and has not sufficiently discussed possible monitoring methodologies or compared their costs. The commenter also stated that allowing alternate monitoring requirements would unfairly advantage new sources over existing sources because the new sources, unlike existing sources, would be allowed “to both use cheaper, less effective monitoring systems and to get away with emitting more NO X ” than existing sources.

Response: EPA disagrees with these comments. In the proposal, EPA discussed the opportunity to reduce monitoring costs under the NO X SIP Call for some sources while continuing to ensure compliance with the Rule's emissions reduction requirements. 48 By definition, a regulatory initiative that reduces overall costs while holding overall benefits constant produces positive net benefits. The commenter has not offered any legal basis or policy rationale supporting the notion that EPA should decline to pursue a regulatory initiative intended to produce positive net benefits simply because the net benefits happen to take the form of a reduction in sources' monitoring costs.

The commenter's suggestion that EPA has presented insufficient evidence to support the existence of monitoring cost reduction opportunities is belied by the information in the proposal, which described the various monitoring methodologies available under part 75 and qualitatively discussed the cost reductions that could be available if the sources using each of those methodologies were to switch to alternate monitoring methodologies. 49 Moreover, all of the comments received on the proposal from source owners and industry associations, as well as most of the comments received from states, agreed that the proposed amendment would make monitoring cost reductions possible for sources in states that choose to revise their SIPs. 50 The commenter asserted that sources had no reason to complain of monitoring costs because they had already installed the necessary CEMS equipment, but as EPA explained in response to a previous comment, this assessment is incorrect as to new sources, because new sources would not yet have installed the CEMS equipment, and materially incomplete as to all sources, because CEMS-related costs include not only equipment installation costs but also ongoing operating costs. EPA sees no reason why, in the absence of any contrary information, more evidence is needed to demonstrate the existence of opportunities for monitoring cost reductions than was already presented in the proposal, as further supported by comments.

With respect to quantification of the potential reductions in monitoring costs, EPA explained in the proposal that because states, not EPA, would decide whether to revise the monitoring requirements in their SIPs and because EPA lacked complete information on the remaining monitoring requirements that the sources would face, it was not possible to predict the amount of monitoring cost reductions that could occur following finalization of the proposed monitoring amendment. 51 EPA still lacks information on the remaining monitoring requirements that sources will face but received comments indicating some likelihood that at least six states would revise their SIPs following finalization of the proposed monitoring amendment. The states' comments make it possible to estimate a potential range of monitoring cost reductions that could occur if these states were to adopt some of the changes in monitoring requirements that EPA considers most likely. EPA's estimates are provided in section V of this document.

Finally, the commenter's suggestion that the proposed monitoring amendment would unfairly advantage new sources over existing sources lacks any support. The NO X SIP Call's current requirements for part 75 monitoring apply to both existing and new sources, and upon finalization of the proposed monitoring amendment, states' flexibility to establish alternate monitoring requirements will likewise apply to both existing and new sources. Commenters have not suggested any reason to believe that states will choose to exercise this new flexibility in a manner that discriminates among their existing and new sources in terms of the prospective monitoring requirements established in their SIPs, and if the commenter is suggesting that EPA should require new sources to incur certain capital expenditures in the future simply because existing sources incurred those same capital expenditures in the past, EPA disagrees. Further, the commenter's assertion that the monitoring amendment will allow new sources to “get away with emitting more NO X ” again rests on the commenter's unsupported assumption that allowing alternate monitoring methods is equivalent to relaxing emissions requirements. EPA has already rebutted the commenter's assumption in response to a previous comment. EPA also reiterates that the proposed monitoring amendment would not change any other emissions or monitoring requirements applicable to either existing or new sources under regulations other than the NO X SIP Call, including requirements that may be more stringent for new sources than existing sources.

Comment: One commenter discussed the superiority of CEMS methodologies compared to non-CEMS monitoring methodologies in terms of the timeliness and reliability or accuracy of the emissions data collected, particularly with respect to NO X emissions, and cited various EPA documents in support. The commenter stated that EPA “should be enhancing the use of CEMS in emissions measurements” instead of allowing monitoring flexibility. In particular, the commenter stated that the continued use of CEMS is necessary to ensure compliance with the Chesapeake Bay Total Maximum Daily Load (TMDL) for nitrogen established under the Clean Water Act. In support of this comment, the commenter summarized the role of atmospheric deposition as a contributor of nitrogen to Chesapeake Bay, citing studies by EPA and others. The commenter also noted that the plan for achieving the TMDL includes commitments from EPA to reduce atmospheric deposition through implementation of rules addressing CAA requirements, including the NO X SIP Call, and stated that EPA must maintain or strengthen air regulations in order to meet its commitments. The commenter stated that without accurate monitoring, states and EPA “will not know whether the reductions necessary to attain the Bay TMDL goals by 2025 are actually being met.”

Response: EPA agrees that CEMS methodologies are often the preferred monitoring approaches for ensuring compliance with particular emissions requirements but disagrees that the acknowledged superiority of CEMS methodologies for some purposes should foreclose the possibility of allowing monitoring flexibility for NO X SIP Call purposes where other monitoring methods would be sufficient to ensure continued achievement of the Rule's emissions reduction requirements. Likewise, EPA does not dispute the commenter's summary regarding the Chesapeake Bay TMDL and EPA's reliance on the NO X SIP Call's emissions reductions to reduce atmospheric deposition contributing nitrogen to the Bay but disagrees that those facts suggest that compliance with the Rule's emissions reduction requirements must be determined using any particular monitoring approach. As discussed in response to a previous comment, the NO X SIP Call's existing monitoring requirements were established to provide monitoring information sufficient to ensure compliance with the control measures adopted to achieve the Rule's required emissions reductions, and monitoring requirements to ensure compliance with other emissions requirements are established in other regulations. Comments concerning whether the NO X SIP Call's existing emissions reductions requirements are sufficiently stringent to address other environmental objectives, including achievement of the Chesapeake Bay TMDL, are outside the scope of the proposal. EPA did not propose to substantively alter any regulatory requirements other than the NO X SIP Call's monitoring requirements.

Comment: One commenter supported a narrower amendment to the NO X SIP Call's monitoring requirements than EPA proposed. Specifically, the commenter supported an amendment that would allow states to eliminate the requirements for reporting emissions data to EPA under part 75 but would not allow the use of substantively different monitoring methodologies for collecting emissions data. The commenter objected to allowing sources that currently monitor emissions using CEMS to use other monitoring methodologies because, unlike CEMS methodologies, non-CEMS methodologies do not allow for accurate and timely determinations of compliance with or violations of short-term emission limits. The commenter also expressed the expectation that if the proposed amendment to emissions monitoring requirements is finalized, some states would be required to revise their SIPs to establish less stringent monitoring requirements because of provisions in state law barring the states from imposing requirements on sources that exceed minimum Federal requirements.

Response: The comment expressing concern that non-CEMS methodologies are less useful than CEMS methodologies for determining compliance with emissions requirements other than the NO X SIP Call's emissions requirements is outside the scope of the proposal. As discussed in response to a previous comment, the NO X SIP Call's existing monitoring requirements were established to provide monitoring information sufficient to ensure compliance with the control measures adopted to achieve the Rule's required emissions reductions, and monitoring requirements to ensure compliance with other emissions requirements are established in other regulations. The NO X SIP Call does not require states to impose short-term emissions limits on their sources, and EPA did not propose to substantively alter any regulatory requirements other than the NO X SIP Call's monitoring requirements.

The comment suggesting that some NO X SIP Call states would be required under state law to revise their SIPs if the proposed monitoring amendment is finalized has no bearing on this action. EPA's proper focus in this action is whether the proposed amendment to allow alternate monitoring requirements in SIPs is appropriate under the CAA. Questions of whether and how state law provisions might affect the decisions of individual states to adopt alternate monitoring requirements allowed under the amendment are outside EPA's purview.

Comment: One commenter stated that allowing sources that currently monitor emissions for NO X SIP Call purposes with CEMS methodologies to instead monitor their emissions with non-CEMS methodologies would result in a loss of data resolution that would make it more difficult to understand the impacts of the sources' emissions on air quality in other states. The commenter stated that, with less detailed emissions data, it would be more difficult for states to work together to develop regionally consistent approaches for addressing good neighbor obligations with respect to the 2015 ozone NAAQS. The commenter also requested that EPA identify the specific units whose monitoring requirements could potentially be altered by states if the proposed monitoring amendment is finalized, as well as the locations of the units.

Response: EPA disagrees that allowing the use of alternate monitoring requirements for NO X SIP Call purposes would materially impact the ability of states to work together to address their good neighbor obligations with respect to the 2015 ozone NAAQS in a regionally consistent manner. As discussed in section II.B. of this document, if the proposed amendment is finalized, over 90% of the emissions from the set of NO X SIP Call large EGUs and large non-EGU boilers and turbines would still be monitored according to part 75 under other regulations if the relative proportions shown for 2017 in Table 1 continue into the future. In addition, the potentially affected sources in states that choose to revise their SIPs would still need to provide emissions monitoring information for each ozone season sufficient for the state to demonstrate compliance with the Rule's emissions reduction requirements. The commenter has not explained the purpose for which the enhanced data resolution provided by part 75 monitoring is desired. In any event, EPA notes that projected hourly emissions data for use in air quality modeling could be prepared based on the intra-year time patterns in the extensive historical emissions data reported by the sources for periods while the sources have been subject to part 75, because those data would remain available even if hourly emissions data are no longer reported in the future for some of these sources. As indicated in Table 1, the total amount of recent seasonal NO X emissions from the units that could potentially switch from part 75 monitoring approaches to non-part 75 monitoring approaches was approximately 15,000 tons during the 5-month ozone season, which by extrapolation suggests possible annual emissions of roughly 36,000 tons. By comparison, the most recent National Emissions Inventory (for 2014) indicates that for the set of NO X SIP Call states, the total amount of annual NO X emissions from all types of stationary sources—that is, not just the large EGUs and large non-EGU boilers and turbines currently subject to part 75 monitoring requirements under the NO X SIP Call—was over 2,000,000 tons, and the total amount of annual NO X emissions from all stationary and mobile sources was over 5,000,000 tons. 52 Thus, the NO X SIP Call units potentially affected by the proposed amendment appear to be responsible for roughly 2% of the total stationary source emissions and less than 1% of the total stationary and mobile source emissions from NO X SIP Call states. Given the small percentages of the relevant overall emissions inventory represented by the large non- EGU boilers and turbines potentially affected by the monitoring amendment proposed for this action, EPA expects that air quality modeling results and analyses of interstate ozone transport would not be materially affected by differences in the intra-year patterns of the projected hourly emissions data for these sources.

With respect to the commenter's request for the identities and locations of units potentially affected by the proposed monitoring amendment—in other words, large non-EGU boilers and turbines as well as large EGUs that are subject to the NO X SIP Call but not the Acid Rain Program or a CSAPR trading program—EPA notes that the requested information is already publicly available in the database of reported part 75 emissions data accessible through the Agency's website. 53 The database identifies each individual unit that has reported according to part 75 and provides the unit's state, county, latitude, and longitude. The database also indicates the regulatory programs for which the data have been reported, using the code “SIPNO X ” to indicate where a unit has reported seasonal NO X mass emissions data for purposes of the NO X SIP Call but not for purposes of the seasonal NO X trading programs established under CAIR, the original CSAPR, and the CSAPR Update. For the convenience of the commenter and others who might be similarly interested, EPA has extracted this information from the database into a spreadsheet which has been added to the docket for this action. 54

Comment: One commenter stated it had no objection to the proposed revisions to the provisions expressing the NO X SIP Call's emissions reduction requirements to the extent that the revisions do not substantively adjust the states' budgets.

Response: EPA thanks the commenter for this comment.

Comment: One commenter agreed with EPA's objective of clarifying and simplifying the provisions describing the NO X SIP Call's emissions reduction requirements but offered suggestions for doing so in ways that differed in some respects from the proposed amendments. First, the commenter suggested replacing the terms “budget” and “NO X budget” with a single term such as “NO X ozone season budget” both for consistency and to clarify that the budgets apply to seasonal rather than annual emissions. The commenter also suggested that EPA specify that the final budgets apply starting in 2007 and define the term “ozone season” in the regulations. Finally, the commenter suggested that all references to the Phase I budgets could be removed from the regulations because these budgets no longer have any substantive effect.

Response: EPA agrees with most of the commenter's suggestions. In particular, EPA agrees that the regulations would be clarified by consistently using the term “NO X ozone season budget” throughout § 202F;51.121, specifying that the final budgets apply starting in 2007, and documenting the definition used for the term “ozone season.” Extending the commenter's suggestions, EPA believes the regulations would be further clarified by indicating that other emissions amounts described in the regulations are also ozone season emissions and documenting the definition used for the term “nitrogen oxides” or “NO X .” The specific changes from proposal that are being adopted in response to the commenter's suggestion are described in section IV of this document.

Although EPA agrees with the commenter's observation that the Phase I budgets no longer have any substantive regulatory effect, EPA disagrees with the suggestion to remove all references to these budgets from the regulations. All but one of the states subject to the NO X SIP Call as implemented was required to adopt a SIP revision designed to comply with a Phase I budget, and some of the control measures adopted in those SIP revisions (such as measures to reduce emissions from cement kilns or stationary internal combustion engines) continue to be implemented as approved SIP provisions. While these control measures now address requirements to comply with the final budgets rather than the Phase I budgets, EPA considers it reasonable to retain the Phase I budgets in the regulations (and to specify their years of applicability) to document and facilitate understanding of both the state regulatory actions that originally adopted the measures and the EPA actions that approved the measures into the SIPs.

Comment: One commenter objected to the proposed removal of the baseline emissions inventory table in § 51.121(g)(2)(ii), requesting that the table be retained (with any necessary updates) for use in implementing the provisions at § 51.121(f)(2) that require enforceable limits on seasonal NO X mass emissions from large EGUs and large non-EGU boilers and turbines. The text of § 51.121(f)(2)(ii), which EPA has not proposed to substantively amend, contains the phrase “the total NO X emissions projected for such sources by the State pursuant to paragraph (g) of this section.” The commenter interprets this phrase as referring to amounts of emissions that the commenter believes either are or should be shown in the baseline emissions inventory table in § 51.121(g)(2)(ii).

Response: EPA disagrees with this comment, which appears to arise from a misinterpretation of the reference to “paragraph (g)” in § 51.121(f)(2)(ii). The various subparagraphs of § 51.121(g) describe or implicate two different types of projected 2007 emissions amounts. The first type is the baseline pre-control emissions amounts projected by EPA to represent emissions absent the reductions required by the NO X SIP Call. The second type is the post-control emissions amounts projected by states to represent emissions following implementation of the control measures adopted in their SIPs. The table in § 51.121(g)(2)(ii) that EPA proposed to delete was intended to contain  55 the first type of emissions amount—specifically, the pre-control emissions amounts projected by EPA for all sources  56 in all sectors. In contrast, the phrase “the total NO X emissions projected for such sources  57 by the State pursuant to paragraph (g) of this section” in § 51.121(f)(2)(ii) refers to the second type of emissions amount—specifically, the post-control emissions amounts projected by states for their large EGUs and large non-EGU boilers and turbines pursuant to § 51.121(g)(2)(iii) and used in the demonstrations required under § 51.121(g)(1). The fact that the phrase in § 51.121(f)(2)(ii) refers to the second type of emissions amount is evident for two reasons: first, the relevant amounts are projected “by the State” and not by EPA, and second, the purpose of § 51.121(f)(2)(ii) is to require enforceable mechanisms to ensure achievement of post-control emissions levels rather than pre-control emissions levels. Thus, the commenter's objection to the removal of the baseline emissions inventory table in § 51.121(g)(2)(ii) is misplaced.

Comment: Without expressing any objection to the proposed clarifying amendments to the post-NBTP transition provision at § 51.121(r)(2), one commenter requested confirmation that EPA does not intend the requirements of the provision as revised to apply with regard to EGUs that participate in the CSAPR Update trading program under the regulations set forth at 40 CFR part 97, subpart EEEEE, 58 pursuant to an approved SIP revision.

Response: The proposed clarifying revisions to the NO X SIP Call post-NBTP transition provision at § 51.121(r)(2) add a cross-reference to 40 CFR 52.38(b)(10)(ii), which is an existing provision of the CSAPR regulations governing SIP approvals. Under this provision of the CSAPR regulations, where a state has an approved full CSAPR SIP revision requiring certain units in the state to participate in a state seasonal NO X trading program integrated with the Federal CSAPR Update seasonal NO X trading program established under 40 CFR part 97, subpart EEEEE, the NO X SIP Call's post-NBTP transition requirements under § 51.121(r)(2) are satisfied with regard to any of the state's large EGUs or large non-EGU boilers and turbines participating in that state trading program. As explained in the proposal, 59 the addition of the cross reference in § 51.121(r)(2) is not a substantive change because the approval of a full CSAPR SIP would produce this result even without a cross-reference, but the cross-reference clarifies the NO X SIP Call regulations.

Comment: Without expressing any objection to the proposed clarifying amendments to the post-NBTP transition provision at § 51.121(r)(2), one commenter requested that EPA further clarify the Rule's post-NBTP transition requirements by adding a new regulatory provision indicating that where a state does not require its large non-EGU boilers and turbines to participate in the CSAPR Update trading program, the state must impose a cap on these units' collective seasonal NO X mass emissions equivalent to the portion of the statewide emissions budget assigned to the units under the NBTP. The commenter requested that EPA add the new provision to § 51.121(f)(2), the provision establishing the requirement for enforceable limits on seasonal NO X mass emissions from large EGUs and large non-EGU boilers and turbines.

Response: This comment is outside the scope of the proposal. A requirement for a cap on the collective NO X mass emissions of each state's large non-EGU boilers and turbines does not appear in the existing regulatory text at § 51.121 because, as discussed in the proposal and summarized in section II.A. of this document, the NO X SIP Call did not require states to control any specific types of sources or to adopt any specific types of control measures. Even where states chose to adopt control measures for large EGUs and large non-EGU boilers and turbines, thereby triggering requirements for enforceable limits on seasonal NO X mass emissions from those sources, the regulations provided several permissible alternative forms for such limits. 60 Similarly, the post-NBTP provision at § 51.121(r)(2) does not prescribe what types of sources states must control to satisfy the post-NBTP transition requirements or what types of control measures states must employ, but simply requires each state with units affected under the NO X SIP Call that do not participate in a successor trading program to the NBTP to “revise the SIP to adopt control measures that satisfy the same portion of the State's emission reduction requirements under [§ 51.121] as the State projected [the NBTP] would satisfy.” The commenter's requested amendment would codify as a Federal requirement what may be the simplest way to satisfy the Rule's post-NBTP transition requirements, but it would also reduce states' flexibility by eliminating options to satisfy the post-NBTP transition requirements in other ways, and the reduction in flexibility would represent a substantive change to the existing regulations. EPA did not propose substantive changes to the post-NBTP transition provision and made clear that the only provision of the NO X SIP Call regulations being reopened for substantive comment was the provision concerning part 75 monitoring requirements for large EGUs and large non-EGU boilers and turbines.

Comment: Without expressing any objection to the proposed clarifying amendments to the post-NBTP transition provision at § 51.121(r)(2), two commenters requested that EPA identify in the regulations the portion of each state's statewide emissions budget assigned to the state's large non-EGU boilers and turbines by adding this information either as a new table or as an additional column in the table of statewide budgets in § 51.121(e)(2)(i). The commenters suggested that inclusion of these amounts in the regulations could help states address their post-NBTP transition requirements. One of the commenters accompanied this comment with a request that EPA confirm “it is the EPA's intent that all required SIP elements for the NO X SIP Call are contained under § 51.121.”

Response: These comments are outside the scope of the proposal. The portions of the statewide emissions budgets assigned to various categories of sources do not appear in the existing regulatory text at § 51.121 because, as discussed in the proposal and summarized in section II.A. of this document, the NO X SIP Call did not establish required post-control emissions amounts for any specific categories of sources. Instead, each state determined what portions of its post-control statewide emissions budget to assign to the specific categories of sources in the state, and the assignments were approved in separate SIP approval actions for each state. 61 Adopting the state-determined, sector-specific assignments as Federal requirements at this time would be a substantive change to the existing regulations because it would reduce states' flexibility to revise their previous choices and select other ways of addressing their post-NBTP transition requirements. EPA did not propose substantive changes to the post-NBTP transition provision and made clear that the only provision of the NO X SIP Call regulations being reopened for substantive comment was the provision concerning part 75 monitoring requirements for large EGUs and large non-EGU boilers and turbines.

Comment: Without expressing any objection to the proposed clarifying revisions to the post-NBTP transition provision at § 51.121(r)(2), one commenter noted the proposed insertion of the words “or included” into the phrase “a State whose SIP . . . includes or included an emission trading program approved under [§ 51.121]” and indicated that the commenter's interpretation of the revised language is that “no action is necessary to affirm [the commenter's] obligation to maintain NO X SIP Call emissions control.” The commenter requested that EPA clarify in this final action if the state's interpretation is not correct.

Response: EPA considers this comment to be outside the scope of the proposal. As discussed in the proposal, the reason for inserting the words “or included” in § 51.121(r)(2) was to eliminate any possible mistaken inference that a state's obligation to maintain NO X SIP Call emission controls might be contingent on whether its SIP currently includes trading program provisions and to reinforce that the Rule's emissions reductions are permanent and enforceable. 62 EPA does not consider this to be a substantive change to the regulations. 63 While the commenter contends that its request for clarification about the need for any further action regarding its SIP arises from the proposed insertion, the commenter has not explained how, if at all, its interpretation of the post-NBTP transition requirements might have been influenced by the proposed insertion, and there is no indication that the commenter's interpretation has changed from its interpretation before issuance of the proposal. 64 Given the lack of any apparent connection between the proposed revision and the commenter's request for clarification, EPA interprets the comment as a request for a determination concerning the commenter's SIP that is outside the scope of the proposal. For this action, EPA did not propose to make any determinations regarding whether any further action is or is not necessary to address any specific state's post-NBTP transition requirements. Accordingly, EPA is not making any such state-specific determinations in this final action, either through express statements or otherwise.

For the reasons discussed in the proposal, as supplemented by the discussion in this document, EPA is finalizing amendments to the NO X SIP Call regulations at 40 CFR 51.121 and 51.122 and amendments to associated cross-references in the CSAPR regulations at 40 CFR 52.38. In place of the current requirement for states to include provisions in their SIPs under which certain emissions sources must monitor their seasonal NO X mass emissions according to 40 CFR part 75, the amended regulations will allow states to include alternate forms of monitoring requirements in their SIPs for NO X SIP Call purposes. Other amendments remove obsolete provisions and clarify the remaining regulations but do not substantively alter any current regulatory requirements.

Descriptions of the individual proposed amendments are provided in sections II.B. and II.C. of this document and further discussion is provided in the proposal. EPA is finalizing the amendments generally as proposed with the following further revisions, all of which EPA considers to be non-substantive changes from the proposal:

• To improve clarity, the final regulatory text of § 51.121(i)(4) is being revised from the proposed amended text in two ways. First, the final revisions indicate that where a state chooses to require part 75 monitoring for some or all large EGUs and large non-EGU boilers and turbines for NO X SIP Call purposes, the “full set of” monitoring, recordkeeping, and reporting provisions in subpart H of part 75 must be required. The added words clarify that the amendments do not authorize states to create partial versions of the part 75 regulations that EPA would then have to administer on a state-specific basis. Second, the final revisions remove a phrase indicating that the amended text does not create any exception to any part 75 requirements that may apply to a source under another legal authority. The removed phrase is unnecessary because, on its face, the amended text merely gives states an option to require part 75 monitoring for NO X SIP Call purposes and does not create or authorize any exceptions to any requirements that may apply to any source under any legal authority. EPA believes the text of the final amendment is clearer and does not differ substantively from the text of the amendment as proposed.

• As discussed in EPA's response to comments in section III.B. of this document, the regulatory text expressing the NO X SIP Call's emissions reduction requirements is being further clarified by using more precise terminology and documenting the definitions that already apply for two important terms. The final revisions (1) use the standard term “NO X ozone season budget” consistently, (2) specify emissions “during the ozone season” where appropriate, (3) indicate the respective years of applicability for the Phase I and final emissions budgets, and (4) add definitions of the terms “nitrogen oxides or NO X ” and “ozone season” to § 51.121. The term “nitrogen oxides or NO X ” is defined as “all oxides of nitrogen except nitrous oxide (N 2 O), reported on an equivalent molecular weight basis as nitrogen dioxide (NO 2 ).” The term “ozone season” is defined as “the period from May 1 through September 30 of a year.” The added definitions do not alter any regulatory requirements because they are substantively identical to the definitions that already explicitly apply for purposes of § 51.122 and that have historically been used in practice for purposes of § 51.121 as well. 65 The additional revisions affect the regulatory text at § 51.121(a)(3), (b)(1)(i) and (iii), (e)(1), (e)(2)(i) and (ii), (f) introductory text, (f)(2) introductory text, (f)(2)(i)(C), (g)(1), (g)(2)(i) and (iii), (i), and (j)(1).

• Instead of being removed as proposed, the provision at § 51.121(d)(2) concerning procedural requirements for SIP submissions is being revised to incorporate the updated procedural requirements for SIP submissions at 40 CFR 51.103. In the proposal, 66 EPA stated the intent for the completeness and format requirements in § 51.103 to apply to any future SIP submissions under § 51.121. The final revision makes such applicability explicit and is consistent with several other provisions of § 51.121 that similarly incorporate requirements set forth in other sections of 40 CFR part 51.

• An additional editorial revision is being made to the text of § 51.121(k)(2). The revision clarifies the regulations by standardizing citation formats.

A redline-strikeout document showing the text of 40 CFR 51.121 and 51.122 with the amendments adopted in this action, including all the proposed amendments to the NO X SIP Call regulations with the further revisions just described, is available in the docket for this action.

The amendments finalized in this action are effective immediately upon publication of the action in the Federal Register . This final action is not subject to requirements specifying a minimum period between publication and effectiveness under either Congressional Review Act (CRA) section 801(a)(3), 5 U.S.C. 801(a)(3), or Administrative Procedure Act (APA) section 553(d), 5 U.S.C. 553(d).

CRA section 801(a)(3) generally prohibits a “major rule” from taking effect earlier than 60 days after the rule is published in the Federal Register . Generally, under CRA section 804(2), 5 U.S.C. 804(2), a major rule is a rule that the Office of Management and Budget (OMB) finds has resulted in or is likely to result in (1) an annual effect on the economy of $100 million or more, (2) major cost or price increases, or (3) other significant adverse economic effects. This action is not a major rule for CRA purposes.

As discussed in section VI.M. of this document, EPA is issuing the amendments under CAA section 307(d). This provision does not include requirements governing the effective date of a rule promulgated under it and, accordingly, EPA has discretion in establishing the effective date. While APA section 553(d) generally provides that rules may not take effect earlier than 30 days after they are published in the Federal Register , CAA section 307(d)(1) clarifies that “[t]he provisions of [APA] section 553 . . . shall not, except as expressly provided in this section, apply to actions to which this subsection applies.” Thus, APA section 553(d) does not apply to the amendments. Nevertheless, in making this final action effective immediately upon publication, EPA has considered the purposes underlying APA section 553(d). The primary purpose of the prescribed 30-day waiting period is to give affected parties a reasonable time to adjust their behavior and prepare before a final rule takes effect. The amendments made in this action do not impose any new regulatory requirements and therefore do not necessitate time for affected sources to adjust their behavior or otherwise prepare for implementation. Further, APA section 553(d) expressly allows an effective date earlier than 30 days after publication for a rule that “grants or recognizes an exemption or relieves a restriction.” This action relieves an existing restriction and allows EPA to approve SIPs with more flexible monitoring requirements, which in turn could lead to reduced monitoring costs for certain sources. Consequently, making the amendments effective immediately upon publication of the action is consistent with the purposes of APA section 553(d).

The only amendment being finalized in this action that substantively alters existing regulatory requirements is the amendment allowing states to revise their SIPs, for NO X SIP Call purposes only, to establish monitoring requirements other than part 75 monitoring requirements. The amendments do not change any of the Rule's existing regulatory requirements related to statewide emissions budgets or enforceable mass emissions limits for large EGUs and large non-EGU boilers and turbines. Accordingly, EPA expects that the amendments will have no impact on emissions or air quality. However, EPA does expect that the amendment to the Rule's monitoring requirements will ultimately allow some sources to reduce their monitoring costs because of alternate monitoring requirements established in SIP revisions submitted and approved for their states. Because states, not EPA, will decide whether to revise the monitoring requirements in their SIPs and because EPA lacks complete information on the remaining monitoring requirements that the sources would face, there is considerable uncertainty concerning the amount of monitoring cost reductions that may be facilitated by this action, and EPA did not present a quantitative estimate of potential monitoring cost reductions in the proposal. For purposes of the final action, based in part on improved information obtained through comments, EPA has estimated a range of potential annual monitoring cost reductions from $1.2 million to $3.3 million, with a midpoint estimate of $2.25 million, as further discussed below. Given the absence of any change in emissions or air quality, there would be no change in the public health and environmental benefits attributable to the NO X SIP Call's emissions reduction requirements, and the likely reductions in monitoring costs therefore are expected to constitute positive net benefits from this action.

As of December 2018, EPA's records indicate that there are approximately 315 existing large EGUs and large non-EGU boilers and turbines in the NO X SIP Call region that could potentially be affected by the monitoring amendment if all states were to revise their SIPs. 67 To estimate how many of these potentially affected existing units may ultimately face alternate monitoring requirements made possible by the monitoring amendment in this action, EPA is relying on information obtained from states' comments. Six states submitted comments expressing support for the proposed monitoring amendment. 68 While these comments do not in any way obligate the states to submit SIP revisions with alternate monitoring requirements, and additional states that did not submit comments could also choose to submit SIP revisions, EPA believes that the comments provide a reasonable basis for assuming, solely for purposes of developing an estimate of this action's impacts, that the 102 existing units in these six states will ultimately face alternate monitoring requirements of some kind. 69 According to the monitoring plans for these units, 34 units use both gas concentration CEMS and stack gas flow rate CEMS, 35 units use gas concentration CEMS but not stack gas flow rate CEMS, and 33 units use non-CEMS methodologies. For purposes of estimating potential monitoring cost reductions, EPA has focused on the units currently using CEMS because, as noted in the proposal and in section II.B. of this document, EPA expects that units already using non-CEMS methodologies under part 75 would experience little or no reduction in monitoring costs from alternate monitoring requirements.

To represent the alternate monitoring requirements that the units currently using CEMS could face in a manner that reflects the substantial uncertainty on this issue, EPA has used a range of assumptions. Specifically, to estimate the low end of the range, EPA has assumed that the only change from current requirements is that the 34 units currently using both gas concentration CEMS and stack gas flow rate CEMS will discontinue the use of stack gas flow rate CEMS. EPA considers this assumption to be reasonable for purposes of estimating potential monitoring cost reductions because requirements to use stack gas flow rate CEMS are relatively uncommon in non-part 75 monitoring regulations. EPA also believes the units currently using stack gas flow rate CEMS are more likely than other potentially affected units to continue to be subject to requirements to use gas concentration CEMS because many of these units combust solid fuel and consequently may have triggered emission control requirements and associated emissions monitoring requirements under other regulations. To estimate the high end of the range, EPA has assumed that in addition to the change just described, the 35 units currently using only gas concentration CEMS will switch to a non-CEMS methodology. While it is possible that some of these units may also face continued requirements to use gas concentration CEMS under other regulations, EPA believes the likelihood that these units, none of which combust solid fuel, would be eligible to use non-CEMS methodologies is greater than for the units that currently use both gas concentration CEMS and stack gas flow rate CEMS.

To estimate the monitoring cost reductions associated with the assumed range of changes in monitoring requirements, EPA has used the cost estimates for the various part 75 monitoring methodologies contained in the information collection request (ICR) renewal prepared in conjunction with this action for purposes of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. 70 Based on the cost estimates in the ICR renewal, EPA has estimated that the potential annual cost reduction from discontinuing the use of stack gas flow rate CEMS—including reductions in labor costs, non-labor operating and maintenance costs (including contractor costs), and annualized capital costs—is approximately $35,000 per unit, while the analogous potential annual cost reduction from discontinuing the use of gas concentration CEMS is approximately $60,000 per unit. 71 Multiplying these per-unit amounts by the respective numbers of units yields an estimated range of potential annual monitoring cost reductions from $1.2 million to $3.3 million. 72 The midpoint of this range is a potential reduction in annual monitoring costs of $2.25 million.

Additional information about these statutes and executive orders can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders .

This action is not a significant regulatory action and was therefore not submitted to OMB for review.

This action is considered an Executive Order 13771 deregulatory action. This final rule provides meaningful burden reduction by allowing states to establish lower-cost monitoring requirements in their SIPs for some sources as alternatives to part 75 monitoring requirements. Because states, not EPA, will decide whether to revise the monitoring requirements in their SIPs and because EPA lacks complete information on the remaining monitoring requirements that the sources would face, there is considerable uncertainty regarding the amount of monitoring cost reductions that may occur, but EPA has quantified an estimated range in section V of this document. In addition, the proposal's qualitative discussion of the potential monitoring cost reductions  73 is summarized in section II.B. of this document.

This action does not impose any new information collection burden under the Paperwork Reduction Act. OMB has previously approved the information collection activities contained in the existing regulations and has assigned OMB control number 2060-0445. However, to reflect the amendment allowing states to establish potentially lower-cost monitoring requirements for some sources as alternatives to the current part 75 monitoring requirements, EPA submitted an information collection request (ICR) renewal to OMB in conjunction with the proposal for this action. The ICR document prepared by EPA, which has been assigned EPA ICR number 1857.08, can be found in the docket for this action. None of the comments that EPA received during the public comment period for the proposal addressed the ICR renewal.

Like the current ICR, the ICR renewal reflects the information collection burden and costs associated with part 75 monitoring requirements for sources that are subject to part 75 monitoring requirements under the SIP revisions addressing states' NO X SIP Call obligations and that are not subject to part 75 monitoring requirements under the Acid Rain Program or a CSAPR trading program. The ICR renewal is generally unchanged from the current ICR except that the renewal reflects projected decreases in the numbers of sources that would perform part 75 monitoring for NO X SIP Call purposes based on an assumption (made only for purposes of estimating information collection burden and costs for the ICR renewal) that, over the course of the 3-year renewal period, some states will revise their SIPs to replace part 75 monitoring requirements for some sources with lower-cost monitoring requirements. As under the current ICR, all information collected from sources under the ICR renewal will be treated as public information.

Respondents/affected entities: Fossil fuel-fired boilers and stationary combustion turbines that have heat input capacities greater than 250 mmBtu/hr or serve electricity generators with nameplate capacities greater than 25 MW and that are not subject to part 75 monitoring requirements under another program.

Respondents' obligation to respond: Mandatory if elected by the state (40 CFR 51.121(i)(4) as amended).

Estimated number of respondents: 340 (average over 2019-2021 renewal period).

Frequency of response: Quarterly, occasionally.

Total estimated burden: 131,945 hours (per year). Burden is defined at 5 CFR 1320.3(b).

Total estimated cost: $19,143,004 (per year), includes $8,256,087 annualized capital or operation & maintenance costs.

An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves this ICR renewal, the Agency will announce that approval in the Federal Register .

I certify that this action will not have a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act, 5 U.S.C. 601-612. In making this determination, the impact of concern is any significant adverse economic impact on small entities. An agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, has no net burden, or otherwise has a positive economic effect on the small entities subject to the rule. This action does not directly regulate any entity, but simply allows states to establish potentially lower-cost monitoring requirements for some sources and generally streamlines existing regulations. EPA has therefore concluded that this action will either relieve or have no net regulatory burden for all affected small entities.

This action does not contain any unfunded mandate as described in the Unfunded Mandates Reform Act, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments. The action imposes no enforceable duty on any state, local, or tribal governments or the private sector. This action simply allows states to establish potentially lower-cost monitoring requirements for some sources and generally streamlines existing regulations.

This action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government. This action simply allows states to establish potentially lower-cost monitoring requirements for some sources and generally streamlines existing regulations.

This action does not have tribal implications as specified in Executive Order 13175. It will not have substantial direct effects on tribal governments, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes. This action simply allows states to establish potentially lower-cost monitoring requirements for some sources and generally streamlines existing regulations. Thus, Executive Order 13175 does not apply to this action.

EPA interprets Executive Order 13045 as applying only to those regulatory actions that concern environmental health or safety risks that EPA has reason to believe may disproportionately affect children, per the definition of “covered regulatory action” in section 2-202 of the Executive Order. This action is not subject to Executive Order 13045 because it does not concern an environmental health risk or safety risk. This action simply allows states to establish potentially lower-cost monitoring requirements for some sources and generally streamlines existing regulations.

This action is not subject to Executive Order 13211 because it is not a significant regulatory action under Executive Order 12866.

This rulemaking does not involve technical standards.

EPA believes that this action is not subject to Executive Order 12898 because it does not establish an environmental health or safety standard. This action simply allows states to establish potentially lower-cost monitoring requirements for some sources and generally streamlines existing regulations. Consistent with Executive Order 12898 and EPA's environmental justice policies, EPA considered effects on low-income populations, minority populations, and indigenous peoples while developing the original NO X SIP Call. The process and results of that consideration are described in the Regulatory Impact Analysis for the NO X SIP Call.

This action is subject to the Congressional Review Act, and EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. This action is not a “major rule” as defined by 5 U.S.C. 804(2).

CAA section 307(b)(1), 42 U.S.C. 7607(b)(1), indicates which United States Courts of Appeals have venue for petitions of review of final actions by EPA. This section provides, in part, that petitions for review must be filed in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) if (i) the Agency action consists of “nationally applicable regulations promulgated, or final action taken, by the Administrator,” or (ii) the action is locally or regionally applicable, but “such action is based on a determination of nationwide scope or effect and if in taking such action the Administrator finds and publishes that such action is based on such a determination.” This action amends existing regulations that apply to 20 states and the District of Columbia, and thus the action applies to the same 21 jurisdictions. The existing regulations were promulgated to address interstate transport of air pollution across the eastern half of the nation and the resulting emissions reductions have been relied on as a basis for actions redesignating areas in at least 20 states to attainment with one or more NAAQS. The states affected under the regulations and relying on the resulting emissions reductions are located in multiple EPA Regions and Federal judicial circuits. Previous final actions promulgating and amending the existing regulations were nationally applicable and reviewed in the D.C. Circuit. For these reasons, the Administrator determines that this final action is nationally applicable or, in the alternative, is based on a determination of nationwide scope and effect for purposes of section 307(b)(1). Thus, pursuant to section 307(b), any petitions for review of this final action must be filed in the D.C. Circuit within 60 days from the date this final action is published in the Federal Register .

CAA section 307(d), 42 U.S.C. 7607(d), contains rulemaking and judicial review provisions that apply to certain EPA actions under the CAA including, under section 307(d)(1)(V), “such other actions as the Administrator may determine.” In accordance with section 307(d)(1)(V), the Administrator determines that the provisions of section 307(d) apply to this final action. EPA has complied with the procedural requirements of section 307(d) during the course of this rulemaking.

For the reasons stated in the preamble, parts 51 and 52 of chapter I of title 40 of the Code of Federal Regulations are amended as follows:

This is a summary of the Commission's document in WT Docket No. 06-150, FCC 19-77, released on February 12, 2019. The complete text of the document is available for viewing via the Commission's ECFS website by entering the docket number, WT Docket No. 06-150. The complete text of the document is also available for public inspection and copying from 8:00 a.m. to 4:30 p.m. Eastern Time (ET) Monday through Thursday or from 8:00 a.m. to 11:30 a.m. ET on Fridays in the FCC Reference Information Center, 445 12th Street SW, Room CY-B402, Washington, DC 20554, telephone 202-488-5300, fax 202-488-5563.

The Commission will send a copy of the document in a report to be sent to Congress and the Government Accountability Office pursuant to the Congressional Review Act, see 5 U.S.C. 801(a)(1)(A).

1. For certain spectrum blocks in the 700 MHz band, licensees that fail to meet the Commission's construction benchmarks keep the areas of the license that they serve, and the remaining unserved areas are returned to the Commission's inventory for relicensing. This approach provides other parties with opportunities to acquire spectrum that is not adequately built out and to serve communities that might otherwise not receive service.

2. This document describes the process for relicensing unserved areas, beginning with the “keep-what-you-serve” (KWYS) rules applicable to failing licensees, and ending with the specific rules and requirements for licensees that acquire unserved areas through the relicensing process, including through auction where necessary. This document is not inclusive of all relevant requirements and restrictions applicable to operations in this band, and it is the responsibility of applicants and licensees to remain current with all Commission rules and with all public notices pertaining to the 700 MHz band, the KWYS rules, and the relicensing process. The Commission also offers maps or examples in certain instances for illustrative purposes only; these are not meant to exhaustively cover all rule requirements or describe the only permissible scenarios.

3. In 2007, the Commission, in the 700 MHz Second Report and Order (72 FR 48814, Aug. 24, 2007), set forth rules governing certain wireless licenses in the 700 MHz band that, among other things, established interim and end-of-term construction benchmarks and status reporting requirements. 1 In 2013, the Commission released the Interoperability Report and Order (78 FR 66298, Nov. 5, 2013), which extended the interim construction deadline for Lower 700 MHz A and B Block licensees and removed the interim construction deadline for certain A Block licensees adjacent to Channel 51 operations. 2 For E Block licensees, the Commission also extended the interim and end-of-term deadlines and permitted a showing of population coverage, rather than geographic coverage. For licensees that fail to meet the applicable interim benchmark, the rules specify that the license term will be accelerated by two years for Lower A and B Block and Upper C Block licenses, and by one year for Lower E Block licenses. Most licensees in these blocks were auctioned in Auction 73 and have the respective construction requirements and deadlines listed in the document.

4. The Commission's rules require that licensees subject to the end-of-term deadline must file construction notifications, including coverage maps and supporting documentation, demonstrating that the licensee has met the end-of-term coverage requirement. Under the KWYS rules applicable to these blocks, if a licensee fails to meet its end-of-term construction deadline, its authorization to operate will terminate automatically without Commission action for those geographic areas of its license authorization in which the licensee is not providing service on the date of the end-of-term deadline, and those areas will become available for reassignment by the Commission. The Commission delegated authority to the Wireless Telecommunications Bureau (Bureau) to establish by public notice the process by which licenses will become available for relicensing under these rules.

5. On August 28, 2017, the Bureau released the 700 MHz Relicensing Comment PN (82 FR 42263, Sept. 7, 2017), which described the foregoing rules and policies set forth in the 700 MHz Second Report and Order and other relevant Commission rules and sought comment on the Bureau's proposed approach to the remaining elements of the KWYS and relicensing process. 3 The Bureau sought comment on several aspects of its proposed approach: (a) The process of identifying a failing licensee's service area and the resulting unserved areas to be returned to the Commission's inventory for relicensing; (b) rules and procedures for the administration of the two-phased relicensing process; and (c) the appropriate requirements and restrictions to be applied to relicensed areas. Interested parties, including mobile wireless providers and trade associations, submitted three comments and five reply comments in response to the 700 MHz Relicensing Comment PN .

6. Licensees must file a construction notification with the Commission no later than 15 days after the relevant end-of-term construction deadline, regardless of whether they have met the construction requirements. Licensees that have satisfied the construction requirement must continue to comply with the specific construction notification filing requirements the Bureau has previously provided by this public notice. Licensees that fail to satisfy the construction requirement must file their construction notification according to the specifications for KWYS, discussed below.

7. In the 700 MHz Second Report and Order, the Commission delegated responsibility to the Bureau for establishing the specifications for filing maps and other documents ( e.g., file format and appropriate data) needed to determine a licensee's service area. The Bureau previously outlined the specific construction notifications required by the Commission's rules in a series of public notices. The Bureau places construction notifications on public notice and reviews each notification and any related comments before making a determination regarding the notification. Interested parties are permitted to file comments, which must be filed no later than 30 days after the public notice release date.

8. After examining the construction notifications and public comments, the Bureau will determine whether each licensee has made a sufficient showing to satisfy the end-of-term construction benchmark and retain its entire license. The Bureau may return the filing and ask the licensee to amend the notification with additional or different information as it deems necessary, e.g., description of service, description of technology, or link budgets. Alternatively, if a licensee files a notification admitting failure, but does not conform to the specifications required for the KWYS process, the Bureau will return the filing and ask the licensee to amend it with the requirements described herein. If a licensee files a request for an extension of time or a waiver of the construction deadline and the Bureau denies the request, the Bureau will instruct the licensee to file a construction notification, either demonstrating compliance with the construction benchmark as of the end-of-term construction deadline or admitting failure. Licensees that fail to meet the end-of-term construction benchmark—whether they admit failure or are deemed by the Bureau to have failed following review of the construction notification—are subject to the KWYS rules and must file their construction notification according to the specifications for KWYS described below.

9. The Commission implements its long-standing auto-termination process here, in combination with the additional filing procedures established below to address the failure of a licensee to make required filings. If a licensee does not file either a request for extension of time before the construction deadline or the required construction notification within 15 days after the construction deadline (as required by § 1.946 of the Commission's rules), the Commission presumes that the license has not been constructed or the coverage requirement has not been met. As a result, the Bureau places such licenses in “Termination Pending” status and lists the license on the Weekly Termination Pending Public Notice. The Bureau also notifies the licensee by letter that, if it has met its construction requirement, it has 30 days from the date of that public notice to file a petition for reconsideration showing that it timely met the construction deadline. If the licensee does not file a petition for reconsideration within the 30-day reconsideration period showing timely construction, the Bureau updates its licensing records in the Commission's Universal Licensing System (ULS) to show the license as “Terminated,” effective as of the construction deadline. The license is also listed on a weekly public notice reflecting its status as changed to Terminated. This process will be applied to 700 MHz KWYS licenses. As applied to such licenses, failure to file either the required construction notification or a timely petition for reconsideration will result in automatic termination of the entire license, regardless of whether a licensee provides service in its license area such that it might otherwise retain that portion of the license under the KWYS rules. The Commission anticipates that this approach will ensure time to confirm that areas are only classified as unserved where the licensee is actually failing to provide service required by the Commission's rules, while avoiding unnecessary delays to the relicensing process.

10. In contrast, one commenter asks the Bureau to find that if licensees fail to file the required construction notifications, the entire license will terminate and become available for relicensing. This commenter also asks the Bureau to require licensees that seek to challenge the Bureau's evaluation of their performance demonstration to submit a map identifying the unserved areas pursuant to the Bureau's evaluation, and it suggests that a licensee's failure to do so should result in termination of the license. The commenter argues that, without these requirements, licensees could thwart the relicensing process, “which is dependent on a clear understanding of the geographic boundaries for served areas.” The Commission declines to implement this specific request to automatically terminate a license if the licensee fails to file the required construction notification so that the license is available for relicensing because it finds that the Commission's long-standing auto-termination process, in combination with the additional filing procedures established in this public notice, will adequately address the failure of a licensee to make required filings. The Commission agrees that the prompt commencement of the relicensing process depends on having licensees that fail to satisfy their construction requirements make the required KWYS filings, as it is these filings that will enable the Bureau to identify the unserved areas available for relicensing.

11. In the 700 MHz Relicensing Comment PN, the Commission noted that licensees that fail to meet the construction requirement—whether they admit failure or are found by the Bureau to have failed following review of the construction notification—are subject to the KWYS rules. Accordingly, they will be required to file an electronic coverage map that demarcates the geographic portion of the licensed area that the licensee will retain and the geographic area that will be returned to the Commission for reassignment. Licensees admitting failure must file their construction notification at the end-of-term construction deadline according to the specifications for KWYS described below. If a licensee claims to have met the construction benchmark, but the Bureau deems the licensee to have failed after review of the construction notification, the licensee will be asked to amend its initial construction notification filing to comply with the KWYS specifications.

12. In the 700 MHz Relicensing Comment PN, the Commission proposed a process whereby licensees would demonstrate the “served” areas of their license by submitting a shapefile showing a smooth enclosed 40 dBμV/m field strength contour  4 of existing facilities by the end-of-term deadline. The portion of the license market covered by the smooth contour would be deemed “served” for purposes of the KWYS rule and become the reduced licensed area that the licensee “keeps.” Noting the requirement that licensees not exceed 40 dBμV/m field strength at the license boundary, as well as the Commission's observations of existing services in the 700 MHz band, the Commission anticipated the 40 dBμV/m field strength smooth contour would be the most suitable means of determining licensees' service areas. However, because some licensees might provide service at lower field strength such that the 40 dBμV/m smooth contour would result in a reduced licensed area that might be substantially smaller than the licensee's actual service area, the Commission proposed an alternative option for licensees. Under the alternative option, if the 40 dBμV/m smooth contour would result in a reduced licensed area that is at least 25% smaller than the licensee's actual service area, the licensee could demonstrate the service area using a lower dBμV/m field strength smooth contour.

13. In response to the Commission's proposal, one commenter argues that the 40 dBμV/m field strength smooth contour will not accurately represent coverage provided by 700 MHz licensees, will penalize licensees providing service at lower field strengths, and will create unnecessarily duplicative coverage filings. Instead, this commenter suggests that the Commission allow licensees to “provide a coverage showing that is based on real-world service to the public and not be bound to a particular metric or technology in doing so.” Three additional commenters expressed general support of this position.

14. Because allowing licensees to tailor their demonstrations to the services they provide more accurately represents their service areas, the Commission agrees with these commenters' suggested modification of its proposal. Accordingly, licensees will be required to identify their service area based on the methodology the licensee deems to best represent the areas of coverage in which it provides service. 5 Licensees must file service area demonstrations that reflect the signal level that the licensee has previously represented as service to its customers ( e.g., in advertised coverage materials) and the Bureau ( e.g., in construction notifications), and licensees should be prepared to defend the methodology used. The Commission also reminds licensees that the service area demonstration will ultimately establish the licensees' revised license boundary; at the boundary, licensees will be required to comply with the 40 dBμV/m field strength limit for 700 MHz licensees set forth in the Commission's rules. Geographic areas to be made available for relicensing must include a contiguous area of at least 50 square miles, and areas smaller than that will be retained by the licensee. Licensees should include and identify such areas in the maps representing their service area. As with all other 700 MHz construction notifications, licensees are required to submit shapefiles, PDF maps, and technical narratives supporting their coverage demonstrations. As demonstrated in Figure 1 below, a licensee's shapefile map reflecting their service area must clearly reflect the market boundary and the areas served, and identify the unserved areas less than 50 square miles that the licensee is retaining.

15. One commenter asks the Bureau to consider a “county-based approach,” under which licensees that serve over 50% of the geography of a county would retain the entire county; licensees that cover 50% or less of a county, in contrast, would have their license area reduced so as to no longer include that county. This commenter argues that this approach would make spectrum available for relicensing in a more efficient manner and that, since most license authorizations are based on county boundaries, county-based areas would conform more easily to the boundaries of licensees' other spectrum assets. It further argues that allowing licensees to define license areas would be burdensome and could lead to inaccurate results. Three other commenters opposing the county-based approach argue that it runs counter to the purpose of the KWYS rules, as it would require licensees serving up to 50% of a county to cease providing service in those areas, while allowing other licensees to retain an entire county even where there were unserved areas in the county, thus leaving potentially large portions of unserved areas unavailable for relicensing.

16. The Commission rejects the county-based approach. Implementing this approach would require a rule change, which is beyond the scope of the authority delegated to the Bureau in the 700 MHz Second Report and Order. It also would be contrary to the underlying purpose of the KWYS rules. In other words, rather than fulfilling the purpose of the rules to allow failing licensees to keep the areas that they serve and make any unserved areas available for relicensing, a county-based determination of coverage would terminate the authorizations of certain licensees in areas where they actually are providing service, while allowing other licensees to retain up to half a county of unserved area.

17. As noted above, the Commission will allow licensees to demonstrate coverage based on their actual service in each geographic license area. A licensee must submit a coverage showing that reflects its actual service to the public, based on the methodology it deems to best represent the areas in which the public receives its actual service.

18. As the Commission also stated above, demonstrations of service area should reflect the signal level that the licensee has previously represented as service to its customers ( e.g., in advertised coverage materials) and the Bureau ( e.g., in construction notifications), and licensees should be prepared to defend the methodology used. The Commission cautions licensees that the Bureau will look critically at demonstrations that deviate from the metrics used in the licensee's interim construction notification or represented to its customers, especially showings that materially reduce the signal level at the boundary such that the demonstration might artificially inflate the licensee's service area.

19. While the Commission recognizes that license boundaries will not be uniform ( see Figure 1), 6 it warns licensees against including areas where no real service is provided that are merely figments of topography ( e.g., areas of high elevation distanced from and not part of areas where actual service is provided). Even though the reduced license boundaries will be non-uniform, applicants participating in the relicensing process can apply for adjacent unserved areas and take advantage of the flexibility in the Commission's power and secondary markets rules to coordinate and cooperate with neighboring licensees.

20. The Commission again reminds licensees that have not met their construction and service requirements that the service area demonstration, if approved, ultimately will establish the licensees' new license boundary. At the boundary, licensees will be required to comply with the 40 dBµV/m field strength limit for 700 MHz licensees set forth in the Commission's rules. Licensees must file demonstrations of service area using map and file formats similar to those required for construction notifications.

21. For these licensees, following the 30-day public notice period and after review of each KWYS filing and any related comments, if the Bureau agrees with the licensee's depiction of areas to be retained, it will accept the licensee's construction notification. The Bureau will also update ULS using the licensee's service area demonstration to reflect the reduced license area. The remaining portion of the original license market will be deemed unserved area and will return to the Commission's inventory for relicensing.

22. The Commission notes that the Bureau will have the opportunity to assess the success of this approach when it is implemented for the first group of licenses subject to KWYS. The Commission will monitor the results of the finalized process described above and will consider adjusting the methodology for future iterations of KWYS should the current approach prove to be cumbersome, inefficient, or ineffective.

23. Information about the available unserved areas will be publicly available. The Bureau will use the shapefiles submitted by failing licensees to determine the unserved areas of each market. The Bureau will then compile those unserved portions together as areas that will be available for relicensing and will provide instructions on how to access that information by public notice. The Bureau will provide applicants with access to a publicly available map displaying the areas available for relicensing, which they can view, download, and use to determine the areas for which they may wish to seek a license. The public notice announcing the unserved areas available for relicensing will also provide further instructions and specific dates for the commencement of the relicensing process. In setting these dates, the Bureau will provide at least 60 days before the commencement of relicensing to enable potential applicants to conduct all manner of due diligence, including evaluating sites and technical requirements, e.g., site acquisition or lease, existing infrastructure, neighboring operations, and network and backhaul needs. These inquiries are particularly important, given the requirements of licensees described in Section IIV.

24. Pursuant to the Commission's rules, relicensing of unserved areas will occur through a two-phase application process, beginning with a 30-day Phase 1 filing window, followed by a Phase 2 rolling window for applications. Applications for available unserved areas must be filed via ULS, and applicants must submit a shapefile describing the areas for which they seek a license.

25. In the interest of administrative clarity and functionality, the Commission proposed to limit the shapefiles attached to applications for unserved areas to include a single shape covering one contiguous area; if an applicant sought non-contiguous areas to be authorized under the same license, the Commission proposed requiring that the shapes be within a single market boundary. 7 The Commission also proposed that, if an applicant files for non-contiguous shapes in a single application, grant of the application would result in a single license and a single buildout requirement that would be applied to all shapes as a whole. Consequently, failure to meet the buildout requirement with respect to one non-contiguous shape would result in the imposition of the penalty for buildout failure on all shapes covered by the license.

26. Only one commenter addressed the Commission's proposals concerning the processing of applications. It requests that applicants be permitted to list all the unserved areas for which they seek a license within a single application to avoid the need to file multiple applications for each unserved area. Second, “rather than relying only on a map to indicate areas available for relicensing, this commenter suggests that the Bureau also provide a `drop-down list' of unserved areas that an interested party may select from when submitting its application.” One other commenter supported both suggested changes in its reply.

27. Consistent with the Commission's initial proposal, licenses issued through the relicensing process may cover unserved area that crosses market boundaries, as long as the license area is a single contiguous shape; if an applicant seeks a single license for multiple non-contiguous areas, those non-contiguous areas must fall within a single FCC-defined market boundary for the appropriate channel block. The Commission will modify the ULS system, however, so that applicants may file requests for multiple licenses within a single application form. 8 Under this process, the number of shapefiles uploaded within a single application form will dictate the number of licenses that will be issued, if the application is granted. For example, if an applicant wishes to apply for multiple areas to be authorized under separate licenses, it may do so within a single application form by uploading separate shapefiles, each covering the area(s) for which it seeks an individual license. Grant of the application will result in separate licenses being issued for the area(s) covered by each shapefile and separate buildout requirements for each license. If an applicant seeks to apply for multiple non-contiguous areas within a single market boundary to be authorized under a single license, it may do so by uploading to its application a single shapefile that includes each of those areas. Grant of the application will result in a single license and a single buildout requirement, which will apply to all the non-contiguous areas as a whole. A request for such a license could be combined in the same application form with requests for other licenses—whether covering another set of non-contiguous areas within a single market boundary, or covering one contiguous area—in which case each additional shapefile uploaded to the application form would result in an additional license.

28. While the Commission is taking several steps to make the relicensing process efficient and easy to use, it rejects the suggested “drop-down list” of available unserved areas. In the 700 MHz relicensing context, available unserved areas will be determined based on the non-uniform, potentially scattered service areas of failing licensees, which will be constantly changing as unserved areas are returned to the Commission's inventory. Moreover, applicants are free to apply to serve as much or as little available unserved area as they choose. Instead, the Commission provides greater flexibility for applicants to choose whatever portions of available unserved areas they wish to serve at that time rather than limiting applicant's choices to a pre-defined “drop-down list.” Therefore, the Commission will allow applicants to select from the available unserved areas by uploading a shapefile covering the area(s) for which they seek a license.

29. Parties must file applications for available unserved areas via ULS by submitting a shapefile describing the area for which they seek a license. Applicants can download the publicly available map displaying the available unserved areas and use the file to create the shapefiles to be included in their application. Acceptable shapefiles include all GIS Map File types, including XML, KML, KMZ, and Shape(zip). Subject to the restrictions of Phase 1 and other relicensing rules described below, applicants may apply for any sized area or number of available areas they choose. For instance, while only unserved areas that are at least 50 square miles will be returned to the Commission for relicensing, there is no minimum size requirement for applications to license available unserved areas. Given the stringent construction benchmarks for relicensed areas and the penalty for failure, described in Section IIV, it is particularly important that potential participants in the relicensing process perform due diligence to determine the areas to which they will be able to provide service, including inquiries about site acquisition or lease, existing infrastructure, neighboring operations, and network and backhaul needs. Applicants should only apply for portions of available unserved areas that accurately reflect their predicted service area based on precise engineering and projected signal propagation specific to the area.

30. As with other processes for the licensing of spectrum, at the application stage applicants will not be required to, and should not, file any technical specifications of the services they intend to provide. If an applicant submits any technical specifications or other information not required in the application, the Bureau will not review such information, and the Bureau's acceptance of an application that includes such information is not an acceptance of those technical specifications. Such filings with technical specifications of the service provided will be reviewed when the licensee files its notification of construction, as discussed in Section IIV.

31. All applications for available unserved areas found acceptable for filing (including the shapefile) will be placed on public notice, and the applications will be available for public review and comment. Because the shapefile contains the primary substantive information for which public notice is provided, i.e., details about the scope of the requested license area sufficient to determine whether the license application is mutually exclusive with another application, we do not anticipate a likely scenario in which confidential treatment of a shapefile would be warranted.

32. Form of Application. Applicants will file an application for either one or more new licenses or to modify an existing license. To file an application for a new license for available unserved area, applicants will select the ULS purpose code NE (New). Alternatively, modifications may be used where an applicant is an existing 700 MHz licensee of area adjacent to available unserved areas and wishes to expand the existing license area to contiguously cover a portion of that adjacent unserved area in the same frequency band. Licensees wishing to modify an existing license in such a manner will select the ULS purpose code MD (Modification). While unserved areas acquired as a new license will have a ten-year license term, the effect of requesting a modification of an existing license would be to include the same expiration date as the original license being modified. However, please note that the same construction requirements will apply, regardless of whether the area is acquired as a new license or a license modification.

33. Permissible Area(s) under Single License. A license issued through the relicensing process may cover unserved area that crosses market boundaries, as long as the license area is a single contiguous shape. If an applicant seeks a single license for multiple non-contiguous areas, those non-contiguous areas must fall within a single market boundary ( see Figure 2). With the exception of applicants filing license modifications during the first round of relicensing, 9 if a licensee wishes to modify an existing license to add available unserved area(s), it may do so as long as the area(s) are adjacent to the area of the existing license ( see Figure 2).

34. In Figure 2 above, the areas labeled as A through H represent unserved areas in various adjacent Cellular Market Areas (CMAs). An applicant could file for F, H, and D to be authorized under a single license, even though those areas cross multiple CMA boundaries, because they are all contiguous with each other. An applicant could also file for B, C, D, and E to be authorized under a single license, even though the areas are non-contiguous, because the non-contiguous areas fall within the same CMA. An applicant could not, however, apply for A and B to be authorized under a single license, because the areas are non-contiguous and are in different CMAs. Multiple licenses would be required to offer service in these areas.

35. Now suppose that in Figure 2 above, the area marked H represents an existing license for the entire market area of CMA089, which is adjacent to market areas containing the available unserved areas labeled A through G. If the licensee in CMA089 wanted to modify its license to add available unserved areas, it could do so with areas C, D, E, F, and G, because they are all contiguous to the existing license. However, the licensee in CMA089 could not modify its license to add areas A or B, because they are not contiguous to the existing license and are not within the same market area as the existing license. Provision of service in areas A or B would require a new license.

36. Applying for Multiple Licenses on a Single Application Form. Applicants seeking new licenses will have the flexibility to file requests for multiple licenses on a single application form. Under this process, the number of shapefiles uploaded within a single application form will dictate the number of licenses that will be issued if the application is granted. For example, if an applicant wishes to apply for multiple contiguous or non-contiguous areas to be authorized under separate licenses, it may do so within a single application form by uploading separate shapefiles, each covering the areas for which it seeks an individual license; grant of the application would result in separate licenses for the areas covered by each shapefile and an individual buildout requirement for each license. If an applicant seeks to apply for multiple non-contiguous areas to be authorized under a single license, it may do so (as long as the areas are within a single market boundary) by uploading to its application a single shapefile that includes all of those areas. Grant of the application would result in a single license and a single buildout requirement would apply to all shapes as a whole. A request for such a license could be combined on the same application form with requests for other licenses—whether covering another set of non-contiguous areas within a single market boundary or covering one contiguous area—in which case each additional shapefile uploaded to the application form would result in an additional license. This functionality will not apply to license modifications, however, because applications to expand into unserved areas adjacent to an existing license require processing through an individual license modification application.

37. Error Codes. When an applicant uploads a shapefile in an application for unserved area that does not conform to the requirements for shapefile filing format, the system will display an error code. The table in Figure 3 below provides an explanation of each error code and how it can be resolved.

38. Ownership Certification. Section 27.14 bars the original licensee of available unserved areas, whose authorization to serve that area terminated due to failure to meet the end-of-term construction benchmark, from applying to relicense that area during Phase 1. The section also permanently bars licensees of areas acquired through the relicensing process from applying to serve that area at any future date if they fail to satisfy the one-year 100% construction requirement.

39. In order to implement § 27.14(j)'s requirements, the Commission proposed to apply the prohibition to any applicant that has any interest or ownership in, or any control of, the original licensee and to any applicant in which the original licensee has any interest, ownership, or control. The Commission sought comment on requiring applicants to make certain certifications regarding the applicant's relationship to any barred parties in each application for unserved area (Ownership Certification). 10 Alternatively, the Commission sought comment on using a standard similar to the one the Commission uses in evaluating pro forma transfers of control, which considers both de jure and de facto control of the licensee, and the Commission asked whether such a standard might be more appropriate than the proposed bright-line test for ownership.

40. All commenters addressing this issue favored the alternate proposal, which would apply the bar based on de jure or de facto control. One commenter argues that barring parties with any interest in a barred party, as proposed, might go too far, and that such a bright-line rule “could inadvertently exclude parties that were not in control of the initial 700 MHz licensee that failed to provide service.” Instead, this commenter argues that determining ownership based on de jure and de facto control will allow the Bureau more effectively and precisely to bar the correct parties. Another commenter asks the Bureau to “take an expansive view of this bar,” and apply the bar to any parties that “have had a management agreement, lease arrangement, or similar interests in the licensee.”  11

41. The Commission concludes, based on the record, that its alternative proposal of using de jure and de facto standards of control will best serve its goals of encouraging licensees to satisfy their construction requirements while providing others with the opportunity to serve areas that remain unconstructed, and ensuring that the appropriate entities are barred from filing pursuant to Commission rule § 27.14. The Commission's initial proposal was designed to provide an easily administered bright-line test to prevent potential gaming of the relicensing process. After review of the record, the Commission recognizes that such a broad standard may inadvertently exclude entities that do not have a significant connection, in terms of ownership or control, with the barred licensee to be indicative of the applicant's future actions. It is the Commission's predictive judgement that using a de jure and de facto standard of control approach strikes a balance that will help to promote a larger and more diverse pool of applicants—particularly given the Commission's goal of promoting prompt provision of service through adoption of a one-year construction period for relicensed areas. In light of this balance, the Commission does not agree with the commenter suggesting that the existence of management agreements or lease arrangements with a barred entity should be sufficient to bar an applicant in all cases. However, the Commission finds that the fact-specific, case-by-case nature of the de jure and de facto control standard will provide the Commission the flexibility to consider that nature of various business relationships between parties to determine whether a party is barred from filing under § 27.14. 12 The Commission therefore makes modifications to its proposed Ownership Certification as described below to implement the rule § 27.14 bar applicable to: (1) Temporarily during Phase 1 to licensees that failed to satisfy their initial term construction requirements (Original Licensee), and (2) permanently to licensees of relicensed area that fail to satisfy the construction requirements (Relicensed Area Licensee).

42. The Commission defines “Original Licensee” or “Relicensed Area Licensee” to include any entities or individuals that have either de jure or de facto of the party that failed to satisfy the construction requirement, and any entities in which the party that failed to satisfy the construction requirement has either de jure or de facto control. A would-be applicant will be barred from applying to serve available unserved areas if any entity or individual that had or has de jure or de facto control of the Original Licensee or Relicensed Area Licensee also has de jure or de facto control of the applicant, the applicant has either de jure or de facto control of the Original Licensee or Relicensed Area Licensee, or if the Original Licensee or Relicensed Area Licensee has de jure or de facto control of the applicant.

43. All applications for available unserved areas filed during both phases of relicensing must include as an attachment the Ownership Certification provided below. While applicants will not be required to file any supporting documentation with respect to the Ownership Certification, the Bureau may request such information at its discretion.

44. One commenter asks the Bureau to create a “Tribal Priority” for the relicensing process. Under its proposal, qualifying Tribal entities would notify the Bureau of “proposed Tribal Lands they wish to serve and, after notice and comment, such lands would be removed from the areas available for relicensing.” This commenter asks for several amendments to the Commission's part 27 rules to implement its proposal. It also asks the Commission to delay the commencement of the relicensing process, as well as to modify and extend our construction obligations for qualifying Tribal entities.

45. The Commission did not adopt any type of priority for Tribal entities when it established the KWYS rules and relicensing process in the 700 MHz Second Report and Order. 14 Moreover, the Bureau did not make any proposals relating to a Tribal Priority in the 700 MHz Relicensing Comment PN. Accordingly, the Commission finds these requests are beyond the scope of the authority delegated to the Bureau in this context and that its comments are outside the scope of the public notice seeking comment on specific aspects for implementing that process. The Commission therefore takes no substantive action in response to those requests, and they will not be considered further in connection with the Bureau's implementation of this relicensing process. 15

46. Filing Window. Relicensing will begin with a 30-day Phase 1 filing window. At least 60 days before the commencement of the relicensing process, the Bureau will issue a public notice announcing the available unserved areas and the relevant dates on which the Phase 1 filing window will start and end. During this Phase 1 filing window, the original licensee of available unserved areas, whose authorization to serve that area terminated due to failure to meet the end-of-term construction benchmark, is barred from applying to relicense that area. This Phase 1 bar is specific to each unserved area, and therefore an applicant that is barred from applying for one unserved area during Phase 1 is not barred from applying for other available areas for which it was not the original licensee. All applications received during the Phase 1 filing window for a particular unserved area are treated as contemporaneous for the purposes of mutual exclusivity. At the end of the 30-day Phase 1 filing window, the Bureau will issue a public notice listing applications found acceptable for filing during Phase 1, and identifying which acceptable applications, if any, are mutually exclusive. No further applications that are mutually exclusive of a pending Phase 1 application may be filed after the 30-day Phase 1 filing window has ended, but licensees and third parties may file petitions to deny any pending applications within 30 days of the release of the public notice listing Phase 1 applications found acceptable for filing.

47. Mutual Exclusivity. Applications will be deemed mutually exclusive if they propose areas overlapping with other applications. As proposed, this definition of mutually exclusive applications includes “daisy chains” of mutual exclusivity, see Figure 7, which occur when two or more applications contain proposed areas that do not directly overlap, but are linked together into a chain by the overlapping proposals of others. Mutually exclusive applications are subject to auction and the Bureau will provide a limited settlement period for the applicants to resolve the mutual exclusivity prior to auction. Subject to the Greenmail Rule, applicants may resolve mutual exclusivity by withdrawing or filing a minor amendment to one or both mutually exclusive applications.

48. Settlement. Pursuant to the Communications Act and the Commission's rules, mutually exclusive applications are subject to auction. The Commission delegated authority to the Bureau to designate a limited settlement period for the applicants to resolve the mutual exclusivity prior to auction. In the 700 MHz Relicensing Comment PN, the Commission proposed that Phase 1 applicants would be permitted to resolve their mutually exclusive applications during a 30-day period that follows the close of the Phase 1 filing window.

49. One commenter asks the Bureau to “provide additional time for settlement discussions following the Phase 1 filing window,” as the 30-day Phase 1 public notice period may be insufficient for the parties to negotiate and settle their mutually exclusive applications. No other parties filed comments in response to this request.

50. Given the complexity of resolving mutually exclusive applications in either Phase 1 or Phase 2, 16 the Commission provides applicants consistency by giving Phase 1 applicants the same settlement period that we proposed for Phase 2 applicants. Therefore, upon release of the public notice listing the applications found acceptable for filing during Phase 1, applicants will have 60 days to attempt to reach a settlement concerning the mutually exclusive applications. Any mutual exclusivity that is not resolved by the end of the 60-day period will subject the mutually exclusive applications to auction.

51. Amendments. Amendments to an application are considered either major amendments or minor amendments, depending on the circumstance. If one or both of the applicants agrees to reduce or “pull back” the area covered by the application to avoid mutual exclusivity, the change is deemed a minor amendment. Minor amendments do not materially alter the original applications and do not require a new public notice period. Such treatment, however, is not available when a modification to an application constitutes a major amendment. If the applicants' agreement would require that either application be modified to “move” the area applied for, such that it would include area that was not part of the area specified in the application as originally filed, 17 such a change would be deemed a major amendment. Because major amendments constitute new applications for unserved area, major amendments to Phase 1 applications after the 30-day Phase 1 filing window has ended are not permitted, and the underlying application may be dismissed unless the applicant withdraws the major amendment or adjusts the filing to represent only a minor amendment. At that point, the dismissed applicant could file a new application for a license covering the modified area, but such application, because it would be filed during Phase 2, would be subject to potential Phase 2 competing filings.

52. Figure 4 above represents two existing licensees—one in CMA435 and one in CMA089—that have applied for available unserved areas adjacent to both existing licenses, in CMA436. Because the areas covered by the applications overlap, the applications are mutually exclusive. In Figure 5, the licensee in CMA089 has pulled back its application for unserved area to eliminate the overlapping area, thereby avoiding mutual exclusivity. Figure 5 reduces the area of the application and therefore represents a minor amendment. In contrast, in Figure 6, in addition to pulling back its application to eliminate the overlapping area, the licensee in CMA089 has also expanded its application to include additional available unserved area in CMA436. While the amendment in Figure 6 avoids mutual exclusivity, it adds unserved area that was not included in the application as originally filed, and therefore represents a major amendment. Such major amendments, if filed after the 30-day Phase 1 filing window has ended, are not permitted; therefore, the underlying application may be dismissed unless the applicant withdraws the major amendment or adjusts the filing to represent only a minor amendment.

53. Following Phase 1, the Bureau will issue a public notice that will (1) list applications found acceptable for filing during Phase 1, (2) direct interested parties to the publicly available information about the available unserved areas, and (3) announce the date on which the Bureau will begin accepting Phase 2 applications. The Bureau will update the publicly available relicensing map to reflect pending applications, licenses that were issued, and areas that remain available for relicensing.

54. During Phase 2, interested applicants, including those that were barred during Phase 1, may file applications on a rolling basis for available unserved areas that were not licensed during Phase 1 or for which there are no pending applications. However, licensees that have failed to satisfy the construction requirements for relicensed area are permanently barred from applying to serve that area at any future date, including during Phase 2. The Bureau will place each first-filed Phase 2 application deemed acceptable for filing on public notice for 30 days, during which interested applicants may file mutually exclusive applications subject to the guidelines in this document.

55. Mutual Exclusivity. As with Phase 1, Phase 2 applications will be deemed mutually exclusive if they propose areas overlapping with other applications. This definition of mutually exclusive applications includes “daisy chains” of mutual exclusivity, which occur when two or more applications contain proposed areas that do not directly overlap but are linked together in a chain by the overlapping proposal(s) of other(s), see Figure 7. The date of the public notice of the first-filed application in a given unserved area will establish the 30-day filing period for all subsequent applications that are mutually exclusive—whether directly or through a “daisy chain” relationship—with the first-filed application. The Bureau may dismiss any further mutually exclusive applications filed after this 30-day filing period, unless the applicant amends the application to avoid mutual exclusivity. Mutually exclusive applications are subject to auction and the Bureau may designate a limited settlement period for the applicants to resolve the mutual exclusivity prior to auction. Subject to the Greenmail Rule, applicants may resolve mutual exclusivity by withdrawing or filing a minor amendment to one or both mutually exclusive applications.

56. Figure 7 illustrates how applications that do not directly overlap with other applications may nevertheless be considered mutually exclusive through a daisy chain. In Figure 7, an applicant files Application 1 for available unserved area during Phase 2, which starts a 30-day public notice period during which third parties may file petitions to deny and applications that are mutually exclusive of Application 1. On day 10 of Application 1's public notice period, a party files Application 2, which is mutually exclusive of Application 1. On day 20 of Application 1's public notice period, another party files Application 3, which is mutually exclusive of Application 2, but not mutually exclusive of Application 1. Applications 1, 2, and 3 represent a daisy chain of mutual exclusivity and all three applicants would be required to reach a settlement to avoid an auction to resolve the conflicting applications. Applications 4 and 5 are filed on day 40, after the close of Application 1's public notice period. Unless Application 4 is amended to avoid mutual exclusivity, Application 4 may be dismissed because it is mutually exclusive of Application 1 and was filed after the close of Application 1's public notice period. Application 5 is mutually exclusive of Application 3 and may be dismissed unless amended to avoid mutual exclusivity, because it is part of the daisy chain of mutual exclusivity with Application 1 and was filed outside of the first-filed application's public notice period.

57. Settlement. As proposed, following a Phase 2 application's 30-day public notice period, if the Bureau determines there are existing applications that are mutually exclusive of the initial application, it will issue a public notice identifying the conflicting applications and providing the parties with 60 days to resolve the mutual exclusivity. Any mutually exclusive applications that are not resolved by the end of the 60-day period are subject to auction.

58. Amendments. As with Phase 1, Phase 2 applicants may withdraw or amend their applications to avoid mutual exclusivity. In contrast to Phase 1, both major and minor amendments to Phase 2 applications are permitted, see Figures 4-6, and such amendments may be filed during the first-filed application's public notice period or the period for settlement of mutually exclusive applications described below. A major amendment to a pending application, however, will require a new public notice period during which the applicant would be subject to further mutually exclusive applications.

59. Licensees of 700 MHz licenses acquired through the relicensing process will have one year from the date the new license is issued to complete construction, provide signal coverage, and offer service over 100% of the geographic area of the relicensed area. If the licensee fails to meet this construction requirement, its license will automatically terminate without Commission action and it will be ineligible to apply to provide service to that area at any future date. Unlike the KWYS rules, which provide that unserved area less than 50 square miles will be deemed “served” for purposes of determining a failing licensee's service area, the rules setting forth the construction requirements for relicensed area do not contain any provision for treating such smaller unserved portions of a licensee's service area as “served.” Rather, § 27.14(j)(3) states, without exception, that the failure of a licensee of relicensed area to complete its construction and provide signal coverage and offer service over 100% of the geographic area of the new license area will result in the automatic termination of the license. Therefore, any portion of the relicensed area that remains unserved at the one-year construction deadline—even if less than 50 square miles—will result in failure to satisfy this requirement and application of the penalty for failure.

60. In the 700 MHz Relicensing Comment PN, the Commission proposed that licensees would not be permitted to modify the license to reduce the licensed area before meeting the one-year construction benchmark, as this would effectively avoid the 100% geographic coverage requirement by reducing the area they must cover.

61. One commenter asks the Bureau to apply a de minimis standard to reductions in license area before the one-year construction benchmark and to permit license modifications as long as the modification does not result in a reduction of greater than 10% in the size of the licensed area. This commenter asserts that the “vagaries of RF radiation” make it difficult for a licensee to precisely duplicate its predicted coverage. The commenter argues that permitting 10% license reductions “will balance the occasional need of a licensee to reduce the size of its coverage area by a de minimis amount to account for real world technical impediments against the Bureau's desire to deter manipulation of its relicensing process.” None of the commenting parties filed in response to this request.

62. The Commission rejects this commenter's proposal, as it would permit a licensee to construct only 90% of the area originally authorized through relicensing without losing the license. Such a proposal is inconsistent with the 100% construction requirement that the Commission adopted and outside the scope of the Bureau's delegated authority. The Commission provided applicants with the flexibility to select whatever size of available unserved areas they choose, and applicants can take into account the variations in real world signal propagation when determining the area they seek to license.

63. Therefore, as proposed, the Commission will deem any modification to reduce the license area of a license acquired through the relicensing process as a failure to satisfy the 100% construction requirement. Such a failure will result in automatic termination of the license and a permanent bar on the licensee, including any entities that would be barred as a result of their relationship to the former licensee, from applying to serve that area at any future date.

64. In the 700 MHz Relicensing Comment PN, we proposed that licensees would be permitted to file applications to assign licenses acquired through relicensing (including requests to partition and disaggregate) only after they have demonstrated that they have met the construction benchmark. The Commission observed that, while the Bureau believes this procedure for assignment would best promote administrative efficiency, we would consider waivers for larger assignment transactions on a case-by-case basis.

65. One commenter objects to the Bureau's proposal to only allow assignment applications after a licensee has satisfied its construction requirement. It argues that the Bureau should permit such assignments “so long as the successor entities are bound by the same 100% coverage requirement at the end of the one-year construction deadline.” None of the commenting parties filed in response to this request.

66. The Commission agrees that this commenter's proposal would increase the flexibility of the Commission's proposed approach without creating unnecessary mutually exclusive applications filed against those of applicants that actually intend to serve those areas. In the WRS Renewal Second Report and Order (82 FR 41531, Sept. 1, 2017), the Commission adopted a requirement that parties to a partition or disaggregation agreement either: (1) Each certify that they will independently meet the construction requirements; or (2) agree to share the responsibility for satisfying the construction requirements. 18 Under the Commission's construction rules, however, in the case of a full assignment, only the assignee, not the assignor, is responsible for satisfying the one-year construction benchmark.

67. To provide the flexibility sought, while at the same time preventing potential gaming of the relicensing process, the Commission will permit assignment of relicensed area (including through partition or disaggregation) before satisfying the one-year construction benchmark subject to two restrictions.

68. First, the license may not be assigned to any parties that would have been barred, given their relationship to the assignor, from applying to serve the relicensed area during the phase of relicensing in which the assignor acquired it. For example, a party that would have been barred from applying during Phase 1 for a particular area could not acquire that area through assignment if the current licensee acquired it during Phase 1, but that same party could acquire it through assignment from a licensee who acquired it during Phase 2 (when the party would no longer have been barred from applying to serve the area). A party who is permanently barred from applying to serve an area due to failure to satisfy the construction requirements for relicensed area would be barred from acquiring that area through assignment in any case, irrespective of whether the current licensee acquired it during Phase 1 or 2.

69. Second, if the one-year construction benchmark is not satisfied with respect to the entire relicensed area, the penalty for failure, i.e., automatic termination of the license and a permanent bar from serving that area at any future date, will apply to all parties to the transaction, including any entities that would be barred as a result of their relationship to either party to the transaction, regardless of whether the assignment is a full assignment, partition, or disaggregation.

70. By eliminating any potential secondary market for assignments to barred parties and holding the assignor, as well as the assignee, accountable for failure to satisfy the construction requirement, the Commission finds this approach will adequately discourage gaming and speculation during the relicensing process. The Commission will require assignment applications filed before the one-year construction benchmark to include the same Ownership Certification regarding non-barred status that applicants are required to file when applying for available unserved areas in the relicensing process.

71. In the 700 MHz Relicensing Comment PN, the Commission proposed to treat any cancellation of a license before meeting the 100% coverage requirement as a failure to satisfy the performance obligations. No party objected to this proposal. The Commission adopts this proposal, based upon the rationale described in the public notice—namely, that it provides an incentive for rapid deployment of service on relicensed spectrum. Therefore, the Commission will deem the cancellation of a license before meeting the one-year construction benchmark as failure to satisfy the required performance obligations. Consequently, the cancelling licensee, including any entities that would be barred because of their relationship to the cancelling licensee, will be ineligible to apply to serve any portion of the cancelled license area at any future date.

72. Licensees must demonstrate compliance with the one-year construction benchmark by filing a construction notification with the Commission no later than 15 days after the relevant deadline demonstrating that they have met the construction requirements. To implement this requirement, the Commission proposed that, at the one-year construction deadline, licensees would be required to demonstrate that they provide signal coverage and offer service to 100% of the geographic area by filing either a 40 dBµV/m smooth contour or an alternative smooth contour. No commenters responded directly to this proposal. Nonetheless, the Commission adjusts our final approach in light of the changes we made above to the required KWYS filing service area demonstration.

73. Accordingly, licensees must demonstrate compliance with the 100% geographic coverage requirement by filing a service area demonstration that reflects their actual service in the license area, based on the methodology the licensee deems to best represent the areas in which it provides an actual service. The Commission expects that licensees will have used due diligence and made necessary inquiries to ensure their ability to meet our 100% geographic coverage requirement before filing their application for unserved areas. Demonstrations of service area should reflect the signal strength that the licensee represents to its customers as service, and licensees should be prepared to defend the methodology used. The Commission cautions licensees that the Bureau will look critically at showings that materially reduce the signal level at the boundary such that the demonstration might artificially inflate the licensee's coverage area. While licensees are permitted to file construction demonstrations that reflect the signal levels they deem to represent the services they provide, those signal levels may not result in a field strength that exceeds 40 dBµV/m at the license boundary, as licensees of relicensed area will be bound by the same license boundary field strength limit applicable to all 700 MHz licensees. As with the KWYS showing, the Commission will require that construction demonstrations be filed using the map and filing formats described herein.

74. The Bureau places construction notifications on public notice and reviews each notification and any related comments before making a determination regarding the notification. Interested parties are permitted to file comments, which must be filed no later than 30 days after the public notice release date. After examining the construction notifications and public comments, the Bureau determines whether each licensee has made a sufficient showing to satisfy the one-year construction benchmark and retain its license.

75. If a licensee does not file either a request for extension of time before the construction deadline, or the required construction notification within 15 days after the construction deadline, as required by § 1.946 of the Commission's rules, the Commission presumes that the license has not been constructed, or the coverage requirement has not been met. As a result, the Bureau places such licenses in “Termination Pending” status and lists the license on the Weekly Termination Pending Public Notice. The Bureau also notifies the licensee by letter that, if it has met its construction requirement, it has 30 days from the date of that public notice to file a petition for reconsideration showing that it timely met the construction deadline. If the licensee does not file a petition for reconsideration within the 30-day reconsideration period showing timely construction, the Bureau updates its licensing records in ULS to show the license as “Terminated,” effective as of the construction deadline. The license is also listed on a weekly public notice reflecting its status as changed to Terminated. The former licensee of the terminated license, including any entities that would be barred because of their relationship to the former licensee, will also be permanently barred from applying to serve the terminated license area at any future date.

76. If a licensee of relicensed area fails to satisfy the one-year 100% construction requirement, the entire relicensed area returns to the Commission's inventory for relicensing. Such area would enter relicensing via Phase 2 status, as there would be no applicable Phase 1 bar such that the 30-day Phase 1 filing window is necessary. Except for the barred parties and related entities, interested parties are permitted to begin filing applications to serve the area on the 30th day after the release of the public notice listing the license as terminated.

77. Regulatory Flexibility Analysis. As required by the Regulatory Flexibility Act of 1980 (RFA), the Commission prepared an Initial Regulatory Flexibility Analysis (IRFA) in connection with the 700 MHz Further Notice   19 and a Final Regulatory Flexibility Analysis (FRFA) in connection with the 700 MHz Second Report and Order . 20 While no commenter directly responded to the IRFA, the FRFA addressed concerns about the impact on small business of the KWYS rules. The IRFA and FRFA set forth the need for and objectives of the Commission's rules for the KWYS rules; the legal basis for those rules, a description and estimate of the number of small entities to which the rules apply; a description of projected reporting, recordkeeping, and other compliance requirements for small entities; steps taken to minimize the significant economic impact on small entities and significant alternatives considered; and a statement that there are no federal rules that may duplicate, overlap, or conflict with the rules. While the proposals in the 700 MHz Relicensing Comment PN did not change any of those descriptions, the Commission sought comment on whether the implementation of our proposals might affect either the IRFA or the FRFA. No comments were filed in response to the 700 MHz Relicensing Comment PN with respect to potential impacts on the IRFA or the FRFA, and the Commission concluded that the implementation of its proposals herein has had no further impact beyond that identified in the IRFA and FRFA.

78. Paperwork Reduction Act. This document does not contain proposed information collection(s) subject to the Paperwork Reduction Act of 1995 (PRA), Public Law 104-13. In addition, it does not contain any new or modified information collection burden for small business concerns with fewer than 25 employees, pursuant to the Small Business Paperwork Relief Act of 2002, Public Law 107-198, see 44 U.S.C. 3506(c)(4).

79. Congressional Review Act. The Commission will send a copy of this Public Notice to Congress and the Government Accountability office, pursuant to the Congressional Review Act. See 5 U.S.C. 801(a)(1)(A).

80. This document shall become effective thirty (30) days after the date of publication in the Federal Register .

81. Action taken under delegated authority pursuant to §§ 0.131 and 0.331 of the Commission's rules, 47 CFR 0.131, 0.331, and Service Rules for 698-746, 747-762, and 777-792 MHz Bands et al., Second Report and Order, 22 FCC Rcd 15289 (2007).

This is a summary of the Commission's Misuse of internet Protocol (IP) Captioned Telephone Service; Telecommunications Relay Services and Speech-to-Speech Services for Individuals with Hearing and Speech Disabilities, Report and Order, document FCC 19-11, adopted on February 14, 2019, released on February 15, 2019, in CG Docket Nos. 03-123 and 13-24. The Commission previously sought comment on these issues in Misuse of internet Protocol (IP) Captioned Telephone Service; Telecommunications Relay Services and Speech-to-Speech Services for Individuals with Hearing and Speech Difficulties, published at 78 FR 54201, September 3, 2013 ( 2013 IP CTS Reform FNPRM ). A Further Notice of Proposed Rulemaking (Further Notice) is contained in document FCC 19-11 and addresses additional issues concerning account identifiers, service for new users, and simplification of 911 call-handling for some forms of IP CTS. The Further Notice will be published elsewhere in the Federal Register . The full text of document FCC 19-11 will be available for public inspection and copying via the Commission's Electronic Comment Filing System (ECFS), and during regular business hours at the FCC Reference Information Center, Portals II, 445 12th Street SW, Room CY-A257, Washington, DC 20554. To request materials in accessible formats for people with disabilities (Braille, large print, electronic files, audio format), send an email to fcc504@fcc.gov, or call the Consumer and Governmental Affairs Bureau at (202) 418-0530 (voice) or (202) 418-0432 (TTY).

The Commission sent a copy of document FCC 19-11 to Congress and the Government Accountability Office pursuant to the Congressional Review Act, 5 U.S.C. 801(a)(1)(A).

The Report and Order in document FCC 19-11 contains modified information collection requirements, which are not effective until approval is obtained from OMB. The Commission, as part of its continuing effort to reduce paperwork burdens, will invite the general public to comment on these information collection requirements as required by the Paperwork Reduction Act (PRA) of 1995, Public Law 104-13. The Commission will publish a separate document in the Federal Register announcing approval of the information collection requirements. Pursuant to the Small Business Paperwork Relief Act of 2002, Public Law 107-198, 44 U.S.C. 3506(c)(4), the Commission previously sought comment on how the Commission might “further reduce the information burden for small business concerns with fewer than 25 employees.” 2013 IP CTS Reform FNPRM .

1. In 2013, the Commission directed the creation of a centralized system of user registration records, for initial application to VRS users and potential application to other forms of TRS. The core function of this Database is to enable the Commission to ensure that TRS is provided only to registered users whose eligibility has been established in accordance with program rules and whose identities have been verified based on uniform criteria. IP CTS, a form of TRS, allows individuals with hearing loss to both read captions and use their residual hearing to understand a telephone conversation.

2. The Commission amends its rules to require the integration of IP CTS into the TRS Database to better ensure accurate registration, verification, and validation of IP CTS users. By this action, the Commission takes further steps to ensure that TRS is made available “in the most efficient manner,” achieve consistency among internet-based TRS programs, and manage waste, fraud, and abuse risks. Expanding the Database to include IP CTS is especially important in light of the ease and convenience of using this service—which can also facilitate its improper use—as well as the incentives and ability of providers to market this service to individuals who do not need it. These factors may be contributing to the exponential IP CTS growth in recent years and have the potential to cause future waste in the program. Database registration of IP CTS users will enable the administrator to conduct objective identity verification in accordance with uniform criteria, perform more effective auditing and review of IP CTS provider practices, and better substantiate the eligibility of IP CTS minutes submitted for compensation, e.g., by matching provider-submitted call detail records with records of registered and verified IP CTS users. In addition, creating a central registry of IP CTS users will improve program management by enabling the Commission to compile and analyze aggregate data on the total number of IP CTS users; the number of IP CTS providers, devices, and phone numbers associated with each user; the pace of turnover among registered users; and other important program statistics and trends that are necessary for the Commission's effective and efficient implementation of the program.

3. Database registration and verification of IP CTS users is a straightforward prophylactic measure that is needed to safeguard the TRS Fund, whether or not the Commission has discovered waste, fraud, and abuse within this particular TRS program. The Commission is not required to wait for a major outbreak of fraud or abuse, such as occurred in two other TRS programs, before taking precautionary steps to prevent such harm from occurring in this program. The Commission has the authority and obligation to identify and improve programs that may be susceptible to waste, fraud, and abuse.

4. The rules the Commission adopts for IP CTS user data submission and verification largely parallel those in place for VRS. Although the two services differ in some respects, those differences do not warrant a substantially different approach to data submission. Therefore, with one exception, the data that the Commission now requires IP CTS providers to submit to the Database when registering users is substantially the same data that the Commission requires for VRS providers. Specifically, the Commission requires submission of a user's full name; full residential address; telephone number; electronic serial number (ESN) of the user's IP CTS device, the user's log-in identification or email address, or another unique identifier for the IP CTS user; last four digits of the user's social security number or Tribal Identification number; date of birth; Registered Location (if applicable); IP CTS provider name; date of service initiation and (when applicable) termination; (for existing users only) the date on which the IP CTS user last placed an IP CTS call; and a digital copy of the user's self-certification of eligibility.

5. The Commission also applies to IP CTS the same data submission and verification procedures used for VRS. These procedures are designed to ensure that IP CTS is used only by individuals who have registered with a provider, provided all required information, self-certified their eligibility to use the service, and had their identities verified in accordance with uniform criteria. Specifically, when the Database is ready to accept IP CTS user data, the Commission or CGB will release a public notice initiating a data submission period for uploading registration information on all current IP CTS users. By the end of the data submission period, IP CTS providers must have transmitted the required information to the Database, in a format prescribed by the Database administrator, for all IP CTS users in service as of the last day of the period. After the end of the period, an IP CTS provider will not be entitled to and shall not seek TRS Fund compensation for providing captioning service to any individual whose registration information has not been submitted to the Database. Further, an IP CTS provider shall not seek compensation for service to users who do not pass the Database identification verification check. However, if a provider submits the required information for an existing IP CTS user on or before the end of the data submission period, and verification by the Database has not been completed, the provider may request compensation for minutes of use incurred by such user after the deadline while verification is being completed, and the TRS Fund administrator will provide compensation for such minutes if the user is ultimately verified, including minutes of service that occur while an appeal of a user verification failure is pending.

6. For users who sign up for service after the end of the data submission period, similar procedures apply, except that providers must not register, or commence providing service to, such users until after the required registration data has been submitted and verified by the Database. The Commission expects that the administrator will coordinate with IP CTS providers, as it did with VRS providers, including conducting trials and tests of procedures for submitting and verifying user registration data. The Commission directs the Managing Director to oversee the integration of IP CTS into the Database and to determine when the Database is ready to accept the submission of IP CTS user data.

7. If an IP CTS provider learns that a registered user is no longer eligible to receive service or a user makes a request to cancel service, the Commission requires the IP CTS provider to promptly request removal of such user's registration from the Database. An IP CTS provider shall not seek TRS Fund compensation for captioning service to any individual whose registration information has been removed from the Database, or for whom the provider obtains information that the individual is not eligible to use IP CTS.

8. Data Privacy. The Commission concludes that the same privacy safeguards that currently protect Database data on VRS users also will be sufficient to protect the privacy of IP CTS users. As is required of VRS providers, IP CTS providers must obtain users' prior consent to transmit to the Database the user information provided by the users to the providers, after notifying the users of the data to be submitted, the reason for disclosure, and the consequences of nondisclosure. The Commission also has incorporated privacy by design into its data collection, limiting the information collected from providers to what is necessary to identify and verify users, and destroying the parts of such information it does not need to maintain long term. For example, only the last four digits of registrants' Social Security numbers are collected, and these truncated numbers are destroyed upon verification. Further, the Database procedures strictly limit access to user registration data and include security safeguards to protect the proprietary and personal information in the database.

9. Further, as a federal information technology system, the Database is reviewed and evaluated annually to ensure compliance with Federal Information Security Modernization Act (FISMA) requirements. In addition to FISMA and Privacy Act requirements, as with other databases the Commission has created to manage its programs, this database must be operated in accordance with the National Institute of Standards and Technology (NIST) guidance for secure, encrypted methods for obtaining, transmitting, storing, and disposing of program beneficiary information and certified program information. The database also must have subscriber notification procedures in the event of a breach that are compliant with Department of Homeland Security and guidance by the U.S. OMB. For the above reasons, and because there is no record evidence demonstrating their insufficiency, the Commission concludes that these layered privacy safeguards will be effective in protecting the personal data of registered IP CTS users—including senior citizens, whose personal data is maintained by many federal agencies.

10. Costs. The Commission concludes that the costs of integrating IP CTS users into the Database will be limited, as discussed below, and that they are reasonable in light of the importance of ensuring that IP CTS is immune from the waste, fraud, and abuse that have plagued the TRS program in the past. First, the Database is already built and has been activated for VRS. Thus, the administrator of this database already has established and tested procedures for collecting, organizing, verifying, protecting, and retrieving consumer registration data. While the database will increase in size, the Commission expects that additional staffing and technology needs are likely to be incremental, rather than substantial, for the TRS Fund. In addition, having thoroughly prepared for the activation of the Database for VRS, the Database administrator is now well acquainted with the planning and preparation processes, including trials and tests of procedures for submitting and verifying user registration data, that necessarily precede the activation of the Database for a new service. The experience gained in populating the Database with VRS user information will enable the Commission and the Database administrator to work efficiently with IP CTS providers to integrate IP CTS user data into the database through the existing administration processes.

11. The Commission expects that the costs incurred by IP CTS providers will be limited as well. IP CTS providers already have been collecting the user registration data that must be populated into the Database. Therefore, the Commission believes that additional expenses incurred by providers will be incurred primarily in contacting users to obtain consent for the submission of user data that already has been collected, uploading the data, and addressing any verification issues regarding such data. Further, IP CTS providers will not be requested to begin submitting user information to the database until the Managing Director determines that these processes have been effectively adapted for use by the IP CTS program and that there has been sufficient advance coordination with IP CTS providers to enable full understanding of such processes.

12. The Commission anticipates that providers' compliance costs will be further limited because, in contrast to VRS, it appears that relatively few IP CTS users register with multiple providers. Moreover, the absence of a per-call validation query requirement for IP CTS will substantially reduce providers' compliance costs. Finally, IP CTS providers will benefit from the administrator's previous work in the VRS context to establish protocols, procedures, and safeguards that are now in place.

13. For all these reasons, the Commission concludes that IP CTS providers' one-time Database implementation costs will not be materially greater than those incurred by VRS providers. For IP CTS, the Commission estimates that the total cost of Database implementation over a three-year period is $16-21 million. These Database implementation costs represent 0.6-0.8% of the $2.676 billion total expenditures on IP CTS in a three-year period. The rules adopted here provide needed accountability, given the marketing incentives inherent in the service. It is reasonable to conclude that these implementation costs are justified by the benefits of adding IP CTS to the Database, in light of the history of waste, fraud, and abuse in the TRS program generally, and the fact that IP CTS is the most heavily used, fastest growing, and largest TRS program.

14. The Commission will allow IP CTS providers to seek recovery of costs associated with implementing the Database during the interim IP CTS compensation period, in accordance with the Commission's exogenous cost recovery guidelines for VRS. Under these guidelines, the general application of which to IP CTS is currently under consideration by the Commission, well-documented provider costs resulting from new TRS requirements are recoverable if they (1) belong to recoverable cost categories, (2) are new costs not factored into the rates for the 2018-19 and 2019-20 TRS Fund years, and (3) if unrecovered may cause a provider's current allowable-expenses-plus-operating margin to exceed its IP CTS revenues. Database implementation costs, especially when incurred by smaller providers, may qualify for reimbursement under these guidelines, as they were not considered when the interim IP CTS compensation rates were determined. Although the Commission has yet to determine whether the VRS exogenous cost recovery guidelines should be generally applicable to IP CTS, the Commission will allow Database cost recovery in accordance with these guidelines during the interim compensation period in order to ensure that costs imposed by these new regulatory requirements are sufficiently addressed in provider compensation. This interim cost recovery measure will remain in effect until June 30, 2020, the end of the interim compensation period, or until a new IP CTS compensation rate becomes effective, whichever is earlier.

15. Differences in the Database Rules Applicable to IP CTS and VRS. The Commission makes the following changes in the Database rules to address issues that are unique to IP CTS and to apply lessons learned in activating the Database for VRS. First, because the record indicates that telephone numbers alone do not uniquely identify IP CTS users, the Commission amends its rules to provide that for IP CTS, the “necessary information for each registered user” submitted to the Database shall include a unique account identifier, such as the electronic serial number of any device provided to the user, the user's log-in ID, or an email address.

16. Second, for registered users of IP CTS who are minors, the Commission amends its rules to clarify that the self-certification of eligibility must be signed on behalf of the minor by the minor user's parent or legal guardian, and, in addition to submitting all the registration data required for other users, the provider must include the name and (if different) address of that parent or legal guardian.

17. Third, for IP CTS, the Commission will allow a one-year data submission period. The Commission makes this change because the IP CTS user population appears to be larger than the number of VRS users and has a disproportionate number of senior citizens, many of whom are more likely to require assistance from family members or others in providing written consent for the submission of information to the Database, and in providing supplemental information to the extent it is needed to complete verification. A one-year window will provide an ample period of time within which to complete the data submission process, and the Commission does not anticipate extending it. In the event that a provider is experiencing unusual difficulty in collecting user consents or otherwise preparing to comply, and finds that it needs to seek a waiver of the deadline, the Commission expects that the provider will make such a request, with a detailed showing and justification, no later than 120 days before the end of the data submission period.

18. Fourth, the Commission does not apply to IP CTS the per-call validation requirement of § 64.615(a) of the rules. Unlike in VRS, there is no dial-around calling in IP CTS, and so there is less need to have a provider query a central database in order to validate an IP CTS call made by a user who is not registered with that provider. Further, because IP CTS providers usually do not assign telephone numbers to registered users and often do not control the connection of calls, a requirement to query the Database for each call could pose practical difficulties for IP CTS that are not present for VRS.

19. Under the rules the Commission adopts in this Report and Order, an IP CTS provider is not entitled to and shall not seek compensation for service to, users whose registration data has not been submitted to the Database, has not passed the Database identification verification check, or has been removed from the Database. Thus, as a matter of maintaining compliance with these requirements, it will be in the interest of an IP CTS provider, before requesting compensation for any call, to check its own records and take any other steps it deems necessary to confirm that the user's registration data was submitted to and entered in (and not removed from) the Database prior to the call. The Commission does not find that there is a need to dictate the specific timing or procedure by which an IP CTS provider confirms compliance with these rules. Accordingly, IP CTS providers will not be required to send a specific call validation query to the Database or the TRS Numbering Directory at the beginning of each call.

20. Fifth, the Commission adopts an exception to the registration and verification requirements, to allow IP CTS providers to be compensated for captioning calls for users whose data has not been entered in the Database when such calls are made to or from temporary, public devices set up in emergency shelters. The Commission takes this step to ensure that users with hearing loss will continue to have access to telephone communications devices during and in the aftermath of natural disasters and other emergencies. However, IP CTS providers must register such devices in the Database before commencing service to such devices, by providing all information reasonably requested by the Database administrator, including the telephone number and location of the device. When service for such a device is initiated and terminated, the IP CTS provider must transmit the dates of activation and termination. Before requesting Fund compensation for calls involving such a device, the provider must check its own records to validate that the device was registered with the Database prior to the call.

21. As required by the Regulatory Flexibility Act of 1980 as amended (RFA), the Commission incorporated an Initial Regulatory Flexibility Analysis (IRFA) into the 2013 IP CTS Reform FNPRM. The Commission sought written public comment on the proposals in the 2013 IP CTS Reform FNPRM, including comment on the IRFA. No comments were received in response to the IRFA.

22. Document FCC 19-11 adopts rule changes to facilitate the Commission's efforts to reduce waste, fraud, and abuse and improve its ability to efficiently manage the IP CTS program by requiring IP CTS providers to (1) submit IP CTS user registration information to the TRS Database so that the Database administrator can verify IP CTS users; and (2) obtain and keep affirmative acknowledgement by every registered IP CTS user of the user's consent to the IP CTS provider to transmit such registration information to the Database.

23. Document FCC 19-11 also adopts rule changes providing that TRS Fund compensation may be paid only for IP CTS provided to users whose registration data has been submitted to and verified by the Database administrator; and that, when users are no longer eligible for or request cancellation of service, the IP CTS provider must remove the user's information from its database and notify the Database administrator of such removal.

24. No comments were filed in response to the IRFA.

25. The Chief Counsel for Advocacy of the Small Business Administration (SBA)did not file any comments in response to the proposed rules in this proceeding.

26. The rules adopted in Document FCC 19-11 will affect obligations of IP CTS providers. These services can be included within the broad economic category of All Other Telecommunications.

27. The rules on submitting user registration data to the Database will require IP CTS providers to submit information that they are currently required to collect from IP CTS users. IP CTS providers will also be required to obtain and keep affirmative acknowledgement by every registered IP CTS user of the user's consent to the IP CTS provider to transmit such registration information to the Database. The Commission has primarily aligned these reporting and recordkeeping requirements with similar requirements currently applicable to VRS providers. However, the Commission makes one addition to the Database registration requirements to require that unique account identifiers, such as the electronic serial numbers of user devices, users' log-in identifications, or email addresses, be included in the user registration information submitted to the Database administrator. Also, before commencing service to temporary, public IP CTS devices set up in emergency shelters, IP CTS providers must provide all information reasonably requested by the Database administrator, including the telephone number and location of the device, and an indication that the device is located in a public emergency shelter.

28. In addition, IP CTS providers are required to keep their registration databases current and notify the Database administrator of any users removed from their databases.

29. The rules requiring IP CTS providers to submit registration data to the Database will have only a minimal effect on small entities because the required data is already maintained by the providers. The increased burdens of obtaining consent from IP CTS users to submit the data to the Database, the retention of such information, and the submission process itself are minor as compared to the benefit of having the Database administrator verify the IP CTS users and relieving IP CTS providers of that obligation. Moreover, the order permits providers to seek reimbursement from the Interstate TRS Fund for exogenous costs associated with the submission of registration data to the Database until such time as the Commission adopts rates that take into consideration the costs associated with such submissions. The rules also require providers to notify the Database administrator of any users removed from their databases. These requirements are similar to the requirements placed on VRS providers.

30. Compared to the initial proposal, which also would have required IP CTS providers to validate each call by querying the Database, these requirements are more narrowly tailored to help the Commission identify and evaluate risks, monitor compliance with program rules, and minimize waste, fraud, and abuse in the IP CTS program and will not be burdensome because providers are already required to keep their databases current.

Pursuant to sections 201 and 225 of the Communications Act of 1934, as amended, 47 U.S.C. 201, 225, document FCC 19-11 is adopted, and Part 64 of Title 47 is amended.

For the reasons discussed in the preamble, the Federal Communications Commission amends 47 CFR part 64 as follows:

Background

The Federal Motor Carrier Safety Regulations (FMCSRs) are located in chapter III of subtitle B of title 49 of the Code of Federal Regulations (49 CFR parts 350 through 399). FMCSA employs regulatory guidance statements to explain how the Agency applies particular regulations to specific facts. A guidance statement does not alter the meaning of an FMCSR. Guidance statements are provided in question-and-answer format; statements interpreting the same regulation are numbered ( e.g., “Section 395.8, Question 7”).

The Agency notifies the public of regulatory guidance through publication in the Federal Register . Over the years, the Federal Highway Administration (FHWA), FMCSA's predecessor agency, and FMCSA have published regulatory guidance on numerous occasions interpreting many parts of the FMCSRs. In 1997, FHWA published a comprehensive compilation of its regulatory guidance (62 FR 16370, April 4, 1997). The Agency stated that regulatory guidance issued prior to that date was superseded to the extent it was inconsistent with the compilation. Agency guidance published since then has been limited to specific topics that amend or supplement the 1997 document.

Section 5203 of the Fixing America's Surface Transportation Act (Pub. L. 114-94, 129 Stat. 1312, 1535, Dec. 4, 2015) (FAST Act), titled “Guidance,” requires that each guidance document issued by FMCSA have a date of issuance or a date of revision, as applicable, and include the name and contact information of a point of contact at the Agency who can respond to questions regarding the guidance. In addition, this section of the FAST Act requires that each guidance document issued or revised by FMCSA be published on a publicly accessible internet website of the Department on the date of issuance or revision. As a result, these interpretations will also be published on FMCSA's website at www.fmcsa.dot.gov.

Further, Section 5203 requires that not later than 5 years after the date on which a guidance document is published under paragraph (a)(2) or during an applicable review under subsection (c), whichever is earlier, the Secretary must revise regulations to incorporate the guidance document to the extent practicable. FMCSA considered this requirement in making deletions and edits to guidance where the regulations themselves now fully address questions answered by the guidance. For example, Question 4 under section 383.73 clarifies that State Driver Licensing Agencies (SDLAs) may facilitate the commercial learner's permit application process and to administer the commercial driver's license general knowledge test to individuals who are not domiciled in that State. FMCSA anticipates publishing a rulemaking to incorporate the guidance document into the regulations. This question would be removed from the guidance when that rulemaking is complete.

Section 5203 also requires that the Administrator publish in the Federal Register a notice and request for comment that solicits input from stakeholders on which guidance documents should be updated or eliminated. Because improvement of guidance documents is a focus for all components of the Department (not just FMCSA), DOT will publish a Federal Register document inviting public comments on which DOT guidance (from any DOT operating administration) should be updated or eliminated. In addition, FMCSA is also reviewing its interpretations and guidance incrementally, starting with parts 383 and 384. This document serves as a separate request for comments and input on guidance for these specific parts.

In response to the FAST Act, FMCSA is also reviewing the guidance statements for 49 CFR part 325 (Compliance with Interstate Motor Carrier Noise Emission Standards) and the rest of the FMCSRs (49 CFR parts 350-382 and 385-399). Any such revisions shall be the subject of separate future Federal Register documents.

The Agency also tasked its Motor Carrier Safety Advisory Committee (MCSAC)  1 with reviewing the existing guidance statements to obtain stakeholders' views prior to making the preliminary decision concerning the deletion, revision, and reorganization of guidance statements. The MCSAC provided recommendations to FMCSA on November 21, 2016, which are available in the docket listed at the beginning of this document. The MCSAC recommendations included guidance statements for 49 CFR parts 383 and 384. FMCSA reviewed the MCSAC final report in the development of these guidance changes. It should be noted that the guidance published today does not include all of the deletions recommended by MCSAC because the Agency believes some of the guidance still has value. In other cases, FMCSA proposes to delete guidance not recommended for deletion by MCSAC.

Since the 1997 comprehensive publication, the guidance noted on the table below was deleted pursuant to the cited Federal Register documents. FMCSA restates those deletions in Table 1 of this document as subsequent regulatory publications did not properly reflect those deletions.

FMCSA deletes 47 regulatory guidance statements that interpret sections in parts 383 and 384 of the CDL regulations as shown in Table 2.

NMFS manages the groundfish fishery in the GOA exclusive economic zone according to the Fishery Management Plan for Groundfish of the Gulf of Alaska (FMP) prepared by the North Pacific Fishery Management Council under authority of the Magnuson-Stevens Fishery Conservation and Management Act. Regulations governing fishing by U.S. vessels in accordance with the FMP appear at subpart H of 50 CFR part 600 and 50 CFR part 679. Regulations governing sideboard protections for GOA groundfish fisheries appear at subpart B of 50 CFR part 680.

The A season allowance of the 2019 Pacific cod total allowable catch (TAC) apportioned to hook-and-line catcher/processors in the Central Regulatory Area of the GOA is 234 metric tons (mt), as established by the final 2018 and 2019 harvest specifications for groundfish of the GOA (83 FR 8786, March 1, 2018).

In accordance with § 679.20(d)(1)(i), the Administrator, Alaska Region, NMFS (Regional Administrator) has determined that the A season allowance of the 2019 Pacific cod TAC apportioned to hook-and-line catcher/processors in the Central Regulatory Area of the GOA will soon be reached. Therefore, the Regional Administrator is establishing a directed fishing allowance of 224 mt and is setting aside the remaining 10 mt as bycatch to support other anticipated groundfish fisheries. In accordance with § 679.20(d)(1)(iii), the Regional Administrator finds that this directed fishing allowance has been reached. Consequently, NMFS is prohibiting directed fishing for Pacific cod by hook-and-line catcher/processors in the Central Regulatory Area of the GOA. While this closure is effective the maximum retainable amounts at § 679.20(e) and (f) apply at any time during a trip.

This action responds to the best available information recently obtained from the fishery. The Assistant Administrator for Fisheries, NOAA (AA), finds good cause to waive the requirement to provide prior notice and opportunity for public comment pursuant to the authority set forth at 5 U.S.C. 553(b)(B) as such requirement is impracticable and contrary to the public interest. This requirement is impracticable and contrary to the public interest as it would prevent NMFS from responding to the most recent fisheries data in a timely fashion and would delay the directed fishing closure of Pacific cod by hook-and-line catcher/processors in the Central Regulatory Area of the GOA. NMFS was unable to publish a notice providing time for public comment because the most recent, relevant data only became available as of March 4, 2019.

The AA also finds good cause to waive the 30-day delay in the effective date of this action under 5 U.S.C. 553(d)(3). This finding is based upon the reasons provided above for waiver of prior notice and opportunity for public comment.

This action is required by § 679.20 and is exempt from review under Executive Order 12866.