2018-24482. Revisions to the Source-Specific Federal Implementation Plan for Navajo Generating Station, Navajo Nation

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Proposed rule.

SUMMARY:

The Environmental Protection Agency (EPA) is proposing limited revisions to the source-specific federal implementation plan (FIP) that regulates emissions from the Navajo Generating Station (NGS), a coal-fired power plant located on the reservation lands of the Navajo Nation near Page, Arizona. We are proposing to lower the emission limitation for particulate matter (PM) to conform to the most stringent emission limitation currently applicable to NGS under another EPA regulation, and to replace the opacity limitation and annual PM source testing requirement with a requirement to demonstrate compliance with the lower PM emission limitation using a continuous emission monitoring system for particulate matter.

DATES:

Any comments on this proposal must arrive by December 10, 2018.

ADDRESSES:

Submit your comments, identified by Docket ID number EPA-R09-OAR-2018-0590, at http://www.regulations.gov,, or via email to [e-mail]. For comments submitted at Regulations.gov, follow the online instructions for submitting comments. Once submitted, comments cannot be edited or removed from Regulations.gov. For either manner of submission, the EPA may publish any comment received to its public docket. Do not submit electronically any information you consider to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Multimedia submissions (audio, video, etc.) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. The EPA will generally not consider comments or comment contents located outside of the primary submission (i.e., on the Web, cloud, or other file sharing system). For additional submission methods, please contact the person identified in the FOR FURTHER INFORMATION CONTACT section. For the EPA's full public comment policy, information about CBI or multimedia submissions, and general guidance on making effective comments, please visit http://www2.epa.gov/​dockets/​commenting-epa-dockets.

FOR FURTHER INFORMATION CONTACT:

Anita Lee, EPA Region IX, [phone], [e-mail].

SUPPLEMENTARY INFORMATION:

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

Table of Contents

I. Background

A. Action

B. Facility

C. Attainment Status

D. The EPA's Authority To Promulgate a FIP in Indian Country

E. Historical Overview of NGS FIP Actions

II. Basis for Proposed Action

III. Summary of FIP Provisions

A. Proposed FIP Revisions

B. Justification for Proposed FIP Revisions

IV. Solicitation of Comments

V. Environmental Justice Considerations

VI. Statutory and Executive Order Reviews

I. Background

A. Action

In this action, the EPA is proposing limited revisions to the FIP for NGS that we promulgated on October 3, 1991 (“1991 FIP”), March 5, 2010 (“2010 FIP”), and August 8, 2014 (“2014 FIP”).^[1] The provisions of the 1991 action are codified in the Code of Federal Regulations (CFR) at 40 CFR 52.145(d), and the 2010 and 2014 regulations are codified at 40 CFR 49.5513. We refer collectively to the provisions from the 1991, 2010, and 2014 actions as the “FIP” or the “NGS FIP.” The NGS FIP includes federally enforceable emission limitations for PM, opacity, sulfur dioxide (SO₂), and oxides of nitrogen (NO_X).

Generally, the EPA is proposing to move provisions from the 1991 FIP to a different section of the CFR and to update certain provisions in the 1991 FIP to be consistent with recent national rulemakings. Specifically, we are proposing to move the 1991 FIP provisions from 40 CFR 52.145(d) to 40 CFR 49.5513. If finalized, the effect of our action will be to move requirements for NGS from subpart D of part 52, which contains the state implementation plan (SIP) provisions for Arizona, to subpart L of part 49, which contains source-specific FIP requirements for NGS, to consolidate all of the applicable requirements for NGS in one section of the CFR. We are proposing to update the definition of “boiler operating day” in the 1991 FIP to be consistent with the definition in the 2014 FIP.^[2]

In addition, we are proposing to revise the PM compliance demonstration from annual source testing to the use of PM continuous emissions monitoring systems (PM CEMS), which were installed and calibrated on each of the three units at the facility in 2016. We are also proposing to lower the PM emission limitation in the 2010 FIP from 0.060 pounds per million British thermal units (lb/MMBtu) to 0.030 lb/MMBtu. This lower emission limitation already applies to NGS pursuant to the EPA's Mercury and Air Toxics Standard (MATS) Rule.^[3] Because the operator of NGS will be using PM CEMS to demonstrate compliance with the 0.030 lb/MMBtu emission limitation for PM, the EPA is also proposing to remove the opacity emission limitation and associated continuous opacity monitoring system (COMS) requirements from the NGS FIP. The opacity limitation and COMS have generally functioned as surrogates for ensuring compliance with PM emission limitations. This proposed revision is consistent with the provisions related to PM CEMS and opacity in the New Source Performance Standard for Electric Utility Steam Generating Units (“NSPS for EGUs”) and the Acid Rain Program requirements at 40 CFR 75.14(e), which generally provide that any owner or operator that elects to install, calibrate, maintain, and operate a PM CEMS for demonstrating compliance with a sufficiently stringent PM emission limitation (i.e., 0.030 lb/MMBtu or lower) need not meet the opacity limit and monitoring requirements.^[4]

Finally, we are proposing to clarify requirements that have already been satisfied (e.g., a one-time requirement that has been met to submit a description of dust suppression methods to the Regional Administrator) and update the addresses to which the owner or operator must submit reports.

B. Facility

NGS is a coal-fired power plant located on the reservation lands of the Navajo Nation, just east of Page, Arizona, and approximately 135 miles north of Flagstaff. NGS is co-owned by several entities and operated by Salt River Project (SRP).^[5] The facility currently operates three units, each with a capacity of 750 megawatts (MW) net generation, providing a total capacity of 2250 MW. Operations at the facility produce air pollutant emissions, including emissions of SO₂, NO_X, and PM. Existing pollution control equipment at NGS includes wet flue gas desulfurization units for SO₂ and PM removal, electrostatic precipitators for PM removal, and low-NO_X burners with separated over-fire air to reduce NO_X formation during the combustion process. In the future, the owner or operator of NGS will be taking steps to reduce emissions of NO_X further, pursuant to the requirements of the 2014 FIP.

C. Attainment Status

The area around NGS is designated attainment, unclassifiable/attainment or unclassifiable for all criteria pollutants under the Act.^[6]

D. The EPA's Authority To Promulgate a FIP in Indian Country

When the CAA was amended in 1990, Congress included a new provision, section 301(d), granting the EPA authority to treat tribes in the same manner as states where appropriate.^[7] In 1998, the EPA promulgated regulations known as the Tribal Authority Rule (TAR).^[8] The EPA's promulgation of the TAR clarified, among other things, that state air quality regulations generally do not, under the CAA, apply to facilities located anywhere within the exterior boundaries of Indian reservations.^[9] Prior to the addition of section 301(d) and the promulgation of the TAR, some states had mistakenly included emission limitations in their SIPs that they may have believed could apply under the CAA to private facilities operating on adjacent Indian reservations.

In the preambles to the proposed and final 1998 TAR, the EPA generally discussed the legal basis in the CAA that authorizes the EPA to regulate sources of air pollution in Indian country.^[10] The EPA concluded that the CAA authorizes the EPA to protect air quality throughout Indian country.^[11] The TAR, therefore, provides that the EPA “[s]hall promulgate without unreasonable delay such federal implementation plan provisions as are necessary or appropriate to protect air quality, consistent with the provisions of sections [301](a) and 301(d)(4), if a tribe does not submit a tribal implementation plan meeting the completeness criteria of 40 CFR part 51, Appendix V, or does not receive EPA approval of a submitted tribal implementation plan.” ^[12]

E. Historical Overview of NGS FIP Actions

On December 2, 1980, EPA issued regulations addressing visibility impairment that is traceable or “reasonably attributable” to a single source or small group of sources.^[13] These regulations required a number of states to submit SIPs no later than September 2, 1981. Most states, including Arizona, failed to submit SIPs as called for by the regulations. Accordingly, in 1987, the EPA issued visibility FIPs consisting of general plan requirements and long-term strategies for 29 states including Arizona.^[14]

In 1989, based on a report submitted by the National Park Service, the EPA proposed to find that a portion of the visibility impairment in Grand Canyon National Park was reasonably attributable to NGS.^[15] Under the 1991 FIP, NGS was required to phase-in compliance with the SO₂ emission limit, by installing scrubbers in 1997, 1998, and 1999.^[16] In establishing the SO₂ emission limit for NGS in the final 1991 FIP, the EPA determined that the FIP would provide for greater reasonable progress toward the national visibility goal than implementation of Best Available Retrofit Technology (BART).^[17]

On September 8, 1999, the EPA proposed a source-specific FIP for NGS.^[18] The 1999 proposed FIP stated: “Although the facility has been historically regulated by Arizona since its construction, the state lacks jurisdiction over the facility or its owners or operations for CAA compliance or enforcement purposes.” The EPA intended for the proposed action in 1999 to “federalize” the emission limitations that Arizona had erroneously included in its SIP.^[19] The EPA received comments on the proposed FIP but did not finalize the proposal.

In 2006, the EPA published a new proposed rule to promulgate federally enforceable numerical emission limitations for PM and SO₂ and took action to finalize it in 2010.^[20] The 2010 FIP also established an opacity limit and a requirement for specific control measures to limit dust emissions. In the 2010 FIP, the EPA determined that the emission limitations for PM and SO₂ were more stringent than, or at least as stringent as, the emission limitations that had historically applied at NGS pursuant to an operating permit issued by Arizona. Therefore, the EPA concluded that air quality in this area would be positively impacted by the 2010 FIP.^[21]

On August 8, 2014, the EPA promulgated a final rule that established limits for NO_X emissions from NGS under BART provisions of the Regional Haze Rule.^[22] We finalized an alternative to BART based on agreed-upon recommendations developed by a group of diverse stakeholders. The 2014 FIP limits emissions of NO_X from NGS by establishing a long-term facility-wide cap on total NO_X emissions from 2009 to 2044 and requires the implementation of one of several alternative operating scenarios to ensure that the 2009 to 2044 cap is met.

II. Basis for Proposed Action

In this proposed FIP revision, the EPA is exercising its discretionary authority under sections 301(a) and 301(d)(4) of the CAA and 40 CFR 49.11(a). The EPA is proposing that it is necessary or appropriate to revise the FIP for NGS to be more consistent with the MATS Rule and the NSPS for EGUs. In particular, we are proposing to require the use of PM CEMS to demonstrate compliance with a lower PM emission limitation and remove the opacity limitation and COMS monitoring requirement, which has served as a surrogate for a compliance demonstration for the PM emission limitation. As explained in the preamble to the 2010 FIP establishing the opacity limitation and COMS requirement, water droplets, which are present in the NGS stacks because of the SO₂ scrubbers, can cause inaccurate excess emission readings from the COMS.^[23] Therefore, the PM CEMS would provide a better continuous demonstration of compliance with the PM emission limitation than an opacity limit and COMS.

For the reasons set forth above, we are proposing to find that limited revisions to the FIP for NGS are necessary or appropriate to further protect air quality on the Navajo Nation.

III. Summary of FIP Provisions

A. Proposed FIP Revisions

The EPA is proposing the following limited revisions to the FIP for NGS at 40 CFR 52.145(d) and 40 CFR 49.5513. We have included two documents in the docket for this proposed rulemaking that show the original text of 40 CFR 52.145(d) and 40 CFR 49.5513 and the EPA's proposed revisions to those provisions.^[24]

1. Revisions to 40 CFR 52.145(d)

The EPA is proposing to move the 1991 FIP promulgated at 40 CFR 52.145(d) to 40 CFR 49.5513(k) to consolidate the NGS FIP requirements in a single section of the CFR. We are also proposing to revise 40 CFR 52.145(d) by changing internal citations referring to paragraph (d) to refer instead to paragraph (k). For clarity, in this action we continue to refer to the 1991 FIP as designated in 40 CFR 52.145(d).

In addition, we are proposing to revise the definition of boiler operating day in paragraph 52.145(d)(1) to be consistent with its definition in the 2014 FIP.

2. Revisions to 40 CFR 49.5513(b)

Under paragraph (b) of 40 CFR 49.5513, we are proposing to clarify that the applicable compliance date for this section is April 5, 2010, which was the original effective date for this section, unless otherwise specified within specific provisions in 40 CFR 49.5513.

3. Revisions to 40 CFR 49.5513(d)

In 40 CFR 49.5513(d)(2), we are proposing to revise the emission limitation for PM from 0.060 lb/MMBtu to 0.030 lb/MMBtu, add a compliance date for this revised limit, and remove specifications related to PM testing. In 40 CFR 49.5513(d)(3), we are proposing to remove the compliance date for submitting to the EPA a dust suppression plan and to clarify the status of this plan, which the owner or operator submitted on June 4, 2010 and revised on February 2, 2015.^[25] The final revision we are proposing to 40 CFR 49.5513(d) is to remove the opacity limit and exclusions for water vapor in paragraph (4).

4. Revisions to 40 CFR 49.5513(e)

In 40 CFR 49.5513(e)(1), we are proposing to delete the requirement to operate COMS. In 40 CFR 49.5513(e)(2), we are proposing to replace the existing specifications related to annual PM testing with a requirement to demonstrate compliance with the PM emission limit in 40 CFR 49.5513(d)(2) using PM CEMS in accordance with 40 CFR part 63 subpart UUUUU and add a compliance date for this requirement. Under 40 CFR 49.5513(e)(4), we are proposing to remove the provision related to COMS. Under 40 CFR 49.5513(e)(8), we are proposing to correct an outdated reference.

5. Revisions to 40 CFR 49.5513(f)

The EPA is proposing revisions to the reporting and recordkeeping requirements to provide additional clarity that all reports and notifications required in 40 CFR 49.5513(f), (f)(2), and (f)(4), should be reported to the Navajo Nation Environmental Protection Agency (NNEPA) and the EPA. We are also revising 40 CFR 49.5513(f) to update addresses for reporting to the EPA. In addition, in 40 CFR 49.5513(f)(4), consistent with the proposed removal of the opacity emission limitation and COMS requirement in 40 CFR 49.5513(d) and (e), we are proposing to replace a requirement to submit excess opacity reports as recorded by COMS with a requirement to submit excess emission reports for PM as recorded by CEMS, and to remove additional provisions related to the COMS.

6. Revisions to 40 CFR 49.5513(j)

Under 40 CFR 49.5513(j)(8), we are proposing to remove addresses for the NNEPA and the EPA that are already provided in 40 CFR 49.5513(f) and to require that all reports and notifications under 40 CFR 49.5513(j) be submitted to the NNEPA and the EPA in accordance with 40 CFR 49.5513(f).

B. Justification for Proposed FIP Revisions

1. Revisions to 40 CFR 52.145(d)

We are proposing to move the 1991 FIP from 40 CFR 52.145(d) to 40 CFR 49.5513(k). The 1991 FIP was originally codified in 40 CFR part 52 subpart D, which contains the SIP provisions for the state of Arizona. The provisions at 52.145 relate to visibility protection and paragraph (d) pertains to the control of SO₂ emissions from NGS based on the effects of those emissions on visibility at Grand Canyon National Park. Because the EPA has subsequently promulgated FIP requirements for NGS in 40 CFR part 49 subpart L, for regulatory clarity, we are proposing to move the SO₂ requirements from the 1991 FIP to the same part of the CFR as the implementation plans in Indian country, including the FIP requirements for NGS promulgated in 2010 and 2014. This move will not relax any existing FIP requirements for NGS and will have no effect on air quality in the area surrounding NGS.

Throughout 40 CFR 52.145(d), the provisions include internal citations referring to specific subparagraphs in paragraph (d). Consistent with our proposal to move the provisions from the 1991 FIP to 40 CFR 49.5513(k), we are also proposing to revise the internal citations that currently refer to paragraph (d) (i.e., 40 CFR 52.145(d)) to refer instead to paragraph (k) (i.e., 40 CFR 49.5513(k)). This proposed revision will not relax any existing FIP requirements for NGS and will have no effect on air quality in the area surrounding NGS.

We are also proposing to revise a definition of boiler operating day in 40 CFR 52.145(d)(1). The term is currently defined as a 24-hour calendar day during which coal is combusted in that unit for the entire 24-hours. We are proposing to revise the definition to mean a 24-hour period between 12 midnight and the following midnight during which any fuel is combusted at any time, such that it is not necessary for fuel to be combusted the entire 24-hour period. This revised definition, if finalized, would be identical to the definition of boiler operating day promulgated in the 2014 FIP and would be consistent with the recent changes to the definition promulgated by the EPA elsewhere (e.g., the NSPS for EGUs).

2. Revisions to 40 CFR 49.5513(b)

Under paragraph (b) of 40 CFR 49.5513, we are proposing to add a statement to the compliance dates specifying that compliance with the requirements of the section is required by April 5, 2010, which was the original effective date for this section, unless otherwise specified within specific provisions in 40 CFR 49.5513. Because the FIP provisions for NGS promulgated in 1991, 2010, and 2014 all have different compliance dates, we are proposing to revise this provision for regulatory clarity. The compliance date for the FIP provisions for NGS promulgated in 2010 would remain April 5, 2010, while the deadlines for the 1991 and 2014 FIPs would remain as specified in paragraphs 40 CFR 52.145(d)(6) and 49.5513(j) respectively. The compliance dates for the revised PM limit and PM CEMS requirements would be specified in paragraphs 40 CFR 49.5513(d)(2) and (e)(2), as explained below. This proposed revision would not relax any existing FIP requirements for NGS and would have no effect on air quality in the area surrounding NGS.

3. Revisions to 40 CFR 49.5513(d)

In 40 CFR 49.5513(d)(2), we are proposing to revise the PM emission limitation from 0.060 lb/MMBtu to 0.030 lb/MMBtu for consistency with the numerical PM emission limitation in the MATS Rule. The current applicable emission limitation for PM in the 2010 FIP is higher than the PM emission limitation in the MATS Rule. Revising the PM emission limitation in 40 CFR 49.5513(d)(2) to 0.030 lb/MMBtu will make the PM emission limitation in the FIP conform to the applicable, more stringent emission limitation in the MATS Rule. The EPA anticipates this will not result in any substantive change in the applicable requirements or the method of PM control for this facility. We propose to require compliance with this limitation in the FIP by the effective date of the final FIP. In 40 CFR 49.5513(d)(2), we are also proposing to delete the current provisions related to PM emissions testing. The requirements for demonstrating compliance with the PM emission limitation are instead addressed in 40 CFR 49.5513(e). In 40 CFR 49.5513(d)(3), we are proposing to clarify the requirement for submitting to the EPA a dust suppression plan.

In 40 CFR 49.5513, we are proposing to remove paragraph (d)(4), which contains provisions related to the opacity limit. In 2016, SRP installed and calibrated PM CEMS on each unit at NGS. We are proposing to remove the opacity limit from the NGS FIP because in 40 CFR 49.5513(e)(2), we are proposing to add a new requirement to operate the PM CEMS on each unit to demonstrate compliance with the PM emission limitation of 0.030 lb/MMBtu. This provision is consistent with the NSPS for EGUs at 40 CFR 60.42Da(b)(1) and the Acid Rain Program requirements at 40 CFR 75.14(e), which generally provide that any owner or operator that elects to install, calibrate, maintain, and operate a PM CEMS for demonstrating compliance with a sufficiently stringent PM emission limitation (i.e., 0.030 lb/MMBtu or lower) need not meet the opacity limit and monitoring requirements.^[26] The PM CEMS is a monitoring system that provides a continuous assessment of compliance with a PM emission limitation. Generally, opacity limits and COMS have been used as a surrogate to ensure compliance with a PM emission standard that would otherwise be subject only to periodic source testing.^[27] NGS is not subject to the NSPS for EGUs at 40 CFR 60.42Da. However, we are proposing to follow the same rationale from Subpart Da to remove the opacity limit and COMS requirement because we are concurrently proposing to revise the NGS FIP to require the installation, calibration, operation, and maintenance of PM CEMS to demonstrate compliance with the lower proposed PM emission limitation of 0.030 lb/MMBtu. As explained in the preamble to our 2010 FIP, water droplets, which are present in the NGS stacks because of the SO₂ scrubbers, can cause inaccurate excess emission readings on the COMS.^[28] Because the PM CEMS provides a better continuous demonstration of compliance with the revised and more stringent PM emission limitation than an opacity limit and COMS, this proposed revision would not relax any existing requirements in the NGS FIP with respect to PM emissions and would not adversely affect air quality in the surrounding area.

4. Revisions to 40 CFR 49.5513(e)

In 40 CFR 49.5513(e)(1) and (e)(4), we are proposing changes to remove testing and monitoring requirements for opacity, consistent with our proposed removal of the opacity limit in 40 CFR 49.5513(d)(4). Because we are proposing to remove the opacity limit, the requirements in 40 CFR 49.5513(e)(1) to operate COMS and in (e)(4) to maintain two sets of opacity filters for the COMS are no longer necessary. In paragraph (e)(2), we are proposing to replace the existing specifications related to annual PM testing with a requirement to install, calibrate, maintain, and operate PM CEMS to demonstrate compliance with the 0.030 lb/MMBtu emission limit in accordance with the specifications in the MATS Rule by the effective date of the final FIP. The use of PM CEMS is a continuous measurement and is a better method for ensuring compliance with the revised and more stringent PM emission limit than annual source testing for the existing less stringent PM emission limit combined with an opacity limit and COMS. Therefore, these combined revisions would not relax existing requirements with respect to PM emissions or result in adverse effects on air quality in the surrounding area.

Under 40 CFR 49.5513(e)(8), we are proposing to correct an outdated reference to “Section 49.24(d)(3),” which has been recodified as 40 CFR 49.5513(d)(3).^[29]

5. Revisions to 40 CFR 49.5513(f)

The EPA is proposing revisions to the reporting and recordkeeping requirements to specify that all reports and notifications required in 40 CFR 49.5513 should be sent to the NNEPA and the Regional Administrator of the Region IX office of the EPA. Because 40 CFR 49.5513(f)(2) repeats addresses and other reporting details already provided in paragraph (f), we are also proposing to delete the redundant provisions in paragraph (f)(2). These proposed administrative changes would not relax any requirements or have any effect on air quality in the area surrounding NGS.

In addition, consistent with the proposed removal of the COMS requirement in paragraph (e), we are also proposing to remove the reporting requirements related to the COMS in paragraph (f)(4). The use of PM CEMS is a continuous measurement and is a better method for ensuring compliance with the revised and more stringent PM emission limit than annual source testing for the existing less stringent PM emission limit combined with an opacity limit and COMS. Therefore, these combined revisions would not relax existing requirements with respect to PM emissions or result in adverse effects on air quality in the surrounding area.

6. Revisions to 40 CFR 49.5513(j)

In 40 CFR 49.5513(j)(8), we are proposing to remove addresses for the NNEPA and the EPA that are already provided in 40 CFR 49.5513(f) and to require that all reports and notifications under paragraph (j) be submitted to the NNEPA and the EPA in accordance with 40 CFR 49.5513(f). This proposed revision removes redundant information and requires reporting for 40 CFR 49.55153(j) to be consistent with the reporting requirements in 40 CFR 49.5513(f). Therefore, these proposed revisions would not adversely affect air quality in the surrounding area. These proposed changes to 40 CFR 49.5513(j)(10) do not relax any requirements or have any effect on air quality in the area surrounding NGS.

IV. Solicitation of Comments

As described above, the EPA is proposing the following revisions: (1) Move the 1991 FIP provisions from 40 CFR 52.145(d) to 40 CFR 49.5513; (2) revise a definition of boiler operating day; (3) clarify the compliance dates applicable to the FIP requirements; (4) lower the PM emission limitation in the 2010 FIP from 0.060 lb/MMBtu to 0.030 lb/MMBtu; (5) revise the PM compliance demonstration from annual source testing to the use of PM CEMS; (6) and replace the existing opacity limit and COMS requirement with a new requirement to demonstrate compliance with the PM emission limitation of 0.030 lb/MMBtu using PM CEMS.

The EPA solicits comments on the limited provisions of the NGS FIP that we are proposing to revise in this rulemaking. We are not accepting comment on any provisions of the NGS FIP that we are not proposing to revise. Accordingly, please limit your comments to those specific provisions listed above that we are proposing to revise in today's action.

V. Environmental Justice Considerations

The Navajo Generating Station is located on the reservation lands of the Navajo Nation, and the EPA recognizes there is significant community interest in the emissions and environmental effects of this facility. As discussed elsewhere in this document, the proposed revisions to the NGS FIP would strengthen the FIP by requiring the use of PM CEMS to demonstrate compliance with the lower PM emission limitation of 0.030 lb/MMBtu. Because the proposed revisions strengthen the NGS FIP, the EPA considers this action to be beneficial for human health and the environment, and to have no potential disproportionately high and adverse effects on minority, low-income, or indigenous populations.

VI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review

This action is not a significant regulatory action and was therefore not submitted to the Office of Management and Budget (OMB) for review. This rule applies to only one facility and is therefore not a rule of general applicability.

B. Executive Order 13771: Reducing Regulations and Controlling Regulatory Costs

This action is not expected to be an Executive Order 13771 regulatory action because this action is not significant under Executive Order 12866.

C. Paperwork Reduction Act (PRA)

This action does not impose an information collection burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. This rule applies to only one facility. Therefore, its recordkeeping and reporting provisions do not constitute a “collection of information” as defined under 44 U.S.C. 3502(3) and 5 CFR 1320.3(c).

D. Regulatory Flexibility Act (RFA)

I certify that this proposed action will not have a significant economic impact on a substantial number of small entities. This action will not impose any requirements on small entities. Firms primarily engaged in the generation, transmission, and/or distribution of electric energy for sale are small if, including affiliates, the total electric output for the preceding fiscal year did not exceed four million megawatt-hours. Each of the owners of the facility affected by this rule, Salt River Project, the Bureau of Reclamation, Arizona Public Service, Tucson Electric Power, and NV Energy, exceed this threshold.

E. Unfunded Mandates Reform Act (UMRA)

This action does not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments.

F. Executive Order 13132: Federalism

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

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

This action does not have tribal implications, as specified in Executive Order 13175. Although this proposed action affects a facility located in Indian country, the proposed limited revisions to existing provisions in the NGS FIP will not have substantial direct effects on any 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. Thus, Executive Order 13175 does not apply to this action. However, we note that we have engaged in numerous discussions with the NNEPA during the development of this proposed rule and continue to invite consultation on this proposed action.

H. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks

EPA interprets Executive Order 13045 as applying only to those regulatory actions that concern health or safety risks that the 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.

I. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use

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

J. National Technology Transfer and Advancement Act

This action involves technical standards. The technical standards in this action are based on the technical standards used in other rulemakings promulgated by the EPA. We refer to the discussion of the technical standards and voluntary consensus standards in the final rule for 40 CFR part 60 subpart Da and 40 CFR part 63 subpart UUUUU at 77 FR 9304 at 9441 (February 16, 2012).

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

The EPA believes the human health or environmental risk addressed by this action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations. If this rule is finalized as proposed, we expect that the limited revisions to the FIP will strengthen requirements for PM compliance demonstrations with a lower PM emission limitation of 0.030 lb/MMBtu, and will not relax any other existing requirements.

List of Subjects

40 CFR Part 49

• Environmental protection
• Administrative practice and procedure
• Air pollution control
• Incorporation by reference
• Indians
• Intergovernmental relations
• Reporting and recordkeeping requirements

40 CFR Part 52

• Environmental protection
• Air pollution control
• Incorporation by reference
• Intergovernmental relations
• Reporting and recordkeeping requirements
• Visibility

Dated: October 26, 2018.

Deborah Jordan,

Acting Regional Administrator, Region IX.

Chapter I, title 40, of the Code of Federal Regulations is proposed to be amended as follows:

PART 49—INDIAN COUNTRY: AIR QUALITY PLANNING AND MANAGEMENT

1. The authority citation for part 49 continues to read as follows:

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

Subpart L—Implementation Plans for Tribes—Region IX

2. Section 49.5513 is amended by:

a. Revising paragraph (b);

b. Revising paragraphs (d)(2) and (3);

c. Removing paragraph (d)(4);

d. Revising paragraphs (e)(1) and (2);

e. Removing and reserving paragraph (e)(4);

f. Revising paragraph (8);

g. Revising paragraphs (f) introductory text and (f)(2) and (4);

h. Revising paragraphs (j)(8) introductory text; and

i. Adding paragraph (k).

The revisions and additions read as follows:

§ 49.5513

Federal Implementation Plan Provisions for Navajo Generating Station, Navajo Nation.

* * * * *

(b) Compliance dates. Compliance with the requirements of this section is required no later than April 5, 2010, unless otherwise indicated by compliance dates contained in specific provisions.

* * * * *

(d) * * *

(2) Particulate matter. By [DATE 30 DAYS AFTER DATE OF PUBLICATION OF FINAL RULE IN THE FEDERAL REGISTER], no owner or operator shall discharge or cause the discharge of particulate matter into the atmosphere in excess of 0.030 lb/MMBtu, on a plant-wide basis.

(3) Dust. Each owner or operator shall operate and maintain the existing dust suppression methods for controlling dust from the coal handling and storage facilities, as documented in the dust suppression plan submitted on February 2, 2015, or any subsequent revision thereto. Each owner or operator shall not emit dust with an opacity greater than 20% from any crusher, grinding mill, screening operation, belt conveyor, truck loading or unloading operation, or railcar unloading station, as determined using 40 CFR part 60, Appendix A-4 Method 9.

(e) Testing and monitoring. (1) On and after the effective date of this regulation, the owner or operator shall maintain and operate Continuous Emissions Monitoring Systems (CEMS) for NO_X and SO₂ on Units 1, 2, and 3 in accordance with 40 CFR 60.8 and 60.13(e), (f), and (h), and Appendix B of Part 60. The owner or operator shall comply with the quality assurance procedures for CEMS found in 40 CFR part 75.

(2) By [DATE 30 DAYS AFTER DATE OF PUBLICATION OF FINAL RULE IN THE FEDERAL REGISTER], the owner or operator shall install, calibrate, maintain, and operate particulate matter CEMS on Units 1, 2, and 3 to assure continuous compliance with the particulate matter limits in paragraph (d)(2) of this section, in accordance with 40 CFR part 63 subpart UUUUU.

* * * * *

(8) A certified EPA Reference Method 9 of Appendix A-4 of 40 CFR part 60 observer shall conduct a weekly visible emission observation for the equipment and activities described under paragraph (d)(3) of this section. If visible emissions are present at any of the equipment and/or activities, a 6-minute EPA Reference Method 9 observation shall be conducted. The name of the observer, date, and time of observation, results of the observations, and any corrective actions taken shall be noted in a log.

(f) Reporting and recordkeeping requirements. All requests, reports, submittals, notifications and other communications to the EPA, Regional Administrator, or Administrator required by this section and references therein shall be submitted to the Director, Navajo Environmental Protection Agency, P.O. Box 339, Window Rock, Arizona 86515, [phone], [phone] (facsimile); and to the Regional Administrator, U.S. Environmental Protection Agency, Region IX, to the attention of Mail Code: ORA-1, at 75 Hawthorne Street, San Francisco, California 94105, [phone]. For each unit subject to the emissions limitations in this section the owner or operator shall:

* * * * *

(2) For excess emissions, notify the Regional Administrator by telephone or in writing within one business day. A complete written report of the incident shall be submitted to the Regional Administrator within ten (10) working days after the event. This notification shall include the following information:

* * * * *

(4) Submit quarterly excess emissions reports for sulfur dioxide and PM as recorded by CEMS together with a CEMS data assessment report to the Regional Administrator no later than 30 days after each calendar quarter. The owner or operator shall complete the excess emissions reports according to the procedures in 40 CFR 60.7(c) and (d) and include the Cylinder Gas Audit.

* * * * *

(j) * * *

(8) Reporting. All reports and notifications under this paragraph (j) must be submitted as required by paragraph (f) of this section to the Director, Navajo Nation Environmental Protection Agency and to the Regional Administrator.

* * * * *

(k) This paragraph (k) is applicable to the fossil fuel-fired, steam-generating equipment designated as Units 1, 2, and 3 at the Navajo Generating Station in the Northern Arizona Intrastate Air Quality Control Region 40 CFR 81.270).

(1) Definitions—(i) Administrator means the Administrator of EPA or his/her designee.

(ii) Affected unit(s) means the steam-generating unit(s) at the Navajo Generating Station, all of which are subject to the emission limitation in paragraph (k)(2) of this section, that has accumulated at least 365 boiler operating days since the passage of the date defined in paragraph (k)(6) of this section applicable to it.

(iii) Boiler operating day means a 24-hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the steam-generating unit. It is not necessary for fuel to be combusted the entire 24-hour period.

(iv) Owner or operator means the owner, participant in, or operator of the Navajo Generating Station to which this paragraph (k) is applicable.

(v) Unit-week of maintenance means a period of 7 days during which a fossil fuel-fired steam-generating unit is under repair, and no coal is combusted in the unit.

(2) Emission limitation. The following emission limitation shall apply at all times. No owner or operator shall discharge or cause the discharge of sulfur oxides into the atmosphere in excess of 42 nanograms per Joule (ng/J) [0.10 pound per million British thermal units (lb/MMBtu)] heat input.

(3) Compliance determination. Until at least one unit qualifies as an affected unit, no compliance determination is appropriate. As each unit qualifies for treatment as an affected unit, it shall be included in the compliance determination. Compliance with this emission limit shall be determined daily on a plant-wide rolling annual basis as follows:

(i) For each boiler operating day at each steam generating unit subject to the emission limitation in paragraph (k)(2) of this section, the owner or operator shall record the unit's hourly SO₂ emissions using the data from the continuous emission monitoring systems, required in paragraph (k)(4) of this section, and the daily electric energy generated by the unit (in megawatt-hours) as measured by the megawatt-hour meter for the unit.

(ii) Compute the average daily SO₂ emission rate in ng/J (lb/MMBtu) following the procedures set out in method 19, appendix A, 40 CFR part 60 in effect on October 3, 1991.

(iii) For each boiler operating day for each affected unit, calculate the product of the daily SO₂ emission rate (computed according to paragraph (k)(3)(ii) of this section) and the daily electric energy generated (recorded according to paragraph (k)(3)(i) of this section) for each unit.

(iv) For each affected unit, identify the previous 365 boiler operating days to be used in the compliance determination. Except as provided in paragraphs (k)(9) and (k)(10) of this section, all of the immediately preceding 365 boiler operating days will be used for compliance determinations.

(v) Sum, for all affected units, the products of the daily SO₂ emission rate-electric energy generated (as calculated according to paragraph (k)(3)(iii) of this section) for the boiler operating days identified in paragraph (k)(3)(iv) of this section.

(vi) Sum, for all affected units, the daily electric energy generated (recorded according to paragraph (k)(3)(i) of this section) for the boiler operating days identified in paragraph (k)(3)(iv) of this section.

(vii) Calculate the weighted plant-wide annual average SO₂ emission rate by dividing the sum of the products determined according to paragraph (k)(3)(v) of this section by the sum of the electric energy generated determined according to paragraph (k)(3)(vi) of this section.

(viii) The weighted plant-wide annual average SO₂ emission rate shall be used to determine compliance with the emission limitation in paragraph (k)(2) of this section.

(4) Continuous emission monitoring. The owner or operator shall install, maintain, and operate continuous emission monitoring systems to determine compliance with the emission limitation in paragraph (k)(2) of this section as calculated in paragraph (k)(3) of this section. This equipment shall meet the specifications in appendix B of 40 CFR part 60 in effect on October 3, 1991. The owner or operator shall comply with the quality assurance procedures for continuous emission monitoring systems found in appendix F of 40 CFR part 60 in effect on October 3, 1991.

(5) Reporting requirements. For each steam generating unit subject to the emission limitation in paragraph (k)(2) of this section, the owner or operator:

(i) Shall furnish the Administrator written notification of the SO₂, oxygen, and carbon dioxide emissions according to the procedures found in 40 CFR 60.7 in effect on October 3, 1991;

(ii) Shall furnish the Administrator written notification of the daily electric energy generated in megawatt-hours;

(iii) Shall maintain records according to the procedures in 40 CFR 60.7 in effect on October 3, 1991; and

(iv) Shall notify the Administrator by telephone or in writing within one business day of any outage of the control system needed for compliance with the emission limitation in paragraph (k)(2) of this section and shall submit a follow-up written report within 30 days of the repairs stating how the repairs were accomplished and justifying the amount of time taken for the repairs.

(6) Compliance dates. The requirements of this paragraph shall be applicable to one unit at the Navajo Generating Station beginning November 19, 1997, to two units beginning November 19, 1998, and to all units beginning on August 19, 1999.

(7) Schedule of compliance. The owner or operator shall take the following actions by the dates specified, but the interim deadlines will be extended if the owner or operators can demonstrate to the Administrator that compliance with the deadlines in paragraph (k)(6) of this section will not be affected:

(i) By June 1, 1992, award binding contracts to an architectural and engineering firm to design and procure the control system needed for compliance with the emission limitation in paragraph (k)(2) of this section.

(ii) By January 1, 1995, initiate on-site construction or installation of a control system for the first unit.

(iii) By May 1, 1997, initiate start-up testing of the control system for the first unit.

(iv) By May 1, 1998, initiate start-up testing of the control system for the second unit.

(v) By February 1, 1999, initiate start-up testing of the control system for the third unit.

(8) Reporting on compliance schedule. Within 30 days after the specified date for each deadline in the schedule of compliance in paragraph (k)(7) of this section, the owner or operator shall notify the Administrator in writing whether the deadline was met. If it was not met, the notice shall include an explanation why it was not met and the steps which shall be taken to ensure future deadlines will be met.

(9) Exclusion for equipment failure during initial operation. (i) For each unit, in determining compliance for the first year that such unit is required to meet the emission limitation in paragraph (k)(2) of this section, periods during which one of the following conditions are met shall be excluded.

(A) Equipment or systems do not meet designer's or manufacturer's performance expectations.

(B) Field installation including engineering or construction precludes equipment or systems from performing as designed.

(ii) The periods to be excluded shall be determined by the Administrator based on the periodic reports of compliance with the emission limitation in paragraph (k)(2) of this section which shall identify the times proposed for exclusion and provide the reasons for the exclusion, including the reasons for the control system outage. The report also shall describe the actions taken to avoid the outage, to minimize its duration, and to reduce SO₂ emissions at the plant to the extent practicable while the control system was not fully operational. Whenever the time to be excluded exceeds a cumulative total of 30 days for any control system for any affected unit, the owner or operators shall submit a report within 15 days addressing the history of and prognosis for the performance of the control system.

(10) Exclusion for catastrophic failure. In addition to the exclusion of periods allowed in paragraph (d)(9) of this section, any periods of emissions from an affected unit for which the Administrator finds that the control equipment or system for such unit is out of service because of catastrophic failure of the control system which occurred for reasons beyond the control of the owner or operators and could not have been prevented by good engineering practices will be excluded from the compliance determination. Events which are the consequence of lack of appropriate maintenance or of intentional or negligent conduct or omissions of the owner or operators or the control system design, construction, or operating contractors do not constitute catastrophic failure.

(11) Equipment operation. The owner or operator shall optimally operate all equipment or systems needed to comply with the requirements of this paragraph consistent with good engineering practices to keep emissions at or below the emission limitation in paragraph (k)(2) of this section, and following outages of any control equipment or systems the control equipment or system will be returned to full operation as expeditiously as practicable.

(12) Maintenance scheduling. On March 16 of each year starting in 1993, the owner or operator shall prepare and submit to the Administrator a long-term maintenance plan for the Navajo Generating Station that accommodates the maintenance requirements for the other generating facilities on the Navajo Generating Station grid covering the period from March 16 to March 15 of the next year and showing at least 6 unit-weeks of maintenance for the Navajo Generating Station during the November 1 to March 15 period, except as provided in paragraph (k)(13) of this section. This plan shall be developed consistent with the criteria established by the Western States Coordinating Council of the North American Electric Reliability Council to ensure an adequate reserve margin of electric generating capacity. At the time that a plan is transmitted to the Administrator, the owner or operator shall notify the Administrator in writing if less than the full scheduled unit-weeks of maintenance were conducted for the period covered by the previous plan and shall furnish a written report stating how that year qualified for one of the exceptions identified in paragraph (k)(13) of this section.

(13) Exceptions for maintenance scheduling. The owner or operator shall conduct a full 6 unit-weeks of maintenance in accordance with the plan required in paragraph (k)(12) of this section unless the owner or operator can demonstrate to the satisfaction of the Administrator that a full 6 unit-weeks of maintenance during the November 1 to March 15 period should not be required because one of the conditions in paragraph (k)(13)(i) through (iv) of this section are met. If the Administrator determines that a full 6 unit-weeks of maintenance during the November 1 to March 15 period should not be required, the owner or operator shall nevertheless conduct that amount of scheduled maintenance that is not precluded by the Administrator. Generally, the owner or operator shall make best efforts to conduct as much scheduled maintenance as practicable during the November 1 to March 15 period.

(i) There is no need for 6 unit-weeks of scheduled periodic maintenance in the year covered by the plan;

(ii) The reserve margin on any electrical system served by the Navajo Generating Station would fall to an inadequate level, as defined by the criteria referred to in paragraph (k)(12) of this section;

(iii) The cost of compliance with this requirement would be excessive. The cost of compliance would be excessive when the economic savings to the owner or operator of moving maintenance out of the November 1 to March 15 period exceeds $50,000 per unit-day of maintenance moved; and

(iv) A major forced outage at a unit occurs outside of the November 1 to March 15 period, and necessary periodic maintenance occurs during the period of forced outage.

PART 52—APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS

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

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

Subpart D—Arizona

§ 52.145

[Amended]

4. Section 52.145 amended by removing and reserving paragraph (d).

Footnotes

1.  See 56 FR 50172 (October 3, 1991), 75 FR 10174 (March 5, 2010), and 79 FR 46552 (August 8, 2014).

2.  See 40 CFR 52.145(d)(1) and 40 CFR 49.5513(j)(2)(iii).

3.  See 77 FR 9303 (February 16, 2012) and 81 FR 20172 (April 6, 2016) (Final Technical Corrections).

4.  See NSPS for EGUs at 40 CFR 60.42Da and the Acid Rain Program requirements at 40 CFR part 75. Subpart Da to part 60 is the “Standard of Performance for Electric Utility Steam Generating Units” and applies to units that are capable of combusting more than 73 MW heat input of fossil fuel and for which construction, modification, or reconstruction commenced after September 18, 1978. The units at NGS were constructed prior to 1978 and are not subject to part 60 subpart Da. The NGS units are subject to the Acid Rain Program requirements of CAA Title IV, but are eligible for an exemption from the requirement for COMS in CAA section 412(a), pursuant to 40 CFR 75.14.

5.  Currently, the participants in NGS are the United States Bureau of Reclamation, SRP, Arizona Public Service Company, Tucson Electric Company, and NV Energy. SRP, which serves as the facility operator, recently increased its ownership share after it purchased the shares previously owned by the Los Angeles Department of Water and Power.

6.  See 40 CFR 81.303.

7.  See 40 U.S.C. 7601(d).

8.  See 40 CFR parts 9, 35, 49, 50, and 81. See also 63 FR 7254 (February 12, 1998).

9.  See 63 FR 7254 at 7258 (noting that unless a state has explicitly demonstrated its authority and has been expressly approved by the EPA to implement CAA programs in Indian country, the EPA is the appropriate entity to implement CAA programs prior to tribal primacy), Arizona Public Service Company v. EPA., 211 F.3d 1280 (D.C. Cir. 2000), cert. denied sub nom, Michigan v. EPA., 532 U.S. 970 (2001) (upholding the TAR); see also Alaska v. Native Village of Venetie Tribal Government, 533 U.S. 520, 526 n.1 (1998) (primary jurisdiction over Indian country generally lies with federal government and tribes, not with states).

10.  See 59 FR 43956 (August 25, 1994); 63 FR 7253 (February 12, 1998).

11.  See 63 FR 7253 at 7262 (February 12, 1998); 59 FR 43956 at 43960-43961 (August 25, 1994) (citing, among other things, to CAA sections 101(b)(1), 301(a), and 301(d)).

12.  See 63 FR at 7273 (codified at 40 CFR 49.11(a)). In the preamble to the final TAR, the EPA explained that it was inappropriate to treat tribes in the same manner as states with respect to section 110(c) of the Act, which directs the EPA to promulgate a FIP within 2 years after the EPA finds a state has failed to submit a complete state plan or within 2 years after the EPA disapproval of a state plan. Although the EPA is not required to promulgate a FIP within the 2-year period for tribes, the EPA promulgated 40 CFR 49.11(a) to clarify that the EPA will continue to be subject to the basic requirement to issue any necessary or appropriate FIP provisions for affected tribal areas within some reasonable time. See 63 FR at 7264-65.

13.  45 FR 80084 (December 2, 1980), codified at 40 CFR 51.300-51.307.

14.  See 52 FR 45132 (November 24, 1987).

15.  56 FR 50172 (October 3, 1991), codified at 40 CFR 52.145.

16.  40 CFR 52.145(d)(7).

17.  56 FR 50172 (October 3, 1991).

18.  See 64 FR 48725 (September 8, 1999).

19.  64 FR 48725 at 48727.

20.  75 FR 10179 (March 5, 2010) codified at 40 CFR 49.24(a) through (i) and redesignated to 40 CFR 49.5513(a) through (i). See 76 FR 23879 (April 29, 2011).

21.  75 FR 10174 (March 5, 2010).

22.  79 FR 46514 (August 8, 2014).

23.  See 75 FR 10175. We also explained that, “NGS will continue to have a requirement to operate COMs on each stack since the COMs do operate properly during start-up and at other times when the SO₂ scrubbers are bypassed for maintenance purposes . . . Therefore, in the final rule excess opacity due to uncombined water droplets in the stack does not constitute an exceedance, but it will be reported on the quarterly excess emissions reports.” 75 FR 10177. See also, 40 CFR 49.5113(f)(4).

24.  See documents titled “2018 NGS part 49 FIP RLSO.docx” and “2018 part 52 FIP RLSO.docx” in the docket for this rulemaking.

25.  See Part 71 Federal Operating Permit Draft Statement Of Basis Navajo Generating Station Permit No. NN-OP-15-06 (September 2015), p. 15.

26.  See NSPS for EGUs at 40 CFR 60.42Da and the Acid Rain Program requirements at 40 CFR part 70. Subpart Da to part 60 is the “Standard of Performance for Electric Utility Steam Generating Units” and applies to units that are capable of combusting more than 73 MW heat input of fossil fuel and for which construction, modification, or reconstruction commenced after September 18, 1978. The units at NGS were constructed prior to 1978 and are not subject to part 60 subpart Da.

27.  See, e.g., discussion of opacity in the 2007 FIP for the Four Corners Power Plant, 72 FR 25698 at 25701 (May 7, 2007), stating that opacity limits are generally applied to ensure a unit is meeting its PM limit.

28.  See 75 FR 10175. We also explained that, “NGS will continue to have a requirement to operate COMs on each stack since the COMs do operate properly during start-up and at other times when the SO₂ scrubbers are bypassed for maintenance purposes . . . Therefore, in the final rule excess opacity due to uncombined water droplets in the stack does not constitute an exceedance, but it will be reported on the quarterly excess emissions reports.” 75 FR 10177. See also, 40 CFR 49.5113(f)(4).

29.  76 FR 23876 (April 29, 2011).