The Texas Natural Resource Conservation Commission (commission) adopts amendments to §116.12, concerning Nonattainment Review Definitions, and §116.150, concerning New Major Source or Major Modification in Ozone Nonattainment Areas. Section 116.12 is adopted with changes to the proposed text as published in the November 6, 1998, issue of the Texas Register (23 TexReg 11278). Section 116.150 is adopted without changes and will not be republished.

EXPLANATION OF THE ADOPTED RULES

The commission adopts these revisions to Chapter 116 and to the State Implementation Plan (SIP) in order to reinstate nonattainment new source review (NNSR) for nitrogen oxides (NO _x ) in the Dallas/Fort Worth (DFW) ozone nonattainment area, an area defined by Collin, Dallas, Denton, and Tarrant Counties. NNSR is a federal air quality permit requirement consisting of four elements: alternative site analysis, compliance certification, lowest achievable emission rate, and offsets.

The 1990 Federal Clean Air Act (FCAA), §172(c)(5) and §173, establishes the permitting requirements for new or modified major stationary sources in nonattainment areas. In addition, the FCAA requires NO _x NNSR. Specifically, the FCAA, §182(f) specifies that required measures for volatile organic compounds (VOC) must also be applied for NOx in ozone nonattainment areas, unless a demonstration is made that NO _x reductions would not contribute to attainment of the ozone standard. The United States Environmental Protection Agency's (EPA) interpretation of §182(f) allows the following federal NO _x measures to be waived if the state demonstrates that NO _x reductions do not contribute to ozone attainment: reasonably available control technology, NNSR, vehicle inspection/maintenance, and general and transportation conformity. On November 28, 1994, the EPA granted conditional approval of a §182(f) exemption from these NO _x measures for DFW. EPA approval was based on the commission's petition, which demonstrated with photochemical dispersion modeling, that NO _x reductions in DFW would be in excess of the reductions necessary for attainment of the ozone standard. The modeling predicted that VOC reductions alone would be sufficient for attainment. A condition of EPA's approval was that the §182(f) exemption would be rescinded if the area did not attain the ozone standard by November 15, 1996, and modeling later showed that NOx reductions would contribute to attainment. In response to the exemption, the commission adopted revisions to §116.150, effective November 2, 1995, which waived NO _x NNSR requirements for the DFW area.

Effective March 20, 1998, EPA reclassified ("bumped up") the DFW area from the "moderate" to the "serious" ozone nonattainment classification, because of monitored violations of the ozone standard. The EPA action called for the state to perform photochemical grid modeling and submit a new SIP by March 20, 1999, that demonstrates attainment of the one-hour ozone standard by November 15, 1999. The FCAA, §110, requires states to submit SIPs which contain enforceable measures to achieve the National Ambient Air Quality Standards (NAAQS). In 1996, the commission began to develop new modeling for the DFW area and now is using newer air quality models with improved meteorological and emission inputs. The new modeling, which was provided for public hearing and comment concurrent with the proposed rulemaking (23 TexReg 11485 (November 6, 1998)), shows that NO _x reductions contribute to attainment of the ozone standard in the DFW area. The modeling further indicates that NO _x reductions are a necessary step toward the area attaining the ozone standard (for both the existing one-hour and the new eight-hour standard). The failure to attain the standard by 1996 and the results of the new modeling mean the rationale for the NO _x exemption for DFW is no longer valid. Based upon its conditional approval of the §182(f) exemption (NO _x waiver), EPA will rescind the NO _x waiver and reinstate the requirements for these rules due to the modeling indicating that NOx reductions will contribute to attainment in the DFW area.

In addition, the adopted rules are being submitted to the EPA as one of several measures of the new ozone attainment demonstration required by the FCAA, §110. Although the NO _x reductions represented by these revisions will not be sufficient for DFW to attain the ozone standard, these reductions are a necessary component of the ozone attainment strategy. Until these rule revisions are in place, there is no assurance that significant point source NO _x emission increases will not occur. The commission is authorized by the Texas Clean Air Act, §§382.012, 382.017, and 382.051 to require the implementation of these rules prior to final EPA action to rescind the NO _x waiver. Therefore, the commission is implementing NO _x NNSR in DFW upon the effective date of these rule revisions in order to control NOx emissions as soon as practicable.

The amendment to §116.12(11), the definition "Major modification," Table I, footnote 3, modifies the description of which ozone nonattainment areas are exempt from NO _x NNSR by specifying that El Paso County is not subject to NO _x NNSR. The reference to "permanent" §182(f) NO _x exemptions has been deleted because, since the expiration in 1997 of the §182(f) NO _x "temporary" exemptions for Houston and Beaumont, there is no need to distinguish between permanent and temporary exemptions. The other amendment to the definition subdivides it, to allow Table I to be located properly, consistent with Texas Register rules. The table will now be located in the new paragraph (11)(A), where it is referenced, rather than under subparagraph (G), at the end of the definition.

The amendment to §116.150(b) removes the NO _x NNSR exemption for the DFW area. The requirements will apply to air quality permit applications for new or modified sources which are major for NO _x in DFW and determined to be administratively complete on or after the effective date of the revision to these rules. The rules will be effective 20 days after they are filed with the Office of the Secretary of State, as provided by the Administrative Procedure Act, Chapter 2001. The effective date is specified at the end of this adoption notice.

FINAL REGULATORY IMPACT ANALYSIS

The staff has reviewed the rulemaking in light of the regulatory analysis requirements of Texas Government Code (the Code), §2001.0225, and has determined that the rulemaking is not subject to §2001.0225 because the rule is not a "major environmental rule" as defined in the Code and it does not meet any of the four applicability requirements listed in §2001.0225(a). This rulemaking does not impose any requirements or costs on owners or operators of existing sources of NO _x in the DFW area. The proposed rules would only apply to major new or modified sources of NOx in the DFW area. Analysis of the 1996 emissions inventory for the area shows that only 12 entities reported emissions above 50 tons per year of NO _x , the "major" threshold for serious ozone nonattainment areas, and since 1980, none of them sought a Prevention of Significant Deterioration (PSD) permit modification. In 1980, the EPA established federal rules requiring PSD permits for all major new or modified sources of NO _x emissions in nitrogen dioxide attainment areas, which includes the DFW area. Since 1980, there have been no PSD permits issued for NO _x in DFW. The absence of PSD permits for NO _x in the DFW area indicates that there has not been a need to increase NO _x emissions equal to or above the PSD levels of 40 tons per year for modifications to existing 100/250 tons per year major sources, or equal to or above 100 or 250 tons per year for new major sources. The absence of PSD NO _x permits for new emissions, and the few existing NO _x sources equal to or above 50 tons per year, suggest that there will be no facilities in the foreseeable future affected by the proposed reimplementation of NO _x NNSR permit rules in DFW. Because few or no facilities will be affected by the reimplementation of NO _x NNSR in DFW, the rules will not adversely affect in a material way the economy, a sector of the economy, productivity, competition, or jobs. Furthermore, this rulemaking will not adversely affect in a material way, the environment, or the public health and safety of the state or a sector of the state. These rules, required by the FCAA, §§110, 172(c)(5), 173, and 182(f), will prevent new point source NO _x emissions from interfering with the ozone attainment demonstration strategy contained in the SIP. No comments were received during the comment period regarding the draft regulatory impact analysis.

TAKINGS IMPACT ASSESSMENT

The commission has prepared a Takings Impact Assessment for these sections under Texas Government Code, §2007.043. The following is a summary of that assessment. The specific purpose of these amendments is to reinstate NO _x NNSR in DFW in order to assist in the commission's effort to bring the DFW ozone nonattainment area into compliance with the FCAA ozone standards. The rules will significantly advance this specific purpose by requiring major new or modified sources of NO _x located in the DFW ozone nonattainment area to be subject to a review of significant new NO _x emissions and possibly emission offsets and additional control measures. This rulemaking does not impose any requirements or costs on owners or operators of unmodified existing sources of NOx in the DFW area. These NO _x NNSR requirements could burden private real property which is the subject of these rules. However, the following exceptions to the application of Chapter 2007 of the Texas Government Code, §2007.003(b)(4) and (13), apply to these rules. Under §2007.003(b)(4), Chapter 2007 does not apply to an action that is reasonably taken to fulfill an obligation mandated by federal law. The amendments implement requirements of the FCAA, §§110, 172(c)(5), 173, and 182(f). Section 172(c)(5) and 173 of the FCAA contain the NNSR requirements. EPA granted the state a waiver from the §182(f) requirements conditioned on a demonstration that NO _x reductions would not contribute to attainment of the ozone standard. New modeling shows that NO _x reductions do contribute to the attainment of the ozone standard. The EPA published notice in the February 18, 1998, Federal Register (63 FR 8128) of a requirement to submit a new attainment demonstration SIP for the ozone NAAQS for DFW by March 20, 1999. These rule revisions will be submitted to EPA as one of several measures of the new ozone attainment demonstration. Also, §2007.003(b)(13) states that Chapter 2007 does not apply to an action that: (1) is taken in response to a real and substantial threat to public health and safety; (2) is designed to significantly advance the health and safety purpose; and (3) does not impose a greater burden than is necessary to achieve the health and safety purpose. This action is taken in response to the DFW area exceeding the federal NAAQS for ground-level ozone, which adversely affects public health, primarily through irritation of the lungs. The action significantly advances the health and safety purpose by ensuring that new point source NO _x emissions do not interfere with the ozone attainment demonstration strategy contained in the SIP. Any NO _x reductions resulting from the current rulemaking are no greater than what the best scientific research indicates is necessary to achieve the desired ozone levels. However, this rulemaking is only one step among many necessary for attaining the ozone standard. In addition, the rules contain multiple compliance methods to minimize costs of compliance. This action does not make the existing rules less stringent.

COASTAL MANAGEMENT PLAN

The commission has determined that this rulemaking action relates to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act of 1991, as amended (Texas Natural Resources Code, §§33.201 et seq.), and the commission's rules in 30 TAC Chapter 281, Subchapter B, concerning consistency with the CMP. As required by 31 TAC §505.11(b)(2) and 30 TAC §281.45(a)(3) relating to actions and rules subject to the CMP, commission rules governing air pollutant emissions must be consistent with the applicable goals and policies of the CMP. The commission has reviewed this rulemaking action for consistency with the CMP goals and policies in accordance with the rules of the Coastal Coordination Council, and has determined that this rulemaking action is consistent with the applicable CMP goals and policies. The CMP goal or policy applicable to the rules is the policy that commission rules comply with regulations in Title 40 Code of Federal Regulations, protect and enhance air quality in the coastal area. The rules, which ensure that new point source emissions in DFW will not interfere with the ozone attainment demonstration strategy, are consistent with the applicable CMP policy because they are consistent with Title 40. Title 40, Part 51, sets out requirements for states to prepare, adopt, and submit implementation plans for the attainment of the NAAQS. The adopted rules will be submitted to EPA under these requirements. No comments were received during the comment period regarding the consistency of the rules with the CMP.

HEARING AND COMMENTERS

A public hearing on this proposal was held in Irving on December 1, 1998, at 7:00 p.m. at the City of Irving Central Library Auditorium, 801 West Irving Boulevard. No commenters submitted oral testimony on the proposal. One commenter, the EPA, submitted written comments on the proposal and generally supported the proposed revisions but suggested changes or clarifications.

No comments were received on §116.12. However, it has come to the commission's attention that there has been some confusion regarding Table I (Major Source/Major Modification Emission Thresholds). Specifically, for ozone nonattainment areas, emissions of NO _x are evaluated against the major source and major modification thresholds for the ozone NAAQS because NO _x is a precursor to ozone formation. The specific thresholds vary depending on the classification (marginal, moderate, serious, or severe) of the ozone nonattainment area. Table I also lists NO _x with major source and major modification thresholds of 100 and 40 tons per year, respectively, but Table I has not explicitly noted that these thresholds only apply to areas which do not meet the NAAQS for nitrogen dioxide (NO ₂ ). (Currently, there are no NO ₂ nonattainment areas in Texas.) In order to distinguish the two different purposes for quantifying NOx emissions, the commission has added a new footnote 5 to Table I which notes that the NO _x thresholds for NO ₂ apply to areas which do not meet the NAAQS for NO ₂ . The commission has also added "(VOC, NO _x )" after "ozone" in Table I which, together with the existing footnote 3 (which notes that VOC and NO _x are precursors to ozone formation) should greatly reduce the chances for confusion. In addition, the commission has revised the syntax of the second sentence in footnote 3 for improved readability.

The EPA stated that as proposed, §116.150(b) does not specify the effective date for the reinstatement of NO _x as an ozone precursor in DFW. The EPA noted that the estimated effective date of the proposed revisions is March 21, 1999, and suggested that it would be clearer to incorporate this transition schedule into the rule.

The commission does not believe that it is necessary to specify the effective date in §116.150(b). As noted in 1 TAC §91.65(b), "The APA (Administrative Procedure Act) states that a rule takes effect 20 days after the date on which it is filed in the Office of the Secretary of State unless a later date is required by statute, specified in the rule, or required by federal mandate." The NO _x NNSR rules for DFW will become effective on the effective date of the rule revisions specified at the end of this adoption notice. Any air quality permit applications for new or modified sources which are major for NO _x in DFW and which are administratively complete before this effective date will not be subject to the NO _x NNSR requirements. The commission has made no changes in response to the comment.

Subchapter A. Definitions

The commission adopts amendments to §117.10, concerning Definitions, §§117.101, 117.103, 117.105, 117.107, 117.109, 117.111, 117.113, 117.115, 117.117, 117.119, and 117.121, concerning Utility Electric Generation; §§117.201, 117.203, 117.205, 117.207-117.209, 117.211, 117.213, 117.215, 117.217, 117.219, 117.221, and 117.223, concerning Commercial, Institutional and Industrial Sources; §§117.510, 117.520, 117.540, concerning Administrative Provisions; and §117.601, concerning Gas-Fired Steam Generation. The changes clarify and improve implementation of certain portions of the commission's rules for existing major stationary sources of nitrogen oxides (NO _x ) emissions in ozone nonattainment areas and extend the rules to the Dallas/Fort Worth (DFW) ozone nonattainment area.

Sections 117.10, 117.103, 117.113, 117.119, 117.203, 117.205, 117.207, 117.211, 117.213, 117.215, 117.219, 117.223, 117.510, 117.520, 117.540, and 117.601 are adopted with changes to the proposed text as published in the November 6, 1998, issue of the Texas Register (23 TexReg 11281). Sections 117.101, 117.105, 117.107, 117.109, 117.111, 117.115, 117.117, 117.121, 117.201, 117.208, 117.209, 117.217, and 117.221 are adopted without changes and will not be republished.

EXPLANATION OF ADOPTED RULES

One purpose of the revisions to Chapter 117 and to the State Implementation Plan (SIP) is to extend NO _x reasonably available control technology (RACT) requirements to DFW, an area defined by Collin, Dallas, Denton, and Tarrant Counties. The 1990 Federal Clean Air Act (FCAA), §182(f), requires NO _x RACT be applied to all major sources of NO _x in ozone nonattainment areas, unless a demonstration is made that NO _x reductions would not contribute to or would not be necessary for attainment of the ozone standard. By policy, the United States Environmental Protection Agency (EPA) requires photochemical grid modeling to demonstrate whether the §182(f) NO _x measures would contribute to ozone attainment. On November 28, 1994, the EPA granted conditional approval of a §182(f) exemption from NO _x measures for DFW. EPA approval was based on the commission's petition which, based on the modeling at the time, showed that volatile organic compound (VOC) reductions alone would be sufficient for attainment. This meant that NO _x reductions in DFW would be in excess of the reductions necessary for attainment of the ozone standard and were not needed. A condition of EPA's exemption was that it would be rescinded if the area did not attain the ozone standard by November 15, 1996, and modeling later showed that NO _x reductions would contribute to attainment.

The DFW area did not attain the ozone standard in 1996. Effective March 20, 1998, in accordance with the FCAA, §181(b)(2)(B), the EPA reclassified the DFW area from moderate to serious, based on a monitored violation of the ozone standard. The reclassification required the state to submit a new SIP by March 20, 1999, that demonstrates attainment by November 15, 1999.

In 1996, the agency began to develop new modeling for the DFW area and now is using newer air quality models with improved meteorological and emission inputs. The new modeling, which was provided for public hearing and comment concurrently with this rulemaking, shows that NO _x reductions contribute to attainment of the ozone standard in the DFW area. The modeling further indicates that NO _x reductions are a necessary step toward the area's attaining the ozone standard (for both the existing 1-hour and the new 8-hour standard). The failure to attain the standard by 1996 and the results of the new modeling mean the rationale for the NO _x exemption for DFW is no longer valid. Based upon its conditional approval of the §182(f) exemption (NOx waiver), EPA will rescind the NO _x waiver and reinstate the requirements for these rules due to the modeling indicating that NO _x reductions will contribute to attainment in the DFW area.

The commission also adopts these revisions in order to improve the implementation of the existing NO _x RACT rules in the Houston/Galveston (HGA) and Beaumont/Port Arthur (BPA) ozone nonattainment areas. These changes are made in response to proposals received from outside entities and from commission staff. Some changes add more explicit recordkeeping and reporting requirements with the objectives of making the requirements more certain and logical, and easier to comply with and to enforce. A benefit is less time spent in determining compliance. Several sections are reorganized significantly to make the rules easier to read and understand. Other clarifications eliminate the need for rule interpretations which are currently posted on the agency's website via the Office of Air Quality's Operating Permits Division.

Numerous minor style changes are adopted. All references in Chapter 117 to "undesignated head" have been changed to "division" to comply with current Texas Register requirements for the terminology of rule structure. The term "executive director" replaces references to "Texas Natural Resource Conservation Commission" where the intent is to refer to agency staff. The term "executive director" as defined in the commission's rules, includes any authorized individual designated to act for the executive director. Text changes reduce the number of words without changing meaning or reducing clarity. This type of change includes certain cross-references which are changed to specify the next higher (more general) level of rule structure. Other cross-references are updated to reflect the reorganized requirements.

The amendments to §117.10, concerning Definitions: add DFW to the definitions of applicable ozone nonattainment area, electric power generating system, and major source, and alphabetize the named areas and counties within those definitions; delete the definition of emergency standby gas turbine/engine because this definition is not used in Chapter 117; and modify the definition of unit to clarify that the limitation on replaced capacity applies to emission credits, not the capacity itself. This last revision removes a limitation on replacement units, consistent with a revision to §117.203(b)(1) made through adoption on May 25, 1994 (19 TexReg 4529). At the time, the definition was left unrevised, inadvertently. In addition, the definitions are numbered to comply with current Texas Register requirements.

The amendments to §117.101, concerning Applicability: add DFW to the applicable ozone nonattainment areas; alphabetize the named areas; list the affected electric utility units numerically; and insert the defined term "unit" to refer to the affected equipment. Using the term clarifies that the rule applies to equipment placed into service before November 15, 1992 and to functionally identical replacements.

The amendments to §117.103, concerning Exemptions, delete existing subsection (a), which cross-references a now outdated version of the upset and maintenance rules in 30 TAC Chapter 101, concerning the commission's air General Rules. Since the subsection is only a restatement of other rules outside Chapter 117, its deletion reduces the volume of rules and simplifies future rule amendments, without changing the substance of exemptions. In addition, the words "as may be specified" are added in §117.103(b), now relettered (a), to clarify that the cross referenced exceptions are more specific and do not apply to the entire set of exempt categories in §117.103.

The amendment to §117.105(f)-(i), concerning Emission Specifications, combines the gas and oil emission limits into single subsections, reducing repetitive language. The changes to §117.105(n)(2) update the compliance date by referencing §117.510, concerning Compliance Schedule for Utility Electric Generation, and eliminate repetitive language.

The amendments to §117.107, concerning Alternative System-wide Emission Specifications, reorganize the requirements using more of a listing format, to make the text less dense and more readable. The changes to §117.109, concerning Initial Control Plan Procedures, clarify subsection (a) by: specifying the applicable areas; numbering the distinctive requirements; and adding paragraph (1), which states that the section applies only to sources which were major for NO _x emissions before November 15, 1992. The commission does not require initial control plans for DFW sources. The sources are simpler and fewer compared to HGA and BPA, and such plans would provide little information that is not already readily accessible. The amendment to §117.111(c), concerning Initial Demonstration of Compliance, clarifies that the initial relative accuracy test audit (RATA) is part of the initial verification of operational status of the continuous emission monitoring system (CEMS) or predictive emission monitoring system (PEMS). In addition, a cross-reference to the test report requirements in the industrial emission specification is added in §117.111(b) to specify the minimum contents of compliance test reports if the test is based on a 40 Code of Federal Regulations (CFR) 60, Appendix A test apparatus.

Amendments to §117.113, concerning Continuous Demonstration of Compliance, reorganize the requirements for clarity. The changes revise the wording of the current carbon monoxide (CO) monitoring requirements for clarity and move them from subsection (k) to subsection (b). This follows the principle of ordering requirements of more general applicability and importance to the front of the rule. Subsections are given titles (catchlines) to identify the topics covered. Requirements are listed to make the text less dense. The option to share CEMS among units is added to subsection (c), consistent with the corresponding revision adopted in the industrial source division of this chapter. Requirements to install fuel meters are collected in one subsection and clarifying language from the industrial source rule division is added. Existing subsection (j), now relettered to subsection (k), is split into two subsections, parallel to the industrial source rule language.

The amendments to §117.115, concerning Final Control Plan Procedures, add specificity to the requirements. The added specificity is anticipated to significantly reduce the time necessary to assess a source's compliance with NO _x RACT. A change to §117.115(a) clarifies and potentially reduces the number of units needed to be listed in the plan, by substituting a reference to the units specified in §117.101, regarding Applicability, for the less precise term, "affected units." To facilitate assessment of compliance with NO _x RACT, new §117.115(a)(2) and (6) require citation of the specific rule or exemption used for NOx compliance. New subsection (a)(3) is designed to reduce the volume of paperwork and simplify tracking, by allowing owners or operators to identify applicable test reports that have previously been submitted, rather than requiring all such reports to be resubmitted at the final compliance date. For many electric utility units, CEMS certifications have already been submitted under the acid rain program and would not need to be resubmitted. The requirement would also aid tracking, by identifying units for which the emission compliance test data will be submitted after the final compliance date, based on 30-day average emission specifications. The changes to §117.115(b) place the requirements in a list format for readability and require identification of the maximum rated capacity and calculations of the system-wide emission limit, to assist in verification of compliance. New §117.115(c) requires certain information to be submitted on forms provided by the executive director (staff). The expected benefit is primarily in reducing the time necessary for staff to assess compliance with NO _x RACT. The requirement to provide copies of the completed forms electronically and on hard copy would allow the staff to distribute the information more efficiently using computer technology while retaining the safeguards of paper. New §117.115(d) places the submittal deadlines at the end of the section and clarifies that the plan is to be updated with 30-day average compliance information that may not be available by the final compliance date.

The adopted amendments to §117.119 add catchlines and number certain requirements for readability. A change to the excess emission reporting requirements of §117.119(d) reduces the frequency of reporting from quarterly to semiannual. This change will result in some savings of effort in the regulated community and will not prevent persons from maintaining a quarterly schedule, if preferred. For consistency, the record retention time specified in recordkeeping, §117.119(e) is changed from two years to five years. The sources subject to Chapter 117 are also subject to FCAA, Title V permit requirements, which specify a 5-year period for retention of compliance records. The recordkeeping wording is simplified. The requirement for recordkeeping of emission monitoring data is cross referenced more generally to the emission monitoring specified in §117.113.

The amendments to §117.121, concerning Alternative Case Specific Specifications, list the requirements for readability. The cross-reference to the commission's procedural rules is updated and the reference to the information that can be found in those rules is deleted.

The amendments to §117.201, concerning Applicability, add DFW to the applicable ozone nonattainment areas and alphabetize the named areas. The changes to §117.203, concerning Exemptions, add the words "as may be specified" to clarify that the cross referenced exceptions are more specific than the entire set of exempt categories in §117.203. In addition, the changes add two types of units which recover sulfur compounds from process streams to the list of exemptions. These additions are consistent with the intent of the Chapter 117 rules developed in 1992, which was to exempt units which commingle fuel and process chemicals. The exemption level for internal combustion engines in DFW is added to §117.203(8)(B), consistent with the level established in the original NO _x RACT rule for a serious ozone nonattainment area.

The amendment to §117.205(a)(3), concerning Emission Specifications, updates the compliance date by referencing §117.520, concerning Compliance Schedule for Commercial, Institutional, and Industrial Combustion Sources. Other changes to §117.205(a) and (b) eliminate repetitive language. The change to §117.205(b)(6) clarifies that the hydrogen multiplier may not be used to increase limits set by permit. The change to §117.205(d)(2) sets the emission specification for rich-burn gas engines in DFW, consistent with the specification previously established in the NO _x RACT rule for a serious ozone nonattainment area. The commission deletes existing §117.205(h), originally drafted to clarify applicability. The insertion of the modifier "NO _x " in the introductory sentences of §117.207, concerning Alternative Plant-wide Emission Specifications, and §117.223(a), concerning Source Cap, clarifies the applicability more efficiently. The reduction in words improves readability.

The amendments to §117.207, concerning Alternative Plant-wide Emission Specifications, reorganize the requirements, using listing and tabular formats, to make the text less dense and more readable. New §117.207(f)(3) clarifies that NO _x opt-in units need to comply with the ammonia and carbon monoxide limits. The purpose of the limits is to require good practice of NO _x control, and the opt-in units should not be exempt from existing standards.

The amendments to §117.209, concerning Initial Control Plan Procedures, clarify subsection (a) by: specifying the applicable areas; numbering the distinctive requirements; and adding paragraph (1), which states that the section applies only to sources which were major for NO _x emissions before November 15, 1992. The commission does not require initial control plans for DFW sources. The sources are simpler and fewer compared to HGA and BPA, and such plans would provide little information that is not already readily accessible.

The amendments to §117.211(a), concerning Initial Demonstration of Compliance, list requirements to reduce the density of the text and clarify that initial testing requirements apply to opt- in sources. The changes to §117.211(c) and (f) clarify that the initial RATA is part of the initial verification of operational status of the CEMS or PEMS. The adopted amendment to §117.211(d) allows some flexibility in the contents of tests conducted before the effective date of the current rule amendments. The addition of §117.211(f)(4) specifies initial compliance procedures for sources complying with the source cap.

New §117.211(g) specifies the minimum contents of compliance stack test and monitor certification reports. The requirements are extracted from Attachment 7, "Contents of Stack Test Reports," from "Air Program Inspector's Manual - Stationary Source and CEMS Test Observation and Test Report Review Protocol," agency publication RG-31d, January 1994. In turn, Attachment 7 is a condensed version of Chapter 14, "Contents of Sampling Reports," from "Sampling Procedures Manual," Texas Air Control Board, July 1985. Chapter 14 is routinely specified in construction permit test requirements. The intent of requiring minimum contents is to ensure that stack sampling resource expenditures, which were estimated at $2000 per test in the original November 20, 1992 NOx RACT rule proposal (17 TexReg 8144), provide the information necessary to confirm emission compliance. Since these contents have been long established through permit requirements, many existing compliance test reports should be conformable to these adopted standards.

Amendments to §117.213, concerning Continuous Demonstration of Compliance, reorganize the requirements for clarity. The new organization is around elements of the monitoring, rather than sizes of emission units. Titles are added to subsections to identify the topics covered and requirements are listed to make the text less dense. The requirements for fuel meters are consolidated in §117.213(a), from five subsections. In response to frequent requests for clarification, a sentence is added, expressing that "totalizing" may be accomplished by a computer. Units required to install oxygen monitors are listed in §117.213(b). The current CO monitoring requirements are reworded for additional clarity and moved from subsection (l) to subsection (d), consistent with the principle of ordering requirements of more general applicability and importance toward the front of the rule section. The commission revises the allowance to share CEMS, currently in §117.213(b), from a limit of three units to a standard based on performance. The revision to §117.213(e)(3) is in response to a request from a representative of an affected company which has been allowed by permit to share one CEMS among four ethylene furnaces.

In response to a request from a representative of an affected company, new §117.213(e)(1)(C) clarifies that certain ongoing Appendix F quality assurance procedures for CEMS apply after the final compliance date. Similarly, in response to a rule petition, new §117.213(f)(5)(B) and (C) specify the time frame for certain RATA required for PEMS. These changes help to clarify between requirements which must be performed before the final compliance date and those which continue after the final compliance date, as part of ongoing quality assurance. In addition, the changes provide some incentive to install CEMS or PEMS earlier than required, by eliminating the costs associated with performing ongoing quality assurance before the final compliance date. Early monitoring system installation will reduce the potential for a temporary shortage of stack testers, or other service bottlenecks to occur, as a result of the required installation of approximately 300 NO _x monitoring systems by the final compliance date.

The amendments to §117.215, concerning Final Control Plan Procedures, add specificity to the requirements. The added specificity is anticipated to significantly reduce the time necessary to assess a source's compliance with NO _x RACT. A change to §117.215(a) clarifies and potentially reduces the number of units needed to be listed in the plan, by substituting a reference to the units specified in §117.201, regarding Applicability, for the less precise term, "affected units." To facilitate assessment of compliance with NO _x RACT, new §117.215(a)(1), (2), and (6) require citation of the specific rule or exemption used for NOx compliance for any unit potentially subject to emission specifications under the division. New §117.215(a)(5) is designed to reduce the volume of paperwork and simplify tracking, by allowing owners or operators to identify applicable test reports that have previously been submitted, rather than requiring all such reports to be resubmitted at the final compliance date. The requirement should also aid tracking, by identifying units for which the emission compliance test data will be submitted after the final compliance date, based on 30-day average emission specifications.

The amendments to §117.215(b) place the requirements in a list format for readability and require the owner or operator to provide the maximum rated capacity for each unit and calculations of the plant-wide emission limit, to assist in verification of compliance. Changes to §117.215(c) add paragraphs (1)-(4) to require submittal of calculations and values of key variables necessary to calculate the source cap. New §117.215(d) requires information to be submitted on forms provided by the executive director (staff). The expected benefit is primarily in reducing the time necessary for staff to assess compliance with NO _x RACT. The requirement to provide copies of the completed forms electronically and on hard copy will allow the staff to distribute the information more efficiently using computer technology while retaining the safeguards of paper. Persons required to prepare the plans should benefit from not having to develop forms themselves. The forms will be readily accessible on the agency's website and through conventional means. New §117.215(e) places the submittal deadlines at the end of the section and clarifies that the plan is to be updated with 30-day average compliance information that may not be available by the final compliance date.

The adopted amendments to §117.219 add catchlines and number certain requirements for readability. A change to the excess emission reporting requirements of §117.219(d) and (e) reduces the frequency of reporting from quarterly to semiannual. This change will result in some savings of effort in the regulated community and will not prevent persons from maintaining a quarterly schedule, if preferred. A semiannual reporting frequency is consistent with the reporting frequency specified for federal operating permits in §122.145 of this title, concerning Reporting Terms and Conditions. New §117.219(d)(1)(B) defines periods of excess emissions which must be reported for units operating under a source cap. For consistency, the record retention time specified in recordkeeping, §117.219(f) is changed from two years to five years. The sources subject to Chapter 117 are also subject to federal operating permit requirements, which specify a 5-year period for retention of compliance records.

Additional paragraphs adding specific recordkeeping requirements, §117.219(f)(2)-(8), are adopted in order to consolidate the requirements in one location and to assure that recordkeeping tracks the methods of determining continuous compliance in §117.213 of this title. The purpose of the additions is to assure that units monitored under various compliance options will have the proper data to demonstrate compliance. The types of additional records specified are consistent with the recordkeeping requirements under Chapter 122, relating to Federal Operating Permits. In addition, the added CO recordkeeping addresses a deficiency identified by the EPA in the previous set of revisions to Chapter 117.

The amendments to §117.221, concerning Alternative Case Specific Specifications, use a list format to improve readability. The cross-reference to the commission's procedural rules is updated and the reference to the information that can be found in those rules is deleted.

The amendment to §117.223(a), concerning Source Cap, adds the modifier "NO _x " in the opening sentence, in order to clarify that the source cap is an alternative only to the NO _x emission specifications of §117.105, not the ammonia and CO limits. The purpose of the limits is to require good practice of NO _x control. The change to §117.223(e) revises the reporting frequency to semiannual, consistent with and for the same reasons as discussed previously for reporting required under §117.219 of this title. The changes to §117.223(i) revise the wording to reflect that initial control plans are not required in DFW and substitute the term "initial" for "final" in the last sentence of the subsection. The final control plan demonstrates initial compliance; the terminology follows from previously adopting the term "initial control plan" to refer to a plan which is substantively a preliminary control plan.

The amendments to §117.510, concerning Compliance Schedule for Utility Electric Generation, and §117.520, concerning Compliance Schedule for Commercial, Institutional and Industrial Combustion Sources, subdivide the sections to allow for a separate compliance schedule for sources located in DFW. The commission adopts a compliance date of March 31, 2001 for DFW, as discussed further in the analysis of testimony section of this notice.

Amendments to §117.540, concerning Phased RACT, subdivide the section to create a parallel schedule for sources located in DFW. The existing requirements for HGA and BPA become located under subsection (a), rather than the current "implied (a)." In addition, in §117.540(a)(2) and in §117.540(a)(9), the term "executive director" replaces "commission," to more accurately reflect the level in the agency at which the action occurs. The change to §117.540(a)(8) deletes an exception which is now repetitive with the commission's procedural rules at 30 TAC §50.37, concerning Motion for Reconsideration. The commission adopts a phased RACT schedule for DFW consistent with the intervals developed for HGA, adjusted according to the DFW final compliance date.

The commission adopts revisions to §117.601(a), concerning Gas-Fired Steam Generation, to clarify the applicability of the section. The changes give historical context to the section and simplify the wording.

FINAL REGULATORY IMPACT ANALYSIS

The commission has reviewed the rulemaking in light of the regulatory analysis requirements of Texas Government Code (the Code), §2001.0225, and has determined that the rulemaking is not subject to §2001.0225 because although the new emission limitations may meet the definition of "major environmental rule" as defined in the Code, it does not meet any of the four applicability requirements listed in §2001.0225(a). The amendments implement requirements of the FCAA. The FCAA, §110 requires states to submit SIPs which contain enforceable measures to achieve the National Ambient Air Quality Standards (NAAQS). Section 110(k)(5) requires the EPA to require states to revise a SIP, on a reasonable deadline, if the EPA finds the SIP to be substantially inadequate. The EPA published notice in the February 18, 1998 Federal Register of a requirement to submit a new attainment demonstration SIP for the ozone NAAQS for DFW by March 20, 1999. The adopted rules, which reduce ambient NO _x and ozone in DFW, will be submitted to the EPA, as one of several measures of the required new attainment demonstration.

These rules also implement NO _x RACT in DFW and improve the implementation of NO _x RACT in HGA and BPA. The FCAA, §182(f), requires any moderate and above ozone nonattainment area to implement NO _x RACT, unless the EPA exempts the area under exemption provisions of §182(f). Although DFW currently is covered by such a waiver, EPA will rescind the waiver and reinstate the requirements for these rules, upon submittal of modeling indicating NO _x reductions will contribute to attainment in the DFW area. The modeling is being submitted to EPA concurrently with this adopted rule.

The rules do not exceed an express requirement of a state law, but were developed specifically in order to implement federal law. The rules are part of a new ozone attainment demonstration SIP for DFW, required by the FCAA, §110. The rules also implement the FCAA, §182(f). The rules do not involve an agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program, and were not developed solely under the general powers of the agency.

Other modifications to Chapter 117 do not meet the definition of "major environmental rule" in the Code. These changes, to improve implementation of the rules, affect: applicability, exemption, testing, monitoring, recordkeeping, and reporting requirements. The changes do not require additional control equipment or measures, and the cost to comply with these requirements is not significant.

No comments on the regulatory impact analysis were received.

TAKINGS IMPACT ASSESSMENT

The commission has prepared a Takings Impact Assessment for these sections under Texas Government Code, §2007.043. The following is a summary of that assessment. The specific purposes of these amendments are: to develop a new attainment demonstration SIP for the ozone NAAQS for DFW, to implement NO _x RACT in DFW, and to improve the implementation of NO _x RACT in HGA and BPA. As adopted, certain major sources located in DFW will be subject to new control measures. Installation of such control equipment could conceivably place a burden on private, real property. However, under §2007.003(b)(4) and (b)(13) of the Texas Government Code, Chapter 2007 does not apply to this action. Under §2007.003(b)(4), Chapter 2007 does not apply to an action that is reasonably taken to fulfill an obligation mandated by federal law. The amendments implement requirements of the FCAA, §110 and §182(f). Also, §2007.003(b)(13) states that Chapter 2007 does not apply to an action that: (1) is taken in response to a real and substantial threat to public health and safety; (2) is designed to significantly advance the health and safety purpose; and (3) does not impose a greater burden than is necessary to achieve the health and safety purpose. This action is taken in response to the DFW area exceeding the NAAQS for ground-level ozone, which adversely affects public health, primarily through irritation of the lungs. The action significantly advances the health and safety purpose by reducing ambient NO _x and ozone levels in DFW. Attainment of the ozone standard will eventually require substantial NOx reductions. Any NO _x reductions resulting from the current rulemaking are no greater than what the best scientific research indicates is necessary to achieve the desired ozone levels. However, this rulemaking is only one step among many necessary for attaining the ozone standard. In addition, the requirements are expressed as performance specifications, and the rules contain multiple compliance methods to minimize costs of compliance.

Other amendments, to improve the implementation of NO _x RACT, affect: applicability, exemptions, control requirements, testing, reporting, and recordkeeping. These changes do not require additional control equipment or measures, and do not materially affect private real property. The costs of complying with these requirements are not significant.

COASTAL MANAGEMENT PLAN

The commission has determined that this rulemaking action relates to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act of 1991, as amended (Texas Natural Resources Code, §§33.201 et. seq.), and the commission's rules in 30 TAC Chapter 281, Subchapter B, concerning Consistency with the Texas Coastal Management Program. As required by 31 TAC §505.11(b)(2) and 30 TAC §281.45(a)(3) relating to actions and rules subject to the CMP, commission rules governing air pollutant emissions must be consistent with the applicable goals and policies of the CMP. The commission has reviewed this rulemaking action for consistency with the CMP goals and policies in accordance with the rules of the Coastal Coordination Council, and has determined that this rulemaking action is consistent with the applicable CMP goals and policies. The primary CMP policy applicable to this rulemaking action is the policy that commission rules comply with regulations at 40 CFR to protect and enhance air quality in the coastal area. The rules, which require additional reductions of air emissions in DFW and improve enforceability of the rules in HGA and BPA, will result in reductions of ambient NO _x and ozone concentrations. The rules are consistent with the applicable CMP policy because they are consistent with 40 CFR, Part 51, which sets out requirements for states to prepare, adopt, and submit implementation plans for the attainment of the NAAQS. The adopted rules will be submitted to EPA under these requirements.

HEARINGS AND COMMENTERS

Public hearings for this rulemaking were held in Irving on December 1, 1998 and in Houston on December 3, 1998. A representative of Texas Utilities (TU) provided oral testimony at the hearing in Irving. Eleven commenters submitted written comments on the proposal: the City of Denton (Denton), the Dallas/Fort Worth International Airport Board (DFWIA), EPA, Exxon Company, U.S.A., Baytown Refinery (Exxon), Garland Power & Light (Garland), an individual, Lockheed Martin Tactical Aircraft Systems (Lockheed), Pavilion Technologies, Inc. (Pavilion), Pennzoil Company (Pennzoil), the Texas Industry Project, via Baker & Botts, L.L.P. (TIP), and TU. Commenters generally supported or did not oppose the proposed revisions, but recommended revisions.

EPA commented that the state must identify all major sources of NOx over 50 tons per year (tpy) in the DFW area to ensure that RACT is in place for major sources.

The commission has added information regarding application of RACT to major sources of NO _x in DFW in Chapter 6 of the February 1999 DFW Attainment Demonstration SIP adopted with this rulemaking. Appendix K of this SIP identifies the sources of NO _x over 50 tpy in the DFW area.

EPA said exemptions based on heat input and operational parameters must link with the definition of a major source.

The applicability and exemption thresholds in Chapter 117 were developed with consideration to the major source definitions applicable in 1992 in the HGA and BPA areas, 25 tpy and 50 tpy, respectively. The exemptions for low annual capacity factor boilers and heaters were based on the assumption that a 100 million Btu per hour (MMBtu/hr) boiler operating at 25% annual capacity factor could emit 25 tpy of NO _x (18 TexReg 3412, May 28, 1993). The exemption of engines rated less than 300 horsepower (hp) was based on a potential to emit of 50 tpy. The exemption of engines operating less than 850 hours per year was based on cost-effectiveness, which for engines operating less than 10% of annual capacity is at least ten times higher than for continuous operation (18 TexReg 3427).

An individual expressed opposition to deleting the maintenance activity recordkeeping in §117.119(a) and §117.219(a) since, unless reportable quantities of unauthorized emissions are emitted, the company will not have to record its maintenance activities under 30 TAC §101.7. The commenter said these maintenance records allow inspectors to look for problems that while small, could become major in the future. EPA said that Chapter 117 includes reporting requirements for excess emissions during start-up and shutdown that exceed the requirements in Chapter 101. EPA said that the commission needs to ensure that the Chapter 117 requirements meet the guidelines in the EPA policy memo of Kathleen Bennett of February 23, 1983.

The commission, under 30 TAC §101.7, concerning Maintenance, Start-up and Shutdown Reporting, Recordkeeping, and Operational Requirements, requires some recordkeeping for any maintenance activities with unauthorized emissions, not just those associated with reportable quantities of unauthorized emissions. Although the commission proposed to delete requirements to record fuel type and quantity used during start-ups and shutdown events, it has come to the commission's attention that 30 TAC §101.7(c)(6) does not require recording estimates of quantities of unauthorized NO _x emissions above the reportable quantity for boilers and combustion turbines, since there is no reportable quantity for NO _x for these sources. Therefore, after further consideration, the commission has decided to maintain the Chapter 117 recordkeeping requirements in §117.119(a) and §117.219(a). In response to EPA's concerns about following EPA's exemption guidance, the commission notes that Chapter 101 provides any exemptions for start-up or shutdown emissions, not Chapter 117. The commission has adopted the deletion of §117.103(a) and §117.203(a), since these subsections only provided cross reference to Chapter 101 rules, the availability of which is already widely known.

An individual expressed opposition to allowing PEMS, saying that an air monitoring instrument which measures actual pollutant concentration is needed to truly monitor emissions, rather than an estimative device, such as PEMS.

The former Texas Air Control Board authorized PEMS as an alternative to CEMS, because it offered the possibility of equivalent accuracy and lower costs compared to CEMS, and an opportunity to reduce emissions. After more operating experience has been achieved with PEMS, an evaluation of its ability to consistently track NO _x emissions over time will be needed. The commission has made no change in response to the comments.

Exxon expressed support for the proposed revision from quarterly to semiannual excess emission reporting. An individual expressed opposition to reducing the frequency from quarterly to semiannual.

The reduction in reporting frequency is consistent with the federal operating permit reporting requirements contained in §122.145 of this title. The change represents a balance between agency goals to reduce the burdens associated with reporting and ensuring that emissions compliance is assessed periodically. The commission has made no change in response to the comments.

TU and TIP commented that there is an error in the wording of the definition of "system-wide emissions limit" in §117.10(35).

The commission agrees with the commenters. When the definition was previously revised, the wording in question inadvertently was not deleted. The commission has deleted the wording as suggested by the commenters.

TU recommended revision to the fuel oil firing provisions to allow testing of emergency fuel oil systems.

The general rules exempt emissions from maintenance if the owner or operator complies with 30 TAC §101.7 and the emissions are minimized to the extent practicable. Annual testing of emergency fuel oil systems to ensure that the systems are maintained in working order sufficient to maintain system reliability is a form of maintenance. Since the existing rules cover this situation, the commission has made no change in response to this comment.

TU recommended strong consideration be given to NO _x RACT compliance only during the ozone season, May-September.

EPA's definition of RACT is tied to an emission limit based on the application of control technology, which carries an implication of continuous control. Although in one application of NO _x RACT, EPA allowed long-term averaging to allow seasonal fuel switching between coal and gas, EPA insisted upon an annual NO _x limit that would at least meet the limit that would result from compliance with the presumptive NO _x RACT limit. (In that case, the presumptive limit would be the coal limit.) TU's proposal to allow seasonal RACT would not comply with this aspect of EPA's policy.

The issue of seasonal controls also involves air quality considerations. The season for the 1- hour ozone standard in DFW has been defined by EPA policy by the monitoring period in 40 CFR Part 58, Appendix D and by commission rule in §101.29(a)(19) of this title, relating to General Rules, as an 8-month period from March 1 through October 31. For the 8-hour ozone standard, the ozone season tends to be longer in Texas. EPA set an 11-month ozone monitoring season for DFW for the 8-hour standard (EPA-454/R-98-001, June 1998). Although the data provided by TU shows that over the last ten years, the exceedances of the 1-hour standard have been limited to the five months of June-October, there may be ozone and other environmental benefits to year-long NO _x RACT control in DFW. Regional transport may move DFW NO _x southerly into areas with more of a year-long potential for ozone exceedances. Year-long controls could help prevent current near-nonattainment areas from becoming nonattainment under the 8-hour ozone standard. Locally, year-long controls would reduce nitrates in the winter season. Nitrates contribute to the winter visibility impairment in DFW sometimes called the white or brown cloud. In addition, NO _x adds to the nitrification of surface waters, an adverse ecological impact which at times may contribute to algae buildup and related problems.

Weighed against the potential NO _x RACT approvability issue and loss of environmental benefits are the reductions in costs and effort that seasonal NO _x RACT controls would offer. The commission expects that the current emission limits will be complied with through the use of additional combustion controls, for which the expense is primarily capital rather than operating. Capital costs must be incurred regardless of the length of the compliance season. The primary benefit to the utility of an 8-month compliance season would be a reduced compliance effort during a portion of the normal unit outage period, when test firing with fuel oil and other scheduled maintenance may occur. While not minimizing these efforts, particularly the fact that there has been a documented visibility problem in DFW in the winter has to be weighed carefully against the additional effort. In this regard, year-long compliance makes sense and is consistent with the application of Chapter 117 elsewhere in the state. The commission has made no change in response to this comment.

Garland commented that the CO limitation should not be necessary, since there is a strong cost efficiency incentive to minimize it.

Combustion modifications to reduce NO _x emissions in some cases may result in CO increases. The CO limits of Chapter 117 reflect good combustion practice consistent with implementation of combustion controls for NO _x . Although there is an economic incentive to minimize CO because it represents incomplete use of fuel, this may not be the primary factor until significantly higher levels of CO occur. The commission has made no change in response to this comment.

EPA asked for rule clarification that sources subject to 40 CFR Part 72 are required to use 40 CFR Part 75.22 reference test methods. The EPA also said that the rule should clarify that sources subject to Part 72 must use Part 75, Subpart E, or optional protocol Appendix E of Part 75 for gas- or oil-fired peaking units.

Chapter 117 points to the acid rain NO _x monitoring regulations in Title 40 Part 75 because that program will satisfy the needs of Chapter 117 for those units which are required to monitor NO _x emissions under Part 75. From the context of the requirements for CEMS in §117.113(c) and §117.213(c)(2), and for PEMS in §117.113(f)(3)-(4), it seems clear that Chapter 117 is not designed to take precedence over the acid rain regulations. The commission disagrees with EPA that Chapter 117 needs to clarify the Title 40 requirements. One of the goals of regulatory reform is to eliminate rule redundancy, and EPA's recommended language is a restatement of federal regulations. The commission has made no change in response to this comment.

Denton recommended that the monitoring for electric utilities in Division 1 of the rule allow sharing of PEMS or CEMS in the same way allowed for industrial sources in Division 2. TIP expressed support for the clarification that a computer may be used to collect, sum, and store electronic data from fuel meters and asked that the same language be included in §117.113 for electric utilities.

The commission agrees with the commenters that these changes would provide more clarity and consistency and has made the necessary changes by inserting the pertinent language from §117.213(e)(3) into §117.113(c) and §117.213(a) into §117.113(h).

EPA commented that they were unclear about recordkeeping and reporting requirements for sources using portable analyzers for periodic sampling of CO allowed in §117.113(b)(2)(A).

The recordkeeping requirement for monitoring data in §117.119(e)(5) was intended to include records of CO monitoring, including periodic CO measurements. The commission has simplified the lead-in sentence to the required recordkeeping in §117.119(e)(5) for clarity.

The reporting requirements of Chapter 117 are geared toward sources which use some type of continuous monitoring system. In Chapter 117, periodic CO monitoring using portable analyzers provides indicator of compliance data, rather than direct compliance data, such as reference method tests, CEMS, PEMS, or steam or water parameter monitoring systems for turbines. The need to provide a specific Chapter 117 procedure for reporting excess CO emissions indicated by portable analyzers would need to be evaluated, and if appropriate, included in a future rulemaking.

DFWIA commented that the language of §117.203, concerning Exemptions, makes it unclear as to the requirements for their stationary engines used for emergency electric power generation.

There are several exemptions which pertain to internal combustion engine (ICE) and more than one may apply. The engines of concern operate less than 850 hours per year and could qualify for the exemption of §117.203(6)(B). Owners or operators using this exemption must use a run time meter and maintain records of monthly operating hours to demonstrate compliance with the exemption criterion, as specified in §117.213(i). An alternative to the exemption in §117.203 could also be used. Two other classes of engines, low annual capacity factor engines, and currently, lean-burn engines, are exempt from Chapter 117 emission limits under §117.205(g)(2) and (6), respectively. Under either of these exemptions, the engine would need a fuel use meter, as specified in §117.213(a)(2). The commission has made no change in response to the comment.

Exxon and TIP commented that the proposed clarification in §117.205(b)(6) and §117.207(h) could be read to restrict the use of the permit limit in cases where the hydrogen multiplier would otherwise increase a level beyond a permit level.

The Chapter 117 NO _x limit is the lower of any Chapter 116 permit limit or the §117.205(b)-(d) limit, as stated in §117.205(a)(1). The adopted revision in §117.205(b)(6) and §117.207(h) reiterates that the hydrogen multiplier cannot be used to increase a permit limit, which would contradict §117.205(a)(1). However, to further clarify the use of the multiplier, the commission has inserted the words "up to" 1.25 in these subsections and in §117.207(g)(4).

Exxon commented that the proposed new §117.207(f)(1) was confusing and added no new meaning. TIP suggested alternative wording for §117.207(f)(1). TIP also suggested that the referant "that" in §117.207(f)(2) should be identified.

Although the language suggested by TIP for §117.207(f)(1) appears to be an improvement, the commission agrees with Exxon that proposed §117.207(f)(1) is repetitive of the preceding sentence in §117.207(f). Proposed §117.207(f)(1) has been deleted and the remaining paragraphs renumbered. In response to TIP's second comment, the commission has also substituted the term "the opt-in" for "that" in proposed §117.207(f)(2), now numbered §117.207(f)(1). For further consistency, "opt" replaces "elect" in §117.207(f) and (f)(2).

DFWIA suggested that the proposed requirement to install boiler oxygen trim systems on their boilers is not a cost-effective method of reducing NOx .

The requirement to install oxygen or CO trim systems on large industrial, commercial, and institutional boilers was not controversial when developed in concert with extensive negotiations with the regulated community in the HGA and BPA areas. The advantages of such systems are that they can pay for themselves with fuel savings while reducing NO _x due to low excess air operation and reduced firing. However, if possible, it would make more sense to install trim concurrently with attainment demonstration level NO _x controls, especially since, for DFW, any such more stringent rules are likely to be adopted within one year of adoption of the current NO _x RACT rules. A higher level of NO _x control than the current rules also is more likely to necessitate a higher level of boiler operational control, such as oxygen trim. Integrating the operational control requirements in one step would be more cost-effective for the five institutional boilers in DFW which are affected by the oxygen trim requirement. In response to comments on the feasibility of the proposed NO _x RACT implementation schedule, the commission has extended the compliance date to allow two years for NO _x RACT. This additional time should also assist the DFWIA in making a more cost-effective decision in their boiler NO _x control strategy. For consistency with the requirements in HGA and BPA, the commission has retained the requirement to install boiler oxygen or CO trim.

Pennzoil expressed concern that exempted facilities may be cited for not having an initial control plan (ICP) even though they only have exempt sources. They referenced §117.203 which states that specifically listed units are exempt from Chapter 117 except for certain requirements; one of those being the listing requirements in the ICP. Pennzoil suggested that §117.209(c) be revised to limit the submission of ICP to major sources.

Section 117.209(a) limits the ICP to major sources, defined by 25 tpy of NO _x in HGA and 50 in BPA. Therefore, Pennzoil's recommended revision to subsection (c) is not necessary. However, all major sources were required to submit an ICP, not just those which had units subject to the rule's emission specifications. The purpose was to identify the specific reasons for major sources being exempt from the emission limitations. The commission has modified the wording in §117.103(a) and §117.203(a) to clarify that the excepted requirements only apply "as may be specified" in the referenced requirements.

Exxon and TIP recommended changes to §117.211(d) to allow for flexibility in the contents of test reports made before the effective date of the proposed revisions. Otherwise, Exxon said, some sources may be required to redo their compliance tests merely to meet all the paperwork requirements of §117.213(g).

The commenters identified the need to strike a balance between ensuring sufficient data is collected to verify compliance and the likelihood that overly prescriptive requirements could be unnecessarily costly. The lack of certain items listed in §117.211(g), such as brief resume/qualifications of test personnel, should not be sufficient to reject a compliance stack test report made before the effective date of this rule. On the other hand, there is no reason that test reports made after the effective date of the rule should lack any of the specified information. The commission has revised the language of §117.211(d) and (g) along the lines recommended by the commenters.

Exxon commented that proposed §117.213(a)(2) would require fuel use meters for rich-burn engines subject to emission limits, which is not currently required. Exxon asked that either this requirement be dropped, or the commission justify its inclusion.

The requirement to install a totalizing fuel flow meter on rich-burn engines subject to emission limits is not new, and was previously contained in §117.213(e). Rich-burn engines subject to the Chapter 117 emission limits are large enough to be potential major sources by themselves. Because they represent a significant portion of emissions, it is important to the ozone control strategy that their emissions are quantified. The fuel use meter is a relatively inexpensive way of greatly improving the quantification of emissions from a combustion source. However, §117.213(a)(2) as proposed, inadvertently would expand the fuel meter requirement to engines exempt under the special use and run time exemptions of §117.203. The commission has corrected §117.213(a)(2) so that it more narrowly applies to engines "not exempt by §117.203(6) or (8)."

Exxon recommended §117.213(a)(4) wording be revised from "supplemental fuel fed to FCCU boilers" to "FCCU boilers using supplemental fuel."

The commission appreciates the opportunity to improve the readability of the rule and has made the revision.

TIP supported the option to periodically sample CO but said that the language in §117.213(d)(2) was unclear as to when the testing is required. TIP suggested clarifying that the rule does not require an owner or operator to sample whenever there is any kind of drop in NO _x emissions. TIP suggested adding a time frame for when CO testing is required and a clarification of the rulemaking intent.

The rule language in §117.213(d)(2) defines a specific set of circumstances which require CO sampling. Sampling is required whenever manual tuning or burner adjustments are performed for the purpose of minimizing NO _x and either the NO _x is sampled with an external (portable or reference method) test apparatus, or the manual adjustments are of such an extent that the NO _x operating level is lower than levels for which CO data was previously gathered. Manual adjustments to lower NO _x typically would be an activity scheduled by the owner or operator at his/her convenience. Even unscheduled manual NO _x adjustments only require a CO measurement if clause (i) or (ii) apply. The commission has made several wording changes to improve the readability of the requirements in §117.113(b)(2)(A) and §117.213(d)(2)(A).

TIP questioned why a portable analyzer could not be used for the annual RATA testing required in §117.213(d)(2)(B).

Measurements with test reference method apparatus are considered more reliable than measurements with portable analyzers since, for the former, quality assurance procedures are explicitly laid out in the regulations. The requirement to use a compliance test method here rather than an indicator of compliance method is not burdensome. A sampling van or trailer equipped to measure NO _x using reference test method apparatus is normally equipped to measure CO and any extra efforts to calibrate the CO instrument and record test results are minimal. The commission notes that unless a combustion unit using a NOx CEMS is subject to an annual NO _x RATA by a requirement outside of Chapter 117, units using NOx CEMS are allowed to substitute a cylinder gas audit (CGA) for the annual RATA. Therefore, the commission has revised the reference in paragraph (2)(B) from "the" to "any" RATA.

Pavilion recommended that an annual RATA be required for ongoing quality assurance of CEMS, rather than allowing substitution of a CGA for the RATA. EPA expressed concern that the rule allows this substitution.

The specific concerns raised by the commenter regarding problems only found by a RATA deserve further investigation. Historically, the commission, and earlier, the Texas Air Control Board, have allowed CGA to substitute for the annual RATA in state-only new source review permits, because staff believes that the additional costs of the annual RATA were not commensurate with the benefits. The required quarterly CGA are often performed in-house and are easier to schedule than RATA, which generally are performed by outside specialists. For Chapter 117, if 200 CEMS are used, and a RATA costs between $2500-$5000, the annual additional rule cost would be in the range of $0.5-$1.0 million each year. The staff also believes that a CGA, if performed properly, identifies the ability of the CEMS to accurately measure NO _x and diluent. The CGA requires insertion of the calibration gas at the CEMS probe tip and does not allow pressurization of a negative pressure system. In the example that Pavilion cites it isn't clear whether the proper CGA procedure was followed. Overall, the comments point to the need to assess performance of all types of continuous NO _x monitors used to comply with the rule. The commission has made no change in response to these comments.

Pavilion suggested that the proposal to allow postponing PEMS RATA until six months after November 15, 1999, should be revised to allow the first ongoing RATA to be performed one year after that date, saying the basis should be whether the initial RATA result at normal load is within 7.5%.

It would not be appropriate to use the initial RATA to justify an immediate reduction in the RATA frequency. The initial RATA is likely to be performed shortly after the model is set up. The issue with computer models is whether over time they remain capable of accurately predicting emissions. The existing rule contains an option for a reduction in RATA from the normally expected semiannual frequency to annual frequency, if the model achieves better than acceptable performance in the 6-month period between two consecutive RATA. These two RATA taken together enable some assessment of the ability of the PEMS to predict emissions over time. The commission has made no change in response to this comment.

Pavilion recommended revisions to the performance requirements for PEMS used to predict oxygen (O ₂ ), carbon dioxide (CO2 ), and CO. Pavilion said that for the diluents O2 and CO ₂ , the relative accuracy (RA) criteria are either no greater than 20% of the mean value of the reference method test data, or 1.0% O ₂ or CO ₂ , whichever is greater. However, the rule currently relies only on the 20% criteria for the RATA skip option. Pavilion recommended if the criterion of 1.0% for O ₂ or CO ₂ , or 5 ppm for CO is used, then only annual RATA should be required.

Pavilion is correct that the federal performance specification test criteria differ for the different compounds. Pavilion's suggested alternative criteria for qualifying for annual RATA is reasonable, since it would avoid the unintended outcomes that diluent rather than NO _x , or CO at levels below regulatory concern, would drive the RATA schedule. The commission has adopted revisions to the requirements of §117.213(f)(5)(C) to address the comment.

Pavilion recommended that the normal emission level test be used to determine if the 7.5% RA criterion is met.

The ongoing RATA is required to be performed at normal load operations. The commission agrees with Pavilion and has revised the requirements in §117.213(f)(5)(C)(iii)(II) accordingly.

EPA asked for an explanation of how the model training process referenced in §117.213(f)(7) ensures PEMS accuracy for alternative fuels.

The intent of the wording is that there may be slight changes to fuel composition for which available data from the model training process could show negligible emission effect, or the data could show that the model adequately predicts emission changes caused by the fuel changes.

Exxon disagreed with the preamble that the additions to §117.215(a), concerning final control report requirements, could reduce the time needed to complete the plan. They said that the additional information would significantly increase the time required to complete the plan and that this should have been included in the analysis of economic impact of the rule. Exxon agreed that the additional information should reduce the time necessary for the agency to assess compliance and said they did not take exception to the data elements that the commission is requesting.

The commission's preamble discussion to the changes in §117.215 assumed that certain changes to the final control plans which may simplify the effort to comply could, in some cases, be greater than the added requirements. Conversely, the commission did not mean to imply that in other cases, the additional requirements would not require additional time to prepare the plans. Chief among the potential time savers is the clarification through the deletion of the term "affected source" in §117.215(a), which is imprecise and has been interpreted in other situations to include exempted equipment. The analysis probably erred in the assumption that requiring the use of standard forms could be a time saver, since providing standard forms but making their use optional would be more likely to save time for the regulated community (although it would reduce the benefit to the commission). The commission may also have overestimated the accessibility of compliance information at some of the larger sources with numerous separate operating units. The commission has made no change in response to the comments.

Exxon recommended wording changes to §117.215(b) to express that the maximum rated capacity (MRC) doesn't establish a grandfathered rate for a unit. Exxon also recommended minor punctuation and grammatical changes to this subsection.

The MRC is used for Chapter 117 emission averaging only. The MRC does not establish a grandfathered rate for a unit. Inspection of the definition of MRC in Chapter 117 indicates that the methodology for establishing MRC is not based on a particular date, unlike the definition of "grandfathered facility" in Chapter 116. The clarification does not seem essential and the commission has chosen for rule simplicity not to add it. The commission appreciates the opportunity to improve the readability of the rule and has made the minor changes to §117.215(b).

Exxon encouraged the electronic forms specified in §117.215(d) to be provided in draft as soon as possible so that the forms are as user friendly as possible and any conversion bugs between WordPerfect and Microsoft Word can be worked out early.

The commission staff will work with the regulated community to meet their concerns and post the forms on the agency website promptly.

TIP and Exxon suggested the final control plans required in §117.215 should be acceptable for Title V purposes to prevent the same information being required twice on separate agency forms. TIP suggested for Title V, sources could either reference the earlier Chapter 117 submission, or resubmit the identical Chapter 117 forms.

The Title V permit forms are designed to provide a comprehensive list of applicable requirements and the data necessary to identify those requirements for each emission unit at a site. These forms are designed for a database which will track the applicable requirements over time. At the time of application, they will need to reflect the applicable requirements and facility data in effect at that time. In contrast, the Chapter 117 final control plan focuses on such data as emission limit calculations and emission test results, which will be used to substantiate emissions compliance at the Chapter 117 compliance date. This information is needed at the final compliance date to ensure timely improvements in air quality and satisfaction of federal emission reduction requirements. The overlapping information between the Chapter 117 control plans and the Title V forms for Chapter 117 is limited and will become more so, since the submittal dates do not coincide. These major differences make it impractical to substitute or incorporate the Chapter 117 form in the Title V permit form.

Exxon suggested that the reports specified in §117.219(c) be required 60 days after the end of the period.

The rule, in §117.219(c), currently requires the reports to be submitted 30 days after the end of the reporting period. The staff reviewed several air regulations, including 30 TAC §122.145, concerning federal operating permits; 40 CFR §60.7(c), concerning Standards of Performance for New Stationary Sources; and 40 CFR §63.10(d) concerning National Emission Standards for Hazardous Air Pollutants, and found them to consistently specify that reports be submitted within 30 days after the end of the reporting period. The commission has made no change in response to the comment.

EPA pointed out that §117.223(i) calls for owners or operators to identify their intention to use the source cap in the initial control plan, but that for the DFW rules, there is no proposed ICP.

The commission has modified §117.223(i) to correct this drafting error.

TU, Denton, and Garland said that the proposed compliance schedule for the electric utilities was not feasible, realistic, or reasonable. TU recommended extending the RACT implementation deadline for DFW to two years from the adoption of the rule to avoid jeopardy to electric reliability and availability. The commenters cited factors such as adequate time to select vendors, prepare engineering analyses and plans, and order, fabricate, install, and test control equipment. Each commenter referred to the need to schedule installation of controls with regard to downtime or outages. Additionally, Garland mentioned the time needed for a municipal utility to procure any necessary funds through the municipal budget process and Denton cited an insufficient number of control equipment vendors in the area.

TU provided information showing that they were able to achieve about a 20% reduction in NO _x in 1998 from ten of TU's 23 power boilers operating in the area. The information also showed that 12 of the 23 boilers still require significant reductions to achieve compliance with the proposed NO _x RACT rules. Considering the number of TU boilers still required to be retrofit and the other cited factors, the commission believes that a 2- year compliance schedule is reasonable. This schedule is consistent with the original NO _x RACT rule schedule adopted for HGA and BPA. The commission has adopted a compliance date for utility electric generation in DFW of March 31, 2001 in §117.510(b) and correspondingly adjusted the dates in §117.540.

Lockheed expressed concern that they may not accomplish their underway replacement of existing boilers by November 15, 1999 and recommended the rule compliance date be extended to May 15, 2000.

The Chapter 117 NO _x RACT rules are designed to achieve an initial set of point source NO _x emission reductions in DFW expeditiously. Lockheed is in the process of replacing 1941 vintage boilers with new, air quality permitted boilers which will use best available control technology. According to their testimony, they are moving as expeditiously as practicable, and have accelerated the construction schedule to minimize additional cost overruns that have been caused by shortages of construction materials in the DFW area. Since they have contractual obligations to complete the construction, and appear to qualify in other respects, phased RACT would be an option, and any Chapter 117 compliance date would be unlikely to affect the ultimate timing of these reductions. However, maintaining the proposed final compliance date for the industrial sources would require additional paper work of Lockheed and the commission staff. In consideration of the minimal emission benefits and other factors (relating to boiler trim controls) associated with a November 15, 1999 compliance date, and for consistency with the adopted utility electric generation compliance date, the commission has adopted a compliance date for industrial, institutional, and commercial sources of March 31, 2001 in §117.520(b).

An individual expressed opposition to phased RACT, saying that additional time should not be necessary for rule compliance.

The phased RACT option is expected to be used sparingly. The rule was designed to require clear and substantial criteria to be met to qualify for any additional time. The EPA will also review the phased RACT applications, which will provide additional opportunities for a critical evaluation. The commission has made no changes in response to the comment.

Subchapter A. Definitions

Subchapter A. General Provisions