Part 1. TEXAS COMMISSION ON ENVIRONMENTAL QUALITY

Chapter 39. PUBLIC NOTICE

Subchapter H. APPLICABILITY AND GENERAL PROVISIONS

30 TAC §39.403

The Texas Commission on Environmental Quality (commission) adopts an amendment to §39.403, Applicability. Section 39.403 is adopted without change to the proposed text as published in the September 6, 2002 issue of the Texas Register (27 TexReg 8411) and will not be republished.

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULE

The commission's practice of permitting pre-injection units and other surface units as part of nonhazardous underground injection control (UIC) permits has varied over time, due to the different scope of applications submitted by applicants, and due to different interpretations of statutes and the provisions of 30 TAC Chapter 331, Underground Injection Control. Generally, it has been the applicants' option whether to include pre-injection facility information in their UIC permit applications. About half of the UIC permits issued by the commission for on-site disposal of nonhazardous waste include specifications for pre-injection units. This rulemaking provides the option of including pre- injection units in a registration under the authority of Texas Water Code (TWC), Chapter 27, and provides a consistent set of standards and guidance to permit applicants, agency staff, and the general public on application requirements for pre-injection units, whether they are to be authorized by permit or registration. The conforming amendments to Chapter 331 also change the terms "Pre-injection facilities" and "Surface facilities," which are considered to be terms of art, to "Pre-injection units." These changes are adopted for consistency with other agency definitions wherein "facility" usually refers to a property along with structures and other appurtenances, and "unit" usually refers to the individual types of equipment used for the management of waste, such as tanks, pumps, or surface impoundments.

This issue was given preliminary consideration by the commissioners at a work session on October 20, 2000. Staff was directed to conduct additional research on the issue and develop recommendations. Staff returned to work session on January 17, 2001, and presented a list of options to the commission relating to the regulation of pre-injection units associated with on-site nonhazardous waste disposal by Class I injection wells and any permitted Class V injection wells. The commissioners directed staff to require applicants for UIC permits to include design information for pre-injection units with the permit application. The commissioners further directed staff to review the design information and ensure the design of the pre-injection units was adequate to protect groundwater. Applicants were to be informed that inclusion of pre-injection units as part of their UIC permits was optional. Applicants who choose not to include pre-injection units in their UIC permits would be subject to a registration process for those facilities. Applicants were also to be informed that sufficient design information must be included in their application so that staff could conduct a thorough technical review and determine whether the pre-injection units are protective of human health and the environment.

Amendments to Chapter 331 are adopted to implement the new registration procedure, and are also published in this issue of the Texas Register . Part of that procedure includes mailed public notice and an opportunity for public comment on the registration of pre-injection units. These mailed notice and public comment procedures for registration of UIC pre-injection units are given in the adopted amended and new sections to Chapter 331, including new §331.17, Pre-Injection Units Registration, and new §331.18, Registration Application, Processing, Notice, Comment, Motion to Overturn. It should be noted that an opportunity to file written comment with the commission will be available to interested parties; however, there will be no opportunity for a contested case hearing on the proposed registrations. Conforming changes are hereby adopted for §39.403, Applicability, to except these notice provisions from Chapter 39. The procedures that apply may be found in adopted new §331.18.

SECTION DISCUSSION

Adopted §39.403, Applicability, is amended to except registrations of pre-injection units for nonhazardous noncommercial injection wells from the public notice requirements in Chapter 39. The requirements that apply may be found in adopted new §331.18. Administrative changes have been made to conform to Texas Register requirements.

FINAL REGULATORY IMPACT ANALYSIS DETERMINATION

The commission has reviewed the rulemaking in light of the regulatory analysis requirements of Texas Government Code, §2001.0225, and has determined that the adopted rule is not subject to §2001.0225 because it does not meet the definition of a "major environmental rule" as defined in that statute. "Major environmental rule" means a rule the specific intent of which is to protect the environment or reduce risks to human health from environmental exposure and that may adversely affect in a material way the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state. The specific intent of the adopted rule is to amend Chapter 39 to exempt the registration of pre-injection units at nonhazardous, noncommercial injection wells from the notice provisions of Chapter 39. The rule does so by amending §39.403 to state that registrations for pre-injection units for nonhazardous, noncommercial injection wells are excluded from the application of Chapter 39. The adopted rule substantially advances its purpose by excluding registrations for pre-injection units for nonhazardous, noncommercial injection wells.

The adopted rule meets one criterion of the definition of a major environmental rule because the intent of this rule is to protect the environment or reduce risks to human health from environmental exposure. However, the rule does not meet the two other criteria of the definition of a major environmental rule. It does not adversely affect in a material way the economy, a sector of the economy, productivity, competition, or jobs because it does not require more from an applicant than is required by current rules which require that pre-injection units be included in the injection well permit. The adopted rule is not anticipated to adversely affect in a material way the environment or the public health and safety of the state or a sector of the state because the adoption is part of a rule package which provides protection for health and the environment that is substantially similar to the protection provided by application of the previous rules.

In addition, the adopted rule does not exceed the four applicability requirements of Texas Government Code, §2001.0025(a)(1) - (4) in that the rule does not: 1) exceed a standard set by federal law; 2) exceed an express requirement of state law; 3) exceed a requirement of a delegation agreement; or 4) adopt a rule solely under the general powers of the agency.

The adopted rule does not exceed a standard set by federal law because there are no such corresponding federal standards for notice concerning registration of pre-injection units at nonhazardous, noncommercial injection wells. The rule does not exceed an express requirement of state law because TWC, Chapter 27 does not establish express requirements for notice concerning registration of pre-injection units at nonhazardous, noncommercial injection wells. The rule does not exceed the requirements of the delegation agreement because the delegation agreement does not establish express requirements for notice concerning registration of pre-injection units at nonhazardous, noncommercial pre-injection units.

This rule is not adopted solely under the general powers of the agency, but is adopted under the specific provisions of the Texas Injection Well Act, TWC, §§27.002, 27.003, 27.011, 27.019(a), and 27.051(3).

TAKINGS IMPACT ASSESSMENT

The commission has prepared a takings impact assessment for this adopted rule in accordance with Texas Government Code, §2007.043. The commission's assessment indicates that the Texas Government Code, Chapter 2007 does not apply to this adopted rule because the rule is an action that is taken in response to a real and substantial threat to public health and safety; it is designed to significantly advance the health and safety purpose; and it does not impose a greater burden than is necessary to achieve the health and safety purpose. Texas Government Code, §2007.003(b)(13), provides that an action that is taken in response to a real and substantial threat to public health and safety; that is designed to significantly advance the health and safety purpose; and that does not impose a greater burden than is necessary to achieve the health and safety purpose is exempt from Chapter 2007.

The real and substantial threat to public health and safety in this rulemaking involves activities that may pollute fresh water. The Texas Injection Well Act, TWC, §27.003 states that it is the policy of the state to "prevent underground injection that may pollute fresh water" and "to require the use of all reasonable methods to implement this policy." Section 27.051(3) requires that the commission make a finding, before it issues a permit, "that, with proper safeguards both ground and surface fresh water can be adequately protected from pollution." Section 27.002(4) defines "pollution" as "the alteration of the physical, chemical, or biological quality of or the contamination of, water that makes it harmful, detrimental, or injurious to humans...."

Other adopted rules would minimize this threat by requiring that certain nonhazardous, noncommercial pre-injection units meet the design criteria for sewerage systems, while offering to applicants the option of using a registration process to authorize such pre-injection units. This rule exempts the registration process from the notice requirements of this chapter because Chapter 39 applies generally to permits and not to registrations.

The adopted rule significantly advances the health and safety purpose by setting a uniform design standard which is protective of human health and safety for certain pre-injection units. The design standards protect health and safety by requiring the management of waste fluids in such a manner as to prevent their excursion into fresh waters in the state.

The adopted rule does not impose a greater burden than is necessary to achieve the health and safety purpose because the adopted design standards for nonhazardous, noncommercial pre-injection units represent the engineering practice necessary to prevent the pollution of fresh water. Further, the adopted rule allows applicants to use, as an option, a registration process to comply with the rule. The option of using a registration process is expected to provide, in some instances, a less burdensome method of administering the design standards than the present rules, which require that nonhazardous, noncommercial pre-injection units be included in the injection well permit.

The adopted rule is not subject to Texas Government Code, Chapter 2007 because it is exempt under the provisions of §2007.003(b)(13).

Nevertheless, the commission further evaluated this adopted rule and performed an assessment of whether this rule constitutes a taking under Texas Government Code, Chapter 2007. The specific purpose of the rule is to exempt the registration process from the notice requirements of Chapter 39, which applies generally to permits and not to registrations. The rule substantially advances this purpose by adding an exemption from the requirements of Chapter 39, Subchapters H - M for applications for registration of pre-injection units for nonhazardous, noncommercial, underground injection wells under §331.17 of this title (relating to Pre-Injection Units Registration). The adopted rule does not require more from an applicant than was required by previously existing rules, which required that pre-injection units be included in the injection well permit. Since the adopted rule does not require more than would be required by previously existing rules, it does not burden an owner of real property in a manner which would be a statutory or constitutional taking. Specifically, the subject rule does not affect a landowner's rights in private real property because this rulemaking does not burden (constitutionally); nor restrict or limit the owner's right to property and reduce its value by 25% or more beyond that which would otherwise exist in the absence of the regulation.

CONSISTENCY WITH THE COASTAL MANAGEMENT PROGRAM

The commission determined that the adopted rule does not relate to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Management Act of 1991, as amended (Texas Natural Resources Code, §§33.201 et seq .) and the commission rules in 30 TAC Chapter 281, Subchapter B, concerning the CMP. The rulemaking action concerns only the procedural rules of the commission, is not substantive in nature, does not govern or authorize any actions subject to the CMP, and is not itself capable of adversely affecting a coastal natural resource area (31 TAC Natural Resources and Conservation Code, Chapter 505; 30 TAC §§281.40 et seq .).

HEARING AND COMMENTERS

There was no public hearing held on the proposed rulemaking, and no written comments were received during the comment period which closed at 5:00 p.m., October 7, 2002.

STATUTORY AUTHORITY

The amendment is adopted under TWC, §5.103, which provides the commission with authority to adopt any rules necessary to carry out its powers and duties under this code and other laws of this state and to adopt rules repealing any statement of general applicability that interprets law or policy; §5.105, which authorizes the commission to establish and approve all general policy of the commission by rule; and §27.019, which requires the commission to adopt rules reasonably required for the regulation of injection wells. The amendment is also adopted under Texas Health and Safety Code (THSC), §361.017 and §361.024, which provide the commission with authority to adopt rules necessary to carry out its powers and duties under the Texas Solid Waste Disposal Act. The amendment is also adopted under THSC, §401.051, which provides the commission with authority to adopt rules necessary to carry out its powers and duties under the Texas Radiation Control Act.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 20, 2002.

TRD-200208431

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 9, 2003

Proposal publication date: September 6, 2002

For further information, please call: (512) 239-4712

1. EMISSION CREDIT BANKING AND TRADING

30 TAC §§101.300 - 101.304, 101.306, 101.309, 101.311

STATUTORY AUTHORITY

The new and amended sections are adopted under Texas Water Code (TWC), §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, §382.017, concerning Rules, which authorizes the commission to adopt rules consistent with the policy and purposes of the Texas Clean Air Act (TCAA). The new and amended sections are also adopted under THSC, §382.002, concerning Policy and Purpose, which establishes the commission's purpose to safeguard the state's air resources, consistent with the protection of public health, general welfare, and physical property; §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to develop a general, comprehensive plan for control of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require a person whose activities cause emissions of air contaminants to submit information to enable the commission to develop an emissions inventory; §382.016, concerning Monitoring Requirements, Examination of Records, which authorizes the commission to prescribe reasonable requirements for the measuring and monitoring of emissions of air contaminants. The new and amended sections are also adopted under 42 USC, §7410(a)(2)(A), which requires SIPs to include enforceable emission limitations and other control measures or techniques, including economic incentives such as fees, marketable permits, and auction of emission rights.

§101.302.General Provisions.

(a) Applicable pollutants. Reductions of volatile organic compounds (VOC) and nitrogen oxides (NO _x ) may qualify as emission credits. Reductions of other pollutants do not qualify as emission credits under this division, except as provided in paragraph (2) of this subsection. Reductions of one pollutant may not be used to meet the requirements for another pollutant, unless:

(1) urban airshed modeling demonstrates that one ozone precursor may be substituted for another, subject to executive director and EPA approval; or

(2) the facility generating the emission reductions is located outside the United States; and

(A) the substitution:

(i) results in a greater health benefit and is of equal or greater benefit to the overall air quality of the area, as determined by the executive director;

(ii) is from the reduction of an air contaminant for which the area has been designated as nonattainment or which leads to the formation of a criteria pollutant for which an area has been designated as nonattainment; and

(iii) is for any air contaminant for which the area has been designated as nonattainment or leads to the formation of a criteria pollutant for which the area has been designated as nonattainment; and

(B) the user:

(i) demonstrates that the use of the reduction does not cause localized health impacts, as determined by the executive director;

(ii) submits all supporting information for calculations and modeling, and any additional information requested by the executive director; and

(iii) is located within 100 kilometers of the Texas - Mexico border.

(b) Eligible generator categories. The following categories are eligible to generate emission credits:

(1) facilities, including area sources;

(2) mobile sources; and

(3) any facility, including area sources, or mobile source associated with actions by federal agencies under §101.30 of this title (relating to Conformity of General Federal Actions to State Implementation Plans).

(c) Emission credit requirements.

(1) Emission reduction credits (ERCs) are certified reductions which meet the following requirements:

(A) reductions must be enforceable, permanent, quantifiable, real, and surplus;

(B) the certified reduction must be surplus at the time it is created, as well as when it is used;

(C) in order to become certified, the reduction must have occurred after the most recent year of emissions inventory used in the state implementation plan (SIP) for VOC and NO _x ; and

(D) the facility's annual emissions prior to the reduction strategy must have been reported or represented in the emissions inventory used in the SIP.

(2) Mobile emission reduction credits (MERCs) are certified reductions which meet the following requirements:

(A) reductions must be enforceable, permanent, quantifiable, real, and surplus;

(B) the certified reduction must be surplus at the time it is created, as well as when it is used;

(C) in order to become certified, the reduction must have occurred after the most recent year of emissions inventory used in the SIP for VOC and NO _x ;

(D) the mobile source's annual emissions prior to the emission credit application must have been represented in the emissions inventory used in the SIP; and

(E) the mobile sources must have been included in the attainment demonstration baseline emissions inventory.

(3) Emission reductions from a facility or mobile source which are certified as emission credits under this division cannot be recertified in whole or in part as credits under another division within this subchapter.

(d) Protocol.

(1) All generators or users of emission credits must use a protocol which has been submitted by the executive director to the EPA for approval, if existing for the applicable facility or mobile source, to measure and calculate baseline emissions. If the generator or user wishes to deviate from a protocol submitted by the executive director, EPA approval is required before the protocol can be used. Protocols shall be used as follows.

(A) Facilities subject to the emission specifications under §§117.106, 117.206, or 117.475 of this title (relating to Emission Specifications for Attainment Demonstrations; and Emission Specifications) shall quantify reductions in NO _x using the testing and monitoring methodologies identified to show compliance with the emission specification.

(B) Facilities subject to the requirements under §§115.112, 115.121, 115.122, 115.162, 115.211, 115.212, 115.352, 115.421, 115.541, or 115.542 of this title (relating to Control Requirements; and Emission Specifications) shall quantify VOC reductions using the testing and monitoring methodologies identified to show compliance with the emission specifications or requirements.

(C) If the executive director has not submitted a protocol for the applicable facility or mobile source to the EPA for approval, the following requirements apply:

(i) the amount of emission credits from a facility or mobile source, in tons per year, will be determined and certified based on quantification methodologies at least as stringent as the methods used to demonstrate compliance with any applicable requirements for the facility or mobile source;

(ii) the generator must collect relevant data sufficient to characterize the facility's or mobile source's emissions of the affected pollutant and the facility's or mobile source's activity level for all representative phases of operation in order to characterize the facility's or mobile source's baseline emissions;

(iii) facilities with continuous emissions monitoring systems or predictive emissions monitoring systems in place shall use this data in quantifying actual emissions;

(iv) the chosen quantification protocol shall be made available for public comment for a period of 30 days and shall be viewable on the commission's web site;

(v) the chosen quantification protocol and any comments received during the public comment period shall be submitted to the EPA for a 45-day adequacy review; and

(vi) quantification protocols shall not be accepted for use with this division after a proposed disapproval of the protocol by the EPA in the Federal Register .

(2) In the event that the monitoring and testing data required under paragraph (1) of this subsection is missing or unavailable, the facility may report actual emissions for that period of time using these listed methods in the following order of preference to determine actual emissions:

(A) continuous monitoring data;

(B) periodic monitoring data;

(C) testing data;

(D) manufacturer's data;

(E) EPA Compilation of Air Pollution Emission Factors (Ap-42), September 2000; or

(F) material balance.

(3) When quantifying actual emissions in accordance with paragraph (2) of this subsection, the generator shall use the most conservative method for replacing the missing data, submit the justification for not using the methods in paragraph (1) of this subsection, and submit the justification for the method used.

(e) Credit certification.

(1) The amount of emission credits in tons per year will be determined and certified, to the nearest tenth of a ton per year.

(2) Applications for certification will be reviewed in order to determine the credibility of the reductions. Reductions determined to be creditable will be certified by the executive director.

(3) The applicant will be notified in writing if the executive director denies the emission credit application. The applicant may submit a revised application in accordance with the requirements of this division.

(4) If a facility's or mobile source's actual emissions exceed its allowable emission limit, reductions of emissions exceeding the limit may not be certified as emission credits.

(5) Applications for certification of emission credit from reductions quantified under subsection (d)(1)(C) of this section may only be approved upon completion of the public comment period.

(f) Geographic scope. Except as provided in paragraph (3) of this subsection, only emission reductions generated in ozone nonattainment areas can be certified. An emission credit must be used in the nonattainment area in which it is generated unless the user has obtained prior written approval of the executive director and the EPA; and:

(1) a demonstration has been made and approved by the executive director and the EPA to show that the emission reductions achieved in another county, state, or nation provide an improvement to the air quality in the county of use; or

(2) the emission credit was generated in an ozone nonattainment area which has an equal or higher nonattainment classification than the ozone nonattainment area of use, and a demonstration has been made and approved by the executive director and the EPA to show that the emissions from the ozone nonattainment area where the emission credit is generated contribute to a violation of the national ambient air quality standard in the ozone nonattainment area of use; or

(3) a facility is using emission reductions generated outside the United States which have been determined by the executive director to be real, permanent, enforceable, quantifiable, and surplus to any applicable international, federal, state, or local law and the result would provide a greater health benefit to the area as determined by the executive director; and the facility:

(A) demonstrates that the use of the reduction does not cause localized health impacts, as determined by the executive director;

(B) submits all supporting information for calculations and modeling, and any additional information requested by the executive director; and

(C) is located within 100 kilometers of the Texas - Mexico border.

(g) Recordkeeping. The generator must maintain a copy of all notices and backup information submitted to the registry for a minimum of five years. The user must maintain a copy of all notices and backup information submitted to the credit registry from the beginning of the use period and for at least five years after. The user must also make such records available upon request to representatives of the executive director, EPA, and any local enforcement agency. The records shall include, but not necessarily be limited to:

(1) the name, emission point number, and facility identification number of each facility or any other identifying number for each mobile source using emission credits;

(2) the amount of emission credits being used by each facility or mobile source; and

(3) the specific number, name, or other identification of emission credits used for each facility or mobile source.

(h) Public information. All information submitted with notices, reports, and trades regarding the nature, quantity, and sales price of emissions associated with the use, generation, and transfer of an emission credit is public information and may not be submitted as confidential. Any claim of confidentiality for this type of information, or failure to submit all information, may result in the rejection of the emission credit application. All nonconfidential notices and information regarding the generation, availability, use, and transfer of emission credits shall be immediately made available to the public.

(i) Authorization to emit. An emission credit created under this division is a limited authorization to emit VOC and/or NO _x , unless otherwise defined, in accordance with the provisions of this section, the FCAA, and the TCAA, as well as regulations promulgated thereunder. An emission credit does not constitute a property right. Nothing in this division may be construed to limit the authority of the commission or the EPA to terminate or limit such authorization.

(j) Program participation. The executive director has the authority to prohibit an organization from participating in emission credit trading either as a generator or user, if the executive director determines that the organization has violated the requirements of the program, or abused the privileges provided by the program.

(k) Compliance burden. Users may not transfer their compliance burden and legal responsibilities to a third party participant. Third party participants may only act in an advisory capacity to the user.

(l) Credit Ownership. The owner of the initial emission credit certificate shall be the owner or operator of the facility or mobile source creating the emission reduction. The executive director may approve a deviation from this subsection considering factors such as, but not limited to:

(1) whether an entity other than the owner or operator of the facility or mobile source incurred the cost of the emission reduction strategy; or

(2) whether the owner or operator of the facility or mobile source lacks the potential to generate one-tenth of a ton of credit.

§101.303.Emission Reduction Credit Generation and Certification.

(a) Methods of generation.

(1) Emission reduction credits (ERCs) may be generated using one of the following methods or any other method that is approved by the executive director:

(A) the permanent shutdown of a facility which causes a loss of capability to produce emissions;

(B) the installation and operation of pollution control equipment which reduces emissions below the level required of the facility;

(C) a change in a manufacturing process which reduces emissions below the level required of the facility;

(D) the permanent curtailment in production, which reduces the facility's capability to produce emissions; or

(E) pollution prevention projects that produce surplus emission reductions.

(2) ERCs may not be generated from the following strategies:

(A) reductions from the shifting of activity from one facility to another facility at the same site, as defined in §122.10 of this title (relating to General Definitions);

(B) that portion of reductions funded through state or federal programs, unless specifically allowed under that program; or

(C) reductions in emissions from the shutdown of a facility which was not reported or represented in the most recent emissions inventory used in the state implementation plan (SIP).

(b) ERC calculation. The quantity of ERCs is determined by subtracting the facility's strategic emissions from the facility's baseline emissions, as calculated in the following equation. The facility's strategic emissions equal the enforceable emission limit for the applicable facilities after the emission reduction strategy has been implemented.

Figure: 30 TAC §101.303(b)

(c) ERC certification.

(1) Facilities with potential ERCs must submit an EC-1 Form, Application for Certification of Emission Credits, within 180 days of the implementation of the emission reduction strategy to the executive director. Applications will be reviewed to determine the credibility of the reductions. Reductions determined to be creditable will be certified by the executive director and an ERC certificate will be issued to the owner.

(2) ERCs shall be quantified in accordance with §101.302(d) of this title (relating to General Provisions). The executive director shall have the authority to inspect and request information to assure that the emissions reductions have actually been achieved.

(3) An application for emission reduction credits must include, but is not limited to, a completed EC-1 Form signed by an authorized representative of the applicant along with the following information for each pollutant reduced at each applicable facility:

(A) a complete description of the emission reduction strategy;

(B) the amount of emission credits generated;

(C) for volatile organic compound reductions, a list of the specific compounds reduced;

(D) documentation supporting the baseline emission activity, baseline emission rate, baseline total emissions, and strategic emissions;

(E) emissions inventory data from the most recent year of emissions inventory used in the state implementation plan and emissions inventory data for the two consecutive years used to determine baseline activity for each applicable pollutant and facility;

(F) the most stringent emission rate and the most stringent emission level for the applicable facility, considering all the local, state, and federal applicable regulatory and statutory requirements;

(G) a complete description of the protocol used to calculate the emission reduction generated; and

(H) the actual calculations performed by the generator to determine the amount of emission credits generated.

(4) ERCs will be made enforceable by one of the following methods:

(A) amending or altering a new source review (NSR) permit to reflect the emission reduction and set a new maximum allowable emission limit;

(B) voiding an NSR permit when a facility has been shut down;

(C) for any facility which is authorized by standard permit, standard exemption, or permit by rule, certifying emissions on a PI-8 Form, Special Certification Form for Exemptions and Standard Permits, or other form deemed equivalent by the executive director, the emission reduction and the new maximum allowable emission limit;

(D) for any facility which is not required to have authorization by permit, standard permit, standard exemption, or permit by rule, certifying emissions on an OPC-RE1 Form, Certified Registration of Emissions Form for Potential to Emit, or other form deemed equivalent by the executive director, the emission reduction and the new maximum allowable emission limit; or

(E) for any facility which is not required to have authorization by permit, standard permit, standard exemption, or permit by rule, obtaining an agreed order which sets a new maximum allowable emission limit.

§101.304.Mobile Emission Reduction Credit Generation and Certification.

(a) Methods of generation.

(1) Mobile emission reduction credits (MERCs) may be generated by any mobile source emission reduction strategy that creates actual mobile source emission reductions under these rules and subject to the approval of the commission.

(2) MERCs cannot be generated from specific reductions funded through state or federal programs, unless specifically allowed under that program.

(3) MERCs cannot be generated from a mobile source if the emissions have been transferred from that mobile source to another mobile source.

(b) MERC calculation. The quantity of MERCs must be calculated from the annual difference between the mobile source emissions baseline and the projected emissions level after the MERC strategy has been put in place. The projected emissions must be based on the best estimate of the actual in-use emissions of the modified or substitute on-road or non-road vehicles or transportation system. Any estimate of a projected annual mobile source emissions level based on an assumption of reduced consumer service or transportation service would not be allowed without the support of a convincing analytical justification of the assumption. Emission baselines for quantifying MERCs should include the following information and data as appropriate, but not be limited to:

(1) the emission standard to which the mobile source is subject or emission performance to which the mobile source is certified;

(2) the estimated or measured in-use emissions levels per unit of use from all significant mobile source emissions sources;

(3) the number of mobile sources in the participating group;

(4) the type or types of mobile sources by model year;

(5) the actual or projected activity level, hours of operation or miles traveled by type, and model year; and

(6) the projected remaining useful life of the participating group of mobile sources.

(c) MERC certification.

(1) Mobile sources with potential MERCs must submit to the executive director an MEC-1 Form, Application for Mobile Emission Credits, within 180 days of implementation of the strategy. Upon approval of the application, the executive director shall issue a MERC certificate(s) to the person, company, business, organization, or public entity generating the mobile emission reduction. A MERC certificate will indicate the total amount of certified emission credits, the quantity available on an annual basis, and the date upon which the last annualized emission reduction expires.

(2) MERCs will be determined and certified in accordance with §101.302(d) of this title (relating to General Provisions) using:

(A) EPA methodologies, when available;

(B) actual monitoring results, when available;

(C) otherwise calculated using the most current EPA mobile emissions factor model or other model as applicable; or

(D) otherwise calculated using creditable emission reduction measurement or estimation methodologies which satisfactorily address the analytical uncertainties of mobile source emissions reduction strategies.

(3) An application for MERCs must include, but is not limited to, a completed MEC-1 Form signed by an authorized representative of the applicant along with the following information for each pollutant reduced at each applicable mobile source:

(A) a complete description of the generation strategy;

(B) the amount of emission credits generated;

(C) documentation supporting the mobile source baseline emission activity, mobile source baseline emission rate, mobile source baseline total emissions, and the mobile source strategy emissions;

(D) a complete description of the protocol used to calculate the emission reduction generated;

(E) the actual calculations performed by the generator to determine the amount of emission credits generated; and

(F) a demonstration that the reductions are surplus to all local, state, and federal rules and to emission modeled in the SIP.

(4) MERCs will be made enforceable by obtaining an agreed order which sets a new maximum allowable mobile source emission limits.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 17, 2002.

TRD-200208330

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 17, 2003

Proposal publication date: June 21, 2002

For further information, please call: (512) 239-0348

30 TAC §§101.302 - 101.304

STATUTORY AUTHORITY

These repealed sections are adopted under TWC, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, §382.017, concerning Rules, which authorizes the commission to adopt rules consistent with the policy and purposes of the TCAA. These repealed sections are also adopted under THSC, §382.002, concerning Policy and Purpose, which establishes the commission's purpose to safeguard the state's air resources, consistent with the protection of public health, general welfare, and physical property; §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to develop a general, comprehensive plan for control of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require a person whose activities cause emissions of air contaminants to submit information to enable the commission to develop an emissions inventory; §382.016, concerning Monitoring Requirements, Examination of Records, which authorizes the commission to prescribe reasonable requirements for the measuring and monitoring of emissions of air contaminants. These repealed sections are also adopted under 42 USC, §7410(a)(2)(A), which requires SIPs to include enforceable emission limitations and other control measures or techniques, including economic incentives such as fees, marketable permits, and auction of emission rights.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 17, 2002.

TRD-200208331

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 17, 2003

Proposal publication date: June 21, 2002

For further information, please call: (512) 239-0348

30 TAC §§101.350 - 101.354, 101.356, 101.360

STATUTORY AUTHORITY

The amended sections are adopted under TWC, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, §382.017, concerning Rules, which authorizes the commission to adopt rules consistent with the policy and purposes of the TCAA. The amended sections are also adopted under THSC, §382.002, concerning Policy and Purpose, which establishes the commission's purpose to safeguard the state's air resources, consistent with the protection of public health, general welfare, and physical property; §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to develop a general, comprehensive plan for control of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require a person whose activities cause emissions of air contaminants to submit information to enable the commission to develop an emissions inventory; §382.016, concerning Monitoring Requirements, Examination of Records, which authorizes the commission to prescribe reasonable requirements for the measuring and monitoring of emissions of air contaminants. The amended sections are also adopted under 42 USC, §7410(a)(2)(A), which requires SIPs to include enforceable emission limitations and other control measures or techniques, including economic incentives such as fees, marketable permits, and auction of emission rights.

§101.353.Allocation of Allowances.

(a) Allowances will be deposited into compliance accounts according to the following equation except as provided in subsection (b) or (h) of this section.

Figure: 30 TAC §101.353(a)

(b) For a new and/or modified facility that has submitted, under Chapter 116 of this title (relating to Control of Air Pollution by Permit for New Construction of Modification), an application which the executive director has not determined to be administratively complete before January 2, 2001, or has qualified for a permit by rule under Chapter 106 of this title (relating to Permits by Rule) and has not commenced construction before January 2, 2001, allowances for each control period or the annual allocation rights shall be acquired from facilities already participating under this division, or in accordance with §101.356(g) of this title (relating to Allowance Banking and Trading).

(c) If actual emissions of nitrogen oxides during a control period exceed the amount of allowances held in a compliance account on March 1 following the control period, allowances for the next control period will be reduced by an amount equal to the emissions exceeding the allowances in the compliance account plus an additional 10%. This does not preclude additional enforcement action by the executive director.

(d) Allowances will be allocated by the executive director, who will deposit allowances into each compliance account:

(1) initially, by January 1, 2002; and

(2) subsequently, by January 1 of each following year.

(e) The annual deposit for any control period may be adjusted by the executive director to reflect new or existing state implementation plan requirements.

(f) Allowances may be added or deducted by the executive director from compliance accounts following the review of reports required under §101.359 of this title (relating to Reporting).

(g) The owner or operator of a facility may, due to extenuating circumstances, request a baseline period more representative of normal operation as determined by the executive director. Applications for extenuating circumstances must be submitted by the owner or operator of the facility to the executive director:

(1) no later than June 30, 2001 to request an alternative three consecutive calendar year period for facilities in operation prior to January 1, 1997;

(2) no later than 90 days after completion of the baseline period to request up to two additional calendar years to establish a baseline period for facilities whose baseline as described by variable (2)(C) listed in the figure contained in subsection (a) of this section is not complete by June 30, 2001; or

(3) at any time as authorized by the executive director.

(h) Allowances calculated under subsection (a) of this section will continue to be based on historical activity levels, despite subsequent reductions in activity levels. If allowances are being allocated based on allowables and the facility does not achieve two complete consecutive calendar years of actual level of activity data, then allowances will not continue to be allocated if the facility ceases operation or is not built.

§101.354.Allowance Deductions.

(a) Allowances will be deducted in tenths of a ton from a site's compliance account for a control period based upon the monitoring and testing protocols established in §§117.114, 117.214, and 117.479 of this title (relating to Emission Testing and Monitoring for the Houston/Galveston Attainment Demonstration; and Monitoring, Recordkeeping, and Reporting Requirements).

(b) In the event that the monitoring and testing data required under subsection (a) of this section is missing or unavailable, the facility may report actual emissions for that period of time using the following equation or other listed methods in the following order to determine actual emissions: continuous monitoring data; periodic monitoring data; testing data; manufacturer's data, and EPA Compilation of Air Pollution Emission Factors (AP-42), September 2000. When reporting actual emissions as required under this subsection, the facility must also submit the justification for not using the methods in subsection (a) of this section and the justification for the method used.

Figure: 30 TAC §101.354(b) (No change.)

(c) If the protocol used to show compliance with this section differs from the protocol used by the commission to establish the allocation of allowances under §101.353 of this title (relating to Allocation of Allowances), the executive director may recalculate the number of allowances allocated per year for consistency between the methods.

(d) When deducting allowances from a site's compliance account for a control period, the executive director will deduct the allowances beginning with the most recently allocated allowances before deducting banked allowances.

(e) Allowances shall be deducted from a site's compliance account in an amount equal to the nitrogen oxides (NO _x ) emissions increases from facilities not subject to an emission specification under §117.206 or §117.475 of this title (relating to Emission Specifications for Attainment Demonstrations; and Emission Specifications) which result from changes made after December 31, 2000 to facilities subject to this division and §117.206(h)(3) or §117.475(f) of this title. Documentation detailing these increases in NO _x emissions shall be included with the submittal of the ECT-1 Form, Annual Compliance Report.

(f) Allowances allocated in accordance with the variables in (a)(2)(B) listed in the figure contained in §101.353(a) of this title may only be used by the facility for which they were allocated and may not be used by other facilities at the same site during the same control period.

(g) On March 1 after every control period, a site shall hold a quantity of allowances in its compliance account that is equal to or greater than the total NO _x emissions emitted during the prior control period.

§101.356.Allowance Banking and Trading.

(a) Allowances not used for compliance at the end of a control period may be banked for use in the following control period in compliance with §101.354 of this title (relating to Allowance Deductions) or traded except as provided in subsection (c) of this section.

(b) Allowances which have not expired or been used may be traded at any time during a control period after they have been allocated except as provided in subsection (d) of this section.

(c) The owner or operator of a site receiving allowances on an annual basis may permanently transfer ownership of the allowances allocated to individual facilities at that site to any person in accordance with the following requirements:

(1) a request for transfer of ownership shall be reviewed for approval by the executive director following the submission of a completed ECT-4 Form, Application for Permanent Transfer of Allowance Ownership;

(2) the ECT-4 Form shall include the price paid per allowance and shall be submitted to executive director at least 30 days prior to the allowances being deposited into the transferee's broker or compliance account;

(3) all information regarding the quantity and sales price of allowances shall be immediately made available to the public; and

(4) the executive director will issue a letter to the purchaser and seller reflecting this transaction. The transaction will be considered finalized upon issuance of this letter.

(d) The banking for future use or trading of allowances not used for compliance during a control period shall be restricted in accordance with the following:

(1) allowances which were allocated in accordance with the variable in (2)(B) listed in the figure contained in §101.353(a) of this title (relating to Allocation of Allowances) may not be banked for future use or traded; and

(2) allowances which were allocated prior to January 1, 2005 in accordance with the with the variables in (3)(D) listed in the figure contained in §101.353(a) of this title may not be banked for future use or traded.

(e) Only authorized account representatives may trade allowances.

(f) Trades will be reviewed for approval by the executive director in accordance with the following:

(1) submittal of a completed ECT-2 Form, Application for Transfer of Allowances;

(2) the completed ECT-2 Form shall include the price paid per allowance and shall be submitted to executive director at least 30 days prior to the allowances being deposited into the transferee's broker or compliance account;

(3) all information regarding the quantity and sales price of allowances shall be immediately made available to the public; and

(4) the executive director will issue a letter to the purchaser and seller reflecting this trade. The trade will be considered finalized upon issuance of this letter.

(g) Trades involving the transfer of individual future year allowances to be allocated to individual facilities at a site may be made in accordance with the following:

(1) the application for trade shall be reviewed for approval by the executive director following the submission of a completed ECT-5 Form, Application for Transfer of Individual Future Year Allowances;

(2) the completed ECT-5 Form shall include the price paid per allowance;

(3) transferred allowances will be deposited in the transferee's broker or compliance account on April 1 of the year in which the allowances are allocated and will be subject to the existence of the allowances in the transferor's account on that date;

(4) all information regarding the quantity and sales price of allowances shall be immediately made available to the public; and

(5) the executive director will issue a letter to the purchaser and seller reflecting this trade. The trade will be considered finalized upon issuance of this letter.

(h) Sites may use nitrogen oxides (NO _x ) discrete emission reduction credits (DERC) or mobile discrete emission reduction credits (MDERC) which have been generated and acquired in accordance with Division 4 of this subchapter (relating to Discrete Emission Credit Banding and Trading) in place of allowances for compliance with this division in accordance with paragraphs (1) - (9) of this subsection. Sites may use volatile organic compound (VOC) DERCs or MDERCs which have been generated and acquired in accordance with Division 4 of this subchapter, in place of allowances for compliance with this division in accordance with paragraphs (1) - (9) of this subsection provided that demonstration has been made and approved by the executive director and the EPA to show that the use of VOC DERCs or MDERCs is equivalent, on a one to one basis or other ratio, to the use of NO _x allowances in reducing ozone.

(1) MDERCs may be used in lieu of allowances at a ratio of one MDERC for one allowance.

(2) Prior to January 1, 2005, DERCs generated prior to January 1, 2005 may be used at a ratio of one DERC for one allowance.

(3) DERCs generated prior to January 1, 2005 may be used in lieu of allowances for compliance with this division for the control period beginning January 1, 2005 through December 31, 2005 at a ratio of four DERCs for one allowance.

(4) DERCs generated prior to January 1, 2005 may be used in lieu of allowances for compliance with this division for the control period beginning January 1, 2006 through December 31, 2006 at a ratio of seven DERCs for one allowance.

(5) DERCs generated prior to January 1, 2005 may be used in lieu of allowances for compliance with this division for the control period beginning January 1, 2007 and all subsequent control periods at a ratio of ten DERCs for one allowance.

(6) DERCs generated on or after January 1, 2005 may be used in lieu of allowances at a ratio of one DERC for one allowance.

(7) Beginning January 1, 2005, no more than 10,000 DERCs may be used in any combination totaled over all sites in the Houston/Galveston (HGA) ozone nonattainment area during a single calendar year. This restriction does not apply to MDERCs.

(8) The 10% environmental contribution and the 5% compliance margin of Division 4 of this subchapter shall not apply.

(9) DERCs or MDERCs submitted with a DEC-2 Form, Notice of Intent to Use Discrete Emission Credits, for the purpose of compliance with this section, must be submitted to the executive director at least 30 days prior to intended use.

(i) Emission reduction credits (ERCs) may be converted into a yearly allocation of allowances at the rate of one ERC to one allowance per year only if they were generated prior to December 1, 2000 and provided that:

(1) the ERC is quantifiable, real, surplus, enforceable, and permanent as required in §101.302 of this title (relating to General Provisions) at the time the ERC is converted;

(2) the ERC was generated in the HGA area;

(3) the ERC was generated from a reduction in NO _x ;

(4) the ERC has not expired; and

(5) the owner of the ERC has prior approval from the executive director.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 17, 2002.

TRD-200208332

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 17, 2003

Proposal publication date: June 21, 2002

For further information, please call: (512) 239-0348

30 TAC §§101.370 - 101.374, 101.376, 101.378, 101.379

STATUTORY AUTHORITY

The new and amended sections are adopted under Texas Water Code (TWC), §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, §382.017, concerning Rules, which authorizes the commission to adopt rules consistent with the policy and purposes of the TCAA. The new and amended sections are also adopted under THSC, §382.002, concerning Policy and Purpose, which establishes the commission's purpose to safeguard the state's air resources, consistent with the protection of public health, general welfare, and physical property; §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to develop a general, comprehensive plan for control of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require a person whose activities cause emissions of air contaminants to submit information to enable the commission to develop an emissions inventory; §382.016, concerning Monitoring Requirements, Examination of Records, which authorizes the commission to prescribe reasonable requirements for the measuring and monitoring of emissions of air contaminants. The new and amended sections are also adopted under 42 USC, §7410(a)(2)(A), which requires SIPs to include enforceable emission limitations and other control measures or techniques, including economic incentives such as fees, marketable permits, and auction of emission rights.

§101.370.Definitions.

The following words and terms, when used in this division, shall have the following meanings, unless the context clearly indicates otherwise.

(1) Activity--The amount of operation at a facility measured in terms of production, use, raw materials input, vehicle miles traveled, or other similar units that have a direct correlation with the economic output and emission rate of the facility or mobile source.

(2) Actual emissions--Shall equal the total emissions during the selected time period, using the facility's or mobile source's actual daily operating hours, production rates, and types of materials processed, stored, or combusted during the selected time period.

(3) Area source--Any facility included in the agency emissions inventory under the area source category.

(4) Baseline--Emissions that occur prior to an emission reduction strategy, considering all limitations required by applicable state and federal regulations. The baseline may not exceed the most recent level of emissions reported in the emissions inventory used in a state implementation plan (SIP). For facilities in an area in which a SIP demonstration is not required for a criteria pollutant, the two consecutive calendar years shall include or follow the 1990 emission inventory. For reduction strategies that exceed 12 months, the baseline is established after the first year of generation and is fixed for the life of the strategy. A new baseline is established for each unique emission reduction strategy.

(5) Baseline activity--The facility's actual level of activity based on the facility's actual daily operating hours, production rates, or types of materials processed, stored, or combusted averaged over any two consecutive calendar years including and following the most recent year of emissions inventory used in the SIP or subsequent year(s) which precede the emission reduction strategy or credit use period. For facilities in an area in which a SIP demonstration is not required for a criteria pollutant, the two consecutive calendar years shall include or follow the 1990 emission inventory. For facilities in existence less than two years or not having two complete calendar years of activity data, a shorter time period of not less than 12 months may be considered by the executive director.

(6) Baseline emission rate--The facility's rate of emissions per unit of activity during the baseline activity period.

(7) Baseline emissions--The facility's total actual emissions based on the baseline activity and baseline emission rate averaged over any two consecutive calendar years including and following the most recent year of emissions inventory used in the state implementation plan or subsequent year(s) which precede the emission reduction strategy or credit use period.

(8) Certified--Any emission reduction that is determined to be creditable upon review and approval by the executive director.

(9) Curtailment--A temporary or partial reduction in activity level at any facility or mobile source.

(10) Discrete emission credit--An emission reduction generated over a discrete period of time, and measured in tenths of a ton. A creditable emission credit such as a discrete emission reduction credit or mobile discrete emission reduction credit.

(11) Discrete emission reduction credit--A creditable emission reduction which is created during a generation period, quantified after the period in which emissions reductions are made, and expressed in tenths of a ton.

(12) Emission reduction--An actual reduction in emissions from a facility or mobile source.

(13) Emission reduction strategy--The method implemented to reduce the facility's or mobile source's emissions beyond that required by state or federal law, regulation, or agreed order.

(14) Facility--As defined in §116.10 of this title (relating to General Definitions).

(15) Generation period--The discrete period of time, not exceeding 12 months, over which a discrete emission reduction credit is created.

(16) Generator--The owner or operator of a facility or mobile source that creates an emission reduction.

(17) Level of activity--The amount of activity at a facility measured in terms of production, fuel use, raw materials input, or other similar units.

(18) Mobile discrete emission reduction credit (MDERC or discrete mobile credit)--A credit that is surplus, generated by a mobile source strategy. It is a creditable emission reduction that is created during a generation period, quantified after the period in which emissions reductions are made, and expressed in tons.

(19) Mobile emissions baseline--Mobile emissions that occur prior to a mobile emission reduction strategy, considering all limitations required by applicable state and federal regulations. A valid mobile emission baseline can be calculated by either using measured emissions of an appropriately sized sample of the participating mobile sources using an approved EPA test procedure or by using estimated emissions of the participating mobile sources using the most recent edition of EPA's on-road or non-road mobile emissions factor models, or other model as applicable. To ensure that mobile credits are surplus, mobile source baseline emissions estimates for each year of the proposed mobile source control program must be the same as, or lower than, those used, or proposed to be used, in the state implementation plan in which the control program is proposed.

(20) Mobile source--On-road (highway) vehicles (e.g., automobiles, trucks, and motorcycles) and non-road vehicles (e.g., trains, airplanes, agricultural equipment, industrial equipment, construction vehicles, off-road motorcycles, and marine vessels).

(21) Mobile source baseline activity--The mobile source's level of activity during the applicable mobile source baseline year.

(22) Mobile source baseline emissions--The mobile source's total emissions based on the product of mobile source baseline activity and mobile source baseline emission rate.

(23) Mobile source baseline emissions rate--The mobile source's rate of emissions per unit of mobile source baseline activity during the mobile source baseline activity period.

(24) Most stringent allowable emissions rate--The emissions rate of a facility or mobile source, considering all limitations required by applicable local, state, and federal regulations.

(25) Ozone season--The portion of the year when ozone monitoring is federally required to occur in a specific geographic area, as defined in 40 Code of Federal Regulations Part 58, Appendix D.

(26) Permanent--An emission reduction that is long-lasting and unchanging for the remaining life of the facility or mobile source.

(27) Protocol--A replicable and workable method of estimating emission rates or activity levels used to calculate the amount of emission reduction generated or credits required for facilities or mobile sources.

(28) Quantifiable--An emission reduction that can be measured or estimated with confidence using replicable techniques.

(29) Real reduction--A reduction in which actual emissions are reduced.

(30) Shutdown--The permanent cessation of an activity producing emissions at a facility.

(31) Site--As defined in §122.10 of this title (relating to General Definitions).

(32) Source--As defined in §101.1 of this title (relating to Definitions).

(33) State implementation plan--A plan which provides for attainment and maintenance of a primary or secondary national ambient air quality standard.

(34) Strategy activity--The facility's or mobile source's level of activity during the discrete emission reduction credit generation period.

(35) Strategy emission rate--The facility's or mobile source's emission rate during the discrete emission reduction credit generation period.

(36) Surplus--An emission reduction that is not otherwise required of a facility or mobile source by a state or federal law, regulation, or agreed order.

(37) Use period--The period of time over which the user applies discrete emission credits to an applicable emission reduction requirement.

(38) User--The owner or operator of a facility or mobile source that acquires and uses discrete emission reduction credits to meet a regulatory requirement, demonstrate compliance, or offset an emission increase.

(39) Use strategy--The compliance requirement for which discrete emission credits are being used.

§101.372.General Provisions.

(a) Applicable pollutants. Reductions of volatile organic compounds (VOC), nitrogen oxides (NO _x ), carbon monoxide (CO), sulfur dioxide (SO ₂ ), and particulate matter with an aerodynamic diameter of less than or equal to a nominal ten microns (PM ₁₀ ) may qualify as discrete emission credits as appropriate. Reductions of other criteria pollutants are not creditable. Reductions of one pollutant may not be used to meet the reduction requirements for another pollutant, unless:

(1) urban airshed modeling demonstrates that one may be substituted for another subject to approval by the executive director and the EPA; or

(2) the facility generating the emission reductions is located outside the United States and:

(A) the substitution:

(i) results in a greater health benefit and is of equal or greater benefit to the overall air quality of the area, as determined by the executive director;

(ii) is from the reduction of a criteria pollutant for which the area has been designated as nonattainment or which leads to the formation of a criteria pollutant for which an area has been designated as nonattainment; and

(iii) is for any criteria pollutant for which the area has been designated as nonattainment or leads to the formation of a criteria pollutant for which the area has been designated as nonattainment; and

(B) the user:

(i) demonstrates that the use of the reduction does not cause localized health impacts, as determined by the executive director;

(ii) submits all supporting information for calculations and modeling, and any additional information requested by the executive director; and

(iii) is located within 100 kilometers of the Texas - Mexico border.

(b) Eligible generator categories. Eligible categories include the following:

(1) facilities (including area sources);

(2) mobile sources; or

(3) any facility, including area sources, or mobile source associated with actions by federal agencies under §101.30 of this title (relating to Conformity of General Federal Actions to State Implementation Plans).

(c) Discrete emission credit requirements.

(1) To be creditable as a discrete emission reduction credit (DERC), an emission reduction must meet the following:

(A) the reduction be real, quantifiable, and surplus at the time the discrete emission credit is generated;

(B) the reduction must have occurred after the most recent year of emissions inventory used in the state implementation plan (SIP) for all applicable pollutants; and

(C) the facility's annual emissions prior to the reduction strategy must have been reported or represented in the emissions inventory used for the SIP.

(2) To be creditable as a mobile discrete emission reduction credit (MDERC), an emission reduction must meet the following:

(A) the reduction must be real, quantifiable, and surplus at the time it is created;

(B) the reduction must have occurred after the most recent year of emissions inventory used in the SIP for all applicable pollutants;

(C) the mobile source's emissions must have been represented in the emissions inventory used for the SIP; and

(D) the mobile sources must have been included in the attainment demonstration baseline emissions inventory. If a mobile reduction implemented is not in the baseline for emissions, this reduction does not constitute a discrete emission reduction.

(3) Emission reductions from a facility or mobile source which are certified as discrete emission credits under this division cannot be recertified in whole or in part as emission credits under another division within this subchapter.

(d) Protocol.

(1) All generators or users of discrete emission credits must use a protocol which has been submitted by the executive director to the EPA for approval, if existing for the applicable facility or mobile source, to measure and calculate baseline emissions. If the generator or user wishes to deviate from a protocol submitted by the executive director, EPA approval is required before the protocol can be used. Protocols shall be used as follows.

(A) Facilities subject to the emission specifications under §§117.106, 117.206, or 117.475 of this title (relating to Emission Specifications for Attainment Demonstrations; and Emission Specifications) shall quantify reductions in NO _x using the testing and monitoring methodologies identified to show compliance with the emission specification.

(B) Facilities subject to the requirements under §§115.112, 115.121, 115.122, 115.162, 115.211, 115.212, 115.352, 115.421, 115.541, or 115.542 (relating to Emission Specifications; and Control Requirements) shall quantify VOC reductions using the testing and monitoring methodologies identified to show compliance with the emission specifications or the requirements.

(C) If the executive director has not submitted a protocol for the applicable facility or mobile source to the EPA for approval, the following applies:

(i) the amount of discrete emission credits from a facility or mobile source, in tons, will be determined and certified based on quantification methodologies at least as stringent as the methods used to demonstrate compliance with any applicable requirements for the facility or mobile source;

(ii) the generator must collect relevant data sufficient to characterize the facility's or mobile source's emissions of the affected pollutant and the facility's or mobile source's activity level for all representative phases of operation in order to characterize the facility's or mobile source's baseline emissions;

(iii) facilities with continuous emissions monitoring systems or predictive emissions monitoring systems in place shall use this data in quantifying actual emissions;

(iv) the chosen quantification protocol shall be made available for public comment for a period of 30 days and shall be viewable on the commission's web site;

(v) the chosen quantification protocol and any comments received during the public comment period shall, upon approval by the executive director, be submitted to the EPA for a 45-day adequacy review; and

(vi) quantification protocols shall not be accepted for use with this division (relating to Discrete Emission Credit Banking and Trading) after a proposed disapproval of the protocol by the EPA in the Federal Register .

(2) In the event that the monitoring and testing data required under paragraph (1) of this subsection is missing or unavailable, the facility may report actual emissions for that period of time using these listed methods in the following order of preference to determine actual emissions:

(A) continuous monitoring data;

(B) periodic monitoring data;

(C) testing data;

(D) manufacturer's data;

(E) EPA Compilation of Air Pollution Emission Factors (AP-42), September 2000; or

(F) material balance.

(3) When quantifying actual emissions in accordance with paragraph (2) of this subsection, the generator shall use the most conservative method for replacing the missing data, submit the justification for not using the methods in paragraph (1) of this subsection, and submit the justification for the method used.

(e) Credit certification.

(1) The amount of discrete emission credits shall be rounded down to the nearest tenth of a ton when generated and shall be rounded up to the nearest tenth of a ton when used.

(2) Applications for certification will be reviewed in order to determine the credibility of the reductions. Reductions determined to be creditable will be certified by the executive director.

(3) The applicant will be notified in writing if the executive director denies the discrete emission credit notification. The applicant may submit a revised discrete emission credit notification in accordance with the requirements of this division.

(4) If a facility's or mobile source's emissions exceed its allowable emission limit, the amount of emissions exceeding the limit may not be certified as discrete emission credits.

(f) Geographic scope. Except as provided in paragraphs (7) and (8) of this subsection, only emission reductions generated in the State of Texas may be creditable and used in the state with the following limitations.

(1) VOC and NO _x discrete emission credits generated in an ozone attainment area may be used in any county or portion of a county designated as attainment or unclassified, except as specified in paragraphs (4) and (5) of this subsection and may not be used in an ozone nonattainment area.

(2) VOC and NO _x discrete emission credits generated in an ozone nonattainment area may be used either in the same ozone nonattainment area in which they were generated, or in any county or portion of a county designated as attainment or unclassified.

(3) VOC and NO _x discrete emission credits generated in an ozone nonattainment area may not be used in any other ozone nonattainment area, except as provided in this subsection.

(4) VOC discrete emission credits are prohibited from use within the covered attainment counties, as defined in §115.10 of this title (relating to Definitions), if generated outside of the covered attainment counties. VOC discrete emission credits generated in a nonattainment area may be used in the covered attainment counties, except those generated in El Paso.

(5) NO _x discrete emission credits are prohibited from use within the covered attainment counties, as defined in §115.10 of this title, if generated outside of the covered attainment counties. NO _x discrete emission credits generated in a nonattainment area, except those generated in El Paso, may be used in the covered attainment counties.

(6) CO, SO ₂ , and PM ₁₀ discrete emission credits must be used in the same metropolitan statistical area (as defined in Office of Management and Budget Bulletin Number 93-17 entitled "Revised Statistical Definitions for Metropolitan Areas" dated June 30, 1993) in which the reduction was generated.

(7) VOC and NO _x discrete emission credits generated in other counties, states, or nations may be used in any attainment or nonattainment county provided a demonstration has been made and approved by the executive director and the EPA, to show that the emission reductions achieved in the other county, state, or nation improve the air quality in the county where the credit is being used.

(8) A facility may use discrete emission reductions generated outside the United States provided that the emission reductions are quantifiable, real, and surplus to any applicable international, federal, state, or local law and the result would provide a greater health benefit to the area as determined by the executive director. The applicant must:

(A) demonstrate that the use of the reduction does not cause localized health impacts, as determined by the executive director;

(B) submit all supporting information for calculations and modeling, and any additional information requested by the executive director; and

(C) be located within 100 kilometers of the Texas - Mexico border.

(g) Ozone season. In areas having an ozone season of less than 12 months (as defined in 40 Code of Federal Regulations Part 58, Appendix D) VOC and NO _x discrete emission credits generated outside the ozone season may not be used during the ozone season.

(h) Recordkeeping. The generator must maintain a copy of all notices and backup information submitted to the registry for a minimum of five years, following the completion of the generation period. The user must maintain a copy of all notices and backup information submitted to the registry for a minimum of five years, following the completion of the use period. Other relevant reference material or raw data must also be maintained on-site by the participating facilities or mobile sources. The user must also maintain a copy of the generator's notice and backup information for a minimum of five years after the use is completed. The records shall include, but not necessarily be limited to:

(1) the name, emission point number, and facility identification number of each facility or any other identifying number for mobile sources using discrete emission credits;

(2) the amount of discrete emission credits being used by each facility or mobile source; and

(3) the specific number, name, or other identification of discrete emission credits used for each facility or mobile source.

(i) Public information. All information submitted with notices, reports, and trades regarding the nature, quantity of emissions, and sales price associated with the use or generation of discrete emission credits is public information and may not be submitted as confidential. Any claim of confidentiality for this type of information, or failure to submit all information may result in the rejection of the discrete emission reduction application. All nonconfidential notices and information regarding the generation, use, and availability of discrete emission credits may be obtained from the registry.

(j) Authorization to emit. A discrete emission credit created under this division is a limited authorization to emit the specified pollutants in accordance with the provisions of this section, the FCAA, and the TCAA, as well as regulations promulgated thereunder. A discrete emission credit does not constitute a property right. Nothing in this division should be construed to limit the authority of the commission or the EPA to terminate or limit such authorization.

(k) Program participation. The executive director has the authority to prohibit a company from participating in discrete emission credit trading either as a generator or user, if the executive director determines that the company has violated the requirements of the program or abused the privileges provided by the program.

(l) Compliance burden and enforcement.

(1) The user is responsible for assuring that a sufficient quantity of discrete emission credits are acquired to cover the applicable facility or mobile source's emissions for the entire use period.

(2) The user is in violation of this section if the user does not possess enough discrete emission credits to cover the compliance need for the use period. If the user possesses an insufficient quantity of discrete emission credits to cover its compliance need, the user will be out of compliance for the entire use period. Each day the user is out of compliance may be considered a violation.

(3) Users may not transfer their compliance burden and legal responsibilities to a third party participant. Third party participants may only act in an advisory capacity to the user.

(m) Credit Ownership. The owner of the initial discrete emission credit certificate shall be the owner or operator of the facility or mobile source creating the emission reduction. The executive director may approve a deviation from this subsection considering factors such as, but not limited to:

(1) whether an entity other than the owner or operator of the facility or mobile source incurred the cost of the emission reduction strategy; or

(2) whether the owner or operator of the facility or mobile source lacks the potential to generate one tenth of a ton of credit.

§101.373.Discrete Emission Reduction Credit Generation and Certification.

(a) Methods of generation.

(1) Discrete emission reduction credits (DERC) may be generated using one of the following methods or any other method that is approved by the executive director:

(A) the permanent shutdown of a facility which causes a loss of capability to produce emissions;

(B) the installation and operation of pollution control equipment which reduces emissions below the level required of the facility; or

(C) a change in the manufacturing process which reduces emission below the level required of the facility;

(2) DERCs may not be generated by the following strategies:

(A) temporary shutdown or permanent curtailment of an activity at a facility;

(B) modification or discontinuation of any activity that is otherwise in violation of a federal, state, or local law;

(C) emission reductions required to comply with any provision under Title I of the FCAA regarding tropospheric ozone, or Title IV of the FCAA regarding acid deposition control;

(D) emission reductions of hazardous air pollutants, as defined in the FCAA, §112, from application of a standard promulgated under FCAA, §112;

(E) emission reductions which have occurred as a result of transferring the emissions to another facility at the same site;

(F) emission reductions credited or used under any other emissions trading program;

(G) emission reductions occurring at a facility which received an alternative emission limitation to meet a state reasonably available control technology requirement, except to the extent that the emissions are reduced below the level that would have been required had the alternative emission limitation not been issued;

(H) emission reductions at a site facility with a flexible permit, unless the reductions are made permanent and enforceable or the generator can demonstrate that the emission reductions were not used to satisfy the conditions for the facilities under the flexible permit.

(I) specific emission reductions funded through state or federal programs, unless specifically allowed under that program;

(J) emission reductions from a facility subject to Division 3 of this subchapter (relating to Mass Emissions Cap and Trade Program); or

(K) emission reductions from the shutdown of a facility that was not included in the state implementation plan (SIP).

(b) DERC calculation.

(1) DERCs, except for shutdowns, are calculated according to the following equations.

Figure: 30 TAC §101.373(b)(1)

(2) For shutdown emission reduction strategies, the quantity of emission reduction generated is equivalent to the baseline emissions.

(3) The generation period for a shutdown is five years. Shutdown DERCs must be generated and noticed to the registry on an annual basis.

(c) DERC certification.

(1) A DEC-1 Form, Notice of Generation and Generator Certification of Discrete Emission Credits, must be submitted to the executive director no later than 90 days after the end of the generation period, or no later than 90 days after the completion of the first 12 months of generation. Submission of the DEC-1 Form should continue every 12 months thereafter for each subsequent year of generation.

(2) DERCs shall be quantified in accordance with §101.372(d) of this title (relating to General Provisions). The executive director shall have the authority to inspect and request information to assure that the emission reductions have actually been achieved.

(3) An application for DERCs must include, but is not limited to, a completed DEC-1 Form signed by an authorized representative of the applicant along with the following information for each pollutant reduced at each applicable facility:

(A) the generation period;

(B) a complete description of the generation activity;

(C) for shutdown emission reduction strategies, an explanation as to whether production shifted from the shutdown facility to another facility at the same site;

(D) the amount of discrete emission credits generated;

(E) for volatile organic compound reductions, a list of the specific compounds reduced;

(F) documentation supporting the baseline emission activity, baseline emission rate, emission reduction strategy emission rate, and emission reduction strategy activity;

(G) emissions inventory data from the most recent year of emissions inventory used in the SIP and emissions inventory data for the two consecutive years used to determine the baseline activity for each applicable pollutant and emission point;

(H) the most stringent emission rate for the applicable facility, considering all the local, state, and federal applicable regulatory and statutory requirements;

(I) a complete description of the protocol used to calculate the emission reduction generated; and

(J) the actual calculations performed by the generator to determine the amount of discrete emission credits generated.

§101.374.Mobile Discrete Emission Reduction Credit Generation and Certification.

(a) Method of generation.

(1) Mobile discrete emission reduction credits (MDERC) may be generated by any mobile source emission reduction strategy that creates actual mobile source emission reductions under this rule, and is subject to the approval of the commission.

(2) MDERCs cannot be generated from specific reductions funded through state or federal programs, unless specifically allowed under that program.

(3) MDERCs cannot be generated from a mobile source if the emissions have been transferred from that mobile source to another mobile source.

(b) MDERC calculation. An MDERC may be calculated from the annual difference between the mobile source emissions baseline and the actual emissions level after the MDERC strategy has been put in place. The MDERC must be based on actual in-use emissions of the modified or substitute mobile source. Emission baselines for quantifying MDERCs should include the following information and data as appropriate, but not be limited to:

(1) the emission standard to which the mobile source is subject or emission performance to which the mobile source is certified;

(2) the measured in-use emissions levels per unit of use from all significant mobile source emissions sources;

(3) the number of mobile sources in the participating group;

(4) the type or types of mobile sources by model year; and

(5) the actual activity level, hours of operation or miles traveled by type, and model year.

(c) MDERC certification.

(1) An MDEC-1 Form, Notice of Generation and Generator Certification of Mobile Discrete Emission Credits, must be submitted to the executive director no later than 90 days after the discrete emission reduction strategy activity has been completed, or no later than 90 days after the completion of the first 12 months of generation. Submission of the MDEC-1 Form should continue every 12 months thereafter for each subsequent year of generation.

(2) MDERCs will be determined and certified in accordance with §101.372(d) of this title (relating to General Provisions) using:

(A) EPA methodologies, when available;

(B) actual monitoring results, when available;

(C) calculations using the most current EPA mobile emissions factor model or other model as applicable; or

(D) calculations using creditable emission reduction measurement or estimation methodologies which satisfactorily address the analytical uncertainties of mobile source emissions reduction strategies. The generator must collect relevant data sufficient to characterize the process emissions of the affected pollutant and the process activity level for all representative phases of source operation during the period under which the MDERCs are created or used.

(3) An application for MDERCs must include, but is not limited to, a completed MDEC-1 Form signed by an authorized representative of the applicant along with the following information for each pollutant reduced for each mobile source:

(A) the date of the reduction;

(B) a complete description of the generation activity;

(C) the amount of discrete mobile source emission credits generated;

(D) documentation supporting the mobile source baseline emission activity, mobile source baseline emission rate, mobile source baseline total emissions, and the mobile source strategy;

(E) a complete description of the protocol used to calculate the discrete mobile source emission reduction generated;

(F) the actual calculations performed by the generator to determine the amount of discrete mobile source emission credits generated;

(G) the calculation protocol as approved by the executive director and submitted to EPA; and

(H) a demonstration that the reductions are surplus to all local, state, and federal rules and to emissions modeled in the SIP.

(4) The owner of the initial emission credit certificate shall be the owner of the facility or mobile source creating the emission reduction. The executive director may approve a deviation from this paragraph considering factors such as, but not limited to:

(A) an entity other than the owner of the facility or mobile source incurred the cost of the emission reduction strategy; or

(B) the owner of the facility or mobile source lacked the potential to generate one-tenth of a ton of credit.

§101.376.Discrete Emission Credit Use.

(a) Requirements to use discrete emission credits. Discrete emission credits may be used if the following requirements are met.

(1) The user must have ownership of a sufficient amount of discrete emission credits before the use period for which the specific discrete emission credits are to be used.

(2) The user must hold sufficient discrete emission credits to cover the user's compliance obligation at all times.

(3) The user shall acquire additional discrete emission credits during the use period if it is determined the user does not possess enough discrete emission credits to cover the entire use period. The user must acquire additional credits as allowed under this section prior to the shortfall, or be in violation of this section.

(4) Facility or mobile source operators may acquire and use only discrete emission credits listed on the registry.

(b) Use of discrete emission credits. With the exception of uses prohibited in subsection (c) of this section or precluded by commission order or condition within an authorization under the same commission account number, discrete emission credits may be used to meet or demonstrate compliance with any facility or mobile regulatory requirement including the following:

(1) to exceed any allowable emission level, if the following conditions are met:

(A) in ozone nonattainment areas, permitted facilities may use discrete emission credits to exceed permit allowables by no more than ten tons for nitrogen oxides (NO _x ) or five tons for volatile organic compounds (VOC) in a 12-month period as approved by the executive director. This use is limited to one exceedance, up to 12 months within any 24-month period, per use strategy. The user must demonstrate that there will be no adverse impacts from the use of discrete emission credits at the levels requested; or

(B) at permitted facilities in counties or portions of counties designated as attainment or unclassified, discrete emission credits may be used to exceed permit allowables by values not to exceed the prevention of significant deterioration significance levels as provided in 40 Code of Federal Regulations (CFR) §52.21(b)(23), as approved by the executive director prior to use. This use is limited to one exceedance, up to 12 months within any 24-month period, per use strategy. The user must demonstrate that there will be no adverse impacts from the use of discrete emission credits at the levels requested;

(2) as new source review (NSR) permit offsets if the following requirements are met:

(A) the user must obtain the executive director's approval prior to the use of specific discrete emission credits to cover, at a minimum, one year of operation of the new or modified facility in the NSR permit;

(B) the amount of discrete emission credits needed for NSR offsets equals the quantity of tons needed to achieve the maximum allowable emission level set in the user's NSR permit. The user must also purchase and retire enough discrete emission credits to meet the offset ratio requirement in the user's ozone nonattainment area. The user must purchase and retire either the environmental contribution of 10% or the offset ratio, whichever is higher; and

(C) the NSR permit must meet the following requirements:

(i) the permit must contain an enforceable requirement that the facility obtain at least one additional year of offsets before continuing operation in each subsequent year;

(ii) prior to issuance of the permit the user must identify the discrete emission credits; and

(iii) prior to start of operation the user must submit a completed DEC-2 Form, Notice of Intent to Use Discrete Emission Credits, along with the original certificate;

(3) to comply with the Mass Emissions Cap and Trade Program requirements as provided in §101.356(g) of this title (relating to Allowance Banking and Trading); or

(4) to comply with Chapters 114, 115, and 117 of this title (relating to Control of Air Pollution from Motor Vehicles; Control of Air Pollution from Volatile Organic Compounds; and Control of Air Pollution from Nitrogen Compounds), as allowed.

(c) Discrete emission credit use prohibitions. A discrete emission credit may not be used under this division:

(1) before it has been acquired by the user;

(2) for netting to avoid the applicability of federal and state NSR requirements;

(3) to meet FCAA requirements for:

(A) new source performance standards under FCAA, §111;

(B) lowest achievable emission rate standards under FCAA, §173(a)(2);

(C) best available control technology standards under FCAA, §165(a)(4) or Texas Health and Safety Code, §382.0518(b)(1);

(D) hazardous air pollutants standards under FCAA, §112, including the requirements for maximum achievable control technology;

(E) standards for solid waste combustion under FCAA, §129;

(F) requirements for a vehicle inspection and maintenance program under FCAA, §182(b)(4) or (c)(3);

(G) ozone control standards set under FCAA, §183(e) and (f);

(H) clean-fueled vehicle requirements under FCAA, §246;

(I) motor vehicle emissions standards under FCAA, §202;

(J) standards for non-road vehicles under FCAA, §213;

(K) requirements for reformulated gasoline under FCAA, §211(k); or

(L) requirements for Reid vapor pressure standards under FCAA, §211(h) and (i);

(4) to allow an emissions increase of an air contaminant above a level authorized in a permit or other authorization that exceeds the limitations of §106.261(3) or (4) or §106.262(3) of this title (relating to Facilities (Emission Limitations); and Facilities (Emission and Distance Limitations)) except as approved by the executive director. This paragraph does not apply to limit the use of discrete emission reduction credits (DERC) or mobile discrete emission reduction credits in lieu of allowances under §101.356(h) of this title;

(5) to authorize a facility whose emissions are enforceably limited to below applicable major source threshold levels, as defined in §122.10 of this title (relating to General Definitions), to operate with actual emissions above those levels without triggering applicable requirements that would otherwise be triggered by such major source status; or

(6) to exceed an allowable emission level where the exceedance would cause or contribute to a condition of air pollution as determined by the executive director.

(d) Notice of intent to use.

(1) A completed DEC-2 Form, signed by an authorized representative of the applicant must be submitted to the executive director in accordance with the following requirements.

(A) Discrete emission credits may be used only after the applicant has submitted the notice and received executive director approval.

(B) The application must be submitted at least 45 days prior to the first day of the use period if the discrete emission credits were generated from a facility, 90 days if the discrete emission credits were generated from a mobile source, and every 12 months thereafter for each subsequent year if the use period exceeds 12 months.

(C) A copy of the application must also be sent to the federal land manager 30 days prior to use if the user is located within 100 kilometers of a Class I area, as listed in 40 CFR Part 81 (2001).

(D) The application must include, but is not limited to, the following information for each use:

(i) the applicable state and federal requirements that the discrete emission credits will be used to comply with and the intended use period;

(ii) the amount of discrete emission credits needed;

(iii) the baseline emission rate, activity level, and total emissions for the applicable facility or mobile source;

(iv) the actual emission rate, activity level, and total emissions for the applicable facility or mobile source;

(v) the most stringent emission rate and the most stringent emission level for the applicable facility or mobile source, considering all applicable regulatory requirements;

(vi) a complete description of the protocol, as submitted by the executive director to the EPA for approval, used to calculate the amount of discrete emission credits needed;

(vii) the actual calculations performed by the user to determine the amount discrete emission credits needed;

(viii) the date on which the discrete emission credits were acquired or will be acquired;

(ix) the discrete emission credit generator and the original certificate of the discrete emission credits acquired or to be acquired;

(x) the price of the discrete emission credits acquired or the expected price of the discrete emission credits to be acquired;

(xi) a statement that due diligence was taken to verify that the discrete emission credits were not previously used, the discrete emission credits were not generated as a result of actions prohibited under this regulation, and the discrete emission credits will not be used in a manner prohibited under this regulation; and

(xii) a certification of use, which must contain certification under penalty of law by a responsible official of the user of truth, accuracy, and completeness. This certification must state that based on information and belief formed after reasonable inquiry, the statements and information in the document are true, accurate, and complete.

(2) DERC use calculation.

(A) To calculate the amount of discrete emission credits necessary to comply with §§117.108, 117.138, 117.210, or 117.223 of this title (relating to System Cap; and Source Cap), a user may use the equations listed in those sections, or the following equations.

(i) For the rolling average cap:

Figure: 30 TAC §101.376(d)(2)(A)(i)

(ii) For maximum daily cap:

Figure: 30 TAC §101.376(d)(2)(A)(ii)

(B) The amount of discrete emission credits needed to demonstrate compliance or meet a regulatory requirement is calculated as follows.

Figure: 30 TAC §101.376(d)(2)(B)

(C) The amount of discrete emission credits needed to comply with permit allowables is calculated as follows.

Figure: 30 TAC §101.376(d)(2)(C)

(D) The user must retire 10% more discrete emission credits than are needed, as calculated in this paragraph, to ensure that the facility or mobile source environmental contribution retirement obligation will be met.

(E) If the amount of discrete emission credits needed to meet a regulatory requirement or to demonstrate compliance is greater than ten tons, an additional 5.0% of the discrete emission credits needed, as calculated in this paragraph, must be acquired to ensure that sufficient discrete emission credits are available to the user with an adequate compliance margin.

(3) A user may submit a notice late in the case of an emergency, but the notice must be submitted before the discrete emission credits can be used. The user must include a complete description of the emergency situation in the notice of intent to use. All other notices submitted less than 45 days prior to use, or 90 days prior to use for a mobile source, will be considered late and in violation;

(4) The user is responsible for determining the credits it will purchase and notifying the executive director of the selected generating facility or mobile source in the notice of intent to use. If the generator's credits are rejected or the notice of generation is incomplete, the use of discrete emission credits by the user may be delayed by the executive director. The user cannot use any discrete emission credits that have not been certified by the executive director. The executive director may reject the use of discrete emission credits by a facility or mobile source if the credit and use cannot be demonstrated to meet the requirements of this section.

(5) If the facility is in an area with an ozone season less than 12 months, the user shall calculate the amount of discrete emission credits needed for the ozone season separately from the non-ozone season.

(e) Notice of use.

(1) The user shall calculate:

(A) the amount of discrete emission credits used, including the amount of discrete emission credits retired to cover the environmental contribution, as described in subsection (d)(2)(C) of this section, associated with actual use; and

(B) the amount of discrete emission credits not used, including the amount of excess discrete emission credits that were purchased to cover the environmental contribution, as described in subsection (d)(2)(C) of this section, but not associated with the actual use, and available for future use.

(2) DERC use is calculated by the following equations.

(A) The amount of discrete emission credits used to demonstrate compliance or meet a regulatory requirement is calculated as follows.

Figure: 30 TAC §101.376(e)(2)(A)

(B) The amount of discrete emission credits used to comply with permit allowables is calculated as follows.

Figure: 30 TAC §101.376(e)(2)(B)

(3) A DEC-3 Form, Notice of Use of Discrete Emission Credits, must be submitted to the commission in accordance with the following requirements.

(A) The notice must be submitted within 90 days after the end of the use period;

(B) The notice must be submitted within 90 days of the conclusion of each 12-month use period, if applicable.

(C) The notice is to be used as the mechanism to update or amend the notice of intent to use and must include any information different from that reported in the notice of intent to use, including, but not limited to, the following items:

(i) purchase price of the discrete emission credits obtained prior to the current use period;

(ii) the actual amount of discrete emission credits possessed during the use period;

(iii) the actual emissions during the use period for VOC and NO _x ;

(iv) the actual amount of discrete emission credits used;

(v) the actual environmental contribution; and

(vi) the amount of discrete emission credits available for future use.

(4) Discrete emission credits that are not used during the use period are surplus and remain available for transfer or use by the holder. In addition, any portion of the calculated environmental contribution not attributed to actual use is also available.

(5) The user is in violation of this section if the user submits the report of use later than the allowed 90 days following the conclusion of the use period.

§101.378.Discrete Emission Credit Banking and Trading.

(a) The credit registry. All discrete emission credit generators, users, and holders will be included in the commission's credit registry.

(1) All notices submitted by a generator, holder, or user will be reviewed for credibility; and when deemed certified, posted to the credit registry.

(2) The credit registry will assign a unique number to each certificate which will include the amount of emission reductions generated to the tenth of a ton.

(3) The credit registry will maintain a listing of all credits available or used for each ozone nonattainment area. One combined listing for all the counties or portions of counties designated as attainment or unclassified will be provided by the credit registry.

(4) The registry shall not contain proprietary information.

(b) Life of a discrete emission credit. A discrete emission credit is available for use after the DEC-1 Form, Notice of Generation and Generator Certification of Discrete Emission Credits, has been received, deemed creditable by the executive director, and deposited in the commission credit registry in accordance with subsection (a) of this section, and may be used anytime thereafter. All credits are deposited in the credit registry and reported as available credits until they are used or withdrawn.

(c) Trading. Discrete emission credits are freely transferable in whole or in part, and may be traded or sold to a new owner at any time after certification.

(1) Prior to the transfer, the executive director must be notified by means of a completed DEC-4 Form, Application for Transfer of Discrete Emission Credits.

(2) The executive director will issue a letter to the discrete emission credit purchaser reflecting the discrete emission credits purchased by the new owner, and a letter to the discrete emission credit seller showing any remaining discrete emission credits available to the original owner. Discrete emission credits are considered transferred only after the executive director grants approval of the transaction.

(3) The trading of discrete emission credits may be discontinued by the executive director in whole or in part and in any manner, with commission approval, as a remedy for problems resulting from trading in a localized area of concern.

§101.379.Program Audits and Reports.

(a) No later than three years after the effective date of this section, and every three years thereafter, the executive director will audit this program.

(1) The audit will evaluate the timing of credit generation and use, the impact of the program on the state's attainment demonstration and the emissions of hazardous air pollutants, the availability and cost of credits, compliance by the participants, and any other elements the executive director may choose to include.

(2) The executive director will recommend measures to remedy any problems identified in the audit. The trading of discrete emission credits may be discontinued by the executive director in part or in whole and in any manner, with commission approval, as a remedy for problems identified in the program audit.

(3) The audit data and results will be completed and submitted to the EPA and made available for public inspection within six months after the audit begins.

(b) No later than February 1 of each calendar year, the executive director shall develop and make available to the general public and the EPA a report that includes:

(1) the amount of each pollutant emission credits generated under this division;

(2) the amount of each pollutant emission credits used under this division; and

(3) a summary of all trades completed under this division.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 17, 2002.

TRD-200208333

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 17, 2003

Proposal publication date: June 21, 2002

For further information, please call: (512) 239-0348

30 TAC §§101.372 - 101.374

STATUTORY AUTHORITY

These repealed sections are adopted under TWC, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, §382.017, concerning Rules, which authorizes the commission to adopt rules consistent with the policy and purposes of the TCAA. The repealed sections are also adopted under THSC, §382.002, concerning Policy and Purpose, which establishes the commission's purpose to safeguard the state's air resources, consistent with the protection of public health, general welfare, and physical property; §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to develop a general, comprehensive plan for control of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require a person whose activities cause emissions of air contaminants to submit information to enable the commission to develop an emissions inventory; §382.016, concerning Monitoring Requirements, Examination of Records, which authorizes the commission to prescribe reasonable requirements for the measuring and monitoring of emissions of air contaminants. These repealed sections are also adopted under 42 USC, §7410(a)(2)(A), which requires SIPs to include enforceable emission limitations and other control measures or techniques, including economic incentives such as fees, marketable permits, and auction of emission rights.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 17, 2002.

TRD-200208334

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 17, 2003

Proposal publication date: June 21, 2002

For further information, please call: (512) 239-0348

Figure: 30 TAC Chapter 115 - Preamble

Much analysis needs to be conducted between now and the MCR, particularly with regard to the contribution of other VOCs to ozone formation in HGA nonattainment area, in order to develop the most cost-effective strategy to attain the standard. This effort will consist of continued evaluation of data already collected, the collection of additional ambient data through an expanded auto gas chromatographs (GC) network, and additional inventory analysis as well as additional modeling analysis. As a full analysis of what is ultimately necessary to fully demonstrate attainment is conducted at the MCR, the commission will be evaluating a number of issues that may change the HRVOC rules, such as: which, if any, additional chemicals need to be addressed, and the sources of these chemicals; what is the appropriate geographic scope for the regulations; what are appropriate averaging times for the chemicals of concern; and what, if any, changes need to be made to the allocation process. By establishing a compliance date of April 1, 2006, approximately 24 months after the conclusion of the MCR process, the commission believes it will have ample time to make necessary adjustments and still allow industry adequate time to fully comply.

The commission has withdrawn the proposed general VOC monitoring rules in Subchapter B, Divisions 7 and 8. In lieu of requiring this monitoring of all VOCs from individual flares, cooling towers, and process vents to obtain emissions data for use in SIP planning, the commission is relying on data from not only the commission's monitoring network, but also data from additional ambient monitors that will be strategically located in HGA. This monitoring is expected to not only be a more efficient use of resources for this data gathering, but will also provide information more quickly. As described more fully in the narrative to the SIP revision and TSD that accompany these rule amendments, the commission is committed to developing the best science possible to understand the causes of high ozone in the HGA. For the MCR, the commission plans to perform an in-depth analysis of the contributions of the less-reactive compounds and to perform top-down analyses similar to those used for the HRVOCs. If warranted, appropriate adjustment factors will be developed for less-reactive VOCs. As explained more fully in the SIP and TSD, the current modeling analysis indicates that emission reductions in the HRVOC alone can compensate for the change of industrial NO _x controls to 80% reductions, but additional controls on VOC sources are likely to be necessary to reach attainment. The commission will continue to study VOC data available now and in upcoming years to determine whether additional compounds should be added. To accomplish this task, the commission needs the support of and expects owners and operators of facilities in HGA which emit VOCs to participate in the ambient monitoring efforts which are scheduled to begin no later than June 1, 2003. If the ambient monitoring network is not fully and timely developed and operated such that the commission has received sufficient data for MCR, the commission may reconsider site-specific monitoring controls of VOC sources.

Duke requested that all chemical species of HRVOC, e.g., the isomers of xylene (meta, ortho, and para), be listed in the definition so that the regulated community and regional inspectors will not have to make assumptions about which chemical species are included in the definition.

The adopted definition of HRVOC only includes 1,3-butadiene, all butenes (butylenes), ethylene, and propylene in Harris County, and ethylene and propylene in Brazoria, Chambers, Fort Bend, Galveston, Liberty, Montgomery, and Waller Counties. The commission revised the definition of HRVOC to clarify that butenes includes all isomers of butene (i.e., alpha-butylene (ethylethylene) and beta-butylene (dimethylethylene, including both cis- and trans- isomers)).

TxOGA stated that the definition of HRVOC would be much clearer if it specifically indicated a distinction between the term "VOC" and the term "highly-reactive" VOC. OxyChem and TxOGA expressed similar concerns about the distinction between HRVOC and VOC in the rules.

The commission agrees and has revised the definition of "highly-reactive volatile organic compound" such that this term is abbreviated as HRVOC. Where the commission intends a requirement to apply to all VOC, it has used the term "VOC."

Definition of "low-density polyethylene"

Dow recommended that a definition of "low density polyethylene" based upon the definition in 40 CFR 60, Subpart DDD be added to clarify §115.722. The definition in 40 CFR 60 Subpart DDD is as follows: "Low-density polyethylene (LDPE) means a thermoplastic polymer or copolymer comprised of at least 50 percent ethylene by weight and having a density of 0.940 g/cm ³ {grams per cubic centimeter} or less."

The commission agrees and has added the suggested definition of "low density polyethylene." Subsequent definitions were renumbered to accommodate the new definition.

Definition of "pressure relief valve"

TCC supported the proposed definition of "pressure relief valve."

The commission appreciates the support.

Definition of "process drain"

TCC commented on the proposed definition of "process drain" and stated that this definition might more appropriately be located in §115.140, concerning Industrial Wastewater Definitions. TCC stated that this would clarify that the process drains of concern are those that are already subject to the underlying provisions of affected VOC wastewater streams as defined in existing Subchapter B, Division 4.

The commission disagrees. Numerous process drains are not subject to Subchapter B, Division 4, yet the process drains could emit HRVOCs uncontrolled under TCC's proposal. Because the definition of "process drain" is used in multiple divisions within Chapter 115, it is most appropriately located in §115.10.

Definition of "process unit"

In order to clarify the meaning of the term "process unit" which is used in Subchapters B, D, and H, the commission has added a definition to §115.10 which is consistent with the one in the EPA guidance document "Protocol for Equipment Leak Emission Estimates," Chapter 4, Mass Emission Sampling (EPA-453/R-95-017, November 1995). This definition is "the smallest set of process equipment that can operate independently and includes all operations necessary to achieve its process objective." In addition, the commission replaced the term "unit" with the term "process unit" where appropriate in Subchapters B, D, and H.

Definitions of "semi-continuous" and "batch"

Dow stated that the definition of "semi-continuous" in §115.160(13) should not be deleted and that additional text should be added to the "batch" definition stating that semi-continuous vent streams are not vent streams subject to Subchapter B, Division 6. Dow disagreed that semi-continuous vents are batch vents and stated that semi-continuous vents are continuous vents from steady-state operations of less than 8,760 hours per year. Dow stated that a batch process is not characterized by steady-state conditions, while a semi-continuous process is steady-state if viewed over the entire process. Dow also stated that in a batch process, reactants are not added and products are not removed simultaneously, while a semi-continuous distillation process is characterized by the simultaneous adding of reactants and removal of product. Finally, Dow stated that the definition of "batch" in §115.160(4) should be revised to specify that the semi-continuous vents are not subject to Subchapter B, Division 6 through the addition of the following sentence: "Semi-continuous vents are not batch vents."

The definition of "batch" specifies noncontinuous and not steady-state, and the definition of "semi-continuous" is steady-state for finite durations. Although the term "semi-continuous" is defined in §115.160, this term is never used in any other portions of the batch process rules of Subchapter B, Division 6, including §115.161.

The commission reviewed the EPA's Control Techniques Guideline (CTG) guidance documents associated with the development of the batch process rules of Subchapter B, Division 6. The CTGs are issued by the EPA for the purpose of assisting states in developing reasonably available control technology (RACT) controls for sources of VOC emissions. Each CTG contains specific source category requirements that the EPA recommends that the states adopt. One specific source category EPA studied was batch processes. However, instead of issuing a CTG for batch processes, the EPA issued a guidance document known as an Alternative Control Techniques (ACT) document. The commission reviewed the EPA's "Control of Volatile Organic Compound Emissions from Batch Processes - Alternative Control Techniques Information Document" (Batch Processes ACT), since the EPA provided the Batch Processes ACT to specify control techniques for states to use in developing RACT for batch processes.

The EPA specified the following in the Batch Processes ACT: "Note that there are two CTGs, the Air Oxidation CTG and the Reactor Processes and Distillation Operations CTG, that cover synthetic organic chemical emissions from continuous processes. The CTGs also exempt batch or semi continuous processes. The information in this document applies to the processes that are exempted because they are not continuous. This includes semi continuous processes ." (emphasis added.)

In this particular statement, EPA clarified that previous EPA guidance documents for reactor processes and distillation operations, which cover the chemical industry, cover continuous processes. The CTGs for continuous processes specifically exempted batch and semi-continuous processes. Based on this, the Batch Processes ACT includes control techniques for noncontinuous processes, including semi-continuous processes and it can be interpreted that EPA may have intended for semi-continuous processes to be regulated under the batch process rule. However, EPA did not structure the ACT in a manner which directly included all semi-continuous processes. As a result, the commission's adopted rule (which is based on EPA's ACT) only discusses batch operations, and the term "semi-continuous" has no functional purpose in the context of applicability, based on a direct reading of the rule language.

In conclusion, although the term "semi-continuous" is defined under §115.160, this term is never used in the associated batch process rules and has no particular significance in terms of applicability. Therefore, if a semi-continuous process meets the §115.160 definitions of "batch" and "batch process," it is subject to the batch process rules contained in Subchapter B, Division 6. A process which does not meet the §115.160 definitions of "batch" and "batch process" is regulated under the vent gas control rules in Subchapter B, Division 2. Therefore, the commission has deleted the definition of "semi-continuous" as proposed and has not revised the definition of "batch."

Definition of "shutdown or turnaround" and "startup"

Sierra-Houston and Sierra-Lone Star questioned how the commission will mesh the definitions of "shutdown or turnaround" and "startup" with the upset/maintenance (now known as the emissions events) requirements in Chapter 101.

The definitions of "shutdown or turnaround" and "startup" in §115.10 both begin with the phrase "for the purposes of this chapter" to make it clear that these §115.10 definitions only apply to the Chapter 115 requirements. Therefore, there is no conflict with the requirements in Chapter 101.

TxOGA stated that the definition of "shutdown or turnaround" should contain an exclusion for a complete or partial shutdown of units due to emergency conditions, such as threat of hurricane. TxOGA stated that when operations shut down for this purpose, it is impractical to schedule equipment leak monitoring and repair into these types of non-routine, emergency events, which may impact an entire plant site. TxOGA suggested adding a third clause to subparagraph (A) to read: "(iii) stop production from a unit or part of a unit due to emergency situations, such as threat of hurricane."

The commission declines to make this change. As stated earlier in this preamble, the definition of "shutdown or turnaround" is applicable only to Chapter 115 requirements. The definition specifically acknowledges three criteria for the work practice: technical feasibility, safety constraints, and that the repairs can be accomplished. Those criteria can be applied when a decision is necessary regarding whether to shutdown due to emergency situations, and this additional language is not necessary for the exclusions in subparagraph (A).

Dow and DuPont stated that the definition of "shutdown or turnaround" should clarify that operation of a unit or part of a unit in recycle mode (i.e., process material is circulated, but production does not occur) for any period of time does not constitute a shutdown or turnaround. Dow and DuPont stated that in certain circumstances, it is necessary to operate in a recycle mode for periods of time greater than 24 hours and that it is not possible to repair/replace leaking components or to install equipment upgrades during these operating times. As examples, Dow cited hydrate or freezing problems, severe upsets, temporary poisoning, or an uncontrolled exothermic reaction, and temporary production distribution or pipeline problems. Dow and DuPont also stated that it is possible to shut down a portion of the plant while other portions continue to run, and that it is often better from an environmental standpoint to remain in a recycle mode than to shut the entire process down because a complete shutdown would likely generate significant flaring as the system is deinventoried.

The commission agrees and has revised the definition of "shutdown or turnaround" accordingly.

TxOGA stated that the definition of "startup" needs to include the time period for attainment of normal operations and that the trigger for fugitive monitoring, for example, should not include the period of time that the unit is being "lined-out" after a turnaround. TxOGA stated that it would be dangerous to have monitoring personnel in a process unit or around equipment that is undergoing startup and activities associated with obtaining equilibrium in the operation, and expressed the belief that it is inappropriate to start any equipment leak monitoring requirements before this period is fully complete. TxOGA suggested adding the following sentence to the end of the definition: "The startup period includes the period of time that the unit or equipment is being "lined-out" for attainment of normal operations." TCC expressed similar concerns and stated that the commission should recognize that "startup" occurs after a "shutdown" and is not necessarily linked to intermediate operations such as loading.

This issue is addressed later in this preamble in the discussion concerning "monitoring of repaired components after startup."

TCC stated that the definition of "startup" should not include the phrase "or waste management." TCC stated that petrochemical plants are chemical manufacturers and do not typically startup units solely for the purposes of waste management.

The commission disagrees. In some cases, a unit may be operating for purposes of waste management. A component in contact with a VOC or HRVOC has the potential for emissions from a leak, regardless of the specific purpose (production or waste management) that the unit is operating.

Definition of "vent gas"

Valero stated that there is currently no definition of "vent gas" in Chapter 101 or Chapter 115. Valero commented that it is common practice in the refining industry to route offgas streams with a high British thermal unit (Btu) content to a fuel gas system. Valero expressed concern that "vent gas" with no definition could be construed to include these streams and subject combustion sources, such as heaters and boilers, to testing and monitoring requirements. Valero recommended that the commission specifically exclude gaseous streams routed to a fuel gas system from the definition of "vent gas" to be consistent with federal MACT standards, such as the 40 CFR §63.101 definition of "process vent" and 40 CFR §63.641 definition of "miscellaneous process vent."

The term "process vent" is not defined, but the terms "process" and "vent" are defined in 101.1. The definition of "process" establishes what constitutes a process. Any vent associated with a process is then considered a "process vent." In the situation cited by the commenter, the vent gas stream from a process vent is routed to a boiler or heater, which functions as a VOC control device in addition to functioning as a boiler or process heater. Such dual-function boilers and heaters are subject to the Chapter 115 requirements specifying vent gas control efficiency, monitoring, recordkeeping, etc. The commenters's suggested change would not ensure that the required control efficiency is met. Therefore, the commission has made no changes in response to the comment. Additional information about the commission's interpretation of vent gas rules is available on the commission's website at http://www.tnrcc.state.tx.us/permitting/airperm/opd/rimhmpg.htm .

TxOGA stated that the vent gas definitions in §115.120 should also apply to Subchapter H, Division 1, and recommended duplication of §115.120 in §115.720.

The definitions in §115.120 are only used in Subchapter B, Division 2, and not in Subchapter H, Division 1. Consequently, there is no need to relocate or copy these definitions to §115.10 or §115.720.

APPLICABILITY

Vent Gas

§115.720

Duke stated that unlike §115.121(a), §115.720 does not specify that the regulation is applicable to vent gas streams from process vents, and requested that §115.720 be revised to clarify the applicability.

The commission has revised §115.720(a) to clarify the applicability and therefore does not believe that the suggested reference to process vents is necessary.

DuPont, ExxonMobil, TCC, and TxOGA stated that the commission must make clear in the rule language that the HRVOC controls only apply to uncontrolled HRVOC vents that release to the atmosphere. ExxonMobil and TxOGA expressed a concern that the proposal as written could be interpreted as applying to every process, relief, and safety vent that is already controlled and vented to an emission control device. TxOGA stated that the requirements for controlled vents should be clarified to be only §115.722(d) and (e), as appropriate, and that the word "uncontrolled" needs to be added to §115.720 such that it reads "Any uncontrolled vent gas stream. "

The commission disagrees that §115.720 should include the word "uncontrolled." Such a narrowing of the applicability would mean that a vent gas stream that was directed to a control device having minimal control efficiency would be exempt from the requirements of Subchapter H, Division 1, thereby resulting in no emission reductions. Regarding the concern that the rule could be interpreted as applying to every process, relief, and safety vent that is already controlled and vented to an emission control device, the commission notes that it is necessary for these emissions to be included in the HRVOC emissions cap in order to achieve the reductions upon which the revisions to the Chapter 117 NO _x ESADs, published elsewhere in this issue of the Texas Register , are based. Regarding pressure relief valves which are not vented to a control device, the commission notes that this concern was addressed in previous rulemaking. Specifically, in the June 30, 1992 issue of the Texas Register (17 TexReg 4685), the Texas Air Control Board (TACB, one of the commission's predecessor agencies) stated that "the vent gas rule addresses only normal process emissions. The staff has previously interpreted that upset conditions (such as the venting of safety relief valves) and maintenance were to be handled by TACB General Rules, §101.6 and §101.7, and not by Chapter 115, unless otherwise specifically stated." While 30 TAC §101.6 and §101.7 were recently revised and relocated to 30 TAC §101.201 and §101.211, respectively, and the terms "upset" and "maintenance, startup, or shutdown" were replaced by the terms "emissions event" and "scheduled maintenance, startup, or shutdown activity," respectively, the commission reaffirms that the intent expressed in the June 30, 1992 issue of the Texas Register remains valid for pressure relief valves which are not vented to a control device.

ExxonMobil and TxOGA stated that §115.720 lacks clarity and creates parallel requirements, and that the language should be specific and include the requirements for a covered HRVOC vent or a covered VOC vent. ExxonMobil and TxOGA commented that a single vent being subject to both requirements is particularly confusing as the proposed rule language switches back and forth between the terms VOC and HRVOC.

In order to clarify the requirements, the commission has used the term "HRVOC" when the requirements are intended to only refer to those compounds included in the definition of "highly-reactive volatile organic compound." Where the commission intends a requirement to apply to all VOC, it has used the term "VOC."

Flares

§115.740(a)

Air Products and DuPont commented that the phrase "or has the potential to emit" should be deleted from §115.740(a), relating to Applicability, HRVOC Flares, stating that it unnecessarily broadens the applicability for flares, particularly those flares that are limited to emergency use. DuPont commented that emergency flares are excluded from 40 CFR §60.18. TCC commented that the phrase "in addition to the applicable requirements . . ." is unnecessary.

As noted earlier in this preamble, the commission has relocated the proposed §115.740(a) to §115.720(a). One of the purposes of the rule is to monitor HRVOC emissions during emergencies. The phrase "or has the potential to emit" is necessary, since otherwise applicability of the rule to a given flare would depend solely on the flare's emissions at any particular point in time. Such a rule would be unworkable, since the monitoring requirements would be applicable only when HRVOC emissions were present; however, monitoring would be necessary to establish the nature and quantity of these emissions in the first place. The fact that emergency flares are excluded from 40 CFR §60.18 does not address the necessity to control HRVOC emissions that contribute to short-term ozone exceedances, something that 40 CFR §60.18 was not designed to do. The phrase "in addition to the applicable requirements . . ." has been replaced by a reference to Subchapter B, Divisions 2 and 6 (Vent Gas Control; and Batch Processes) and Subchapter D, Division 1 ( Process Unit Turnaround and Vacuum-Producing Systems in Petroleum Refineries). This is included to ensure that §115.127(a)(6) does not provide an inadvertent loophole and as a courtesy to the reader.

Cooling Towers

§117.760(a)

TCC commented that a cooling tower heat exchange system (CTHES) should not be subject to more than one division in Chapter 115, since this would cause confusion and misunderstanding from potentially conflicting and duplicative requirements. Accordingly, TCC recommended that the last phrase in §115.760(a), "in addition to the applicable requirements of any other division in this chapter," be deleted. TCC commented that text should be included in Subchapter H, Division 3 (relating to HRVOC CTHES) stating that if a CTHES is subject to the requirements of this division, then the CTHES is not subject to the requirements of Subchapter B, Division 8 (relating to general VOC CTHES). TCC noted that its comments regarding Subchapter B, Division 8, relating to CTHES only in VOC service are also intended to apply to Division 3, relating to CTHES in HRVOC service.

The commission has withdrawn the proposed general VOC rules for cooling towers in Subchapter B, Division 8. Therefore, the comments pertaining to this withdrawn division are moot. With regard to the phrase "in addition to the applicable requirements of any other division in this chapter" in §115.760(a), the rule language has been changed to "in addition to the applicable requirements of any other division in this chapter or any other subchapter in this chapter." With this language, the commission intends to clarify that applicability under Chapter 115 is not necessarily limited to the division in question alone.

TCC and TXOGA commented that for readability the definitions in §115.760 should be moved to §115.10, which contains definitions for terms used in Chapter 115. TCC commented that the language in §115.760 concerning fin fan coolers, etc. is more appropriate for §115.768.

The commission believes that locating the definition for "cooling tower heat exchange system" in the rule to which the definition applies is useful, and therefore makes no change to the rule. Similarly, listing in this section certain types of cooling tower heat exchange systems and other equipment to which the rule does not apply helps the reader in quickly establishing whether the rule applies.

Fugitive Emissions

TCC commented on proposed §115.352(10), which specifies that any petroleum refinery; synthetic organic chemical, polymer, resin, or methyl tert-butyl ether manufacturing process; or natural gas/gasoline processing operation in HGA in which an HRVOC is a raw material, intermediate, final product, or in a waste stream, is subject to the requirements of the new Subchapter H in addition to the applicable requirements of Division 3 of Subchapter D. TCC suggested that the reference to "waste stream" be deleted.

The commission disagrees. In some cases, a unit may be operating for purposes of waste management. A component in contact with a VOC or HRVOC has the potential for emissions from a leak, regardless of the specific purpose (production or waste management) that the unit is operating.

§115.780

TxOGA stated that §115.780 should be revised to clarify that the HRVOC fugitive monitoring requirements apply to a unit or process within a petroleum refinery; synthetic organic chemical, polymer, resin, or methyl tert-butyl ether manufacturing process; or natural gas/gasoline processing operation. TxOGA stated that as written, Subchapter H, Division 4 becomes applicable to the entire site as opposed to individual process units.

The commission agrees and has revised §115.780 accordingly.

§115.781(a)

EnRUD commented on §115.781(a) and suggested that "of another unit" be changed to "within the unit."

The commission agrees that the reference should be to components which are not subject to this Subchapter H, Division 4, and has revised §115.781(a) accordingly.

TxOGA commented on §115.781(a) and stated that the requirement to identify components of each unit should apply only to HRVOC components and suggested the addition of the phrase "in HRVOC service."

The commission agrees and has revised §115.781(a) accordingly.

Dow commented on §115.781(a) and stated that individually tagging each component subject to or exempt from the rule should not be a requirement. Dow suggested that the component identification requirement in §115.781(a) is really a recordkeeping requirement and should be relocated to §115.786 or somehow combined with §115.786(e). Dow stated that if the audit provisions in §115.788 are retained, then §115.788(a)(1)(A) and (B) and §115.788(d) should be made consistent with the identification methods allowed in §115.781(a). Finally, Dow stated that lines and equipment that are clearly not in VOC service (e.g., steam and nitrogen lines) should not need to be individually identified.

It is unclear how components could be accurately identified on a unit-wide basis, as opposed to a component by component basis. If each component is not identified with a unique component identification code, it would be difficult to identify which specific components had been monitored on a particular date, which components were not monitored, which components were leaking, etc. Therefore, the commission believes that for the rule to be enforceable, each component ideally would be identified with a unique component identification code. However, the commission also recognizes that connectors present a unique difficulty in labeling due to the sheer number of connectors, which is estimated to be three to four times the number of valves. Therefore, the commission has revised §115.781(a) accordingly to specify that each component other than connectors must be labeled with a unique component identification code in order to improve the enforceability of the rule, with connectors not required to be individually labeled if they are clearly identified individually in the master components log. This will also ensure consistency with §115.788(a)(1)(A) and (B) and §115.788(d). Regarding components in non-VOC service, such as steam, nitrogen, and water lines, the commission revised §115.781(a) to specify that the requirements apply to the components in HRVOC service.

§115.781(b)(2) and (3)

Dow, ExxonMobil, Sierra-Houston, Sierra-Lone Star, TCC, and TxOGA commented on §115.781(b)(2), which prohibits leak-skip under §115.354(7) and (8). Sierra-Houston and Sierra-Lone Star supported the monitoring of each component and not allowing leak-skip periods. ExxonMobil and TxOGA stated that a leak-skip program is more important if the number of components to be monitored increases significantly. TxOGA asserted that most of the components being added to the monitoring program are those which are less likely to leak (e.g., connectors), and stated that the large number of components being added to the monitoring program would make incorporation of a skip-period monitoring program a logical choice for the management of resources for such a labor-intensive program. Dow and TCC expressed similar concerns. Dow, DuPont, ExxonMobil, Phillips, TCC, and TxOGA commented on the list of components in §115.781(b)(3). DuPont asserted that the list of components is unreasonable and extremely expensive for a complex manufacturing site to implement and maintain. Dow, TCC, and TxOGA expressed similar concerns. Phillips stated that component types should be added only after evaluation that emission reductions are commensurate with the resource requirements. BP stated that it conducted a survey of four process units and found a leak rate of less than 1.0% for the flanges, connectors, heat exchanger heads, and pressure gauges. TCC stated that the components listed in §115.781(b)(3) have not been shown to leak HRVOCs, while Dow stated that they "contribute only a very small portion of overall emissions from a process unit." DuPont stated that it estimates 2.3 flanges (connectors) for every valve, and that plugs, caps, and blind flanges serve the purpose to eliminate fugitive emissions and should not require additional monitoring (per the HON rule). DuPont stated that segregated stormwater drains would be unlikely sources of fugitive emissions. DuPont stated that the commission should narrow down the list and include only those components that have truly demonstrated significant and frequent leakage. ExxonMobil and TxOGA stated that the HON provisions should be used to establish the list of components to be monitored, and that HRVOCs and VOCs should not be subject to more stringent monitoring provisions than those for air toxics. Dow and TCC stated that as an alternative, the commission should consider monitoring of these components during 2003 and based on the findings, reduce or allow leak-skip monitoring of these components in future periods. Dow and TCC stated that including the existing leak-skip provisions should be a consideration as well. TCC suggested that the word "unsegregated" be added before "stormwater drains" to clarify that dedicated stormwater conveyances do not require monitoring. Dow suggested consideration of four alternatives for these additional types of components: 1) monitoring within five calendar days if a potential leak is found by audible, visual, or olfactory (AVO), or any other detection method; 2) leak-skip monitoring; 3) sweep monitoring (in which monitoring personnel start monitoring at one end of a plant and then monitor all components within an area without checking for component identifications); and 4) statistical sampling (using a graph similar to the graph in §115.788(a)(2)(B)). Dow also suggested establishing alternate monitoring frequencies for connectors similar to the alternative frequencies allows in the Consolidated Federal Air Rule. Dow further suggested that instead of monitoring sampling connection systems on a quarterly basis, the commission should provide the option to comply with the sampling connection system requirements in HON Subpart H, 40 CFR §63.166.

The commission disagrees with TCC's claim that non-traditional components have not been shown to leak. In Volume 2A: Comments on Process Vents, Storage Vessels, Transfer Racks and Equipment Leaks , section 5.1.13, §63.174: Connectors in Gas/Vapor Service and in Light Liquid Service , of EPA's background information document for the HON, "Hazardous Air Pollutant Emissions from Process Units in the Synthetic Organic Chemical Manufacturing Industry -- Background Information for Promulgated Standards" (January 1994), EPA responded to a similar comment concerning connectors as follows: "The EPA does not agree with the commenter's (A-90-19: IV-D-68) view that a LDAR program for connectors is inappropriate and is not a cost-effective means of emissions reduction. The commenter (A-90-19: IV-D-68) did not provide the basis for the emission estimates used in concluding that the LDAR program for connectors was not cost-effective. The EPA believes that it is important to include process equipment connectors in the LDAR program because emissions from these connectors can be significant. The revised SOCMI average factors show that the factor for connectors is one-half to one-third of the factors for valves in light liquid and gas service. Because of the large number of connectors in process units, connector emissions could easily exceed emissions from valves and pumps. In fact for the number of components reported by the commenter (A-90-19: IV-D-68), the revised SOCMI average factors indicate that connectors contribute roughly 55 percent of total emissions and valves contribute 40 percent. While the average factors may not be indicative of emission rates for the commenter's (A-90-19: IV-D-68) units, they do indicate that on a national basis it is important to consider control measures for connectors." The commission likewise concluded that an LDAR program for connectors in HRVOC service is appropriate. Concerning other non-traditional components, such as heat exchanger heads and sight glasses, BP did not submit detailed results of its survey. These non-traditional components have been found to leak, yet in most cases are not currently required to be monitored at all. As described elsewhere in this preamble, reductions of HRVOC emissions from these sources are necessary to allow continued progress toward attainment of the ozone NAAQS.

Concerning stormwater drains, the commission agrees that segregated stormwater drains would be unlikely sources of fugitive emissions. The situation in which the commission found significant fugitive emissions involved a company which knowingly allowed contaminated condensate to empty into the stormwater drain, resulting in significant emissions where none would normally be expected. Because enforcement action for the improper discharge of contaminated condensate is the appropriate course of action in this and similar situations, the commission has deleted the reference to stormwater drains in §115.781(b)(3).

The commission has considered the comments requesting the availability of a leak-skip option and has concluded that this is appropriate for connectors. The committee which developed the HON generally agreed that connectors could be a significant source of emissions at a well-controlled plant and that emissions could be reduced. In the development of the HON provisions, the committee considered LDAR data and the contribution of connector emissions to total emissions for several process units. These data showed a range of connector leak frequencies at different leak definitions (e.g., 3.0% at 10,000 ppmv to less than 2.0% at 250 ppmv) and showed that connectors could be a significant source of the total emissions. Some committee members believed the relatively high leak rates observed at some process units were a result of infrequent or no inspections and maintenance. The committee agreed that connector leaks should be controlled and established a connector LDAR program to ensure that low leak rates are attained.

The commission likewise believes that LDAR can reduce connector leak frequencies and that less frequent monitoring for connectors may be necessary than that for pumps, compressors, and valves because connectors have no moving parts. Once repaired, connectors would be expected to remain leak-free for extended periods. A number of actions can be taken to reduce or eliminate leaks. In most cases, tightening the flange bolts on flanged connectors is expected to eliminate the leak. In other cases, it may be necessary to replace the gasket or to correct faulty alignment of surfaces, although these latter cases are expected to be relatively infrequent. It is also possible to undertake "extraordinary efforts" (e.g., sealant injection) to repair leaks on connectors. Because bolted manways, heat exchanger heads, hatches, and sump covers have no moving parts, they are analogous to connectors (and in some cases even could be considered a subset of connectors). Therefore, the commission believes it is appropriate that these components be included in a leak-skip option for connectors. In conclusion, the commission has added the availability of a leak-skip option for connectors, bolted manways, heat exchanger heads, hatches, and sump covers, as new §115.781(f) which is similar to the skip-period provisions for connectors in the HON.

As in the HON, a base performance level of 0.5% leaking connectors was established. Process units that have 0.5%, or greater, leaking connectors, bolted manways, heat exchanger heads, hatches, and sump covers are required to implement an annual LDAR program for these components. Process units that have less than 0.5% leaking connectors, bolted manways, heat exchanger heads, hatches, and sump covers are allowed to monitor these components in a biennial or quadrennial program. However, if the leak rate exceeds 0.5%, but is no greater than 1.0%, then annual monitoring is specified. If the leak rate exceeds 1.0%, but is no greater than 2.0%, then semi-annual monitoring is specified. Finally, if the leak rate exceeds 2.0%, then quarterly monitoring is specified.

For valves in a leak-skip program, it is likely that leaks that occur will not be detected and will accumulate with time. The fact that valves have moving parts makes them much more susceptible to leaks which would not be detected under a leak-skip program. Therefore, the commission is not allowing leak-skip monitoring of valves.

For components such as pump seals and compressor seals, leak-skip monitoring is not allowed because there are not enough of these components present for the statistics of skip monitoring to apply. In addition, leaks from these components are not particularly predictable and might operate with low leak rates for long periods of time and then fail instantaneously with sudden increases in leak rates. Consequently, no matter how many consecutive successful inspections are performed, there is little assurance that a low leak rate would continue if skipping were allowed.

Concerning Dow's suggestion concerning sampling connection systems, the commission agrees that sampling connection systems which are in compliance with §63.166(a) and (b) can be exempted from the LDAR program because §63.166(b) requires control of emissions from sampling connection systems. This exemption has been added as §115.787(c)(6).

Dow, ExxonMobil, and TxOGA stated that §115.781(b)(3) should reference HRVOC service rather than VOC service.

The commission agrees and has revised §115.781(b)(3) accordingly. However, the term "VOC water separator" has been retained because it is the defined term used to describe this equipment.

MISCELLANEOUS RULE LANGUAGE COMMENTS

The commission made several minor changes in wording for which no comments were received. Specifically, the commission added section symbols to §§115.126(1)(A)(iv) and (B), 115.144(3)(E), and 115.166(1)(B) where these symbols were missing. The commission also replaced the outdated term "exemption from permitting" with the correct term "permit by rule" in §115.142(4)(A) and §115.160(2). In addition, the commission revised §115.357(1) by adding language to clarify which specific portions of §115.354 a component would be exempt from if the conditions of the exemption in §115.357(1) are met. The text added to make this clarification is "instrument monitoring (with a hydrocarbon gas analyzer)," and the specific paragraphs in §115.354 are "115.354(1) and (2)." The commission is also replacing the wording "within this same section" with "in §115.354(1) and (2) of this title" to clarify which specific inspection schedules are being referenced. The commission is making the changes to §115.357(1) to clarify that the remaining requirements of §115.354 apply to components which contact a process fluid containing VOC having a true vapor pressure equal to or less than 0.044 pounds per square inch absolute (psia) at 68 degrees Fahrenheit (20 degrees Celsius). The exemption only exempts components in heavy liquid service from the instrument monitoring requirements related to scheduled inspection requirements of §115.354(1) and (2).

BCCA-AG, Lyondell, TCC, and TxOGA commented that the proposed rules would create parallel rules for flares, cooling towers, and LDAR, with one set regulating VOCs generally and the other set regulating HRVOCs. BCCA-AG and Lyondell stated that although the HRVOC rules generally contain more emission limits and control requirements and more stringent monitoring provisions, each HRVOC rule substantially tracks its VOC counterpart and that much of the language of the regulations are identical. BCCA-AG and Lyondell noted that the proposed rules make clear that sources can be subject to both sets of rules. BCCA-AG, Lyondell, and TCC expressed concern that confusion may result if the same source is subject to both VOC and HRVOC rules. BCCA-AG and Lyondell recommended that each HRVOC rule should be structured so as to include all of the salient aspects of the parallel VOC rule, revised or supplemented to address HRVOCs, and to exempt any source that is subject to it from the parallel VOC rule. BCCA-AG and Lyondell stated that a less desirable, but nonetheless preferable, alternative would be to have both rules apply, but include in the HRVOC rules only those requirements that apply over and above the parallel VOC rule. TxOGA requested that for ease in regulatory interpretation, compliance, and Title V identification, the commission should write into Subchapter H all substantive requirements for both HRVOCs and VOCs such that only Subchapter B or Subchapter H applies to a unit. TxOGA stated that this will eliminate duplication and conflicts between the sections and assure that there are no redundancies, and that trying to incorporate separate and distinct requirements from different sections for the same facility is extremely confusing and difficult to implement.

The commission has withdrawn the proposed general VOC monitoring rules in Subchapter B, Divisions 7 and 8. In lieu of requiring this monitoring of all VOCs from individual flares, cooling towers, and process vents to obtain emissions data for use in SIP planning, the commission is relying on data from not only the commission's monitoring network, but also data from additional ambient monitors that will be strategically located in HGA. This monitoring is expected to not only be a more efficient use of resources for this data gathering, but will also provide information more quickly. As described more fully in the narrative to the SIP revision and TSD that accompany these rule amendments, the commission is committed to developing the best science possible to understand the causes of high ozone in the HGA. For the MCR, the commission plans to perform an in-depth analysis of the contributions of the less-reactive compounds and to perform top-down analyses similar to those used for the HRVOCs. If warranted, appropriate adjustment factors will be developed for less-reactive VOCs. As explained more fully in the SIP and TSD, the current modeling analysis indicates that emission reductions in the HRVOC alone can compensate for the change of industrial NO _x controls to 80% reductions, but additional controls on VOC sources are likely to be necessary to reach attainment. The commission will continue to study VOC data available now and in upcoming years to determine whether additional compounds should be added. To accomplish this task, the commission needs the support of and expects owners and operators of facilities in HGA which emit VOCs to participate in the ambient monitoring efforts which are scheduled to begin no later than June 1, 2003. If the ambient monitoring network is not fully and timely developed and operated such that the commission has received sufficient data for MCR, the commission may reconsider site-specific monitoring controls of VOC sources.

TxOGA stated that throughout the proposal, the term "VOC" is used, without clarity as to whether VOC is intended, or HRVOC is intended, because the term "highly-reactive" has been dropped. TxOGA stated that from the context, it appears that the intent is inconsistent and requested that the two terms be separate and that throughout the entire proposal, the term VOC or HRVOC be identified, as appropriate. Solutia and TCC suggested that the commission conduct a consistency check of the various divisions of the two subchapters. As an example, Solutia and TCC stated that all references to VOCs in Subchapter H should instead use the term HRVOC, thereby clearly indicating which compounds or chemicals are affected. Solutia stated that if someone were to read a section of Subchapter H out of context, they could easily be mislead on what the proper requirements were.

As noted earlier in this preamble, the commission revised the definition of "highly-reactive volatile organic compound" such that this term is abbreviated as HRVOC. Where the commission intends a requirement to apply to all VOC, it has used the term "VOC."

Solutia stated that both Subchapter B and H should contain a clause allowing alternate methods with executive director approval for monitoring or testing requirements. Solutia and TCC noted that some reporting requirements specify that reports be submitted to the Technical Analysis Division, with other items submitted to the Engineering Services Team. Solutia suggested that the commission should clarify the difference to avoid confusion by affected facilities. TCC also stated that approval authority should remain with the executive director, as has historically been the case in most agency programs, rather than Engineering Services. TCC stated that this shift in responsibility could restrict the ability to appeal matters to higher agency offices.

The commission has deleted all references in the rules to the Technical Analysis Division. "Executive director" is defined in 30 TAC §3.2 as "the executive director of the commission, or any authorized individual designated to act for the executive director." The references to the Engineering Services Team are necessary to clearly designate where within the agency certain information should be directed and who will review such information. This allows a more efficient flow of information to the appropriate area within the agency. The inclusion of references in the rules to specific areas of the agency has never prevented industry representatives from appealing matters to higher offices in the past, and is not expected to do so now.

BCCA-AG and Lyondell recommended that references to "continuous" compliance in the VOC and HRVOC flare rules be deleted, stating that the use of this term is unnecessary and may be misinterpreted to require a particular task be performed without interruption, when in fact the regulation requires that it only be performed periodically.

The commission disagrees, since continuous compliance is the basic intent of the rule. The commission believes that the rule's requirements for conducting continuous measurements (flow monitoring devices, for example) and noncontinuous measurements (HRVOC analyzers) are clear. However, the commission has clarified in §115.722(b) that flares must continuously comply with 40 CFR §60.18 by adding "when vent gas containing VOC is being routed to the flare" to the rule language.

EXEMPTIONS

Exemption for Small Percentages of HRVOC

BCCA-AG, Dow, DuPont, ExxonMobil, Goodyear-Houston, Lyondell, TCC, TxOGA, and Valero commented that the proposed HRVOC vent gas stream, cooling tower, and flare rules exempt from the control requirements streams in which HRVOCs comprise less than 1.0% by weight of the VOC in the stream, while the proposed HRVOC fugitives rule exempts from control requirements any component that contacts a process fluid that contains less than 1.0% by weight HRVOC. BCCA-AG, Dow, DuPont, ExxonMobil, Goodyear-Houston, Lyondell, TCC, TxOGA, and Valero agreed that a low HRVOC percent exemption is appropriate, but stated that the exemption should be based on the percentage of HRVOCs in the gas stream, not the percentage of HRVOCs in the VOC portion of the gas stream, because many streams contain significant percentages of non-VOCs. BCCA-AG, Goodyear-Houston, and Lyondell stated that this would make the basis of the exemption more straightforward, and would make it consistent with other, similar exemptions. As an example of why they believed that the exemption should be based on the entire content of the stream, BCCA-AG and Lyondell provided the following hypothetical example. Assume a site includes a non-condensable blow-down vent gas stream that normally consists of 99.95% nitrogen, 0.05% total VOC, and 0.005% ethylene. Given these relative percentages, the ethylene accounts for 10% of the VOC in this vent gas stream, but only 0.005% of the total stream, although this vent gas stream still would be subject to the new HRVOC requirements.

The commission agrees that the exemption should be based on the percentage (or concentration) of HRVOCs in the total stream for the reasons in the example cited by BCCA-AG and Lyondell, and has revised §115.727 and 115.768(2) (renumbered as §115.768(3)) accordingly.

BCCA-AG, DuPont, ExxonMobil, Goodyear-Houston, Lyondell, TCC, and TxOGA stated that each of the low HRVOC percent exemptions is provided for streams with 1.0% or less HRVOC. BCCA-AG, DuPont, ExxonMobil, Goodyear-Houston, and Lyondell agreed that a low HRVOC percent exemption is appropriate for the proposed HRVOC rules, but asserted that the proposed exemption level does not provide a meaningful exemption for streams with negligible amounts of HRVOCs. BCCA-AG, DuPont, ExxonMobil, Lyondell, TCC, and TxOGA suggested that the exemption level be set at 5.0% HRVOC of the total amount of material in the stream under normal operating conditions. BCCA-AG and Lyondell stated that "even the most stringent air regulations typically provide a 5.0% exemption, e.g., the HON leak detection and repair requirements" of 40 CFR §63.161 (definition of "in organic HAP service"). Phillips stated that the 1.0% HRVOC exemption limit is unrealistically low and should be raised to at least 5.0% to be meaningful. Valero recommended changing the exemption to 5.0% HRVOC of the total amount of material in the stream. Valero stated that this is similar in concept to the relief provided in the federal MACT standards for low hazardous air pollutant streams, and asserted that the proposed 1.0% level is too stringent and will not provide relief to insignificant HRVOC streams which do not cause ozone exceedances. Dow expressed similar concerns and suggested an exemption of 5.0% HRVOC by weight on an annual average basis. ExxonMobil and TxOGA requested that the exemption in §115.727(a) be established when the HRVOC level is 5.0% or less of the total vent gas stream from any uncontrolled vent. ExxonMobil stated that limiting the exemption to less than 1.0% HRVOC of the VOC stream produces overly broad rule coverage, impacting low-density streams that will have little effect on total HRVOC emissions in the nonattainment area. Goodyear-Houston expressed support for a 5.0% to 10% HRVOC stream composition exemption. TCC stated that monitoring fugitive emissions from components that contact process streams with concentrations of less than 5.0% will be difficult because some of these streams contain high nitrogen concentrations and low VOC concentrations, making detection with standard VOC analyzers impossible. TCC also stated that some of the dilute process streams are associated with vent headers and flare systems, making them difficult or unsafe-to-monitor. TCC further stated that including components in process streams with less than 5.0% VOC will require considerable engineering work to reassess process streams and compile new component counts. TCC asserted that these low concentration streams do not contribute significantly to the overall HRVOC emissions. Finally, TCC stated that Chapter 115 should be consistent with HON Subpart H and the other Part 63 NESHAP standards on the concentration exemption to simplify compliance. TCC stated that HON Subpart H (and all other Part 63 NESHAP standards) regulate equipment intended to operate in organic hazardous air pollutant service 300 hours or more during the calendar year, with the definition of "in organic hazardous air pollutant or in organic HAP service" meaning that a piece of equipment either contains or contacts a fluid (liquid or gas) that is at least 5.0% by weight of total organic hazardous air pollutants (HAPs) as determined according to the provisions of §63.180(d). TCC noted that the provisions of §63.180(d) also specify how to determine that a piece of equipment is not in organic HAP service.

The commission agrees that an appropriate exemption level is 5.0% by weight of HRVOCs in the total stream for flares, cooling towers, and fugitive emissions, and has revised §§115.727(a) and (b), 115.768(3), and 115.787(a) accordingly. For vent gas streams, however, the exemption levels in the existing Subchapter B vent gas rules range from 408 to 612 ppmv of the total stream. Therefore, an exemption level of 5.0% (50,000 ppm) by weight of HRVOCs in the total stream would exempt many vent gas streams from the Subchapter H vent gas requirements. The commission has revised §115.727(a) to establish a 100 ppmv exemption level because this threshold will ensure that all vent gas streams which are currently subject to Subchapter B, Division 2 (Vent Gas) are subject to, rather than inadvertently exempted from, Subchapter H.

Goodyear-Houston stated that an exemption should be added for sites that contribute a small portion of HRVOC to HGA (for example, 0.1% or less of the daily HRVOC allocation for HGA), or for industries who are users of HRVOC, but do not significantly contribute HRVOC emissions to HGA, such as industries under SIC code 2822. Goodyear-Houston also suggested the addition of an exemption for sites whose combustion sources are not beneficiaries of a less stringent alternate NO _x emission specification. Ethyl stated that the commission should consider categories of HRVOC users/emitters, with varying regulatory requirements in much the same way as EPA has regulated chlorofluorocarbons. Ethyl specifically stated that small specialty chemical plants should be considered separately from refineries and ethylene plants because operations and emission rates and potential for VOC emissions are dramatically different between large refineries/ethylene plants as compared to small specialty chemical plants.

Even though a particular individual site's emissions may form a relatively small fraction of the total emissions in HGA, the same can be said of most categories of emission sources. The logic of allowing no (or minimal) reductions from a source sector because it individually contributes only marginally to the area's ozone problem would cumulatively result in an inadequate plan for the area's attainment of the ozone standard due to insufficient emission reductions. Because significant contributions to air pollution occur throughout the HGA area, reductions from only the largest sources will not be enough to meet federal air quality standards.

To consider the concept of exempting certain "non-contributing" sources would imply that ozone formation is generally caused by specific emission units. This premise is unsupported by decades of scientific research concerning photochemical oxidants and ozone. In fact, ozone is a regional problem to which all sources of photochemical oxidants contribute. During ozone exceedance episodes, ozone tends to build slowly over time so that more sources contribute to the problem, over a much wider area, than for other criteria pollutant emissions. The available evidence on ozone formation points out the inherent difficulties in placing arbitrary borders around a problem which does not recognize geographical boundaries.

Furthermore, creation of a protected source category, such as industries under SIC code 2822, would permit continued growth in emissions, thereby jeopardizing the SIP.

Low Annual Hours of Operation

Dow and DuPont stated that an exemption should be added to both §115.357 and §115.787 for equipment in VOC or HRVOC service less than 300 hours per calendar year. Dow stated that in certain chemical plants, particularly batch processes that produce a number of different products, there is equipment that is used in VOC service only occasionally. Dow asserted that in such cases, implementation of the standards can be difficult and achieves very little emission reduction. Dow stated that pumps and compressors used only during startup or shutdown of a process unit are one example of such equipment, and that other examples include equipment used in batch steps in continuous processes and components on a closed vent system that routes emissions from pressure relief devices to a control device. DuPont also suggested that the commission consider adding an exemption to the flare, cooling tower, and vent gas requirements for equipment in service less than 300 hours per calendar year.

The commenters' suggestion would exempt sources that might operate solely on summer days with a particularly high potential for ozone formation, yet would be uncontrolled. Therefore, the commission has made no change in response to the comments.

Minimum Mass Flow Rate of HRVOCs - §§115.727, 115.747, 115.787

Ethyl stated that §115.727 and §115.787 should include additional qualifying requirements of minimum mass flow rate of HRVOCs for the vent stream, to account for small vents from batch processes.

The commission disagrees. Vents with a low flow rate, but high concentration, can have significant short-term emissions. The commenter's suggestions would allow higher emissions on a day when ozone may be a problem and cannot assure the level of control required on the hot summer days when ozone is most likely to form.

General VOC Industrial Wastewater

§115.147(3)

TxOGA commented that the first sentence of §115.147(3) is confusing. TxOGA stated that the sentence contemplates inclusion of specific requirements to identify other divisions of Chapter 115 as being applicable, and suggested that the wording of the proposed sentence should be revised accordingly to include the specific requirements of Subchapter D, Division 3 and Subchapter H rather than eliminate this exemption for specific components. TxOGA stated that there are several reasons the current wording is confusing. TxOGA stated that the term "component" has a different connotation in the industrial wastewater rules than in the fugitive emissions rules. TxOGA also questioned whether the second sentence means that components subject to Subchapter D, Division 3 and Subchapter H are now subject to any and all divisions of Chapter 115, or only to industrial wastewater (Division 4) and the additional ones listed. TxOGA stated that as written, it would seem to imply the broader applicability, where it should be adequate to have only the additional requirements of the fugitives emission divisions.

The current language of §115.147(3) (i.e., the first sentence) addresses pieces of equipment which are subject to §115.142, but which are also addressed by other divisions within Chapter 115, such as Storage of Volatile Organic Compounds. The intent is that only the industrial wastewater requirements apply to these pieces of equipment. In the absence of the first sentence of §115.147(3), these pieces of equipment also would be subject to one or more other divisions in Chapter 115. For this reason, the commission revised §115.147(3) to include a reference to Subchapters D and H. The commission agrees with TxOGA that the term "component" has a different meaning in the industrial wastewater rules than in the fugitive emissions rules, and has replaced this term with the more accurate term "piece of equipment" to clarify the intent. The second sentence in §115.147(3) means that some components or pieces of equipment are subject to the fugitive monitoring requirements of Subchapter D, Division 3, and/or Subchapter H. The commission has replaced the term "components" in the second sentence with the more accurate phrase "pieces of equipment or components" to clarify the intent.

Natural Gas Transmission Lines and Compressor Stations

§115.727(a)

Duke requested that special consideration with respect to §115.727(a) be given to vent gas streams in which the gas stream being vented is a relatively consistent compound, e.g., natural gas at transmission pipelines and compressor stations. With respect to natural gas transmission pipelines and compressor stations, Duke stated that there are a significant number of vent gas streams in which natural gas is the only compound being vented, and noted that natural gas contains trace amounts of HRVOC. Duke stated that it currently has only one extended gas analysis, for which the HRVOC would be anticipated to be in pipeline natural gas, which indicates an HRVOC content of 0.5% by weight. Although the chemical composition of natural gas does vary to a certain degree, Duke stated that it is unlikely that the HRVOC content of pipeline natural gas would ever exceed the exemption threshold of 1.0% by weight. Duke suggested that for vent gas streams consisting solely of pipeline quality natural gas, the commission should either specifically exempt pipeline quality natural gas from any sampling requirement, or allow the collection of representative samples for VOC analysis from the pipeline as opposed to the collection of samples at each individual piece of piping from which the natural gas is vented.

As noted earlier in this preamble, the commission revised §115.727(a) to establish an exemption level of 5.0% by weight of HRVOCs in the total stream. Because it is unlikely that the HRVOC content of pipeline natural gas would ever exceed 1.0% by weight, a vent gas stream in which only natural gas is vented would not be expected to be subject to the HRVOC rules.

HRVOC Vent Gas

Goodyear-Houston stated that vent gas streams in compliance with the polymer and resins MACT requirements of 40 CFR 63, Subpart U (40 CFR §63.494) should be exempt. Goodyear- Houston stated that alternatively, an exemption should be included for vent gas streams where stripping technology is used for MACT compliance.

MACT standards, such as 40 CFR Part 63, Subpart U (40 CFR §63.494), are not adequate to provide reductions for ozone strategy. Specifically, the MACT standards are based on the need to reduce exposure to HAPs, while the purpose of Chapter 115 is to reduce emissions which contribute to ozone formation. Because the purposes of the rules are so different, there is no reason they should necessarily have the same thresholds or exemptions.

§115.727(b)

Dow stated that the 100 ppmv criteria and 14 lbs/day criteria in §115.727(b) should apply only to HRVOC and not to all VOC in a vent gas stream.

The commission has deleted the proposed §115.727(b). Therefore, the commission has made no changes in response to the comment.

§115.727(b) and (c)

ExxonMobil recommended that §115.727(b) and (c) be amended to allow exemption for HRVOC vents that are able to demonstrate either a concentration threshold recognizing cost of control, or a mass flow rate recognizing an insignificant emissions level, and stated that combining these two restrictive limits results in cost-ineffective controls on insignificant emission sources. DuPont, Goodyear-Houston, and TCC expressed similar concerns. Goodyear-Houston stated that the existing mass emission threshold of 100 pounds of VOC per 24-hour period should be retained.

The commission has deleted the proposed §115.727(b) and (c). Therefore, the commission has made no changes in response to the comment.

§115.727(c)

Dow stated that §115.727(c) should be consistent with proposed §115.725(a) with respect to the requirement to conduct reference method testing. Dow also stated that §115.727(c) contradicts §115.725(a)(1)(A) to some degree. Dow commented that §115.725(a)(1)(A) states that if the measured concentration with a portable analyzer is less than 306 or 204 ppmv, then no mass emission rate test is needed, and implies that the stream may continue to be vented to the atmosphere. Dow commented that §115.727(c) states that both the concentration limit and the VOC mass emission rate must be met in order to be exempt from controls, such that it would be necessary to conduct a reference method test for each stream regardless of the concentration measured with a portable analyzer. Dow and Goodyear-Houston suggested that §115.727(c) be structured so that a vent stream is exempt from controls if either the concentration limit, as measured with a portable analyzer, or the mass flow rate limit is met. In addition, Dow stated that both sections should require reference test method testing only if testing with a portable analyzer shows concentrations in excess of the 306 or 204 ppmv cutoffs specified in the rule.

The commission has deleted the proposed §115.727(c). Therefore, the commission has made no changes in response to the comment.

DuPont commented on §115.727(c) and expressed disappointment that the commission back-calculated from EI data to develop the exemption threshold of 14 pounds in a continuous 24-hour period, while Goodyear-Houston stated that it is not clear how this threshold was developed. DuPont stated that the commission should insert language to allow for review of data at a particular date (December 31, 2003) to determine what level of control is necessary instead of prescribing a control point based on EI data.

The commission has deleted the proposed §115.727(c). Therefore, the commission has made no changes in response to the comment.

Combustion Unit Exhaust Streams Not Being Used as Control Devices

§115.727(d)

Duke and TxOGA stated that unlike §115.127(a)(7), §115.727 does not provide an exemption for combustion unit exhaust streams that are not being used as control devices for a vent gas stream which originates from a non-combustion source, but by contrast, §115.727(d) provides the §115.127(a)(6) exemption for vent gas streams for which requirements of a different division of Chapter 115 are applicable. Duke and TxOGA requested that an exemption be provided for combustion unit exhaust streams that are not being used as control devices for a vent gas stream which originates from a non-combustion source.

The exemptions available in §115.727(a) and (b) are designed to provide an appropriate exemption, while also ensuring that all appropriate vent gas streams are included in the site-wide cap. Therefore, the commission does not believe that the suggested exemption is necessary or appropriate.

VOC Flares

BCCA-AG and Lyondell commented that the proposed VOC flare rule applies to any flare in the HGA area which emits or has the potential to emit any VOC. In light of the potential high costs, BCCA-AG and Lyondell recommended that the commission include an exemption based on appropriate low emission and low annual usage thresholds. TCC commented that under §115.747, it should be clarified that if a source meets the exemption criteria, it is exempt from the subchapter, and that as stated, the exemption only relieves an operator from corrective action.

The commission has withdrawn the proposed general VOC rules for flares in Subchapter B, Division 7. For flares in HRVOC service under Subchapter H, Division 1, §115.727(a) exempts from the site-wide cap accounts for which no gas stream that is routed to a flare contains 5.0% or greater by weight of HRVOC at any time. However, such flares are still subject to recordkeeping requirements to document exempt status. The site-wide cap allows a company to take into account factors such as low emissions and low annual usage thresholds when designing its control plan for complying with the cap.

HRVOC Flares

§115.747

Green commented that some plants may not be subject to 40 CFR §60.18, and suggested that a one-time demonstration be allowed to determine the appropriate exemption level. Green commented that acceptable calculation methods or a one-time 40 CFR §60.18 performance test should be allowed. Green stated that there should be a de minimus level, expressed both as a percentage and a mass limit, to account for the fact that methane (which is not an HRVOC) is a major constituent of the flare gas.

All flares subject to the HRVOC rule must comply with 40 CFR §60.18 when vent gas containing VOC is being routed to the flare. This ensures that the flare is operated under proper operating conditions with regard to exit velocity and net heating value of the gas stream(s) routed to the flare. Section 115.727(a) exempts from the site-wide cap accounts for which no gas stream that is routed to a flare contains 5.0% or greater by weight of HRVOC at any time. Since this exemption applies to the percentage HRVOC in the total gas stream, not in the VOC portion of the stream, the presence of methane does not penalize the stream with regard to exemptability. In addition, the commission has added §115.725(c), which exempts flares used solely for abatement of emissions from loading operations for transport vessels from the rule's monitoring requirements, and instead allows the emissions to be calculated. However, such flares are still subject to recordkeeping requirements to document exempt status.

Green commented that the rule should be revised to exclude small companies that use a flare as their primary VOC control device, and stated that the inclusion of toluene and xylene in the definition of HRVOC would be detrimental to small companies. Green requested flexibility for small companies handling toluene and xylenes by allowing tanks storing these materials to be taken off the flare header as long as the exemption criteria for vapor pressure and tank size under §115.112 are met.

Toluene and xylenes are not included in the definition of HRVOC. Compliance with the storage tank provisions elsewhere in Chapter 115 does not necessarily exclude gas streams associated with the tanks from the applicability of the HRVOC rules.

Green requested clarification on the reason that the exemption is expressed in percent by weight rather than percent by volume, stating that most performance tests report volume percent in the flared gas.

Compliance with the site-wide cap is determined on a mass basis, averaged over a rolling 24-hour period. Therefore, in determining whether a unit or stream is exempt from the HRVOC rules, the commission believes that it is appropriate to use weight-based criteria.

TCC suggested that the following exemptions be added: 1) flares in dedicated VOC service from on-line or other speciated VOC analysis; and (in addition to Dow, 2) flares in emergency service (defined by Dow as flares with a routine feed rate of ten lb/hr or less of VOC), since these devices should be receiving no process gas during normal operation, and it is not practical to monitor these flares.

Information available to the commission indicates that very few flares are used solely for emergencies. At a minimum, there are fugitive emissions which are routinely routed to the flares from the relief valves on a non-emergency basis. The potential for large amounts of emissions to be released from such flares requires that monitoring be conducted. The commission has added §115.725(e), which exempts flares used solely for abatement of emissions from loading operations for transport vessels from the rule's monitoring requirements and instead allows the emissions to be calculated, provided that certain recordkeeping and other provisions are met.

Dow recommended that temporary flares be exempt from the rule, stating that such flares are generally used for short-term operations as temporary maintenance facilities used in planned startup, shutdown, and maintenance activities. Dow suggested that temporary flares be exempt for a period of 180 days, with extensions available on a case-by-case basis. Dow stated that there would not be enough time for a complete installation of necessary monitoring equipment, which could take six eight months. Dow also commented that temporary flares are not part of routine operations, and are usually responsible for few emissions because they are intended for short-term use.

The commission does not agree that an operating period of up to 180 days constitutes short- term use, and, more importantly, from an emissions standpoint sees no difference between a temporary flare and a permanent installation. Exempting temporary flares would essentially mean that their emissions would not be accounted for under the site-wide cap, and might even create an incentive to favor their use over permanent flares. In particular, the commission has concerns about exempting a control device used in startup, shutdown, and maintenance activities, given that these activities have the potential for creating excess emission events. No action has been taken in response to the comment.

Allied and Waste Management commented on the impact of the proposed rules on municipal solid waste (MSW) landfills. They stated that MSW landfills should be exempted from the rules because the gases routed to flares are essentially all methane and carbon dioxide (CO ₂ ), with typically less than 1% VOC by volume. Waste Management commented that the amount of HRVOC (toluene and xylene) routed to flares is extremely small. The commenters interpreted the proposed rule as requiring control unless the HRVOC content is less than 1.0% by weight of total VOC in the gas stream.

The commission has withdrawn the proposed general VOC rules for flares in Subchapter B, Division 7. For flares in HRVOC service under Subchapter H, Division 1, §115.727(a) exempts from the site-wide cap accounts for which no gas stream that is routed to a flare contains 5.0% or greater by weight of HRVOC at any time. However, such flares are still subject to recordkeeping requirements to document exempt status. Based on the information submitted by the commenters on their operations, it is extremely unlikely that a landfill waste gas stream routed to a flare would contain anywhere near 5.0% by weight HRVOC, which is equivalent to 50,000 ppm. This refers to the percentage HRVOC in the total gas stream, not the percentage HRVOC in the VOC portion of the stream. When EPA was developing New Source Performance Standards (NSPS) for new MSW landfills and emission guidelines for existing MSW landfills, the default concentration of non-methane organic compounds in lieu of testing was 8,000 ppm. Based on more complete operating data, this default was later reduced to 4,000 ppm. However, actual test data showed emissions in the 2,000 ppm range. Based on this information, the commission is not specifically exempting MSW landfills from the rule, but concludes that the 5.0% by weight HRVOC exemption level can easily be met by all MSW landfills.

VOC Cooling Towers

BCCA-AG and Lyondell commented that the VOC cooling tower rule should include exemptions for systems that have only a de minimis potential to significantly contribute to ozone development in the HGA area. BCCA-AG and Lyondell recommended that the exemptions should apply to cooling tower systems that: 1) service process streams containing less than 1.0% total VOC, based on the average for all heat exchangers in the cooling tower system; 2) service heat exchangers containing materials with minimal vapor pressure (heavy liquids); and 3) have circulation rates below a low threshold. BCCA-AG and Lyondell stated that since the intent of the proposed VOC cooling tower rule is to target monitoring and control requirements for cooling tower systems that have the greatest potential for VOC emissions, applying the proposed regulation to the cooling tower systems that meet the suggested exemption criteria is unnecessary and overly burdensome.

The commission has withdrawn the proposed general VOC rule for cooling towers in Subchapter B, Division 8. Therefore, the specific concerns expressed by the commenter are no longer applicable.

HRVOC Cooling Towers

BCCA-AG and Lyondell commented that for HRVOC cooling towers, the requirement that the hourly emission limit be met for the exemption to apply should be deleted. BCCA-AG and Lyondell also stated that the exemption should provide relief not only from the emission limit and the corrective action requirement, but from all of the proposed HRVOC cooling tower requirements. BCCA-AG and Lyondell further commented that if a HRVOC cooling tower system has no potential for leaking HRVOC to the atmosphere, there is no justification for its regulation under the proposed rule.

The commission has revised §115.768 to exempt any account for which no stream directed to a cooling tower heat exchange system contains 5.0% or greater by weight HRVOC. In addition, any CTHES in which no individual heat exchanger has HRVOC in the process side of the fluid is exempt from the requirements of the division, with the exception of recordkeeping requirements. These changes, in addition to the elimination of individual unit emission limits and establishment of a site-wide cap, provides the owner or operator of a cooling tower with considerable flexibility.

BCCA-AG and Lyondell commented that cooling towers subject to appropriate MACT standards should be exempt from the current proposed rules.

MACT standards are not adequate to provide reductions for ozone strategy. Specifically, the MACT standards are based on the need to reduce exposure to HAPs, while the purpose of Chapter 115 is to reduce emissions which contribute to ozone formation. Because the purposes of the rules are so different, there is no reason they should necessarily have the same thresholds or exemptions.

BCCA-AG and Lyondell commented that the proposed HRVOC cooling tower rule, which exempts from the 24-hour corrective action requirement cooling tower systems in which the minimum pressure on the cooling water side is at least 5.0 psig greater than the maximum pressure on the process side of all of its heat exchangers, should exempt a cooling tower system from all of the HRVOC cooling tower requirements, not merely the 24-hour corrective action requirement. TCC commented that the exemptions listed in §115.768, relating to Exemptions, should apply to the entire division, not just to the monitoring or control requirements. TCC stated that having such a complete exemption would prevent duplicative or conflicting requirements for the same CTHES.

The commission agrees, and has revised §115.768(1) to exempt such cooling towers from the requirements of the entire division, with the exception of the recordkeeping requirements of §115.767. Recordkeeping is needed to demonstrate that the minimum pressure on the cooling water side is at least 5.0 psig greater than the maximum pressure on the process side of all of the cooling tower's heat exchangers.

TCC recommended revising §115.768 to clarify that this exemption applies only if all heat exchangers serviced by the HRVOC CTHES meet the exemption criteria. TCC also suggested changing the phrase "minimum pressure" to "minimum normal operating pressure."

The commission has revised §115.768 to specify that each individual heat exchanger in the cooling tower system must meet the exemption criteria in order to qualify for exemption. The commission believes that the phrase "minimum pressure" should be retained in the rule. "Normal" implies an averaging period or baseline conditions. However, even if the suggested change were made, leaks could still occur; the intent of the rule is to address all conditions. Records documenting exempt status still need to be maintained.

TCC recommended that the exemption should not include a reference to the proposed mass emission rate limit found in §115.761 as a criterion for exemption from the proposed rule.

The commission agrees, and has eliminated this language from the rule.

TCC recommended moving the circulation rate exemption criteria from §115.760 to 115.768. TCC also requested clarification on the commission's reason for setting exemption criteria based on an 8,000 gpm circulation rate.

The rule makes a distinction between cooling towers with a water circulation rate equal to or greater than 8,000 gpm and those with a water circulation rate less than 8,000 gpm with regard to stringency of monitoring requirements. These requirements, however, are not criteria for exemption. Section 115.768 exempts a CTHES from the requirements of the division, with the exception of recordkeeping, if either pressure criteria or HRVOC criteria are met, and exempts an account for which no stream directed to a CTHES contains 5.0% or greater by weight HRVOC from the site-wide cap requirements. Therefore, no changes were made in response to the comments.

Fugitive Emissions

§115.357(10)

TxOGA commented on §115.357(10), which specifies that the requirements of the new Subchapter H apply to components which qualify for one or more of the exemptions in §115.357(1) - (9). TxOGA recommended writing the specific exemptions for Subchapter H in §115.787, but stated that if not, the exemptions excluded here should include only §115.357(1), (3), and (6) - (8).

The commission has retained §115.357(10) and is addressing exemptions for HRVOC in §115.787. Comments on the specific exemptions in §115.787 are discussed in the response to the next comment.

§115.781(b)(1)

Dow, DuPont, ExxonMobil, TCC, and TxOGA noted that §115.781(b)(1) specifies that the exemptions of §115.357 do not apply to Subchapter H, Division 4. DuPont stated that smaller sites with less than 250 components, water streams containing one ppm VOC, and sealless pumps would all be "inappropriately pulled into" the HRVOC fugitive emissions requirements. DuPont stated that existing exemptions such as "valves . . . venting to a control device" (§115.357(2)) "pumps and compressors with a shaft sealing system . . ." (§115.357(4)) should be retained. DuPont stated that the commission should justify removing any exemptions based on the emissions, reinstate appropriate exemptions, and provide a de minimis level of HRVOC for applicability. TxOGA stated that the exemptions in §115.357(1) - (4), (6), and (7) and the exemptions in §115.357 other than those §115.357(1), (3), and (6) - (8) should remain valid for HRVOC fugitive requirements. ExxonMobil and TxOGA also stated that, as proposed, §115.781(b)(1) inadvertently includes §115.357(10). TCC stated that the exemptions in §115.357(2) - (4) should remain valid for HRVOC fugitive requirements. ExxonMobil stated that the exemptions in §115.357(1) - (4) and (6) - (7) should remain valid for HRVOC fugitive requirements. Dow stated that the exemption in §115.357(9) for valves rated greater than 10,000 psig should remain valid for HRVOC fugitive requirements "to address potential safety hazards."

An exemption for de minimis level of HRVOC is available in §115.787(a), and an exemption for sealless pumps is available in §115.787(b). The commission agrees that exemptions are appropriate for plant sites covered by a single account number with less than 250 components in VOC service, pumps and compressors equipped with a shaft sealing system that prevents or detects emissions from the seal, PRVs equipped with a rupture disk or venting to a control device, and valves rated greater than 10,000 psig. The commission has added these exemptions as §115.787(c)(4) and (d) - (f). In addition, the commission has revised §115.781(b)(1) by changing the reference from "§115.357" to "§115.357(1) - (9)" in order to exclude §115.357(10). Finally, although no revisions to the 250 component exemption of §115.357(7) were proposed, the commission clarifies that the reference to "facilities" is intended to refer to plant sites covered by a single account number with less than 250 components in VOC service. This interpretation is supported by documentation for the 1993 rulemaking in which this exemption was added.

Dow stated that the exemption provided in §115.357(4) needs to be repeated in §115.787, with the addition of agitators that are equipped with shaft sealing systems. Dow stated that equipping pumps, agitators, and compressors with a shaft sealing system should be an alternative to quarterly monitoring, and that because automatic leakage control and detection is already required, there is no need for quarterly monitoring with a hydrocarbon gas analyzer.

The commission agrees that pumps, agitators, and compressors equipped with a shaft sealing system should be exempt from the monitoring requirements of §115.781(b) and (c), and has added an exemption as §115.787(d).

§115.352(4) - Open-ended Lines

Air Products and Dow noted that §115.354(4) specifies that except for PRVs, no valves shall be installed or operated at the end of a pipe or line containing VOC unless the pipe or line is sealed with a second valve, a blind flange, or a tightly-fitting plug or cap. Air Products expressed concerns about the additional requirement in §115.352(4) for a "tightly-fitting" plug or cap and stated that it has processes where material, if confined between a valve and a cap, could under certain conditions rapidly decompose and result in an explosion. Air Products stated that in some cases, its safety policy would not allow the configuration as proposed, and suggested the commission adopt language similar to the HON exemption in 40 CFR §63.167(e). Dow stated that an exemption to this requirement should be added to §115.357 and §115.787 similar to 40 CFR §63.167(d) - (e) of HON Subpart H. Dow stated that HON Subpart H provides two exemptions from equipping each open-ended valve or line with a cap, blind flange, plug, or a second valve as follows: "(d) Open-ended valves or lines in an emergency shutdown system which are designed to open automatically in the event of a process upset are exempt from the requirements of paragraphs (a), (b) and (c) of this section" and "(e) Open-ended valves or lines containing materials which would autocatalytically polymerize or, would present an explosion, serious overpressure, or other safety hazard if capped or equipped with a double block and bleed system as specified in paragraphs (a) through (c) of this section are exempt from the requirements of paragraph (a) through (c) of this section."

Dow stated that according to the Background Information Document following the December 31, 1992 proposal of the HON, EPA added the exemption in 40 CFR §63.167(d) because "the EPA agrees that automatically opening vent lines which are part of an emergency shutdown system should not be required to add a second valve or cap. It was also determined that the requirements for block and bleed systems were not appropriate. Section 63.167(d) was, therefore, added to the final rule to address a potential safety hazard." Dow stated that EPA added the exemption in 40 CFR §63.167(e) for open-ended lines or valves containing material that represented a safety or explosion hazard because "in a few processes, the requirement to cap, or plug the line could result in trapping highly-reactive monomer in the line. In these cases, the polymerization reaction will cause serious overpressure and catastrophic equipment failure presenting a safety hazard to plant personnel and creating the potential for greater emissions to the atmosphere than if the line were left uncapped." (60 FR 18073, April 10, 1995) Air Products likewise suggested the commission adopt language similar to 40 CFR §63.167(e).

The existing requirements of §115.354(4) concerning open-ended valves or lines implement federal RACT requirements for fugitive monitoring and, as such, cannot be relaxed. Should Air Products or Dow wish to pursue the matter further, the commission suggests that they present the issue to EPA and determine if EPA will agree to relax the federal RACT requirements.

§115.357 and §115.787(c) - Low Annual Hours of Operation

Dow and DuPont stated that an exemption should be added to both §115.357 and §115.787(c) for equipment in VOC service or HRVOC service less than 300 hours per calendar year. Dow stated that in certain chemical plants, particularly batch processes that produce a number of different products, there is equipment that is used in VOC service only occasionally, and that in such cases, implementation of the standard can be difficult and achieves very little emission reduction. Dow stated that pumps and compressors used only during startup or shutdown of a process unit are one example of such equipment, and that other examples include equipment used in batch steps in continuous processes and components on a closed vent system that route emissions from pressure relief devices to a control device. TCC expressed similar concerns.

The commission disagrees with the suggested addition of an exemption for equipment in VOC service or HRVOC service less than 300 hours per calendar year because such an exemption would conflict with federal RACT requirements for fugitive monitoring and, as such, cannot be relaxed. Should Dow or DuPont wish to pursue the matter further, the commission suggests that they present the issue to EPA and determine if EPA will agree to relax the federal RACT requirements. Therefore, when such equipment is in VOC or HRVOC service, the emissions from leaking components need to be included in the LDAR program to ensure that timely repair occurs in order to minimize emissions which contribute to exceedances of the ozone NAAQS. Monitoring is not required during those times that this equipment is not in VOC or HRVOC service.

§115.787(c) - Insulated Components

TCC stated that an exemption for insulated components should be added as §115.787(c)(3) because of related safety and accessibility issues. TCC stated that removing insulation can cause corrosion which presents a safety concern and suggested the commission evaluate non-obtrusive methods if monitoring of insulated components is required.

The commission agrees that an exemption for insulated components is appropriate due to inaccessibility of the components, and has added an exemption as §115.787(c)(5).

Nonaccessible or Unsafe to Monitor Valves

TCC recommended an exemption for "nonaccessible or unsafe-to-monitor" valves.

As described in the response to the previous comment, the commission has added an exemption for insulated components as §115.787(c)(5) due to inaccessibility of such components. As described later in this preamble in the discussion regarding §115.781(b)(8), the commission agrees that difficult-to-monitor PRVs should be monitored annually, as is currently required under §115.354(1)(B), and has revised §115.781(b)(8) accordingly. Similarly, the commission believes that components which are unsafe-to-monitor should be on a reduced monitoring schedule as is currently allowed under §115.354(1)(C), and has added a new §115.781(b)(7) which is based upon §115.354(1)(C). The commission has included a provision in §115.781(b)(7) which specifies that components which are difficult to monitor (i.e., cannot be inspected without elevating the inspecting personnel more than two meters above a permanent support surface) may instead be monitored annually.

EMISSION SPECIFICATIONS

General VOC Vent Gas Control

§115.121

For ease in regulatory interpretation, compliance, and Title V identification, TXOGA requested that the commission write into Subchapter H all substantive requirements for both HRVOCs and VOCs such that only Subchapter B or Subchapter H applies to a unit. TxOGA stated that this will eliminate duplication and conflicts between the sections and assure that there are no redundancies, and that trying to incorporate separate and distinct requirements from different sections for the same facility is extremely confusing and difficult to implement. TCC and TxOGA suggested that §115.121(a)(4) be changed to read: "Any vent gas stream in the Houston/Galveston area which includes an HRVOC, as defined in §115.10 of this title, is subject only to the requirements of Subchapter H of this title . . .."

Under the revision to §115.121(a)(4) suggested by TCC and TxOGA, a gap in coverage would result because vent gas streams which are currently subject to Subchapter B, Division 2, would no longer have any applicable vent gas requirements until the compliance date in 115.729. Therefore, the commission has not made the suggested change, but may revisit the issue after the compliance date in §115.729.

HRVOC Vent Gas Control

§115.722

ExxonMobil recognized that the commission is faced with a serious challenge in addressing emission of ozone precursors in the HGA area, but asserted that the proposal to unilaterally assign a single standard emission limitation on a per capita basis to every uncontrolled HRVOC vent gas stream is arbitrary and does not recognize technical feasibility, cost impact, volumes, necessity, or safety.

The commission has stated that the intent of this proposed revision to the SIP is to demonstrate a more cost-effective approach in lieu of the nominal 90% NO _x reduction incorporated in the currently approved SIP. The commission believes it has a significant amount of technical justification to support that conclusion. As the commission continues its stated course of action towards an MCR SIP, it will continue to analyze the data and determine if additional controls are warranted on other compounds besides the ones targeted for this revision. The commission agrees that the regulation of pollutants should be based upon the best available science. The commission believes that the tremendous wealth of data acquired since the summer of 2000 has provided the commission with a very strong basis for determining the pollutants that warrant control at this time and the level to which they should be controlled. The commission disagrees that it is premature to establish numerical emission limitations. In fact, in order to justify a more cost-effective control strategy other than that already in the adopted SIP, specific numeric emission limitations are essential to maintain the integrity of the SIP and ensure an approvable attainment demonstration. However, the commission does recognize that there are some issues associated with the different types and sizes of flares and cooling towers, and has therefore incorporated specific language to allow for a site-wide cap to address these issues.

HRVOC Flares

§115.741

EPA commented that the rule sets a pound per hour emission limit for a flare, but that the assumed destruction removal efficiency for the flares is not clear. EPA stated that the commission should specify in the rule the assumed destruction efficiency for a flare that meets 40 CFR §60.18, and should also provide justification for the chosen destruction efficiency. EPA further commented that the rule is not enforceable without a clearly stated assumed destruction efficiency. ED requested that the commission address the subject of destruction efficiency, and suggested that a study be undertaken to measure the destruction efficiency of typical VOC mixtures routed to flares in the HGA area.

As noted earlier in this preamble, the proposed Subchapter H, Division 2, flare requirements were relocated to Subchapter H, Division 1, and a site-wide HRVOC emissions cap has replaced individual (i.e., unit by unit) emission limits. Based upon more recent information concerning flare efficiency, the commission has specified in §115.725(d)(4) and (6) that a 98% destruction efficiency is assumed when the flare is in compliance with the heating value and exit velocity requirements of 40 CFR §60.18. Otherwise, a destruction efficiency of 93% is specified. The 93% destruction efficiency value is based on the approximate median destruction efficiency from selected flare tests conducted during EPA flare studies in the 1980s. Accountability under the site-wide cap is a crucial element that goes along with the flexibility offered by the cap. For this reason, increased emissions from flares that are not operating in compliance with the performance standard of 40 CFR §60.18 must be accounted for in the cap. With regard to studies on flare destruction efficiency, the commission has contracted for such a study, which currently is underway. The results of this study may be used to refine requirements for flares by the time of the MCR, which will be completed by May 1, 2004.

BCCA-AG and Lyondell commented that the proposed HRVOC flare emission limit of 7.4 lb/hr ignores the differences in flare size and flare service, as well as the underlying emission sources tied into the flares. BCCA-AG and Lyondell stated that the commission offers no technical justification for setting an individual hourly limit for each flare without regard to its physical characteristics or use, or considering the severity of the emission reduction required to meet the limit. BCCA-AG and Lyondell further stated that this emission limit is arbitrary and capricious because it is based on a per capita distribution of a source-category allocation that treats all flares that have the potential to emit any HRVOC the same and assumes that all such flares emit the same each hour.

As noted earlier in this preamble, the proposed Subchapter H, Division 2, flare requirements were relocated to Subchapter H, Division 1, and a site-wide HRVOC emissions cap has replaced individual (i.e., unit by unit) emission limits. The site-wide cap addresses the commenters' concerns because it enables each owner or operator to select the most cost-effective and technically feasible means of maintaining continuous compliance with the site-wide cap. Therefore, the commission has made no changes in response to the comments.

Under §115.741, relating to Emission Specifications, TCC commented that the term "excess emissions" should be deleted to avoid confusion with the Chapter 101 rules.

Because the site-wide HRVOC emissions cap has replaced individual (i.e., unit by unit) emission limits, the commenter's concerns are moot.

TCC commented that language should be added to §115.741 to require review of the flare emission specification after new monitoring data is obtained, and that the emission limitation should then be apportioned based on the size or complexity of the source. TCC also stated that this approach would provide a useful tool should a VOC emission allocation program be established. TCC commented that §115.741 should clarify that the pound per hour limitation is an "average" hourly rate rather than an instantaneous value. Dupont requested clarification that the specified lb/hr emission limitation is an average rate and not an instantaneous rate.

As noted earlier in this preamble, the proposed Subchapter H, Division 2, flare requirements were relocated to Subchapter H, Division 1, and a site-wide HRVOC emissions cap has replaced individual (i.e., unit by unit) emission limits. The site-wide cap is based on a 24- hour rolling average, rather than the hourly unit by unit emission limit that was proposed. The MCR which will be completed by May 1, 2004 provides an opportunity for the commission to reevaluate the level of the site-wide emission cap.

Sierra-Lone Star opposed the withdrawal of the proposed flare emission rate of 0.6 lb/hour of HRVOCs and the proposal of a 7.4 lb/hr emission rate.

As stated in the preamble of the proposal, the original 0.6 lb/hr emission limitation was the result of an inadvertent calculation error. The emission limitation was therefore withdrawn and replaced by the proper figure of 7.4 lb/hr. However, the site-wide cap has replaced individual unit emission limitations.

ED commented that the commission's intended interpretation and enforcement of the emission specification of §115.741 and the control requirement of §115.742(b) is ambiguous, and suggested that language be included to clarify that each hour during which the emission specification of §115.741 is exceeded will result in a separate violation, and that failure to fulfill the corrective action requirements of §115.742(b) within 24 hours will be separate and distinct from the violations of §115.741.

The individual unit emission specifications have been replaced by a site-wide cap which requires compliance on a rolling 24-hour average. Therefore, the distinctions pointed out by the commenter are no longer applicable. However, compliance with the overall HRVOC emissions cap will require that appropriate corrective actions be taken to remain within the cap on a rolling 24-hour average.

ED requested clarification regarding the recordkeeping requirements in §115.741 to ensure that the mass flow rate of VOC averaged in pounds per hour is recorded as well as how many calculations were performed to obtain the recorded quantity.

The emission specifications for HRVOC flares proposed in §115.741 have been replaced by a site-wide cap under §115.722. The monitoring requirements in §115.725(d)(2) specify that HRVOCs and other constituents be determined every 15 minutes using an on-line analyzer.

HRVOC Cooling Towers

TCC commented that the proposed hourly HRVOC mass emission rate limit on each CTHES is based on a per capita distribution of a source-category allocation which treats all CTHES that have the potential to emit any amount of HRVOC equally, and assumes that all such cooling towers emit HRVOCs at the same hourly rate. TCC also commented that this source-category allocation was derived from the 1999 emissions inventory, the accuracy of which has been questioned in the commission's recent "ground-truthing" analysis.

The commission has eliminated individual unit HRVOC emission limits, and in their place has established a site-wide cap. The site-wide cap allows an affected company to choose the most cost-effective and technically feasible methods for continuous compliance under the cap, and therefore addresses the concerns expressed.

CONTROL REQUIREMENTS

VOC Industrial Wastewater

TCC stated that the commission should add language in §115.142 stating that any industrial wastewater stream in the HGA area which includes an HRVOC is subject only to the requirements of Subchapter H, Division 4 of this chapter. TCC stated that this would avoid redundancies between §115.783(5)(A) and (B) and §115.142, and between §115.781(b)(5) and (6) and 115.144. ExxonMobil expressed similar concerns.

Under the revision to §115.142 suggested by TCC, a gap in coverage would result because industrial wastewater streams which are currently subject to Subchapter B, Division 4, would no longer have any applicable wastewater requirements until the compliance date in 115.789. Therefore, the commission has not made the suggested change, but may revisit the issue after the compliance date in §115.789.

§115.142(1)(A) and §115.783(5)(A)(i) and (B)

DuPont, TCC, and TxOGA stated that an allowance should be made for use of ethylene glycol where freezing of water seals may cause equipment damage or process disruptions. TxOGA suggested the inclusion of the following language: "For any component equipped with water seal controls, the only acceptable alternative to water is the use of ethylene glycol or other low vapor pressure anti- freeze, which may be used only during the period of November through February." DuPont suggested that propylene glycol be specifically listed as well. TCC and TxOGA also suggested that §115.783(5)(A)(i) could be deleted as redundant with §115.142(1)(A), but stated that it should be consistent with §115.142(1)(A) if retained. TCC and TxOGA further suggested that §115.783(5)(B) could be deleted as redundant with §115.142(1)(A). Dow and ExxonMobil expressed similar concerns.

The commission has revised §115.142(1)(A) and §115.783(5)(A)(i) to allow for freeze protection of water seals. The commission has retained §115.783(5)(A)(i) and (B) and has ensured that §115.142(1)(A) is consistent with §115.783(5)(A)(i) and (B).

§115.142(1)(H)

TxOGA commented that in §115.142(1)(H), the first attempt at repair within five days is reasonable. However, TCC and TxOGA stated that the commission should clarify the means of getting a waiver for situations where a final repair within 15 days is technically infeasible. TCC and TxOGA suggested that in addition to infeasibility due to unit shutdown, the rule should allow an extension in cases where the repair requires a capital project or construction which cannot be feasibly completed within 15 days or parts are not readily available. In addition, TCC and TxOGA stated that Test Method 21 should only be required where a repair has been made and stated that replacement of a cap, cover, or plug or the addition of water to a water seal should not require monitoring. TxOGA stated that monitoring in those instances is not a good use of resources since the cap or cover may removed again because the drain is used very shortly thereafter, rendering the monitoring not very useful. DuPont stated that once a leaking condition has been repaired, the component should not have to be monitored using Test Method 21 to confirm the repair is complete because it adds cost to the repair. EPA stated that proposed change to §115.142(1)(H) implies that no repair is necessary if Test Method 21 does not measure a leak. EPA commented that there could be a variety of reasons due to process variability that a component in disrepair does not show a measurable leak at a given time and therefore, if visual inspection of the seals and other components shows they are not in proper condition as described in §115.142(1)(G), a repair should be made. EPA stated that Test Method 21 should be used to confirm that the repair was effective, and suggested that §115.142(1)(H) be revised to include language stating that Test Method 21 must be used to confirm that a leak or improper condition is repaired.

The commission has revised §115.142(1)(H) to clarify that if a repair or correction is technically infeasible without a unit shutdown, the repair or correction may be delayed until the next unit shutdown. The commission believes that this provision renders moot any perceived need for a "waiver." The commission agrees with EPA that Test Method 21 is necessary to confirm that a leak or improper condition is repaired. This confirmation monitoring is an inherent part of the LDAR program and should not present an undue burden. If, as TCC and TxOGA suggested, monitoring was not required for the replacement of a cap, cover, or plug, or the addition of water to a water seal, then there would be no confirmation that a leak was properly repaired. Consequently, the commission has retained the requirement for Test Method 21 monitoring to confirm that each leak or improper condition is repaired.

HRVOC Vent Gas Control

Sierra-Lone Star supported vent gas control requirements, but stated that they needed to be improved.

The commission appreciates the support and has improved the vent gas control requirements wherever necessary and reasonable.

§115.722

Ethyl recommended a minimum mass discharge limit for vent gas streams before being subject to monitoring and control requirements, as very small vent streams which may exceed 20 ppmv would be subject to costly monitoring and control systems. As an example, Ethyl stated that it has one permitted scrubber vent of less than 0.01 tpy which possibly would be subject to monitoring and controls if testing showed greater than 20 ppmv of VOC at maximum or peak operation. Ethyl also stated that vents to the scrubber are from batch operated processes where there are very short-duration emissions spikes. Ethyl asserted that facilities that have such small vents could be subject to large costs, with no benefit to the environment or to the emissions inventory database.

There are numerous options for compliance, and the availability of a site-wide emissions cap provides each owner or operator with the maximum flexibility to select the most cost-effective and technically feasible method of controlling emissions. Therefore, the commission declines to add these specific options to the rule.

§115.722(a) - LDPE Plants

Dow, ExxonMobil, and TCC stated that there does not appear to be adequate technical analysis and justification for the proposed emission levels in §115.722(a) for low and high-pressure polyethylene processes. Dow agreed that the proposed LDPE emission specifications represent best available control technology (BACT), but stated that significant retrofits would be required for existing LDPE production facilities. Dow and TCC asserted that installation of controls such as catalytic oxidizers would increase NO _x emissions. Dow, ExxonMobil, and TCC recommended that the commission establish a site-wide allocation system based on data analysis and appropriately include at a later date any new emission limits that are needed.

As noted earlier in this preamble, the proposed Subchapter H, Division 2, flare requirements were relocated to Subchapter H, Division 1, and a site-wide HRVOC emissions cap has replaced individual (i.e., unit by unit) emission limits. Therefore, the commission has deleted §115.722(a). The site-wide cap addresses the commenters' concerns because it enables each owner or operator to select the most cost-effective and technically feasible means of maintaining continuous compliance with the site-wide cap. Regarding the commenters' concerns about increased NO _x emissions, the commission notes that Chapter 117 classifies a catalytic oxidizer as an incinerator, which is subject to inclusion in the Chapter 101 mass emissions cap and trade program if it has a maximum rated capacity of 40 million British thermal units per hour (MMBtu/hr) or greater. A newly-installed incinerator with a maximum rated capacity of 40 MMBtu/hr or greater would not receive allowances under the Chapter 101 mass emissions cap and trade program, thereby ensuring that no increase in NO _x emissions occurred. Therefore, the commenters' concerns about increased NO _x emissions are overstated.

Sierra-Lone Star opposed the exclusion of not counting the fugitive emissions in the allowable VOC emission rate from LDPE plants of 90 pounds of ethylene per 1.0 million pounds of product and high-pressure (HP) LDPE plants of 200 pounds of ethylene per 1.0 million pounds of product from all the vent gas streams associated with the formation, handling, and storage of solidified product, based on a 30-day rolling average. Sierra-Lone Star stated that the commission is aware that LDPE and HPLDPE plants are sources of high volumes of fugitive HRVOCs like ethylene that are in need of better control, and that the commission needs to require including the fugitive emissions in the 30-day rolling average VOC emission rate. Sierra-Lone Star also stated that LDPE and HPLDPE fugitive emissions need to be better monitored and controlled in the LDPE and HPLDPE plant process units, and that the commission needs to determine if these LDPE and HPLDPE plant fugitives are detectable with Test Method 21 or are undetectable because they are occurring under the insulation from either leaking piping or leaking equipment components.

The commission disagrees with Sierra-Lone Star and believes that fugitive emissions are more appropriately regulated in the divisions which address fugitive emissions (Subchapter D, Division 2, and Subchapter H, Division 3). Emerging technologies such as CO ₂ laser imaging are much more likely than Test Method 21 to be able to find leaks occurring underneath pipe insulation since Test Method 21 is not designed for finding such leaks. As noted earlier in this preamble, a site-wide HRVOC emissions cap has replaced individual (i.e., unit by unit) emission limits for vents, flares, and cooling towers. The commission has made no changes in response to the comments.

§115.722(b) - Alternative Vent Gas Control Requirements for LDPE Plants

Sierra-Lone Star supported the control requirement of achieving at least 98% or higher destruction efficiency for all vent gas streams as long as the plant has evidence and maintains records that 98% efficiency or higher is continuously achieved.

The commission appreciates the support. However, the site-wide HRVOC emissions cap has replaced the need for the specified control efficiency for control devices to which individual LDPE vents are routed. Therefore, the commission has deleted §115.722(b).

§115.722(c) - Vent Gas Control Requirements non-LDPE Plants

Sierra-Lone Star supported the control requirement of achieving at least 98% destruction efficiency (or to 20 ppmv) for all vent gas streams as long as the plant has evidence and maintains records that 98% efficiency or higher is continuously achieved. TxOGA also supported the control requirement of achieving at least 98% destruction efficiency (or to 20 ppmv) for all vent gas streams.

The commission appreciates the support. However, the site-wide HRVOC emissions cap has replaced the need for the specified control efficiency for control devices to which individual vents are routed. Therefore, the commission has deleted §115.722(c).

§115.722(d)

Sierra-Lone Star supported the proposed §115.722(d), which requires that whenever VOC emissions are vented to a closed-vent system, control device, or recovery device used to comply with the provisions of this chapter, the system or control device must be operating properly. Dow suggested adding a provision that would allow a minimum on-stream time (e.g., 95% or better) to allow for short periods of time when these new systems need to be taken off-line or experience an upset. Dow stated that a shutdown of a polyethylene facility will cause high short-term emissions, which will likely exceed the emissions from not operating the control equipment for a short period of time. Dow stated that another alternative would be the use of Start-up, Shutdown, Malfunction Plans in 40 CFR 63, Subpart A, which detail how the production plants and emission controls systems will be operated during these times.

The site-wide HRVOC emissions cap has replaced the need for the proposed §115.722(d) because under a cap, the additional HRVOC emissions resulting from a control device which is not operating properly will be deducted from an account's site-wide cap. Therefore, the commission has deleted the proposed §115.722(d).

§115.722(e)

ExxonMobil and TxOGA stated that §115.722(e) is redundant with the proposed flare rules and should be deleted.

The commission has combined the proposed Subchapter H, Divisions 1 and 2, into Division 1. Therefore, there is no redundancy.

§115.722(f)

TCC commented on §115.722(f), which specifies that an owner or operator may not use ERCs or DERCs in order to demonstrate compliance with Subchapter H, Division 1. TCC stated that the commission should withhold judgment on trading mechanisms until such time as an HRVOC allocation/trading program can be addressed. TCC stated that programs that provide flexibility for industry to comply in the most cost-effective manner should be encouraged.

Because there is not a program in place for HRVOC banking and trading and HRVOC ERCs and DERCs do not exist, it would be inappropriate to allow the use of HRVOC ERCs and DERCs. Therefore, the commission has made no changes in response to the comment. However, the commission has relettered §115.722(f) as §115.722(c).

HRVOC Flares

BCCA-AG and Lyondell commented that §115.171 requires flares to comply with every subsection of 40 CFR §60.18, but only subsections (c), (e), and (f) of 40 CFR §60.18 contain substantive flare control provisions that are appropriate for adoption by reference. BCCA-AG and Lyondell further commented that the other subsections of 40 CFR §60.18 have no applicability in the context of the proposed rules.

As noted earlier in this preamble, the commission has deleted the proposed §115.171. The commission agrees with the commenters, however, and has changed the corresponding language in §115.742(a), which was relocated to §115.722(b), to reference "40 CFR §60.18(c) - (f)." The revised and relocated language includes 40 CFR §60.18(d) because it is applicable.

§115.742

EPA commented that this rule properly requires that deviations from the limit in §115.741 should be corrected promptly within 24 hours, and further commented that the rule should also be clear that the same requirement for correction within 24 hours also applies any time a flare deviates from the requirements of 40 CFR §60.18.

The site-wide HRVOC emissions cap has replaced the need for the proposed §115.742 to address deviations from the limit in §115.741 because under the cap, unit-by-unit compliance does not apply. Additional HRVOC emissions resulting from deviations from the applicable requirements of 40 CFR §60.18 will have to be accounted for in the account's site- wide cap.

§115.742(a)

TCC and TxOGA commented that the word "continuous" should be deleted from §115.742(a), relating to Control Requirements, noting that 40 CRF §60.18 does not require continuous compliance.

The proposed §115.742(a) has been relocated to §115.722(b). The commission disagrees with the commenters because continuous compliance is the basic intent of the rule. However, the commission has clarified the requirement in §115.722(b) that flares must continuously comply with 40 CFR §60.18(c) - (f) by adding "when vent gas containing VOC is being routed to the flare" to the rule language.

TCC commented that §115.742(a) should not impose control requirements on emergency flares which do not typically receive vent streams, stating that this would result in increased NO _x emissions by forcing compliance with the minimum heating value levels when the flare would otherwise be idle.

Most flares are used as routine control devices, and very few flares are used solely for emergencies. In addition, the purpose of the site-wide HRVOC emissions cap is, as the name implies, to limit HRVOC emissions at a site to a capped value. The site-wide cap provides each owner or operator with the maximum flexibility to select the most cost-effective and technically feasible method of controlling emissions. Therefore, the commission has made no changes in response to the comment.

§115.742(b)

TCC and Goodyear-Houston commented that it is not possible in all cases to make flare repairs within 24 hours. TCC suggested that a period of 15 days should be allowed to troubleshoot the flare header and make appropriate adjustments, further noting that options for additional delay of repair should be allowed on a case-by-case basis, depending on approval of the regional office. For this rule requiring corrective action to be completed within 24 hours, EPA requested clarification on whether avoidable unauthorized emissions that occur for less than 24 hours will be considered violations. EPA also questioned whether facilities can apply for discretion under §101.222 for unauthorized emissions that persist longer than 24 hours. EPA stated that the level of emissions assumed to be achieved by the rule depends on these factors. BCCA-AG and Lyondell commented that the emissions from the process units(s) shutdown(s) could cause more HRVOC emissions than are being emitted on a daily basis from the leak, and that the 24-hour repair period would require many unplanned unit shutdowns whose environmental consequences, including ozone formation, could outweigh the benefit associated with more quickly reducing HRVOC emissions. BCCA-AG and Lyondell stated that these factors could be appropriately taken into account in individual emissions management plans (EMPs). BCCA-AG, Lyondell, and TxOGA commented that the requirement for corrective action within 24 hours is not needed since the commission's existing upset rules and associated enforcement exemption criteria already provide an additional regulatory incentive for resolving excess emission problems as quickly as possible. BCCA-AG and Lyondell further commented that the 24-hour corrective action provision is unnecessary because, even in the absence of such a provision, an owner or operator would be under a continuing obligation to stop violating the limit as soon as possible, and that the 24-hour provision merely serves to enable the commission to cite a separate violation for the same underlying activity. TCC commented that the commission should consider deletion of §115.742(b), relating to corrective action. TCC stated that corrective action related to upset events should be addressed in the Chapter 101 rules, and that when an emission limitation or standard is exceeded, the regulated community typically reviews the Chapter 101 rules for necessary response requirements for these events.

As noted earlier in this preamble, under the site-wide HRVOC emissions cap the owner or operator is not required to make repairs on any particular schedule, provided that the 24-hour rolling average HRVOC emission cap is not exceeded. Likewise, the site-wide cap has replaced the need for the proposed §115.742 to address deviations from the limit in §115.741 because under the cap, unit-by-unit compliance does not apply. The site-wide cap simply requires that each site stay below its 24-hour rolling average HRVOC emission cap. Therefore, the commission has made no changes in response to the comments.

HRVOC Cooling Towers

Sierra-Lone Star stated that miles of insulated piping and thousands of large pieces of insulated equipment continuously undergo great wear and tear, stress, and strain from normal pressure changes and heat changes causing expansions and contractions that weaken and damage metal materials until leaks occur; and corrosive effects of certain chemical materials will also damage piping and lead to leakage. Sierra-Lone Star stated that a significant portion of cooling tower fugitive VOC emissions evidently result from these kinds of piping leaks and process equipment leaks with some of the leaking fugitive VOC emissions finally escaping at cooling towers, and although the new rules address this one aspect of the widespread problem, the cooling towers account for only 7% of the fugitive HRVOC emissions in the EI.

The types of leaks described are fugitive emissions from equipment leaks, which are totally separate from cooling tower emissions. Fugitive emissions are addressed in other parts of Chapter 115.

§115.762

EPA requested clarification on whether, if unauthorized emissions persist beyond 24 hours, the facility can apply for discretion under §101.222, or whether unauthorized emissions beyond 24 hours are automatically a violation. EPA commented that how this issue is handled should be factored into the assumed effectiveness of the rule.

The Chapter 101 emissions event rules do not apply to a facility until it exceeds its authorized emission limitations. Therefore, if the site-wide cap has not been exceeded and no other limitations have been exceeded, the facility would still be authorized to emit and therefore would not fall under the reporting and demonstration requirements of Chapter 101. Any unauthorized emissions which meet the definition of an emissions event may be eligible for exemption.

EPA commented that for cooling water systems in HRVOC service, it would not be unreasonable to expect facilities to have sufficient heat exchanger capacity such that a leaking heat exchanger could be taken out of service and repaired without delay until shutdown of the facility.

A parallel heat exchanger design would be necessary to change out leaking heat exchangers as suggested by EPA. Not all cooling towers have this type of design, however, and the commission is not requiring that companies implement this design.

BCCA-AG and Lyondell commented that the 24-hour corrective action requirement should be deleted, stating that the EMPs would ensure that cooling tower emissions meet the applicable site-wide HRVOC cap and address potential short-term contributions to ozone formation. TCC commented that the proposal to require repair of any leaking CTHES within 24 hours of detection is unrealistic. TCC recommended modifying this requirement to allow for no more than 45 days to make such repairs.

The commission has eliminated the individual unit emission limitations and 24-hour corrective action requirement proposed in the HRVOC cooling tower rule, and has replaced them with a site-wide cap requiring compliance on a 24-hour rolling average. However, under the new requirements for compliance under the cap, when emissions increase above the cap limit the company must still take action to maintain compliance on a 24-rolling average basis. The commission supports the development and submission of EMPs that address specific actions to be taken to ensure compliance with the site-wide cap.

BCCA-AG, Goodyear, and Lyondell commented that identifying and repairing cooling tower leaks within 24 hours usually is not logistically possible, because it may take from 24 - 48 hours to several days merely to verify the initial sample result and determine which exchanger(s) may be the cause of the leak. BCCA-AG and Lyondell also commented that if a cooling tower serves multiple process units within a site and a process unit shutdown is required to correct the leak in one heat exchanger, it may require multiple process unit shutdowns to be coordinated, and the time required for such an effort would be days and weeks, not hours. BCCA-AG, Goodyear, and Lyondell further commented that the federal SOCMI HON and Ethylene MACT standards allow 45 days for leaks to be repaired. TCC recommended revision of §115.762 to allow 24 hours to initiate investigation upon confirmation of the presence of a leak, five days to determine the source of the leak or else submit a forward plan to the regional office, to initiate corrective actions within 24 hours after confirming the source of the leak, and 45 days to correct the problem or else submit a forward plan to the regional office. Citing the fact that a typical cooling tower heat exchange system may have over 50 heat exchangers, TCC stated that it can take in excess of 24 - 48 hours just to collect the necessary samples to identify the heat exchanger(s) responsible for the leak. TCC further stated that this does not include additional time for analytical work, especially if it is being done off-site. TCC commented that the timing for repair is consistent with the existing provisions found in the HON (40 CFR 63.104) and in the recently promulgated ethylene MACT rule.

The 24-hour corrective action requirement proposed by the commission has been replaced by a site-wide cap requiring compliance over a 24-hour rolling average. The long time periods claimed to be necessary for identification and correction of the referenced problems may very well be plausible, based on current operating practices. However, in order to reduce HRVOC emissions to avoid short-term ozone exceedances, the response to such problems needs to be proactive instead of reactive. With regard to sufficient time for analytical work, the commission has taken this factor into account in §115.764(c), which requires the speciated strippable VOC or HRVOC concentration to be determined as soon as this information is available, but no later than 48 hours after the sample(s) has been collected. This provision takes into account the typical turnaround time for an analytical laboratory to provide speciated results. With regard to MACT, the MACT standards are designed specifically to reduce exposure to HAPs, and do not adequately reduce emissions which contribute to ozone formation, which is the purpose of Chapter 115. Because the purposes of these rules are so different, there is no reason they should necessarily have the same thresholds or exemptions.

BCCA-AG and Lyondell commented that the emissions from the process units(s) shutdown(s) could cause more HRVOC emissions than is being emitted on a daily basis from the leak, and that the 24-hour repair period would require many unplanned unit shutdowns whose environmental consequences, including ozone formation, could outweigh the benefit associated with more quickly reducing HRVOC emissions. BCCA-AG and Lyondell stated that these factors could be appropriately taken into account in individual EMPs.

As described in the previous response, the rule has been changed to allow 48 hours for the speciated results to be obtained from laboratory analysis of samples. However, under the site- wide HRVOC emissions cap the owner or operator is not required to make repairs on any particular schedule, provided that the cap emission limit is not exceeded on a 24-hour rolling average.

BCCA-AG and Lyondell commented that the commission's existing upset rules and associated enforcement exemption criteria already provide an additional regulatory incentive for resolving excess emission problems as quickly as possible, and that the requirement for corrective action within 24 hours is therefore not needed in the rule. BCCA-AG and Lyondell further commented that the 24-hour corrective action provision is unnecessary because, even in the absence of such a provision, an owner or operator would be under a continuing obligation to stop violating the limit as soon as possible, and that the 24-hour provision merely serves to enable the commission to cite a separate violation for the same underlying activity.

The response to the previous comment is also applicable to this comment.

ALTERNATE CONTROL REQUIREMENTS

HRVOC Vent Gas Control

§115.723

Dow and TCC stated that they appreciate that the alternate control standard in §115.723 allows existing control devices to operate with efficiencies of 95%, but suggested that a limit of 90% is more justifiable. Dow stated that several of the existing rules that will be impacted by Subchapter H currently require only 90% controls, including §§115.121(a)(1), 115.162, and 115.312(a)(2), all referenced in §115.722(c). ExxonMobil and TxOGA stated that under §115.723(1), the commission proposed that a control device approved under an ARACT must operate at its maximum efficiency. ExxonMobil stated that the regulated community cannot design and install emission control equipment that exceeds the minimum requirements of state and federal rules to ensure operation within emission restrictions, if each piece of equipment must be operated at maximum efficiency. ExxonMobil and TxOGA suggested the maximum efficiency phrase be replaced with the phrase "operating properly." BCCA-AG, ExxonMobil, and Lyondell recommended that the commission add a provision that vents controlled to MACT standards are approved as meeting the alternate control requirements. BCCA-AG and Lyondell stated that the level of emission control required by MACT standards will likely exceed the level required by the proposed rule and such sources should not be subject to both standards. Sierra-Lone Star expressed concern that the commission did not publish in the rules the criteria that will be required for determining "economic reasonableness." Sierra-Lone Star's concern is that without such published criteria being subjected to public scrutiny, the commission might not be consistent in determining and concluding when this level of cost is triggered. Sierra-Lone Star requested that the commission publish the alternate control requirement criteria that will be used in this determination in this rule.

As noted earlier in this preamble, §117.723 has been withdrawn. Therefore, the commission has made no changes in response to the comments.

HRVOC Cooling Towers

§115.763

TCC suggested changes in the wording in §115.763, relating to Alternate Control Requirements, to make the section consistent with TCC's related comments on other sections.

As noted earlier in this preamble, §117.763 has been withdrawn. Therefore, the commission has made no changes in response to the comments.

PROCEDURES AND SCHEDULE FOR LEAK REPAIR AND FOLLOW-UP

Fugitive Emissions

Delay of Repair/Shutdown List

§115.352(2)

Phillips stated that the delay of repair requirements are unduly restrictive. Phillips suggested that the commission should contemplate unplanned unit shutdowns for equipment leak repair only on a case-by-case basis after thorough consideration of all the ramifications and resultant environmental impact.

The commission has revised the delay of repair requirements in response to a variety of comments, as described elsewhere in this preamble, and believes that the revised requirements are reasonable and necessary. The commission agrees that unplanned unit shutdowns should be contemplated on a case-by-case basis with appropriate consideration given to the ramifications and resultant environmental impact.

OxyChem stated that when given the opportunity to plan a shutdown, it can minimize emissions to the environment and cited as an example a planned shutdown in one of its units which resulted in only 12 pounds of total VOC emissions over the course of several days. OxyChem stated that some relief should be given to those units that have components which may be leaking at rate greater than that which would be experienced during a shutdown, particularly for those owners and operators who actively and aggressively minimize shutdown emissions. OxyChem recommended that difficult-to- repair components (those that are typically scheduled for repair during a turnaround) for which emissions would be greater than a shutdown event be repaired at the next scheduled shutdown provided that "extraordinary efforts" to repair the component have taken place. OxyChem stated that extraordinary efforts may include, but are not limited to, non-routine leak prevention methods, and that extraordinary efforts will need to be undertaken within seven days of the component being place on the shutdown list.

The commission agrees that §115.352(2) should include an incentive for owners and operators who actively go above and beyond the current leak repair requirements. Consequently, the commission has added a new §115.352(2)(A)(iii) which provides an alternative to documenting that the total cumulative mass emissions from leaking components in the unit for which delay of repair is sought are less than the mass emissions resulting from shutdown of the unit. The new §115.352(2)(A)(iii) is based upon §115.782(b)(2)(A)(i), which is described later in this preamble, and specifies that delay of repair is allowed for each leaking component for which the owner or operator has chosen to undertake "extraordinary efforts" (e.g., sealant injection) to repair the leak. For leaks detected over 10,000 ppmv, extraordinary efforts shall be undertaken within seven days of the valve being placed on the shutdown list; however, the owner or operator may keep the leaking valve on the shutdown list only after two unsuccessful attempts to repair a leaking valve through extraordinary efforts, provided that the second extraordinary effort attempt is made within 15 days of the first extraordinary effort attempt. For all other leaks, extraordinary efforts shall be undertaken within 15 days of the valve being placed on the shutdown list, and a second extraordinary effort attempt is not required. The commission emphasizes that the extraordinary efforts are an option, not a requirement, in §115.352(2)(A)(iii).

§115.352(2)(A)

Air Products requested that the commission clarify §115.352(2)(A) to state whether "emissions" to be evaluated include only the material leaking or all air contaminants. Air Products questioned whether the amount of VOC leaking from a valve (or valves) is to be compared only to VOC emissions during the unit shutdown and start-up, or compared to all emissions from a unit shutdown and start-up (i.e. NO _x , carbon monoxide (CO), etc.).

Section 115.352(2)(A) specifies that repair may be delayed until the next shutdown if the repair of a component within 15 days after the leak is detected would require a unit shutdown "which would create more emissions than the repair would eliminate." Because §115.352(2)(A) specifies that the comparison of shutdown emissions is to the emissions from the leaking component, and a component that is subject to §115.352 will be emitting VOC if the component is leaking, then it is a direct reading of the rule that only VOC emissions are included in the comparison.

Dow stated that the commission should allow repair attempts while the component is on delay of repair, but prior to the expected date of shut down. Dow stated that the commission should consider adding an additional delay of repair reason consistent with HON Subpart H (40 CFR §63.171(a)), NSPS Subpart VV (40 CFR §60.482-9(a)), and NESHAP V (40 CFR §61.242-10(a)), as these rules were amended on December 14, 2000. Dow stated that each of these rules includes the following delay of repair reason: "Delay of repair of equipment for which leaks have been detected is allowed if the repair within 15 days after the leak is detected is technically infeasible without a process unit shutdown. Repair shall occur by the end of the next process unit shutdown." (Dow's emphasis supplied.) Dow stated that the preamble to the CAR provides explanation as to why this clarification was made (63 FR 57776) as follows: "The CAR clarified language dealing with repair of leaks. Leaks must be repaired within 15 days of detection, unless the leak qualifies for delay of repair. Provisions in all three referencing subparts (NSPS VV, NESHAP V, HON Subpart H) allow for delay of repair ". . . if the repair is technically infeasible without a process unit shutdown." This language potentially discourages any attempts at repair between the 15th day after detection and the next process unit shutdown, since a successful repair within that period would then disqualify one from the original delay of repair. Some equipment leaks legitimately qualify for delay of repair, yet they can be repaired after the 15-day repair deadline and before the next process unit shutdown. These repairs can be effected by continued repeat attempts over time until the leak is repaired. In order to eliminate the potential disincentive to attempt repair of leaks after the 15th day, the CAR revises the wording of this provision to state that delay of repair is allowed if repair "within 15 days after a leak is detected" is technically infeasible without a process shutdown."

The commission agrees and has revised §115.352(2)(A) and §115.782(c)(1)(B) accordingly.

§115.352(2)(A)(i)

ATOFINA agreed with the concept of qualifying components for a shutdown list, but disagreed that the owner must submit documentation to the Office of Compliance and Enforcement within 30 days after the leak is detected. ATOFINA stated that historically, it places approximately 150 components on the shutdown list every quarter, and that notification for each component placed on the shutdown list is impracticable. ATOFINA stated that because of the quantity of notices the commission would receive from regulated sites, it is unlikely that the commission has the necessary manpower or resources to review and comment on notification. ATOFINA suggested that component records for the shutdown list be maintained on site. BCCA-AG, Dow, ExxonMobil, Lyondell, and TCC expressed similar concerns and stated that if the commission chooses to revise the delay of repair (DOR) process so as to require prior agency action on DOR requests, such action should be taken by the executive director, and not by Engineering Services. DuPont and Goodyear-Beaumont disagreed with the requirement that notification be submitted within 30 days regarding a leak. DuPont stated that in some operating areas, it may take over 30 days to complete all monitoring in that area, such that if a leak is found on the first day that cannot be fixed (i.e., requires a shutdown), then multiple reports would have to be submitted. DuPont recommended that all such records be kept on-site available for inspector review during routine inspections and that no submittals be required. Goodyear-Houston and TxOGA likewise stated that no submittals should be required.

The commission agrees and has revised §115.352(2)(A)(i) to require that the owner or operator maintain, and make available upon request, DOR documentation to authorized representatives of EPA, the executive director, appropriate regional office, and any local air pollution control agency having jurisdiction.

BCCA-AG and Lyondell noted that §115.352(2) requires each leaking component to be repaired within 15 days, but allows owners and operators to submit DOR calculations under §115.352(2)(A)(i) within 30 days. BCCA-AG stated that the proposal should be revised to make clear that DOR is allowed from the end of the initial 15-day deadline until the commission rejects a DOR request.

Because the revision to §115.352(2)(A)(i) in response to the previous comment changed the DOR submittal requirement to a record maintenance requirement, there is no inconsistency with the 15-day repair requirement. Therefore, the commission has made no change in response to the comment.

BCCA-AG, Dow, ExxonMobil, Lyondell, TCC, and TxOGA recommended that DOR emissions be calculated and reported quarterly, within 30 days of the end of the monitoring quarter. BCCA-AG, Dow, ExxonMobil, Lyondell, TCC, and TxOGA stated that those cumulative emissions would then be compared to the emissions that are projected by the owner or operator to result from a complete unit shutdown and subsequent startup, and that an unplanned shutdown would then have to be scheduled within the next six months if the DOR emissions are greater than the shutdown/startup emissions. BCCA-AG, Dow, ExxonMobil, Lyondell, TCC, and TxOGA stated that records would be kept documenting the evaluation of emissions from DORs and comparing them to shutdown/startup emissions.

As noted in the response to the previous comment, the commission has revised §115.352(2)(A)(i) to require that the owner or operator maintain, and make available upon request, DOR documentation to authorized representatives of EPA, the executive director, appropriate regional office, and any local air pollution control agency having jurisdiction. Therefore, the commission has made no change in response to the comments.

§115.352(2)(A)(i)(II)

Dow, EnRUD, and Goodyear-Beaumont commented on §115.352(2)(A)(i)(II), which references the mass emissions sampling method ("bagging") of the EPA guidance document "Protocol for Equipment Leak Emission Estimates," Chapter 4, Mass Emission Sampling (EPA-453/R-95-017, November 1995). Dow, EnRUD, and Goodyear-Beaumont stated that bagging is an intensive and costly task. Goodyear-Beaumont suggested that fugitive emission factors from the commission's "Air Permit Technical Guidance for Chemical Sources: Equipment Leak Fugitives" (October 2000) should be allowed in lieu of bagging. Dow recommended using the methods in the EPA guidance document "Protocol for Equipment Leak Emission Estimates," EPA Correlation Approach in Section 2.3.3 or the Mass Emission Sampling approach in Chapter 4 (EPA-453/R-95-017, November 1995).

The commission agrees that bagging is an intensive and costly task, and has revised §115.352(2)(A)(i)(II) to give owners and operators the choice of using either bagging or the correlation equations to estimate the mass emissions from leaking components.

Dow and Goodyear-Beaumont suggested that §115.352(2)(A)(i)(II) be revised to clarify that leaking compounds for which delay of repair is not being sought and which will be repaired such that they will not leak until the next shutdown are not included in the calculation as if they will leak until the next shutdown.

The commission agrees and has added the wording "for which delay of repair is sought" after "each leaking component in the unit."

§115.352(2)(A)(i)(III)

Goodyear-Beaumont suggested that §115.352(2)(A)(i)(III) be revised to clarify that leaking compounds for which delay of repair is not being sought and which will be repaired such that they will not leak until the next shutdown are not included in the calculation as if they will leak until the next shutdown. BCCA-AG, Dow, ExxonMobil, Lyondell, and TCC likewise stated that the DOR calculation should be clarified such that only the emissions from leaking components that cannot be repaired without a unit shutdown (and therefore, are candidates for DOR) should be included in the DOR emissions calculation. BCCA-AG and Lyondell stated that otherwise, owners and operators will have to recalculate DOR eligibility every time a new leaking component is identified, which would render the DOR approval process wholly unworkable because many large facilities include over 200,000 components and fugitive monitoring is conducted almost daily.

The commission agrees and has added the wording "in the unit for which delay of repair is sought" after "each leaking component." The commission has made corresponding revisions to §115.352(2)(A)(i)(IV) and (ii).

ATOFINA stated that refineries and certain petrochemical plants have incorporated scheduled shutdowns into their operating schedule, but that many petrochemical facilities have no need to schedule shutdowns. ATOFINA commented that as an example, polyethylene and polypropylene plants have no need to schedule shutdowns every four years, because shutdowns at these facilities occur as a result of economics and/or technical problems. As a result, ATOFINA stated that attempting to estimate emissions between the date a leak is discovered and the next unit shutdown is not possible.

The commission agrees and has deleted the reference to the next scheduled shutdown in §115.352(2)(A)(i)(III).

BCCA-AG, Dow, ExxonMobil, Lyondell, TCC, and TxOGA stated that leaking components are not necessarily leaking at the rate previously detected. BCCA-AG, ExxonMobil, and Lyondell asserted that assuming leaking components are leaking at the rate detected since the last monitoring event will overestimate emissions. BCCA-AG, Dow, ExxonMobil, Lyondell, TCC, and TxOGA stated that it should be assumed that the component has been leaking at the average of the current rate and the previous rate over the number of days since the last time the component was monitored. DuPont stated that the date that a component was discovered to be leaking should be considered the starting date. The commenters also stated that leaking components can increase or decrease leak rates, and even drop below the threshold defined as leaking without any repairs being made.

The commission agrees and has revised §115.352(2)(A)(i)(III) accordingly.

§115.352(2)(A)(ii)

ATOFINA, BCCA-AG, Dow, ExxonMobil, DuPont, Lyondell, TCC, and TxOGA commented on §115.352(2)(A)(ii) and stated that requiring unit shutdowns to be triggered when emissions from leaking components approach 50% of the emissions resulting from a shutdown has the potential to increase emissions. Consequently, ATOFINA, BCCA-AG, Dow, ExxonMobil, Lyondell, TCC, and TxOGA suggested that shutdown be required only when emissions from leaking components equal the emissions that would result from a shutdown, while DuPont stated that the commission should allow flexibility in a facility selecting an appropriate factor based on its shutdown plans. BCCA-AG and Lyondell asserted that repeated startup/shutdown cycling of units will shorten the life spans of seals in some components and thus result in increased emissions. ExxonMobil stated that inflexibility in mandating shutdown for repairs could cause shutdowns during peak ozone season, and that the unit shutdown could be better scheduled outside the peak ozone season and thereby decrease the likelihood that the shutdown will contribute to an ozone exceedance. BCCA-AG and Lyondell stated that the DOR calculation should recognize this by ensuring that it does not result in frequent shutdowns and start-ups. TCC stated that only DOR components should be included in the calculation. BCCA-AG, Dow, ExxonMobil, Lyondell, TCC, and TxOGA also stated that startup emissions should be included in the calculation and that §115.352(2)(A)(i)(I) and (ii) should be revised accordingly.

The commission agrees and has revised §115.352(2)(A)(ii) accordingly. The commission notes that the rules specifying that only shutdown emissions are included in the calculation became effective on August 22, 1980. The commission does not believe that it is appropriate to relax the requirement to also include startup emissions because the current shutdown-only calculation has been in place for over 22 years and has been approved by EPA in that configuration. The suggested change could jeopardize EPA approval.

Rohm & Haas stated that §115.352(2)(A)(ii) stipulates that repair may be delayed if "the total cumulative mass emissions from leaking components in the unit as determined in subclause (IV) of this clause are less than 50% of the mass emissions resulting from shutdown of the unit as determined in subclause (IV) of this clause." Similarly, §115.782(c)(1)(B) allows that "if the repair of a component would require a unit shutdown which would create more emissions than the repair would eliminate, the repair may be delayed until the next shutdown." Rohm & Haas suggested that these requirements should be modified to include a provision to delay repairs based on a de minimis amount of leaking components, similar to those presented in §115.782(e)(3)(B).

As discussed later in this preamble, the commission has deleted §115.782(e)(3)(B). The commission believes that the revisions it has made to §115.352(2) render moot the potential need for a provision to delay repairs based on a de minimis amount of leaking components. Therefore, the commission has made no changes in response to the comment.

§115.352(2)(A)(iii)

Dow, DuPont, ExxonMobil, and TCC recommended that §115.352(2)(A)(iii) not be adopted and stated that a large shutdown could involve placing hundreds of components on a shutdown list for approval during any one year. DuPont stated that submitting this information for review and approval is time-consuming and of little benefit, and that such data is available for review by inspectors at the facility at any time. BCCA-AG, Dow, ExxonMobil, and Lyondell stated that the 30 days allotted for shutdown upon DOR disapproval under §115.352(2)(A)(iii)(III) is too short. BCCA- AG, Dow, ExxonMobil, and Lyondell stated that planning for a safe unit shutdown and startup takes more than 30 days and usually requires at least six months of detailed planning. BCCA-AG, Dow, and Lyondell suggested that the provision should be revised to require a shutdown within six months of the disapproval of DOR.

As noted in the response to comments on §115.352(2)(A)(i), the commission revised §115.352(2)(A)(i) to require that the owner or operator maintain DOR documentation and make it available upon request. For consistency with the revised §115.352(2)(A)(i), the commission has deleted the proposed §115.352(2)(A)(iii).

§115.352(2)(B)

Sierra-Houston and Sierra-Lone Star supported the requirement in §115.352(2)(B) that each component for which repair has been delayed must be repaired at the next unit shutdown.

The commission appreciates the support. The commission has revised §115.352(2)(B) to specify an additional 15 days to initiate a process unit shutdown after comparison of the calculations of the process unit leaking component emissions to the shutdown emissions. A company will not know if a shutdown is triggered until it updates the calculation after each day of monitoring. Because a monitored concentration can change after an attempt at repair and the rule was allowing seven days to enter hand data, 15 extra days (from the date the leaks are found, not when the company makes the calculation) was selected because it fit with that time frame. The commission's expectation is that no process unit shutdowns will be required under the revised §115.352(2)(B) because companies will find it more desirable to make extraordinary efforts at repairing leaks.

§115.352(2)(C)

Sierra-Houston and Sierra-Lone Star supported the proposed §115.352(2)(C), which specifies that DOR beyond a unit shutdown is allowed for a component that is isolated from the process and does not remain in VOC service.

The commission appreciates the support.

§115.352(2)(D)

DuPont commented on the proposed §115.352(2)(D), which specifies that valves which can be repaired without purging and/or cleaning the line may not be placed on the shutdown list. DuPont stated that it will not repair lines and/or components that have not been adequately cleared due to safety concerns, and recommended deletion of §115.352(2)(D).

The commission appreciates DuPont's concerns and has added the modifier "safely" before "repaired" in §115.352(2)(D). The commission also replaced "purging and/or cleaning the line" with "a unit shutdown" and "valves" with "components" to clarify the intent. As an example, pumps may operate in tandem, one in service with the other serving as a spare, and in such cases a leaking seal can be repaired without the need for a unit shutdown.

Monitoring of repaired components after startup

§115.352(2)(E) and §115.781(b)(4)

Air Products, BCCA-AG, Dow, DuPont, Ethyl, ExxonMobil, Lyondell, OxyChem, TCC, and TxOGA noted that the proposed §115.352(2)(E) and §115.781(b)(4) require that all components opened or repaired during a shutdown be re-monitored within seven days after startup. BCCA-AG, Dow, ExxonMobil, Lyondell, OxyChem, TCC, and TxOGA stated that following an extensive unit shutdown, there typically would be a very large number of components subject to this requirement, and that monitoring all of these components within seven days is impractical and would require a substantial increase in monitoring personnel. BCCA-AG, ExxonMobil, Lyondell, and TxOGA suggested that 60 days be allowed for the required monitoring of repaired components after startup, with ExxonMobil and TxOGA suggesting a full quarter as an alternative. ExxonMobil also suggested 30 days. OxyChem suggested that 90 days be allowed for the required monitoring of repaired components after startup, while TCC suggested that monitoring occur at the next monitoring period. Dow suggested allowing 30 days or until the next monitoring period, whichever occurs first. BCCA-AG and Lyondell stated that it should be clarified that only those components identified in §115.354(4) are subject to re-monitoring. DuPont, Goodyear-Beaumont, and OxyChem stated that only components opened during a shutdown for repair of a leak should be subject to re-monitoring. Dow and DuPont stated that it is extremely difficult to determine which components might have been disturbed following a shutdown and that the entire unit would likely have to be monitored, which could not be accomplished in seven days. DuPont recommended deletion of the phrase "within seven days after startup is completed following the shutdown." Air Products also stated a belief that seven days is not a reasonable time period to recheck components that were repaired or opened. Air Products stated that in some cases there are certain areas with restricted access until the start-up is complete which could take several days, and in other cases, the individuals who would normally conduct the monitoring are occupied with activities associated with the completion of the turnaround and are not available for monitoring. Air Products stated that monitoring during the next scheduled monitoring period should be adequate. Ethyl opposed the proposed requirement to monitor repaired components within seven days after a startup of a repaired component in the LDAR program for smaller specialty chemical plants such as the Ethyl Houston Plant. Ethyl stated that the Ethyl Houston Lubricant Additives Plant is rather new, has small line sizes, handles materials with heavy vapor pressures, and operates under low pressure, mainly on a batch basis, and that an experienced and qualified contract third-party firm conducts LDAR monitoring for 3,000 - 4,000 components quarterly. Ethyl stated that the plant averages one to two leaking components per quarter at the 500 ppm leak level, which are immediately repaired and re-monitored within hours of discovery, certainly within a few days. Ethyl stated that, in contrast to refineries and ethylene plants, there is no such thing as delayed repairs and leak lists. Therefore, Ethyl stated that continued quarterly emission monitoring is sufficient to detect VOC and the even heavier HRVOC leaks, and repair occurs on a timely basis. Ethyl stated that monitoring within seven days of a small repair would require the special call out of the third-party contractor to monitor for such trivial repairs as the replacement of a pressure gauge or two-inch valve. Ethyl stated that alternatively, it would have to purchase equipment and train personnel for the additional seven-day monitoring, which would likewise be costly, with no significant reduction in VOC emissions. Ethyl stated that several years of LDAR monitoring data provide proof of the sufficiency of the current approach, and asserted that continued routine visual and odor monitoring by operation and maintenance personnel is sufficient to assure no significant HRVOC emissions following line breaks from smaller specialty chemical plants that operate similarly to Ethyl.

The commission has revised the monitoring schedule in §115.352(2)(E) and §115.781(b)(4) from seven days to 30 days or until the next monitoring period, whichever occurs first. In addition, the commission has clarified that only components opened during a shutdown for repair of a leak are subject to re-monitoring because these components are more likely to be leaking upon startup than components which were not opened during a shutdown.

BCCA-AG and Lyondell stated that the phrase "opened or repaired" should be clarified to mean "disturbed" in §115.352(2)(E) and §115.781(b)(4) because the term "opened" may be broader than intended. BCCA-AG and Lyondell recommended the use of the term "disturbed," which is drawn from the SOCMI HON and is familiar to industry. DuPont stated that the word "opened" could likely double or triple the monitoring requirements after startup and recommended deletion of the word "opened." OxyChem suggested the use of the term "repaired or disturbed" instead of "opened or repaired," while TCC suggested use of the term "repaired."

The commission has replaced the phrase "that have been opened or repaired" with "for which a repair attempt was made," in reference to a repair attempt in §115.352(2)(E) and §115.781(b)(4) in order to clarify the intent. The commission believes that "repair attempt" will be more easily understood than "disturbed."

§115.352(2)(F)

Sierra-Houston and Sierra-Lone Star supported the requirement in §115.353(2)(F) that components be monitored even if on the shutdown list. DuPont stated that components should be taken off the shutdown list if they quit leaking while on the shutdown list (i.e., pass remonitoring). DuPont stated that an example is a compressor which routinely settles after a few weeks of run time following a shutdown, which it believed should not have to be monitored as a leaking component until the next shutdown. Dow stated that §115.353(2)(F) and §115.782(c)(3) should be deleted. Dow stated that this requirement is unnecessary and will inevitably result in additional issues that must be resolved. Dow stated that most fugitive emissions database management software programs do not currently allow for delay of repair items to be downloaded with the routine monitoring. Dow also stated that if the subsequent monitoring reading while the component is on the shutdown list is different than the original reading, there is the question of which reading should be used for emission calculating purposes. Dow also stated that the commission will need to provide additional guidance on what to do if the component is no longer shown to be leaking upon re-monitoring.

The commission agrees with Dow and has deleted §115.353(2)(F) and §115.782(c)(3).

§115.352(8)

The commission has revised §115.352(8) to clarify the requirements for leak testing of new and reworked connections.

§115.782(b)

ATOFINA expressed concern that the proposed §115.782(b), which specifies that a first attempt to repair a leaking component must be made within 24 hours after the leak is detected and the leaking component repaired within 15 calendar days, will severely complicate its current monitoring program. ATOFINA stated that currently, the monitoring technician begins rounds early in the morning and submits findings to the maintenance staff at the end of each day. ATOFINA stated that if a leaking component is found early in the technician's rounds, a work order may not be written until the end of the day, resulting in as much as a ten-hour delay before maintenance is even notified. ATOFINA also stated that most maintenance work is completed during normal business hours, resulting in work orders being submitted as the maintenance staff is leaving for the day. ATOFINA stated that without significant changes in its monitoring program and work order system, there is a potential that maintenance staff would not receive a first attempt of repair work order within 24 hours of the leak's discovery, thus making it impossible to make the first attempt in the proposed allotted time. ATOFINA also stated that its technicians are required to monitor 400 - 600 components each day and its current system allows each technician to efficiently focus on monitoring components without interruptions. ATOFINA questioned whether interrupting a technician's rounds for each insignificant component leak (> 500 ppmv but < 10,000 ppmv) is justified, because each interruption potentially results in significant delays. ATOFINA suggested that components that are found to have insignificant leaks should remain on a five-day first attempt to repair schedule. ATOFINA agreed that if a component is found to have a significant leak of greater than 10,000 ppmv, the technician should contact maintenance immediately and the first attempt to repair should be made within 24 hours. BCCA-AG, Dow, DuPont, ExxonMobil, Goodyear-Houston, Lyondell, TCC, and TxOGA expressed similar concerns. BCCA-AG, ExxonMobil, Goodyear-Houston, Lyondell, and TxOGA suggested that the first attempt of repair be required by the next business day following a leak detected at over 10,000 ppmv, and within five days for all other leaks. DuPont suggested that leaks be prioritized according to severity, with repair required in three to five days at a minimum. TCC suggested that the first attempt of repair be required within three days following a leak detected at over 50,000 ppmv, and within five days for all other leaks. Dow suggested that the first attempt of repair be required by five days (i.e., the current requirement) but no less than the next business day. As an alternative, Dow suggested that leaks be prioritized according to severity as follows: for leaks detected over 10,000 ppmv, a first attempt at repair required by the next business day and repair required no later than seven calendar days after the leak is detected; and for all other leaks, the currently-required first attempt at repair within five days and repair within 15 calendar days after the leak is detected.

The commission agrees that it is appropriate and logical to prioritize leaks according to severity, such that the components with the higher leak rates are addressed before components with smaller leaks. The commission has reviewed the various options and revised §115.782(b) to require a first attempt at repair within one business day for leaks over 10,000 ppmv, with repair required no later than seven calendar days after the leak is detected. For leaks of no more than 10,000 ppmv, the commission revised §115.782(b) to require a first attempt at repair within five days, with repair required no later than 15 calendar days after the leak is detected. The commission selected this tiered approach in order to balance the implementation of an effective control strategy for repairing leaking components in a timely manner against concern that a significantly more aggressive schedule will be difficult or impractical to implement for the reasons cited by the commenters.

Dow stated that the commission should clarify that if action is taken to repair leaks within the specified time, failure of that action to successfully repair the leak is not a violation. Dow suggested that the following language be added as new §115.352(2)(G) and §115.782(e)(5): "In all cases where the provisions of Chapter 115 require an owner or operator to repair leaks by a specified time after the leak is detected, it is a violation of Chapter 115 to fail to take action to repair the leaks within the specified time. If action is taken to repair the leaks within the specified time, failure of that action to successfully repair the leak is not a violation of Chapter 115. However, if the repairs are unsuccessful, a leak is detected and the owner or operator shall take further action as required by applicable provisions of Chapter 115."

The commission does not believe that the suggested language is necessary. The rules already specify the action to be taken if a leak is detected, as well as the steps to be taken if the first attempt to repair the leak is unsuccessful. Failure to comply with the rules clearly represents a violation. The commission does not believe it is necessary or appropriate to specify in the rules that compliance with the rules does not represent a violation.

§115.782(c)(1)(A) and (2)(B)

TxOGA stated that "VOC" should be changed to "HRVOC" in §115.782(c)(1)(A) and (2)(B).

The commission agrees and has revised §115.782(c)(1)(A) and (2)(B) accordingly.

§115.782(c)(1)(B)(ii)

BCCA-AG, DuPont, ExxonMobil, Lyondell, and TxOGA stated that the four-year limit for repair or replacement of components on the DOR list in proposed §115.782(c)(1)(B)(ii) should be deleted. BCCA-AG and Lyondell stated that many major shutdowns occur from five to eight years apart and that an appropriate DOR calculation will account for the continued emissions from the leaking component until the next scheduled shutdown, whenever that occurs. ExxonMobil and TxOGA expressed similar concerns.

The commission agrees that the four-year limit should be deleted and has revised §115.782(c)(1)(B)(ii) accordingly.

Extraordinary Efforts

§115.782(c)(2)(A)

ATOFINA, BCCA-AG, Dow, ExxonMobil, Lyondell, TCC, and TxOGA noted that the proposed rules require that "extraordinary efforts" be made for valves (other than PRVs and automatic control valves) which are found to be leaking. ATOFINA, BCCA-AG, Dow, Lyondell, and TxOGA stated that extraordinary efforts should be made on valves that are found to be significant leakers (>10,000 ppmv). TCC stated that extraordinary efforts should be made on valves that are leaking at >50,000 ppmv. TCC also stated that extraordinary efforts should be required for valves that are leaking at >10,000 ppmv and have been on the DOR list for three years or more. ATOFINA stated that extraordinary efforts should be limited to significant leakers while valves with insignificant leak rates should be exempt from extraordinary efforts. TCC stated that sealant injection may not be appropriate in certain cases like high pressure service. BCCA-AG, Dow, and Lyondell stated that the requirement for extraordinary efforts should be tied to the 15 pounds per day mass emissions rate proposed in §115.782(e)(3)(C). BCCA-AG, Dow, and Lyondell also stated that an owner or operator should be able to exempt certain valves from the requirement to make extraordinary efforts upon a demonstration that such efforts would upset or contaminate the process. BCCA-AG, Dow, and Lyondell stated that the time frame for the second attempt should be extended to 15 days to allow time to evaluate alternative extraordinary efforts. ExxonMobil and TxOGA stated that the four-year limit of §115.782(c)(2)(A) should be deleted for the reasons given in the ExxonMobil and TxOGA comments on §115.782(c)(1)(B)(ii). Similarly, TCC recommended that the four-year limit of §115.782(c)(2)(A) be deleted. ExxonMobil commented that pumps are often spared and can be fixed without shutdown, but compressors are seldom spared and shutdown is usually required to fix compressor leaks.

The commission disagrees with TCC's suggestion that extraordinary efforts be limited to valves that are leaking at >10,000 ppmv and have been on the DOR list for three years or more because it would allow leaks to continue unabated for three years before the extraordinary effort would be required. Under TCC's suggestion, the cost for the extraordinary effort would be the same, but an additional three years' worth of emissions would occur that could have been prevented had the extraordinary effort been made three years earlier. The commission also disagrees with the suggestion that extraordinary efforts should be required only if the valve's mass emissions rate exceeds 15 pounds per day. Such a cutoff would allow over 2.7 tpy of emissions without repair. Because units can often operate five to ten years between shutdowns, a 15 pounds per day cutoff could cumulatively result in 13.7 to 27.4 tons of uncontrolled emissions before the leak is repaired or the component is replaced.

The commission agrees with the commenters' suggestion that more attention be focused on valves that are found to be significant leakers (>10,000 ppmv), and has revised §115.782(c)(2)(A) to require that the first extraordinary effort be made within seven days of the valve being placed on the shutdown list. The commission believes that it is appropriate to require a second attempt to repair a leaking valve through extraordinary efforts for significant leakers, given the low cost ($100 - $150 per valve) and the potential that a leak can be stopped that otherwise could continue for five or even ten years. The commission agrees that 15 days should be allowed for the second attempt at extraordinary efforts to stop a leak and has revised §115.782(c)(2)(A) accordingly. For leaks of 10,000 ppmv or less, the commission has revised §115.782(c)(2)(A) to require that an extraordinary effort be made within 15 days of the valve being placed on the shutdown list, with no second attempt to repair a leaking valve through extraordinary efforts required. In addition, the commission has changed "repair" to "repair or replacement" because both methods may be used to correct a component for which repair has been delayed until the next shutdown. The commission agrees that the four-year limit should be deleted and has revised §115.782(c)(2)(A) accordingly. Concerning TCC's comment that sealant injection may not be appropriate in certain cases like high pressure service, the commission notes that §115.782(c)(2)(A)(ii) provides an exception to the extraordinary efforts requirement if the owner or operator documents that there is a safety, mechanical, or major environmental concern posed by repairing the leak by using extraordinary efforts.

§115.782(c)(2)(A)(i)

Dow, TCC, and TxOGA requested that the requirement for a second "extraordinary effort" to repair a valve be deleted. TxOGA asserted that a valve that does not respond to a first repair such as sealant injection is not likely to respond to a second. Dow stated that if the second extraordinary effort requirement is retained, the time frame for the second attempt should be extended to 15 calendar days from the first extraordinary effort attempt to allow time to evaluate alternative extraordinary means.

The commission disagrees that the requirement for a second "extraordinary effort" to repair a valve should be deleted. However, the commission agrees that the time frame for the second attempt should be extended to 15 calendar days from the first extraordinary effort attempt and has revised §115.782(c)(2)(A)(i) accordingly. The commission believes that it is appropriate to retain the second "extraordinary effort" because the cost is minimal ($100 - $150 per valve), in some cases a second attempt is needed to successfully stop a leak, and the second attempt may stop a leak that otherwise could continue for five or even ten years.

§115.782(c)(2)(A)(ii)

ExxonMobil and TxOGA stated that §115.782(c)(2)(A)(ii) does not specify how long an operator has to comply by other means if the Engineering Services Team does not approve the reason given for not using "extraordinary efforts" on valves. ExxonMobil and TxOGA stated that the seven/seven days for using "extraordinary efforts" may have already passed by the time the decision is made. ExxonMobil and TxOGA also asserted that the commission should not be in the business of deciding what is a justified safety concern. TCC expressed similar concerns.

The commission agrees and has revised §115.782(c)(2)(A)(ii) to require that the owner or operator maintain, and make available upon request, documentation to authorized representatives of EPA, the executive director, the appropriate regional office, and any local air pollution control agency having jurisdiction.

§115.782(c)(3)

Sierra-Houston and Sierra-Lone Star supported §115.782(c)(3), which requires that shutdown list components must be monitored until they have been repaired.

The commission appreciates the support. However, as noted earlier in this preamble in the discussion about §115.353(2)(F), the commission deleted §115.353(2)(F) and §115.782(c)(3).

§115.782(d)

Dow, DuPont, ExxonMobil, OxyChem, TCC, and TxOGA expressed similar concerns regarding §115.782(d) as they expressed regarding §115.352(2)(E) and §115.781(b)(4). ATOFINA commented that the proposed §115.782(d)(2) requires that if an attempt to repair a component during a unit shutdown is unsuccessful, the unit shall be shut back down and the component repaired or replaced. ATOFINA stated that in a perfect world, all components can be repaired or replaced the first time, but that experience suggests otherwise as newly installed components sometimes leak upon start-up of a unit. ATOFINA stated that as a result, even if reasonable efforts are made to repair/replace leaking components, it can reasonably be expected that a small percentage may still leak and that requiring a unit to shutdown again to repair/replace a single component will result in excess and unnecessary emissions and is counterproductive to the goals of the proposed rules. ATOFINA recommended the removal of this requirement. BCCA-AG, Dow, DuPont, ExxonMobil, and Lyondell expressed similar concerns. BCCA-AG and Lyondell stated that the commission could require documentation of best-faith efforts to repair the component to guard against components being placed on the DOR list indefinitely, and that at the very least, the commission should allow components to remain on the DOR list despite one unsuccessful repair during shutdown.

Because the emissions from the shutdown would far outweigh the emissions from the leaking component, the commission has deleted §115.782(d)(2). Similarly, the commission has reevaluated §115.782(d)(1) and deleted it due to concerns about the reasonableness of the proposed requirement for monitoring one day after startup. Because the remaining language in §115.782(d) is redundant with §115.781(b)(4), the commission has deleted §115.782(d).

Limit on the number of components on a shutdown list

§115.782(e)

ExxonMobil and TxOGA commented on §115.782(e) and stated that term "non-repairable" is misleading in that these components are not unable to be repaired, but only require access or methods that cannot be provided without shutdown. Dow and TCC suggested that the HON definition (40 CFR §63.161) of "non-repairable" be used as follows: "technically infeasible to repair a piece of equipment from which a leak has been detected without a process unit shutdown." Dow also suggested that automatic control valves be added to the exceptions in §115.782(e) to be consistent with §115.782(c)(2).

The commission agrees that a definition of "non-repairable" would be useful. However, as described later in this section of the preamble in response to comments on §115.782(e)(3), the commission has deleted §115.782(e) in its entirety.

§115.782(e)(1)

Dow, ExxonMobil, TCC, and TxOGA stated that replacement should not be mandated because repair may still be a viable option.

The commission agrees that many components can be repaired rather than replaced. However, as described later in this section of the preamble in response to comments on §115.782(e)(3), the commission has deleted §115.782(e) in its entirety.

Dow, ExxonMobil, TCC, and TxOGA stated that the four-year limit of §115.782(e)(1) should be deleted for the reasons given in their comments on §115.782(c)(1)(B)(ii).

The commission agrees with the commenters. However, as described later in this section of the preamble in response to comments on §115.782(e)(3), the commission has deleted §115.782(e) in its entirety.

§115.782(e)(2)

ATOFINA, BCCA-AG, Dow, DuPont, Lyondell, TCC, and TxOGA commented on §115.782(e)(2), which limits the percentage of non-repairable leaking components at each unit. ATOFINA stated that placing a limit on the number of components on a shutdown list has the potential to actually increase emissions. ATOFINA stated that an emissions increase can occur if the majority of leaking components placed on a shutdown list are insignificant leakers, because the required shutdown would take place well before the emission reductions from repairing the components approach the emissions resulting from a unit shutdown. ATOFINA, BCCA-AG, Dow, and Lyondell suggested that unit shutdowns be based upon mass emission rates only, as determined by the use of EPA correlation equations. Dow, DuPont, and TCC stated that a major chemical manufacturing plant could have over 10,000 components and that the 25 component threshold is biased against complex operations. Dow, DuPont, and TCC recommended deletion of the wording "or 25 components, whichever is less," and that all facilities use a percentage.

As described later in this section of the preamble in response to comments on §115.782(e)(3), the commission has deleted §115.782(e) in its entirety. Therefore, the commenters' concerns are moot.

§115.782(e)(3)

Dow, EnRUD, ExxonMobil, TCC, and TxOGA commented on the proposed §115.782(e)(3). EnRUD suggested that as an alternative for Subchapter D, Division 3, the rule could instead specify that the correlation equations are used to estimate emissions if one "extraordinary effort at repair" is made, but that bagging must be used to estimate emissions if no "extraordinary effort at repair" is made. ExxonMobil and TxOGA asserted that the emission limit values in §115.782(e)(3) have been reduced by a factor of ten from Bay Area Air Quality Management District (BAAQMD) Regulation 8, Rule 18, without any justification given. TCC expressed similar concerns and recommended deletion of the limits. EnRUD suggested that as an alternative, the rule could instead require two "extraordinary efforts at repair," with bagging required to estimate emissions for all components put on the shutdown list or delay or repair, and seven days allowed to repair each component having a mass emission rate greater than 15 pounds per day. ExxonMobil and TxOGA stated that no rule should set an individual or cumulative emission caps for DORs that would cause more emission from shutdown and startup than the repairs would reduce. ExxonMobil and TxOGA also stated that the percentage calculations can only apply to existing units with at least four quarters of data, and that new units would have to be calculated based on initial data until additional quarters are past. Dow and TCC suggested specifying that the correlation equations are used to estimate emissions, rather than bagging within seven days to estimate mass emissions. Dow also recommended changing the 15 pounds per day leak rate limit and seven calendar day repair time limit in §115.782(e)(3)(C) to a concentration limit (e.g. 10,000 ppmv). Dow further suggested moving the requirement in §115.782(e)(3)(C) to §115.782(b).

The commission has reevaluated §115.782(e) and believes that the "extraordinary effort" requirements specified in §115.782(c)(2) will largely eliminate the need for limitations on the number of non-repairable components specified in §115.782(e). Because most leaking components are valves and, based on recent information concerning a refinery in HGA which demonstrated that the vast majority of those valves can be repaired through "extraordinary efforts," the commission has deleted §115.782(e).

EQUIPMENT STANDARDS

HRVOC Fugitive Emissions

§115.783

BP and TCC stated that the commission should set performance standards rather than equipment standards. In particular, BP stated that the commission should reconsider the proposed equipment standards for process drains, flanges, heat exchanger heads, sight glasses, etc.

The commission has revised many of the proposed equipment standards in the fugitive monitoring rules in response to comments, as described elsewhere in this preamble. In general, a performance standard for equipment leak sources, such as pumps and valves, is not feasible. For example, even though compressor seals can be equipped to release emissions into a closed-vent system, measurement of these emissions is impractical, although the rules include a performance standard for the control device to which the closed-vent system conveys emissions. Except for those components for which standards can be set at a specific concentration, the only method of measuring emissions is total enclosure of individual components, collection of emissions for a specified time period, and measurement of the emissions. This procedure, known as bagging, is a time-consuming and prohibitively expensive technique considering the great number of individual components in a typical process unit. In addition, this procedure would not be useful for routine monitoring and identification of leaking components for repair. The adopted fugitive monitoring rules primarily include standards intended to result in the repair of leaks in a timely manner.

§115.783(2)

Dow recommended that the recovery and control device efficiency requirements in the proposed new §115.783(2) be consistent with HON Subpart H, 40 CFR §63.172(b) - (e), which requires a 95% control efficiency (or to 20 ppmv) for recovery or recapture devices (e.g., condensers and absorbers) and enclosed combustion devices.

MACT standards, such as the HON, are not adequate to provide reductions for ozone strategy. Specifically, the MACT standards are based on the need to reduce exposure to HAPs, while Chapter 115's purpose is to reduce emissions which contribute to ozone formation. Because the purposes of the rules are so different, there is no reason they should necessarily have the same thresholds or exemptions. The commission has retained the requirement in §115.783(2)(C) for 98% control efficiency (or to 20 ppmv).

§115.783(3)

DuPont, ExxonMobil, and Rohm & Haas disagreed with the requirement in §115.783(3) that each PRV be equipped with a rupture disk and a pressure sensing device. DuPont and Rohm & Haas stated that these systems can present a safety hazard. Rohm & Haas stated that industry has been moving away from such systems. Rohm & Haas stated that although current fugitive monitoring rules allow such equipped PRVs to be exempt from monitoring, in many cases, they would rather monitor such PRVs rather than install rupture disks. An individual suggested that PRVs which discharge to closed-vent systems should be exempt from the requirement of having a rupture disk installed in their inlets. The individual stated that many of the air quality management districts in California specifically state that relief valves that discharge to a closed-vent system are not required to have rupture disks installed on their inlets. The individual also stated that rupture disk installation in a closed-vent system will be very difficult because, even though the rupture disk itself is small, it needs a special holder for proper operation, which will result in having to modify the piping to accommodate the changed dimensions. In addition, the individual stated that the capacity of relief valves used in combination with a rupture disk must either be derated or the combination must be tested to determine its capacity as required by Section VIII of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code. The individual stated that in a few cases, a larger relief valve would be required to obtain the required capacity for safe operation, requiring even more modifications to existing piping and possible replacement of the nozzle of the original pressure vessel. The individual asserted that little, if anything, is to be gained by installing a rupture disk upstream of the relief valve because the discharge from these relief valves eventually goes to a control device, such as a flare. TCC expressed similar concerns as the individual. DuPont suggested that rupture disks be used on new valve systems (when a safety analysis has been performed to confirm adequacy of the design of the rest of the system). ExxonMobil and TxOGA stated that clarification is needed that rupture disks are required on relief devices venting to atmosphere only, not relieving to a control device. TxOGA recommended adding "not routed to a control device" after "Each pressure relief valve."

The commission agrees that rupture disks are unnecessary on PRVs which vent to a closed- vent system and has revised §115.783(3) by adding "in gaseous HRVOC service that vents to atmosphere" after "Each pressure relief valve." The commission also agrees that rupture disks should not be mandated due to possible safety concerns, but that PRVs with rupture disks should be equipped with a pressure sensing device between the PRV and the rupture disk to monitor disk integrity. The commission has revised §115.783(3) accordingly.

TCC suggested that §115.783(3) be revised to allow 30 days for replacement of failed rupture disks, rather than five days. TCC stated that 30 days for repair is reasonable because the rupture disk is coupled with a relief valve.

The commission agrees and has revised §115.783(3) accordingly.

§115.783(4) - Shaft sealing systems

ATOFINA, Dow, DuPont, and TCC commented on proposed §115.783(4), which requires that all pumps, agitators, and compressors be equipped with shaft sealing systems prior to December 31, 2005. ATOFINA stated that proposed §115.783(4), which requires that all pumps, agitators, and compressors be equipped with shaft sealing systems prior to December 31, 2005, should be changed to allow an exemption to be submitted to the executive director for approval. ATOFINA recommended that an exemption be allowed if, after an economic review is completed, it is determined that the cost of upgrading is not justified. ATOFINA stated that historically, the emissions from many of these components have been very low, and expressed concern that the emission reductions achieved would not justify the cost of implementing this requirement. DuPont and TCC stated that shaft sealing systems are not technically feasible for some older equipment and that the proposed requirement could impact hundreds of pumps at a typical site. DuPont recommended restricting the shaft sealing system requirements to new equipment. Dow stated that §115.783(4)(A)(ii) should mention vapor recovery systems in addition to control devices, and stated that the terms in §115.10 seem to make a distinction between "vapor control system" and "vapor recovery system." Dow also stated that §115.783(4)(A)(iii) should mention specifically gas barrier seals as an acceptable pressurized sealing method or clarify that the term "fluid" means gas or liquid.

The commission agrees that some older equipment may be difficult or impossible to retrofit, and therefore believes that it would be appropriate to limit the shaft sealing system requirements to new equipment. In order to give affected owners and operators time to plan for incorporating shaft sealing systems in the design of new equipment, the commission revised §115.787(b) to exempt pumps, agitators, and compressors installed before July 1, 2003 from the shaft sealing requirements of §115.783(4). In response to Dow's comments, the commission notes that "vapor recovery system" and "vapor control system" are synonymous in Chapter 115, as noted in the definition of these terms in §115.10. Whenever possible, however, the commission has been replacing "vapor recovery system" with the more appropriate term "vapor control system" in Chapter 115. The commission has clarified §115.783(4)(A)(iii) as suggested to clarify that gas barrier seals are an acceptable pressurized sealing method.

§115.783(4)(B)(iii)

TCC suggested that action on requests for approval of alternate shaft sealing systems should be taken by the executive director, and not by Engineering Services.

"Executive director" is defined in 30 TAC §3.2 as "the executive director of the commission, or any authorized individual designated to act for the executive director." The reference to the Engineering Services Team is necessary to clearly designate where within the agency requests for approval of alternate shaft sealing systems should be directed and who will review and respond to such requests. Therefore, the commission has made no change in response to the comment.

§115.783(5)(A)(i) - Water seals

Comments concerning water seal are addressed earlier in this preamble in the discussion concerning §115.142(1)(A).

§115.783(5)(A)(ii) - Process drain alarms/flow monitoring

Comments concerning alarms and flow monitoring devices for process drains are addressed later in this preamble in the discussion concerning §115.781(b)(5).

§115.783(6) - Upgrades of leaking valves at shutdown

ATOFINA, Dow, DuPont, ExxonMobil, TCC, and TxOGA commented on proposed §115.783(6), which requires that all leaking valves added to a shutdown list be replaced with either a bellows or diaphragm valve, or an alternative valve design approved by the executive director. ATOFINA strongly objected to proposed §115.783(6), and stated that site operators must be allowed to choose the valve type that best suits the service the equipment is in, taking into account several factors, including safety and service of the component. ATOFINA expressed a belief that by mandating a particular type of valve and approving alternatives, the commission is opening itself up to litigation in the event of catastrophic failure. In addition, ATOFINA expressed concern that the approval process may be delayed, resulting in the installation of a bellows or diaphragm valve in the wrong service, or installation of a valve that may not meet the approval of the executive director. ATOFINA suggested that the rule be changed to specify that the executive director or designated representative must review alternatives within 15 days or the alternative be automatically approved. DuPont stated that it does not support completely replacing valves due to age and historical leakage. DuPont and TCC stated that replacement of packing may be sufficient to prevent any further leakage for the life of the valve, and suggested use of the word "repaired" rather than "replaced" to discourage unnecessary replacement of equipment. ExxonMobil and TxOGA stated that only chronic leakers that are subject to requiring shutdown for repair should be reviewed for upgrade applicability, and that an alternative to allow for system modification to redesign the component should also be allowed. Dow stated that automatic control valves should be added to the exceptions in §115.783(6) to be consistent with §115.782(c)(2).

The commission agrees with the commenters that the proposed valve upgrades should not be mandated, and has deleted §115.783(6).

§115.783(6)(B)(i)

DuPont and TCC stated that the executive director should consider on a case-by-case basis the technological circumstances of a type of valve or a valve used in a particular service, and make that list available via guidance (not rule), as opposed to approving one individual valve for one particular entity.

As described earlier in this preamble, the commission has deleted §115.783(6).

§115.783(6)(B)(ii)

DuPont stated that it is unclear on how BACT would be set for valves that vary in weather conditions, type of chemical service, pressure of service, etc. DuPont stated that the phrase "after the application of best available control technology" should be deleted until further study can provide a more appropriate technical approach.

As described earlier in this preamble, the commission has deleted §115.783(6).

PREVENTION MEASURES PROCEDURES

HRVOC Fugitive Emissions

§115.784

Ethyl objected to the proposed preventive measures procedures, and asserted that they are overly prescriptive and apply a "one size fits all" prescription to any pressure safety valve (PSV) release. Ethyl stated that these regulations are best left to process safety management requirements regulated by the Occupational Safety and Health Administration (OSHA), and that these proposed regulations have not been critiqued by the Chemical Safety Board, American Institute for Chemical Engineers' Center for Process Safety, or any other group specializing in the development of process safety management standards or requirements. Ethyl expressed a belief that manpower and paperwork would be excessive, burdensome, and extremely costly as currently proposed, with little, if any, likelihood of reduction of pressure safety device venting for most facilities. Ethyl supported an incident investigation, identifying contributing factors, and taking appropriate procedural or control measures to reduce the likelihood of a repeat release from a pressure control device; however, Ethyl stated that appropriate solutions should take into account the magnitude and potential seriousness of the potential release. For example, the appropriate response, investigation, and remedial measures for a PSV release of a small amount of heavy oil or wastewater into a contained area from thermal expansion of contained liquid in a blocked in line should be treated differently from the release of a large quantity of highly flammable light organic compound into the atmosphere, which is the type of event the commission should be trying to focus on and minimize through these proposed regulations. Ethyl stated that the requirement for a second process hazard analyses following a PSV release in overly prescriptive, as a well-conducted incident investigation should be sufficient for most releases. Ethyl stated that the evaluation for routing a vent to a control device upon a second PSV release is overly prescriptive for most releases, in that it does not take into account the magnitude and severity of the release, or the time span between releases, which could be anywhere from five to 20 years. Ethyl stated that the commission should consider the magnitude, severity, and frequency of potential releases and develop a review/prevention strategy which takes those factors into account. Regarding the proposed definition for "process hazard analysis" (PHA), Solutia stated that OSHA also has a definition for PHA which can be found at 29 CFR §1910.119(c)(2), and that broadly speaking, OSHA's rules are intended as a systematic study of the entire process that finds where the process could fail in a way that results in catastrophic events. Solutia stated that a team of process experts and a methodology expert evaluate what, if any, additional safeguards are needed to prevent the event, but it is not designed to find the specific cause of a process failure. Solutia stated that incident investigations would be better suited to finding why a system or piece of equipment failed, or released material, in a specific incident, and requested that the commission revise the proposed rule language to allow the affected facility to investigate the incident, find the causes, and take corrective actions to prevent recurrence. In addition, Solutia suggested that the commission use another term such as "incident investigation." Solutia also cautioned the commission about trying to put into its rules terms and procedures that are not in its jurisdiction and commented that the commission's Title V program is on record as stating that it is not qualified to review a facility's risk management plan. Solutia suggested that the commission rules include broader, more generic, language that references these other areas which would let a facility's safety personnel better determine the methodology used. Dow, ExxonMobil, TCC, and TxOGA expressed similar concerns as those of Ethyl and Solutia. Dow also stated that definitions provided in §115.784(a) should be moved to §115.10.

The commission agrees that additional research is needed before prevention measures procedures should be adopted. Therefore, the commission is withdrawing the proposed §115.784 and is not adopting the following proposed rules which included references to §115.784: §115.786(c) and §115.789(6). In addition, the commission has deleted references to §115.784 in §§115.781(e), 115.788(e)(1) and (e)(1)(B), and 115.789(2).

INSPECTION REQUIREMENTS

Industrial Wastewater

§115.144(5)

Dow, DuPont, TCC, and TxOGA recommended that the requirement in §115.144(5) for daily inspection of water seals be changed to weekly. TCC and TxOGA stated that unless there is a design flaw, water seals should be no more likely to fail on a daily basis than other types of seal designs. Dow and TxOGA suggested an alternative, that the commission could request more frequent (daily) monitoring or an evaluation of seal design where a process drain is found to have habitual water seal failures.

The commission has revised the water seal inspection schedule in §115.144(5) from daily to weekly, except that daily inspections are required for those seals that have failed three or more inspections in any 12-month period.

§115.144(6)

Sierra-Houston, Sierra-Lone Star, and TxOGA supported the requirement in §115.144(6) that process drains not equipped with water seal controls must be inspected weekly to ensure that gaskets, caps, and/or plugs are in place and that there are no gaps, cracks, or other holes in these devices. TCC suggested monthly inspections.

The commission agrees that process drains not equipped with water seals controls are less likely to leak than process drains with water seals controls, such that a monthly inspection schedule appears adequate. Therefore, the commission has revised the inspection schedule in §115.144(6) from weekly to monthly.

Fugitive Emissions

§115.354

Sierra-Houston and Sierra-Lone Star supported the requirement in §115.354 that all component monitoring take place when the components are actually in service and not when they are in shutdown; §115.354(1) which requires an electronic data collection device that includes the time and date stamp so that monitoring cannot be done faster than Method 21 requires; and §115.354(12) which requires the actual monitored VOC concentrations be recorded instead of notations such as "not leaking."

The commission appreciates the support.

§115.354(3)

TxOGA stated that the weekly AVO inspection of flanges should be deleted. TxOGA stated that because connectors are being added to the definition of "component," the weekly AVO inspections should be deleted and instrument monitoring of the flanges should replace the weekly flange AVO inspection requirements. TxOGA stated that if instrument monitoring is not at least as effective as the AVO monitoring was, the new requirement should not be incorporated.

Rather than adding a requirement for instrument monitoring of flanges to §115.354 as suggested by TxOGA, the commission is instead revising §115.354(3) to exclude flanges that are monitored using Test Method 21 as required by §115.781(b)(3). This will ensure that new instrument monitoring requirements are not added to flanges which are not subject to Subchapter H, Division 3.

§115.354(9)

BCCA-AG, DuPont, EnRUD, ExxonMobil, Goodyear-Beaumont, Lyondell, TCC, and TxOGA commented on §115.354(9), which is intended to prevent owners and operators from monitoring components in units that are shut down, thereby inflating the count of components that are not leaking and lowering, on paper, the percentage of components that are leaking. EnRUD, ExxonMobil, and TxOGA stated that the language is unclear. BCCA-AG, DuPont, and Lyondell did not object to such a prohibition in concept, but stated that the proposed rule uses multiple terms to express the same idea. BCCA-AG, ExxonMobil, Goodyear-Beaumont, and Lyondell suggested that the rule would be clearer if the first two sentences of the proposed rule are retained, and the remainder of the paragraph removed. TCC suggested that the rule would be clearer if the first three sentences of the proposed rule are replaced with a sentence which states: "Components must be in contact with process fluids to be considered in the total component count." DuPont stated that various commission regional offices have stated that a material must be flowing in the line to be considered for monitoring, but that DuPont expressed the belief that it is unreasonable to check every line for flow prior to monitoring. DuPont stated that it monitors components without verifying active flow or residuals, and suggested that §115.354(9) be revised to require that monitoring be done when components are in contact with process material. TxOGA stated that §115.354(9) should only apply to units utilizing a skip- period for leak detection monitoring schedules.

The commission has deleted the last two sentences of the proposed §115.354(9) and has replaced the second sentence with a sentence which states: "If a unit is not operating during the required monitoring period but a component in that unit is in contact with process fluid which is circulating and/or under pressure, then that component is considered to be in service and is required to be monitored." The commission has also added TCC's suggested sentence. These changes express the intent more clearly.

§115.354(10)

TCC commented on §115.354(10) and stated that the commission should give operators a choice in determining whether paper or electronic data collection is best-suited for their plant. TCC stated that either approach can provide accurate results and similarly, neither approach is without possibility of error.

Because §115.354(10)(B) provides the flexibility to use paper logs where necessary or more feasible, the commission has made no change in response to the comment.

§115.354(10)(A)

BCCA-AG, Dow, EnRUD, ExxonMobil, Goodyear-Beaumont, Lyondell, TCC, and TxOGA commented on the proposed §115.354(10)(A), which includes language that invalidates data that was not collected in accordance with Test Method 21. BCCA-AG, Dow, Goodyear-Beaumont, Lyondell, and TCC stated that it is not clear whether all monitoring results must be reviewed by someone other than the technician, what criteria are to be used in determining how quickly Test Method 21 can be followed, exactly what data must be invalidated, etc. EnRUD, ExxonMobil, Goodyear-Beaumont, and TxOGA stated that the language is ambiguous, with TxOGA suggesting that §115.354(10)(A) be deleted. EnRUD suggested that a benchmark time be set. BCCA-AG and Lyondell stated that because data discrepancies must be dealt with on a case-by-case basis, it would be better to address the problem in guidance. DuPont stated that there is an opportunity for interpretation in assessing Test Method 21. For example, DuPont considers that if the initial datalogger reading is 50% of the leak definition, then monitoring time must not be less than two times the instrument response rate. Dow recommended adding the following language to §115.354(10)(A): "The acceptable rate for recording data shall be determined individually by each company considering such factors including, but not limited to, the size of the equipment, the equipment type, the accessibility of the equipment, the number of leakers being found, the skill of the monitoring technicians, etc. Each company shall have a documented auditing process in place to identify response time failures and assess pace anomalies."

Because the commission can take enforcement action against owners or operators as necessary for failure to correctly follow the requirements of Test Method 21, it has deleted the second sentence of §115.354(10)(A). The second sentence of Dow's suggested language provides a reasonable way to guard against monitoring technicians's collection of data in a way that is contrary to Test Method 21, and has revised §115.354(10)(A) accordingly. The commission has also revised §115.354(10)(A) to clarify that the collected monitoring data include the identification of each component and each calibration run, the maximum screening concentration detected, the time of monitoring (beginning and end), a date stamp, an operator identification, an instrument identification, and calibration gas concentrations and certification dates.

§115.354(10)(B)

Air Products commented on the proposed §115.354(10)(B) and requested that the commission provide guidance on the meaning of "small rounds" as used in the context of the use of paper logs. TxOGA suggested that the last sentence be deleted for the reasons noted in its comments on §115.354(3) for AVO inspections.

Small rounds refers to the monitoring of fewer than 100 components. The commission has revised §115.354(10)(B) accordingly, and has also revised §115.354(10)(B) to include a reference to the information required in §115.354(10)(A).

§115.354(10)(C)

BCCA-AG, Dow, DuPont, EnRUD, ExxonMobil, Goodyear-Beaumont, Lyondell, OxyChem, TCC, and TxOGA commented on the proposed §115.354(10)(C), which prohibits changes to monitoring data that has been transferred from a datalogger to the facility's database. BCCA-AG, Dow, DuPont, ExxonMobil, Goodyear-Beaumont, Lyondell, OxyChem, TCC, and TxOGA stated that this provision is too broad because quality assurance reviews may disclose potential problems with data in the facility's database. DuPont stated that changes may be necessary if the monitoring technician entered the wrong date, operator identification, analyzer identification, etc. BCCA-AG, Dow, DuPont, EnRUD, ExxonMobil, Goodyear-Beaumont, Lyondell, OxyChem, TCC, and TxOGA stated that changes to databases should be allowed if justified and properly documented. Dow, DuPont, and EnRUD suggested that such documentation could include the name of the person who made the change and an explanation to support the change.

The commission agrees that in some situations, it may be necessary to correct information in the database. Therefore, the commission has replaced the proposed language in §115.354(10)(C) with language which requires documentation of each change.

§115.354(11) and §115.781(b)(10) - Response Factors

Goodyear-Beaumont stated that the response factor multiplier (RFM) is defined as actual concentration divided by measured concentration, and the relative response factor (RRF), which is the inverse of the corresponding RFM. However, Goodyear-Beaumont indicated that it is unfamiliar with the term relative response factor multiplier used in the proposed §115.354(11) and §115.781(b)(10), and suggested that this term be defined in §115.10.

Air Products stated that the requirements in §115.354(11) and §115.781(b)(10) for "response factors" are unnecessary and would add a significant burden with no corresponding benefit. Air Products referenced the background information document for the hazardous organic NESHAPS in which EPA indicated that response factors were not intended to be used to adjust screening in LDAR programs and will not reduce emissions from an LDAR program. Air Products suggested a compromise to adopt the response factor criteria in EPA Test Method 21 and make the use of response factors voluntary for process streams whose average response factor is less than ten. EnRUD stated that although no other LDAR regulation in the United States requires a response factor adjustment, it can be done once process stream specific response factors are developed.

Goodyear-Beaumont stated that several problems arise regarding the use of RFMs and RRFs. Specifically, Goodyear-Beaumont stated that RFMs and RRFs are available for only a relatively small number of chemicals out of the thousands of VOCs in process lines across Texas. Goodyear-Beaumont also stated that RFMs and RRFs vary with measured concentration, detector lamp energy and detector type (i.e., flame ionization detector vs. photoionization detector). Goodyear-Beaumont further stated that components are often in contact with mixtures, and it is difficult to calculate the composite RFM or RRF for each component, especially since so few chemicals have available response factors. Goodyear-Beaumont stated that complex hydrocarbon mixtures in contact with a component may vary over a manufacturing cycle, particularly for batch operations.

BCCA-AG, Dow, ExxonMobil, Lyondell, and TxOGA stated that response factors are a function of both compounds and concentration and that determination of a response factor for a component cannot reasonably be made prior to monitoring. BCCA-AG, ExxonMobil, Lyondell, and TxOGA stated that response factors are commonly used to adjust emission data for more accurate emissions estimates, not for real time monitoring, and that modification of data management programs to include component-specific response factors with monitoring runs would require extensive program modifications for little benefit. As an alternative, BCCA-AG and Lyondell recommended that the facility set and report a conservative response factor for the entire unit, or for certain delineated sections of units, and apply that factor. DuPont expressed similar concerns and recommended clarifying that response factors should be developed based on the annual average composition for the process fluid because many process components see compositional variability by design (e.g., hazardous waste incinerators). Dow and DuPont recommended only correcting measured concentrations for components where the annual average response factor is greater than 3.0 at the applicable leak definition. DuPont also stated that if the commission continues efforts to obtain more accurate EI data and retains the requirement to correct measured concentrations when the response factor is greater than one, then correcting measured concentrations with a response factor less than one should also be required to accurately reflect fugitive emissions.

Dow and TCC stated that Section 8.1.1 of Test Method 21 requires that a response factor be determined "for each compound that is to be measured, either by testing or from reference sources." Dow and TCC stated that §115.354(11) should provide that response factor criteria in Section in 8.1.1.2 of Test Method 21 shall be for the average composition of the process fluid not each individual VOC in the stream. Dow and TCC stated that for process streams that contain nitrogen, water, air, or other inerts which are not organic HAPs or VOCs, the average stream response factor may be calculated on an inert-free basis, and that the response factor may be determined at any concentration for which monitoring for leaks will be conducted. Dow and TCC recommended that language from 40 CFR §63.180(b)(2) of HON Subpart H be added to §115.354(11).

Dow and TCC further stated that EPA's "Protocol for Equipment Leak Emission Estimates" (November 1995) recommends adjusting the screening value if the compound (or mixture) has a response factor greater than three. Dow and TCC stated that this EPA document provides a procedure for evaluating whether a response factor adjustment should be made, and that one of the steps in this procedure states: "If the RF's at both actual concentrations are below 3, it is not necessary to adjust the screening values. If either of the RF's are greater than 3, then the EPA recommends an RF be applied for those screening values for which the RF exceeds 3." Dow and TCC stated that if the commission decides to retain the requirement to correct measured concentrations if the response factor is greater than 1.0, then correcting measured concentrations if the relative response factor is less than or equal to 1.0 should also be required. Dow and TCC stated that ethylene and propylene, for example, have a response factor less than 1.0, which, in effect implies emissions may be currently overestimated from these components.

Goodyear-Beaumont stated that if the objective is to use more accurate VOC concentrations to compare to a leak definition, then the application of both RFMs greater than 1.0 and less than 1.0 is appropriate, but that if the objective is to reduce emissions, then a simple reduction in the leak definition is the appropriate approach, rather than response factors. Finally, Goodyear-Beaumont stated that if the objective is generate more accurate EI data, as suggested by the rule proposal preamble, then the EI rules in 30 TAC §101.10 and/or EI guidance documents should be revised.

After further evaluation, the commission concluded that issues associated with response factors are complex. Therefore, the commission has deleted §115.354(11) and §115.781(b)(10) and has renumbered subsequent paragraphs accordingly. The commission notes that the current §115.352(1) allows calibration by propane or hexane, which can modify the screening concentration that was used in the correlation equations, although methane is the industry standard calibration gas. Therefore, the commission has revised §115.352(1) to delete the propane and hexane options in conjunction with the removal of the use of a response factor adjustment. The commission also deleted the compliance schedule in §115.359(4) and §115.789(9) for the newly deleted §115.354(11) and §115.781(b)(10).

§115.354(12) and §115.781(b)(11) - Pegged Components

BCCA-AG, Dow, DuPont, ExxonMobil, Lyondell, OxyChem, TCC, and TxOGA commented on the proposed requirement to record a default value of 500,000 ppmv for any monitor reading that is higher than the upper end of the monitor scale. BCCA-AG, ExxonMobil, Lyondell, TCC, and TxOGA stated that this value is "arbitrarily high" and may artificially increase emissions estimates, resulting in premature shutdowns. BCCA-AG, ExxonMobil, Lyondell, OxyChem, TCC, and TxOGA recommended that the default pegged value should be the maximum detectable value of the instrument, with consideration given to a dilution probe reading when available. DuPont and TCC recommended that the default pegged value should be 100,000 ppmv because most monitoring instruments only span to 100,000 ppmv, not 500,000 ppmv. Dow stated that consistent with EPA's "Protocol for Equipment Leak Emission Estimates" (November 1995), the 10,000 and 100,000 ppmv "pegged" emissions rates (in lb/hr per source or kilograms/hr per source) in Tables 2-13 and 2-14 should be used instead of recording a default pegged value of 500,000 ppmv. Dow stated that this would allow develop a more accurate emissions inventory.

After further evaluation, the commission concluded that a pegged component default of 100,000 ppmv is appropriate and has revised §115.354(12) and §115.781(b)(11) accordingly.

§115.354(13)

Dow, Goodyear-Beaumont, and TxOGA commented on §115.354(13), which specifies that exemptions for valves with a nominal size of two inches or less expired on July 31, 1992. Goodyear- Beaumont stated that it was granted a permit on August 31, 1993 that included an exemption for valves with a nominal size of two inches or less. TxOGA stated that §115.354(13) should be deleted, while Dow stated that valves nominally 0.5 inches and smaller, and connectors nominally 0.75 inches and smaller in diameter, should be exempted because these components are exempted from the HON through the definition of "instrumentation system" in 40 CFR §63.161.

The permit provisions in a new source review permit do not represent an exhaustive list of all requirements that may apply, and a permit provision cannot authorize noncompliance with a commission rule. In effect, each rule or permit stands on its own. Thus, compliance with the permit provisions does not necessarily represent full compliance with all applicable rules. It is the responsibility of the owner or operator to ensure compliance with all applicable permits and rules. As noted in the preamble, new §115.354(13) is necessary due to the continued misconception that such an exemption is available in Chapter 115 for ozone nonattainment areas, despite the fact that the rule change which eliminated the exemption was adopted over 11 years ago. (See the July 2, 1991 issue of the Texas Register (16 TexReg 3722 - 3724)). Goodyear-Beaumont's comment is a clear indication that §115.354(13) is needed, and that as new source review permits are amended, modified, or renewed, industry and the commission should work together to remove obsolete permit provisions such as the one which is apparently in Goodyear-Beaumont's permit. In addition, the exemption for valves with a nominal size of two inches or less was removed from the Chapter 115 fugitive monitoring rules applicable in ozone nonattainment areas in response to a federal requirement to remove the exemption. EPA required removal of the exemption because it was inconsistent with RACT requirements in that no exemption for valves with a nominal size of two inches or less is allowed under EPA's RACT requirements for fugitive monitoring. The fact that the HON includes an exemption for small valves in instrumentation systems does not relieve the commission of the separate federal requirement to ensure that the Chapter 115 rules represent RACT. However, it is possible to consider an exemption for connectors in instrumentation systems because connectors other than flanges are not included in the federal RACT requirements for fugitive emissions.

MONITORING REQUIREMENTS

Chevron supported the commission's focus on HRVOC monitoring as a means to control ozone spikes. One individual supported VOC monitoring and stated that the proposed changes to vent gas monitoring are appropriate.

The commission appreciates the support.

EPA commented that for cooling towers, flares, and fugitives, the proposed rules significantly enhance the monitoring and recordkeeping provisions to improve the inputs to the modeling analysis. EPA stated that the commission should also consider revising the monitoring and recordkeeping requirements for the general VOC rules to try and better capture hourly, daily, and weekly emissions and the resulting fluctuations in emission rates. EPA commented that improved general VOC emission rate information could be used in future SIP modeling demonstrations. EPA further commented that the proposed HRVOC recordkeeping and reporting requirements should attempt to obtain the highest temporal resolution on emission rates, and that where the data collected makes it possible to calculate hourly and daily emission rates, these rates should be calculated and reported to the commission for ozone season days. EPA stated that averaging of emissions over time does not improve the resolution of the data, and should not be done in the reporting of emissions.

As noted earlier in this preamble, the commission is implementing a site-wide HRVOC emissions cap. The commission agrees that the HRVOC recordkeeping and reporting requirements should attempt to obtain the highest temporal resolution on emission rates, and that where the data collected makes it possible to calculate hourly and daily emission rates, these rates should be calculated and reported to the commission for ozone season days. The site-wide cap requires that each site stay below its 24-hour rolling average HRVOC emission cap, with appropriate documentation to demonstrate continuous compliance. Concerning the general VOC rules for flares and cooling towers, the commission agrees that improved emission rate information could be used in future SIP modeling demonstrations. However, as noted earlier in this preamble, the commission has withdrawn the proposed Subchapter B, Divisions 7 and 8.

EPA Test Method 21

Sierra-Lone Star stated that one major drawback in the proposed revisions is the VOC equipment monitoring limitations of EPA's Test Method 21 utilizing a calibrated organic vapor analyzer (OVA) that is being used routinely and widely for fugitive leak detection in HGA, and asserted that the commission has not acknowledged the detection limitations in the new rules. Sierra-Lone Star stated that Test Method 21 is limited to the detection of fugitive VOC leaks that are readily accessible to the analyzer's sensor of a few inches at most, but other fugitive VOC leaks that are completely hidden within the equipment and process units will not be sensed or measured by the OVA detectors. Sierra- Lone Star stated that the current state-of-the-art analytical technique required by federal and state regulations in fugitive leak detection is the OVA known in the EPA regulations as Test Method 21. Sierra-Lone Star stated that the OVA's serious detection limitation, and Test Method 21 as well, is that it is a hand-held device that senses leaking hydrocarbon vapors at only a single measurement point. Sierra-Lone Star stated that in order to traverse wide plant areas with an OVA or FID instrument, it is necessary to manually sweep it over those areas, a labor intensive and time consuming process, and basically which is unable to see leaking hydrocarbons beyond a few inches at best in sprawling plants with an immense expanse of process units vertically and horizontally. Sierra-Lone Star supported the use of Test Method 21 as appropriate and effective for finding the smaller range of fugitive VOC leaks on hundreds of thousands of pieces of equipment items where direct OVA monitoring access is readily available, but stated that the major monitoring drawback is that many larger fugitive VOC leaks (especially concentrations above 10,000 ppm to beyond 100,000 ppm and up to 300,000 - 500,000 ppm and higher) are going undetected and uncorrected due to Test Method 21's inherent sensing limitations. Sierra-Lone Star stated that a prime factor in this Test Method 21 problem is because HGA's industrial chemical, petrochemical, and refining plants contain thousands of miles of heavily insulated piping and thousands of pieces of heavily insulated equipment that are leaking unknown concentrations and volumes of VOCs, serious leaks which are not addressed in the proposed rules. Sierra-Lone Star provided references to several experimental and commercial infrared and CO ₂ laser VOC imaging technologies that may be useful in the monitoring of VOC leaks, which included the Sandia Laboratories laser backscatter absorption gas imaging video gas leak visualization, the Pacific Advanced Technology electro-optical systems using their patented technology Image Multi-spectral sensing, and the Gas Imaging Systems laser VOC video imaging technology. In one example, Sierra-Lone Star stated that field testing of an experimental infrared laser imaging monitor quickly and easily identified a large benzene leak in excess of 100,000 ppm when aimed from ground level at a series of large heat exchangers, while not surprisingly, the large benzene leak was initially missed by persons using the Test Method 21. Sierra-Lone Star recommended that the commission adopt a requirement to implement fugitive VOC monitoring with some type of portable laser imaging system, preferably infrared, CO ₂ , or similar system, to be used in all the industrial plants to evaluate them for large fugitive VOC leaks occurring under the insulation.

The commission agrees that Test Method 21 has certain limitations. The commission is aware of the CO ₂ laser imaging technology. However, this emerging technology also has limitations. For example, it is tuned to respond to a specific compound (e.g., ethylene), must have the appropriate background, and is not yet as portable as a Test Method 21 OVA. The commission will continue to follow the development of the CO2 laser imaging technology.

General VOC Flares

§115.173

ED indicated support for the quantification of mass material entering flares in §115.173. However, ED requested clarification regarding whether it is the commission's intent to quantify the mass material via measurement or calculation.

As noted earlier in this preamble, the commission has withdrawn the proposed general VOC rules for flares in Subchapter B, Division 7. Therefore, no changes have been made in response to the comments.

General VOC Cooling Tower Heat Exchange Systems

§115.182

EPA stated that the elements of the quality assurance plan should be made more clear so that the commission review and approval can be considered a replicable procedure and thus the sampling plans would not require EPA approval. In particular, EPA commented that the rule should explain the minimum leak the system must be able to detect, and that this evaluation should be part of the sampling plan. EPA further commented that the rule should specify the minimum frequency for auditing the monitoring equipment as well as the test methods used for auditing the monitors.

The commission has withdrawn the general VOC rules for cooling towers in Subchapter B, Division 8. Similar comments made by EPA for the HRVOC rules in Subchapter H are addressed below.

HRVOC Flares

Ethyl stated that there are no exceptions to the proposed HRVOC rules based on limited use and limited emissions of HRVOCs and that a source is subject to the proposed rules if it has the potential to emit certain compounds, in contrast to a rule based on actual or estimated emissions. As an example, Ethyl stated that its Houston plant uses formaldehyde and trimethylbenzenes in the production of certain products and that tank vents and process vents that may have small quantities of these components are routed to a flare to minimize atmospheric emissions and reduce potential personnel exposures to these chemicals. Ethyl stated that the total permitted VOC emissions from the flare are 0.21 lb/hr and 0.93 tpy, and that actual emissions of the proposed HRVOCs would be less than 10% of the VOCs, which is significantly less than the permitted annual amounts. Ethyl stated that the proposed continuous emission monitoring requirements for sources with relatively small emissions of HRVOCs will result in no benefit to the environment and no significant improvement in the quality of HRVOC data.

The commission has revised the exemption provisions in §115.727 to exempt from the site-wide cap any account for which no gas stream that is routed to a flare contains 5.0% or greater by weight of HRVOC at any time and no vent gas stream that is not routed to a flare contains more than 100 ppmv HRVOC at any time. If a gas stream cannot meet either of these exemption criteria, an internal emissions management plan needs to be developed to properly control the stream.

§115.744

EPA commented that it can approve a provision providing for the executive director to approve minor modifications to test methods, but not to approve alternative methods. EPA commented that the rules themselves should contain a replicable procedure for the evaluation of alternative test methods, or else, alternative methods must be approved through a SIP revision process. EPA further stated that the proposed rule does not contain a replicable procedure for evaluation of alternative test methods.

In response to the comment, the commission added EPA Test Method 301, which provides for a comparison of any two given methods, as §115.725(d)(8) and §115.766(3). This will provide flexibility while also ensuring federal approvability.

Solutia commented that its flares handling hydrogen cyanide, which may also contain propylene, an HRVOC, cannot meet the flow monitoring, sampling, and speciation requirements of the proposed general VOC or HRVOC rules because of safety concerns. In addition, nitriles present in the stream form polymers that could plug up the sampling system. Solutia stated that it has demonstrated compliance with 40 CFR §60.18 using acceptable alternative methods to determine gas velocity, and that it adds natural gas to ensure the heating value requirements are met. Solutia further commented that the hydrogen cyanide MACT standard recognizes these safety concerns, and allows alternate methods to demonstrate compliance with the flare standards. Solutia recommended that an exemption be added to the rules for "unsafe-to-monitor" flares.

Flow monitoring in this situation could be adequately performed using ultrasonic flow monitors. The provisions of §115.725(d)(8), which allow a company to submit minor modifications to the specified monitoring methods for approval by the Engineering Services Team, provide flexibility in the use of a monitoring method. This exemption is not appropriate because the determination of "unsafe-to-monitor" flares is very difficult given the extreme variability in materials handled, flaring conditions, and other factors.

BCCA-AG, Goodyear, and Lyondell stated that the proposed revision requiring VOC sampling every four hours and the continuous HRVOC monitoring requirement should be replaced by flare- specific monitoring plans. BCCA-AG, Goodyear, and Lyondell recommended that the frequency of speciated VOC sampling be tied to the significance of the emissions from the particular flare operation. For example, the presumptive sampling frequency for flares handling normal process, maintenance clearing, and emergency flows could be: daily (> 25 tpy emissions), weekly (ten 25 tpy emissions), and monthly (< ten tpy emissions), with additional sampling for defined flaring events. The sampling for flares only in emergency service should be limited to flaring events. BCCA-AG, Goodyear, and Lyondell stated that these presumptive frequencies could be evaluated, and departed from when appropriate, as part of individual EMPs.

The commission has withdrawn the proposed general VOC requirements for flares in Subchapter B, Division 7. Section 115.725(d)(2) requires that HRVOC and other substituents be sampled on the main flare header every 15 minutes. The requirement under §115.725(d)(4) to determine the HRVOC concentration in the flare header gas every four hours applies only during periods when the on-line analyzer is down. The commission believes that the monitoring frequency specified in the rule is necessary because of the potentially large emissions of HRVOC from flaring operations.

BCCA-AG, Goodyear, and Lyondell disagreed with the rule proposal which uniformly requires the installation of continuous flow monitors on each flare, regardless of its specific characteristics and uses. BCCA-AG and Lyondell recommended that companies be required to include as part of their EMPs a monitoring plan detailing collection of appropriate flow data. BCCA-AG and Lyondell stated that a comprehensive and tailored monitoring plan must address speciation and flow together in order to be effective. Depending on the flare, however, the appropriate means could be a continuous flow monitor, a flow-level indicator, an on-off flow indicator or another type of monitoring device.

Because of the potentially high flow rates of gas streams being routed to a flare, it is important that accurate flow data be collected to determine compliance under the rule. Section 115.725(d)(8) allows minor modifications to the specified monitoring methods upon approval by the agency's Engineering Services Team.

BCCA-AG, Goodyear-Houston, and Lyondell commented that the HRVOC rule for flares should provide flexibility for monitoring the heating value. BCCA-AG and Lyondell stated that the commission had provided no technical justification supporting the use of an on-line analyzer as the only acceptable means of monitoring flare gas heating value in all cases. BCCA-AG and Lyondell further commented that the commission should separate into two provisions the different objectives of: 1) monitoring to assure heating value maintenance and 2) monitoring to understand VOC composition in the flare gas for emission inventory purposes.

The primary purpose of the rules is to assure compliance with the HRVOC site-wide cap. Flexibility for monitoring the heating value is provided by §115.725(d)(8), which allows minor modifications to the specified monitoring methods upon approval by the agency's Engineering Services Team. One possible example of such an alternative method for determining heating value is the calorimeter.

BCCA-AG, Dow, Goodyear-Houston, and Lyondell commented that the rules for VOC and HRVOC flares should not specify the location of monitoring devices or sampling locations. BCCA-AG and Lyondell further stated that measurement location is a site-specific engineering decision that is inappropriate for specification by rule. Instead, sampling and monitoring locations should be included in flare-specific EMPs and approved by the commission as long as they capture flow with reasonable accuracy.

Section 115.725(d)(8) allows minor modifications to the location of monitoring devices or sampling locations upon approval by the agency's Engineering Services Team. The commission supports the use of flare-specific EMPs, submitted to the agency for review and approval under §115.726, as a means of ensuring compliance with the site-wide cap.

BCCA-AG and Lyondell commented that the monitoring requirements for VOC and HRVOC flares should better account for safety considerations, recommending that each rule provide that sampling not be required for any flare event that: 1) is the a result of a catastrophic event, including a major fire or an explosion at the facility, or 2) constitutes a safety hazard to the sampling personnel at the sampling location approved in a flare monitoring plan, provided that a sample is collected at an alternative safe location.

This situation is properly handled under enforcement discretion. Under §115.725(d)(8), an affected company may submit a request for an alternative sampling location for approval by the agency.

As an alternative to the monitoring provisions in the proposed rule for HRVOC flares, BCCA- AG and Lyondell recommended that each owner or operator of a flare in HRVOC service be required to prepare and implement an EMP to establish a technically achievable short-term limit suitable for the specific flare application. DuPont suggested that the commission consider requesting sites to develop and implement an analytical plan that is representative of the materials that could go to the flare, and have the plan available for review during inspection.

The commission supports the use of flare-specific EMPs, submitted to the agency for review and approval under §115.726, as a means of ensuring compliance with the rule's monitoring requirements. Minor modifications to the monitoring requirements are allowed under the rule.

TCC commented that in §115.744, relating to Monitoring Requirements, continuous flare flow monitoring may be appropriate if the commission provides the necessary practical considerations related to calibration, analytical techniques, etc. TCC encouraged the commission to consider alternatives to continuous VOC speciation, stating that it unnecessarily complicates the analyzer and makes maintenance of these devices more difficult when a large number of components are present in very small quantities. DuPont commented that the commission has done little to investigate the consequences of the requirements, including the multiple train analytical instruments, the facilities that would have to be built to house such analytical instruments, the methods to be used, and the personnel to conduct maintenance to keep field instrumentation functioning.

The commission has provided sufficient detail in the rule concerning calibration, analytical techniques, and other criteria that are necessary to properly perform continuous HRVOC monitoring. Samples must be collected for speciation every 15 minutes. The commission believes that this sampling frequency is necessary because of the potentially high HRVOC emissions from flares. The commission is aware of the possible complexities of designing and operating monitoring systems required by the rule, but at the same time believes that the requirements are technically feasible. The commission has added §115.725(c), which exempts flares used solely for abatement of emissions from loading operations for transport vessels from the rule's monitoring requirements, and instead allows the emissions to be calculated using heating value data from a calorimeter and certain recorded parameters. The commission believes that this alternative approach is appropriate for flares in dedicated service. However, such flares are still subject to recordkeeping requirements to document exempt status.

TCC commented that continuous monitoring of exit velocity and net heating value as required in §115.744 would be costly with little environmental benefit, and recommended that language be added to the section allowing periodic monitoring of these parameters.

All flares subject to the HRVOC rule must comply with 40 CFR §60.18 when vent gas containing VOC is being routed to the flare. This ensures that the flare is operated under proper operating conditions with regard to exit velocity and net heating value of the gas stream(s) routed to the flare.

EPA commented that the rule requires monitoring using a flow monitoring device meeting the accuracy requirements of 40 CFR Part 60, Appendix A, Method 2D, and that the rule also calls for annual calibration. EPA stated that Method 2D is one of many test methods developed by the EPA for stack testing. It provides a reference method of measuring a flow rate during a unit performance test. EPA stated that the method was not designed to be a method for continuous monitoring. In fact, one use of Method 2D is to confirm the relative accuracy of continuous flow monitors. Method 2D calls for the use of a flow monitoring device which has been previously calibrated to read flow rates within 5% of the true value. Therefore, EPA stated, it would be more appropriate to say that the flow measuring device will be accurate within ±5% over the full range of expected operation. The accuracy of the flow measuring device will be confirmed on an annual basis using Method 2D. The first accuracy test should be conducted no later than 60 days after installation of the monitoring device. This comment also applies to proposed §115.744. TCC commented that although §115.744 requires monitoring of mass flow rate, Method 2D specified in this provision is applicable to volumetric flow rates. TCC recommended deletion of references to Method 2D in this section.

The rule as proposed did not require that facilities perform an EPA Method 2D test; rather, it stated that the monitor should meet the accuracy specifications of EPA Method 2D. The rule has been revised to make this requirement clearer by specifically citing the accuracy specification from EPA Method 2D. However, the commission disagrees with EPA's comment that the flow monitor should be accurate to ±5% over the full range of expected operation. Such a requirement could be extremely difficult for instrument manufacturers and facilities to prove at the very low end of the expected operation. With regard to EPA's comment on performing accuracy tests with Method 2D on the flow monitors installed on flare headers, while relative accuracy test audits (RATA) are an important part of verifying monitor accuracy, performing such a test on a flare header will be problematic at flow rates that are typical of normal flare operation. Additionally, a comparative flow rate RATA test on a flare header will be burdensome on industy. The accuracy specifications selected for the flow monitors are equivalent to Method 2D. The commission has deleted references to 2D in response to the comments. Notwithstanding, volumetric flow rate is necessary to determine mass flow.

TCC and Valero commented on the flow monitoring requirements in §115.744, stating that the commission should recognize that variations in flow composition can lead to inaccuracies in flow measurements, as most flow measurement devices are accurate only within a specified range.

The commission realizes that some inaccuracy is inherent in any measurement device, but must also emphasize the importance of establishing accuracy requirements for data collection. Section 115.725(d)(1) includes the following accuracy specifications: flow monitor, ±5.0%; temperature gauge, ±2.0% at absolute temperature; and pressure gauge, ±5.0 mm mercury.

TCC commented that the commission should consider alternative methods to obtain VOC data on a periodic basis in lieu of continuous monitors. The proposed requirement to continuously monitor and speciate HRVOCs will require multiple GCs to adequately separate and quantify the various constituents. Each GC could cost as much as $100,000 simply for the analyzer. This cost could increase to over $300,000 when analyzer housing, piping, and the like are considered. Alternative methods should be explored which could provide the desired information at reduced cost.

The commission disagrees with the cost estimate of $100,000 for a single GC. Considering that other acceptable options are much less expensive, this scenario is unlikely. Depending on the number and type of detectors, other advanced features, and the requirements dictated by the particular stream, information available to the commission indicates that $20,000 to $30,000 would be a typical cost. Some streams may be able to use a single column/detector system, such as a gas chromatograph/thermal conductivity (GC/TCD).

TCC commented that use of Method 18, as indicated in 40 CFR Part 50, Appendix 1, is focused on grab sample analysis and is not appropriate for continuous, on-line analysis. TCC also stated that the detector specified by Method 18 would easily malfunction due to saturation expected during a significant flaring event. TCC recommended that the term "continuous" should be deleted from this section and that Method 18 should be reserved for periodic monitoring.

The commission disagrees that Method 18 is focused on grab sample types of analyses; this method can be used on-line. Section 8.2.2 in Method 18, which addresses direct interface type analyses, could be used for an on-line GC system. Although Method 18 is geared more toward an emission test run and not continuous operation, this method can be carried out for the latter procedure. Most of Method 18 and American Society for Testing and Materials (ASTM) D1946 would not be applicable. To give the plant more flexibility, methodology has not been specified. With regard to saturation, companies should take this effect into account when designing their monitoring plan. If the detector malfunctions because of a large "dump," §115.725(4) requires that grab samples be taken every four hours during monitor downtime.

TCC commented that the commission should clarify why it proposes monitoring for inorganic constituents in a rule directed at HRVOC control, stating that CO and CO ₂ are not significant constituents in most flare headers. TCC commented that mandatory carbon oxides analysis would require either addition of either an infrared analyzer or a methanator to allow GC analysis, and that this is an additional expense which does not contribute to the overall goals of this proposal.

The commission disagrees that a GC would require an infrared analyzer or methanator (also referred to as "methanizer"). A GC with a thermal conductivity detector (TCD) is commonly used to measure CO, CO ₂ , and many other compounds. In fact, the TCD is the detector used in the GC analysis under ASTM D1946, the required method for CO and hydrogen measurement in 40 CFR §60.18. The primary reason for analyzing for CO and CO2 , as well as other inerts like nitrogen, is to obtain an accurate molecular weight of the stream. Most of the flow measurement instruments that would typically be used are dependent on the molecular weight of the stream. Additionally, CO and hydrogen add Btu content to the stream, and disregarding them would require more supplemental fuel than actually needed.

ED stated that the commission should clarify that §115.744 requires monitoring of both HRVOCs and general VOCs on a speciated basis.

The monitoring requirements for flares, which have been relocated to §115.725, specify that only the HRVOC hourly average mass emission rate must be calculated for determining compliance with the site-wide cap. However, as a practical matter, all VOCs are speciated by the on-line analyzer, but only the HRVOCs are required to be reported.

HRVOC Cooling Tower Heat Exchange Systems

TCC commented that the commission can obtain improved data for compliance, emissions inventory and SIP modeling purposes for CTHES in HRVOC service without requiring multiple continuous HRVOC monitors that are costly to install and to maintain. TCC and Goodyear-Houston commented that periodic sampling and analysis coupled with enhanced CTHES EMPs should be allowed as appropriate to meet these data needs. BCCA-AG and Lyondell stated that the proposed monitoring requirements are "exceedingly onerous" and exceed what is reasonably necessary to improve the emissions inventory and ensure compliance with applicable requirements. BCCA-AG and Lyondell stated that the proposed monitoring does not provide significantly more useful data than can be obtained by frequent sampling. BCCA-AG and Lyondell recommended the monitoring requirements be replaced with EMPs tailored to each unique operation, which take into account its physical characteristics, service, and emissions. BCCA-AG, Lyondell, and TxOGA commented that quality assurance plans for HRVOC cooling towers should not be submitted to the commission for approval, but instead, each VOC cooling tower system should be covered by an EMP maintained on- site and available for inspection. These EMPs would detail normal monitoring requirements, as well as appropriate responses to the detection of leaks found in cooling tower systems, and include the information contemplated by the commission in quality assurance plans.

The commission partially agrees with the commenters and has revised the monitoring requirements for cooling towers. Continuous flow monitoring is required for all affected cooling towers. For cooling water heat exchange systems with a design capacity to circulate 8,000 gpm or greater of cooling water, a continuous monitoring system to determine the total strippable VOC concentration is required at each inlet of each cooling tower. For cooling water heat exchange systems with a design capacity to circulate less than 8,000 gpm of cooling water, the total strippable VOC concentration is obtained by collecting grab samples from each inlet of each cooling tower at least twice per week, with an interval of not less than 48 hours between samples. In addition, speciation for HRVOC must be performed monthly. The rule sets the trigger level for more frequent HRVOC speciation at 50 ppbw total strippable VOC. When this level is triggered, an additional sample must be collected for strippable VOC analysis from each inlet of the affected cooling tower at least once daily, and this speciated sampling must continue on a daily basis until the concentration of total strippable VOC drops below 50 ppbw. The commission encourages EMPs that incorporate best operating practices and ensure compliance, and believes that the revisions to the rules provide sufficient flexibility while ensuring that leaks are detected and repaired in a timely manner.

TCC commented that continuous on-line samplers and GC analyzers are often not the best method for determining leaks in water systems (including cooling towers). To support this comment, TCC cited a 1992 study which concluded that the performance of continuous on-line VOC monitors on ppb-level VOCs in actual waste streams was unsatisfactory for the use of this data for compliance purposes. TCC and Lyondell recommended periodic instead of continuous monitoring, as follows: monitoring requirements for CTHESs in HRVOC service should be separated between that for: 1) emissions inventory purposes, and 2) for leaks that have been detected by an appropriate surrogate means. Monitoring for EI purposes should include monthly grab samples from a point in the CTHES system that would allow for appropriate estimation of emissions from the CTHES. Monitoring for leak detection purposes should be done at least three times per week using appropriate surrogate methods to provide for leak detection. Once a leak has been confirmed, specific grab sampling for speciated HRVOC analysis is appropriate.

The revised monitoring requirements for cooling towers described in the response to the previous comment provide additional flexibility in monitoring, as requested by the commenter. However, continuous monitoring for total strippable VOC is still needed to detect leaks as soon as they occur. Some surrogates may not be accurate enough for the level of accuracy needed. However, alternative methods may be submitted to the Engineering Services Team for review and approval.

TCC commented that if the commission decides to require the proposed monitoring in the final rule, VOC speciation should be limited to HRVOCs by definition for each CTHES (and other constituents as may be required by permit requirements). TCC further stated that it is impractical to analyze for each and every VOC compound that has the potential to be leaking to the CTHES, and that it is also unnecessary and burdensome to require complete speciation of every potential VOC compound that could be in the CTHES at the frequency proposed. Ethyl stated that it supports a de minimis quantity concentration for speciation of HRVOCs and VOCs for monitoring under the proposed rules.

The previously described revisions to the cooling tower rule address the concerns stated in the comment. Each monitoring system (continuous flow monitor, and continuous on-line analyzer or grab samples twice per week) must be operated at least 95% of the time when the cooling tower is operational, averaged over a calendar year. Total strippable VOC must be routinely monitored (either continuously or twice per week, depending on circulation rate with relation to 8,000 gpm), and HRVOC speciation must be performed monthly. The frequency of HRVOC speciation is increased to once daily when a 50 ppbw concentration of total strippable VOC is reached, and daily HRVOC speciation must continue until the total strippable VOC concentration falls below 50 ppbw. For each sample, the speciated concentration of at least 90% of the total VOC must be determined on a mass basis.

Goodyear-Houston commented that the ten ppbw minimum detection requirement is unrealistic, especially for a cooling tower system with a high circulation rate. DuPont commented that it is unrealistic to assume that the same ten ppbw minimum detection limit could be achieved for all HRVOC in a sample. Likewise, the selection of the actual method should be based on the material in a heat exchanger, not the individual components.

The commission disagrees, and believes that a detection level of ten ppbw is readily achievable, using commonly available flow monitors, over the range of cooling water flow rates expected to be encountered in affected cooling towers. Section 115.766 now requires that the total strippable VOC, not HRVOC, concentration be determined with a ten ppbw minimum detection limit. In addition, the rule allows alternative monitoring and testing methods to be approved by the Engineering Services Team.

TCC commented that if the commission decides to require the proposed monitoring in the final rule, the requirement for grab sampling during VOC monitor out-of-order periods as detailed in §115.764(1), relating to Monitoring Requirements, should be modified to daily.

The monitoring provisions in §115.764(a)(2) add the requirement that during periods when the VOC monitor(s) are out of order a sample must be collected for total VOC analysis according to the commission air-stripping method (Appendix P, TCEQ Sampling Procedures Manual, December 2002). This sample must be collected at least three times per calendar week, with an interval of no less than 36 hours between samples.

TCC suggested the addition of "skip provisions" for the periodic sampling requirements of §115.764(1) for each CTHES that has demonstrated good historical performance (no leak periods). TCC recommended that such sampling be reduced from: 1) monthly to quarterly after six months of monthly sampling that indicates no leaks into the CTHES, and 2) from quarterly to annually quarterly after 12 months of monthly/quarterly sampling that indicates no leaks into the CTHES. TCC stated that the inclusion of such "skip provisions" in the rule will provide incentives to good performers.

For cooling tower heat exchange systems, leak-skip monitoring is not allowed because there are not enough of these units present for the statistics of skip monitoring to apply. In addition, leaks from these units are not particularly predictable and might operate with low-leak rates for long periods of time and then fail instantaneously with sudden increases in leak rates. Consequently, no matter how many consecutive successful inspections are performed, there is little assurance that a low-leak rate would continue if skipping were allowed.

TCC commented that submittal for approval of the CTHES EMPs should be required no sooner than 180 days after promulgation of the rule, and that the submitted CTHES EMP should receive automatic approval by the executive director if approval or disapproval of the EMP is not issued within 30 days after submittal.

The commission encourages EMPs that incorporate best operating practices and ensure compliance with the rules. Section 115.764(d) specifies the schedule for submittal of monitoring quality assurance plans for approval by the agency. For cooling towers existing on or before June 30, 2004, plans must be submitted no later than April 30, 2004, and for cooling tower heat exchange systems that become subject to the requirements of the division after June 30, 2004, at least 60 days prior to being placed in HRVOC service. In addition, the plan must define each compound which could potentially leak through the heat exchanger, and therefore directly impact the emissions of the cooling water system.

§115.766(2)

Similar to its comment on §115.184(1), EPA stated that the El Paso stripping method for compliance, required by this rule, is not a federally-approved method. However, EPA stated that the method may have advantages for sampling high volatility compounds, and requested that a copy of the specific procedure be included as part of the SIP revision, and that available information on the precision and accuracy of the method be provided to facilitate the EPA's evaluation.

Commission staff are currently refining this method, and plan to submit the final document to EPA in early 2003, but independent of the submittal of this SIP revision. Since the rules require compliance with the site-wide cap by April 1, 2006, EPA should have adequate time to review and approve this method.

§115.766(4)

EPA stated that the elements of the quality assurance plan should be made more clear so that the commission review and approval can be considered a replicable procedure and thus the sampling plans would not require EPA approval.

The Engineering Services Team is developing a sampling/monitoring plan guidance document for both flares and cooling towers. This guidance is expected to be available shortly after the effective date of the adopted rules.

EPA stated that the rule should explain the minimum leak the system must be able to detect. If, for example, the system must detect a leak of one lb/hr, the facility may have to locate the sampling point further up stream at the inlet and outlet of an individual heat exchanger or group of heat exchangers so that the flow will be small enough that a leak can be detected by the test method. EPA commented that this evaluation should be part of the sampling plan.

The commission has amended the HRVOC rule for cooling towers by eliminating individual unit emission limits and requiring compliance with a site-wide cap. Therefore, it is more appropriate to specify minimum leak criteria in terms of concentration rather than the mass emission rate. The commission has revised the monitoring requirements for cooling towers in §115.764(a)(5) and (b)(5) to require that if the concentration of total strippable VOC is equal to or greater than 50 ppbw, an additional sample must be collected for strippable VOC analysis from each inlet of the affected cooling tower at least once daily. The additional speciated strippable VOC sampling must continue on a daily basis until the concentration of total strippable VOC drops below 50 ppbw. Since the rule specifies the minimum detectable concentration at ten ppbw, the rule requirement ensures that speciation is triggered at 50 ppbw, a reasonable concentration above ten ppbw. The actual lb/hr figure that corresponds to either the ten ppbw or 50 ppbw concentration thresholds will depend on the flow rate of circulation water in the cooling tower.

EPA commented that the rule should provide the minimum frequency that the monitoring equipment will be audited and the test methods that will be used for auditing the monitors. EPA stated that with the addition to the rule of a leak detection threshold and audit frequency and methods, the EPA can consider the quality assurance plan evaluation a replicable procedure that does not require individual SIP revisions.

Section 115.766 specifies the minimum leak that the VOC monitor must be able to detect on a concentration basis: ten ppbw in the cooling water. The commission considers a concentration- based value to be an appropriate and achievable detection requirement that does not unfairly bias monitoring expense and technology requirements against high volume cooling towers in favor of smaller cooling towers.

An agency sampling/monitoring plan guidance document which specifies the elements of the plan will be available for industry shortly after the effective date of the rule adoption. The adopted regulations address minimum calibration frequency requirements for monitoring equipment; however, RATAs would be inappropriate and unnecessarily burdensome on industry. An audit of a cooling tower monitoring system could only be scheduled and performed after a leak of sufficient magnitude was detected if meaningful results in such a comparison are to be obtained.

BCCA-AG, Goodyear, and Lyondell commented that the proposed rules requiring continuous flow monitoring for both general VOC and HRVOC cooling towers should be changed to allow the use of design flow rate (via pump curves or a similar technical analysis method).

In principle, certain parameters could be used as surrogates for continuous flow monitoring of cooling tower circulation water. However, caution must be applied in assuming that such surrogates are representative and reliable and remain that way, particularly when compared to a readily available, relatively inexpensive conventional flow monitor. For example, pump curves can deteriorate over time, and the design flow rate may not be representative of actual operating conditions. The rule allows alternative monitoring methods to be approved by the Engineering Services Team. Any alternative monitoring approach must meet the agency's predictive emissions monitoring system protocol and must have an accuracy of ±5%.

Ethyl suggested that some type of criteria, such as vapor pressure or boiling point, be used to exclude heavier complex molecules from the requirements of speciation. Ethyl stated that technology does not exist to readily identify heavy complex molecules on a continuous basis at a practical cost.

The commission has revised the monitoring requirements of §115.764 so that speciation is no longer required on a continuous basis. High-molecular weight compounds would not be expected to be emitted in significant quantities. However, the concern over heavy complex components should be addressed by the rule's requirement that only require 90% of total VOC be speciated on a mass basis. In addition, approval of alternative methods is allowed under the rule.

HRVOC Fugitive Emissions

§115.781(b)(5) and §115.783(5)(A)

BCCA-AG, DuPont, ExxonMobil, Lyondell, Phillips, TCC, and TxOGA stated that the requirement for instrumentation on process drains is technically infeasible. BCCA-AG, Dow, DuPont, Lyondell, Phillips, TCC, and TxOGA suggested that the requirement for daily inspections of process drains with water seals should be changed to weekly. Phillips stated that this is adequate to control leaks from these sources without level alarms. ExxonMobil stated that a required periodic inspection program is adequate to control leaks from these sources without level alarms. For those seals that have failed three inspections in any 12-month period, BCCA-AG, Lyondell, and TxOGA suggested that daily inspections are appropriate, and TxOGA suggested an alternative would be to require a compliance study. ExxonMobil stated that it presumes that if the water seal is at the proper working level, it is effective.

The commission has revised the water seal inspection schedule in §115.781(b)(5) from daily to weekly, except that daily inspections are required for those seals that have failed three or more inspections in any 12-month period. In addition, the commission has revised §115.783(5)(A)(ii) such that an alarm or flow-monitoring system is an alternative to the weekly water seal inspections. Regarding the ExxonMobil comment, the commission agrees that if the water seal is at the proper working level, it should be effective in preventing a free-flow of emissions.

Dow and TCC stated that §115.781(b)(5) should only apply to sources subject to Subchapter B, Division 4 (Industrial Wastewater).

The commission disagrees. Numerous process drains are not subject to Subchapter B, Division 4, yet the process drains could emit HRVOCs uncontrolled under TCC's proposal.

§115.781(b)(6)

ExxonMobil and TxOGA stated that weekly inspections of process drains not equipped with water seals controls are appropriate, while Dow and TCC suggested monthly inspections.

The commission agrees that process drains not equipped with water seals controls are less likely to leak than process drains with water seals controls, such that a monthly inspection schedule appears adequate. Therefore, the commission has revised the inspection schedule in §115.781(b)(6) from weekly to monthly.

§115.781(b)(7)

Sierra-Houston and Sierra-Lone Star supported monitoring twice during the third quarter when leaks occur more frequently. ATOFINA stated that it contracts outside vendors to implement and maintain a fugitive monitoring program, and that in choosing the vendors, it performs extensive reviews to ensure that they have adequate and qualified personnel. ATOFINA stated that it invests significant time and resources to ensure each technician understands and can work within its work order system, and that these technicians are granted access to the most sensitive areas of ATOFINA's facilities. ATOFINA stated that as a result, each technician must undergo an extensive security review prior to entering ATOFINA process units. ATOFINA stated that since the September 11, 2001 terrorist attacks, industry has been on high alert for anything out of the ordinary, but that even with these security procedures in place, seeing a new face in process areas can create unnecessary concern. ATOFINA expressed concern that requiring two monitoring rounds during the third quarter would be redundant and jeopardize the quality of the technical staff available, and to implement this proposed requirement, fugitive monitoring companies will need to hire and train additional technicians to monitor for the third quarter. However, after the two monitoring rounds are conducted in the third quarter, ATOFINA stated that it will be forced to lay the excess staff off, which could lead to the creation of a less qualified "temporary fugitive monitoring team" every third quarter and that these unqualified and inexperienced technicians may not operate as efficiently and may place themselves and other personnel in dangerous situations. ATOFINA suggested that the commission remove this requirement. Likewise, EnRUD and Phillips stated that drastic manpower fluctuations resulting from redundant third-quarter fugitive monitoring and re-monitoring required after unit startup are impractical and not expected to produce significant emission reductions. EnRUD suggested that as an alternative, a performance-based extra monitoring program or an NSPS-type monitoring program. BCCA-AG, Dow, DuPont, ExxonMobil, Goodyear-Houston, Lyondell, TCC, and TxOGA expressed similar concerns as ATOFINA and Phillips. Dow, ExxonMobil, and TxOGA suggested limiting additional quarterly monitoring to remonitoring of all DOR components, all components determined to be leaking above 500 ppmv during the last 12 months, and all components which are categorized as "repeat leakers," or components which have leaked more than one quarter in the last two-year period.

The commission agrees with the commenters that an additional round of monitoring during the third quarter presents staffing difficulties and has deleted the proposed §115.781(b)(7).

§115.781(b)(8)

ATOFINA, BCCA-AG, Dow, DuPont, ExxonMobil, Lyondell, Sierra-Houston, Sierra-Lone Star, TCC, and TxOGA commented on the proposed §115.781(b)(8), which requires quarterly monitoring of PRVs in gaseous service and not vented to a closed-vent system. Sierra-Houston and Sierra-Lone Star supported monitoring each PRV every quarter regardless of accessibility and stated that it is time to change piping configurations so that all components are accessible. ATOFINA expressed concern that the proposed rule requires that components that are currently listed as "unsafe" or "difficult" to monitor, be monitored quarterly. ATOFINA agreed that extra steps can and should be made to monitor "difficult" to monitor components, but stated that components that are listed as "unsafe" to monitor should remain on an annual schedule. ATOFINA stated that monitoring these components puts their fugitive technicians in hazardous situations and that by requiring that they be monitored quarterly, quadruples the risk to which the technicians will be exposed. ATOFINA questioned whether the risk of injury outweighs the amount of potential emission reductions that can be achieved by more frequent monitoring. BCCA-AG and Lyondell stated that an exemption for difficult- to-monitor PRVs is routinely included in federal and state LDAR regulations because they are necessary for safe operations. BCCA-AG, Dow, DuPont, ExxonMobil, Lyondell, TCC, and TxOGA asserted that the emissions benefits are far outweighed by safety issues associated with monitoring difficult-to-access PRVs, which usually are elevated. DuPont suggested the addition of wording such as "unless they have been documented to be unsafe-to-monitor or inaccessible." ExxonMobil stated that monitoring of difficult-to-monitor PRVs should remain on an annual basis. Dow suggested that the quarterly monitoring requirement in §115.354(2)(D) and §115.781(b)(8) be replaced using language from HON Subpart H, 40 CFR §63.165.

The commission agrees that difficult-to-monitor PRVs should be monitored annually, as is currently required under §115.354(1)(B), and has revised §115.781(b)(8) accordingly. Similarly, the commission believes that components which are unsafe-to-monitor should be on an alternate monitoring schedule, and therefore has added a new §115.781(b)(7). The commission has included a provision in §115.781(b)(7) which specifies that components which are difficult-to-monitor (i.e., cannot be inspected without elevating the inspecting personnel more than two meters above a permanent support surface) may instead be monitored annually. No changes were made to §115.354(2)(D) because it was not proposed for revision.

BCCA-AG, ExxonMobil, Lyondell, and TxOGA asserted that for difficult-to-access PRVs, owners and operators should have the option of verifying the integrity of the rupture disk quarterly via a gauge reading or visual inspection.

Verification of the rupture disk integrity using a pressure sensing device (or equivalent device or system) between the PRV and the rupture disk would reasonably be expected to be an appropriate alternative to quarterly monitoring. Therefore, the commission has added §115.787(e) which provides this option.

ExxonMobil and TxOGA suggested that because most such PRVs are located in difficult-to- access locations, an alternative to conventional hydrocarbon gas analyzer procedures should be allowed, such as a sample line from the PRV outlet to grade with sufficient sample draw.

ExxonMobil and TxOGA did not provide sufficient details about their suggested alternative for the commission to be able to determine if it is an acceptable, equivalent method for monitoring a PRV. In addition, the existing RACT requirements of §115.354(2)(D) regarding quarterly PRV monitoring implement federal RACT requirements for fugitive monitoring and, as such, cannot be relaxed. Should ExxonMobil or TxOGA wish to pursue the matter further, the commission suggests that they present the issue to EPA and determine if EPA will agree to relax the federal RACT requirements.

Dow suggested that monitoring at the weep hole be specified as an acceptable way to check a PRV for leakage if the exhaust pipe is purged prior to monitoring.

The commission notes that Section 4.3.1.d. of Test Method 21 states: "The configuration of most pressure relief devices prevents sampling at the sealing seat interface. For those devices equipped with an enclosed extension, or horn, place the probe inlet at approximately the center of the exhaust area to the atmosphere." Test Method 21 does not appear to allow monitoring as Dow suggested, and therefore, the commission has made no change in response to this comment.

BCCA-AG, Dow, ExxonMobil, and Lyondell recommended that the requirement to equip each PRV with a rupture disk and pressure sensing device between the PRV and the rupture disk should be an exemption or option in lieu of quarterly monitoring of PRVs under §115.781(b)(8). BCCA- AG and Lyondell stated that a rupture disk and gauge monitoring effectively separates process fluid and the inlet of the PRV and prevents leaking. ExxonMobil expressed similar concerns.

The existing requirements of §115.354(2)(C) for quarterly monitoring of PRVs in gaseous service implement federal RACT requirements for fugitive monitoring and, as such, cannot be relaxed through the suggested exemption from §115.781(b)(8). Should the commenters wish to pursue the matter further, the commission suggests that they present the issue to EPA and determine if EPA will agree to relax the federal RACT requirements.

§115.781(b)(9)

EnRUD suggested that a leak definition of 100 ppmv would result in emission reductions. TCC recommended that pumps have a leak definition of 1,000 ppmv because that is consistent with the HON.

Components either leak, or they do not leak, such that lowering the leak definition from 500 ppmv to 100 ppmv is expected to have little effect. In other words, a component that monitors as a leaker using a 100 ppmv leak definition would probably be leaking at 500 ppmv or more. The HON's leak definition of 1,000 ppmv is based on the need to reduce exposure to HAPs, while Chapter 115's purpose is to reduce emissions which contribute to ozone formation. Because the purposes of the rules are so different, there is no reason they should necessarily have the same thresholds. Therefore, the commission has retained the 500 ppmv leak threshold for pumps.

§115.781(b)(10) and (11)

Comments concerning §115.781(b)(10) and (11) are addressed earlier in this preamble in the comments concerning §115.354(11) and (12).

§115.781(c)

DuPont, ExxonMobil, TCC, and TxOGA commented on proposed §115.781(c), which specifies that pumps, compressors, and agitators must be inspected weekly or equipped with an alarm that alerts operators of leaks. DuPont and TCC recommended that §115.781(c)(1) be revised to clarify that the weekly inspection is a visual inspection. DuPont, ExxonMobil, and TxOGA asserted that alarms are expensive and unnecessary, and DuPont recommended that §115.781(c)(2) be deleted. ExxonMobil and TxOGA commented that "indications of liquid dripping" is not consistent with other standards of seals leaking such as three drips per minute, and that many seal systems will show dark stains as normal weeping of lube oil. ExxonMobil and TxOGA stated that compressors and agitators in gas service will not show apparent leaks as drips.

The commission has revised §115.781(c)(1) to clarify that the weekly inspection is a visual inspection, and has deleted the wording "indications of." However, the commission has retained §115.781(c)(2) because it provides an alternative to weekly inspections.

§115.781(d)

Dow, ExxonMobil, TCC, and TxOGA commented on proposed §115.781(d), which specifies that for closed-vent systems containing bypass valves which are secured in the closed position with a car-seal or a lock-and-key type configuration, inspections of the seal or closure mechanism must be conducted on a weekly basis and after any maintenance activity that requires the seal to be broken. ExxonMobil and TxOGA supported this inspection requirement, while Dow and TCC suggested that the proposed weekly monitoring be changed to monthly for consistency with the HON.

The commission agrees with Dow and TCC that a monthly inspection is adequate, and has revised §115.781(d) accordingly.

§115.781(e)

Ethyl, ExxonMobil, and TxOGA objected to the §115.781(e) requirement for VOC monitoring of any PRV discharge within 24 hours. Ethyl stated that this is unreasonable for its operations in which almost all of the pressure relief devices already vent to the plant flare. Ethyl stated that emissions of the PRV discharge are already controlled to minimize emissions, and that the required monitoring would be impractical and could well present a significant safety hazard as well as increase VOC emissions to the atmosphere. Ethyl and TxOGA stated that this requirement should be limited to PRVs which are routed directly to the atmosphere and not to an existing control device. TCC recommended deletion of the reference to "release event." TxOGA also requested clarification that this monitoring is of the PRV "outlet," as opposed to the valve parts (stem, etc.).

The commission has revised §115.781(e) to specify that it applies to PRVs which vent directly to the atmosphere. In addition, the commission has deleted the reference to "release event" because this definition has been deleted. Concerning TxOGA's question about whether monitoring is of the PRV outlet, as opposed to the valve parts (stem, etc.), the commission notes that the purpose of monitoring any PRV discharge within 24 hours is to ensure that the valve reseated properly. Section 4.3.1.d. of Test Method 21 states: "The configuration of most pressure relief devices prevents sampling at the sealing seat interface. For those devices equipped with an enclosed extension, or horn, place the probe inlet at approximately the center of the exhaust area to the atmosphere." Therefore, PRV monitoring is done at the relief valve opening (horn), which TxOGA referred to as the "outlet."

ExxonMobil and TxOGA asked if "after actuation" refers to the beginning or the end of the release event.

A PRV is actuated when the pressure becomes high enough for the PRV to vent. Thus, "actuation" refers to when the PRV initially vents emissions, rather than when the PRV closes.

REPORTING REQUIREMENTS

General VOC Flares

BCCA-AG and Lyondell commented on the ambiguous wording of the provisions stating that reporting requirements apply and data must be submitted to the commission by April 30, 2003 "if a flare at an account has monitoring data for any speciated" VOC or HRVOC. BCCA-AG and Lyondell commented that the phrase "if a flare at an account has data" suggests that the reporting requirements apply by April 30, 2003 if an affected company has any speciated VOC data, even historical data, from any flare at an account. BCCA-AG and Lyondell stated that if the commission merely meant to require that any speciated VOC data routinely being collected should be submitted beginning with the first quarter of 2003, these provisions should be reworded to simply require that, but to delete any reference to applicability of the reporting requirements by April 30, 2003. BCCA-AG and Lyondell further commented that one compliance date should be used for all regulated entities, and that an early reporting obligation places an unfair burden on companies that may have installed such equipment for other reasons, even voluntarily. ED commented that extending the proposed sampling requirements for flares in HRVOC service to flares in general VOC service would not be overly burdensome, and that the sampling should be conducted at the same frequency. ED also suggested that at least 95% of the total VOC in a general VOC stream be speciated.

As noted earlier in this preamble, the commission has withdrawn the proposed general VOC rules for flares in Subchapter B, Division 7. Therefore, the commission has made no changes in response to the comments.

General VOC Flares and Cooling Towers

§§115.174, 115.183, 115.745, 115.765

Ethyl stated the 30-day reporting requirements under the proposed regulations are unduly burdensome for smaller specialty chemical plants with limited staffs and budgets, and recommended a 90-day reporting period. Ethyl commented that the commission's resources are too limited to process all of the newly-required data under the proposed regulations within a 30-day period. ED stated concern that the proposed quarterly reporting requirements in §115.174 are insufficient to accomplish the objectives outlined in the preamble, and suggested that the reporting requirements be amended and expanded to account for the temporal variability in the emissions from each flare instead of an average hourly emissions rate each quarter for each VOC.

EPA commented that the requirement for the quarterly reporting of the average hourly speciated VOC emission rate implies that facilities only have to report the average of all of the data for the quarter. EPA stated that hourly emissions based on much shorter averaging times could be estimated based on the sampling which is required twice per week, and recommended that the rules clarify the expectation so that the information for future modeling exercises will be as useful as possible.

As noted earlier in this preamble, the commission has withdrawn the proposed general VOC rules for flares and cooling towers in Subchapter B, Divisions 7 and 8. In addition, the monitoring, testing, recordkeeping, and reporting requirements for HRVOC flares and cooling towers have been revised for consistency with the site-wide HRVOC emissions cap. Therefore, the commission has made no changes in response to the comments.

HRVOC Flares

§115.745

TCC recommended that §115.745, relating to Reporting Requirements, be revised to allow semiannual reporting instead of quarterly reporting as proposed. TCC also commented that the term "average hourly emission rate" in §115.745 refers to the average of the hourly emissions for the reporting period.

The proposed quarterly reporting requirements have been removed and replaced by the recordkeeping requirements of §115.726. Therefore, the commenter's concerns are moot.

HRVOC Cooling Towers

§115.765(1)

TCC requested clarification on what is intended by the term "average-hourly HRVOC rate" in §115.765(1), and whether the requirement is specifically limited to known leak events. For clarity, TCC suggested that such reporting provisions be kept as part of the Chapter 101 rules. BCCA- AG and Lyondell disagreed with the proposed requirement for cooling towers to submit emissions monitoring reports on a quarterly basis, stating that it is an unnecessary paperwork burden on the regulated entity and the commission which provides the agency with no additional benefit. BCCA-AG and Lyondell suggested that if there is a concern at a particular facility or source, the commission should use its discretion to require more restrictive reporting on a case-by-case basis, where appropriate. Goodyear-Houston recommended annual reporting.

The commission has withdrawn §115.765, concerning Reporting Requirements. The recordkeeping requirements in §115.767 specify procedures for retention of records.

BCCA-AG and Lyondell commented on the ambiguous wording of the provisions stating that reporting requirements apply and data must be submitted to the commission by April 30, 2003 "if a cooling tower heat exchange system at an account has data that reflects chlorine usage amounts and/or monitoring data for any speciated" VOC or HRVOC. BCCA-AG and Lyondell commented that the phrase "if a cooling tower heat exchange system at an account has data" suggests that the reporting requirements apply by April 30, 2003 if an affected company has any speciated VOC data even historical data from any cooling tower system at an account. BCCA-AG and Lyondell stated that if the commission merely meant to require that any speciated VOC data routinely being collected should be submitted beginning with the first quarter of 2003, these provisions should be reworded to simply require that, but to delete any reference to applicability of the reporting requirements by April 30, 2003. BCCA-AG and Lyondell further commented that one compliance date should be used for all regulated entities, and that an early reporting obligation places an unfair burden on companies that may have installed such equipment for other reasons, even voluntarily.

The commission has deleted from §115.769 the requirement to submit speciated monitoring data.

Commenting on §115.765, Reporting Requirements, TCC stated that if the commission decides to retain the quarterly reporting requirement of HRVOCs from each CTHES, the provision should be modified so that if applies only to CTHES's in HRVOC service, and that reports be submitted to the executive director, not the Technical Analysis Division. TCC further commented that the reporting of hourly emissions from each CTHES in HRVOC service could be beneficial to the commission only during leak periods, and that reporting of this hourly information would be covered by the upset reporting provisions of the Chapter 101 rules. TCC stated that reporting hourly emissions is excessive and overly burdensome.

The commission has withdrawn proposed §115.765, so the reporting requirements have been deleted.

TCC commented that it is inappropriate to include the hourly usage of chlorine at a CTHES in the reporting requirements for HRVOCs from a CTHES. Although acknowledging that the contribution of gaseous chlorine emissions to ozone formation in the HGA airshed is not completely understood, TCC suggested that such data gathering efforts would be better accomplished through the annual air emissions inventory. TCC further commented that the commission should account for all sources of gaseous chlorine in the HGA airshed, not just those emitted by industry. TCC stated that total annual chlorine usage (which could be obtained from company purchasing information) rather than hourly usage should be acceptable for inventory purposes.

The commission has withdrawn proposed §117.745 pertaining to Reporting Requirements. The deleted reporting requirements include reporting for chlorine.

BCCA-AG, Lyondell, and TCC favored deletion of the proposed requirement for quarterly reporting of the total amount of chlorine introduced into each cooling tower system on an hourly basis. In their comment, BCCA-AG and Lyondell stated that all sources of gaseous chlorine (not just industrial cooling towers) need to be included in the evaluation, that the contribution of gaseous chlorine emissions from cooling towers is minimal (a cooling tower is normally operated with a 1.0 - 3.0 ppb level of residual chlorine), and that this proposed provision is inappropriate for Chapter 115, which addresses VOCs.

TCC commented that most large petrochemical sites are either already using a liquid chlorination agent such as bleach or are in the process of converting from gaseous chlorine to a liquid chlorination agent, and that the rule should clarify whether the term "chlorine" refers to gaseous chlorine only and/or to sodium hypochlorite or similar chlorination solutions. TCC questioned the basis for requesting "total chlorine" use, stating that if the commission intended such data to be used for leak determination then the parameter of residual chlorine in a CTHES may be of more interest and would be better addressed in the context of an EMP for the CTHES. TCC stated that it is not valid to assume that all gaseous chlorine added to a CTHES is emitted to the atmosphere, and that a "rule of thumb" for cooling towers along the Gulf Coast is that 2.0 lb/day of chlorine gas equivalent for every 1,000 gpm recirculation rate is used as the primary biocide for industrial cooling towers. TCC stated that it is generally accepted than an increase in chlorine demand to 5.0 lb/day for every 1,000 gpm recirculation rate indicates a leak of a process material that reacts with chlorine. TCC emphasized that chlorine demand over and above the minimum application of 2.0 lb/day gaseous chlorine equivalent does not volatilize from the cooling water into the air passing through the tower, but, rather, is reduced to chlorides and remains in the water phase.

The commission has withdrawn proposed §117.745 pertaining to Reporting Requirements. The deleted reporting requirements include reporting for chlorine.

TESTING REQUIREMENTS

Exemption from Testing - Vent Gas

Duke stated that there appears to be an inconsistency between the testing requirements for vent gas streams that are claimed to be exempt under §115.725(a)(1) and the exemption from control requirements under §115.727(c). Duke further stated that in accordance with §115.725(a)(1)(B), vent gas streams, for which testing has demonstrated that VOC emissions do not exceed the appropriate concentration thresholds, are not required to be tested to demonstrate that the VOC mass emission rate is below 14 pounds in any continuous 24-hour period. In addition, Duke stated that in accordance with §115.725(a)(1)(A) and (B), these vent gas streams are not subject to controls. Duke stated that the listed citations appear to conflict with the exemption under §115.727(c), because the exemption is only applicable if VOC emissions don't exceed the appropriate concentration thresholds and 14 pounds in any continuous 24-hour period. Finally, Duke stated that a similar situation exists with respect to §115.725(a)(1)(C) and §115.727(c).

The commission has revised §115.725 and §115.727 to ensure that the rules are consistent.

Dow suggested that §115.725(a) exempt from testing a vent gas stream that is already measured with a CEMS because a CEMS would provide a concentration value that is more accurate than that determined by a portable analyzer.

The commission agrees and has revised §115.725(b) to provide an alternative to testing for vents equipped with CEMS.

Rohm & Haas commented that §115.725 should consider the safety of sampling vent gas streams containing highly toxic substances, such as cyanide.

The unique situation described by the commenters can be taken into consideration as part of the test plan and quality assurance plan review specified in §115.726(a). Therefore, the commission has made no change in response to the comment.

Vent Gas

§115.725

HCPC supported the proposed §115.725 which addresses testing requirements for vent gas streams claiming to be exempt.

The commission appreciates the support.

Sierra-Lone Star supported the new rule as generally proposed, but expressed concerns about exemptions from other requirements for certain vent gas streams where the owner or operator seeks options for weaker pollution control standards. Sierra-Lone Star expressed concern because the rule states that only vent gas streams where the reference method testing determines that the mass emission rate exceeds a combined weight of VOC greater than 14 pounds in any continuous 24-hour period do not have to be directed to a control device. Sierra-Lone Star stated that the 14 pound limitation is too lenient.

As described earlier in this preamble, the commission has replaced the individual emission specifications with a site-wide HRVOC cap. The fundamental goal of this strategy is to ensure that the air quality in HGA is not compromised and, in fact, can be improved from what was demonstrated in the previous SIP. The vast wealth of real physical measurements of what emissions are in the ambient air in HGA provide the commission with a very sound basis for these rules. By limiting the amount of emissions allowed into the ambient atmosphere on a pound-per- hour basis, as opposed to determining how much has to be reduced, the commission believes it will achieve compliance much more effectively.

ATOFINA, BCCA-AG, and Lyondell suggested that the rule language be revised to allow a single performance test for equipment in similar service, e.g., to allow testing of one of ten pellet silos that all receive the same product, and using the results from the one performance test to demonstrate compliance with all ten.

The commission is concerned about the variability of such tests. A similar comment was received during the NO _x RACT rulemaking in 1993 in which a commenter stated that "many of the heaters at this facility have identical designs and firing rates (i.e. an ethylene unit has five identical furnaces that are all fired at the same rate). One stack test would suffice for identical furnaces." However, the commenter had six ethylene cracking furnaces in Unit 33 performance tested for permit compliance. Furnace No. 2 burns butane, Furnace No. 5 burns propane and ethane, and Furnace Nos. 1, 3, 4, and 6 burn propane. The furnaces are identical in all other respects, yet the testing showed a range of NO _x emissions from 0.053 lb NO _x /MMBtu for Furnace No. 6 to 0.078 lb NO _x /MMBtu for Furnace No. 2. This variability is large enough to warrant testing of each unit. Similar variability may occur if §115.725 was revised to allow a single performance test for equipment in similar service. Finally, because an agency representative will not be required to be present during testing, the commission also believes that all HRVOC vent gas streams should be tested. This requirement would minimize the chance of submitting only the best test results for one unit out of a group of identical equipment.

DuPont and TCC stated that §115.725(a) should be revised to specify that vent gas stream testing is a one-time event to demonstrate compliance with the exemptions, unless operating conditions change.

The referenced provision is not ambiguous with regard to the testing requirements, and therefore the commission has made no change in response to the comments. In addition, the commission notes that it has the right under 30 TAC §101.8 to require additional testing as necessary.

BCCA-AG, Dow, Lyondell, and TCC noted that proposed §115.725(a) provides that the required testing may be conducted with a "portable analyzer" and stated that the term "portable analyzer" is ambiguous. BCCA-AG, Dow, Lyondell, and TCC suggested that the rule language be revised to clarify that this term includes the type of hydrocarbon gas analyzers typically used for leak detection and repair monitoring.

As described earlier in this preamble, the commission has revised §115.725 to specify that reference method testing is required. This is necessary to ensure the accuracy of the data used in the HRVOC site-wide cap.

§115.725(a)(1)

Dow stated that §117.725(a)(1) should be revised to delete the reference to §115.727(b) because this rule requires reference method testing in order to qualify for the exemption. In addition, Dow stated that §117.725(a)(1)(A) and (B) should be revised to clarify the types of portable analyzers that are acceptable for use in testing.

Dow's suggested change to §115.725(a)(1) is unnecessary due to the addition of the site- wide HRVOC cap and the revisions to §115.725 and §115.727 described earlier in this preamble. As described earlier in this preamble, the commission has revised §115.725 to specify reference method testing.

TCC suggested that §115.725(a)(1) be revised to delete the wording "for vent gas streams claimed exempt under §115.127 of this title" and the word "being" in the second sentence. TCC also suggested deleting the last sentence of §115.725(a)(1) and suggested that these changes would result in improved readability.

The commission has replaced the proposed §115.725(a)(1) with §115.725(a) which specifies reference method testing. Therefore, the commenter's suggestion is moot.

§115.725(a)(1)(B)

TCC asserted that the commission established the pound-per-hour exemption on vents based on an extrapolated emission inventory rate and the number of affected sources identified in the inventory, and that there is no technological basis for this exemption. TCC stated that the commission should revisit this exemption threshold as improved monitoring data dictates.

As discussed in Chapter 7 of the HGA SIP, this SIP revision is another phase in the process of continued analysis and review of the science. The data collected as a result of these revisions will further assist the commission as it develops its full reassessment of the attainment demonstration at the MCR. As appropriate, the commission will revisit this exemption threshold as improved data becomes available.

§115.725(a)(1)(C)

Ethyl recommended that the 0.011 standard cubic meter per minute maximum flow rate, which could trigger the routing of a very small vent to a control device, be modified to adjust for batch operations with peak flows of short duration. Ethyl stated that the commission should consider triggering this requirement when the 0.011 cubic meter per minute rate is exceeded for a given number of hours per year and stated further that small facilities with peak flows, the condition required for monitoring, could be subject to costly and unnecessary controls with little, if any, environmental benefit. Alternately, Ethyl suggested the commission consider a minimum annual mass VOC emission rate before this requirement is triggered.

The commission disagrees. Batch operations can have significant short-term emissions. The commenter's suggestions would allow higher emissions on a day when ozone may be a problem and cannot assure the level of control required on the hot summer days when ozone is most likely to form.

§115.725(a)(2)

DuPont and TCC commented on the proposed §115.725(a)(2), which specifies that testing is to be conducted a maximum production rates. DuPont stated that a unit may not be able to run at that rate for test purposes and that the commission should provide some allowance for other operating conditions combined with engineering judgment to determine emission rates. TCC stated that if the operator cannot test at maximum operating conditions, alternate approval should be granted by the regional office on a case-by-case basis.

As described earlier in this preamble, the commission has deleted the proposed §115.725(a)(2). However, the factors described by the commenters can be taken into consideration as part of the test plan and quality assurance plan review specified in §115.726(a).

§115.725(a) and (b)

BCCA-AG, ExxonMobil, Goodyear-Houston, Lyondell, and TCC stated that for §115.725(a) and (b), engineering calculations should be allowed in lieu of testing for certain vents. BCCA-AG, ExxonMobil, Goodyear-Houston, and Lyondell also stated that while the proposed rules contain detailed testing requirements to confirm the applicability of certain exemptions and compliance with the new emission limits, they do not include an alternative for vents located in areas that are difficult or unsafe-to-monitor. In addition, BCCA-AG and Lyondell stated that testing is required for all vents, even where it is obvious that the applicable exemption level or emission rate is met. Dow suggested that testing should be required only when HRVOC are known to be emitted in some quantity via process knowledge or previous testing. BCCA-AG, Goodyear-Houston, and Lyondell recommended addition of a new provision allowing engineering calculations to be used as an alternative to testing for vents that are located in areas that are difficult or unsafe-to-monitor. BCCA- AG, Dow, Lyondell, and TCC stated that the rule should be revised to provide that testing is not required where engineering calculations show that the concentration and/or mass emission rate of the vent stream is less than 50% of the proposed exemption levels.

The commission is aware that sampling ports and platforms are not always available and notes that 30 TAC §101.9 requires the installation of platforms and sampling ports for use in determining the nature and quantity of emissions. The commission recognizes that there may be difficulty in providing these arrangements. One approach to economic reasonableness in installing platforms is that sampling platforms should first be installed on units which are being modified with control equipment during turnarounds or plant outages. The units which are not being modified should have less priority on sampling platform installation. Unique situations, such as vents which are located in areas that are documented to be difficult or unsafe-to-monitor, can be taken into consideration as part of the test plan and quality assurance plan review specified in §115.726(a).

The commission believes that it is critical that the test methods for establishing rule compliance are EPA reference methods. Besides the primary benefit of emissions reductions due to identification of vents which should be controlled to provide continued progress toward attainment of the ozone standard, reference method testing will also enhance the emissions inventory and input to the model. The commission believes that because vent gas streams are major sources of HRVOC emissions, the need for testing to determine the quantity of emissions is reasonable. Various industry representatives have asserted that there should be more emphasis placed on gathering data to properly determine the emission reductions that are necessary for the SIP. Without testing data, compliance with the exemptions and control requirements cannot be determined due to the variability of tester experience, dedication, and technique, particularly if portable analyzers were allowed to be used for compliance testing.

Regarding Dow's comment that testing should be required only when HRVOC are known to be emitted in some quantity, the commission notes that §115.720 specifically limits the applicability of Subchapter H, Division 1, to each vent gas stream which includes an HRVOC.

§115.725(b)

Sierra-Lone Star strongly supported the new stack test rule in §115.725(b) to confirm that the control efficiency requirements are being met, and generally supported the stack test reporting requirements of control devices as proposed.

The commission appreciates the support and notes that the proposed §115.725(b) has been replaced by §115.725(a), which requires reference method testing.

TCC stated that the commission should clarify that, consistent with other rules (e.g., NSPS Subparts NNN, RRR, etc.), vent streams that are routed to a process heater or boiler or that are to be added in the flame zone (40 CFR §60.662(a)) and then, if the boiler or process heater has a design capacity of 150 MMBtu/hr or greater, the initial performance test is waived, in accordance with 40 CFR §60.8(b).

NSPS is based on the need to reduce emissions from new or modified sources, while Chapter 115's purpose is to reduce emissions which contribute to ozone formation. Because the purposes of the rules are so different, there is no reason they should necessarily have the same exemptions. Therefore, the commission has made no changes in response to the comment.

§115.725(c)

TCC suggested deletion of §115.725(c), which specifies that the owner or operator is responsible for providing testing facilities and conducting the sampling and testing operations at its expense. TCC questioned why the commission needs to state that the owner or operator will pay for the test.

The referenced language was proposed to make it clear that the commission will not be underwriting the cost of testing the regulated community's vent gas emissions. While the proposed §115.725(c) is not being adopted, the commission again emphasizes that it will not be underwriting the cost of testing the regulated community's vent gas emissions.

§115.725(c)(1)

Dow commented on the proposed §117.725(c)(1) and stated that a pretest meeting should only be required prior to reference method testing.

While the proposed §115.725(c) is not being adopted, the commission notes that reference method testing is required under §115.725(a), except for vents equipped with CEMS. The pretest meeting can be addressed as part of the test plan and quality assurance plan review specified in §115.726(a).

TCC commented on §117.725(c)(1) and stated that it should not be necessary to provide the name of the testing firm unless the commission plans to regulate this industry.

It would be difficult for agency staff to hold a pretest meeting without knowing with whom they were meeting. In addition, knowing the identity of the testing firm makes it easier for agency staff to take into account the testing firm's experience and history in order to focus the appropriate level of attention to observing the testing and reviewing the test results. Finally, the commission believes that notification of testing done to comply with the rule is important because agency representatives will not be required to be present during the testing.

§117.725(c)(5)

ExxonMobil also suggested that the submission of all testing data within 60 days would merely burden the commission and the regulated community with unneeded clerical duties. ExxonMobil recommended that the rule be revised to require that covered facilities maintain all test data on site for review by appropriate regulatory officials.

The commission disagrees. Submittal of the final sampling report within 60 days after sampling is completed has been an agency standard for over 20 years. Further submittal of the final sampling report is necessary to allow agency staff an opportunity to review the report and ensure that it is acceptable in a timely manner. The deadline for submittal of the final sampling report can be addressed as part of the test plan and quality assurance plan review specified in §115.726(a).

§115.725(e)

Goodyear-Houston stated that previous vent sampling results should be allowed in lieu of testing for certain vents.

Previous valid test results are allowed under §115.725(e), which has been relettered as §115.725(c).

ATOFINA recognized that the commission seeks to place VOC emission limits on process vents that exit to the atmosphere as well as to document process vents that are exempt from controls. ATOFINA stated that extensive performance testing of several process vents has already been completed as required by air permits, and in some cases, sampling plans for performance tests conducted for air permits have undergone extensive commission review and written reports summarizing the results have been submitted to the commission. ATOFINA suggested that because the proposed rules allow the use of previous performance tests only if approved by the executive director, the rule language should be changed to allow use of previously submitted performance tests without resubmitting for further review. ATOFINA stated that this would avoid the executive director being inundated by previously reviewed performance test reports, review process delays, and unnecessary retesting of vents to ensure compliance by December 31, 2003. ATOFINA suggested that because the proposed rules allow the use of previous performance tests only if approved by the executive director, the rule language should be changed to allow use of previously submitted performance tests without resubmitting for further review. ATOFINA stated that this would avoid the executive director being inundated by previously reviewed performance test reports, review process delays, and unnecessary retesting of vents to ensure compliance by December 31, 2003.

As ATOFINA noted, previous test results are allowed under §115.725(e), which has been relettered as §115.725(c). However, it is necessary that previous test results be reviewed by the Engineering Services Team to ensure that such testing results are valid.

§115.725(f)(2)(D)

TCC stated that §115.725(f)(2)(D) should be deleted because the commission "should not require negative documentation."

The commission disagrees and believes that it is important to document that no changes to the process have occurred since the compliance test was conducted that could result in a significant change in VOC emissions. This is necessary to allow a determination of whether the sufficient process changes have occurred such that the test is no longer representative. Because the commission has replaced §115.725(f) with the test plan and quality assurance plan review specified in §115.726(a), this issue can be addressed as part of that test plan and quality assurance plan.

General VOC and HRVOC Cooling Towers

§115.184 and §115.766(4)

EPA commented that it can approve a provision providing for the executive director to approve minor modifications to test methods, but not to approve alternative methods. EPA stated that either the rules themselves must contain a replicable procedure for the evaluation of alternative test methods, or alternative methods must be approved through a SIP revision process. EPA commented that the proposed §115.184 does not contain a replicable procedure for the evaluation of alternative test methods.

The commission has withdrawn the proposed general VOC requirements for cooling towers in Subchapter B, Division 8. The issue raised by EPA is addressed in the RESPONSE TO COMMENTS section under the corresponding HRVOC rule at §115.744.

§115.184(1) and §115.766(2)

BCCA-AG and Lyondell commented that continuous flow meters on both the inlet and outlet of each cooling tower should not be required, stating that circulation flow is typically determined by the design capacity of the cooling tower pumps in service as well as the addition of makeup water to the cooling tower, not by continuous flow monitoring.

The commission has withdrawn the proposed general VOC requirements for cooling towers in Subchapter B, Division 8.

BCCA-AG and Lyondell commented that the proposed minimum detection limit of no more than ten ppb in water is unrealistic to achieve for each HRVOC in each sample case, and especially so for a cooling tower system with a large circulation rate. BCCA-AG and Lyondell suggested that detection limits should be addressed along with other technical issues as part of the EMP for each cooling water system.

The commission has withdrawn the proposed general VOC requirements for cooling towers in Subchapter B, Division 8.

TCC commented on §115.766 and stated that determination of which method to use (either §115.766(2) or (3)) should be more simply based on the process material contacting any heat exchanger in the CTHES, not on the individual components that make up the material.

The El Paso method air stripping method specified in §115.766(2) must be used at all times. With the revision to the definition of HRVOC, all compounds with a normal boiling point greater than 140 degrees Fahrenheit are no longer included, so only one stripping method applies.

TCC recommended that any specified minimum detection limit be set for total VOCs, not for individual HRVOCs that may be present within the total VOCs. TCC stated that it is unrealistic to assume that the same ten ppbw minimum detection limit be achieved for all HRVOCs that may be included in the VOCs detected in a sample. TCC further commented that it is improper to require that all analyses meet such a low minimum detection limit, which realistically cannot be achieved for the sampling of each and every CTHES. TCC recommended that the minimum detection limit should be set on a case-by-case basis for each CTHES and documented in the CTHES EMP for approval.

The commission disagrees, and believes that a detection level of 10 ppbw is readily achievable, using commonly available flow monitors, over the range of cooling water flow rates expected to be encountered in affected cooling towers. §115.766 now requires that the total strippable VOC, not HRVOC, concentration be determined with a 10 ppbw minimum detection limit. In addition, the rule allows alternative monitoring and testing methods to be approved by the Engineering Services Team.

HRVOC Fugitives

§115.785

Rohm & Haas stated that the testing requirement in §115.785 to demonstrate compliance with §115.783(2) places an unnecessary burden on sources that have recently conducted testing of these systems. Rohm & Haas suggested that recovery systems or control devices that have been tested within the last five years should not be required to retest. DuPont and ExxonMobil expressed similar concerns. DuPont stated that the commission should insert language in §115.785 to clarify that these are procedures for testing new units, or if the commission deems, testing on a specific unit (due to performance issues) is required. Dow and TxOGA stated that §115.785 should make clear that additional testing of control devices that have been previously tested is not necessary. ExxonMobil stated that unless §115.785 requires testing of control devices under circumstances that are not already covered by other rules, then it is redundant and should be deleted.

The commission has added §115.785(5) to allow previous valid test results, and has renumbered proposed §115.785(5) as §115.785(6). In addition, the commission has revised the renumbered §115.785(6) to reference the stack test report requirements of §115.725(f) in order to provide consistent requirements for stack test reports.

Dow stated that the following control devices should be exempt from performance testing requirements under §115.785: a boiler or process heater with a design heat input capacity of 44 megawatts or greater; a boiler or process heater into which the process vent stream is introduced with the primary fuel or is used as the primary fuel; a control device for which a performance test was conducted for determining compliance with a regulation promulgated by the EPA or the commission and the test was conducted using the same methods specified in §115.125 and either no process changes have been made since the test, or the owner or operator can demonstrate that the results of the performance test, with or without adjustments, reliably demonstrate compliance despite process changes; a boiler or process heater burning hazardous waste for which the owner or operator has been issued a final permit under 40 CFR Part 270 and complies with the requirements of 40 CFR Part 266, Subpart H, or has certified compliance with the interim status requirements of 40 CFR Part 266, Subpart H; and a hazardous waste incinerator for which the owner or operator has been issued a final permit under 40 CFR Part 270 and complies with the requirements of 40 CFR Part 264, Subpart O, or has certified compliance with the interim status requirements of 40 CFR Part 265, Subpart O.

As noted in the response to the previous comment, the commission has added §115.785(5) to allow previous valid test results. This is expected to address the majority of scenarios Dow described. For other scenarios, the commission believes that it is critical that the control efficiency be determined in order to ensure that the HRVOC emissions which are contributing to ozone exceedances in HGA are controlled properly.

TxOGA stated that it presumes that §115.785 is being added for the case where pressure relief devices are routing to a control device. TxOGA stated that there is not a maximum production rate which can be associated with a stack test for these sources, and that maximum production might not correlate to releases from PRVs in any way. TxOGA stated that §115.785 is redundant and should be eliminated. Dow recommended that §115.785(4) be revised to allow the stack emission testing to be conducted under such conditions based on representative performance (i.e. performance based on normal operating conditions) of the process unit, rather than at maximum production rate, and stated that future production rates should not be limited to the rates established during testing. Dow suggested the addition of language similar to 40 CFR §63.7(e)(1) to address normal operating conditions.

TxOGA presumes correctly that one case would be a pressure relief device which is routed to a control device. Another instance would be a shaft sealing system which is routed to a control device. The testing specified in §115.785 is necessary to determine the control efficiency of the control device and verify that it meets or exceed the minimum acceptable control efficiencies. "Maximum production rate" refers not to the pressure relief device, shaft sealing system, etc., but instead to the underlying process of which the pressure relief device, shaft sealing system, etc. are an integral part. As noted in the response to the previous comment, the commission added §115.785(5) to allow previous valid test results. The commission agrees with Dow that the addition of language similar to 40 CFR §63.7(e)(1) would be beneficial and has revised §115.785(4) accordingly.

ExxonMobil and TxOGA stated that final reports may not always be available from contractors within 60 days following testing.

The requirement to submit a report within 60 days is a standard condition with which most testing contractors are able to comply. Therefore, the commission believes that it is a reasonable schedule.

RECORDKEEPING REQUIREMENTS

First Attempt at Repair

Sierra-Houston and Sierra-Lone Star stated that under §115.142(1)(H), §115.149(f), and anywhere else in Chapter 115 where first attempt at repair within five calendar days is required, such as §115.326 and §115.356, the commission should require recordkeeping to include the date, time, component, and who made the first repair attempt. Sierra-Houston and Sierra-Lone Star stated that this information is not currently required to be recorded so there is no way to know if a first attempt at repair was made within the specified time frame.

Sections 115.326(2)(G) and 115.356(1)(G) (renumbered as §115.356(2)(F)) already require documentation of the first attempt at repair. Records necessary to document the first attempt at repair required by §115.782(b) are addressed later in this preamble. Regarding §115.142(1)(H), the commission agrees that recordkeeping requirements are necessary. Because §115.146, concerning Recordkeeping Requirements, was not proposed for revision, the commission has revised §115.142(1)(H) to include the appropriate recordkeeping requirement, with the expectation that this will be relocated to §115.146 in the future. For vent gas streams, flares, and cooling towers, the commission has added §115.726(c)(3) and §115.767(a)(4) to include the appropriate recordkeeping requirements for corrective actions and associated emissions.

General VOC Vent Gas Control

§115.126

DuPont and TxOGA stated that the requirement in §115.126 to maintain records for five years, as opposed to two years, should have an effective date assigned. Otherwise, it may be assumed to require retroactive recordkeeping, which is not possible. TxOGA stated that several years from now, it may be confusing as to why five years of records are not available. TCC stated that the current two-year period should be retained. DuPont also stated that not all facilities are required to have Title V permits and it is an unnecessary burden to maintain records for five years. DuPont recommended that the five-year recordkeeping requirement only apply to sites subject to Title V.

The commission believes that it is appropriate for owners and operators to maintain records for five years, but agrees that §115.126 should be revised to provide a transition from the current two-year record retention period. Therefore, the commission has revised §115.126 to specify that the five-year record retention requirement does not apply to records generated before December 31, 2000. This date was selected because it is two years before the estimated effective date of the revised rules, and consequently will ensure that the new five-year record retention requirement is not retroactive to records that were not required to be maintained under the current two-year record retention requirement.

General VOC Cooling Towers

§115.186(3)

EPA commented that the rationale was not clear for keeping records on a weekly basis of the twice per week tests for speciated VOC compounds, and asked whether weekly averages were required by the rule. EPA further commented that the facility should keep all records as required by §115.186(3) and provide reports quarterly as required by §115.183(1).

As noted earlier in this preamble, the commission has withdrawn the proposed general VOC rules for cooling towers in Subchapter B, Division 8. Therefore, the commission has made no changes in response to the comments.

Fugitive Emissions

§115.356(1)

Dow stated that the commission should make the component identification requirements in Subchapter D, Division 3, and Subchapter H, Division 4 consistent throughout each rule. Dow expressed a preference for the multiple means of component identification allowed in the proposed §115.781(a). Dow also stated that individually tagging each component subject to, or exempt from, the rule should not be a requirement. Dow stated that §115.356(1) should include the options for component identification that are provided in §115.786(e).

It is unclear how components could be accurately identified on a unit-wide basis, as opposed to a component-by-component basis. If each component is not identified with a unique component identification code, it would be difficult to identify which specific components had been monitored on a particular date, which components were not monitored, which components were leaking, etc. Therefore, the commission believes that for the rule to be enforceable, each component ideally would be identified with a unique component identification code. However, the commission also recognizes that connectors present a unique difficulty in labeling due to the sheer number of connectors, which is estimated to be three to four times the number of valves. Therefore, the commission has revised §115.781(a) accordingly to specify that each component other than connectors must be labeled with a unique component identification code in order to improve the enforceability of the rule, with connectors not required to be individually labeled if they are clearly identified individually in the master components log. This will also ensure consistency with §115.786 and §115.356.

As noted elsewhere in this preamble, the commission has replaced §115.786(e), relettered as §115.786(d), with a reference to §115.356, and renumbered §115.356(1) as §115.356(2). Section 115.356(4)(C) requires records identifying and justifying each exemption by component claimed under §115.357. The commission revised the relettered §115.786(d) to require records identifying and justifying each exemption claimed exempt under §115.787. The requirement to identify and justify each exemption is necessary to ensure that records of the appropriate data are maintained, thereby improving the enforceability of the rule.

§115.356(1)(E)

Sierra-Houston and Sierra-Lone Star supported the requirement in §115.356(1)(E) which requires that the results of AVO inspections of flanges be recorded.

The commission appreciates the support.

§115.356(1)(E)(ii)

TxOGA commented on §115.356(1)(E)(ii) and stated that all requirements for monitoring, recordkeeping and reporting of flanges should be deleted because connectors are being added to the definition of "component."

Rather than deleting §115.356(1)(E)(ii), which is a necessary requirement for documenting compliance with the existing requirement in §115.354(3) to conduct AVO inspections of flanges, the commission is instead revising §115.356(1)(E)(ii) (renumbered as §115.356(2)(D)) to exclude flanges that are monitored using Test Method 21 as required by §115.781(b)(3).

§115.356(1)(F) and §115.356(2)

Dow commented on §115.356(1)(F) and (2) and stated that the commission should provide flexibility on where all the required records must be kept as long as they can be easily accessed. Dow suggested referencing electronically and/or hard copy records.

The commission agrees and has revised §115.356 accordingly.

§115.356(2)

TxOGA commented on §115.356(2) and recommended deletion of the requirement to maintain records of AVO inspections of connectors other than flanges, but only if a leak is detected.

It is apparent that TxOGA erroneously believes that inspection requirements are being added to §115.354 for connectors other than flanges. While AVO inspections of flanges are already required, there is no requirement to conduct AVO or instrument monitoring of connectors other than flanges in Subchapter B, Division 3. To clarify this, the commission has replaced "records of the..." with "records of any..." in §115.356(2) (renumbered as §115.356(2)(G)).

ExxonMobil and TCC also recommended deletion of §115.356(2). TCC asserted that "this language requires inspection records of all flanges even if they are not leaking," which TCC stated is unnecessary. ExxonMobil expressed similar concerns.

Flanges are one of the types of connectors. The current §115.354(3) requires weekly flange inspections, but there is no requirement under Subchapter B, Division 3, to conduct inspections of connectors other than flanges. Therefore, the commission has revised §115.356(2) (which was renumbered as §115.356(2)(G)) by adding the qualifier "any." The commission has also deleted the phrase "other than flanges" because even though inspections of non-flange connectors are not required, the commission believes that incidents of such components found to be leaking during any non-required inspections should be recorded. Information concerning leaks from non-flange connectors will enable owners and operators, as well as commission staff, to determine where additional focus on leak inspection and repair is warranted.

§115.356(3)

DuPont suggested that "subject to this division" in §115.356(3) should be changed to "requiring monitoring" to clarify that exempt components are not included in this recordkeeping.

The commission agrees that the phrase "subject to this division" could be overly broad. However, the commission has deleted §115.356(3) because it has updated the recordkeeping requirements of §115.356(1) and (2) to match the exemptions, inspection and monitoring requirements, etc.

§115.356(3)(E)

DuPont suggested the addition of the following wording to §115.356(3)(E): "For components requiring only an audio, visual, or olfactory inspection, such as valves in heavy liquid service, a response factor is not required." TxOGA recommended changing §115.356(3)(E) to reference the composite, representative response factor being used for the unit or stream which the component is in. ExxonMobil stated that the response factor may not be a set value but may change with concentration. ExxonMobil questioned whether it should ignore the concentration effect and record the response factor for the composition of the material contacted at a presumed concentration.

As noted earlier in this preamble, the commission has deleted the requirement for response factors; therefore, the commenters' concerns are moot.

§115.356(3)(F)

DuPont, ExxonMobil, TCC, and TxOGA stated that rule citations for exempted components should be provided on request and on a unit-wide basis, not component by component, and therefore §115.356(3)(F) should be deleted. ExxonMobil and TCC stated that as written, §115.356(3)(F) could be interpreted to include all components in non-VOC service, which would include steam, nitrogen, water, and fuel lines. ExxonMobil and TCC stated that such information could be obtained from existing process and instrument diagrams, for example, and provided upon request. ExxonMobil suggested that §115.356(3)(F) be deleted.

The proposed §115.356(3)(F) was replaced by §115.356(4)(C), as described earlier in this preamble. The new §115.356(4) requires records identifying and justifying each: 1) unsafe-to-monitor valve; 2) nonaccessible (difficult to monitor) valve; and 3) exemption by component claimed under §115.357. This revision will ensure that records of the appropriate data are maintained, thereby improving the enforceability of the rule. However, the commission does not intend that §115.356(4) include components in non-VOC service, such as steam, nitrogen, and water lines. It is unclear how exempted components could be accurately identified on a unit-wide basis, as opposed to a component-by-component basis. Therefore, the commission made no changes in response to the comment. The commission has renumbered the previous §115.356(4) as §115.356(5) to accommodate the new §115.356(4).

§115.356(3)(G)

Goodyear-Beaumont stated that the only reason that a valve is inaccessible is because the valve is more than two meters from a support structure, and therefore the reference to inaccessible valves should be deleted from §115.356(G).

The commission notes that §115.354(1)(C) already requires records of unsafe-to- monitor valves, and §115.352(7) requires that nonaccessible valves be identified in a list to be made available upon request. Such records are necessary to allow identification of valves which have the potential to leak because they are in VOC service, but are not being monitored or inspected for leaks. Therefore, the commission has retained the recordkeeping requirement, although it has relocated §115.356(3)(G) to §115.356(4)(A) and (B).

§115.356(4)

TCC commented on the proposed requirement in §115.356(4) to maintain records for five years, as opposed to two years. TCC stated that the two-year recordkeeping requirement should be retained.

The commission believes that it is appropriate for owners and operators to maintain records for five years, but that §115.356 should be revised to provide a transition from the current two-year record retention period. Therefore, the commission has revised §115.356 to specify that the five-year record retention requirement does not apply to records generated before December 31, 2000. This date was selected because it is two years before the estimated effective date of the revised rules, and consequently will ensure that the new five-year record retention requirement is not retroactive to records that were not required to be maintained under the current two-year record retention requirement. As noted in the response to comments concerning §115.356(3)(G) earlier in this preamble, the commission has renumbered §115.356(4) as §115.356(5).

HRVOC Vent Gas Control

§115.726(b)

Sierra-Lone Star supported the proposed requirement that records which must be kept to provide demonstration of continuous compliance for vapor control systems, but requested that §115.726(b) be amended to require that valid and certified stack test emission reports for all pollution control devices be maintained for the life of the control device.

The commission disagrees because submittal of test reports will be required as part of the test plan and quality assurance plan review specified in §115.726(a). Therefore, the commission will have access to test reports even after the end of the five-year record retention period of §115.726(e).

§115.726(c) and (d)

Dow suggested that §115.726(c), which specifies required records for LDPE plants, allow analyses that are conducted in accordance with the frequencies required in existing new source review permits to be adequate to generate information and records used to show compliance with the ethylene emissions limits for polyethylene plants in §115.722(a). TCC suggested that §115.726(c) be revised to specify that the records are on an annual basis. Dow stated that a one-time test is used to demonstrate compliance with the exemption criteria, and that §115.726(d) should be clarified such that additional testing and recordkeeping are only required when a physical or operational change occurs that may increase the HRVOC concentration or HRVOC emission rates. Dow and TCC stated that the word "continuous" should be removed from §115.726(d)(1) and (2) because compliance with the exemption criteria is based on the results of the testing.

As noted earlier in this preamble, a site-wide HRVOC emissions cap has replaced individual (i.e., unit-by-unit) emission limits. Therefore, the commission has made no changes in response to the comment. However, the commission disagrees with Dow and TCC concerning the term "continuous" because continuous compliance is the basic intent of the rule.

§115.726(e)

TCC commented on §115.726(e) and stated that records should be kept for two years rather than five years.

Section 115.726(e) has been relettered as §115.726(f). The commission disagrees because most sources subject to Chapter 115 are also subject to FCAA Title V permit requirements, which specify a five-year period for retention of compliance records. Therefore, the commission believes that it is appropriate for owners and operators to maintain records for five years.

HRVOC Flares

§115.746

TCC commented on §115.746 and stated that information concerning corrective action data should be retained if required by the Chapter 101 rules (relating to emission events).

As noted earlier in this preamble, under the site-wide HRVOC emissions cap the owner or operator is not required to make repairs on any particular schedule, provided that the 24-hour rolling average HRVOC emission cap is not exceeded. Likewise, the recordkeeping requirements for the site-wide cap have replaced the need for the proposed §115.746 to address corrective action data because under the cap, unit-by-unit compliance does not apply. The site-wide cap simply requires that each site stay below its 24-hour rolling average HRVOC emission cap. Therefore, the commission has made no changes in response to the comments.

HRVOC Cooling Towers

§115.767(2)

Commenting on §115.767(2), relating to Recordkeeping Requirements, TCC stated that records should be maintained that indicate the basis for the circulation rate of the CTHES (design rate, validation testing, etc.).

The rule allows alternative monitoring methods to be approved by the Engineering Services Team. Any alternative monitoring approach must meet the agency's PEMS protocol and must have an accuracy of ±5%. The appropriate recordkeeping requirements for the alternative method will be specified in the agency's approval, if granted. Therefore, there is no need to include such recordkeeping requirements in this rule section.

§115.767(4)

TCC recommended that §115.767(4), which requires that weekly records be maintained that document the pounds per hour emitted for all HRVOC in the process fluid for each cooling tower heat exchange system with a cooling water circulation rate less than 8,000 gpm must demonstrate continuous compliance with the applicable criteria, be deleted based on the suggested change to the exemption criteria.

The references to the cooling tower circulation rate (either equal to or greater than 8,000 gpm or less than 8,000 gpm) have been deleted from the recordkeeping requirements in 115.767. Records of all monitoring and testing must be kept to demonstrate compliance, regardless of the size of the cooling tower.

§115.767(5)

TCC recommended deletion of the requirement in §115.767(5) for maintenance of records of in-house testing. TCC stated that unless the need for retention of in-house records related to pH, addition of cooling tower chemicals, etc. can be demonstrated, the requirement should be deleted.

The commission has deleted the specific requirement to maintain records of in-house testing. However, §115.767(c) requires that all records necessary to demonstrate compliance, and records of periodic measurements, be maintained for at least five years and made available upon request to the agency staff or other authorized persons.

§115.767(6)

TCC suggested deletion of the phrase "on a weekly basis" in §115.767(6), stating that specifying the frequency of "maintaining" records is overly prescriptive.

The commission has retained this provision, now located in §115.767(4), so that field enforcement staff will have adequate records to review compliance status.

§115.767(7)

TCC recommended deletion of the word "continuous" in §115.767(7) and stated that such a requirement makes no provisions for process upset periods. TCC further commented that maintaining records documenting an engineering review of the normal operating pressure ranges of the cooling water side of all heat exchangers, as compared to the process side of all heat exchangers in a CTHES, should be adequate for compliance purposes.

The commission disagrees with TCC concerning the term "continuous" because continuous compliance is the basic intent of the rule. As noted earlier in this preamble, the individual unit emission specifications have been replaced by a site-wide cap which requires compliance on a rolling 24-hour average. However, compliance with the overall HRVOC emissions cap will require that appropriate corrective actions be taken to remain within the cap on a rolling 24-hour average in the event of a process upset.

§115.767(9)

TCC commented that in §115.767(9), the required period for maintaining records should be changed from five to two years, unless Title V air permits have been issued to the owner or operator for each CTHES in question, in which case the retention period would be five years.

The commission disagrees, because most sources subject to Chapter 115 are also subject to FCAA Title V permit requirements, which specify a five-year period for retention of compliance records. Therefore, the commission believes that it is appropriate for owners and operators to maintain records for five years.

TCC commented that a provision for establishing and maintaining an approved CTHES EMP should be added to §115.767.

The commission supports any company's use of an EMP to determine the best operating practices that will ensure continuing compliance with the rules. Section 115.764(d)(1) and (2) specify the procedures and dates for submitting monitoring quality assurance plans for approval by the Engineering Services Team. The commission believes that the requirements as stated in this rule section are sufficient, and that placing the requirements in the recordkeeping section as well would be redundant.

HRVOC Fugitive Emissions

Phillips stated that its Sweeny refinery is subject to nine different state and federal equipment leak programs with overlapping requirements. Phillips stated that the commission could greatly lessen the reporting and recordkeeping burdens of regulated sources by identifying Chapter 115 fugitives requirements as being more stringent than other state permit and federal equipment leak standards. TxOGA expressed similar concerns.

It can be exceedingly difficult to compare two fugitive monitoring programs and conclude that one is more stringent than another. This is because each fugitive monitoring program may include certain requirements that are more stringent than another, and vice versa. For example, in 1995 - 1996, commission staff and industry representatives attempted to develop a new fugitive monitoring program that would streamline similar state and federal rules, which would have offered the regulated community a one-stop option for complying with LDAR requirements. The LDAR requirements of the following rules were to be consolidated by this new program: Federal Rules - 40 CFR Part 60, Subparts VV, DDD, GGG, and KKK; 40 CFR Part 61, Subparts F, FF, J, and V; 40 CFR Part 63, Subparts F, H, I, JJJ, U, and CC; 40 CFR Part 264, Subparts AA, BB, and CC; 40 CFR Part 265, Subparts AA, BB, and CC; State Rules - Chapter 115; 30 TAC Chapter 335; and the following LDAR programs administered under 30 TAC Chapters 106 and 116: 1) condition 28 VHP; 2) condition 28 RCT; 3) condition 28 MD; 4) condition 28 M; 5) condition 28 Old; and 6) conditions for connector monitoring. Some programs require quarterly monitoring, and others require monthly monitoring. Some programs define a leak as 10,000 ppmv, while others define a leak as 1,000 ppmv or 500 ppmv. Some programs include a two-inch size exemption, while others have no size exemption. Most programs do not require monitoring of connectors and agitators, but some do. Still others require monitoring of process drains. It simply is not possible to categorically state that the Chapter 115 HRVOC fugitives requirements are more stringent than other state permit and federal equipment leak standards.

§115.786

Sierra-Houston and Sierra-Lone Star urged the commission to require that the date, time, procedures attempted, and person who made the attempt for the leak repair within 24 hours be recorded so that there is documentation that the repair was actually attempted as required by §115.782(b).

The renumbered §115.786(d) requires maintenance of records in accordance with 115.356. Section 115.356(1)(G) was renumbered as §115.356(2)(F) and already requires documentation of the first attempt at repair. Because Subchapter H, Division 3 applies in addition to Subchapter D, Division 3, the records required by the renumbered as §115.356(2)(F) will provide the necessary documentation for the first attempt at repair required by §115.782(b). Therefore, the commission has made no changes in response to the comment.

§115.786(a)

ExxonMobil and TxOGA stated that the flow through the bypass valve may be difficult to determine unless the line is directly monitored, or the total vent stream is diverted and is measured upstream. ExxonMobil and TxOGA questioned whether the flow indicator is required on the total vent stream before any bypass, after any bypass, through each potential bypass, or all of these locations. TxOGA also stated that §115.786(a) is straying from fugitive emissions to process vents, and that the monitoring and recordkeeping should default to §115.726. ExxonMobil expressed similar concerns and recommended that only a flow record be required for the vent stream before any potential bypass, with inspection and exception records being adequate for the rest.

Using a flow indicator to determine whether vent stream flow is present in a bypass line is an option for complying with §115.783(1). The intent is that bypass line be monitored for vent stream flow if this option is chosen, and the commission has revised §115.783(1)(A) to clarify this intent. The commission disagrees with TxOGA's assertion that §115.786(a) is not appropriate for fugitive emissions. It is necessary to address bypass lines in the fugitive monitoring rules to ensure that emissions from PRV discharges which should be routed to a control device are not instead simply being emitted uncontrolled through a bypass line.

§115.786(d)

Sierra-Houston and Sierra-Lone Star stated that the commission should require that all local air pollution programs with jurisdiction receive the non-reparable components records so that the local programs are aware of these leaks and if necessary can take action to reduce emissions from these leaking components.

The proposed §115.786(d) was relettered as §115.786(c) and already includes submittal to local programs. Therefore, the commission has made no changes in response to the comment.

DuPont and TCC stated that the commission is already receiving the information in §115.786(d) semi-annually and asserted that adding another quarterly report does nothing to improve emissions. DuPont recommended deletion of §115.786(d), while TCC suggested changing "quarterly" to "semiannually."

The commission agrees with TCC that a semiannual report is adequate, and has revised the relettered §115.786(c) accordingly.

Dow stated that §115.786(d)(5) should include a reference to replacement as well as repair.

The proposed §115.786(d)(5) was lettered as §115.786(c)(5). The commission agrees and has revised the relettered §115.786(c)(5) accordingly.

ExxonMobil and TxOGA stated that the report content is not consistent with the information required to demonstrate compliance under §115.782(e). ExxonMobil and TxOGA stated that the estimated leak rate for each component should also be included if the second table option is selected; that the initial date that each component was first measured as leaking is needed; and that the total number of components of each type required to be monitored under this rule is needed to calculate percentages.

The commission agrees with the commenters. However, as described earlier in this preamble in response to comments on §115.782(e)(3), the commission has deleted §115.782(e) in its entirety.

§115.786(e)

TCC stated that the database required under §115.786(e) should be updated on an ongoing basis. Therefore, TCC suggested deleting the wording "and update at least once every 12 months."

For consistency with §115.356, the commission has replaced §115.786(e), relettered as §115.786(d), with language which refers to §115.356. Therefore, the commission has made no changes in response to the comment.

§115.786(e)(6)

ExxonMobil and TxOGA stated that only components with specific exemptions under §115.786(e)(6) should be required, and that components exempt under §115.787(a) because they contact a process fluid that contains less than 1.0% HRVOC should not be required to be in the database. ExxonMobil and TxOGA stated that including these components would unnecessarily overload the database. ExxonMobil and TxOGA stated that exemptions for components exempt under §115.787(a) because they contact a process fluid that contains less than 1.0% HRVOC can be maintained in another database or appropriate records, or supported by other documentation such as process diagrams. TCC stated that the commission should not require a component-by-component listing of rule citations to prove an exemption, and that the commission should provide a simplified approach for certain equipment or lines (such as nitrogen or water lines) that are not in VOC service.

As noted in the response to the previous comment, the commission has replaced §115.786(e), relettered as §115.786(d), with a reference to §115.356. Section 115.356(4) requires records identifying and justifying each: 1) unsafe-to-monitor valve; 2) nonaccessible (difficult-to-monitor) valve; and 3) exemption by component claimed under 115.357. The commission revised the relettered §115.786(d) to require records identifying and justifying each exemption claimed exempt under §115.787. This will ensure that records of the appropriate data are maintained, thereby improving the enforceability of the rule. However, the commission does not intend that §115.356(4) or §115.786(d) include components in non-VOC service, such as steam, nitrogen, and water lines. The regulated community is free to maintain records of exempted components in a separate database if it desires.

§115.786(f)

TCC stated that the requirement in §115.786 to maintain records for five years should have an effective date assigned. Otherwise, it may be assumed to require retroactive recordkeeping, which is not possible.

The proposed §115.786(f) was lettered as §115.786(e). The compliance date for the recordkeeping requirements is specified in §115.789, and this date is when owners and operators must begin keeping the initial records, which logically would not be retroactive to a time before the owner or operator was subject to the rule. Therefore, TCC's concerns are unfounded.

AUDIT PROVISIONS

HRVOC Fugitive Emissions

§115.788

HCPC fully supported the requirements in proposed §115.788 regarding audit provisions for local air pollution control agency personnel. HCPC specifically supported the requirements in §115.788(e)(3), which will provide a new tool for swift enforcement. Sierra-Houston and Sierra- Lone Star agreed that an audit should be done by an independent third-party to keep the company and the contractor honest. Sierra-Houston and Sierra-Lone Star stated that the commission and local air pollution programs with jurisdiction should also conduct audits to ensure that the company, local contractor, and third-party auditor are honest in the dealings with the leak detection program. OxyChem stated that it does not object to an audit requirement.

The commission appreciates the support and agrees with the commenters that the third- party audit program is an effective means of further assuring compliance with the rules.

ATOFINA, BCCA-AG, Dow, DuPont, ExxonMobil, Goodyear-Houston, Lyondell, Solutia, TCC, and TxOGA opposed the requirement for fugitive monitoring programs to undergo independent third-party audits every two years. BCCA-AG, Dow, DuPont, ExxonMobil, Goodyear-Houston, Lyondell, Solutia, TCC, and TxOGA stated that practical experience with third-party audits shows that they are of considerably less value than internal audits because third parties are not familiar with each facility's unique units and processes, and that such familiarity is critical to conducting an effective fugitives audit. ATOFINA suggested that rather than a third-party audit program, the fugitive monitoring companies themselves should undergo a general certification process overseen by the commission. ATOFINA stated that certifications can focus on training personnel, auditing procedures and protocols, and calibration of equipment, and the certification process could also include observing sampling techniques at a given facility and occasional spot checks. ATOFINA stated that the number of fugitive monitoring companies is much lower than the number of industrial plants they monitor; therefore, by certifying one fugitive monitoring company, the commission would ensure that the fugitive monitoring program for multiple industrial facilities is being operated correctly. OxyChem expressed the belief that its own program is at a minimum equal to that which a third-party auditor could provide. OxyChem requested that internal audits of the fugitive emissions program be allowed at companies that have a certified audit program. ExxonMobil and TxOGA stated that companies that qualify for the commission's environmental management system rules should be exempted from this auditing requirement.

The commission shares the commenters' concern that monitoring contractors need to be competent; however, the commission cannot implement the ATOFINA and OxyChem recommendations at this time. The Chapter 115 rules are authorized by THSC, Chapter 382, but there are no provisions in the THSC that explicitly authorize any type of occupational licensing or certification program for monitoring contractors. It is not commission practice to establish and regulate a licensing program without explicit statutory authority. The commission's licensing programs are based on the authority provided in Texas Water Code (TWC), Chapter 37. Although there is a precedent for requiring explicit statutory authority for the licensing or certification of occupational programs related to gasoline dispensing facilities that the commission currently administers, such as Underground Storage Tank Contractor Registration/Installers and Leaking Petroleum Storage Tank Corrective Action Specialist/Project Managers, there are no provisions in the TWC for the licensing of monitoring contractors.

An additional concern is the issue of staffing. The two primary methods of regulating such an activity are to hold the facilities accountable for the proper implementation of their LDAR program or to license the persons performing the function. The first method can be accomplished with the commission's current staffing while implementation of a licensing program will require additional staffing. Due to current staffing constraints, the commission is not presently in a position to dedicate the additional staff required to establish a new licensing program. Therefore, the commission made no changes in response to this comment. However, the commission has added a new §115.788(f) which specifies that in lieu of complying with the LDAR program audit provisions of §115.788(a) - (d), an owner or operator may request approval from the executive director of an alternative method which demonstrates equivalency with the independent third-party audit. The equivalency demonstration must include a detailed explanation of how the equivalency will be demonstrated, including the appropriate recordkeeping and reporting requirements that will be implemented which are sufficient to demonstrate compliance with the alternative method, and must demonstrate that it is a replicable procedure and detail how the equivalency will be demonstrated. The new §115.788(f) will add flexibility while ensuring equivalency.

Solutia requested that language be added to the rule that would allow for an upfront audit with provisions for skipping subsequent audits if certain criteria are met, similar to the "leak skip" provisions of the current LDAR program.

The commission disagrees that having an upfront audit will accomplish the objective of the independent audit process, which is to ensure that the LDAR program, as implemented, has been done correctly. The commission also disagrees that a skip period is appropriate for the audit program because it likewise is inconsistent with the intent of the program, which is to ensure that the elements of the various LDAR programs are in fact being properly implemented, including those programs with skip period provisions. The commission expects that the affected companies will set up an appropriate program to properly train staff and contractors, and the purpose of the audit requirements is not to replace that function.

ExxonMobil and TxOGA stated that the audit should be allowed to be conducted under the commission's audit privilege rules.

The commission does not agree that this audit may be conducted under the audit privilege act. Section 115.788 requires a copy of the results of each audit authored by the independent third-party organization to be submitted to the commission. Because the report itself is required to be disclosed, the disclosure of this report is not voluntary under the audit privilege act, and the regulated entity will not quality for conditional immunity from civil and administrative penalties Therefore, this particular audit report generated pursuant to this rule cannot be privileged under the audit privilege act (see Texas Environmental, Health, and Safety Audit Privilege Act, Article 4447cc, §10(b)(4) (Vernon 2002).

Furthermore, this particular audit report generated pursuant to this rule cannot be privileged, meaning it will be admissible as evidence or subject to discovery in: 1) a civil action whether legal or equitable; or 2) an administrative proceeding, under §8(a) of the audit privilege act because it is a report required by a regulatory agency to be reported.

It has been argued, however, that the audit privilege act should be broadly construed and that disclosure of this report would be voluntary, and any violations disclosed in the report would qualify for conditional immunity from enforcement, if the report was generated pursuant to an audit done under the audit privilege act because it is "not a report to a regulatory agency required solely by a specific condition of an enforcement order or decree." (See §10(c) of the audit privilege act). The commission has not found this argument to be persuasive.

However, there is nothing to preclude a regulated entity under the audit privilege act from performing an audit of broad scope in which it audits and reviews for everything this rule requires and discloses violations before the actual report required by this rule would be submitted.

§115.788(a)(1)(A)

TCC questioned whether §115.788(a)(1)(A) applies to leakers that were not identified or components with missing tags.

Section 115.788(a)(1)(A) refers to both.

§115.788(a)(2)

TCC suggested replacing "status" with "factor" in §115.788(a)(2).

The suggested change does not appear to clarify the rule language, and therefore the commission has made no change in response to the comment.

§115.788(a)(2)(A)

ExxonMobil and TxOGA stated that most larger companies conduct ongoing fugitive monitoring daily and therefore the seven-day beginning requirement in §115.788(a)(2)(A) is not applicable. TCC also suggested deletion of the seven-day language.

The commission agrees and has revised §115.788(a)(2)(A) accordingly.

§115.788(a)(2)(C)

TCC commented on §115.788(a)(2)(C) and stated that the components should be randomly selected during any given audit. ExxonMobil and TxOGA stated that no requirement for selection of monitored components randomly has been included. ExxonMobil and TxOGA expressed concern that the commission could use the facility's own leak data to focus on known leakers, no matter what exceptions or provisions have been provided elsewhere in Subchapter H, Division 3.

For audits conducted by independent third-party contractors, the commission has included a reasonable imitation on the pool of components to include in a current audit and does not believe that any further definition of selection is required. The limitations reasonably exclude components for which an audit would not provide representative results. This is why §115.788(2) excludes components which were included in either of the most recent two audits, unless unavoidable due to the shutdown of process units not included in either of the most recent two audits, or for other reasons agreed upon in advance by the appropriate regional office and any local air pollution control agency having jurisdiction.

For audits conducted under §115.788(e), commission staff have developed guidance documents, "Air Program Investigations Related to Leak Detection and Repair (LDAR)," and "Op-Leaks Forms Package" (October 23, 2001) which describe the investigation protocol used when agency inspectors conduct LDAR investigations intended to: 1) evaluate whether the regulated entity's LDAR program meets the requirements of the rules; and 2) predict the accuracy of the regulate entity's historically reported emissions data. This guidance is quite detailed and ensures that each audit will reveal representative results. The commission does not believe that any further definition of the component selection in an audit is required. Should an owner or operator be concerned that the regulatory agency inspectors may not be selecting the appropriate components for an audit such that the results would not be representative, the owner or operator can request that all components with a unit be audited. Commission staff have, in fact, made such offers to regulated companies in the past in such situations.

§115.788(d)

TCC suggested that the 30-day audit submittal requirement in §115.788(d) be changed to 60 days.

The commission has not identified any reason for delaying the audit submittal beyond 30 days and believes that 30 days is sufficient time for submittal of the completed audit results. Therefore, the commission has made no change in response to the comment.

§115.788(e)(1)(B)

TCC commented on §115.788(e)(1)(B) and stated that the definition of "major gas leak" should specify 500 ppmv rather than 200 ppmv.

The commission agrees and has revised §115.788(e)(1)(B) accordingly.

§115.788(e)(1)(C)

TCC commented on §115.788(e)(1)(C) and stated that the definition of "minor gas leak" should be deleted because it is not used in the rules.

The commission agrees and has made the suggested change.

§115.788(e)(3)

Ethyl opposed the three-drop per minute leak rate being classified as an automatic violation of the LDAR program and stated that this classification makes no allowance for the vapor pressure of the organic compound being leaked, such as heavy oils or very low vapor pressure organic compounds or wastewater containing VOCs, which Ethyl asserted would not release any significant VOCs into the air. Ethyl did support the timely repair of such leaks. Dow stated that the commission should not automatically treat a major gas leak (over 50,000 ppmv) as a violation unless the leak was determined to be a violation under §101.201 (Emissions Event Reporting and Recordkeeping Requirements) or a violation under the applicable LDAR program. Dow stated that multiple regulations on the same major gas leak creates a scenario where sometimes one or the other regulation applies and other times, both regulations apply. Dow stated that this can become very difficult to implement and difficult to give detailed understanding to all site personnel who have a role and responsibility in environmental reporting.

The commission has reevaluated §115.788(e) and believes that the "extraordinary effort" requirements specified in §115.782(c)(2) and the audits conducted by regional and local program inspectors will largely eliminate the need for limitations on the number of leaking components specified in §115.788(e)(1) - (4). Therefore, the commission has deleted §115.788(e)(1) - (4).

§115.788(e)(4)

Ethyl stated that the maximum number of leaking components in §115.788(e)(4), including connectors, should always be a percentage of the total component type amount and not an absolute amount, to account for differences in size and complexity of facilities. ExxonMobil and TxOGA stated that the set number limits of allowable major leakers does not give due consideration to the larger facilities. Ethyl also stated that newly monitored components should be exempt from violation criteria until after the first or second round of monitoring of the newly required components, to allow adequate time to repair or replace leaking components which are new to the LDAR system.

The commission agrees with the commenters. However, as described earlier in this preamble in response to the previous comment, the commission has deleted §115.788(e)(1) - (4).

COMPLIANCE SCHEDULE

ExxonMobil stated that the compliance schedule for any needed HRVOC controls should be extended to March 31, 2007, as it is unreasonable to expect a facility to plan, engineer, construct, and initiate start-up and post start-up actions on a control device with a single year. ExxonMobil stated that a compliance date of March 31, 2007 would allow facilities to complete testing as proposed on December 31, and mandate that they are in compliance by the start of the ozone season for the attainment year. BCCA-AG and Lyondell expressed similar concerns as ExxonMobil and suggested the following compliance dates: for vent gas, March 31, 2007; for the cooling tower monitoring requirements, July 31, 2004 (with the availability of an extension if a process unit shutdown is required to install a monitoring device); and for flares, a date that is consistent with unit turnaround schedules specific to each owner or operator (with owners and operators allowed to request alternate implementation schedules along with their monitoring plans). Phillips stated that the compliance schedule for implementation of many of the proposed requirements is infeasible and that monitoring equipment and analyzer installation projects would be expected to require a timeline of at least 18 months for engineering, procurement, and construction. Phillips commented that additional complicating considerations are the number of construction projects already required for NO _x reduction and low-sulfur fuels, the demand for similar systems by a large number of sources in the area (supply and installation issues), and the potential need to coordinate unit shutdowns for installation. OxyChem suggested a compliance schedule of at least two years for all initial requirements, and at least three years for rules which require a process modification or addition of equipment. TCC stated that the monitoring requirements are excessive and cannot be implemented according to the proposed schedule.

The commission has made a number of revisions to the proposed rules, as described elsewhere in this preamble, to address the concerns raised by the commenters about conducting tests, as well as installation of control equipment and monitoring equipment, necessary to comply with these rules. The commission believes it is reasonable and practical to comply with the limitations by the specified compliance dates for the reasons given in the following paragraphs in this section of the preamble.

Industrial Wastewater

§115.149(e)

Dow, DuPont, TCC, and TxOGA stated that the compliance date in §115.149(e) is inadequate where new process drain controls are required. Specifically, Dow and DuPont recommended a December 31, 2003 compliance date, while TxOGA stated that the proposed April 30, 2003 compliance date is adequate for existing controlled drains, but that the compliance date for new required controls on wastewater systems should be December 31, 2005. TxOGA suggested that at a minimum, an extension provision is needed where new controls are required on process drains involving construction. TCC also recommended inclusion of a provision that would allow an extension approved by the executive director beyond the December 31, 2003 compliance date if a process unit shutdown is required to install the required equipment.

The commission agrees with Dow and DuPont and has revised the compliance date to December 31, 2003. The commission has not added a compliance date extension because §115.950 provides that an owner or operator may meet the emission control requirements of Chapter 115, in whole or in part, by obtaining ERCs, mobile emission reduction credits (MERC), DERCs, or mobile discrete emission reduction credits (MDERC) in accordance with §115.950 and Chapter 101, Subchapter H, Division 1 (Emission Credit Banking and Trading) or Chapter 101, Subchapter H, Division 4 (Discrete Emission Reduction Banking and Trading). Therefore, Chapter 115 already includes an appropriate mechanism for addressing situations in which a process unit shutdown is necessary to install the controls on process drains.

§115.149(f)

Dow, DuPont, and TCC stated that the compliance date in §115.149(f), which establishes a repair schedule, should be extended to December 31, 2003 for consistency with §115.149(e).

The commission agrees and has revised the compliance date to December 31, 2003.

§115.149(g)

Dow and DuPont stated that the compliance date in §115.149(g), which establishes an inspection for water seals and process drains not equipped with water seals, should be extended to December 31, 2003 for consistency with §115.149(e).

The commission agrees and has revised the compliance date to December 31, 2003.

TCC stated that §115.149(g) should be changed to reflect weekly water seal inspections rather than daily.

The commission has revised §115.149(g) for consistency with the changes to §115.144(5) and (6) described earlier in this preamble.

VOC Fugitive Emissions

§115.359(1)

TxOGA commented on §115.359(1) and stated that §115.930 speaks for itself and does not need to be repeated in this section.

The reference to §115.930 is included to make clear the compliance date for requirements for which a specific compliance date is not given in the rules. This reference is necessary and was added in previous rulemaking due to confusion expressed by TxOGA member companies.

§115.359(2) and (3)

DuPont, ExxonMobil, TCC, and TxOGA stated that the compliance date in §115.359(2) and (3) is inadequate. DuPont recommended a December 31, 2003 compliance date, while ExxonMobil, TCC, and TxOGA recommended a compliance date of 12 months after promulgation (essentially identical to a December 31, 2003 compliance date). TCC also suggested adding the availability of extensions by the executive director for special circumstances (e.g., if a supplier was not able to modify purchased LDAR database software for the company to meet the deadline).

The commission agrees with the commenters and has revised the compliance date in §115.359(2) and (3) to December 31, 2003. Because the commission has extended the compliance date, it has not added a compliance date extension. However, the commission has revised §115.359(2) to clarify that the compliance date applies to the requirements of §115.356(1)(E)(ii).

§115.359(4)

TCC commented on §115.359(4), which specifies a December 31, 2003 compliance date for adjusting the measured VOC concentration using the appropriate relative response factor specified in §115.354(11). TCC stated that §115.359(4) should be deleted because §115.354(11) is impractical to implement.

As noted earlier in this preamble, the commission concluded that issues associated with response factors are complex. Therefore, the commission has deleted §115.354(11) and §115.781(b)(10) and has renumbered subsequent paragraphs accordingly. The commission also deleted the compliance schedule in §115.359(4) and §115.789(9) for the now-deleted §115.354(11) and §115.781(b)(10).

HRVOC Vent Gas

Dow commented that paragraphs within other sections of this division are lettered (a), (b), (c), etc., and §115.729 is numbered (1) and (2). Dow stated that a consistent numbering system should be used throughout the division.

The numbering of proposed §115.729 is in accordance with Texas Register requirements.

§115.729(1)

DuPont and Goodyear-Houston commented on the December 31, 2003 compliance date in the proposed §115.729(1) and recommended that testing of process vents be completed within 18 months of rule promulgation (i.e., June 30, 2004) and test results be submitted within 30 days of testing. Goodyear-Houston recommended a December 31, 2004 compliance date due to the large number of vents that may need to be tested. TCC recommended that completion of testing be required by December 31, 2003, with the submittal of the test results within 30 days after completion of the test or as soon as practical, whichever is sooner.

The proposed §115.729(1) was renumbered as §115.729(1)(A). The commission has considered the comments and believes that the most appropriate compliance date for completion and submittal of testing results is June 30, 2004. This will allow approximately 18 months from the effective date of the rule revisions for testing of process vents. The additional six months being added to the proposed compliance date is necessary due to the number of vents that will need to be tested. If a later compliance date were selected, such as the December 31, 2004 date suggested by Goodyear-Houston, there might not be enough time remaining for affected companies to install controls on vents that need to be controlled by the April 1, 2006 compliance date described in the response to the following comment.

§115.729(2)

Dow, DuPont, Goodyear-Houston, and TCC commented on the December 31, 2004 compliance date in the proposed §115.729(2). Dow stated that any future control requirements for low density polyethylene production facilities subject to §115.722(a) should have a compliance date no earlier than December 31, 2005, based on its estimate of 29 months needed to implement multiple LDPE production line retrofits. Dow and TCC stated that a December 31, 2005 compliance date will also be consistent with the flare and cooling tower compliance dates. DuPont expressed similar comments and also recommended a December 31, 2005 compliance date. Goodyear-Houston recommended a March 31, 2007 compliance date. TCC stated that the compliance date should include a provision that would allow extension on a case-by-case basis approved by the executive director if the installation of any needed emission controls requires a process unit shutdown and that process unit shutdown is not planned prior to the recommended December 31, 2005 compliance date.

The proposed §115.729(2) was renumbered as §115.729(1)(B). The commission has considered the comments and believes that the most appropriate compliance date is April 1, 2006. This compliance date will allow 21 months after the testing deadline for the installation of controls on vents that need to be controlled, and is slightly more than three years from the effective date of the rule revisions. The commission notes that 42 USC, §7410 and §7502(a)(2), require the state to submit a revised SIP which demonstrates that the area will attain the ozone standard as expeditiously as practicable. A compliance schedule that shifted the HRVOC vent gas emission reductions beyond April 1, 2006 would not meet the "as expeditiously as practicable" requirement.

Because the commission has extended the compliance date, it has not added a compliance date extension. In addition, §115.722 establishes a site-wide cap which limits HRVOC emissions at a site to a capped value. The site-wide cap provides each owner or operator with the maximum flexibility to select the most cost-effective and technically feasible method of controlling emissions, and to address situations such as those described by the commenters. Therefore, Chapter 115 already includes an appropriate mechanism for addressing situations in which the installation of any needed emission controls requires a process unit shutdown and that process unit shutdown is not planned prior to the April 1, 2006 compliance date.

HRVOC Flares

TCC commented that the April 30, 2003 compliance date for submittal of data if it is already available should be deleted, and that one compliance date should be used for all regulated entities. TCC and Dow also commented that the compliance date for instrumentation and emissions limits should be changed to December 31, 2005 (for HRVOC flares), and TCC recommended to July 31, 2004 (for HRVOC cooling towers), citing the lengthy timing required to coordinate a project of this magnitude.

The proposed §115.749 was relocated to §115.729(2). The commission has considered the comments and believes that the most appropriate compliance date is December 31, 2004 for demonstrating compliance with the flare monitoring, testing, recordkeeping, and reporting requirements. The commission further believes that the most appropriate compliance date is April 1, 2006 for demonstrating continuous compliance with the site-wide HRVOC cap. This compliance date will allow 15 months after the deadline for the flare monitoring, testing, recordkeeping, and reporting requirements, and is slightly more than three years from the effective date of the rule revisions. The commission notes that 42 USC, §7410 and §7502(a)(2), require the state to submit a revised SIP which demonstrates that the area will attain the ozone standard as expeditiously as practicable. A compliance schedule that shifted the HRVOC emission reductions beyond 2005 would not meet the "as expeditiously as practicable" requirement.

Because the commission has extended the compliance date, it has not added a compliance date extension. In addition, §115.722 establishes a site-wide cap which limits HRVOC emissions at a site to a capped value. The site-wide cap provides each owner or operator with the maximum flexibility to select the most cost-effective and technically feasible method of controlling emissions, and to address situations such as those described by the commenters. Therefore, Chapter 115 already includes an appropriate mechanism for addressing situations in which the installation of any needed emission controls requires a process unit shutdown and that process unit shutdown is not planned prior to the April 1, 2006 compliance date.

HRVOC Flares and Cooling Towers

§115.749 and §115.769

ED stated that although the flare and cooling tower monitoring rules are required by December 2003, implementation of controls does not take place until December 2005. ED asserted that the commission has not provided any basis for a three-year schedule for compliance with rules that it expects industry to comply with through best management practices. ED stated that the compliance date should be advanced in order to ensure that the next major air quality field study can determine the effectiveness of these rules. ED stated that commission staff and the Texas Environmental Research Consortium have discussed the possibility of a major follow-up to TexAQS 2000 in 2005. ED asserted that the commission should require that its industrial VOC control strategy be in place before that field study, although the commission could extend deadlines on a case-by-case basis.

The commission disagrees. The commission believes that in order for industry to comply with the emission limitations specified in the rules, that it will need to develop detailed and effective emission mitigation plans. The commission believes that before emission mitigation plans can be conducted, industry must have adequate monitoring information to characterize the streams and develop what appropriate mitigation measures can occur at reasonable interim thresholds. The commission does not believe that an April 1, 2006 compliance date represents an unreasonable amount of time to expect this to occur and believes that in many cases, requiring compliance any sooner may result in ineffective plans.

HRVOC Cooling Towers

§115.769

BCCA-AG, Goodyear, and Lyondell opposed the December 31, 2003 compliance date. BCCA- AG and Lyondell commented that meeting the proposed December 31, 2003 compliance date will be very difficult due to potential shortages in supply of on-line monitoring systems. BCCA-AG and Lyondell recommended that the compliance date be extended to July 31, 2004, and that the rule should allow for extensions of this deadline if process unit shutdowns are required to install monitoring systems. BCCA-AG and Lyondell commented that the December 31, 2003 compliance deadline for the completion of design, engineering, procurement, construction, and startup of all new facilities should be harmonized with planned turnarounds, and that affected companies should be allowed to request alternate implementation schedules along with their monitoring plans.

The commission has considered the comments and believes that the most appropriate compliance date is December 31, 2004 for demonstrating compliance with the cooling tower monitoring, testing, recordkeeping, and reporting requirements. The commission further believes that the most appropriate compliance date is April 1, 2006 for demonstrating continuous compliance with the site-wide HRVOC cap. This compliance date will allow 15 months after the deadline for the cooling tower monitoring, testing, recordkeeping, and reporting requirements, and is slightly more than three years from the effective date of the rule revisions. The commission notes that 42 USC, §7410 and §7502(a)(2), require the state to submit a revised SIP which demonstrates that the area will attain the ozone standard as expeditiously as practicable. A compliance schedule that shifted the HRVOC emission reductions beyond April 1, 2006 would not meet the "as expeditiously as practicable" requirement.

Because the commission has extended the compliance date, it has not added a compliance date extension. In addition, §115.761 establishes a site-wide cap which limits HRVOC emissions at a site to a capped value. The site-wide cap provides each owner or operator with the maximum flexibility to select the most cost-effective and technically feasible method of controlling emissions, and to address situations such as those described by the commenters. Therefore, Chapter 115 already includes an appropriate mechanism for addressing situations in which the installation of any needed emission controls requires a process unit shutdown and that process unit shutdown is not planned prior to the April 1, 2006 compliance date.

HRVOC Fugitive Emissions

§115.789

Sierra-Lone Star fully supported December 31, 2002 as the first compliance date, but Sierra- Houston and Sierra-Lone Star objected to the final compliance date of March 31, 2007 because it places compliance too late in the ozone nonattainment schedule to make a determination if the rules are being complied with in a meaningful way. Sierra-Houston and Sierra-Lone Star requested a compliance date of 2005 to give additional time for the program to work and to give the commission two years to see how ambient ozone concentrations are affected by the fugitive emissions control measure. ExxonMobil stated that in general, the compliance dates in §115.789 are too soon to be practicably met, and that many changes will require much more time to properly implement. ExxonMobil also stated that some of the more difficult changes with less emission reduction impact should be dropped until seen to be justified at the MCR in 2004. ATOFINA expressed a belief that identifying and tagging components will require significant input from its operations and engineering staff, and just entering this new data into the existing database for thousands of components will be a major undertaking which cannot be completed by December 31, 2003. ATOFINA suggested that the commission establish a more realistic schedule requiring completion by December 31, 2005. DuPont, and TxOGA expressed similar concerns. DuPont, TCC, and TxOGA suggested adding the availability of extensions by the executive director for special circumstances (e.g., if a supplier was not able to modify purchased LDAR database software for the company to meet the deadline). TxOGA also recommended that §115.789(1) provide at least 18 months from rule promulgation (i.e., approximately June 30, 2004) for the addition of components to be monitored, while TCC believed that §115.789(1) and (5) should provide a compliance date at least 12 months from rule promulgation (i.e., approximately December 31, 2003). TCC stated that a transitional stage, as was done in the HON, should be provided in §115.789(1) for monitoring of additional components such as flanges and heat exchanger heads because these components have not historically been monitored.

The revisions to §115.783, described earlier in this preamble, deleted requirements for equipment upgrades on pumps, compressors, agitators, PRVs (for rupture disks), and valves other than PRVs. The remaining situations in which an equipment upgrade are required are expected to be relatively limited in number and difficulty. For example, installation of a car seal to secure a bypass valve in a closed position could be readily accomplished in under an hour. As noted earlier in this preamble, §115.781(f) provides the availability of a leak-skip option for connectors, bolted manways, heat exchanger heads, hatches, and sump covers. Also, the commission clarified that connectors do not have to be individually tagged. For any equipment upgrades for which a process unit shutdown is necessary, but for which the shutdown will not occur by the compliance date, §115.950 provides that an owner or operator may meet the emission control requirements of Chapter 115, in whole or in part, by obtaining ERCs, MERCs, DERCs, or MDERCs in accordance with §115.950 and Chapter 101, Subchapter H, Division 1 (Emission Credit Banking and Trading) or Chapter 101, Subchapter H, Division 4 (Discrete Emission Reduction Banking and Trading). Therefore, the commission believes that a December 31, 2003 compliance date is appropriate because it provides an adequate amount of time for implementation of the new requirements. In addition, due to the revisions to §115.786(e) (relettered as §115.786(d)) described earlier in this preamble, the commission revised §115.789(5) to refer to the recordkeeping requirements of §115.786 rather than the master components list.

ATOFINA stated that it self-imposed a leak definition rate of 500 ppmv prior to the rule proposal and is already monitoring many of the components identified in the proposed fugitive monitoring rules. ATOFINA stated that the number of leakers found in each unit increased significantly upon implementing the 500 ppmv limit, and that initially the company was unable to meet repair deadlines. ATOFINA stated that it took about one year to be able to respond to leaks in the specified time periods, and expressed a belief that companies imposing the 500 ppmv leak definition for the first time will face the same situation. ATOFINA recommended that the final rule allow facilities to slowly phase in repair requirements over a reasonable time period.

The commission questions how ATOFINA could have "self-imposed" a leak definition rate of 500 ppmv when 500 ppmv is already the leak definition for some components as required by the existing Subchapter D, Division 3. The commission believes that the compliance schedule, in conjunction with the availability of a leak-skip option in §115.781(f) for connectors, bolted manways, heat exchanger heads, hatches, and sump covers, provides an adequate amount of time for implementation of the new requirements.

§115.789(2)

TxOGA stated that the installation of controls on all process drains not currently controlled by either a water seal or cap or plug needs to be clarified as being an "equipment upgrade" for the purpose of §115.789(2). TxOGA also stated there may be isolated cases where the equipment upgrade cannot be done at the next unit shutdown, and suggested changing the phrase "at the next unit shutdown after December 31, 2002" to "as soon as practicable." TCC stated that the compliance date should be revised to "at the next planned unit shutdown after July 1, 2003 but no later than 5 years after the effective date of this rule" (i.e., approximately December 31, 2007). Dow stated that the compliance date should be revised to "at the next scheduled or planned unit shutdown after December 31, 2004, but no later than 5 years after the effective date of this rule" (i.e., approximately December 31, 2007). Dow stated that it was important to clarify that the retrofit requirements are only triggered when there is a planned or scheduled shutdown, not an unplanned shutdown. Dow stated that otherwise, it will be difficult to complete the engineering needed, order additional equipment, and have the parts ready to install if an unplanned unit shutdown occurs.

The revisions to §115.783, described earlier in this preamble, deleted requirements for equipment upgrades on pumps, compressors, agitators, pressure relief valves (for rupture disks), and valves other than pressure relief valves. The remaining situations in which an equipment upgrade are required are expected to be relatively limited in number and difficulty. For example, installation of a car seal to secure a bypass valve in a closed position could be readily accomplished in under an hour. The commission has retained the compliance date of December 31, 2003 and has not added a compliance date extension because §115.950 provides that an owner or operator may meet the emission control requirements of Chapter 115, in whole or in part, by obtaining ERCs, MERCs, DERCs, or MDERCs in accordance with §115.950 and Chapter 101, Subchapter H, Division 1 (Emission Credit Banking and Trading) or Chapter 101, Subchapter H, Division 4 (Discrete Emission Reduction Banking and Trading). Therefore, Chapter 115 already includes an appropriate mechanism for addressing situations in which a process unit shutdown is necessary to install the controls on process drains.

§115.789(3)

Dow and TCC commented on §117.789(3) and stated that the compliance date for the first third-party audit should be 12 months after the complete implementation of other requirements of the rule. Dow and TCC stated that if the timing remains the same as the timing requirement for implementing these other requirements, the audit will not provide an appropriate indication of how well the new requirements have been implemented.

The commission agrees that the initial should occur after the final compliance date for the other HRVOC fugitive monitoring requirements. Because §115.788(a)(2)(B) references the average of the most recent four quarters in the determination of the number of components in a process unit to be audited, the commission agrees that the appropriate compliance date for the initial audit is 12 months after the final compliance date for the other HRVOC fugitive monitoring requirements. Therefore, the commission has revised §115.789(3) accordingly.

§115.789(4)

TCC stated that §115.789(4), which establishes a compliance date for the testing required by §115.785, should include a provision which would allow the use of historical performance tests that are substantially similar in lieu of conducting another performance test at the same control device.

As noted earlier in this preamble, the commission added §115.785(5) to allow previous valid test results.

§115.789(7)

DuPont and TCC recommended deletion of §115.789(7).

As noted earlier in this preamble, the commission agrees that an additional round of monitoring during the third quarter presents staffing difficulties and deleted the proposed §115.781(b)(7). Therefore, the commission has also deleted §115.789(7).

§115.789(9)

TCC recommended deletion of §115.789(9), which establishes a compliance date for adjustment of measured VOC concentration using the appropriate relative response factor specified in §115.781(b)(10). TCC referred to its earlier comments in which it asserted that §115.781(b)(10) is impractical to implement.

As noted earlier in this preamble, the commission concluded that issues associated with response factors are complex. Therefore, the commission has deleted §115.354(11) and §115.781(b)(10) and has renumbered subsequent paragraphs accordingly. The commission also deleted the compliance schedule in §115.359(4) and §115.789(9) for the now-deleted §115.354(11) and §115.781(b)(10).

COST

Phillips gave several examples of cost-effective requirements to update emissions inventories which included monthly monitoring of cooling towers for determination of VOC leaks and emissions inventory; periodic grab samples of normal, routine flare flow to establish baselines and improved emission inventory data; weekly visual monitoring of process drains and unsegregated stormwater drains; and requirements to use correlation equations and actual data from fugitives monitoring to provide a better representation of emissions for the emissions inventory.

The commission appreciates the support.

Ethyl stated that many companies (including Ethyl) have already committed to reduce NO _x emissions according to the existing SIP, and that the proposed HRVOC requirements will cause "undue financial harm" to such companies trying to reduce emissions in an orderly, cost-effective manner.

Ethyl did not include documentation to support its claim of "undue financial harm." However, the commission appreciates the support for the current requirements.

TCC stated that the commission underestimated the costs for compliance with the rules and has provided no estimate of environmental benefits in terms of cost of control per ton of emission reduction. Because of the costs involves in the VOC/HRVOC portions of the proposed rules, TxOGA expressed the belief that the commission must promulgate only requirements with commensurate environmental value. ATOFINA expressed a concern that the proposed rules will impose an unnecessary significant financial burden on industry. Ethyl stated that the commission has underestimated the annual reporting costs for increased flare, cooling tower, and LDAR monitoring, and that the commission has not provided adequate substantiation for the estimates of the increased costs associated with the reporting requirements. BCCA-AG and Lyondell stated that the monitoring requirements are costly.

The commission complied with the requirements to provide estimated costs for compliance. The cost note in the proposal attempted to identify all additional costs to industry due to implementation of the proposed amendments. The analysis provided both capital and operating costs, including recordkeeping costs, by the various types of sources affected by the rules. The costs were provided for each of the particular subchapters where the commission has identified likely increased costs due to implementation of rule amendments. Although the commission identified significant costs to industry to implement the proposed VOC rule amendments, concurrent rulemaking that proposes the revisions of NO _x ESADs in Chapter 117 is estimated to save industry considerable capital and annual operating expenses. Therefore, the commission disagrees that it underestimated the cost to comply with the proposed rules. Further, since the commission is not adopting the general VOC monitoring rules proposed in Subchapter B, Divisions 7 and 8, the costs to comply will be lower than those included in the fiscal note.

The commission has complied with the requirement to provide the public benefits expected and probable economic costs for compliance with the rule. There is no specific requirement to provide the estimate of environmental benefits in any specific units, such as cost of control per ton of emission reduction. In addition, there is no specific requirement that the limits the commission to only adopting rules with environmental value that is commensurate with the costs.

LDPE Plants

Dow and ExxonMobil commented that there does not appear to be adequate cost analysis for the proposed emission levels in §115.722(a) for low and high-pressure polyethylene processes. Dow stated that, based upon a preferred technology of replacing existing extruders with a vacuum type extruder, the capital cost will range from $7 million per manufacturing line for its smaller processing areas to $13 million per manufacturing line for its larger processing areas. TCC stated that in certain polyethylene manufacturing operations, the finishing area for the polyethylene flakes and pellets consists of tanks, numerous vents that are open to atmosphere, and loading facilities that move polyethylene pellets and flakes to railcars. TCC stated that the emissions from these processes are expected to be relatively small in comparison to other VOC sources, but the cost to capture these emissions and convey them to a recovery system is expected to be so costly ($40,000/ton of emission reduced) as to necessitate the need for some type of VOC trading program.

As noted earlier in this preamble, the commission is adopting a site-wide HRVOC emissions cap in place of the proposed individual (i.e., unit by unit) emission limits. The site-wide cap addresses the commenters' concerns because it enables each owner or operator to select the most cost-effective and technically feasible means of maintaining continuous compliance with the site- wide cap. Therefore, the commission has made no changes in response to the comments.

Flares

BCCA-AG and Lyondell commented that the commission did not provide an analysis and summary of the installation costs for flare gas compression and other similar flare gas recovery devices which would be necessary to comply with the proposed rule. BCCA-AG and Lyondell stated that the costs can easily range from $5 million to $10 million per flare system.

The commission has not contacted vendors of alternative technology; however, these system costs could be substantial, and costs in the suggested range or more might be possible. It is important to note that control systems as complex and expensive as those mentioned by the commenters will not be necessary in all cases to comply with the rule. Devices which control vent gas streams on the process side, such as recovery devices (including, but not limited to, absorbers, carbon adsorbers, and condensers), would be preferred from the cost standpoint, and more costly alternatives on the flare side, such as flare gas compression and similar flare gas recovery devices, should be considered as the solution of last resort.

BCCA-AG and Lyondell commented that the commission significantly underestimated the costs of continuous flow monitoring for HRVOC flares. BCCA-AG and Lyondell cited the commission's estimate that the combined cost of the on-line analyzer, flow monitor, and temperature and pressure gauges for each HRVOC flare would be only $90,000 in the first year and $20,000 in subsequent years. BCCA-AG and Lyondell disagreed, stating that the cost of installation alone of flow monitoring systems is estimated to be about $75,000 per flare.

The cited cost figures are considerably higher than the cost information available to the commission. The commission's $2,000 - 10,000 cost estimate for flow monitors was based on vendor contacts, and the commission estimated GC costs of $30,000 - 50,000 per instrument. The commission's experience indicates that $75,000 is extremely high for a flow monitor installation. Installation costs for the VOC monitor will depend on availability of existing facilities to house the monitor system.

Cooling Towers

BCCA-AG and Lyondell commented that the preamble to the proposed rules grossly underestimates the necessary costs by a factor of three to four. BCCA-AG and Lyondell stated that the commission has estimated the initial capital costs and annual operating expenses for the first year for continuous monitors and on-line gas analyzers for each HRVOC cooling tower system in the HGA at $88,000. BCCA-AG and Lyondell also stated that because the rule would require flow meters and analyzers to be installed on both the inlet and the outlet of each cooling tower, at a cost of at least $30,000 per flow meter and $115,000 per analyzer, the cost of this equipment alone is at least $235,000. BCCA-AG and Lyondell commented that when the costs of analyzer housing facilities, installation, and process computer tie-ins are included, the total capital costs for a cooling tower system that serves many process units and has cooling water supply and return loops will be in the $1 2 million range. BCCA-AG and Lyondell stated that when annual operating costs are considered, the commission's estimates are even further underestimated.

The commission has obtained vendor estimates of $20,000 to 88,000 for HRVOC monitors, with the low-end cost corresponding to total VOC monitors and the upper end corresponding to speciated VOC monitors. Information supplied by instrument suppliers indicates that the cost of a cooling tower flow monitor to handle water flows up to 180,000 gpm is approximately $6,000 - 8,000. The commission has eliminated the requirement to install a flow monitor on each cooling tower outlet. The commission realizes that there are additional costs to install monitor systems, with installed costs depending on the cooling tower size and complexity. A cost of $1 2 million as suggested by BCCA-AG and Lyondell appears to be quite high, considering that the adopted rules contain cooling tower monitoring requirements that are less stringent than those proposed. A continuous speciated VOC monitor may offset the cost of monthly or daily speciated lab analyses. Finally, smaller cooling tower systems (less than 8,000 gpm) do not have continuous VOC monitoring requirements.

Fugitive Emissions

TCC asserted that the commission has underestimated the complexity and cost of retrofitting existing PRV systems. TCC stated that the one-time cost for installation of rupture disks at a typical petrochemical plant is expected to be $6,000 - 8,000 per device plus installation, but that costs could easily escalate if significant piping changes are required or if vessel nozzles must be changed to meet inlet line pressure loss constraints. TCC stated that the installation of a rupture disk upstream of a PRV will result in increased pressure drop in the line and, as a result, will require the relief system to be reevaluated. TCC stated that whenever a rupture disk is installed upstream of a relief valve, there is a need to derate the available relief area by 10% per ASME Section VIII, such that the size of the relief valve may need to be increased to accommodate the derating. TCC stated that this is expensive.

The commission appreciates TCC's concerns. However, as noted earlier in this preamble, the commission has revised the requirements for PRVs such that retrofitting with rupture disks is not required.

Dow, EnRUD, and Goodyear-Beaumont commented that the mass emissions sampling method ("bagging") of the EPA guidance document "Protocol for Equipment Leak Emission Estimates," Chapter 4, Mass Emission Sampling (EPA-453/R-95-017, November 1995) is a costly task.

The commission agrees and has revised the rules to specify that bagging is not required, but is an available method for estimating mass emissions.

DuPont stated that the proposed fugitive monitoring requirements are extremely burdensome and expressed concern that the commission has significantly underestimated the cost of the proposed rules. DuPont also expressed concern that economically stressed businesses will be burdened, with little or no environmental benefit.

As described earlier in this preamble, the commission has made numerous revisions in the proposed rules to address commenters' concerns and ensure that the requirements are reasonable and appropriate.

Subchapter A. DEFINITIONS

30 TAC §115.10

STATUTORY AUTHORITY

The amendment is adopted under Texas Water Code (TWC), §5.103, which provides the commission the authority to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, TCAA, §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the TCAA. The amendment is also adopted under TCAA, §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.034, concerning Research and Investigations, which authorizes the commission to require any research it considers advisable and necessary to perform its duties; and §382.051(d), concerning Permitting Authority of Commission; Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382; and FCAA, 42 USC, §§7401 et seq .

§115.10.Definitions.

Unless specifically defined in the Texas Clean Air Act (TCAA) or in the rules of the commission, the terms used by the commission have the meanings commonly ascribed to them in the field of air pollution control. In addition to the terms which are defined by the TCAA, the following terms, when used in this chapter (relating to Control of Air Pollution from Volatile Organic Compounds), shall have the following meanings, unless the context clearly indicates otherwise. Additional definitions for terms used in this chapter are found in §3.2 and §101.1 of this title (relating to Definitions).

(1) Background--The ambient concentration of volatile organic compounds (VOC) in the air, determined at least one meter upwind of the component to be monitored. Test Method 21 (40 Code of Federal Regulations (CFR) 60, Appendix A) shall be used to determine the background.

(2) Beaumont/Port Arthur area--Hardin, Jefferson, and Orange Counties.

(3) Capture efficiency--The amount of VOC collected by a capture system which is expressed as a percentage derived from the weight per unit time of VOC entering a capture system and delivered to a control device divided by the weight per unit time of total VOC generated by a source of VOC.

(4) Carbon adsorption system--A carbon adsorber with an inlet and outlet for exhaust gases and a system to regenerate the saturated adsorbent.

(5) Closed-vent system--A system that:

(A) is not open to the atmosphere;

(B) is composed of piping, ductwork, connections, and, if necessary, flow-inducing devices; and

(C) transports gas or vapor from a piece or pieces of equipment directly to a control device.

(6) Component--A piece of equipment, including, but not limited to, pumps, valves, compressors, connectors, and pressure relief valves, which has the potential to leak VOC.

(7) Connector--A flanged, screwed, or other joined fitting used to connect two pipe lines or a pipe line and a piece of equipment. The term connector does not include joined fittings welded completely around the circumference of the interface. A union connecting two pipes is considered to be one connector.

(8) Continuous monitoring--Any monitoring device used to comply with a continuous monitoring requirement of this chapter will be considered continuous if it can be demonstrated that at least 95% of the required data is captured.

(9) Covered attainment counties--Anderson, Angelina, Aransas, Atascosa, Austin, Bastrop, Bee, Bell, Bexar, Bosque, Bowie, Brazos, Burleson, Caldwell, Calhoun, Camp, Cass, Cherokee, Colorado, Comal, Cooke, Coryell, De Witt, Delta, Ellis, Falls, Fannin, Fayette, Franklin, Freestone, Goliad, Gonzales, Grayson, Gregg, Grimes, Guadalupe, Harrison, Hays, Henderson, Hill, Hood, Hopkins, Houston, Hunt, Jackson, Jasper, Johnson, Karnes, Kaufman, Lamar, Lavaca, Lee, Leon, Limestone, Live Oak, Madison, Marion, Matagorda, McLennan, Milam, Morris, Nacogdoches, Navarro, Newton, Nueces, Panola, Parker, Polk, Rains, Red River, Refugio, Robertson, Rockwall, Rusk, Sabine, San Jacinto, San Patricio, San Augustine, Shelby, Smith, Somervell, Titus, Travis, Trinity, Tyler, Upshur, Van Zandt, Victoria, Walker, Washington, Wharton, Williamson, Wilson, Wise, and Wood Counties.

(10) Dallas/Fort Worth area--Collin, Dallas, Denton, and Tarrant Counties.

(11) El Paso area--El Paso County.

(12) External floating roof--A cover or roof in an open-top tank which rests upon or is floated upon the liquid being contained and is equipped with a single or double seal to close the space between the roof edge and tank shell. A double seal consists of two complete and separate closure seals, one above the other, containing an enclosed space between them. For the purposes of this chapter, an external floating roof storage tank which is equipped with a self-supporting fixed roof (typically a bolted aluminum geodesic dome) shall be considered to be an internal floating roof storage tank.

(13) Fugitive emission--Any VOC entering the atmosphere which could not reasonably pass through a stack, chimney, vent, or other functionally equivalent opening designed to direct or control its flow.

(14) Gasoline bulk plant--A gasoline loading and/or unloading facility, excluding marine terminals, having a gasoline throughput less than 20,000 gallons (75,708 liters) per day, averaged over each consecutive 30-day period. A motor vehicle fuel dispensing facility is not a gasoline bulk plant.

(15) Gasoline terminal--A gasoline loading and/or unloading facility, excluding marine terminals, having a gasoline throughput equal to or greater than 20,000 gallons (75,708 liters) per day, averaged over each consecutive 30-day period.

(16) Heavy liquid--VOCs which have a true vapor pressure equal to or less than 0.044 pounds per square inch absolute (psia) (0.3 kPa) at 68 degrees Fahrenheit (20 degrees Celsius).

(17) Highly-reactive volatile organic compound (HRVOC)--As follows.

(A) In Harris County, one or more of the following VOCs: 1,3-butadiene; all isomers of butene (i.e., alpha-butylene (ethylethylene) and beta-butylene (dimethylethylene, including both cis- and trans- isomers)); ethylene; and propylene.

(B) In Brazoria, Chambers, Fort Bend, Galveston, Liberty, Montgomery, and Waller Counties, one or more of the following VOCs: ethylene and propylene.

(18) Houston/Galveston area--Brazoria, Chambers, Fort Bend, Galveston, Harris, Liberty, Montgomery, and Waller Counties.

(19) Incinerator--For the purposes of this chapter, an enclosed control device that combusts or oxidizes VOC gases or vapors.

(20) Internal floating cover--A cover or floating roof in a fixed roof tank which rests upon or is floated upon the liquid being contained, and is equipped with a closure seal or seals to close the space between the cover edge and tank shell. For the purposes of this chapter, an external floating roof storage tank which is equipped with a self-supporting fixed roof (typically a bolted aluminum geodesic dome) shall be considered to be an internal floating roof storage tank.

(21) Leak-free marine vessel--A marine vessel whose cargo tank closures (hatch covers, expansion domes, ullage openings, butterworth covers, and gauging covers) were inspected prior to cargo transfer operations and all such closures were properly secured such that no leaks of liquid or vapors can be detected by sight, sound, or smell. Cargo tank closures shall meet the applicable rules or regulations of the marine vessel's classification society or flag state. Cargo tank pressure/vacuum valves shall be operating within the range specified by the marine vessel's classification society or flag state and seated when tank pressure is less than 80% of set point pressure such that no vapor leaks can be detected by sight, sound, or smell. As an alternative, a marine vessel operated at negative pressure is assumed to be leak-free for the purpose of this standard.

(22) Light liquid--VOCs which have a true vapor pressure greater than 0.044 psia (0.3 kPa) at 68 degrees Fahrenheit (20 degrees Celsius), and are a liquid at operating conditions.

(23) Liquefied petroleum gas--Any material that is composed predominantly of any of the following hydrocarbons or mixtures of hydrocarbons: propane, propylene, normal butane, isobutane, and butylenes.

(24) Low-density polyethylene--A thermoplastic polymer or copolymer comprised of at least 50% ethylene by weight and having a density of 0.940 grams per cubic centimeter (g/cm ³ ) or less.

(25) Marine loading facility--The loading arm(s), pumps, meters, shutoff valves, relief valves, and other piping and valves that are part of a single system used to fill a marine vessel at a single geographic site. Loading equipment that is physically separate (i.e., does not share common piping, valves, and other loading equipment) is considered to be a separate marine loading facility.

(26) Marine loading operation--The transfer of oil, gasoline, or other volatile organic liquids at any affected marine terminal, beginning with the connections made to a marine vessel and ending with the disconnection from the marine vessel.

(27) Marine terminal--Any marine facility or structure constructed to transfer oil, gasoline, or other volatile organic liquid bulk cargo to or from a marine vessel. A marine terminal may include one or more marine loading facilities.

(28) Metal-to-metal seal--A connection formed by a swage ring which exerts an elastic, radial preload on narrow sealing lands, plastically deforming the pipe being connected, and maintaining sealing pressure indefinitely.

(29) Natural gas/gasoline processing--A process that extracts condensate from gases obtained from natural gas production and/or fractionates natural gas liquids into component products, such as ethane, propane, butane, and natural gasoline. The following facilities shall be included in this definition if, and only if, located on the same property as a natural gas/gasoline processing operation previously defined: compressor stations, dehydration units, sweetening units, field treatment, underground storage, liquified natural gas units, and field gas gathering systems.

(30) Petroleum refinery--Any facility engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants, or other products through distillation of crude oil, or through the redistillation, cracking, extraction, reforming, or other processing of unfinished petroleum derivatives.

(31) Polymer or resin manufacturing process--A process that produces any of the following polymers or resins: polyethylene, polypropylene, polystyrene, and styrenebutadiene latex.

(32) Pressure relief valve--A safety device used to prevent operating pressures from exceeding the maximum allowable working pressure of the process equipment. A pressure relief valve is automatically actuated by the static pressure upstream of the valve, but does not include:

(A) a rupture disk; or

(B) a conservation vent or other device on an atmospheric storage tank that is actuated either by a vacuum or a pressure of no more than 2.5 pounds per square inch gauge (psig).

(33) Process unit--The smallest set of process equipment that can operate independently and includes all operations necessary to achieve its process objective.

(34) Printing line--An operation consisting of a series of one or more printing processes and including associated drying areas.

(35) Process drain--Any opening (including a covered or controlled opening) which is installed or used to receive or convey wastewater into the wastewater system.

(36) Rupture disk--A diaphragm held between flanges for the purpose of isolating a VOC from the atmosphere or from a downstream pressure relief valve.

(37) Shutdown or turnaround--For the purposes of this chapter, a work practice or operational procedure that stops production from a process unit or part of a unit during which time it is technically feasible to clear process material from a process unit or part of a unit consistent with safety constraints, and repairs can be accomplished.

(A) The term shutdown or turnaround does not include a work practice that would stop production from a process unit or part of a unit:

(i) for less than 24 hours; or

(ii) for a shorter period of time than would be required to clear the process unit or part of the unit and start up the unit.

(B) Operation of a process unit or part of a unit in recycle mode (i.e., process material is circulated, but production does not occur) is not considered shutdown.

(38) Startup--For the purposes of this chapter, the setting into operation of a piece of equipment or process unit for the purpose of production or waste management.

(39) Synthetic organic chemical manufacturing process--A process that produces, as intermediates or final products, one or more of the chemicals listed in 40 Code of Federal Regulations §60.489 (October 17, 2000).

(40) Tank-truck tank--Any storage tank having a capacity greater than 1,000 gallons, mounted on a tank-truck or trailer. Vacuum trucks used exclusively for maintenance and spill response are not considered to be tank-truck tanks.

(41) Transport vessel--Any land-based mode of transportation (truck or rail) that is equipped with a storage tank having a capacity greater than 1,000 gallons which is used to transport oil, gasoline, or other volatile organic liquid bulk cargo. Vacuum trucks used exclusively for maintenance and spill response are not considered to be transport vessels.

(42) True partial pressure--The absolute aggregate partial pressure (psia) of all VOC in a gas stream.

(43) Vapor balance system--A system which provides for containment of hydrocarbon vapors by returning displaced vapors from the receiving vessel back to the originating vessel.

(44) Vapor control system or vapor recovery system--Any control system which utilizes vapor collection equipment to route VOC to a control device that reduces VOC emissions.

(45) Vapor-tight--Not capable of allowing the passage of gases at the pressures encountered except where other acceptable leak-tight conditions are prescribed in this chapter.

(46) Waxy, high pour point crude oil--A crude oil with a pour point of 50 degrees Fahrenheit (10 degrees Celsius) or higher as determined by the American Society for Testing and Materials Standard D97-66, "Test for Pour Point of Petroleum Oils."

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 18, 2002.

TRD-200208358

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 17, 2003

Proposal publication date: June 21, 2002

For further information, please call: (512) 239-0348

2. VENT GAS CONTROL

30 TAC §§115.120 - 115.123, 115.126, 115.127, 115.129

STATUTORY AUTHORITY

The amendments are adopted under TWC, §5.103, which provides the commission the authority to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, TCAA, §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the TCAA. The amendments are also adopted under TCAA, §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.034, concerning Research and Investigations, which authorizes the commission to require any research it considers advisable and necessary to perform its duties; and §382.051(d), concerning Permitting Authority of Commission; Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382; and FCAA, 42 USC, §§7401 et seq .

§115.123.Alternate Control Requirements.

(a) The alternate control requirements for vent gas streams in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston areas are as follows.

(1) Alternate methods of demonstrating and documenting continuous compliance with the applicable control requirements or exemption criteria in this division (relating to Vent Gas Control) may be approved by the executive director in accordance with §115.910 of this title (relating to Availability of Alternate Means of Control) if emission reductions are demonstrated to be substantially equivalent.

(2) The owner or operator of a synthetic organic chemical manufacturing industry (SOCMI) reactor process or distillation operation in which vent gas stream emissions are controlled by a control device with a control efficiency of at least 90% which was installed before December 3, 1993 may request an alternate reasonably available control technology (ARACT) determination. The executive director may approve the ARACT if it is determined to be economically unreasonable to replace the control device with a new control device meeting the requirements of §115.122(a)(2) of this title (relating to Control Requirements). Each ARACT approved by the executive director shall include a requirement that the control device be operated at its maximum efficiency. Each ARACT shall only be valid until the control device undergoes a replacement, a modification as defined in 40 Code of Federal Regulations (CFR) §60.14 (October 17, 2000), or a reconstruction as defined in 40 CFR §60.15 (December 16, 1975), at which time the replacement, modified, or reconstructed control device shall meet the requirements of §115.122(a)(2) of this title. Any request for an ARACT determination shall be submitted to the executive director in writing no later than May 31, 1994. The executive director may direct the holder of an ARACT to reapply for an ARACT if it is more than ten years since the date of installation of the control device and there is good cause to believe that it is now economically reasonable to meet the requirements of §115.122(a)(2) of this title. Within three months of an executive director request, the holder of an ARACT shall reapply for an ARACT. If the reapplication for an ARACT is denied, the holder of the ARACT shall meet the requirements of §115.122(a)(2) of this title as soon as practicable, but no later than two years from the date of the executive director's written notification of denial.

(b) For all persons in Nueces and Victoria Counties, alternate methods of demonstrating and documenting continuous compliance with the applicable control requirements or exemption criteria in this division may be approved by the executive director in accordance with §115.910 of this title if emission reductions are demonstrated to be substantially equivalent.

(c) For all persons in Aransas, Bexar, Calhoun, Matagorda, San Patricio, and Travis Counties, alternate methods of demonstrating and documenting continuous compliance with the applicable control requirements or exemption criteria in this division may be approved by the executive director in accordance with §115.910 of this title if emission reductions are demonstrated to be substantially equivalent.

§115.126.Monitoring and Recordkeeping Requirements.

The owner or operator of any facility which emits volatile organic compounds (VOC) through a stationary vent in Aransas, Bexar, Calhoun, Matagorda, Nueces, San Patricio, Travis, and Victoria Counties or in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston areas shall maintain the following information at the facility for at least five years, except that the five-year record retention requirement does not apply to records generated before December 31, 2000. The owner or operator shall make the information available upon request to representatives of the executive director, EPA, or any local air pollution control agency having jurisdiction in the area.

(1) Vapor control systems. For vapor control systems used to control emissions in Victoria County and in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston areas from vents subject to the provisions of §115.121 of this title (relating to Emission Specifications), records of appropriate parameters to demonstrate compliance, including:

(A) continuous monitoring and recording of:

(i) the exhaust gas temperature immediately downstream of a direct-flame incinerator;

(ii) the inlet and outlet gas temperatures of a catalytic incinerator or chiller;

(iii) the exhaust gas VOC concentration of any carbon adsorption system, as defined in §101.1 of this title (relating to Definitions); and

(iv) the exhaust gas temperature immediately downstream of a vapor combustor. Alternatively, the owner or operator of a vapor combustor may consider the unit to be a flare and meet the requirements specified in 40 Code of Federal Regulations (CFR) §60.18(b) and Chapter 111 of this title (relating to Control of Air Pollution from Visible Emissions and Particulate Matter) for flares;

(B) in the Beaumont/Port Arthur, Dallas/Fort Worth, and Houston/Galveston areas, the requirements specified in 40 CFR §60.18(b) and Chapter 111 of this title for flares; and

(C) for vapor control systems other than those specified in subparagraphs (A) and (B) of this paragraph, records of appropriate operating parameters.

(2) Test results. A record of the results of any testing conducted in accordance with §115.125 of this title (relating to Testing Requirements).

(3) Records for exempted vents. Records for each vent exempted from control requirements in accordance with §115.127 of this title (relating to Exemptions) shall be sufficient to demonstrate compliance with the applicable exemption limit, including the following, as appropriate:

(A) the pounds of ethylene emitted per 1,000 pounds of low-density polyethylene produced;

(B) the combined weight of VOC of each vent gas stream on a daily basis;

(C) the concentration of VOC in each vent gas stream on a daily basis;

(D) the maximum design flow rate or VOC concentration of each vent gas stream exempt under §115.127(a)(4)(C) of this title; and

(E) the total design capacity of process units exempt under §115.127(a)(4)(B) of this title.

(4) Alternative records for exempted vents. As an alternative to the requirements of paragraph (3)(B) and (C) of this section, records for each vent exempted from control requirements in accordance with §115.127 of this title and having a VOC emission rate or concentration less than the applicable exemption limits at maximum actual operating conditions shall be sufficient to demonstrate continuous compliance with the applicable exemption limit. These records shall include complete information from either test results or appropriate calculations which clearly documents that the emission characteristics at maximum actual operating conditions are less than the applicable exemption limit. This documentation shall include the operating parameter levels that occurred during any testing, and the maximum levels feasible (either VOC concentration or mass emission rate) for the process.

(5) Bakeries. For bakeries subject to §115.122(a)(3)(A) - (B) of this title (relating to Control Requirements), the following additional requirements apply.

(A) The owner or operator of each bakery in the Houston/Galveston area with a total weight of VOC emitted from all bakery ovens on the property, when uncontrolled, equal to or greater than 25 tons per calendar year, shall submit a control plan no later than March 31, 2001, to the executive director, the appropriate regional office, and any local air pollution control program with jurisdiction. The plan shall demonstrate that the overall emission reduction from the uncontrolled VOC emission rate of the oven(s) will be at least 80% by December 31, 2001. At a minimum, the control plan shall include the emission point number (EPN) and the facility identification number (FIN) of each bakery oven and any associated control device, a plot plan showing the location, EPN, and FIN of each bakery oven and any associated control device, and the 2000 VOC emission rates (consistent with the bakery's 2000 emissions inventory). The projected 2002 VOC emission rates shall be calculated in a manner consistent with the 2000 emissions inventory.

(B) All representations in control plans become enforceable conditions. It shall be unlawful for any person to vary from such representations if the variation will cause a change in the identity of the specific emission sources being controlled or the method of control of emissions unless the owner or operator of the bakery submits a revised control plan to the executive director, the appropriate regional office, and any local air pollution control program with jurisdiction within 30 days of the change. All control plans shall include documentation that the overall emission reduction from the uncontrolled VOC emission rate of the bakery's oven(s) continues to be at least the specified percentage reduction. The emission rates shall be calculated in a manner consistent with the most recent emissions inventory.

(6) Bakeries (contingency measures). For bakeries subject to §115.122(a)(3)(C) and (D) of this title, the following additional requirements apply.

(A) No later than six months after the commission publishes notification in the Texas Register as specified in §115.129(d) or (e) of this title (relating to Counties and Compliance Schedules), the owner or operator of each bakery shall submit an initial control plan to the executive director, the appropriate regional office, and any local air pollution control program with jurisdiction which demonstrates that the overall reduction of VOC emissions from the bakery's 1990 emissions inventory will be at least 30%. At a minimum, the control plan shall include the EPN and the FIN of each bakery oven and any associated control device, a plot plan showing the location, EPN, and FIN of each bakery oven and any associated control device, and the 1990 VOC emission rates (consistent with the bakery's 1990 emissions inventory). The projected VOC emission rates shall be calculated in a manner consistent with the 1990 emissions inventory.

(B) In order to document continued compliance with §115.122(a)(3) of this title, the owner or operator of each bakery shall submit an annual report no later than March 31 of each year to the executive director, the appropriate regional office, and any local air pollution control program with jurisdiction which demonstrates that the overall reduction of VOC emissions from the bakery's 1990 emissions inventory during the preceding calendar year is at least 30%. At a minimum, the report shall include the EPN and FIN of each bakery oven and any associated control device, a plot plan showing the location, EPN, and FIN of each bakery oven and any associated control device, and the VOC emission rates. The emission rates for the proceeding calendar year shall be calculated in a manner consistent with the 1990 emissions inventory.

(C) All representations in control plans and annual reports become enforceable conditions. It shall be unlawful for any person to vary from such representations if the variation will cause a change in the identity of the specific emission sources being controlled or the method of control of emissions unless the owner or operator of the bakery submits a revised control plan to the executive director, the appropriate regional office, and any local air pollution control program with jurisdiction within 30 days of the change. All control plans and reports shall include documentation that the overall reduction of VOC emissions from the bakery's 1990 emissions inventory continues to be at least 30%. The emission rates shall be calculated in a manner consistent with the 1990 emissions inventory.

(7) Additional flare requirements. The owner or operator of a facility that uses a flare to meet the requirements of §115.122(a)(2) of this title shall install, calibrate, maintain, and operate according to the manufacturer's specifications, a heat-sensing device, such as an ultraviolet beam sensor or thermocouple, at the pilot light to indicate continuous presence of a flame.

§115.127.Exemptions.

(a) For all persons in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston areas, the following exemptions apply.

(1) A vent gas stream from a low-density polyethylene plant is exempt from the requirements of §115.121(a)(1) of this title (relating to Emission Specifications) if no more than 1.1 pounds of ethylene per 1,000 pounds (1.1 kg/1,000 kg) of product are emitted from all the vent gas streams associated with the formation, handling, and storage of solidified product.

(2) The following vent gas streams are exempt from the requirements of §115.121(a)(1) of this title:

(A) a vent gas stream having a combined weight of volatile organic compounds (VOC) equal to or less than 100 pounds (45.4 kg) in any continuous 24-hour period;

(B) a vent gas stream specified in §115.121(a)(1) of this title with a concentration of VOC less than 612 parts per million by volume (ppmv);

(C) a vent gas stream which is subject to §115.121(a)(2) or (3) of this title; and

(D) a vent gas stream which qualifies for exemption under paragraphs (3), (4)(B), (4)(C), (4)(D), (4)(E), or (5) of this subsection.

(3) The following vent gas streams are exempt from the requirements of §115.121(a)(2)(B) - (E) of this title:

(A) a vent gas stream having a combined weight of VOC equal to or less than 100 pounds (45.4 kilograms) in any continuous 24-hour period;

(B) a vent gas stream from any air oxidation synthetic organic chemical manufacturing process with a concentration of VOC less than 612 ppmv; and

(C) a vent gas stream from any liquid phase polypropylene manufacturing process, any liquid phase slurry high-density polyethylene manufacturing process, and any continuous polystyrene manufacturing process with a concentration of VOC less than 408 ppmv.

(4) For synthetic organic chemical manufacturing industry (SOCMI) reactor processes and distillation operations, the following exemptions apply.

(A) Any reactor process or distillation operation that is designed and operated in a batch mode is exempt from the requirements of §115.121(a)(2)(A) of this title. For the purposes of this subparagraph, batch mode means any noncontinuous reactor process or distillation operation which is not characterized by steady-state conditions, and in which the addition of reactants does not occur simultaneously with the removal of products.

(B) Any reactor process or distillation operation operating in a process unit with a total design capacity of less than 1,100 tons per year, for all chemicals produced within that unit, is exempt from the requirements of §115.121(a)(2)(A) of this title.

(C) Any reactor process or distillation operation vent gas stream with a flow rate less than 0.011 standard cubic meters per minute or a VOC concentration less than 500 ppmv is exempt from the requirements of §115.121(a)(2)(A) of this title.

(D) Any distillation operation vent gas stream which meets the requirements of 40 Code of Federal Regulations (CFR) §60.660(c)(4) or §60.662(c) (concerning Subpart NNN--Standards of Performance for VOC Emissions From SOCMI Distillation Operations, December 14, 2000) is exempt from the requirements of §115.121(a)(2)(A) of this title.

(E) Any reactor process vent gas stream which meets the requirements of 40 CFR §60.700(c)(2) or §60.702(c) (concerning Subpart RRR--Standards of Performance for VOC Emissions From SOCMI Reactor Processes, December 14, 2000) is exempt from the requirements of §115.121(a)(2)(A) of this title.

(5) Bakeries are exempt from the requirements of §115.121(a)(3) and §115.122(a)(3) of this title (relating to Emission Specifications and Control Requirements) if the total weight of VOC emitted from all bakery ovens on the property, when uncontrolled, is less than 25 tons per calendar year.

(6) A vent gas stream is exempt from this division (relating to Vent Gas Control) if all of the VOCs in the vent gas stream originate from a source(s) for which another division within Chapter 115 (for example, Storage of Volatile Organic Compounds) has established a control requirement(s), emission specification(s), or exemption(s) which applies to that VOC source category in that county.

(7) A combustion unit exhaust stream is exempt from this division provided that the unit is not being used as a control device for any vent gas stream which is subject to this division and which originates from a non-combustion source.

(8) As an alternative to complying with the requirements of this division (or, in the case of bakeries, as an alternative to complying with the requirements of §115.121(a)(1) and §115.122(a)(1) of this title) for a source that is addressed by a Chapter 115 contingency rule (i.e., one in which Chapter 115 requirements are triggered for that source by the commission publishing notification in the Texas Register that implementation of the contingency rule is necessary), the owner or operator of that source may instead choose to comply with the requirements of the contingency rule as though the contingency rule already had been implemented for that source. The owner or operator of each source choosing this option shall submit written notification to the executive director and any local air pollution control program with jurisdiction. When the executive director and the local program (if any) receive such notification, the source will then be considered subject to the contingency rule as though the contingency rule already had been implemented for that source.

(b) For all persons in Nueces and Victoria Counties, the following exemptions apply.

(1) A vent gas stream from a low-density polyethylene plant is exempt from the requirements of §115.121(b)(1) of this title if no more than 1.1 pounds of ethylene per 1,000 pounds (1.1 kg/1,000 kg) of product are emitted from all the vent gas streams associated with the formation, handling, and storage of the solidified product.

(2) The following vent gas streams are exempt from the requirements of §115.121(b) of this title:

(A) a vent gas stream having a combined weight of the VOC or classes of compounds specified in §115.121(b)(2) and (3) of this title equal to or less than 100 pounds (45.4 kg) in any continuous 24-hour period; and

(B) a vent gas stream with a concentration of the VOC or classes of compounds specified in §115.121(b)(2) and (3) of this title less than 30,000 ppmv.

(3) A vent gas stream is exempt from this division if all of the VOCs in the vent gas stream originate from a source(s) for which another division within Chapter 115 (for example, Storage of Volatile Organic Compounds) has established a control requirement(s), emission specification(s), or exemption(s) which applies to that VOC source category in that county.

(4) A combustion unit exhaust stream is exempt from this division provided that the unit is not being used as a control device for any vent gas stream which is subject to this division and which originates from a non-combustion source.

(c) For all persons in Aransas, Bexar, Calhoun, Matagorda, San Patricio, and Travis Counties, the following exemptions apply.

(1) The following vent gas streams are exempt from the requirements of §115.121(c)(1) of this title:

(A) a vent gas stream from a low-density polyethylene plant provided that no more than 1.1 pounds of ethylene per 1,000 pounds (1.1 kg/1,000 kg) of product are emitted from all the vent gas streams associated with the formation, handling, and storage of solidified product;

(B) a vent gas stream having a combined weight of the VOC or classes of compounds specified in §115.121(c)(1)(B) - (C) of this title equal to or less than 100 pounds (45.4 kg) in any continuous 24-hour period; and

(C) a vent gas stream having a concentration of the VOC specified in §115.121(c)(1)(B) and (C) of this title less than 30,000 ppmv.

(2) A vent gas stream specified in §115.121(c)(2) of this title which emits less than or equal to five tons (4,536 kg) of total uncontrolled VOC in any one calendar year is exempt from the requirements of §115.121(c)(2) of this title.

(3) A vent gas stream is exempt from this division if all of the VOCs in the vent gas stream originate from a source(s) for which another division within Chapter 115 (for example, Storage of Volatile Organic Compounds) has established a control requirement(s), emission specification(s), or exemption(s) which applies to that VOC source category in that county.

(4) A combustion unit exhaust stream is exempt from this division provided that the unit is not being used as a control device for any vent gas stream which is subject to this division and which originates from a non-combustion source.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 18, 2002.

TRD-200208359

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 17, 2003

Proposal publication date: June 21, 2002

For further information, please call: (512) 239-0348

30 TAC §§115.142 - 115.144, 115.147, 115.149

STATUTORY AUTHORITY

The amendments are adopted under TWC, §5.103, which provides the commission the authority to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, TCAA, §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the TCAA. The amendments are also adopted under TCAA, §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.034, concerning Research and Investigations, which authorizes the commission to require any research it considers advisable and necessary to perform its duties; and §382.051(d), concerning Permitting Authority of Commission; Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382; and FCAA, 42 USC, §§7401 et seq .

§115.142.Control Requirements.

The owner or operator of an affected source category within a plant in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston areas, as defined in §115.10 of this title (relating to Definitions), shall comply with the following control requirements. Any component of a wastewater storage, handling, transfer, or treatment facility, if the component contains an affected volatile organic compounds (VOC) wastewater stream, shall be controlled in accordance with either paragraph (1) or (2) of this section, except for properly operated biotreatment units which shall meet the requirements of paragraph (3) of this section. In the Dallas/Fort Worth and El Paso areas, and until December 31, 2002 in the Houston/Galveston area, the control requirements apply from the point of generation of an affected VOC wastewater stream until the affected VOC wastewater stream is either returned to a process unit or is treated to remove VOC so that the wastewater stream no longer meets the definition of an affected VOC wastewater stream. In the Beaumont/Port Arthur area, and after December 31, 2002 in the Houston/Galveston area, the control requirements apply from the point of generation of an affected VOC wastewater stream until the affected VOC wastewater stream is either returned to a process unit, or is treated to reduce the VOC content of the wastewater stream by 90% by weight and also reduce the VOC content of the same VOC wastewater stream to less than 1,000 parts per million by weight. For wastewater streams which are combined and then treated to remove VOC, the amount of VOC to be removed from the combined wastewater stream shall be at least the total amount of VOC that would be removed to treat each individual affected VOC wastewater stream so that they no longer meet the definition of affected VOC wastewater stream, except for properly operated biotreatment units which shall meet the requirements of paragraph (3) of this section. For this division, a component of a wastewater storage, handling, transfer, or treatment facility shall include, but is not limited to, wastewater storage tanks, surface impoundments, wastewater drains, junction boxes, lift stations, weirs, and oil-water separators.

(1) The wastewater component shall meet the following requirements.

(A) All components shall be fully covered or be equipped with water seal controls. For any component equipped with water seal controls, the only acceptable alternative to water as the sealing liquid in a water seal is the use of ethylene glycol, propylene glycol, or other low vapor pressure antifreeze, which may be used only during the period of November through February. For any process drain not equipped with water seal controls, the process drain shall be equipped with a gasketed seal, or a tightly-fitting cap or plug.

(B) All openings shall be closed and sealed, except when the opening is in actual use for its intended purpose or the component is maintained at a pressure less than atmospheric pressure.

(C) All liquid contents shall be totally enclosed.

(D) For junction boxes and vented covers, the following requirements apply.

(i) In the Dallas/Fort Worth and El Paso areas, and until December 31, 2002 in the Houston/Galveston area, if any cover, other than a junction box cover, is equipped with a vent, the vent shall be equipped with either a vapor control system which maintains a minimum control efficiency of 90% or a closed system which prevents the flow of VOC vapors from the vent during normal operation. Any junction box vent shall be equipped with a vent pipe at least 90 centimeters (cm) (36 inches (in.)) in length and no more than 10.2 cm (4.0 in.) in diameter.

(ii) In the Beaumont/Port Arthur area, and after December 31, 2002 in the Houston/Galveston area, the following requirements apply.

(I) If any cover or junction box cover, except for junction boxes described in subclause (II) of this clause, is equipped with a vent, the vent shall be equipped with either a vapor control system which maintains a minimum control efficiency of 90% or a closed system which prevents the flow of VOC vapors from the vent during normal operation.

(II) Any junction box that is filled and emptied by gravity flow (i.e., there is no pump) or is operated with no more than slight fluctuations in the liquid level may be vented to the atmosphere, provided it is equipped with:

(-a-) a vent pipe at least 90 cm (36 in.) in length and no more than 10.2 cm (4.0 in.) in diameter; and

(-b-) water seal controls which are installed and maintained at the wastewater entrance(s) to or exit from the junction box restricting ventilation in the individual drain system and between components in the individual drain system.

(E) All gauging and sampling devices shall be vapor-tight except during gauging or sampling.

(F) Any loading or unloading to or from a portable container by pumping shall be performed with a submerged fill pipe.

(G) All seals and cover connections shall be maintained in proper condition. For purposes of this paragraph, "proper condition" means that covers shall have a tight seal around the edge and shall be kept in place except as allowed by this division, that seals shall not be broken or have gaps, and that sewer lines shall have no visible gaps or cracks in joints, seals, or other emission interfaces.

(H) If any seal or cover connection is found to not be in proper condition, a first attempt at repair shall be made no later than five calendar days after the leak or improper condition is found. The repair or correction shall be completed as soon as possible but no later than 15 calendar days after detection, unless the repair or correction is technically infeasible without requiring a process unit shutdown, in which case the repair or correction shall be made at the next process unit shutdown. Test Method 21 must be used to confirm that a leak or improper condition is repaired, and the following records shall be maintained:

(i) the date on which a leak or improper condition is discovered;

(ii) the date on which a first attempt at repair was made to correct the leak or improper condition;

(iii) the date on which a leak or improper condition is repaired; and

(iv) the date and instrument reading of the recheck procedure after a leak or improper condition is repaired.

(2) If a wastewater component is equipped with an internal or external floating roof, it shall meet the following requirements.

(A) All openings in an internal or external floating roof except for automatic bleeder vents (vacuum breaker vents) and rim space vents shall provide a projection below the liquid surface or be equipped with a cover, seal, or lid. Any cover, seal, or lid shall be in a closed (i.e., no visible gap) position at all times except when the opening is in actual use for its intended purpose.

(B) Automatic bleeder vents (vacuum breaker vents) shall be closed at all times except when the roof is being floated off or landed on the roof leg supports.

(C) Rim vents, if provided, shall be set to open only when the roof is being floated off the roof leg supports or at the manufacturer's recommended setting.

(D) Any roof drain that empties into the stored liquid shall be provided with a slotted membrane fabric cover that covers at least 90% of the area of the opening.

(E) There shall be no visible holes, tears, or other openings in any seal or seal fabric.

(F) For external floating roof storage tanks, the secondary seals shall be the rim-mounted type (i.e., the seal shall be continuous from the floating roof to the tank wall). The accumulated area of gaps that exceed 1/8 in. (0.32 cm) in width between the secondary seal and tank wall shall be no greater than 1.0 in. ² per foot (21 cm2 /meter) of tank diameter.

(3) In the Beaumont/Port Arthur area, and after December 31, 2002 in the Houston/Galveston area, each properly operated biotreatment unit shall meet the following requirements.

(A) The VOC content of the wastewater shall be reduced by 90% by weight; and

(B) The average concentration of suspended biomass maintained in the aeration basin of the biotreatment unit shall equal or exceed 1.0 kilogram per cubic meter (kg/m ³ ), measured as total suspended solids.

(4) Any wastewater component that becomes subject to this division by exceeding the provisions of §115.147 of this title (relating to Exemptions) or an affected VOC wastewater stream as defined in §115.140 of this title (relating to Industrial Wastewater Definitions) will remain subject to the requirements of this division, even if the component later falls below those provisions, unless and until emissions are reduced to no more than the controlled emissions level existing prior to the implementation of the project by which throughput or emission rate was reduced to less than the applicable exemption levels in §115.147 of this title; and

(A) the project by which throughput or emission rate was reduced is authorized by any permit or permit amendment or standard permit or permit by rule required by Chapter 116 or Chapter 106 of this title (relating to Control of Air Pollution by Permits for New Construction or Modification; and Permits by Rule). If a permit by rule is available for the project, compliance with this division must be maintained for 30 days after the filing of documentation of compliance with that permit by rule; or

(B) if authorization by permit, permit amendment, standard permit, or permit by rule is not required for the project, the owner or operator has given the executive director 30 days' notice of the project in writing.

§115.144.Inspection and Monitoring Requirements.

The owner or operator of an affected source category within a plant in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston areas shall comply with the following inspection and monitoring requirements.

(1) All seals and covers used to comply with §115.142(1) of this title (relating to Control Requirements) shall be inspected according to the following schedules to ensure compliance with §115.142(1)(G) and (H) of this title:

(A) initially and semiannually thereafter to ensure compliance with §115.142(1)(G) of this title; and

(B) upon completion of repair to ensure compliance with §115.142(1)(G) and (H) of this title.

(2) Floating roofs and internal floating covers used to comply with §115.142(2) of this title shall be subject to the following requirements. All secondary seals shall be inspected according to the following schedules to ensure compliance with §115.142(2)(E) and (F) of this title.

(A) If the primary seal is vapor-mounted, the secondary seal gap area shall be physically measured annually to ensure compliance with §115.142(2)(F) of this title.

(B) If the tank is equipped with a mechanical shoe or liquid-mounted primary seal, compliance with §115.142(2)(F) of this title may be determined by visual inspection.

(C) All secondary seals shall be visually inspected semiannually to ensure compliance with §115.142(2)(E) and (F) of this title.

(3) Monitors shall be installed and maintained as required by this section to measure operational parameters of any emission control device or other device installed to comply with §115.142 of this title. Such monitoring and parameters shall be sufficient to demonstrate proper functioning of those devices to design specifications, and include the monitoring and parameters listed in subparagraphs (A) - (H) of this paragraph, as applicable. In lieu of the monitoring and parameters listed in subparagraphs (A) - (H) of this paragraph, other monitoring and parameters may be approved or required by the executive director:

(A) for an enclosed non-catalytic combustion device (including, but not limited to, a thermal incinerator, boiler, or process heater), continuously monitor and record the temperature of the gas stream either in the combustion chamber or immediately downstream before any substantial heat exchange;

(B) for a catalytic incinerator, continuously monitor and record the temperature of the gas stream immediately before and after the catalyst bed;

(C) for a condenser (chiller), continuously monitor and record the temperature of the gas stream at the condenser exit;

(D) for a carbon adsorber, continuously monitor and record the VOC concentration of exhaust gas stream to determine if breakthrough has occurred. If the carbon adsorber does not regenerate the carbon bed directly in the control device (e.g., a carbon canister), the exhaust gas stream shall be monitored daily or at intervals no greater than 20% of the design replacement interval, whichever is greater, or as an alternative to conducting monitoring, the carbon may be replaced with fresh carbon at a regular predetermined time interval that is less than the carbon replacement interval that is determined by the maximum design flow rate and the VOC concentration in the gas stream vented to the carbon adsorber;

(E) for a flare, meet the requirements specified in 40 Code of Federal Regulations §60.18(b) and Chapter 111 of this title (relating to Control of Air Pollution from Visible Emissions and Particulate Matter);

(F) for a steam stripper, continuously monitor and record the steam flow rate, the wastewater feed mass flow rate, the wastewater feed temperature, and condenser vapor outlet temperature;

(G) for a vapor combustor, continuously monitor and record the exhaust gas temperature either in the combustion chamber or immediately downstream before any substantial heat exchange. Alternatively, the owner or operator of a vapor combustor may consider the unit to be a flare and meet the requirements of subparagraph (E) of this paragraph; and

(H) for vapor control systems other than those specified in subparagraphs (A) - (G) of this paragraph, continuously monitor and record the appropriate operating parameters.

(4) In the Beaumont/Port Arthur and Houston/Galveston areas, units used to comply with §115.142(3) of this title shall:

(A) initially demonstrate a 90% reduction in VOCs by using the methods in §115.145 of this title (relating to Approved Test Methods); and

(B) measure on a weekly basis the total suspended solids in the aeration basin of the biotreatment unit.

(5) All water seal controls shall be inspected weekly to ensure that the water seal controls are effective in preventing ventilation, except that daily inspections are required for those seals that have failed three or more inspections in any 12-month period. Upon request by the executive director, EPA, or any local program with jurisdiction, the owner or operator shall demonstrate (e.g., by visual inspection or smoke test) that the water seal controls are properly designed and restrict ventilation.

(6) All process drains not equipped with water seal controls shall be inspected monthly to ensure that all gaskets, caps, and/or plugs are in place and that there are no gaps, cracks, or other holes in the gaskets, caps, and/or plugs. In addition, all caps and plugs shall be inspected monthly to ensure that they are tightly-fitting.

§115.147.Exemptions.

The following exemptions apply in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston areas.

(1) Any plant with an annual volatile organic compounds (VOC) loading in wastewater, as determined in accordance with §115.148 of this title (relating to Determination of Wastewater Characteristics), less than or equal to ten megagrams (Mg) (11.03 tons) is exempt from the control requirements of §115.142 of this title (relating to Control Requirements).

(2) At any plant with an annual VOC loading in wastewater, as determined in accordance with §115.148 of this title greater than ten Mg (11.03 tons), any person who is the owner or operator of the plant may exempt from the control requirements of §115.142 of this title one or more affected VOC wastewater streams for which the sum of the annual VOC loading in wastewater for all of the exempted streams is less than or equal to ten Mg (11.03 tons).

(3) Unless specifically required by this division (relating to Industrial Wastewater), any piece of equipment of a wastewater storage, handling, transfer, or treatment facility to which the control requirements of §115.142 of this title apply is exempt from the requirements of any other division of this chapter. This paragraph does not apply to pieces of equipment or components which are subject to the requirements of Subchapter D, Division 3, and/or Subchapter H of this chapter (relating to Fugitive Emission Control in Petroleum Refining, Natural Gas/Gasoline Processing, and Petrochemical Processes in Ozone Nonattainment Areas; and Highly-Reactive Volatile Organic Compounds).

(4) If compliance with the control requirements of §115.142 of this title would create a safety hazard in a component of a wastewater storage, handling, transfer, or treatment facility, the owner or operator may request the executive director to exempt that component from the control requirements of §115.142 of this title. The executive director shall approve the request if justified by the likelihood and magnitude of the potential injury and if the executive director determines that reducing or eliminating the hazard is technologically or economically unreasonable based on the emissions reductions that would be achieved.

(5) Wet weather retention basins are exempt from the requirements of this division.

(6) Petroleum refineries in the Beaumont/Port Arthur area are exempt from the requirements of this division.

(7) The following exemptions apply to petroleum refineries in the Houston/Galveston area.

(A) Petroleum refineries are exempt from the requirement in §115.142 of this title that after December 31, 2002, the control requirements apply from the point of generation of an affected VOC wastewater stream until the affected VOC wastewater stream is either returned to a process unit, or is treated to reduce the VOC content of the wastewater stream by 90% by weight and also reduce the VOC content of the same VOC wastewater stream to less than 1,000 parts per million by weight, provided that petroleum refineries continue to apply the requirement in §115.142 of this title that the control requirements apply from the point of generation of an affected VOC wastewater stream until the affected VOC wastewater stream is either returned to a process unit, or is treated to remove VOC so that the wastewater stream no longer meets the definition of an affected VOC wastewater stream.

(B) Junction boxes are exempt from the requirements of §115.142(1)(D)(ii) of this title, provided that after December 31, 2002 they continue to comply with the requirements of §115.142(1)(D)(i) of this title.

(C) Properly operated biotreatment units are exempt from the requirements of §§115.142(3), 115.144(4), and 115.145(7) and (8) of this title (relating to Control Requirements; Inspection and Monitoring Requirements; and Approved Test Methods).

§115.149.Counties and Compliance Schedules.

(a) The owner or operator of each affected source category within a plant in Brazoria, Chambers, Collin, Dallas, Denton, El Paso, Fort Bend, Galveston, Harris, Liberty, Montgomery, Tarrant, and Waller Counties shall continue to comply with this division (relating to Industrial Wastewater) as required by §115.930 of this title (relating to Compliance Dates).

(b) The owner or operator of each affected source category within a plant in Hardin, Jefferson, and Orange Counties shall be in compliance with this division as soon as practicable, but no later than December 31, 2002.

(c) The owner or operator of each affected source category within a plant in Brazoria, Chambers, Fort Bend, Galveston, Harris, Liberty, Montgomery, and Waller Counties shall control all junction boxes equipped with pumps in accordance with §115.142(1)(D)(ii)(II) of this title (relating to Control Requirements) as soon as practicable, but no later than December 31, 2002.

(d) The owner or operator of each affected source category within a plant in Brazoria, Chambers, Fort Bend, Galveston, Harris, Liberty, Montgomery, and Waller Counties shall control all biotreatment units in accordance with §115.142(3) and §115.144(4) of this title (relating to Control Requirements; and Inspection and Monitoring Requirements) as soon as practicable, but no later than December 31, 2002.

(e) The owner or operator of each affected source category within a plant in Brazoria, Chambers, Collin, Dallas, Denton, El Paso, Fort Bend, Galveston, Hardin, Harris, Jefferson, Liberty, Montgomery, Orange, Tarrant, and Waller Counties shall comply with the requirement in §115.142(1)(A) of this title for gasketed seals or tightly-fitting caps or plugs on process drains not equipped with water seal controls as soon as practicable, but no later than December 31, 2003.

(f) The owner or operator of each affected source category within a plant in Brazoria, Chambers, Collin, Dallas, Denton, El Paso, Fort Bend, Galveston, Hardin, Harris, Jefferson, Liberty, Montgomery, Orange, Tarrant, and Waller Counties shall comply with the requirement in §115.142(1)(H) of this title for a first attempt at repair within five calendar days and for follow-up monitoring as soon as practicable, but no later than December 31, 2003.

(g) The owner or operator of each affected source category within a plant in Brazoria, Chambers, Collin, Dallas, Denton, El Paso, Fort Bend, Galveston, Hardin, Harris, Jefferson, Liberty, Montgomery, Orange, Tarrant, and Waller Counties shall comply with the requirements in §115.144(5) and (6) of this title for water seal inspections and inspections of process drains not equipped with water seals as soon as practicable, but no later than December 31, 2003.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 18, 2002.

TRD-200208360

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 17, 2003

Proposal publication date: June 21, 2002

For further information, please call: (512) 239-0348

30 TAC §§115.160, 115.161, 115.166, 115.167

STATUTORY AUTHORITY

The amendments are adopted under TWC, §5.103, which provides the commission the authority to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, TCAA, §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the TCAA. The amendments are also adopted under TCAA, §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.034, concerning Research and Investigations, which authorizes the commission to require any research it considers advisable and necessary to perform its duties; and §382.051(d), concerning Permitting Authority of Commission; Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382; and FCAA, 42 USC, §§7401 et seq .

§115.160.Batch Process Definitions.

The following words and terms, when used in this division (relating to Batch Processes), shall have the following meanings, unless the context clearly indicates otherwise. Additional definitions for terms used in this division are found in §§3.2, 101.1, and 115.10 of this title (relating to Definitions).

(1) Aggregated--The summation of all process vents containing volatile organic compounds (VOC) within a process.

(2) Annual mass emissions total--The sum of all VOC emissions (pounds per year), evaluated before control but after the last recovery device, from a process vent. Annual mass emissions shall be calculated from an individual process vent or groups of process vents by using emission estimation equations contained in Chapter 3 of EPA's Control of Volatile Organic Compound Emissions from Batch Processes-Alternative Control Techniques Information Document (EPA-453/R-94-020, February 1994) and then multiplying by the historical duration and frequency of the emission or groups of emissions over the course of a year. For process vents that are included in a new source review air permit, standard permit, or permit by rule registered by Form PI-8, the annual mass emissions total shall be based on the maximum allowable emission rate (MAER) levels in the permit or Form PI-8 (adjusted to represent the level before control, but after the last recovery device), whether they correspond to the maximum design production potential or to the actual annual production estimate.

(3) Average flow rate--The flow rate in standard cubic feet per minute (scfm) averaged over the amount of time that VOCs are emitted during an emission event. For the evaluation of average flow rate from an aggregate of sources, the average flow rate is the weighted average of the average flow rates of the emission events and their annual venting time, or:

Figure: 30 TAC §115.160(3) (No change.)

(4) Batch--A noncontinuous process involving the bulk movement of material through sequential manufacturing steps. Mass, temperature, concentration, and other properties of a system vary with time. Batch processes are not characterized by steady-state conditions. Reactants are not added and products are not removed simultaneously.

(5) Batch cycle--A manufacturing event of an intermediate or product from start to finish in a batch process.

(6) Batch process (for the purpose of determining reasonably available control technology (RACT) applicability)--The batch equipment assembled and connected by pipes, or otherwise operated in a sequence of steps, to manufacture a product in a batch fashion.

(7) Batch process train--An equipment train that is used to produce a product or intermediates in batch fashion. A typical equipment train consists of equipment used for the synthesis, mixing, and purification of a material.

(8) Emissions before control--The emissions total before the application of a control device but after the last recovery device, or the emissions total if no control device is used. The emissions total may not be reduced to account for discharge of VOC into wastewater if the wastewater is further handled or processed with the potential for VOC emissions to the atmosphere.

(9) Primary fuel--The fuel that provides the principal heat input to a device. To be considered a primary fuel, the fuel must be able to sustain operation without the addition of other fuels.

(10) Process vent--A vent gas stream that is discharged from a batch process. Process vents include gas streams that are discharged directly to the atmosphere or are discharged to the atmosphere after diversion through a recovery device. Process vents exclude relief valve discharges, leaks from equipment, vents from storage tanks, vents from transfer/loading operations, and vents from wastewater. Process gaseous streams that are used as primary fuels are also excluded. The lines that transfer such fuels to a plant fuel gas system are not considered to be vents.

(11) RACT--Reasonably available control technology.

(12) Recovery device--An individual unit of equipment capable of and used for recovering chemicals for use, reuse, or sale. Recovery devices include, but are not limited to, absorbers, carbon adsorbers, and condensers.

(13) Unit operations--Those discrete processing steps that occur within distinct equipment that are used to prepare reactants, facilitate reactions, separate and purify products, and recycle materials.

(14) Volatility--As follows.

(A) Low volatility VOCs are those which have a vapor pressure less than or equal to 75 millimeters of mercury (mm Hg) at 20 degrees Celsius.

(B) Moderate volatility VOCs are those which have a vapor pressure greater than 75 and less than or equal to 150 mm Hg at 20 degrees Celsius.

(C) High volatility VOCs are those which have a vapor pressure greater than 150 mm Hg at 20 degrees Celsius.

(D) To evaluate VOC volatility for single unit operations that service numerous VOCs or for processes handling multiple VOCs, the weighted average volatility can be calculated from the total amount of each VOC emitted in a year and the individual component vapor pressure, as follows.

Figure: 30 TAC §115.160(14)(D)

§115.166.Monitoring and Recordkeeping Requirements.

The owner or operator of each batch process operation in the Beaumont/Port Arthur and Houston/ Galveston areas shall maintain the following information for at least five years at the plant, as defined by its air quality account number, except that the five-year record retention requirement does not apply to records generated before December 31, 2000. The owner or operator shall make the information available upon request to representatives of the executive director, EPA, or any local air pollution control agency having jurisdiction in the area:

(1) Vapor control systems. For vapor control systems used to control emissions from batch process operations, records of appropriate parameters to demonstrate compliance, including:

(A) continuous monitoring and recording of:

(i) for a direct-flame incinerator, the exhaust gas temperature in the firebox or in the ductwork immediately downstream of the firebox before any substantial heat exchange. The temperature monitoring device shall have an accuracy of ±0.5 degrees Celsius, or alternatively, ±1.0%;

(ii) for a catalytic incinerator, the exhaust gas temperature immediately before and after the catalyst bed. The temperature monitoring device shall have an accuracy of ±0.5 degrees Celsius, or alternatively, ±1.0%;

(iii) for an absorber, either:

(I) the scrubbing liquid temperature. The temperature monitoring device shall have an accuracy of ±1.0% of the temperature being monitored in degrees Celsius, or alternatively, ±0.02 specific gravity unit; or

(II) the concentration level of volatile organic compounds (VOC) exiting the recovery device based on a detection principle such as infrared, photoionization, or thermal conductivity;

(iv) for a condenser or refrigeration system, either:

(I) the condenser exit temperature. The temperature monitoring device shall have an accuracy of ±1.0% of the temperature being monitored in degrees Celsius, or alternatively, ±0.5 degrees Celsius; or

(II) the concentration level of VOC exiting the recovery device based on a detection principle such as infrared, photoionization, or thermal conductivity;

(v) for a carbon adsorption system, as defined in §101.1 of this title (relating to Definitions), either:

(I) steam flow (using an integrating steam flow monitoring device) and the carbon bed temperature. The steam flow monitor shall have an accuracy of ±10%. The temperature monitor shall have an accuracy of ±1.0% of the temperature being monitored in degrees Celsius, or ±0.5 degrees Celsius, whichever is greater; or

(II) the concentration level of VOC exiting the recovery device based on a detection principle such as infrared, photoionization, or thermal conductivity;

(vi) for a pressure swing adsorption unit that is the final recovery device, the temperature of the bed near the inlet and near the outlet. The temperature monitoring device shall have an accuracy of ±1.0% of the temperature being monitored in degrees Celsius, or ±0.5 degrees Celsius; and

(vii) for a vapor combustor, the exhaust gas temperature in the firebox or in the ductwork immediately downstream of the firebox before any substantial heat exchange. The temperature monitoring device shall have an accuracy of ±0.5 degrees Celsius, or alternatively, ±1.0%. Alternatively, the owner or operator of a vapor combustor may consider the unit to be a flare and meet the requirements of subparagraph (B) of this paragraph;

(B) for flares, the requirements specified in 40 Code of Federal Regulations §60.18(b) and Chapter 111 of this title (relating to Control of Air Pollution from Visible Emissions and Particulate Matter); and

(C) for vapor control systems other than those specified in subparagraphs (A) and (B) of this paragraph, records of appropriate operating parameters.

(2) Process vents. A record of the following emission stream parameters for each process vent contained in the batch process:

(A) the annual mass emission total and documentation verifying these values. If emission estimate equations are used, the documentation shall be the calculations coupled with the expected or permitted (if available) number of emission events per year; and

(B) the average flow rate in standard cubic feet per minute and documentation verifying these values.

(3) Performance test monitoring parameters. Records of the following parameters required to be measured during a performance test required under §115.165 of this title (relating to Approved Test Methods and Testing Requirements) and required to be monitored under paragraph (1) of this section:

(A) where an owner or operator seeks to demonstrate compliance with §115.162 of this title (relating to Control Requirements) through use of either a direct-flame or catalytic incinerator, the average firebox temperature of the incinerator (or the average temperature upstream and downstream of the catalyst bed for a catalytic incinerator), measured continuously and averaged over the same time period as the performance test;

(B) where an owner or operator seeks to demonstrate compliance with §115.162 of this title through use of a smokeless flare, the flare design (i.e., steam-assisted, air-assisted, or nonassisted), all visible emissions readings, heat content determinations, flow rate measurements, and exit velocity determinations made during the performance test; continuous flare pilot flame monitoring; and all periods of operations during which the pilot flame is absent; and

(C) where an owner or operator seeks to demonstrate compliance with §115.162 of this title:

(i) with an absorber as the final control device, the exit specific gravity (or alternative parameter which is a measure of the degree of absorbing liquid saturation, if approved by the executive director) and average exit temperature of the absorbing liquid measured continuously and averaged over the same time period as the performance test (both measured while the vent stream is routed normally);

(ii) with a condenser as the control device, the average exit (product side) temperature measured continuously and averaged over the same time period as the performance test while the vent stream is routed normally;

(iii) with a carbon adsorption system as the control device, the total steam mass flow measured continuously and averaged over the same time period as the performance test (full carbon bed cycle), temperature of the carbon bed after regeneration (and within 15 minutes of completion of any cooling cycle(s)), and duration of the carbon bed steaming cycle (all measured while the vent stream is routed normally);

(iv) the concentration level or reading indicated by an organic monitoring device at the outlet of the absorber, condenser, or carbon adsorption system, measured continuously and averaged over the same time period as the performance test while the vent stream is routed normally; and

(v) with a pressure swing adsorption unit as the final recovery device, the temperature of the bed near the inlet and near the outlet. The temperature monitoring device shall have an accuracy of ±1.0% of the temperature being monitored in degrees Celsius, or ±0.5 degrees Celsius.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 18, 2002.

TRD-200208361

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 17, 2003

Proposal publication date: June 21, 2002

For further information, please call: (512) 239-0348

1. LOADING AND UNLOADING OF VOLATILE ORGANIC COMPOUNDS

30 TAC §§115.211, 115.215, 115.219

STATUTORY AUTHORITY

The amendments are adopted under TWC, §5.103, which provides the commission the authority to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, TCAA, §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the TCAA. The amendments are also adopted under TCAA, §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.034, concerning Research and Investigations, which authorizes the commission to require any research it considers advisable and necessary to perform its duties; and §382.051(d), concerning Permitting Authority of Commission; Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382; and FCAA, 42 USC, §§7401 et seq .

§115.215.Approved Test Methods.

Compliance with the emission specifications, vapor control system efficiency, and certain control requirements, inspection requirements, and exemption criteria of §§115.211 - 115.214 and 115.217 of this title (relating to Loading and Unloading of Volatile Organic Compounds) shall be determined by applying one or more of the following test methods and procedures, as appropriate.

(1) Flow rate. Test Methods 1-4 (40 Code of Federal Regulations (CFR) Part 60, Appendix A) are used for determining flow rates, as necessary.

(2) Concentration of volatile organic compounds (VOC).

(A) Test Method 18 (40 CFR Part 60, Appendix A) is used for determining gaseous organic compound emissions by gas chromatography.

(B) Test Method 25 (40 CFR Part 60, Appendix A) is used for determining total gaseous nonmethane organic emissions as carbon.

(C) Test Methods 25A or 25B (40 CFR Part 60, Appendix A) are used for determining total gaseous organic concentrations using flame ionization or nondispersive infrared analysis.

(3) Performance requirements for flares and vapor combustors.

(A) For flares, the performance test requirements of 40 CFR §60.18(b) shall apply.

(B) For vapor combustors, the owner or operator may consider the unit to be a flare and meet the performance test requirements of 40 CFR §60.18(b) rather than the procedures of paragraphs (1) and (2) of this section.

(C) Compliance with the requirements of 40 CFR §60.18(b) will be considered to demonstrate compliance with the emission specifications and control efficiency requirements of §115.211 and §115.212 of this title (relating to Emission Specifications; and Control Requirements).

(4) Vapor pressure. Use standard reference texts or American Society for Testing and Materials (ASTM) Test Methods D323-89, D2879, D4953, D5190, or D5191 for the measurement of vapor pressure.

(5) Leak determination by instrument method. Use Test Method 21 (40 CFR Part 60, Appendix A) for determining VOC leaks.

(6) Gasoline terminal test procedures. Use the additional test procedures described in 40 CFR §60.503(b) - (d) (February 14, 1989), for pre-test leak determination, emission specifications test for vapor control systems, and pressure limit in transport vessel.

(7) Vapor-tightness test procedures for marine vessels. Use 40 CFR §63.565(c) (September 19, 1995) or 40 CFR §61.304(f) (October 17, 2000) for determination of marine vessel vapor tightness.

(8) Flash point. Use ASTM Test Method D93 for the measurement of flash point.

(9) Minor modifications. Minor modifications to these test methods may be used, if approved by the executive director.

(10) Alternate test methods. Test methods other than those specified in paragraphs (1) - (8) of this section may be used if validated by 40 CFR Part 63, Appendix A, Test Method 301 (December 29, 1992). For the purposes of this paragraph, substitute "executive director" each place that Test Method 301 references "administrator."

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 18, 2002.

TRD-200208362

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 17, 2003

Proposal publication date: June 21, 2002

For further information, please call: (512) 239-0348

30 TAC §115.229

STATUTORY AUTHORITY

The amendment is adopted under TWC, §5.103, which provides the commission the authority to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, TCAA, §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the TCAA. The amendment is also adopted under TCAA, §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.034, concerning Research and Investigations, which authorizes the commission to require any research it considers advisable and necessary to perform its duties; and §382.051(d), concerning Permitting Authority of Commission; Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382; and FCAA, 42 USC, §§7401 et seq .

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 18, 2002.

TRD-200208363

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 17, 2003

Proposal publication date: June 21, 2002

For further information, please call: (512) 239-0348

30 TAC §115.239

STATUTORY AUTHORITY

The amendment is adopted under TWC, §5.103, which provides the commission the authority to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, TCAA, §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the TCAA. The amendment is also adopted under TCAA, §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.034, concerning Research and Investigations, which authorizes the commission to require any research it considers advisable and necessary to perform its duties; and §382.051(d), concerning Permitting Authority of Commission; Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382; and FCAA, 42 USC, §§7401 et seq .

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 18, 2002.

TRD-200208364

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 17, 2003

Proposal publication date: June 21, 2002

For further information, please call: (512) 239-0348

1. PROCESS UNIT TURNAROUND AND VACUUM-PRODUCING SYSTEMS IN PETROLEUM REFINERIES

30 TAC §115.312

STATUTORY AUTHORITY

The amendment is adopted under TWC, §5.103, which provides the commission the authority to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, TCAA, §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the TCAA. The amendment is also adopted under TCAA, §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.034, concerning Research and Investigations, which authorizes the commission to require any research it considers advisable and necessary to perform its duties; and §382.051(d), concerning Permitting Authority of Commission; Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382; and FCAA, 42 USC, §§7401 et seq .

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 18, 2002.

TRD-200208365

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 17, 2003

Proposal publication date: June 21, 2002

For further information, please call: (512) 239-0348

30 TAC §115.326

STATUTORY AUTHORITY

The amendment is adopted under TWC, §5.103, which provides the commission the authority to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, TCAA, §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the TCAA. The amendment is also adopted under TCAA, §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.034, concerning Research and Investigations, which authorizes the commission to require any research it considers advisable and necessary to perform its duties; and §382.051(d), concerning Permitting Authority of Commission; Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382; and FCAA, 42 USC, §§7401 et seq .

§115.326.Recordkeeping Requirements.

For Gregg, Nueces, and Victoria Counties, the owner or operator of a petroleum refinery shall have the following recordkeeping requirements.

(1) Submit to the executive director a monitoring program plan. This plan shall contain, at a minimum, a list of the refinery units and the quarter in which they will be monitored, a copy of the log book format, and the make and model of the monitoring equipment to be used.

(2) Maintain a leaking-components monitoring log for all leaks of more than 10,000 parts per million by volume (ppmv) of volatile organic compound detected by the monitoring program required by §115.324 of this title (relating to Inspection Requirements). This log shall contain, at a minimum, the following data:

(A) the name of the process unit where the component is located;

(B) the type of component (e.g., valve or seal);

(C) the tag number of the component;

(D) the date the component was monitored;

(E) the results of the monitoring (in ppmv);

(F) a record of the calibration of the monitoring instrument;

(G) if a component is found leaking:

(i) the date on which a leaking component is discovered;

(ii) the date on which a first attempt at repair was made to a leaking component;

(iii) the date on which a leaking component is repaired;

(iv) the date and instrument reading of the recheck procedure after a leaking component is repaired; and

(v) those leaks that cannot be repaired until turnaround and the date on which the leaking component is placed on the shutdown list;

(H) the total number of components checked and the total number of components found leaking; and

(I) the test method used (Test Method 21, or sight/sound/smell).

(3) Retain copies of the monitoring log for a minimum of five years after the date on which the record was made or the report prepared.

(4) Maintain all monitoring records for at least five years and make them available for review upon request by authorized representatives of the executive director, EPA, or local air pollution control agencies with jurisdiction.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 18, 2002.

TRD-200208366

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 17, 2003

Proposal publication date: June 21, 2002

For further information, please call: (512) 239-0348

30 TAC §§115.352, 115.354, 115.356, 115.357, 115.359

STATUTORY AUTHORITY

The amendments are adopted under TWC, §5.103, which provides the commission the authority to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, TCAA, §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the TCAA. The amendments are also adopted under TCAA, §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.034, concerning Research and Investigations, which authorizes the commission to require any research it considers advisable and necessary to perform its duties; and §382.051(d), concerning Permitting Authority of Commission; Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382; and FCAA, 42 USC, §§7401 et seq .

§115.352.Control Requirements.

For the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston areas as defined in §115.10 of this title (relating to Definitions), no person shall operate a petroleum refinery; a synthetic organic chemical, polymer, resin, or methyl tert-butyl ether manufacturing process; or a natural gas/gasoline processing operation, as defined in §115.10 of this title, without complying with the following requirements.

(1) Except as provided in paragraph (2) of this section, no component shall be allowed to have a volatile organic compound (VOC) leak for more than 15 calendar days after the leak is found which exceeds the following:

(A) for all components except pump seals and compressor seals, a screening concentration greater than 500 parts per million by volume (ppmv) above background as methane, or the dripping or exuding of process fluid based on sight, smell, or sound; and

(B) for pump seals and compressor seals, a screening concentration greater than 10,000 ppmv above background as methane, or the dripping or exuding of process fluid based on sight, smell, or sound.

(2) A first attempt at repair shall be made no later than five calendar days after the leak is found and the component shall be repaired no later than 15 calendar days after the leak is found, except as provided in subparagraphs (A) - (C) of this paragraph. A component in gas/vapor or light liquid service is considered to be repaired when it is monitored with an instrument using Test Method 21 and shown to no longer have a leak after adjustments or alterations to the component. A component in heavy liquid service is considered to be repaired when it is monitored by audio, visual, and olfactory means and shown to no longer have a leak after adjustments or alterations to the component.

(A) If the repair of a component would require a process unit shutdown, the repair may be delayed until the next scheduled process unit shutdown, provided that:

(i) the owner or operator maintains, and makes available upon request, documentation to authorized representatives of EPA, the executive director, and any local air pollution control agency having jurisdiction which includes a calculation of:

(I) the expected mass emissions resulting from the next scheduled process unit shutdown of the unit, including the basis for the calculation and all assumptions made;

(II) the mass emission rates from each leaking component in the process unit for which delay of repair is sought as determined by using the methods in the EPA correlation approach in Section 2.3.3 of the EPA guidance document "Protocol for Equipment Leak Emission Estimates," (EPA-453/R-95-017, November, 1995) alone or in combination with the mass emission sampling approach in Chapter 4 of the guidance document (EPA-453/R-95-017, November, 1995). To use the EPA correlation approach, the estimated hourly mass emission rate for each component shall be based on the average of the component's current screening concentration and the previous screening concentration using Test Method 21 for the days between the two monitoring efforts, and the last screening concentration shall be used for the days following that last monitoring through the date of the planned process unit shutdown. Where the monitoring instrument is not calibrated to read past the leak definition or 100,000 ppmv, the pegged emission rate values in Tables 2-13 and 2-14 in Section 2.3.3 of the EPA guidance document "Protocol for Equipment Leak Emission Estimates" shall be used as appropriate. Leaking components in heavy liquid service shall be assigned the appropriate screening range leak rate for greater than 10,000 ppmv as defined in Section 2.3.2 of the guidance document. If the mass emission sampling approach is used, it replaces the estimated emissions rate of the EPA correlation approach in the calculation;

(III) the cumulative mass emissions from each leaking component in the process unit for which delay of repair is sought, from the last day it was monitored and was not leaking through the date of the next planned process unit shutdown; and

(IV) the total cumulative mass emissions in the process unit from the calculations made in subclause (III) of this clause for leaking components in the unit for which delay of repair is sought;

(ii) the total cumulative mass emissions from leaking components in the process unit for which delay of repair is sought as determined in subclause (IV) of this clause are less than the mass emissions resulting from shutdown of the unit as determined in subclause (IV) of this clause; and

(iii) as an alternative to the requirements of clause (i) and (ii) of this subparagraph, delay of repair is allowed for each leaking component for which the owner or operator has chosen to undertake "extraordinary efforts" to repair the leak. For purposes of this subparagraph, "extraordinary efforts" is defined as nonroutine repair methods (e.g., sealant injection) or utilization of a closed-vent system to capture and control the leaks by at least 90%. For leaks detected over 10,000 ppmv, extraordinary efforts shall be undertaken within seven days of the valve being placed on the shutdown list; however, the owner or operator may keep the leaking valve on the shutdown list only after two unsuccessful attempts to repair a leaking valve through extraordinary efforts, provided that the second extraordinary effort attempt is made within 15 days of the first extraordinary effort attempt. For all other leaks, extraordinary efforts shall be undertaken within 15 days of the valve being placed on the shutdown list, and a second extraordinary effort attempt is not required.

(B) Process unit shutdown and component repairs are required within 15 days of the day that leaks are determined to exceed the requirement of subparagraph (A)(ii) of this paragraph for components that were not subjected to extraordinary efforts, and except as provided in subparagraph (C) of this paragraph, each component for which repair has been delayed must be repaired or replaced at the next process unit shutdown.

(C) Delay of repair beyond a process unit shutdown will be allowed for a component if that component is isolated from the process and does not remain in VOC service.

(D) Valves which can be safely repaired without a process unit shutdown may not be placed on the shutdown list.

(E) All components for which a repair attempt was made during a shutdown shall be monitored (with a hydrocarbon gas analyzer) and inspected for leaks within 30 days or at the next monitoring period, whichever occurs first, after startup is completed following the process unit shutdown.

(3) All leaking components, as defined in paragraph (1) of this section, which cannot be repaired until a process unit shutdown shall be identified for such repair by tagging. The executive director, at his discretion, may require an early process unit shutdown or other appropriate action based on the number and severity of tagged leaks awaiting a process unit shutdown.

(4) Except for pressure relief valves, no valves shall be installed or operated at the end of a pipe or line containing VOC unless the pipe or line is sealed with a second valve, a blind flange, or a tightly- fitting plug or cap. The sealing device may be removed only while a sample is being taken or during maintenance operations, and when closing the line, the upstream valve shall be closed first.

(5) Construction of new and reworked piping, valves, and pump and compressor systems shall conform to applicable American National Standards Institute, American Petroleum Institute, American Society of Mechanical Engineers, or equivalent codes.

(6) New and reworked underground process pipelines shall contain no buried valves such that fugitive emission monitoring is rendered impractical.

(7) To the extent that good engineering practice will permit, new and reworked valves and piping connections shall be so located to be reasonably accessible for leak-checking during plant operation. Valves elevated more than two meters above a support surface will be considered nonaccessible. Nonaccessible valves shall be identified in a list to be made available upon request.

(8) New and reworked piping connections shall be welded, flanged, or consist of pressed and permanently formed metal-to-metal seals. Screwed connections are permissible only on new piping smaller than two inches in diameter. All new connections shall be checked for leaks within 30 days of being placed in VOC service by monitoring with a hydrocarbon gas analyzer for components in light liquid and gas service and by using visual, audio, and/or olfactory means for components in heavy liquid service.

(9) For pressure relief valves installed in series with a rupture disk, pin, second relief valve, or other similar leak-tight pressure relief component, a pressure gauge or an equivalent device or system shall be installed between the relief valve and the other pressure relief component to monitor for leakage past the first component. When leakage is detected past the first component, that component shall be repaired or replaced at the earliest opportunity, but no later than the next process unit shutdown. Equivalent devices or systems shall be identified in a list to be made available upon request and must have been approved by the methods required by §115.353 of this title (relating to Alternate Control Requirements).

(10) Any petroleum refinery; synthetic organic chemical, polymer, resin, or methyl tert-butyl ether manufacturing process; or natural gas/gasoline processing operation in the Houston/Galveston area in which a HRVOC, as defined in §115.10 of this title, is a raw material, intermediate, final product, or in a waste stream is subject to the requirements of Subchapter H of this chapter (relating to Highly- Reactive Volatile Organic Compounds) in addition to the applicable requirements of this division (relating to Fugitive Emission Control in Petroleum Refining, Natural Gas/Gasoline Processing, and Petrochemical Processes in Ozone Nonattainment Areas).

§115.354.Inspection Requirements.

All affected persons in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston areas shall conduct a monitoring program consistent with the following provisions.

(1) Measure yearly (with a hydrocarbon gas analyzer) the emissions from all:

(A) process drains;

(B) nonaccessible valves as identified in §115.352(7) of this title (relating to Control Requirements); and

(C) unsafe to monitor valves. An unsafe to monitor valve is a valve that the owner or operator determines is unsafe to monitor because monitoring personnel would be exposed to an immediate danger as a consequence of complying with paragraph (2) of this section. Valves which are unsafe to monitor shall be identified in a list made available upon request. If an unsafe to monitor valve is not considered safe to monitor within a calendar year, then it shall be monitored as soon as possible during safe to monitor times.

(2) Measure each calendar quarter (with a hydrocarbon gas analyzer) the screening concentration from all:

(A) compressor seals;

(B) pump seals;

(C) accessible valves; and

(D) pressure relief valves in gaseous service.

(3) Inspect weekly, by visual, audio, and/or olfactory means, all flanges, excluding flanges in the Houston/Galveston area that are monitored using Test Method 21 as required by §115.781(b)(3) of this title (relating to General Monitoring and Inspection Requirements).

(4) Measure (with a hydrocarbon gas analyzer) emissions from any relief valve which has vented to the atmosphere within 24 hours.

(5) Upon the detection of a leaking component, affix to the leaking component a weatherproof and readily visible tag, bearing an identification number and the date the leak was detected. This tag shall remain in place until the leaking component is repaired.

(6) The monitoring schedule of paragraphs (1) - (3) of this section may be modified to require an increase in the frequency of monitoring in a given process area if the executive director determines that there is an excessive number of leaks in that process area.

(7) After completion of the required quarterly valve monitoring for a period of at least two years, the operator of a petroleum refinery; synthetic organic chemical, polymer, resin, or methyl-tert-butyl ether manufacturing process; or a natural gas/gasoline processing operation may request in writing to the executive director that the valve monitoring schedule be revised based on the percent of valves leaking. The percent of valves leaking shall be determined by dividing the sum of valves leaking during current monitoring and valves for which repair has been delayed (including valves which have been classified as non-repairable under §115.357(8) of this title (relating to Exemptions)) by the total number of valves subject to the requirements. This request shall include all data that have been developed to justify the following modifications in the monitoring schedule.

(A) After two consecutive quarterly leak detection periods with the percent of valves leaking equal to or less than 2.0%, an owner or operator may begin to skip one of the quarterly leak detection periods for the valves in gas/vapor and light liquid service.

(B) After five consecutive quarterly leak detection periods with the percent of valves leaking equal to or less than 2.0%, an owner or operator may begin to skip three of the quarterly leak detection periods for the valves in gas/vapor and light liquid service.

(8) Alternate monitoring schedules approved before November 15, 1996, under §§115.324(a)(8)(A), 115.334(3)(A), and 115.344(3)(A) of this title (relating to Inspection Requirements), as in effect December 3, 1993, are approved monitoring schedules for the purposes of paragraph (7) of this section.

(9) All component monitoring shall occur when the component is in contact with process material and the process unit is in service. If a unit is not operating during the required monitoring period but a component in that unit is in contact with process fluid which is circulating or under pressure, then that component is considered to be in service and is required to be monitored. Valves must be in gaseous or light liquid service to be considered in the total valve count for alternate valve monitoring schedules of paragraph (7) of this section.

(10) Except as provided in subparagraph (B) of this paragraph, the owner or operator shall use dataloggers and/or electronic data collection devices during all monitoring required by this section. The owner or operator shall use best efforts to transfer, on a daily basis, electronic data from electronic datalogging devices to the electronic database required by §115.356(2) of this title (relating to Monitoring and Recordkeeping Requirements).

(A) For all monitoring events in which an electronic data collection device is used, the collected monitoring data shall include the identification of each component and each calibration run, the maximum screening concentration detected, the time of monitoring (beginning and end), a date stamp, an operator identification, an instrument identification, and calibration gas concentrations and certification dates. The acceptable rate for recording data shall be determined individually by each owner or operator considering such factors including, but not limited to, the size of the equipment, the equipment type, the accessibility of the equipment, the number of leakers being found, and the skill of the monitoring technicians. Each owner or operator shall have a documented auditing process in place to assure proper calibration, identify response time failures, and assess pace anomalies.

(B) The owner or operator may use paper logs where necessary or more feasible (e.g., small rounds (less than 100 components), re-monitoring following component repair, or when dataloggers are broken or not available), and shall record, at a minimum, the information required in subparagraph (A) of this paragraph. For audio, visual, and olfactory inspections, the owner or operator shall record, at a minimum, the identification of the person conducting the inspection, the date, and the area that was inspected. The owner or operator shall transfer any manually recorded monitoring data to the electronic database required by §115.356(2) of this title within seven days of monitoring.

(C) Each change to the database shall be detailed in a log or inserted as a notation in the database. All such changes shall include the name of the person who made the change, the date of the change, and an explanation to support the change.

(11) Monitored screening concentrations must be recorded for each component. Notations such as "pegged," "off scale," "leaking," "not leaking," or "below leak definition" may not be substituted for hydrocarbon gas analyzer results. For readings that are higher than the upper end of the scale (i.e., pegged) even when using the highest scale setting or a dilution probe, record a default pegged value of 100,000 parts per million by volume.

(12) All exemptions for valves with a nominal size of two inches or less expired on July 31, 1992 (final compliance date).

§115.356.Monitoring and Recordkeeping Requirements.

All affected persons in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston areas shall have the following recordkeeping requirements, maintained either electronically or in hard copy form:

(1) records identifying each process unit subject to fugitive monitoring in accordance with this division (relating to Fugitive Emission Control in Petroleum Refining, Natural Gas/Gasoline Processing, and Petrochemical Processes in Ozone Nonattainment Areas) including, at a minimum, the following information:

(A) the name of each process unit;

(B) a scale plot plan showing the location of each process unit;

(C) process flow diagrams for each process unit showing the general process streams and major equipment on which the components are located; and

(D) the expected volatile organic compound (VOC) emissions if the process unit is shut down for repair of components or other equipment, including:

(i) the total emissions;

(ii) the calculations used; and

(iii) engineering assumptions applied;

(2) records on components and process areas that contain, at a minimum, the following data:

(A) the name of the process unit where the component is located;

(B) the type of component (e.g., pump, compressor, valve, pressure relief valve, etc.;

(C) all data required to be collected by the monitoring and inspection requirements of §115.354 of this title (relating to Inspection Requirements) for each component required to be monitored with a hydrocarbon gas analyzer;

(D) the weekly audio, visual, and olfactory inspections of flanges, including, at a minimum, the identification of the person conducting the inspection and the area that was inspected. Flanges in the Houston/Galveston area that are monitored using Test Method 21 as required by §115.781(b)(3) of this title (relating to General Monitoring and Inspection Requirements) are excluded from this recordkeeping requirement;

(E) the calibration of the monitoring instrument data required in §115.354(10) of this title;

(F) if a component is found leaking:

(i) the component identification and method of leak determination (Test Method 21, sight/sound/smell, or inert gas or hydraulic testing);

(ii) the date on which a leaking component is discovered;

(iii) the date on which a first attempt at repair was made to a leaking component;

(iv) the date on which a leaking component is repaired;

(v) the date and instrument reading of the recheck procedure after a leaking component is repaired;

(vi) the dates and nature of each extraordinary effort to repair the leaking component;

(vii) the date on which the leaking component is placed on the shutdown list;

(viii) the date on which the leaking component was taken out of service as allowed by §115.352(2)(C) of this title (relating to Control Requirements); and

(ix) the calculation showing the estimated VOC emission rates of the component as required by §115.352(2)(A)(i)(II) of this title if extraordinary efforts are not going to be initiated; and

(G) maintain records of any audio, visual, and olfactory inspections of connectors, but only if a leak is detected;

(3) records for each process unit with leaking components, updated each day after a leaking component is determined to require a process unit shutdown to repair and where extraordinary efforts to repair the component will not be pursued, including the following:

(A) the date, calculations, and estimated emissions of VOC as required by §115.352(2)(A)(i)(III) of this title;

(B) the date, calculations, and comparison of emissions of VOC as required by §115.352(2)(A)(i)(IV) of this title; and

(C) the date of each process unit shutdown required due to VOC emissions of leaking components exceeding the expected VOC emissions from the shutdown;

(4) records by process unit identifying and justifying each:

(A) unsafe to monitor valve;

(B) nonaccessible (difficult to monitor) valve; and

(C) each exemption by component claimed under §115.357 of this title (relating to Exemptions); and

(5) maintain all monitoring records for at least five years and make them available for review upon request by authorized representatives of the executive director, EPA, or local air pollution control agencies with jurisdiction, except that the five-year record retention requirement does not apply to records generated before December 31, 2000.

§115.357.Exemptions.

For all affected persons in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/ Galveston areas, the following exemptions shall apply.

(1) Components which contact a process fluid containing volatile organic compounds (VOCs) having a true vapor pressure equal to or less than 0.044 pounds per square inch absolute (psia) (0.3 kPa) at 68 degrees Fahrenheit (20 degrees Celsius) are exempt from the instrument monitoring (with a hydrocarbon gas analyzer) requirements of §115.354(1) and (2) of this title (relating to Inspection Requirements) if the components are inspected visually according to the inspection schedules specified in §115.354(1) and (2) of this title.

(2) Conservation vents or other devices on atmospheric storage tanks that are actuated either by a vacuum or a pressure of no more than 2.5 pounds per square inch gauge (psig), pressure relief valves equipped with a rupture disk or venting to a control device, components in continuous vacuum service, and valves that are not externally regulated (such as in-line check valves) are exempt from the requirements of this division (relating to Fugitive Emission Control in Petroleum Refining, Natural Gas/Gasoline Processing, and Petrochemical Processes in Ozone Nonattainment Areas), except that each pressure relief valve equipped with a rupture disk shall comply with §115.352(9) of this title (relating to Control Requirements).

(3) Compressors in hydrogen service are exempt from the requirements of §115.354 of this title if the owner or operator demonstrates that the percent hydrogen content can be reasonably expected to always exceed 50.0% by volume.

(4) All pumps and compressors which are equipped with a shaft sealing system that prevents or detects emissions of VOC from the seal are exempt from the monitoring requirement of §115.354 of this title. These seal systems may include, but are not limited to, dual pump seals with barrier fluid at higher pressure than process pressure, seals degassing to vent control systems kept in good working order, or seals equipped with an automatic seal failure detection and alarm system. Submerged pumps or sealless pumps (including, but not limited to, diaphragm, canned or magnetic driven pumps) may be used to satisfy the requirements of this paragraph.

(5) Reciprocating compressors and positive displacement pumps used in natural gas/gasoline processing operations are exempt from the requirements of this division.

(6) Components at a petroleum refinery; synthetic organic chemical, polymer, resin, or methyl-tert-butyl ether manufacturing process, which contact a process fluid that contains less than 10% VOC by weight and components at a natural gas/gasoline processing operation which contact a process fluid that contains less than 1.0% VOC by weight are exempt from the requirements of this division.

(7) Facilities with less than 250 components in VOC service are exempt from the requirements of this division.

(8) Components in ethylene, propane, or propylene service, not to exceed 5.0% of the total components, may be classified as non-repairable beyond the second repair attempt at 500 parts per million by volume (ppmv). These components will remain in the fugitive monitoring program and be repaired no later than 15 calendar days after the concentration of VOC detected via Test Method 21 exceeds 10,000 ppmv. For the purposes of this division, components which contact a process fluid with greater than 85% ethylene, propane, or propylene by weight are considered in ethylene, propane, or propylene service, respectively.

(9) Valves rated greater than 10,000 psig are exempt from the requirements of §115.352(4) of this title.

(10) In the Houston/Galveston area, the requirements of Subchapter H of this chapter (relating to Highly-Reactive Volatile Organic Compounds) apply to components which qualify for one or more of the exemptions in paragraphs (1) - (9) of this section at any petroleum refinery; synthetic organic chemical, polymer, resin, or methyl tert-butyl ether manufacturing process; or natural gas/gasoline processing operation in which a HRVOC, as defined in §115.10 of this title (relating to Definitions), is a raw material, intermediate, final product, or in a waste stream.

§115.359.Counties and Compliance Schedules.

The owner or operator of each affected source in Brazoria, Chambers, Collin, El Paso, Dallas, Denton, Fort Bend, Galveston, Hardin, Harris, Jefferson, Liberty, Montgomery, Orange, Tarrant, and Waller Counties shall:

(1) continue to comply with this division (relating to Fugitive Emission Control in Petroleum Refining, Natural Gas/Gasoline Processing, and Petrochemical Processes in Ozone Nonattainment Areas) as required by §115.930 of this title (relating to Compliance Dates); and

(2) comply with §115.356(2)(C) and (D) of this title (relating to Monitoring and Recordkeeping Requirements) as soon as practicable, but no later than December 31, 2003; and

(3) develop and make available upon request to the appropriate regional office, EPA, and any local air pollution control agency having jurisdiction the recordkeeping required by §115.356(1), (3), and (4) of this title as soon as practicable, but no later than December 31, 2003.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 18, 2002.

TRD-200208367

Stephanie Bergeron

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: January 17, 2003

Proposal publication date: June 21, 2002

For further information, please call: (512) 239-0348

2. SURFACE COATING PROCESSES

30 TAC §§115.420, 115.421, 115.427, 115.429

STATUTORY AUTHORITY

The amendments are adopted under TWC, §5.103, which provides the commission the authority to adopt rules necessary to carry out its powers and duties under the TWC; and under THSC, TCAA, §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the TCAA. The amendments are also adopted under TCAA, §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.034, concerning Research and Investigations, which authorizes the commission to require any research it considers advisable and necessary to perform its duties; and §382.051(d), concerning Permitting Authority of Commission; Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382; and FCAA, 42 USC, §§7401 et seq .

§115.420.Surface Coating Definitions.

(a) General surface coating definitions. The following terms, when used in this division (relating to Surface Coating Processes), shall have the following meanings, unless the context clearly indicates otherwise. Additional definitions for terms used in this division are found in §§3.2, 101.1, and 115.10 of this title (relating to Definitions).

(1) Aerosol coating (spray paint)--A hand-held, pressurized, nonrefillable container that expels an adhesive or a coating in a finely divided spray when a valve on the container is depressed.

(2) Coating--A material applied onto or impregnated into a substrate for protective, decorative, or functional purposes. Such materials include, but are not limited to, paints, varnishes, sealants, adhesives, thinners, diluents, inks, maskants, and temporary protective coatings.

(3) Coating application system--Devices or equipment designed for the purpose of applying a coating material to a surface. The devices may include, but are not be limited to, brushes, sprayers, flow coaters, dip tanks, rollers, knife coaters, and extrusion coaters.

(4) Coating line--An operation consisting of a series of one or more coating application systems and including associated flashoff area(s), drying area(s), and oven(s) wherein a surface coating is applied, dried, or cured.

(5) Coating solids (or solids)--The part of a coating that remains after the coating is dried or cured.

(6) Daily weighted average--The total weight of volatile organic compound (VOC) emissions from all coatings subject to the same emission standard in §115.421 of this title (relating to Emission Specifications), divided by the total volume of those coatings (minus water and exempt solvent) delivered to the application system each day. Coatings subject to different emission standards in §115.421 of this title shall not be combined for purposes of calculating the daily weighted average. In addition, determination of compliance is based on each individual coating line.

(7) High-volume low-pressure spray guns--Equipment used to apply coatings by means of a spray gun which operates between 0.1 and 10.0 pounds per square inch gauge air pressure at the air cap.

(8) Normally closed container--A container that is closed unless an operator is actively engaged in activities such as adding or removing material.

(9) Pounds of VOC per gallon of coating (minus water and exempt solvents)--Basis for emission limits for surface coating processes. Can be calculated by the following equation:

Figure: 30 TAC §115.420(a)(9) (No change.)

(10) Pounds of VOC per gallon of solids--Basis for emission limits for surface coating process. Can be calculated by the following equation:

Figure: 30 TAC §115.420(a)(10) (No change.)

(11) Spray gun--A device that atomizes a coating or other material and projects the particulates or other material onto a substrate.

(12) Surface coating processes--Operations which utilize a coating application system.

(13) Transfer efficiency--The amount of coating solids deposited onto the surface of a part or product divided by the total amount of coating solids delivered to the coating application system.

(b) Specific surface coating definitions. The following terms, when used in this division, shall have the following meanings, unless the context clearly indicates otherwise.

(1) Aerospace coating.

(A) Ablative coating--A coating that chars when exposed to open flame or extreme temperatures, as would occur during the failure of an engine casing or during aerodynamic heating. The ablative char surface serves as an insulative barrier, protecting adjacent components from the heat or open flame.

(B) Adhesion promoter--A very thin coating applied to a substrate to promote wetting and form a chemical bond with the subsequently applied material.

(C) Adhesive bonding primer--A primer applied in a thin film to aerospace components for the purpose of corrosion inhibition and increased adhesive bond strength by attachment. There are two categories of adhesive bonding primers: primers with a design cure at 250 degrees Fahrenheit or below and primers with a design cure above 250 degrees Fahrenheit.

(D) Aerospace vehicle or component--Any fabricated part, processed part, assembly of parts, or completed unit, with the exception of electronic components, of any aircraft including but not limited to airplanes, helicopters, missiles, rockets, and space vehicles.

(E) Aircraft fluid systems--Those systems that handle hydraulic fluids, fuel, cooling fluids, or oils.

(F) Aircraft transparency--The aircraft windshield, canopy, passenger windows, lenses, and other components which are constructed of transparent materials.

(G) Antichafe coating--A coating applied to areas of moving aerospace components that may rub during normal operations or installation.

(H) Antique aerospace vehicle or component--An aerospace vehicle or component thereof that was built at least 30 years ago. An antique aerospace vehicle would not routinely be in commercial or military service in the capacity for which it was designed.

(I) Aqueous cleaning solvent--A solvent in which water is at least 80% by volume of the solvent as applied.

(J) Bearing coating--A coating applied to an antifriction bearing, a bearing housing, or the area adjacent to such a bearing in order to facilitate bearing function or to protect base material from excessive wear. A material shall not be classified as a bearing coating if it can also be classified as a dry lubricative material or a solid film lubricant.

(K) Bonding maskant--A temporary coating used to protect selected areas of aerospace parts from strong acid or alkaline solutions during processing for bonding.

(L) Caulking and smoothing compounds--Semi-solid materials which are applied by hand application methods and are used to aerodynamically smooth exterior vehicle surfaces or fill cavities such as bolt hole accesses. A material shall not be classified as a caulking and smoothing compound if it can also be classified as a sealant.

(M) Chemical agent-resistant coating--An exterior topcoat designed to withstand exposure to chemical warfare agents or the decontaminants used on these agents.

(N) Chemical milling maskant--A coating that is applied directly to aluminum components to protect surface areas when chemically milling the component with a Type I or II etchant. Type I chemical milling maskants are used with a Type I etchant and Type II chemical milling maskants are used with a Type II etchant. This definition does not include bonding maskants, critical use and line sealer maskants, and seal coat maskants. Additionally, maskants that must be used with a combination of Type I or II etchants and any of the above types of maskants (i.e., bonding, critical use and line sealer, and seal coat) are not included. Maskants that are defined as specialty coatings are not included under this definition.

(O) Cleaning operation--Spray-gun, hand-wipe, and flush cleaning operations.

(P) Cleaning solvent--A liquid material used for hand-wipe, spray gun, or flush cleaning. This definition does not include solutions that contain no VOC.

(Q) Clear coating--A transparent coating usually applied over a colored opaque coating, metallic substrate, or placard to give improved gloss and protection to the color coat.

(R) Closed-cycle depainting system--A dust free, automated process that removes permanent coating in small sections at a time, and maintains a continuous vacuum around the area(s) being depainted to capture emissions.

(S) Coating operation--Using a spray booth, tank, or other enclosure or any area (such as a hangar) for applying a single type of coating (e.g., primer); using the same spray booth for applying another type of coating (e.g., topcoat) constitutes a separate coating operation for which compliance determinations are performed separately.

(T) Coating unit--A series of one or more coating applicators and any associated drying area and/or oven wherein a coating is applied, dried, and/or cured. A coating unit ends at the point where the coating is dried or cured, or prior to any subsequent application of a different coating.

(U) Commercial exterior aerodynamic structure primer--A primer used on aerodynamic components and structures that protrude from the fuselage, such as wings and attached components, control surfaces, horizontal stabilizers, vertical fins, wing-to-body fairings, antennae, and landing gear and doors, for the purpose of extended corrosion protection and enhanced adhesion.

(V) Commercial interior adhesive--Materials used in the bonding of passenger cabin interior components. These components must meet the Federal Aviation Administration (FAA) fireworthiness requirements.

(W) Compatible substrate primer--Either compatible epoxy primer or adhesive primer. Compatible epoxy primer is primer that is compatible with the filled elastomeric coating and is epoxy based. The compatible substrate primer is an epoxy-polyamide primer used to promote adhesion of elastomeric coatings such as impact-resistant coatings. Adhesive primer is a coating that:

(i) inhibits corrosion and serves as a primer applied to bare metal surfaces or prior to adhesive application; or

(ii) is applied to surfaces that can be expected to contain fuel. Fuel tank coatings are excluded from this category.

(X) Confined space--A space that:

(i) is large enough and so configured that a person can bodily enter and perform assigned work;

(ii) has limited or restricted means for entry or exit (for example, fuel tanks, fuel vessels, and other spaces that have limited means of entry); and

(iii) is not suitable for continuous occupancy.

(Y) Corrosion prevention compound--A coating system or compound that provides corrosion protection by displacing water and penetrating mating surfaces, forming a protective barrier between the metal surface and moisture. Coatings containing oils or waxes are excluded from this category.

(Z) Critical use and line sealer maskant--A temporary coating, not covered under other maskant categories, used to protect selected areas of aerospace parts from strong acid or alkaline solutions such as those used in anodizing, plating, chemical milling and processing of magnesium, titanium, or high- strength steel, high-precision aluminum chemical milling of deep cuts, and aluminum chemical milling of complex shapes. Materials used for repairs or to bridge gaps left by scribing operations (i.e., line sealer) are also included in this category.

(AA) Cryogenic flexible primer--A primer designed to provide corrosion resistance, flexibility, and adhesion of subsequent coating systems when exposed to loads up to and surpassing the yield point of the substrate at cryogenic temperatures (-275 degrees Fahrenheit and below).

(BB) Cryoprotective coating--A coating that insulates cryogenic or subcooled surfaces to limit propellant boil-off, maintain structural integrity of metallic structures during ascent or re-entry, and prevent ice formation.

(CC) Cyanoacrylate adhesive--A fast-setting, single component adhesive that cures at room temperature. Also known as "super glue."

(DD) Dry lubricative material--A coating consisting of lauric acid, cetyl alcohol, waxes, or other noncross linked or resin-bound materials that act as a dry lubricant.

(EE) Electric or radiation-effect coating--A coating or coating system engineered to interact, through absorption or reflection, with specific regions of the electromagnetic energy spectrum, such as the ultraviolet, visible, infrared, or microwave regions. Uses include, but are not limited to, lightning strike protection, electromagnetic pulse (EMP) protection, and radar avoidance. Coatings that have been designated as "classified" by the Department of Defense are excluded.

(FF) Electrostatic discharge and electromagnetic interference coating--A coating applied to space vehicles, missiles, aircraft radomes, and helicopter blades to disperse static energy or reduce electromagnetic interference.

(GG) Elevated-temperature Skydrol-resistant commercial primer--A primer applied primarily to commercial aircraft (or commercial aircraft adapted for military use) that must withstand immersion in phosphate-ester hydraulic fluid (Skydrol 500b or equivalent) at the elevated temperature of 150 degrees Fahrenheit for 1,000 hours.

(HH) Epoxy polyamide topcoat--A coating used where harder films are required or in some areas where engraving is accomplished in camouflage colors.

(II) Fire-resistant (interior) coating--For civilian aircraft, fire-resistant interior coatings are used on passenger cabin interior parts that are subject to the FAA fireworthiness requirements. For military aircraft, fire-resistant interior coatings are used on parts that are subject to the flammability requirements of MIL-STD-1630A and MIL-A-87721. For space applications, these coatings are used on parts that are subject to the flammability requirements of SE-R-0006 and SSP 30233.

(JJ) Flexible primer--A primer that meets flexibility requirements such as those needed for adhesive bond primed fastener heads or on surfaces expected to contain fuel. The flexible coating is required because it provides a compatible, flexible substrate over bonded sheet rubber and rubber-type coatings as well as a flexible bridge between the fasteners, skin, and skin-to-skin joints on outer aircraft skins. This flexible bridge allows more topcoat flexibility around fasteners and decreases the chance of the topcoat cracking around the fasteners. The result is better corrosion resistance.

(KK) Flight test coating--A coating applied to aircraft other than missiles or single-use aircraft prior to flight testing to protect the aircraft from corrosion and to provide required marking during flight test evaluation.

(LL) Flush cleaning--Removal of contaminants such as dirt, grease, oil, and coatings from an aerospace vehicle or component or coating equipment by passing solvent over, into, or through the item being cleaned. The solvent may simply be poured into the item being cleaned and then drained, or assisted by air or hydraulic pressure, or by pumping. Hand-wipe cleaning operations where wiping, scrubbing, mopping, or other hand action are used are not included.

(MM) Fuel tank adhesive--An adhesive used to bond components exposed to fuel and must be compatible with fuel tank coatings.

(NN) Fuel tank coating--A coating applied to fuel tank components for the purpose of corrosion and/or bacterial growth inhibition and to assure sealant adhesion in extreme environmental conditions.

(OO) Grams of VOC per liter of coating (less water and less exempt solvent)--The weight of VOC per combined volume of total volatiles and coating solids, less water and exempt compounds. Can be calculated by the following equation:

Figure: 30 TAC §115.420(b)(1)(OO) (No change.)

(PP) Hand-wipe cleaning operation--Removing contaminants such as dirt, grease, oil, and coatings from an aerospace vehicle or component by physically rubbing it with a material such as a rag, paper, or cotton swab that has been moistened with a cleaning solvent.

(QQ) High temperature coating--A coating designed to withstand temperatures of more than 350 degrees Fahrenheit.

(RR) Hydrocarbon-based cleaning solvent--A solvent which is composed of VOC (photochemically reactive hydrocarbons) and/or oxygenated hydrocarbons, has a maximum vapor pressure of seven millimeters of mercury (mm Hg) at 20 degrees Celsius (68 degrees Fahrenheit), and contains no hazardous air pollutant (HAP) identified in the 1990 Amendments to the Federal Clean Air Act (FCAA), §112(b).

(SS) Insulation covering--Material that is applied to foam insulation to protect the insulation from mechanical or environmental damage.

(TT) Intermediate release coating--A thin coating applied beneath topcoats to assist in removing the topcoat in depainting operations and generally to allow the use of less hazardous depainting methods.

(UU) Lacquer--A clear or pigmented coating formulated with a nitrocellulose or synthetic resin to dry by evaporation without a chemical reaction. Lacquers are resoluble in their original solvent.

(VV) Limited access space--Internal surfaces or passages of an aerospace vehicle or component that cannot be reached without the aid of an airbrush or a spray gun extension for the application of coatings.

(WW) Metalized epoxy coating--A coating that contains relatively large quantities of metallic pigmentation for appearance and/or added protection.

(XX) Mold release--A coating applied to a mold surface to prevent the molded piece from sticking to the mold as it is removed.

(YY) Monthly weighted average--The total weight of VOC emission from all coatings divided by the total volume of those coatings (minus water and exempt solvents) delivered to the application system each calender month. Coatings shall not be combined for purposes of calculating the monthly weighted average. In addition, determination of compliance is based on each individual coating operation.

(ZZ) Nonstructural adhesive--An adhesive that bonds nonload bearing aerospace components in noncritical applications and is not covered in any other specialty adhesive categories.

(AAA) Operating parameter value--A minimum or maximum value established for a control equipment or process parameter that, if achieved by itself or in combination with one or more other operating parameter values, determines that an owner or operator has continued to comply with an applicable emission limitation.

(BBB) Optical antireflection coating--A coating with a low reflectance in the infrared and visible wavelength ranges that is used for antireflection on or near optical and laser hardware.

(CCC) Part marking coating--Coatings or inks used to make identifying markings on materials, components, and/or assemblies of aerospace vehicles. These markings may be either permanent or temporary.

(DDD) Pretreatment coating--An organic coating that contains at least 0.5% acids by weight and is applied directly to metal or composite surfaces to provide surface etching, corrosion resistance, adhesion, and ease of stripping.

(EEE) Primer--The first layer and any subsequent layers of identically formulated coating applied to the surface of an aerospace vehicle or component. Primers are typically used for corrosion prevention, protection from the environment, functional fluid resistance, and adhesion of subsequent coatings. Primers that are defined as specialty coatings are not included under this definition.

(FFF) Radome--The nonmetallic protective housing for electromagnetic transmitters and receivers (e.g., radar, electronic countermeasures, etc.).

(GGG) Rain erosion-resistant coating--A coating or coating system used to protect the leading edges of parts such as flaps, stabilizers, radomes, engine inlet nacelles, etc. against erosion caused by rain impact during flight.

(HHH) Research and development--An operation whose primary purpose is for research and development of new processes and products and that is conducted under the close supervision of technically trained personnel and is not involved in the manufacture of final or intermediate products for commercial purposes, except in a de minimis manner.

(III) Rocket motor bonding adhesive--An adhesive used in rocket motor bonding applications.

(JJJ) Rocket motor nozzle coating--A catalyzed epoxy coating system used in elevated temperature applications on rocket motor nozzles.

(KKK) Rubber-based adhesive--A quick setting contact cement that provides a strong, yet flexible bond between two mating surfaces that may be of dissimilar materials.

(LLL) Scale inhibitor--A coating that is applied to the surface of a part prior to thermal processing to inhibit the formation of scale.

(MMM) Screen print ink--An ink used in screen printing processes during fabrication of decorative laminates and decals.

(NNN) Sealant--A material used to prevent the intrusion of water, fuel, air, or other liquids or solids from certain areas of aerospace vehicles or components. There are two categories of sealants: extrudable/rollable/brushable sealants and sprayable sealants.

(OOO) Seal coat maskant--An overcoat applied over a maskant to improve abrasion and chemical resistance during production operations.

(PPP) Self-priming topcoat--A topcoat that is applied directly to an uncoated aerospace vehicle or component for purposes of corrosion prevention, environmental protection, and functional fluid resistance. More than one layer of identical coating formulation may be applied to the vehicle or component.

(QQQ) Semiaqueous cleaning solvent--A solution in which water is a primary ingredent. More than 60% by volume of the solvent solution as applied must be water.

(RRR) Silicone insulation material--An insulating material applied to exterior metal surfaces for protection from high temperatures caused by atmospheric friction or engine exhaust. These materials differ from ablative coatings in that they are not "sacrificial."

(SSS) Solid film lubricant--A very thin coating consisting of a binder system containing as its chief pigment material one or more of the following: molybdenum, graphite, polytetrafluoroethylene, or other solids that act as a dry lubricant between faying (i.e., closely or tightly fitting) surfaces.

(TTT) Space vehicle--A man-made device, either manned or unmanned, designed for operation beyond earth's atmosphere. This definition includes integral equipment such as models, mock-ups, prototypes, molds, jigs, tooling, hardware jackets, and test coupons. Also included is auxiliary equipment associated with test, transport, and storage, that through contamination can compromise the space vehicle performance.

(UUU) Specialty coating--A coating that, even though it meets the definition of a primer, topcoat, or self-priming topcoat, has additional performance criteria beyond those of primers, topcoats, and self-priming topcoats for specific applications. These performance criteria may include, but are not limited to, temperature or fire resistance, substrate compatibility, antireflection, temporary protection or marking, sealing, adhesively joining substrates, or enhanced corrosion protection.

(VVV) Specialized function coating--A coating that fulfills extremely specific engineering requirements that are limited in application and are characterized by low volume usage. This category excludes coatings covered in other specialty coating categories.

(WWW) Structural autoclavable adhesive--An adhesive used to bond load-carrying aerospace components that is cured by heat and pressure in an autoclave.

(XXX) Structural nonautoclavable adhesive--An adhesive cured under ambient conditions that is used to bond load-carrying aerospace components or other critical functions, such as nonstructural bonding in the proximity of engines.

(YYY) Surface preparation--The removal of contaminants from the surface of an aerospace vehicle or component or the activation or reactivation of the surface in preparation for the application of a coating.

(ZZZ) Temporary protective coating--A coating applied to provide scratch or corrosion protection during manufacturing, storage, or transportation. Two types include peelable protective coatings and alkaline removable coatings. These materials are not intended to protect against strong acid or alkaline solutions. Coatings that provide this type of protection from chemical processing are not included in this category.

(AAAA) Thermal control coating--A coating formulated with specific thermal conductive or radiative properties to permit temperature control of the substrate.

(BBBB) Topcoat--A coating that is applied over a primer on an aerospace vehicle or component for appearance, identification, camouflage, or protection. Topcoats that are defined as specialty coatings are not included under this definition.

(CCCC) Touch-up and repair coating--A coating used to cover minor coating imperfections appearing after the main coating operation.

(DDDD) Touch-up and repair operation--That portion of the coating operation that is the incidental application of coating used to cover minor imperfections in the coating finish or to achieve complete coverage. This definition includes out-of-sequence or out-of-cycle coating.

(EEEE) VOC composite vapor pressure--The sum of the partial pressures of the compounds defined as VOCs, determined by the following calculation:

Figure: 30 TAC §115.420(b)(1)(EEEE) (No change.)

(FFFF) Waterborne (water-reducible) coating--A coating which contains more than 5.0% water by weight as applied in its volatile fraction.

(GGGG) Wet fastener installation coating--A primer or sealant applied by dipping, brushing, or daubing to fasteners that are installed before the coating is cured.

(HHHH) Wing coating--A corrosion-resistant topcoat that is resilient enough to withstand the flexing of the wings.

(2) Can coating--The coating of cans for beverages (including beer), edible products (including meats, fruit, vegetables, and others), tennis balls, motor oil, paints, and other mass-produced cans.

(3) Coil coating--The coating of any flat metal sheet or strip supplied in rolls or coils.

(4) Fabric coating--The application of coatings to fabric, which includes rubber application (rainwear, tents, and industrial products such as gaskets and diaphragms).

(5) Factory surface coating of flat wood paneling--Coating of flat wood paneling products, including hardboard, hardwood plywood, particle board, printed interior paneling, and tile board.

(6) Large appliance coating--The coating of doors, cases, lids, panels, and interior support parts of residential and commercial washers, dryers, ranges, refrigerators, freezers, water heaters, dishwashers, trash compactors, air conditioners, and other large appliances.

(7) Metal furniture coating--The coating of metal furniture (tables, chairs, wastebaskets, beds, desks, lockers, benches, shelves, file cabinets, lamps, and other metal furniture products) or the coating of any metal part which will be a part of a nonmetal furniture product.

(8) Mirror backing coating--The application of coatings to the silvered surface of a mirror.

(9) Miscellaneous metal parts and products coating.

(A) Clear coat--A coating which lacks opacity or which is transparent and which may or may not have an undercoat that is used as a reflectant base or undertone color.

(B) Drum (metal)--Any cylindrical metal shipping container with a nominal capacity equal to or greater than 12 gallons (45.4 liters) but equal to or less than 110 gallons (416 liters).

(C) Extreme performance coating--A coating intended for exposure to extreme environmental conditions, such as continuous outdoor exposure; temperatures frequently above 95 degrees Celsius (203 degrees Fahrenheit); detergents; abrasive and scouring agents; solvents; and corrosive solutions, chemicals, or atmospheres.

(D) High-bake coatings--Coatings designed to cure at temperatures above 194 degrees Fahrenheit.

(E) Low-bake coatings--Coatings designed to cure at temperatures of 194 degrees Fahrenheit or less.

(F) Miscellaneous metal parts and products (MMPP) coating--The coating of MMPP in the following categories at original equipment manufacturing operations; designated on-site maintenance shops which recoat used parts and products; and off-site job shops which coat new parts and products or which recoat used parts and products:

(i) large farm machinery (harvesting, fertilizing, and planting machines, tractors, combines, etc.);

(ii) small farm machinery (lawn and garden tractors, lawn mowers, rototillers, etc.);

(iii) small appliances (fans, mixers, blenders, crock pots, dehumidifiers, vacuum cleaners, etc.);

(iv) commercial machinery (computers and auxiliary equipment, typewriters, calculators, vending machines, etc.);

(v) industrial machinery (pumps, compressors, conveyor components, fans, blowers, transformers, etc.);

(vi) fabricated metal products (metal-covered doors, frames, etc.); and

(vii) any other category of coated metal products, including, but not limited to, those which are included in the Standard Industrial Classification Code major group 33 (primary metal industries), major group 34 (fabricated metal products), major group 35 (nonelectrical machinery), major group 36 (electrical machinery), major group 37 (transportation equipment), major group 38 (miscellaneous instruments), and major group 39 (miscellaneous manufacturing industries). Excluded are those surface coating processes specified in paragraphs (1) - (8) and (10) - (14) of this subsection.

(G) Pail (metal)--Any cylindrical metal shipping container with a nominal capacity equal to or greater than 1 gallon (3.8 liters) but less than 12 gallons (45.4 liters) and constructed of 29 gauge or heavier material.

(10) Paper coating--The coating of paper and pressure-sensitive tapes (regardless of substrate and including paper, fabric, and plastic film) and related web coating processes on plastic film (including typewriter ribbons, photographic film, and magnetic tape) and metal foil (including decorative, gift wrap, and packaging).

(11) Marine coatings.

(A) Air flask specialty coating--Any special composition coating applied to interior surfaces of high pressure breathing air flasks to provide corrosion resistance and that is certified safe for use with breathing air supplies.

(B) Antenna specialty coating--Any coating applied to equipment through which electromagnetic signals must pass for reception or transmission.

(C) Antifoulant specialty coating--Any coating that is applied to the underwater portion of a vessel to prevent or reduce the attachment of biological organisms and that is registered with the EPA as a pesticide under the Federal Insecticide, Fungicide, and Rodenticide Act.

(D) Batch--The product of an individual production run of a coating manufacturer's process. (A batch may vary in composition from other batches of the same product.)

(E) Bitumens--Black or brown materials that are soluble in carbon disulfide, which consist mainly of hydrocarbons.

(F) Bituminous resin coating--Any coating that incorporates bitumens as a principal component and is formulated primarily to be applied to a substrate or surface to resist ultraviolet radiation and/or water.

(G) Epoxy--Any thermoset coating formed by reaction of an epoxy resin (i.e., a resin containing a reactive epoxide with a curing agent).

(H) General use coating--Any coating that is not a specialty coating.

(I) Heat resistant specialty coating--Any coating that during normal use must withstand a temperature of at least 204 degrees Celsius (400 degrees Fahrenheit).

(J) High-gloss specialty coating--Any coating that achieves at least 85% reflectance on a 60 degree meter when tested by the American Society for Testing and Materials (ASTM) Method D-523.

(K) High-temperature specialty coating--Any coating that during normal use must withstand a temperature of at least 426 degrees Celsius (800 degrees Fahrenheit).

(L) Inorganic zinc (high-build) specialty coating--A coating that contains 960 grams per liter (eight pounds per gallon) or more elemental zinc incorporated into an inorganic silicate binder that is applied to steel to provide galvanic corrosion resistance. (These coatings are typically applied at more than two mil dry film thickness.)

(M) Maximum allowable thinning ratio--The maximum volume of thinner that can be added per volume of coating without exceeding the applicable VOC limit of §115.421(a)(15)(A) of this title.

(N) Military exterior specialty coating--Any exterior topcoat applied to military or United States Coast Guard vessels that are subject to specific chemical, biological, and radiological washdown requirements.

(O) Mist specialty coating--Any low viscosity, thin film, epoxy coating applied to an inorganic zinc primer that penetrates the porous zinc primer and allows the occluded air to escape through the paint film prior to curing.

(P) Navigational aids specialty coating--Any coating applied to Coast Guard buoys or other Coast Guard waterway markers when they are recoated aboard ship at their usage site and immediately returned to the water.

(Q) Nonskid specialty coating--Any coating applied to the horizontal surfaces of a marine vessel for the specific purpose of providing slip resistance for personnel, vehicles, or aircraft.

(R) Nonvolatiles (or volume solids)--Substances that do not evaporate readily. This term refers to the film-forming material of a coating.

(S) Nuclear specialty coating--Any protective coating used to seal porous surfaces such as steel (or concrete) that otherwise would be subject to intrusion by radioactive materials. These coatings must be resistant to long-term (service life) cumulative radiation exposure (ASTM D4082-83), relatively easy to decontaminate (ASTM D4256-83), and resistant to various chemicals to which the coatings are likely to be exposed (ASTM 3912-80). (For nuclear coatings, see the general protective requirements outlined by the U.S. Atomic Energy Commission in a report entitled "U.S. Atomic Energy Commission Regulatory Guide 1.54" dated June 1973, available through the Government Printing Office at (202) 512-2249 as document number A74062-00001.)

(T) Organic zinc specialty coating--Any coating derived from zinc dust incorporated into an organic binder that contains more than 960 grams of elemental zinc per liter (eight pounds per gallon) of coating, as applied, and that is used for the expressed purpose of corrosion protection.

(U) Pleasure craft--Any marine or fresh-water vessel used by individuals for noncommercial, nonmilitary, and recreational purposes that is less than 20 meters (65.6 feet) in length. A vessel rented exclusively to, or chartered for, individuals for such purposes shall be considered a pleasure craft.

(V) Pretreatment wash primer specialty coating--Any coating that contains a minimum of 0.5% acid by weight that is applied only to bare metal surfaces to etch the metal surface for corrosion resistance and adhesion of subsequent coatings.

(W) Repair and maintenance of thermoplastic coating of commercial vessels (specialty coating)--Any vinyl, chlorinated rubber, or bituminous resin coating that is applied over the same type of existing coating to perform the partial recoating of any in-use commercial vessel. (This definition does not include coal tar epoxy coatings, which are considered "general use" coatings.)

(X) Rubber camouflage specialty coating--Any specially formulated epoxy coating used as a camouflage topcoat for exterior submarine hulls and sonar domes.

(Y) Sealant for thermal spray aluminum--Any epoxy coating applied to thermal spray aluminum surfaces at a maximum thickness of one dry mil.

(Z) Ship--Any marine or fresh-water vessel, including self-propelled vessels, those propelled by other craft (barges), and navigational aids (buoys). This definition includes, but is not limited to, all military and Coast Guard vessels, commercial cargo and passenger (cruise) ships, ferries, barges, tankers, container ships, patrol and pilot boats, and dredges. Pleasure craft and offshore oil or gas drilling platforms are not considered ships.

(AA) Shipbuilding and ship repair operations--Any building, repair, repainting, converting, or alteration of ships or offshore oil or gas drilling platforms.

(BB) Special marking specialty coating--Any coating that is used for safety or identification applications, such as ship numbers and markings on flight decks.

(CC) Specialty interior coating--Any coating used on interior surfaces aboard United States military vessels pursuant to a coating specification that requires the coating to meet specified fire retardant and low toxicity requirements, in addition to the other applicable military physical and performance requirements.

(DD) Tack coat specialty coating--Any thin film epoxy coating applied at a maximum thickness of two dry mils to prepare an epoxy coating that has dried beyond the time limit specified by the manufacturer for the application of the next coat.

(EE) Undersea weapons systems specialty coating--Any coating applied to any component of a weapons system intended to be launched or fired from under the sea.

(FF) Weld-through preconstruction primer (specialty coating)--A coating that provides corrosion protection for steel during inventory, is typically applied at less than one mil dry film thickness, does not require removal prior to welding, is temperature resistant (burn back from a weld is less than 1.25 centimeters (0.5 inches)), and does not normally require removal before applying film-building coatings, including inorganic zinc high-build coatings. When constructing new vessels, there may be a need to remove areas of weld-through preconstruction primer due to surface damage or contamination prior to application of film-building coatings.

(12) Vehicle coating.

(A) Automobile and light-duty truck manufacturing.

(i) Automobile coating--The assembly-line coating of passenger cars, or passenger car derivatives, capable of seating 12 or fewer passengers.

(ii) Light-duty truck coating--The assembly-line coating of motor vehicles rated at 8,500 pounds (3,855.5 kg) gross vehicle weight or less and designed primarily for the transportation of property, or derivatives such as pickups, vans, and window vans.