The Texas Commission on Environmental Quality (TCEQ or commission) adopts the amendments to §§117.114, 117.201, 117.203, 117.206, 117.213, 117.214, 117.479, and 117.520. Sections 117.203, 117.206, 117.213, 117.214, 117.479, and 117.520 are adopted with changes to the proposed text as published in the December 3, 2004, issue of the Texas Register (29 TexReg 11279). Sections 117.114 and 117.201 are adopted without changes to the proposed text and will not be republished.

These amended sections and corresponding revisions to the state implementation plan (SIP) will be submitted to the United States Environmental Protection Agency (EPA).

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

The Federal Clean Air Act (FCAA) Amendments of 1990 as codified in 42 United States Code (USC), §§7401 et seq . require the EPA to set national ambient air quality standards (NAAQS) to ensure public health, and to designate areas as either in attainment or nonattainment with the NAAQS, or as unclassifiable. States are primarily responsible for ensuring attainment and maintenance of NAAQS once the EPA has established them. Each state is required to submit a SIP to the EPA that provides for attainment and maintenance of the NAAQS.

The Dallas-Fort Worth area (DFW area), consisting of four counties (Collin, Dallas, Denton, and Tarrant), was designated nonattainment and classified as moderate, in accordance with the 1990 FCAA Amendments, and was required to attain the one-hour ozone NAAQS by November 15, 1996. A SIP was submitted based on a volatile organic compound (VOC) reduction strategy, but the DFW area did not attain the NAAQS by the mandated deadline. Consequently, in 1998 the EPA reclassified the DFW area from "moderate" to "serious," resulting in a requirement to submit a new SIP demonstrating attainment by the new deadline of November 15, 1999.

The DFW area also failed to reach attainment by the November 1999, deadline. In the attainment demonstration SIP adopted by the commission in April 2000, the importance of local nitrogen oxides (NO _x ) reductions as well as the transport of ozone and its precursors from the Houston-Galveston-Brazoria ozone nonattainment area (HGB area) were considered. Based on photochemical modeling demonstrating transport from the HGB area, the agency requested an extension of the DFW area attainment date to November 15, 2007, the same attainment date as for the HGB area, in accordance with an EPA policy allowing extension of attainment dates due to transport of pollutants from other areas.

The EPA transport policy was overturned by federal courts, which ruled that the EPA does not have authority to extend an area's attainment date based on transport. Although the DFW area was not the specific subject of any of these suits, the DFW area one-hour ozone attainment demonstration SIP, including an extended attainment date, was not approvable by the EPA. Thus, the DFW area does not currently have an approved attainment demonstration SIP for the one-hour ozone NAAQS.

On July 18, 1997, the EPA promulgated a revised ozone standard (the eight-hour ozone NAAQS), and on April 30, 2004, promulgated the first phase implementation rule for the eight-hour ozone NAAQS (Phase I Implementation Rule) (69 FR 23951). Also on April 30, 2004, the DFW area was designated as nonattainment and classified as moderate for the eight-hour ozone NAAQS. Five additional counties (Ellis, Johnson, Kaufman, Parker, and Rockwall) were added to the DFW area. The DFW eight-hour nonattainment area consists of nine counties (Collin, Dallas, Denton, Ellis, Johnson, Kaufman, Parker, Rockwall, and Tarrant) effective June 15, 2004, for the eight-hour ozone NAAQS. The DFW area must attain the eight-hour ozone NAAQS by June 15, 2010.

The EPA's Phase I guidance provided three options for eight-hour ozone nonattainment areas that do not have an approved one-hour ozone attainment SIP: 1) submit a one-hour ozone attainment demonstration no later than one year after the effective date of the designation (by June 15, 2005); 2) submit an eight-hour ozone plan no later than one year after the effective date of the designation (by June 15, 2005) that provides a 5% increment of reductions from the area's 2002 emissions baseline in addition to federal measures and state measures already approved by the EPA, and achieves these reductions by June 15, 2007; or 3) submit an eight-hour ozone attainment demonstration by June 15, 2005. Options one and three require successful photochemical grid modeling performance. The commission, in coordination with the EPA, determined that option two is the most expeditious approach to beginning to achieve the reductions ultimately needed to: 1) meet the June 15, 2005, transportation conformity deadline; and 2) attain the eight-hour ozone NAAQS by June 15, 2010. In order for the DFW area to comply with the requirement to submit a 5% increment of progress (IOP) plan that provides a 5% emission reduction from the 2002 emissions baseline, additional emission reduction strategies are necessary.

The 5% IOP plan includes implementing new emission specifications and other requirements for certain industrial, commercial, and institutional stationary internal combustion engines in Collin, Dallas, Denton, Ellis, Johnson, Kaufman, Parker, Rockwall, and Tarrant Counties to reduce NO _x emissions and ozone air pollution.

The emission reduction requirements that will result from this adopted rulemaking will result in reductions in ozone formation in the DFW area and will help bring the DFW area into compliance with the eight-hour ozone NAAQS. These emission reductions are one component of the DFW SIP that the state is required to submit to the EPA to assure attainment and maintenance of the eight-hour ozone NAAQS. Attainment of the eight-hour ozone standard may require further reductions in NO _x emissions as well as VOC emissions. This rulemaking is one step toward meeting the state's obligations under the FCAA. The EPA has not yet issued Phase II of its eight-hour implementation rule (Phase II guidance) for states to use in developing eight-hour ozone attainment demonstrations. Phase II guidance, expected to be promulgated by the EPA in 2005, will provide additional information relating to eight-hour ozone attainment demonstrations. The commission is continuing to prepare for the required eight-hour ozone attainment demonstration SIP.

In addition to the changes applicable to certain engines in the DFW area, the commission is making technical changes to improve the language to best state the commission's intent regarding current requirements for major and minor sources of NO _x emissions in ozone nonattainment areas. Each change affects one or more of the ozone nonattainment areas of the state. The ozone nonattainment areas are Beaumont-Port Arthur ozone nonattainment area (BPA area), DFW area, and HGB area. The commission is also correcting references and typographical errors as required by Texas Register formatting requirements.

SECTION BY SECTION DISCUSSION

To conform with commission and Texas Register formatting requirements, non-substantive revisions were made throughout the sections to correct citations, formatting for dates, acronym usage, and other minor issues.

Subchapter B, Combustion at Major Sources

Division 1, Utility Electric Generation in Ozone Nonattainment Areas

§117.114, Emission Testing and Monitoring for the Houston-Galveston Attainment Demonstration

The commission amends §117.114(a)(4)(A) to correct the mass balance equation to show that the variable for the correction factor "d" multiplies the result of the operations of the other variables. The subparagraph containing the equation and associated variables has been reformatted for readability. The adopted amendment to §117.114(a)(4)(A) specifies that minor changes to the required test methods or EPA-approved alternative test methods may be approved by the executive director for the testing required to determine the correction factor "d." In §117.114(a)(4)(D) language has been removed that states that for this subparagraph the Engineering Services Team acts for the executive director.

Division 3, Industrial, Commercial, and Institutional Combustion Sources in Ozone Nonattainment Areas

§117.201, Applicability

The commission adds the phrase "or as otherwise specified" after the listing of ozone nonattainment areas. This addition is needed to alert potentially affected persons that other sections within this division may contain additional applicability requirements. In the case of this adopted rule package, persons in Ellis, Johnson, Kaufman, Parker, and Rockwall Counties, could be subject to control requirements found in §117.206, even though these counties are not listed in the current definition of "Dallas-Fort Worth (DFW) ozone nonattainment area" found in §117.10.

§117.203, Exemptions

The commission removes an extraneous "and" from §117.203(a)(11)(B) and adds "and" to §117.203(a)(12)(B).

The commission also adds, in adopted §117.203(a)(13), an exemption for cogeneration boilers that recover waste heat from one or more carbon black reactors for sources in the BPA area, except as may be specified in 30 TAC §§117.206(i), 117.209(c)(1), 117.213(i), 117.214(a)(2), 117.216(a)(5), and 117.219(f)(6) and (10). This exemption is added because it was not the commission's intent that these units be subject to Chapter 117, Subchapter B, Division 3. This exemption does not impact the BPA area SIP demonstration because NO _x reductions from these units are not included in the attainment demonstration. In addition, based on comments received, the adopted §117.203(a)(13) specifies that a cogeneration boiler in the BPA area that utilizes as a fuel source the tail gas from one or more carbon black reactors is also exempt.

Adopted §117.203(c) removes the exemption in §117.203(a)(1) from engines subject to the emission specifications in §117.206(b)(3). This assures that all gas-fired lean-burn and gas-fired rich-burn engines rated 300 horsepower (hp) or greater in the affected counties are required to meet the new emission specifications in §117.206(b)(3), regardless of when the units were placed into service. Subsequently, the commission removes the June 15, 2007, date because it is the commission's intent that this exemption no longer applies as of the effective date of the adopted rule.

Under 42 USC, §7511a(f), any moderate, serious, severe, or extreme ozone nonattainment area was required to implement NO _x reasonably available control technology (RACT) unless a demonstration was made that NO _x reductions would not contribute to, or would not be necessary for, attainment of the ozone standard. The exemption in §117.203(a)(1) for units placed into service after November 15, 1992, was part of the initial NO _x RACT rules adopted on May 11, 1993. This exemption included the November 15, 1992, date because this was the FCAA deadline by which states were to promulgate NO _x RACT rules. The emission specifications relating to RACT were adopted to implement controls on units permitted before November 15, 1992, because previous best available control technology determinations may not have been as stringent as RACT. The pollution controls in the permits issued after November 15, 1992, were expected to be equal to or more stringent than RACT.

Section 117.203(a)(1) was included in the Dallas-Fort Worth SIP to exclude new sources placed into service after the effective date of nonattainment new source review, November 15, 1992, from the emission standards in Chapter 117. Under these rules, major net increases from new or modified major stationary sources must apply controls representing the lowest achievable emission rate and obtain emission offsets in order to construct and operate. The DFW area is now designated nonattainment for the eight-hour NAAQS. Additional emission reductions from previously exempted units and source categories are necessary to achieve the reductions for the 5% IOP SIP revision.

§117.206, Emission Specifications for Attainment Demonstrations

The commission amended §117.206(b) to remove the words "in the Dallas-Fort Worth ozone nonattainment area" because each paragraph in this subsection now specifies the particular counties in which emission limitations apply, and the particular compliance schedule for each paragraph.

Amended §117.206(b)(1) states that gas-fired boilers in Collin, Dallas, Denton, and Tarrant Counties must comply with the existing NO _x emission limitations according to the compliance schedule in §117.520(b)(1). The commission amended §117.206(b)(2) to change "gas/liquid-fired" to "dual-fuel" to be consistent with references to types of engines in other sections of Chapter 117. Amended §117.206(b)(2) states that gas-fired lean-burn engines in Collin, Dallas, Denton, and Tarrant Counties must comply with the existing NO _x emission limitations according to the compliance schedule in §117.520(b)(1).

The adopted amendment to §117.206(b)(3) establishes new emission specifications for gas-fired lean-burn, and gas-fired rich-burn stationary reciprocating internal combustion engines rated 300 hp or greater in Collin, Dallas, Denton, Ellis, Johnson, Kaufman, Parker, Rockwall, and Tarrant Counties. Amended §117.206(b)(3) also specifies that the engines in these counties must comply with the emission standard in accordance with the compliance schedule in §117.520(b)(2). As previously noted in this preamble, the commission has selected option two from EPA's Phase I guidance, which requires the commission to submit a 5% IOP plan that provides a 5% reduction from the 2002 emissions inventory by June 15, 2007. Reductions resulting from these units are necessary to satisfy the 5% IOP and are part of the commission's approach to achieve the reductions ultimately needed to attain the eight-hour ozone NAAQS by June 15, 2010.

The proposed emission specification was 0.5 grams NO _x per horsepower hour (g/hp-hr) for both lean-burn internal combustion engines and rich-burn internal combustion engines. Subsequently, the commission revises the emission specification to 2.0 g/hp-hr for rich-burn engines placed into service before January 1, 2000, and all lean-burn engines. The revisions also require rich-burn engines placed into service on or after January 1, 2000, to comply with a 0.5 g/hp-hr emission specification.

The commission determined that the revised emission specifications are a reasonable first phase of reductions from these sources. Further reductions from these sources may be required to attain the eight-hour ozone standard. The commission will continue to analyze emissions inventories for future attainment demonstrations and determine what reductions may or may not be necessary.

Based on the data reported by industry, the commission's 2002 emissions inventory indicated that the new emission specifications affect a total of 13 lean-burn engines and six rich-burn engines at four sites in the DFW area. Subsequently, the commission determined that one of the engines previously categorized as a lean-burn engine is a rich-burn engine.

All seven of the affected rich-burn engines in the commission's 2002 emissions inventory should achieve the 2.0 g/hp-hr emission specification through engine modifications and/or the application of non-selective catalytic reduction. All rich-burn engines in Collin, Dallas, Denton, and Tarrant Counties were required to meet the existing emission specification of 2.0 g/hp-hr by March 31, 2002. The 12 affected lean-burn engines in the DFW area should achieve the emission specification with engine modifications. Both lean-burn and rich-burn engines are also required to perform a stack test in accordance with §117.211.

Based on comments received, adopted §117.206(b)(3)(C) specifies a 3.0 g carbon monoxide (CO)/hp-hr emission limit to clarify the commission's intent that the same CO emission limit in §117.205(d) or §117.206(b)(2) applies to affected engines in Ellis, Johnson, Kaufman, Parker, and Rockwall Counties.

Subsequently, the term "carbon monoxide" is replaced with the previously defined acronym "CO" in §117.206(e)(1).

The commission adds language in §117.206(h)(1), to clarify that the maximum rated capacity of units subject to §117.206(c) should be used to determine requirements for control plans, compliance demonstration, monitoring, testing requirements, and final control plan. This language ensures that the prohibition of circumvention provisions of subsection (h)(1) establish maximum rated capacity for the emission specifications in subsection (c) as well as any control plans, compliance, monitoring, and testing requirement in §§117.209, 117.211, 117.213, 117.214, and 117.216. This amendment applies in the HGB area as the provisions in §117.206(h)(1) are applicable only to HGB area sources.

§117.213, Continuous Demonstration of Compliance

The commission adds language to §117.213(a) that specifies the accuracy of totalizing fuel flow (TFF) meters to ± 5%. An accuracy specification for the TFF meters is necessary to ensure that fuel usage data is representative of actual operations and to demonstrate compliance with the NO _x Mass Emissions Cap and Trade (MECT) requirements in 30 TAC Chapter 101, Subchapter H. The ± 5% specification is sufficient for the commission's intended purpose for the fuel data and should be readily achievable by suppliers of fuel meters. Language added to this subsection also allows the amount of fuel burned in pilot flames to be calculated based on the manufacturer's design flow rates instead of requiring a separate fuel flow meter to measure the amount of fuel burned. This amendment requires that the calculated result be added to the metered value for total fuel use. This amendment applies in the BPA area, DFW area, and HGB area because all three areas have fuel flow requirements. Based on public comment, language is added to this subsection to require that owners or operators of units with totalizing flow meters installed before March 31, 2005, that do not meet the ± 5% accuracy requirement either recertify or replace the meters to meet the ± 5% accuracy requirement by March 31, 2007.

The commission clarifies the TFF requirements for wood-fired boilers in the HGB area by revising §117.213(a)(1)(B)(i). The commission requires a mechanism to measure activity or throughput for wood-fired boilers; however, a TFF meter can only be used to measure gas or liquid fuel. The revision requires maintaining records of fuel usage as required in §117.219(f) or monitoring exhaust flow. This revision only applies in the HGB area as there are currently no wood-fired boiler requirements in the BPA area or DFW area.

The commission adds language to §117.213(a)(1)(B)(xiii) that exempts vapor streams resulting from vessel cleaning and routed to an incinerator from the TFF meter requirements. The requirement to install TFF meters on these vapor streams is removed because the heating value of these vapor streams is expected to be low and variable. The total heating value contribution from these vapor streams to the combustion process must still be estimated based on calculations regardless of whether the vapor stream flow rate is determined by direct monitoring or by engineering calculations. This amendment specifies that the flow of vapor streams resulting from vessel cleaning must be calculated using good engineering methods. This requirement applies only in the HGB area. There are currently no fuel flow requirements for incinerators in the BPA area or DFW area. Adopted §117.213(a)(1)(B)(xiii) is revised to clarify that only vapor streams from vessel cleaning are exempt from fuel metering requirements, and that all other fuel and vapor streams are not exempt.

The commission restructures §117.213(a)(2) by adding new subparagraph (B) that allows a single TFF meter to monitor flow to multiple units as long as the units exhaust to a common stack monitored with a continuous emissions monitoring system (CEMS). The changes also add to §117.213(a)(2)(C) language that allows a fuel flow alternative for stationary diesel internal combustion engines. As long as the diesel engine is equipped with a run time meter, the use of monthly fuel use records is sufficient to measure activity or throughput. Adopted §117.213(a)(2)(C) is revised to clarify that monthly fuel use records must be maintained for each engine. These amendments apply to the BPA area, DFW area, and HGB area.

The commission amended §117.213(b)(3) to replace the word "necessitated" with "required" to better express the commission's intent of this rule.

The commission adds §117.213(c)(3) to provide for collection of substitute emissions compliance data in the event that the NO _x CEMS or predictive emissions monitoring system (PEMS) is off-line. In this event, the owner or operator of the unit would be required to comply with the missing data procedures in 40 Code of Federal Regulations (CFR) Part 75 as well as in §117.213. This amendment applies in the BPA area, DFW area, and HGB area.

The commission amended §117.213(e)(2) to correct a typographical error in the term "O ₂ ."

The commission amended §117.213(e)(3) to clarify that all exhaust stacks, from a unit for which a CEMS is required, must be monitored using a single monitor per stack or a time-shared monitor that can analyze each stack individually. Each exhaust with units with multiple exhaust stacks must be monitored to ensure that the emissions are accurately quantified. This amendment applies in the BPA area, DFW area, and HGB area.

The commission adds language to §117.213(e)(4)(A) that allows bypass stacks to be monitored upstream of the stack provided no additional NOx gas streams are introduced downstream of the monitor. The commission makes this change because, depending on the unit, installing a CEMS in the bypass stack itself may require that the unit be forced into upset in order to perform initial certification of the CEMS. The amendment requires that accurate readings be maintained and bypass stacks be continuously monitored to determine when the stack is in operation. The commission is retaining the option that currently exists in the rule allowing latitude in monitor placement, but this amendment ensures that no additional contaminants are introduced into the exhaust where they cannot be monitored. In addition, the commission clarifies that process knowledge and engineering calculations may be used to determine volumetric flow rate for the purposes of quantifying mass emissions for each event when the bypass stack is open. The adopted language requires that the maximum potential calculated flow rate be used and that the owner or operator maintain records on all process information and calculations and make these records available upon request by the executive director. An amendment to §117.213(e)(4)(B) allows CEMS to be shared among multiple exhaust stacks on a single unit provided certain conditions are met. A change to §117.213(e)(4)(C) adds an "and" to accommodate §117.213(e)(4)(D) that specifies that each individual stack must be analyzed separately for units with multiple exhaust stacks. The revisions to §117.213(e)(4) apply in the HGB area.

The commission updates §117.213(f)(5)(A)(ii)(VI) to replace "Engineering Services Team" with "executive director."

§117.214, Emission Testing and Monitoring for the Houston-Galveston Attainment Demonstration

The commission amends §117.214(a)(1)(D)(i) to correct the mass balance equation to show that the variable for the correction factor "d" multiplies the result of the operations of the other variables. The clause containing the equation has been reformatted for readability. The amendment in the figure also revises the previous language in §117.214(a)(1)(D)(i) to specify that minor changes to the required test methods or EPA-approved alternative test methods may be approved by the executive director for the testing required to determine the correction factor "d." In the figure of adopted §117.214(a)(1)(D)(i), the acronym "NO _x " is defined because the table is printed separately from the rule text in the Texas Register , a citation is corrected, and the second occurrence of "(relating to Initial Demonstration of Compliance)" is deleted because it is not needed. Also, §117.214(a)(1)(D)(iv) is amended to remove language stating that the Engineering Services Team acts for the executive director in approving alternate monitoring methods for ammonia.

In adopted §117.214(b)(1), the citation to §117.211 is revised to include "(relating to Initial Demonstration of Compliance)" because this is the first occurrence of the citation in the actual rule text as printed in the Texas Register .

Adopted §117.214(b)(2)(B) clarifies that affected stationary internal combustion engines must be tested biennially or every 15,000 hours of engine operation as required by §117.213(g)(1), in addition to the testing for proper operation required by §117.214(b)(2).

Subchapter D, Small Combustion Sources

Division 2, Boilers, Process Heaters, and Stationary Engines and Gas Turbines at Minor Sources

§117.479, Monitoring, Recordkeeping, and Reporting Requirements

The amendment to §117.479 applies in the HGB area only because this division only applies to the HGB area.

The commission adds language to §117.479(a) that specifies the accuracy of TFF meters to an accuracy of ± 5%. An accuracy specification for the TFF meters is necessary to ensure that fuel usage data is representative of actual operations and to demonstrate compliance with the NO _x MECT requirements in Chapter 101, Subchapter H. The ± 5% specification is sufficient for the commission's intended purpose for the fuel data and should be readily achievable by suppliers of fuel meters. Based on public comment, language is added to this subsection to require that owners or operators of units with totalizing flow meters installed before March 31, 2005, that do not meet the ± 5% accuracy requirement either recertify or replace the meters to meet the ± 5% accuracy requirement by March 31, 2007. Language added to this subsection also allows the amount of fuel burned in pilot flames to be calculated using the manufacturer's design flow rates instead of requiring a separate fuel flow meter. The calculated result must be added to the metered value for total fuel use.

The commission also adds language to exempt units from the TFF meter requirements if the site is not subject to the MECT program in Chapter 101, Subchapter H, Division 3. For the purposes of this division, fuel metering is not required unless the unit is subject to the MECT program or the owner or operator is claiming that the unit is exempt from the emission specifications in §117.475 due to low heat input as specified in §117.473(b). TFF meters should only be required for units that must demonstrate continuous compliance with the MECT program and the heat input limits in §117.473(b), unless the unit qualifies for one of the fuel metering alternatives provided §117.479(a)(2).

Adopted §117.479(a)(2)(B) allows a single TFF meter to monitor flow to multiple units as long as the units exhaust to a common stack monitored with a CEMS. The adopted amendment to §117.479(a)(2)(C) allows for a fuel flow alternative for stationary diesel internal combustion engines. If the diesel engine is equipped with a run time meter, the use of monthly fuel use records is sufficient to meet fuel flow monitoring requirements.

The commission provides an alternative to the TFF meter requirements in adopted §117.479(a)(2)(D) for units subject to the MECT program by allowing meter sharing among units. This alternative is an option for owners or operators who perform a stack test on all units sharing a TFF meter in accordance with §117.479(e). The owner or operator is required to use the emission rate from the stack test with the highest emission rate to quantify the emissions for purposes of MECT reporting in accordance with 30 TAC 101.359. This alternative in §117.479(a)(2)(D) minimizes economic impact for minor sources. Adopted §117.479(a)(2)(D) is revised to specify that only units of the same category of equipment may quality for this alternative. This is necessary to ensure that emissions estimates based on this alternative are reflective of actual emissions. It is important to note that although units that are not subject to the MECT program are not required to have a TFF meter, the owner or operator of each unit claiming the exemption in §117.473(b) is still subject to the annual fuel usage recordkeeping requirements in §117.479(g)(1).

Based on comments received, the commission adopts §117.479(a)(2)(E) to provide an alternative to the TFF meter requirements for independent school districts. Adopted §117.479(a)(2)(E)(i) specifies that owners or operators that elect to follow this alternative provision must maintain monthly records of fuel usage for the entire site and monthly records for each unit of the hours of operation, average operating rate, and estimated fuel usage. Adopted §117.479(a)(2)(E)(ii) specifies that within 60 days of written request by the executive director, the owner or operator must submit for review and approval all methods, engineering calculations, and process information used to estimate the hours of operation, operating rates, and fuel usage for each unit. The commission is providing this alternative specifically for independent school districts because schools are typically closed during the ozone season, and to prevent financial hardship due to lack of funding.

The commission also adopted §117.479(a)(2)(F) to allow TFF meter sharing for units exempted under §117.473(b), provided that all units at the same site qualify for the exemption and the total fuel usage for the entire site meets the appropriate fuel usage limitation.

The commission amended §117.479(e)(3) to allow shorter test times provided that they are approved by the executive director. This change ensures that the executive director has sufficient flexibility to address issues that may result from affected units that only operate for short periods of time in a day.

In response to comment, the adopted amendment to §117.479(e)(3)(G) allows for the use of American Society of Testing and Materials (ASTM) D6522-00 as an alternative to the specified test methods for testing performed on natural gas fired reciprocating engines, combustion turbines, boilers, and process heaters. The adopted provision also specifies that if an owner or operator uses ASTM D6522-00 to conduct the performance testing, the report must contain the information specified in §117.211(g). At adoption, the description "(relating to Initial Demonstration of Compliance)" after the citation in §117.479(e)(4) is deleted because it previously appears in §117.479(e)(3)(G). At adoption, the phrase "(relating to Exemptions)" is deleted after the citation in §117.479(h) because this description of the citation previously appears in this section after the same citation in §117.479(a)(1).

Subchapter E, Administrative Provisions

§117.520, Compliance Schedule for Industrial, Commercial, and Institutional Combustion Sources in Ozone Nonattainment Areas

The commission restructures §117.520(b) in order to accommodate the following changes. Amended §117.520(b)(1) restates the current compliance schedule that applies to DFW area sources, noting an exception for adopted §117.520(b)(2). Adopted §117.520(b)(2) specifies the June 15, 2007, compliance date for the amended emissions specifications, monitoring, testing requirements, and final control plans for certain internal combustion engines in the DFW area. The compliance date of June 15, 2007, is established to meet the EPA requirements in 40 CFR §51.905 relating to the 5% IOP. The amendment also specifies that all sources must submit the first semiannual report by January 31, 2008. Reference to these compliance dates is set forth for the DFW area engine emission specifications in §117.206(b)(3).

The commission also corrects a rule reference in §117.520(c)(1)(A)(iii).

The commission proposed amended §117.520(c)(2)(A)(ii) to clarify the intent of the compliance schedule. Subsequently, the commission determined that the proposed language did not accurately specify the intent. The commission is amending §117.520(c)(2)(A)(i) by adding two new subclauses, (I) and (II), to require an owner or operator to submit the results of CEMS or PEMS performance evaluation and quality assurance procedures within 60 days after startup of a unit following installation of emissions monitors or within 60 days of startup of a unit that is shut down as of March 31, 2005, respectively. Additionally, to avoid a conflict with §117.520(c)(2)(A)(i)(II), the commission deletes the final sentence from §117.520(c)(2)(A)(ii)(II). Finally, because the provisions of §117.520(c)(2)(A)(ii) only address units placed into service after March 31, 2005, that install emission controls, the commission amends §117.520(c)(2)(C) to clarify the compliance dates for units without emission controls. This clarification relates to compliance dates in the HGB area only.

Units subject to the System Cap requirements of §117.210, and not in operation prior to January 1, 1997, have the option of choosing any two consecutive years out of five for the average daily heat input level of activity (LOA) certification requirements. The compliance dates in §117.520(c)(2)(B)(ii) specify that the certification of LOA must be submitted no later than 60 days after the second consecutive third quarter of actual LOA is complete, but does not allow companies to choose any two out of five years before certifying the LOA. The proposed language in subsection (c)(2)(B)(ii) specified that owners or operators are allowed 60 days after the second consecutive third quarter of actual LOA out of the first five years of operation is chosen to submit their LOA. Adopted §117.520(c)(2)(B)(ii) is revised for clarity to specify that the certification of activity level must be submitted no later than 60 days after the second consecutive third quarter of actual level of activity data are available, selected from the first five years of operation.

The commission adopted the amendment to §117.520(c)(2)(G) to provide owners or operators of units that will be permanently shut down within six months of the compliance date, September 30, 2005, relief from the monitoring requirements in §117.214(a). Specifically, an owner or operator must have submitted written notification to the executive director no later than March 31, 2005, containing the following information: a list of units, by emission point number, that the owner or operator intends to shut down on or before September 30, 2005; the projected date each unit will be shut down; and the projected dates of the stack testing. The owner or operator will also be required to perform a stack test in accordance with §117.211 after March 31, 2005, and prior to September 30, 2005. For the time period from March 31, 2005, and September 30, 2005, the results of this testing will be used for demonstrating compliance with the emission specifications in §117.206(c) or to quantify the emissions for units subject to the MECT program. The revision also requires owners or operators that have not installed TFF meters to use the maximum rated capacity of the unit to quantify the emissions between March 31, 2005, and September 30, 2005. The revision also specifies that if the unit is not permanently shut down by September 30, 2005, the owner or operator will be considered in violation of §117.520(c) as of March 31, 2005, and that extensions beyond September 30, 2005, will not be granted. At adoption, the word "permanently" is added to the term "shut down" in §117.520(c)(2)(G)(i) and (iv) to clarify that the unit must be permanently shut down by September 30, 2005.

FINAL REGULATORY IMPACT ANALYSIS DETERMINATION

The commission reviewed the rulemaking considering the regulatory analysis requirements of Texas Government Code, §2001.0225, and determined that the rulemaking does not meet the definition of a "major environmental rule." A 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, a sector of the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state. The adopted amendments revise the SIP. While this rulemaking is intended to protect the environment by reducing NO _x , the commission does not find that the specific lean-burn and rich-burn engines in the DFW area comprise a sector of the economy, or that the rules will adversely affect in a material way the economy, productivity, competition, jobs, the environment, or the public health and safety in the DFW area. Further, the commission does not find that the changes that add the exemption for cogeneration boilers in the BPA area and the changes to improve the implementation of the requirements for compliance with existing rules in the BPA area, DFW area, and HGB area apply to sources that comprise a sector of the economy, or that the rules will adversely affect in a material way the economy, productivity, competition, jobs, the environment, or the public health and safety in the BPA area, DFW area, and HGB area.

The amendments to Chapter 117 are not subject to the regulatory analysis provisions of Texas Government Code, §2001.0225(b), because the adopted rules do not meet any of the four applicability requirements. Texas Government Code, §2001.0225 only applies to a major environmental rule, the result of which is to: 1) exceed a standard set by federal law; 2) exceed an express requirement of state law, unless the rule is specifically required by federal law; 3) exceed a requirement of a delegation agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program; or 4) adopt a rule solely under the general powers of the agency instead of under a specific state law.

Specifically, the amendments were developed as part of the control strategy to meet the eight-hour ozone NAAQS set by the EPA under 42 USC, §7409, and therefore meet a federal requirement. In addition to the changes applicable to certain engines in the DFW area, the amendments include technical changes to improve the language to best state the commission's intent regarding current requirements for major and minor sources of NO _x emissions in ozone nonattainment areas. Each change affects one or more of the ozone nonattainment areas of the state, BPA area, DFW area, and HGB area. 42 USC, §7410, requires states to adopt and submit a SIP which provides for "implementation, maintenance, and enforcement" of the primary NAAQS in each air quality control region of the state. While 42 USC, §7410 does not require specific programs, methods, or reductions in order to meet the standard, SIPs must include "enforceable emission limitations and other control measures, means, or techniques (including economic incentives such as fees, marketable permits, and auctions of emissions rights), as well as schedules and timetables for compliance as may be necessary or appropriate to meet the applicable requirements of this chapter," (meaning 42 USC, Chapter 85, Air Pollution Prevention and Control). While 42 USC, §§7401 et seq . does require some specific measures for SIP purposes, like the inspection and maintenance program, the statute also provides flexibility for states to select other necessary or appropriate measures. The federal government, in implementing 42 USC, §§7401 et seq ., recognized that the states are in the best position to determine what programs and controls are necessary or appropriate to meet the NAAQS, and provided for the ability of states and the public to collaborate on the best methods for attaining the NAAQS within a particular state. However, this flexibility does not relieve a state from developing and submitting a SIP that meets the requirements of 42 USC, §7410. Thus, while specific measures are not generally required, the emission reductions are required. States are not free to ignore the requirements of 42 USC, §7410 and must develop programs to assure that the nonattainment areas of the state will be brought into attainment on schedule.

The requirement to provide a fiscal analysis of regulations in the Texas Government Code was amended by Senate Bill (SB) 633 during the 75th Legislative Session, 1999. The intent of SB 633 was to require agencies to conduct a regulatory impact analysis of extraordinary rules. These are identified in the statutory language as major environmental rules that will have a material adverse impact and will exceed a requirement of state law, federal law, or a delegation federal program, or are adopted solely under the general powers of the agency. With the understanding that this requirement would seldom apply, the commission provided a cost estimate for SB 633 that concluded "based on an assessment of rules adopted by the agency in the past, it is not anticipated that the bill will have significant fiscal implications for the agency due to its limited application." The commission also noted that the number of rules that would require assessment under the provisions of the bill was not large. This conclusion was based, in part, on the criteria set forth in the bill that exempted rules from the full analysis unless the rule was a major environmental rule that exceeds a federal law. As previously discussed, 42 USC, §§7401 et seq . does not require specific programs, methods, or reductions in order to meet the NAAQS; thus states must develop programs for each nonattainment area to ensure that the area will meet the attainment deadlines. Because of the ongoing need to address nonattainment issues, the commission routinely proposes and adopts SIP rules. The legislature is presumed to understand this federal scheme. If each rule included in the SIP was considered to be a major environmental rule that exceeds federal law, then every SIP rule would require a full regulatory impact analysis contemplated by SB 633. This conclusion is inconsistent with the conclusions reached by the commission in its cost estimate and by the Legislative Budget Board in its fiscal notes. Since the legislature is presumed to understand the fiscal impacts of the bills it passes, and that presumption is based on information provided by state agencies and the Legislative Budget Board, the intent of SB 633 was only to require the full regulatory impact analysis for rules that are extraordinary in nature. While the SIP rules may have broad impacts, those impacts are no greater than necessary or appropriate to meet the requirements of 42 USC, §§7401 et seq . For these reasons, rules included in the SIP fall under the exception in Texas Government Code, §2001.0225(a), because they are required by federal law.

In addition, 42 USC, §7502(a)(2), requires attainment as expeditiously as practicable and 42 USC, §7511a(c), requires states to submit attainment demonstration SIPs for ozone nonattainment areas, such as the DFW area. The adopted rules, which will reduce ozone in the DFW area, will be submitted to the EPA as one of several measures in the federally required SIP. By reducing emissions of NO _x , a precursor of ozone, these controls will result in reductions in ozone formation in the BPA area, DFW area, and HGB area and help bring these areas into compliance with the air quality standards established under federal law as NAAQS for ozone. Therefore, the adopted rulemaking is a necessary component of, and consistent with, the eight-hour ozone attainment demonstration DFW SIP required by 42 USC, §7410, and for the state's existing plans for the BPA area and HGB area.

The commission has consistently applied this construction to its rules since this statute was enacted in 1997. Since that time, the legislature has revised the Texas Government Code, but left this provision substantially unamended. The commission presumes that "when an agency interpretation is in effect at the time the legislature amends the laws without making substantial change in the statute, the legislature is deemed to have accepted the agency's interpretation." Central Power & Light Co. v. Sharp , 919 S.W.2d 485. 489 (Tex. App. Austin 1995), writ denied with per curiam opinion respecting another issue , 960 S.W.2d 617 (Tex. 1997); Bullock v. Marathon Oil Co. , 798 S.W.2d 353, 357 (Tex. App. Austin 1990, no writ ); Cf. Humble Oil & Refining Co. v. Calvert , 414 S.W.2d 172 (Tex. 1967); Sharp v. House of Lloyd, Inc. , 815 S.W.2d 245 (Tex. 1991); Southwestern Life Ins. Co. v. Montemayor , 24 S.W.3d 581 (Tex. App. Austin 2000, pet. denied ); and Coastal Indust. Water Auth. v. Trinity Portland Cement Div. , 563 S.W.2d 916 (Tex. 1978).

As discussed earlier in this preamble, this rulemaking action implements requirements of 42 USC, §§7401 et seq . There is no contract or delegation agreement that covers the topic that is the subject of this action. Therefore, the adopted rulemaking does not exceed a standard set by federal law, exceed an express requirement of state law, exceed a requirement of a delegation agreement, nor is it adopted solely under the general powers of the agency. Finally, this rulemaking action was not developed solely under the general powers of the agency, but is authorized by specific sections of Texas Health and Safety Code, Chapter 382 (also known as the Texas Clean Air Act), and the Texas Water Code, that are cited in the STATUTORY AUTHORITY section of this preamble. Therefore, this rulemaking action is not subject to the regulatory analysis provisions of Texas Government Code, §2001.0225(b), because the adopted rulemaking does not meet any of the four applicability requirements.

TAKINGS IMPACT ASSESSMENT

The commission completed a takings impact analysis for the adopted rulemaking action under Texas Government Code, §2007.043. The specific purposes of this rulemaking are to achieve reductions of NO _x emissions to reduce ozone formation in the DFW area and help bring the DFW area into compliance with the air quality standards established under federal law as NAAQS for ozone. In addition to the changes applicable to engines in the DFW area, the amendments include technical changes to improve the language to best state the commission's intent regarding current requirements for major and minor sources of NO _x emissions in ozone nonattainment areas. Each change affects one or more of the ozone nonattainment areas of the state, BPA area, DFW area, and HGB area. If certain amendments are adopted, certain engines located in the DFW area may be required to install equipment to monitor emissions and implement new reporting and recordkeeping requirements. Installation of the necessary equipment could conceivably place a burden on private, real property. Other amendments provide clarification as to monitoring and reporting requirements and will not place a burden on private, real property.

Texas Government Code, §2007.003(b)(4), provides that Chapter 2007 does not apply to this rulemaking action, because it is reasonably taken to fulfill an obligation mandated by federal law. The emission limitations and control requirements within this rulemaking action were developed in order to meet the eight-hour ozone NAAQS set by the EPA under 42 USC, §7409. States are primarily responsible for ensuring attainment and maintenance of NAAQS once the EPA has established them. Under 42 USC, §7410, and related provisions, states must submit, for approval by the EPA, SIPs that provide for the attainment and maintenance of NAAQS through control programs directed to sources of the pollutants involved. Therefore, one purpose of this rulemaking action is to meet the air quality standards established under federal law as NAAQS. Attainment of the eight-hour ozone standard may require further reductions in NO _x emissions as well as VOC emissions. This rulemaking is one step toward meeting the state's obligations under the FCAA. Attainment of the eight-hour ozone standard may require further reductions in NO _x emissions as well as VOC emissions. This rulemaking is one step toward meeting the state's obligations under the FCAA.

In addition, Texas Government Code, §2007.003(b)(13), states that Chapter 2007 does not apply to an action that: 1) is taken in response to a real and substantial threat to public health and safety; 2) is designed to significantly advance the health and safety purpose; and 3) does not impose a greater burden than is necessary to achieve the health and safety purpose. Although the rules do not directly prevent a nuisance or prevent an immediate threat to life or property, they do prevent a real and substantial threat to public health and safety and significantly advance the health and safety purpose. This action is taken in response to the DFW area exceeding the federal eight-hour ozone NAAQS, which adversely affects public health, primarily through irritation of the lungs. The action significantly advances the health and safety purpose by reducing ozone levels in the DFW area. Consequently, these adopted rules meet the exemption in Texas Government Code, §2007.003(b)(13). This rulemaking action therefore meets the requirements of Texas Government Code, §2007.003(b)(4) and (13). For these reasons, the adopted rules do not constitute a takings under Texas Government Code, Chapter 2007.

CONSISTENCY WITH THE COASTAL MANAGEMENT PROGRAM

The commission determined the adopted rulemaking relates to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act of 1991, as amended (Texas Natural Resources Code, §§33.201 et seq. ), and the commission rules in 30 TAC Chapter 281, Subchapter B, concerning Consistency with the Texas Coastal Management Program. As required by 30 TAC §281.45(a)(3) and 31 TAC §505.11(b)(2), relating to actions and rules subject to the CMP, commission rules governing air pollutant emissions must be consistent with the applicable goals and policies of the CMP. The commission reviewed this action for consistency with the CMP goals and policies in accordance with the regulations of the Coastal Coordination Council and determined that the amendments are consistent with the applicable CMP goal expressed in 31 TAC §501.12(1) of protecting and preserving the quality and values of coastal natural resource areas, and the policy in 31 TAC §501.14(q), which requires that the commission protect air quality in coastal areas. The adopted rulemaking and SIP revision will ensure that the amendments comply with 40 CFR Part 50, National Primary and Secondary Air Quality Standards, and 40 CFR Part 51, Requirements for Preparation, Adoption, and Submittal of Implementation Plans. This rulemaking action is consistent with CMP goals and policies, in compliance with 31 TAC §505.22(e).

EFFECT ON SITES SUBJECT TO THE FEDERAL OPERATING PERMITS PROGRAM

Chapter 117 is an applicable requirement under 30 TAC Chapter 122, Federal Operating Permits Program; therefore, owners or operators subject to the federal operating permit program must, consistent with the revision process in Chapter 122, revise their operating permit to include the revised Chapter 117 requirements at their sites affected by the revisions to Chapter 117.

PUBLIC COMMENT

Public hearings on the proposal were held in Arlington on January 3, 2005, Austin on January 4, 2005, and in Houston on January 5, 2005, but no oral comments were received. The public comment period ended at 5:00 p.m. on January 6, 2005. Written comments were submitted by Degussa Engineered Carbons (Degussa); Dow Chemical Company (Dow); Houston Sierra Club (HSC); the Honorable Robert N. Cluck, M.D., Mayor of the City of Arlington (Mayor Cluck); Powell and Associates (Powell); Texas Chemical Council (TCC); and the EPA Region 6. Mayor Cluck indicated general support for the rules. Degussa, Dow, HSC, Powell, TCC, and the EPA Region 6 did not indicate whether they were for or against the adoption of the rules, but provided specific comments on the rules.

RESPONSE TO COMMENTS

HSC suggested that the commission define "minor changes" in §117.114(a)(4)(A) and §117.214(a)(1)(D)(i).

RESPONSE

The term "minor" modification is consistent with provisions in other commission rules and EPA regulations regarding modifications to test methods and monitoring requirements. An exact definition of a minor modification is not possible because what constitutes a minor modification is dependent on the specific method, situation, source type, and technical nature of the requested modification. Specifying an exhaustive list of "minor" modifications within the rules is not practical and would limit the executive director's ability to deal with unique situations that may arise during testing events. The technical staff of the commission determine on a case-by-case basis if a requested modification is minor in nature and is acceptable for the specific source and situation. Therefore, the commission declines to make the suggested change.

HSC suggested that in §117.203(a)(13) the commission only exempt cogeneration boilers that recover waste heat from one or more carbon black reactors if the source is a minor source, but not if the source is a major source. HSC states that NO _x emissions will be needed to meet the new eight-hour ozone standard, and therefore the commission should not exempt any major sources that can provide NO _x reductions. The EPA Region 6 requested that the commission elaborate on the facilities affected by the new exemption in §117.203(a)(13) and the associated emissions.

RESPONSE

The emission reductions necessary for the BPA attainment demonstration SIP were based on the modeling episode from September 6, 1993 - September 11, 1993, and the controlling day, September 10, 1993. Modeling for the controlling day indicated that a point source NO _x reduction of approximately 40% from 1997 levels, or about 60 tons per day, was necessary. The staff analyzed the most recent available point source NO _x emissions inventory, which was 1997. Emission specifications to achieve the necessary reductions were developed for the four largest of the source categories: industrial boilers, process heaters, electric utility boilers, and engines. This exemption is added because it was not the commission's intent that these units be subject to Chapter 117, Subchapter B, Division 3. This exemption does not impact the BPA area SIP demonstration because NO _x reductions from these units are not included in the attainment demonstration. Thus, there will be no emissions increases or decreases associated with the SIP with the addition of this exemption. The commission will continue to analyze emissions inventories for future attainment demonstrations and determine what reductions may or may not be necessary or achievable.

DEC commented that §117.203(a)(13) should be clarified and suggested the language read "any combustion unit in the BPA area that recovers heat from, or utilizes as a fuel source, the tail gas from one or more carbon black reactors."

RESPONSE

The commission agrees with the commenter's suggested language regarding "recovers heat from, or utilizes as a fuel source, the tail gas from one or more carbon black reactors." This revision will clarify that the exemption covers units that use tail gas for either heat recovery or fuel. However, this exemption is limited to cogeneration boilers, therefore, the commission declines to make the requested change regarding the term "combustion unit."

HSC suggested that the portion of the preamble that describes the changes to §117.206(h)(1) clarify that owners/operators "must" use the maximum rated capacity of units subject to §117.206(c) to determine requirements.

RESPONSE

The commission has clarified the preamble by stating that the maximum rated capacity of units subject to §117.206(c) "must" be used to determine requirements.

TCC commented that the commission should delete the language proposed in §117.206(h)(1) concerning prohibition of circumvention. TCC wants to retain the ability to take an enforceable permit condition to lower the maximum rated capacity below the CEMS monitoring limit and stated that the compliance deadline for CEMS installation is too near for the agency to impose this new requirement.

RESPONSE

The language in §117.206(h)(1) is to clarify the commission's intent regarding the provisions under the prohibition of circumvention and derating of a unit. In response to comments in the adopted revisions to Chapter 117, Subchapter B, Division 3, published in the Texas Register on October 12, 2001 (26 TexReg 8142), the commission indicated that the maximum rated capacity on December 31, 2000, would establish the applicability of the monitoring requirements for those units in §117.213(c)(1) for which a maximum rated capacity threshold applies. The commission maintains that the commenter does not have the option to derate a unit to avoid monitoring requirements. The adopted revisions to §117.206(h)(1) clarify this intent and, therefore, the provision is not a new requirement for CEMS.

TCC expressed support for the proposed language in §117.213(a) that allows calculation of fuel flow to pilots in lieu of separate metering of pilot fuel flow rate.

RESPONSE

The commission appreciates this comment in support of the rule.

TCC commented that it was impractical for large sites to review each individual fuel flow meter and guarantee that all meters meet the proposed ± 5% accuracy requirements for TFF meters proposed in §117.213(a). TCC added that some preexisting fuel flow meters may not meet this specification and replacement may be difficult to achieve the March 31, 2005, compliance date. Dow also objected to the proposed new 5% accuracy specification for TFF meters in §117.213(a), commenting that many of its combustion sources have existing fuel flow meters or have already made installations for the existing version of the rule. Dow commented that Dow facilities in Texas have more than 200 meters already in this service and that the proposed accuracy requirement may or may not be achievable for all existing meters. TCC and Dow suggested that TCEQ either delete the proposed required accuracy specification for the TFF meters required in §117.213(a) or allow some sort of variance for existing meters.

RESPONSE

The commission expects that owners or operators will have knowledge of the accuracy of a TFF meter in order to quantify emissions for MECT and emissions inventory reporting, and to ensure proper facility operations. Owners or operators may demonstrate compliance with this requirement based on pre-installed calibrations or manufacturer's specifications. However, the commission has amended the rule language to allow owners or operators additional time to comply with the ± 5% accuracy requirements for existing TFF meters that do not meet this requirement. These existing TFF meters must be replaced or recertified to meet the ± 5% accuracy requirement by March 31, 2007. All TFF meters installed after March 31, 2005, must meet the ± 5% accuracy requirement.

HSC suggested that in §117.213(a)(1)(B)(xiii) the commission only exempt dilute vapor streams resulting from vessel cleaning and routed to an incinerator if the source is a minor source, not if the source is a major source. HSC states that NO _x emission reductions will be needed to meet the new eight-hour ozone standard, and therefore the commission should not exempt any major sources that can provide NO _x reductions.

RESPONSE

The changes in §117.213(a)(1)(B)(xiii) do not exempt dilute vapor streams resulting from vessel cleaning from controls or vapor destruction requirements. The change would only remove the requirement to install a TFF meter in a vapor line containing a stream originating from the process of cleaning vessels. This change would not impact the emission reductions necessary for attainment because the changes will not allow an increase in emissions nor will the changes exempt units from the emission specifications in §117.206 or the MECT. The commission revises the proposed language to clarify that the incinerator used in conjunction with vessel cleaning itself is not exempt from the TFF metering requirements. Only the vapor stream resulting from the cleaning of vessels would be exempt from the TFF metering requirements. All other fuel sources and vapor streams routed to incinerators remain subject to the TFF metering requirements.

HSC suggested that in §117.213(a)(1)(B)(xiii) the commission define "good engineering methods." TCC suggested that TCEQ delete proposed language in §117.213(a)(1)(B)(xiii), "including calculation methods in general use and accepted in new source review permitting in Texas." TCC commented that "accepted" calculation methods for new source review permits are not defined, and should, therefore be deleted.

RESPONSE

Good engineering practice will vary depending on the specific operation and source and, therefore, cannot be specifically defined. The requirement to use calculation methods in new source review permitting is in place to establish the commission's expectation for what constitutes good engineering practices for the purposes of §117.213(a)(1)(B)(xiii). The language addressed by the commenters is consistent with language used in other commission rules such as the MECT rules in Chapter 101.

TCC suggested that TCEQ should add language in §117.213(a)(2) concerning alternatives to fuel flow monitoring for small heaters less than 10 million British thermal units per hour (MMBtu/hr) or infrequently used heaters operating less than 45 calendar days per year. Specifically, TCC suggested that these small or infrequently used heaters should be allowed to use maximum design fuel flow rate to estimate fuel flow in lieu of metering.

RESPONSE

The exemption in §117.203(a)(9) already establishes the minimum size process heater that is subject to the requirements of the major source rules. This exemption is consistent with the requirements for sources subject to the minor source rules in Chapter 117, Subchapter D, Division 2. Also, an infrequently used (i.e., operating less than 45 days per year) process heater could have emissions exceeding those of a frequently used unit depending upon the operating parameters and emission rates of the units. The commission maintains that fuel monitoring for the demonstration of compliance with large, small, and/or infrequently used units is necessary to ensure that the reductions for attainment are accurately quantified and enforceable. Therefore, the commission makes no changes as a result of the comments.

TCC expressed support for the proposed language in §117.213(a)(2)(C) concerning monthly fuel use records as an alternative to TFF meters for diesel engines operating with run time meters.

RESPONSE

The commission appreciates this comment in support of this part of the rule proposal.

HSC suggested that the commission explain the missing data procedures in §117.213(c). TCC commented that TCEQ should delete the proposed language in §117.213(c)(3)(A) concerning data substitution for NO _x monitors that are CEMS, indicating that the data substitution requirements in 40 CFR Part 75 are onerous, unnecessary, and contradict §101.354(b). TCC also commented that TCEQ should clarify §117.213(c)(3)(D) regarding whether the use of the data substitution method in §117.213(c)(3)(A) is optional and that an owner or operator can use the maximum block one-hour emission rate as measured during the initial demonstration of compliance.

RESPONSE

The language added to §117.213(c)(3) regarding data substitution is intended to clarify the rule requirements for missing data during periods of CEMS or PEMS downtime. TCC's comment regarding §117.213(c)(3)(D) is correct; §117.213(c)(3)(D) is provided as an option to the methods specified in §117.213(c)(3)(A) - (C). Therefore, the commission's references to 40 CFR Part 75 are not mandatory unless the owner or operator chooses to follow 40 CFR Part 75 procedures or the unit is already subject to 40 CFR Part 75. The prescriptions in §101.354 are for allowance deductions in the MECT program. The MECT allowance deduction methods are not intended to supercede the monitoring requirements of Chapter 117.

TCC commented that TCEQ should clarify that §117.213(f)(7), concerning PEMS, does not require submittal of information to the ED for approval.

RESPONSE

The language in §117.213(f) stating that , "The PEMS shall be subject to the approval of the executive director," regarding PEMS requirements is similar to the language in §117.213(e)(6) regarding CEMS requirements. Neither of these provisions are intended to specifically require submitting information to the executive director for prior approval before installation and certification of a CEMS or PEMS for the monitoring requirements of this rule. Rather, these provisions clarify that the executive director may require changes if some aspect of the CEMS or PEMS is determined to be inadequate.

TCC commented that the commission should clarify the applicability of testing and monitoring related to engines. In particular, TCC requested clarification for the diesel engine monitoring requirements under §117.213(g) and whether diesel engines are subject to the testing requirements of §117.211.

RESPONSE

The language in §117.214(b)(2)(B), specifying periodic testing requirements, was added to clarify that all engines must be monitored in accordance with §117.213(g)(1), including diesel engines. Diesel engines that are subject to an emission limitation of Division 3 are subject to the testing requirements of §117.211.

TCC commented that TCEQ should consider changing the mass balance equation in §117.214(a)(1)(D)(i) to {a/b x 1,000,000 - (c)(d)} and change the definition of variable "(d)" to be "the measured molar ratio of NO _x removal per mole of ammonia added, as determined by the stack sampling...." TCC also commented that the reference to §117.111(a)(2) in §117.214(a)(1)(D)(i) regarding the definition of variable "d," should reference §117.211(a)(2).

RESPONSE

The suggested change to the mass balance equation would require additional testing to accurately determine the ratio of NO to NO ₂ in order to adjust for the molar ratio of NO _x removal. Furthermore, the proposed change would only correct for errors in the calculated ammonia slip resulting from a source having a significant amount of NO ₂ present; other potential sources of error in the calculated ammonia slip would not be corrected by the suggested equation. The variable "d," as adopted, is a general bias correction factor that corrects for any error introduced to the calculated ammonia slip since "d" is determined based on measured ammonia versus the theoretical ammonia slip. This correction factor includes error that may result from the NO to NO ₂ ratio as well as other sources of potential errors. Therefore, the commission declines to make the suggested change to the mass balance equation. The commission agrees with TCC's suggested change regarding the rule reference in §117.214(a)(1)(D)(i) and has changed the rule accordingly.

Powell commented that §117.473(b) should be modified to allow any boiler or process heater with a maximum rated capacity greater than 2.0 MMBtu/hr that has an annual heat input less than or equal to 9.0 (10 ⁹ ) BTU per calendar year to be exempt.

RESPONSE

The commission's proposal did not modify §117.473. Therefore, the commission declines to make the suggested change because affected persons would not have an opportunity for notice and comment on the change.

Powell suggested that §117.479(a)(1) be modified to allow a utility company's gas meter to be used as an acceptable TFF meter. Powell further stated that this change would save school districts money and would aid in compliance.

RESPONSE

The suggested change is not necessary. Any gas meter that satisfies the requirements of §117.479(a)(1) may be used by an owner or operator; this might include a utility company's gas meter. The owner or operator is responsible for verifying that the particular gas meter installed by the utility company supplying natural gas to the site meets all requirements in the rules. No change to the rule has been made in response to this comment.

Powell also suggested that school districts would save money if §117.479(a)(1) were modified to allow one totalizing gas meter for multiple boilers claiming the exemption in §117.473(b).

RESPONSE

The commission has provided two alternatives in §117.479(a)(2)(B) and (D) that would allow an owner or operator to use one TFF meter for more than one unit. The commission has included in the adopted rule a new alternative in §117.479(a)(2)(E) specifically intended for school districts. In addition, adopted §117.479(a)(2)(F) clarifies that TFF meter sharing is allowed for units exempted under §117.473(b), provided that all units at the same site qualify for the exemption and the total fuel usage for the entire site meets the appropriate fuel usage limitation.

Powell suggested that school districts would also be provided some financial relief if the commission removed all references to "emission limitations of §117.475 of this title" from §117.479, including requirements for TFF meters, recordkeeping, etc.

RESPONSE

This suggested change would not provide financial relief because if this language were removed, the sources would still be subject to the requirements specified in §117.479. The testing, monitoring, recordkeeping, and reporting requirements specified in §117.479 for units subject to the ESADs are necessary for the commission to verify compliance. The adopted rule provides financial relief by providing alternatives to the TFF meter requirements as previously noted in this preamble.

Powell suggests rewording §117.479(e) to allow portable combustion analyzers to be used. Powell stated that this would allow for more a practical test run time period, and would reduce costs to school districts.

RESPONSE

During the recent adopted revisions to 40 CFR Part 60, Subpart GG, "Standards of Performance for Stationary Gas Turbines," in the July 8, 2004, Federal Register (69 FR 41346 - 41364), the EPA allowed the use of ASTM D6522-00, "Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers," for conducting performance tests required for Subpart GG. While not all methods that use portable analyzers may be appropriate for conducting performance tests, the commission recognizes that the EPA has evaluated the use of portable analyzers according to ASTM D6522-00 and determined that the method is acceptable for conducting performance tests on certain sources. The commission has also reviewed ASTM D6522-00 and determined that portable analyzers, if used according to the procedures specified in the ASTM method, can generate results of sufficient quality to satisfy the intent of the performance testing requirements of this rule. In addition, the commission recognizes that some cost savings may be realized by owners or operators if this ASTM method is allowed as an alternative to the EPA test methods already specified in §117.479(e). Therefore, the commission has revised §117.479(e) to allow the use of ASTM D6522-00 for performance tests on natural gas-fired reciprocating engines, combustion turbines, boilers, and process heaters. The use of ASTM D6522-00 for performance testing on all other sources will be considered on a case-by-case basis as provided in §117.479(e)(3)(F).

Dow and TCC commented that the commission should take a more flexible approach to CEMS and PEMS requirements for combustion sources that plan to cease operations shortly after March 31, 2005, and suggested revised rule language for §117.520(c)(2)(G). Specifically, Dow and TCC suggested changing the date that units must be permanently shut down from May 31, 2005, to September 31, 2005. The commenters also suggested that the requirement to conduct a reference method test between March 31, 2005, and May 31, 2005, was overly restrictive and that an owner or operator should be allowed to use earlier test results. Finally, Dow and TCC commented that a provision should be included to allow the executive director to grant extensions beyond September 30, 2005, on a case-by-case basis.

RESPONSE

The commission agrees with the commenters' suggested change to extend the date that the unit must be permanently shut down to September 30, 2005. This six-month time frame is necessary to address most situations the commission is aware of that companies have planned a permanent shutdown shortly after March 31, 2005, and does not adversely impact the long-term enforcement or effectiveness of the rule. The adopted rulemaking allows a unit that is required to install CEMS to operate until September 30, 2005, without a CEMS. However, the commission maintains that the requirements to install CEMS are necessary to demonstrate compliance with the emission specifications and the MECT and that the compliance with the associated reductions is the mechanism for demonstrating attainment with the NAAQS. The requirement to conduct a new stack test is necessary to provide the commission with accurate and current representations of the emissions during that period. Older tests may not reflect recent adjustments made to the unit for more current operating scenarios and demands. The cost savings realized by not having to install the required CEMS or PEMS will greatly outweigh the cost associated with performing a new stack test. Also, the suggested provision to allow open-ended extensions beyond the compliance date on a case-by-case basis would erode the enforcement of the rules and would impact the approvability of the SIP. Therefore, the commission declines to make the suggested changes regarding the use of prior test results and case-by-case extensions.

Dow and TCC urged the commission to adopt the technical correction prior to the March 31, 2005, compliance date to ensure that the regulated community does not have to comply with rules that are in the process of being changed.

RESPONSE

The commission will consider this proposal for adoption on April 27, 2005.

The EPA Region 6 recommended that the commission include an appropriate corresponding CO emission specification for the 0.5 g NO _x /hp-hr emission specification for lean-burn and rich-burn engines.

RESPONSE

It was the intent of the commission that units subject to §117.206(b)(3) be subject to the 3.0 g CO/hp-hr emission specification in §117.205(d) or §117.206(b)(2). However, the proposed applicability section, §117.201, inadvertently exempted engines in Ellis, Johnson, Kaufman, Parker, and Rockwall Counties from the CO limit specified in §117.205(d) or §117.206(b)(2). Therefore, the commission has revised §117.206(b)(3) to include the 3.0 g/hp-hr CO emission specification.

Mayor Cluck stated support for the commission's work with the EPA to bring cleaner air to north Texans.

RESPONSE

The commission appreciates the support of Mayor Cluck and will continue to work with the EPA to improve air quality in the north Texas region.

Subchapter B. COMBUSTION AT MAJOR SOURCES