The Texas Natural Resource Conservation Commission (commission) adopts amendments to §115.10, concerning Definitions; §§115.211-115.217 and 115.219, concerning Loading and Unloading of Volatile Organic Compounds (VOC); §§115.221-115.227, and 115.229, concerning Filling of Gasoline Storage Vessels (Stage I) for Motor Vehicle Fuel Dispensing Facilities; and §§115.234-115.237 and 115.239, concerning Control of VOC Leaks from Transport Vessels. Adopted with changes to the proposed text as published in the January 1, 1999 issue of the Texas Register (24 TexReg 61) are §§115.10, 115.211-115.217, 115.219, 115.221, 115.222, 115.224-115.227, 115.229, 115.234, 115.235, 115.237, and 115.239. Sections 115.223 and 115.236 are adopted without changes and will not be republished.

The commission adopts these revisions to Chapter 115, concerning Control of Air Pollution from VOCs, and to the State Implementation Plan (SIP) in order to reduce overall background levels of ground-level ozone in attainment, near-nonattainment, and ozone nonattainment areas.

The revisions are one element of the new Texas Clean Air Strategy (TCAS), which includes a variety of options in order to meet the National Ambient Air Quality Standards (NAAQS) for ground-level ozone. The purpose of the strategy is to reduce overall background levels of ozone in order to assist in keeping ozone attainment areas and near-nonattainment areas, such as Austin, Corpus Christi, Longview/Tyler/Marshall, San Antonio, and Victoria in compliance with the federal ozone standards. The new strategy is also necessary to help the Beaumont/Port Arthur, Dallas/Fort Worth, and Houston/Galveston ozone nonattainment areas move closer to ultimately reaching attainment with the ozone NAAQS. The TCAS takes into account recent science which shows that regional approaches may provide improved control of air pollution. In particular, staff has conducted photochemical grid modeling which indicates that implementation of Stage I vapor recovery, cleaner burning gasoline, and national low-emitting vehicles (NLEV) will result in ozone reductions (peak eight-hour average) of one to four parts per billion (ppb) in much of east and central Texas. Additional modeling conducted specifically for the one-hour ozone standard has shown reductions of up to 3.6 ppb in east and central Texas. Additional details concerning the need for a regional strategy are as follows.

BACKGROUND

At the time the 1990 Federal Clean Air Act (FCAA) Amendments were enacted, the focus on controlling ozone pollution was centered on local controls. However, for many years an increasing number of air quality professionals have felt that ozone is a regional problem requiring regional strategies in addition to local control programs. As nonattainment areas across the United States prepared attainment demonstration SIPs in response to the 1990 FCAA Amendments, several areas found that modeling attainment was made much more difficult, if not impossible, because of high ozone and ozone precursor levels entering from the boundaries of their respective modeling domains, commonly called transport.

The commission has conducted air quality modeling and upper air monitoring that found regional air pollution should be considered when studying air quality in Texas' ozone nonattainment areas. This work is supported by research conducted by the Ozone Transport Assessment Group (OTAG), the most comprehensive attempt ever undertaken to understand and quantify the transport of ozone. Both the commission and OTAG study results point to the need to take a regional approach, such as that proposed in the TCAS, to controlling air pollutants.

As part of the Coastal Oxidant Assessment for Southeast Texas (COAST) project, the commission and its contractor, Environ, Inc., conducted regional-scale modeling to develop future-year boundary conditions for the COAST modeling domain. The emissions inventory used in this modeling was based on the OTAG emission inventory and the modeling was conducted for a domain covering most of Texas as well as several southern states.

During the OTAG process, the commission's modeling staff ran several sensitivity analyses using this regional modeling setup to assess the impact of potential OTAG reductions on Texas. Applying the OTAG 5c reductions across the domain (60% reduction of point source oxides of nitrogen (NO _X ), 30% reduction of low-level NO _X , 30% reduction of VOC), compared to the case of no reductions, indicated that modeled reductions would significantly reduce ozone throughout most of the eastern half of Texas. Overall, the modeling indicated that a regional reduction strategy would be beneficial across a wide area of the state.

During modeling for the Houston/Galveston attainment demonstration SIP for the one-hour ozone standard, the commission's modeling staff conducted sensitivity analyses to determine the benefits that regional reductions might have on Houston/Galveston, when applied simultaneously with local reductions. Unlike the commission's regional modeling exercises discussed in the previous paragraphs, these model runs offer an opportunity to assess separately the benefits of reductions made within and outside a region, since model runs with and without the regional reductions scenarios in Houston/Galveston were conducted. Modeling runs were completed to evaluate the eight-hour average ozone concentrations in the COAST modeling domain for September 8, 1993 with 2007 projected emissions and assuming a 70% reduction of NO _x and a 15% reduction of VOC in the eight-county Houston/Galveston area. Even with the large reductions in Houston/Galveston, much of the upper Texas Coast is well above the eight-hour standard. Also, Austin, Victoria, and Corpus Christi show modeled eight-hour average concentrations above 85 ppb. The benefit of applying OTAG 5c reductions outside the Houston/Galveston eight-county area clearly showed that the reductions are beneficial to Houston/Galveston and provided additional ozone benefits of between five and ten ppb in Houston/Galveston.

Additional modeling has been completed by commission staff assessing the potential benefits of the TCAS. This modeling indicates that mobile source reductions (cleaner gasoline, NLEVs, and Stage I vapor recovery) have a potential to reduce peak eight-hour ozone averages of between one and four ppb in much of east and central Texas, with the greatest reductions seen in the Austin and San Antonio areas. Modeling completed since these rules were proposed further backs the effectiveness of these rules for reducing ozone. The latest modeling indicates one-hour and eight-hour ozone reductions in most of east and central Texas, with the most benefit seen in northeast Texas (Tyler/Longview) and central Texas (San Antonio and Austin). This modeling indicates significant reductions in some areas with lesser reductions in others. The main conclusion to be drawn from these models is that the appropriate controls have been selected for reducing ozone levels.

This modeling provides part of the evidence of the benefit of regional reductions on Texas' nonattainment areas and further provides justification that a regional strategy will help maintain air quality in near-nonattainment and attainment areas. Conclusions from the commission's work are supported by OTAG studies that also illustrate the importance of implementing a regional air quality control strategy.

The adopted rule revisions implement the Stage I vapor recovery option of the TCAS. The Stage I vapor recovery rules currently apply to approximately 7,000 gasoline stations in the Beaumont/Port Arthur, El Paso, Houston/Galveston, and Dallas/Fort Worth ozone nonattainment areas (Brazoria, Chambers, Collin, Dallas, Denton, El Paso, Fort Bend, Galveston, Hardin, Harris, Jefferson, Liberty, Montgomery, Orange, Tarrant, and Waller Counties). These rules regulate the filling of gasoline storage tanks at gasoline stations by tank-trucks. To comply with Stage I requirements, a vapor balance system is typically used to capture the vapors from the gasoline storage tanks which would otherwise be displaced to the atmosphere as these tanks are filled with gasoline. The captured vapors are routed to the gasoline tank-truck, and the vapors are processed by a vapor control system when the tank-truck is subsequently refilled at a gasoline terminal or gasoline bulk plant. The adopted rules will reduce VOC emissions which are precursors to ground-level ozone formation, resulting in ground-level ozone reductions.

The effectiveness of Stage I vapor recovery rules depends on the captured vapors being: (1) effectively contained within the gasoline tank-truck during transit; and (2) controlled when the transport vessel is refilled at a gasoline terminal or gasoline bulk plant. Otherwise, the emissions captured at the gasoline station will simply be emitted at a location other than the gasoline station, resulting in no reduction in VOC emissions despite the Stage I requirements.

Chapter 115 includes specific requirements for gasoline terminals in 16 ozone nonattainment counties (Brazoria, Chambers, Collin, Dallas, Denton, El Paso, Fort Bend, Galveston, Hardin, Harris, Jefferson, Liberty, Montgomery, Orange, Tarrant, and Waller). A gasoline terminal is a gasoline transfer facility, excluding marine terminals, with a gasoline throughput of at least 20,000 gallons per day, averaged over any consecutive 30-day period. Less restrictive Chapter 115 gasoline terminal rules apply in Gregg, Nueces, and Victoria Counties. Chapter 115 regulates gasoline terminals in Aransas, Bexar, Calhoun, Matagorda, San Patricio, and Travis Counties under general VOC transfer rules.

On December 14, 1994, the United States Environmental Agency (EPA) promulgated Title 40 Code of Federal Regulations (CFR) 63, Subpart R, pursuant to §112(d) of the 1990 Amendments to the FCAA. Subpart R is the National Emission Standards for Hazardous Air Pollutants (NESHAP) for Gasoline Distribution. Subpart R requires gasoline terminals nationwide to control emissions from the refilling of gasoline tank-trucks if emissions of hazardous air pollutants (HAPs) reach a threshold of ten tons per year of any one HAP or 25 tons per year of total HAPs.

Gasoline tank-trucks may also be refilled at a gasoline bulk plant, which is a gasoline transfer facility, excluding marine terminals, with a gasoline throughput less than 20,000 gallons per day, averaged over any consecutive 30-day period. Sections 115.211-115.219 require gasoline bulk plants in ozone nonattainment counties to control gasoline transfer emissions using a vapor balance (similar to that used at gasoline stations meeting Stage I requirements). Outside of the ozone nonattainment counties, however, there is currently no Chapter 115 requirement for control of emissions from gasoline bulk plants. Likewise, there is no Chapter 115 requirement for control of emissions from gasoline tank-truck leaks outside of the ozone nonattainment counties.

The adopted rule changes extend the existing Chapter 115 Stage I vapor recovery, gasoline terminal, gasoline bulk plant, and gasoline tank-truck leak testing requirements (§§115.211-115.217, 115.221-115.227, and 115.234-115.237) to 95 counties in the eastern half of Texas. These counties are: 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.

Concurrently, the commission adopts revisions which reorganize and clarify the rules, including incorporation of a variety of rule interpretations made by the agency's Air Rule Interpretation Team (RIT). These clarifying/reorganizing revisions include, where possible, consolidation or elimination of redundant language or requirements, the use of the active (rather than passive) voice, and relocation of rule language to more logical locations. In general, the commission's goal is to make the rules easier to read and more explicit concerning which requirements apply.

EXPLANATION OF ADOPTED RULES

The changes to §115.10, concerning Definitions, add a new definition of covered attainment counties which specifies the 95 counties to which Stage I, gasoline tank-truck testing, gasoline terminal, and gasoline bulk plant controls were extended; and add new definitions of flare, vapor combustor, and vapor control system. The definition of vapor control system is identical to the existing definition of vapor recovery system, and will facilitate a transition in the Chapter 115 rules to this term from the misleading term "vapor recovery system," which is defined to include both recovery and combustion control devices. The changes to §115.10 also delete the definitions of consumer-solvent products, municipal solid waste landfill emissions, and hand-held lawn and garden and utility equipment because these three definitions are no longer used in the Chapter 115 rules.

In addition, the changes to §115.10 delete the definitions of alcohol, alcohol substitutes, batch, cleaning solution, fountain solution, heatset, lithography, non-heatset, and offset lithography. These terms are used within the Chapter 115 offset printing rules (§§115.442, 115.443, 115.445, 115.446, and 115.449). In separate rulemaking, the commission recently adopted revisions which relocated the definitions of these terms to a new §115.440, concerning Offset Printing Definitions (see the March 12, 1999 issue of the Texas Register (24 TexReg 1777)).

The changes to §115.10 also delete the definition of cutback asphalt. This term is used within the Chapter 115 cutback asphalt rules (§§115.512, 115.513, 115.515-115.517, and 115.519). In separate rulemaking, the commission is proposing to relocate the definition of this term to a new §115.510, concerning Cutback Asphalt Definitions (see the April 23, 1999 issue of the Texas Register (24 TexReg 3178)).

Finally, the changes to §115.10 delete the following redundant definitions because these terms are already defined in 30 TAC §101.1, concerning Definitions, and are used in multiple chapters of the commission's rules: capture system, carbon adsorber, cold solvent cleaning, condensate, control device, control system, conveyorized degreasing, custody transfer, exempt solvent, gasoline, industrial solid waste, leak, liquid-mounted seal, marine vessel, mechanical shoe seal, motor vehicle fuel dispensing facility, municipal solid waste facility, municipal solid waste landfill, open-top vapor degreasing, process or processes, property, remote reservoir cold solvent cleaning, sludge, solid waste, source, submerged fill pipe, system or device, true vapor pressure, vapor-mounted seal, vent, and VOC water separator. Definitions which remain in §115.10 have been numbered in response to revised Texas Register rules (23 TexReg 1289, February 13, 1998).

The changes to §115.211, concerning Emission Specifications, establish an emission limit for gasoline bulk plants in the covered attainment counties which is equivalent to the current emission limit for gasoline bulk plants in ozone nonattainment counties. Likewise, the changes also establish an emission limit for gasoline terminals in the covered attainment counties. A 1990 rule effectiveness study, in which the agency staff stack-tested all gasoline terminals in the Dallas/Fort Worth area (other than those equipped with flares), found these gasoline terminals to be capable of meeting an emission limit of 10.8 milligram per liter (mg/l) of gasoline loaded. In order to gather more current data, the commission surveyed the test results for gasoline terminals in the covered attainment counties and the current ozone nonattainment counties and determined that the vast majority (94%) meet the 10.0 mg/l emission limit in 40 CFR 63, Subpart R (Gasoline Distribution NESHAP). The remaining 6.0% of the test results show compliance with a 20.0 mg/l emission limit. Consequently, the commission adopts a 20.0 mg/l emission limit for gasoline terminals in the covered attainment counties. Based on the test results, the commission believes that properly-maintained control devices at gasoline terminals can consistently meet the 20.0 mg/l emission limit. The commission solicited information regarding specific gasoline terminals in the covered attainment counties which cannot meet this emission limit when properly maintained, but none were identified. In addition, the revisions establish an expiration date for the less-stringent emission limit (80 mg/l) which currently applies to gasoline terminals in Gregg, Nueces, and Victoria Counties, and relocate the emission limit for gasoline terminals in these three counties from the existing §115.211(b) to the proposed §115.211(1)(B). The less stringent emission limit will expire upon the compliance date for the new limits. Finally, the revisions delete the emission limit of the existing §115.211(a)(3) for marine terminals in the Houston/Galveston ozone nonattainment area because this limit is already included in the existing §115.212(a)(8)(A).

The changes to §115.212, concerning Control Requirements, extend to the covered attainment counties the requirement that vapors from gasoline transfers at gasoline bulk plants be controlled rather than vented to the atmosphere. Likewise, the changes extend to the covered attainment counties the requirement that vapors from gasoline loading at gasoline terminals be controlled rather than vented to the atmosphere. Also, the changes establish requirements designed to minimize emissions during gasoline transfer at gasoline terminals and gasoline bulk plants in the covered attainment counties. In addition, the changes also extend to the covered attainment counties the requirement that VOC vapors remaining in transport vessels after unloading be kept in vapor-tight transport vessels until the vapors are returned to a loading, cleaning, or degassing operation and discharged in accordance with the control requirements of that operation; and update references to definitions which previously were in §115.10 but are now included only in §101.1.

The changes to §115.212(a)(1) also add an option which allows general VOC (i.e., non-gasoline) loading to be controlled through pressurized loading. This will clarify the control requirements for loading of VOCs which are stored and transported under pressure, such as propane.

The changes to §115.212 further add an allowance for draining VOC from a liquid line after transfer into a portable container, which is then closed vapor-tight and disposed of properly. This was added to the existing §115.212(a)(3) and (4) and (b)(3) and (4). The changes to §115.212 also concurrently relocate the requirements of the existing §115.212(a)(4) and (b)(4) to the revised §115.212(a)(3)(E) and (b)(3)(E), respectively. The gasoline terminal loading lockout provision of existing §115.212(a)(9), which currently applies in the Dallas/Fort Worth, El Paso, and Houston/Galveston ozone nonattainment areas, is relocated to the revised §115.212(a)(4)(C)-(E). This rule requires instrumentation which prevents gasoline transfer if the vapor line is not connected between the transport vessel and the terminal's vapor collection system, or if the control device malfunctions or is not operational. The purpose is to prevent uncontrolled gasoline loading at the loading rack. In addition, the changes to §115.212 extend to the covered attainment counties and the Beaumont/Port Arthur ozone nonattainment area a requirement for instrumentation which prevents gasoline transfer if the gasoline terminal's control device malfunctions or is not operational.

Also, the changes to §115.212 consolidate the gasoline bulk plant loading and unloading requirements of existing §115.212(a)(6) and (7) into the revised §115.212(a)(5), and add an option for gasoline bulk plants to control emissions using a vapor control system rather than a vapor balance system between the storage tank and the storage vessel. The revisions delete the existing §115.212(a)(6)(B), which concerns permissible pressure-vacuum relief valve emissions from gasoline transfer at gasoline bulk plants during emergency situations, because upset conditions are already addressed in §101.6, Upset Reporting and Recordkeeping Requirements.

In addition, the changes to §115.212(b)(1), concerning general land-based VOC loading (i.e., non-gasoline, non-marine), require that at VOC loading operations in Aransas, Bexar, Calhoun, Gregg, Matagorda, Nueces, San Patricio, Travis, and Victoria Counties, the vapors from the transport vessel must be controlled by a vapor control system which maintains a control efficiency of at least 90%, a vapor balance system, or pressurized loading. Under the current §115.212(b)(1) and (c)(1), VOC emissions from loading operations in these nine counties must be controlled such that the aggregate true vapor pressure of all VOC does not exceed 1.5 psia. When the Texas Air Control Board (TACB) first adopted this requirement on April 10, 1973, the intent and expectation was that the 1.5 psia control level represented a 90% control efficiency, according to a TACB staff memo dated November 12, 1973. However, the use of an aggregate true vapor pressure as a surrogate control efficiency has resulted in some confusion over the past 25 years. To eliminate this confusion, the rule revisions change the control efficiency to reflect the rule's original intent by using more commonly understood terminology. Most control devices can readily achieve and maintain a control efficiency of at least 90%. For example, flares which meet the standard design and operating criteria of 40 CFR 60.18(b) have been shown to operate with a control efficiency of at least 98%. However, some existing control devices, such as condensers, may be unable to consistently meet a 90% control level. The commission believes that the 90% overall control option for general land-based VOC loading, which is available in the proposed §115.213(c), will allow many general VOC loading operations in Aransas, Bexar, Calhoun, Gregg, Matagorda, Nueces, San Patricio, Travis, and Victoria Counties the flexibility to offset the increased emissions from existing lower-efficiency (less than 90%) control devices with reduced emissions from higher-efficiency (greater than 90%) control devices at the same account number. The commission solicited information regarding specific situations in these nine counties for which the 90% overall control option for general land-based VOC loading will not be a viable method for addressing existing lower-efficiency control devices. However, none were identified.

For marine terminals in the Houston/Galveston ozone nonattainment area, the changes to §115.212 also relocate the vapor balance option and the non-dedicated loading lines control requirement from the existing §115.217(a)(7)(C) and (D) to the revised §115.212(a)(6)(A) and (D), respectively. In addition, the revised §115.212(a)(6)(A) and (D) add an option which allows marine vessel loading to be controlled through pressurized loading. This will clarify the control requirements for loading of VOCs which are stored and transported under pressure, such as propane. Finally, the changes relocate the annual marine vessel vapor-tightness test in the existing §115.212(a)(8)(B) to the revised §115.214(a)(3)(A).

The changes to §115.213, concerning Alternate Control Requirements, revise the term "section" (which should have been "undesignated head") to "division" in response to revised Texas Register rules (23 TexReg 1289, February 13, 1998); extend the availability of alternate means of control to the entire covered attainment counties; and condense the three existing subsections into a single subsection. In addition, the changes relocate the 90% overall control options for marine terminals and general land-based VOC loading (i.e., non-gasoline, non-marine) in the existing §115.217(a)(6), (a)(8), (b)(4), and (c)(4) to the revised §115.213(b)-(d), with the addition of a requirement that loading of VOC with a vapor pressure of 11 psia or more must be controlled by either pressurized loading, a vapor control system, or a vapor balance system.

The changes to §115.214, concerning Inspection Requirements, establish inspection requirements for gasoline terminals and gasoline bulk plants in the covered attainment counties; require annual vapor-tightness testing of gasoline tank-truck tanks in the covered attainment counties; specify that the leak testing requirements apply to gasoline tank-truck tanks at both the loading and unloading points; specify that the leak testing requirements apply to general VOC (i.e., non-gasoline) tank-truck tanks at the loading point; and update references to definitions which previously were in §115.10 but are now included only in §101.1.

The changes to §115.214 also relocate the monthly gasoline terminal leak inspection requirement of the existing §115.214(a)(5), which currently applies in the Dallas/Fort Worth, El Paso, and Houston/Galveston ozone nonattainment areas, to the revised §115.214(a)(2). The revisions extend this monthly gasoline terminal leak inspection requirement to the Beaumont/Port Arthur ozone nonattainment area and the covered attainment counties.

In addition, the changes to §115.214 relocate the annual marine vessel vapor-tightness testing requirements in the existing §115.212(a)(8)(B), which applies to marine terminals in the Houston/Galveston ozone nonattainment area, to the revised §115.214(a)(3)(A). The revised §115.214(a)(3)(D) (currently §115.214(a)(4)(C)) is updated to reference an additional vapor-tightness test available under 40 CFR 63.565(c). The inclusion of this second test method for determining marine vessel vapor-tightness will provide additional flexibility to the regulated community.

The revised §115.214(a)(1)(D), (a)(3)(G), and (b)(1)(D) add exclusions from the leak inspection requirements for fumes from hatches or vents resulting from VOC transfer for which control of the transfer emissions is not required. The revised §115.214(b)(1)(C) adds a requirement to gasoline terminals and gasoline bulk plants in the covered attainment counties that gasoline tank-truck tanks pass an annual leak-tightness test.

The changes to §115.215, concerning Approved Test Methods, extend the existing test methods to the covered attainment counties and consolidate the existing §115.215(a) and (b) into a single subsection. Because it is not reasonably possible to measure the mass emission rate from an elevated flare (an elevated flare's flame is open to the atmosphere, such that the emissions cannot be routed through a stack), the test methods for flow rate and VOC concentration in §115.215(1) and (2) do not apply to flares. In order to specify performance requirements for flares, the revised §115.215(3) establishes the test requirements of 40 CFR 60.18(b). Because flares cannot be stack-tested, the revised §115.215(3) also specifies that compliance with the requirements of 40 CFR 60.18(b) represents compliance with the emission specifications of §115.211 and the control efficiency requirements of §115.212. The revisions to §115.215 also add a new paragraph (10), which authorizes the use of test methods other than those specifically listed in §115.215, provided that any new test method is validated using the procedures in 40 CFR 63, Appendix A, Test Method 301, with the executive director acting as the administrator. This revision is necessary because in some specific unique situations, the listed test methods may be inappropriate. The new paragraph (10) increases flexibility by allowing the use of additional test methods which may be more cost-effective and more appropriate in certain unique situations.

The changes to §115.216, concerning Monitoring and Recordkeeping Requirements, extend the recordkeeping requirements to gasoline terminals and gasoline bulk plants in the covered attainment counties; update references to definitions which previously were in §115.10 but are now being included only in §101.1; revise a reference to the EPA for consistency with the commission's style guidelines; consolidate the existing §115.216(a) and (b) into a single subsection; specify that flares must meet the requirements of 40 CFR 60.18(b) and 30 TAC Chapter 111; and state that records of appropriate operating parameters must be kept for types of vapor control systems not specifically listed in §115.216(1)(A) and (B). The revised §115.216(1)(A)(iv) and (1)(B) specify exhaust gas temperature monitoring of vapor combustors, with an option that the owner/operator of a vapor combustor may consider it to be a flare and monitor the unit under the flare requirements specified in 40 CFR 60.18(b) and Chapter 111. These revisions are necessary to ensure that control devices are functioning properly, and to clarify how vapor combustors are to be monitored. Based upon information from the agency's New Source Review Permits Division, most existing flares at gasoline terminals and land-based general VOC (non-gasoline) loading facilities meet the design and operating criteria of 40 CFR 60.18(b). The commission solicited information regarding flares that do not meet the requirements of 40 CFR 60.18(b). However, none were identified. The commission deleted the proposed change to §115.216 which would have added a requirement that records must include information on how the design standard or operation of equipment meets the emission specifications and control requirements. The commission believes a more thorough analysis of the impacts on the regulated community is needed.

The revisions to the existing §115.216(a)(3)-(5), (b)(3), and (b)(5), which specify the daily recordkeeping for land-based VOC transfer operations, consolidate and relocate these requirements to the revised §115.216(3), with the only records required being those which are necessary to establish compliance with, or exemption from, the rule requirements. The existing §115.216(a)(1) and (b)(1), which require a daily record of the total quantity of VOC loaded at the plant, are being consolidated and relocated to the revised §115.216(3)(D), and the applicability reduced. Specifically, this record of daily VOC loaded will only be required when needed to establish the exemption eligibility of loading operations and gasoline bulk plants below the 20,000 and 4,000 gallons per day thresholds, respectively. Similarly, for general VOC (non-gasoline) transfer operations in which all VOC handled has a low vapor pressure, the revised §115.216(3)(C) will allow these operations to simply keep records of the type and vapor pressure of each VOC transferred, and any appropriate test results.

Previously, §115.216 did not include specific recordkeeping requirements for land-based VOC transfer operations in Aransas, Bexar, Calhoun, Matagorda, San Patricio, and Travis Counties. The revisions to §115.216 add recordkeeping requirements for land-based general VOC (i.e., non-gasoline) transfer operations in these counties which are sufficient to document compliance with the control requirements, inspection requirements, and exemptions.

The existing §115.216(a)(2)(D) and (b)(2)(D), which concern records associated with control device maintenance activities, are being deleted because maintenance activities are already addressed in 30 TAC §101.7, Maintenance, Start-up and Shutdown Reporting, Recordkeeping, and Operational Requirements.

The changes to §115.217, concerning Exemptions, establish an exemption for small (less than 4,000 gallons per day) gasoline bulk plants in the covered attainment counties; update references to definitions which previously were in §115.10 but are now being included only in §101.1; revise the term "undesignated head" to "division" in response to revised Texas Register rules (23 TexReg 1289, February 13, 1998); and consolidate the existing §115.217(b) and (c) into a single subsection.

In addition, the revisions to §115.217 relocate the 90% overall control options for marine terminals and general land-based VOC loading (i.e., non-gasoline, non-marine) in the existing §115.217(a)(6), (a)(8), (b)(4), and (c)(4) to the revised §115.213(b)-(d). The revisions also relocate the marine vessel exemptions in the existing §115.217(a)(4) and (7) to the revised §115.217(a)(5), and add §115.217(a)(5)(A)(ii) to clarify that transfer of VOC from one marine vessel to another marine vessel ("lightering") is exempt, as long as the VOC transfer does not use loading arm(s), pump(s), meter(s), valve(s), or piping that are part of a marine terminal. Any lightering which uses a marine terminal's loading arm(s), pump(s), meter(s), valve(s), or piping is treated as though the VOC was loaded directly from the marine terminal into the marine vessel, and is required to be controlled the same as any other marine vessel loading which occurs at the terminal.

Further, the changes to §115.217 revise the existing exemptions for low vapor pressure VOC loading, low throughput of land-based VOC loading, crude oil, condensate, liquefied petroleum gas (LPG), and small gasoline bulk plants to make clear which requirements these operations must meet. In the existing §115.217(a)(1)-(3), (b)(1)-(3), and (c)(1)-(3), low vapor pressure VOC loading, low throughput of land-based VOC loaded, and LPG are exempt from the requirements of §115.212 only. Similarly, the existing §115.217(b)(3) and (c)(3) exempt the transfer of crude oil and condensate in Aransas, Bexar, Calhoun, Gregg, Matagorda, Nueces, San Patricio, Travis and Victoria Counties from the requirements of §115.212 only. The revisions specify that after unloading, the transport vessel must be kept vapor-tight until the vapors in the transport vessel are returned to a loading, cleaning, or degassing operation and are discharged in accordance with the control requirements of that operation.

The revisions broaden the existing exemptions for crude oil and condensate (applicable only in Aransas, Bexar, Calhoun, Gregg, Matagorda, Nueces, San Patricio, Travis and Victoria Counties), LPG, low vapor pressure VOC loading, low throughput of land-based VOC loading, and small gasoline bulk plants to exempt most inspection, testing, and recordkeeping requirements. However, these operations will continue to be required to conduct inspections for visible liquid leaks, cease VOC transfer when a liquid leak is observed, and repair the leak before transferring additional VOC. General land-based (i.e., non-gasoline) transfer of low vapor pressure VOC and small general land-based VOC loading plants which handle both exempt and non-exempt VOC will be required to maintain records of test results (e.g., vapor pressure testing) and the vapor pressure and type of each VOC transferred (excluding gasoline). As noted previously, under the revised §115.216(3)(D), the requirement of the current §115.216(a)(1) and (b)(1) to maintain records of total VOC loaded will continue to apply to low throughput gasoline bulk plants and low throughput general VOC loading operations. The revisions to §115.217(b) also relocate the existing exemption for loading and unloading of marine vessels in Aransas, Bexar, Calhoun, Gregg, Matagorda, Nueces, San Patricio, Travis and Victoria Counties to a new paragraph (6), and clarify that this exemption applies to all of the covered attainment counties.

The changes to §115.219, concerning Counties and Compliance Schedules, specify the compliance schedule for the new requirements; delete language which is obsolete due to the passing of a November 15, 1996 compliance date; and revise references to the Texas Natural Resource Conservation Commission (TNRCC) and the EPA for consistency with the commission's style guidelines.

The changes to §115.221, concerning Emission Specifications, add an emission limit for filling of gasoline storage tanks at motor vehicle fuel dispensing facilities in the covered attainment counties; and change a reference from "vapor recovery system" to "vapor control system" for clarification. This emission limit is the same one already required in ozone nonattainment counties.

The changes to §115.222, concerning Control Requirements, extend to the covered attainment counties the requirements designed to minimize emissions during these gasoline transfer operations, as well as the requirement that filling of gasoline storage tanks at motor vehicle fuel dispensing facilities be controlled through a vapor balance system rather than vented to the atmosphere. The changes to §115.222 also require non-coaxial Stage I connections for the installation of new storage tanks or modification of existing storage tanks in the covered attainment counties after December 22, 1998. In addition, the changes to §115.222 extend to the covered attainment counties the requirement that VOC vapors remaining in tank-truck tanks after unloading be kept in vapor-tight tank-truck tanks until the vapors are returned to a loading, cleaning, or degassing operation and discharged in accordance with the control requirements of that operation. Finally, the changes to §115.222 update references to definitions which previously were in §115.10 but are now being included only in §101.1, and delete language which became obsolete upon the passing of the final Stage II compliance deadline on December 22, 1998.

The changes to §115.223, concerning Alternate Control Requirements, revise the term "undesignated head" to "division" in response to revised Texas Register rules (23 TexReg 1289, February 13, 1998); and establish the availability of alternate means of control in the covered attainment counties.

The changes to §115.224, concerning Inspection Requirements, extend to the covered attainment counties the inspection requirements for gasoline transfers at motor vehicle fuel dispensing facilities and the annual vapor-tightness testing requirement for gasoline tank-truck tanks; revise the term "undesignated head" to "division" in response to revised Texas Register rules (23 TexReg 1289, February 13, 1998); and update the title of the division for consistency with a previous name change.

The changes to §115.225, concerning Approved Test Methods, extend the existing test methods to the covered attainment counties.

The changes to §115.226, concerning Recordkeeping Requirements, establish recordkeeping requirements for motor vehicle fuel dispensing facilities in the covered attainment counties; add recordkeeping requirements for exempt facilities in the covered attainment counties to ensure compliance with the gasoline tank-truck leak testing requirements; and correct the title of a division.

The changes to §115.227, concerning Exemptions, establish exemptions for gasoline storage tanks in the covered attainment counties; add an exemption from gasoline throughput recordkeeping for small gasoline storage tanks (no more than 1,000 gallons capacity); clarify that the requirements are applicable to motor vehicle fuel dispensing facilities; revise the term "undesignated head" to "division" in response to revised Texas Register rules (23 TexReg 1289, February 13, 1998); and correct the title of a division. The revised rules include an exemption for gasoline stations in the covered attainment counties with a gasoline throughput less than 125,000 gallons per month.

The changes to §115.229, concerning Counties and Compliance Schedules, specify the compliance schedules for the new requirements in the covered attainment counties; revise the term "undesignated head" to "division" in response to revised Texas Register rules (23 TexReg 1289, February 13, 1998); and correct the title of a division. The changes to §115.229 specify that larger gasoline stations (those with a gasoline throughput of at least 125,000 gallons per month) are required to comply by April 30, 2000. The changes also specify that the intent of the phrase "as soon as practicable, but no later than..." in §115.229(d) is that before this compliance date, gasoline stations which are equipped for Stage I vapor recovery must utilize Stage I for each gasoline delivery by a gasoline tank-truck which is likewise equipped for Stage I vapor recovery. The commission solicited comments regarding possible city, county, or state incentives to encourage early implementation of the Stage I requirements. However, no comments regarding possible incentives were received.

The changes to §115.234, concerning Inspection Requirements, establish annual vapor-tightness testing requirements for gasoline tank-truck tanks in the covered attainment counties; specify that the leak testing requirements apply to gasoline tank-truck tanks at both the loading and unloading points; specify that the leak testing requirements apply to general VOC (i.e., non-gasoline) tank-truck tanks at the loading point; and revise the term "undesignated head" to "division" in response to revised Texas Register rules (23 TexReg 1289, February 13, 1998).

The changes to §115.235, concerning Approved Test Methods, specify the testing requirements and approved test methods for gasoline tank-truck tanks in the covered attainment counties; specify that the leak testing requirements apply to gasoline tank-truck tanks at both the loading and unloading points; specify that the leak testing requirements apply to general VOC (i.e., non-gasoline) tank-truck tanks at the loading point; and clarify that the alternative testing option of the existing §115.235(4) applies to general VOC (i.e., non-gasoline) tank-truck tanks at the loading point; and more specifically references the leakage test method of 49 CFR 180.407(h).

The changes to §115.236, concerning Recordkeeping Requirements, add recordkeeping requirements for gasoline tank-truck leak testing in the covered attainment counties; clarify that records of leakage tests conducted under 49 CFR 180.407(h) should be kept as specified in 49 CFR 180.417 instead of Method 27 records; revise the term "undesignated head" to "division" in response to revised Texas Register rules (23 TexReg 1289, February 13, 1998); and revise references to the TNRCC and the EPA for consistency with the commission's style guidelines.

The changes to §115.237, concerning Exemptions, add an exemption in the covered attainment counties for transport vessels other than tank-trucks (e.g., railcars); add an exemption for portable tanks, as defined in 49 CFR 171.8; delete language which is obsolete due to the passing of a May 31, 1995 compliance date; and revise the term "undesignated head" to "division" in response to revised Texas Register rules (23 TexReg 1289, February 13, 1998).

The changes to §115.239, concerning Counties and Compliance Schedules, specify an April 30, 2000 compliance date for the gasoline tank-truck leak testing in the covered attainment counties; and delete language which is obsolete due to the passing of January 31, 1994 and May 31, 1995 compliance dates. The changes also specify that the intent of the phrase "as soon as practicable, but no later than..." in §115.239(b) is that before the applicable compliance date, gasoline tank-trucks which are equipped for Stage I vapor recovery must utilize Stage I for each gasoline delivery at a gasoline station which is likewise equipped for Stage I vapor recovery.

FINAL REGULATORY IMPACT ANALYSIS

The commission has reviewed the rulemaking in light of the regulatory analysis requirements of Texas Government Code (the Code), §2001.0225, and has determined that the rulemaking is not subject to §2001.0225 because although it meets the definition of a "major environmental rule" as defined in the Code, it does not meet any of the four applicability requirements listed in §2001.0225(a). Specifically, the emission limitations and control requirements within this rulemaking were developed in order to meet the NAAQS for ozone set by the EPA under §109 of the FCAA. States are primarily responsible for ensuring attainment and maintenance of NAAQS once the EPA has established them. Under §110 of the FCAA 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. This rulemaking is not an express requirement of state law, but was developed specifically in order to meet the air quality standards established under federal law as NAAQS. Specifically, this rulemaking is intended to help bring ozone nonattainment areas into compliance, and help keep attainment and near-nonattainment areas from going into nonattainment. There is no contract or delegation agreement that covers the topic that is the subject of this rulemaking. Therefore, this rulemaking does not involve an agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program, and was not developed solely under the general powers of the agency. No comments were received during the comment period regarding the draft regulatory impact analysis.

TAKINGS IMPACT ASSESSMENT

The commission has prepared a takings impact assessment for these rules pursuant to Texas Government Code, §2007.043. The following is a summary of that assessment. The specific purpose of the rulemaking is to extend to 95 counties in the eastern half of Texas the Chapter 115 rules for Stage I vapor recovery, gasoline terminals, gasoline bulk plants, and gasoline tank-truck leak testing which currently apply in the Beaumont/Port Arthur, El Paso, Houston/Galveston, and Dallas/Fort Worth ozone nonattainment areas. This rulemaking is part of the new TCAS which includes a variety of options to control ground-level ozone. The purpose is to help keep ozone attainment and near-nonattainment areas, such as Austin, Corpus Christi, Longview/Tyler/Marshall, and San Antonio, in compliance with the federal ozone standard, and to help the Beaumont/Port Arthur, Dallas/Fort Worth, and Houston/Galveston ozone nonattainment areas reach attainment. Promulgation and enforcement of the rule amendments may possibly burden private real property because this rulemaking action requires the installation of Stage I vapor recovery systems at gasoline stations, which includes the permanent installation of subsurface piping. In addition, this rulemaking action requires the installation of a vapor balance system at gasoline bulk plants, which also requires the permanent installation of piping. Finally, this rulemaking action requires the permanent installation of a heat-sensing device, such as an ultraviolet beam sensor or thermocouple, at the pilot light to indicate the continuous presence of a flame. Although the rule revisions do not directly prevent a nuisance, prevent an immediate threat to life or property, or prevent a real and substantial threat to public health and safety, the rule revisions fulfill a federal mandate under §110 of the 1990 Amendments to the FCAA. Specifically, the emission limitations and control requirements within this rulemaking were developed in order to meet the NAAQS for ozone set by the EPA under §109 of the FCAA. States are primarily responsible for ensuring attainment and maintenance of NAAQS once the EPA has established them. Under §110 of the FCAA 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, the purpose of the rulemaking is to meet the air quality standards established under federal law as NAAQS. Consequently, the following exemption applies to these rules: an action reasonably taken to fulfill an obligation mandated by federal law.

COASTAL MANAGEMENT PROGRAM CONSISTENCY REVIEW

The commission has determined that this rulemaking action is 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.), the rules of the Coastal Coordination Council (31 TAC Chapters 501-506), and the commission's rules in 30 TAC Chapter 281, Subchapter B, concerning Consistency with the Texas Coastal Management Program. As required by 31 TAC §505.11(b)(2) and 30 TAC §281.45(a)(3) relating to actions and rules subject to the CMP, agency rules governing air pollutant emissions must be consistent with the applicable goals and policies of the CMP. The commission has reviewed this action for consistency, and has determined that this rulemaking is consistent with the applicable CMP goals and policies. The primary CMP policy applicable to this rulemaking action is the policy that commission rules comply with regulations at 40 CFR, to protect and enhance air quality in the coastal area. No new sources of air contaminants will be authorized by the rule revisions, and the revisions will result in a reduction in VOC emissions due to the new control requirements on gasoline stations, gasoline terminals, gasoline bulk plants, and gasoline tank-trucks in 95 counties in the eastern half of Texas. Therefore, in compliance with 31 TAC §505.22(e), the commission affirms that this rulemaking is consistent with CMP goals and policies. No comments were received during the comment period regarding the consistency of the proposed rules with the CMP.

HEARING AND COMMENTERS

Public hearings on this proposal were held in Austin on January 25, 1999 at 11:00 a.m. in Building F, Room 2210 at the TNRCC Complex, located at 12100 Park 35 Circle; in San Antonio on January 25, 1999 at 7:00 p.m. at the San Antonio City Council Chambers located at 103 Main Plaza; in Lufkin on January 26, 1999 at 2:00 p.m. at the Lufkin City Council Chambers located at 300 East Shepherd, Room 102; and in Tyler on January 26, 1999 at 7:00 p.m. at the Tyler Junior College Regional Training and Development Complex located at 1530 South Southwest Loop 323, Room 104. The comment period initially was to close on February 1, 1999, but was extended until February 15, 1999.

Two commenters submitted oral testimony, and 16 commenters submitted written testimony on the proposal. Austin Transportation Study, EPA, Lower Colorado River Authority, and the City of San Antonio (San Antonio) supported the proposed revisions. Austin Sierra Club (Sierra Club), Chevron Products Company (Chevron), Citgo Petroleum Corporation (Citgo), Dow Chemical Company (Dow), Exxon Company U.S.A. (Exxon), GATX Terminals Corporation (GATX), Jenkens and Gilchrist (Jenkens), Mobil Business Resources Corporation (MBRC), Mobil Oil Corporation (Mobil), Texas Chemical Council (TCC), Texas Oil and Gas Association (TXOGA), Ultramar Diamond Shamrock Corporation (UDS), and an individual generally supported the proposed revisions but suggested changes or clarifications. The City of Corpus Christi (Corpus Christi) opposed the proposed revisions. Chevron, Citgo, and GATX supported TXOGA's comments, while Dow supported TCC's comments.

The Sierra Club commented that Stage I vapor recovery reduces toxins and VOCs which can impact neighboring property.

The commission notes that implementation of Stage I vapor recovery results in reductions of ground-level ozone in ozone near-nonattainment areas, ozone nonattainment areas, and surrounding counties, as well as reduced public exposure to air toxics such as benzene.

Exxon, TXOGA, and UDS commented on the STATUTORY AUTHORITY section of the proposal and stated that the extension of the Texas Clean Air Act's authorizing provisions to adopt control measures in ozone attainment areas is "a stretch from a legal standpoint." However, Exxon, TXOGA, and UDS commented that from a technical standpoint, they believed the intent is directionally correct, although they would prefer "a complete sound science determination."

The commission believes that it does have authority to adopt the proposed rules pursuant to Texas Health and Safety Code, §382.012 and §382.017. This rulemaking is demonstrated to help the state achieve attainment of the ozone standards in its nonattainment areas as well as in its near nonattainment areas and therefore is needed to meet those federal standards. In adopting rules under §382.017(e), the commission's authority is not limited by the attainment status of an area but instead the commission is required to consider factors including, "existing physical conditions topography, population, and prevailing wind direction and velocity." This statutory language clearly allows for the commission to consider a regional approach to improve air quality as it has done here. Additionally, while certain air control strategies such as Stage II vapor recovery systems are statutorily limited to use in nonattainment areas, control requirements for Stage I vapor recovery, gasoline terminals, gasoline bulk plants, and tank-truck leak testing are not.

An individual expressed concern about enforcement of the Stage I, gasoline bulk plant, gasoline terminal, and tank-truck leak testing rules in the 110-county TCAS area, while San Antonio commented that enforcement is critical to the success of the program.

The Field Operations Division and the Enforcement Division of the Office of Compliance and Enforcement are responsible for enforcing the Chapter 115 rules, with the Air Program responsible for the gasoline bulk plant, gasoline terminal, and tank-truck leak testing rules, and the Waste Program responsible for the petroleum storage tank (PST) rules at gasoline stations. The Waste Program's inspectors will enforce the Stage I vapor recovery rules at gasoline stations when conducting their routine PST inspections.

Most of the gasoline terminals which will have to comply with the proposed rules are currently subject to air permits and/or to similar requirements under 40 CFR 63, Subpart R (the Gasoline Distribution NESHAP), and therefore are already being inspected for compliance. Consequently, only a limited number of additional gasoline terminals will need to be inspected for compliance with the proposed Chapter 115 rules. Based on a survey of throughput at gasoline bulk plants, an estimated 75% are expected to be exempt from the vapor balance requirement because their gasoline throughput is less than 4,000 gallons per day (averaged over each consecutive 30-day period). Therefore, only a relatively small number of gasoline bulk plants will need to be inspected for compliance with the substantive requirements of the proposed rules. The Air Program's inspectors will enforce the gasoline tank-truck leak testing requirements when conducting their routine inspections at gasoline terminals and gasoline bulk plants. In conclusion, enforcement of these rules will not significantly increase the number of facilities currently inspected by the state and local governments. However, enforcement of these rules will cause a minor increase in workload during inspection of the affected facilities.

Mobil commented on a February 4, 1999, letter from the commissioners to Governor George W. Bush and suggested that this letter inaccurately represented that the proposed rulemaking only affects gasoline stations that dispense over 125,000 gallons of gasoline per month. Mobil noted that other facilities (for example, gasoline terminals and gasoline bulk plants) will be affected by the rulemaking.

The purpose of the letter was to clarify several common misconceptions regarding the TCAS and to provide a status report to Governor Bush. For example, the purpose of the portion of the letter that Mobil cited was simply to clarify that the proposed Stage I rules would not require installation of Stage I equipment at all gasoline stations in the covered attainment counties, but only at the largest of these gasoline stations (those with a monthly gasoline throughput of at least 125,000 gallons). The letter was never intended to give a detailed description of the elements of the proposed rulemaking.

Citgo suggested that it be clarified that the use of equipment in maintenance operations, which can involve transfer of VOC liquid, does not require controls when conducted for periodic maintenance purposes as allowed under §101.7. Citgo cited the following examples of these types of operations: removal of basic sediment and water or water draw into vacuum trucks from storage tanks, tank-to-tank product transfers using portable pumps, or other such activities.

Air emissions associated with upset conditions and maintenance are regulated by Chapter 101, 30 TAC §101.6 (concerning Upset Reporting and Recordkeeping Requirements), and §101.7 (concerning Maintenance, Start-up, and Shutdown Reporting, Recordkeeping, and Operational Requirements), and not by Chapter 115, unless otherwise specifically stated. The commission has made no changes in response to the comment.

Exxon, MBRC, TXOGA, and UDS commented on the definition of continuous monitoring in §115.10(6) and stated that this definition is more stringent than federal requirements and TNRCC monitoring protocols being developed for federal compliance assurance monitoring (CAM) and periodic monitoring (PM) requirements by state rule.

There are no federal CAM or PM requirements that define the percentage of data that must be collected for a monitoring device to be considered continuous. Therefore, the definition of continuous monitoring in §115.10(6) is not more stringent than federal requirements. The CAM requirements will be included in General Operating Permits (GOPs), but the commission has not established or even proposed any CAM requirements yet. It should be noted that Title 40 CFR 64.10 (Savings Provisions) of the CAM rules states:

"(a) Nothing in this part shall:

(1) Excuse the owner or operator of a source from compliance with any existing emission limitation or standard, or any existing monitoring, testing, reporting or recordkeeping requirement that may apply under federal, state, or local law, or any other applicable requirements under the Act. The requirements of this part shall not be used to justify the approval of monitoring less stringent than the monitoring which is required under separate legal authority and are not intended to establish minimum requirements for the purpose of determining the monitoring to be imposed under separate authority under the Act, including monitoring in permits issued pursuant to title I of the Act. The purpose of this part is to require, as part of the issuance of a permit under title V of the Act, improved or new monitoring at those emissions units where monitoring requirements do not exist or are inadequate to meet the requirements of this part. [emphasis added]"

Regarding PM, Title 40 CFR 70 (State Operating Permit Programs) simply specifies that states must implement PM, but there are no federal rules which establish the details of PM. Instead, the EPA is giving the states guidance on PM. No PM requirements established or drafted to date have required continuous monitoring.

In addition, neither CAM nor PM rules in 40 CFR 64 and 70, respectively, define "continuous monitoring." However, the CAM rule preamble does say that the rule requires data collection four times per hour, which is consistent with the EPA's definition of continuous monitoring. The rule does not specify a certain percentage of data that must be collected, but instead simply requires monitoring at all times the unit is operating, except during events such as monitoring malfunctions, quality assurance/quality control, etc.

Finally, it should be noted that the commission did not propose to revise the existing definition of continuous monitoring. This definition is simply being numbered in response to revised Texas Register rules (23 TexReg 1289, February 13, 1998) which require numbering of definitions. The commission has made no changes in response to these comments.

No comments were received on the definition of cutback asphalt. This term is used within the Chapter 115 cutback asphalt rules (§§115.512, 115.513, 115.515-115.517, and 115.519). Because in separate rulemaking the commission is proposing to relocate the definition of this term to a new §115.510, concerning Cutback Asphalt Definitions (see the April 23, 1999 issue of the Texas Register (24 TexReg 3178)), the commission has deleted the definition of cutback asphalt from §115.10.

MBRC, TXOGA, and UDS commented on §115.10 and suggested that the proposed new definitions of flare and vapor combustor do not allow vapor combustors to be treated as flares.

While it is true that vapor combustors are clearly excluded from the definition of flare, §115.215 and §115.216 allow the owner/operator of a vapor combustor the option of treating the unit as a flare for purposes of testing, monitoring, and recordkeeping requirements as an alternative to meeting the corresponding vapor combustor requirements. The commission has made no changes in response to the comment. However, the commission has revised the definition of flare to make it clear that a flare is an open combustor which is used as a control device. This will prevent the definition from being incorrectly used for open combustors which are not control devices.

No comments were received on the proposed definition of regional VOC zone. The commission has replaced this definition with a definition of covered attainment counties because it believes this term is more descriptive. The counties specified in the definition are the same as proposed. The commission has replaced all references to regional VOC zone in the rule language accordingly.

Jenkens commented on §115.10 and suggested that the definition of tank-truck tank be revised to apply only to tanks that are permanently mounted on and affixed to a tank-truck or trailer. Jenkens' intent was to exclude portable tanks, known as "isocontainers," from the definition of tank-truck tank such that isocontainers would be exempt from the annual vapor-tightness testing requirements of §§115.214(a)(1)(C) and 115.234-115.239.

This comment focuses on vapor-tightness testing of "isocontainers." The commission does not believe that the definitions section (i.e., §115.10) is the appropriate place to address concerns about §§115.214(a)(1)(C) and 115.234-115.239, and has made no changes to §115.10 in response to the comment. The commission instead is addressing the commenter's concerns in the discussion regarding §115.214(a)(1)(C) and §115.234(4).

Exxon, MBRC, TXOGA, and UDS commented that the definitions of vapor control system and vapor recovery system in §115.10 are the same, and stated that a vapor recovery system can include a recovery device that does not destroy emissions but instead recovers them. The commenters also noted that federal rules differentiate a recovery device from a control device.

The new definition of vapor control system is deliberately identical to the existing definition of vapor recovery system. The existing definition of vapor recovery system includes both recovery and combustion (destruction) control devices, but often the term has been mistakenly read to mean that only recovery-type control devices are included. To minimize any confusion, the commission is adding a definition of vapor control system, which is identical to the existing definition of vapor recovery system. This will facilitate a transition in the Chapter 115 rules to the more general term "vapor control system" from the misleading term "vapor recovery system." The terminology used in federal rules is not pertinent to the clarification of the Chapter 115 state rules which the commission is making by adding a definition of vapor control system. The commission has made no changes in response to the comment.

Citgo and an individual commented on §115.211(1)(B), which establishes an emission limit of 20.0 mg/l for vapor control systems at gasoline terminals in the covered attainment counties. Citgo, while noting that the company's gasoline terminals meet the 20.0 mg/l emission limit, objected to this limit on the basis that it would remove approximately one half of the compliance margin which is now available to accommodate operational and test method variables. The individual suggested that since nearly all gasoline terminals in the covered attainment counties can meet a 10.0 mg/l emission limit, the TNRCC should require all gasoline terminals in this area to meet this limit.

The 20 mg/l limit is more stringent than the current 80 mg/l limits in Chapter 115 (for Gregg, Nueces, and Victoria Counties) and in 40 CFR 60, Subpart XX, for gasoline terminals; and the 35 mg/l limit of 40 CFR 60, Subpart XX, for gasoline terminals which were constructed or refurbished on or after December 17, 1980. As noted previously, the commission surveyed the test results for gasoline terminals in the covered attainment counties and the current ozone nonattainment counties and determined that the vast majority (94%) meet the 10.0 mg/l emission limit in 40 CFR 63, Subpart R (Gasoline Distribution NESHAP), with the remaining 6.0% showing compliance with a 20.0 mg/l emission limit. Adequate maintenance, rather than replacement, of existing control devices in the covered attainment counties is more cost-effective. It should be noted that Citgo stated that its control devices "operate well below both the current as well as the proposed [(20 mg/l)] mass emission limitation," which indicates that the 20 mg/l limit affords gasoline terminals in the covered attainment counties an adequate "compliance margin." Consequently, the commission believes that a 20.0 mg/l emission limit is appropriate for gasoline terminals in the covered attainment counties. The commission has made no changes in response to the comment.

MRBC, TXOGA, and UDS stated that §115.211 should specify that facilities are required to either meet the flare requirements of 40 CFR §60.18(b), or meet the specified emission limit.

Section 115.215(3) already specifies that compliance with the flare requirements of 40 CFR §60.18(b) is considered to demonstrate compliance with the emission specifications and control efficiency requirements of §115.211 and §115.212. The commission has made no changes in response to the comment.

The commission has revised §115.211(1)(B) by extending the compliance date to April 30, 2000 in response to Mobil's comment on §115.219 that the proposed December 31, 1999 compliance date represents an aggressive schedule. The revised compliance date will provide the regulated community with additional time to comply with the new requirements, but will still ensure that the emission reductions occur prior to the critical 2000 ozone season.

Dow commented on §115.212(a)(1) and (6), and (b)(1) and suggested that pressurized loading should be given as an alternative to using a vapor control system or a vapor balance system.

The commission agrees and has made the suggested changes. This will clarify how compressed or liquefied gas loading is to be controlled.

Dow commented on §115.212(a)(2) and (b)(2), which state: "After unloading, transport vessels must be kept vapor-tight until the vapors in the transport vessel are returned to a loading, cleaning, or degassing operation and discharged in accordance with the control requirements of that operation." Dow requested confirmation that the intent of the new language "in accordance with the control requirements of that operation" is equivalent to the previous language "the requirement to discharge the vapors remaining in the transport vessel after unloading to a vapor recovery system does not apply if the transport vessel is refilled, degassed, and/or cleaned at an operation for which control of the vapors is not required."

The new language is intended to be a shorter, but equivalent, version of the old language. The commission has made no changes in response to the comment.

An individual suggested that the phrase "the contents may be placed in a portable container" in §115.212(a)(3)(A)(ii) and (E) and (b)(3)(A)(ii) and (E) be modified so that the portable container is leak-tight and will not emit any liquid or vapor VOC emissions.

As proposed, §115.212(a)(3)(A)(ii) and (E) and 115.212(b)(3)(A)(ii) and (E) allow residual VOC from a liquid transfer line, after VOC transfer, to be drained into a portable container, which is then closed and disposed of properly. The intent is that the portable container be closed vapor-tight when not in use, in order to prevent evaporation of the VOC into the atmosphere. The commission has clarified this intent by adding "vapor-tight" to the referenced rules.

Chevron, Exxon, MBRC, Mobil, TXOGA, and UDS commented on §115.212(a)(4)(C), which currently applies to gasoline terminals in the Dallas/Fort Worth, El Paso, and Houston/Galveston ozone nonattainment areas and is proposed to be relocated from the existing §115.212(a)(9) and extended to the Beaumont/Port Arthur ozone nonattainment area and the covered attainment counties. The existing §115.212(a)(9) states that: "Each vapor control system shall be instrumented so that the pump(s) transferring gasoline to the transport vessels will not operate unless the vapor control system is properly connected and properly operating. No transport vessel loading shall take place at a loading rack when the vapor control system serving that loading rack is out of service or is not operating in accordance with the manufacturer's parameters." Chevron, Exxon, MBRC, TXOGA, and UDS stated that this "loading lockout" language is overly broad and needs to be clarified.

The intent of the requirements is twofold. First, the intent is for gasoline terminals to be equipped with sensors and other equipment which is designed and connected to monitor the status of the control device, and if the control device malfunctions (i.e., is not operating in accordance with the control device manufacturer's specifications) or is not operational (i.e., not in service), then the system automatically stops gasoline transfer to the transport vessel(s) immediately. Most control devices are equipped so that when they complete a startup cycle and are operating in accordance with the manufacturer's specifications, they send a permissive signal to the pump(s) serving the loading rack(s) which allows loading to begin. Because this is a standard feature on gasoline terminal control devices, the commission believes that this requirement is appropriate and has revised the proposed §115.212(a)(4)(C) and (b)(4)(C) to more clearly state the intent.

Second, the intent of the requirements is for gasoline terminals to be equipped with sensors and other equipment which is designed and connected to monitor either a positive coupling of the vapor return line to the transport vessel, or the presence of vapor flow in the vapor return line between the transport vessel and the terminal's vapor collection system. Further, the intent is that if the system detects that the vapor return line is not connected during gasoline transfer, then the system automatically stops the transfer of gasoline to the transport vessel in the affected loading bay. These requirements have applied to gasoline terminals in the Dallas/Fort Worth, El Paso, and Houston/Galveston ozone nonattainment areas since the November 15, 1996 compliance date.

Chevron, TXOGA, and UDS commented that specific information regarding the emission reductions associated with loading lockout was unavailable from the commission staff. Chevron, MBRC, TXOGA, and UDS stated that the commission's cost estimates are low and that the cost of control is too high for relatively low emission reductions.

For the Dallas/Fort Worth, El Paso, and Houston/Galveston ozone nonattainment areas, the emission reductions associated with the loading lockout are included as part of the gasoline terminal emission reduction estimates of 2.17, 0.77, and 0.63 tons per day, respectively, as given in the 1996 "Fix-Ups to the 15% Rate-of-Progress SIP for Dallas/Fort Worth, El Paso, Beaumont/Port Arthur, and Houston/Galveston Ozone Nonattainment Areas." It should be noted that any loss of emission reduction credit could require the implementation of other rules to make up the difference. Specific estimates for the covered attainment counties were unavailable because most of the companies did not provide the necessary information regarding current terminal configuration when requested. The commission clarifies that the estimated cost given in the rule proposal for equipping a gasoline terminal in the covered attainment counties to meet the loading lockout requirement associated with vapor return line connections should have specified that the estimate was per loading bay. However, because gasoline terminals in the Dallas/Fort Worth, El Paso, and Houston/Galveston ozone nonattainment areas were already required to meet the loading lockout requirements by November 15, 1996, there is no additional cost to these terminals associated with continuing to comply with the rule. The commission believes that it is appropriate for gasoline terminals in ozone nonattainment areas to have more stringent requirements than in attainment and near-nonattainment areas, and therefore is retaining the vapor return line loading lockout requirement for gasoline terminals in the Dallas/Fort Worth, El Paso, and Houston/Galveston ozone nonattainment areas. For the covered attainment counties and the Beaumont/Port Arthur ozone nonattainment area, the commission has revised §115.212(b)(4)(C) to include the gasoline transfer lockout requirement when the vapor control system is out of service or not operating properly, but has deleted the proposed loading lockout requirement associated with vapor return line connections. In future rulemaking, the commission may propose to add this requirement to all or part of the covered attainment counties if additional VOC emission reductions are found to be necessary.

Chevron, MBRC, TXOGA, and UDS stated that the requirement for instrumentation on the vapor connection goes beyond federal requirements found in the gasoline distribution NESHAP (Title 40 CFR Part 63, Subpart R), the gasoline terminal new source performance standards (NSPS) (Title 40 CFR Part 60, Subpart XX), and benzene transfer operations NESHAP (Title 40 CFR Part 61, Subpart BB).

The benzene transfer operations NESHAP applies to materials which are predominantly benzene. Title 40 CFR Part 61, §61.300(a) specifically excludes loading racks at which gasoline is loaded. Consequently, the requirements of the benzene transfer operations NESHAP are not pertinent. The requirements of the gasoline distribution NESHAP and gasoline terminal NSPS were developed to apply to larger sources of air toxics and to new or modified gasoline terminals, respectively. In contrast, the Chapter 115 loading lockout requirements were developed to help achieve attainment with the ozone standard in ozone nonattainment areas. The commission believes that it is appropriate for the requirements of the rules to vary, given the varying purposes of those rules.

Chevron, MBRC, TXOGA, and UDS commented that automatic instrumentation cannot determine if the vapor hose is properly connected and can allow loading to continue if the hose is damaged or only partially connected. Chevron, MBRC, TXOGA, and UDS also stated that the operator loading the transport vessel can more effectively inspect the condition of the vapor hose and correct closure of the camlock latches, and also terminate gasoline loading if necessary. Mobil stated that ensuring transport vessels are prevented from loading without a properly connected and operating vapor control system should be left to the gasoline terminal.

While it is true that automatic instrumentation can allow loading to occur if the vapor hose contains a hole, or if the camlock fitting between the vapor hose and the truck is not completely secured, such instrumentation will prevent the uncontrolled loading of gasoline. During visits to various gasoline terminals, the commission's staff determined that transport vessel operators allow vapor and liquid gasoline leaks to occur without taking corrective action. Therefore, the commission does not believe that relying on the operators alone is sufficient to ensure control of gasoline loading emissions. The commission has made no changes in response to the comment.

Chevron, MBRC, TXOGA, and UDS commented that because of design limitations, there is a response time for certain technology (thermistor-based or pressure-based mass flow sensors) before mass flow is detected. Consequently, some time may pass in which gasoline transfer is allowed, even if the vapor hose is not connected.

The commission's staff reviewed existing systems at gasoline terminals and determined that the response time of these systems allowed from approximately 110 to as high as 290 gallons of gasoline loading before mass flow of the vapors was detected. A typical response time is one minute, based upon the manufacturer's recommendation. Therefore, the commission has revised §115.212(a)(4)(C) to allow a response time of up to one minute. This will ensure that completely uncontrolled loading of an entire transport vessel does not occur while still taking into account a reasonable response time for thermistor-based and pressure-based mass flow sensors.

Chevron, MBRC, TXOGA, and UDS commented that loading pumps generally serve multiple loading bays and that the requirement that instrumentation shut off the loading pump(s) for a failure at a single bay would unnecessarily shut down all loading bays.

The commission has added a new §115.212(a)(4)(C)(ii), which allows the lockout of gasoline transfer to be limited to the loading bay in which the sensor was triggered.

Chevron, TXOGA, and UDS stated that some facilities, which have a vapor collection and holding design, do not require that the control device be activated during each transfer, and therefore will not necessarily have the control device operating at the time of loading.

The commission is aware of one gasoline terminal which has a variable vapor space holding tank design that can process the vapors independent of transport vessel loading. In order to address this unique design, the commission has revised the rule language to add a new §115.212(a)(4)(D), which specifies that for such gasoline terminals, if the variable vapor space holding tank serving the loading rack(s) does not have the capacity to store additional vapors for processing by the control device at a later time and the control device malfunctions or is not operational, then the system shall automatically stop gasoline transfer to the transport vessel(s) immediately.

Citgo commented on the proposed removal of the existing §115.212(a)(6)(B), which concerns permissible pressure relief valve emissions from gasoline transfer at gasoline bulk plants during emergency situations. This removal was proposed because upset conditions are already addressed in §101.6, Upset Reporting and Recordkeeping Requirements. Citgo commented that it is unclear whether this type of occurrence is in fact permissible or in fact an upset.

The paragraph being deleted only allows emissions from pressure relief valves during "emergency situations." While this term is not defined, the commission believes that an "emergency situation" which results in emissions from a pressure relief valve is clearly an upset condition. As noted earlier, air emissions associated with upset conditions (such as the venting of safety relief valves) are regulated by Chapter 101, §101.6 (concerning Upset Reporting and Recordkeeping Requirements), and not by Chapter 115, unless otherwise specifically stated. The commission has made no changes in response to the comment.

Dow commented on §115.212(a)(6)(D), concerning the non-dedicated loading lines control requirements for marine terminals in the Houston/Galveston ozone nonattainment area. Dow noted that "flash point less than 150 degrees Fahrenheit" should be "flash point of 150 degrees Fahrenheit or greater" for consistency with the low vapor pressure/high flash point exemption of §115.217(a)(5)(B)(iv).

The commission has corrected this typographical error in §115.212(a)(6)(D).

Dow also suggested that §115.212(a)(6)(D) be deleted. Dow stated that United States Coast Guard (USCG) regulations (33 CFR 154.850(h)) do not allow residual vapors in the loading line to be cleared with compressed air or gas, that clearing the loading line using a nitrogen purge is not practical, and that clearing the loading line using pigging is defined as pneumatic clearing by the USCG and therefore is not allowed.

Section 115.212(a)(6)(D) does not require purging of the loading lines with compressed air or gas, such as nitrogen, or by pigging. Instead, §115.212(a)(6)(D) requires that when VOC with a vapor pressure of 0.5 psia or greater is loaded into a marine vessel and the next VOC transfer through the same (i.e., non-dedicated) loading line(s) is a VOC with a low vapor pressure (i.e., less than 0.5 psia), then the low vapor pressure loading must be controlled in order to recover or destroy the residual vapors from the previous VOC transfer. The commission has made no changes in response to the comment.

Dow requested clarification of the intent of the "once-in, always-in" requirement of §115.212(a)(7).

Once-in, always-in (OIAI) is an EPA concept which means that once emissions from a source exceed the applicability cutoff for a particular VOC regulation in the SIP, that source is always subject to the control requirements of the regulation. The purpose of this requirement is two-fold. First, it serves to discourage a source already subject to regulation from installing minimal controls to circumvent Reasonably Available Control Technology (RACT) requirements. Second, it improves the clarity of VOC regulations by minimizing the confusion over whether variations in production cause a particular source to be covered by a regulation. A major EPA concern which resulted in the OIAI requirements was their desire to prevent the removal of a control device, which would then result in a significant increase in emissions (i.e., a throughput reduction of 5.0% could result in an emissions increase of 90% if the control device were removed). To provide flexibility but prevent such emissions increases, the rule language includes an incentive for cost-effective and innovative approaches to pollution prevention and waste minimization which reduce emissions to no more than the controlled levels prior to removal of control devices. Also, it should be noted that in the event of revised rules which are less stringent than previous requirements (for example, revisions to definition of VOC which exclude additional compounds from classification as VOC), the OIAI requirements will apply to the extent that emissions from a source exceed the applicability cutoff for the revised version of the rules. The commission has revised §115.212(a)(7) to refer to "exemption from permitting" rather than "standard exemption" due to the repeal of §116.211, concerning Standard Exemption List, and the adoption of new sections in Chapter 106, concerning Exemptions from Permitting (see the March 4, 1997 issue of the Texas Register (22 TexReg 2439)).

Dow commented on §115.212(b)(1), concerning general (i.e., non-gasoline) VOC loading, and suggested that this rule specifically exclude marine terminals.

Section 115.212(b) specifically states that the requirements apply only to "land-based VOC transfer." In addition, the proposed §115.217(b)(4) specifically includes an exemption for all loading and unloading of marine vessels in the covered attainment counties. To clarify the exempt status of marine vessel loading/unloading in the covered attainment counties, the commission has relocated this exemption from the proposed §115.217(b)(4) to a new §115.217(b)(6). In addition, it has come to the commission's attention that the phrase "general vapor control" in the catchlines of §115.212(a)(1) and (b)(1) would more accurately reflect the contents of these rules if changed to "general VOC control." The commission has revised §115.212(a)(1) and (b)(1) accordingly.

Dow commented on the 90% overall control options of §115.213(b), (c), and (d). Dow stated that the applicable vapor pressure range should be stated as "equal to or greater than..." 0.5 or 1.5 psia, depending on the rule, because the vapor pressure exemptions in §115.217 are stated as "less than...."

The commission has corrected §115.213(b), (c), and (d) as suggested.

Dow stated that the parenthetical expression "(excluding loading into marine vessels and loading at gasoline terminals and gasoline bulk plants)" in §115.213(b), (c), and (d) is redundant with the phrase "other than gasoline terminals, gasoline bulk plants, and marine terminals" and should be deleted.

Neither phrase is used in §115.213(d). In §115.213(b) and (c), both phrases are necessary to clearly delineate the operations and associated emissions which are included in and excluded from the 90% overall control option. However, because §115.213(b) and (c) include this clear delineation, the parenthetical phrase "(excluding loading into marine vessels and loading at gasoline terminals and gasoline bulk plants)" in paragraph (1) of §115.213(b) is unnecessary. Therefore, the commission has deleted this phrase from §115.213(b)(1).

Dow commented that the reference to §115.212(b)(1)-(5) in §115.213(c) instead should be to §115.213(b)(1)-(5).

The commission has corrected this typographical error.

Dow suggested that §115.213(b) and §115.214(a)(1)(D) be reworded to add more exclusions from control for those VOC loading operations which, under the 90% overall control option in §115.213(b), are not required to control vapors caused by loading of VOC. Dow noted that the 90% overall control option in §115.213(b) was previously in the exemptions section but is being relocated to the alternate control requirements section. Dow suggested that §115.214(a)(1)(D) be reworded to exclude from the requirements of §115.214(a)(1)(A) and (B) a VOC loading operation which, under the 90% overall control option, is not required to control vapors caused by loading VOC. Dow also suggested that §115.213(b) exclude from §115.212(a)(3)(A) and (C) and §115.214(a)(1)(A)(ii) and (iii) and (C) any loading operations which, under the 90% control option, are not required to control vapors caused by loading VOC into transport vessels.

For VOC loading operations which are not required to control vapors caused by loading VOC into a transport vessel, the suggested changes would exclude the requirements for annual vapor tightness testing and inspections for visible fumes and significant odors. The commission agrees that it is not necessary to impose these requirements if the emissions from the transport vessel loading operation are not required to be controlled. The liquid leak inspection and repair requirements will still apply, however. The commission agrees that these revisions are appropriate and has added a new §115.213(b)(6) and §115.214(a)(1)(D) as suggested. For consistency, the commission has made similar revisions to §115.214(b)(1)(D) and §115.213(c).

Dow suggested that §115.213(d)(5) and §115.214(a)(3)(G) be reworded to add more exclusions from control for those marine vessel loading operations which, under the 90% control option in §115.213(d)(5), are not required to control vapors caused by loading of VOC. Specifically, Dow stated that §115.214(a)(3)(g) should be clarified to exclude marine vessel loading operations which, under the 90% control option, are not required to control vapors caused by loading VOC into a marine vessel. Dow also suggested that §115.213(d) exclude from §115.214(a)(3)(A), (B)(ii) and (iii), and (D) any marine vessel loading operations which, under the 90% control option, are not required to control vapors caused by loading VOC into a marine vessel.

For marine vessel loading operations which are not required to control vapors caused by loading VOC into a marine vessel, the suggested changes would exclude the requirements for annual vapor tightness testing and inspections for visible fumes and significant odors. The commission agrees that it is not necessary to impose these requirements if the emissions from the marine vessel loading operation are not required to be controlled. The liquid leak inspection and repair requirements will still apply, however. The commission agrees that these revisions are appropriate and has revised §115.213(d)(5) and §115.214(a)(3)(G) as suggested.

Dow commented on §115.214(a)(1)(C) and (b)(1)(C), and §115.224(2), concerning the annual leak testing requirements for tank-truck tanks. Dow suggested that these rules be revised to only require that the tank-truck tank be leak-tested at the loading point (provided that the loading point is in Texas), and that all unloading operations be exempt from the leak testing requirements of §115.214(a)(1)(C) and (b)(1)(C), and §115.224(2). Dow noted that intermodal portable tanks (such as "isocontainers") can come from a multitude of world-wide shipping points. Dow commented that leak testing would be less burdensome on the loading facility because that facility will have more control over, and be in a better position to test, each tank before it is loaded.

Dow's comments are addressed in detail in the discussion regarding §115.235(4). In summary, the commission agrees that the leak testing requirements should apply to general (i.e., non-gasoline) VOC tank-truck tanks at the loading point, but not at the unloading point. However, the commission believes that for gasoline tank-truck tanks, the leak testing requirements should apply at both the loading point (i.e., gasoline terminals and gasoline bulk plants) and unloading point (i.e., gasoline bulk plants and gasoline stations). Therefore, the commission has revised §115.214(a)(1)(C) and (b)(1)(C), and §115.224(2) accordingly.

An individual commented on §115.214(a)(2), concerning the monthly leak inspection requirement for gasoline terminals. The individual suggested that wording from §§115.352-115.357, concerning Fugitive Emission Control in Petroleum Refining, Natural Gas/Gasoline Processing, and Petrochemical Processes in Ozone Nonattainment Areas, be incorporated to make this leak repair effort equivalent. The individual also stated that the phrase "reasonable effort," concerning repairing of leaking components at gasoline terminals, is subjective and should be defined.

Section 115.214(a)(2) already allows a gasoline terminal owner/operator to use a hydrocarbon gas analyzer to meet the fugitive monitoring requirements of §§115.352-115.357 as an alternative to conducting a monthly audio/visual/olfactory (AVO) program. The individual's suggestion would mandate the use of an instrument monitoring program. During the development of the federal Gasoline Distribution NESHAP standards for gasoline terminals (Title 40 CFR Part 63, Subpart R, promulgated December 14, 1994 (59 FR 64303)), the EPA revised the requirement for control of equipment leak fugitives from a quarterly instrument monitoring program to a monthly AVO program. The EPA relaxed the requirement in response to its review of data submitted by the American Petroleum Institute (API) which showed that: 1) emission factors for gasoline terminals using an AVO monitoring program are over 99% lower than the 1980 AP-42 refinery equipment emission factors that the EPA had used for the development of the proposed NESHAP standard; and 2) gasoline terminals that implemented an AVO program achieved essentially equivalent emission reductions as those terminals that used an instrument monitoring program. Because the API data, submitted to and accepted by the EPA and used in the agency permitting guidelines, showed that AVO and instrument leak detection and repair fugitive monitoring programs achieve essentially equivalent emission reductions for gasoline terminals, the commission has made no changes in response to the comment. Regarding the phrase "reasonable effort," while the commission agrees that this phrase is subjective, this term has the meaning commonly ascribed to it in the field of air pollution control, and the commission does not believe that further definition is necessary. However, it has come to the commission's attention that the reference to §§115.352-115.357 and 115.359 in §115.214(a)(2) and (b)(2) instead should be to only §§115.352-115.357, since the compliance date in §115.359 is not pertinent to gasoline terminals opting to use this instrument leak detection program. The commission has revised §115.214(a)(2) and (b)(2) accordingly. Likewise, for marine terminals the commission has revised §115.214(a)(3)(F) to refer only to §§115.352-115.357.

Dow and TXOGA commented on the proposed §115.215(3). TXOGA stated that the rule language should make clear that all flares, and vapor combustors which the owners or operators elect to treat as flares, are sufficient to meet the gasoline terminal emission standard of 10.8 mg/l which applies in ozone nonattainment counties, while Dow stated that it should be clarified that the flare requirements also apply to marine terminals. TXOGA also expressed concern that a vapor combustor which the owner or operator elects to treat as a flare would have to comply with the contradictory requirements of §115.215 and 40 CFR 60.18, and stated that such vapor combustors should only be subject to the flare requirements. TXOGA expressed a similar concern about §115.216(1)(A)(iv) and (B).

The intent is that the owner/operator of a vapor combustor treat the unit as a direct-flame incinerator (or thermal oxidizer), but alternatively may choose to consider the unit to be a flare and meet the flare requirements specified in 40 CFR 60.18(b) and Chapter 111. As noted in §115.215(3), compliance with the flare requirements of 40 CFR 60.18(b) is considered to demonstrate compliance with the emission specifications and control efficiency requirements of §115.211 and §115.212, which include the gasoline terminal, gasoline bulk plant, land-based VOC loading, and marine terminal emission standards. The commission has revised §115.215(3) to make it clear that this presumption applies to flares as well as vapor combustors which the owner/operators have elected to treat as flares. In addition, the commission has revised §115.213 to make it clear that vapor combustors which the owner/operators have elected to treat as flares are to comply with the flare requirements as an alternative, and not in addition to, the requirements for vapor combustors which the owner/operators have not chosen to treat as flares. Consequently, there is no contradictory requirement.

No comments were received on the proposed change to §115.216, which would have added a requirement that records must include information on how the design standard or operation of equipment meets the emission specifications and control requirements. However, the commission deleted this proposed change because it believes a more thorough analysis of the impacts on the regulated community is needed.

TXOGA commented on §115.216(1)(A)(iv) and (B) and expressed a similar concern that a vapor combustor which the owner or operator elects to treat as a flare would have to comply with the requirements for both flares and vapor combustors.

Section 115.216(1)(A)(iv), which specifies the monitoring requirements for vapor combustors, specifically states "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." The commission believes that it is clear from the inclusion of the word "alternatively" that a vapor combustor which the owner or operator elects to treat as a flare would only have to comply with the flare requirements. The commission has made no changes in response to the comment.

Exxon, GATX, MBRC, TXOGA, and UDS suggested the addition of an exemption to §115.217(a)(2) which would allow the uncontrolled loading of interface/transmix/off-specification product at gasoline terminals of up to 1.0% (on an annual basis) of the volume of gasoline throughput that is controlled.

The commenters did not provide any supporting documentation, such as the volume of interface/transmix/off-specification product loaded and the cost of controlling the associated emissions. Control of the occasional loading of interface/transmix/off-specification product at gasoline terminals into transport vessels could be done relatively simply by either: 1) adding a vapor return pipe to the interface/transmix/off-specification product tank so that the loading of this product is controlled by the existing vapor control device serving the gasoline loading rack; or 2) adding a product pipe from the interface/transmix/off-specification product tank to one of the loading rack bays so that the loading of this product is done at the rack where an existing vapor return pipe is available to deliver the vapors to the existing control device. In either case, the addition of only one pipe is needed to control the emissions from the loading of interface/transmix/off-specification product into transport vessels since an existing control device would be used. The cost is expected to be insignificant compared to the cost of the existing control device and associated piping.

It should also be noted that the suggested 1.0% cutoff would allow a significant volume of gasoline to be loaded uncontrolled at a gasoline terminal. In order to estimate the potential emissions associated with the suggested exemption, the commission obtained statewide gasoline throughput data from gasoline tax records. The statewide gasoline throughput was allocated to each county by the estimated vehicle miles traveled. The total gasoline throughput for the 110-county TCAS area was then assumed to be a reasonable approximation of the total volume of gasoline loaded at gasoline terminals in the TCAS area. Even if half of the interface/transmix/off-specification product is assumed to be diesel fuel, the commenters' suggested exemption would still allow up to approximately 165 tons per year of uncontrolled emissions in the 110-county TCAS area. Consequently, the commission does not believe that the suggested exemption is appropriate and has made no changes in response to the comment.

No comments were received on §115.217(a)(5), concerning marine vessel transfer exemptions. However, the commission has revised §115.217(a)(5)(A)(i) to clarify that all loading and unloading of marine vessels in ozone nonattainment areas other than the Houston/Galveston area are exempt from the entire division (concerning Loading and Unloading of VOC). The commission has also revised §115.217(a)(5)(B) to clarify that in the Houston/Galveston area, inspections required during marine vessel transfer operations which are exempt from §115.212(a)(6) do not include looking for visible fumes and significant odors since emissions from the VOC transfer are not required to be controlled under §115.212(a)(6). However, inspections required during marine vessel transfer operations which are exempt from §115.212(a)(6) include looking for and correcting liquid leaks.

Dow and Mobil commented on §115.219. Dow stated that §115.219 should include a compliance date for flares which do not meet the requirements of 40 CFR §60.18. Mobil stated that the proposed December 31, 1999 compliance date represents an aggressive schedule. Mobil stated that some small facilities may have a difficult time in complying and questioned whether the commission intends to enforce the requirements and shut down these facilities immediately.

In response to Mobil's comment, the commission has extended the compliance date in §115.219 from December 31, 1999 to April 30, 2000. For consistency, the commission has likewise extended the December 31, 1999 compliance date to April 30, 2000 in §§115.211(1)(B), 115.229(d), and 115.239(b). This revised compliance date will provide the regulated community with additional time to comply with the new requirements, but will still ensure that the emission reductions occur prior to the critical 2000 ozone season. As with all of its rules, the commission will enforce the requirements after the compliance date and take appropriate action for noncompliance situations. In response to Dow's comment, the commission has added a new subsection (h) to §115.219 which establishes a compliance date of April 30, 2000 for flares which do not currently meet the requirements of 40 CFR §60.18.

Corpus Christi opposed the implementation of the proposed Stage I revisions in Nueces and San Patricio Counties and stated that Stage I controls have been implemented voluntarily at approximately 85% of the gasoline stations in these two counties. Corpus Christi suggested that the proposed revisions are unnecessary in Nueces and San Patricio Counties.

As noted in the BACKGROUND section of this preamble, the commission staff has conducted modeling which indicates that mobile source reductions (cleaner gasoline, NLEVs, and Stage I vapor recovery) will result in ozone reductions of one to four ppb (peak eight-hour ozone averages) and up to 3.6 ppb (peak one-hour ozone average) in much of east and central Texas. While the greatest reductions are seen in the Austin, San Antonio, and Tyler/Longview areas, modeling of the mobile source strategies shows a large area, including near-nonattainment areas (such as Corpus Christi) and attainment areas, of reductions in peak one-hour and eight-hour average ozone levels. If, as Corpus Christi commented, most gasoline stations in Nueces and San Patricio Counties are already voluntarily implementing Stage I controls, then the adoption of Stage I requirements for the largest gasoline stations (those with a monthly gasoline throughput of at least 125,000 gallons) should not be burdensome to these gasoline stations. The commission has made no changes in response to the comment.

Dow's comments regarding §115.224(2) were addressed earlier. (See the discussion regarding comments on §115.214(a)(1)(C) and (b)(1)(C)). In summary, the commission believes that for gasoline tank-truck tanks, the leak testing requirements should apply at both the loading point (i.e., gasoline terminals and gasoline bulk plants) and unloading point (i.e., gasoline bulk plants and gasoline stations). Therefore, the commission has revised §115.224(2) accordingly for consistency with the corresponding changes to §115.214(a)(1)(C) and (b)(1)(C).

No comments were received on §115.225. However, it has come to the commission's attention that the lead-in paragraph in §115.225 should refer to §115.224 in addition to §115.221 and §115.222. This is because §115.225 includes Test Method 21 for determining VOC leaks by instrument, and §115.224 requires inspections for leaks. In order to include the proper reference, the commission has revised the lead-in paragraph of §115.225 to also refer to §115.224. In addition, the commission has revised §115.225 to add titles (catchlines) to the subsections in order to identify the topics covered. The commission also combined paragraphs (2)-(4) into a single paragraph since these three paragraphs address the same topic (i.e., test methods for determining the concentration of VOC).

Mobil commented on §115.226(1), which requires that facilities maintain gasoline delivery and tank-truck leak testing records on-site. Mobil suggested that facilities be given the option of maintaining these records at an off-site location from which they can be provided to an inspector within a certain time frame, possibly one week.

Section 115.226(2)(A) and (B) already allows only the minimum records to be kept at the facility (specifically, those required by §115.226(1)), with records of testing and throughput kept, but not necessarily at the site. Therefore, the commission has made no changes to §115.226(1) in response to the comment.

Dow commented that §115.226(2)(B) should specify that the monthly gasoline throughput records should include the calendar month and year, and the total facility gasoline throughput for each calendar month, for consistency with §115.226(2)(C).

The commission agrees and has made the suggested change. In addition, the commission has revised §115.226(2)(C) by relocating the language which specifies that records must be made available to representatives of the executive director, EPA, or any local air pollution control program with jurisdiction from §115.226(2)(C) to the lead-in paragraph of §115.226. This change will make it clear that in all cases, the required records must be made available upon request by these representatives.

Dow suggested that rather than listing the sections that do not apply, the exemptions in §115.227 should instead list the sections which still apply.

The commission agrees that the exemptions in §115.227 should list the sections which apply, rather than listing the sections that do not apply, and has revised §115.227 accordingly.

Dow commented that §115.227(1) and (3), which provide exemptions for small capacity (no more than 1,000 gallons) gasoline storage tanks at gasoline stations, are not complete and should include more sections from which the owner or operator is exempt. Specifically, Dow stated that a gasoline station which is exempt based on having one or more small storage capacity tanks should also be exempt from the leak-tightness testing requirement of §115.224(2), the testing requirements of §115.225, and the gasoline delivery and tank-truck leak test recordkeeping requirements of §115.226.

The commission agrees that a gasoline station which is exempt based on having one or more small storage capacity tanks should also be exempt from the leak-tightness testing requirement of §115.224(2) and the gasoline delivery and tank-truck leak test recordkeeping requirements of §115.226(1), since the gasoline delivery is not required to utilize Stage I vapor recovery equipment. Therefore, the commission has revised §115.227 accordingly. The commission agrees that a gasoline station which is exempt based on having one or more small storage capacity tanks should also be exempt from testing requirements of §115.225. As noted earlier in the discussion of §115.225, Test Method 21 (for determining VOC leaks by instrument) is listed in §115.225, while §115.224(1) requires inspections for leaks. Although §115.224(1) applies regardless of storage tank capacity or gasoline throughput, it is necessary for §115.225 to apply because an owner or operator would use Test Method 21 to identify vapor leaks. Specifically, since the gasoline delivery is not required to utilize Stage I vapor recovery equipment, it is unnecessary to inspect for vapor leaks and significant odors. The commission believes, however, that it is reasonable to inspect for and correct liquid gasoline leaks during gasoline delivery at gasoline stations which are exempt from utilizing Stage I equipment based on having one or more small storage capacity tanks. The commission also believes that after unloading gasoline at such exempt gasoline stations, it is reasonable to require that tank-truck tanks be kept vapor-tight until the vapors in the tank-truck are returned to a loading, cleaning, or degassing operation and discharged in accordance with the control requirements of that operation. The commission has revised §115.227(1) and (3) accordingly.

Dow commented that §115.227(2) and (4), which provide exemptions for gasoline stations based upon gasoline throughput, are not complete and should include more sections from which the owner or operator is exempt. Specifically, Dow stated that a gasoline station which is exempt based on gasoline throughput should also be exempt from the leak-tightness testing requirement of §115.224(2), the testing requirements of §115.225, and the gasoline delivery and tank-truck leak test recordkeeping requirements of §115.226.

For the reasons given in the discussion of comments on §115.227(1) and (3), the commission agrees that a gasoline station which is exempt based on gasoline throughput should also be exempt from the leak-tightness testing requirement of §115.224(2) and the gasoline delivery and tank-truck leak test recordkeeping requirements of §115.226(1). Therefore, the commission has revised §115.227 accordingly. For the reasons given in the discussion of comments on §115.227(1) and (3), the commission agrees that a gasoline station which is exempt based on gasoline throughput should also be exempt from testing requirements of §115.225, but believes, however, that it is reasonable to inspect for and correct liquid gasoline leaks during gasoline delivery at gasoline stations which are exempt from utilizing Stage I equipment based on gasoline throughput. The commission also believes that after unloading gasoline at such exempt gasoline stations, it is reasonable to require that tank-truck tanks be kept vapor-tight until the vapors in the tank-truck are returned to a loading, cleaning, or degassing operation and discharged in accordance with the control requirements of that operation. The commission has revised §115.227(2) and (4) accordingly.

The EPA and Sierra Club commented on §115.227(4), which exempts gasoline stations in the covered attainment counties with a gasoline throughput of less than 125,000 gallons per month from the Stage I requirements of §115.221 and §115.222. The EPA and Sierra Club expressed the desire that gasoline stations below the 125,000 gallons per month threshold in the covered attainment counties be subject to these Stage I requirements.

The commission has estimated that the cost-effectiveness of Stage I for a small gasoline station (i.e., a station with a gasoline throughput between 10,000 and 25,000 gallons per month) is approximately $1,614 per ton of VOC reduced. By comparison, the EPA estimated the cost-effectiveness of recently promulgated motor vehicle control programs in EPA's Tier 2 Study, EPA420-R-98-008 (July 31, 1998) as follows: 1) $6,000 per ton of VOC reduced and $1,380 to $1,800 per ton of NO _x reduced for Tier 1 standards for light-duty vehicles and light-duty trucks; 2) $457 to $552 per ton of VOC reduced and $150 to $172 per ton of NO _x reduced for supplemental federal test procedure (SFTP) standards for aggressive driving; 3) $2,050 to $2,574 per ton of NOx reduced for SFTP standards for emissions with the air conditioner on; and 4) $1,974 per ton of VOC reduced and $1,974 per ton of NO _x reduced for on-board diagnostics requirements. The commission has made no changes in response to the comment. However, the commission agrees that Stage I controls are cost-effective for gasoline stations having gasoline throughput as low as 10,000 gallons per month, and in the future may consider a second phase of rulemaking which would implement Stage I in the covered attainment counties for gasoline stations with a gasoline throughput below 125,000 gallons per month.

The commission has revised §115.229 by extending the compliance date to April 30, 2000 in response to Mobil's comment on §115.219 that the proposed December 31, 1999 compliance date represents an aggressive schedule. The revised compliance date will provide the regulated community with additional time to comply with the new requirements, but will still ensure that the emission reductions occur prior to the critical 2000 ozone season.

The Sierra Club commented on §115.229, which establishes the Stage I compliance schedule, and stated that cities should be given the flexibility to implement Stage I regulations prior to the 1999 ozone season.

Cities have the flexibility to implement the Stage I requirements early through city ordinances or voluntary programs. In response to Sierra Club's comment, the commission has revised §115.229(d) to make it clear that the phrase "as soon as practicable, but no later than..." in §115.229(d) means that before the April 30, 2000 compliance date, gasoline stations which are equipped for Stage I vapor recovery must utilize Stage I for each gasoline delivery by a gasoline tank-truck which is likewise equipped for Stage I vapor recovery. Likewise, the commission has revised §115.239(b) to make it clear that the phrase "as soon as practicable, but no later than..." in §115.239(b) means that before the April 30, 2000 compliance date, gasoline tank-trucks which are equipped for Stage I vapor recovery must utilize Stage I for each gasoline delivery at a gasoline station which is likewise equipped for Stage I vapor recovery.

Dow commented that the description of the proposed changes to §115.235 and §115.236 in the EXPLANATION OF PROPOSED RULES section of the rule proposal preamble gave incorrect titles for these sections.

The correct titles for §115.235 and §115.236 are Approved Test Methods and Recordkeeping, respectively. The commission corrected these titles in the EXPLANATION OF ADOPTED RULES section.

Dow and TCC commented on the proposed revisions to §115.235(4), which proposed that the alternative testing option applies to tank-truck tanks not required to be equipped with vapor collection equipment (e.g., pressure tanks), and more specifically references the leakage test method of 49 CFR 180.407(h).

The commenters' specific issues regarding tank-truck leak testing and the commission's responses are as follows.

TCC stated that the commission has "instituted a significant regulatory interpretation without notice and comment" which is "not specifically addressed in this rulemaking." TCC further stated that this rulemaking is the first opportunity for the regulated community to comment on the interpretation that "for tank-trucks not equipped with vapor collection equipment, the leakage test in 49 CFR §180.407(h) (U.S. Department of Transportation leakage test) is the appropriate test for the determination of vapor tightness.... For tank-trucks equipped with vapor collection equipment, Method 27 is applicable and should be used."

TCC is referring to an interpretation made by the agency's Air RIT, and specifically to interpretation Code Number R5-234.001 (signed July 3, 1997). It should be noted that the Air RIT established a "reconsideration process" in which the regulated community or the public may submit a request for reconsideration of any interpretations issued by the Air RIT. No such request has been received for the subject interpretation. In addition, the preamble to this rule proposal specifically stated that the proposed revisions "reorganize and clarify the rules, including incorporation of a variety of interpretations made by the agency's Rule Interpretation Team" (24 TexReg 62, January 1, 1999) and that "the proposed changes to §115.235 also clarify that the alternative testing option of the existing §115.235(4) applies to tank-trucks not required to be equipped with vapor collection equipment (e.g., pressure tanks)...(24 TexReg 66)." Therefore, the commission disagrees with TCC's comments.

TCC requested clarification on the meaning of the phrase "equipped with vapor collection equipment."

Method 27 (Title 40 CFR Part 60, Appendix A) was originally promulgated to ensure that gasoline tank-trucks subject to the gasoline terminal NSPS (Title 40 CFR Part 60, Subpart XX) met the NSPS vapor-tightness standards. The definitions section of Method 27 (Definitions and Nomenclature, 2.1) defines "delivery tank vapor collection equipment" as "any piping, hoses, and devices on the delivery tank used to collect and route gasoline vapors either from the tank to a bulk terminal vapor control system or from a bulk plant or service station into the tank." In November 1993, Chapter 115 rule revisions were adopted which extended the ozone nonattainment area leak test requirements applicable to gasoline transport trucks to all tank trucks loading or unloading VOC having a true vapor pressure greater than or equal to 0.5 psia at loading facilities affected by the Chapter 115 division relating to VOC loading and unloading. When Test Method 27 is used for leak testing of tank-trucks carrying VOCs other than gasoline, "vapor collection equipment" means "any piping, hoses, and devices on the tank-truck tank used to collect and route VOC vapors either from the tank-truck tank to a vapor control system or from a fixed roof storage tank into the tank-truck tank." The commission has deleted the reference in §115.235(a)(4) to "vapor collection equipment" in response to changes it made in §115.234 and §115.235 for the reasons discussed following the next comment.

Dow and TCC stated that 49 CFR 180.407(h) should be an acceptable alternative to EPA Test Method 27, regardless of whether the tank-truck tank is equipped with vapor collection equipment, due to their belief that: 1) out-of-state truck owners/operators which ship products to Texas are familiar with the United States Department of Transportation (DOT) requirements, but not the Chapter 115 requirements, which could result in confusion and probable noncompliance; 2) applying the Chapter 115 testing requirements to tank-truck tanks at the point of unloading could interfere with interstate commerce; 3) many Texas companies rely on the DOT leakage test in an effort to satisfy the Chapter 115 requirements, regardless of whether the tank-truck tank is equipped with vapor collection equipment; 4) Title 49 CFR 180.407(h) allows, but does not mandate, Test Method 27 in lieu of the DOT leakage test; and 5) because loading emissions are more significant than unloading emissions, there is little environmental benefit to requiring tank-truck tanks to have been leak tested using Test Method 27 at the unloading point.

Chapter 115 has required compliance with Test Method 27 leak testing for gasoline tank-trucks at both the loading point (i.e., gasoline terminals and gasoline bulk plants) and unloading point (i.e., gasoline bulk plants and gasoline stations) in ozone nonattainment counties for many years. The gasoline terminal NSPS (Title 40 CFR Part 60, Subpart XX) has also required compliance with Test Method 27 at new or modified gasoline terminals for many years. There are numerous reasons why Test Method 27 is superior to the DOT leakage test for tank-truck tanks equipped with vapor collection equipment. In 1994, the DOT revised 49 CFR §180.407(h) to allow Method 27 to be substituted for 49 CFR §180.407(h), if the cargo tank is equipped with vapor collection equipment: "Cargo tanks equipped with vapor collection equipment may be leakage tested in accordance with the EPA's Method 27, as set forth in 40 CFR Part 60, Appendix A" (49 CFR §180.407(h)(2), November 3, 1994). The previous version of 49 CFR §180.407(h) established Method 27 an acceptable alternative "where applicable" (49 CFR §180.407(h)(2), June 12, 1989). The DOT interpreted this to mean where Method 27 was required, it could be substituted for the DOT leakage test. The revision to the rule, while making Method 27 more generally substitutable for 49 CFR §180.407(h), also highlights that Method 27 is designed physically for applicability to cargo tanks with vapor recovery equipment. The test apparatus section of Method 27 includes a test cap (Apparatus, 3.7) which is inserted on the end of the vapor recovery hose, to which the manometer and pressure-vacuum supply hose are connected. The applicability section of Method 27 (Applicability and Principle, 1.1) states "This method is applicable for the determination of vapor tightness of a gasoline delivery tank which is equipped with vapor collection equipment." Since Method 27 is not applicable to cargo tanks not equipped with vapor recovery equipment, the DOT leakage test is the appropriate test for these cargo tanks.

However, for cargo tanks which are equipped with vapor recovery equipment, the commission considers Method 27 to be a better test method because it is a more sensitive test and is more effective at finding leaks than the tests in 49 CFR §180.407. The following discussion compares Method 27 to the 49 CFR §180.407 tests and provides rationale for not considering the 49 CFR §180.407 tests equivalent to Method 27 for tank-truck tanks equipped with vapor recovery equipment.

The DOT leakage test generally requires pressurization to 80% of the tank's maximum allowable working pressure. Review of this test method and comparison with Method 27 shows several notable differences. The major difference is that Method 27 requires a tank-truck tank to be tested under both pressure and vacuum conditions, while 49 CFR §180.407(h) does not require testing for leaks under vacuum conditions. The commission believes that vacuum testing is an integral part of leak testing, due to the fact that in some instances when a component is placed under pressure, the seals used in the different components can seal off, thus giving the appearance that no leak is present. These leaks would be detected with the vacuum test. The same kind of problem can exist when only vacuum testing is performed; therefore, conducting both pressure and vacuum testing is a more thorough method for locating leaks than either test by itself.

Additional support for this argument is found in the EPA response to comments received on the proposed Gasoline Distribution NESHAP (40 CFR 63, Subpart R). On Pages 7-8 of the Background Information Document for Promulgated Standards for Gasoline Distribution Industry (Stage I) , a comment was made that because leakage rates have declined over the years, the vapor tightness testing is unnecessary and the requirements are duplicative of current federal and state regulations. Another company commented that current DOT testing programs, with modifications if necessary, sufficiently address the leakage problem. EPA responded to these comments with the following statement: "Further, the test does not duplicate USDOT programs or Federal and State requirements. As pointed out in the BID [Background Information Document], Volume I, Section 4.1.4.2, the current USDOT leakage test does not verify the integrity of some portions of the vapor containing equipment, etc..."

Another difference between the DOT leakage test method and Method 27 is that Method 27 requires that once the required testing pressure is reached, the tank be allowed to equilibrate. Pressure readings are taken initially and after five minutes to determine pressure change. A similar test is conducted under vacuum conditions. However, the DOT leakage test does not require an equilibration period.

While both the DOT leakage test and Method 27 require that pressure be maintained for five minutes, the DOT leakage test does not specify the necessary precision of the pressure gauge used, and therefore, how much loss of pressure is acceptable due to this lack of specified precision. In contrast, Method 27 specifies that the pressure gauge (liquid manometer, or equivalent) be capable of reading up to 500 mm of water, with 2.5 mm water precision. Since the DOT test pressures are specified in units of pounds of pressure gauge, a fairly stringent interpretation of "no loss of pressure" might be less than one psig (or 700 mm water). The Method 27 test requires that pressure loss be limited to no more than 75 mm of water. The detection of a smaller difference in pressure directly corresponds to detection of smaller leaks. Therefore, Method 27 is a more sensitive method for the detection of leaks than the DOT leakage test methods.

In addition, 49 CFR §180.407(h)(2) allows Method 27 as an acceptable alternative, but Method 27 does not allow 49 CFR §180.407(h) as an acceptable alternative. The implication is that Method 27 is the more stringent test.

While the commission believes that Test Method 27 is clearly superior to the DOT leakage test for tank-truck tanks equipped with vapor collection equipment, the commission also recognizes the inherent difficulties in requiring Test Method 27 leak testing for general VOC (i.e., non-gasoline) tank-truck tanks which originate outside Texas. Therefore, the commission has revised §115.234(a) and (b), and §115.235(a)(1) and (4), and (b)(1) such that Test Method 27 is mandatory for gasoline tank-truck tanks and an optional alternative to the 49 CFR §180.407(h) leakage test for general VOC (i.e., non-gasoline) tank-truck tanks. This change will provide maximum flexibility to the regulated community regarding leak testing of general VOC (i.e., non-gasoline) tank-truck tanks.

In addition, the commission revised §115.234(a)(1) and §115.235(a)(1) and (4) so that the leak testing requirements apply to general VOC (i.e., non-gasoline) tank-truck tanks at the loading point, but not at the unloading point. For gasoline tank-truck tanks, the commission has retained the requirement that such tanks comply with Method 27 leak testing at both the loading point (i.e., gasoline terminals and gasoline bulk plants) and unloading point (i.e., gasoline stations) in ozone nonattainment counties. This is necessary to continue to fulfill the EPA's RACT requirements for gasoline tank-trucks and also because gasoline has a relatively high volatility and is a high-volume product.

The commission has also revised §115.234(a) and (b), and §115.235(a)(1) and (b)(1) so that the tank-truck leak testing requirements only apply at facilities which are subject to §115.214(a)(1)(C), (b)(1)(C), or §115.224(2). This will ensure that the tank-truck leak testing requirements do not apply at facilities addressed by §§115.211-115.217 and 115.221-115.227 which are exempt from §115.214(a)(1)(C), (b)(1)(C), or §115.224(2) under §115.217 or §115.227.

Dow and Jenkens suggested that intermodal portable tanks ("isocontainers") be excluded from the leak testing requirements. Dow noted that such tanks can come from a multitude of world-wide shipping points. Jenkens stated that isocontainers are subject to DOT requirements of 49 CFR §173.32b (or the International Maritime Dangerous Goods (IDMG) requirements if transported outside the United States), that pressure testing conducted every five years to meet DOT or IMDG requirements is similar to the leak testing required under §§115.214(a)(1)(C) and 115.234-115.239, that only a small number of isocontainers fail the pressure testing conducted every five years to meet DOT or IMDG requirements, and that therefore more frequent testing of isocontainers will result in minimal emission reductions. Jenkens also stated that the companies who load or unload VOCs into or out of isocontainers generally do not own the isocontainers and that they are typically not dedicated for any particular product, facility, or transportation route. Jenkens commented that this made implementation of the testing requirements very difficult.

Jenkens did not provide specific data on how many isocontainers fail the DOT or IMDG pressure testing. In any case, the pressure testing identified by Jenkens is not equivalent to Test Method 27 for a variety of reasons. For example, pressure testing is intended to test structural integrity. The pressure test requires pressurization to levels according to the tank's DOT classification. These levels are generally one and one-half times the tank's design or maximum allowable working pressure. At these higher pressures, the seals used in the components of the tank can be pushed outward and can seal off any possible leaks, thus giving the appearance that no leaks are present.

Also, the use of soap bubbles does not give a precise reading regarding possible leaks. Human error involved during the application of the soap and water solution may allow a leak to go undetected (i.e., failure to cover the entire tank system, including all valves, with the soap solution). There is also the problem of not being able to observe all areas of the tank where the solution has been applied. Furthermore, the soap-solution test is not equivalent, since the test is performed only under pressure conditions and cannot be performed under vacuum conditions. Finally for insulated tanks, visual inspection of leaks is limited by the insulation coating, resulting in the potential for error with the pressure test.

Isocontainers are normally attached to a trailer (or possibly a truck or railcar) when being loaded with VOC. Any truck, trailer, or railcar which is equipped with an isocontainer having a capacity greater than 1,000 gallons will meet the definition of "transport vessel," and therefore is subject to the loading/unloading requirements of §§115.211-115.217.

While the commission believes that Test Method 27 is clearly superior to the DOT or IMDG pressure test for portable tanks, the commission also recognizes the inherent difficulties in requiring Test Method 27 leak testing for such tanks. Therefore, the commission has revised §115.237(a) by adding a new paragraph (3) which exempts portable tanks, as defined in 49 CFR 171.8, from the leak testing requirements. Section 115.214(a)(1)(C) references the requirements of §§115.234-115.237, but does not need to be revised because the new §115.237(a)(3) exempts portable tanks, as defined in 49 CFR 171.8. Therefore, the commission has made no changes to §115.214(a)(1)(C) in response to the comments.

An individual commented on §115.237(b), which exempts transport vessels other than tank-trucks from the annual vapor-tightness testing requirements. The individual opposed excluding railcars and marine vessels from the testing requirements in the covered attainment counties and suggested that the requirements of §§115.234-115.236 be applied to these sources.

The individual's suggestion is beyond the scope of this rulemaking, and therefore the commission has made no changes in response to this comment. However, the commission may reevaluate this suggestion in the future if additional VOC reductions are needed for attainment of the ozone NAAQS in the covered attainment counties.

The commission has revised §115.239 by extending the compliance date to April 30, 2000 in response to Mobil's comment on §115.219 that the proposed December 31, 1999 compliance date represents an aggressive schedule. The revised compliance date will provide the regulated community with additional time to comply with the new requirements, but will still ensure that the emission reductions occur prior to the critical 2000 ozone season.

Subchapter A. Definitions