The Texas Natural Resource Conservation Commission (commission) adopts amendments to §114.2 (Inspection and Maintenance (I/M) Definitions); §114.50 (Vehicle Emissions Inspection Requirements), §114.51 (Equipment Evaluation Procedures for Vehicle Exhaust Gas Analyzers), §114.52 (Waivers and Extensions for Inspection Requirements), and §114.53 (Inspection and Maintenance Fees). The commission adopts these revisions to Chapter 114 (Control of Air Pollution from Motor Vehicles), and to the State Implementation Plan (SIP) in order to control ground-level ozone in the Dallas/Fort Worth (DFW), Houston/Galveston (HGA), and El Paso (ELP) ozone nonattainment areas. Sections 114.2, 114.50, 114.51, and 114.53 are adopted with changes to the proposed text as published in the December 31, 1999 issue of the Texas Register (24 TexReg 11905). Section 114.52 is adopted without changes to the proposed text and will not be republished.

The adopted amendments are one element of the DFW Attainment Demonstration SIP. The purpose of these adopted rules is to establish a vehicle emissions testing program as part of the control strategy to reduce emissions of oxides of nitrogen (NO _x ) and other pollutants necessary for the counties included in the DFW nonattainment area to be able to demonstrate attainment with the national ambient air quality standard (NAAQS) for ozone.

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

The DFW ozone nonattainment area, an area defined by Collin, Dallas, Denton, and Tarrant Counties, was originally designated "moderate" under the Federal Clean Air Act (FCAA) Amendments of 1990 (42 United States Code (USC)) and thus was required to attain the one-hour NAAQS for ozone by November 15, 1996. As required by the FCAA, the state submitted an attainment demonstration plan in 1994 which projected attainment of the ozone NAAQS by 1996. This plan was based on a volatile organic compound (VOC) reduction strategy. DFW did not attain the ozone NAAQS in 1996. The United States Environmental Protection Agency (EPA) is authorized to redesignate an area to the next higher classification ("bump up") if the area fails to attain by the required date. In March 1998, in accordance with 42 USC, §7511(b)(2), the EPA reclassified the DFW area from moderate to serious, based on monitored exceedances of the ozone NAAQS between 1994 and 1996. The reclassification required the state to submit a revised SIP that demonstrates that the ozone NAAQS will be met in DFW by November 15, 1999. Because the DFW area continued to exceed the ozone NAAQS in 1999, the EPA may bump up the area to the severe classification. Regardless, the EPA and 42 USC, §7410 and §7502(a)(2), require the state to submit a revised SIP which demonstrates that the area will attain the ozone NAAQS as expeditiously as practicable. The rules adopted for DFW in this notice are one element of the ozone attainment demonstration SIP for DFW being adopted concurrently in this issue of the Texas Register . The commission plans to submit this SIP to the EPA in April, 2000.

In 1996, the commission began to develop new modeling for the DFW area and now is using newer air quality models with improved meteorological and emission inputs. The newer modeling since 1996 shows that reductions of NOx in the DFW area and regionally will be necessary to attain the ozone NAAQS. The current modeling also shows that achieving the ozone NAAQS in the DFW area will require strenuous effort because the area's rapid growth has resulted in increasing amounts of emissions due to increased levels of activity in the area. The emissions from increased activity are offsetting the emission reductions being achieved from new emission standards applicable to the on-road and non-road engine source categories which dominate the emissions inventory in the DFW area.

The emission reduction requirements adopted as part of this SIP package are the outcome of a development process which involved the EPA, the commission, local elected officials, citizens, industrial stakeholders, air quality researchers, and hired consultants. Local officials from the DFW area have formally submitted a resolution to the commission requesting the inclusion of many specific emission reduction strategies, including the one contained in these rules.

The NO _x reductions required for the area to attain the ozone NAAQS have been estimated by extensive use of sophisticated air quality grid modeling which, because of its scientific and statutory grounding, is the chief policy tool for designing emission reductions. Title 42 USC, §7511a(c)(2), requires the use of photochemical grid modeling for ozone nonattainment areas designated serious, severe, or extreme. The modeling has been conducted with input from a technical advisory committee. Hundreds of emission control strategies were considered in developing the modeling. Varying degrees of reductions from point sources and mobile sources were analyzed in at least forty modeling iterations, to test the effectiveness of different NO _x reductions. The attainment demonstration modeling submitted for public hearing and comment concurrently with these rules shows that, in order for DFW to achieve the ozone NAAQS by 2007, almost all of the practicably achievable NO _x reductions are necessary from each emission source category, including reductions from counties surrounding the DFW nonattainment area. Therefore, each strategy, including the reductions required by this rulemaking, is crucial to meet federal requirements for the DFW nonattainment area.

The North Texas Clean Air Steering Committee (steering committee) representing the DFW ozone nonattainment area counties requested an air pollution control strategy involving emissions testing of vehicles to reduce NO _x and other emissions necessary for the counties included in the DFW nonattainment area to be able to demonstrate attainment with the ozone NAAQS. These amendments are one element of the control strategy for the proposed DFW Attainment Demonstration SIP.

At the request of the steering committee as well as certain counties surrounding the DFW nonattainment area, the commission is adopting an air control strategy for NO _x reductions which requires emissions testing of motor vehicles that are registered and primarily operated in the DFW area. The testing would utilize on-board diagnostic (OBD) technology and acceleration simulation mode (ASM-2), or a vehicle emissions testing program that meets SIP emissions reduction requirements and is approved by EPA. Modeling, performed for the steering committee assessing the benefits of this NO _x emissions reduction strategy, demonstrated that significant emissions reductions could be achieved from implementing a vehicle emissions testing, i.e., I/M program. This I/M program was modeled to cover nine counties in the DFW area.

In its effort to ensure that the SIP strategies impose no more burden than necessary to protect health and welfare, the commission decided not to include the counties of Hunt, Hood, and Henderson as affected counties of these rules due to their limited impact on the air quality within the DFW nonattainment area. Due to the relatively low population, percentage of commuters, and growth rate of these counties the commission has reevaluated the need for implementing this rule in these three counties. The reevaluation included new photochemical modeling runs which applied these rules in the nine remaining counties only. The results of these runs indicated a minor impact of including Hunt, Hood, and Henderson counties in this rule but also showed that the area could demonstrate attainment of the NAAQS without those reductions in emissions. Additionally, these three counties have not submitted resolutions requesting inclusion in the I/M program. However, other control measures which were proposed for these counties do have measurable benefits for attainment of the NAAQS.

These amendments will modify the vehicle emissions testing program by implementing ASM-2 testing, or a vehicle emissions testing program that meets SIP emissions reduction requirements and is approved by EPA, in nine counties of the DFW area. Unlike the current two-speed idle (TSI) test, ASM-2 technology has the ability to detect NO _x emissions. Because NOx is a precursor to ground-level ozone formation, reduced NO _x and VOC emissions will result in ground-level ozone reduction.

The rule amendments addressed in this rule change include: adding counties opting into the I/M program; changing the testing technology to ASM-2, or a vehicle emissions testing program that meets SIP emissions reduction requirements and is approved by EPA, in the DFW program area; an update to the minimum expenditure waiver; increase to the emissions inspection fee; incorporation of new technical specifications for emissions test equipment (TSI and ASM-2) by reference; new requirements regarding the servicing and maintenance of emissions test equipment; and the addition of OBD testing requirements to go into effect by January 1, 2001. In addition, the rule and SIP revisions deleted outdated language throughout Subchapter C.

The amendments detail vehicle emissions inspection and maintenance requirements in counties not subject to a specific federal I/M requirement (Ellis, Johnson, Kaufman, Parker, and Rockwall Counties) in response to resolutions submitted to the commission by each individual county and the most populous municipality within each county.

EPA stated that before SIP measures could be determined complete the state must have underlying legal authority to implement the rules. Texas statutes mandate that Texas must receive resolutions requesting inclusion in the program from each county and municipality not specifically subject to a federal requirement. All comments regarding opt-in will be addressed in the ANALYSIS OF TESTIMONY section of this preamble.

The revisions establish an I/M program utilizing ASM-2 vehicle emissions testing equipment or a vehicle emissions testing program that meets SIP emissions reduction requirements and is approved by EPA beginning May 1, 2002, in Dallas, Denton, Collin, and Tarrant Counties, and beginning May 1, 2003, in Ellis, Johnson, Kaufman, Parker, and Rockwall Counties. The commission solicited comments on implementing the ASM-2 and OBD testing program on January 1, 2002, in the surrounding eight-county attainment area. This phase-in approach may make for a smoother implementation of the proposed I/M program while still providing significant air quality improvements. These revisions will also require as of January 1, 2001, an OBD check of all 1996 and newer model year vehicles subject to the I/M program at that time. The I/M program being adopted involving ASM- 2 testing of vehicles, or a vehicle emissions testing program that meets SIP emissions reduction requirements and is approved by EPA, will reduce NO _x and other emissions necessary for the counties included in the DFW nonattainment area to be able to demonstrate attainment with the ozone NAAQS. In addition, the inclusion of OBD in the I/M program satisfies a federal mandate. These amendments to the rules and SIP were in response to a request from the steering committee representing the DFW ozone nonattainment area counties for an air pollution control strategy involving emissions testing of vehicles, EPA regulations in Title 40 Code of Federal Regulations (CFR) Part 51 (Requirements for Preparation, Adoption, and Submittal of Implementation Plans), Subpart S (Inspection/Maintenance Program Requirements), and the FCAA (42 USC, §§7401, et seq.) as amended on November 15, 1990.

The commission received no comments in response to implementing ASM-2 and OBD testing in the surrounding eight-county attainment areas beginning January 1, 2002.

The commission solicited comments regarding conducting OBD-only vehicle emissions testing for 1996 and newer vehicles in the counties surrounding the DFW ozone nonattainment area (Ellis, Henderson, Hood, Hunt, Johnson, Kaufman, Parker, and Rockwall Counties) should they collectively or individually submit a resolution requesting such a program. This would eliminate the ASM-2 requirements in those counties upon adoption.

The commission received six comments in response to conducting OBD-only vehicle emissions testing on 1996 and newer vehicles in those counties surrounding the DFW ozone nonattainment area. All comments are addressed in the ANALYSIS OF TESTIMONY section of this preamble.

The commission solicited comments on raising the minimum expenditure waiver amount from $450, adjusted by the Consumer Price Index (CPI), to an amount of $750 if the steering committee in the local program area can establish a repair assistance program to provide financial assistance to qualifying motorists.

The commission received no comments on raising the minimum expenditure waiver amount from $450 to $750. However, the commission did receive four comments in response to raising the minimum expenditure waiver amount to $450, adjusted by the Consumer Price Index (CPI). All comments are addressed in the ANALYSIS OF TESTIMONY section of this preamble.

The commission also solicited comments on establishing a market-driven vehicle emissions test fee instead of a set fee for the I/M Program areas upon adoption.

The commission received six comments in response to market-driven fees. All comments are addressed in the ANALYSIS OF TESTIMONY section of this preamble.

SECTION BY SECTION DISCUSSION

Section 114.2 incorporates numerous editorial changes to ensure that the definitions are consistent with the guiding principles and policies of the commission, and are consistent in format, style, and tone per commission guidelines. New and amended definitions are renumbered to be consistent with Texas Register rules, as published in the February 13, 1998 issue (23 TexReg 1289). Several new definitions, modifications to existing definitions, and deletion of existing definitions are adopted in §114.2 to define terms specific to the state I/M program. These new definitions include "acceleration simulation mode (ASM-2) test," "Consumer Price Index," and "on- board diagnostic (OBD) system." Modified definitions include "on-road test," "primarily operated," "program area," and "testing cycle." The definition for "program area" was modified to include the DFW program area to which are added Denton and Collin Counties, adding the ELP program area, the HGA program area, and a new definition was added for the "extended Dallas Fort Worth Program (EDFW) area." Finally, five definitions were deleted because they were no longer necessary. These deleted definitions include "adjusted annually," "basic program area," "core program area," "emissions tune-up," and "enhanced program area."

Revisions to Subchapter C incorporate numerous editorial changes to ensure the language is consistent with the guiding principles and policies of the commission, and is consistent in format, style, and tone per commission guidelines. Revisions to specific sections in Subchapter C are discussed in the following paragraphs.

Amendments to §114.50 establish revised program requirements for the state I/M program for vehicle testing and inspection. The amendments to the program concern the applicability, the control requirements, the frequency of testing, the recognized emissions repair technicians requirements, and the certified emissions inspection station requirements.

Subsection 114.50(a) is amended by adding some vehicle classes to be excluded from the program. For the DFW, ELP, and HGA areas, the inspection frequency option for biennial testing is deleted. Subsection (a) is further modified by deleting paragraphs (1), (2), and (3) concerning testing cycles and previous program start-up dates in Dallas, Tarrant, Harris, and El Paso Counties and by adding new paragraphs (1)-(5) for clarification of program areas, model year vehicles to be tested, types of equipment to be utilized, and implementation dates. New paragraph (1) defines model year vehicles to be tested using only the current TSI test in Dallas, Tarrant, El Paso, and Harris Counties through December 31, 2000. Paragraph (2) applies to all vehicles registered and primarily operated in the DFW program area. Paragraph (2)(A) defines model year vehicles to be tested using OBD and TSI test equipment beginning January 1, 2001. Paragraph (2)(B) defines model year vehicles to be tested using TSI beginning January 1, 2001, and clarifies that testing stations must offer both OBD and TSI test. Paragraph (2)(C) defines model year vehicles to be tested using OBD in conjunction with ASM-2 test equipment, or a vehicle emissions testing program that meets SIP emissions reduction requirements and is approved by EPA, instead of the TSI test, beginning May 1, 2002. Paragraph (2)(D) defines model year vehicles to be tested using ASM-2, or a vehicle emissions testing program that meets SIP emissions reduction requirements and is approved by EPA, instead of the TSI test, beginning May 1, 2002 and clarifies that testing stations must offer both OBD and ASM-2 test. Paragraph (3) applies to all vehicles registered and primarily operated in the EDFW program area. Paragraph (3)(A) defines model year vehicles to be tested using OBD and ASM-2 test equipment, or a vehicle emissions testing program that meets SIP emissions reduction requirements and is approved by EPA, beginning May 1, 2003. Paragraph (3)(B) defines model year vehicles to be tested using ASM-2, or a vehicle emissions testing program that meets SIP emissions reduction requirements and is approved by EPA, beginning May 1, 2003. Paragraph (3)(B) also clarifies that testing stations must offer both OBD and ASM-2 test, or a vehicle emissions test that meets SIP emissions reduction requirements and is approved by EPA. Paragraph (4) applies to all vehicles registered and primarily operated in Harris county of the HGA program area. Paragraph (4)(A) defines model year vehicles to be tested using OBD in conjunction with TSI test equipment beginning January 1, 2001. Paragraph (4)(B) defines model year vehicles to be tested using a TSI test beginning January 1, 2001 and clarifies that testing stations must offer both OBD and TSI tests. Paragraph (5) applies to all vehicles registered and primarily operated in El Paso County. Paragraph (5)(A) defines model year vehicles to be tested using OBD in conjunction with TSI test equipment beginning January 1, 2001. Paragraph (5)(B) defines model year vehicles to be tested using TSI beginning January 1, 2001, and clarifies that testing stations must offer both OBD and TSI tests.

Subsection 114.50(b) specifies control requirements for motorists, state and governmental entities, and certain federal employees. The affected vehicles are required to comply with the air pollution emissions control related requirements included in the annual vehicle safety inspection administered by the Department of Public Safety (DPS), the vehicle emissions inspection and maintenance requirements contained in the revised Texas I/M SIP, and the on-road emissions test requirements. Paragraph (1) is amended by incorporating editorial changes; deletion of paragraph (2) which is incorporated into paragraph (1); addition of new paragraph (2) concerning certifying federal vehicles; addition of "or appointed designee," after executive director; addition of EDFW program area in paragraphs (1), (3), and (6); and renumbering of the subsection. Paragraph (6)(B) is amended by adding a period after SIP, and deleting "within 60 days of written notice by the DPS."

In order to maximize NO _x emissions reductions, the biennial testing requirements in §114.50(d) are deleted to put the I/M inspection cycle on an annual basis. Section 114.50(e) is renumbered to §114.50(d). New paragraph (e)(3) is amended by deleting "revised Texas I/M SIP" and adding "Texas Transportation Code, Sections §§548.401 - 548.404." This subsection also establishes that inspection stations and repair technicians in the program must be designated by the DPS.

Subsection (f), Requirements for Recognized Emissions Repair Technician of Texas, and subsection (g), Certified Emissions Inspection Station Requirements, are deleted because the requirements of both subsections are contained in DPS rules found in 37 TAC §23.93.

Section §114.51 is amended to update the equipment evaluation procedures for vehicle emissions test equipment. This section currently specifies application, certification, maintenance, and service requirements for manufacturers or distributors of vehicle emissions testing equipment seeking approval of an exhaust gas analyzer or analyzer system for use in the Texas I/M program. Subsection 114.51(a) previously specified a date of April 26, 1996 for the exhaust analyzer technical specifications known as "Specifications for Preconditioned Two Speed Idle Vehicle Exhaust Gas Analyzer Systems for use in the Texas Vehicle Emissions Testing Program." In order to incorporate new and updated specifications into the program, the rule amendment specifies a date of March 15, 2000 for both the TSI exhaust analyzer technical specifications, and the "Specifications for Acceleration Simulation Mode Vehicle Exhaust Gas Analyzer System for use in the Texas Vehicle Emissions Testing Program." This subsection will also require manufacturers to resubmit certification to the commission stating that their existing units meet the requirements of the new specifications. Subsection (a) has been updated to reflect the new date for both TSI and ASM-2 specifications as March 15, 2000.

Section 114.51(e) requires applicants to comply with all special provisions and conditions in the notice of approval and notifies applicants of enforcement consequences for misrepresentation or compliance failure. The amendments to §114.51(e), add paragraph (3) that clarifies the analyzer service requirements for analyzer manufacturers by adding a two-day response time (excluding weekends and holidays) to the rule. This has always been a requirement in the specifications; however, in order to highlight the provision, the commission is adding it to the rule language. Paragraphs (5) and (6) were also added to make clear the on-going service and update requirements for manufacturers. Subsection (f) is deleted because the 1996 start-up date has already passed.

Section 114.52 previously specified two types of waivers and time extensions, along with the associated qualification criteria. Subsection (b)(1)(A) is amended to read that the minimum expenditure waiver amount in any affected county shall be at least $450 or that amount as adjusted by the CPI. Previously, Dallas and Tarrant Counties had a lower minimum expenditure because the area was classified as a moderate area. However, because the DFW nonattainment area was reclassified as a serious area, the minimum expenditure must be increased to $450 as adjusted by the CPI. Additionally, this language will allow the executive director to adjust the fee by the CPI at any time. Subsection (b)(1)(B) and (D), and (2), and subsection (d)(2) are amended by deleting "after January 1, 1997," since this date has already passed.

Amendments to §114.53 establish fee schedules for the different counties which must be paid for the vehicle emissions inspection at an inspection station. Subsection (a)(4) is amended by adding counties opting into the I/M program beginning May 1, 2003.

The commission proposed a testing fee increase in Dallas and Tarrant Counties of $5.00 (from $13 to $18) for an inspection using ASM-2 or OBD equipment. Staff re-evaluated the fee proposal based on comments received and adjusted the emissions testing fee to include the costs of labor, training, warranties, insurance, and consumable items used in conducting emissions testing, in addition to the costs of purchasing ASM equipment. Subsection (a) is further amended by deleting paragraphs (1)-(3) and by adding new paragraphs (1)-(4). New paragraph (1) states that through December 31, 2000, emissions inspection stations required to conduct a TSI test in Dallas, El Paso, Harris, and Tarrant Counties will continue to collect $13 per emissions test. Paragraph (2) states that beginning January 1, 2001, emissions stations required to conduct a TSI and OBD test in Dallas, El Paso, Harris, and Tarrant Counties will collect $14 per emissions test. Paragraph (3) states that beginning May 1, 2002, emissions stations required to conduct an OBD test and an ASM-2 test, or a vehicle emissions test that meets SIP emissions reduction requirements and is approved by EPA, in Dallas, Collin, Denton, and Tarrant Counties will collect $22.50 per emissions test. Paragraph (4) states that beginning May 1, 2003, emissions stations required to conduct an OBD test and an ASM-2 test, or a vehicle emissions test that meets SIP emissions reduction requirements and is approved by EPA, in Ellis, Johnson, Kaufman, Parker, and Rockwall will collect $22.50 per emissions test.

In subsection (c), after "on-road testing," the comma is changed to a period, the remaining two sentences are deleted, and the following sentence after on-road testing is added; "If the vehicle passes the vehicle emissions inspection, the vehicle owner may request reimbursement from DPS."

In addition to the rule changes, the revisions to the SIP narrative clarify the new program elements such as applicability changes; state resources for the program; new performance standards; emissions testing network type; emissions testing; affected vehicle populations; strategies for quality control and quality assurance; projection of waiver rates; enforcement actions related to vehicles and service providers; data collection, analysis, and reporting; inspector training, licensing, and certification; public information strategies; plans for improving repair effectiveness; on-road vehicle emissions testing; and the implementation schedule.

FINAL REGULATORY IMPACT ANALYSIS

The commission reviewed the rulemaking in light of the regulatory analysis requirements of Texas Government Code, §2001.0225, and determined that the rulemaking is not subject to §2001.0225 because it does not meet the definition of a "major environmental rule" as defined in that statute. "Major environmental rule" means a rule the specific intent of which is to protect the environment or reduce risks to human health from environmental exposure and that may adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state. The amendments to Chapter 114 are intended to protect the environment or reduce risks to human health from environmental exposure to ozone. However, the inspection stations in and around nonattainment areas would not normally be considered a sector of the economy. In addition, the commission structured the fees in this program to ensure that most additional costs of equipment can be recovered. Therefore, the adopted rules do not affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state. The amendments are intended to establish a vehicle emissions testing program as part of the control strategy to reduce NO _x emissions necessary for the counties included in the DFW nonattainment area to be able to demonstrate attainment with the ozone NAAQS. While the I/M program is mandatory for nonattainment counties, it may be voluntary for attainment counties. The steering committee representing the DFW ozone nonattainment area counties requested an air pollution control strategy, including emissions testing of vehicles, to be established to reduce NO _x emissions necessary to demonstrate attainment with the NAAQS. The amendments are part of the commission response to the request and one element of the SIP. As defined in Texas Government Code, §2001.0225 only applies to a major environmental rule, the result of which is to: 1. exceed a standard set by federal law, unless the rule is specifically required by state law; 2. exceed an express requirement of state law, unless the rule is specifically required by federal law; 3. exceed a requirement of a delegation agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program; or 4. adopt a rule solely under the general powers of the agency instead of under a specific state law. This rulemaking action does not meet any of these four applicability requirements. Specifically, the emissions testing program within this rulemaking action was developed in order to meet the NAAQS for ozone set by the EPA under 42 USC, §7409, and therefore meet a federal requirement. States are primarily responsible for ensuring attainment and maintenance of NAAQS once EPA has established those standards. Under 42 USC, §7410 and related provisions, states must submit, for EPA approval, SIPs that provide for the attainment and maintenance of NAAQS through control programs directed to sources of the pollutants involved. This rulemaking action 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. This rulemaking action is intended to help bring the DFW ozone nonattainment area into compliance. The amendments do not exceed a standard set by federal law, exceed an express requirement of state law unless specifically required by federal law, nor exceed a requirement of a delegation agreement. The amendments were not developed solely under the general powers of the agency but were specifically developed to meet the air quality standards established under federal law as NAAQS. There were no comments submitted on the draft regulatory impact analysis during the public comment period.

TAKINGS IMPACT ASSESSMENT

The commission prepared a takings impact assessment for these rules in accordance with Texas Government Code, §2007.043. The following is a summary of that assessment. The specific purpose of the rulemaking is to implement a revised I/M program in the ELP and HGA ozone nonattainment areas and in nine counties in the DFW area as part of the strategy to reduce emissions of ozone precursors necessary for the areas to be able to demonstrate attainment with the ozone NAAQS.

Promulgation and enforcement of the rules will not burden private, real property because this rulemaking action does not require the installation of permanent equipment. Although the rule revisions do not directly prevent a nuisance or prevent an immediate threat to life or property, they do prevent a real and substantial threat to public health and safety and partially fulfill a federal mandate under 42 USC, §7410. Specifically, the emissions limitations and control requirements within this proposal were developed in order to meet the ozone NAAQS set by the EPA under 42 USC, §7409. States are primarily responsible for ensuring attainment and maintenance of the NAAQS once the EPA has established them. Under 42 USC, §7410 and related provisions, states must submit, for approval by the EPA, SIPs that provide for the attainment and maintenance of NAAQS through control programs directed to sources of the pollutants involved. Therefore, the purpose of the rulemaking action is to implement a revised I/M program which is necessary for the ozone nonattainment areas to meet the air quality standards established under federal law as NAAQS. Consequently, the exemption which applies to these rules is that of an action reasonably taken to fulfill an obligation mandated by federal law. Therefore, this rulemaking action will not constitute a takings under Chapter 2007 of the Texas Government Code.

COASTAL MANAGEMENT PROGRAM CONSISTENCY REVIEW

The commission determined that this rulemaking action relates to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act of 1991, as amended (Texas Natural Resources Code, §§33.201 et seq.), and the commission rules in 30 TAC Chapter 281, Subchapter B (Consistency with the CMP). As required by 31 TAC §505.11(b)(2) and 30 TAC §281.45(a)(3) relating to actions and rules subject to the CMP, commission rules governing air pollutant emissions must be consistent with the applicable goals and policies of the CMP. The commission reviewed this rulemaking action for consistency with the CMP goals and policies in accordance with the rules of the Coastal Coordination Council, and determined that the action is consistent with the applicable CMP goals and policies. The CMP policy applicable to this rulemaking action is the policy (31 TAC §501.14(q)) that commission rules comply with federal regulations in 40 CFR to protect and enhance air quality in the coastal area (31 TAC §501.14(q)). This rulemaking action will have a beneficial effect on SIP emissions reduction obligations relating to reasonable further progress and attainment demonstrations by making additional emissions reductions over those made by the existing I/M program. Further, no new air contaminants will be authorized by the rule revisions. Therefore, in compliance with 31 TAC §505.22(e), this rulemaking is consistent with CMP goals and policies.

There were no comments submitted on the consistency of the proposed rules with the CMP during the public comment period.

HEARING AND COMMENTERS

The commission held public hearings on this proposal on January 24, 2000, in El Paso; January 25, 2000, in Austin; January 26, 2000, in Longview and Irving; January 27, 2000, in Dallas and Lewisville; January 28, 2000, in Fort Worth; January 31, 2000, in Beaumont and Houston; and February 9, 2000, in Denton. The comment period was originally scheduled to close on February 1, 2000, but was extended until 5:00 p.m. on February 14, 2000. (see the January 21, 2000 issue of the Texas Register (25 TexReg 461)).

Twenty-seven persons provided oral testimony at the hearings and 892 persons submitted written testimony. The following 919 commenters, provided both oral and/or submitted written testimony: the American Automobile Association (AAA); Association of International Automobile Manufacturers (AIAM); American Lung Association (ALA); American Lung Association of Dallas (ALA-Dallas); Cities of Dallas, Cleburne, Greenville, Lewisville, Plano, and Waxahachie; Citizens for a Safe Environment (CSE); Dallas Sierra Club (Sierra-Dallas); Department of Defense (DoD); Downwinders At Risk (DAR); Ellis County Judge (Ellis); EPA-Region 6; Fort Worth Chamber of Commerce (CoC- Fort Worth); Fort Worth Sierra Club (Sierra-Fort Worth); Hood County Commissioner, Precinct 3 (Hood County); KEATING Technologies, Inc. (Keating); League of Women Voters of Tarrant County (LWV-Tarrant); Lone Star Chapter of the Sierra Club (Sierra-Lone Star); Pennzoil-Quaker State Company; Senior Citizens Alliance of Tarrant County (SCATC); Senior Political Action Committee (SPAC); Sustainable Economic and Environmental Development (SEED); Tarrant Coalition for Environmental Awareness (TCEA); Texas Automobile Dealers Association (TADA); Texas Campaign for the Environment (TCE); Texas Public Citizen (TPC); Texas Public Policy Foundation (TPPF); Texas State Inspectors Association (TSIA); Texas Clean Water Action (TCWA), and 892 individuals.

The following commenters generally supported the proposal: Sierra-Dallas, DAR, Sierra-Fort Worth, SEED, TCE, TCWA, TPC, LWV-Tarrant, ALA-Dallas, TCEA, CoC-Fort Worth, SCATC, SPAC, Dallas, EPA-Region 6, Sierra-Lone Star, CSE, and 782 individuals.

The following commenters generally opposed the proposal: Hood County, TADA, TSIA, and ten individuals.

The following commenters suggested changes to the proposal as stated in the ANALYSIS OF TESTIMONY section of this preamble: the Cities of Cleburne, Greenville, Lewisville, and Waxahachie, Ellis County, AIAM, Keating, TCEA, TSIA, and eight individuals.

ANALYSIS OF TESTIMONY

Emissions Testing Fee

One individual suggested tying vehicle inspection fees to the fuel efficiency/pollution generation of the vehicle so that vehicles that pollute the air more would bear more responsibility for paying for the clean-up of the air.

The vehicle inspection fees are set to allow the state and inspection stations to recoup the cost of implementing the program. Tying emission inspection fees to fuel efficiency/pollution generation would require legislative authorization and is beyond the scope of this rulemaking.

TADA, TSIA, and three individuals commented that a market-based fee system would be appropriate if ASM testing is adopted. Cleburne feels that the concept of market-driven fees may hurt economically-disadvantaged citizens within rural areas because of the lack of competition.

Concerns surrounding unfair pricing, fraudulent testing, inspection quality, and public perception of the program make it necessary for a fixed fee at this time; however, a market-based fee system will be re-evaluated in future program changes. Implementation of a market-based fee will require consideration of issues of equity.

Plano asked that the commission to consider a testing fee exemption for local governments.

If the commission reduced the test fees for local government vehicles, the overall testing fee would have to be increased to recoup the losses especially for the inspection stations that perform the tests. The commission made no change to the rule language in response to this comment.

One shop owner and state inspector stated that the $5.00 increase is insufficient and that an emissions testing fee of $60 is more adequate. Another inspection station owner stated that the emissions testing fee should be $45.

The commission adjusted the proposed inspection fee to $22.50 in order to cover additional costs involved in the use of loaded mode test equipment. These increased costs include labor, training, warranties, insurance, and consumable items (such as calibration gases) used in conducting emissions tests. The commission believes that this level of fee is sufficient to allow a majority of inspection stations to recoup their expenses within five years.

Vehicle Coverage

One individual stated that all vehicles should be required to meet the emission standards that they were originally required to meet when manufactured, and that older cars should not be exempted from the test because they are the ones polluting, not the new cars which are subject to tighter emissions standards. Another individual recommended that all vehicles be required to pass emissions testing.

The I/M program will continue to test vehicles 2-24 years old. This allows a two-year exemption for the newest vehicles which are less likely to fail an emissions test. Vehicles that are 25 years and older are exempt for several reasons: many older vehicles were not required to have many of the pollution control devices now required, a large percentage of vehicles in this age group are classified as classics or antiques, and the vehicles in this age group make up a small percentage (approximately 2.5%) of the total fleet and drive fewer miles per year making their overall emissions impact relatively small.

OBD testing will require vehicle emissions to be within 1.5 times the Federal Test Procedure emissions standard to which they were originally certified at the time of manufacture. OBD testing technology became available with 1996 model year vehicles and will be the test required on 1996 and newer model year vehicles equipped with OBD.

Two individuals commented that vintage (antique) cars should be exempted from emissions testing.

Section 114.50(a) excludes antique vehicles registered with the Texas Department of Transportation (TxDOT) from emissions testing. Additionally, the program is designed with a "rolling" 24-year window with the most recent 24 model years being subject to the I/M program. The "rolling" 24-year window option was selected due to the small amount of vehicles that are on the road after 25 years and a large percentage of these vehicles being classified as classics and/or antiques, which are not subject to emissions testing.

DoD expressed concern that the reporting requirements for federal fleets in both the existing and proposed state regulations appear to exceed the waiver of sovereign immunity set forth in the FCAA.

The commission disagrees that the reporting requirements exceed the sovereign immunity waiver of §118 of the FCAA. Currently the commission requires commanding officers or directors of federal facilities to certify annually that all subject vehicles have been tested and are in compliance with the FCAA. EPA distributed a draft document titled "Interim Guidance for Federal Facility Compliance with Clean Air Act Sections 118(c) and 118(d) and Applicable Provisions of State Vehicle Inspection and Maintenance Programs" dated December 1999, to assist facility managers in determining the following: 1) which requirements apply to their government vehicles; 2) which government vehicles are covered; 3) how to approach inspection and reporting requirements; 4) what constitutes compliance with the substantive and procedural requirements of the applicable I/M program for their facility.

The determination whether a state I/M program qualifies as an FCAA, §118(a) or §118(c) program will be made by the EPA through notice-and-comment rulemaking in the near future. Once the final EPA rule has been published in the Federal Register , the commission will at that time amend the state rule concerning federal facility reporting if necessary.

One individual wanted to know how effective our current emissions testing program is, and also wanted to exempt newer model vehicles up to seven years because he says 99% of these vehicles pass the test. Additionally, one individual wanted to exempt two, three, or even six year old vehicles from auto emissions testing.

The TSI testing program is considered effective in identifying vehicles grossly polluting for hydrocarbons or carbon monoxide. However, idle testing does not allow for the measurement of NO _x because under idle modes the temperature and pressure in the combustion chambers are not high enough to produce a significant amount of measurable NO _x . In order to help the DFW nonattainment areas achieve the necessary NO _x reductions, the current TSI test must be upgraded to an alternative test type, such as ASM-2 with OBD, that can measure NO _x emissions, and therefore achieve significant NO _x reductions.

The emissions testing program tests vehicles 2-24 years old. These vehicles account for the vast majority of vehicles on the road and the vehicle miles traveled, which have a direct correlation to the impact on air quality. The failure rate for vehicles less than six years old is approximately 1.0%. Because some newer vehicles do fail the test and because vehicles subject to testing are more likely to be properly maintained, the amount of emissions reduction benefits that can be claimed for an I/M program is reduced as more model years are exempted from the program.

Waivers

Two individuals commented that there should be no minimum expenditure waivers and that all failing vehicles must be required to come into prompt compliance or have their registration revoked.

Waivers are a way to ensure that motorists making every "good faith" effort to comply with I/M program requirements do not incur excessive repair costs and/or are not excessively inconvenienced. Waivers are not extended beyond one test cycle. Vehicle owners must meet all requirements and reapply, if necessary, the following year to receive a new waiver for that test cycle.

The minimum expenditure waiver is available to those who have made repairs to their vehicle within the established criteria (to include repairs made within 60 days of an inspection) and have met the dollar limits established by the EPA.

The commission committed to limit all waivers to no more than 3.0% in each program area. Since the inception of the current program, the waiver rate has not exceeded 0.4%. The commission will continue to monitor waiver rates in all program areas.

One individual supported raising the minimum expenditure waiver amount, but wanted a local repair assistance program to help those who have trouble coming into compliance.

The minimum expenditure waiver is established by EPA rule. For areas designated as enhanced I/M areas, such as DFW, HGA, and ELP, the minimum expenditure waiver amount is $450 (which may be adjusted based on the CPI). The commission recognizes that this could be an economic hardship for some individuals. Thus, the commission encourages the local councils of government and the repair community to establish repair assistance programs where possible.

One individual wanted to do away with waivers and extensions by 2004 for model years 1991 and older.

Since implementing the current emissions testing program in July 1996, the overall waiver and extension rate has not exceeded 0.4%, well below the 3.0% waiver limit established by the commission. A waiver rate of no more than 3.0% is sufficient to enable the commission to meet applicable federal program requirements. The commission will continue to monitor waiver rates in all program areas. The commission has made no change to the rule.

One individual stated that for as little as $75 a vehicle can get a waiver for up to three years and never has to comply.

Under the current emissions testing program, the minimum expenditure waiver amount for vehicles 1980 and older in the DFW area is $75. This was the case because DFW was formerly classified as a moderate nonattainment area. On March 20, 1998, the DFW area was reclassified as a serious nonattainment area. Because of this reclassification, EPA rules require that the minimum expenditure waiver be brought into line with that for HGA and ELP, which is $450 for all vehicles. According to §114.52, the minimum expenditure waiver shall only be valid for the remaining portion of the testing cycle. At the next cycle, the vehicle will have to be retested and make new expenditures in order to receive another minimum expenditure waiver. Additionally, the cost of parts for only emissions-related repairs directly applicable to the cause of the failure count toward the waiver amount, unless the repairs are performed by a DPS recognized emissions repair technician/facility, then parts and labor costs count toward the waiver amount. Furthermore, if the vehicle emissions components were found to be tampered with, the repairs to the tampered components may not count toward the waiver.

Public Information

The EPA stated that it is unclear how the public awareness plan will be implemented.

The SIP requires that the commission and the DPS implement public awareness plans that specifically addresses eight subject areas. The commission and DPS plan to accomplish the goals set forth in the public awareness plan through, but not limited to, inspector and technician training, public service announcements, brochures at the inspection stations, media coverage, and the assistance of local councils of government. These commitments can be reviewed in the DFW SIP that is adopted concurrently with this rulemaking.

Remote Sensing

Two individuals wanted to know what happened to the remote sensing vans at the entrance ramps to the freeways.

Currently, remote sensing vans are in operation in the DFW, HGA, and ELP program areas. The remote sensing element of the vehicle emissions testing program is operated by the DPS and is used to find high-polluting vehicles commuting in from the outlying counties. Remote sensing vans are randomly moved to monitor commuting traffic. DPS has requested one additional van to meet increased demands in the DFW area.

Dallas, TADA, and 27 individuals supported the expansion of the remote sensing program to target grossly-polluting vehicles.

The I/M program will continue to use remote sensing to identify gross polluters. The commission agrees that remote sensing has a useful role to play in detecting high-emitting vehicles in the I/M program areas. The revisions adopted in this rulemaking would expand the remote sensing program to include vehicles registered in the EDFW area.

One individual suggested bringing any trucks used as passenger vehicles into compliance with standard automobile emissions laws and in addition implementing road-side testing to identify and correct the 10% of the vehicles on the road causing 50% of the mobile pollution.

The current TSI emissions test uses the same emissions standards for all gasoline-powered passenger vehicles and trucks with a gross vehicle weight rating of 8,500 pounds or less. Subject passenger vehicles and light-duty trucks registered and primarily operated in program areas must undergo an annual emissions test. The current on-road testing component of the Texas I/M program uses remote sensing to identify high-emitting vehicles. Owners of vehicles identified as gross polluters receive written notice of the violation instructing them to submit their vehicles to an emissions test at a state-certified emissions testing station for verification of exhaust emissions and to make necessary repairs to bring the vehicle into program compliance. Failure to comply with written notification of an emissions violation is a Class C misdemeanor punishable by a fine of not more than $350. Repeat violations are punishable by a fine of not more than $1,000.

TADA recommended that remote sensing be combined with a mandatory smoking vehicle program to ensure that all smoking vehicles are required to be repaired or retired.

The state-wide smoking vehicle program is a voluntary program and relies on conscientious citizens to identify and report vehicles that they observe emitting visible exhaust. Current remote sensing technology does not have the ability to identify the particulate matter and sulfur compounds generally associated with visible exhaust. Future improvements in remote sensing technology, along with enforceable particulate standards for vehicle exhaust emissions, may make possible such a component of the Texas program to control mobile source emissions.

One individual commented that requiring emission testing of vehicles in outlying rural counties that are not in violation of the ozone standards will punish all motorists, and that a more effective method would be to have more extensive use of random roadside testing on commuter highways.

In the DFW metropolitan area, four counties are considered to have failed to attain national ozone standards: Collin, Dallas, Denton, and Tarrant Counties. Participation in a vehicle I/M program for counties besides these four has been decided by local authorities, according to procedures described in the Texas Transportation Code, §548.301(b) and the Texas Health and Safety Code, §382.037(c) in order to reduce the impact of those motorists on air quality in the entire area. The reductions achieved from these outlying counties are necessary to demonstrate attainment within the DFW nonattainment area. Remote sensing on highways in the DFW and HGA areas to identify high-emitting vehicles began in October 1998. Identified high- emitting vehicles may be vehicles either registered in the designated I/M program counties or commuting from surrounding nonattainment counties. Owners of vehicles identified as gross polluters receive written notice of the violation instructing them to submit their vehicles to an emissions test at a state-certified emissions testing station for verification of exhaust emissions and to make necessary repairs to bring the vehicle into program compliance. Failure to comply with written notification of an emissions violation is a Class C misdemeanor punishable by a fine of not more than $350. Repeat violations are punishable by a fine of not more than $1,000.

The EPA expressed concern that the proposed revision appears to describe on-road testing only in the HGA nonattainment area which does not fulfill the on-road testing mandate in the federal rule.

Remote sensing is used to satisfy two requirements for on-road testing in enhanced I/M programs. First, as specified in 40 CFR §51.351(b), on-road testing is to be used to supplement periodic inspections required in a vehicle I/M program, providing continuous monitoring of the effectiveness of the program. Second, on-road testing is to be used to identify high-emitting vehicles being operated in a nonattainment area in situations where the number of vehicles subject to an I/M program is smaller than the estimated fleet in the nonattainment area (i.e., there is a vehicle shortfall due to unregulated commuting vehicles). Since the current proposal adds the vehicle fleets in Collin and Denton Counties to the subject fleet, there will no longer be a vehicle shortfall in the DFW nonattainment area, thereby obviating the need to satisfy the second requirement for on-road testing in DFW. The DPS plans to use remote sensing to evaluate the on-road emissions performance of at least 20,000 of the vehicles subject to emissions testing in the DFW nonattainment area, and Harris and El Paso Counties, which will satisfy the first requirement for on-road testing. While not specifically required by federal law, the rule has expanded the remote sensing program to cover vehicles registered in the EDFW area. This expansion contributes to the reductions needed for the SIP by capturing vehicles which commute from these outlying counties. Although remote sensing in attainment counties is not specifically authorized under Texas Health and Safety Code, §382.037, the commission has authority to make this expansion under §382.037(c), which gives the commission general authority to design the program as needed to demonstrate attainment and to include attainment counties which have opted in to the program.

One individual in Denton County wanted to see remote sensing data and does not believe Denton County is part of the pollution problem.

Dallas, Tarrant, Denton, and Collin Counties have been designated as the DFW nonattainment area as a result of monitored ambient air quality levels that exceeded the ozone NAAQS. Ozone levels are monitored at designated sites throughout the state using special ambient air monitoring equipment. Remote sensing devices are used to detect individual vehicle tailpipe emissions. Remote sensing is currently used in program areas to detect high-emitting vehicles registered in or commuting into any of the affected nonattainment counties. Modeling which demonstrates that areas as far away as east Texas can impact the air quality of DFW is included in the SIP which is adopted concurrently with these rules.

TPPF commented that a more effective I/M strategy is to implement a system for cleaning up on- road vehicles which pay attention to incentives for motorists to keep their cars clean. TPPF stated that the DFW SIP takes a strong step forward with its proposed implementation of remote sensing and OBD to detect high-emitting vehicles. However, an adjunct program that would further refine the focus of I/M on the small number of high emitters should be considered. Beyond the identification of high- emitting automobiles, remote sensors can be used to detect clean cars, which can subsequently be exempted from annual inspection, thus reducing the load on the planned dynamometer test centers, and saving motorists time and money.

The commission agrees that remote sensing has a useful role to play in detecting high- emitting vehicles in the I/M program areas. However, the commission does not feel that "clean- screening" is a viable option at this time for the following reasons: 1. The possibilities of false failures increase dramatically as the cut-points are tightened, thus, a tailpipe test is necessary to verify more accurately vehicle emissions resulting from remote sensing readings; 2. Even though the EPA has collected data regarding the effectiveness of remote sensing for clean-screening and for identification of high- emitting vehicles, and plans to include options to model remote sensing credits in MOBILE6, the model is still under development. Thus, the current MOBILE model does not allocate any credit reductions for remote sensing; 3. The cost of clean-screening depends on many factors, such as market competitiveness, total number of remote sensing measurements, level of automation, economies of scale, and term of contract. According to the "California Inspection and Maintenance Review Committee Report on Remote Sensing of Vehicle Emissions," dated September 9, 1998, a clean-screening program that exempted 25% of the subject fleet would cost approximately $34 million per year. Although the commission feels that clean- screening is not a viable option at this time, as technology evolves, the commission will continue to evaluate technological advances in emissions testing to ensure the best possible testing methodologies and equipment are considered in future program development.

Program Start-up

EPA had two comments regarding the proposed schedule. First, the final DPS rules of April 28, 1998, will not contain changes necessary to implement the ASM-2 test. These rules must be updated to reflect the changes to the I/M program in the DFW nonattainment area and outlying counties. Second, in the DFW program area the full-stringency cut points on January 1, 1997, will not apply in the ASM test. EPA stated that the dates must be revised to reflect implementation of cut points for ASM testing, or full implementation of final cut points must take place at start-up.

The rules for DPS will be amended after the commission adopts these rules. The DPS rule amendment process will take approximately 90 days, and the commission anticipates that the DPS rules will be adopted by September 1, 2000.

The commission revised the schedule contained in the SIP, Chapter 22: State Implementation Plan Submission, to clarify that TSI testing using full stringency cut points were implemented in all program areas on January 1, 1997. Language has also been added to clarify that loaded mode type tests will be implemented using "start-up" cut points on May 1, 2002.

Program Equipment

One individual suggested bringing back IM-240 testing.

Senate Bill (SB) 178, passed by the 74th Texas Legislature in 1995, repealed the commission's legal authority to implement a centralized I/M program using an IM-240 emissions test. Two years later, SB 1856 was passed which gave the commission the authority to establish the current I/M program. The current TSI program improved convenience by providing more than 2,300 testing facilities in the four I/M program counties compared to 60 facilities in the old centralized IM-240 program. The test is significantly less expensive and less time-consuming than IM-240, and is also considered effective in identifying grossly polluting vehicles. However, because the DFW nonattainment area now needs to reduce NO _x emissions, modifications to the current emissions testing program are being adopted. The ASM, or similar type test which uses a dynamometer, plus OBD testing is required for the DFW program area. An ASM type test is estimated to achieve VOC and NO _x emission reductions comparable to those achieved by an IM-240 type test, but at less than one-third of the cost, and can be implemented through the current decentralized testing network.

One individual wanted to have the option of testing annually using either the current TSI test or biennially using IM-240.

The current TSI program improved convenience by providing more than 2,300 testing facilities in the four I/M program counties compared to 60 facilities in the old centralized IM-240 program. The test is significantly less expensive and less time consuming than IM-240, and is also considered effective in identifying grossly polluting vehicles. However, because the DFW nonattainment area now needs to reduce NO _x emissions, modifications to the current emissions testing program are being adopted. The ASM or similar type test, which uses a dynamometer, plus OBD testing is required for the DFW program area. An ASM type test is estimated to achieve VOC and NOx emission reductions comparable to those achieved by an IM-240 type test, but at less than one-third of the cost, and can be implemented through the current decentralized testing network.

The emission reduction credits achieved by any type of I/M program are reduced when implemented as a biennial rather than annual test. Also, emissions testing is currently conducted as an integrated part of the safety inspection which is required annually. For these reasons, the commission has not made any changes to allow for biennial testing.

The TCEA and one individual supported ASM testing with volume mass sampling (V _MAS ), and integrated OBD testing in all 12 counties of the DFW area and stated that increased enforcement should be facilitated.

The commission agrees that a loaded mode test like ASM with integrated OBD testing is vital to the success of the I/M program. OBD testing will commence in Dallas, Tarrant, Harris, and El Paso Counties beginning in January 2001. In order to help achieve the NO _x emissions reductions needed for the DFW area to demonstrate ozone attainment, a loaded mode test like ASM testing in conjunction with OBD testing will be implemented in Dallas, Tarrant, Denton, and Collin Counties beginning May 1, 2002 and in Ellis, Johnson, Kaufman, Parker, and Rockwall Counties beginning May 1, 2003.

In its effort to ensure that the SIP strategies impose no more burden than necessary to protect health and welfare, the commission has decided not to include the counties of Hunt, Hood, and Henderson as affected counties of these rules due to their limited impact on the air quality within the DFW nonattainment area. Due to the relatively low population, percentage of commuters, and growth rate of these counties the commission has re-evaluated the need for implementing the rules in these three counties. The re-evaluation included new photochemical modeling runs which applied this rule in the nine remaining counties only. The results of these runs indicated a minor impact of including Hunt, Hood, and Henderson Counties in these rules, but also showed that the area could demonstrate attainment of the NAAQS without those reductions in emissions. However, other control measures which were proposed for these counties do have measurable benefits for attainment of the NAAQS.

The EPA requires the use of the most current version of the MOBILE model to determine the emissions reduction credits that can be claimed for an I/M program. In MOBILE5 the ASM test at start-up cutpoints achieves VOC and NOx emissions reductions comparable to those achieved by the IM-240 test at start-up cutpoints, but at less than one-third of the cost. There is currently no additional modeled benefit for using V _MAS . However, as technology evolves over time, the agency will continue to evaluate technological advances in emissions testing to ensure the best possible testing methodologies and equipment are considered in future program development. The commission is committed to helping enforce the I/M program and will continue to work with the DPS to ensure that the integrity of the program is maintained.

TADA and one individual supported OBD testing, but disagreed with the use of ASM testing and stated that it will be inconvenient and extremely expensive for the driving public.

The DFW area now needs to reduce NO _x emissions in order to achieve the ozone NAAQS. An ASM, or similar test, is estimated to achieve VOC and NO _x emission reductions comparable to those achieved by an IM-240 type test, but at less than one- third of the cost, and can be implemented through the current decentralized testing network, which includes over 2,300 testing facilities in the four I/M program counties. The test fee for a loaded mode test like ASM will not be substantially higher than the current TSI test and will not be above the average of what is currently charged nationwide for a similar test. Additionally, OBD testing is applicable only to 1996 and new vehicles. Another test such as ASM or TSI must be available in conjunction with OBD in order to capture the pre-1996 vehicles as well as vehicles for which the OBD system has failed.

TADA suggested a more equitable method of paying for emissions testing equipment is to provide a tax credit or exemption.

For vehicle emissions testing station owners, participation in the vehicle emission testing program is voluntary. Purchasing new testing equipment is a business decision and is the responsibility of the buyer at any given point in time to determine if an investment in an analyzer is worth the cost. Provisions for a tax credit or exemption for station owners would require legislative authorization and is beyond the scope of this rulemaking.

TSIA and one individual claimed that ASM equipment will cost between $74 million and $88 million based on recent real-world equipment pricing made to the TSIA members by equipment manufacturers, which exceeds the commission estimate of $60 million. TSIA also commented that there will be additional costs of technical training, higher wages for greater skilled labor, annual warranty costs, building upgrades, and increased insurance and liability claims due to dynamometer testing, and decreased throughput.

Based on information from ASM type testing equipment manufacturers, the commission estimates that roughly 25% of inspection stations in Dallas and Tarrant Counties would be able to upgrade their existing analyzers to ASM capability for $25,000. The other 75% of stations, plus stations that do not currently have analyzers, would need to purchase new ASM or similar equipment for roughly $40,000. The total estimated cost for installation of ASM type equipment in all currently operating inspection stations would be roughly $60 million.

The commission increased the proposed inspection fee from $18 to $22.50 to take into account increased operating costs such as equipment installation, higher wages, warranty costs, and other costs of doing business. Of the fee, $20.50 per test will be retained by the inspection station.

The number of vehicles requiring an annual emissions inspection is not expected to decrease in coming years, while an increasing number of vehicles each year will be inspected using the less time-consuming OBD test, encompassing over 50% of subject vehicles by 2002 and 80% by 2007. Participation in the I/M program will continue to be a business decision that each station owner will make independently.

The TSIA and two individuals stated that the program needs a guaranteed term of at least five years for return on investment, an escape clause, and an adequate fee.

The commission does not concur that there needs to be a guaranteed term of at least five years for return of investment or an escape clause. An emissions testing program is required by federal law and has been authorized to be implemented through Texas state law. The program is subject to change based on changes that could occur in the federal and/or state laws which authorize the current program. Purchasing new testing equipment is a business decision and is the responsibility of the buyer at any given point in time to determine if an investment in an analyzer is worth the cost. Furthermore, as technology evolves over time, the commission will continue to evaluate technological advances in emissions testing to ensure the best possible testing methodologies and equipment are considered in future program development.

The commission agrees that an adequate test fee should be established. Stations deciding to participate in the emissions testing program will be retaining more income per test than currently collected. This additional income can be used to offset the expenses of equipment upgrades. Based on internal cost analysis of the loaded mode testing program, the commission has approved a $22.50 emissions test fee for the new program. The combined annual safety and emissions tests are $35, which includes $22.50 for the emissions test, and $12.50 for the safety test. The station keeps $20.50 of the emissions fee and $7.00 of the safety fee for a total of $27.50 from the combined test fees. According to the cost analysis study at an emission test fee of $22.50/test, for a station to break even in five years, based just on equipment cost of $40,000, a station must perform about 43 emissions test per month. For a station to break even in five years based on equipment cost combined with an average monthly operating cost of $1,000, a station must perform about 94 tests per month.

Ellis County expressed that the cost of an ASM program stands to be way out of proportion to the benefits over the OBD test.

An OBD test achieves significant NO _x reductions, but it can only be conducted on 1996 and newer model year vehicles that are equipped with an OBD system. Pre-1996 model year vehicles must also be subject to a test capable of achieving NO _x reductions to help attain the necessary NO _x reductions in the DFW nonattainment area. A loaded test, such as ASM or IM-240, is needed to achieve NO _x reductions for pre-1996 vehicles. The ASM test achieves modeled VOC and NO _x reductions comparable to those achieved by an IM-240 test but at less than one-third of the cost.

Keating commented that the state should use V _MAS technology because it is more effective than ASM when comparing the cost of each system to the emissions reductions and SIP credits gained.

The EPA requires the use of the most current version of the MOBILE model to determine the emissions reduction credits that can be claimed for an I/M program. The current version, MOBILE5, has the capability of modeling five test types: an idle test, a TSI test, a loaded idle test, a transient (IM-240) test, and an ASM test. In MOBILE5 the ASM test at start-up cutpoints achieves VOC and NO _x emissions reductions comparable to those achieved by the IM-240 test at start-up cutpoints. There is currently no additional modeled benefit for using V _MAS . However, as technology evolves over time, the agency will continue to evaluate technological advances in emissions testing to ensure the best possible testing methodologies and equipment are considered in future program development.

TSIA expressed concern that there is no equity in asking independent businesses to make an investment in equipment without knowing the size of the tested fleet, the frequency of the test, and the number of years the program will last. They commented that few companies will participate in the program without this verification and legislative approval.

The commission does not concur that independent businesses are being asked to make an investment without knowing the size of the tested fleet or the frequency of the emissions tests. The estimated number of vehicles subject to emissions testing (by county) and the frequency of the emissions test are outlined in the approved revisions to the SIP. Section 114.50(a) states that all gasoline-powered motor vehicles 2-24 years old are subject to an annual emissions inspection. Military tactical vehicles, motorcycles, diesel-powered vehicles, dual-fueled vehicles which cannot operate using gasoline, and antique vehicles registered with the TxDOT are excluded from the program. In addition, Chapter 6 of the I/M SIP outlines test frequency and convenience and Chapter 7 outlines vehicle coverage.

Although there is no set number of years the vehicle emissions testing program will last, the emissions testing program is required by federal law and has been authorized to be implemented through Texas state law. The program is subject to change based on changes that could occur in the federal and/or state laws which authorize the current program. Purchasing new testing equipment is a business decision and is the responsibility of the buyer at any given point in time to determine if an investment in an analyzer is worth the cost. Furthermore, as technology evolves over time, the agency will continue to evaluate technological advances in emissions testing to ensure the best possible testing methodologies and equipment are considered in future program development.

TSIA expressed concern that equipment suppliers will not have adequate time to manufacture, install, and test equipment prior to program implementation.

The commission believes that 18-24 months is sufficient time to manufacture, install, and test equipment. Therefore, beginning on May 1, 2002, a loaded mode test like ASM with integrated OBD testing will commence in Dallas, Tarrant, Collin, and Denton Counties. Beginning on May 1, 2003, a loaded mode test like ASM with integrated OBD testing will commence in Parker, Ellis, Johnson, Ellis, Kaufman, and Rockwall Counties. The new program start dates will assist manufacturers in ensuring that enough certified equipment is available. The commission and the DPS staff are working closely with analyzer manufacturers to ensure that sufficient certified emissions testing equipment is available for the program start date.

Repair Program

One individual commented that failing vehicles will have to have repairs conducted at an L1 certified repair shop.

The DPS established the criteria for technicians wanting to participate in, and become a "Recognized Repair Technician." These technicians must obtain certification in the following four areas offered by the Automotive Service of Excellence (ASE): Engine Repair (Test A1), Electrical Systems (Test A6), Engine Performance (Test A8), and Advanced Engine Performance Specialist (Test L1).

The commission does not require emissions-related repairs to be completed by a recognized repair technician. A motorist has the additional options of completing the repairs himself or herself, or using a technician that is not ASE qualified. However, if the motorist wants the labor expense to count toward a waiver, the repairs must be performed by a recognized repair technician.

Program Convenience

Two individuals expressed hopes that there will be an adequate number of inspection stations so that it will not take all day to get an inspection.

The current decentralized network improved convenience over the previous centralized network by providing more than 2,300 testing facilities in the original four I/M program counties. The amended program will be implemented using the decentralized network. However, continued participation in the program as it evolves will be a business decision made by each individual station owner.

Program Network

Five individuals stated opposition to the commission reinstating a centralized IM-240-type inspection system.

The commission has no intention of mandating a centralized program. However, in order to achieve equivalent emissions reductions to those modeled for IM-240 testing, modifications to the current emissions testing program are adopted. The steering committee representing the DFW ozone nonattaiment area counties, requested that a decentralized program utilizing a loaded mode test, such as ASM, be implemented. An ASM type test is estimated to achieve VOC and NOx emission reductions comparable to those achieved by an IM-240 test, but at less than one-third the cost, and can be implemented through the same decentralized testing system as is used for the current TSI test.

One individual commented that a plan to have one company administer the test is monopolistic and not in the best interests of the citizens.

The state has no intention of implementing a centralized testing system operated by one company, as was the case with the original IM-240 program. The I/M program will continue to be implemented using the current decentralized network comprised of individual inspection station owners. Continued participation in the program as it evolves will be a business decision made by each individual station owner.

Two individuals wanted to reinstate the inspection program which was in place five years ago but was canceled.

SB 178, passed by the 74th Texas Legislature in 1995, repealed the commission's legal authority to implement a centralized I/M program using an IM-240 emissions test. Two years later, SB 1856 was passed which gave the commission the authority to establish an I/M program meeting the state's air quality needs. The TSI testing program improved convenience by providing over 2,300 decentralized testing facilities in the four I/M program counties.

Ten individuals supported tougher auto emissions testing and getting the worst polluting trucks and cars off the road.

The commission agrees that a more stringent test is necessary to help achieve the NO _x reductions necessary for the DFW area. The program as adopted is more stringent in that it evaluates NO _x emissions.

One individual recommended a quick tailpipe test to catch vehicles that are out of tune.

There is no quick tailpipe test that can be utilized to determine why a car is out of tune. However, beginning on January 1, 2001, the current TSI tailpipe test will be replaced with the OBD test for model year 1996 and newer vehicles. OBD utilizes a computer link to download information on a vehicle's malfunctioning emissions system directly from the vehicle computer which can be used as a diagnostic tool to help determine why a vehicle may be operating out of tune. Model year 1995 and older vehicles will be required to submit to the appropriate tailpipe test to ensure compliance with I/M program requirements.

The LWV-Tarrant, ALA, ALA-Dallas, Sierra-Fort Worth, CSE, Sierra-Dallas, DAR, SEED, TCE, TCWA, TPC, and 215 individuals supported ASM testing with integrated OBD testing in all 12 counties of the DFW CMSA (which is included in the Citizen's Implementation Plan).

The commission agrees that a loaded mode test, such as ASM with integrated OBD testing, is vital to the success of the I/M program. OBD testing will commence in Dallas, Tarrant, Harris, and El Paso Counties beginning in January 2001. In order to help achieve the NO _x emissions reductions needed for the DFW area to demonstrate ozone attainment, an OBD test in conjunction with a loaded mode test such as an ASM-2 test, or a vehicle emissions test that meets SIP emission reduction requirements and is approved by EPA, will be implemented in Dallas, Tarrant, Denton, and Collin Counties beginning May 1, 2002 and in Ellis, Johnson, Kaufman, Parker, and Rockwall Counties beginning May 1, 2003.

In its effort to ensure that the SIP strategies impose no more burden than necessary to protect health and welfare, the commission decided not to include the counties of Hunt, Hood, and Henderson as affected counties of these rules due to their limited impact on the air quality within the DFW nonattainment area. Due to the relatively low population, percentage of commuters, and growth rate of these counties, the commission re-evaluated the need for implementing the rules in these three counties. The re-evaluation included new photochemical modeling runs which applied these rules in the nine remaining counties only. The results of these runs indicated a minor impact of including Hunt, Hood, and Henderson Counties in these rules, but also showed that the area could demonstrate attainment of the NAAQS without those reductions in emissions. However, other control measures which were proposed for these counties do have measurable benefits for attainment of the NAAQS.

One individual supported emissions testing of all vehicles driving into the United States from Mexico.

The regulation of air emissions for international traffic is beyond the scope of this rulemaking; therefore, the commission made no change in response to this comment.

The CoC-Fort Worth strongly expressed that vehicles are the largest source of pollution in the DFW area and that every citizen with a vehicle must make every reasonable effort to reduce the emissions.

The commission agrees that vehicles are a source of pollution in the DFW area. On-road mobile source emissions account for approximately 51% of NOx emissions, 55% of carbon monoxide (CO) emissions, and 28% of VOC emissions. The commission therefore, is adopting a package of rules, including the I/M rules, to address emissions from vehicles. In addition, the commission and the DPS plan to implement improved inspector and technician training, public service announcements, brochures at the inspection stations, media coverage, and other outreach projects with the assistance of the local councils of government to inform citizens of the importance of having their vehicles tested.

One individual suggested that vehicle owners report the county in which they work or go to school, and if that county has a more stringent inspection standard, the vehicle must be inspected in the county with higher standards.

The state I/M program does not collect specific vehicle travel or destination data. All 2-24 year old gasoline-powered vehicles registered in an I/M program area, as well as vehicles that operate more than 60 calender days per testing cycle in an I/M program area, are required to comply with emissions standards for such an area. Vehicles must comply with the safety and emissions testing program to be issued a safety certificate. As an additional enforcement mechanism, remote sensing is used to identify high-emitting vehicles operating in an I/M program area. Once a high-emitting vehicle is identified, the owner of the vehicle is instructed by written notice to bring the vehicle in to a state-certified emissions testing station for a verification emissions test and to make necessary repairs to bring the vehicle into program compliance.

One individual supported the annual testing.

The commission agrees. Emission reduction credits achieved by any type of I/M program are reduced significantly when implemented as a biennial rather than annual test. Also, emissions testing currently conducted as an integrated part of the annual safety inspection is more convenient for the motorist.

One individual stated that more stringent testing needs to be started by January 2002.

The commission is adopting an emissions testing system that has the capability to identify NO _x emissions. The current TSI analyzer is not capable of testing for NO _x emissions. The loaded mode type test in conjunction with the implementation of OBD testing will allow for the identification of vehicles emitting excess hydrocarbons (HC), CO, and/or NO _x . In order to establish a proper testing network and ensure equipment availability, the loaded mode test equipment will be phased into the most populous counties of Dallas, Tarrant, Collin, and Denton beginning May 1, 2002. The remaining five counties, Ellis, Johnson, Kaufman, Parker, and Rockwall, will begin loaded mode testing May 1, 2003.

One individual expressed opposition to the proposed program because it will be hugely expensive in both actual cash outlay and in lost time/productivity. The individual also commented that it is based on outdated ideas that cars require periodic inspection of pollution equipment to be sure they are "tuned-up."

Although implementing the proposed changes to the vehicle emissions testing program may seem inordinately expensive to some individuals, cleaner air provides economic benefits to the community, such as fewer sick days off, lower medical costs, and fewer pollution-associated illnesses. In addition, if federal ozone reduction requirements are not met, businesses attracted by the state's quality of life would be adversely affected by sanctions imposed by the federal government.

Two individuals commented that the commission does not have the will nor the manpower to police rules requiring every vehicle to go in for testing and mandatorily removing super emitters (extremely high-emission vehicles).

Enforcement of the program is the responsibility of the DPS, TxDOT, and the commission. Vehicles registered in an I/M program area must comply with the safety and emissions testing program to be issued a safety certificate. The commission, TxDOT, and DPS implemented a vehicle re-registration denial enforcement element for vehicles that fail to comply with the emissions testing program. Remote sensing is used to identify high-emitting vehicles commuting into an area and as an additional enforcement mechanism to identify high-emitting vehicles that have not complied with the program. Once a high-emitting vehicle is identified, the owner of the vehicle is instructed by written notice from the DPS to bring the vehicle in to a state-certified emissions testing station for a verification emissions test and to make necessary repairs to bring the vehicle into program compliance. Failure to comply with the notice is a Class C misdemeanor. Local law enforcement officials are responsible for ensuring that vehicles operating on public roads have a valid registration sticker and safety certificate.

TADA and four individuals commented that small business owners will decline to participate is an ASM program because the equipment is more expensive, higher wages will have to be paid for more qualified inspectors, and insurance and liability claims will increase due to dynamometer testing.

The commission adjusted the proposed emissions test fee for the new program in order to cover additional costs involved in the use of loaded mode test equipment. These increased costs include labor, training, warranties, insurance, and consumable items (such as calibration gases) used in conducting emissions tests. Based on internal cost analysis of the proposed loaded mode testing program, the commission approved a $22.50 emissions test fee for the new program. According to the cost analysis study at a fee of $22.50/test, for a station to break even in five years, based just on equipment cost of $40,000, a station must perform about 43 emissions test per month. For a station to break even in five years based on equipment cost combined with an average monthly operating cost of $1,000, a station must perform about 94 tests per month. Continued participation in the program as it evolves will be a business decision made by each individual station owner. However, staff are in discussion with analyzer manufacturers to devise ways to relieve the economic burden for inspection station operators at the outset of the program.

One individual stated opposition to the proposed vehicle inspection program for the DFW area, because the program has too high of a financial burden on individuals that must drive older, less efficient vehicles for their livelihood.

Vehicles that are properly maintained should have no problem passing the emissions test regardless of their age. In the event that repairs are necessary, the commission acknowledges that these vehicle repairs may be costly, but there are mechanisms in place (waivers and extensions) that help alleviate the cost of emissions repairs for those who need help. The vehicle emissions testing program includes two waiver options: the minimum expenditure waiver and the individual vehicle waiver. The minimum expenditure waiver is available to those who have made repairs to their vehicle within the established criteria and met the dollar limits established by EPA rule. The individual vehicle waiver is for those who cannot meet emissions standards despite every reasonable effort by the motorist. In addition to these two waivers, the low-income time extension is available for those who can demonstrate a financial inability to either afford adequate repairs or to meet the applicable minimum expenditure waiver amount. The waivers are a way to ensure that motorists who are making a "good faith" effort to comply with the I/M program requirements do not incur excessive repair costs, are not excessively inconvenienced, or are not denied re-registration of their vehicle.

Cleburne and Greenville supported the use of OBD testing systems on gasoline-powered on-road vehicles; however, along with the Hood County, they commented that the requirements to do ASM testing in an I/M program will be burdensome to the small businesses and citizens of rural counties and will not be cost effective for an inspection facility due to the relatively low number of vehicles registered in rural counties. Additionally, the commenters stated that ASM testing should be limited to the four designated nonattainment counties. Since those comments were submitted the City of Cleburne has submitted a resolution requesting inclusion in the proposed I/M program which includes ASM testing.

An OBD test will achieve significant NO _x reductions, but can only be conducted on 1996 and newer model year vehicles that are equipped with an OBD system. Pre-1996 model year vehicles must also be subject to a test capable of achieving NO _x reductions to help attain the necessary NO _x reductions in the DFW nonattainment area. A loaded test, such as ASM, is needed to achieve NOx reductions for pre-1996 vehicles. The ASM test achieves modeled VOC and NO _x reductions comparable to those achieved by an IM-240 test but at less than one-third of the cost.

Based on information from ASM type testing equipment manufacturers, the commission estimates that stations would need to purchase new ASM or similar equipment for roughly $40,000. Participation in the program as it evolves will be a business decision made by each individual station owner. However, staff is in discussion with analyzer manufacturers to devise ways to relieve the economic burden for inspection station operators at the outset of the program.

Expansion of the program into surrounding CMSA counties is necessary for reduction of NO _x emissions to be able to demonstrate attainment with the NAAQS for ozone for the DFW nonattainment area. Since they have opted in, the program will cover Johnson County including the City of Cleburne.

One individual commented that the future implementation of OBD III will virtually eliminate vehicle emissions testing before new testing machines required by the proposal have a chance to pay a break-even return on investment.

OBD-III was a pilot program in California that tested the feasibility of using on-vehicle radio transponders in conjunction with roadside readers, station networks, and satellites to monitor and download OBD fault codes directly to regulators. The transmission of fault codes would be in real-time and would decrease the time between fault detection and the repair of the vehicle. Although the technology is available to support an OBD-III program, there are several legal and public hurdles that would make it difficult for this type of testing system to be supported by the public. While the EPA requires OBD testing for model year 1996 and newer vehicles commencing by January 1, 2001, the commission has no plans to implement an OBD-III type test.

Waxahachie requested that a vehicle I/M program consisting of an OBD test only and not an ASM test be implemented within the City of Waxahachie. Subsequently, the city submitted a resolution requesting inclusion in the ASM and OBD program.

The commission believes there is a need to conduct emissions testing on pre-1996 vehicles, to which OBD is not applicable, in order to achieve the necessary NO _x emission reductions for a program area. The commission does not have the authority to implement an I/M program confined within the boundaries of a single city. The Texas Transportation Code, §548.301(b) and the Texas Health and Safety Code, §382.037(c) allow the commission to establish by rule an I/M program at the county level, provided the county and its most populous municipality adopt a resolution requesting such a program. Since both Waxahachie and Eillis County have submitted such resolutions, the program will be implemented throughout Ellis County.

AIAM supported the proposed ASM/OBD testing program with the following provisions: exempt vehicles for testing until they are five years old (except on change of ownership), test on a biennial frequency, and require change of ownership testing.

The commission appreciates the support for the vehicle emissions testing program. The emissions testing program tests vehicles 2-24 years old. These vehicles account for the vast majority of vehicles on the road and the vehicle miles traveled, which have a direct correlation to the impact on air quality. In reference to biennial testing, the emission reduction credits achieved by any type of I/M program are reduced when implemented as a biennial rather than annual test. In order to meet attainment goals by 2007 for the DFW area, maximum emissions reductions are required. Also, emissions testing is currently conducted as an integrated part of the safety inspection which is required annually. For these reasons, the continuation of annual testing is considered an integral part of a successful I/M program. Test on resale is not necessary to meet the I/M program requirements of the FCAA and does not produce additional modeled emissions reduction benefits. The commission does recognize that the test on resale component is an additional enforcement tool and has consumer protection values, and may consider this component in future program enhancements.

TSIA recommended implementation of their Clean Cars 2000 I/M plan, which includes the following: (1) upgraded TX96 Two-Speed Idle analyzer; (2) a five-gas bench; (3) lower cut-points for the TSI test; (4) OBD testing for 1996 and newer; (5) gas tank/gas cap pressure test; (6) functional exhaust gas recirculation (EGR) valve test; (7) model year coverage from two years old to 1975 model year; (8) 0.5% waiver rate; (9) 30% failure rate for all models; (10) remote sensing of 15% of vehicles in core counties and 10% of vehicles in commuter area; (11) low-income assisted repair (wheels to work); (12) statewide electronic transfer of safety/emission test data; (13) a 98% compliance rate; and (14) expansion of testing program to include additional counties divided into core, maintenance, commuter, and transitional groups. TSIA also proposed specific testing strategies for each group.

The Clean Cars 2000 Plan contains several elements common to the commission safety and emissions testing program. These include OBD test for 1996 and newer vehicles, check engine light function check, visual emissions component check, statewide gas cap pressure check, aggressive emissions repair technician training, program evaluation through mass emissions transient testing, and real-time transfer of emissions/safety data. In addition to the design elements common to both programs, TSIA recommended the following: (1) upgraded TX96 TSI analyzer; (2) a five-gas bench; (3) lower cutpoints for the TSI test; (4) gas tank/gas cap pressure test; (5) functional EGR valve test; (6) model year coverage from two years old to 1975 model year; (7) 98% compliance rate; (8) 0.5% waiver rate; (9) 30% failure rate for all vehicles; (10) remote sensing of 15% of vehicles in core counties and 10% of vehicles in commuter area; (11) low-income assisted repair (wheels to work); (12) statewide electronic transfer of safety/emission test data; and (13) expansion of testing program outside of state recommended core counties.

Upgraded TX96 TSI Analyzer

TSIA made no mention of what type of upgrades would be included in the upgrade from the TX96 to a TX2000 analyzer other than going to the five-gas bench. The commission upgrade to analyzer equipment includes a five-gas bench, dynamometer testing, OBD testing, tethered gas cap testing, and bar code scanning.

Five-gas Bench

TSIA recommended the use of a five-gas bench with the upgraded TSI emissions testing analyzers with OBD, in lieu of upgrading existing testing equipment in the DFW region to a loaded mode dynamometer test with OBD and for the proposed TSI-plus OBD system in El Paso and Harris Counties. Using a five-gas bench analyzer will allow for detection of NO _x , but using a TSI procedure does not allow the NO _x to be quantified. Idling vehicles do not produce much NO _x . Only by putting a vehicle under a load, transient or steady-state, can the vehicle engine produce NO _x in amounts similar to on-road conditions, and that can be more accurately quantified. By placing the vehicle under a load, the reproduction of high operating temperature and pressure needed to quantify NO _x is provided. Under the EPA current MOBILE5 model, the state would receive no more NOx benefits from implementing the TSI/five-gas bench combination than for implementing the current TSI test.

Lower Cutpoints for Two-speed Idle Test

The current TSI test uses the default cutpoints set by the EPA. The MOBILE5 model does allow non-default cutpoints to be entered for the TSI test; however, the EPA does not have a data file containing credits for any cutpoints other than the default. For this reason, an alternate data file would have to be created establishing credits for non-default cutpoints. Substantial testing of vehicles and justification for the alternate credits at tighter cutpoints would be required for the EPA to accept the new cutpoints. However, lowering the TSI cutpoints will not allow the measurement of NO _x because when the vehicle engine is idling, the temperature and pressure in the combustion chambers are not high enough to produce a sufficient amount of measurable NO _x .

Gas Tank/Gas Cap Pressure Test

Based on conversations with representatives from Snap-on Diagnostics, gas tank pressure/purge test cannot be added to the current analyzers used for the TSI test because of software problems and conflicts. The cost to add the pressure/purge test to ASM type units would be approximately $2,100. Although this test would be effective in detecting fugitive HC emissions escaping from bad gas tank caps or fractures in the tank system, and would provide additional HC credits, the test would not check or gain credit for NO _x .

Functional EGR Valve Test

According to the EPA, performance of a functional EGR test does not provide any NO _x credits beyond what is given for the visual EGR check already existing in the current TSI test. Research indicates a visual or functional EGR check may detect malfunctions in model year 1980 and older vehicles. However, in newer technology vehicles the exhaust gas recirculation system is a more integral process of the engine, so a functional or visual check of just one component or valve cannot necessarily indicate whether the EGR system is functioning properly. Also according to the EPA, research indicates that EGR valve failure does not necessarily lead to excess NO _x emissions. For these reasons, the EPA does not grant any additional NO _x credit in the MOBILE model for a functional EGR check. The commission will include in its upcoming research on various loaded mode test methodologies, such as ASM and BAR31, the effectiveness of an EGR functionality test in achieving NO _x reductions.

Model Year Coverage

TSIA proposed emissions testing on vehicles two years old to the 1975 model year. The I/M program tests vehicles 2-24 years old, which includes the testing of 1976 model year vehicles. Inclusion of one additional year in testing coverage will make no modeled difference in emission reductions. The registration distributions used for MOBILE modeling group all vehicles 24 years and older together; therefore, modeling program coverage of 2-24 years will give the same results as modeling program coverage of 2-25 years. Even modeling program coverage of 2-23 years, so that the 24 and older group is not included in testing, has only a slight impact on reduction credits because there is such a small percentage of vehicles in the 24 and older grouping (only 1.4% of light-duty gas vehicles in the Dallas/Tarrant registration distribution).

98% Compliance Rate

The default compliance rate in the MOBILE model is 96%. This default rate is normally used for modeling purposes. Current I/M program data and a 1996 vehicle safety inspection sticker compliance rate survey for Dallas, El Paso, Harris, and Tarrant Counties (Appendix J of the SIP) suggests a compliance rate of approximately 96%. Compliance rate data collected by the commission does not support the use of a compliance rate higher than 96% for modeling purposes, and the commission will continue to monitor compliance rate data.

0.5% Waiver Rate

TSIA proposed a waiver rate of 0.5%. A default waiver rate of 3.0% is normally used in modeling scenarios. The actual waiver rate for the current TSI program is approximately 0.25%. An increase in the waiver rate is expected with the implementation of a $450 minimum expenditure waiver amount in all I/M program areas.

30% Failure Rate for All Vehicles

MOBILE modeling requires input of a stringency rate which refers to the initial test failure rate for pre-1981 model year passenger cars and pre-1984 light-duty trucks. The stringency rate is used in the model to determine the credits obtained for the emissions testing of these older model vehicles. The default stringency rate used in modeling is 20%. The TSIA program calls for a 30% failure rate for all vehicles. More stringent cutpoints would have to be implemented to realize an increased failure rate for a TSI test. The current TSI test uses the default cutpoints set by the EPA. The MOBILE5 model does allow non-default cutpoints to be entered for the TSI test; however, the EPA does not have a data file containing credits for any cutpoints other than the default. For this reason, an alternate data file would have to be created establishing credits for non-default cutpoints. Substantial testing and justification for the alternate credits at tighter cutpoints would be required for the EPA to accept the new cutpoints. Tightening the TSI cutpoints still will not address the need for NO _x reductions. The TSI test does not allow for the measurement of NO _x because when the vehicle engine is idling, the temperature and pressure in the combustion chambers are not high enough to produce a sufficient amount of measurable NO _x .

Remote Sensing of 15% of Vehicles in Core Counties and 10% of Vehicles in Commuter Area

The I/M program uses remote sensing to identify high-emitting vehicles commuting into nonattainment areas. The state will increase the use of remote sensing in all program areas to detect any high emitting vehicles, not just those commuting. The EPA plans to include the capability for modeling remote sensing programs in MOBILE6 which is still being developed. Remote sensing of vehicles registered within the I/M counties is used as an enforcement tool, and therefore does not gain any further emissions reduction credit.

Low Income Assisted Repair (Wheels to Work)

A low-income repair assistance program could potentially reduce the number of low income time extensions and minimum expenditure waivers issued and possibly increase compliance with the program. No direct credits for a low income repair assistance program can be modeled in the MOBILE model; however, the waiver rate and compliance rate can be adjusted.

Statewide Electronic Transfer of Safety/Emission Test Data

During the Texas 76th Legislative Session, the legislature attempted to implement automation of the safety test statewide; however, the measure was vetoed by the governor. TSIA stated that implementation of electronic transfer of safety/emission test data would eliminate the need for registration denial. The commission does not believe this to be the case. Registration denial is one of the enforcement components of the emission testing program and is required by the EPA.

Expansion of Testing Program Outside of State Recommended Core Counties

Expansion of the I/M program to include emissions testing in Bexar, Brazoria, Travis, Waller, Ellis, Henderson, Hood, Hunt, Johnson, Kaufman, Parker, Rockwall, Wise, Bastrop, Caldwell, Comal, Guadalupe, Gregg, Harrison, Hays, Nueces, Rusk, San Patricio, Smith, and Upshur Counties as suggested by TSIA, is beyond the scope of this rulemaking and would require legislative authority absent a federal requirement. However, the Texas Transportation Code, §548.301(b) and the Texas Health and Safety Code, §382.037(c) allow the commission to establish by rule an I/M program in any county provided the county and its most populous municipality adopt a resolution requesting such a program. The commission has included every county for which these resolutions have been submitted.

One individual stated that annual vehicle emissions testing is an inconvenience because people must drive to a test station when there is remote sensing technology that could screen out clean vehicles from the outset.

Implementation of a decentralized system of inspection stations was selected as the best method to ensure availability of a sufficient number of testing facilities throughout the participating counties. "Clean-screening," or exempting clean vehicles from annual emissions testing using remote sensing, is under study in other states and may be available in the future provided the technology is proven both reliable at correctly identifying vehicle emissions and cost- effective to the citizens of Texas.

One individual expressed concern that too much emphasis is being placed on the inspection side of I/M instead of on maintenance.

Effective emission-related repairs are essential to the overall goals of the Texas I/M program. The inspection process alone will only identify those vehicles that have unacceptable emissions levels. Pollution from mobile sources is reduced only through effective emissions repairs. The commission agrees than an effective maintenance program will result in substantial reductions in emissions from motor vehicles.

One individual supportrf centralized testing, and expressed concern about fraud and enforcement.

The commission believes a decentralized test network is more acceptable to the public. The current decentralized I/M program has mechanisms in place to prevent fraud and ensure compliance, such as referee challenge facilities, citations, fines, registration denial, and covert audits.

Lewisville supported OBD testing beginning in 2001; however, they proposed that ASM with V _MAS be adopted no earlier than 2003, and only if the EPA provides information that the air quality in the North Texas CMSA is not improving.

The commission appreciates the city's support of OBD testing which will be implemented in Dallas, Tarrant, Harris, and El Paso Counties beginning in January 2001. In order to help achieve the NO _x emissions reductions needed for the DFW area to demonstrate ozone attainment, a loaded mode test like ASM testing in conjunction with OBD testing will be implemented in Dallas, Tarrant, Denton, and Collin Counties beginning May 1, 2002, and in Ellis, Johnson, Kaufman, Parker, and Rockwall Counties beginning May 1, 2003. In its effort to ensure that the SIP strategies impose no more burden than necessary to protect health and welfare, the commission decided not to include the counties of Hunt, Hood, and Henderson as affected counties of these rules due to their limited impact on the air quality within the DFW nonattainment area. Due to the relatively low population, percentage of commuters, and growth rate of these counties, the commission re-evaluated the need for implementing the rules in these three counties. The re-evaluation included new photochemical modeling runs which applied this rule in the nine remaining counties only. The results of these runs indicated a minor impact of including Hunt, Hood, and Henderson Counties in these rules, but also showed that the area could demonstrate attainment of the NAAQS without those reductions in emissions. However, other control measures which were proposed for these counties do have measurable benefits for attainment of the NAAQS.

In regard to the use of a loaded mode test like ASM with V _MAS , there is currently no additional modeled benefit for using VMAS . However, as technology evolves, the agency will continue to evaluate technological advances in emissions testing to ensure the best possible testing methodologies and equipment are considered in future program development. Ozone levels will continue to be monitored at designated sites throughout the state using special ambient air monitoring equipment.

One individual stated that testing a car on a dynamometer requires individuals who are very knowledgeable in running a dynamometer and suggested that the commission come up with a proposal to get cars tested annually and tuned-up because this will reduce emissions.

An intensive training program will be implemented for all inspectors operating a dynamometer type emissions test. A training program will include proper use, safety, and calibration of dynamometers. Currently, all subject vehicles registered in and operated more than 60 calendar days a year in an I/M program area are required to take an emissions test. As a result of emissions testing, failing vehicles are required to be repaired. The repair may involve a tune-up, or replacement of an emissions-related part in order to comply with emissions testing requirements.

State Compliance

The EPA expressed concern that the state must obtain the necessary commitments from the outlying counties to implement the proposed vehicle I/M program, or will be required to make up equivalent emission reductions from other sources.

The commission believes the SIP and rule packages being adopted, which includes a revised I/M program, will achieve the emission reductions needed for the DFW area to demonstrate attainment. The commission also believes the counties and most populous municipalities within the EDFW program area are committed to participating in the revised I/M program. However, an I/M program will not be implemented in any of the counties that comprise the EDFW program area until the county and its most populous municipality submit a resolution requesting the program.

Motorist Compliance

One individual commented that no one in El Paso or the federal government certifies that vehicles owned by military personnel have the required pollution control equipment upon return to Texas.

Current commission rules state that federal employees must show proof of compliance with I/M program requirements if their stay on the federal facility exceeds 60 calendar days per year. The federal government also requires that all vehicles owned by service members entering the United States be equipped with a catalytic converter. All vehicles registered in Texas must pass an annual safety inspection which includes a visual inspection to assure all required pollution control equipment is present and shows no evidence of tampering. TxDOT requires that vehicles displaying Armed Forces license plates to register their vehicle within 45 days upon entering the state. If the service member displays foreign plates, i.e., German plates, the member must register the vehicle immediately and meet all pollution control and emission requirements.

Four individuals expressed concern that older model vehicles may be denied registration or scrapped because the owners are unable to afford repairs and cannot afford the cost of a newer vehicle, and that the test is unreliable so a new vehicle may not pass.

Motorists will not be required to scrap their vehicles. Vehicles that are properly maintained should have no problem passing the emissions test. In the event that repairs are necessary, the commission acknowledges that these vehicle repairs may be costly, but there are mechanisms (waivers and extensions) in place that help alleviate the up-front cost of emissions repairs. The vehicle emissions testing program includes two waiver options: the minimum expenditure waiver and the individual vehicle waiver. The minimum expenditure waiver is available to those who have made repairs to their vehicle within the established criteria and met the dollar limits established by EPA rule. The individual vehicle waiver is for those motorists who cannot meet emissions standards despite every reasonable effort. In addition to these two waivers, the low income time extension is available for those who can demonstrate a financial inability to either afford adequate repairs or to meet the applicable minimum expenditure waiver amount. This extension is available for only one test cycle and may not be issued to the same vehicle two test cycles in a row. The waivers are a way to ensure that motorists who are making a "good faith" effort to comply with the I/M program requirements do not incur excessive repair costs, are not excessively inconvenienced, or are not denied re-registration of their vehicle.

Regarding test reliability, the EPA has approved both ASM and TSI testing methodologies in a number of I/M programs nationwide. Any subject vehicle that does not meet the vehicle emissions requirements of these tests will fail regardless of the age of the vehicle.

Two individuals recommended that the police issue tickets to motorists in the 12-county DFW area who are driving visibly smoking vehicles.

Texas Transportation Code, Chapter 548, Subchapter F, §548.306, specifies that a motor vehicle registered in an ozone nonattainment area commits an offense if visible smoke remains suspended in the air ten or more seconds before fully dissipating. Therefore, law enforcement personnel may issue a citation to the registered owner of a vehicle that produces excessive visible smoke. In addition, a law enforcement officer who has probable cause to believe that this offense has been committed, has the authority to issue the driver of the vehicle an informative citation and explain that the registered owner of the vehicle may receive notice in the mail about the violation. Addionally, 30 TAC §111.111(a)(5) states that motor vehicles shall not have visible exhaust emissions for more than ten consecutive seconds. This rule applies statewide and can be enforced by local law enforcement agencies.

One individual commented that older cars do not necessarily pollute, but that any car (new or old) that is poorly maintained will pollute; and therefore, all motorists need to be responsible for maintaining their vehicles.

The commission agrees that it is the responsibility of the motorists to properly maintain their vehicles. A properly maintained vehicle, old or new, should meet all emissions requirements.

Modeling/Good Faith Efforts

TSIA and one individual stated that it is unclear that ASM testing as proposed for the DFW area will have any positive effect on cleaning the air, and commented that the EPA should be required to prove that ASM testing will provide the pollution reductions claimed in the EPA MOBILE model.

The EPA requires that states use the most current version of their MOBILE model to estimate the emissions reduction credits achieved by I/M programs. In the MOBILE5 model, an ASM-2 (50/15-25/25) test using start-up cutpoints achieves VOC and NO _x reductions comparable to those achieved by an IM-240 test at start-up cutpoints. EPA devised the I/M credits for ASM test procedures based on a combination of the data from the California El Monte Study and EPA testing in Phoenix, Arizona. The commission believes that a loaded test, such as ASM, will achieve significantly more real-world NO _x reduction benefits than the TSI test.

Geographic Coverage

One individual requested to know if the impact of the vehicles from surrounding communities has been evaluated and if any ideas or plans are being presented to deal with this aspect of the pollution problem in the DFW Metroplex.

The emissions from vehicles in the surrounding communities and counties (Collin, Denton, Parker, Hood, Johnson, Ellis, Henderson, Kaufman, Rockwall, Hunt) have been considered in planning the I/M program. Currently in the DFW area, vehicle emissions testing is limited to Dallas and Tarrant counties. The I/M program has been modified to include Collin and Denton Counties beginning May 1, 2002; and Parker, Johnson, Ellis, Kaufman, and Rockwall Counties beginning May 1, 2003. The I/M program will continue to include remote sensing to identify high-emitting commuting into the area. In addition, remote sensing of vehicles operating within I/M program areas will also be conducted.

In its effort to ensure that the SIP strategies impose no more burden than necessary to protect health and welfare, the commission decided not to include the counties of Hunt, Hood, and Henderson as affected counties of these rules due to their limited impact on the air quality within the DFW nonattainment area. Due to the relatively low population, percentage of commuters, and growth rate of these counties the commission re-evaluated the need for implementing the rules in these three counties. The re-evaluation included new photochemical modeling runs which applied these rules in the nine remaining counties only. The results of these runs indicated a minor impact of including Hunt, Hood, and Henderson Counties in these rules, but also showed that the area could demonstrate attainment of the NAAQS without those reductions in emissions. However, other control measures which were proposed for these counties do have measurable benefits for attainment of the NAAQS.

Dallas, SCATC, SPAC, and 18 individuals expressed favor for a mandatory I/M program in the 12-county DFW CMSA. Additionally, Dallas supported remote sensing in the 12-county DFW CMSA.

The commission agrees that an I/M program in the DFW program area is vital to the overall success of a clean air strategy. In order to help achieve the NO _x emissions reductions needed for the DFW area to demonstrate ozone attainment, a loaded mode test like ASM testing in conjunction with OBD testing will be implemented in Dallas, Tarrant, Denton, and Collin Counties beginning May 1, 2002. The commission cannot mandate surrounding counties unless the county and the most populous municipality have submitted a resolution to the commission requesting inclusion in the Texas I/M program.

The commission agrees that remote sensing has a useful role to play in detecting high- emitting vehicles in the I/M program areas, and the I/M program will continue to use remote sensing to identify gross polluters.

Other Issues

Four individuals commented that stricter vehicle emission standards would not help clean the air in El Paso County unless vehicles from New Mexico and Cuidad Juarez, Chihuahua, Mexico that come into El Paso County are required to meet the same standards.

The suggestion that vehicles from New Mexico, Cuidad Juarez, and Chihuahua, Mexico meet the same standards is beyond the scope of this rulemaking; therefore, the commission made no change in response to this comment.

Two individuals commented that tougher testing is not needed to find polluters, but that once a polluting vehicle is identified by the current testing program it should not be allowed to continue operating because it costs too much to fix.

The commission is adopting an emissions testing system that has the capability to identify NO _x emissions. The current TSI analyzer is not capable of testing for NO _x emissions. The loaded mode type test in conjunction with the implementation of OBD testing will allow for the identification of vehicles emitting excess HC, CO, and/or NO _x . If a vehicle fails the emissions test for any pollutant, the vehicle must be repaired and pass a re-test or qualify for a low-income time extension, individual vehicle waiver, or a minimum expenditure waiver. A waiver or extension does not exempt a motorist from meeting the requirements of the I/M program, but rather gives the individual the time necessary to properly have the vehicle repaired. In addition, waivers are a way to ensure that motorists are making a "good faith" effort to comply with the I/M program requirements and do not incur excessive repair costs, are not excessively inconvenienced, or denied re-registration of their vehicle. Since waivers or extensions are not extended past one test cycle, a non-compliant vehicle must be brought into compliance or the vehicle cannot be legally driven on public roadways. Vehicles that do not meet the safety and emission test requirements are not issued a safety certificate and will be denied re-registration.

Pennzoil/Quaker State requested the commission petition the EPA to coordinate corporate average fuel economy testing with the time of the recommended oil change to capture the true fuel economy of the engine.

The suggestion is beyond the scope of this rulemaking.

One individual wanted to mandate that every vehicle (personal or commercial) receive a thorough, patented "Best Engine Care"(BEC) engine cleaning every three years or 30,000 miles, which ever comes first.

The suggestion to mandate a BEC maintenance procedure that motorists must adhere to is beyond the scope of this rulemaking.

Subchapter A. DEFINITIONS

The Texas Natural Resource Conservation Commission (commission) adopts new §114.6 (Low Emission Fuel Definitions), §114.312 (Low Emission Diesel Standards), §114.313 (Designated Alternative Limits), §114.314 (Registration of Diesel Producers and Importers), §114.315 (Approved Test Methods), §114.316 (Monitoring and Recordkeeping Requirements), §114.317 (Exemptions to Low Emission Diesel Requirements), and §114.319 (Affected Counties and Compliance Dates). The commission adopts these revisions to Chapter 114 and to the State Implementation Plan (SIP) in order to control ground-level ozone in the Dallas-Fort Worth (DFW) ozone nonattainment area. Sections 114.6, 114.312, 114.314, 114.316, 114.317, and 114.319 are adopted with changes from the proposed text as published in the December 31, 1999 issue of the Texas Register (24 TexReg 11916). Section 114.313 and §114.315 are adopted without changes and will not be republished.

Subchapter H is renamed to "Low Emission Fuels." New Division 1 (Gasoline Volatility) includes existing §§114.301, 114.302, and 114.305-114.309 and new Division 2 (Low Emission Diesel) includes new §§114.312-114.317 and 114.319. Subchapter A (Definitions) includes new §114.6.

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

The DFW ozone nonattainment area, an area defined by Collin, Dallas, Denton, and Tarrant Counties, was originally designated "moderate" under the Federal Clean Air Act (FCAA) Amendments of 1990 (42 United States Code (USC)) and thus was required to attain the one-hour national ambient air quality standard (NAAQS) for ozone by November 15, 1996. As required by the FCAA, the state submitted an attainment demonstration plan in 1994 which projected attainment of the ozone NAAQS by 1996. This plan was based on a volatile organic compound (VOC) reduction strategy. DFW did not attain the ozone NAAQS in 1996. The United States Environmental Protection Agency (EPA) is authorized to redesignate an area to the next higher classification ("bump up") if the area fails to attain by the required date. In March 1998, in accordance with 42 USC, §7511(b)(2), the EPA reclassified the DFW area from moderate to serious, based on monitored exceedances of the ozone NAAQS between 1994 and 1996. The reclassification required the state to submit a revised SIP that demonstrates that the ozone NAAQS will be met in DFW by November 15, 1999. Because the DFW area continued to exceed the ozone NAAQS in 1999, the EPA may bump up the area to the severe classification. Regardless, the EPA and 42 USC, §7410 and §7502(a)(2), require the state to submit a revised SIP which demonstrates that the area will attain the ozone NAAQS as expeditiously as practicable. The rules adopted for DFW in this notice are one element of the ozone attainment demonstration SIP for DFW being adopted concurrently in this issue of the Texas Register . The commission plans to submit this SIP to the EPA in April, 2000.

In 1996, the commission began to develop new modeling for the DFW area and now is using newer air quality models with improved meteorological and emission inputs. The newer modeling since 1996 shows that reductions of oxides of nitrogen (NO _x ) in the DFW area and regionally will be necessary to attain the ozone NAAQS. The current modeling also shows that achieving the ozone NAAQS in the DFW area will require strenuous effort because the area's rapid growth has resulted in increasing amounts of emissions due to increased levels of activity in the area. The emissions from increased activity are offsetting the emission reductions being achieved from new emission standards applicable to the on-road and non-road engine source categories which dominate the emissions inventory in the DFW area.

The emission reduction requirements adopted as part of this SIP package are the outcome of a development process which involved the EPA, the commission, local elected officials, citizens, industrial stakeholders, air quality researchers, and hired consultants. Local officials from the DFW area have formally submitted a resolution to the commission requesting the inclusion of many specific emission reduction strategies, including the one contained in these rules.

The NO _x reductions required for the area to attain the ozone NAAQS have been estimated by extensive use of sophisticated air quality grid modeling which, because of its scientific and statutory grounding, is the chief policy tool for designing emission reductions. Title 42 USC, §7511a(c)(2), requires the use of photochemical grid modeling for ozone nonattainment areas designated serious, severe, or extreme. The modeling has been conducted with input from a technical advisory committee. Hundreds of emission control strategies were considered in developing the modeling. Varying degrees of reductions from point sources and mobile sources were analyzed in at least forty modeling iterations, to test the effectiveness of different NO _x reductions. The attainment demonstration modeling submitted for public hearing and comment concurrently with these rules shows that, in order for DFW to achieve the ozone NAAQS by 2007, almost all of the practicably achievable NO _x reductions are necessary from each emission source category, including reductions from counties surrounding the DFW nonattainment area. Therefore, each strategy, including the reductions required by this rulemaking, is crucial to meet federal requirements for the DFW nonattainment area.

These adopted rules are one element of the control strategy for the DFW Attainment Demonstration SIP. The purpose of these rules is to establish a low emission diesel (LED) fuel air pollution control strategy in nine-counties of the DFW area to reduce NO _x necessary for the counties included in the DFW nonattainment area to be able to demonstrate attainment with the ozone NAAQS.

These adopted rules implement an LED fuel program requiring diesel fuel used for both on-road and off-road applications to meet the LED standards. The LED fuel will lower the emissions of NO _x and other pollutants from fuel combustion. Because NO _x is a precursor to ground-level ozone formation, reduced emissions of NO _x will result in ground-level ozone reductions. To comply with the state LED regulations, diesel fuel producers and importers must ensure diesel fuel distributed to the LED fuel zone meets the specifications stated in these rules. The rules require that diesel fuel produced for delivery and ultimate sale to the consumer in the affected area does not exceed 500 parts per million (ppm) sulfur, must contain less than 10% by volume of aromatic hydrocarbons, and must have a cetane number of 48 or greater. Also, the rules require diesel fuel producers and importers who provide fuel to the affected areas to register with the commission and provide quarterly status reports.

The new rules require LED fuel in nine counties of the DFW area which includes Collin, Dallas, Denton, Ellis, Johnson, Kaufman, Parker, Rockwall, and Tarrant Counties.

The commission is aware that the EPA is currently evaluating the feasibility and effectiveness of revising nationwide diesel sulfur controls. If the outcome of these evaluations is a federal rule which covers the areas in Texas impacted by this rule, and the federal rule is at least as stringent as these rules, then the commission will consider compliance with the national rule equally effective and may repeal the state sulfur requirements for diesel fuel.

The North Texas Clean Air Steering Committee (steering committee) representing the DFW ozone nonattainment area counties requested an air pollution control strategy involving the use of an LED fuel to reduce NO _x and other emissions necessary for the counties included in the DFW ozone nonattainment area to be able to demonstrate attainment with the ozone NAAQS.

At the request of the steering committee, the commission developed an LED fuel ozone control strategy which requires diesel fuel content limits more restrictive than federal diesel fuel regulations. The federal regulations governing diesel fuel quality in Title 40 Code of Federal Regulations (40 CFR) Part 80 (Regulation of Fuels and Fuel Additives), §80.29 (Controls and Prohibitions on Diesel Fuel Quality), establish limits for fuel content for diesel fuel used in on-road motor vehicle applications. These regulations limit sulfur in on-road diesel fuel to 500 ppm and allow the producer to choose between meeting a minimum cetane number of 40 or a maximum aromatic hydrocarbon content of 35% by volume. However, the EPA does not regulate the fuel content for non-road diesel fuel. Therefore, since there is currently no federal limit on the content of non-road diesel, the state has the authority to control the fuel content and the LED fuel requirements developed by the commission for this NO _x emission reduction strategy will result in a change to the sulfur, aromatic hydrocarbon, and cetane content levels in non-road diesel fuel. Thus, diesel fuel used for both on-road motor vehicles and off-road diesel engines is subject to the same LED fuel requirements developed for this strategy. The commission is submitting, as part of the SIP, concurrent with this rulemaking, a request for a waiver in accordance with the 42 USC, §7545(C)(4)(c), for the on-road portion of this rule. The commission does not believe a waiver is needed for the non-road portion of this rule. This SIP submittal is available to the public by contacting Heather Evans at (512) 239-1970.

Modeling performed for the steering committee assessing the benefits of this NO _x emission reduction strategy demonstrated that significant emission reductions could be achieved from using a low aromatic hydrocarbon/high cetane diesel fuel as specified by the commission's LED fuel requirements. By the year 2007, the LED fuel program will reduce NO _x emissions in the affected area by 3.48 tons per day. The commission estimated the cost effectiveness of this strategy to be approximately $12,500 per ton of NO _x reduced. This figure was calculated from the estimated NO _x reductions from this strategy of 3.48 tons per day, the increased production costs of $.04 per gallon for diesel fuel to comply with the rules, and the estimated 423,161,950 gallons of diesel fuel sold in the affected area (as extrapolated from fiscal year 1998 fuel tax data provided by the Texas State Comptroller's Office).

The commission, at the request of the steering committee, developed this NO _x emission control strategy to cover a nine-county region contained in the DFW area. The coverage area includes the four ozone nonattainment counties of Collin, Dallas, Denton, and Tarrant Counties, as well as five surrounding counties of Ellis, Johnson, Kaufman, Parker, and Rockwall Counties. The involvement of nine counties as part of the NOx emission control strategy is necessary for the area to demonstrate attainment of the ozone NAAQS. This coverage will also provide a greater market for diesel fuel producers and importers to provide the fuel required by these regulations and should help alleviate concerns regarding out of area refueling practices. In its effort to ensure that the SIP strategies impose no more burden than necessary to protect health and welfare, the commission has decided not to include the counties of Hunt, Hood, and Henderson as affected counties of these rules due to their limited impact on the air quality within the DFW nonattainment area. Due to the relatively low population, percentage of commuters, and growth rate of these counties, the commission has reevaluated the need for implementing the rules in these three counties. The reevaluation included new photochemical modeling runs which applied the rules in the nine remaining counties only. The results of these runs indicated a minor impact of including Hunt, Hood, and Henderson counties in these rules but also showed that the area could demonstrate attainment of the NAAQS without those reductions in emissions. However, other control measures which were proposed for these counties do have measurable benefits for attainment of the NAAQS. The commission solicited comments on expanding these cleaner diesel rules to east and central Texas, but only received one comment. This comment is discussed in the ANALYSIS OF TESTIMONY section of this preamble.

SECTION BY SECTION DISCUSSION

Subchapter H is renamed from "Gasoline Volatility" to "Low Emission Fuels" to more accurately reflect the contents of the subchapter. A new Division 1 includes the existing gasoline volatility rules found in §§114.301, 114.302, and 114.305-114.309. The rule language in these sections was not revised in this rulemaking action. A new Division 2 includes the new LED fuel rules adopted in this rule package.

A new §114.6 contains definitions applicable to the low emission fuel rules. These definitions include: additive, barrel, bulk plant, bulk purchaser/consumer, designated alternative limit, diesel fuel, final blend, further process, gasoline, imported, import facility, importer, low emission diesel, motor vehicle fuel, produce, producer, production facility, refiner, refinery, retail fuel dispensing outlet, and supply. The definition for "additive" was added as a result of comments, and the other definitions were renumbered accordingly.

The new §114.312 establishes standards for diesel fuel content for sulfur, aromatic hydrocarbons, and cetane in nine counties of the DFW area. Sulfur is limited to 500 ppm, aromatic hydrocarbons are limited to 10% by volume, and the cetane number must be 48 or greater. The new §114.312 also allows diesel fuel which has been produced to comply with all specifications for a Certified Diesel Fuel Formulation as approved by an executive order issued by the California Air Resources Board (CARB) to be used in place of fuel meeting the specified content standards. In addition, alternative diesel fuel formulations which demonstrate equivalent emission reductions to the diesel fuel standards specified in §114.312 to the satisfaction of the executive director and EPA may also be used to comply with these regulations. The commission made changes to §114.312(g) in response to comments to clarify the requirements of §114.312 to address the use of additives in alternative diesel fuel formulations to provide additional flexibility for producers and importers to comply with the fuel requirements.

The new §114.313 was not changed as proposed in the Texas Register . It provides flexibility to diesel fuel producers and importers by allowing alternative limits to be designated for aromatic hydrocarbon content. The designated alternative limits allow a specified amount of diesel fuel to be produced or imported with an aromatic hydrocarbon content in excess of the standard, if within 90 days diesel fuel is produced or imported with an aromatic hydrocarbon content sufficiently below the standard and in a sufficient volume to offset the excess.

The new §114.314 requires diesel fuel producers and importers that provide fuel to the affected areas to register with the commission using forms prescribed by the executive director. Registrants are also required to sign a statement of acceptance of the rules and a statement of consent allowing the commission to collect samples and access documentation and records. The commission also made changes to §114.316 in response to comment to require producers and importers to register with the executive director by December 1, 2001; or after May 31, 2002, within 30 days after the first date that such person will produce or import LED.

The new §114.315 was not changed as proposed in the Texas Register . It establishes American Society for Testing and Materials (ASTM) Test Method D2622-98 as the approved test method for determining sulfur content, ASTM Test Method D5186-99 as the approved test method for determining aromatic hydrocarbon content, ASTM Test Method D2425-99 as the approved test method for determining polycyclic aromatic hydrocarbon content, ASTM Test Method D4629-96 as the approved test method for determining nitrogen content, and ASTM Test Method D613-95 as the approved test method for determining the cetane number of the diesel fuel. The new §114.315 also includes a paragraph which authorizes the use of test methods other than those specifically listed, provided the alternate test method is validated in accordance with federal regulations. This paragraph is necessary because in some specific unique situations the listed test methods may be inappropriate. The paragraph increases flexibility by allowing the use of additional test methods which may be more cost-effective and more appropriate in certain unique situations.

The new §114.316 requires diesel fuel producers and importers subject to the provisions of §114.312 to maintain records of the sulfur and aromatic hydrocarbon content and the cetane number of the diesel fuel produced for or imported into the affected areas. The new §114.316 also contains a provision requiring all parties in the distribution chain (producer, importer, terminals, pipelines, truckers, rail carriers, and retailers) to maintain transfer document records for a minimum of two years. In addition, the new §114.316 requires producers and importers to provide the executive director with a report for each final blend of LED produced for, or imported into, the affected areas and a quarterly report summarizing the quarter's transactions relative to the testing and recordkeeping requirements. The title was changed to add the words "and Reporting" to more accurately reflect the function of the section. The commission also made changes to §114.316 in response to comment to require the submission of a report on each final blend and a quarterly summation report, which is similar to what is required by the federal reformulated gasoline and anti-dumping reporting regulations. Transfer document tracking provisions in §114.316 have also been revised in response to comment to require that product transfer documents must include at least the following information: date of transfer; the name and address of the transferor and the transferee; in the case of transferors or transferees who are producers or importers, the registration number of those persons as assigned by the commission under §114.314; the volume of diesel fuel being transferred; the location of the diesel fuel at the time of transfer; and the following certification statement: "This product complies with the requirements for low emission diesel fuel specified in Title 30 Texas Administrative Code, §114.312 and may be used in any Texas county requiring the use of low emission diesel fuel in compression-ignition engines." This revision requires tracking information similar to that required by federal regulations and removes the requirements for blend identity and batch number tracking since blend batches are mixed together in the distribution system and tracking individual batches is rendered impossible.

The new §114.317 establishes exemptions from all testing and recordkeeping requirements of the new §114.316, except the provision for keeping transfer document records for owners or operators of retail motor vehicle diesel fuel dispensing facilities. The new §114.317 also contains a provision allowing for the transfer or storage of diesel fuel, which does not meet the requirements of the new §114.312, within the affected areas as long as the fuel is not ultimately used in these areas. The reference to §114.316 was changed to reflect the revision of its title.

The new §114.319 specifies the counties which are subject to the new requirements and by which date these counties are to become subject to these new requirements. The reference to §114.316 was changed to reflect the revision of its title.

FINAL REGULATORY IMPACT ANALYSIS

The commission reviewed the rulemaking in light of the regulatory analysis requirements of Texas Government Code, §2001.0225, and determined that the rulemaking is subject to §2001.0225 because it could meet the definition of a "major environmental rule" as defined in that statute. "Major environmental rule" means a rule the specific intent of which is to protect the environment or reduce risks to human health from environmental exposure and that may adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state. The amendments to Chapter 114 are intended to protect the environment or reduce risks to human health from environmental exposure to ozone and could affect in a material way, a sector of the economy, competition, and the environment due to its impact on the fuel manufacturing and distribution network of the state. The amendments are intended to implement an LED fuel air pollution control program as part of the strategy to reduce emissions of NO _x necessary for the counties included in the DFW nonattainment area to be able to demonstrate attainment with the ozone NAAQS. The steering committee representing the DFW ozone nonattainment area counties requested an air pollution control strategy, including the use of an LED fuel, to reduce NO _x emissions necessary to demonstrate attainment with the ozone NAAQS. The amendments are part of the commission response to the request and one element of the proposed DFW Attainment Demonstration SIP. Although the amendments could meet the definition of a "major environmental rule" as defined in the Texas Government Code, §2001.0225 only applies to a major environmental rule, the result of which is to: 1. exceed a standard set by federal law, unless the rule is specifically required by state law; 2. exceed an express requirement of state law, unless the rule is specifically required by federal law; 3. exceed a requirement of a delegation agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program; or 4. adopt a rule solely under the general powers of the agency instead of under a specific state law.

This rulemaking action does not meet any of these four applicability requirements. Specifically, the LED fuel requirements within these rules were developed in order to meet the ozone NAAQS set by the EPA under 42 USC, §7409, and therefore meet a federal requirement. States are primarily responsible for ensuring attainment and maintenance of NAAQS once EPA has established those standards. Under 42 USC, §7410 and related provisions, states must submit, for EPA approval, SIPs that provide for the attainment and maintenance of NAAQS through a control program directed to sources of the pollutants involved. These rules are not an express requirement of state law, but were developed specifically in order to meet the air quality standards established under federal law as NAAQS. These rules are intended to help bring ozone nonattainment areas into compliance and to help keep attainment and near nonattainment areas from going into nonattainment. The amendments do not exceed a standard set by federal law, exceed an express requirement of state law unless specifically required by federal law, nor exceed a requirement of a delegation agreement. The amendments were not developed solely under the general powers of the agency, but were specifically developed to meet the air quality standards established under federal law as NAAQS. Four persons submitted comments on the draft regulatory impact analysis during the public comment period. These comments are addressed in the ANALYSIS OF TESTIMONY section of this preamble.

TAKINGS IMPACT ASSESSMENT

The commission prepared a takings impact assessment for these rules in accordance with Texas Government Code, §2007.043. The following is a summary of that assessment. The specific purpose of the rulemaking was to establish a LED fuel program which will act as an air pollution control strategy to reduce NO _x emissions necessary for the four counties included in the DFW ozone nonattainment area to be able to demonstrate attainment with the ozone NAAQS. The affected area consists of the four-county DFW ozone nonattainment area as well as the five additional counties in the DFW area which include Ellis, Johnson, Kaufman, Parker, and Rockwall Counties. Promulgation and enforcement of the rules may possibly burden private, real property because this rulemaking action may result in investment in the permanent installation of new refinery processing equipment. Although the rules do not directly prevent a nuisance or prevent an immediate threat to life or property, they do prevent a real and substantial threat to public health and safety, and partially fulfill a federal mandate under 42 USC, §7410. Specifically, the emission limitations and control requirements within this proposal were developed in order to meet the ozone NAAQS set by the EPA under 42 USC, §7409. States are primarily responsible for ensuring attainment and maintenance of the NAAQS once the EPA has established them. Under 42 USC, §7410 and related provisions, states must submit, for approval by the EPA, SIPs that provide for the attainment and maintenance of NAAQS through control programs directed to sources of the pollutants involved. Therefore, the purpose of the rules is to implement cleaner burning diesel fuel which is necessary for the DFW nonattainment area to meet the air quality standards established under federal law as NAAQS. Consequently, the exemption which applies to these rules is that of an action reasonably taken to fulfill an obligation mandated by federal law; therefore, these rules do not constitute a takings under the Texas Government Code, Chapter 2007.

COASTAL MANAGEMENT PROGRAM CONSISTENCY REVIEW

The commission has determined that the rulemaking relates to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act of 1991, as amended (Texas Natural Resources Code, §§33.201 et seq.), and the commission rules in 30 TAC Chapter 281, Subchapter B, concerning Consistency with the CMP. As required by 31 TAC §505.11(b)(2) and 30 TAC §281.45(a)(3), relating to actions and rules subject to the CMP, commission rules governing air pollutant emissions must be consistent with the applicable goals and policies of the CMP. The commission has reviewed this action for consistency with the CMP goals and policies in accordance with the rules of the Coastal Coordination Council, and has determined that the action is consistent with the applicable CMP goals and policies. The CMP policy applicable to this rulemaking action is the policy that commission rules comply with regulations in 40 CFR, to protect and enhance air quality in the coastal area (31 TAC §501.14(q)). No new sources of air contaminants will be authorized by these rules. Therefore, in compliance with 31 TAC §505.22(e), the commission affirms that this rulemaking is consistent with CMP goals and policies.

No persons submitted comments on the consistency of the proposed rules with the CMP during the public comment period.

HEARINGS AND COMMENTERS

The commission held public hearings on this proposal at the following times and locations: January 24, 2000 in El Paso; January 25, 2000 in Austin; January 26, 2000 in Longview and Irving; January 27, 2000 in Dallas and Lewisville; January 28, 2000 in Fort Worth; January 31, 2000 in Beaumont and Houston; and February 9, 2000 in Denton. The comment period was originally scheduled to close on February 1, 2000, but was extended until 5:00 p.m. on February 14, 2000 (see the January 21, 2000 issue of the Texas Register (25 TexReg 461)). The following 666 commenters provided oral testimony and/or submitted written testimony: Association of American Railroads (AAR), American Short Line and Regional Railroad Association (ASL&RRA), Brinks, Inc. (Brinks), Business Coalition for Clean Air (BCCA), City of Cleburne (Cleburne), City of Dallas (Dallas), Craddock Moving and Storage (CMS), Dallas Sierra Club (Sierra--Dallas), Daryl Flood Warehouse and Movers (DFWM), Downwinders at Risk (DAR), Engine Manufacturers Association (EMA), Ethyl Petroleum Additives (Ethyl), ExxonMobil Chemical Company (ExxonMobil), Fort Worth Sierra Club (Sierra--Fort Worth), Greater Fort Worth Sierra Club (Sierra--Greater Forth Worth), Koch Petroleum Group (Koch), League of Women Voters of Tarrant County (LWV--Tarrant), League of Women Voters of Texas (LWV--Texas), Lone Star Chapter of the Sierra Club (Sierra--Lone Star), National Freight, Inc. (NF), National Petrochemical and Refiners Association (NPRA), Neighbors for Neighbors (NFN), North Texas Clean Air Steering Committee (steering committee), Public Citizens (PC), Senior Citizen Alliance of Tarrant County (SCA--Tarrant), Senior Political Action Committee (SPAC), Sustainable Economic and Environmental Development (SEED), Tarrant Coalition for Environmental Awareness (TCEA), Texas Campaign for the Environment (TCE), Texas Clean Water Action (TCWA), Texas Public Citizen (TPC), Texas Motor Transportation Association (TMTA), Texas Nursery and Landscape Association (TNLA), Texas Oil and Gas Association (TxOGA), Turner, Mason and Company (TMC), Ultramar Diamond Shamrock Corporation (Shamrock), EPA, U.S. Public Interest Research Group (PIRG), and 627 individuals. The following persons generally supported the proposal: Cleburne, Dallas, DAR, Sierra--Dallas, EPA, Sierra--Fort Worth, Ethyl, Sierra--Greater Forth Worth, Sierra--Lone Star, NFN, Steering committee, PC, PIRG, SCA--Tarrant, SEED, SPAC, LWV--Tarrant, LWV--Texas, TCE, TCEA, TCWA, TPC, and 610 individuals. The following persons generally opposed the proposal: AAR, ASL&RRA, Brinks, BCCA, CMS, DFWM, EMA, ExxonMobil, Koch, NF, NPRA, TMC, TMTA, TNLA, TxOGA, Shamrock, and 15 individuals. The following persons suggested changes to the proposal as stated in the ANALYSIS OF TESTIMONY section of this preamble: AAR, ASL&RRA, Brinks, BCCA, CMS, DFWM, EMA, EPA, Ethyl, ExxonMobil, Koch, Sierra--Lone Star, NF, NPRA, steering committee, TxOGA, TMTA, Shamrock and two individuals.

ANALYSIS OF TESTIMONY

EMA, ExxonMobil, and TxOGA expressed opposition to region-specific, patchwork, or boutique diesel fuel control strategy methods. EMA expressed concern that the proposal would take focus away from impending federal ultra-clean fuel standards, and does so with little or no emission benefits while increasing costs for diesel fuel users.

The commission is aware that the EPA is currently evaluating the feasibility and effectiveness of revising nationwide diesel fuel standards. If the outcome of these evaluations is a federal rule which covers the areas in Texas impacted by these adopted rules, and the federal rule is at least as stringent as any rules adopted as a result of this rulemaking, then the commission will consider compliance with the national rule equally effective and may repeal all or portions of the state requirements for diesel fuel. The commission has made no change to the rule language in response to this comment.

Koch and TxOGA commented that the commission should petition the EPA to take full credit in the DFW SIP for the projected emission reductions resulting from the planned federal diesel engine and fuel standards and therefore, regulation of diesel fuel in the interim should not be included as a control strategy in the DFW SIP.

Since the EPA is still in the Advanced Notice stage of this rulemaking process, the commission could not claim credit for this proposed initiative. For example, specific fuel parameters such as cetane and aromatics levels have not been finalized. For this reason emission reductions from this measure are neither quantifiable nor creditable at this time. In addition, based on the Advanced Notice, it is quite likely that the EPA will only mandate sulfur reductions, leaving aromatics and cetane values at their current levels. Since the EPA believes that the 2004 emission standards can and will be met without recourse to NO _x after-treatment devices, sulfur reductions alone are not expected to generate further NO _x reductions beyond the engine standards themselves. Finally, with regard to obtaining credit for "low emission diesel vehicles," the commission has modeled the effects of heavy diesel vehicles meeting the 2004 emission standards, and included these results in the 2007 emission projections. For these reasons the commission believes the SIP modeling effort has already claimed the maximum amount of NO _x reduction credits available from diesel vehicles and fuels, given the current federal rulemaking status.

Shamrock commented that instead of requiring California Diesel in such a short time frame for the DFW area, the commission should wait until the EPA has finalized their proposed low sulfur diesel rules.

The DFW ozone nonattainment area is required to have three years of emissions monitoring data demonstrating compliance with the NAAQS to support the 2007 attainment demonstration. Therefore, implementing the LED standards in May 2002 provides the area the necessary time to allow the results of this control strategy to be realized through emission monitoring data. The commission is aware that the EPA is currently evaluating the feasibility and effectiveness of revising federal diesel fuel standards. If the outcome of these evaluations is a federal rule which covers the areas in Texas impacted by these state rules, and the federal rule is at least as stringent as these state rules, then the commission will consider compliance with the national rule equally effective from the time of implementation of the federal fuel and may repeal all or portions of the state requirements for diesel fuel. The commission has made no change to the rule language in response to this comment.

EPA commented that the commission needs to provide a more thorough review of why the 375 control measures mentioned in the SIP submittal's application for a waiver to FCAA, §211(c)(4)(C), for the proposed LED fuel rules are impossible or impracticable.

The commission believes that sufficient data is provided in Chapters 3 and 6 of the DFW Attainment Demonstration SIP regarding the various alternate control strategies that were reviewed to determine whether the proposed implementation of the LED fuel control strategy is justified to be included as part of the attainment demonstration. The commission is clarifying the SIP language to ensure that the waiver request addresses EPA's concerns.

NPRA commented that the commission should reevaluate the effectiveness of increasing cetane number as a measure to reduce NO _x emissions because recent reports, such as Society of Automotive Engineers (SAE) Paper 1999-01-1478 entitled "The Effects of 2-Ethylhexyl Nitrate and Di-Tertiary-Butyl Peroxide on the Exhaust Emissions from a Heavy Duty Diesel Engine" (May 1999) and the Eastern Research Group (ERG) assessments of the benefits from California Diesel, have shown a range of results from a 2.0% - 4.0% NO _x reduction for an eight cetane number increase to a slight increase in NO _x emissions in some engine systems. Koch and TxOGA commented that the commission should remove the cetane specification from the proposal because California diesel regulations do not specify a minimum cetane number and recent studies have indicated that the cetane number has a negligible effect on NO _x and other emissions. In addition, Koch commented that the commission should provide a technical basis for each property being specified.

Cetane number is a measure of diesel fuel auto-ignition quality. Higher cetane numbers characterize improved grades of diesel fuel. Increasing cetane number reduces the size of the premixed combustion by reducing the ignition delay. This in effect lowers the rate of NO _x formation due to the fact that the combustion pressure rises more slowly in the combustion chamber resulting in more time for cooling through heat transfer and dilution by incoming charge. This phenomenon results in lower combustion temperature, in effect lower NO _x . As stated by NPRA, studies indicate about a 3.0% - 4.0% reduction in NO _x from an increase in cetane number. The commission agrees that this characteristic varies for different engines. However, the rules do allow alternative diesel fuel formulations to be used, including diesel fuel with a lower cetane number or higher aromatic content than specified in the proposal, as long as the emissions reduction performance of the alternative formulation is equivalent to the specified LED fuel standards. The commission has made no change to the rule language in response to this comment.

Koch and NPRA commented that the test specified in the proposal to determine the cetane number requires the use of a test engine which only two commercial laboratories in the United States have installed and each additional test engine would cost hundreds of thousands of dollars to purchase, install, and operate. NPRA commented that the commission assessment that there will not be any additional costs to producers to test the proposed LED is incorrect. NPRA further stated that there will be significant additional costs, because the LED that would supply the DFW area would be produced in smaller batches and would require separate tests for each small batch, which would increase the per-gallon costs.

The commission disagrees with this comment. The adopted rules do not require producers or importers to purchase test engines, but only to use the test methodology to determine compliance to the standard. The commission understands that producers regularly use independent laboratories to test diesel fuels and that the cost to determine cetane number using the test methodology specified in the adopted rules is usually $150 or less per test. The commission has also been informed by a representative of the independent laboratory industry that there are at least seven independent labs across the nation with the capability to conduct the required cetane tests, and that there are at least three independent labs in Texas that have this capability. The commission has made no change to the rule language in response to this comment.

TxOGA opposed the adoption of California Diesel. TxOGA also stated that the proposal as written is not in actuality California Diesel because of the minimum cetane requirement, which is not part of California's diesel fuel requirements, but a characteristic of the California test fuel.

The commission did not propose adoption of the California diesel fuel rules as the fuel required by the LED fuel proposal. The Texas rules specify standards for sulfur and aromatics which are the same as those specifications for California Diesel, but adds a requirement for cetane because of the additional NOx reductions to be gained. The commission has made no change to the rule language in response to this comment.

Ethyl commented that the commission should remove the low aromatic requirement from the proposal and increase the minimum cetane number to 50, allowing each refiner to choose how best to raise cetane. The result would be a better quality diesel fuel that could be introduced within a few months of notification, produce more emission benefits, and be more cost effective than the fuel required by the proposal.

Based on recent studies, there are no clear directions on how a change in only the diesel fuel aromatic content affects emissions of hydrocarbons (HC), carbon monoxide (CO), and particulate matter (PM) in real life conditions when tested with in-use motor vehicle engines. Some studies have experienced only marginal reductions of these pollutants from diesel fuel with an aromatic content reduced to 20%, while other studies indicate no response to the emissions of HC, CO, and PM from reduced aromatic content. Variability in behaviors in this situation may be associated with the state of the engine and its condition: design, age, application, test conditions, etc. However, changes in aromatic content clearly affect NO _x emissions. So far, studies have shown that a reduction in aromatic content in diesel fuel from 30% - 10% will yield about 4.0% - 5.0% reduction in NO _x emissions.

The rules do allow alternative diesel fuel formulations to be used, including diesel fuel with a higher aromatic content or higher cetane number than specified in the proposal, as long as the emission performance of the alternative formulation is equivalent to the specified LED fuel standard. The commission has made no change to the rule language in response to this comment.

AAR and ASL&RRA opposed the LED fuel proposal insofar as it proposes to regulate diesel fuel used in locomotives. AAR and ASL&RRA commented that the proposed diesel fuel will not provide the emission benefits claimed when used in current technology locomotive engines and that there is no evidence that the requirement to use the proposed LED fuel could be implemented at a reasonable price.

The commission's emission inventory for the year 2007 estimates locomotive engines emit 8.2 tons per day of NO _x emissions in the DFW four-county area. The commission believes that the reduced sulfur and aromatic content level and the increased cetane levels in the proposed LED fuel will provide an emissions benefit when used in locomotive engines and that the control of non-road diesel fuel is necessary for demonstrating attainment with the ozone NAAQS. Sulfur levels greatly impact the emission levels of NO _x , PM, CO, and HC. Substantial reductions of sulfur levels in diesel fuel drastically reduce the emissions of NOx , PM, and HC. There is additional reduction of NOx , PM, and HC emissions when the low sulfur level is coupled with a reformulation that has lower diesel fuel aromatic content. The commission has made no change to the rule language in response to this comment.

TxOGA commented that the commission has failed to show appropriate justification for including non-road diesel fuel in this proposal.

The commission's emissions inventory for the year 2007 estimates that the non-road NO _x emissions sources will represent about 33% of the total NO _x emissions in the DFW four-county area. Therefore, the commission has determined that the control of non-road diesel fuel is necessary for demonstrating attainment with the ozone NAAQS. The commission has made no change to the rule language in response to this comment.

EPA commented that the commission has the legal authority to control diesel fuel content for non-road engines since the pre-emption provisions of the FCAA, §211(c)(4), only apply to the control of fuels for purposes of on-road motor vehicle emission controls.

The commission agrees with this comment.

Koch and TxOGA commented that the commission should be required to conduct a thorough regulatory impact analysis (RIA) prior to the adoption of any rule that regulates diesel fuel in a manner that is not identical to a federal rule. Koch and TxOGA also stated that the commission was incorrect in its assessment that proposed rules do not exceed a standard set by federal law as it has been developed in order to meet the ozone NAAQS. TMTA commented that due to the significant consumer costs associated with this proposal, a thorough analysis of the production, distribution, and retailing issues specific to the DFW area is needed to adequately disclose the economic impact of this proposal. Koch, TxOGA, and Shamrock commented that a more thorough RIA should be performed to ensure that this proposal is necessary for the DFW area to meet air quality goals and is a cost-effective alternative strategy in comparison with other strategies that might be implemented.

Although the commission has determined that this is a major environmental rule because it may adversely impact in a material way a sector of the economy, the commission is not required to perform a RIA because these rules do not meet any of the criteria listed in Texas Government Code, §2001.0225(a). The rules do not exceed a standard set by federal law or state law. The federal standard used for comparison is the ozone NAAQS which is a more stringent standard in this case than the federal diesel program. The state is required to demonstrate compliance with this standard under federal law, 42 USC, §7410, and under state law, Texas Health and Safety Code, §382.012 and §382.039. As shown in the modeling for the SIP that is associated with this control strategy, the state is requiring no more emission reductions than absolutely required to meet the standard. The SIP submittal includes a waiver request which demonstrates that no other alternative strategies are practicable. Additionally, these rules would not exceed a requirement of a delegation agreement or contract with the federal government because none exists on this topic. Finally, as noted in the STATUTORY AUTHORITY section of this preamble, these rules have not been proposed under the general powers of the agency, but instead have been proposed under the specific state laws found in Texas Health and Safety Code, §§382.011, 382.012, 382.017, 382.019, 382.037(g), and 382.039. For these reasons, the commission is not required to perform an RIA for these rules.

AAR and ASL&RRA questioned, that based on the restrictions on state action in the FCAA, §209, and that the preemption provisions of FCAA, §211 may apply to non-road engines as well as motor vehicles, whether the commission has the authority to unilaterally impose a fuel specification on companies selling diesel fuel for use in non-road engines.

The commission disagrees with the commenters' interpretation of FCAA, §209 and §211. Section 209 generally prohibits states from adopting standards for the control of emissions from motor vehicles and new non-road vehicles and engines, and does not address fuel standards. The proposed Texas diesel rules would not directly or indirectly set an emission standard for non-road vehicles and engines. Section 211(c)(4) does generally prohibit states from adopting fuel standards for controlling emissions from motor vehicles if the EPA has already regulated that component of the fuel. In other places of the FCAA, the term "motor vehicle" is used to describe only on-road vehicles while non-road vehicles and engines are identified separately. Therefore, the prohibition in §211 does not apply to fuel for non-road vehicles and engines. The commission has made no change to the rule language in response to this comment.

TMTA commented that the emission reductions attributed to adoption of low emission "CARB" diesel will be significantly lower than projected by the agency due to increased use of newer technology engines.

The test engine used in the EPA Heavy-Duty Engine Work Group (HDEWG) study (the basis for the commission's benefit estimate) was actually tested at 2.7 grams per brake horsepower-hour (g/bhp-hr) NO _x levels, which is quite close to the upcoming year 2004 standard of 2.5g/bhp-hr. Therefore, the commission believes that the benefit estimate is representative of upcoming, late-technology engines. The commission has made no changes in response to this comment.

TMTA commented that the emission reductions attributed to adoption of low emission "CARB" diesel will be significantly lower than projected by the agency due to the assumption that a large percentage of diesel-fueled vehicles operating in the coverage area will be refueled outside the coverage area with cheaper non-conforming fuel. AAR and ASL&RRA commented that the emission benefits claimed by the proposal are incorrect because the commission has mistakenly assumed that the majority of diesel fuel purchased in the affected areas would be used in the region. This will not be the case with locomotive engines, because most locomotives have very large fuel tanks which allow them to travel for as much as a thousand miles before refueling and thus any emission benefit from the use of the proposed diesel fuel would be outside of the affected area. One individual commented that unless the LED fuel provides the same performance and economy as fuel available outside the control area, truckers will not refuel with LED fuel; but drive through the area using noncompliant fuel purchased elsewhere. In addition, Koch, NPRA, TxOGA, and Shamrock commented that the emission benefits may be overstated due to possible shifts in refueling practices of area fleets, especially long-haul trucking firms, to locations outside the affected areas. These practices could also have large economic impacts on local businesses marketing diesel fuel.

The commission agrees that the benefit of LED fuel may be diminished in the DFW area due to trucks operating in the area but purchasing fuel outside of the covered counties. However, the commission is not aware of any estimates of the fraction of vehicle miles traveled (VMT) attributable to such "pass through" truck traffic. Therefore, without additional information, the commission is not able to estimate a reasonable offset factor for this effect. Nevertheless, the intent of the rules is to impact as large a fraction of area-wide diesel VMT as is reasonable, which the commission believes will be accomplished through these rules. The commission has made no change to the rule language in response to these comments; however, the commission is considering expanding the area in future rulemaking.

Koch commented that the emission benefits were overestimated because the assessment of the benefits was based on a ERG study which was too limited in scope and does not meaningfully model the real world conditions. Koch encouraged the commission to reevaluate its assessment of the emission benefits based on the SAE Paper 982649 entitled "Fuel Quality Impact on Heavy Duty Diesel Emissions: A Literature Review" (October 1998) in which the results and conclusions do not agree with the conclusion drawn by the ERG study. Koch commented that the Caterpillar 3176 engine used as the basis of the EPA HDEWG test program is not representative of typical engines operated in the DFW area, and therefore should not be used to estimate emissions benefits of the proposed rules.

The commission believes that while the uncertainty of the estimates from mechanically controlled diesel engines provided by the ERG study, which was based on a small CARB data set operating on California diesel, is greater than the uncertainty of the estimates for newer, electronically controlled engines, the claimed reductions are indeed reasonable and conservative. The 7.0% NO _x emission reduction value is only slightly higher than the 5.7% figure used for electronically controlled engines in this analysis. Also, the mechanically-controlled engines make up less than 2.0% of the on-road VMT by 2007, based on local registration distributions and MOBILE5 default mileage accumulation rates. Therefore, for the on-road sector the impact of any uncertainty in these figures is diminished by the small size of the fleet under consideration.

In Phase I of the HDEWG testing, five to six fuel blends were sent to several different engine manufacturers, including Cummins and Detroit Diesel, for baseline testing. The EPA determined that the Caterpillar 3176 engine had emissions typical of equivalent technology engines from other manufacturers. These engines were selected to be representative of upcoming engines meeting 1998/2004 standards, according to the Southwest Research Institute (SwRI) program manager. Therefore, the Caterpillar 3176 engine was deemed an appropriate selection for further testing. This was the consensus among participating manufacturer representatives as well. The commission has made no change to the rule language in response to this comment.

Koch commented that the specially blended fuel set used in the HDEWG test program was not representative of typical number (No.) 2 diesel fuels consumed in the DFW area, and that the high fraction of cetane enhancers in the test fuel set rendered the fuels even more atypical; therefore, the specialty fuel should not be used as the basis for estimating benefits for No. 2 reformulations. Shamrock commented that the emission benefits estimated for this proposal may be overstated if these benefits were calculated using a theoretical baseline or on DFW's actual "in place fuel" quality.

While it is true that the fuel set used in the HDEWG test program is atypical, the study could not have achieved its objective of determining parameter-specific effects without some sort of manipulations of the blends involved. In addition, SwRI technical staff involved in the test program point out that, by and large, the fuel set parameters were selected to mimic the fuel properties anticipated from advanced diesel fuel production in the near future. Finally, in regard to cetane enhancers, the test program clearly demonstrated that there was no significant difference in the interaction between natural or boosted cetane levels and other effects such as aromatics-induced reductions. Therefore, the pervasive presence of boosted cetane in the fuel matrix did not bias the outcome of the test program.

The SAE Paper 982649, which summarizes the available research up to that point on diesel fuel property impacts on emissions, cites a less than 5.0% impact for total aromatic reductions from 30% - 10% by weight. However, the authors of the paper themselves acknowledge that "on a percent basis, polyaromatics should contribute more to NO _x than a corresponding amount of mono-aromatics." Thus, if polyaromatics are reduced disproportionately compared to mono-aromatics, the reductions could be even greater than stated above. Since the HDEWG predictive model accounts for both poly- and mono-aromatic levels, the commission believes that the modeled result of 5.7% is within the range of reasonable reductions. In addition, the SAE authors themselves reference the ongoing work by the HDEWG as a source of future data concerning the differential effect of aromatic species. The commission has made no change to the rule language in response to these comments.

Koch commented that the 2.5% emission reduction benefit claimed by the ERG study, and used by the commission to estimate the NO _x benefit of the proposed LED program, should be reduced to a 1.75% NO _x reduction benefit because the modeling in the ERG study assumed a typical alternative diesel formulation at 20% aromatics, compared to 10% aromatics required by the California diesel fuel standards. Information provided in the SAE Paper 982649 showed 2.5% to be a reasonable estimate only if aromatics were reduced from 30% - 10%.

The commission disagrees with this comment because all CARB certified alternative diesel formulations must demonstrate equivalent emissions performance to the base standard at 10% aromatics, and other parameters, such as cetane number, are usually raised to compensate for an increase in aromatics. Accordingly, the commission accounted for the modified parameters specified in the certified alternative diesel formulations, including relative contributions of poly- and mono-aromatics, in its modeling. Therefore, the fact that California diesel fuels were modeled by the commission at 20% aromatics levels to emulate the diesel fuel currently being used in California does not warrant the proposed correction factor. The 0% - 5.0% range cited in the SAE Paper 982649 may also be somewhat biased by the model year of the engines tested. Specifically, of approximately ten engines used to generate the 0% - 5.0% estimate, all but two were 1995 or older models (as old as 1991). Although more detailed research would be needed to quantify the effect, the commission believes that these engines most likely featured a higher pre-mix burn fraction than is found in the most advanced engines today, such as the Catepillar 3176 engine tested by the HDEWG. This factor would tend to decrease the impact of aromatic reductions somewhat for the relatively older engines. The commission has made no change to the rule language in response to this comment.

Koch encouraged the commission to use a 0% benefit base for VOC emissions when comparing CARB diesel and federal diesel based on a European Auto Oil study and SAE Paper 982649.

The commission agrees with the comment in that the VOC benefits should be adjusted based on the 1996 study, "European Auto-Oil I," and SAE Paper 982649. However, the language in the rules does not address VOC emissions. The commission has made no change to the rule language in response to this comment.

Koch and NPRA commented that the proposal does not correctly address the fiscal impact to local small businesses, especially local fuel distributors, which could see a significant loss of volume and revenue due to potential large differences in fuel prices inside and outside the control areas. These price differences could result in a shift in the refueling practices of local users and transient users to areas outside the control areas. Brinks, CMS, DFWM, and NF expressed concern that the adoption of this proposal would have serious financial impacts on local businesses with regard to fuel costs, with relatively minor impacts on air quality, and that local trucking operations will be placed at a competitive disadvantage with operations located outside the affected counties not having to purchase LED fuel.

The commission agrees that these rules may have a fiscal impact on businesses within the control area in regard to fueling costs; however, the commission contends that the fiscal impact will likely be conveyed on to the customers in the way of higher cost for services. The commission does not believe that with LED fuel being implemented in nine counties of the DFW area will put local businesses at a significant competitive disadvantage to those businesses outside of the control area due to the distances involved. The commission has made no change to the rule language in response to these comments; however, the commission is considering expanding the area in future rulemaking.

TMTA commented that the actual cost of requiring "CARB" diesel in the DFW area has not been properly evaluated by the commission, and will result in an inflationary pressure on all area goods and services resulting in higher consumer cost. TMTA claims that the cost to produce the proposed LED fuel will be $.05 to $.06 per gallon as opposed to the $.04 per gallon pump price increase stated in the LED rule proposal preamble and that an approximate $.01 per gallon mileage penalty should be added to the production cost of diesel fuel. TMTA commented that the cost figure is not representative of the cost of producing diesel fuel for a single metropolitan area. As the level of investment capital required to produce LED fuel has the potential to reshape the diesel fuel production and distribution system within the entire state, a thorough assessment of the refining impacts of the proposal is needed. AAR and ASL&RRA commented that the commission estimate that the proposed diesel fuel specification would lead to a price increase of $.04 per gallon is too low, and that since the infrastructure to produce and distribute the proposed diesel fuel is not in place, the differential cost between the proposed diesel fuel and the diesel fuel used by railroad locomotives today would be higher even under a best case scenario. In addition, AAR and ASL&RRA commented that there has been no indication of how many Texas refiners would make the capital investments necessary to produce the proposed diesel fuel, therefore, it would be reasonable to think that supplies of the proposed diesel fuel could be limited, resulting in extremely high fuel prices. Koch commented that the commission underestimated the costs to produce the diesel fuel required by the proposal and that the proposed diesel fuel will cost substantially more to produce based on the October 1999 MATHPRO, Inc. study, entitled "Refining Economics of Diesel Fuel Standards," which was produced for the EMA. The study showed California diesel is estimated to increase the manufacturing costs by $.09 per gallon. The study also stated that the investment costs of $80 million to $100 million per refinery to install the necessary equipment to manufacture California diesel is two to five times greater than the investment needed to produce diesel in the sulfur range contemplated for the new Federal diesel standards. Koch commented that the commission does a disservice to represent the Northeast States for Coordinated Air Use Management (NESCAUM) cost when another, at least equally credible, study such as the October 1999 MATHPRO study and actual market data indicate that the true costs will be substantially greater than the $.04 per gallon cost used in the commissions cost benefit analysis and that the commission should attempt to use the best estimate for a cost comparison between California diesel fuel and federal diesel fuel. Brinks, CMS, DFWM, and NF commented that they have estimated the cost of LED fuel to be $.14 over that of conventional diesel fuel.

According to a CARB publication entitled, "California Diesel Fuel Factsheet," published in March 1997, a gallon of California diesel fuel costs approximately $.01 to $.04 more to produce than diesel fuel in other states. While other factors beside production costs can and do affect the retail prices of diesel fuel in California, the commission contends that production costs are the most stable measure for comparison analysis. A recent report published by the California Attorney General's Office entitled, "Preliminary Report to the Attorney General Regarding California Gasoline Prices," dated November 22, 1999, stated that differences between fuel prices in California and most of the rest of the states can be attributed to a relative lack of competition within the California refining and marketing structure, California's unique fuel specifications and the distances from major refining centers and potential supply sources outside the state, and somewhat higher state taxes.

A comparison of the weekly average retail prices for on-highway diesel fuel published by the Department of Energy for the week ending January 24, 2000 showed retail prices of California diesel to be $.16 more expensive than the retail prices of diesel fuel sold in the Gulf Coast region and $.13 more expensive than the national average. However, the commission contends that the $.04 increase in production costs is a valid determination of the costs associated with the proposed rules since other factors which could affect retail prices, as indicated above, are not the same in Texas as those in California.

The commission does agree with the comments that the actual retail price could be more expensive than just the difference in production costs. However, the commission is not aware of any firm method of determining what the actual retail price of LED fuel will be in May 2002 and what factors will be affecting the price difference to that of conventional diesel fuel. The commission has made no change to the rule language in response to these comments.

NPRA and TMTA commented that the cost-effectiveness of $7,454 per ton of NO _x reduced for the LED fuel proposal is miscalculated and has relied on out-of-date cost estimates.

The commission agrees with the comment that the cost-effectiveness figure should be revised and has made changes to the preamble in response to this comment. The $7,454 per ton was based on estimated emission reductions of 16.9 tons per day that were modeled during the initial development of the control strategy. After further refinements to the modeling assumptions, those emission reductions were reduced to 3.48 tons per day without associated adjustments being made to the cost-effectiveness figure. The cost-effectiveness for the proposed rules has been recalculated as $12,500 per ton of NO _x reduced. This cost estimate was calculated from the estimated NOx reductions of 3.48 tons per day, the increased production costs of $.04 per gallon for diesel fuel to meet the rules, and the estimated 423,161,950 gallons of diesel fuel sold in the affected area (extrapolated from fiscal year 1998 fuel tax data provided by the Comptroller's Office).

Koch commented that the commission's analysis into the cost of California diesel does not show the additional cost penalty associated with the 3.0% reduction in energy content per gallon of California diesel fuel when compared with federal diesel fuel. This 3.0% penalty will add another $.03 per gallon to the user's fuel costs at the current price diesel price of $1.20 per gallon.

According to the CARB, California Diesel may have a per gallon energy content reduction of up to 3.0% when compared to conventional diesel fuel, however fuel milage tests have only demonstrated a reduction in fuel mileage of up to 1.0%. This reduction in fuel mileage could result in a small increase in cost of up to an estimated 1.2 cents per gallon when based on a retail price of diesel fuel of $1.20 per gallon. Therefore, the commission does not believe that the possible slight reduction in energy content will pose a significant impact to fuel costs. The commission has made no change to the rule language in response to this comment.

Shamrock commented that the cost to produce the proposed diesel fuel could be higher than estimated by the commission because of patent infringement issues relating to California Diesel fuel formulations.

The commission acknowledges that there may be issues with some producers over patent infringement. However, the rules allow the use of California Certified Diesel Fuel Formulations as an option for compliance flexibility, not as a requirement. Also, the rules do not prohibit diesel fuel producers from submitting their own diesel fuel formulations to California for certification and possibly preventing any patent infringement issues. In addition, the commission is unable to adequately address the issue of cost in this comment because the commenter did not provide any estimates toward the possible cost of patent infringement issues. The commission has made no change to the rule language in response to this comment.

Koch commented that the commission did not include in its cost benefit analysis the cost factors associated with the downtime, labor, and material costs to repair elastomeric seals in diesel engines, which may be adversely effected by the proposed diesel fuel with its 10% aromatic content limit.

Investigation by the EPA and the CARB has shown that the reduced aromatic contents of low aromatic diesel fuels has contributed to fuel leaks in older diesel engines and vehicles, mainly from the shrinkage and possible cracking of the elastomeric seals, commonly known as O-rings, in some older diesel engines, but not in every case. The change from a higher to a lower aromatic fuel may cause elastomeric seals found in some older engines to shrink and possibly crack, especially those seals made of nitrile rubber that have seen long service at high temperatures. Commonly, the seals that failed were worn considerably and due for replacement. Thus, the cost for the worn seal or O-ring replacement would have to be incurred by the vehicle operator at some point, regardless of the change in fuel. The commission suggests that proper seal replacement and maintenance schedules will help prevent untimely equipment failures. Studies have shown that after the replacement of these seals, the occurrence of leaks was virtually eliminated.

In addition, the rules do allow alternative formulations of diesel fuel to be used, including diesel fuel with a higher aromatic content than specified in the rules, as long as the emission performance of the alternative formulation is equivalent to the specified LED fuel. The commission has made no change to the rule language in response to this comment.

ExxonMobil, Koch, NPRA, TxOGA, and Shamrock commented that the implementation date for production and marketing of the proposed diesel fuel by May 1, 2002 is not realistic for refiners that must modify their refineries to comply with the proposed rules and that a minimum of three to four years is necessary to plan, engineer, permit, construct, and test the additional diesel refining unit(s) needed to comply with the proposed fuel standard. TxOGA and Shamrock expressed concern that the affected area will experience reduced fuel supply if the implementation date is not practically attainable. Koch commented that refiners are not expected to make any investments to satisfy any hypothetical DFW LED market in time for the proposed 2002 implementation deadline and whatever supplies of California diesel are available now is what will probably be available then and until the EPA promulgates the next phase of diesel fuel properties, therefore market tightness and susceptibility to price spikes are more likely to be experienced in the DFW area than a smooth transition to the $.04 per gallon price increase estimated by the commission. Shamrock commented that the commission should survey the refiners who supply the affected area to ensure that adequate supplies will be available and verify suppliers construction plans, because if the expected economics for the expansion of their refining facilities is not promising, some refiners may decide to not make the significant capital investments required to produce the proposed fuel and no longer supply this area with fuel. TxOGA commented that due to the timing of the proposal there is a significant chance that supplies would not be available by the 2002 deadline. TMTA commented that some refiners will choose not to produce LED fuel because of the significant capital investment that is required.

The commission agrees that the May 2002 implementation date could be difficult for some diesel fuel producers to achieve if the producers were required to install additional refining facilities in the near term. However, the rules do allow the use of alternative formulations that provide the same emissions performance as the specified fuel content standards and the commission believes that producers should be able to provide these alternative formulations in sufficient quantities in the near term to alleviate any concerns over supply to the DFW area. The alternative formulations may be produced through refining practices or through the use of additives as long as the emissions performance is equivalent to the specified fuel standards. As such, if alternative formulations are used, producers should be able to begin supplying diesel fuel compliant to the rules within the specified time frame. The commission has made no change to the rule language in response to these comments.

Shamrock commented that the control strategy implemented by the diesel fuel proposal should not be expanded to other areas currently in attainment or who may be designated nonattainment this summer and that enlarging the control area has the potential of greatly increasing the cost to outlying areas that have few, if any, air quality concerns.

The commission is evaluating the need to expand these rules to cover other ozone nonattainment areas and will take this comment into consideration.

Shamrock expressed concern about the equitable enforcement of the proposal, especially the equivalency fuel defined in §114.312(g), in that it is very important that refiners who decide to make the capital investment can be assured that all refiners are held to the same level of emission reductions. Shamrock also recommended that determination of equivalency be patterned after the procedures in the California Code of Regulations (CCR), §2282(g), Certified Diesel Fuel Formulations Resulting in Equivalent Emissions Reductions.

The rule requires that all diesel fuel supplied to the affected area meet the LED requirements under §114.312. For the sake of flexibility, the rule also allows the use of alternative diesel fuel formulations which have been certified in accordance with CCR §2282(g) and the use of alternative diesel fuel formulations approved by the commission and EPA if these fuels demonstrate equivalent emission reductions. The commission has made no change to the rule language in response to this comment.

Koch and TxOGA commented that Texas should not confer its decision rights on the approval of alternate formulations of diesel fuel to California and that the proposal contains no incentive for California to expend the effort required to approve formulations that are proposed for the DFW area.

The use of a California Certified Diesel Fuel Formulation is only one of three options for demonstrating compliance to the LED requirements. Producers and importers may also choose to meet the specified diesel fuel standards for sulfur, aromatic content and cetane number, or use a alternative diesel fuel formulation that has been approved by the commission as being equivalent in reducing emissions as the specified standards. The commission has allowed the option of using a California Certified Diesel Fuel Formulation as additional flexibility for producers and importers already producing such fuels for the California market. The commission has made no change to the rule language in response to these comments.

Koch and TxOGA commented that the proposed enforcement mechanism is excessive and unworkable. They also stated that it is not possible for parties in the distribution system downstream from the refiner to report, or even know the blend batch numbers that might be contained in a particular shipment of fuel and it is not practical to test each shipment of fuel and report the results on transfer documents. Koch suggested that the commission require the same information to be maintained by the refiner and the other parties in the distribution system as required by existing federal regulations, testing of each transfer should not be required, and the requirement to list batch numbers and test results on all transfer documents should be deleted. In addition, Koch suggested that additive use should be tracked by a system similar to that required for demonstrating compliance with gasoline detergent additive rules, that applicable minimum and maximum specifications should be listed on the transfer documents. TxOGA commented that the monthly reporting is excessive and that the recordkeeping and reporting should be no more than required by current federal requirements which only require quarterly reports.

The commission concedes that the recordkeeping and reporting provisions could be construed as excessive and has made changes in response to this comment. The rules will require the submission of a report on each final blend and a quarterly summation report, which is similar to what is required by the federal reformulated gasoline and anti-dumping reporting regulations. Transfer document tracking provisions in §114.316 have also been revised in response to comment to require that product transfer documents must include at least the following information: date of transfer; the name and address of the transferor and the transferee; in the case of transferors or transferees who are producers or importers, the registration number of those persons as assigned by the commission under §114.314; the volume of diesel fuel being transferred; the location of the diesel fuel at the time of transfer; and the following certification statement: "This product complies with the requirements for low emission diesel fuel specified in Title 30 Texas Administrative Code, §114.312 and may be used in any Texas county requiring the use of low emission diesel fuel in compression-ignition engines." This revision requires tracking information similar to that required by federal regulations and removes the requirements for blend identity and batch number tracking since blend batches are mixed together in the distribution system and tracking individual batches is rendered impossible.

TxOGA commented that the requirement for registration 30 days prior to supplying diesel in the affected area would limit any potentially available supply to this market in the event of a disruption in the supply due to planned or unplanned outages from any source.

The commission agrees with this comment and has made changes to the rule to require producers and importers that begin supplying fuel to the affected areas after May 1, 2002, to register within 30 days after the first date they begin to supply fuel to the area.

Koch supported the concept in the proposal allowing a fuel producer to provide a fuel with equivalent emission reduction properties, however, Koch expressed concern that the proposed §114.312(g) does not provide the flexibility necessary to substitute Koch's own low emission diesel product, "Performance Gold Diesel," which was recently introduced into the DFW area, for the diesel fuel required by the proposal. In addition, Koch expressed concern that the proposed testing, recordkeeping, and reporting mechanisms provide a bias toward the diesel fuel specifications required by the proposal and would prevent the substitution of diesel fuels where the emissions benefits are not dependant on aromatics concentration and/or cetane number. Koch stated that the commission should revise the proposed rules to allow maximum flexibility in substituting alternate diesel formulations.

The commission has made changes in response to these comments to clarify the requirements of §114.312 to address the use of additives in alternative diesel fuel formulations to provide additional flexibility for producers and importers to comply with the fuel requirements.

Sierra--Lone Star, LWV-TX expressed support for a statewide use of cleaner diesel fuels with lower sulfur content applying to both off-road and on-road vehicles and commented that sulfur content in fuels is directly related to the effectiveness of emissions control systems in motor vehicles. The steering committee and two individuals commented that the sulfur content should be reduced in diesel fuel.

The commission is aware that the EPA is currently evaluating the feasibility and effectiveness of revising federal sulfur standards for diesel fuel. If the outcome of these evaluations is a federal rule which covers the areas in Texas impacted by these state rules, and the federal rule is at least as stringent as these state rules, then the commission will consider compliance with the federal rule equally effective from the time of implementation of the federal fuel and may repeal all or portions of the state requirements for sulfur in diesel fuel. The commission has made no change to the rule language in response to these comments; however, the commission is considering expanding the area in future rulemaking.

NPRA commented that the commission should remove all references to "natural" with regard to cetane number in §§114.312, 114.315, and 114.316 because specifying a "natural" cetane number is an unjustifiable narrow definition of the diesel fuel's cetane property. In terms of environmental performance, a diesel fuel that has a natural cetane number of 48 is indistinguishable from a diesel fuel that has a cetane number of 48 obtained through the use of a cetane enhancing additive.

The commission agrees, but would like to note that the proposal approved by the commission for public comment on December 16, 1999, did not include any references to "natural" in regard to cetane numbers. Regarding the issue of natural cetane versus additive improved cetane effects on NO _x , scientific studies document that they both give similar reductions. A comparison of different cetane-improver additives shows that while they may differ quantity-wise to achieve a required certain cetane number, their NO _x reduction effects are similar. The commission has made no change to the rule language in response to this comment.

Koch commented that §114.6 should include a definition for "additive."

The commission agrees and has revised §114.6 to include the definition for "additive" to read as follows: "Additive--Any substance, other than one composed solely of carbon and/or hydrogen, that is intentionally added to gasoline or diesel fuel (including any added to a motor vehicle fuel system) and that is not intentionally removed prior to sale or use and that is approved by and registered with the EPA in accordance with 40 Code of Federal Regulations 79."

Koch commented, without explanation, that §114.312(a) should be revised to delete, "which may ultimately," from the text.

The commission believes that any diesel fuel that could ultimately be used for the control area must be LED. This provision is specifically directed at producers and importers. While the producers and importers may not have control over the handling of the fuel once it leaves their possession, they generally know the area in which it is to be used. This language puts a burden on a producer or importer who is sending fuel for use near the covered area to either: 1) ensure that noncompliant fuel is not meant for distribution in the covered area; or 2) ensure that the fuel complies with these rules. The commission made no change to the rule language in response to this comment.

Koch suggested that the commission delete the proposed requirement that any alternate diesel fuel formulation meet comparable or better emissions of toxic compounds and PM, in addition to VOC and NO _x emissions, when compared to the LED and that §114.312(g) should be revised to read as follows (italics indicate commenter's suggested changes): "(g) Diesel fuel which the producer has demonstrated to the executive director's satisfaction, through emissions and performance testing programs with supporting data, as achieving comparable or better reductions in emissions of the principal ozone precursors ( oxides of nitrogen, plus volatile organic compounds may be used to satisfy the requirements of subsection (a) of this section. For alternative formulations that incorporate additive systems, the estimated emissions benefits of the alternative fuel formulation may be determined by comparing the in-use emissions and performance characteristics of the alternative fuel versus the emissions and performance characteristics of an unadditized fuel, as determined by testing with diesel engines. TNRCC recognizes that additive formulation and testing technology often include factors that can reasonably be considered confidential. Therefore TNRCC will provide a mechanism where details can be supplied by the producer for evaluation of an alternative formulation by an "impartial expert" who can competently judge the merits of the alternative fuel system while retaining the confidentiality of proprietary information. "

The commission agrees with most of the suggested changes, except for the suggested exclusion of PM emissions from the equivalency requirement and the use of an "impartial expert," and has made changes in response to this comment. The commission believes that the emissions performance of the alternative diesel fuel formulations should be equivalent to the specified diesel fuel standards in all emission reductions including PM, not just NO _x and VOC. A mechanism is provided in the rule for the executive director to approve alternative diesel fuel formulations. Proprietary or confidential information would need to be identified as such in the submittal to the executive director. If it is found to be trade secret information, the Texas Public Information Act protects the information from public disclosure.

Koch commented that §114.316(a) should be revised to read as follows: "(a) Every producer or importer that has elected to sell, offer for sale, supply, or offer for supply LED fuel in counties listed in §114.319 of this title (relating to Affected Counties and Compliance Dates) is subject to the requirements of this section. Under these requirements LED which has been produced or imported must conform with the standards for sulfur content, aromatic hydrocarbon content, and minimum cetane number as specified in §114.312 of this title (relating to Low Emission Diesel Standards) or other standards, including type and concentration of additive as specified per §114.312(g) . All records relating to LED must contain a statement declaring whether the aromatic hydrocarbon content of the sample conforms to the basic standard, to a designated alternative limit (DAL) in accordance with §114.313 of this title (relating to Designated Alternative Limits), or to a limit specified in a Certified Diesel Fuel Formulation as approved by an executive order issued by the CARB, or whether the fuel conforms to a formulation approved per §114.312(g)."

The commission agrees that the suggested change clarifies the rule language and has made changes in response to this comment.

Koch commented that §114.316(b) should be revised to read as follows (italics indicate commenter's suggested changes): "(b) Each producer or importer of a fuel that conforms to §114.312 (a) through (f) shall sample and test...."

The commission agrees and made changes in response to this comment.

Koch commented that §114.316(c) should be revised by renumbering it as (d) and a new (c) inserted to read as follows (italics indicate commenter's suggested changes): " (c) Each producer or importer of a fuel that conforms to §114.312 (g) shall sample and test for the appropriate components approved by the executive director in each final blend of LED which the producer or importer has produced or imported, by collecting and analyzing a representative sample of diesel fuel taken from the final blend, using the methodologies specified in §114.315 of this title (relating to Approved Test Methods). If a producer or importer blends diesel fuel components directly to pipelines, tank ships, railway tank cars, or trucks and trailers, the loading(s) shall be sampled and tested for the appropriate components approved by the executive director by the producer or importer or authorized contractor. If the approved blend contains an additive system, the producer or importer or authorized contractor shall maintain records showing that sufficient additive was added to maintain the appropriate additive concentration as approved by the executive director. The producer or importer shall maintain, for two years from the date of each sampling, records showing the sample date, identity of blend sampled, container or other vessel sampled, final blend volume, and the appropriate fuel components. All diesel fuel produced by the producer or imported by the importer and not tested as LED by the producer or importer as required by this section shall be deemed to exceed the standards specified in §114.312 of this title, unless the producer or importer demonstrates that the diesel fuel meets those standards and limits. "

The commission agrees that producers should have the flexibility to use additives to comply with the LED requirements and has made changes in response to this comment.

Koch commented that §114.316(d) should be revised by renumbering it as (e) and to delete "blend identity, blend batch numbers,...test results," from the text. In addition, Koch commented that §114.316(e) should be revised by renumbering it as (f).

The commission agrees that only the producers and importers should be required to submit blend identity and batch numbers on the transfer documents due to downstream combining of different blends and has made changes in response to this comment.

Subchapter A. DEFINITIONS

The Texas Natural Resource Conservation Commission (TNRCC or commission) adopts amendments to §117.10, concerning Definitions. The commission also adopts new §§117.131, 117.133, 117.134, 117.135, 117.138, 117.141, 117.143, 117.145, 117.147, and 117.149, concerning Utility Electric Generation in East and Central Texas; §§117.260, 117.261, 117.265, 117.273, 117.279, and 117.283, concerning Cement Kilns; §117.512, concerning Compliance Schedule for Utility Electric Generation in East and Central Texas; and §117.524, concerning Compliance Schedule for Cement Kilns. Sections 117.10, 117.131, 117.133, 117.135, 117.138, 117.141, 117.143, 117.145, 117.149, 117.260, 117.261, 117.265, 117.279, 117.283, 117.512, and 117.524 are adopted with changes to the proposed text as published in the December 31, 1999 and January 14, 2000 issues of the Texas Register (24 TexReg 11959 and 25 TexReg 308). Sections 117.134, 117.147, and 117.273 are adopted without changes and will not be republished.

The commission adopts these revisions to Chapter 117, concerning Control of Air Pollution from Nitrogen Compounds, and to the State Implementation Plan (SIP) in order to reduce nitrogen oxide (NO _x ) emissions from cement kilns and electric utility power boilers and stationary gas turbines located in ozone attainment counties in east and central Texas. The 34 affected ozone attainment counties in which cement kilns or electric utility power boilers and stationary gas turbines are located are Atascosa, Bastrop, Bexar, Brazos, Calhoun, Cherokee, Comal, Ellis, Fannin, Fayette, Freestone, Goliad, Gregg, Grimes, Harrison, Hays, Henderson, Hood, Hunt, Lamar, Limestone, Marion, McLennan, Milam, Morris, Nueces, Parker, Red River, Robertson, Rusk, Titus, Travis, Victoria, and Wharton Counties. Because of regional transport, the commission believes that this rulemaking will reduce ozone in ozone attainment areas, ozone near-nonattainment areas, and, in combination with other emission reduction rules, is a necessary and essential component of the one- hour attainment demonstration for ozone nonattainment areas.

In addition, the commission has renumbered the existing Division 2, concerning Commercial, Institutional, and Industrial Sources, as Division 3, and existing Subchapter D, concerning Administrative Provisions, as Subchapter E. Sections 117.131, 117.133 - 117.135, 117.138, 117.141, 117.143, 117.145, 117.147, and 117.149 were placed in a new Subchapter B, Division 2, concerning Utility Electric Generation in East and Central Texas, and §§117.260, 117.261, 117.265, 117.273, 117.279, and 117.283 were placed in a new Subchapter B, Division 4, concerning Cement Kilns. Sections 117.512 and 117.524 were placed in the renumbered Subchapter E, concerning Administrative Provisions. The renumbering of the existing Subchapter D as Subchapter E is necessary because the commission adopted a new Subchapter D in separate rulemaking published in this issue of the Texas Register .

The new sections are one element of the Dallas/Fort Worth (DFW) Attainment Demonstration SIP and were developed at the request of the North Texas Clean Air Steering Committee, which represents the DFW ozone nonattainment area. The purpose of these rules is to reduce NO _x emissions from cement kilns and electric utility power boilers and stationary gas turbines as part of the control strategy to reduce emissions of ozone precursors in order for the DFW ozone nonattainment area to be able to demonstrate attainment with the National Ambient Air Quality Standards (NAAQS) for ground-level ozone.

In addition, the revisions are one element of a new combined strategy to meet the 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 in compliance with the federal ozone standards. The new strategy is also necessary to help the Beaumont/Port Arthur (BPA), DFW, and Houston/Galveston (HGA) ozone nonattainment areas as defined in 30 TAC §101.1, concerning Definitions, move closer to reaching attainment with the ozone NAAQS. The strategy takes into account recent science that shows that regional approaches may provide improved control of air pollution. In particular, staff has conducted photochemical grid modeling which indicates that 50% reductions in NO _x from elevated point sources in east and central Texas will reduce peak one-hour ozone between 14 and 27 parts per billion (ppb) at specific locations in the region, depending on the modeling day. The one-hour ozone benefits stretch across the east and central Texas counties and average six to seven ppb. Based on a one-hour exceedance design value of 128 ppb, the projected benefits of 50% point source NOx reductions in the attainment counties of east and central Texas may be large enough to prevent some areas from being reclassified as not attaining the one-hour ozone NAAQS. It is the requirement under the Federal Clean Air Act (FCAA) Amendments of 1990 (42 United States Code (USC)) for meeting the one-hour standard that forms the basis for the regional NOx control requirements. This rulemaking is based upon a body of evidence from aircraft measurements, seasonal modeling, back trajectories, and statistical studies indicating that electric generating facilities and cement kilns in central and eastern Texas contribute to the background levels of NO _x which impact the DFW area. Documents explaining these additional studies are included as appendices to the SIP. Additional details concerning the need for a regional strategy are as follows.

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

The DFW ozone nonattainment area, an area defined by Collin, Dallas, Denton, and Tarrant Counties, was originally designated "moderate" under the FCAA Amendments of 1990 (42 USC) and thus was required to attain the one-hour NAAQS for ozone by November 15, 1996. As required by the FCAA, the state submitted an attainment demonstration plan in 1994 which projected attainment of the ozone NAAQS by 1996. This plan was based on a volatile organic compound (VOC) reduction strategy. DFW did not attain the ozone NAAQS in 1996. The United States Environmental Protection Agency (EPA) is authorized to redesignate an area to the next higher classification ("bump up") if the area fails to attain by the required date. In March 1998, in accordance with 42 USC, §7511(b)(2), the EPA reclassified the DFW area from moderate to serious, based on monitored exceedances of the ozone NAAQS between 1994 and 1996. The reclassification required the state to submit a revised SIP that demonstrates that the ozone NAAQS will be met in DFW by November 15, 1999. Because the DFW area continued to exceed the ozone NAAQS in 1999, the EPA may bump up the area to the severe classification. Regardless, the EPA and 42 USC, §7410 and §7502(a)(2), require the state to submit a revised SIP which demonstrates that the area will attain the ozone NAAQS as expeditiously as practicable. The rules adopted for DFW in this notice are one element of the ozone attainment demonstration SIP for DFW being adopted concurrently in this issue of the Texas Register . The commission plans to submit this SIP to the EPA in April, 2000.

In 1996, the commission began to develop new modeling for the DFW area and now is using newer air quality models with improved meteorological and emission inputs. The newer modeling since 1996 shows that reductions of NOx in the DFW area and regionally will be necessary to attain the ozone NAAQS. The current modeling also shows that achieving the ozone NAAQS in the DFW area will require strenuous effort because the area's rapid growth has resulted in increasing amounts of emissions due to increased levels of activity in the area. The emissions from increased activity are offsetting the emission reductions being achieved from new emission standards applicable to the on-road and non-road engine source categories which dominate the emissions inventory in the DFW area.

The emission reduction requirements adopted as part of this SIP package are the outcome of a development process which involved the EPA, the commission, local elected officials, citizens, industrial stakeholders, air quality researchers, and hired consultants. Local officials from the DFW area have formally submitted a resolution to the commission requesting the inclusion of many specific emission reduction strategies, including the one contained in these rules.

The NO _x reductions required for the area to attain the ozone NAAQS have been estimated by extensive use of sophisticated air quality grid modeling which, because of its scientific and statutory grounding, is the chief policy tool for designing emission reductions. Title 42 USC, §7511a(c)(2), requires the use of photochemical grid modeling for ozone nonattainment areas designated serious, severe, or extreme. The modeling has been conducted with input from a technical advisory committee. Hundreds of emission control strategies were considered in developing the modeling. Varying degrees of reductions from point sources and mobile sources were analyzed in at least fifty modeling iterations, to test the effectiveness of different NO _x reductions. The attainment demonstration modeling submitted for public hearing and comment concurrently with these rules shows that, in order for DFW to achieve the ozone NAAQS by 2007, almost all of the practicably achievable NO _x reductions are necessary from each emission source category, including reductions from counties surrounding the DFW nonattainment area. Therefore, each strategy, including the reductions required by this rulemaking, is crucial to meet federal requirements for the DFW nonattainment area.

At the time the 1990 FCAA Amendments were enacted, the focus of controlling ozone pollution was on local controls. However, over the last ten years an increasing number of air quality professionals have concluded 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 with aircraft that found that regional air pollution from sources inside of Texas should be considered when studying air quality in Texas' ozone nonattainment areas. The Texas studies are corroborated by research studies of the Ozone Transport Assessment Group (OTAG), the most comprehensive attempt ever undertaken to understand and quantify the transport of ozone. The results of both the commission and OTAG studies point to the need to take a regional approach, as proposed in this rulemaking, to controlling air pollutants.

During the OTAG studies, the commission's modeling staff ran several sensitivity analyses for Texas using a regional modeling setup based on the Coastal Oxidant Assessment for Southeast Texas (COAST) study. This analysis used the OTAG emission inventory, updated for Texas sources, to assess the impact of potential OTAG reductions on Texas. One modeling scenario, OTAG 5c, consisting of reductions across the domain (60% reduction of point source NO _x , 30% reduction of low-level NO _x , and 30% reduction of VOC), indicated that modeled reductions would reduce peak eight-hour ozone by as much as 20 ppb throughout most of the eastern half of Texas. Overall, the modeling indicated that a regional reduction strategy would benefit a wide area of the state.

During modeling for the HGA 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 HGA, when applied simultaneously with local reductions. Unlike the commission's regional modeling exercises discussed in the previous paragraphs, these HGA model runs offer an opportunity to assess separately the benefits of reductions made within and outside a region. Model runs with and without the regional reduction scenarios in HGA were conducted. Modeling runs were completed to evaluate the ozone concentrations in the COAST modeling domain for September 8, 1993 with year 2007 projected emissions and assuming a 70% reduction of NOx combined with a 15% reduction of VOC in the eight-county HGA area. Even with the large reductions in HGA, much of the upper Texas Coast had ozone concentrations that challenge the one-hour standard. The application of OTAG 5c reductions outside the HGA eight-county area showed that the reductions are clearly beneficial to HGA, with additional ozone benefits of between five and ten ppb.

Additional modeling has been completed by commission staff assessing the potential benefits of regional NO _x reductions in the attainment counties of east and central Texas. This modeling indicates that controls which reduce all elevated point source NO _x emissions by 50% in the region will reduce peak one-hour ozone between 14 and 27 ppb at specific locations in the region, depending on the modeling day. The one-hour ozone benefits stretch across the east and central Texas counties and average six to seven ppb. Based on a one-hour exceedance design value of 128 ppb, the projected benefits of 50% point source NO _x reductions in the attainment counties of east and central Texas may be large enough to prevent some areas from being reclassified as not attaining the one-hour ozone NAAQS.

Modeling tests indicate that point source NO _x reductions of less than 50% have limited ozone reduction benefit, whereas reductions at and above 50% show increasing ozone reduction benefits. For example, in the DFW area, 25% NO _x reductions in all attainment counties of east and central Texas result in a seven to ten ppb one-hour ozone reduction, whereas 50% NO _x reductions over the same area result in a 21-27 ppb one-hour ozone reduction. Doubling the NO _x reduction from 25% to 50% provides more than twice the ozone reduction benefit. However, this test also includes reductions made in the DFW area. The benefit attributable to the regional reduction is about four to five ppb. It is clear that NO _x reductions in just the attainment counties of east and central Texas are not sufficient for DFW to attain the one-hour ozone NAAQS. Substantial reductions will still be needed within the DFW four-county nonattainment area and the surrounding eight consolidated metropolitan statistical area (CMSA) counties.

The commission's air quality modeling studies conducted for the DFW area show that attaining the one-hour ozone NAAQS will be difficult, and that NOx reductions from all modeled source categories that impact DFW's air quality will be required. Therefore, reductions of 50% NOx in the attainment counties of east and central Texas are a necessary component for the DFW area to attain the one-hour ozone NAAQS. Consequently, these Chapter 117 rules are a necessary component of the DFW and regional NO _x reduction strategy.

The increasing benefit of 50% NO _x reductions is also seen in other areas of east and central Texas. In evaluating eight-hour modeling data for six episode days in the Tyler-Longview area, a 25% decline in NO _x provides an average reduction in peak eight-hour ozone of 12 ppb, whereas a 50% decline in NO _x provides an average reduction of 29 ppb. Similarly in Austin, a 25% NO _x reduction provides an average ozone benefit of six ppb, whereas a 50% reduction provides an average ozone benefit of 15 ppb. Tyler-Longview and Austin air quality monitoring data have had values in excess of the eight-hour NAAQS. The reductions in the eight-hour ozone average will be very helpful to these areas.

The commission is developing a regional strategy to reduce most categories of man-made NO _x emissions by approximately 50% in the attainment counties of east and central Texas. Emissions of NOx come mainly from the combustion of fossil fuels, particularly motor vehicles and electric power plants. In recent years, the power plants in the attainment counties in east and central Texas accounted for nearly as much NO _x as all motor vehicles used on all roads in the region. However, recently adopted regulations requiring cleaner fuels and vehicles are projected to reduce vehicular NO _x emissions in the attainment counties in east and central Texas by 2007 to an amount approaching half of the 1996 emissions. In contrast, new regulations would be necessary in order to cut the NO _x emissions from power plants and other point sources in the region approximately in half by 2007.

Under the new emission reduction mandates contained in Senate Bill (SB) 7, 76th Legislature, 1999, the 1997 NO _x emissions of approximately 270 tons per ozone day (tpd) (daily emissions June-August) from the grandfathered electric generating facilities (EGFs) in the attainment counties of east and central Texas could be expected to decline by about 50%. However, when the SB 7 reduction requirement is expressed as a percentage reduction of the NO _x from all EGFs in the attainment counties of east and central Texas, including permitted facilities, the 50% reduction amounts to only an 18% reduction, since 480 tpd of the total EGF emissions of 750 tpd of NO _x in 1997 came from permitted facilities. In combination with the SB 7 reductions in Chapters 101, concerning General Air Quality Rules, and 116, concerning Control of Air Pollution by Permits for New Construction or Modification (see the January 7, 2000 issue of the Texas Register (25 TexReg 128)), these Chapter 117 rules would reduce 1997 EGF NO _x emissions in the attainment counties of east and central Texas by about 50%, cement kiln NO _x emissions in these counties by about 27%, and total point source NO _x emissions in these counties by about 35%. Therefore, these Chapter 117 rules are a necessary component of the regional NO _x reduction strategy. As noted earlier, a 50% NO _x reduction was the goal, but in some cases technology is not available which would achieve a 50% or higher NO _x reduction. Specifically, for wet process cement kilns, selective noncatalytic reduction (SNCR) reportedly has difficulties involved in continuous injection of the reducing agents. While SNCR is apparently not applicable to wet process cement kilns, it does appear to be a promising technology for dry process cement kilns. The other post-combustion control available, selective catalytic reduction (SCR), has been tested previously on cement kilns. The application of SCR at cement kilns was found to be problematic due to the high concentrations of particulate matter in the exhaust gas stream. This leads to catalyst fouling, causing high pressure drops and reduced catalyst activity. A 30% NO _x reduction was established as the goal for cement kilns since this is a level which the commission expects can be achieved through combustion modifications.

PUBLIC UTILITY REGULATORY ACT DETERMINATION

As described earlier in this preamble, the commission adopts these revisions to Chapter 117 and the SIP in order to reduce NO _x emissions in ozone attainment counties in east and central Texas. Because of regional transport, the commission believes that this rulemaking will reduce ozone in ozone attainment areas, ozone near-nonattainment areas, and, in combination with other emission reduction rules, is a necessary and essential component of the one-hour attainment demonstration for ozone nonattainment areas. Accordingly, the commission makes the following determination, as required by the Public Utility Regulatory Act (PURA), Texas Utilities Code (TUC), §39.263(c)(1)(A) and §39.263(c)(3): reductions of NO _x made in compliance with this rulemaking are hereby determined to be an essential component in achieving compliance with the NAAQS for ground-level ozone; and the amount and location of reductions of NO _x emissions resulting from this rulemaking are hereby determined to be consistent with the air quality goals and policies of the commission.

SECTION BY SECTION DISCUSSION

The changes to §117.10 add definitions of "continuous emission monitoring system (CEMS)," "large DFW system," "small DFW system," "predictive emissions monitoring system (PEMS)," and "twenty-four hour rolling average." The terms "CEMS" and "PEMS" are used in multiple sections of Chapter 117 but are not currently defined. The new definitions of CEMS and PEMS will clarify these terms. The terms "large DFW system" and "small DFW system" are being added as new §117.10(18) and (36), respectively, in response to comments on the proposed 30 TAC Chapter 117 rules identified as Rule Log No. 1999-056-117-AI (24 TexReg 11977, December 31, 1999). The reasoning for the suggested definitions are found in the preamble for the final 30 TAC Chapter 117 rules identified as Rule Log No. 1999-056-117-AI which is published elsewhere in this issue of the Texas Register . The definition of "twenty-four hour rolling average" was developed in response to a request for clarification from electric utilities and is consistent in form with the recently adopted definition of "thirty-day rolling average." (See the November 12, 1999 issue of the Texas Register (24 TexReg 10113).) In addition, the changes to §117.10 revise the definition of "electric power generating system" by replacing the use of this term within the definition with a reference to generation of electricity for compensation; and clarify that the rules continue to apply if the electric power generating system is sold to an entity which otherwise would not be subject to the rules. The changes to the definition of "electric power generating system" further revise the definition to include boilers, steam generators, auxiliary steam boilers, and stationary gas turbines that generate electric energy for compensation; are owned or operated by an electric cooperative, independent power producer, municipality, river authority, or public utility, or any of its successors; and are located in the listed 31 attainment counties of east and central Texas in which EGFs are located. The changes to §117.10 also revise the definition of "major source" by adding the major source definition contained in the Prevention of Significant Deterioration of Air Quality regulations applicable in the listed 34 attainment counties of east and central Texas in which EGFs or cement kilns are located. This revision would prevent confusion caused by the title under which these Chapter 117, Subchapter B rules were proposed: "Combustion at Existing Major Sources." In addition, the changes to §117.10 clarify the intent of the definition of "nitric acid production unit" by replacing a reference to "facility" with the term "source" and clarify the intent of the definition of "parts per million by volume (ppmv)" by replacing the reference to "rule" with a reference to the more descriptive term "chapter." The changes to §117.10 also clarify the intent of the definitions of "stationary gas turbine" and "stationary internal combustion engine" by replacing the reference to "facility" with a reference to "major source," and revise the definition of "stationary internal combustion engine" by incorporating language from 40 Code of Federal Regulations (CFR) Part 89 (Control of Emissions from New and In-Use Nonroad Engines), §89.2 (Definitions), to clarify the distinction between stationary and mobile nonroad engines. In addition, the changes to §117.10 revise the definition of "unit" by deleting language regarding the date a unit was placed into service. The language being deleted is unnecessary because it duplicates language contained in §§117.103(a)(1), 117.105(k)(2), 117.203(1), and 117.205(a)(3). Finally, the changes to §117.10 would update the reference to Chapter 101 to reflect the new title of this chapter adopted by the commission on December 1, 1999. (See the December 17, 1999 issue of the Texas Register (24 TexReg 11494).)

The new §117.131, concerning Applicability, identifies the sources affected by the requirements. This rule applies to boilers and stationary gas turbines used to generate electric power which were placed into service before December 31, 1995. The rule would not apply to auxiliary boilers which are sometimes present at power plants. Auxiliary boilers are much smaller than power boilers, operate rarely, and account for only 0.01% of the power plant emissions in the attainment counties of east and central Texas. Requiring these small boilers to meet the emission specifications would not be cost-effective, considering the emission control, monitoring, and administrative costs and the negligible emission reductions that would result. The applicability of this division is limited to the major electricity producers: electric cooperatives, independent power producers, municipalities, river authorities or public (investor owned) utilities in the specified counties. Electricity production is either the principal product, or one of the principal products of these entities. Not included are owners or operators of commercial, institutional, and industrial sources that sell less than one-third of their potential electrical output capacity to the electric grid for compensation. Among these non-utility sources are some of the gas turbine cogeneration facilities located at certain chemical plants and refineries in the affected counties. Examples of other, smaller sources outside the scope of the revised rule include a sawmill which could use a boiler to cogenerate steam and electricity, and smaller entities, such as a recreational vehicle park owner or operator who provides electricity for park residents. Emissions related to electric generation from such commercial, institutional, and industrial sources are small, and the resulting reductions from these smaller sources would not be cost-effective. The commission will evaluate the need for reductions from these exempt non-utility sources separately from this rulemaking.

Section 117.131 as adopted does not include units which were placed into service after December 31, 1995. Inclusion of new units is not necessary because the best available control technology (BACT) requirements of the commission's new source review permitting program will ensure that NO _x emissions are adequately controlled at units placed into service after that date. Therefore, it is unnecessary to include counties other than the 31 listed counties.

The new §117.133, concerning Exemptions, identifies emission units which would not be subject to the new emission specification. This division does not apply to utility electric power boilers or stationary gas turbines if the annual heat input does not exceed 2.2 (10 ¹¹ ) British thermal units (Btu) per year, averaged over three years. If operated at 2.2 (10 ¹¹ ) Btu per year or less, potential emissions are less than 30 tons per year of NO _x from any of the affected permitted gas-fired power boilers or turbines. Similarly, this division does not apply to stationary gas turbines and auxiliary boilers which are used solely to power other units during start-ups; units which operate no more than an average of 10% of the hours of the year, averaged over the three most recent calendar years, and no more than 20% of the hours in a single calendar year; and cogeneration units that, averaged over the three most recent calendar years, sold less than one-third of its potential electrical output capacity to a utility power distribution system. Requiring such small emission sources to meet the emission specifications would not be cost-effective, considering the emission control, monitoring, and administrative costs and the negligible emission reductions that would result.

The new §117.134, concerning Gas-Fired Steam Generation, relocates existing NO _x emission specifications for electric utility boilers in certain ozone attainment counties from §117.601, concerning Gas-Fired Steam Generation. In addition to the 12 DFW and HGA ozone nonattainment counties, the minimal NO _x standards of §117.601 have been applicable in 19 counties comprising the attainment counties of the Houston and Dallas/Fort Worth Air Quality Control Regions since 1972. The change brings the Chapter 117 utility boiler NO _x limits affecting ozone attainment counties into consecutive sections of a common rule division. Counties listed in §117.601 which do not contain boilers above the applicability threshold of 600,000 pounds per hour maximum steam generation capacity have been removed. Maintaining rule applicability in these counties for future units is unnecessary, because any new gas-fired boilers would be subject to much lower BACT emission limitations of the commission's NSRP program. In separate rulemaking which is published elsewhere in this issue of the Texas Register , the commission is repealing §117.601 because the §117.601 requirements for the affected counties in ozone nonattainment areas are being relocated to the rule division for electric utility generation in ozone nonattainment areas.

The new §117.135, concerning Emission Specifications, sets the NOx emission limit at 0.165 pound (lb) of NO _x per million Btu (MMBtu) for coal or lignite-fired electric power boilers. Many permitted EGFs are currently authorized to operate at an emission rate in excess of 0.165 lb/MMBtu. Specifically, current average emission rates for permitted EGFs in attainment counties in East Texas are approximately 0.33 lb NO _x /MMBtu. A reduction to 0.165 lb NOx /MMBtu would accomplish the goal of a 50% reduction necessary to achieve regional reductions in ambient ozone. For gas-fired electric power boilers, the NO _x emission limit is at 0.14 lb NO _x /MMBtu, while for stationary gas turbines, the NO _x emission limit is at 0.15 lb NOx /MMBtu (or alternatively, 42 ppmv NO _x , adjusted to 15% oxygen), except those subject to SB 7 which are limited to 0.14 lb NO _x /MMBtu.

The new §117.138, concerning System Cap, creates a flexible alternative to direct compliance with the NO _x emission specifications in §117.135. This section is patterned on the existing source cap compliance option in §117.223, for industrial, commercial and institutional combustion sources. The system cap sets limits on total pounds of NO _x allowed to be emitted by an electric utility system. A cap has the advantage over rate-based standards of allowing the source owner to control the activity levels of the regulated equipment as a means of compliance. This means that a company can comply by installing less extensive emission controls and choosing to operate the regulated equipment less, or by upgrading equipment to require less fuel combustion.

The averaging period for the NO _x system cap is an annual average, consistent with the emission specifications of §117.135, which are on the basis of an annual (calendar year) average. The baseline period for H _i , the historical heat input used in the annual average of §117.138(c)(1), is 1996, 1997, and 1998. This three-year period is consistent with the commission staff's modeling period. Fluctuations in ambient temperature patterns often cause significant annual variation in electric demand. An average over three years limits the influence of one particular year on the design value.

Section 117.138 does not require the inclusion of new electric generating units in the system cap. Inclusion of new units is not necessary because the BACT requirements of new source review permitting will ensure that NOx emissions are adequately controlled at new units.

The new §117.141, concerning Initial Demonstration of Compliance, establish the criteria for an initial demonstration of compliance at utility electric power boilers and stationary gas turbines, including testing, and installation and verification of operational status of CEMS and PEMS before the testing. The requirements are parallel to existing requirements in §117.111 and §117.211, concerning Initial Demonstration of Compliance.

The new §117.143, concerning Continuous Demonstration of Compliance, requires installation of CEMS or PEMS, or less stringent monitoring requirements in some cases. Many of the electric utility boilers in the 31 affected attainment counties are currently monitoring NO _x continuously under the federal acid rain rules of 40 CFR 75; some of the smaller units not subject to the federal acid rain rules of 40 CFR 75 are required to monitor NO _x under existing new source review permitting requirements. For peaking plants, the owner or operator may choose to comply with the less stringent requirements of 40 CFR Part 75, Appendix E, §1.1 or §1.2, and calculate NO _x emission rates based on those procedures, rather than install CEMS or PEMS. Similarly, for auxiliary boilers, the owner or operator may choose to comply with the appropriate (considering boiler maximum rated capacity and annual heat input) industrial boiler monitoring requirements of §117.213, concerning Continuous Demonstration of Compliance, in lieu of installing CEMS or PEMS. The relatively limited situations in which additional costs for new NO _x monitors would be necessary is expected to make the system cap an attractive option for electric utilities. The requirements are parallel to existing requirements in §117.113 and §117.213, concerning Continuous Demonstration of Compliance.

The new §117.145, concerning Final Control Plan Procedures, specifies certain information requirements for showing compliance with the emission specifications of §117.135 or the system cap of §117.138, to be included in a report submitted to the executive director. The requirements are parallel to existing requirements in §117.115 and §117.215, concerning Final Control Plan Procedures.

The new §117.147, concerning Revision of Final Control Plan, allows the owner or operator to submit a revised final control plan, provided that the revised plan continues to demonstrate compliance with the appropriate emission limits and the final compliance dates.

The new §117.149, concerning Notification, Recordkeeping, and Reporting Requirements, specify the required start-up and shutdown records, notification, reporting of test results, annual reports, and recordkeeping for electric power boilers and stationary gas turbines. The requirements are parallel to existing requirements in §117.119 and §117.219, concerning Notification, Recordkeeping, and Reporting Requirements.

The new §117.260, concerning Cement Kiln Definitions, adds definitions of clinker, long dry kiln, long wet kiln, portland cement, portland cement kiln, precalciner kiln, and preheater kiln.

The new §117.261, concerning Applicability, specifies the five counties (Bexar, Comal, Ellis, Hays, and McLennan) in which the new portland cement kiln requirements apply. These are the counties in east and central Texas in which existing portland cement kilns are located. Inclusion of new cement kilns is not necessary because the BACT requirements of new source review permitting will ensure that NO _x emissions are adequately controlled at new kilns. Therefore, it is unnecessary to include counties other than the five listed counties.

The new §117.265, concerning Emission Specifications, establishes emission limits on the basis of pounds of NO _x per ton of clinker produced. These emission limits are based on the NOx emissions for a 30-day rolling average, and vary depending on the type of cement kiln (long wet; long dry; preheater; preheater-precalciner; or precalciner). The emission limits are based on those described in the EPA's notice of proposed rulemaking concerning Federal Implementation Plans to Reduce the Regional Transport of Ozone which was published in the October 21, 1998 issue of the Federal Register (63 FR 56394). The EPA stated that these limits represent an average 30% decrease in NO _x emissions from uncontrolled levels. In order to ensure emission reductions of approximately 30% from the 1996 emissions inventory in Ellis County, the commission has established a more stringent limit for wet process cement kilns in this county. To provide additional flexibility in all affected counties yet still ensure that all reasonable emission reduction measures have been implemented, the commission has added an option which provides that each kiln equipped with low-NO _x burners and mid-kiln firing is not required to meet the NO _x emission limits.

The new §117.273, concerning Continuous Demonstration of Compliance, requires the installation, calibration, maintenance, and operation of a CEMS or PEMS to monitor kiln exhaust NO _x . Either a CEMS or PEMS is necessary in order to determine continuous compliance with the emission limits.

The new §117.279, concerning Notification, Recordkeeping, and Reporting, requires notification concerning CEMS or PEMS performance evaluation and submission of any CEMS or PEMS relative accuracy test audit. The new §115.279 also requires monitoring records of daily NO _x emissions, daily production of clinker, average NO _x emission rate (30-day rolling average), stack sampling results, and the results of initial certification testing, evaluations, calibrations, checks, adjustments, and maintenance of CEMS and PEMS.

The new §117.283, concerning Source Cap, provides an alternative to complying with the NO _x emission limits of §117.265. Specifically, §117.283 allows an owner or operator to choose to reduce total NO _x emissions (in pounds per day (ppd)) from all cement kilns at the account to at least 30% less than the total NOx emissions (in ppd) from all cement kilns in the account's 1996 emissions inventory. At cement plants with multiple kilns, this will allow NO _x emission reductions to be achieved at these kilns in whatever manner the owner or operator considers to be the most cost-effective and technically feasible. Any cement kilns placed into service on or after December 31, 1999 are included in order to allow a new cement kiln's lower NO _x emission rate to be credited toward the NO _x emission reductions needed by older cement kilns at the same account while still achieving the goal of an overall reduction in NO _x emissions.

The new §117.512, concerning Compliance Schedule for Utility Electric Generation in East and Central Texas, sets a compliance date of May 1, 2003 for units owned by utilities which are subject to the cost-recovery provisions of TUC, §39.263(b), and May 1, 2005 for all other units. This date allows approximately three years to achieve emission compliance for units owned by utilities which are subject to the cost-recovery provisions of TUC, §39.263(b). A two-year implementation schedule has been considered necessary but achievable for other emission reduction requirements in Chapter 117. The FCAA requires states to develop SIPs that will result in attainment as expeditiously as practicable, and compliance with regional NO _x reduction rules by May 1, 2003, has been considered by the EPA to be necessary for such expeditious attainment of the ozone NAAQS. For EGFs, an additional year for compliance appears necessary to allow adequate time for design engineering, equipment procurement, and installation. The commission expects that most projects necessary to meet the new Chapter 117 requirements for EGFs will be able to qualify for the standard permit available under 30 TAC Chapter 116, §116.617 (Standard Permit for Pollution Control Projects). An additional two years is being provided for units owned by utilities which are not subject to the cost-recovery provisions of TUC, §39.263(b), in order to address concerns about the availability of engineering, fabrication, and installation contractors.

The new §117.524, concerning Compliance Schedule for Cement Kilns, establishes a compliance date of May 1, 2003 for cement kilns in Ellis County, and May 1, 2005 for cement kilns in Bexar, Comal, Hays, and McLennan Counties. This date allows approximately three years for Ellis County cement kilns to achieve emission compliance. A two-year implementation schedule has been considered necessary but achievable for other emission reduction requirements in Chapter 117. Because of the unique nature of cement kilns, the commission believes it is appropriate to allow approximately three years for design engineering, equipment procurement, and installation. The commission expects that most projects necessary to meet the new Chapter 117 requirements for cement kilns will be able to qualify for the standard permit available under 30 TAC Chapter 116, §116.617 (Standard Permit for Pollution Control Projects). An additional two years is being provided for cement kilns in Bexar, Comal, Hays, and McLennan Counties in order to address concerns about the availability of engineering, fabrication, and installation contractors.

The commission requested comments on what, if any, emission banking and trading program should be developed to offer alternative means of compliance for facilities required to make NO _x reductions for SIP purposes. The commission is exploring the possibility of either the creation of a mass cap and trade system or revising the existing emission banking and trading system in Chapter 101, General Air Quality Rules, §101.29, concerning Emissions Banking and Trading. The commission intends to propose a comprehensive trading system during summer 2000. The commission believes it is appropriate to develop a holistic approach to emission trading, as opposed to a piecemeal approach. As noted in the rule proposal preamble, the commission is open to accepting all ideas regarding an emission trading program. Comments on emission trading will not be addressed as part of this rulemaking, but will be addressed when the commission considers its banking and trading program during summer 2000.

A mass cap and trade system would require that the commission allocate allowances to participating facilities. Each allowance would be an authorization to emit a specific amount of NO _x , for example 100 tons. Each participating facility would be required to have allowances equal to or greater than its emissions during a specific control period. The control period could be identified as an ozone season, a 12-month period, or some other appropriate period. Allowances could be traded from one facility to another so a facility that reduced emissions below its allotted allowances could sell excess allowances to another facility or a broker. Additionally, a facility that finds required reductions to be cost-prohibitive can purchase equivalent credits to meet its burden of compliance. This option would require monitoring and reporting on a regular basis to assure that compliance with the allowances is met. This system would put a cap on all emissions from participating facilities. Participation in this type of system is usually mandatory to insure that participating facilities must comply with equivalent emission requirements. An allowance trading system could be similar to the Emissions Banking and Trading of Allowances System adopted on December 16, 1999 under Subchapter H of Chapter 101, implementing the allowance trading requirements of SB 7. (See the January 7, 2000 issue of the Texas Register (25 TexReg 128).)

The existing emission reduction credit (ERC) and discrete ERC (DERC) trading systems are based on the concepts of open market systems. Participation is not mandatory; facilities have the option of either complying with the emission standard or using emission credits to offset the emission standard. Those sources choosing to participate in the open market system would quantify their reductions from a set baseline. These reductions could then be purchased and used by other sources to satisfy their NO _x reduction obligation.

If a mass cap and trade system were proposed, the commission requested comment on the following issues: trading restrictions; expiration of allowances; addition of new sources into the system; initial allotment of allowances; and relationship to federal new source review permitting (prevention of significant deterioration (PSD) and nonattainment).

If the existing trading program is relied on to provide flexibility, the commission requested comments on what changes need to be made to address the following issues: insuring that banked emissions are not also used towards any SIP demonstration (double counting); usability of the trading system; and baseline.

The commission requested comments on these issues and any other issues that might be relevant to the development of an emission banking and trading program. Since the commission is not proposing a program at this time, this rule adoption preamble does not include an analysis of the comments on this issue. The purpose of soliciting these comments is to assist the commission in the development of an emission banking and trading program. The commission held stakeholder meetings to discuss the comments received and solicit input before formally proposing an emissions banking and trading program, estimated to occur sometime during summer 2000.

EFFECT ON SITES SUBJECT TO THE FEDERAL OPERATING PERMITS PROGRAM

Since 30 TAC Chapter 117 is an applicable requirement under 30 TAC Chapter 122, owners or operators subject to the Federal Operating Permit Program must, consistent with the revision process in Chapter 122, revise their operating permit to include the revised Chapter 117 requirements for each emission unit affected by the revisions to Chapter 117 at their site.

FINAL REGULATORY IMPACT ANALYSIS

The commission has reviewed the rulemaking in light of the regulatory analysis requirements of Texas Government Code, §2001.0225, and has determined that the rulemaking meets the definition of a "major environmental rule" as defined in that statute. "Major environmental rule" means a rule the specific intent of which is to protect the environment or reduce risks to human health from environmental exposure and that may adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state. The amendments to Chapter 117 will require emission reductions from cement kilns and utility electric boilers and stationary gas turbines in attainment counties in east and central Texas. The rules are intended to protect the environment and may have adverse effects on certain EGFs and cement kilns which could be considered a sector of the economy.

Although the amendments meet the definition of a "major environmental rule" as defined in the Texas Government Code, they do 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 EPA under FCAA, §109, and therefore meet a federal requirement. States are primarily responsible for ensuring attainment and maintenance of the NAAQS once EPA has established them. Under FCAA, §110 and related provisions, states must submit, for approval by EPA, SIPs that provide for the attainment and maintenance of NAAQS through control programs directed to sources of the pollutants involved. The commission has performed photochemical grid modeling which predicts that the controls required by these rules will result in reductions in ozone formation in one or more nonattainment areas in Texas. 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 to help keep attainment and near-nonattainment areas from going into nonattainment. The rulemaking does not exceed a standard set by federal law, exceed an express requirement of state law (unless specifically required by federal law), or exceed a requirement of a delegation agreement. The rulemaking was not developed solely under the general powers of the agency, but was specifically developed to meet the air quality standards established under federal law as the NAAQS and authorized under Texas Clean Air Act (TCAA), §§382.011, 382.012, and 382.017. Comments received during the comment period regarding the draft regulatory impact analysis (RIA) are addressed in the SECTION BY SECTION ANALYSIS section of this preamble.

TAKINGS IMPACT ASSESSMENT

The commission has completed a takings impact assessment for this rulemaking. The following is a summary of that assessment. The rules requires NOx emission reductions from cement kilns located in Bexar, Comal, Ellis, Hays, and McLennan Counties. The rules also require NOx emission reductions from utility electric power boilers and stationary gas turbines that generate electric energy for compensation owned or operated by an electric cooperative, independent power producer, municipality, river authority, or public utility located in Atascosa, Bastrop, Bexar, Brazos, Calhoun, Cherokee, Fannin, Fayette, Freestone, Goliad, Gregg, Grimes, Harrison, Henderson, Hood, Hunt, Lamar, Limestone, Marion, McLennan, Milam, Morris, Nueces, Parker, Red River, Robertson, Rusk, Titus, Travis, Victoria, and Wharton Counties.

The rules are one element of the DFW Attainment SIP as well as part of a new strategy to meet the NAAQS for ground-level ozone. The strategy is necessary to reduce overall background levels of ozone in order to assist in keeping ozone attainment areas and near-nonattainment areas in compliance with federal ozone standards. The strategy and the modeling supporting it are discussed in other sections of this preamble. Promulgation and enforcement of the rule amendments may possibly burden private real property because the permanent installation of new equipment, such as low- NO _x burners or post-combustion controls, may be necessary to comply with the new requirements. Although the rules do not directly prevent a nuisance or prevent an immediate threat to life or property, they do prevent a real and substantial threat to public health and safety and 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 this 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 relates to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act of 1991, as amended (Texas Natural Resources Code, §§33.201 et seq.), and the commission's rules in 30 TAC Chapter 281, Subchapter B, concerning Consistency with Texas Coastal Management Program. As required by 31 TAC §505.11(b)(2) and 30 TAC §281.45(a)(3), relating to actions and rules subject to the CMP, commission rules governing air pollutant emissions must be consistent with the applicable goals and policies of the CMP. The commission has reviewed this action for consistency with the CMP goals and policies in accordance with the regulations of the Coastal Coordination Council. For this rulemaking, the commission has determined that the rules are consistent with the applicable CMP goal expressed in 31 TAC §501.12(1) of protecting and preserving the quality and values of coastal natural resource areas, and the policy in 31 TAC §501.14(q), which requires that the commission protect air quality in coastal areas. This rulemaking is intended to reduce overall emissions of NO _x from cement kilns and electric utility boilers and stationary gas turbines. This action is consistent with the CMP because it does not authorize any new emissions and will reduce existing emissions of NO _x . No comments were received during the comment period regarding the consistency of the rulemaking with the CMP goals and policies.

HEARING AND COMMENTERS

Public hearings on this proposal were held on January 24, 2000 in El Paso; on January 25, 2000 in Austin; on January 26, 2000 in Longview and Irving; on January 27, 2000 in Dallas and Lewisville; on January 28 in Fort Worth; on January 31, 2000 in Beaumont and Houston; and on February 9, 2000 in Denton. The comment period was originally scheduled to close on February 1, 2000, but was extended until 5:00 p.m. on February 14, 2000. (See the January 21, 2000 issue of the Texas Register (25 TexReg 461).)

Sixty-two commenters submitted oral testimony on this proposal. Six hundred twenty commenters submitted written testimony on the proposal. Alamo Cement Company (Alamo); Capitol Cement, a division of Capitol Aggregates, Ltd (Capitol); Cemex USA (Cemex); Texas Industries, Inc. (TXI); Texas-Lehigh Cement Company; and North Texas Cement Company (North Texas) submitted joint comments as TNACC. The Sierra Club - Dallas Regional Group; Greater Fort Worth Sierra Club (GFWSC); Downwinders At Risk (DAR); Sustainable Economic and Environmental Development (SEED); Texas Campaign for the Environment; Texas Clean Water Action (TWCA); and Texas Public Citizen (TPC) submitted joint comments and will be referred to as Dallas Sierra Club. The City of Denton and the City of Garland submitted joint comments and will be referred to as Denton/Garland. The Senior Citizens Alliance of Tarrant County (SCATC) and the Senior Political Action Committee (SPAC) submitted joint comments and will be referred to as SCATC/SPAC. The Texas Public Power Association (TPPA) and Environmental Defense (ED) submitted joint comments and will be referred to as TPPA/ED.

Nine individuals supported the proposed revisions, while three individuals opposed the proposed revisions. Alamo; American Lung Association of Texas (ALAT); City of Austin d/b/a Austin Energy (Austin); DeSoto City Council Member James Billion (Billion); Brazos Electric Power Cooperative (Brazos); Bryan Texas Utilities (Bryan); Capitol; Cemex; the Center for Energy and Economic Development (CEED); Central and South West Services, Inc. (CSW); Citizens for a Safe Environment (CSE); City Public Service of San Antonio (CPS); Clean Air Action Corporation (CAAC); the City of Cleburne (Cleburne); City of Dallas (Dallas); Dallas Sierra Club; DAR; Denton City Council Member Mark Burroughs (Burroughs); Denton/Garland; Dow Chemical Company (Dow); Duncanville City Council Member Judy Richards (Richards); the Ellis County Cement Industry (ECCI); ED; Engine Manufacturers Association (EMA); EPA; Fort Worth Chamber of Commerce (FWCC); State Representative Toby Goodman (Goodman); GFWSC; Green Party of Tarrant County (GPTC); Cedar Hill City Council Member Amanda Hall (Hall); Holnam Texas Limited Partnership (Holnam); League of Women Voters of Dallas (LWVD); League of Women Voters of Tarrant County (LWVTC); League of Women Voters of Texas (LWVTX); Lower Colorado River Authority (LCRA); State Representative Tommy Merritt (Representative Merritt); Neighbors for Neighbors (NFN); North American Coal Corporation (NACC); Ontario Power Generation (OPG); Reliant Energy (Reliant); Sabine Mining Company (Sabine); San Miguel Electric Cooperative, Inc. (San Miguel); Sierra Club - Lone Star Chapter (SCLSC); North Texas Clean Air Steering Committee (Steering Committee); Tarrant Coalition for Environmental Awareness (TCEA); Tenaska III Texas Partners (Tenaska); Texas Chemical Council (TCC); Texas Mining and Reclamation Association (TMRA); Texas Municipal Power Agency (TMPA); NAACP - Texas State Conference (NAACP); TNACC; TPC; TPPA/ED; Turner, Mason, and Company (Turner); TWCA; TXU Electric Company (TXU); City of Tulsa (Tulsa); City of Tyler (Tyler); and 594 individuals generally supported the proposed revisions but suggested changes or clarifications. Cemex and Capitol supported the comments submitted by TNACC. Brazos and CPS supported the comments submitted by TPPA/ED. Dallas Sierra Club's comments included the Citizen's Implementation Plan for Cleaner Air in DFW (January 2000). ALAT, CSE, LWVD, SCLSC, and 184 individuals expressed support for this plan.

ANALYSIS OF TESTIMONY

CEED, CPS, CSW, Holnam, NACC, Sabine, TMRA, TNACC, and TXU commented on the draft RIA. CEED, CPS, Holnam, NACC, TNACC, and TXU stated that the proposed rules were not evaluated in accordance with the analysis requirements for a major environmental rule. CEED, CPS, CSW, Holnam, NACC, Sabine, TMRA, TNACC, and TXU stated that the commission should perform a regulatory analysis and prepare a detailed economic analysis as required by Texas Government Code, 2001.0225. TNACC commented that The Senate Natural Resources Committee, Interim Report to the 75th Legislature, Use of Cost Benefit Analysis in Environmental Regulation(September 1996) regarding §2001.0225 states on page 8 that "[t]he heightened scrutiny approach would be applied only to the environmental regulations that are not specifically required by federal law, a federally-delegated program agreement or an express requirement of state law. Obviously, if the agency has no discretion about whether to adopt regulations , it should not be required to prepare a heightened scrutiny document." (TNACC's emphasis added) TXU urged the commission to perform a cost-benefit analysis with reductions at different intervals between 25% and 50% for electric utilities. TXU stated that Texas Government Code, §2001.0224(5), also requires a cost-benefit note and commented that Texas Health and Safety Code, TCAA, §382.011 and §382.024, require the commission to take into account the economic feasibility and reasonableness.

While CEED, CSW, Holnam, NACC, and TXU agreed that the proposed NOx limits are not specifically required by state law, CEED, CPS, CSW, Holnam, NACC, and TNACC asserted that the proposed rules are not specifically required by federal law because the FCAA does not set out specific rules that states must implement the NAAQS, but instead provides broad directives regarding how states must go about obtaining compliance with the NAAQS. TNACC stated that the NAAQS do not provide in and of themselves any standards applicable to the regulated community, and that a state with an approved SIP has broad flexibility on how to meet the NAAQS. CPS asserted that the proposal exceeds a standard set by federal law, such as the acid rain deposition control program of 40 CFR 76 (Acid Rain Nitrogen Oxides Emission Reduction Program). TNACC stated that the commission failed to cite "an 'express requirement of state law' that justifies the promulgation of the proposed rule without complying with the mandates of §2001.0225."

TNACC and TXU stated that the rules were proposed solely under the under the general powers of the commission and noted that the rule proposal preamble states that the rules were proposed under Texas Health and Safety Code, TCAA, §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.017, concerning Rules, which provides the commission with the authority to adopt rules consistent with the policy and purposes of the TCAA; and §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air, such as the SIP. TNACC stated that none of these provisions is an express requirement of state law to adopt NOx emission reductions for the cement industry.

CEED, CPS, CSW, Holnam, and NACC further stated that because Texas Government Code, §2001.0225(a)(2), requires that rules not expressly required by state law must be specifically required by federal law and not merely developed to meet federal law, the commenters believed that the requirements of §2001.0225 do apply to the proposed rules. Holnam asserted that to allow the commission to claim that it is not required to conduct a regulatory analysis and prepare a draft impact analysis for any rule specifically developed to meet the NAAQS would render §2001.0225 meaningless because the commission could argue that any of its rules are somehow related to its efforts to meet the NAAQS. CPS stated that the absence of an RIA "serves to frustrate the intent of the Legislature in enacting section §2001.0225." CSW asserted that the commission will not be able to comply with the procedural requirements of Texas Government Code, §2001.033 and §2001.035, because inadequate technical and scientific support exists for the proposal, especially the NO _x limits for coal-fired power plants. TNACC stated that the proposed rules are invalid because the commission "proposed these rules without quantifying the costs and benefits or describing reasonable alternative methods for achieving the purpose of the rule, as required by §2001.0225."

Although the commission has determined that this is a major environmental rule because it may adversely impact in a material way a sector of the economy, the commission is not required to perform an RIA because the rules do not meet any of the criteria listed in Texas Government Code, §2001.0225(a). The rules do not exceed a standard set by federal law or state law. The standard in this case is the NAAQS for ozone. The state is required to demonstrate compliance with this standard under federal law, 42 USC 7410, and under state law, TCAA, 382.012. As shown in the modeling for the SIP that is associated with this control strategy, the state is requiring no more emission reductions than absolutely required to meet the standard. Additionally, these rules would not exceed a requirement of a delegation agreement or contract with the federal government because none exists on this topic. Finally, the rules have not been proposed under the general powers of the agency but instead have been proposed under the specific state laws found in TCAA, §§ 382.011, 382.012, and 382.017. Section 382.012 is a specific requirement to maintain the SIP.

The commenters have stated that the commission cannot avoid the requirement to perform an RIA simply by saying that if a rule is needed for SIP purposes, then the rule is federally mandated. Section 7410 of the FCAA requires states to adopt a SIP which provides for "implementation, maintenance, and enforcement" of the primary NAAQS in each air quality control region of the state. While §7410 does not require specific programs, methods, or reductions in order to meet the standard, state SIPs must include "enforceable emission limitations and other control measures, means or techniques (including economic incentives such as fees, marketable permits, and auctions of emissions rights), as well as schedules and timetables for compliance as may be necessary or appropriate to meet the applicable requirements of this chapter," (meaning Chapter 85, Air Pollution Prevention and Control). It is true that the FCAA does require some specific measures for SIP purposes, like the inspection and maintenance program, but those programs are the exception, not the rule, in the SIP structure of the FCAA. The provisions of the FCAA recognize that states are in the best position to determine what programs and controls are necessary or appropriate in order to meet the NAAQS. This flexibility allows states, affected industry, and the public, to collaborate on the best methods for attaining the NAAQS for the specific regions in the state. Even though the FCAA allows states to develop their own programs, this flexibility does not relieve a state from developing a program that meets the requirements of §7410. Thus, while specific measures are not generally required, the emission reductions are required. States are not free to ignore the requirements of §7410 and must develop programs to assure that the nonattainment areas of the state will be brought into attainment on schedule. Therefore, adopting the SIP rules is specifically required by federal law.

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

CPS and CSW asserted that the commission had not provided a "reasoned justification" for the proposal. CSW and NACC asserted that consequently the commission can not finalize the Chapter 117 rule proposal and that the proposal must be withdrawn and reproposed.

The commission has provided a "reasoned justification" for the rules in this adoption package as required by Texas Government Code, §2001.033. Only a brief explanation of the rule is required upon proposal in addition to other elements such as the fiscal note and public benefit evaluations. See Texas Government Code, §2001.024. Both the rule proposal and adoption meet all of the requirements of the Administrative Procedure Act (APA). Therefore, it is not required that this rule be withdrawn and reproposed.

Austin, Brazos, Bryan, CAAC, Capitol, CEED, CSW, Dow, ED, Holnam, LCRA, LWVTX, NACC, OPG, Reliant, San Miguel, Tenaska, TCC, TMPA, TNACC, TPPA/ED, and TXU urged the commission to adopt a regional NO _x trading program as soon as possible and provided suggestions they wished included in such a program. Brazos suggested that the commission delay adoption of the proposed Chapter 117 rules such that a banking and trading rule could be adopted concurrently.

As noted earlier in this preamble, comments on emission trading will not be addressed as part of this rulemaking, but will be addressed when the commission considers its banking and trading program during summer 2000. The commission held stakeholder meetings to discuss the comments received and solicit input before formally proposing an emissions banking and trading program, estimated to occur sometime during summer 2000. The commission's goal is to adopt rules for an emissions banking and trading program no later than December 2000. Due to APA constraints, the commission must file final action on the Chapter 117 with the Texas Register no later than June 30, 2000 or the proposal will be automatically withdrawn. Additionally, if the commission delayed adoption of the proposed Chapter 117 rules such that banking and trading rules could be adopted concurrently, the commission would be unable to submit the final Chapter 117 rules to the EPA with the DFW Attainment SIP by the April 30, 2000 deadline, thereby potentially resulting in sanctions under the FCAA.

CAAC and nine individuals expressed concern about enforcement of the proposed rules, and three of these individuals recommended high penalties for noncompliance.

The commission agrees that adequate enforcement is critical to the success of the program. As with all of its rules, the commission will enforce the requirements after the compliance date and take appropriate action for noncompliance situations.

CEED, CPS, NACC, and TXU commented that power plants in east and central Texas comprise only part of the inventory of NO _x emission sources. CEED stated that the commission should consider requiring reductions at other NO _x sources before requiring power plants to reduce NO _x emissions. NACC stated that coal-fired EGFs in east and central Texas emit 709 tpd of NO _x (based on 1998 EPA CEMS data), while elevated point sources which are largely exempt emit 420 tpd or nearly 60% as much as coal- fired EGFs. CPS, CWS, LWVTC, NACC, Steering Committee, SCATC/SPAC, TXU, and two individuals stated that emission reductions should be required in east and central Texas from larger stationary sources of NO _x other than cement kilns and power plants. One of the individuals recommended a 90% NOx reduction requirement for all major sources in the eastern half of the state. Tyler supported obtaining additional NO _x reductions from larger stationary sources of NO _x other than power plants that are beneficial in helping to meet the ozone standard. CPS further suggested that under a broad cap-and-trade program these non-utility point sources could easily be required to achieve a specified percentage reduction in NO _x . CSW believed that it was "arbitrary, improper, and unfair" that the proposed rules only apply to EGFs and cement kilns, and stated that other NO _x source categories are responsible for about 33% of the total point source NO _x emissions in east and central Texas and potentially cause more ozone in nonattainment areas due to their proximity to these areas.

Cemex and TNACC stated that cement plants in east and central Texas comprise only part of the inventory of NO _x emission sources. Cemex stated that the commission should not include cement plants in central Texas as part of a regional strategy to reduce NO _x emissions, while TNACC asserted that the cement industry was arbitrarily targeted for NO _x reductions. TNACC stated that the nine cement plants targeted by the rules emit only 56.12 tpd and are less than 5.0% of the total NO _x emissions from point sources in the 95 east and central Texas attainment counties. TNACC also suggested that cement plant emissions are insignificant compared to EGF emissions in these counties. Finally, TNACC stated that none of the nine cement plants targeted by the rules are in counties that are nonattainment for ozone and suggested that this demonstrates that something other than cement kiln NOx emissions are responsible for the nonattainment status of DFW and other ozone nonattainment areas.

Commission staff reviewed the 1997 emissions inventory and note that 12 of the 13 largest stationary NO _x sources in the 95 east and central Texas attainment counties are power plants. In fact, the category of electric utilities (Standard Industrial Classification (SIC) code 4911) is the largest stationary source of NO _x emissions in these counties. Therefore, the commission does not agree with CEED's contention that reductions from non- utility NO _x sources should be required before power plants.

Commission staff reviewed the 1997 emissions inventory and note that cement plants represent 26.1% of the permitted non-utility stationary NO _x sources in the 95 east and central Texas attainment counties and 13.7% of the total (permitted and grandfathered) non-utility stationary NOx sources in these counties. Because cement plants are one of the largest stationary sources of NO _x emissions in the east and central Texas and because modeling has demonstrated that NO _x reductions from these sources are beneficial for meeting the one-hour ozone standard in DFW as well as in the east and central Texas counties, the commission believes it is appropriate to include these cement plants as part of a regional strategy to reduce NO _x emissions.

The commission agrees that non-utility NO _x sources should also be targeted and has already done so. For example, the commission is adopting NO _x limits for cement kilns and has negotiated agreed orders with other major non-utility NOx sources in these counties which will result in substantial NO _x reductions. The commission may consider future rulemaking to address possible NO _x emission reductions from non-utility, non-cement kiln stationary point sources. As noted earlier in this preamble, the commission expects to propose a banking and trading program during summer 2000.

Regarding TNACC's last comment, the commission notes that TNACC is in effect suggesting that NO _x emissions from cement kilns do not contribute to ozone formation in the ozone nonattainment areas. The commission believes that the modeling and monitoring data described elsewhere in this preamble demonstrate that NO _x emissions from cement kilns do in fact contribute to ozone formation in the ozone nonattainment and near-nonattainment areas.

TNACC stated that mobile source emissions are the source of ozone problems in DFW and other ozone nonattainment areas and stated that until mobile source emissions are dramatically reduced, additional point source controls are a questionable measure.

Mobile source emissions make varying contributions to ozone formation in the ozone nonattainment and near-nonattainment areas. There is no question that the largest contributor of ozone precursors in DFW is the mobile source category, but there is no basis for TNACC's conclusion that point source controls are not beneficial in making progress toward attaining the ozone NAAQS, as demonstrated by the modeling described elsewhere in this preamble. The commission agrees that mobile source emissions need to be reduced and has incorporated a variety of state and federal mobile source rules which will result in cleaner-burning gasoline, cleaner-burning diesel fuel, cleaner heavy diesel equipment, cleaner large gasoline engines, cleaner new motor vehicles, an improved program for inspection and maintenance of motor vehicles, and a voluntary scrappage program to retire high-emitting motor vehicles.

TNACC stated that the cement industry was targeted as part of the commission's ozone strategy solely because a set of controls developed by the Steering Committee for addressing the ozone nonattainment status in DFW included a recommendation for up to 50% NO _x reductions from Ellis County cement kilns. TNACC expressed concern that Ellis County was not represented on the Steering Committee and suggested that the Ellis County cement plants were targeted because they are not in the DFW ozone nonattainment area, even though the Steering Committee's consultant, Environ, "believed the contribution of Ellis County cement plants to the DFW Area ozone problem to be negligible."

The commission disagrees with the commenter. The Ellis County cement plants were targeted as part of the DFW ozone control strategy because the modeling described earlier in this preamble revealed that these plants are contributing to the DFW ozone problem and that reductions from this industry are beneficial in making progress toward attaining the ozone standard. While it is true that the modeling performed by Environ incorporates some improvements over the commission's earlier regional modeling analyses, the commission does not agree that Environ's work supercedes the earlier work. Environ's analysis in no way contradict's the commission's conclusions that a 50% reduction in point source NO _x emissions would lead to reductions in peak ozone of between 14 and 27 ppb.

CEED, CSW, NACC, and TNACC commented on the discussion in the rule proposal preamble concerning improvements in the eight-hour ozone levels in Tyler, Longview, Austin, and much of the upper Texas Coast. CEED, CSW, NACC, and TNACC stated that no eight-hour standard exists because this standard has been struck down in federal court.

It is true that the EPA may be unable to enforce the eight-hour ozone standard pending a decision by the United States Supreme Court. The modeling to which the commenters refer was analyzed for both the one-hour and the eight-hour ozone standards, and the benefits in one-hour ozone concentrations are accompanied by a corresponding improvement in eight-hour ozone levels. The modeling indicates that controls which reduce all elevated point source NO _x emissions by 50% in east and central Texas will reduce peak one-hour ozone between 14 and 27 ppb at specific locations in the region, depending on the modeling day. The one-hour ozone benefits stretch across the east and central Texas counties and average six to seven ppb. Based on a one-hour exceedance design value of 128 ppb, the projected benefits of 50% point source NOx reductions in the attainment counties of east and central Texas may be large enough to prevent some areas from being reclassified as not attaining the one- hour ozone NAAQS. It is the FCAA requirement for meeting the one-hour standard that forms the basis for the regional NOx control requirements.

CSW and TNACC also stated that it is inappropriate for one of the rulemaking purposes to be a decrease in one-hour ozone concentrations in the attainment counties of east and central Texas because these one-hour ozone concentrations are currently below the one-hour ozone NAAQS.

As noted earlier in this preamble, additional modeling was completed by commission staff assessing the potential benefits of regional NO _x reductions in the attainment counties of east and central Texas. This modeling indicates that controls which reduce all elevated point source NO _x emissions by 50% in the region will reduce peak one- hour ozone between 14 and 27 ppb at specific locations in the region, depending on the modeling day. The one-hour ozone benefits stretch across the east and central Texas counties and average six to seven ppb. Based on a one-hour exceedance design value of 128 ppb, the projected benefits of 50% point source NO _x reductions in the attainment counties of east and central Texas may be large enough to prevent some areas from being reclassified as not attaining the one-hour ozone NAAQS.

The primary purposes of the rulemaking are: 1) to help the BPA, DFW, and HGA ozone nonattainment areas move closer to reaching attainment with the ozone NAAQS; and 2) to reduce overall background levels of ozone in order to assist in keeping ozone attainment areas and near-nonattainment areas in compliance with the federal ozone standards. This regional NO _x reduction strategy provides a concurrent benefit of reduced peak one-hour ozone levels in much of east and central Texas. The commission believes that it is appropriate to include a description of these benefits in this preamble.

TXU commented on the discussion in the preamble which stated that the commission's modeling staff ran several sensitivity analyses for Texas using a regional modeling setup based on the COAST study, and that one modeling scenario, OTAG 5c, consisting of reductions across the domain (60% reduction of point source NO _x , 30% reduction of low-level NO _x , and 30% reduction of VOC), indicated that modeled reductions would reduce peak eight-hour ozone by as much as 20 ppb throughout most of the eastern half of Texas. TXU stated that the OTAG regional modeling is only a sensitivity model and is not capable of determining appropriate control levels for a SIP. TXU asserted further that the OTAG 5c study is of little value because the modeled domain reductions (60% reduction of point source NO _x , 30% reduction of low-level NO _x , and 30% reduction of VOC) are not the reductions being proposed in this rulemaking. TXU also stated that the OTAG modeling was based on the eight-hour ozone standard that has been deemed unenforceable in federal court.

The commenter is mistaken in claiming that OTAG's modeling was conducted based on the eight-hour federal ozone standard. In fact, with the exception of selection of episodes, photochemical modeling is conducted independently of the ozone standard. The model outputs predicted ozone concentrations, which can then be analyzed relative to any arbitrary standard. OTAG model output was analyzed both for the one-hour and proposed eight-hour standards.

The commenter also appears to be confused about the difference between modeling conducted by OTAG and regional modeling conducted by TNRCC using the OTAG 5c scenario. As part of the 1998 HGA SIP, the commission reported that applying the OTAG 5c strategy regionally could mitigate the reduction required to meet the one-hour standard in the HGA area by as much as 5.0%. While the OTAG 5c scenario is somewhat more stringent than the proposed regional rules, the commission believes that modeling conducted with the OTAG 5c assumptions is of significant value in assessing the potential benefits of regional NOx reductions.

CSW and TXU commented that the sensitivity studies discussed in the preamble are based upon old inventories, incorrect biogenics, and have been superseded by more accurate fine grid modeling in central and eastern Texas.

CSW and TXU correctly point out that the original modeling has been updated to include better treatment of point source inventories and biogenics. They are not correct that the newer modeling uses finer grids. The objective of sensitivity modeling is designed to determine the most effective path toward attainment early in the modeling process. Although the early work has been updated, that fact does not invalidate the earlier work. Further, the updates and improvements have not changed the original directional guidance. The numerous point sources in central and eastern Texas still contribute large amounts of NO _x to the air over Texas, and NO _x controls are still the most effective path toward attainment.

CSW, TXU and TNACC all comment that the existing modeling (the 1995 and 1996 DFW episodes) do not show large contributions to DFW ozone directly attributable to point sources in central and eastern Texas, and that those contributions have not been quantified.

The commission acknowledges that the two current DFW episodes do not show a large contribution from elevated point sources in central and eastern Texas. However, the two current DFW episodes were chosen to evaluate the controls necessary in the DFW area, not specifically to demonstrate transport. The proposed controls are based upon a body of circumstantial evidence from aircraft measurements, seasonal modeling, back trajectories, and statistical studies indicating that electric generating facilities and cement kilns in central and eastern Texas contribute to the background levels of NO _x which impact the DFW area. Documents explaining these additional studies are included as appendices to the SIP.

As pointed out previously, NO _x is the most important single contributor to ozone formation. Although emissions from each point source taken individually may not be significant, in aggregate the point sources contribute to the high background concentrations of NO _x measured in Texas. These high levels of NO _x raise the concentration of ozone transported into DFW which makes it more difficult for DFW to attain and maintain the ozone standard. The proposed rules are designed to reduce the high background levels of NO _x which affect not only DFW, but impact the ability of many other Texas cities to meet the ozone standard as well.

ED stated that they had the University of Texas (UT) perform regional scale modeling with 75% reductions of NO _x and that this modeling showed larger reductions of ozone in the DFW area.

The regional modeling performed by UT for the commission analyzed reductions of 20%, 30%, 40%, and 50% applied to all point sources east of Interstate 35. It is not possible to evaluate the ED/UT results without reviewing the whole modeling report. The work that ED had performed appears to have excluded the point sources in part of the DFW nonattainment area, but the exact geographical extent is not clear from the information in the comment letter. ED/UT modeled only the 1993 episode which was the episode for urban scale modeling in the HGA area. The 1995 and 1996 episodes which were developed for the DFW SIP development were not modeled by ED/UT. The maximum difference for their modeling was on September 11, 1993 with six ppb for a 50% reduction and eight ppb for a 75% reduction. The maximum modeled one-hour ozone concentration on September 11, 1993 was 116 ppb, significantly below the one- hour ozone NAAQS of 125 ppb. The information from the ED/UT modeling can be added to the information already presented for the other reduction scenarios and considered in making the policy decision for the amount of control that should be applied to each source category.

ED suggested that the commission include the results of the trajectory analysis that was performed and presented at a previous meeting.

Trajectory analyses provide insight into the path an air parcel took prior to arriving at a monitor. However, these analyses do not include information on quantity of source emissions, atmospheric chemical reactions and ozone formation, or response of ozone to various control strategy options. They have been considered for episode selection and development of a conceptual model for high ozone, but should not otherwise be considered in the core information in the SIP as they do not directly address evaluation of control strategy options.

TNACC noted that the Complex Air Quality Model with Extensions (CAMx) photochemical model has the capability of accounting for the dispersion and chemical evolution of individual elevated point source plumes (for example, those emitted from cement kilns). TNACC stated that in the commission's SIP modeling, the number of elevated point sources within the entire modeling domain that were treated as individual plumes in CAMx was limited to about 120 to reduce the computation time and that as a result, only one cement kiln stack in Ellis County was chosen to be modeled in CAMx as a separate plume. The remaining cement kiln stacks in Ellis County were assigned to the 4- kilometer (km) by 4-km modeling grid cell within which the kilns are located. The model then assumed that the emissions from these remaining kilns were uniformly mixed with other emissions in the area throughout the horizontal dimensions of the cell. TNACC asserted that consequently, instead of recognizing each cement kiln plume and individually tracking its transport and photochemical reactions as it entered DFW, the model lost the precise location and identity of all but one of these plumes immediately upon their release into the atmosphere. TNACC asserted further that it was impossible for CAMx to accurately determine either individual or collective contributions of cement kiln plumes to ozone concentrations for the meteorological events examined in the modeling.

The first few sentences of the comment are true, except that two of the cement kiln stacks in Ellis County were modeled as discrete plumes in CAMx, not just one. These two stacks happened to be the tallest, the two newest, and two of the largest NO _x sources. Therefore, they met the criteria for treatment with the Plume-in-Grid (PiG) algorithm of the CAMx model. The purpose of the PiG algorithm is not to enable the tracking of transport and photochemical reactions of individual plumes, but to provide a more realistic model for the fate of these larger plumes as they react downwind. It should also be noted that the vertical resolution which is maintained, with or without PiG treatment, depends on the effective plume height achieved by the emissions. Since these point source emissions are modeled at various levels in the atmosphere, they are not simply allowed to mix with all other emissions in the grid cell, until the meteorological conditions allow such.

In the last sentence of the comment, the commenter asserts that because the Ellis County sources were not treated individually as PiG sources, their individual or collective contributions cannot be accurately assessed. While there is always some uncertainty in the modeling predictions, the analyses performed by the commission employ the accepted methodologies for simulating ozone formation in an urban area. By performing CAMx model runs with and without the cement kilns included and then taking the difference in predicted ozone contributions, the commission has developed a reasonable assessment of the contribution of the Ellis County cement kilns toward ozone formation in the DFW area. More detailed analysis of these specific sources would require a special modeling study directed at these sources, which could be costly and could not be completed in time for this SIP.

TNACC asserted that the commission did not analyze the sensitivity of ozone concentrations to reductions in emissions from the cement kilns in the modeling. TNACC commented that the science of atmospheric photochemistry has shown repeatedly that not all reductions in the emissions of ozone precursors result in reductions in ambient ozone concentrations and stated that in one of its periodic project updates on the DFW photochemical modeling effort, the firm hired by the North Central Texas Council of Governments (NCTCOG) to perform the CAMx modeling stated that the real issue is not what control measures will achieve in terms of reductions in emissions of ozone precursors but what effect will they have in terms of ozone formation. TNACC asserted that there is no evidence that the commission examined each emissions control option in terms of its part-per-billion contribution to reduced ozone concentrations and that instead, most of the modeling scenarios included more than one change in mitigation measures. TNACC asserted that as a result it was not possible to determine what modeled changes in ozone concentrations would result from each of the proposed measures.

Analyzing the sensitivity of ozone concentrations to reductions in emissions from cement kilns was not one of the goals of CAMx modeling for this SIP. The commission agrees that it is always a goal of ozone photochemical modeling to predict what effect the combinations of ozone precursor emissions will have in terms of ozone formation. It is not feasible for the commission to examine each control option proposed by all interested parties in terms of amount of predicted ozone reduced. It is the combination of controls (not individual controls) that affects the chemistry in an area. Therefore, the commission does not emphasize individual control options when they are not modeled within the likely control scenario for the entire area. Furthermore, the effects of individual measures change, depending upon what other control options are assumed. For instance, the effectiveness of an individual NO _x control measure may increase if it is applied in concert with several other rules. It is therefore not feasible to assess the effectiveness of each individual proposed control measure. Hence, it is true that most of the modeling scenarios included more than one change in mitigation measures. It is never the intention of the commission to single-out any one class of controls or any single area with which to apply controls.

With regard to the commission's use of NCTCOG modeling, TNACC asserted that the commission did not properly treat or sufficiently analyze the emissions from cement kilns to identify the effectiveness of reducing their emissions. TNACC further stated that the commission did not account for the specific characteristics of individual cement kiln releases in its modeling and did not analyze the sensitivity of ozone concentrations to reductions in emissions from the cement kilns in the SIP modeling.

The commission made a sensitivity model run with zero-out (removal of all emissions) for the cement kilns. This information was presented at one of the modeling oversight committee meetings. The results of the zero-out modeling on ozone in the DFW area were: 1) maximum concentrations were reduced by a small amount; 2) the maximum difference found was 11 ppb; 3) the values for the aerial extent was reduced (the size of the area of exceedance was significantly reduced); and 4) the values for the exposure metric were significantly reduced. It is not practical for the commission to make a sensitivity model run for each specific control strategy. Also, by itself there may not be a large response for the implementation of any specific control, but it is the result of the ensemble of all controls that is effective in reducing ozone concentrations.

TNACC stated that none of the 23 emission control scenarios the commission modeled isolated the effects of reducing cement kiln emissions alone. TNACC commented that the effects of NO _x emissions reductions in Ellis County were first modeled as Control Strategy D11, but that Ellis County emissions were not the only ones changed from the previous modeling. Rather, the changes between Strategies D10 and D11 included reducing emissions due to construction equipment start time delays and reducing emissions due to implementation of a voluntary mobile emissions program.

The first sentence of this comment is incorrect. At the time of the submittal of the proposed SIP and the accompanying rules, the commission had run 30 modeling scenarios. The TNACC's consultants were provided with an early modeling scenario (D2) in which the only change was cement kiln reductions. This scenario was not included in the SIP because the base case was revised subsequent to strategy D2 to include proposed controls in the surrounding areas and to make several improvements to the modeling. If the surrounding area controls had been included (essentially yielding a smaller background) in the modeling of strategy D2, then the differences observed due to Midlothian reductions could have been more pronounced. Were the analysis to be repeated using more recent modeling scenarios, the commission expects the results would still show meaningful reductions in peak and aerial coverage of predicted ozone concentrations, as did the results provided to TNACC's consultant. The commission drew no conclusions regarding Ellis County from Control Strategy D11.

TNACC also stated that in Control Strategy D19, when a 50% reduction in Ellis County NO _x reductions was first considered (as opposed to a 30% reduction in Ellis County NO _x emissions as examined in the previous CAMx run), the following changes were made to the CAMx inputs: building code modifications were included, vehicle recycling was raised from 3,000 to 5,000 cars per year, construction equipment was delayed only until 8:30 a.m., no use of very low-sulfur fuel in mobile sources was considered, and the use of low-NO _x water heaters was added. TNACC stated that the changes proposed for Control Strategy D19 (which included a decrease in Ellis County cement kiln NOx emissions) resulted in a modeled increase in the peak ozone concentration of 2.5 ppb. TNACC commented that it is impossible to tell from the modeling runs for Control Strategies Dl8 and Dl9 how the reduction in the cement kiln emissions affected the modeled ozone concentrations, if at all.

The commission drew no conclusions regarding Ellis County from Control Strategy D19. It was not the intent of this scenario to quantify ozone reductions from Ellis County.

TNACC commented that in Control Strategy D29, one of the changes to the model inputs was to include reductions in emissions from cement kilns in east and central Texas, based on the proposed changes to Chapter 117. TNACC stated that these changes resulted in a modeled peak ozone concentration increase of 0.2 ppb. TNACC stated that it is impossible to tell from the modeling whether reductions in emissions from cement kilns located outside of Ellis County contributed to DFW's ozone problem, or whether the modeled increase in ozone concentrations between Scenario D28 and D29 was due to other factors.

The commission drew no conclusions regarding Ellis County from Control Strategy D29. It was not the intent of this scenario to quantify ozone reductions from Ellis County.

TNACC commented that limitations in the Baylor aircraft monitoring may prevent the monitoring data from providing support for the proposed reductions in NO _x emissions from cement plants in the east and central Texas region. Specifically, TNACC asserted that Sonoma Technologies (Sonoma), the firm the commission hired to evaluate the Baylor data, did not evaluate the data from a "downwind" perspective, but instead looked at the air flow coming into the urban areas. TNACC stated that Sonoma's data review was aimed at determining what was coming into the DFW area, not where or what it was coming from, and that Sonoma did not attempt to determine if regional long-range transport was occurring.

Determination of long-range transport was never one of the stated objectives of flights that Sonoma analyzed. Sonoma was asked to review regional (i.e., East Texas) ozone production and its contribution to ozone in and downwind of major urban areas in Texas. Sonoma did this by comparing ozone levels measured upwind and to ozone levels measured downwind of the DFW area and assuming the difference was produced by the urban area. Sonoma found that, on average (six cases), the DFW area's local contribution was approximately 65 ppb (or 50%). Since Sonoma was concerned with general regional ozone levels and not any particular wind directions, their upwind/downwind approach was appropriate.

TNACC asserted that of the 91 Baylor flights flown, only the data from one (Flight Number 39) indicated any real evidence of regional transport. TNACC stated that the Flight Number 39 data allowed tracking of a sulfur dioxide (not NO _x ) plume, thought to be from the Big Brown power plant, for approximately 80 kilometers (km) downwind, but that there was no conclusive evidence of transport other than this one flight. TNACC asserted that there is nothing in the Baylor aircraft monitoring data which demonstrates that long-range transport exists at all beyond 80 km (50 miles).

Fewer than half the flights flown by Baylor University have been quality assured and analyzed so to say that only one out of 91 flights contained evidence of transport is inaccurate. Sonoma was only able to track the sulfur dioxide plume from the Big Brown power plant out to 80 km because the aircraft never attempted to track the plume out any further on this particular flight. Data exists to plot a NO _x plume, but this task simply has not been done. TNACC's comments are based on an incomplete review of the data. Work has been done under the Southern Oxidants Study indicating that power plant plumes can extend up to 200 km in the day and even longer overnight. Regional transport can occur over hundreds of miles.

TNACC stated that the results of the Baylor aircraft monitoring study provide no basis for concluding that ozone levels monitored at the aircraft's sampling altitude (approximately 2,000 feet) would reach the ground in the same concentrations.

Comparison of ground monitoring data with airborne pollutant levels suggests that airborne data compares relatively well to ground-based data. Baylor aircraft flights are planned so the aircraft is being flown at a time and an altitude in which the atmosphere is mixed. In these conditions, pollutant levels can usually be assumed to be fairly uniform from ground height all the way up to the "mixing layer." Also, the aircraft usually performs more than one up-and-down spiral precisely for the purpose of measuring how pollutant levels change in the vertical. Consequently, any changes in pollutant levels can be identified and taken into account.

TNACC also commented that the data only represent a snap-shot in time of the concentrations of ozone, NO _x , and other air contaminants at an altitude of approximately 2,000 feet and that as a result, the data do not demonstrate or even indicate what the concentrations of such air contaminants would be at a later time or day after mixing and/or dispersion has occurred.

While it is true that a given pollutant measurement point is only a "snap-shot in time," the same could be said for any single measurement point at ground monitoring site. Baylor University's airborne monitoring platform has several capabilities which allow it to overcome this "limitation." First, the Baylor aircraft can, and does, fly over the same latitude and longitude coordinates more than once in a given flight which means that it has the ability to measure pollutants at a single point over time. Second, since the aircraft moves, it can, and does, track a particular "parcel" of air throughout the day as it moves through a geographic area and disperses. Third, because the aircraft can climb and descend, it can, and does, measure vertical changes in pollutant levels. Additionally, the aircraft is often flown during a time of the day when the atmosphere is relatively well-mixed so that differences with ground-based monitors can be further minimized.

TNACC further stated that meteorological conditions (e.g., wind speed and direction) associated with the aircraft monitoring were not always known or were so variable as to limit or eliminate the value of the data for the proposed NO _x emission limits. As examples, TNACC cited the descriptions of Flight Number 61 (flown on July 17, 1998), which it stated was the primary basis for the commission staff's belief that NO _x emissions from point sources in the Tyler/Longview area are contributing to ozone concentrations in DFW, and of Flight Number 42 (flown on August 28,1997), which was also flown around the Tyler/Longview area. TNACC commented that the descriptions state that "there are no data available to describe the winds [direction or speed] at 2,000 feet, the aircraft altitude," and that during the flight, surface winds shifted quite a bit, both in time and over space. TNACC commented that both flight descriptions stated that "conclusions about source attribution during the flight are necessarily tentative."

While it is true that having wind data collected by the aircraft during its flight is the preferred mode of operation, the inability to do so does not prevent the Baylor aircraft from providing important information. Indeed, the commenter is only able to cite two examples where conclusions were rendered tentative by the lack of such data. When this is put in the context of the number of flights analyzed by Sonoma, it becomes clear that existing data is sufficient to allow analysts to reach firm conclusions in the large majority of cases. Also, additional resources such as ground monitoring data, meteorological models, and radar data can provide important wind information needed to interpret flight data.

TNACC stated that the aircraft monitoring data do not indicate whether, and if so, how much, the proposed cement kiln NO _x emissions reductions will reduce one-hour ozone concentrations in DFW or any other area of the state. TNACC stated that the data do not indicate what percentage of NO _x emissions reductions in the east and central Texas region are needed to allow the commission to demonstrate attainment with the one-hour NAAQS in DFW or any other nonattainment area, or to prevent near-nonattainment areas from becoming nonattainment with the one-hour ozone NAAQS.

While this comment is true, the airborne monitoring program was never intended to quantify the effect of emissions reductions. What the program does show, however, is that regional ozone levels account for approximately 50% of the peak ozone concentration in the DFW area. This indicates that regional ozone production plays a crucial role in determining peak ozone concentrations inside the DFW area.

TNACC further asserted that the airplane monitoring data do not demonstrate how much of the measured ozone concentrations is due to mobile sources in the area, or to other NO _x point sources.

Based on their analysis of Baylor aircraft data, Sonoma determined that point, area, and mobile sources contribute almost equally to regional ozone concentrations.

NFN, TCEA, and 18 individuals stated that facilities that predate the commission's air permitting requirements (i.e., those that are "grandfathered") should be subject to the NO _x limitations.

The proposed NO _x limits for cement kilns and utility boilers and stationary gas turbines apply to both permitted and non-permitted ("grandfathered") sources in the eastern half of the state. This is the area for which air quality modeling and upper air monitoring with aircraft found that regional air pollution should be considered concerning the impact on ozone nonattainment and near-nonattainment areas. The commission has made no change in response to the comment.

Representative Merritt encouraged the commission to recognize the benefits of utilizing technologies and fuels such as cogeneration and natural gas as methods to reduce NO _x emissions from EGFs as outlined in SB 7.

The proposed rules do not specify a required technology or fuel. Instead, the commission proposed emission limits for EGFs which represent NO _x emission reductions of approximately 50%. Establishing emission limits provides more flexibility so that individual utility boilers and stationary gas turbines can be evaluated to determine the most cost-effective approach to reducing NO _x emissions.

Dallas Sierra Club, DAR, ED, GPTC, NFN, TPC, and 15 individuals supported retiring the oldest and highest-emitting power plants and/or cement kilns. DAR commented that wet process cement kilns generally emit more NO _x than dry process cement kilns (including preheater, precalciner, and preheater-precalciner kilns), and that no new wet kiln has been built in more than 20 years. DAR asserted that wet process kilns are obsolete and that reasonably available control technology (RACT) for cement kilns should be dry process kilns.

The commission agrees that retiring older, higher-emitting units and replacing them with modern units often results in a reduction in emissions. In some cases, however, the increased activity rate of a new unit results in an increase in emissions, even though the emission rate per quantity of product is far lower than that of the unit being replaced. Rather than mandate the retirement of older units, the commission believes that it is more appropriate to set emission limits for these units, thus providing more flexibility so that the owners or operators can evaluate individual units to determine the most cost-effective approach to reduce NO _x emissions.

Regarding DAR's comments, there is no question that new dry process cement kilns (including preheater, precalciner, and preheater-precalciner kilns) are more energy efficient and produce fewer NO _x emissions per ton of clinker produced as compared to wet process kilns. However, the FCAA definition of RACT specifically refers to "retrofit equipment," while the EPA has defined RACT in a variety of guidance documents as "the lowest emission limitation that a particular source is capable of meeting by the application of control technology that is reasonably available considering technological and economic feasibility." As such, RACT for an existing source can not be established as a complete shutdown and replacement of the existing source. Regardless, the cement kiln rules were not proposed to implement RACT. Rather, these rules were proposed to reduce NO _x emissions which impact ozone nonattainment and near-nonattainment areas.

Burroughs and FWCC recommended giving consideration to the level of reductions feasible for power plants so as not to affect the system reliability, while the Steering Committee recommended giving consideration to the level of reductions feasible for older and smaller power plants so as not to affect the system reliability.

A January 1999 joint Public Utility Commission of Texas (PUCT)/TNRCC report, Electric Restructuring and Air Quality: A Preliminary Analysis of Reductions and Costs of NO _x Controls from Electric Utility Boilers in Texas , analyzed impacts of three levels of NO _x control on electric generating units owned by the major utilities in Texas and found that only a few units would likely be forced to retire at the highest level of control because the cost of controls would make their power production costs uneconomical. The study was a high level report, but is one of the few available indicators of the potential for unit shutdowns. The commission considers the study one indicator that the economic impacts of the proposed emission limits will not result in widespread shutdowns. A definitive analysis of which units may be shutdown is not feasible because such analysis is highly dependent on the future price of power in the area, which depends on such factors as future demand, fuel costs, which new power projects go into operation, and the influence of a more competitive market for electricity. The commission has addressed the commenters' concerns by extending the compliance date to May 1, 2005 for units owned by utilities which are not subject to the May 1, 2003 cost-recovery deadline in SB 7 (Texas Utilities Code (TUC), §39.263(b)).

Reliant requested inclusion of a PURA determination statement in the adoption preamble which would specify that the reductions meet the criteria for stranded cost recovery under SB 7.

The commission agrees and has included such a statement in the preamble.

Reliant stated that the preamble should specify that the standard permit under 30 TAC Chapter 116, §116.617 (Standard Permit for Pollution Control Projects) is available to authorize control technology improvements.

The commission expects that most projects necessary to meet the new Chapter 117 requirements for EGFs and cement kilns will be able to qualify for the standard permit available under §116.617. The commission has revised the preamble accordingly.

No comments were received on the definition of "electric power generating system" in 117.10. However, it has come to the commission's attention that this definition may not clearly enough specify that an electric power generating system encompasses the units in a single ozone nonattainment area, or in the 31 listed attainment counties of east and central Texas. The commission has revised the definition accordingly. EMA commented on the definition of "maximum rated capacity" in §117.10 and stated that the reference to "Diesel Equipment Manufacturer's Association" (DEMA) conditions in subparagraph (D) should be changed to "International Standards Organization (ISO)" conditions. EMA suggested this change because it believes that DEMA and that this association's conditions now reflect the use of outmoded technology.

Because many existing units have already used the DEMA conditions to establish their rating, the commission has revised the definition of "maximum rated capacity" to reference both DEMA and ISO conditions. This will allow existing units to continue using their already- established rating while also addressing newer units.

As part of their comments on the proposed 30 TAC Chapter 117 rules identified as Rule Log Number 1999-056-117-AI (24 TexReg 11977, December 31, 1999), Denton/Garland suggested that definitions of "large DFW system" and "small DFW system" be added to §117.10.

Denton/Garland's reasoning for the suggested definitions and the commission's evaluation of these comments are found in the preamble for the final 30 TAC Chapter 117 rules identified as Rule Log No. 1999-056-117-AI which is published elsewhere in this issue of the Texas Register . In response to these comments, the commission has added definitions of "large DFW system" and "small DFW system" as new §117.10(18) and (36), respectively, and has renumbered other definitions in §117.10 accordingly.

It has come to the commission's attention that Hays County was misspelled in the definition of "major source" in §117.10. The commission has corrected this definition.

EMA commented on the definition of "stationary internal combustion engine" in §117.10 and stated that this definition includes engines that are otherwise classified as mobile nonroad engines under federal law. EMA stated that language from 40 CFR Part 89 (Control of Emissions from New and In-Use Nonroad Engines), §89.2 (Definitions), should be incorporated into the definition of "stationary internal combustion engine."

The commission has revised the definition of "stationary internal combustion engine" using language from 40 CFR 89.2 to clarify the distinction between stationary and mobile nonroad engines.

It has come to the commission's attention that the definitions of "30-day rolling average" and "24-hour rolling average" in §117.10 contain a redundant phrase (specifically, "as the average"). The commission has corrected these definitions.

Austin stated that §117.131 appears to conflict with the trading provisions included in §39.264 of SB 7 and should be harmonized with the legislative intent of SB 7. Austin also stated that the proposed rules should be revised to include the trading program of SB 7.

The commission disagrees that there is a conflict with SB 7. However, as described elsewhere in this preamble, the commission has revised the system cap of §117.138 to facilitate trading within an electric power generating system until the forthcoming emission banking and trading program is finalized. The commission expects that the forthcoming banking and trading program will lower the cost of compliance and ultimately will be the preferred compliance option for affected EGFs because such a program will allow overcontrol of the more cost-effective units to be applied to units which are less cost-effective. The commission has made no change in response to the comment.

CEED, NACC, and Tenaska commented on §117.131 and suggested that the requirements only apply during the ozone season. CEED and NACC stated that year-round reduction does not affect ozone levels during the ozone season. CEED and NACC cited as precedent rules in 30 TAC Chapter 114 that only apply during the ozone season, while Tenaska commented that the emission limitations proposed for the Section 126 petition and Ozone Transport Commission states are seasonal.

The issue of seasonal controls involves significant air quality considerations. The season for the one-hour ozone standard in DFW has been defined by EPA policy by the monitoring period in 40 CFR Part 58, Appendix D and by commission rule in §101.29(a)(19) of this title, relating to General Air Quality Rules, as an eight-month period from March 1 through October 31. For BPA and HGA, the season for the one-hour ozone standard has been defined as year-round by EPA policy by the monitoring period in 40 CFR Part 58, Appendix D and by commission rule in §101.29(a)(19). Although exceedances of the one-hour standard in DFW generally have been limited to the five months of June-October, there may be ozone and other environmental benefits to year-long NO _x control in DFW. Regional transport may move DFW NO _x southerly into areas with more of a year-long potential for ozone exceedances, such as BPA and HGA. Year-long controls could help prevent current near- nonattainment areas from becoming nonattainment under the ozone NAAQS. Locally, year-long controls would reduce nitrates in the winter season. Nitrates contribute to the winter visibility impairment in DFW sometimes called the white or brown cloud. In addition, NO _x adds to the nitrification of surface waters, an adverse ecological impact which at times may contribute to algae buildup and related problems.

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

Tenaska commented that the terms "independent power producer" and "utility electric power boiler and stationary gas turbine" are used in §117.131 but are not defined in §117.10. Tenaska stated that this creates uncertainty as to whether or not the Tenaska units 1 and 2 in Paris are subject to the proposed rules. Tenaska also suggested that the commission clarify whether "exempt wholesale generators," as this term is defined by the Federal Energy Regulatory Commission (FERC), are subject to the proposed rules. Tenaska stated that the concepts of qualifying facilities and exempt wholesale generators have explicit regulatory meaning recognized by FERC and PUCT.

Tenaska units 1 and 2 are subject to the proposed rules, although it should be noted that these units are currently permitted at 42 ppmv NO _x , which is equivalent to the proposed limit of 0.15 lb NO _x /MMBtu in §117.135(2)(B) and (C). The commission believes that it is clear that the rules apply to boilers and stationary gas turbines used to generate electric power which were placed into service before December 31, 1995, and that cogeneration units are subject to the rules. It should be noted that appropriate exemptions are included in §117.133. The commission has made no change in response to the comment. However, the commission has added the phrase "or any of its successors" to §117.131(2) for consistency with the definition of "electric power generating system" in §117.10.

San Miguel suggested that §117.131 be revised to apply statewide, rather than to just selected counties in east and central Texas. San Miguel stated that it was unfair that the power plants in east and central Texas were subject to the limits while those elsewhere in Texas were not. San Miguel expressed concern that limiting the rules to only certain counties will limit competition in the electric utility industry.

The commission can not revise §117.131 upon adoption to apply statewide in this rulemaking because the newly affected parties in the western half of Texas would not have had adequate notice and opportunity to comment. Regarding the commenter's assertion that the rules are unfair to power plants in the eastern half of Texas and will affect competition in the electric utility industry, the rules are targeting the eastern half of the state because modeling (described in detail elsewhere in this preamble) has shown that NO _x emissions from sources in that area are contributing to exceedances of the one-hour ozone NAAQS in ozone nonattainment and near-nonattainment areas. The commission believes that it is appropriate for those sources which are contributing to the ozone problem to be part of the solution. Consequently, the commission has made no change in response to the comment.

No comments were received on §117.133(1), which exempts utility electric power boilers or stationary gas turbines if the annual heat input does not exceed 2.2 (10 ¹¹ ) Btu per year, averaged over the three most recent calendar years. However, it has come to the commission's attention that the proposed exemption was inadvertently limited to permitted units. The exemption is intended to be available to both permitted and grandfathered units, and the commission has revised the rule accordingly.

Austin and Tenaska supported the proposed exemption in §117.133(2) for stationary gas turbines which are used solely to power other units during start-ups; or operate less than 850 hours per year, based on a rolling 12-month average. Tenaska stated that the "850 hours per year" exemption of §117.133(2)(B) should be made more consistent with the federal acid rain rule definitions of 40 CFR 75, such that units that operate no more than an average of 10% of the hours of the year, averaged over three years, and no more than 20% of the hours in a single calendar year would be exempt. Tenaska stated that this flexibility is important considering the seasonal and highly weather dependent operation of units designed to cover peak loads, and that installation of post-combustion controls on infrequently operated units is not cost-effective.

The suggested change would allow at most an average of only 26 more hours of operation per year. The commission agrees that installation of post-combustion controls on infrequently operated units is not cost-effective, and therefore has revised §117.133(2)(B) and §117.143(h) accordingly.

CPS stated that §117.133(2) should include an exemption for auxiliary boilers. CPS commented that the rule proposal preamble stated: "The proposed rule would not apply to auxiliary boilers which are sometimes present at power plants. Auxiliary boilers are much smaller than power boilers, operate rarely, and account for only 0.01% of the power plant emissions in the attainment counties of east and central Texas." CPS noted that the definition of electric power generating system in §117.10 includes auxiliary boilers.

The intent, as noted in the rule proposal preamble, is to exempt auxiliary boilers. Therefore, the commission has revised §117.133(2) to exempt auxiliary boilers.

TCC commented on §117.133 and noted that the rule proposal preamble contained a description of the unit applicability. TCC suggested including these descriptions in §117.133 to clarify the applicability and exemptions.

The commission believes that the rule applicability and exemptions are clear. The commission has made no change in response to the comment.

Tenaska suggested the inclusion of an exemption in §117.133 for "qualifying facilities," which are cogeneration facilities that meet the specific criteria of the FERC and which are not subject to regulation by the PUCT. TCC recommended adding an exemption to §117.133 for non-utility gas turbine cogeneration facilities.

The commission has added a new paragraph (3) to §117.133 which exempts each unit that generates electric energy primarily for internal use but that, averaged over the three most recent calendar years, sold less than one-third of its potential electrical output capacity to a utility power distribution system. This exemption is based upon §116.910(g) of this title (Applicability). In addition, the exemptions of §117.133(1) and (2) are available to small cogenerators who may exceed the one-third limitation.

Bryan, CEED, CPS, CSW, NACC, Reliant, and TXU commented on the format of the NO _x limits in §117.135. Bryan, CEED, CSW, NACC, Reliant, and TXU supported the use of the traditional heat input-based format of lb NO _x /MMBtu rather than the output-based format of lb NO _x /megawatt-hour. CEED and NACC stated that output-based standards discriminate against Texas lignite and coal since these fuels have a higher moisture content (and thus a lower heat rate) which makes achieving the standard more difficult. TXU stated that input-based standards are consistent with all commission and EPA standards (except for the recently adopted New Source Performance Standards (NSPS) for new electric utility steam generating units), as well as CEMS and data management programs for utilities. TXU also stated that it is difficult to make significant efficiency improvements on existing units and expressed the belief that most utilities will choose to use the system cap or the forthcoming emission banking and trading program. CPS stated that the forthcoming emission banking and trading program will make the format of the emission standards a moot point since the focus of such a program will be on tons emitted.

The NO _x standards of §117.135 were proposed in the traditional heat input-based format of lb NO _x /MMBtu, although the commission requested comment on expressing the §117.135 NO _x limits in the output-based format of lb NOx /megawatt-hour. Output-based standards allow the source owner to improve the efficiency of the regulated equipment. By harmonizing the environmental and economic goals more closely, output-based standards can lower the cost of regulation compared to input-based standards. The numeric value of equivalent output-based emission standards could be calculated readily from electric production records for the baseline emission period. However, because the commission also proposed to allow emission cap compliance, which also permits efficiency improvements to contribute toward rule compliance, and offers even more flexibility, an output-based format would only be useful if a utility were likely to choose the option of direct emission compliance with the standard. The commission did not recommend making a change but solicited comments from the regulated community to allow for constructive feedback and change if the comments indicated support for a change. The commission agrees with the reasoning provided by the commenters. Output-based standards would provide little benefit for existing units and would needlessly complicate the existing regulatory procedures in place. The commission has retained the proposed traditional heat input-based format of lb NO _x /MMBtu.

ED, LWVTC, Steering Committee, Tulsa, and 515 individuals supported the proposed NO _x emission limits for utility boilers and stationary gas turbines in §117.135. CEED, CPS, CSW, Dallas Sierra Club, LWVTX, NACC, Reliant, Sabine, San Miguel, SCLSC, TMPA, TMRA, TXU, and five individuals opposed the proposed limits. One individual recommended that at least a 90% NO _x reduction be required, SCLSC recommended NO _x reductions of 80%, while Dallas Sierra Club and LWVTX recommended NO _x reductions of 88%. Hall and two individuals recommended that at least an 88% NOx reduction be required in all 12 counties of the DFW CMSA. Three individuals simply stated that the proposed limits were not stringent enough.

CEED, CSW, NACC, Reliant, and TXU stated that most coal or lignite-fired power plants can not meet the proposed limit of 0.165 lb/MMBtu for coal-fired utility boilers specified in §117.135(1)(B)(ii) and (iii) without post-combustion control. CPS stated that two of its three coal- fired units in Bexar County are "first generation western coal-fired units" which were designed before all the difficulties of firing western low-sulfur coal were known. CPS stated that compared to later designs, these two units have smaller furnace volumes, higher burner zone and volumetric heat release rates, and considerably smaller distances between burners and between the uppermost burner level and the top of the furnace, which CPS stated would make it difficult to achieve the 0.165 lb/MMBtu limit through combustion modifications. Reliant, Sabine, San Miguel, and TMRA suggested a limit of 0.2 lb/MMBtu, which they believed could be met by Texas lignite-fired power plants. CSW and TMPA likewise suggested a limit of 0.2 lb/MMBtu for coal-fired power plants, which they believed is an economically realistic value, while TXU suggested a limit of 0.2 to 0.22 lb/MMBtu for lignite and coal-fired power plants.

Austin stated that its consultants estimate (and equipment vendors have confirmed) that installation of low-NO _x burners at units 1 and 2 of the Sam Seymour power plant will allow these units to just barely meet the 0.165 lb/MMBtu limit. Bryan and LCRA stated that the 0.165 lb/MMBtu limit may be achievable at their coal-fired units through combustion modifications, while TMPA stated that combustion modifications at its coal-fired unit may reduce NO _x emissions to levels quite near the proposed 0.165 lb/MMBtu limit. However, Austin, Bryan, LCRA, and TMPA expressed concern that in practice the units could fall short of meeting the limit and stated that additional flexibility, such as higher limits or a broad trading program, would avert this potential problem. CSW commented that the lowest NO _x rate that its coal-fired EGFs can achieve with combustion modifications is 0.235 lb/MMBtu. Reliant stated that an advanced low- NO _x burner/separated overfire air system being installed in March 2000 at its Limestone Electric Generating Station is guaranteed to achieve a NO _x emission rate of 0.2 lb/MMBtu.

CEED and NACC asserted that SCR technology has never been applied to a coal or lignite-fired power plant, while CSW and TXU asserted that SCR technology has never been applied to a lignite- fired power plant in the United States. CSW also asserted that SCR technology has never been demonstrated to be technically practicable on a powder river basin (PRB) coal or Texas lignite-fired EGF. San Miguel asserted that SCR technology has never been applied to a power plant which is fired on Texas lignite. CEED and TXU also stated that utilities in the United States have had minimal success in retrofitting these controls on coal-fired power plants. CEED and NACC stated that only two United States power plants (one in New Jersey, and one in New Hampshire) have been retrofitted with SCR technology. CSW stated that at least one (unnamed) catalyst vendor is unwilling to guarantee SCR catalyst performance for EGFs that burn PRB coal. CPS asserted that if it were to install SCR at its EGFs in Bexar County, the cost would be borne by a population that has lower income levels and which has a more limited economy than any of the ozone nonattainment areas where most of the ozone reductions resulting from the rules will occur.

CEED stated that a coal-fired power plant in Texas was able to achieve emission levels near the 0.165 lb/MMBtu limit through the use of "advanced low-NO _x burners and sophisticated control technology" but that other units at the same power plant could only reach 0.21 lb/MMBtu using the same technology. TMPA suggested that an alternative emission specification be available for instances in which the installation of aggressive combustion modifications at units subject to the 0.165 lb/MMBtu NO _x limit of §117.135(1)(B)(ii) and (iii) fell short of achieving total compliance.

TXU asserted that SCR is the only post-combustion control available for coal or lignite-fired utility boilers. TXU commented further that SCR performance at coal and lignite-fired boilers is influenced by a number of factors (temperature, fuel sulfur content, ammonia-to-NO _x ratio, NOx concentration at the SCR inlet, gas flow rate, and catalyst condition). CSW and TXU stated that SCR can cause operational problems, such as plugging of the air heater, poisoning of the catalyst, and corrosion resulting in forced outages. TXU stated that in January 1999, the Electric Power Research Institute (EPRI) advised that at that time there had been six coal-fired units built with SCR and one retrofit, and that the retrofit unit could not meet the proposed NO _x limit of 0.165 lb/MMBtu.

CEED, CPS, CSW, Reliant, TMPA, and TXU stated that post-combustion controls are extremely expensive. TXU commented that it estimates the cost of retrofitting SCR on a lignite-fired unit to be $60 million to $80 million, with estimated annual operating and maintenance costs of $5 million per year. CSW estimated the cost of retrofitting SCR to be $38 million on one of its coal-fired units and $60 million for one of its lignite-fired units, with estimated annual operating and maintenance costs of $3 million to $5 million per year. San Miguel estimated the cost of retrofitting SCR on its lignite-fired unit to be $8 million to $15 million. Reliant estimated the cost of retrofitting SCR or SNCR on its lignite-fired Limestone Station to be $20 million to $100 million. CSW stated that unlike most other utilities, it would not be able to recover any of its stranded environmental costs for four of its five coal- fired EGFs in east and central Texas. CEED, CSW, San Miguel, TMPA, and TXU asserted that the cost rises significantly to meet the proposed NO _x limit of 0.165 lb/MMBtu instead of a limit of 0.2 lb/MMBtu due to the need for SCR rather than combustion modifications.

There appears to be a misconception on the part of a number of commenters that SCR is the only post-combustion control option available to them. In fact, SCR is merely one of several post-combustion control options for reducing NO _x emissions on an EGF, with other options including but not limited to SNCR and SNCR/SCR hybrid systems (in which SNCR is followed by a smaller SCR system). Other options for reducing NO _x emissions include low-NO _x burners, low excess air operation, staged combustion (for example, overfire air), flue gas recirculation (FGR), and fuel-lean and conventional (fuel-rich) reburn.

Status Report on NO _x Control Technologies and Cost Effectiveness for Utility Boilers (June 1998), prepared for Northeast States for Coordinated Air Use Management (NESCAUM) and Mid-Atlantic Regional Air Management Association (MARAMA), included case studies of various utility boilers which were controlled with various technologies, including SCR, SNCR, gas reburn, and gas-fired low-NO _x combustion modifications. The utility boiler operators cooperated by providing actual project cost, operating cost, as well as operating experience. Because the actual cost information for completed projects was available and was provided directly by the operators, the cost analysis is "anchored in reality" rather than being mere speculation. Of the 11 Group 1 coal-fired utility boilers in the case studies, five were equipped with SCR, five were equipped with SNCR, and one was equipped with gas reburn. Because the NESCAUM/MARAMA report was issued nearly two years ago, additional coal-fired boilers undoubtedly have been, or are in the process of being, equipped with post-combustion controls. In any event, it is clear that multiple coal-fired utility boilers have been equipped with post-combustion controls. Of the ten Group 1 coal-fired utility boilers with SCR or SNCR, there were a total of three forced outages (all in the initial months of operation at the first electric utility boiler SNCR system) after a total of 230 boiler-months of operation. The NESCAUM/MARAMA report concluded that "the experience with these technologies has been extremely positive. While each project had its challenges, the overall reliability and performance of the secondary control technologies has been extremely good. Technology suppliers appear to have addressed the concerns that have been expressed by the utility industry regarding difficulties in applying these technologies to commercial U.S. facilities and any impact to facility reliability." For coal-fired utility boilers, capital costs for SCR and SNCR were found to be $50/kW - $70/kW and $15/kW, respectively, for the scenarios most similar to the units in east and central Texas. Since lignite is simply coal with a lower Btu value, there is no reason to expect costs for control of lignite-fired units to vary significantly from that of coal-fired units. Some of the commenters' capital cost estimates for SCR appear to be higher than the actual experience has shown. The commenters did not provide detailed cost estimates or vendor quotes to document their reported cost estimates. It should also be noted that SNCR is available at a capital cost approximately 20- 30% that of SCR. There are 30 commercially operating SNCR systems under one vendor's trade name on utility boilers, most of which are tangentially-fired. The NOx reductions from these systems range from 32% to 55%, with a typical reduction of 35-40%. Fuel type is not an issue with SNCR; this technology puts urea reagent in the furnace above the combustion zone, and getting the reagent to find the NO _x does not depend on ash properties. For NO _x control, a lignite-fired utility boiler is easier to control than the average coal-fired boiler, since the big furnace volumes, low fuel heating values, and tangential firing are all favorable to NO _x control. In addition, the NESCAUM/MARAMA report noted that "hybrid SCR/SNCR is one technology that has been demonstrated at some facilities to provide high levels of NOx reduction at congested sites where a full SCR system may be very expensive."

The system cap of §117.138 provides flexibility for finding cost-effective emission reductions. In addition, the commission expects that the forthcoming rules for an emissions banking and trading program will provide a way to address a situation in which combustion modifications to a unit left it just over the emission rate allowable. As discussed earlier, the emissions banking and trading program is also expected to reduce the cost.

There are two strategies for NO _x emission reductions from EGFs. SB 7 is a strategy for reductions from grandfathered EGFs. Separate and apart from SB 7, this Chapter 117 rulemaking is designed to achieve NO _x emission reductions from EGFs as part of the strategy for reaching attainment with the ozone NAAQS in DFW. In order to avoid the inequity associated with a more stringent emission limit (0.14 lb/MMBtu) for grandfathered EGFs than for permitted EGFs (0.165 lb/MMBtu), the commission has revised §117.135(1)(B) to specify an emission limit of 0.165 lb/MMBtu for coal-fired EGFs. However, grandfathered EGFs which use coal (including lignite) as a fuel will also be subject to the SB 7 reduction requirements in Chapters 101, concerning General Air Quality Rules, and 116, concerning Control of Air Pollution by Permits for New Construction or Modification (see the January 7, 2000 issue of the Texas Register (25 TexReg 128)). The change to the language in §117.135(1)(B) simply allows units which are subject to SB 7 to count their reductions toward the system cap set out in §117.138.

Regarding the comments that the NO _x emission limits for utility boilers and stationary gas turbines in east and central Texas are not stringent enough, the commission disagrees. The adopted DFW SIP and individual enforceable rule measures necessary to make it approvable required a careful balancing of many factors. The commission's focus has been on the goal of developing a credible plan to attain the one-hour ozone standard. The commission believes that the adopted SIP realistically may solve a pollution problem that to date has proved to be virtually unsolvable in the largest urban areas in the country. The plan is certainly based fundamentally on quantitative analysis, much of which is dictated by the EPA. The current models demonstrate the difficulty of attaining the ozone standard. Air emissions derive from most sectors of human activity, and the required reductions are large enough to require reductions from all sectors. The uncertainties involved in the vast amount of numerical analysis also introduce the need for qualitative assessments of the plan. An important insight from the model is that the benefits of reductions do not accrue linearly. When a certain threshold level is achieved, the model response improves, so that a ton of NO _x reduced produces more ozone reduction than a ton of reduction when the overall reduction is less. This response indicates that plans which rely too much on marginal analyses to demonstrate attainment are more likely to fail.

The adopted SIP contains 13 measures which as a whole are projected to bring DFW back into attainment. Each measure varies in terms of costs, social impact, and ozone benefit. The regional electric utility rule is an attractive measure compared to the other measures because of its low social impact. Other measures affect far greater numbers of much smaller sources and are more difficult to implement from this standpoint.

CSW and TXU stated that SCR technology results in ammonia emissions from ammonia "slip" (i.e., ammonia which did not react completely with the combustion gases and instead is emitted from the unit) and that ammonia also contaminates the fly ash, which then must be treated as a hazardous substance under the Comprehensive Environmental Response, Liability, and Compensation Act, §42, USC §§9601 et seq. (CERCLA), rather than being recycled. CSW and TXU expressed concerns about safety of transportation, storage, and handling of ammonia required for SCR, as well as the disposal of spent catalyst. CSW and TXU stated further that the use of SCR decreases the efficiency of the unit in which it is used because booster fans are required to overcome the pressure drop created by the SCR system.

Minimizing ammonia slip depends on designing the system such that injected ammonia is properly-mixed and well-distributed and such that the amount of catalyst is sufficient to control both NO _x and ammonia to the desired levels. An EPA study ( Applications of Selective Catalytic Reduction Technology on Coal-Fired Utility Boilers , 1997) examined 14 coal-fired units for which ammonia slip data were available. Ammonia slip at seven of the units was in the 0.1 to 1.0 ppmv range, and ammonia slip at the remaining seven units was below 5.0 ppmv. Thus, with good design, SCR can achieve ammonia slip values well below 5.0 ppmv. Similarly, for SNCR the ammonia slip is addressed through good design (particularly, improved operating control using better signal inputs on boiler temperatures, which is now real-time optical sensing). Indeed, an SNCR vendor guarantees ammonia concentrations of no more than 5.0 ppmv ahead of the air preheater, which is a more challenging limit than an in-stack limit).

The Resource Conservation and Recovery Act (RCRA) was established in 1976. It gave the EPA authority to regulate hazardous waste from generation to disposal, including transportation, treatment, storage, and ultimate disposal. CERCLA refers to the "Superfund" program, whose mission is to remediate abandoned or inactive sites that pose an unacceptable risk to public health and safety or the environment. Consequently, RCRA appears to be the appropriate federal requirement of concern. According to the EPA, fly ash from electric utility boilers is exempt under RCRA. While there is little data from SCR or SNCR units on the relationship between ammonia slip and adsorption of ammonia in fly ash, there is no evidence that ammonia slip rates below 5.0 ppmv affect the marketability of fly ash. In fact, ammonia in the fly ash is not preventing utilities in the eastern United States from selling fly ash to cement manufacturers for use in cement kilns, with typical values of 60-100 ppm in electrostatic precipitator ash. From a chemical standpoint, the more alkaline Texas lignite would result in lower ammonia adsorption on the fly ash as compared to eastern coals.

Various safety programs such as the Accidental Chemical Release Risk Management Program will minimize risks associated with the transportation, storage, and handling of ammonia. Most of the safety concerns related to anhydrous ammonia can be avoided through the use of aqueous ammonia, which has concentrations of less than 30% ammonia in water, or urea, which is noncombustible. Urea can be shipped either as a solid or as a liquid solution in water. Processes are available which convert urea into ammonia on-site as needed, which avoids whatever risks may be associated with the transportation, storage, and handling of ammonia. Regarding SCR's reported effect on boiler efficiency, the commenters did not provide details about the efficiency difference. However, the NESCAUM/MARAMA report indicated a 0.5% loss in heat rate with SCR, SNCR, and SNCR/SCR hybrid systems. The commission considers this to be minor in light of the associated NO _x reductions.

CPS stated that the limits in §117.135 which apply to grandfathered EGFs should be deleted because setting limits for these units contradicts 30 TAC §101.333 (Allocation of Allowances). CPS stated that the Chapter 101 and 116 rules which enforce the SB 7 requirements tie the emission limit to the 1997 rate and cap the emission tons for the unit, and do not impose an emission limit. CPS stated that the proposed inclusion of grandfathered EGFs makes the trading program meaningless because the grandfathered gas-fired units will now have to meet an emission rate restriction, rather than allowing the flexibility to achieve compliance by trading. CPS stated further that there will be no incentive to opt-in permitted, electing units to the trading program if emission rates are specified for all gas-fired units.

As described elsewhere in this preamble, the commission has revised the system cap of §117.138 to facilitate trading within an electric power generating system until the forthcoming emission banking and trading program is finalized. The commission expects that the forthcoming banking and trading program will lower the cost of compliance and ultimately will be the preferred compliance option for affected EGFs because such a program will allow overcontrol of the more cost-effective units to be applied to units which are less cost-effective. The commission has made no change in response to the comment.

CPS also suggested that a NO _x emission reduction requirement of 30% (approximately 0.23 lb/MMBtu) be specified for EGFs in Atascosa and Bexar Counties, and possibly Fayette and Goliad Counties as well. CPS asserted that EGFs in these counties do not contribute significantly to the overall regional ozone problem because extensive aircraft investigations have demonstrated that transport to the nonattainment counties generally does not originate from these counties, or that transport distances for the nonattainment areas are too short to be materially affected by emissions from an area roughly described as the triangular area formed by connecting the cities of Austin, San Antonio, and Corpus Christi. CPS asserted that EGFs in these counties (Atascosa, Bexar, Fayette, and Goliad) should therefore not be regulated under the proposed rules. CPS also asserted that aircraft flights in the San Antonio area demonstrate that the upper air conditions of Bexar County are usually VOC-limited, meaning that elevated point source emissions in Bexar County actually reduce upper air ozone levels in that county. However, CPS stated that this beneficial impact is somewhat diminished by the further finding that the plume centerlines of San Antonio's urban ozone plume and the elevated power plant plume from southeastern Bexar County do not coincide. CPS stated that this leads to the conclusion that while emissions from sources outside Bexar County have a great impact on San Antonio's ozone attainment status, the sources within Bexar County do have not near as great an impact on the nonattainment or near-nonattainment areas in northeast Texas.

CPS stated that modeling conducted by the Alamo Area Council of Governments demonstrates that Bexar County point sources contribute only about 2.0% of the ozone in San Antonio while 60% is imported from outside San Antonio. CPS asserted that this demonstrates that power plant emissions in Bexar County have a minimal effect on San Antonio's ozone levels, while transport of emissions into Bexar County have a significant impact on San Antonio. CPS stated that modeling demonstrates that emission reductions resulting from the proposed rulemaking will reduce ozone levels in northeast Texas by an average of 12.6 ppb but an average of only 2.4 ppb in San Antonio. CPS suggested that as a result it was inequitable for sources in the southwestern portion of the eastern half of Texas to be subject to the same control levels and costs as sources in the northeast portion of the eastern half of Texas. CPS also stated that high ozone levels, including exceedances of the ozone NAAQS, have occurred in San Antonio while one or more of the CPS coal-fired EGFs were off-line or operating at reduced levels which approach or exceed the goal of a 50% NO _x reduction.

The commission is not aware of any "extensive aircraft investigations" performed in this triangular area, but would be interested in viewing any scientific data or studies collected by stakeholders. Without missions being flown on a continuous basis, one cannot say that these counties do not generally contribute to regional ozone; one or two investigations cannot form the basis for such a broad conclusion. A recent analysis of missions flown on behalf of the commission in the San Antonio area suggests that, on average, only about 40% of the peak ozone concentration in San Antonio is produced locally, which in turn suggests that regional ozone levels play a crucial role in San Antonio.

This analysis also showed that rural point sources can make significant contributions to background ozone levels which can then make their way to urban areas. Furthermore, this analysis found that air parcel trajectories frequently recirculate through an area and that air pollutants can therefore linger in that area for up to two days. This allows ample time for ozone levels to build up in an urban or rural level even if the direct distance between rural sources and urban areas is relatively short. Even if transport distances from the counties in this triangle were too short for significant ozone to form, ozone precursors would still exist in abundance and would be able to react with other precursors created in the urban area.

The modeling performed by the Alamo Area Council of Governments is one episode with Urban Airshed Model version IV (UAMIV) modeling. This modeling has been revised with the more appropriate CAMx model used by the commission for SIP development and regional scale modeling. The episode was not selected to evaluate the impact of the CPS sources on the air quality in San Antonio. Extensive sensitivity modeling with the UAMIV developed episode has not been performed, and the work performed has not been documented or reviewed by the commission. Therefore, the accuracy or appropriateness of the comments of the impact of the CPS sources can not be verified. If this model has been exercised to provide analysis of transport, the results have not been presented or documented, so it is not possible to verify the accuracy or appropriateness of the comments relating to transport into the San Antonio area. An ozone reduction of 2.4 ppb is a very significant reduction when considering the relative impacts found during analysis of control strategies for the DFW and HGA SIP modeling.

CSW, NACC, and TXU commented on the limit of 0.165 lb/MMBtu for coal-fired utility boilers proposed in §117.135(1)(B)(ii) and (iii) as it relates to ozone levels. CSW and TXU stated that this limit is more stringent than necessary to achieve and maintain compliance with the ozone standard in Longview and Tyler. TXU stated that modeling conducted by Environ on behalf of the East Texas Council of Governments (ETCOG) and North East Texas Air Care (NETAC) shows that a NO _x limit of 0.20 to 0.22 lb/MMBtu (a 35% to 40% reduction) at electric utilities in east Texas would eliminate all ozone exceedances in Longview and Tyler with a margin of safety of nearly 6 ppb. CSW stated that modeling conducted by Environ on behalf of the ETCOG and NETAC shows that a NO _x limit of even higher than 0.20 lb/MMBtu at electric utilities in east Texas would strengthen the previous demonstration that Longview and Tyler will remain in attainment with the one-hour ozone NAAQS.

The commission concurs with the description of the modeling results mentioned in the comment. However, based on the regional analyses cited in the proposal, the commission concluded that reducing regional power plant emissions by 50% (corresponding to a 0.165 lb/MMBtu limit for coal-fired units) would be sufficient to make a significant reduction in ozone and ozone precursor levels transported into the state's nonattainment areas. This level of control was therefore assumed in the DFW control strategy modeling. Even assuming these regional reductions, severe controls are required in the DFW area to demonstrate attainment of the ozone NAAQS. By reducing the level of regional control, even greater reductions would be required in the nonattainment counties to demonstrate attainment. Consequently, the regional NO _x emission reductions resulting from the proposed limit of 0.165 lb/MMBtu for coal-fired utility boilers are crucial for DFW to attain the ozone NAAQS.

TXU asserted that the difference between the proposed limit of 0.165 lb/MMBtu and a limit of 0.2 lb/MMBtu would be less than 0.1% on peak ozone concentrations in DFW. CSW stated that modeling by Environ shows that the difference between the proposed limit of 0.165 lb/MMBtu and a limit of 0.2 lb/MMBtu would be only about 0.1 ppb on ozone concentrations in DFW. NACC stated that modeling by Environ shows that the difference between the proposed NO _x limit of 0.165 lb/MMBtu and a limit of 0.2 lb/MMBtu on peak ozone concentrations in DFW would be 0.1 to 0.2 ppb and that reducing power plant emissions by 50% will have less than a five ppb impact on DFW. NACC further stated that according to the commission this reduction is within the margin of error of the model. CSW asserted that the Environ modeling demonstrates that the difference between the proposed limit of 0.165 lb/MMBtu and a limit of 0.235 lb/MMBtu would be a reduction of 0.1 to 0.3 ppb in ozone concentrations in DFW. TXU asserted that the Environ modeling demonstrates that there is minimal difference in air quality impacts between the proposed NO _x limit of 0.165 lb/MMBtu and a limit of 0.2 lb/MMBtu, and therefore no justification for the 0.165 lb/MMBtu limit based on any claim of benefit to the DFW area. Similarly, TXU asserted that for Austin and San Antonio the commission has not demonstrated that the proposed NO _x limit of 0.165 lb/MMBtu would provide significantly more benefit than a limit of 0.20 to 0.22 lb/MMBtu. TXU also stated that the one-hour ozone concentrations for Austin and San Antonio are currently below the one- hour ozone NAAQS.

The commission agrees that no analysis was done to determine the specific contribution of a 0.165 lb/MMBtu limit or other alternative control levels applied on distant power plants. However, based on the regional analyses cited in the proposal, the commission concluded that reducing regional power plant emissions by 50% (corresponding to a 0.165 lb/MMBtu limit for coal-fired units) would be sufficient to make a significant reduction in ozone and ozone precursor levels transported into the state's nonattainment areas. This level of control was therefore assumed in the DFW control strategy modeling. Even assuming these regional reductions, severe controls are required in the DFW area to demonstrate attainment of the ozone NAAQS. By reducing the level of regional control, even greater reductions would be required in the nonattainment counties to demonstrate attainment.

The particular episodes modeled were not chosen to demonstrate the effectiveness of regional power plant controls, and should not be expected to do so. The commission would like to model additional episodes, but time and budget restrictions prevented doing so for these particular SIP revisions. The commission agrees that the modeling's margin of error is greater than five ppb when comparing peak ozone predictions to monitored ambient concentrations. However, in this instance the modeling is used to estimate the change in ozone concentrations as a result of applying controls. In this case, the margin of error is generally considered to be well below five ppb. The commission agrees with the commenters' interpretation of Environ's results but cannot confirm or refute the modeling itself since it has not performed a thorough peer review. In any case, for an area on the borderline of nonattainment, an increase in ozone of 0.2 ppb could easily be enough to throw the area into nonattainment.

NACC commented that local facilities have a greater impact on air quality than more distant facilities.

The commission agrees that local facilities have a greater impact on air quality than more distant facilities. However, emissions from distant facilities are frequently significant. Analysis of continuous air monitoring station (CAMS) monitoring data for the DFW area shows that regional sources contributed to all but three of the 78 exceedances of the one-hour ozone NAAQS since 1990. On the average, local urban sources caused the formation of 63 ppb of ozone, while the more distant regional sources caused only 35 ppb. While the urban contribution is clearly larger, both are significant and must be controlled in order to attain the one-hour ozone NAAQS.

NACC commented that the commission is asking Texas ratepayers to spend hundreds of millions of dollars to reduce emissions that contribute only 2.3% of the total ozone precursor emissions.

The commission agrees that 2.3% of total ozone precursors is technically correct, but irrelevant. Because it compares coal-fired power plant NOx emissions to the total of all biogenic and anthropogenic emissions of VOC and NO _x for the entire 110-county East Texas area (including the DFW, HGA, and BPA nonattainment areas), it results in a very small number. However, the control strategy is based primarily on NO _x emissions, and coal-fired power plants emit approximately 20% of the NO _x in that same area.

The incremental production cost should not exceed $2.00 per megawatt hour for controls, which assuming a retail price of $.10 per kilowatt hour, would be a 2.0% increase.

CSW questioned why the commission did not pursue further NO _x reductions from sources in the DFW, BPA, and HGA ozone nonattainment areas before proposing NO _x reductions for permitted coal-fired EGFs located in areas that are currently meeting the one-hour ozone standard. CSW stated that the proposed NO _x limits for permitted coal-fired EGFs in areas that are currently meeting the one-hour ozone standard must be based on a much stronger and more sound technical and scientific basis than would be necessary if that same NO _x limit were proposed to be applied in the DFW, BPA, and HGA ozone nonattainment areas.

As noted earlier, the commission is pursuing emission reductions from a variety of sources in the ozone nonattainment areas, as well as in the ozone attainment counties of east and central Texas, and it is likely that additional emission reductions will be necessary in the future. It should also be noted that the emission limitations for EGFs in ozone nonattainment counties are significantly more stringent than those for EGFs in the ozone attainment counties of east and central Texas. For example, EGFs within the DFW ozone nonattainment area are being required to reduce NO _x emissions by approximately 88% as opposed to the estimated 50% reduction required of similar facilities in attainment and near-nonattainment counties.

CSW stated further that the EPA's Acid Rain Database shows EGFs in Texas as having some of the lowest NO _x emission rates in the United States. CSW also stated that when the SB 7 NO _x emission reductions are achieved, the average NO _x for EGFs in Texas will be less than the average NO _x emission rates for EGFs in 43 of the other states, while TMRA stated that the average NO _x emission rate for EGFs in Texas is lower than the average NO _x emission rates for EGFs in 47 of the other states and that these rates will continue to decline as the SB 7 NO _x emission reductions are achieved. TXU stated that when the SB 7 NO _x emission reductions are achieved, the average NO _x emission rate for EGFs in Texas will be less than the average NO _x emission rates for EGFs in 45 of the other states, according to the EPA's Acid Rain Database. TXU also stated that the average NO _x for EGFs in Texas is 40% lower than the national average NOx emission rate for EGFs.

While EGFs in Texas have a lower emission rate than the national average on a lb/MMBtu basis, ozone formation results from reactions of ozone precursors in the presence of sunlight. It is the mass emission rate of ozone precursors that is of relevance, rather than the NO _x emission rate on a lb/MMBtu basis. In addition, there are many high- NO _x baseline coal-fired EGFs in the Midwest which raise the national average NO _x emission rate. Consequently, the average lb/MMBtu emission rate for EGFs is not the appropriate basis for a comparison of Texas to other states, many of which do not even have any ozone nonattainment areas.

CSW and TXU asserted that the commission's choice of a NO _x emission reduction goal of 50%, rather than another percentage, for the proposed NO _x emission limit for permitted coal-fired EGFs is without any technical or scientific justification. CSW stated that the commission's choice of a 50% emissions reduction goal was based primarily on the fact that SB 7 is anticipated to result in a 50% reduction in NO _x emissions from grandfathered EGFs, and that SB 7's goal has no technical or scientific basis but instead was merely a negotiated, politically-drive decision. TXU expressed the belief that combustion modifications at EGFs in east and central Texas, in conjunction with the reductions required by SB 7 and anticipated to be required in BPA, DFW, and HGA, would approach an overall reduction of more than 55% from EGFs in east and central Texas.

The commission disagrees with the commenters. As noted earlier in this preamble, modeling tests indicate that point source NO _x reductions of less than 50% have limited ozone reduction benefit, whereas reductions at and above 50% show increasing ozone reduction benefits. For example, in the DFW area, 25% NO _x reductions in all attainment counties of east and central Texas result in a seven to ten ppb one-hour ozone reduction, whereas 50% NO _x reductions over the same area result in a 21-27 ppb one-hour ozone reduction. Doubling the NO _x reduction from 25% to 50% provides more than twice the ozone reduction benefit. The commission's choice of a 50% emissions reduction goal was based on this fact. TXU did not provide an analysis to support their contention that combustion modifications at EGFs in east and central Texas, in conjunction with the reductions required by SB 7 and anticipated to be required in BPA, DFW, and HGA, would approach an overall reduction of more than 55% from EGFs in east and central Texas.

CSW asserted that the Baylor aircraft monitoring does not support the proposed 50% reduction in NO _x emissions from coal-fired EGFs due to a variety of limitations in the data. Specifically, CSW stated that the monitoring data only represent a snap-shot in time of the concentrations of ozone, NO _x , and other air contaminants and do not demonstrate or indicate what the concentrations would be at a later time or day. CSW also stated that the data only represent a snap-shot in space of the concentrations of ozone, NO _x , and other air contaminants and do not demonstrate what the concentrations would be at a different altitude or at different locations at the same altitude. CSW further commented that the relevant altitude for modeling and monitoring attainment with the one-hour ozone NAAQS is ground level, that the Baylor aircraft monitoring data was generally collected at 800 feet to 10,500 feet, and that the commission has not presented information or data to support a conclusion that the one-hour concentration at a ground level location would be the same as the concentration measured by aircraft at a much higher altitude directly above the ground level location. CSW also stated that meteorological conditions (e.g., wind speed and direction) associated with the aircraft monitoring were not always known or were so variable as to limit or eliminate the value of the data for the proposed NO _x emission limits. Finally, CSW stated that the aircraft monitoring data do not indicate or demonstrate whether or by how much the proposed NO _x emission reductions will decrease one-hour ozone concentrations in ozone nonattainment areas to allow a demonstration of attainment with the one-hour ozone NAAQS in or near-nonattainment areas to help them avoid being designated as one-hour ozone nonattainment areas.

Comparison of ground monitoring data with airborne pollutant levels suggests that airborne data compares relatively well to ground-based data. Baylor aircraft flights are planned so the aircraft is being flown at a time and an altitude in which the atmosphere is mixed. In these conditions, pollutant levels can usually be assumed to be fairly uniform from ground height all the way up to the "mixing layer." Also, the aircraft usually performs more than one up-and-down spiral precisely for the purpose of measuring how pollutant levels change in the vertical. Consequently, any changes in pollutant levels can be identified and taken into account.

While it is true that a given pollutant measurement point is only a "snap-shot in time," the same could be said for any single measurement point at ground monitoring site. Baylor University's airborne monitoring platform has several capabilities which allow it to overcome this "limitation." First, the Baylor aircraft can, and does, fly over the same latitude and longitude coordinates more than once in a given flight which means that it has the ability to measure pollutants at a single point over time. Second, because the aircraft moves, it can, and does, track a particular "parcel" of air throughout the day as it moves through a geographic area and disperses. Third, because the aircraft can climb and descend, it can, and does, measure vertical changes in pollutant levels. Additionally, the aircraft is often flown during a time of the day when the atmosphere is relatively well-mixed so that differences with ground-based monitors can be further minimized.

Even though having wind data collected by the aircraft during its flight is the preferred mode of operation, the inability to do so does not prevent the Baylor aircraft from providing important information. Additional resources, such as ground monitoring data, meteorological models, and radar data can provide important wind information needed to interpret flight data.

Tenaska commented on the proposed limit of 0.15 lb/MMBtu for stationary gas turbines specified in §117.135(2)(B) and (C). Tenaska noted that this limit is approximately equivalent to 42 ppmv NO _x and suggested that the rule specify an alternate limit of 42 ppmv NO _x , adjusted to 15% oxygen. Tenaska stated that this would avoid unintended impacts on facilities that lack systems and guarantees to demonstrate compliance with the proposed limits in lb/MMBtu. Tenaska also stated that even the latest combustion technology can not achieve lower than 42 ppmv NO _x emissions while firing fuel oil without post-combustion controls.

The commission has revised §117.135(2)(B) and (C) to specify an alternate limit of 42 ppmv NO _x , adjusted to 15% oxygen. Regarding the comment about fuel oil firing, the commission notes that natural gas enjoys a significant cost advantage over fuel oil on a cost-per-heating-value basis, and this economic difference will generally discourage the use of fuel oil. While some minimal fuel oil firing may still occur (for example, to ensure reliability of fuel oil backup systems), the emission limits of §117.135 are on an annual (calendar year) basis. The commission expects that this averaging period will easily allow occasional firing of fuel oil without jeopardizing compliance with the emission limits.

Brazos, Bryan, CSW, EPA, Reliant, San Miguel, Tenaska, TPPA/ED, and TXU commented on the proposed optional system cap of §117.138, which provides a flexible alternative to direct compliance with the NO _x emission specifications of §117.135. Brazos, Reliant, TPPA/ED, and TXU noted that the system cap does not allow inter-company trading. Brazos, TPPA/ED, and TXU stated that the cost of compliance for EGFs will be higher than estimated in the rule proposal preamble because the commission did not concurrently propose a regional NO _x trading program.

Bryan stated that TMPA, of which Bryan is a part, operates a single coal-fired unit, while Brazos and San Miguel stated that San Miguel operates a single lignite-fired unit. Reliant stated that they only have two units (at the Limestone Station) with which to average under a system cap. Brazos, Bryan, and San Miguel commented that without the ability to trade with other companies, they will not be able to use the system cap. Tenaska stated that the proposed system cap is unworkable for its units because the baseline heat input will be below the summer rated capacity heat input, although they are contractually obligated to supply the summer rated capacity heat input when called upon by the customer.

Brazos, CPS, CSW, the EPA, Tenaska, and TXU commented specifically on §117.138(c)(1), concerning the rolling 30-day average emission cap. The EPA stated that the baseline period for the historical heat input should match the commission staff's modeling period. TXU recommended that the highest annual heat input for 1997, 1998, and 1999 be used for allowance calculation using the EPA's Acid Rain Database, while CPS commented that 30 TAC Chapter 101, Subchapter H, Division 2 (Emissions Banking and Trading of Allowances) sets a yearly tonnage rate based on 1997 emissions for EGFs and electing EGFs. Reliant expressed support for the use of data from 1996-1998 and stated that data from later years (i.e., 1999) begin to include the effect of ongoing emission reduction work, lowering the baseline and penalizing companies who have been proactive in emission reduction activities. Brazos stated that the peak period for electric utilities has historically been the months of June, July, August, and September and for this reason suggested that the historic high heat input should be changed to these four months rather than July, August, and September. CSW recommended use of an annual average for consistency with the proposed annual average emission limits of §117.135.

Tenaska stated that the proposed rolling 30-day average would pose serious limitations on the use of fuel oil during winter months. Tenaska stated that since fuel oil usage is likely to occur only during extreme winter cold periods, the rolling 30-day average cap should not apply on a year-round basis. Tenaska suggested that the system cap be for the summer ozone season of May through September, and should be based on the potential heat input, not baseline values. CPS, CSW, and TXU stated that a rolling 30-day average is inconsistent with the cap and trade provisions of SB 7, and TXU also commented that the added complexity of a rolling 30-day average is not justified since the rule applies to ozone attainment counties. CSW commented that a rolling 30-day average emission cap would require greater than a 50% NO _x emission reduction and therefore, is unnecessary to reach the 50% NOx emission reduction goal.

TXU stated that almost all of the permitted power plants in east Texas are coal or lignite-fired base-load units that operate continuously, and suggested that an annual average is appropriate for these units. TXU also stated that there will be no excess allowances available for trading due to the low emission limits of §117.135, which they believed conflicts with the intent of the trading program designed by the Texas Legislature in SB 7.

The commission believes that the cost estimates for EGFs included in the rule proposal preamble are reasonable. The commission agrees that the forthcoming banking and trading program will lower the cost of compliance and expects that ultimately it will be the preferred compliance option for affected EGFs because such a program will allow overcontrol of the more cost-effective units to be applied to units which are less cost-effective, even between companies. The commission has revised the system cap of §117.138 by changing from 30-day rolling average and daily emission caps to an annual average (based on the total annual heat input for each unit in the emission cap for 1996, 1997, and 1998) in order to facilitate trading within an electric power generating system until the forthcoming emission banking and trading program is finalized. The commission selected the 1996-1998 timeframe because it is the same timeframe used for EGFs in the modeling.

LCRA and TXU commented on §117.138(e), which provides procedures for substituting emissions data during periods when a NO _x monitor is off-line. LCRA and TXU suggested that the data substitution procedures for determining NO _x emissions be consistent with the data substitution procedures of 40 CFR 75, Part D. LCRA stated that this would result in the same NO _x emission rate data being reported to the commission for the Chapter 117 rule and to the EPA for the acid rain program. LCRA also stated that this would eliminate the need for maintaining two NO _x emissions databases and avoid having to make changes to software programs in existing data acquisition and handling systems.

The commission agrees that the suggested changes will minimize costs while also ensuring that adequate substitute emissions data is reported for periods when a NO _x monitor is off-line. Therefore, the commission has revised §117.138(e) accordingly.

Reliant commented on §117.138(g), which requires the owner or operator of any unit subject to a system cap to report exceedances of the system cap emission limit. Reliant stated that the 48-hour report deadline and the 21-day report requirement are unreasonable and commented that the upset and maintenance reporting requirements of 30 TAC Chapter 101, §101.6 (Upset Reporting and Recordkeeping Requirements) and (Maintenance, Start-up and Shutdown Reporting, Recordkeeping, and Operational Requirements), exempt boilers and gas turbines equipped with CEMS from requirements for immediate reporting and creating records. Reliant suggested that the reporting requirements of §117.149 are adequate to ensure that any system cap exceedances are addressed.

The specified exemptions from the upset and maintenance reporting requirements of §101.6 would not apply to exceedances which occurred for other reasons, such as failure to properly maintain control equipment or simply a failure to comply with the system cap emission limit. However, because the commission has revised the system cap of §117.138 to an annual average basis and, as described later in this preamble, has changed the reporting period of §117.149(d) to an annual calendar year basis, the commission agrees that the 48-hour and 21- day report requirements are no longer necessary. The commission has revised §117.138(g) accordingly.

The EPA commented on §117.138(i) and stated that units which are permanently retired or decomissioned and rendered inoperable should be eligible for inclusion in the system cap emission limit only if the shutdown occurred after the modeled emission inventory. Shutdowns that occurred before could only be used to generate credit if the previous shutdowns were carried as existing emissions in the most recent inventory relied on for the rate of progress plan or the attainment demonstration SIP.

The commission agrees and has revised §117.138(i) to specify that a shutdown is creditable only if it occurred on or after January 1, 1999. This date was selected because it is consistent with the 1996-1998 modeling period and because the baseline period for type-name="sub">i , the historical heat input used in the annual average of §117.138(c)(1), is 1996, 1997, and 1998.

Reliant commented on §117.138(j), which states that emission reductions from shutdowns or curtailments which have been used for netting or offset purposes under the requirements of Chapter 116 of this title may not be included in the baseline for establishing the system cap. Reliant stated that this requirement is unnecessary.

The commission believes that it is appropriate to clearly specify that emission reductions from shutdowns or curtailments which have been used for netting or offset purposes under the requirements of Chapter 116 may not be included in the baseline for establishing the system cap. This is necessary to ensure that no double-counting of emission reductions occurs. The commission has made no change in response to the comment.

CEED and NACC commented on §117.138(k) and stated that startups, shutdowns, and upsets should not be included in the system cap. CEED and NACC stated that the system cap is impractical if startups, shutdowns, and upsets are included.

Consistent with how this issue has been addressed in previous rulemaking, the commission believes that inclusion of startups, shutdowns, and upsets in the system cap is necessary to provide an incentive for owners or operators to minimize emissions from these events. The commission has made no change in response to the comment.

The proposed §117.138(k) includes a maximum daily rate data fill-in procedure which allows an owner or operator to show to the satisfaction of the executive director that the actual emissions were less than maximum emissions. To address concerns expressed by the EPA about the corresponding language in §117.108(k), concerning System Cap, (specifically, what replicable procedure will be used to determine whether actual emissions were less than maximum emissions), the commission has revised §117.138(k) to specify that satisfaction of both EPA and the executive director is necessary.

TXU suggested the addition of a new subsection (l) to §117.138 which would specify that units eligible to be included in a system cap that are subsequently sold to a new owner or operator may continue to operate under the system cap if the former and new owners enter into a contract agreement to meet all requirements of the system cap and operate the units with combined NO _x emissions in compliance with the original system cap. TXU stated that this is necessary so that construction of NOx controls on units they plan to sell can be maintained for completion by the compliance date specified in §117.512.

The commission believes that the inclusion of two separate owners in a single utility cap is unnecessary. The commission expects that the compliance flexibility that the commenter seeks will be available through use of the forthcoming banking and trading rules. The suggested alternative makes it more difficult for the commission to determine compliance because correcting problems is more complicated when there are two entities responsible. The commission has no control over any contract between utilities. The commission has made no change in response to the comment.

CSW suggested that the proposed §117.141(d)(2) be deleted as part of its request that the basis of the system cap of §117.138 be changed to an annual average.

The commission agrees and has made the suggested revision and renumbered the proposed §117.141(d)(1) as §117.141(d).

An individual commented on §117.143 and opposed allowing PEMS as an alternative to CEMS for NO _x monitoring. The individual expressed concern that PEMS are not accurate enough and do not reflect actual emissions.

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

CPS and TXU stated that §117.143(b), which requires CO monitoring, should be deleted since there is not a CO limit specified. CPS also suggested adding an exemption from the CO analyzer requirement for acid rain peaking units which use meet the requirements of 40 CFR Part 75, Appendix E, since such units are not even required to install a NO _x monitor under Appendix E. CPS commented that Appendix E allows stack testing for NO _x every five years or 3,000 operating hours, in lieu of installing a CEMS, as long as the unit maintains its peaking status.

Because a CO limit was inadvertently omitted from the proposal and cannot be added at this time, there is presently no need for the proposed CO monitoring requirement. Since the commission is deleting the proposed CO monitoring requirement of §117.143(b), the suggested exemption for acid rain peaking units which use meet the requirements of 40 CFR Part 75, Appendix E is a moot point but will be considered in the event the commission proposes adding a CO limit and monitoring requirement in the future.

CPS commented on §117.143(c)(2), which provides an option in which one CEMS may be shared among multiple units. CPS stated that the requirement that the exhaust stream of each unit be analyzed separately and the requirement that the CEMS meets the applicable certification requirements for each exhaust stream seemed to contradict each other. CPS stated that §117.143(c)(2)(A) and (B) should either be deleted or clarified to mirror the common stack CEMS requirements in 40 CFR Part 75, §75.16.

There is no contradiction between the requirements. In addition, the option to share CEMS among units is consistent with the corresponding rule in the industrial source division of this chapter. The commission has made no change in response to the comment.

CSW suggested that the proposed §117.145(b) be revised to reflect its request that the basis of the system cap of §117.138 be changed to an annual average.

The commission agrees and has made the suggested revision.

CSW suggested that the proposed §117.149(d)(1)(B) be deleted as part of its request that the basis of the system cap of §117.138 be changed to an annual average.

The commission agrees and has made the suggested revision and has renumbered the proposed §117.149(d)(1)(A) as §117.149(d)(1). In addition, since the system cap has been changed to an annual basis, the commission has changed the proposed semiannual reporting periods of §117.138(g) and §117.149(d) to an annual calendar year basis.

Richards and four individuals suggested that emissions of air toxics from cement kilns in Ellis County can be directly linked with the appearance of rare diseases, including cancer, and urged that these emissions be reduced. Eleven other individuals generally opposed the burning of waste-derived fuel in cement kilns. Another individual recommended that burning of waste-derived fuel be reduced through changes in manufacturing processes which minimize the volume of waste generated.

The purpose of the proposed rulemaking is to address emissions of ozone precursors (specifically, NO _x ) in order to help bring ozone nonattainment areas into compliance and to help keep attainment and near-nonattainment areas from going into nonattainment. The proposal does not address emissions of air toxics, which instead are regulated by other commission rules as well as a variety of federal standards. However, the Community Air Toxics Monitoring network currently includes a total of 44 monitors in 18 counties, with two in Ellis County, two in Dallas County, and one in Tarrant County. Should this air toxics monitoring indicate levels of concern, the commission will take appropriate action to ensure that health effects concerns are thoroughly addressed. Because the individual's suggestion is beyond the scope of this rulemaking, the commission has made no change in response to this comment.

Alamo stated that the rule should include a maximum cost (in dollars per ton of NO _x reduced), while Capitol stated that the commission should provide some assurance that the rules will have a reasonable economic impact on the cement industry.

The commission agrees that cost should be taken into account in the development of control strategies and has done so. However, the commission disagrees with the suggested concept of including a maximum cost (in dollars per ton of NOx reduced) in the proposed rules. Such a concept would not ensure that the necessary emission reductions occur. In addition, the concept raises numerous issues such as the calculation methodology, enforceability, and especially the cutoff level. For example, the commission is aware of one company that spent approximately $31,000 per ton to comply in an ozone nonattainment area while the company was in Chapter 11 bankruptcy. The commission has made no change in response to the comments.

No comments were received on §117.260, concerning Definitions. However, in conjunction with the revisions to §117.265, concerning Emission Specifications, described later in this preamble, the commission has added definitions of "low-NO _x burners" and "mid-kiln firing" to §117.260.

Alamo and Capitol commented on §117.261. Alamo suggested that Ector and Nolan Counties should be included so that the two west Texas cement plants are included in the NO _x reduction requirements. Alamo stated that it was unfair that the cement plants in east and central Texas were subject to the limits while these two west Texas cement plants were not.

The commission can not revise §117.261 to apply in Ector and Nolan Counties in this rulemaking because the cement plants in those counties would not have had adequate notice and opportunity to comment. Regarding the commenter's assertion that the rules are unfair to cement plants in the eastern half of Texas, the rules are targeting the eastern half of the state because modeling (described in detail elsewhere in this preamble) has shown that NO _x emissions from sources in that area are contributing to exceedances of the one-hour ozone NAAQS in ozone nonattainment areas as well as contributing to elevated ozone levels in near-nonattainment areas. The commission believes that it is appropriate for those sources which are contributing to the ozone problem to be part of the solution. Consequently, the commission has made no change in response to the comment.

Capitol questioned whether NO _x emissions from its cement plant in San Antonio impact ozone concentrations in DFW and stated that the rules' applicability should be limited to Ellis County until it is demonstrated that emissions from cement plants in other counties are contributing to an exceedance of the ozone standard.

As noted earlier, the proposed controls are based upon a body of circumstantial evidence from aircraft measurements, seasonal modeling, back trajectories, and statistical studies indicating that electric generating facilities and cement kilns in central and eastern Texas contribute to the background levels of NO _x which impact the DFW area. Documents explaining these additional studies are included as appendices to the SIP.

It has come to the commission's attention that Hays County was misspelled in §117.261. The commission has corrected the spelling.

Holnam commented on §117.265 and noted that in the preamble to the proposed rules, the commission solicited comments regarding the technical feasibility and cost-effectiveness of NO _x emission reductions beyond those which would be achieved by the proposed cement kiln rules. Holnam noted that the rule proposal further stated that if the commission determined that NO _x emission reductions beyond those which would be achieved by the proposed rules are technically feasible and cost-effective, then in the adoption of the final rules the commission might incorporate more stringent emission reduction requirements. Holnam stated that adoption of more stringent limits than those proposed would not comply with the notice and opportunity for comment sections of the APA (specifically, Texas Government Code, §2001.023 and §2001.029) and cited a court case (State Board of Insurance v. Deffebach, 631 S.W.2d 794, 801) (Tex. App.-Austin 1982, writ ref'd n.r.e) which it claimed made such action illegal.

The commission disagrees with the commenter's interpretation of the caselaw cited. As long as the adopted rules do not regulate new parties or affect new subjects of regulation and the agency does not adopt rules which are completely different rules than those proposed, there is no requirement that an agency repropose the rules prior to adoption. The commission believes that a change in the emission limits would not be enough to require reproposal especially given the fact that the regulated industry was put on notice in the rule proposal preamble that the commission would consider lowering the standards during the comment period.

Holnam further stated that the commission's air permit staff accepted a NO _x emission level of approximately 5.4 pounds per ton (lbs/ton) of clinker produced as best available control technology (BACT) for its new preheater-precalciner kiln in Ellis County.

The commission disagrees with the commenter. The company's recently-amended permit (Permit Number 8996/PSD-TX-454M2) allows up to 770 tons per year (tpy) of NO _x emissions from each of two cement kilns with a maximum allowable production rate of 7,000 tpd of clinker. At maximum production, this represents an average NO _x emission level of 1.4 lbs/ton of clinker produced.

ALAT, Billion, Cleburne, Dallas, Dallas Sierra Club, DAR, GPTC, LWVTC, LWVTX, SCLSC, Turner, TWCA, and 577 individuals commented that the requirements of §117.265 are not stringent enough. Alamo, Capitol, and Cemex commented that the proposed limits are too stringent. Alamo, Capitol, Cemex, and ECCI suggested that the proposed limits be changed to reflect the equipment-based standards (low-NO _x burners, mid-kiln firing, or equivalent) proposed by the EPA in the Ozone Transport Federal Implementation Plan. Tulsa, OPG, and eight individuals supported the proposed requirements. One individual stated that cement kilns in Ellis County should be required to reduce NO _x emissions by 90%; DAR and an individual recommended 80% to 90%; TWCA and six individuals recommended 88%; ALAT, Dallas Sierra Club, SCLSC, and 21 individuals recommended 80%; one individual recommended 70% to 80%; GFWSC and one individual recommended 70%; SCATC/SPAC and an individual recommended 50% to 70%; one individual recommended 60%; Dallas, Goodman, LWVTC, LWVTX, NAACP, and 510 individuals recommended 50%; Cleburne and the Steering Committee recommended up to 50%; and two individuals recommended 40%. DAR and NAACP stated that anything less than a 50% reduction for Ellis County cement plants raises issues of environmental justice for residents of southern Dallas and Tarrant Counties.

The equipment-based standards suggested by Alamo, Capitol, Cemex, and ECCI would not achieve the necessary emission reductions because some cement kilns are already equipped to meet the suggested equipment-based standards and consequently would not have to make further reductions. Rather than setting equipment-based standards, the commission believes that it is more appropriate to establish emission limits because this approach provides more flexibility so that individual kilns can be evaluated to determine the most cost-effective approach to reduce NO _x emissions.

Regarding the specific emission limits for Ellis County cement kilns, review of the company's emissions inventory and associated data subsequent to publication of the proposal indicates that post-1996 process modifications (mid-kiln firing of tires, and addition of steel slag) at the North Texas wet process kilns have reduced NO _x emissions by 30% as of 1998 such that these kilns can meet a NO _x limit of 4.0 lb/ton of clinker. This emission limit would represent a NO _x emission reduction of approximately 30% from the 1996 emissions inventory baseline for the Ellis County wet process cement kilns. However, in order for this emission reduction to be creditable in the SIP, it must be enforceable. Consequently, the commission is revising the emission limit in §117.265 to reflect a NO _x limit of 4.0 lb/ton of clinker for wet process cement kilns in Ellis County. To provide additional flexibility in all affected counties yet still ensure that all reasonable emission reduction measures have been implemented, the commission has added an option which provides that each kiln equipped with low-NO _x burners and mid-kiln firing is not required to meet the NO _x emission limits. As a practical matter, the commission expects that North Texas and TXI would utilize either this equipment standard option or the source cap option of §117.283 (described later in this preamble) rather than directly complying with the emission limits of §117.265, regardless of whether the limit was set at 4.0 or 6.0 lb/ton of clinker for wet process kilns in Ellis County.

Regarding the commenters' concerns about environmental justice, the commission notes that the adopted emission limits will result in substantial NOx emission reductions of approximately 30% from the 1996 baseline, despite a 74% increase in clinker production capacity at the Ellis County cement plants since 1996. Additionally, NO _x is not generally associated with environmental justice concerns because it does not have the localized impact of VOCs, especially toxics. Regarding the desire of many commenters that greater emission reductions be required of Ellis County cement kilns, the commission believes that the adopted limits are the most stringent that are reasonably achievable for the wet process kilns in Ellis County. The significant post-1996 combustion modifications at North Texas described earlier reduced NO _x emissions sufficiently in 1998 to achieve approximately a 30% NO _x emission reduction from 1996 levels. TXI will be bringing a new preheater/precalciner kiln on-line by the end of 2000. This new kiln will be equipped with low-NOx burners and staged combustion, thus minimizing thermal NO _x generated from the heating of raw materials prior to entry to the kiln. TXI's existing No. 2 and No. 3 wet process kilns will not be allowed to operate when the new preheater/precalciner kiln is in operation. However, TXI will continue to operate its No. 1 and No. 4 wet process kilns after the new kiln is operating. In order to address previous odor complaints related to sulfur compounds, the commission has required TXI's wet process kilns to maintain an average oxygen content, as measure at the kiln exit, of at least 0.75% by volume on a five-minute average. While this successfully resolved the odor situation, excess oxygen has the unfortunate side effect of resulting in the formation of additional NO _x . Even if these kilns were equipped with low-NO _x burners and mid-kiln firing of tires to reduce NO _x , it is unlikely that the company would be able to meet the NOx limit for wet kilns specified in §117.265. As discussed elsewhere in this preamble, no reasonably effective and practical post-combustion controls are currently available for wet process kilns. Consequently, the commission believes it is appropriate to revise §117.283 to allow the Ellis County cement kilns to participate in the source cap. This will allow TXI to operate its new kiln below the permit limits and apply the difference toward the required emission reductions from its wet process kilns. The necessary NO _x emission reductions will still be achieved with this approach, but TXI and North Texas will have additional flexibility in making the emission reductions. Holnam's two preheater/precalciner kilns (one existing, one recently-permitted) will be equipped with low-NOx burners and operated at reduced combustion air input (sub-stoichiometric conditions) to reduce NO _x emissions by approximately 27.5% from 1996 levels, despite a doubling of clinker production capacity. The commission expects that Holnam will be able to comply with the NO _x limit of 2.8 lb/ton of clinker for preheater/precalciner kilns, based upon its permit.

DAR stated that low-NO _x burners and mid-kiln firing of tires are viable control technologies for wet process cement kilns and together could reduce NO _x emissions from the North Texas and TXI wet kilns by 50% or more.

The commission agrees that low-NO _x burners and mid-kiln firing of tires are viable control technologies for wet process cement kilns, such as those at North Texas and TXI in Ellis County. Low NOx burner technology is based on producing an early ignition of the fuel in an oxygen deficient atmosphere in order to reduce the formation of NO _x . Low NO _x burners require an indirect firing system for solid fuels, which allows the primary air to be reduced about 6.0-10%, resulting in less NOx formation. In Table 2-2 of the EPA's alternative control techniques (ACT) guidance document titled Alternative Control Techniques Document -- NO _x Emissions from Cement Manufacturing (EPA-453/R-94-004, March 1994), the EPA estimates that NO _x reductions from conversion to low-NO _x burners range from 20-30% and estimates that NO _x reductions from mid-kiln firing of tires range from 20-40%. On page 7-2 of the ACT, EPA assumes a 25% reduction efficiency for each control measure. However, it should be noted that the percentages are not additive. Thus, while it might be reasonable to expect better than a 25% NO _x reduction from use of both low-NOx burners and mid-kiln firing of tires at a wet kiln, it is highly unlikely that a 50% reduction would be achieved.

DAR and five individuals suggested that post-combustion controls (SCR and SNCR) are viable options for cement kilns. DAR also stated that SCR has been used successfully on boilers, internal combustion engines, and gas turbines, as well as on coal-fired boilers where exhaust gases contain a significant amount of particulate and sulfur dioxide (SO ₂ ). Regarding a 1976 trial program which evaluated SCR on three cement kilns (each equipped with an electrostatic precipitator (ESP) for particulate control), DAR stated that while the initial NO _x control efficiencies of 98% had dropped to about 75% due to catalyst coating after seven months of operation, the efficiency was still over 50%. DAR also suggested that particulate control technology (ESPs or baghouses) could be used prior to the kiln exhaust stream entering the SCR.

Regarding SNCR, DAR stated that this technology could be applied to dry kilns. DAR acknowledged that there are no installations of SNCR on cement kilns in the United States but stated that in 1995 a cement kiln with built-in SNCR was designed and permitted as BACT in Nevada (albeit never constructed). DAR stated that Iowa's Department of Natural Resources designated SNCR as BACT for a cement plant in that state. DAR also referred to a discussion in the Alternative Control Techniques Document (ACT) which described experimental tests of SNCR on preheater/precalciner kilns. DAR noted that in one test, the ACT stated that in one test the NO _x emissions were reduced by an average of 40% but reached 90% when the ammonia injection rate was 10-20% in excess of stoichiometric, while in a test of a urea-based SNCR the NO _x emission reduction ranged from 27-55%. DAR commented that the ACT stated that in a test on a European preheater-type kiln, an SNCR system with a 1:1 molar ratio of reagent to nitrogen dioxide achieved NO _x emissions of about 70% with ammonia-based reagent and about 35% with urea.

Review of Permit Number 99-A-579P issued by the Iowa Department of Natural Resources (DNR) on November 9, 1999 revealed that SNCR was in fact not designated as BACT for this preheater/precalciner cement kiln. Instead, the company and Iowa DNR negotiated a limit of 4.0 lb NO _x /ton of clinker. The permit requirements for the Nevada cement kiln are irrelevant. Because the plant was never constructed, its SNCR system obviously was never demonstrated in practice.

As noted earlier, a 50% NO _x reduction was the goal, but in some cases technology is not available which would achieve a 50% or higher NO _x reduction. Specifically, for wet process cement kilns, SNCR reportedly has difficulties involved in continuous injection of the reducing agents. The temperature where the reagent (urea or ammonia) is injected is critical because there is no catalyst with SNCR. The necessary temperature is approximately 1,600 to 2,000 degrees Fahrenheit, but on a wet kiln this temperature range occurs roughly halfway down the length of the kiln. While access is possible once per kiln revolution through ports in the kiln (such as those used for mid-kiln firing), the reagent must be added continuously in a specific stoichiometric ratio in order to properly control NO _x emissions and reduce ammonia slip. While SNCR is not applicable to wet process cement kilns, it does appear to be a promising technology for dry process cement kilns. The ACT notes on page 5-17 that "greater NO _x reductions were observed with more than stoichiometric amount of reagent, although there was increasing ammonia 'slip' in the exhaust gases." Regarding the urea-based SNCR test, the ACT notes on page 5-16 that "limited short term data were obtained." Simply put, SNCR has not yet been proven on dry process cement kilns in the United States, although perhaps in the near future additional information will be available which documents that SNCR or some variation of it is a viable NOx control technique for dry process cement kilns in the United States.