The Texas Commission on Environmental Quality (TCEQ or commission) adopts amendments to §§114.6, 114.312, 114.313, and 114.315 - 114.318. Sections 114.6, 114.313, 114.315, 114.316, and 114.318 are adopted with changes to the proposed text as published in the December 16, 2005, issue of the Texas Register (30 TexReg 8407). Sections 114.312 and 114.317 are adopted without changes and will not be republished.

The amended sections as adopted will be submitted to the United States Environmental Protection Agency (EPA) as revisions to the state implementation plan (SIP).

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

On March 9, 2005, the commission adopted revisions to the low emission diesel fuel (LED) rules (§§114.312 - 114.319) and submitted them as a SIP revision to the EPA on March 23, 2005. Subsequently, EPA raised concerns with certain provisions of §114.315 that give the state unilateral authority to accept alternative methods of compliance. Specifically, EPA stated that subsections (b) and (c)(4)(C)(ii)(V) of §114.315 were problematic in regard to EPA's approval of the rule and SIP revision.

On July 5, 2005, the TCEQ's executive director (ED) wrote to the EPA's Region 6 director, Mayor Greene, requesting EPA exclude certain provisions of §114.315 from its review of the SIP submittal, and stating that the commission would address these provisions in a future rulemaking. On August 10, 2005, the EPA published a notice of proposed rulemaking in the Federal Register (70 FR 46448), proposing to approve the revisions, excluding the provisions of §114.315 the ED requested. On October 6, 2005, the EPA published a final rule in the Federal Register (70 FR 58325) that approved the SIP revision submitted by Texas, excluding the provisions of §114.315 the ED requested. The commission is adopting in this rulemaking revisions to the excluded provisions of §114.315(b) so that the ED consults EPA before approving an alternative test method and, accordingly, removes §114.315(c)(4)(C)(ii)(V).

These adopted rules also address issues raised by EPA regarding its consideration of alternative emission reduction plans (AERPs) as allowed under §114.318. Under the previous rule, the AERPs must be approved by both the ED and EPA. The ED has approved 17 AERPs to date. The EPA determined that the commission must submit the AERPs in the form of a SIP revision, requiring public review of each AERP. However, many of the diesel fuel producers consider their AERPs to be confidential business information. Furthermore, the commission would be required to submit a new SIP revision any time a producer amended its AERP. In lieu of a SIP revision, this rulemaking changes §114.318 to establish a method by which all AERPs could be approved by the ED and EPA without a SIP revision. The ED notified all holders of currently approved AERPs of the commission's intention to develop a protocol to facilitate EPA approval of AERPs that may impact the approvability of some strategies in these AERPs; however, the protocol will continue to allow a majority of the strategies in these AERPs, with some modifications. Under this adoption, all currently approved AERPs will expire December 31, 2006. Under the adopted changes to §114.318, producers wishing to use an AERP for compliance with the LED rules must submit an AERP under the new protocol by no later than November 15, 2006, to be approved before December 31, 2006. The commission believes that a December 31, 2006, expiration date provides an appropriate amount of time for producers to submit an AERP that would be approvable under the new protocol.

On October 14, 2005, the commission held a stakeholder meeting in Austin to solicit feedback on a draft protocol for state and federal approval of AERPs. Comments received as a result of this meeting were considered prior to the commission's proposal to revise the LED rules.

The LED amendments adopted on March 9, 2005, contained changes that included section restructuring, which require revisions to other sections of Subchapter H, Division 2 that were not modified in that rulemaking in order to correct citation references for consistency and accuracy. This adopted rulemaking makes changes to §114.313, Designated Alternative Limits, and §114.317, Exemptions to Low Emission Diesel Requirements, to correct rule references.

The commission is also adopting changes to the testing requirements for alternative diesel fuel formulations in §114.315. These changes clarify test procedures consistent with procedures and guidance approved by the EPA and the California Air Resource Board (CARB) from which the LED rules were initially patterned. The EPA requested the commission make these changes to ensure consistent and accurate emission testing results. The adopted changes also apply to the testing of diesel fuel additive-based formulations.

SECTION BY SECTION DISCUSSION

Administrative changes are adopted throughout the rules to be consistent with Texas Register requirements and agency guidelines.

The adopted changes to §114.6 amend the definition of additive to clarify that substances added to gasoline or diesel that are registered with the EPA or added for the purposes of reducing exhaust emissions from motor vehicles or non-road equipment and are exempted from the EPA registration requirements are also considered to be additives under these rules. In addition, the new definition of additive does not reference the exclusion of an additive composed solely of carbon and/or hydrogen because this exclusion is already provided under 40 Code of Federal Regulations (CFR) Part 79 as it relates to fuel additive registration requirements. Also, the other adopted changes in §114.6 amend the definitions of final blend and LED for consistency relating to the acronym for LED and the definition of gasoline for accuracy in citing the reference to the American Society for Testing and Materials (ASTM) standard.

The adopted changes to §114.312(f) remove volatile organic compounds (VOCs) from the comparison requirements that are needed for consistency with the proposed changes to §114.315(c)(5) as described in the paragraph concerning changes to §114.315. Diesel engines emit very little VOCs and therefore, their contribution to total VOC emissions inventories is very small as well. In addition, since test data from alternative diesel fuel formulation approval testing has demonstrated that VOC emissions from the engines being tested on both the reference fuel and candidate fuels are significantly below the EPA's emission certification standards for these test engines, there is no additional benefit in comparing VOC emissions when determining whether an alternative formulation can achieve oxides of nitrogen (NO _x ) emission reductions that are comparable to those attributed to LED in the SIP.

The adopted changes to §114.313 amend references to other sections of Subchapter H, Division 2, as needed for accuracy and consistency. The commission also adopts amendments to §114.313(a)(1) and (2) to change the word "shall" to "must" or "may" to conform to the drafting rules in the Texas Legislative Council Drafting Manual , November 2004.

The adopted changes to §114.315(a) specify the correlation equation to be used with ASTM Test Method D5186 (Standard Test Method for Determination of Aromatic Content and Polynuclear Aromatic Content of Diesel Fuels and Aviation Turbine Fuels by Supercritical Fluid Chromatography) to convert the supercritical fluid chromatography (SFC) results in mass percent to volume percent. The adopted changes to §114.315(b) require the ED to consult with and obtain agreement of the EPA before approving an alternative to the test methods listed under §114.315(a) in response to EPA's comments relating to ED approval without EPA review.

The adopted changes to §114.315(c) amend the procedures and testing requirements for alternative diesel fuel formulations to clarify what information is required to be submitted as part of the test protocol; specify that the sulfur content of the candidate fuel must not exceed 15 parts per million (ppm); clarify how many hot start emission test cycles will be required for each hot start only alternative test sequence; and remove the Alternative 5 test sequence in response to EPA's comments relating to ED approval without EPA review. These adopted changes also require that the engine used for the testing have a minimum of 125 hours of use and exhibit stable operation before beginning the testing and be within 110% of the applicable exhaust emission standards when tested on the reference fuel. This change was needed to be consistent with the testing procedures and guidance approved for EPA's Environmental Technology Verification (ETV) Program. The adopted changes to §114.315(c)(5) require that the NO _x and particulate matter (PM) emissions of the reference and candidate fuels be compared when determining whether an alternative diesel fuel formulation is comparable or better than LED. This change was needed for consistency with the CARB regulations for approving alternative diesel fuel formulations since CARB-approved formulations are acceptable under §114.312(e). In addition, these changes also require that the average individual emissions of total hydrocarbons (THC) and non-methane hydrocarbons (NMHC), respectively, recorded during testing with the candidate fuel not exceed 110% of the test engine's applicable exhaust emission standards in order to prevent unacceptable increases in VOC emissions. The adopted changes to §114.315(c)(6) were needed for consistency with the approval notification provisions in §114.315(d). The adopted changes to §114.315(d) remove THC and NMHC from the comparison requirements for consistency with the adopted changes to §114.315(c)(5). The adopted new §114.315(d)(3) allows the approval of alternative diesel formulations that use the EPA's Unified Model to demonstrate that the applicable fuel properties of the formulation will achieve at least a 5.5% reduction in NO _x emissions from on-road diesel fuel for the year 2007, and at least a 6.2% reduction in NO _x emissions from non-road diesel. The adopted new §114.315(d)(4) allows the approval of alternative diesel formulations that receive a verification from EPA's ETV Program's Air Pollution Control Technologies Center and the EPA's Office of Transportation and Air Quality's Voluntary Diesel Retrofit Program demonstrating at least a 5.78% reduction in NO _x emissions when compared against a base diesel fuel with fuel properties within the ranges as described for nationwide average fuel in EPA's Verification Protocol for Determination of Emissions Reductions Obtained by Use of Alternative or Reformulated Liquid Fuels, Fuel Additives, Fuel Emulsions, and Lubricants for Highway and Nonroad Use Diesel Engines and Light Duty Gasoline Engines and Vehicles (Revision No. 03, September 2003). These additions were needed to specify criteria that may be used to demonstrate to the satisfaction of the ED and the EPA that the formulation will achieve reductions in emissions of NO _x and PM that are comparable to or better than LED.

The commission requested comments on whether additional "no-harm" testing should be required as part of the alternative diesel fuel formulation approval process to provide assurance that approved fuels and fuel additives are not harmful to the mechanical operation of diesel engines and what test protocols and/or test methods should be used if "no-harm" testing is required. The commission appreciates the response to the request for comment on this issue, however, as explained in the PUBLIC COMMENT section of this preamble, the commission does not agree that a no-harm testing requirement is a necessary prerequisite for LED compliance.

The adopted changes to §114.316(b) clarify that only those records relating to sampling require a statement declaring the appropriate aromatic hydrocarbon content standard of the fuel. The adopted changes to §114.316(e) correct the reference citation for the federal code for the new federal on-highway diesel fuel standards. The adopted changes to §114.316(k) require producers who have AERPs approved under §114.318 to include information in their quarterly report that is required to be collected in accordance with the sampling and testing requirements of this subsection and to also include a reconciliation of the quarter's transactions relative to the requirements of this section for the appropriate fuel components of the diesel fuel that the projected emission reductions demonstrated in the producer's AERP were based upon.

The adopted changes to §114.317 amend references to other sections of this division as needed for accuracy and consistency.

The adopted changes to §114.318 establish a protocol that producers must follow when developing AERPs to ensure that equivalent emission reductions are being achieved. These adopted changes allow producers to submit AERPs using the EPA's Unified Model to demonstrate that the average of all on-road diesel fuel produced in any given calendar year that is sold, offered for sale, supplied, or offered for supply by the producer in the counties affected by these rules achieves at least a 5.5% reduction in NO _x emissions for the year 2007, and at least a 6.2% reduction from the average of all non-road diesel produced by the producer for use in the affected counties, equating to an average reduction of approximately 5.78% for both on-road and non-road diesel combined. Currently, a producer may use the Unified Model under §114.315(d) to demonstrate compliance using a specific fuel formulation. This adopted option allows for the submission of an AERP using a methodology that allows the averaging of different diesel fuel formulations within the same geographic area.

In addition, the adopted changes to §114.318 include procedures to allow AERPs to include diesel credits from early gasoline sulfur reduction that can be used in the 90-county area listed in §114.319(b)(4). The adopted changes to §114.318(b)(2) are significantly different than the proposed amendment, specifically, the tables containing gasoline-to-diesel offset ratios based on four wide ranges of sulfur reduction percentages have been replaced with methodologies to calculate the amount of noncompliant diesel fuel that may be offset by using the actual percentage of sulfur reduction in the gasoline supplied by the producer to the affected counties to calculate the appropriate gasoline-to-diesel offset ratio. The commission made these changes in response to public comments requesting a higher level of accuracy in the offset calculations than provided in the proposed amendment.

The diesel credits from early gasoline sulfur reductions will be calculated from the actual barrels of lower sulfur gasoline that was produced and supplied to the affected counties by the producer using the level of gasoline sulfur reduction to calculate the appropriate gasoline-to-diesel offset. The adopted methodologies for determining the appropriate offset ratios were developed using the EPA MOBILE6 emissions model to calculate the percentage of emission reduction from varying the sulfur level of gasoline in calendar years 2003, 2004, and 2005, from the MOBILE6 default gasoline sulfur level assumptions for those years, then weighting the reduction percentages by vehicle type between the four classes of gasoline vehicles with catalysts. Since the NOx emission inventories change each year, the number of lower sulfur gasoline barrels needed to offset noncompliant diesel fuel is calculated by comparing the reduction percentages to the applicable emissions inventory of on- and off-road diesel fueled vehicles and equipment. However, the overall NO _x emissions inventory from on- and off-road diesel engines is always greater than just the on-road NOx emissions inventory from gasoline engines. Therefore, in working out the appropriate offset ratio, the reductions in NO _x emissions from lower sulfur gasoline is discounted as a reflection of its smaller overall contribution to the inventory. Because gasoline credits would start to be used in calendar year 2007, the 2007 diesel NO _x emissions inventory is used and remains a constant for these calculations. The weighted average NO _x emissions reduction achieved by using LED in the on-road and non-road fleets in 2007 is 5.78%.

For example, the gasoline NO _x emissions inventory in 2003 for the 90-county area was 229.51 tons per day. A 25% reduction in gasoline sulfur from 259 ppm to 194 ppm achieves a 2.75% reduction in gasoline NO _x emissions. The 2007 on- and off-road diesel NO _x emissions inventory for the same 90-county area is 450.56 tons. To calculate the appropriate 2003 gasoline-to-diesel offset ratio the following methodology is used: determine the 2003 MOBILE6 gasoline emission reduction associated with a 25% reduction in sulfur level using the following equation, i.e., ((0.0000007)(194 ² ) - (0.0007)(194) + (0.137)) = 0.0275, and then use these results to determine the appropriate gasoline-to-diesel offset ration using the 2007 diesel inventory multiplied by the weighted average LED reductions in 2007 divided by the 2003 gasoline inventory multiplied by the 2003 MOBILE6 gasoline emission reduction associated with a 25% reduction in sulfur level, i.e., ((450.56)x(0.0578)) / ((229.51)x(0.0275)), which calculates an offset ratio of 4.12. Using this example, a producer that supplied gasoline with a 25% reduction in sulfur to the 90-county area in 2003 would be allowed to offset one barrel of noncompliant diesel fuel being supplied to the 90-county area in the years 2006 - 2010 for each 4.12 barrels of lower sulfur gasoline produced in 2003.

Also, the adopted changes to §114.318 provide an option to calculate diesel credits from early gasoline sulfur reduction in certain counties when used in combination with a "cleaner" diesel fuel, calculated with the Unified Model from the average fuel properties of the diesel fuel supplied by the producer in the 90-county area as part of the equation. If a producer is supplying a cleaner diesel fuel to the 90-county area, although not as clean as LED, the adopted rule allows the producer to use the emission reduction calculated with the Unified Model to decrease the offset ratio of gasoline. For example, if a producer elects to produce a diesel fuel that achieves a 2.0% NOx emissions reduction in 2007 according to the Unified Model, the producer would calculate an offset ratio as follows: ((450.56)x(0.0578 - 0.02)) / ((229.51)x(0.0275)), for an offset ratio of 2.69. In this case, only 2.69 barrels of lower sulfur gasoline would be needed to offset each barrel of "cleaner" noncompliant diesel fuel. Under this option, credits from early gasoline sulfur reduction can only be generated from the gasoline supplied by the producer in calendar years 2003, 2004, and 2005, to the counties listed under §114.319(b)(4) and these credits can only be used to demonstrate compliance through December 31, 2010.

The commission requested comments on the feasibility of accepting residual NO _x emission benefits from the supply of early lower sulfur gasoline as a creditable fuel strategy for producers to submit as part of an AERP and how best to calculate the residual NO _x emission benefit using currently available EPA-approvable calculation methodologies. Based on comments received regarding this issue, the commission adopted a new §114.318(b)(4) specifying a methodology to determine the amount of noncompliant diesel that may be offset in the Dallas-Fort Worth (DFW) and Houston-Galveston-Brazoria (HGB) nonattainment area counties with credits from the residual effects of early gasoline sulfur reduction on the NO _x emission reduction efficiencies of catalytic converters installed in gasoline-powered motor vehicles. These credits may only be generated from the volumes of reformulated gasoline (RFG) supplied to the DFW and HGB nonattainment area counties in 2004 and 2005 that had an average sulfur level that was below the sulfur level of 92 ppm in 2004 and 77 ppm in 2005, identified by EPA as being the base average sulfur levels for RFG during those years in both areas. These credits can only be used in the DFW and HGB nonattainment area counties for compliance through December 31, 2008. The credits generated in either one of these nonattainment areas may not be used for compliance in the other.

In addition, the adopted changes to §114.318(c) specify that all AERPs approved by the ED prior to December 16, 2005, will expire on December 31, 2006, with the exception that the ED may allow a producer operating under a previously approved AERP to continue to operate under that plan for a limited time beyond December 31, 2006, if the following conditions are met: the producer's previously approved AERP relied on the use of an alternative diesel formulation that has not been approved by the ED under §114.315(c); the producer has submitted an application to the EPA's ETV Program to pursue verification of this specific alternative diesel fuel formulation to demonstrate that it will achieve at least a 5.78% reduction in NO _x emissions; the producer has a contract with the EPA's testing center to perform the verification testing that is signed by both parties and paid in full by September 1, 2006; and the emissions testing as specified under a test plan approved by both the testing center and EPA is completed before December 1, 2006.

The adopted new §114.318(e) requires the ED to approve or disapprove newly submitted AERPs within 45 days of submittal.

The adopted new §114.318(f) specifies that AERPs submitted to the ED must contain sufficient documentation to validate the average diesel fuel properties used to calculate the emission reductions claimed when using EPA's Unified Model and, as appropriate, the sulfur properties and volumes of the gasoline that is being used to generate the diesel credit from early gasoline sulfur reductions. This documentation is necessary for the ED to determine in a timely manner if the submitted AERP is approvable.

The commission also requested comments on whether to allow credits from early gasoline sulfur reduction to be used until December 31, 2010, in the Beaumont-Port Arthur (BPA) ozone nonattainment area containing Hardin, Jefferson, and Orange Counties. Based on comments received from the EPA, the commission will not allow credit from early gasoline sulfur reductions to be used in the BPA nonattainment area counties.

FINAL REGULATORY IMPACT ANALYSIS DETERMINATION

The commission reviewed the adopted rulemaking considering the regulatory analysis requirements of Texas Government Code, §2001.0225, and determined that the rulemaking does not meet the definition of a "major environmental rule." A major environmental rule means a rule, the specific intent of which is to protect the environment or reduce risks to human health from environmental exposure, and that may adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state. The adopted amendments to §§114.6, 114.312, 114.313, and 114.315 - 114.318 provide for EPA consultation and agreement prior to commission approval of alternative test methods; establish a protocol by which AERPs, or revisions to those plans, could be approved by the EPA without the need for individual SIP revisions for each plan; make alternative formulation testing requirements consistent with EPA guidance and CARB regulations; and make corrections to citations for accuracy and consistency. In addition, the adopted amendments are intended to provide additional clarification and flexibility in the LED air pollution control program as part of the strategy to reduce emissions of NO _x necessary for the counties in the HGB, BPA, and DFW nonattainment areas to be able to demonstrate attainment with the ozone national ambient air quality standard (NAAQS). While this strategy is intended to protect the environment by reducing NO _x emissions that help form ozone, the commission does not find that the diesel fuel producers and importers covered by this rulemaking comprise a sector of the economy, or that the revisions adopted in this rulemaking will adversely affect in a material way the economy, productivity, competition, jobs, the environment, or the public health and safety in the HGB, BPA, and DFW nonattainment areas. This rulemaking will address EPA concerns regarding its input on test methods and review of alternative formulations; create consistency with EPA and CARB guidance and regulations of which the refining industry is familiar; and create a protocol for AERPs that will simplify EPA approval of all AERPs and protect producers' potentially confidential information.

The adopted amendments to Chapter 114 are not subject to the regulatory analysis provisions of Texas Government Code, §2001.0225(b), because the adopted rules do not meet any of the four applicability requirements. Texas Government Code, §2001.0225 only applies to a major environmental rule, the result of which is to: 1) exceed a standard set by federal law; 2) exceed an express requirement of state law, unless the rule is specifically required by federal law; 3) exceed a requirement of a delegation agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program; or 4) adopt a rule solely under the general powers of the agency instead of under a specific state law.

Specifically, the LED requirements in Chapter 114 were developed as part of the control strategy to meet the ozone NAAQS set by the EPA under Federal Clean Air Act (FCAA), 42 United States Code (USC), §7409, and therefore meet a federal requirement. The amendments to this chapter were developed in order to provide more clarity and consistency to the LED requirements, provide a smoother process for EPA approval of AERPs and revisions to those plans, and address concerns from the EPA. FCAA, 42 USC, §7410, requires states to adopt and submit a SIP that provides for "implementation, maintenance, and enforcement" of the primary NAAQS in each air quality control region of the state. While 42 USC, §7410 does not require specific programs, methods, or reductions in order to meet the standard, SIPs must include "enforceable emission limitations and other control measures, means or techniques (including economic incentives such as fees, marketable permits, and auctions of emissions rights), as well as schedules and timetables for compliance as may be necessary or appropriate to meet the applicable requirements of this chapter," (meaning 42 USC, Chapter 85, Air Pollution Prevention and Control). While 42 USC, §§7401 et seq . does require some specific measures for SIP purposes, like the inspection and maintenance program, the statute also provides flexibility for states to select other necessary or appropriate measures. The federal government, in implementing 42 USC, §§7401 et seq ., recognized that the states are in the best position to determine what programs and controls are necessary or appropriate to meet the NAAQS, and provided for the ability of states and the public to collaborate on the best methods for attaining the NAAQS within a particular state. However, this flexibility does not relieve a state from developing and submitting a SIP that meets the requirements of 42 USC, §7410. Thus, while specific measures are not generally required, the emission reductions are required. States are not free to ignore the requirements of 42 USC, §7410, and must develop programs to assure that the nonattainment areas of the state will be brought into attainment on schedule.

As discussed earlier in this preamble, this rulemaking action implements requirements of 42 USC, §§7401 et seq . There is no contract or delegation agreement that covers the topic that is the subject of this action. Therefore, the adopted rulemaking does not exceed a standard set by federal law, exceed an express requirement of state law, or exceed a requirement of a delegation agreement. Finally, this rulemaking action was not developed solely under the general powers of the agency, but is authorized by specific sections of Texas Health and Safety Code, Chapter 382 (also known as the Texas Clean Air Act), and the Texas Water Code, which are cited in the STATUTORY AUTHORITY section of this preamble, including Texas Health and Safety Code, §§382.012, 382.019, 382.202, and 382.208. Therefore, this rulemaking action is not subject to the regulatory analysis provisions of Texas Government Code, §2001.0225(b), because the adopted rulemaking does not meet any of the four applicability requirements.

TAKINGS IMPACT ASSESSMENT

The commission completed a takings impact analysis for the adopted rulemaking action under Texas Government Code, §2007.043. The specific purpose of this strategy is to achieve reductions of NO _x emissions to reduce ozone formation in the HGB, BPA, and DFW nonattainment areas and thus help bring these areas into compliance with the air quality standards established under federal law as NAAQS for ozone. As adopted, the amendments to §§114.6, 114.312, 114.313, and 114.315 - 114.318 provide for EPA consultation and agreement prior to commission approval of alternative test methods; establish a protocol by which AERPs, or revisions to those plans, could be approved by the EPA without the need for individual SIP revisions for each plan; make alternative formulation testing requirements consistent with EPA guidance and CARB regulations; and make corrections to citations for accuracy and consistency. These amendments will not place a burden on private, real property because this action does not require an investment in the permanent installation of new refinery processing equipment.

Texas Government Code, §2007.003(b)(4), provides that Chapter 2007 does not apply to this rulemaking action, because it is reasonably taken to fulfill an obligation mandated by federal law. Specifically, the emission limitations and control requirements of the LED air pollution control program 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 NAAQS once the EPA has established them. Under 42 USC, §7410, and related provisions, states must submit, for approval by the EPA, SIPs that provide for the attainment and maintenance of NAAQS through control programs directed to sources of the pollutants involved. Therefore, one purpose of this rulemaking action is to provide additional clarification and flexibility in implementing the LED program necessary for the state's nonattainment areas to meet the air quality standards established under federal law as NAAQS. Attainment of the ozone standard will eventually require substantial reductions in NOx emissions as well as VOC emissions. This rulemaking is only one step among many necessary for attaining the ozone standard.

In addition, Texas Government Code, §2007.003(b)(13), states that Texas Government Code, Chapter 2007 does not apply to an action that: 1) is taken in response to a real and substantial threat to public health and safety; 2) is designed to significantly advance the health and safety purpose; and 3) does not impose a greater burden than is necessary to achieve the health and safety purpose. Although the rules do not directly prevent a nuisance or prevent an immediate threat to life or property, they do prevent a real and substantial threat to public health and safety and significantly advance the health and safety purpose. This action is taken in response to the HGB, BPA, and DFW areas exceeding the federal ozone NAAQS, that adversely affects public health, primarily through irritation of the lungs. The action significantly advances the health and safety purpose by improving the LED program that reduces ozone levels in these nonattainment areas and 90 central and eastern Texas counties. Consequently, these adopted rules meet the exemption in Texas Government Code, §2007.003(b)(13). This rulemaking action therefore meets the requirements of Texas Government Code, §2007.003(b)(4) and (13). For these reasons, the adopted rules do not constitute a takings under Texas Government Code, Chapter 2007.

CONSISTENCY WITH THE COASTAL MANAGEMENT PROGRAM

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

The commission solicited comments on the consistency of the amendments with the CMP during the public comment period, but did not receive any comments during the public comment period.

PUBLIC COMMENT

The public hearing for this rulemaking was held on January 10, 2006, in Austin. The following persons submitted written or oral comment: Alamo Area Council of Governments (AACOG); Biofriendly Corporation (Biofriendly); Capital Area Council of Governments (CAPCOG); City of Houston (Houston); Dallas Area Rapid Transit (DART); Delek Refining, Ltd. (Delek); Flint Hills Resources, LP (FHR); Sierra Club, Houston Regional Group (Sierra-Houston); Lloyd Gosselink on behalf of the Texas Low Emission Diesel Coalition (Coalition); Texas Low Emission Diesel Coalition (Coalition) (forms turned in at hearing); EPA; and Valero Energy Corporation (Valero).

RESPONSE TO COMMENTS

Biofriendly, DART, and EPA generally supported the direction of the proposal. AACOG, Houston, and Sierra-Houston generally opposed the proposal. AACOG, Biofriendly, CAPCOG, Coalition, DART, Delek, EPA, FHR, Sierra-Houston, and Valero expressed concerns and/or suggested changes to the proposal.

Gasoline Credits

AACOG commented that it is opposed to the proposed changes to the AERP provisions in §114.318 because the use of credits from early introduction of lower sulfur gasoline will be allowed through 2010. AACOG also commented that the commission has not quantified possible loss of emission reduction credit in 2007 due to this rule proposal nor has the commission evaluated the impact on ozone attainment demonstrations. AACOG further commented that the quantity of gasoline credits available from petroleum producers has not been published nor is the distribution of such credits certain as necessary to assist AACOG's or the state's air quality planners in determining the extent of impact on AACOG's region from the proposed rule. CAPCOG expressed opposition to the use of credits from early gasoline sulfur reduction to offset LED compliance requirements through 2010 in the Austin Early Action Compact (EAC) counties as allowed under the proposed changes to §114.318 and recommended that the proposed LED rule revision be modified to offer the same protections on AERP approvals for the Austin EAC area as it does for nonattainment areas.

The commission believes that both the greater San Antonio and Austin areas received significant early reductions in NO _x emissions due to the efforts of fuel suppliers to these areas in the years 2003, 2004, and 2005. These early reductions were due to a voluntary lowering of the gasoline sulfur levels in these years. The commission believes these reductions played a part in the Austin area avoiding nonattainment of the eight-hour NAAQS for ozone and lowering the eight-hour ozone levels in San Antonio.

The LED rules were originally adopted in the 110 East Texas County area to assist DFW and HGB in reaching attainment with the one-hour NAAQS for ozone. Emission reductions for the EAC areas and other counties were a side benefit of the program. Having the LED rules applying to all 110 counties is still very beneficial and necessary for the ultimate achievement of attainment for both DFW and HGB. The commission has made no change in response to this comment.

EPA commented that the early reduction credits and averaging, banking, and trading (ABT) provisions of the federal Tier 2 Motor Vehicle Emissions Standards and Gasoline Sulfur Control Rule (40 CFR §§80.275, 80.285, and 80.305 - 80.315) allow most refineries to generate either sulfur allotments or early sulfur credits from early compliance with the Tier 2 sulfur requirements that began in 2000 and such emissions reductions can only be claimed once. EPA also commented that while it is possible for the MOBILE model to calculate a benefit to pre-Tier 2 vehicles, EPA does not believe the model can reflect real-world benefits because of the uncertainty of fueling habits of the general public. EPA further commented that it does not support allowing credits for early implementation of low sulfur gasoline for use in BPA nonattainment area and the EAC areas past December 31, 2006. Valero stated there will be a reduction in NO _x levels in 2006, 2007, and 2008, due to a residual NO _x effect because the catalytic converters in gasoline-powered motor vehicles in DFW and HGB were exposed to less sulfur and will perform more efficiently. Valero expressed concern that the commission's proposal to eliminate the credit for residual NO _x effects after December 2006, is based on the commission's belief that these credits are to difficult to calculate. Valero also commented that its AERP using residual credits was approved by the commission in August of 2005.

The commission agrees with Valero's comments and has made changes to the rule to include a methodology for determining credits from the residual effects of early gasoline sulfur reduction on the NO _x emission reduction efficiencies of catalytic converters installed in gasoline-powered motor vehicles in the DFW and HGB counties.

FHR recommended that the commission calculate the credits from early gasoline sulfur reduction based on the percent reduction on the refiner's actual annual gasoline reduction sulfur concentration instead of being placed into one of the three current categories. FHR requested that an equation that interpolates between the MOBILE 6.2 derived reductions of 25%, 50%, and 75%, which uses the refiner's actual average production sulfur level be used instead of the percent reduction corresponding to the highest sulfur level in the defined ranges.

The commission agrees with both comments and made changes to the rule to use the percent reduction from a refiner's actual annual gasoline sulfur reduction to calculate credits. In addition, the commission has revised the rules to include equations to calculate the percent reduction in NO _x for any average gasoline sulfur level between an upper and lower valid range.

Valero provided suggested regulatory language and a calculation protocol for determining credits from the residual NO _x effects of early gasoline sulfur reductions. Valero requested that the rule allow residual credits in 2006, 2007, and 2008, based on a calculation using actual barrels of lower sulfur gasoline produced and supplied to the DFW and HGB areas in 2005, and using offset ratios to determine diesel credits that were developed using EPA's MOBILE6 and RFG survey data. Valero noted an RFG survey that indicates sulfur levels different than that used in the SIP for years 2003, 2004, and 2005. Specifically, Valero stated the actual average sulfur in the HGB and DFW areas for these years was below the values projected by the SIP. Valero stated the average RFG sulfur value in the United States in 2004 was 92 ppm and the standard deviation was 63 ppm; and the average RFG sulfur for the first three quarters of 2005 was 77 ppm and the standard deviation was 56 ppm. Valero recommended setting the maximum sulfur for the base case at 189. Valero recommended using actual sulfur levels to counteract the issue that a given vehicle does not receive gasoline produced by just one refiner. Valero recommended using the same maximum sulfur or cap in the base case run and the early low sulfur gasoline case run in 2003 to counteract the effect of vehicles refueling with higher sulfur outside the DFW and HGB areas. Valero noted for the SIP, the RFG pool was not modeled separately from the conventional pool for sulfur, overstating NO _x emissions and taking a conservative approach. Valero stated that it has not seen sulfur credits used to raise the sulfur in the RFG pool that supplies DFW and HGB. Valero recommended use of the actual average sulfur value when available. Valero stated a producer that supplied early low sulfur gasoline as part of an AERP to DFW or HGB would divide the volume of gasoline supplied in 2005 by the offset ratios for 2006, 2007, and 2008, to determine the volume of noncompliant diesel for supply to the areas. FHR encouraged the commission to adopt Valero's proposal for the calculation of the residual NO _x effects from early gasoline sulfur reduction that could be used in the DFW and HGB areas. FHR also suggested that the same approach for capturing the benefits of the residual NO _x effects be applicable to the counties in §114.319(b)(4).

The commission considered Valero's comments and made changes to the rule to include a methodology for determining diesel credits for residual benefits in DFW and HGB from the early gasoline sulfur reductions. The commission coordinated with EPA in the development of the base case sulfur values for RFG in 2004 and 2005, and the gasoline-to-diesel offset ratios used for determining the amount of diesel credit from residual benefits that is used in the methodology adopted for use in the DFW and HGB nonattainment area counties. The EPA determined that there was no difference between the EPA-defined default values of gasoline sulfur in 2003, and what actually occurred in the HGB and DFW areas, but EPA did find a difference in the years 2004 and 2005 (based on RFG survey data for the two areas) and these values were used to calculate gasoline-to-diesel offset ratios for residual benefit adopted in this rulemaking. These gasoline-to-diesel offset ratios are valid for use starting in 2006 and expiring at the end of 2008. The commission appreciates the suggested rule language provided by Valero but adopted its own language to better fit the existing rule structure and to conform to the Texas Register style requirements.

Valero provided comments on a TCEQ white paper. Valero disagreed with the paper by stating it is appropriate to use the MOBILE6 model. Valero also raised the issue of sulfur irreversibility. Valero expressed the belief that there is no technical issue in using the MOBILE6 model to calculate benefits of early low sulfur gasoline.

The commission agrees that using the EPA's MOBILE6 emissions model is an appropriate method for calculating the benefits of early gasoline sulfur reductions. The methodologies for determining diesel credits from early gasoline sulfur reductions adopted in this rulemaking are based on modeling from the MOBILE6 model.

General Comments

EPA asked the commission to explain how the TxLED program will achieve the desired emission reductions if cumulative effect additives are approved for use, but are not consistently used in vehicles. EPA also asked how will trucks achieve the claimed reductions if they use different fuels approved under the TxLED program but not the same additive regularly. EPA expressed that the claimed emission reductions from cumulative effect additives should only be considered when the additive is used consistently such as in centrally fueled fleets where vehicles only use fuel with the additive.

The provisions for alternative formulations have been in the rule since 1999 and have been approved by EPA during all of the previous rulemakings. The provision for the Alternative 4 test sequence (allowing the testing of formulations with cumulative effects) was adopted by the commission in March of 2005, with no specific comments from EPA relating to this provision, and was ultimately approved by EPA in a final rule published on October 6, 2005, in the Federal Register (70 FR 58325). The commission has made no changes as a result of this comment.

Valero expressed support for the TxLED program, for the commission's efforts to meet clean air standards, and noted its capital expenditures to produce compliant diesel.

The commission appreciates Valero's long support of this diesel fuel emissions reduction strategy and implementation program.

Sierra-Houston commented that it is opposed to any proposal that allows AERPs to be labeled as "confidential business information" and kept from the public. Biofriendly commented that §114.315(c)(2)(B) should be amended to indicate specifically that all information gathered by the commission regarding the composition of an additive and/or the test (detection) method for that additive be confidential and may not be released by the commission to any third party without approval of the owner/provider of the confidential information.

The commission maintains that companies that submit AERPs have the right to claim that the information contained within these plans is confidential business information. In addition, as stated in the previous rulemaking on LED (30 TexReg 1782), the commission does not believe it is necessary or appropriate to include language suggested by Biofriendly. The commission is prohibited by Texas Health and Safety Code, §382.041 from releasing information to the public related to secret processes or methods of manufacture or production that has been marked confidential when submitted. The Texas Public Information Act (PIA) provides exceptions from public disclosure by any state agency for trade secret and business confidential information. Any confidential or trade secret information submitted to TCEQ should be clearly marked as such at the time submitted. Any requests for information so marked will be forwarded to the Office of the Attorney General as appropriate for a determination of the applicability of the PIA exceptions. The commission has made no changes to the rule based on these comments.

Sierra-Houston commented that the commission should clearly explain the importance of VOC in the control of air pollution from the evaporation and combustion of diesel fuels.

The contribution from diesel engines to the total VOC emissions inventories is very small because diesel engines inherently emit very little exhaust VOC emissions and diesel fuel emits virtually no evaporative VOC emissions in normal refueling operations. However, since VOC emissions can help contribute to the formation of ozone, the adopted rules will ensure that in order to be approved by the commission, alternative diesel formulations must demonstrate that no significant increase in VOC emissions occurs when the fuel is used in a diesel engine. The commission made no changes to the rules in response to these comments.

Sierra-Houston commented that the proposal was confusing because of the multiple average percentage requirements listed in the rule proposal (i.e., 5.5%, 5.7%, 5.78%, and 6.2%) and requested that the commission simplify the rule.

The emission reductions from the LED rules are not inconsistent. Emission reductions are different for on-road (5.5% reduction) and non-road (6.2% reduction). The weighted average based on the percentage of NO _x from the on-road and non-road inventories is 5.78%. The commission made no changes to the rules in response to this comment but did make a change in the SECTION BY SECTION DISCUSSION of this preamble to correctly reference the weighted average of 5.78%.

Biofriendly commented that the commission should accept biodiesel that meets the ASTM D6751 standards when approving an acceptable biodiesel blended LED.

The commission has provided biodiesel producers the opportunity to comply with the LED requirements under an AERP that will allow the blending of B100 biodiesel with LED-compliant diesel fuel for use in the 110 counties affected by the LED requirements. The B100 biodiesel must meet ASTM D6751 standards for B100 biodiesel and must be mixed with LED-compliant diesel fuel. This AERP will expire on December 31, 2006. After December 31, 2006, all biodiesel blends produced for use in the affected 110-county region must be produced in compliance with an alternative diesel formulation that is approved by the commission.

Delek recommended that the commission issue a grandfather waiver, until at least 2010, for small refiners that complied with original AERP rules and were granted an AERP. Delek noted that grandfathered AERP fuel subject to a waiver could be limited to fuel transported directly from the refiner to a retail outlet or fleet user and not commingled with other fuel in a pipeline or terminal tanks.

The commission cannot create a grandfather provision for any diesel supplier without losing a potentially significant amount of NO _x reduction. There are several ways to comply with the LED rules, including the purchase of approved additives. With the multitude of compliance options, the commission does not believe a grandfathering provision is warranted.

Delek stated that it does not have the financial resources of the large refining companies and the proposed change in the AERP rules for TxLED will pose an unacceptably high financial burden, which cannot be recovered through competitive market pricing.

The LED rules provide multiple options for compliance and the commission would be glad to assist Delek in determining which option would best accommodate Delek's needs.

Delek commented that the proposal provides only two months after final rule adoption for existing approved plans to remain in effect and before new/revised plans would have to be approved and implemented. Delek stated that additional time is required for compliance with the proposed rule change. Delek noted that because the commission approved the facility's AERP, Delek committed to the EPA to make all ultra-low sulfur diesel (ULSD) as a condition of a small refinery hardship waiver, extending compliance with Tier II gasoline sulfur standards to 2008.

An agreement with the EPA for a federal gasoline program does not relieve Delek of its responsibilities to comply with the commission's state diesel fuel regulation.

FHR supported the commission's proposal to extend the expiration date on the use of early gasoline credits from 2007 until 2010. FHR also requested that the commission consider not having an expiration date and allowing refiners to utilize all of the gasoline credits that they have generated.

The commission disagrees. Credits should be expended by 2010. This time period should be adequate for a refiner to implement changes to comply with LED requirements without the use of gasoline credits.

Delek recommended that the commission should determine if the extensive use of additives and probable elimination of existing approved AERPs will have a market price impact beyond the previous estimated range.

The commission believes that the market will determine the most economical way of complying with the LED requirements. If an additive's cost or supply is at issue, a refiner has other compliance options.

Delek stated that the commission should provide an added incentive to move to low- NO _x engines by allowing the use of conventional (non-TxLED) ULSD. Additionally, ULSD sold for use in a low-NO _x engine should not only qualify for an AERP, but should generate a credit to be used for fuel that does not meet TxLED standards, if those engines have not been converted or purchased using Texas Emission Reduction Plan (TERP) funding.

The commission believes there is some level of additional reduction from the use of LED even in advanced technology low NO _x engines. The commission has made no change in response to this comment.

FHR suggested that the commission avoid the possibility of approving additives that are not acceptable to diesel engine and diesel exhaust after treatment system suppliers by requesting that additives be ashless.

Some additives contain fuel-borne catalysts that are usually metals, these are commonly defined as ash. These catalysts can help reduce diesel PM but also can contribute to plugging of diesel particulate filters. Metals are also commonly found in the lube oil. Lube oil being burned and passed through the combustion chamber also contributes to ash in the exhaust. It is not expected that diesel particulate filters will be in widespread use in the United States for the foreseeable future. Therefore, the commission is not including an ashless requirement for diesel fuel additives used for compliance with the LED rules. The commission reserves the right to require ashless additives in the future if warranted.

No-Harm Testing

EPA commented that a supplier should be in a position to guaranty that the approved fuels or fuel additives are not harmful to the mechanical operation of diesel engines. EPA also stated that the key factor for determining "no harm" is the effect of the fuel or additives on the elastomers used in diesel engines and that there are several ASTM standards available upon which a test system should be formulated to test the properties of the elastomers under different conditions. EPA further commented that requiring the supplier of an approved alternative diesel formulation to provide a warranty or the results of such tests prior to the approval of an alternative formulation would be appropriate. Both EPA and the Coalition supported the inclusion of some type of "no-harm" test requirement in the rule. EPA recommended that the rules should be amended to include a supplier or producer guarantee that the "approved fuels and fuel additives are not harmful to the mechanical operation of diesel engines." The Coalition commented that the current rule only requires emission and performance testing methods for additives and alternative formulations. The Coalition suggested that the commission's current position on not providing for no-harm testing violates its statutory mandate to implement cost-effective environmental regulations. The Coalition expressed the belief that extreme market conditions of the LED fuel market may result in unreliable products being forced onto the market as producers take extreme measures to avoid fuel shortages. The Coalition expressed concern that the current rule language does not provide for "no-harm" testing of additives that would demonstrate the long-term compatibility of fuels and additives with diesel engine components and dynamometer tests that demonstrate the impact of fuels and additives on engine horsepower. Additionally, the Coalition suggested that the commission require filter media compatibility testing and elastometer testing. EPA also suggested that a key component of no-harm testing should be elastometer testing. EPA commented that such tests could be similar to current tests conducted by lubricant manufacturers on wear and tear on piston rings, cylinders, and crankshaft bearings. EPA also suggested that a supplier's warranty of no-harm testing prior to approval of a formulation would be appropriate.

The commission appreciates the response to our request for comment on this issue, however, does not agree that a no-harm testing requirement is a necessary prerequisite for LED compliance. All of the approved additives, up to this point, have voluntarily done no-harm testing without being required by our agency. The commission is confident that in order to be competitive an additive would not only have to compete on price but also on the assurance that the product would not damage engines by showing that no-harm testing has been done. The commission does not believe that there are "extreme market conditions" in the LED market because of the numerous strategies available for compliance with LED requirements. Therefore, the commission does not anticipate producers taking "extreme measures" such as using unreliable products in order to come into compliance with LED regulations. Additionally, this type of information should be available through EPA. All fuels and fuel additives that are intended for use in on-road motor vehicles are required by federal regulation to be registered with EPA prior to introduction into commerce. Registration involves providing a chemical description of the product and certain technical, marketing, and health-effects information. This allows EPA to identify the likely combustion and evaporative emissions. The commission also recognizes that its authority to regulate diesel fuels is predicated on the need to reduce air emissions and protect public health and the environment. The commission does not have the authority to restrict the production, sale, or importation of fuels or additives based upon engine quality and performance impacts of those products. However, the commission does expect that fuel and additive producers will have conducted these no-harm tests in order to meet customer expectations and market their product. The commission encourages fuel and additive producers to make these no-harm tests publicly available. The commission made no changes to the rules in response to these comments.

Section-Specific Comments

EPA commented that the phrase "required to be" in the definition of additive in §114.6 may be misinterpreted to mean that additives may be used in Texas before being approved and registered by EPA and therefore, EPA does not recommend the adoption of this change.

The commission made changes to the rule in response to this comment and revised the definition of additive to clarify that substances added to gasoline or diesel fuel, which are registered with the EPA in accordance with 40 CFR Part 79 and those that are added for the purpose of reducing exhaust emissions from vehicles and equipment but are exempted from EPA registration requirements under 40 CFR Part 79, are considered to be additives under these rules.

EPA commented that the changes to §114.315(b) do not resolve its concerns regarding ED discretion and stated that "consultation" is not adequate in the case of disagreements. EPA suggested that this subsection be changed to read "with the consent of EPA," or "consultation and agreement by EPA," or changed to resemble §114.315(d) in which it would be demonstrated to the satisfaction of the ED and the EPA.

The commission agrees with the comment and has made the changes to §114.315(b) as noted.

EPA commented that §114.315(c)(4) should be amended to add the phrase, "and in the Environmental Technology Verification Protocol of the EPA, where applicable" at the end of the reference to 40 CFR Part 86, Subpart N.

The commission declines to make this change. The emission testing procedures specified under §114.315(c) are designed to certify that the emissions generated when using an alternative diesel formulation are comparable to the emissions generated when using the LED reference fuel in the same test engine. The test procedures under this rule are not designed to verify a specific percentage of emission reductions as the EPA's Verification Protocol for Determination of Emissions Reductions Obtained by Use of Alternative or Reformulated Liquid Fuels, Fuel Additives, Fuel Emulsions, and Lubricants for Highway and Nonroad Use Diesel Engines and Light Duty Gasoline Engines and Vehicles (Revision No. 03, September 2003) was designed to achieve. The commission made no changes to the rules in response to these comments.

FHR commented that the language in the proposed §114.315(c)(6)(A)(i) is less clear than current language and could be interpreted to be requiring a specific aromatics concentration, rather than a maximum. FHR also stated that §114.315(c)(6)(A)(ii) does not clearly define the requirements for this "minimum specifications of the base diesel fuel" and that it would be clearer to use language similar to the present regulations and say that the base fuel properties for total aromatics should not exceed those of the base fuel used in the additive verification.

The commission disagrees. The commission believes that the approval notification for alternative diesel formulations should only contain information regarding the characteristics of the formulation that are relevant for compliance and enforcement purposes. The commission made no changes to the rules in response to this comment.

Biofriendly commented that §114.315(d) should be revised to add the phrase, "EPA's Environmental Technology Verification program," in the sentence just after ". . . to the satisfaction of the executive director" to allow fuels and fuel additives that have been tested under this EPA program to be considered for approval as an alternative diesel formulation.

The commission declines to make the suggested changes. The need for EPA's approval is already explicit under the existing rule text in this section, therefore, there is no need to include a specific EPA program.

EPA commented that §114.315(d)(2) should be amended to add the phrase, "and the EPA," in the sentence just after "executive director" to be consistent with subsection (d).

The commission agrees with the EPA comment and made changes to the rule accordingly.

EPA commented that it does not oppose the removal of EPA approval from §114.318(a) because a replicable procedure for the state to approve the AERPs is being proposed. EPA commented that the critical part of a replicable procedure is public participation in the process at the state level and that public participation is being carried out through the proposal notice and comment period in which the state is enacting the revised §114.318.

The commission appreciates the support for this method.

FHR commented that there are two distinct problems with the December 31, 2006, expiration date for currently approved AERPs as proposed in §114.318(c). First, it does not appear that the commission has provided itself with the discretion to extend the year-end expiration date when circumstances warrant. Second, the proposed transition process from existing plans to revised plans creates unnecessary confusion and is inconsistent with how the commission handles such transitions in analogous situations under other environmental rules.

The commission considered FHR's comment and made changes in §114.318(c) of the adopted rule to provide the ED flexibility to allow a producer to continue using a currently approved AERP for a limited time beyond the December 31, 2006, expiration date if certain specific conditions are met.

CAPCOG recommended that §114.319(b) be revised to move the Austin EAC counties (Travis, Williamson, Hays, Bastrop, and Caldwell) to a separate grouping under a new paragraph (5) or specify that credits from early gasoline sulfur reduction as provided under §114.318 may not be used in the Austin EAC counties. DART recommended revisions to §114.319 to mitigate the cost impact of future potential changes to the TxLED regulations by adding a new subsection (d) to read "Any rule changes affecting the cost or availability of fuel shall allow sufficient time for replacement of long term contracts for supply of fuel under this rule."

The commenters are requesting an action that is beyond the scope of this rulemaking, as §114.319 (Affected Counties and Compliance Dates) was not amended in the proposed rules that were published in the December 16, 2005, issue of the Texas Register (30 TexReg 8407). The commission has no authority to specify the length of private long-term fuel contracts. Contractual provisions should be made to long-term contracts to accommodate potential rule changes which may affect prices. The commission made no changes to the rules in response to these comments.

Supply and Distribution Data from Producers and Importers

The Coalition commented that end users of diesel fuel cannot determine the market availability of fuel types in their specific areas. The commission registration forms do not provide adequate information and many are submitted by producers and importers under claims of confidentiality. The only information provided by the commission publicly is a one-page summary containing a list of producers and importers, total volumes, and projected volumes of LED-compliant fuel. This information does not adequately provide information on whether the fuel is provided under an AERP, alternative formulation, or other LED-compliant fuel. The Coalition suggested that the commission could "re-aggregate" the data collected from registration forms into a more useful format that explains how much fuel will be produced using additives, under AERPs, or some other LED compliance strategy in each of the 110 counties. The Coalition commented that this information could be made available publicly without compromising the confidentiality of market information submitted by producers and importers.

The commenters are requesting a change to §114.314, Registration of Diesel Producers and Importers. This section is not open for amendment in this rulemaking. The Coalition also suggests data collection changes that are not required by rule and were developed as part of the TCEQ registration form. The commission will continue to work with producers and importers of LED-compliant fuel as well as end users to develop useful information about market supply without compromising the confidentiality of individual producers' data.

The Coalition expressed the belief that the commission could greatly enhance its ability to predict impacts within regions of the 110-county area if it were to utilize data directly derived from demand projections based on actual diesel fuel usage in the affected counties. The commission used data that appears to be extrapolated from gasoline usage and population distribution. The Coalition expressed the belief that the TCEQ has severely underestimated diesel fuel demand for the 110-county affected area. An approach that uses real diesel fuel sales data to assess fuel demand is suggested, using data collected from the Texas Comptroller's Office representative of fuel consumption in the 110-county area. Alternatively, the commission should require fuel producers and importers to submit such data or its equivalent. Delek raised concern of potential supply issues and increased prices. Delek recommended that the commission should re-survey suppliers before setting a compliance date for the revised rule to determine if volumes previously committed will still be available.

As stated previously, market data aggregation through producer registration forms is not open for amendment at this time. The commission remains confident that supply of -compliant fuel in the 110-county area of Texas will be sufficient due to the variety of choices (i.e., LED fuel, alternative formulations, CARB diesel, and AERPs) available to producers and importers to comply with the rule. The amendments adopted in this rulemaking will not alter this assessment of supply. In fact, these changes in the LED rules should provide greater flexibility and assurances that adequate supply of LED-compliant fuel will be available in the affected counties. For instance, the AERP protocol in §114.318 will create a more consistent approach to developing these plans and streamline the TCEQ and EPA approval process, thereby giving producers through end users more confidence that LED supply will not be disrupted due to any compliance uncertainties.

Price Concerns and Fiscal Note Analysis

The Coalition expressed concern about the potentially inflated fuel prices that are likely to result from the boutique and additized LED fuel market. The LED program and its purposes have evolved over many years and the changes made have been substantive, yet there has never been a meaningful fiscal analysis of the rule. There seems to be no doubt that the evolving LED program will increase the cost of LED-compliant fuel and this cost may or may not be able to be passed on to customers. This is especially true for certain end users such as municipalities, small businesses, and private citizens. The Coalition commented that the fiscal note in the proposal fails to consider the impact on state agencies, local governments, the public, and the regulated community, as required under Texas Government Code, §2001.0225(c) and §2001.024(a)(4) and (5). The proposal states any fiscal implications will primarily affect the producer and suppliers, and not typically government entities. The commission should evaluate how the fuel price increase will be passed on to local governments, state agencies, and the public.

The commission disagrees with this comment and has made no changes to the rule. As discussed in the response regarding the regulatory impact analysis, this rule is not a major environmental rule. Therefore, §2001.0225(c) does not apply. However, the commission did meet the requirements of §201.024. Section 2001.024 does not require an evaluation of how an increase in diesel prices resulting from this rule will affect end users. The Government Code requires the commission to assess costs to persons that must comply with the rules. In previous rulemakings, the commission has done just that, by estimating a production cost increase of $.04 to $.08 per gallon of diesel to meet LED standards. As stated in the proposal, the commission believes that these specific amendments to the LED rules will primarily affect producers and suppliers of LED, which typically do not include governmental entities. The adopted amendments make changes to testing, recordkeeping, and AERP requirements. This rulemaking does not amend the LED standard itself and does not change the rules in such a way that would increase the production cost estimated by the commission in previous rulemakings on LED.

Regulatory Impact Analysis

The Coalition stated that the commission did not develop a full regulatory impact analysis and fiscal analysis as required for a major environmental rule under Texas Government Code, §2001.0225. The Coalition argued that the amendments to Chapter 114, Subchapter H, Division 2 is a major environmental rule because it exceeds a standard set by federal law. As evidence, the commission was required to submit a waiver in accordance with 42 USC, §7545(C)(4)(c) when the rules were originally adopted. The state has also not demonstrated how this rule is specifically required by state law.

The commission disagrees with this comment. As stated in the preamble published in the Texas Register on December 16, 2005 (30 TexReg 8407 and 8410), the commission determined that this rulemaking does not meet the definition of a "major environmental rule." The commission discussed at length in the draft regulatory impact analysis section of the preamble that the ozone NAAQS is a federal requirement set by EPA that must be met by states at a certain date. The FCAA (42 USC, §7410) provides that states must develop SIPs that include "enforceable emission limitations, and other control measures, means or techniques" necessary to meet the NAAQS. The LED rules were developed as part of the control strategy to meet the NAAQS. The commission also described in the draft regulatory impact analysis that this rule is specifically required by Texas Health and Safety Code, §382.012, which requires the state to develop a general, comprehensive plan for the proper control of the state's air, in other words, a SIP. The rule also meets the specific requirements of: Texas Health and Safety Code, §382.019, providing the commission the authority to control and reduce emission from engines used to propel land vehicles; §382.202, restricting the establishment of fuel content standards before January 1, 2004, or the distribution of Texas LED as described in the SIP prior to February 1, 2005; and §382.208, requiring the commission to develop and implement, in coordination with federal, state, and local transportation planning agencies, transportation programs and other measures necessary to demonstrate attainment of the NAAQS and protect the public from exposure to hazardous air contaminants from motor vehicles. Because the rule is not a "major environmental rule," the regulatory analysis requirements of Texas Government Code, §2001.0225 do not apply.

Applicability of Rule on Wholesale Bulk Purchasers

Because of additive based alternative plans, the Coalition expressed the belief that some end users will in fact become "producers" and thus be subject to the reporting and recordkeeping requirements. Some Coalition members may become producers because they purchase large quantities of diesel fuel for fleet use and will blend in additives to create TxLED-compliant fuel on their sites prior to use in individual fleet engines. The commission's guidance on TxLED appears to set a trigger of 50,000 gallons for becoming a wholesale bulk purchaser, however, there is no explanation for this cut-off and whether there is an exception for lesser quantities of fuel. The Coalition suggested a clarification in the preamble to better explain the applicability of the rule to end users.

The provisions for timing of when bulk purchasers should start distributing LED have passed. As of January 1, 2006, only LED should be provided to bulk purchasers regardless of the tank size. The commission has made no changes to the rule in response to these comments.

Subchapter A. DEFINITIONS