Subchapter B. OUTDOOR BURNING

The Texas Natural Resource Conservation Commission (commission) adopts amendments to Subchapter A, Definitions, §116.10 and §116.18; and Subchapter I, Electric Generating Facility Permits, §§116.910, 116.911, 116.913, 116.921, and 116.930. The commission adopts new §§116.770 - 116.772, 116.774 - 116.777, 116.779 - 116.781, 116.783, 116.785 - 116.788, 116.790, 116.793 - 116.802, and 116.804 - 116.807 in Subchapter H, Permits for Grandfathered Facilities; and new §§116.917, 116.918, 116.926, and 116.928 in Subchapter I. Sections 116.18, 116.771, 116.774 -116.776, 116.779, 116.780, 116.783, 116.787, 116.790, 116.797, 116.807, 116.911, 116.913, 116.917, and 116.928 are adopted with changes to the proposed text as published in the January 4, 2002 issue of the Texas Register (27 TexReg 78). Sections 116.10, 116.770, 116.772, 116.777, 116.781, 116.785, 116.786, 116.788, 116.793 - 116.796, 116.798 - 116.802, 116.804 - 116.806, 116.910, 116.918, 116.921, 116.926, and 116.930 are adopted without changes and will not be republished. All sections of Subchapter H except, §116.776, will be submitted to the United States Environmental Protection Agency (EPA) as a revision to the state implementation plan (SIP). The new and amended sections of Subchapter A and I will also be submitted to the EPA as a revision to the SIP.

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

During the 75th Legislature, 1997, House Bill (HB) 3019 directed the commission to develop a voluntary emissions reduction plan for the permitting of existing significant sources. These existing significant sources are commonly known as grandfathered facilities. A grandfathered facility is one that existed at the time the legislature created the Texas Clean Air Act (TCAA) in 1971. These facilities were not required to comply with (i.e., grandfathered from) the then new requirement to obtain permits for construction or modifications of facilities that emit air contaminants. If grandfathered facilities had not been modified since 1971, they continued to be authorized to operate without a permit. The intent of HB 3019 was to create a program that would encourage the remaining grandfathered facilities to voluntarily obtain permits that would reduce the emissions from those facilities. In response to HB 3019, the commission created the Clean Air Responsibility Enterprise (CARE) Committee to develop recommendations for the voluntary permitting of grandfathered facilities.

In 1999, the 76th Legislature used the CARE Committee's recommendation as the basis for Senate Bill (SB) 766, which directed the commission to develop rules containing incentives for the voluntary permitting of grandfathered facilities. This program is known as the Voluntary Emission Reduction Permit (VERP) program. The commission adopted rules to implement the VERP program on December 16, 1999. Since the VERP rules became effective, the owners and operators of a number of grandfathered facilities have taken advantage of the incentives offered by the VERP program and submitted VERP applications for their grandfathered facilities. Additionally, the owners and operators of other grandfathered facilities have submitted permit-by-rule registrations and other new source review permit applications to permit their grandfathered facilities. The deadline to apply for a VERP was August 31, 2001.

Additionally, the 76th Legislature, 1999, amended the Texas Utilities Code, Title 2, Public Utility Regulatory Act, Subtitle B, Electric Utilities, and created a new Chapter 39, Restructuring of Electric Utility Industry by adopting SB 7. SB 7 required the commission to implement the permitting and allowance requirements of new Texas Utilities Code, §39.264, concerning Emissions Reductions of "Grandfathered Facilities." SB 7 required the commission to develop a mass cap and trade system to distribute emission allowances for use by electric generating facilities (EGFs). Under SB 7, two categories of EGFs are eligible to use the proposed trading system. The first category consisted of EGFs in existence on January 1, 1999, which were not subject to the requirement to obtain a permit under TCAA, §382.0518(g). These facilities are commonly referred to as grandfathered facilities. SB 7 also mandated that grandfathered EGFs apply for a permit on or before September 1, 2000, and obtain a permit by, or cease operation after May 1, 2003. The second category of EGFs consisted of permitted EGFs that were not subject to the permitting requirements of SB 7, yet elected to participate in the allowance trading system.

Most recently, the 77th Legislature, 2001, amended Texas Health and Safety Code (THSC), TCAA to require that all grandfathered facilities obtain permits. The mandatory permitting requirements of HB 2912 are the culmination of legislative efforts, beginning in 1997, to permit or otherwise authorize all grandfathered facilities. HB 2912 created four new types of permits for grandfathered facilities: existing facility permits; small business stationary source permits; EGF permits; and pipeline facilities permits. HB 2912 also mandated the dates by which grandfathered facilities must apply for a permit and have controls operational or submit a shutdown notice. Grandfathered facilities that are addressed by an application for a VERP are not required to comply with the provisions of HB 2912 for grandfathered facilities. However, grandfathered facilities that withdraw their VERP applications and elect to submit a permit application for an authorization under HB 2912 will forfeit those incentives, including eligibility for amnesty from enforcement.

HB 2912 specifies certain requirements based upon the geographic location of the grandfathered facility. Grandfathered facilities must submit permit applications or notices of shutdown by September 1, 2003 for facilities in East Texas; September 1, 2004 for facilities in West Texas; and for small business stationary source permits, by September 1, 2004, irrespective of the location of the facility. The commission is required to act on applications by the first anniversary after receipt of an administratively complete application. HB 2912 provides that the applicant may request a onetime, one-year, "good cause" extension of time to install controls if the permit is not issued within the one year from receipt of an administratively complete application. This provision for a good cause extension has been added as new §116.771(b).

Existing facility permits are available for all grandfathered facilities, and require consideration of ten-year-old best available control technology (BACT), considering the age and remaining useful life of the facility. Existing facility flexible permits are also available for grandfathered facilities and facilities permitted under a VERP, located at a single site. Small business stationary source permits are available for sources defined as a small business stationary source in TCAA, §382.0365(h), and which do not have to submit emissions inventory information under TCAA, §382.014. Facilities eligible for small business stationary source permits may not emit air contaminants after March 1, 2008 if they do not have a permit or a pending application. HB 2912 provides that gas-fired EGFs that were required to obtain a permit under SB 7, or were exempt from the requirement to obtain a SB 7 permit, are considered permitted for all air contaminants. The commission will issue a "permit" to these facilities. The permit will identify the facilities which have been permitted and will contain the general provisions in §116.913. Permits issued under §116.917 will receive the additional general and special conditions in §116.918. HB 2912 also provided that coal-fired EGFs that were required to obtain a permit under SB 7 are considered permitted for nitrogen oxides (NO _x ), sulfur dioxide (SO2 ), and particulate matter (PM) as it relates to opacity. HB 2912 further provides that coal-fired EGFs are eligible for an EGF permit for the criteria pollutants not addressed by the SB 7 permit. Additionally, TCAA, §382.05185 provides for the permitting of: 1) generators that do not generate electric energy for compensation and are not used more than 10% of the annual operating schedule; and 2) auxiliary fossil-fuel-fired combustion facilities that do not generate electric energy and do not emit more than 100 tons per year (tpy)of any air contaminant.

Grandfathered reciprocating internal combustion engines that are part of the processing, treating, compression, or pumping facilities connected to, or part of, a gathering or transmission pipeline may apply for a pipeline facilities permit. In the proposed rule, the commission provided that an applicant could apply for a single permit for all engines connected to a pipeline or a separate permit for all discrete and separate engines. In this final rule, the commission is changing the rule language to read that the applicant may apply for a single permit for a group of engines connected to a pipeline or a separate permit for all discrete and separate engines. The commission is making this change in part due to the difficulty in determining where one pipeline ends and another begins, thus making it difficult to determine if all engines have been included in the permit. Additionally, the commission must allow for mandatory emission reductions to be achieved at either a single engine or by averaging reductions among multiple engines connected to a pipeline. HB 2912 requires a 50% reduction in NO _x emissions at facilities located in East Texas, and allows the commission to require up to a 50% reduction in volatile organic compounds (VOC). For facilities located in West Texas, the commission may require up to a 20% reduction in NO _x and VOC emissions. For facilities located in West Texas, the commission will focus on reductions that can be achieved at little or no capital cost. Owners or operators who elect to average among more than one account cannot include reductions made to comply with other state or federal requirements. However, if the owner or operator does not average emissions to achieve the mandatory reductions, they may include reductions made since January 1, 2001 to comply with other state or federal requirements.

TCAA, §382.05181(h), provides that applications for pipeline facilities permits, existing facility permits, existing facility flexible permits, and EGF permits are subject to the public notice and hearing requirements of TCAA, §382.05191. TCAA, §382.05191 provides that public participation for initial issuance of a permit under TCAA, §§382.05183, 382.05185(c) or (d), 382.05186, or 382.0519 will be done in the manner of TCAA, §382.0561, concerning Federal Operating Permit; Hearing, and TCAA, §382.0562, concerning Notice of Decision. These sections allow for notice and comment hearings instead of contested case hearings under Texas Government Code, Chapter 2001. Notice and comment hearing procedures provide for public inspection of the draft permit and a 30-day comment period. In this comment period, any person may submit a written statement to the commission. Additionally, a person who may be affected by the emissions or a member of the legislature from the general area in which the facility is located can request a hearing. At the hearing, any person may submit an oral or written statement concerning the application. The public comment period extends to the close of the hearing. The commission will send notice of the final action on the permit to all persons who comment during the public comment period or at a public hearing. The notice will include a response to any comment submitted during the public comment period. The notice and comment hearing process is the same process authorized for VERPs by SB 766.

Small business stationary source permits are not subject to these notice and comment hearing procedures. Review and renewals of existing facility permits, EGF permits, pipeline facilities permits, and small business stationary source permits will be conducted under the same procedures for preconstruction permits, generally. Existing facility permits, EGF permits, pipeline facilities permits, and small business stationary source permits are subject to judicial review, under TCAA, §382.032.

HB 2914, §78, 77th Legislature, 2001, created a new incentive program to assist in retrofitting reciprocating internal combustion engines associated with pipelines. The new TCAA, §382.051865, Reimbursement Program for Certain Emissions Reductions from Reciprocating Internal Combustion Engines Associated with Pipelines, provides that the commission may develop a program, in cooperation with local governments, other agencies, and EPA to provide incentives to owners or operators of reciprocating internal combustion engines that are required to make a 50% reduction in NO _x emissions under new TCAA, §382.05186, Pipeline Facilities Permits.

HB 2914, §78 also established an Emissions Reductions Incentives Account within the Clean Air Account Number 151. The section establishes guidelines for how any money deposited into this account is to be distributed to owners or operators making reductions in NO _x emissions from grandfathered reciprocating internal combustion engines associated with pipelines. HB 2914 provides for a partial reimbursement for the capital cost of installing technology to reduce emissions that meet certain criteria. To implement these revisions, the commission is adopting new §116.776, Distribution of Funds from the Emissions Reductions Incentives Account for Control of Emissions from Grandfathered Reciprocating Internal Combustion Engines Located in the East Texas Region, in Subchapter H. The section identifies the facilities which are eligible for a partial reimbursement for the cost of controls. The rules also contain the criteria the commission will consider in determining who will receive money from the account and how much money a particular facility will receive. In order to be eligible for reimbursement under this program, the owner or operator of a grandfathered reciprocating internal combustion engine must make at least a 50% reduction in actual emissions of NO _x as compared to the emissions reported for the facility in the 1997 industrial point source emissions inventory. The commission believes that an actual reduction in emissions is necessary to receive reimbursement in order to assure that air quality benefits will be achieved under this incentive program. Another criteria for reimbursement is the requirement to obtain a pipeline facilities permit or replace the grandfathered engine with an electric engine. This implements the HB 2914 requirement that limits reimbursement to facilities required to achieve a 50% reduction in NO _x emissions. Facilities that obtain pipeline facilities permits are the only facilities required to achieve a 50% reduction in NO _x emissions and the replacement of grandfathered engines with electric engines will eliminate that source of NO _x emissions. In response to comments, the commission has made changes to when the owner or operator of a pipeline facility must request reimbursement from the Emissions Reductions Incentives Account. These changes are described in the response to comments. The commission also changed §116.776(a)(10) to clarify that only facilities required by any other state or federal law to make reductions in emissions of NO _x are not eligible for reimbursement. In the proposed rule, the commission identified the following criteria for distribution: location of the facility; percentage of reduction in the hourly emissions of NO _x ; cost effectiveness of the controls; and when the reductions are actually achieved and the request for reimbursement is received. Due to the changes in when the request for reimbursement must be received, the commission is deleting when the request for reimbursement is received as a criteria for reimbursement. The remaining criteria will provide incentives to ensure that reimbursements for emission reductions are prioritized for those reductions that occur in areas of the state where those reductions will be beneficial, for projects that achieve the highest percentage reductions first, are most cost effective, and for projects that occur early. Weighting the criteria to provide for larger, cost effective, earlier reductions considering the area of the state where the reduction is proposed will maximize the air quality benefits for the state. Guidance concerning the implementation of the reimbursement program is still under development by the commission. Interested stakeholders will be provided the opportunity to comment on the guidance before the guidance is finalized.

The proposal contained language allowing the commission to delegate to the executive director the authority to take action on permit applications for grandfathered facilities. The commission solicited comment on the proposal to delegate to the executive director the authority to take any action on these grandfathered facility permits, and also to make decisions regarding the implementation and administration of the permitting program, generally. The commission received no comments in response to this solicitation. Therefore, the commission has changed the rule in the delegation sections to state that the commission delegates to the executive director the authority to take any action on these grandfathered facility permits, and also to make decisions regarding the implementation and administration of the permitting program, generally. As a consequence of this delegation, it is necessary for the commission to change the Notice of Final Action sections of the rule to allow for the filing of a motion to overturn rather than a petition for rehearing. In addition, the commission has added language to §116.928 that states that any Notice of Final Action sent regarding a permit action under Subchapter I will state that a person affected by a decision of the executive director may file a motion to overturn the executive director's decision under §50.139 rather than a petition for rehearing. It was necessary to add this language to §116.928 because the commission did not originally propose changes to §116.922 (relating to Notice of Final Action). The commission has provided further detail concerning the specifics of this rulemaking in the Response to Comments portion of this preamble.

To implement these revisions to TCAA, the commission adopts new and amended rules in Chapter 116, Subchapter A, Definitions; Subchapter H, Permits for Grandfathered Facilities; and Subchapter I, Electric Generating Facility Permits. Additionally, revisions to 30 TAC Chapter 39, Public Notice, are necessary to implement the provisions of HB 2912. The adopted amendments to Chapter 39 are also published in this issue of the Texas Register .

SECTION BY SECTION DISCUSSION

Subchapter A, Definitions

The adopted amendment to §116.10, General Definitions, revises the definition of "grandfathered facility" to be consistent with TCAA, §382.0518(g). The revised definition clarifies that a grandfathered facility is one that is not a new facility, was constructed prior to August 30, 1971 (or no construction contract was executed on or before August 30, 1971 that specified a beginning construction date on or before February 29, 1972) and has not been modified since August 30, 1971.

The amendments to §116.18, Electric Generating Facility Permits Definitions, are adopted with changes to the proposed text. The adopted amendments add a definition for "natural gas-fired electric generating facility" for consistency with the EGF permit requirements of HB 2912. HB 2912, in TCAA, §382.05185(i), provides that a natural gas-fired EGF includes a facility that was designed to burn either natural gas or fuel oil of a grade approved by commission rule. In general, physical or operational changes at a facility to allow the burning of fuel oil will be considered a part of the design as long as they do not constitute a modification of the facility. It is the commission's position that "designed to burn" usually means that all of the necessary equipment (including fuel oil tanks, fuel lines, atomizers, and pre-heaters if necessary) were constructed and maintained as part of the grandfathered EGF. Any modification necessary to allow an EGF to burn fuel oil will be required to comply with the requirements of Subchapter B, New Source Review Permits, before beginning the construction.

The commission conducted a modeling analysis of grandfathered EGFs with the potential to burn fuel oil in all areas of the state. The commission looked at the maximum short-term emission rate for SO ₂ associated with burning fuel oil. The modeling approach assumed all facilities operated continuously at maximum firing rate. This approach is conservative because not all grandfathered gas-fired EGFs designed to burn fuel oil will be firing fuel oil at the maximum firing rate at the same time. A screening procedure was used for the initial analysis. For those sites that did not meet screening criteria, a more detailed analysis was performed. The commission first looked at firing fuel oil with a sulfur content of 0.3% by weight or less for those facilities in Harris and Jefferson Counties and fuel oil with a sulfur content of 0.7% by weight or less for all other counties in the state. Facilities in Harris and Jefferson Counties are limited to burning fuel oil with a sulfur content of 0.3% by weight or less by current rules. Using the approach outlined previously, the SO ₂ maximum predicted ground level concentrations were compared to relevant air standards. For the initial screening procedure, all concentrations were below standards, with the exception of the state SO ₂ 30-minute standard. Two sites were identified as potentially exceeding the state SO2 standard. These sites were then modeled again using a more detailed analysis. The number of hours these sites were predicted to exceed the SO ₂ standard were counted at each point and found to be less than 0.15% of all hours modeled. Due to the conservative nature of the modeling demonstration, which assumes all sources operating at full capacity simultaneously at all hours of the year, 100% compliance with the state SO ₂ standard is expected. Metals have been identified as the primary hazardous air pollutant associated with the burning of fuel oil. Adverse impacts from metals are caused by long-term exposure to unacceptable levels of emissions. The commission does not expect long-term exposure to metals emissions because fuel oil is only burned for short periods of time due to natural gas curtailments or extremely high natural gas prices. Historical data has shown that these curtailments and high natural gas prices have occurred infrequently and last only for short periods of time. Thus, the commission does not expect any adverse health effects associated with the burning of fuel oil. However, the commission has added a general condition to §116.913 requiring the EGF to keep records of fuel oil burning and submit those records with the report required under §101.336(b). In addition, EPA is developing a maximum achievable control technology (MACT) standard which is expected to address emissions of metals, primarily nickel, from fuel oil fired EGFs. Any EGF which burns fuel oil for any extended period of time would likely be subject to this MACT standard. The commission has also added language in §116.913(a)(8) that clarifies that the burning of waste or used oils is not authorized under Subchapter I. Based on this analysis, and with the limitations mentioned previously, the commission's Toxicology and Risk Assessment Section has concluded that burning American Society for Testing and Materials (ASTM) grades of fuel oil or any blend of ASTM grades of fuel oil, as limited by the adopted rules, will not pose adverse health or welfare effects in the general public. The establishment of acceptable fuel oil grades does not relieve the owner or operator of a natural-gas-fired EGF from the responsibility to comply with any emissions limitations or conditions of any permit or state or federal regulation.

The adopted amendments also add a definition for "normal annual operating schedule." This definition is needed to establish the normal annual operating schedule at an EGF site. The normal annual operating schedule is needed to determine if a generator that the owner or operator is seeking to permit under an EGF permit is used not more than 10% of the normal annual operating schedule as required by TCAA, §382.05185(d)(1). The final rule establishes the normal operating schedule as the maximum number of operating hours for an EGF in any 12 consecutive month period between 1997 and 1999. For sites with more than one EGF, the owner or operator may use the EGF with the highest number of operating hours.

Subchapter H, Permits for Grandfathered Facilities

The adopted amendments to Subchapter H include changing the subchapter title from "Voluntary Emission Reduction Permits" to "Permits for Grandfathered Facilities" in order to correctly reflect the modified content of the subchapter. The subchapter has been divided into four divisions. The existing sections of the subchapter are placed into Division 4, Voluntary Emission Reduction Permits. Division 1, General Applicability; Division 2, Small Business Stationary Source Permits, Pipeline Facilities Permits, and Existing Facility Permits; and Division 3, Existing Facility Flexible Permits contain new sections of Subchapter H adopted to implement and administer the requirements of HBs 2912 and 2914.

Division 1, General Applicability

Division 1 contains the general requirement for a grandfathered facility to obtain a permit, permit by rule, or shutdown. The owner or operator of a grandfathered facility must choose which permitting option is best for his or her facility and situation. If the facility meets the qualifications, the owner or operator may choose one of the new types of types of permits for grandfathered facilities contained in Division 2 and 3 of this subchapter or the electric generating facility permit contained in Subchapter I. The owner or operator may also choose any other permit type under Chapter 116 or permit by rule under Chapter 106 for which the facility qualifies as long as the application is submitted by the applicable deadline contained in this division. Adopted new §116.770, Requirements to Apply, contains the deadlines by which the owner or operator of a grandfathered facility must apply for a permit to operate that facility under Chapter 116, qualify for a permit by rule under 30 TAC Chapter 106, or submit a notice of shutdown. As required by HB 2912, a permit application or notice of shutdown must be submitted before September 1, 2003, for facilities located in the East Texas region and before September 1, 2004, for facilities located in the West Texas region and El Paso County. HB 2912 defines the East Texas region as all counties traversed by or east of Interstate Highway 35 North of San Antonio or traversed by or east of Interstate Highway 37 South of San Antonio, including Bexar, Bosque, Coryell, Hood, Parker, Somervell, and Wise Counties. The West Texas region is then defined as all counties not contained in the East Texas region. This definition is slightly different from the definition created by SB 7 in that the SB 7 definition for West Texas region does not include El Paso County. Therefore, rather than create a new definition, the commission uses the language, "West Texas Region as defined in §101.330 of this title (relating to Definitions) and El Paso County" in place of the West Texas region as defined by HB 2912.

New §116.771, Implementation Schedule for Additional Controls, is adopted with changes to the proposed text. The adopted new section explains in subsection (a) the implementation schedule to be contained in a permit if the installation of additional controls is required for a grandfathered facility to meet an emissions limit for a pollutant. As required by HB 2912, required controls must be installed and operating before March 1, 2007, for facilities located in the East Texas region and before March 1, 2008, for facilities located in the West Texas region and El Paso County. Also as provided by HB 2912 the applicant may request a onetime, up to one-year "good cause" extension of the time to install controls if the permit is not issued within one year of the receipt of an administratively complete application. This good cause extension language has been added as §116.771(b).

Consistent with TCAA, §382.05182, Notice of Shutdown, adopted new §116.772, Notice of Shutdown, establishes the procedures for submitting a notice of shutdown in lieu of obtaining a permit for a grandfathered facility, and the deadlines by which a grandfathered facility shutting down must cease emitting air contaminants. Facilities for which the owner or operator submits a notice of shutdown by the application deadlines contained in §116.770 may continue to operate until March 1, 2007, if the facility is located in the East Texas region or March 1, 2008, if the facility is located in the West Texas region or El Paso County. The deadlines for sources eligible for a small business stationary source permit are described in the following discussion of §116.774. Facilities that have been shut down and for which a notice of shutdown has been submitted must obtain authorization under Chapter 116 or Chapter 106 prior to restarting operations. In order to enable the commission to keep better track of facilities which are shut down, the notice of shutdown will be required to include, at a minimum, an identification of the facility being shut down, the date the facility intends to cease operating, and an inventory of the type and amount of emissions that will be eliminated.

Division 2, Small Business Stationary Source Permits, Pipeline Facilities Permits, and Existing Facility Permits

New §116.774, Eligibility for Small Business Stationary Source Permits, is adopted with changes to the proposed text. The adopted new section states the facilities which are eligible for a small business stationary source permit in accordance with TCAA, §382.05184. Only the owners or operators of facilities located at small business stationary sources as defined by TCAA, §382.0365(h), and which are not required by TCAA, §382.014 to submit emissions inventories to the commission may apply for a small business stationary source permit. The owner or operator must apply for the small business stationary source permit before September 1, 2004. The new section specifies that any grandfathered facility, including any facility for which the owner or operator has submitted a notice of shutdown under proposed §116.772, located at a small business stationary source may not emit air contaminants on or after March 1, 2008, unless the facility is permitted or has a pending permit application under Chapter 116, or a pending registration for a permit by rule under Chapter 106. The new section also requires an application for a small business stationary source permit to be submitted under the seal of a Texas licensed professional engineer, if required by §116.110(e), and states that the facility's owner or operator is responsible for applying for the permit and complying with the subchapter. The commission revised §116.774(b) to clarify that a small business stationary source may not emit air contaminants on or after March 1, 2008, unless the facility is permitted, has a permit application pending, or has a registration or pending registration for a permit by rule.

New §116.775, Eligibility for Pipeline Facilities Permits, is adopted with changes to the proposed text. The adopted new section identifies the facilities which are eligible for a pipeline facilities permit in accordance with TCAA, §382.05186. The owner or operator of a grandfathered reciprocating internal combustion engine or group of engines that are part of processing, treating, compression, or pumping facilities connected to or part of a gathering or transmission pipeline may apply for a pipeline facilities permit. The new section also requires an application for a pipeline facilities permit to be submitted under the seal of a Texas licensed professional engineer, if required by §116.110(e), and states that the facility's owner or operator is responsible for applying for the permit and complying with the subchapter. The new section allows the owner or operator of more than one grandfathered reciprocating internal combustion engine to apply for a pipeline facilities permit for a single grandfathered engine or for a group of grandfathered engines connected to or part of a gathering or transmission pipeline. The commission revised §116.775(d) to clarify that the owner or operator may apply for a permit for a single engine or a group of engines.

New §116.776, Distribution of Funds from the Emissions Reductions Incentives Account for Control of Emissions from Grandfathered Reciprocating Engines Located in the East Texas Region, is adopted with changes to the proposed text. The adopted new section implements the requirements of HB 2914, §78 to establish procedures and criteria for reimbursement to owners or operators for the partial cost of installing controls to reduce emissions from grandfathered reciprocating internal combustion engines at facilities associated with pipelines. The new section establishes which facilities will be eligible for reimbursement, the limitations on reimbursement, and the criteria for distribution. The adopted subsection (a)(6) was revised to require identification of those facilities requesting a reimbursement from the Emissions Reductions Incentives Account at the time the permit application is filed. However, no money can be paid to a facility until the permit is issued and the required reductions have been accomplished at the facility. The commission also clarified in §116.776(a)(10) that only the owners or operators of grandfathered engines required to reduce emissions of NO _x by some other state or federal law are not eligible for reimbursement. Because grandfathered engines in nonattainment areas for ozone are required to reduce emissions of NO _x , they are not eligible for reimbursement. Therefore, the adopted criteria for distribution in subsection (c)(1) will only consider whether a facility is located in an attainment area for ozone or a near nonattainment area for ozone.

Although HB 2912 limits reimbursement to the owners or operators of those facilities required to reduce emissions of NO _x by 50% because they are seeking a pipeline facilities permit, the commission believes it is also appropriate to provide the opportunity for reimbursement to certain owners or operators who choose to replace their grandfathered internal combustion engines with new electric engines. This section will allow the commission to process requests for reimbursement for the replacement of grandfathered reciprocating internal combustion engines through the registration of the replacement electric engines. Registration of the electric engines is necessary because there is no requirement to permit an electric engine since there are no emissions associated with electric engines.

Adopted new §116.777, Eligibility for Existing Facility Permits, states the facilities which are eligible for an existing facility permit in accordance with TCAA, §382.05183. The owner or operator of any grandfathered facility may apply for an existing facility permit. The new section also requires an application for an existing facility permit to be submitted under the seal of a Texas licensed professional engineer, if required by §116.110(e), and states that the facility's owner or operator is responsible for applying for the permit and complying with Subchapter H.

New §116.779, Applications for Small Business Stationary Source Permits, Pipeline Facilities Permits, or Existing Facility Permits, is adopted with changes to the proposed text. The adopted new section specifies the application requirements and demonstrations which must be met in order for a facility to be granted a small business stationary source permit, pipeline facilities permit, or existing facility permit. These requirements are consistent with the requirements for other permits issued under Chapter 116.

Adopted new §116.779(a)(1) provides that the emissions from the facility must comply with the rules and regulations of the commission, including the protection of public health and physical property. The commission may not issue a permit for a grandfathered facility if it finds that the emissions from the grandfathered facility will not be protective of public health and physical property. The requirement to protect public health and physical property is also included in the adopted §116.794(1), concerning existing facility flexible permits and the adopted §116.917(a)(1), concerning permits for certain grandfathered coal-fired EGFs and certain grandfathered facilities located at EGF sites. In order to assure that permits are protective of public health and property, the commission will conduct an appropriate health effects review for each permit application for a grandfathered facility. Details of what the review will entail will be developed and provided in a guidance document. The guidance document will be published at a later date, and the commission will invite stakeholder input prior to finalizing the guidance. The permit may also have provisions for the measurement of air contaminants, including installation of sampling ports and sampling platforms.

In order to be consistent with the current review process for permits and applicable federal requirements, §§116.779, 116.794, and 116.917 require the owner or operator of a grandfathered facility applying for a small business stationary source permit, pipeline facilities permit, existing facility permit, existing facility flexible permit, or EGF permit to be able to demonstrate that they meet applicable federal New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP). Facilities must be able to meet performance standards specified in the application and may be required to provide information that demonstrates ongoing compliance after the permit is issued. If applicable, facilities would be required to comply with Prevention of Significant Deterioration (PSD) and nonattainment review as specified in Chapter 116, Subchapter B. Since grandfathered facilities must comply with federal requirements, if applicable, it is appropriate to ensure that these facilities are in compliance with federal requirements in the process of reviewing applications. These sections also require the facility to submit air dispersion modeling if a more refined health effects review is required. Finally, these sections require the application to identify each grandfathered facility to be included in the permit, identify the air contaminants emitted, and provide emission rate calculations.

Adopted new §116.779(b) specifies additional requirements which apply to applicants for a pipeline facilities permit. In accordance with TCAA, §382.05186(e), facilities located in the East Texas region will be required to demonstrate that each engine will achieve at least a 50% reduction of the hourly emissions rate of NO _x , and may also be required to demonstrate a 50% reduction of the hourly emissions rate of VOC, both expressed in terms of grams per brake horsepower-hour (g/bhp-hr). Consistent with TCAA, §382.05186(f), the new section also states that the commission shall require up to a 20% reduction in the hourly emissions rate of NO _x and may require up to a 20% reduction in the hourly emissions rate of VOC, expressed in terms of g/bhp-hr, for facilities located in the West Texas region or El Paso County. In accordance with TCAA, §382.05186(b), the proposed section allows the owner or operator of more than one grandfathered reciprocating internal combustion engine to average the reductions achieved among more than one engine connected to or part of a gathering or transmission pipeline in order to demonstrate the required reductions or to demonstrate that the required reductions will be achieved at each individual facility. Consistent with TCAA, §382.05186(c) and (d), the new section states that, if the owner or operator chooses to average among engines located in both the East and West Texas regions or El Paso County, the owner or operator must demonstrate that the sum of the reductions achieved from all of the engines located in the East Texas region will achieve the 50% reduction required for facilities located in the East Texas region. If the emission reductions required by this adopted subsection will be achieved by averaging reductions, the rule also states that the average may not include emission reductions achieved in order to comply with any other state or federal law. If the emission reductions required by this adopted subsection will be achieved at one account, the rule allows the reduction to include emission reductions achieved since January 1, 2001 in order to comply with another state or federal law.

Adopted §116.779(c) specifies additional requirements with which applicants for an existing facility permit will have to comply. In accordance with TCAA, §382.05183(b), applicants for existing facility permits will have to propose an air pollution control method that is at least as beneficial as the BACT that the commission required or would have required for a facility of the same class or type as a condition of issuing a permit or permit amendment 120 months (ten-year-old BACT) before the submittal of the existing facility permit application, considering the age and remaining useful life of the facility, and identify the date by which the control method will be implemented.

New §116.780, Public Participation for Initial Issuance of Pipeline Facilities Permits and Existing Facility Permits, is adopted with changes to the proposed text. The adopted new section requires that an applicant for a pipeline facilities permit or an existing facility permit publish notice of intent to obtain a permit in accordance with Chapter 39, Subchapters H and K. The new section establishes that any person who may be affected by emissions from the grandfathered facility seeking a permit may request that the commission hold a notice and comment hearing on the permit application. The new section states that any hearing request must be submitted during the 30-day comment period, which ends 30 days after publication of the notice of intent. The new section specifies the procedures and requirements for the hearing and the rights of affected persons. In accordance with TCAA, §382.05181, small business stationary source permits are not subject to these notice and comment hearing procedures. The commission corrected a typographical error in §116.780(d) to correctly reference procedures in §116.783.

Adopted new §116.781, Notice and Comment Hearings for Initial Issuance of Pipeline Facilities Permits and Existing Facility Permits, specifies the applicability of the hearing requirements in the section, the responsibilities of the commission in determining whether or not to hold a hearing, the applicant's responsibilities if a hearing is to be held, and the requirements regarding submission of oral or written statements and data concerning a draft permit. TCAA, §382.05181(h) provides that applications for pipeline facilities permits, existing facility permits, existing facility flexible permits, and EGF permits are subject to the public notice and hearing requirements of TCAA, §382.05191. TCAA, §382.05191 provides that public participation for initial issuance of a permit under TCAA, §§382.05183, 382.05185(c) or (d), 382.05186, or 382.0519 will be done in the manner of TCAA, §382.0561, concerning Federal Operating Permit; Hearing, and §382.0562, concerning Notice of Decision. These sections allow for notice and comment hearings instead of contested case hearings under Texas Government Code, Chapter 2001, and require the commission to send notice of final action to persons who comment during the comment period or during a hearing.

New §116.783, Notice of Final Action on Pipeline Facilities Permit Applications and Existing Facility Permit Applications, is adopted with changes to the proposed text. The adopted new section specifies the commission's responsibilities for sending notice of the final action on an application for a pipeline facilities permit or an existing facility permit, and the information that the commission must include in the notice. The new section will require the commission to individually notify persons who commented during the public comment period or at a permit hearing, of the final action of the commission. The notice must be sent by first-class mail to the commenters and to the applicant. The proposed rule stated that the notice must include the response to comments, the identification of any changes in the permit, and a statement that any person affected by the decision of the commission may petition for rehearing and for judicial review. Because, in §116.790, the commission is delegating to the executive director the authority to take any action on a permit issued under this division, this section now requires that the notice state that any person affected by the decision of the executive director may file a motion to overturn rather than a petition for rehearing.

Adopted new §116.785, Permit Fee, establishes a permit fee of $450 for persons applying for a permit under Subchapter H, Division 1, unless the facility is a small business stationary source, as defined by TCAA, §382.0365(h), then the fee will be $100. These fees will allow the commission to partially offset the cost of processing the applications. The new section also establishes requirements for payment and return of fees. TCAA, §382.062 authorizes the commission to establish fees for permits.

Adopted new §116.786, General and Special Conditions, allows the commission to include general and special conditions in the permits issued under Subchapter H, Division 2, and requires that permit holders comply with any and all general and special conditions that the permit may contain. The new section also lists the general conditions permit holders are subject to, regardless of whether they are specifically stated within the permit document. These requirements are consistent with the requirements for other permits issued under Chapter 116.

New §116.787, Amendments and Alterations of Permits Issued Under this Division, is adopted with changes to the proposed text. The adopted new section specifies that owners or operators planning the modifications of a facility permitted under Chapter 116, Subchapter H, Division 2, must comply with the requirements of Subchapter B, New Source Review Permits, before beginning the construction of the modification. The new section also states that amendments and alterations of permits issued under Subchapter H, Division 2, are subject to the requirements of Subchapter B. The commission corrected a typographical error in this section.

Adopted new §116.788, Renewal of Permits Issued Under this Division, implements TCAA, §382.055 and the changes to §382.05192 to require that small business stationary source permits, pipeline facilities permits, and existing facility permits be renewed in accordance with Chapter 116, Subchapter D, Permit Renewals.

New §116.790, Delegation, is adopted with changes to the proposed text. In accordance with the commission's authority under TCAA, §382.061, and Texas Water Code (TWC), §5.122, adopted new §116.790 delegates to the executive director the authority to take any action on a permit issued under Subchapter H, Division 2.

Division 3, Existing Facility Flexible Permits

Adopted new §116.793, Eligibility for Existing Facility Flexible Permits, identifies the conditions under which a grandfathered facility or group of grandfathered facilities is eligible for an existing facility flexible permit in accordance with TCAA, §382.05183(c). Consistent with §382.05183(c), the new section also allows facilities permitted under §382.0519 to be included in the existing facility flexible permit. The new section requires an application for an existing facility flexible permit to be submitted under the seal of a Texas licensed professional engineer, if required by §116.110(e). The new section also requires specific actions by owners or operators of facilities covered by an existing facility flexible permit for changes of ownership. The new section specifies that the facility's owner or operator is responsible for applying for the permit and complying with Subchapter H, except after a change of ownership as explained in the section.

Adopted new §116.794, Existing Facility Flexible Permit Application, specifies the application requirements and demonstrations which must be met in order for a facility to be granted an existing facility flexible permit. These requirements are consistent with current flexible permit requirements, except for the required level of control. The level of control required by the adopted section, consistent with the requirement of TCAA, §382.05183, is at least as beneficial as ten- year-old BACT, considering the age and remaining useful life of the facility.

Adopted new §116.795, Public Participation for Initial Issuance of Existing Facility Flexible Permits, requires that an applicant for an existing facility flexible permit publish notice of intent to obtain a permit in accordance with Chapter 39, Subchapters H and K. The new section establishes that any person who may be affected by emissions from the grandfathered facility seeking a permit may request that the commission hold a notice and comment hearing on the permit application. The new section states that any hearing request must be submitted during the 30-day comment period, which ends 30 days after publication of the notice of intent. The new section specifies the procedures and requirements for the hearing and the rights of affected persons.

Adopted new §116.796, Notice and Comment Hearings for Initial Issuance of Existing Facility Flexible Permits, specifies the applicability of the hearing requirements in the section, the responsibilities of the commission in determining whether or not to hold a hearing, the applicant's responsibilities if a hearing is to be held, and the requirements regarding submission of oral or written statements and data concerning a draft permit. TCAA, §382.05181(h) provides that applications for pipeline facilities permits, existing facility permits, existing facility flexible permits, and EGF permits are subject to the public notice and hearing requirements of §382.05191. TCAA, §382.05191 provides that public participation for initial issuance of a permit under §§382.05183, 382.05185(c) or (d), 382.05186, or 382.0519 will be done in the manner of TCAA, §382.0561, concerning Federal Operating Permit; Hearing, and §382.0562, concerning Notice of Decision. These sections allow for notice and comment hearings instead of contested case hearings under Texas Government Code, Chapter 2001, and require the commission to send notice of final action to persons who comment during the comment period or during a hearing.

New §116.797, Notice of Final Action on Existing Facility Flexible Permit Applications, is adopted with changes to the proposed text. The adopted new section specifies the commission's responsibilities for sending notice of the final action on an application for an existing facility flexible permit and the information that the commission must include in the notice. The new section requires the commission to individually notify persons who commented during the public comment period or at a permit hearing, of the final action of the commission. The notice must be sent by first-class mail to the commenters and to the applicant. The proposed rule stated that the notice must include the response to comments, the identification of any changes in the permit, and a statement that any person affected by the decision of the commission may petition for rehearing and for judicial review. Because, in §116.807, the commission is now delegating to the executive director the authority to take any action on a permit issued under this division, this section now requires that the notice state that any person affected by the decision of the executive director may file a motion to overturn rather than a petition for rehearing.

Adopted new §116.798, Permit Fee, establishes a permit fee of $450 for persons applying for a permit under Subchapter H, Division 3, unless the facility is a small business stationary source facility, as defined by TCAA, §382.0365(h), and then the fee would be $100. These fees will allow the commission to partially offset the cost of processing the applications. The new section also establishes requirements for payment and return of fees. TCAA, §382.062 authorizes the commission to establish fees for permits.

Adopted new §116.799, General and Special Conditions, requires that permit holders comply with any and all general and special conditions that the existing facility flexible permit may contain. The new section states that upon a specific finding by the executive director that an increase of a particular air contaminant could result in a significant impact on the air environment, or could cause the facility, group of facilities, or account to become subject to review under §116.150 and §116.151 and §§116.160 - 116.163 (relating to Nonattainment Review or Prevention of Significant Deterioration Review), or Subchapter C of Chapter 116 (relating to Hazardous Air Pollutants: Regulations Governing Constructed or Reconstructed Major Sources (FCAA, §112(g), 40 CFR Part 63)), the permit may include a special condition which requires the permittee to obtain written approval from the executive director before constructing a facility under a standard permit or a permit by rule under Chapter 106. Additionally, the new section specifies that a pollutant specific emission cap or multiple emission caps and/or individual emission limitations shall be established for each air contaminant for all facilities authorized by the permit. The new section also lists the general conditions applicable to every existing facility flexible permit and states that there may be additional special conditions attached to an existing facility flexible permit upon issuance or amendment of the permit that may be more restrictive than the requirements of the section. These requirements are consistent with the requirements for flexible permits issued under Subchapter G.

Adopted new §116.800, Emission Caps and Individual Emission Limitations, specifies the criteria for establishing the emission cap for a specific pollutant and the criteria for establishing an individual emission limitation for a pollutant. The new section also specifies the requirements for readjustment of the emission cap when a facility is shut down, a new facility is brought into the permit, or a facility becomes subject to any new state or federal regulation which would lower emissions or require an emissions reduction. These requirements are consistent with the requirements for flexible permits issued under Subchapter G, except that there is not an insignificant emission factor specified for grandfathered facilities. The commission does not believe that an insignificant emission factor would be necessary or appropriate for grandfathered facilities, since use of the ten-year-old BACT control method will provide sufficient flexibility for these facilities.

Adopted new §116.801, Implementation Schedule for Additional Controls, explains the implementation schedule to be contained in a permit if the installation of additional controls is required for a grandfathered facility to meet an emission cap for an air contaminant. As required by TCAA, §382.05181, installation of required controls must be completed before March 1, 2007, for facilities located in the East Texas region, and before March 1, 2008, for facilities located in the West Texas region or El Paso County. The new section also specifies how the emission cap will be adjusted if such a facility is taken out of service or fails to install the additional control equipment as provided by the implementation schedule in the permit.

Adopted new §116.802, Significant Emission Increase, defines when an increase in emissions from operational or physical changes at an existing facility covered by an existing facility flexible permit will be considered insignificant for the purposes of state new source review under Subchapter H, and will not require a permit amendment. The new section states that any increase in emissions from a new facility or emissions of an air contaminant not previously emitted by an existing facility will require a permit amendment.

Adopted new §116.804, Limitation on Physical and Operational Changes, states that neither operational nor physical changes at an account may result in an increase in actual emissions at facilities not covered by the existing facility flexible permit unless those affected facilities are authorized in accordance with §116.110, Applicability.

Adopted new §116.805, Amendments and Alterations for Existing Facility Flexible Permits, specifies that amendments and alterations for existing facility flexible permits are subject to the requirements of Subchapter B.

Adopted new §116.806, Existing Facility Flexible Permit Renewal, states that existing facility flexible permits will be renewed in accordance with the requirements of Subchapter D, Permit Renewals, consistent with the permit requirements of Chapter 116.

New §116.807, Delegation, is adopted with changes to the proposed text. In adopted new §116.807 the commission delegates to the executive director the authority to take any action on a permit issued under Subchapter H, Division 3 consistent with the authority of TCAA, §382.061, and TWC, §5.122. This delegation will allow for efficient processing of permit applications.

With the addition of three new divisions to this subchapter, the existing requirements for VERPs have been placed under a new Division 4. There have been no changes to the requirements for VERPs.

Subchapter I, Electric Generating Facility Permits

The adopted amendments to Subchapter I implement the portions of TCAA, §382.05185, which create a new EGF permit. The EGF permit will allow the owners or operators of EGFs who have already applied for a permit required by SB 7, 76th Legislature to apply for a permit for: 1) generators that do not generate electric energy for compensation and are not used more than 10% of the annual operating schedule; and 2) auxiliary fossil-fuel-fired combustion facilities that do not generate electric energy and do not emit more than 100 tpy of any air contaminant. The adopted changes will also allow coal-fired EGFs which were required to apply for a permit under SB 7, 76th Legislature to apply for an EGF permit for criteria pollutants other than NO _x , SO2 , and PM as it relates to opacity. In addition, the amendments to Subchapter I provide that gas-fired EGFs which were required to be permitted under SB 7, 76th Legislature or were exempt from the requirement to apply for such a permit are considered permitted for all air contaminants.

The adopted amendments to Subchapter I include revising the subchapter title to Electric Generating Facility Permits.

The adopted amendments to §116.910, Applicability, allow the owners or operators of EGFs who have already applied for a permit required by SB 7, 76th Legislature to apply for an EGF permit for certain auxiliary generators or other combustion equipment. The amendments delete the old subsection (e) as unnecessary since this section deals with applicability and the pollutants covered by the permit are identified in §116.119 and the permit document itself. The changes adopted in subsection (f) clarify that EGFs generating electric energy primarily for internal use are not required to obtain a permit under this subchapter. However, since these internal use generators are grandfathered, TCAA, §382.05181, as codified in §116.770, requires that the owners or operators obtain authorization from the commission. The facility must obtain a permit under either Chapter 116 or qualify for a permit by rule under Chapter 106.

The amendments to §116.911, Electric Generating Facility Permit Application, are adopted with changes to the proposed text. The adopted amendments clarify that gas-fired EGFs which were required to be permitted under SB 7, 76th Legislature or were exempt from the requirement to apply for such a permit are considered permitted under the TCAA for all air contaminants. The adopted additions to this section also allow the owners or operators of EGFs who have already applied for a permit required by SB 7, 76th Legislature to apply for a permit for generators that do not generate electricity for compensation and are not used more than 10% of the normal operating schedule, or for other combustion equipment that does not generate electric energy and does not emit more than 100 tpy of any air contaminant. The adopted amendments to this section allow coal-fired EGFs which were required to apply for a permit under SB 7, 76th Legislature to apply for an EGF permit for criteria pollutants other than NO _x , SO ₂ , and PM as it relates to opacity. The adopted additions to this section identify the date by which applications must be filed and state that emissions of air contaminants from auxiliary generators or other combustion equipment that is permitted must be included in the allowance trading program created by SB 7, 76th Legislature. The commission revised §116.911(d) and (e) for clarification and to correct a typographical error.

The amendments to §116.913, General and Special Conditions, are adopted with changes to the proposed text. The adopted amendments update the conditions of any permit issued under this subchapter, including the pollutants or allowances that may be authorized for each permit and the requirements of the SB 7 allowance trading program for the additional equipment which may be permitted under this subchapter. Existing paragraph (2) of this section is deleted as it is no longer necessary because HB 2912 either considers these additional air contaminants already permitted for gas-fired EGFs which have obtained or applied for a permit under SB 7, or provides for the permitting of the additional criteria pollutants for coal-fired EGFs which have obtained or applied for a SB 7 permit. Subsequent paragraphs have been renumbered. Permits for certain grandfathered coal-fired EGFs and certain grandfathered facilities located at EGF sites authorized under §116.917 will contain additional general and special conditions, as identified in adopted new §116.918. The proposed rule established ASTM Grade Number 2 fuel oil containing not more than 0.3% sulfur by weight as acceptable. The commission stated in the preamble to the proposed rule that staff was continuing to analyze other fuel oil grades and refine the modeling analysis. As a result of this additional analysis, the commission has determined that any ASTM grade of fuel oil with a sulfur content of 0.7% by weight or less is acceptable, except in those areas where a lower sulfur content is required by 30 TAC Chapter 112. This limitation has been added to the general conditions in §116.913 along with a clarification that the burning of waste or used oils is not authorized under Subchapter I. The commission has also added a general condition to §116.913 requiring the EGF to keep records of fuel oil burning and submit those records with the report required under §101.336(b). Additionally, the commission made a minor language clarification in §116.913(a)(2) and clarified the language in §116.913(a)(1)(E) to apply only to criteria pollutants instead of all air contaminants in order to be consistent with TCAA, §382.05185.

New §116.917, Electric Generating Facility Permit Application for Certain Grandfathered Coal-Fired Electric Generating Facilities and Certain Grandfathered Facilities Located at Electric Generating Facility Sites, is adopted with changes to the proposed text. The adopted new section outlines the application requirements for grandfathered coal-fired EGFs which choose to permit their additional criteria pollutants, and the auxiliary generators and the additional combustion equipment which can now be permitted under this subchapter. In order to be consistent with the current review process for permits and applicable federal requirements, §116.917 requires the owner or operator of a grandfathered facility applying for an EGF permit to be able to demonstrate that the facility meets applicable federal NSPS and NESHAP. Facilities must be able to meet performance standards specified in the application and may be required to provide information that demonstrates ongoing compliance after the permit is issued. If applicable, facilities would be required to comply with PSD and nonattainment review as specified in Chapter 116, Subchapter B. Since grandfathered facilities must comply with federal requirements, if applicable, it is appropriate to ensure that these facilities are in compliance with federal requirements in the process of reviewing applications. These sections also require the facility to submit air dispersion modeling if a more refined health effects review is required. Finally, these sections require the application to identify each grandfathered facility to be included in the permit, identify the air contaminants emitted, and provide emission rate calculations. The commission revised an incorrect reference to §116.611(f)(1) and (2) to correctly reference §116.911(f)(1) and (2).

Adopted new §116.918, Additional General and Special Conditions for Grandfathered Coal- Fired Electric Generating Facilities and Certain Grandfathered Facilities Located at Electric Generating Facility Sites, identifies some of the general and special conditions which may be included in any permit issued under the adopted §116.917 and states that there may be additional special conditions attached to a permit upon issuance of the permit that may be more restrictive than the requirements of the section. Additional general and special conditions are required by §116.913. Permit holders are required to comply with any and all general and special conditions that the permit may contain. These requirements are consistent with the requirements for permits issued under Chapter 116.

The adopted amendments to §116.921, Notice and Comment Hearings for Initial Issuance, are necessary to include the auxiliary generators and additional combustion equipment described in adopted §116.911(f), which may be permitted under this subchapter, as facilities subject to the notice and hearing requirements of this section. These changes implement the requirement contained in TCAA, §382.05191.

Adopted new §116.926, Permit Fee, is necessary to allow the commission to collect application fees for any permits issued in accordance with §116.917. These fees will allow the commission to partially offset the cost of processing the applications. TCAA, §382.062 authorizes the commission to establish fees for permits.

New §116.928, Delegation, is adopted with changes to the proposed text. In new §116.928, the commission delegates to the executive director the authority to take any action on a permit issued under this subchapter, consistent with the authority of TCAA, §382.061, and TWC, §5.122. This delegation will allow for efficient processing of permit applications. In this section the commission also provides that because of this delegation to the executive director, the notice of final action under §116.922 will now notify the persons affected by the executive director's decision of the opportunity to file a motion to overturn rather than a petition for rehearing. It was necessary to add this language to §116.928 because the commission did not originally propose changes to §116.922 (relating to Notice of Final Action).

The adopted amendments to §116.930, Modifications, include a revision of the section title to "Amendments and Alterations of Permits Issued Under this Subchapter." The adopted amendments are intended to clarify that the owner or operator of a facility with a permit issued under this subchapter must comply with the requirements of Subchapter B prior to beginning the construction of the modification and that any required alteration or amendment will follow the procedures contained in Subchapter B.

FINAL REGULATORY IMPACT ANALYSIS DETERMINATION

The commission reviewed the adopted rulemaking in light of the regulatory analysis requirements of Texas Government Code, §2001.0225, and determined that the changes to this chapter needed to implement the substantive permitting requirements of HB 2912, §§5.02 - 5.04 meet the definition of a "major environmental rule" as defined in that statute. However, the adopted rulemaking implementing HB 2914, §78 does not meet the definition of a major environmental rule. The 77th Legislature amended THSC to require that all grandfathered facilities obtain permits. These rules implement the comprehensive permitting system created by HB 2912, including four different types of permits which will cover all grandfathered facilities, and provide for potential emission reductions. The rules implementing HB 2914 specify the procedures and criteria governing reimbursement from the Emissions Reductions Incentives Account, established to assist certain owners or operators making reductions in emissions from grandfathered reciprocating internal combustion engines associated with pipelines.

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, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state.

Although the adopted rules to implement the HB 2912 sections are intended to protect the environment or reduce risks to human health from environmental exposure, they may have adverse effects on the economy, productivity, competition, or jobs of the state or a sector of the state since they require mandatory permitting or shut down of certain grandfathered facilities. However, the analysis required by Texas Government Code, §2001.0225(c) does not apply because the adopted rules do not meet any of the four applicability requirements of a major environmental rule. The adopted rules do not exceed a standard set by federal law, exceed an express requirement of state law, exceed a requirement of a delegation agreement, or adopt a rule solely under the general powers of the agency. The rules are adopted specifically to comply with HB 2912 and related provisions of TCAA, and do not exceed the requirements of either.

The adopted rules to implement the HB 2914 sections are intended to protect the environment or reduce risks to human health from environmental exposure. Because this is an incentive program designed to provide financial assistance to certain facilities, the adopted rules will not adversely affect in a material way the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state. Therefore, the adopted rules implementing the HB 2914 sections do not fit the definition of a major environmental rule, and the analysis required by §2001.0225(c) does not apply.

TAKINGS IMPACT ASSESSMENT

The commission completed a takings impact assessment for the adopted rules. The purpose of the adopted rules is to fulfill the commission's obligation to implement HB 2912, §§5.02 - 5.04 and HB 2914, §78, concerning grandfathered facilities. The adopted rules advance this purpose by creating a comprehensive permitting system including four different types of permits which cover all grandfathered facilities, and provide the potential for emission reductions. The rules also contain procedures and criteria governing partial reimbursement from the Emissions Reductions Incentives Account, established to assist certain owners or operators making reductions in emissions from grandfathered reciprocating internal combustion engines associated with pipelines.

The commission evaluated the adopted rules and performed an assessment of whether Texas Government Code, Chapter 2007 is applicable. The commission's assessment indicated that Texas Government Code, Chapter 2007 does not apply to the adopted rules because this is an action that is reasonably taken to fulfill an obligation mandated by federal law, which is exempt under Texas Government Code, §2007.003(b)(4). Section 2007.003(b)(13) states that Chapter 2007 does not apply to an action that: 1) is taken in response to a real and substantial threat to public health and safety; 2) is designed to significantly advance the health and safety purpose; and 3) does not impose a greater burden than is necessary to achieve the health and safety purpose. Although the 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 significantly advance the health and safety purpose. In addition, these rules fulfill an obligation mandated by federal law. The adopted rules implement requirements of 42 United States Code (USC), §7410. The reductions in NO _x and VOC significantly advance a health and safety purpose by assisting the state's efforts to attain the ozone national ambient air quality standards (NAAQS) set by the EPA under 42 USC, §7409, for nonattainment areas of the state and maintain the quality of the state's air in attainment areas. The action is mandated by federal law because the rules will be submitted for EPA approval as part of the SIP. Texas Government Code, Chapter 2007 also does not apply because this is an action that is taken in response to a real and substantial threat to public health and safety, that is designed to significantly advance the health and safety purpose, and that does not impose a greater burden than is necessary to achieve the health and safety purpose. Reductions required by these rules will be no greater than those required by HB 2912. Thus, this action is exempt under Texas Government Code, §2007.003(b)(13).

Adoption and enforcement of these rules will not burden private real property. The adopted rules do not affect private property in a manner which restricts or limits an owner's right to the property that would otherwise exist in the absence of governmental action. Consequently, the adopted rules do not meet the definition of a taking under Texas Government Code, §2007.002(5).

CONSISTENCY WITH THE COASTAL MANAGEMENT PROGRAM

The commission 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, 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 the rulemaking for consistency with the CMP goals and policies in accordance with the rules of the Coastal Coordination Council, and determined that the rulemaking is consistent with the applicable CMP goals and policies. The CMP goal applicable to this rulemaking is the goal to protect, preserve, and enhance the diversity, quality, quantity, functions, and values of coastal natural resource areas (31 TAC §501.12(l)). The CMP policy applicable to this rulemaking is the policy (31 TAC §501.14(q)) that commission rules comply with federal regulations in 40 Code of Federal Regulations (CFR) to protect and enhance air quality in the coastal area (31 TAC §501.14(q)). This rulemaking requires the owners or operators of all previously grandfathered facilities to obtain a permit for those facilities in order to continue to operate. The permits issued for these facilities are expected to result in reduced emissions of air contaminants and improved compliance with state and federal air pollution control requirements. Therefore, this rulemaking is consistent with the applicable policy and goal.

No comments on the CMP consistency determination were received.

HEARING AND COMMENTERS

Public hearings on the proposal were held at the following times and locations: January 22, 2002, 7:00 p.m., Tyler Junior College Regional Training and Development Center, Room 104, 1530 South Southwest Loop 323, Tyler; January 23, 2002, 7:00 p.m., City of Houston City Council Chambers, 2nd Floor, 901 Bagby, Houston; January 24, 2002, 7:00 p.m., City of Odessa City Council Chambers, 5th Floor, 411 West 8th Street, Odessa; January 28, 2002, 6:30 p.m., City of Irving Central Library Auditorium, 801 West Irving Boulevard, Irving; and January 29, 2002, 2:00 p.m., Texas Natural Resource Conservation Commission, 12100 North I-35, Building F, Room 2210, Austin.

The commission received comments from the following organizations and companies: Birds-i Network (BIN); Southeast Coalition of Civic Clubs (SCCC); St. Francis Xavier Catholic Church (St. Francis); League of Women Voters of Dallas (LOWV); TXU Business Services Company, on behalf of TXU Energy (TXU); Texas Oil & Gas Association (TxOGA); Texas Campaign for the Environment (TCE); Sierra Club Houston Regional Group (HSC); Galveston-Houston Association for Smog Prevention (GHASP); United States Environmental Protection Agency (EPA); Environmental Defense (EDef); Downwinders at Risk/Blue Skies Alliance (DAR/BSA); Association of Texas Intrastate Natural Gas Pipelines/Gas Processors Association (ATINGP/GPA); Association of Electric Companies of Texas (AECT); and City Public Service of San Antonio (CPS).

In addition, the commission received comments from, or on behalf of, the following elected officials: Mr. Larry Green representing the Honorable Sheila Jackson Lee, U.S. House of Representatives, Eighteenth District of Texas; House Committee on Environmental Regulation, Texas House of Representatives, the Honorable Warren Chisum, Chairman; the Honorable Warren Chisum, District 88, Texas House of Representatives; the Honorable Lon Burnam, District 90, Fort Worth, Texas House of Representatives; the Honorable Al Edwards, District 146, Houston, Texas House of Representatives; the Honorable Lee Brown, Mayor, City of Houston; and the Honorable Ada Edwards, Council Member, District D, City of Houston.

SCCC, St. Francis, Larry Green (Congresswoman Sheila Jackson Lee's office), Representative Edwards, Houston City Council Member Edwards, GHASP, EPA, and Lee P. Brown, Mayor, City of Houston, generally supported the proposed rulemaking. All commenters suggested changes to some portion of the proposed rules.

TXU supported the comments of AECT. GHASP expressed support for the comments expressed by others regarding the details of the rules relating to grandfathered pipeline facilities. Representative Lon Burnam expressed support for the comments submitted by the Houston Sierra Club and the Texas Campaign for the Environment.

RESPONSE TO COMMENTS

SCCC, St. Francis, Larry Green (Congresswoman Sheila Jackson Lee's office), Representative Edwards, Houston City Council Member Edwards, GHASP, EPA, and Lee P. Brown, Mayor, City of Houston, expressed general support for the rule.

The commission appreciates the support.

GHASP commented that any good cause extensions for the installation of controls should not be automatic, and the duration of the extensions should be minimized. TCE commented that the commission should provide definitions or conditions that justify the extension. Lee P. Brown, Mayor, City of Houston urged the commission to complete the review of permit applications within six to 12 months after receipt.

The commission appreciates the comments, and has designated the proposed §116.771 as subsection (a) and added new language under subsection (b) to provide for the possible good cause extensions. The commission is committed to completing the permit review for these facilities within the required time frame. The commission will make every effort to review and act on all permit applications submitted in accordance with these rules within one year from the date of receipt of the administratively complete application.

TCE expressed concern that many aspects of the implementation of the legislation are being left to guidance documents and that the public has a limited role in the guidance document process, and suggested that a balanced work group be used to develop the guidance documents.

The commission has made no change in response to this comment. The development of guidance documents will be conducted through a balanced stakeholder process, which allows for public review and comment from interested persons.

HSC and DAR/BSA commented that the proposed rules should specify the details of the health effects review, so that the public may review and comment on the criteria. HSC also commented that they wanted specific criteria in the rules to prevent the commission from acting arbitrarily and capriciously by treating some facilities in a more beneficial manner than others. ATINGP/GPA expressed support for the commission's proposals regarding health effects review guidance and encouraged the commission to ensure that the extent and nature of the review corresponds to the potential health risks from a particular facility.

The commission has made no change in response to these comments. The development of the guidance for health effects review will be conducted through a balanced stakeholder process, which allows for public review and comment from interested persons. The commission does not agree that the use of a guidance document would allow the commission to act in an arbitrary and capricious manner with respect to the review for any permit. The commission appreciates the support for the development of the health effects review guidance, and looks forward to working with all stakeholders in its development.

TCE and GHASP commented that the health effects review should include a review of complaints against the facility. Additionally, GHASP commented that health effects reviews should include a review of notices of violation, and any other compliance information that might indicate past problems at a site. GHASP commented that adding these items to the health effects review would be particularly important for facilities that will not be required to make pollution reductions in exchange for a permit. TCE also stated that they want to make sure that the compliance history of grandfathered plants is thoroughly reviewed, including, but not limited to, violations and complaints, before permits are issued to grandfathered facilities - small and large.

The commission has made no change in response to this comment. The commission notes that the classification and use of compliance history in all types of permit reviews, including permits for grandfathered facilities, is currently being addressed in separate rulemakings. Notices of violation are now included in the components of a person's compliance history.

TCE commented that the rule should specifically address the prevention of public nuisance and the prevention of immediate threat to life or property in addition to the rule inclusion for prevention of real and substantial threat to public health and safety.

The commission has made no change in response to the comment. Generally, the health effects reviews conducted by the commission will consider the nuisance effects from compounds either through a review of the compliance history of the facility or through a detailed look at the off-property impacts of the emissions from the facility. When the commission conducts a detailed modeling analysis, the off-property impacts are compared to the effects screening level (ESL) of the compound. The ESL for each compound is based on the nuisance potential or the potential for adverse health effects, whichever is lower. In addition, the commission's rule regarding nuisance, 30 TAC §101.4, provides adequate enforcement authority regarding nuisance conditions. The commission also notes that private citizens may have other private remedies regarding nuisance conditions. Immediate threats to life and property from potential acute exposures will also be considered during the permit review.

GHASP, DAR/BSA, and TCE commented that the $450 fee is too low for large businesses, but support the low fee for small business sources. HSC also commented that the $450 fee was too low, and that the fee should be a minimum of $1,000. TCE commented that there should be a higher fee for companies that did not participate in the VERP program. TCE suggested that the commission use the existing fee structure for new and modified sources. TCE suggested that the commission consider hiring persons with accounting backgrounds, rather than engineering backgrounds, to determine the appropriate value of the facilities being permitted. TCE also suggested that the commission not charge a single fee for a permit for numerous facilities located on a pipeline.

The commission has made no change in response to this comment. The commission does not agree that it is appropriate to use the existing fee structure for facilities that were constructed over 30 years ago, and that have not been modified. The permitting of these facilities is not anticipated to require as many resources as reviewing a permit for new construction. The commission notes, however, that fees for the permitting of grandfathered facilities have been included in a review of permit fees currently being conducted to assess whether changes should be proposed to permit fees in general. The commission will charge a fee for each permit application reviewed. Even if an application for a permit includes multiple facilities associated with a pipeline, the fee will be a single application fee.

TCE and DAR/BSA questioned how the commission will compile an accurate listing of the additional large, small, and micro-business grandfathered facilities not included in the 1997 emissions inventory. TCE and DAR/BSA also questioned how the addition of these facilities to the inventory will affect the SIP.

The commission has made no change in response to these comments. The commission will not attempt to compile a list of the additional large, small, and micro-business grandfathered facilities which are not included in the 1997 emissions inventory. The commission will make efforts to outreach to as many businesses as possible to make sure they are aware that any grandfathered facilities they may have will need to be permitted. However, the emissions from most of these businesses are already accounted for in the inventory, and thus the SIP, by established procedures used to estimate the emissions from area sources. Thus, there should be little or no impact on the SIP.

EPA commented that the proposed §§116.771, 116.776, 116.779, 116.794, and 116.801 should clarify that control measures and implementation schedules be agreed upon prior to permit issuance and included in permits.

The commission agrees that control measures and implementation schedules should be codified in the permit, when controls are required. The proposed §116.771 specifies that if any additional controls are required by a permit for a grandfathered facility, the permit will specify a schedule for the implementation of those controls. This requirement applies to any permit issued under Subchapter H.

EPA commented that the proposed rules provided that notice and comment hearing requirements apply only to the initial issuance of pipeline facilities permits, existing facility permits, existing facility flexible permits, and EGF permits. EPA states that the commission should require public notice for revisions and modifications of pipeline facilities permits, existing facility permits, existing facility flexible permits, and EGF permits to meet 40 CFR §51.161.

The commission has made no change in response to this comment. HB 2912 provided that public participation for initial issuance of pipeline facilities permits, existing facility permits, existing facility flexible permits, and EGF permits, would be conducted in the same manner as public participation for federal operating permits. Therefore, for initial issuance , public participation includes a requirement for publication of newspaper notice, signposting, and an opportunity to request a notice and comment hearing. However, HB 2912 provided that for modifications and renewals of pipeline facilities permits, existing facility permits, existing facility flexible permits, and EGF permits must comply with TCAA, §382.0518, which requires public participation to include publication of newspaper notice, signposting, and an opportunity to request a contested case hearing. Proposed and adopted §§116.787, 116.788, 116.805, and 116.806 require that modifications and renewals of small business stationary source permits, pipeline facilities permits, existing facility permits, and existing facility flexible permits comply with Chapter 116, Subchapters B and D, and therefore, meet the requirements of 40 CFR §51.161. Adopted §116.930 requires that modifications of EGF permits comply with Subchapter B and existing §116.931 requires that renewals of EGF permits comply with Subchapter D, thus also satisfying the requirements of 40 CFR §51.161 for EGF permits.

EPA commented that proposed §§116.786(b)(2), 116.799(c)(2), and 116.918(b)(2) do not meet the requirements of 40 CFR §51.212(c), which provides that compliance must be determined by methods in 40 CFR 51 Appendix M; 40 CFR 60 Appendix A; or as approved by the EPA administrator.

The commission has made no change in response to this comment. The rules as written continue the current practice of reviewing any alternate method requests and sending recommendations to EPA for approval as appropriate. These rules and procedures satisfy the requirements of 40 CFR §51.212(c).

LOWV expressed concern regarding whether the hearing process has any impact on permit issuance. LOWV also stated that air contaminants are carried by prevailing winds, can be carried far away from sources, and the wind currents are not always the same. Lastly, LOWV commented that the agency response to this issue has been very weak and industries do not have the right to pollute the air. LOWV stated that citizens have the right to breathe clean air.

The commission has made no changes to the rule in response to these comments. The commission supports input from the public in all permitting decisions through both public comment and the opportunity to request a hearing where authorized by statute. The commission agrees that certain air contaminants may be carried some distance by prevailing winds. The commission assesses the impact of these air contaminants on downwind areas as part of the permit review process.

TXU commented that the permitting of existing facilities is a new process and does not necessarily have to be consistent with the processes for permitting new and modified facilities. TXU stated that the permitting process for grandfathered facilities should adhere closely to what is authorized in SB 7 and HB 2912 and not add on traditional permitting procedures.

The commission has made no change in response to this comment. The commission agrees that HB 2912 provides specific permitting requirements for grandfathered facilities in acknowledgment of the fact that these facilities have already been constructed. However, HB 2912 also provides that review and renewal of these permits be completed under existing Chapter 116 procedures. This requires that the commission harmonize the review of grandfathered facilities in the context of the existing structure for permitting new and modified facilities.

TxOGA requested that the commission create a "regional permit for aggregated facilities" for grandfathered tank or pipeline facilities other than engines. TxOGA's proposed regional permit would require that the aggregate allowable emissions meet the equivalent overall emission limit of current BACT.

The commission appreciates the suggestion; however, this suggestion is beyond the scope of this rulemaking, so no change has been made in response to this comment.

TCE and DAR/BSA requested that the commission change the word "may" to "shall" in the sections of the rules relating to the provision for measurement of air contaminants, including installation of sampling ports and sampling platforms. In addition, TCE comments that the rules do not include requirements for certified monitoring data.

The commission has made no change in response to these comments. These general conditions are included in all permits. The commission does not agree that it is appropriate to require the installation of sampling ports and sampling platforms for all facilities. In those cases where the permit engineer determines that it is appropriate to require sampling and/or monitoring, the permit will contain specific conditions requiring the provisions for these activities. In addition, permit engineers are aware of the periodic monitoring and compliance assurance monitoring requirements of Title V and permits for grandfathered facilities will satisfy those requirements where appropriate.

TCE and DAR/BSA supported the rule language stating that there may be special conditions included in the permit that may be more restrictive than the requirements of the section.

The commission appreciates the support.

HSC commented that the commission should define the criteria it uses to determine when the basis of a hearing request by a person who may be affected (by a facility requesting a permit) is determined to be unreasonable. HSC's perspective is that any person who is breathing or may breathe the air contaminants from a facility is affected and the commission does not have the right to withhold from any person the right to have a public hearing.

The commission has made no changes in response to these comments. The public notice provisions in the adopted rules implement the requirements of HB 2912, §§5.02 - 5.05 to provide for public notice and an opportunity for a notice and comment hearing, in the same manner as provided for federal operating permits under TCAA, §382.0561. Section 382.0561 provides that the commission is not required to hold a hearing if the basis of the request by a person who may be affected is determined to be unreasonable. Therefore, reasonableness is the statutory standard by which requests for hearings are required to be judged by the commission. Although the commission believes that "reasonableness" is a term that is circumstantial and not required to be defined by the commission, the factors relevant to a determination of reasonableness have previously been discussed in the commission's procedural rules, and the commission could use those factors as guidance.

EPA commented that these regional reductions will not only result in improvements to air quality near the specific facilities, but should also provide benefits in reducing ozone levels in the nonattainment and near nonattainment areas, as well as reduce regional haze.

The commission appreciates the support.

EPA commented that §116.772 should clarify that a source which shuts down and then restarts must be re-permitted under Chapter 116, Subchapter B or under Chapter 106.

The commission has made no change in response to this comment. The proposed §116.772(c) requires that the owner or operator of a source which is shut down and which the owner or operator then elects to restart must obtain authorization under Chapter 116 or Chapter 106 prior to operating the facility. The permitting is not limited to Chapter 116, Subchapter B. For instance, if an owner or operator of a grandfathered facility located in West Texas shuts the facility down in 2002, but elects to re-start the facility, the owner or operator may submit an application for a grandfathered facility permit under Subchapter H (except for Division 4 - VERP) prior to September 1, 2004.

EPA asked if Form PI-1GSD, Notice of Shutdown, along with application forms for Small Business Stationary Source Permits, Pipeline Facilities Permits, and Existing Facility Permits were available for public review and comment.

The forms to implement these grandfather permitting rules are being developed. The forms will be made available to the public when they have been completed, and the commission always welcomes public comment on how forms and guidance can be improved.

EPA commented that §116.786(b)(3) should also discuss public availability of records, and that records should be available to the public upon request unless determined to be confidential business information under 40 CFR 2.

The commission has made no change in response to this comment. The commission agrees that public availability is an important component of the permitting process, and has implemented procedural rules, 30 TAC §1.5, to ensure that the records of the agency are properly available to the public, subject to appropriate confidentiality restrictions. The commission provides information to the public, subject to the limitations provided in TCAA, the Texas Public Information Act, and copyright law.

EPA commented that §116.786(c)(2)(A), special conditions for written approval, should provide that the public record for any permit application should document the basis for requiring, or not requiring, prior written approval from the executive director.

The commission has made no change in response to this comment. The proposed §116.786(c)(2)(B) identifies the reasons why the commission may include a provision requiring prior written approval before constructing a source under certain authorizations. The basis for including such a condition in a permit will be identified in the technical review of the permit application. This technical review is available in the permit file available to the public.

EPA commented that permits for coal-fired EGFs and certain grandfathered facilities located at EGF sites as identified in §116.917 should contain provisions for measuring the emissions of air contaminants as determined by the commission. Specifically, EPA commented with regard to §116.917(a)(6), that the commission should require both initial and ongoing compliance measures (for example, periodic monitoring), in order to ensure initial and ongoing compliance. EPA commented that the pipeline facilities permit needs to specify the method for determining how the source will demonstrate achievement of 50% and 20% reduction, respectively, on a continual basis. DAR/BSA also commented that the emissions from these pipeline facilities should be reliably monitored and tracked to ensure greatest reductions.

The commission has made no change in response to these comments. Permits issued by the commission include any appropriate measures needed to ensure initial and ongoing compliance with the permit and any underlying standards. In addition, most, if not all, of these facilities are required to obtain a Title V permit and are subject to acid rain permitting requirements. The commission is required to place the appropriate periodic monitoring and compliance assurance monitoring requirements in these permits.

EDef stated that the commission should ensure that the owners and operators of facilities applying for a permit under these proposed rules cannot use the permit to make operational or physical changes such as increasing the utilization, capacity, or throughput of existing units without going through the normal New Source Review (NSR) permitting process. EDef stated that the commission should add a requirement that the maximum capacity under any grandfathered permit may not significantly exceed historical levels.

The owner or operator of a facility for which an application for a grandfathered facility permit is submitted should be able to document that the facility is truly a grandfathered facility and thus eligible for one of the four new types of permits for grandfathered facilities. The commission staff will review this information along with the remainder of the application information (including utilization, capacity, and throughput information) to ensure that the facility qualifies for the type of permit for which the application was submitted. In those cases where applications are submitted for facilities that are not grandfathered, or for which the applicant is requesting physical or operational changes to the facility that would constitute a modification the applicant will be directed to submit the appropriate type of NSR permit application.

EDef requested that the commission require in the final rules a certification, signed by a responsible official that the facility has not been modified since 1971.

The commission has made no change in response to this comment. The commission does not believe that a certification of grandfathered status is necessary. As mentioned previously, the owner or operator of the grandfathered facility must be able to provide documentation regarding the grandfathered status of the facility being permitted. The commission also notes that for those facilities which have submitted Title V permit applications, the owner or operator has provided information regarding the grandfathered status of the facilities with applicable requirements at the site and has certified that the information provided is true and accurate.

DAR/BSA commented that the proposed rule is of concern since a recently released EPA study of MOBILE6 projects that vehicles will emit 90% more NOx and 21% more VOC in 2003 than previously documented, which will result in further reductions necessary for nonattainment areas to meet federal law and protect the public from harmful air pollution.

The commission has made no change in response to this comment. If the new mobile source model predicts more emissions than the previous model, the commission, along with the local stakeholders, may be required to identify more reductions in NO _x and/or VOC emissions in order to reach attainment of the NAAQS in the nonattainment areas. The need for additional reductions will be evaluated after the results from the new mobile source model are evaluated.

ATINGP/GPA requested that the commission establish a procedure whereby all permit applications for grandfathered facilities at the same account be processed at the same time.

The commission has made no change in response to this comment. The commission will work with any applicant and is developing internal procedures to coordinate the review and issuance of permits to the extent that the requirements are similar.

For example: If the owner or operator applies for both an existing facility permit and a pipeline facilities permit, the commission may be able to coordinate the review for both applications to provide for a single public notice for both applications, concurrent review of the applications, and issuance of a single permit. Such coordination of review and issuance will require the assistance of the applicant. Both applications must be submitted together and must clearly identify the request for a single permit number and combined public notice. The applicant must also ensure that any deficiencies identified with either application are addressed quickly so that the coordinated review is not jeopardized.

Lee P. Brown, Mayor, City of Houston urged the commission to quantify the emissions reductions from both permitting of grandfathered facilities and fewer industrial upsets resulting from the implementation of HB 2912 as soon as possible. Additionally, the City of Houston urged the commission to complete air quality modeling to determine resulting ozone and fine particle reductions to allow the City of Houston to work with regional stakeholders in developing strategies to avoid nonattainment for the forthcoming fine particle standard.

The commission has made no change in response to these comments. Although the comments address areas beyond the scope of this rulemaking, the commission appreciates the comments and provides the following response.

The commission agrees that emission reductions of ozone precursors resulting from the implementation of HB 2912 should be quantified. These emission reductions will be quantified as part of the ozone modeling for the Houston/Galveston Area's mid-course review. Phase I of the modeling for the midcourse review is currently in progress.

The commenter makes reference to "the forthcoming fine particle standard." The commission wishes to clarify that the federal fine particle (PM _2.5 ) standards were promulgated in 1997. However, nonattainment designations for PM _2.5 have not yet been made by the state and the EPA. Pending further guidance from EPA regarding the implementation of the PM _2.5 standard, such designations, if deemed appropriate from the monitoring data, could be made as early as 2003. The designations would be based on monitoring data from the three- year period 2000 through 2002.

The commenter requests that the commission complete PM _2.5 air quality modeling to allow the City of Houston to work with regional stakeholders in developing strategies to avoid PM _2.5 nonattainment in the Houston area. The commission does not plan to conduct PM _2.5 modeling in advance of any PM2.5 nonattainment designations. However, the commission would conduct such modeling should the Houston area be designated nonattainment, as part of the development of an attainment demonstration SIP.

The commission acknowledges the program begun in late 1999 by the City of Houston and stakeholders to help the area avoid a PM _2.5 nonattainment designation. Participants in this program developed and implemented a number of early PM _2.5 control strategies.

In 2000, a field study was conducted by universities, with assistance from the commission, to better understand the formation and transport of PM2.5 in the Houston area. Data from the study are being analyzed, and will provide an enhanced scientific basis for evaluating the effectiveness of potential controls should the area be designated nonattainment for PM _2.5 .

The representative from the Birds-i Network commented regarding personal observations of increased incidence of diabetes, lupus, and other diseases with mysterious lupus-like symptoms, and other various birth defects.

Birds-i Network also expressed concern regarding mercury, and noted that EPA provides an annual report to Congress regarding mercury that appears to indicate that mercury from utility emissions is responsible for birth defects and immune illnesses.

Birds-i Network commented that all lignite fired plants have no filters on the smokestacks.

Birds-i Network commented that a federal grand jury investigating the Rocky Flats nuclear reservation in Colorado issued more than 60 criminal indictments for how that plant was being operated, and that the federal grand jury should be convened to take testimony from utility officials about what occurred during the nineties, regarding mercury.

The commission has made no change in response to these comments. The 1990 amendments to the Federal Clean Air Act identified 189 hazardous air pollutants (HAPs). Congress directed EPA to identify source categories which emit significant amounts of these HAPs and further directed them to establish standards requiring reductions in the emissions of these HAPs. One of the HAPs identified by Congress was mercury, and one of the source categories identified by EPA as emitting mercury was coal-fired EGFs. As the commission discussed elsewhere in this preamble, the commission expects that EPA will be addressing mercury emissions from EGFs in the near future. The commission has no data to support the comments regarding the alleged increases in various diseases or birth defects. The commission has no information regarding events at the Rocky Flats nuclear reservation in Colorado and the commission does not have authority to convene a federal grand jury regarding any matter.

EPA requested additional discussion of what is a "Small Business" under TCAA, §382.014.

The commission has made no change in response to this comment. TCAA, §382.014 does not define "Small Business." TCAA, §382.014 enables the commission to require a person whose activities cause emissions of air contaminants to submit information the commission needs in order to develop an inventory of emissions in Texas. The requirement to submit this information needed to develop the inventory is based on the level of emissions from the facilities located at the account (site), and applies to any person or company regardless of whether or not the person or company is a small business. As stated in §116.774(a), small business is defined in TCAA, §382.0365(h).

TCE and DAR/BSA stated that industry representatives testified at legislative hearings that they do not have exact emission figures for all pipeline facilities. TCE and DAR/BSA are concerned that the owners or operators of pipeline facilities that apply for a small business stationary source permit may indeed be above the 50 tpy threshold of any regulated air pollutant or may emit more than 75 tpy of all regulated air pollutants. TCE and DAR/BSA are concerned that these pipeline facilities may be improperly exempt from having to obtain an existing source permit.

The commission has made no changes in response to this comment. The commission anticipates that most pipeline facilities will receive pipeline facilities permits. However, there may be some pipeline facilities that will qualify for a small business stationary source permit. The commission will review each application to ensure that it meets the eligibility criteria, including the emission limits to be considered a small business source. Any applicant who does not meet the eligibility criteria for the type of application submitted will be required to submit a new application appropriate for the facility.

TCE and DAR/BSA commented that the proposed rules will not necessarily result in significant reductions in emissions, and therefore, do not accurately reflect legislative intent. TCE commented that the proposed rules require a reduction in the rate of emissions for a pipeline facilities permit rather than a reduction in the tonnage of emissions. TCE stated that permits that require a 50% reduction in NO _x emission rates, in addition to VOC reductions, should not be issued without substantial changes to those facilities.

The rule provisions may not result in reductions in emissions. This is consistent with the statute since reductions are not required in all cases, as noted in other responses to comment in this rulemaking. HB 2912 provides clear statutory direction for the situations in which emission reductions or controls are required for the permitting of grandfathered facilities. The commission notes, however, that the permitting of these facilities will provide for codification of requirements applicable to these facilities, which may result in air quality benefits from better enforcement.

TCAA, §382.05186(e) clearly states that the commission shall grant a pipeline facilities' permit for a facility or facilities located in the East Texas Region, if the commission finds that the conditions of the permit will require a 50% reduction in the hourly emissions rate of NO _x expressed in terms of g/bhp-hr. The statute also requires up to a 50% reduction in VOC emissions from facilities located in East Texas, and up to a 20% reduction in NO _x and VOC emissions from facilities located in West Texas. All of these reductions are expressed in terms of g/bhp-hr. The staff of the Air Permits Division (APD) will be reviewing the applications for these facilities to ensure that any reductions claimed are a result of real and substantial changes at the facility. There will be no claims of a 50% reduction in NO _x emissions allowed where there has not been any physical or operational change made to the facility in order to achieve those reductions.

EDef commented that the commission should use its general authority to protect public health and adopt stronger rules that ensure predictable and significant reductions occur from the permitting of grandfathered pipeline facilities. EDef commented that if the commission is going to claim credit for permitting grandfathered emissions in the SIP, it must provide reasonable assurance that the projected emission reductions will be achieved in practice, and that the commission will have to do more than adopt a 50% reduction in emissions from pipeline facilities in order for this measure to be creditable under the SIP. EDef commented that the commission should establish a cap on emissions from pipeline facilities, modeled after the emission reduction program established in SB 7.

The commission has made no change in response to these comments. Section 382.05186(e) clearly states that the commission shall issue a permit for a pipeline facility or facilities located in East Texas if the conditions of the permit will require a 50% reduction in the hourly emissions rate of NOx expressed in terms of g/bhp-hr. However, if these reductions overall do not result in the amount of NO _x emissions predicted for SIP purposes, the commission, along with the local stakeholders, may be required to identify additional reductions of NO _x emissions in order for the ozone nonattainment areas to achieve compliance with the NAAQS.

ATINGP/GPA stated that the use of the word "may" in the proposed §116.779(b)(1) for an up to 50% reduction in VOC emissions does not provide due notice to owners/operators of grandfathered engines of the level of reductions that may be required by the commission to obtain a permit. ATINGP/GPA stated that some types of NO _x controls will actually result in an increase in the emissions of VOC, thus creating an implementation problem. ATINGP/GPA stated that the commission should not require any VOC reductions without a demonstrated regional air quality or public health need. ATINGP/GPA stated that natural gas-fired engines are not significant sources of VOC emissions, but diesel-fired engines emit relatively significant quantities of VOCs. ATINGP/GPA stated that VOC emission reductions, if warranted by regional air quality needs, should be imposed on diesel, rather than natural gas engines. ATINGP/GPA requested that the commission modify the proposed rules to state that grandfathered engines in East Texas are not required to reduce VOC emissions in order to obtain a pipeline facilities permit. ATINGP/GPA suggested that if there is a demonstrated need for reductions in VOC emissions, the commission should consider requiring reductions of up to 50% for VOC emissions from diesel-fueled engines.

The commission has made no change in response to these comments. The regulatory language in §116.779(b)(1) allowing the commission to request up to a 50% reduction in VOC emissions is consistent with the statutory language in TCAA, §382.0518(e). The commission acknowledges that some NO _x reduction techniques may result in increases in VOC emissions. The commission also acknowledges that the VOC emissions from gas-fired engines are minimal and requiring control of these VOC emissions at this time may result in minimal improvement in air quality. However, the commission will review the emissions from each facility, including diesel-fueled engines, on a case-by-case basis to determine if reductions in VOC emissions are appropriate.

ATINGP/GPA expressed support for the portion of the proposed rule requiring reductions for pipeline engines on a g/bhp-hr basis. ATINGP/GPA stated that this conforms to legislative intent to protect a pipeline's capacity and not impair the deliverability of natural gas throughout Texas.

The commission appreciates the support.

TCE and DAR/BSA are concerned about the commission determining and verifying the following for all pipeline facilities permits: 1) the determination of the emissions rate; 2) verification of the actual rates prior to and post reduction by the commission; 3) baseline rate estimation - how will the commission calculate the baseline emissions for the facilities that are required to make the 50 and 20% reductions in the emissions; 4) guarantee of tonnage reductions; and 5) commission verification of applicants that choose to average emissions are not also including reductions made to comply with other state or federal requirement.

The commission has made no changes in response to this comment. With the exception of the guarantee of tonnage reductions, all of these items will be reviewed and verified by the permit engineer actually assigned to the permit. The actual method of verification will depend on the specific situation. For example, there may be cases where the permit engineer determines that there is enough data available about the emissions associated with a particular engine type that no additional testing or monitoring is necessary. In other cases, the permit engineer may request the use of a portable analyzer to verify before modification emissions, after modification emissions, or both.

With regard to the guarantee of tonnage reductions, the statutory language does not support the position that the legislature intended a tpy reduction from these facilities. Therefore, these rules will not require a reduction in annual emissions except in the cases where the owner or operator is seeking partial reimbursement for the cost of controls from the Emissions Reductions Incentives Account. In this case, the commission asserts that reductions in annual emissions are appropriate for reasons outlined elsewhere in this analysis of testimony.

EDef requested that the commission define a clear methodology to determine the baseline from which pipeline facilities' emissions reductions are measured. EDef suggested either requiring certified monitoring data for each facility or establishing default baseline rates for various engine types based on either published emissions data or certified testing of a representative sampling of engines in Texas.

The commission has made no change in response to this comment. The commission will establish procedures to verify both before and after control emissions from pipeline facilities to ensure that the specified reductions are actually achieved. Because different types of engines will require different procedures, the verification process will be accomplished during the review of the permit for the engine or engines. Where the commission determines that the same type of information is needed to verify emissions for a particular type of engine, the commission may develop guidance for that engine type if there are a sufficient number of engines that such guidance will be useful. Any guidance that is developed will be made available through the agency web site and other appropriate means.

TxOGA and ATINGP/GPA commented that the rules should provide that zero reductions may be acceptable in instances in West Texas where reductions cannot be economically achieved, and ATINGP/GPA commented that the statutory language does not mandate reductions of either VOC or NO _x from facilities located in West Texas, but instead allows the commission to find that zero reduction is required. ATINGP/GPA stated that any expenditure of funds by industry in West Texas to achieve emissions reductions is not justified and serves to consume personnel and capital resources that could otherwise be directed toward making improvements in the East Texas and nonattainment regions of the state. ATINGP/GPA stated that unless the commission ties a requirement to reduce emissions to a specific finding of need to protect the public health, general welfare, or physical property, the requirement to reduce emissions is not authorized by the Clean Air Act. ATINGP/GPA stated that the legislature viewed the West Texas reductions as a very narrow provision, not to be applied in a blanket-fashion across the breadth of West Texas, but rather only to meet limited regional air quality needs. ATINGP/GPA stated that there is no modeling or other evidence that a 20% or less reduction of the relatively minor emissions from grandfathered engines would improve public health or any regional air quality condition. ATINGP/GPA stated that a 1% reduction level is an arbitrary floor. Representative Warren Chisum expressed support for the proposed language regarding the potential reductions for NO _x and VOC from pipeline facilities applying for a permit in West Texas. Representative Chisum commented that it was not the intent of the legislature to require at least a 1% reduction, and that in some cases a 0.0% reduction would be completely appropriate in West Texas.

The commission has made no change in response to these comments. The proposed rule language in §116.779(b)(2) closely tracks the statutory language in TCAA, §382.05186(f), and while the commission agrees it is appropriate to review, among other things, health effects and proximity to nonattainment areas, such reviews will be done on a case-by-case basis. The commission agrees that there may be some instances where reductions cannot be economically achieved based on specific engine models or configurations or the age and remaining life of the engine. Decisions regarding the level of control required, if any, will be based on technical and economic evaluations of the control options available to specific facilities. However, the commission has determined that it is appropriate to ask for reductions from engines located in West Texas when there are measures that can be applied to the engine that will result in reductions of emissions at little or no capital cost.

HSC commented that the commission should maximize the emission reduction requirements for pipeline facilities in West Texas so that they will be 20%, not "up to a 20%" reduction. HSC commented that the commission has been negligent in protecting important natural resources such as the Guadalupe Mountains National Park, Big Bend National Park, Big Bend Ranch State Natural Area, Franklin Mountains State Park, Hueco Tanks State Historic Park, and Fort Davis State Historic Park from visibility problems, and that now is the time to require maximum reductions, not delay.

The commission has made no change to this comment. TCAA, §382.05186(f) specifically requires that the commission grant a permit if the commission finds that the conditions of the permit will require up to a 20% reduction of the hourly emissions rate of NO _x . The commission notes that there are ongoing efforts relating to regional haze, which are not the subject of this rulemaking.

EDef stated that the commission should define how average emissions from multiple pipeline facilities are calculated. EDef stated that the averaging process needs to ensure that there is not a reduction in the actual amount of emissions reduction that would have been achieved through the permitting process if the units had been permitted individually.

The commission has made no change in response to these comments. The commission is developing guidance on the procedures to be used to calculate the required emission reductions from pipeline facilities. This guidance will include the procedures to be used when the owner or operator elects to average the required reductions over more than one engine. The guidance will not be finalized until interested stakeholders have had the opportunity to review and comment on the draft guidance.

ATINGP/GPA indicated support for the rule proposals that allow the permitting of more than one engine under a single pipeline facilities permit and the provisions allowing the owner/operator to average among more than one engine statewide in order to achieve any necessary emission reductions.

The commission appreciates the support.

ATINGP/GPA recommended that the criteria for averaging emission reductions among more than one engine be incorporated into the rule and recommended the following criteria: 1) use g/bhp-hr in the emissions averaging calculations and extend the g/bhp-hr for engines of different horsepowers; 2) enable use of emissions reductions achieved as a result of shut down engines in the permitting of operating engines; 3) enable use of emissions reductions achieved as a result of engines shut down after September 1, 1997 in any emissions averaging calculations; 4) ATINGP/GPA stated this would be rewarding, not penalizing, early participants in the voluntary program; 5) the commission should create a mechanism to bank and utilize emission reduction credits. In the alternative, an accounting of emission reduction credits that are generated or utilized should be kept by the permittee/commission; 6) enable use of various emissions credits available under other agency emissions credit programs for the purposes of emission averaging, such as discrete emission reduction credit (DERC), emission reduction credit (ERC), and mobile emission reduction credit (MERC); 7) if emission averaging is utilized, a supporting schedule should be incorporated into the pipeline facilities permit that documents the creation and utilization of emission credits; and 8) an entity with excess emission credits should be allowed to transfer or sell those credits to another entity.

The commission believes that there is sufficient flexibility built into the statute and rule by allowing owners and operators to average the required emissions reductions across multiple sites and that the additional flexibility provided by an emission trading program is not authorized by statute and not needed. Owners or operators electing to average the required emission reductions over more than one engine will be required to establish the emission rate for each engine and will not be allowed to establish a cap and make changes to individual engine emission rates to stay under the cap. The emission rate for each engine will be identified in the pipeline facilities permit. Since the commission will not establish a cap and trade type system for pipeline facilities, the owners or operators will not be allowed to transfer or sell "credits" to another entity.

Existing rules regarding the use of ERCs or MERCs would have to be modified to allow the use of ERCs and MERCs to comply with the required emission reductions needed in order to obtain a pipeline facilities permit. However, since the rules for DERCs allow the use of these credits for compliance with any SIP requirement, the commission will allow the use of DERCs to comply with the required emission reductions.

TxOGA requested that the commission clarify that engine shutdowns can be used when averaging among more than one engine to achieve the emission reductions required for a pipeline facilities permit. TxOGA also requested that the commission clarify that emission reductions achieved through the VERP program can be included in the average.

The commission has made no change in response to these comments. The commission agrees that engine shutdowns (or other emission reductions not required by another state or federal rule) that occurred on or after January 1, 1997 may be used when averaging reductions among more than one reciprocating internal combustion engine connected to or part of a gathering or transmission pipeline. The baseline year for purposes of SIP planning is 1997, and therefore it would be inappropriate to allow the inclusion of shutdowns occurring prior to January 1, 1997 in the calculation of the average. Please note that if reductions are averaged over more than one engine, and if shutdown engines are included in the average, the g/bhp-hr emission rate for each shut down engine, prior to the shutdown, must be included in the average to determine the amount emissions must be reduced to meet the appropriate reduction requirement.

Engines for which an owner or operator has received a VERP are not eligible for inclusion in an average. The pipeline facilities permit and the requirement for reductions in order to be eligible for the permit apply only to grandfathered facilities. Facilities for which a VERP has been issued are no longer considered grandfathered facilities and thus cannot be included in the average.

ATINGP/GPA stated that the language in proposed §116.779(b) does not specifically state that engines in nonattainment areas are subject to the provisions of the SIP for the area rather than the emission reduction requirements of these proposed sections. ATINGP/GPA suggested that the commission include language clarifying the applicability of the emission reductions requirements of these proposed rules to engines located in nonattainment areas.

The commission has made no change in response to this comment. Pipeline facility engines located in nonattainment areas are subject to both the requirements of the SIP for the area and the requirements of these sections. These rules require all grandfathered facilities in the state to obtain a permit or shut down. Grandfathered reciprocating internal combustion engines associated with pipelines, including those located in nonattainment areas, can apply for a pipeline facilities permit in order to comply with this requirement. In order to obtain a pipeline facilities permit, the owner or operator of the facility must demonstrate that the engine will meet the emissions reductions requirements contained in the proposed §116.779(b)(2). In addition, these facilities must meet the appropriate emissions reductions required in the SIP. The owner or operator should be aware that the reductions must satisfy both of these requirements when choosing how to reduce the emissions. Section 116.779(b)(4) of the proposed rules allow the owner or operator to take credit for any reductions, such as those required by the SIP, which are achieved after January 1, 2001 as long as the owner or operator does not average emissions from more than one account.

ATINGP/GPA expressed support for the provision in §116.779(a)(9) stating that the commission may require computerized air dispersion modeling if the modeling is necessary to determine impacts from the facility. However, ATINGP/GPA stated that the provision for ambient monitoring contained in this same subsection is generally not warranted because of the expense and time involved in performing the monitoring in remote areas of the state where many of these facilities are located.

The commission has made no change in response to this comment. Although not often required, there may be situations where ambient monitoring is appropriate and useful. The commission reserves the ability to require ambient monitoring in those situations. In addition, a few applicants have elected to perform ambient monitoring in order to establish the level of impacts from their facility on the surrounding property or to provide for an ongoing compliance demonstration.

ATINGP/GPA stated that the commission's cost analysis fails to take into account the engineering costs and studies that must be performed to study and analyze the types of controls that will be successful in achieving controls on a particular engine. ATINGP/GPA stated that no one-size-fits-all control technology or parametric controls will work for every engine. ATINGP/GPA specifically cited the commission's cost estimates for low emission combustion technology and non-selective catalytic reduction as being too low. In both instances, ATINGP/GPA cited the commission's failure to account for any needed engine/exhaust/intake/etc modifications necessary to make the control systems operate properly.

The commission's cost estimates were based on publicly available information, the EPA's alternative control techniques (ACT) document for NO _x controls on stationary reciprocating engines. The authors of the EPA document attempted to reconcile lower cost estimates from control equipment vendors with higher costs suggested by the regulated community. Although hundreds of stationary gas-fired engines have been modified to reduce NO _x emissions in the last decades, complete cost documentation is often guarded by engine owners for competitiveness or other reasons. The published cost estimates are only rough approximations, using standard estimating factors for engineering costs. Qualitatively, a population of older engines is likely to require more costly engineering analysis of control options compared to a newer one because engine conditions become more varied over time. Nonetheless, once engineering studies are completed, the more modest emission reduction goals of the grandfathered pipeline permit program as compared to low emission retrofits presumed in the cost note should result in lower costs in many instances than the cost note. From limited cost information in applications for use determination filed with the commission in conjunction with property tax abatements for pollution control systems, it appears that the capital costs for non-selective catalytic reduction agree fairly well with the ACT. Two use determinations for low emission retrofits for compliance with the Chapter 117 engine NOx rule in Beaumont Port/Arthur (75% - 85% NO _x reduction) indicate higher engine modification costs than identified in the ACT. These higher costs may result from a combination of additional modifications necessary to make the control systems operate properly, not identified in the ACT, and upgrades which provide both qualitative emission benefit and more quantitative operational benefit. Sometimes it is difficult to separate these costs. The commission will have the opportunity to consider costs more specifically with individual permit applications.

HSC stated that the reimbursement criteria, "highest percentage reductions" and "projects that occur early" should be weighed more heavily than those that "are most cost effective." HSC stated that "cost effectiveness" is a company determination, not a commission determination. HSC also commented that the use of purchased emission credits allows companies to ignore environmental justice and local community impacts of emissions.

The commission has made no change in response to this comment. However, as noted elsewhere in the response to comments, the commission is not going to allow the use of credits in achieving the reductions required by these rules. The one exception to this, as also noted elsewhere, is the use of DERCs. The commission does not anticipate the widespread use of DERCs to comply with the emission reduction requirements of these rules. The commission also wishes to note that the commission has addressed environmental justice issues relating to the cap and trade program in a previous rulemaking regarding that program. Those rules provide for the executive director to halt trading for a certain area if problems result from trading in a localized area of concern and provide that increases in emissions by use of credits are allowed on a temporary basis, not perpetually, and are limited to 25 tons for NO _x and five tons for VOC in any 12-month period. All other uses would allow sources only to remain at the current emission rates or lower. Additionally, the commission has made a strong policy commitment to address environmental equity by creating an environmental equity program within the Office of Public Assistance. This program works to help citizens and neighborhood groups participate in the regulatory process; to ensure that agency programs that substantially affect human health or the environment operate without discrimination; and to make sure that citizens' concerns are considered thoroughly and are handled in a way that is fair to all. The Office of Public Assistance can be reached at 1-800-687-4040 for further information.

EPA stated that the provisions of the rule pertaining to the partial reimbursement of the cost of controls for pipeline facilities does not need to be submitted as a part of the SIP.

The commission agrees with the commenter, and has removed the sections of the rule regarding reimbursement from the SIP submittal, since the reimbursement portion of the rules will be effective for a limited duration, and are not directly tied to attainment or maintenance of air quality.

TCE and EDef expressed general support for the proposed requirement for a 50% reduction in annual emissions in order for pipeline facilities located in East Texas to be eligible for partial reimbursement of the cost of controls. EDef also stated they supported the proposed criteria for the distribution of funds with one exception - they state funds should not be used for reductions already required in a SIP. ATINGP/GPA stated that proposed §116.776(c)(1) contains a typo in that it still has a reference to a facility that is located in a nonattainment area for ozone. ATINGP/GPA stated that this clause should be deleted to make it consistent with other subsections of this section.

The commission appreciates the support, and agrees that facilities required to make reductions in NO _x emissions by another state or federal requirement are not allowed to request reimbursement from the Emissions Reductions Incentives Account. This restriction was included in §116.776(a), and has been clarified in §116.776(c)(1) by removing "...located in... a nonattainment area for ozone" from the criteria to be considered.

ATINGP/GPA expressed support for the proposed provision that makes engines required to reduce emissions by some other state or federal law ineligible for reimbursement from the Emissions Reductions Incentives Account, but asked that the commission clarify the intent of this section, otherwise the section could be misconstrued to make ineligible those engines that will be subject to a MACT standard.

The commission appreciates the support. The commission has changed the language of §116.776(a)(10) to state, "Facilities required by any other state or federal law to make reductions in emissions of NO _x are not eligible for reimbursement." MACT standards are intended to regulate emissions of hazardous air pollutants, and not NO _x . Therefore, the commission agrees that an engine subject to a MACT standard is still eligible for reimbursement as long as it is not subject to any state or federal law which specifically requires a reduction in NOx emissions.

ATINGP/GPA expressed general support for the provisions of proposed §116.775 regarding the distribution of funds from the Emissions Reductions Incentives Account. ATINGP/GPA and TXU commented that the criteria requiring a reduction of 50% in the annual emissions of NO _x in order to qualify for a reimbursement of a portion of the cost of controls for pipeline facilities in East Texas should be deleted, since HB 2912 and HB 2914 require only a 50% reduction in hourly emissions of NO _x .

The commission has made no change in response to these comments. The commission disagrees with the comment that the requirement to achieve actual reductions in NO _x emissions from the 1997 emissions inventory detracts from requirement to obtain a 50% reduction in g/bhp-hr in order to obtain a pipeline facilities permit. Indeed, the commission believes that the requirement to make reductions in annual NO _x emissions from the 1997 emissions inventory actually helps to achieve the purpose behind the reimbursement program, which was to encourage real, annual reductions in NO _x emissions from sources outside the nonattainment areas in East Texas. HB 2912 does require a 50% reduction in hourly emissions of NO _x in order to obtain a pipeline facilities permit in East Texas. HB 2914 states that facilities required to obtain a 50% reduction in NO _x emissions in East Texas are eligible for a partial reimbursement of the cost of controls from the Emissions Reductions Incentives Account. Further, HB 2914 directs the commission to develop the criteria for reimbursement and leaves the criteria to the commission's discretion. The Emissions Reductions Incentives Account was created to provide for a partial reimbursement of the cost of controls for pipeline engines outside the nonattainment areas in East Texas because the owners and operators of these engines are being asked to make reductions in NO _x emissions in order to help nonattainment areas reach attainment. The commission believes that setting one of the criteria for reimbursement as a reduction in annual emissions of NO _x is appropriate since these emission reductions will be needed in order to reach the goal of attainment for ozone in the East Texas nonattainment areas.

ATINGP/GPA commented that proposed §116.776(a)(6), requiring a pipeline facilities permit to be issued before the owner/operator can request a distribution from the reimbursement account is awkward, and that the review should take place simultaneously with the review of the application. ATINGP/GPA suggested that the rule be revised to require an application for a pipeline facilities permit to be filed and undergoing review before the owner/operator may request a distribution from the fund.

The commission agrees with this comment and has changed §116.776(a)(6) to require identification of those facilities requesting a reimbursement from the Emissions Reductions Incentives Account at the time the permit application is filed. The commission is requesting this information in order to obtain a list of the facilities potentially eligible for reimbursement as early as possible. However, no money can be paid to a facility until the permit is issued and the required reductions have been accomplished at the facility. The actual process for reimbursement is still under development at this time and will be provided in a guidance document at a later date.

ATINGP/GPA requested that the commission delete the requirement in proposed §116.779(b)(1) to obtain "at least" a 50% reduction of the hourly emissions rate of NOx , expressed in g/bhp-hr, in order to be eligible for reimbursement. ATINGP/GPA indicated they thought that the "at least" should be removed so that it will not be construed that the commission may require reductions beyond 50% from facilities in East Texas in order to get a pipeline facilities permit.

The commission has made no change in response to this comment. The "at least" language was included in this rule to make it clear that a 50% reduction in the emissions of NO _x , expressed in terms of g/bhp-hr, is the minimum amount of reductions that will be needed in order to be eligible for a pipeline facilities permit. Any reductions over the required 50% are welcomed and encouraged by the commission. However, the commission will not require greater than 50% reductions in order to qualify for a pipeline facilities permit.

TCE commented that they did not find any language relating to HB 2914 emission rate reductions in the proposed rules.

The commission has not made any change in response to this comment. HB 2914 itself does not specify any emissions rate reductions. HB 2914 does require that a facility be a grandfathered reciprocating internal combustion engine associated with a pipeline that is subject to the requirement to reduce emissions by 50%. HB 2914 also specifies that the engine be reducing its hourly emissions of NO _x by 50% in order to request reimbursement from the Emissions Reductions Incentives Account.

TCE requested clarification regarding the specific criteria the commission is referring to in the proposed language regarding the distribution of funds from the Emissions Reductions Incentives Account.

The criteria that the commission will use in determining the priorities for reimbursement from the Emissions Reductions Incentives Account are listed in §116.776(c). However, the actual process that will be used to assess the weighting of each of the criteria to determine the priority and amount of distribution from the Emissions Reductions Incentives Account is still under development at this time and will be addressed in guidance which will be provided at a later date. The commission will invite stakeholder input prior to finalizing the guidance.

ATINGP/GPA requested clarification of the proposed §116.779(a)(5), regarding demonstration of compliance with any applicable MACT standard. ATINGP/GPA requested clarification that the commission did not expect the owner/operator of an engine subject to a MACT standard to have any required MACT controls installed by the date they must submit a permit application when the MACT standard provides for a later date by which controls must be installed.

The commission has made no change in response to this comment, but does confirm that an existing source will not have to be in compliance with any applicable MACT standard until the compliance date for that standard. The commission does encourage owners and operators of sources that are required to install controls to obtain a permit for a grandfathered source to take into consideration any additional controls that may be required by an applicable MACT standard.

Lee P. Brown, Mayor, City of Houston stated that the commission should take extra care to ensure that the emission reduction standards of HB 2912 are consistently met for any facility-wide, flexible permits.

Any permit issued by the commission, including any flexible permit or existing facility flexible permit, will specify the emissions limits and control requirements necessary to obtain the permit. The permit will also contain conditions necessary to ensure ongoing compliance with those emissions limitations and control requirements.

EPA stated that §116.777, Eligibility for Existing Facility Permits, should clarify how an "Existing Facility Permit" differs from a permit to operate under §116.770.

The commission has made no rule change in response to this comment. The proposed §116.770 states the general requirement for the owners or operators of all grandfathered facilities to obtain a permit for those facilities. Additional language was added to the Section by Section Discussion portion of this preamble for Division 1 which explains the relationship between the general requirements in Division 1 and the specific permit requirements contained in Divisions 2 and 3 and Subchapter I. The "Existing Facility Permit" is one type of permit that the owners or operators of certain grandfathered facilities may use to satisfy the requirements of §116.770 to obtain a permit.

ATINGP/GPA requested that the commission develop a guidance document that identifies ten- year BACT for many common grandfathered sources in order the streamline the review process for existing facility permits.

The commission has existing guidance which is updated annually and identifies ten-year-old BACT for many common types of sources. The document is entitled, "Guidance for Air Quality - Qualified Changes Under Senate Bill 1126." Appendix A of this document contains the information on ten-year-old BACT. Appendix A can be found on the APD web site at: www.tnrcc.state.tx.us/permitting/airperm/nsr_permits/bact.htm

You may also contact the APD for a copy of this guidance. Although the guidance document itself was developed for different purposes, the information on ten-year-old BACT can be used as a starting place for identifying ten-year-old BACT for existing facility permits. However, this is a guidance document, and is not a final determination of acceptability by the commission. APD or the individual permit engineer should be contacted to ensure that the information is still current and the control technology still meets the ten-year-old BACT requirement.

TCE and DAR/BSA expressed support for the commission's position that an insignificant emission factor would not be included when calculating the emissions limit for and existing facility flexible permit.

The commission appreciates the support.

HSC commented that the proposed §116.802 provides for the avoidance of NSR permitting for any company that increases its emissions. HSC stated that the commission does not define "significant," and that the public should allowed to review and comment on the definition.

The commission has made no change in response to this comment. Although the proposed §116.802 does not specifically define "significant," it states that any increase in emissions from operational or physical changes at an existing facility covered by an existing facility flexible permit that does not result in an increase in emissions over the cap is insignificant. As part of the permit review for an existing facility flexible permit, the commission conducts a review of the emissions as established in the cap. Therefore, any increase in emissions which does not exceed this cap has already been reviewed by the commission and the company is not "avoiding" NSR permitting. In addition, the public has access to all of this information during the permit review process. Finally, the company is not allowed to install new facilities or emit a new air contaminant under the cap - either of these activities will require a new review under the NSR permitting procedures.

EPA requested clarification of how an "Existing Facility Flexible Permit" is distinguished from a "Flexible Permit" under Subchapter G of the rule.

The commission has made no change in response to this comment. Flexible permits under Subchapter G may be used by any facility, including grandfathered facilities, provided the facility meets the requirements of Subchapter G. Existing facility flexible permits are only available for grandfathered facilities. Additionally, flexible permits require BACT and an opportunity for a contested case hearing and existing facility flexible permits require ten-year-old BACT and a notice and comment hearing for initial issuance. Once issued, existing facility flexible permits are subject to the same renewal and amendment requirements as flexible permits, including BACT for amendments and an opportunity for a contested case hearing for both amendments and renewals.

EPA commented that the air pollution control methods discussed in §116.794(3) should be agreed upon prior to permit issuance and incorporated as terms and conditions into the permit.

The commission has made no change in response to this comment. The commission agrees with this comment and notes that the control methods necessary for any air permitting process must be identified in the application, agreed to prior to permit issuance, and appropriately incorporated into the issued permit.

EPA requested clarification of how the commission will implement the provision, "are considered permitted for all air contaminants" for gas-fired EGFs that were required to obtain a permit under SB 7 or were exempt from the requirement to obtain a permit under SB 7.

SB 7 required the commission to establish allowances for NO _x emissions from gas-fired EGFs. However, the permits required by SB 7 are issued under the Texas Utilities Code. HB 2912 clearly states that any gas-fired EGF which satisfies the permitting requirements of SB 7 or which is exempt from the permitting requirements of SB 7 is considered permitted for all air contaminants under THSC, Chapter 382. Thus, these EGFs are no longer considered grandfathered facilities under THSC, Chapter 382. The commission will issue a "permit" to these facilities. The permit will identify the facilities which have been permitted and will contain the general and special conditions in §116.913. Permits issued under §116.917 will receive the additional general and special conditions in §116.918.

EPA commented that the commission should clarify and explain the phrases "emissions of all air contaminants" and "all air contaminants," contained in §116.913(a)(1)(A) and (E), respectively.

The commission has made no change to this comment. In enacting the requirements of HB 2912, the Texas Legislature specifically stated in TCAA, §382.05185, that an electric generating facility is considered permitted with respect to all air contaminants if the facility met certain conditions. Section 116.913 implements this plain requirement for electric generating facility permits. "Air contaminant" is defined in TCAA, §382.003.

TXU identified what they assumed was a typographical error in the proposed §116.917(a). TXU stated that they believed the reference to an application for grandfathered facilities identified in §116.611(f)(1) or (2) should instead reference §116.911(f)(1) and (2). TXU stated that if the reference as they believe it was intended is correct then the owner or operator of an EGF seeking an EGF permit must demonstrate that the facility will meet protection of public health and welfare requirements. TXU states that the only requirement for coal-fired EGFs is to look at criteria pollutants, and the only requirement for non-EGF combustion units is to include their emissions in the emission allowance trading program without additional allowances. TXU states that the term "air contaminants" in §116.917(a)(11) should be replaced with "relevant criteria pollutants."

The commission agrees with the comment regarding the typographical error and has changed the rule to reflect the correct citation of §116.911(f)(1) or (2).

The statutory language of TCAA, §382.05185 clearly requires the commission to issue permits for coal-fired EGFs for the criteria pollutants other than NO _x , SO ₂ or opacity if the emissions from the facility will not contravene the intent of the TCAA, including the protection of the public's health and physical property. The commission has determined that the appropriate way to implement this requirement is to require that EGF permits be subject to permitting application and issuance requirements similar to the requirements for NSR permits. This will ensure consistent permit reviews with appropriate emphasis on the relevant statutory obligations for EGFs, in the context of the appropriate permit review.

The commission agrees that §382.05185(e) clearly requires emissions from non-EGF combustion units to be included in the emission allowance trading program, and the commission may not issue new allowances. However, the commission also observes that the allowance program only provides for emissions on NOx , while the legislature clearly contemplated that these EGF permits would address all air contaminants, and that emissions from these facilities would not contravene the intent of the TCAA, including the protection of the public's health and physical property.

The commission has not changed the language of §116.917(a)(11), since limiting the required information submitted in applications to "relevant criteria pollutants" would not ensure that adequate information would be provided to meet the requirements of the complete permit review, which includes the requirement to ensure that emissions from the facility will not contravene the intent of the TCAA, including the protection of the public's health and physical property.

CPS opposes the application of §116.771 to EGFs because it implies that controls are mandated and that an implementation schedule must be provided for the installation and operation of such controls.

The commission has made no change in response to this comment. The commission disagrees that §116.771 implies any mandate for controls since this section begins with the conditional phrase, "If the installation of additional controls is required...." Although the commission does not anticipate any control requirement for EGFs beyond any controls necessary to comply with SB 7, TCAA, §382.05181 specifies that the requirement to have any additional controls installed prior to March 1, 2007 in East Texas and March 1, 2008 in West Texas applies to any facility affected by TCAA, §382.0518(g), not just any non-EGF facility.

CPS stated that they hope the commission will continue to consider EGF permits unique from other permits in providing the flexibility of control and allocation of allowances based on annual limits provided for Chapter 101, Subchapter H, Division 2.

The commission has made no change in response to this comment. The commission intends to continue to allow EGFs the flexibility to meet the allowance requirements for air contaminants covered by SB 7. However, the commission will issue permits with maximum allowable emission rate tables (MAERT) for grandfathered auxiliary generators and other grandfathered combustion equipment located at an EGF site, but which is also required by HB 2912 to obtain a permit or shut down. In addition, the emissions from the auxiliary generators and other combustion equipment must be included in the amount of allowances needed for the site in any given year. As stated in HB 2912, no new allowances will be issued to the site for the operation of this equipment.

CPS commented that the proposed methodology for adding new units at existing EGFs brings these new units into the standardized state permitting requirements rather than continuation of the flexible allowance based system of SB 7. CPS stated that the proposed language needs to be changed to provide for the allowance based system envisioned by SB 7.

The commission agrees with the comment that the proposed methodology for permitting existing combustion equipment at an EGF is similar to the methodology for permitting new and modified units. However, the allowance based system provided by SB 7 is retained in §382.05185(e) and the proposed methodology provides the flexibility of SB 7 permits for emissions of NO _x in that the only limit on NO _x emissions contained in the permit for the additional combustion units will be the NOx allowances for the site resulting from SB 7. The other air contaminants emitted from these facilities will have limits included in a MAERT just like any other NSR permit. The commission believes this approach is appropriate and is consistent with the statute. These facilities are required to apply for a permit and specified that any modifications to the permit or renewal of the permit be reviewed under the existing requirements contained in the act. Because these EGF permits will follow the existing procedures for modification and renewal, it is appropriate that they use similar methodology and look as similar as possible to permits for new and modified sources. This harmonizes the requirements of HB 2912 and the pre-existing TCAA permitting requirements.

HSC and GHASP commented that they oppose allowing a company to operate for 10% of its operating hours without applying for a permit. HSC and GHASP also commented that this operation could occur during peak ozone season, which would have the most impact on citizen's health and welfare. GHASP stated that the provision should be revised to establish a maximum weekly operating limit of 20 hours in addition to the proposed restriction.

The commission has made no changes in response to these comments. The proposed rules do not allow a company to operate any unit for 10% of its normal operating hours and avoid the requirement to obtain a permit. The proposed rules require all grandfathered facilities in Texas to obtain a permit or shut down. If an auxiliary generator operating at a facility which is required to obtain a permit under SB 7 operates less than 10% of the normal operating hours (as defined in §116.10), the owner or operator of the facility may apply for an EGF permit rather than some other type of permit. Although these auxiliary generators could operate during the ozone season, there will not be any additional annual emissions of NO _x from these facilities since they do not get any additional allowances under SB 7.

The statute is clear that facilities operating less than 10% of the normal operating hours of the EGFs at the site may apply for an EGF permit. Therefore, the commission does not believe it is appropriate to place any additional limitations on the operating time of these facilities in order to obtain an EGF permit.

TCE is concerned that if impacts are found, the commission might not request changes to the permit if an auxiliary generator is operated less than 10% of the time.

The commission has made no change in response to this comment. If a facility is found to violate a standard such as the NAAQS, the commission may not issue a permit to that facility no matter what percent of the time it operates.

TXU commented that the definition of "normal operating schedule" should be based on the normal operating schedule of the grid (8,760 hours per year) rather than the normal operating schedule of the EGFs at a particular site.

The commission does not agree that the "normal operating schedule" should be the operating schedule of the electric grid. The statutory language in TCAA, §382.05185(d) refers to facilities, not the electric grid. There is no indication in the statutory requirements for electric generating facility permits that the legislature intended to rely upon such a schedule, in lieu of the schedule applicable to a specific site. However, the commission does agree that the statute may be interpreted to provide some additional flexibility, and the commission has changed the language in this definition to establish the normal operating schedule as the maximum number of operating hours for an EGF in any 12 consecutive month period between 1997 and 1999. For sites with more than one EGF, the owner or operator may use the EGF with the highest number of operating hours.

EPA commented that there was no basis specified for the definition of "Normal Annual Operating Schedule," particularly why years 1997 - 1999 were required to be included in the calculation of the average, but years 2000 and 2001 were not.

The commission used the heat input for 1997 as the basis for establishing allowables for EGFs under SB 7. Since HB 2912 requires the emissions from these auxiliary combustion units which receive an EGF permit to fit under those same allowables, the commission considers it appropriate to use a similar basis to define "normal operating schedule." However, in order to provide some additional flexibility, the commission decided to use the maximum number of operating hours for an EGF in any 12 consecutive month period between 1997 and 1999. For sites with more than one EGF, the owner or operator may use the EGF with the highest number of operating hours. The commission has changed the language in this definition for the reasons mentioned in the response to the previous comment.

TCE expressed concern that the modeling for grandfathered EGF's designed to burn fuel oil is not sufficient to make a determination that any grade of fuel oil should be allowable. HSC stated that they support requiring EGF facilities to undergo NSR permitting if they decide to burn fuel oil rather than natural gas. The House Committee on Environmental Regulation stated that the goals of the legislation were to provide for the widest range of fuel oil use possible to give grandfathered EGFs a meaningful choice of fuel and to ensure that emissions controls would not interfere with the SIPs, specifically with regard to NO _x . AECT stated that the intent of the legislature regarding acceptable fuel oil grades was that the commission would designate as being acceptable as broad a range of grades of fuel oil as possible, as long as air quality standards would be met. AECT stated that designation of a broad range of acceptable grades of fuel oil is critical to ensure maximum fuel flexibility and continued availability of reliable electric power in Texas. AECT stated that the proposed §116.18(11) unnecessarily and unreasonably limits the range of fuel oil grades that could be burned in grandfathered EGFs. AECT and the House Committee on Environmental Regulation stated that the legislative intent was to limit the commission's review of acceptable fuel oil grades to "standards," and since the commission's effects screening levels are not standards, the evaluation of fuel oil firing with respect to the ESLs is contrary to legislative intent. AECT stated that the methodology the commission used to establish the acceptable fuel oil grades proposed in §116.18(11) was unnecessarily restrictive and resulted in a limit that was too stringent. The House Committee on Environmental Regulation and AECT commented that the commission should allow grandfathered EGFs to burn any grade of fuel oil that meets the specifications in §112.9, as long as the owner or operator of the grandfathered EGF can ensure that the burning of the desired grade of fuel oil in the EGF will not cause a violation of the SO ₂ property line standard. AECT also requested that the rule language in proposed §116.18(11)(B) be changed to refer to a "determination" by the executive director rather than a "demonstration" by the owner or operator of the facility. The House Committee on Environmental Regulation and AECT suggested that proposed §116.18(11) be revised to reads as follows: "11) Natural gas-fired EGF - For purposes of Subchapter I of this chapter, an EGF that was designed to burn either natural gas or fuel oil, and that when burning fuel oil only burns fuel oil of a grade determined by the commission to be acceptable. Burning of a fuel oil designated by this definition as acceptable does not relieve the owner or operator of the EGF from the responsibility to comply with the emission limitations, allowances, or conditions of any permit or state or federal regulation, such as the applicable sulfur dioxide (SO ₂ ) property line standard in §112.3. Acceptable fuel oil grades are: A) Any American Society for Testing and Materials (ASTM) grade of fuel oil, the burning of which will comply with the applicable limits in §112.9. B) Any other grade of fuel oil which the executive director determines is protective of the SO ₂ property line standard in §112.3."

TXU stated that it had a great deal of concern over the process being used by the commission to establish acceptable fuel oil grades. TXU and CPS stated that the maximum fuel oil sulfur content that should be modeled by the commission should be 0.7% because a higher sulfur content would result in a stack concentration that exceeds the limit in Chapter 112. TXU stated that the grade of acceptable fuel oil should be changed to any grade with 0.7% sulfur except for specific plants where the modeling indicates there may be a problem. CPS commented that the commission should consider allowing utilities to burn fuel oil at levels of sulfur at or below 0.7% or at least consider modeling these levels to determine impacts with the state standards. TXU stated that the analysis should be an open process that includes a review by the owners of the facilities being modeled to ensure that the model inputs are accurate. AECT and the House Committee on Environmental Regulation commented that the commission's interpretation of the the term "designed to burn" is more narrow than allowed by the statutory language in TCAA, §382.05185(i). The House Committee on Environmental Regulation and AECT commented that "designed to burn" should only prohibit a physical change that would constitute a modification under §116.10(9). AECT stated that based on the regulatory definitions of "EGF" and "facility" the EGF does not include every piece of equipment at a grandfathered EGF site that is involved with the burning of fuel oil. AECT stated that any maintenance or repairs to any equipment that comprises the EGF, or any like-kind replacement of any such equipment, that is necessary to allow the EGF to burn fuel oil, should not prevent the EGF from being considered to be "designed to burn" fuel oil. The House Committee on Environmental Regulation stated that "designed to burn" in TCAA, §382.05185(i) means a facility was designed to burn any fuel oil grade - even if the grade will no longer be considered acceptable for burning following the adoption of these rules. Similarly, AECT stated that if an EGF is "designed to burn" a grade of fuel oil, the fact that such fuel oil grade may not be considered acceptable under the final rules should not prevent the EGF from meeting the "designed to burn" condition. The House Committee commented that the statute only limits the grade of fuel oil prospectively, but does not mean the grade historically burned should prohibit burning a lighter grade in the future. AECT stated that proposed §116.18(11) and the associated preamble need to be revised to clearly provide that the "designed to burn" condition is met for such an EGF. AECT requested that the review process for case-by-case determinations be made quick and simple and be based on modeling and/or monitoring results related to the impact of burning of the desired grade of fuel oil on the ability of the site to meet the SO2 property line standard. EPA stated that with regard to §116.18(11)(B), there should be a "replicable" procedure for how the executive director will determine if "any other grade of fuel oil" is protective of public health and physical property." AECT specifically requested that the procedure involve submittal of a written request to the commission staff that includes any necessary fuel and facility information. The commission should then use modeling or monitoring information it already has to evaluate the request, model the request using staff resources, or request that the applicant conduct the modeling or monitoring anaysis and submit it to the staff for review. AECT requested that this case-by-case determination process be discussed in the preamble to the final rule. AECT also requested that §116.18(11)(B) provide for an opportunity to request reconsideration of any determination of acceptable fuel oil grades under 30 TAC Chapter 55. AECT requested that the following language be used for §116.18(11)(B): "In the event that the owner or operator of the EGF disagrees with the executive director's determination, the owner or operator may request a reconsideration of that determination under the procedures of Chapter 55."

TXU stated that facilities should be allowed to combust the fuel they have on-site and any limitations should be placed on the receipt of any new fuel oil. TXU stated that limiting the ability of utilities to fire residual oils will limit the market for these fuels in Texas and could result in the fuels being combusted by sources that would have a higher impact on the public because of the location and height of the emissions. TXU also stated that prohibiting the burning of Number 5 fuel oil could impact winter reliability if natural gas is curtailed before a conversion to Number 2 oil can be accomplished. TXU stated that it would cost them $30 million to $40 million to convert 14 facilities from firing Number 5 fuel oil to firing Number 2 fuel oil with the majority of the cost being to change out the fuel.

The proposed rule established ASTM Grade Number 2 fuel oil containing not more than 0.3% sulfur by weight as acceptable. The commission stated in the preamble to the proposed rule that staff was continuing to analyze other fuel oil grades and refine the modeling analysis. As a result of this additional analysis of the effects of burning fuel oil in grandfathered EGFs and in order to address all of the comments on the burning of fuel oil, the commission changed the proposed definition of "Natural gas-fired EGF" in §116.18(11) to simply state that for purposes of Subchapter I, a natural gas- fired EGF is, "an EGF that was designed to burn either natural gas or an EGF that was designed to burn both natural gas and fuel oil." The conditions governing the burning of fuel oil at grandfathered EGFs have been added as general conditions §116.913(a)(8) and (9).

The commission has determined that any ASTM grade of fuel oil with a sulfur content of 0.7% by weight or less is acceptable, except in areas where sulfur content is limited further by Chapter 112. This limitation has been added to the general conditions in §116.913. The modeling analysis for SO2 concluded that there will not be any exceedances of the NAAQS or state standards in Chapter 112. Metals have been identified as the primary hazardous air pollutant associated with the burning of fuel oil. Adverse impacts from metals are caused by long term exposure to unacceptable levels of emissions. The commission does not expect long term exposure to metals emissions because fuel oil is only burned for short periods of time due to natural gas curtailments or extremely high natural gas prices. Historical data has shown that these curtailments and high natural gas prices have occurred infrequently and last only for short periods of time. Thus, the commission does not expect any adverse health effects associated with the burning of fuel oil. However, the commission has added a general condition to §116.913 requiring the EGF to keep records of fuel oil burning and submit those records with the report required under §101.336(b). In addition, EPA is developing a MACT standard which is expected to address emissions of metals, primarily nickel, from fuel oil fired EGFs. Any EGF which burns fuel oil for any extended period of time would likely be subject to this MACT standard. The commission has also added language in §116.913(a)(8) that clarifies that the burning of waste or used oils is not authorized under Subchapter I.

EPA recommended adding "as determined by ASTM method D396" to the end of the sentence in §116.18(11)(a) which reads "American Society for Testing and Materials (ASTM) grade number 1 or 2 fuel oil containing not more than 0.3% sulfur by weight."

The commission has made the suggested addition to the condition contained in §116.913(a)(8).

TCE and DAR/BSA commented that the commission should review mercury emissions from grandfathered facilities. Additionally, TCE commented that the commission should review all the pollutants from grandfathered power plants, including five-minute exposure to sulfur compounds. TCE stated that they were concerned about places where people congregate in close proximity to power plants and the effects of power plants on waterways that are far from the facility. DAR/BSA also expressed concern regarding lead emissions, and commented that this rulemaking would be a good opportunity to obtain lower emissions of mercury and lead.

The commission has made no change in response to these comments. Mercury has been raised by many organizations across the country as an air contaminant of concern for coal-fired power plants. However, there are significant technical and policy questions which need to be answered before a comprehensive strategy to handle mercury emissions from EGFs can be fully developed. Mercury emissions associated with these units will be addressed in the future by the President's Clear Skies Initiative multi-pollutant strategy and/or a MACT standard under development by the EPA. Accordingly, without downplaying the important issues with respect to mercury, the commission considers it prudent to review the outcomes of the Clear Skies Initiative and the utility MACT before making further decisions about regulation of mercury from EGFs in Texas.

Coal-fired EGFs can apply for an EGF permit for the criteria pollutants not addressed by SB 7, and once they obtain this EGF permit, they are no longer considered grandfathered facilities. The commission notes that lead is a criteria pollutant; therefore, these EGFs will have to address any lead emissions in the EGF permit application.

The commission agrees that numerous studies have shown that five-minute exposure to bursts of SO ₂ can cause individuals with asthma to experience respiratory effects due to bronchial constriction. In fact, the EPA has a proposed intervention level for SO ₂ of 600 parts per billion (ppb) (five-minute averaging period), above which asthmatics may experience shortness of breath, chest tightness, wheezing, and disruption of normal activities. While the NAAQS is not protective of these five-minute bursts, the Chapter 112 standard for SO ₂ , 30- minute average net ground level concentration of 400 ppb, helps to minimize the potential occurrence of five-minute concentrations greater than 600 ppb. Therefore, the commission notes that the required demonstration of compliance with the Chapter 112 standard would alleviate five-minute SO2 concerns.

Subchapter A. DEFINITIONS