The Texas Natural Resource Conservation Commission (commission) adopts new §116.16, concerning Voluntary Emission Reduction Permit Definitions; §116.810, concerning Eligibility; §116.811, concerning Voluntary Emission Reduction Permit Application; §116.812, concerning Project Emission Reduction Credits; §116.813, concerning Application Review Schedule; §116.814, concerning General and Special Conditions; §116.816, concerning Deferral of Emission Reductions; §116.820, concerning Modifications; §116.840, concerning Public Participation for Initial Issuance; §116.841, concerning Notice and Comment Hearings for Initial Issuance; §116.842, concerning Notice of Final Action; §116.850, concerning Voluntary Emission Reduction Permit Application Fee; §116.860, concerning Voluntary Emission Reduction Permit Renewal; and §116.870, concerning Delegation. These new sections implement those portions of Senate Bill (SB) 766, 76th Legislature, 1999, that require the commission to create a voluntary emission reduction permit (VERP) program. These new sections will be placed in a new Subchapter H, concerning Voluntary Emission Reduction Permit.

The commission also adopts new §116.601, concerning Types of Standard Permits; §116.602, concerning Issuance of Standard Permits; §116.603, concerning Public Participation in Issuance of Standard Permits; §116.604, concerning Duration and Renewal of Registrations to Use Standard Permits; §116.605, concerning Standard Permit Amendment and Revocation; §116.606, concerning Delegation; and amendments to §116.610, concerning Applicability; §116.611, concerning Registration to use a Standard Permit; and §116.614, concerning Standard Permit Fees. These new sections and amendments implement those portions of SB 766 that authorize the commission to issue standard permits. The commission also intends §§116.601-116.605, 116.610, 116.611, and 116.614 to be revisions to the state implementation plan (SIP).

Sections 116.16, 116.601, 116.603, 116.604, 116.605, 116.614, 116.810, 116.811, 116.812, 116.816, 116.840, 116.842, and 116.850 are adopted with changes to the proposed text as published in the September 10, 1999 issue of the Texas Register (24 TexReg 7148). The remaining sections are adopted without changes and will not be republished.

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES CONCERNING VERPS

During the 75th legislative session in 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 amended 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 have not been modified, they continue to be authorized to operate without a permit. Beginning in the early 1990s, efforts were made to develop concepts and provide incentives to bring grandfathered facilities into the permit program. 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 the legislative directive in HB 3019, the commission appointed an 11-member advisory panel to provide recommendations regarding the criteria for a voluntary emission reductions plan for grandfathered facilities. This committee, the Clean Air Responsibility Enterprise (CARE) Committee, consisted of representatives from local governments, the environmental community, and industry groups, and met several times in the fall of 1997 to provide the commission with recommendations. Those recommendations were presented to the commission at the December 18, 1997, Commissioner's Work Session. The commission held several hearings to obtain comments on the recommendations made by the CARE committee and received comments from the public and industry groups.

In order to implement the recommendations of the CARE committee and the requirements of HB 3019, the 76th Legislature passed SB 766 in 1999. In general, SB 766 recategorizes the new source review authorizations under the TCAA and creates the new program for the voluntary permitting of grandfathered facilities. Prior to the revisions by SB 766, the TCAA authorized the commission to issue permits for the construction or modification of facilities that will emit air contaminants; standard permits adopted by rule; and exemptions from permitting, also adopted by rule. SB 766 modified this structure by authorizing the commission to issue standard permits using a process that does not require each standard permit to be in a rule. A new authorization--permits by rule--was created for the construction of certain types of insignificant facilities. Exemptions from permitting now authorize only changes at insignificant facilities. Finally, the commission is now authorized to develop criteria for facilities that emit a de minimis amount of air contaminants that do not need preconstruction authorization. Within the category of permits, SB 766 created two new permitting options: the VERP program for permitting of grandfathered facilities, and the multiple plant permit. As a part of the VERP program and with this adoption, the commission is creating an emission reduction credit program for use by grandfathered facilities that are unable to meet the control method requirements of the VERP program.

SB 766 also provided several incentives for grandfathered facilities to apply for a permit under the VERP program. Section 11 of the bill provides that not later than January 15, 2001, the commission shall prepare a report on the number of companies that have obtained or applied for a VERP and the reductions in emissions anticipated. The report shall be submitted to the governor, the lieutenant governor, the speaker of the House of Representatives, the chair of the Senate Committee on Natural Resources, and the chair of the House Committee on Environmental Regulation. Section 12 of the bill states that the commission may not initiate an enforcement action against a person for the failure to obtain a preconstruction permit under TCAA, §382.0518, concerning Preconstruction Permit, or a rule adopted or order issued by the commission under that section, that is related to the modification of a facility that may emit air contaminants if, on or before August 31, 2001, the person files an application for a VERP. Section 12 does not apply to an act related to the modification of a facility that occurs after March 1, 1999. The bill also amended TCAA, §382.0621(d) to require increasing emission fees for the largest grandfathered facilities which do not participate in the VERP program by the dates established. The fee increases will be proposed in rulemaking scheduled for February 2000.

This adoption implements two of the new requirements of SB 766, the VERP program and the new process for issuing standard permits. The authority for the VERP program is in TCAA, §382.0519, concerning Voluntary Emissions Reduction Permit; §382.05191, concerning Voluntary Emissions Reduction Permit: Notice and Hearing; §382.05192, concerning Review and Renewal of Voluntary Emissions Reduction Permit; and §382.05193, concerning Emissions Permits Through Emissions Reduction. The new process for issuance of standard permits is authorized by TCAA, §382.05195, concerning Standard Permit. The remaining elements of SB 766, including emissions fees, multiple plant permits, permits by rule, and de minimis criteria, will be addressed in rulemaking scheduled for proposal in February 2000.

This adoption provides a significant amount of flexibility to owners and operators of grandfathered facilities to voluntarily make cost-effective emissions reductions. Applications for a VERP are voluntary and applicants must demonstrate the ability to meet flexible control options not available to new permitted facilities. For a grandfathered facility to be eligible for a VERP, an application must be submitted before September 1, 2001.

SECTION BY SECTION DESCRIPTION

The new §116.16 defines "airshed." For grandfathered facilities in a nonattainment area, an airshed is defined as the nonattainment area in which it is located. Nonattainment areas are geographic areas which exceed a National Ambient Air Quality Standard (NAAQS). Nonattainment areas are defined in §101.1, concerning Definitions. For facilities in attainment areas, the airshed is defined as the East Texas Region or the West Texas Region, or El Paso County. The East Texas Region and the West Texas Region are defined in a concurrent adoption concerning Chapter 101 in this issue of the Texas Register for implementation of certain provisions of SB 7, 76th Legislature, 1999, concerning Emissions Banking and Trading of Allowances for Grandfathered Electric Generating Facilities.

The requirements applicable to VERPs are placed in a new Subchapter H of Chapter 116. Consistent with TCAA, §382.0519(a), the new §116.810 requires VERP applications to be submitted before September 1, 2001. The adoption requires that applications be submitted under the seal of a Texas licensed professional engineer, if required under §116.110(e). The owner--or one authorized to act for the owner--of a facility, group of facilities, or account is responsible for compliance with the requirements of Subchapter H.

The new §116.811 describes VERP application requirements, and states that emissions from the grandfathered facility issued a VERP will comply with the intent of the TCAA. TCAA, §382.0519(c), provides that the commission may not issue a VERP if it finds that the emissions from the grandfathered facility will not meet the control methods specified in TCAA, §382.0519(b), or will not be protective of public health and property. The requirement to protect physical health and property is included in §116.811(1). Because of these requirements, the commission will conduct a health effects review for each VERP application. The majority of the CARE Committee recommended that a company seeking a VERP should be required to undergo an abbreviated health effects review, as appropriate. A minority report of the CARE Committee also contained recommendations regarding health effects reviews and they are summarized in the Analysis of Testimony in this preamble.

If an applicant proposes an allowable emission rate which represents a reduction in actual emissions from the highest rate emitted over the prior three years, an abbreviated health effects review would automatically be performed. If there are proposed allowable emissions higher than the highest rate emitted over the prior three years, the commission will consider other factors when determining if an abbreviated health effects review is appropriate. Those factors include: whether best available control technology (BACT) is being proposed; whether the controls required by the VERP program are already being used; the proximity of the nearest off-property receptor; whether any monitoring data exists which indicates that no adverse off-property impacts will occur; whether the applicant proposes to use fenceline or stack monitoring technology to demonstrate ongoing protection of public health; and whether emissions reductions should be determined from emission rates over other representative periods. The commission believes that this approach will protect public health and provide incentives for reductions in emissions from the 1997 survey of grandfathered facilities. If the commission determines that an abbreviated health effects review is not appropriate, a routine health effects review will be done consistent with the commission's Technical Guidance Package concerning Modeling and Effects Review Applicability (RG-324, August 1998). Copies of this document are available from the commission's Office of Permitting, Remediation, and Registration. The VERP may also have provisions for the measurement of air contaminants, including installation of sampling ports and platforms, portable analyzers, or emission calculations.

Section 116.811(3) implements the control requirements and emission reduction options consistent with TCAA, §382.0519(b). Generally, the facility must be able to use 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 for permitting 120 months prior to an application for a VERP (ten-year-old BACT), considering the age and remaining useful life of the facility. A nonattainment area is a geographic area of the state where monitored air contaminant levels are in excess of a NAAQS. Facilities located in a nonattainment or near-nonattainment area for a criteria pollutant must use the more stringent of either ten-year-old BACT or a control technology that the commission finds is generally achievable for facilities in the same area and of the same type permitted by a VERP, considering the age and remaining useful life of the facility. Solely for the purposes of the VERP program, the commission lists the following attainment counties as near-nonattainment areas for ozone: Bexar, Gregg, Harrison, Nueces, Smith, Travis, and Victoria. These counties are derived from HB 1, Article VI, §13, 76th Legislature, 1999 (the General Appropriations Act), which allocates funding for air quality planning activities in the following areas considered to be near-nonattainment for the ozone standards under the Federal Clean Air Act Amendments of 1990: Austin, Corpus Christi, Longview-Tyler-Marshall, San Antonio, and Victoria. In order to provide for a consistent starting point for determining what constitutes GACT, the commission will use the first-tier of BACT (i.e., the control technology used by a representative number of identical facilities). The stringency of GACT may be adjusted, as necessary, according to the area in which the facility is located and considering the age and remaining useful life of the facility. This method should provide for GACT determinations which are as consistent as possible. Consistent with TCAA, §382.0519(e), the new §116.816 authorizes the commission to defer required emission reductions if certain conditions are met. In addition, §116.811 provides that if an owner or operator of a grandfathered facility is unable to make the reductions required to obtain a VERP, they may meet the requirements by acquiring project emission reduction credits (PERCs) under the program in the new §116.812.

In order to be consistent with the current review process for permits and applicable federal requirements, §116.811 requires grandfathered facilities applying for VERPs to be able to demonstrate compliance with applicable federal New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPS). 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 Subchapter B of Chapter 116. 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 VERP applications. If a routine health effects review is required, the facility may be required to submit air dispersion modeling. The VERP application would identify each facility to be included in the VERP, identify the air contaminants emitted, and provide emission rate calculations, propose a control method, and identify the date by which the control method will be implemented.

The new §116.812 establishes procedures and conditions under which PERCs may be obtained. PERCs must result in emission reductions in the airshed in which the grandfathered facility is located. The PERCs must provide reductions comparable to the reductions that would be achieved through ten-year-old BACT or GACT, and the reductions must be made from one or more facilities in Texas.

The new §116.812 provides a list of qualifying emission reduction projects that includes, but is not limited to, generation of electric energy by a low-emission method (wind, biomass gasification, and solar power), the purchase and destruction of high-emission automobiles or other mobile sources, the reduction of emissions from a permitted facility that emits air contaminants to a level significantly below the levels necessary to comply with the facility's permit, a carpooling or alternative transportation program for the owner's or operator's employees, telecommuting for the owner's or operator's employees, or switching of a motor vehicle fleet operated by the owner or operator to a lower-sulfur fuel than required or an alternative fuel approved by the commission. Facilities must provide specific information in applications for a VERP concerning any proposal to use the qualifying emission reduction projects for the creation of PERCs. The commission will provide guidance, as needed, for the implementation of this program, including qualification of credits.

Section 116.812 also requires that applications for VERPs with PERCs demonstrate that the emission reductions will be permanent, quantifiable, enforceable by the commission, real reductions in actual emissions, and not be required of a facility by a state or federal law, regulation, or agreed order.

These requirements are generally accepted for creation of emission reduction credits and are used in the commission's existing emissions credit banking and trading program. Credits under the PERC program are not transferable consistent with TCAA, §382.05193(f). A VERP that authorizes a PERC will contain specific conditions that require the successful completion of the project. This will ensure that the anticipated emissions reductions actually occur in a reasonable amount of time.

The new §116.813 requires the commission to process VERP applications under §116.114, concerning Application Review Schedule, and as required by TCAA, §382.0519(f), to give priority to processing VERP applications for grandfathered facilities located less than two miles from schools, day care centers, nursing homes, or hospitals. The new §116.814 allows the commission to include general and special conditions within the VERP and requires holders of VERPs to comply with the general and special conditions contained in §116.115, concerning General and Special Conditions.

The new §116.816 implements the provisions of TCAA, §382.0519(e), and authorizes the commission to issue permits that defer reductions in emissions of certain air contaminants only if the applicant will make substantial reductions in other specific air contaminants based on a prioritization of contaminants considering local, regional, and state air quality needs. The legislature intended very limited use of deferrals. An applicant must clearly document that exceptional economic hardship or specific technical impracticability problems are a barrier to implementing the reductions required by a VERP (SB 766-Statement of Legislative Intent Adoption of Conference Committee Report). When prioritizing air quality needs to determine whether to grant a deferral, the commission proposes to consider: the location of the grandfathered facility; the size of the reduction of emissions of other specific air contaminants and whether the reductions are in addition to the reductions that are required for other specific air contaminants by §116.811(3); the impact of the reduction of emissions of other specific air contaminants and the deferral on attaining NAAQS; anticipated state or federal regulations that may require reductions of the air contaminants being deferred; and the benefit to public health from the reduction of other specific air contaminants versus the deferral. As a point of clarification, deferrals are intended for grandfathered facilities which cannot meet the control requirements of the VERP program due to exceptional economic hardship or specific technical impracticability problems, as stated earlier. Applicants will not have to apply for a deferral in order to phase in controls required under the VERP program.

The new §116.820 would require that modifications of grandfathered facilities permitted under VERPs must comply with Subchapter B of Chapter 116. In other words, once a VERP has been issued, existing requirements for amending or altering permits under Subchapter B of Chapter 116 are applicable. This section implements the requirements of TCAA, §382.0519(d).

The new §116.840 requires applicants for initial issuance of a VERP to publish notice of intent to obtain a permit in accordance with Chapter 39, Subchapter H of this title, concerning Applicability and General Provisions, and Subchapter K of this title, concerning Public Notice of Air Quality Applications. Subchapters H and K implement the new requirements of TCAA, §382.056, as amended by the 76th Legislature by HB 801. Subchapter K also includes alternative means of notice for small businesses, as required by TCAA, §382.05191(b). TCAA, §382.05191 provides that public participation for initial issuance of a VERP 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 respond to comments and send notice of final action to persons who comment during the comment period or during a hearing. The requirements of §§116.840-116.842 are based on the sections in 30 TAC Chapter 122, concerning Federal Operating Permits, that implement the requirements of TCAA, §382.0561 and §382.0562. Section 116.840 provides that any person who may be affected by emissions from the grandfathered facility may request a notice and comment hearing on a VERP application within 30 days after the publication of notice under 30 TAC §39.418, concerning Notice of Receipt of Application and Intent to Obtain Permit. Persons affected by a decision to issue or deny a VERP may seek review as appropriate under 30 TAC Chapter 50, concerning Action on Applications and Other Authorizations and may seek judicial review under TCAA, §382.032, concerning Appeal of Commission Action.

The new §116.841 contains the hearing requirements for the initial issuance of VERPs. The rule allows the commission to decide whether to hold a hearing based on the reasonableness of a request. The commission is not required to hold a hearing if the basis of the request by a person who may be affected by emissions from a grandfathered facility is determined to be unreasonable. If a hearing is requested by a person who may be affected by emissions from a grandfathered facility, and that request is reasonable, the commission will hold a notice and comment hearing. This section requires that notice of hearing on a draft permit be published in the public notice section of one issue of a newspaper of general circulation in the municipality where the grandfathered facility is located or in the nearest municipality. The notice must be published at least 30 days prior to a hearing. The notice is published at the applicant's expense, and the rule specifies the content of the notice. The rule provides the procedures for the submission of comments at a hearing and specifically states that the period for submitting written comments extends to the close of the hearing and may be extended beyond the close of the hearing. Any person, including the applicant, may submit comments on whether the draft permit contains inappropriate conditions or whether the preliminary decision to issue or deny the VERP is inappropriate. Commenters shall raise all issues and submit all comments supporting their position by the end of the public comment period. This requirement will assist the commission in developing its response to comments as required by the new §116.842. To ensure a complete record of the comments, the rule prohibits the incorporation by reference of supporting materials for comments unless the materials meet the criteria in §116.842(g). The commission is required to keep a record of all comments submitted or raised at a hearing and to have an audio recording or written transcript of the hearing. The record is available to the public. Draft permits may be revised based on comments pertaining to whether the permit provides for compliance with the requirements of a VERP.

The new §116.842 would 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 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 may seek judicial review. The notice must also state that persons affected by a decision to issue or deny a VERP may seek review as appropriate under 30 TAC Chapter 50, concerning Action on Applications and Other Authorizations and may seek judicial review under TCAA, §382.032, concerning Appeal of Commission Action.

The new §116.850 requires a permit fee from VERP applicants. The amount of the application fee would vary based on the level of control, a factor that directly affects the amount of commission resources needed to review an application. Applicants who propose controls at least as stringent as ten-year-old BACT or GACT under §116.811(3)(A) and (B) would remit a flat fee of $450. The fee for ten-year-old BACT or GACT is appropriate, since determining the level of control due to the age and remaining useful life of the facility can involve extensive resources. Since GACT is a new standard for controls, the commission anticipates that this determination will require extended staff and management time. The maximum fee for a VERP for a small business, as defined in the Federal Clean Air Act (FCAA), §507(c), shall be $100, if the grandfathered facility will use a control method at least as stringent as those defined in §116.811(3)(A) or (B). Applicants proposing to defer emission reductions or to use PERCs would remit a fee of $1,000. The commission expects that extensive staff time will be required to verify the conditions of deferrals and to validate PERCs. If an applicant for a VERP at an account proposes to include more than one grandfathered facility in the VERP, the highest applicable fee would apply. However, only one fee per VERP would be required.

The new §116.860 implements the requirements of TCAA, §382.05192, which requires the renewal of a VERP in accordance with Chapter 116, Subchapter D, concerning Permit Renewals. TCAA, §382.05193(e) adds specific requirements to be considered in the renewal of a VERP that was issued based on emission credits under §116.818. To renew such a VERP, the facility owner shall have made the equipment improvements or emissions reductions necessary to meet the requirements of §116.811(3), or acquire additional credits under the program, as necessary, to meet the permit requirements.

The new §116.870 states that the commission may delegate to the executive director any action regarding a VERP. This delegation is authorized by TCAA, §382.061, which allows the commission to delegate to the executive director the powers and duties under TCAA, §§382.051-382.0563, and Texas Water Code, §5.122, which authorizes the commission to delegate uncontested matters to the executive director.

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES CONCERNING STANDARD PERMITS

SB 766 created a new process for the development and issuance of standard permits. A standard permit is applicable to new or existing similar facilities. Prior to the amendments by SB 766, standard permits were required to be developed under the rulemaking procedures of the Administrative Procedure Act. Prior to this adoption, the commission adopted standard permits under §116.617, concerning Standard Permits for Pollution Control Projects; §116.620, concerning Installation and/or Modification of Oil and Gas Facilities; and §116.621, concerning Municipal Solid Waste Landfills. The new procedures authorized by TCAA, §382.05195 required the commission to establish the criteria for issuing and amending a standard permit. The actual standard permits are no longer required to be adopted by rule. "Issuing" in this case means that the commission has developed a standard permit and made it available for use by similar facilities. This process is similar to that used for the development of general permits under the Texas Water Code. Consistent with current practice, the executive director will continue to approve registrations to use the commission-issued standard permits. The new process requires public notice, an opportunity for a public meeting, and a response to comments that is similar to the process used for rulemaking. The benefit of this new process is that it allows the standard permits to be issued and amended in an efficient manner without sacrificing public input. In addition, the process will allow the commission to quickly develop and seek comment on proposed standard permits which will benefit affected facilities as well as the public, since facilities choosing to construct under a standard permit will be limited by the conditions of the permit. Throughout the preamble and the adopted rules concerning standard permits, the existing standard permits that were developed by rule are referred to as standard permits "adopted" by the commission, while standard permits that will be developed under the new process are referred to as standard permits "issued" by the commission.

SECTION BY SECTION DISCUSSION

The new §116.601 categorizes a standard permit as one either adopted as a rule or those issued by the commission under the procedures of the new §116.603. The section includes procedures to ensure that currently-authorized facilities continue to be covered by a standard permit if an existing standard permit adopted by the commission is repealed and replaced with no changes by a standard permit issued under the new procedures. Existing registrations for the repealed permit would be automatically converted as long as the facility continues to meet the requirements.

SB 766 made a significant revision to the existing process for continued operation under a standard permit. Prior to these amendments, if a facility was authorized by a standard permit and that standard permit was revised, the facility could continue to operate under the version by which it was authorized. TCAA, §382.05195(f) specifically requires facilities authorized by a standard permit to comply with amendments to a standard permit within certain time periods. To be consistent with those requirements, the commission will now require existing standard permit holders to register and comply with the standard permit, as amended. If a standard permit adopted by the commission is repealed and replaced with a standard permit issued by the commission, and the requirements of the standard permit are changed in the process, then existing registrations will be invalidated. The facility would have to be registered under the issued standard permit by the later of either the deadline established by the commission in the issued standard permit, or the tenth anniversary of the original registration. Holders of registrations not wishing to register for the issued standard permit will have the option of applying for or qualifying for other applicable permits or exemptions from permitting.

The commission will notify, in writing, all holders of existing registrations of the date by which a new registration must be submitted. All registrations, new and existing, will be renewed according to the requirements of the new §116.604. SB 766 requires registrations to use a standard permit to be renewed. To be consistent, it is appropriate for all registrations, including those approved under the existing adopted standard permits, to be renewed.

The new §116.602 establishes the conditions under which the commission may issue a standard permit. The standard permit must be enforceable, and the commission must be able to adequately monitor compliance. Generally, facilities authorized under standard permits must use current BACT. There are two exceptions to this requirement. TCAA, §382.057 provides for a standard permit to authorize emission reduction projects that constitute reasonably available control technology under the rules adopted as part of the SIP. TCAA, §382.05195(a)(3) provides that a standard permit for grandfathered facilities applied for before September 1, 2001 is not required to meet BACT.

The new §116.603 establishes the requirements of public participation to be satisfied prior to the issuance by the commission of a standard permit. The section establishes geographic coverage for newspaper publication by the commission of proposed standard permits. The rule requires the commission to publish notice of standard permits that will have statewide applicability in a daily newspaper of largest general circulation within each of the following metropolitan areas: Amarillo, Austin, Corpus Christi, Dallas, El Paso, Houston, the Lower Rio Grande Valley, Lubbock, the Permian Basin, San Antonio, and Tyler. Notice of standard permits that affect a limited area will be published in a daily or weekly newspaper of general circulation in that area. The commission will also publish notice of all proposed standard permits in the Texas Register . The commission is required to publish newspaper notice of a proposed standard permit in accordance with 30 TAC §39.411, concerning Text of Public Notice, and will include an invitation for public comment with a comment period of at least 30 days. The commission is required to hold a public meeting to provide additional opportunity for public comment and to respond to any comments at the time the commission issues or denies the standard permit. A copy of the commission's response will be mailed to each person who made a comment. A notice of the commission's final action and the text of its response to comments would be published in the Texas Register . Copies of issued permits and responses to comments would be available for inspection at the commission's Office of Permitting, Remediation, and Registration in Austin and at the appropriate regional offices. The commission believes that these procedures will provide ample opportunity for public input into the development and issuance of standard permits.

The new §116.604 establishes the duration of a registration to use a standard permit as a term not to exceed ten years. The rule requires that the registrations be renewed by the date the registration expires. The commission will send notice of the renewal deadline to standard permit holders at least 180 days prior to expiration of the registration. Instead of requiring permit holders to submit registrations for renewal, the commission may automatically renew the registration. For example, if the standard permit is relatively simple or if no state or federal requirements have changed for that industry, it may be a more efficient use of commission and industry resources to allow the commission to automatically renew the registration. The section also provides requirements governing the renewal of registration to use standard permits.

The new §116.605 establishes the procedures for commission amendment or revocation of issued standard permits. Standard permits would remain in effect until amended or revoked. The commission will be able to amend or revoke standard permits after providing notice in the Texas Register and newspapers in areas affected by the standard permit, or in Austin, Dallas, and Houston if the standard permit has statewide applicability. The commission will also provide written notice to registrants and any persons requesting to be on a mailing list concerning a specific standard permit. The commission believes that these notice requirements are appropriate, since amendments to standard permits would likely be as stringent, or more stringent, than the existing standard permits. Similarly, in the unlikely event that a standard permit is revoked, it will probably be replaced with another standard permit, and affected registrants will be given individual notice.

The commission may add or delete requirements through amendment of a standard permit. The following criteria will be used by the commission to determine whether or not to amend or revoke a standard permit: whether a condition of air pollution exists; the applicability of other state or federal standards that apply or will apply to the types of facilities covered by the standard permit; requests from the regulated community or the public to amend or revoke a standard permit consistent with the requirements of the TCAA; and whether the standard permit requires BACT. The commission believes that adhering to these criteria will harmonize implementation of state and federal requirements as well as providing a measure of certainty for the regulated community. Consistent with TCAA, §382.05195(f), facilities choosing to retain standard permit authorization would be required to comply with the amendments on the later of either the deadline of the original registration renewal date or on a date otherwise provided by the commission in the amended standard permit. The commission will not require compliance with an amended standard permit earlier than 24 months after an amendment unless it is necessary to protect public health. However, standard permit registrants must still comply with changes in other state or federal requirements within the time frames stated in those requirements. Facilities may be required to register to use the amended standard permit, or if the amendments are minor, the commission may defer reregistration requirements until the original renewal date for the registration. If the commission revokes a standard permit, it will provide written notice to registrants of the revocation and inform them that other authorization must be sought. As provided by TCAA, §382.05195(g), the issuance, amendment, or revocation of a standard permit, or the issuance, renewal, or revocation of a registration to use a standard permit is not subject to Texas Government Code, Chapter 2001.

The new §116.606 states that the commission may delegate any authority in Subchapter F to the executive director. This delegation is authorized by TCAA, §382.061, which allows the commission to delegate to the executive director the powers and duties under TCAA, §§382.051-382.0563, and Texas Water Code, §5.122, which authorizes the commission to delegate uncontested matters to the executive director. The commission is not delegating the authority to issue standard permits at this time. The executive director is already authorized to approve registrations under §116.611, concerning Registration to Use a Standard Permit.

The current §116.610 contains general requirements for meeting state and federal emission limitations as conditions for entitlement to standard permits currently existing and adopted into this subchapter. The adopted amendment to §116.610 would require facilities to meet these general requirements as conditions for operation under standard permits issued by the commission as a result of this adoption. In addition, §116.610(a)(6) is deleted, since the requirement to register is stated in the new §116.604.

The amendment to §116.611 clarifies that registrations on form PI-1s are registrations to use a particular standard permit. The name of the section has been changed.

Section 116.614 is amended to clarify that the commission may waive application fees for registrations to use specific standard permits and that persons may be required to register to use specific standard permits rather than simply claiming them. This section requires fees for registrations to use an amended standard permit, or to renew a registration to use a standard permit, unless waived by the commission, or when a standard permit is automatically renewed by the commission. This fee is consistent with the permit amendment and renewal process for permits for individual facilities under Chapter 116.

FINAL REGULATORY IMPACT ANALYSIS

The commission has reviewed the rulemaking in light of the regulatory analysis requirements of Texas Government Code, §2001.0225, and has determined that the rulemaking is not subject to §2001.0225 because it does not meet the definition of a "major environmental rule" as defined in that statute. "Major environmental rule" means a rule the specific intent of which is to protect the environment or reduce risks to human health from environmental exposure and that may adversely affect in a material way the economy, or a sector of the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state. The amendments for standard permits provide streamlined processes to issue and amend standard permits. The new requirements for registration to use standard permits and registration renewals will not adversely affect, in a material way, the economy, a sector of the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state. The new requirement to comply with amended standard permits is not expected to have an adverse effect because the proposed rules provide criteria to be used by the commission for determining when and if a standard permit should be amended. Permit holders would be given ample time to comply with the amended standard permit. Because the adopted amendments for a VERP are voluntary, they are not anticipated to adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state. In addition, the adopted amendments do not meet any of the four applicability requirements of a "major environmental rule." Specifically, the amendments will not impose any significant additional requirements not already required by state or federal law, and the amendments do not exceed a standard set by federal law, an express requirement of state law, or a requirement of a delegation agreement. In addition, these rules and amendments are adopted under a specific state law.

TAKINGS IMPACT ASSESSMENT

The commission has completed a takings impact assessment for the amendments and new sections. The following is a summary of that assessment. These amendments and new sections authorize the VERP program. The amendments also implement a new process for issuance and amendment to standard permits and the new requirements for registrations. If an owner or operator of a grandfathered facility chooses to participate in the VERP program, it is possible that controls may be required for the facility to meet the requirements of the program. As an alternative to controls, applicants can propose a project that will provide emission reductions in an amount needed to meet the control requirements. In limited circumstances, applicants can request a deferral of the permitting of certain air contaminants if other emissions are controlled. However, this is a voluntary action at the discretion of the owner. The new requirements for permit holders to comply with amended standard permits will provide ample time for facilities to comply with the amendments, if they choose to do so. These amendments do not affect private property in a manner that restricts or limits an owner's right to the property that would otherwise exist in the absence of the governmental action. Consequently, this adoption does not meet the definition of a takings under Texas Government Code, §2007.002(5). The reductions obtained from the issuance of VERPs will assist in the efforts of the commission to attain the NAAQS. This action is taken in response to a real and substantial threat to public health and safety, and significantly advances the health and safety purpose, and imposes no greater burden than is necessary to achieve the health and safety purpose.

COASTAL MANAGEMENT PROGRAM CONSISTENCY REVIEW

The commission has determined that this rulemaking relates to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act of 1991, as amended (Texas Natural Resources Code, §§33.201 et seq.), and the commission's rules in 30 TAC Chapter 281, Subchapter B, concerning Consistency with Texas Coastal Management Program. As required by 31 TAC §505.11(b)(2) and 30 TAC §281.45(a)(3), relating to actions and rules subject to the CMP, commission rules governing air pollutant emissions must be consistent with the applicable goals and policies of the CMP. The commission has reviewed this action for consistency with the CMP goals and policies in accordance with the regulations of the Coastal Coordination Council. For the adopted amendments and new sections related to the authorization of VERPs, and the new process to issue standard permits, the commission has determined that the rules are consistent with the applicable CMP goal expressed in 31 TAC §501.12(1) of protecting and preserving the quality and values of coastal natural resource areas, and the policy in 31 TAC §501.14(q), which requires that the commission protect air quality in coastal areas. This adoption is intended to provide incentive to owners and operators of grandfathered facilities to make voluntary reductions. The adoption also allows the commission to issue standard permits using a streamlined and efficient process while still allowing for public participation. This action is consistent with 40 Code of Federal Regulations because it does not authorize an emission rate in excess of that specified by federal requirements.

PUBLIC HEARINGS AND COMMENTERS

The commission held public hearings on this adoption in El Paso and Lubbock on October 1, 1999, in Austin on October 4, in Irving on October 5, and in Houston and Beaumont on October 7, 1999.

The commission received comments from 28 individuals and the following organizations and companies: People Against Contaminated Environments (PACE), Bastrop County Environmental Network (BCEN), the Sierra Club (SC), Galveston-Houston Association for Smog Prevention (GHASP), Texas Campaign for the Environment (TCE), Tarrant Coalition for Environmental Awareness (TCEA), Texas Oil and Gas Association (TxOGA), Association of Texas Intrastate Natural Gas Pipelines (ATINGP), Mobil Corporation (Mobil), GPM Gas Services Company (GPM), Coastal Corporation (Coastal), BP Amoco, Environmental Defense Fund (EDF), Baker and Botts, L.L.P., on behalf of the Texas Industry Project (TIP), Clark and Seay, L.L.P. (C&S), Brown McCarroll and Oaks Hartline, L.L.P. (BMOH), Bracewell and Patterson, L.L.P. (B&P), Mothers for Clean Air (MCA), Neighbors for Neighbors (NFN), the League of Women Voters of Texas (LWV), the Texas Compliance Advisory Panel (CAP), Public Citizen (PC), Texas Renewable Power Coalition (TRPC), Sustainable Energy and Economic Development Coalition (SEED), the United States Environmental Protection Agency (EPA), the Texas Cotton Ginner's Association (TCGA), and the El Paso Energy Corporation (EPE).

The commission also received joint comments from the following state representatives: the Honorable Glen Maxey, District 51, Austin; the Honorable Lon Burnam, District 90, Fort Worth; the Honorable Dawnna Dukes, District 50, Austin; the Honorable Ruth Jones McClendon, District 120, San Antonio; and the Honorable Zeb Zbranek, District 20, Winnie.

ANALYSIS OF TESTIMONY

BCEN supported the comments of NFN, and GPM and Coastal supported the comments filed by TxOGA and TIP.

ATINGP commented that the commission should consider developing the rules for the multiple plant permit so that maximum flexibility in operations can be conducted between the covered facilities within the confines of the PSD program.

The commission agrees that rules for the multiple plant permit should provide flexibility as long as federal New Source Review (NSR) permitting programs are not triggered. The multiple plant permit provisions will be included in the second phase of rulemaking to implement the provisions of SB 766. The second phase rules are expected to be adopted in the second quarter of 2000.

One individual made several suggestions for how emissions could be reduced: school could be delayed to start after Labor Day when it is cooler; retail establishments could be closed on Sunday and Monday; the age for persons to obtain drivers licenses could be raised to take some cars off the road or persons without car insurance should be prohibited from driving; people should be required to buy insurance for six or 12-month periods; car inspection stations should be inspected to protect against fraud; busing of school children could be eliminated or the Dallas Area Rapid Transit buses should be used; teachers should be assigned to schools closest to their homes; the highways could be restructured to eliminate bottlenecks from four lanes when they merge into two or three lanes; cars from Mexico should be required to have a Texas inspection and insurance; limitations could be put on the use of fireplaces; IH-35 should be moved to the west and all trucks should be required to use IH-35 and the same for I-20; auto racing and drag racing strips should not allow the burning of fuels and car manufacturers should be required to have overdrive transmissions that activate at 55 miles per hour; Texas needs to withdraw its bid for the Olympics to cut down on traffic and flights; and the federal government should increase highway funding to cut down on traffic congestion.

These comments raise issues that are beyond the scope of this rulemaking. Therefore, the commission has not made any changes in response to the comments.

The EPA commented that it has serious concerns about the approvability of the amnesty section because it could be taken to include amnesty for federal sources. Since nothing is included in the rule, EPA requested that the commission explain how it intends to implement that provision of SB 766.

SB 766 does not provide amnesty for facilities which should have obtained a nonattainment NSR permit or a PSD permit. Chapter 116, Subchapter B already requires, as applicable, PSD or nonattainment review.

EDF commented that the commission should include in the rules a comprehensive review of all grandfathered facilities to analyze whether major modifications have been made at each facility. Amnesty is only an incentive if there is a real threat of penalties if the companies do not volunteer. The review must be completed by the end of the period for volunteering, or within a few months thereafter, and must be accompanied by a policy statement of the commission that proceedings to recover penalties from non-volunteering offenders will be instituted in the fall of 2001. Such a review and penalty program would turn the amnesty into a meaningful incentive. Without such an effort, the amnesty is a gratuitous gift to law-breaking free riders. Finally, EDF stated that the report should indicate how many grandfathered plants are affected by the potential of higher emission fees, in order to ascertain whether the emission fee provision constitutes a meaningful incentive.

The commission believes that the amnesty provision in SB 766 was meant to provide a nonthreatening process for encouraging companies to voluntarily permit grandfathered facilities. Therefore, the commission believes that the amnesty provision is a meaningful incentive as written and needs no enhancement. As a part of the VERP application review process, applicants must verify that they meet all federal requirements. If, during the course of the VERP application review, it is discovered that the facility modified under either the TCAA or the FCAA, then the appropriate permitting actions would be required. Because the rules already provide for compliance with federal requirements, the commission has not revised the rules in response to the comments. The commission will include information in the report to the legislature about how many grandfathered plants are affected by the potential of higher emission fees in accordance with TCAA, §382.0621(d).

The CAP commented that the commission must clarify the potential enforcement implications of making a voluntary permit application. This information should be summarized in outreach materials and made available to small businesses via numerous avenues, including industry associations. Many small businesses consider themselves to be grandfathered, but in actuality may not be.

The commission agrees, and will provide guidance concerning its interpretation of the amnesty provision.

BMOH commented that the commission should make clarification in the rules that the amnesty provision applies to any grandfathered facility which obtains a VERP or a standard permit, or explain why a standard permit does not qualify for amnesty.

If the commission creates a standard permit for similar grandfathered facilities for the purpose of meeting the requirements of TCAA, §382.0519, the commission agrees that the amnesty provision would apply to qualified registrants for that standard permit. The commission is not including the amnesty provision in this adoption. Therefore, the rules have not been revised in response to this comment.

TxOGA, GPM, Coastal, BP Amoco, and TIP requested that the commission include all actions to remove facilities from grandfathered status in the online report, "Progress in Permitting Grandfathered Sources," and in the legislative reports required by SB 766, including supplemental information and resulting emission reductions. This will more accurately demonstrate the true program effects by considering reductions made though other authorizations such as standard permits, exemptions from permitting, flexible permits, or NSR permits.

The commission agrees that any permit action that meets or exceeds the VERP program should be reflected in both reports, and will do so.

TIP added that the commission should consider developing a mechanism to identify companies which plan to apply for a VERP after January 15, 2001, but before September 1, 2001. One idea might be to allow companies to submit a kind of abbreviated application or commitment to file an application before September 1, 2001.

The commission agrees that a mechanism, such as an abbreviated application or commitment letter, should be made available in order to facilitate accurate reporting to the Legislature regarding the effectiveness of the VERP program. If, upon submission of the full application, the information provided by the facility has changed, the Legislature will be updated accordingly.

EDF commented that if it is to provide the right incentives to industry and useful information to the public and policymakers, the report should include: 1) the actual reductions, to date, versus promised reductions; 2) the consequences for failing to make the promised reductions; 3) the amount of promised reductions compared to the amount of reductions which would have been achieved if the facility had met current BACT; 4) the amount of promised and actual reductions in comparison to total emissions from grandfathered facilities; and 5) the amount of additional emission reductions that other facilities and automobile owners must make in nonattainment areas under SIPs as a result of the continued grandfathering of non-volunteering plants and the less stringent standards applicable to volunteering plants.

SB 766 requires the commission to submit, no later than January 15, 2001, to the governor, the lieutenant governor, the speaker of the house, the chair of the Senate Committee on Natural Resources, and the chair of the House Committee on Environmental Regulation, a report on the number of companies that have obtained or applied for a VERP, and the reductions in emissions anticipated to result. The commission agrees that emissions reductions and their comparison to total emissions from grandfathered facilities will be included in the report. The commission also agrees that the report should include the amount of grandfathered emissions from non-volunteers. The commission does not believe it is possible to include information about the consequences for failure to make promised reductions because the report is due before the application deadline. However, enforcement of any VERP condition will be done in the same manner as any other NSR permit condition. The commission also believes that it will require extensive agency resources to tabulate information about the amount of reductions that would have been achieved using BACT as opposed to the VERP controls, and therefore disagrees that this information should be included in the report.

The EPA commented that it understands that the commission will use emission reduction credits which occur under the VERP program to help demonstrate attainment and maintenance of the NAAQS, and that it further understands that reductions will not be used for offsets and netting under federal NSR. The commenter stated that if this understanding is not correct, the commission should explain how these rules will ensure attainment and maintenance of the NAAQS and show how the rules are consistent with the FCAA. A separate EPA commenter commented that if emission reduction credits created by VERPs are to be creditable in the commission's banking and trading rules, they would have to be surplus as defined in 40 Code of Federal Regulations 51.491 to prevent the double counting of emission reductions. TIP commented that the commission should not include the emission reductions that result from the VERP program in an attainment demonstration for an area without the prior consent of the company or companies that achieve the reductions. As is the case with the current NSR program, the company that achieves those emission reductions should be allowed to preserve them as emission netting credits or for trading. Circumstances may arise where the company and the commission can reach an agreement by which some of the emission reductions are applied to attainment demonstrations. BMOH commented that the commission should provide a detailed description of the implications that the VERP reductions will have on attainment demonstrations. It is uncertain as to whether it is commission's intention to make VERP emission reductions federally enforceable, and thus not creditable toward offsets and netting calculations in nonattainment permitting exercises.

The commission did not propose the VERP program as a SIP submittal, therefore, the commission cannot, in this adoption, commit the VERP reductions to the SIP. However, the commission may do so in a future SIP submittal or use a portion, or all, of the reductions in SIP attainment demonstration modeling. Since the VERP program is voluntary, it is understood that emission reductions created through the VERP program would be creditable for netting, offsetting, or trading until such time that a SIP submittal is made where they are used in SIP attainment demonstration modeling and are demonstrated to be a necessary component of the control strategy which demonstrates attainment of the NAAQS. Prior to that time, the commission will work with the interested parties, including affected companies and the EPA, to develop an appropriate strategy for maintaining the integrity of emission reduction credits and federal permitting programs, balanced with the need to demonstrate attainment of the NAAQS. The commission agrees with the EPA that emissions reductions cannot be double counted, i.e., used for the SIP and as offsets and netting for NSR purposes. The commission also agrees with the EPA that any emission reduction credits used in the banking and trading program would have to be surplus. The term "surplus" is defined in 30 TAC §101.29(25) to mean emission reductions not otherwise required of a source by a state or federal law, regulation, or agreed order.

Most of the 28 individuals commented negatively on the proposed rules concerning VERPs. Several individuals and organizations questioned the effectiveness of the VERP program. Eight individuals commented that the VERP program should be as strict as possible, with another individual and the TCEA commenting that the VERP program should be as protective of public health as possible. TCE commented that protecting public health is more important than protecting economically inefficient old facilities. Three individuals commented that the commission should enforce reduced emissions from grandfathered plants with four more adding that the results should be closely monitored and quantified.

GHASP commented that it has steadily opposed a voluntary permitting program, and expects to realize the pollution cleanup results the governor and the commission have assured would follow from a voluntary program.

The commission understands the concerns that exist due to the voluntary nature of the VERP program and the desire for reduced emissions from grandfathered facilities and the desire for protection of public health. The commission has attempted to address these concerns by crafting a program which is flexible enough to encourage a high rate of volunteers, with incentives for encouraging actual emission reductions, while maintaining responsible review of controls and health effects. Therefore, the commission expects the VERP program to result in many grandfathered facilities being permitted, and is committed to achieving a reduction in emissions and greater protection of public health. The commission also notes that the Legislature will be monitoring the effectiveness of the VERP program, and the commission intends to provide information which is useful to the legislature and to the public in evaluating the effectiveness of the VERP program as part of the report to the Legislature, due January 15, 2001.

The EPA commented that the term "grandfathered" is nowhere defined, making it unclear to which facilities the rules apply. Although §116.10 appears to contain a definition of "grandfathered facility," it actually defines only a "qualified" grandfathered facility and not a grandfathered facility itself.

Grandfathered facility is defined in §116.10(6). The EPA referred to §116.10(2)(C), a subparagraph of the definition of "Allowable emissions."

While reviewing the definition of "Airshed" in §116.16(1), the staff noted that the definition of "El Paso Region" in the referenced §101.330, which is being adopted in a concurrent rulemaking, had been expanded to include areas outside of this state. To retain the intent of "airshed" as proposed, and to be consistent with TCAA, §382.05193, which requires PERCs to be generated in the same "airshed" from sources " in this state," §116.16(1) was amended to refer to "El Paso County" instead of the "El Paso Region."

EPE commented that the commission should require submittal under the seal of a licensed professional engineer only on those projects exceeding a capital cost of $2 million, in accordance with 30 TAC §116.110. The commenter stated that this requirement imposes unnecessary costs and discourages voluntary participation.

The commission agrees with EPE that submittal of a VERP application under the seal of a licensed professional engineer should be done only in accordance with §116.110, which includes permits resulting in a capital cost of greater than $2 million. This was the intent of the proposed §116.810(b); however, the commission has reworded this section to clarify the intent.

TCGA commented that the total number of small business grandfathered facilities is significantly more than the 50 to 100 that the agency estimated in the Small Business Analysis of the preamble of the proposed rules. The commenter believes this since there are probably 50 to 100 grandfathered cotton gins alone.

In the proposal preamble, it was necessary for the commission to estimate the number of small business grandfathered facilities because many small businesses were below the reporting threshold for the 1997 Grandfathered Sources Survey and since no agency records exist for many of them. In making the estimate, the commission believed that most of the potential small business grandfathered facilities were authorized by one or more commission exemptions from permitting or permits by rule, and would therefore not participate in or be affected by the VERP program. While using the best information at its disposal to make the estimate, the commission anticipated and appreciates comments that will more accurately reflect the number of small business grandfathered facilities. Because the VERP program is voluntary, the commission does not believe that its estimate will adversely affect the small business community. The commission, through its Small Business and Environmental Assistance Office, will work with the CAP, small business advisory committees, and trade associations, etc., to notify and assist small businesses that wish to participate in the program.

The EPA commented that the terms "grandfathered" and "account" are not defined in §116.810(c), making applicability unclear.

The term "Grandfathered facility" is defined in §116.10(6). The term "Account" is defined in §101.1, concerning Definitions.

One individual commented that a health effects review should be mandatory. Thirteen individuals, C&S, GHASP, LWV, MCA, NFN, PC, TCE, and TCEA commented that the commission should require a full health effects review, and SC commented that the commission should not streamline health effects reviews out of existence. Three individuals and the organizations added that at the very least, a full health effects review should be performed for any plant within two miles of a school, nursing home, or day care center. One individual suggested a three-mile distance and included hospitals in the list, and GHASP suggested including in the list other centers where the population is known to be especially vulnerable to the effects of air pollution. MCA commented that a separate health effects review should be done for children, because they are at increased risk of suffering from air pollution because of their size, development, and exposure. One individual, C&S, LWV, NFN, PC, and TCEA commented that a health effects review should be performed for any facility not using BACT. PC added that it was never intended for the commission to waive health effects reviews for any less stringent control measures than BACT, and that a full health effects review should be waived only if an air dispersion study is presented to the commission that shows there are no harmful emissions based on monitoring of actual emissions at the fencelines or downwind. PC also commented that the commission should use its authority to ensure that monitors are put in place near schools, nursing homes, and daycare centers to assure no adverse health effects and that monitoring should be required at remote locations as well, since many emissions come from stacks high above fence lines and travel at high altitudes.

The commission has made no changes in response to these comments. The commission will conduct a health effects review for every VERP permit issued. The minimum health effects review that the commission would perform would be to determine the amount and type of emissions, the location of the nearest off-property receptor (not just schools, nursing homes, day care centers, etc.), and to consider any compliance history relevant to off-property impacts. A full health effects review could involve conducting refined air dispersion modeling to predict off-property ground-level concentrations at off-property receptors (not just schools, nursing homes, day care centers, etc.) and comparing them with commission effects screening levels. It is the commission's goal to improve air quality through the VERP program. It is not always necessary to perform a full health effects review to accomplish that goal or to ensure that public health is protected. The commission believes that actual reductions in emissions of air contaminants from grandfathered facilities reduces off-property impacts, and therefore warrants an abbreviated health effects review. The commission also believes that it is advantageous to bring grandfathered facilities into the permitting system to evaluate existing and proposed controls, and to set limitations on emissions from those facilities. Future modifications to a facility permitted under a VERP would require a permit amendment under the permitting procedures in Chapter 116, Subchapter B, meaning implementation of BACT and the appropriate health effects review. Therefore, it is appropriate to provide for an abbreviated health effects review when actual reductions result in improved air quality.

It is not appropriate to use BACT as the sole factor to determine what level of health effects review should be performed. Other factors, especially the amount and type of emissions, the location of off-property receptors, and compliance history relative to off-property impacts, may be more important in determining impact on public health. The commission does not see any connection in SB 766 between BACT and the discretion of the commission to prescribe the appropriate health effects review. TCAA, §382.0519(c) does not allow the commission to issue VERPs to facilities which are not protective of public health and physical property. This provision was based, in part, on the authority that the commission has in the NSR permitting program under TCAA, §382.0518 to do a health effects review. In both cases, the discretion is left to the commission to determine the appropriate level of health effects review that is needed. Concerning the specific comment, the commission agrees that monitoring showing no adverse impacts could be an appropriate mechanism for allowing an abbreviated health effects review.

Two individuals commented that the commission should study the effects, or the cumulative effects of grandfathered facilities. SEED commented that the commission should require a strict, cumulative health effects review and that simply reducing emissions is not the same as ensuring that public health is protected. SEED added that a health effects review should include a study of the cumulative impacts of various pollutants emitted by the plant seeking a permit, as well as those from surrounding plants, and that it is the obligation of the commission to consider these cumulative effects and ensure that emissions are reduced to levels demonstrated to be safe prior to granting a VERP. TCE commented that a health effects review should include an analysis of cumulative impacts from multiple sources and chemicals that contribute to background levels. One individual commented that the health effects review should include a study of secondary sources, and that the commission should publish the results.

The commission has made no changes in response to these comments. If an applicant proposes an allowable emission rate higher than the highest rate reported over the previous three years, the commission's health effects review procedures could result in plant-wide modeling. However, to require such an extensive analysis for every VERP would be inappropriate, especially when actual reductions are obtained. The commission believes that it will rarely, if ever, be appropriate to require plant-wide, or area-wide modeling as a requirement for obtaining a VERP. The VERP program is intended to permit individual grandfathered facilities. The goal of the commission through the VERP program is to obtain reductions in emissions from those facilities. The commission believes that computer air dispersion modeling should be a tool that is used generally for predicting impacts from new or modified facilities. When there are actual reductions from existing, grandfathered facilities, the off-property impacts will be reduced when compared to historic levels. Therefore, the commission believes that its proposal for health effects review, which varies in scope depending on whether or not actual reductions occur, will protect public health.

EDF commented that the commission should adopt the minority report of the CARE committee on health effects review. EDF also noted that the proposed preamble concerning health effects review gives the impression that the environmental representatives voted with the industry majority on when to have abbreviated health impact reviews, and that it ought to be corrected to accurately reflect how the committee split on this issue. In addition, the commenter stated that the use of the highest actual emissions in a three-year period as a trigger mechanism rewards high-polluting companies and companies with upsets, and that the commission's use of the highest level of pollution for any of the baselines may result in this grandfathered program resulting in increased emissions of pollution over the average for normal levels.

The commission did not intend to mischaracterize the opinion of the environmental representatives on the CARE Committee and has revised the preamble to reflect the existence of a minority report. The minority report mentioned health effects several times. It stated that medium and large grandfathered facilities that are at or close to BACT emission limits, have demonstrated good compliance history, and for which there is no record of citizen complaints in the area may obtain a simplified standard permit and recommended that the commission should retain the option to require a health effects review as appropriate. The report also contained a recommendation for a flexible permit and stated that the commission should conduct appropriate health effects modeling based on baseline emissions and projected decreases, taking into consideration the type of facility and emissions profile. The report also contained a statement that the commission must require cumulative health impact analysis at a site when granting permits where large quantities of toxic emissions are evident, or complaints from neighbors have occurred, and that the commission should give special attention to areas of concentrated industrial activity and conduct monitoring and modeling for cumulative impacts in response to citizen health concerns.

The commission believes that the criteria for conducting health effects review discussed in the preamble are largely consistent with the recommendations of the minority report, the major exceptions being: that the minority report seems to base the level of health effects review on whether or not BACT is used, and the report contains a recommendation for cumulative health impacts review. As stated previously, the commission believes that the primary consideration in determining the level of health effects review is reductions in emissions, although BACT would receive consideration.

The commission believes that using the highest actual emissions over the previous three years as a baseline for triggering an abbreviated health effects review is appropriate. One of the goals of the VERP program is to obtain reductions in actual emissions from the 1997 level. Using a three-year period as the trigger, instead of simply using the 1997 level, eliminates the argument that any given year is not representative of the emissions of a facility, and should provide a representative rate from which to measure reductions. Since this approach should result in reductions, the commission believes that using the highest actual rate over any of the previous three years as an abbreviated health effects review trigger would not result in increased emissions over normal levels.

The EPA commented that it understands §116.811(1) to include protection of the NAAQS and that the rule ensures that no VERP or PERC will cause or contribute to ambient air concentration of a pollutant in excess of a NAAQS and that it will be consistent with any SIP and associated control strategy which ensures the attainment and maintenance of the NAAQS.

Section 116.811(1) provides that emissions from grandfathered facilities will comply with all rules and regulations of the commission. That includes regulations which are intended to ensure compliance with the NAAQS.

EPE supported the abbreviated health effects review, stating that no benefit would be gained from requiring a full health effects review at facilities with no demonstrated adverse impacts, and that a full review would discourage participation in the VERP program. BP Amoco commented that an abbreviated health effects review is appropriate in most cases, considering that the facilities are existing, rather than new sources. BMOH supported the concept of a limited health effects review for grandfathered facilities unless there are documented confirmed health effects from the facility at the emission levels proposed in the permit. GPM commented that the proposed requirement for a health effects review if a facility increases emissions and/or if controls do not meet current BACT is inconsistent with the language of SB 766 and unmandated by any other statute.

TIP commented that no health effects review should be required if a facility has already implemented BACT. Mobil commented that if an applicant has already installed BACT, it will not affect off-site receptors, or has previously reduced emissions, then the commission should be able to accept an abbreviated health effects review. TIP commented that a reduced emission rate should not be the only trigger for an abbreviated health effects review, and that the commission should consider that these units are existing, rather than new, sources. Therefore, the commission should also consider: 1) past reductions in actual emissions since 1971; 2) proximity to the nearest off-property receptor; and 3) monitoring data which demonstrates no off-property impacts. TxOGA commented that the commission should expand the proposed guidelines for automatic qualification for abbreviated health effects review of VERP applications to encourage voluntary streamlined permitting of grandfathered facilities and not impose burdensome special requirements. TxOGA added that granting an automatic health effects review only to those facilities that decrease emissions is an unnecessarily stringent application of commission discretion, since the sources volunteering for permits have been operating for many years. TxOGA recommended the following guidelines for determining an automatic abbreviated health effects review: 1) no emissions increases relative to the highest emission rate for the last three years; 2) sources which are or will use BACT or MACT; and 3) sources which utilize adequate controls required by the VERP program, but still have emission increases for some contaminants related to operation of those controls.

Similarly, GPM supported an abbreviated health affects review provided that the commission takes into account the following factors: 1) no health effects review should be required if BACT or VERP controls are proposed; 2) actual reductions from 1991 to the present should be considered (companies need the opportunity to demonstrate that the last three years is not the best basis for estimating grandfathered emission rates); and 3) proximity to the nearest off-site receptors. Coastal and BP Amoco mirrored GPM, but commented instead that reductions made from 1971 to the present should be considered. Coastal also commented that the commission should perform an abbreviated health effects review on sources which utilize adequate controls required by the VERP program, but still have emission increases for some contaminants related to operation of those controls. Coastal and BP Amoco suggested considering any monitoring data which can demonstrate that there are no adverse impacts.

TCAA, §382.0519(c) does not allow the commission to issue VERPs to facilities which are not protective of public health and physical property. The commission agrees that an abbreviated health effects review can be used to meet this requirement in some, perhaps even most, instances when the criteria stated previously in this analysis of testimony and in this adoption preamble are considered, especially when actual reductions are achieved. Similarly, it is not appropriate to use BACT as the sole factor to determine what level of health effects review should be performed. Other factors, especially the amount and type of emissions, the location of off-property receptors, and compliance history relative to off-property impacts, may be more important in determining impact on public health. However, the commission does not believe that the lack of documentation of adverse impacts, alone, is adequate reason to allow an abbreviated health effects review. The commission does not see any inconsistency with SB 766 by requiring a health effects review. In fact, §382.0519(c) clearly mandates that a VERP that will contravene protection of public health and physical property cannot be granted. This provision was based, in part, on the authority that the commission has in the NSR permitting program under TCAA, §382.0518 to do a health effects review. In both cases, the discretion is left to the commission to determine the appropriate level of health effects review that is needed. The commission believes that the only automatic mechanism for triggering an abbreviated health effects review is a reduction in actual emissions. Actual reductions in emissions is an important factor in improving air quality, and the commission feels that it is appropriate to automatically grant an abbreviated health effects review based upon emission reductions. However, considering any reduction made since 1971 when determining the appropriate level of health effects review may rarely be appropriate. One of the goals of the VERP program is to obtain reductions in actual emissions from the 1997 level. The commission believes that using the highest actual emissions over the previous three years as a baseline for triggering an abbreviated health effects review will result in a reasonable representation of recent actual emissions from a facility. The commission disagrees that failure to expand the guidelines for abbreviated health effects reviews is a burdensome special requirement, nor is it an unnecessarily stringent application of commission discretion. The commission is under no obligation to provide any automatic factors. Because an automatically abbreviated health effects review is allowed for what the commission considers to be the most important factor, actual reductions, it does not mean that it is burdensome to provide other factors, which, when considered together, could result in an abbreviated health effects review. Since grandfathered facilities have been operating for many years, streamlined permitting of grandfathered facilities and an abbreviated health effects review will often be appropriate when considering the previously listed factors, including the automatic factor.

TxOGA and Coastal commented that it is not clear what an "abbreviated health effects review" would be. They do not believe that the current health effects review flowchart is a suitable applicability method, and requested the commission to advise the regulated community what it proposes to do in making such a review. BMOH commented that further guidance should be proposed to identify the level of the abbreviated health effects review for grandfathered facilities, and that the term "abbreviated" is not specified in the rule or the proposed preamble in a manner which would apprise applicants of its meaning.

An abbreviated health effects review would be the minimum review required for the reviewing engineer to determine that the public's health and property will be protected. The minimum health effects review that the commission would perform would be to determine the amount and type of emissions, the location of the nearest off-property receptor, and to consider any compliance history relevant to off-property impacts.

One individual commented that the commission should require annual emission testing for PM ₁₀ , PM _2.5 , nitrogen oxides (NO _x ), CO, volatile organic compounds (VOC), Mercury, and Selenium.

The commission has made no changes in response to this comment. However the commission notes that when necessary to demonstrate compliance with the permit, a VERP permit will contain conditions for testing these and other air contaminants.

SC commented that the commission should be strict with the application of §116.811(2) because of the uncertainties of relying on emissions calculations and estimates. The EPA commented that §116.811(2) should more clearly specify when emission tests are required or explain how it is adequate to assure compliance. It noted that the commission should also address whether this applies to federal requirements, and if so, the source must perform testing pursuant to EPA approved methods and procedures.

The language in §116.811(2) is consistent with the language in §116.111(2)(B), which allows the commission to require measurement of emissions for regular NSR permits, and §116.711(2), which allows the commission to require measurement of emissions for flexible permits. In short, these provisions allow the commission to require testing, when appropriate, to determine compliance with the issued permit. For example, testing might be required to verify emission factors used, or the efficiency of a control device when there is some doubt as to their accuracy. These determinations are made, as needed, and the commission disagrees that more specificity is needed to clarify when these longstanding provisions are required, or how they are adequate to assure compliance. These provisions have no effect on any other state or federal requirements, except that they will be as consistent as possible with the other state or federal requirements, as applicable. The commission may not issue any permit which is not demonstrated to comply with state or federal requirements.

TIP and BP Amoco commented that the commission should provide flexibility to applicants to measure emissions via portable analyzers or to calculate emissions if some known process variable is monitored. Section 116.811(2) should in no way be construed to imply that continuous emissions monitoring will be required for a voluntary permit. TxOGA, GPM, and Coastal added that the commission should clarify proposed VERP requirements for measurement of emissions to demonstrate compliance with applicable federal standards, because §116.811(2) could be misconstrued to mean that continuous emission monitors would be required for VERP authorization, which would far exceed the intent of the legislature.

The commission agrees that §116.811(2) does not require, in and of itself, continuous emissions monitoring, and does provide the flexibility for the commission to require other forms of emissions measurement, such as portable analyzers or emission calculations. For clarity, the commission has added the examples that the commenters mentioned to §116.811(2).

Coastal added that Title V monitoring requirements should be considered adequate for the VERP program.

The commission has made no changes in response to this comment. The commission agrees that Title V monitoring requirements would be adequate for the VERP program, if they are required for the facility and if they demonstrate compliance with the VERP permit. Further, it does not intend to require conflicting or duplicative requirements for measurement of emissions through the air permitting program. The commission believes that §116.811(2) gives the commission the ability to require measurement consistent with ten-year old BACT or GACT and that Title V monitoring requirements would be at least as stringent as those requirements.

Representatives Maxey, Burnam, Dukes, McClendon, and Zbranek recommended that the commission designate the entire East Texas Region (as defined in Senate Bill 7) a near-nonattainment area due to the specific impact that the designation might have on public health and attainment of the NAAQS (specifically resulting from the transport of ozone) and on the use of PERCs within an airshed.

The commission has made no changes in response to this comment. In the development of this provision, the commission considered a number of factors. The list of counties considered near-nonattainment was derived from the cities listed in Article VI, §13, of the commission's appropriation in House Bill 1, 76th Legislature. That section appropriates funding for air quality planning in near-nonattainment areas, defined as Austin, Corpus Christi, Longview-Tyler-Marshall, San Antonio, and Victoria. The counties listed in the adopted rules correspond to these cities. The commission believes that it is appropriate to implement the near-nonattainment area provisions in a manner that is consistent with the Appropriations Act. The commission chose a narrow approach because it was hesitant to designate any specific county as near-nonattainment without scientific evidence. While pollutants from specific counties may contribute to ozone nonattainment, through transport, the specific counties themselves may or may not be near-nonattainment. In the future, the EPA might tend to designate a nonattainment area as broadly as the near-nonattainment area had previously been designated. If the commission designated the entire East Texas Region as near-nonattainment, and the EPA subsequently designated the entire region as nonattainment, many counties in the East Texas Region could suffer the economic consequences of being designated nonattainment without any scientific evidence indicating they specifically are in violation of the NAAQS. Second, a review of the data regarding grandfathered sources showed that designating the entire East Texas Region to be near-nonattainment, solely for the purpose of grandfathered permitting, would have little, if any, positive environmental impact. There are several reasons for this. When considering the largest sources, statewide, which represent 90% of grandfathered emissions, 18% are located in the attainment areas of the East Texas Region. Excluding ALCOA, who is not expected to be affected by the designation of "near-nonattainment," 22% of grandfathered emissions from the largest sources are in that region. Most of the largest, non-electric generating facility sources identified in the East Texas Region are oil and gas production facilities or paper production facilities. When considering the aggregate of emission units located at these types of sources, it is expected that the percentage difference in reductions resulting from ten-year old BACT or GACT would be small. As a result, only 3.0% of the largest sources statewide, representing approximately 5.0% of emissions, would be significantly affected by expanding the designation of "near-nonattainment area" to the entire East Texas Region. If ten-year old BACT could achieve reductions of 50% from those sources and GACT could achieve reductions of 90%, the potential impact on statewide reductions from the largest sources would still be, at the most, 2.0%. Therefore, analysis shows that based on the number and type of industry in the East Texas Region, there is little difference between the results of applying either control technology allowed under the VERP program. Although the commission believes that reductions in the East Texas Region are necessary and important to future attainment strategies, designating the entire region "near-nonattainment" does not seem to be warranted in light of the potential economic impact on the region.

GHASP and TCEA commented that the commission should define nonattainment area and near-nonattainment area broadly, with TCEA and NFN adding that the area should include contributing counties so that the toughest possible standards will be applied to as many grandfathered plants as possible. SC commented that the VERP program should get maximum reductions in the eastern airshed, and PC commented that the commission should define the area in which GACT applies as the entire 60-county region, and that at the very least, the definition needs to be broadened to include those counties that affect nonattainment counties, e.g., Ellis County affects Dallas. PC added that the commission cannot argue logically or legally that transport is limited to an area of four or eight counties in one portion of its rules while arguing that it is appropriate to set up a credit trading scheme for pollution in another section of the same rules. PC noted that considering core airsheds only limits the comparable plants to be considered for GACT, as most of the newer plants tend to be in areas outside the core urban areas; and that GACT needs to be tough enough to result in real reductions. TCE and SEED commented that to expand the number of variables for evaluating the most effective control strategy, the area for GACT determination should include the entire airshed, or maybe the entire region as defined in SB 7.

EDF commented that the commission should consider the entire eastern region (as defined in SB 7) plus El Paso County to be the region where GACT would be applied, noting that emissions from facilities in this region impact air quality in attainment, near-nonattainment, and nonattainment areas downwind. In addition, EDF commented that all counties in potential nonattainment areas which have violated the eight-hour standard should be included in the list of nonattainment counties. The current proposal is unfair to core urban counties and favors economic development in suburban counties, which often have the highest levels of ozone in a region and are significant contributors to the regions air problems. The commenter stated that the commission must reconcile the discrepancy between the region where GACT applies and the region where PERCs can be generated. Allowing PERCs to be generated in a broader region reflects an understanding that emissions reductions in another part of an airshed have the potential to prevent a comparable amount of pollution that would be necessary to comply with a VERP. On the other hand, the proposal to very narrowly define where GACT applies suggests that the commission sees little benefit in requiring GACT controls in counties upwind of nonattainment and near-nonattainment areas. The commenter suggested that the commission either expand the region where GACT applies, or limit the generation of PERCs to the same county or nonattainment area in which an applicant seeks a VERP.

As stated in a related response, the commission has determined that broadening the area where GACT could apply would have little environmental benefit in nonattainment counties when considered solely for the purpose of the VERP program, since few large grandfathered sources would be affected. The commission is not making a determination about whether ozone transported from the attainment counties in the eastern region of Texas impacts the nonattainment areas. Rather, the decision to limit the counties where GACT applies was made entirely within the context of the VERP program.

For that same reason, the commission does not believe that there is a need to reconcile the discrepancy between the region where GACT applies and the region where PERCs can be generated. If the newer plants are located outside the core urban areas and emissions from these areas impact ozone levels in the core urban areas, the commission believes that it makes sense for PERC reductions to be made at these newer facilities if the required reductions cannot be made at the grandfathered facilities in the core counties.

TCGA commented that §116.811(3)(B) seems to require a higher level of controls for businesses in the listed counties, on the basis that these counties are near-nonattainment. This seems to apply to any type of pollutant regardless of whether the area is near-nonattainment for that type of pollutant. For example, facilities emitting only particulate matter could be required to install a higher level of controls in Nueces County, even though particulate matter is not a pollutant of concern in this area.

The commission believes that the Legislature intended the term "near-nonattainment" in TCAA, §382.0519 to apply to NAAQS on a pollutant-by-pollutant basis. Therefore, since the listed counties are not considered to be near-nonattainment for particulate matter, §116.811(3)(B) has been amended to clarify that GACT might apply in the listed counties to grandfathered facilities which emit VOC or NO _x .

TxOGA and TIP supported the concept of listing specific counties in the regulation in which GACT may be required instead of defining near-nonattainment area. ATINGP added that by listing the counties in which GACT may be used, the commission has eliminated confusion and controversy. The association supports the listing of the following counties as areas where GACT may apply: Bexar, Gregg, Harrison, Nueces, Smith, Travis, and Victoria.

As it was proposed, the adopted rule lists the counties in which GACT applies.

Representatives Maxey, Burnam, Dukes, McClendon, and Zbranek recommended that the commission set limits on the length of time allowed for installation of control equipment, and that if a timeline is exceeded, the affected facility should cease operation, unless the timeline is extended by the commission for extraordinary situations.

The commission agrees that timely installation of control equipment is important to achieving the goals of SB 766. The current practice of the commission is to define timelines for installation of control equipment on a case-by-case basis through permit conditions, when a permit covering existing facilities is issued, and there is no immediate danger to public health. Typically, an existing facility is allowed no more than 18 months to install control equipment. However, in some cases, such as when an entire site is permitted under a flexible permit, applicants are allowed as long as ten years to install control equipment on existing facilities if it would prove financially impracticable to add controls to all facilities at once, the public health is protected, and controls are added annually. If a timeline is exceeded, the commission implements enforcement procedures. However, it is rarely necessary to elevate enforcement to the level of shutting down a facility. To encourage implementation of controls as soon as possible, the commission does not believe it is appropriate to place specific timelines in the rules, but would rather address the issue on a case-by-case basis in the permit.

Representatives Maxey, Burnam, Dukes, McClendon, and Zbranek recommended that the commission include a condition in the rules that would require those facilities that use a less stringent control requirement due to "the age and useful life of the facility" to cease operation once the projected limit on useful life is reached. This is because the considering the age and useful life of the facility would prove problematic to the agency when making control technology determinations. As an alternative that would allow continued operation of a facility, the commission should allow PERCs to be used if a facility continued to operate beyond its projected remaining useful life.

No changes were made in response to these comments. The commission recognizes that the consideration of the age and useful life of a facility will complicate control technology determinations, and agrees that permit conditions should limit, on a case-by-case basis, the continued operation of a facility beyond its projected remaining useful life. The commission believes it is appropriate to do this on a case-by-case basis through permit conditions rather than adding it to the rules. This approach will allow the commission to make determinations that are specific to the permit, and could include shorter or longer time frames, as necessary. The commission also believes that flexibility should be provided if a facility continues to operate beyond its projected remaining useful life. One option for flexibility would be to require the controls that would be required for a new or modified facility at the end of the projected remaining useful life. However, the commission does not believe that PERCs could be used to control emissions at the end of the projected remaining useful life, since an owner or operator may only seek authorization to use PERCs at the time of initial application for a VERP.

EDF commented that the commission should include special permit conditions if a VERP contains control methods less stringent than BACT because the applicant claimed the facility had only a limited remaining useful life. The facility should be required to cease operation at the end of the projected remaining useful life, or: 1) install the most up-to-date BACT prior to continuing operation; and 2) retire an amount of emission reduction credits equal to the cumulative difference in emissions between BACT at the time the VERP was issued and the less stringent GACT standard that was applied due to claims of a limited remaining useful life.

The commission agrees that permit conditions should limit, on a case-by-case basis, the continued operation of a facility beyond its projected remaining useful life. To continue operation, the commission agrees that the most appropriate approach would be to require the level of controls that would be required for a new or modified facility at the end of the projected remaining useful life. However, as previously noted, the commission does not believe that PERCs could be used to control emissions at the end of the projected remaining useful life, since an owner or operator may only seek authorization to use PERCs at the time of initial application for a VERP.

TCEA commented that when analyzing cost/benefit, the commission should include offsets for health care costs.

If the commenter was referring to the upper limit specified for GACT, the commission will make the determination compared with the cost of controls per ton of emissions reduced. The commission will not consider health care costs, since the long-accepted method of analyzing the cost/benefit of controls is to compare the cost of controls with the amount of emissions reduced. The commission may not issue a VERP which is not protective of public health.

Nine individuals commented that the commission should require BACT instead of VERP controls. TCEA commented that BACT should be implemented to minimize pollutants in all grandfathered facilities, as well as for all other facilities. Two individuals commented that the commission should require more stringent controls in nonattainment or near-nonattainment areas, and SC commented that the commission should probably require lowest achievable emission rate in nonattainment areas.

TCAA, §382.0519(b) allows grandfathered facilities to use either ten-year old BACT or GACT. Therefore, the commission has made no changes in response to this comment.

GHASP commented that the commission should define GACT stringently. Similarly, TCEA, and NFN commented that GACT should be stringent enough to result in reductions approaching 50%. MCA commented that the strictest allowable reductions on volunteering plants are necessary. If BACT is not used, GACT must result in real reductions. Plants must show real reductions in order to qualify for a permit.

The commission has made no changes in response to these comments. TCAA, §382.0519 does not specify the percentage of emission reductions in order to qualify for a VERP. Rather, the level of controls that must be achieved in order to qualify for a permit is specified. TCAA, §382.0519 has defined GACT as a control technology that the commission has found to be generally achievable for facilities in the area of the same type, considering the age and remaining useful life of the facility. Before age and remaining useful life are considered, the commission interprets GACT to be equivalent to the first-tier of BACT, which is the level of control technology used by a representative number of identical facilities.

One individual and PC commented that the commission should define the term "good faith effort." Another individual commented that the commission should remove the terms "good faith effort," "generally achievable for facilities in that area," and "remaining useful life of the facility" from §116.811 because they are arbitrary and capricious.

The commission has made no changes in response to these comments. The commission's use of these terms is consistent with TCAA, §382.0519(b) and §382.05193(a)(1). Further, the commission declines to define "good faith effort," because of its circumstantial nature. Since this is a term used to determine eligibility for use of PERCs in lieu of VERP controls, the commission believes that each case should be determined on its own merit.

The EPA commented that the commission should address whether it is appropriate to include enforceable restrictions on operation if a facility, at the time it applies for a VERP, operates at less than its design capacity. Without restrictions, the facility could exceed its current level of emissions if it later increased its operation, even with the application of ten-year old BACT or GACT.

The commission agrees that it would be possible for a facility to exceed its current level of emissions even with application of VERP controls. For example, that situation could occur without triggering a modification (which would result in permitting under Chapter 116, Subchapter B) if a facility is already using the required controls and is emitting at a rate below a proven, historical grandfathered emission rate. Section 116.814 allows for general and special conditions to be placed in VERPs. These conditions will be used to establish allowable emission rates and to ensure compliance with VERP requirements and the protection of public health. Therefore, the commission agrees that it is appropriate to include enforceable conditions in a permit, regardless of whether a facility is operating at its design capacity.

The EPA commented that control requirements in §116.811 appear to only apply at initial issuance of VERPs, and that if modifications are made, the BACT in effect at that time would apply.

The commission agrees with the EPA's understanding.

EPE commented that the commission should require ten-year old BACT for all grandfathered facilities regardless of location, with GACT eliminated entirely. The commenter further stated that requiring more stringent controls in nonattainment and near-nonattainment areas will have the undesired affect of penalizing facilities that elect to obtain a VERP. If the commission retains GACT, it should be clearly defined as first-tier BACT, so that it will not be a moving target, and to provide assurance that GACT requirements remain reasonable.

The commission has made no changes in response to these comments. TCAA, §382.0519(b)(2) requires VERP applicants to use the more stringent of ten-year old BACT or GACT in nonattainment and near-nonattainment areas. Before age and remaining useful life are considered, the commission interprets GACT to be equivalent to the first tier of BACT, which is the level of control technology used by a representative number of identical facilities.

EDF commented that defaulting to first-tier BACT as a working definition of GACT is appropriate.

The commission agrees that first-tier BACT is the most appropriate starting point for determining GACT. The first tier of BACT is the level of control technology used by a representative number of identical facilities. Before age and remaining useful life are considered, this is almost identical with the definition of GACT provided in TCAA, §382.0519(b)(2)(B).

One individual asked how BACT is defined. BMOH commented that ten-year old BACT is a more appropriate starting point for determining GACT, because it avoids the presumption that current BACT is GACT, and ensures that the factors applied to any potential additional controls are considered in light of what is generally achievable. When there has not been a previous determination of ten-year old BACT, the generally achievable standard would ensure that the applicant would be able to evaluate controls in place at other sources within the area in making the decision whether to go forward in the filing of a VERP application. The commission's approach to define first-tier BACT as the starting point does not establish why the final control selection is generally achievable. TxOGA and Coastal commented that ten-year old BACT should be the starting point for discussions as to what controls are generally achievable with first-tier BACT as the ceiling and that GACT should be interpreted to involve widespread use of certain control technology for similar facilities in a specific area, and not individual or isolated applications. BP Amoco and TIP also commented that the term "generally achievable" should imply widespread use in an area, not simply individual cases of control technology applicability. TxOGA commented that statewide determinations of GACT for the VERP program should not be driven by control strategies developed for nonattainment areas; such control strategies should remain focused on the nonattainment areas themselves.

The first tier of BACT is the level of control technology used by a representative number of identical facilities, not isolated applications. Before age and remaining useful life are considered, this is almost identical with the definition of GACT provided in TCAA, §382.0519(b)(2)(B). Therefore, the commission believes that it is the most appropriate starting point for determining GACT. The commission agrees that first-tier BACT would be the ceiling for GACT since age and remaining useful life, as well as the controls achieved by other facilities in the area, might then be considered. The commission agrees that attainment areas should not necessarily be considered the same as a nonattainment area. Therefore, it could be argued that SIP controls required for nonattainment areas might not be appropriate where GACT applies in attainment counties.

TxOGA and TIP commented that the commission should adequately consider facility age and remaining useful life in determining GACT.

The commission recognizes that consideration of facility age and remaining useful life is part of determining GACT. It will carefully consider age and remaining useful life and will use permit conditions to limit the continued operation of a facility beyond its projected remaining useful life.

TxOGA and Coastal commented that the commission should reconsider its stated presumption that GACT is between ten-year old BACT and BACT in stringency. The commenters stated that the legislature recognized that GACT may be less stringent than ten-year old BACT in requiring that the more stringent of the two be used in nonattainment areas. GACT is required as the control technology only in the instances when it is more stringent than ten-year old BACT. TIP also commented that in many cases GACT may be less than ten-year old BACT.

The commission believes, that in most, if not all, cases, GACT will be more stringent than ten-year old BACT. Before consideration of age and remaining useful life, the definition of GACT provided in TCAA, §382.0519(b)(2)(B) is almost identical to the first tier of BACT. The commission has revised the preamble to clarify that GACT will, in most cases, be more stringent than ten-year old BACT, and removed the statement that GACT is between ten-year old BACT and BACT in stringency.

BP Amoco commented that in nonattainment areas, the commission should defer to the SIP strategy to define necessary controls rather than using the VERP program to drive/define control requirements. New SIP rules will be promulgated in late 2000.

The commission agrees that, if known, future SIP control requirements should be considered when determining VERP control levels, to the extent that the SIP requirements would be ten-year old BACT or GACT.

TxOGA and Coastal commented that the commission should reconsider its presumption that GACT could cost up to $10,000 per ton of emission reductions, and that the commission appears to be taking the position that any controls which do not exceed that cost would be reasonable. This cost factor is commonly applied to BACT determinations and is not reasonable for application to facilities that will already be 30-plus years old at the time the expenditures are required. The commenters stated that the commission presumption is not consistent with the legislative intent that age and remaining useful life of the facility be considered. Coastal added that the cost of retrofitting grandfathered facilities, in view of their expected life and environmental benefits, must be considered when evaluating controls. Mobil commented that the commission has not complied with the requirements of the statute in development of GACT. The preamble states that GACT is presumed to lie between ten-year old BACT and BACT in stringency and sets an arbitrary value for emission reduction costs up to $10,000 per ton. The statute states that the age and remaining useful life of a facility should be considered in determining GACT. BP Amoco and TIP commented that $10,000 per ton for GACT is not reasonable, as this amount is typically reserved for BACT, if appropriate. TIP added that equating the cost of GACT with BACT ignores the age and remaining useful life of the facility.

The commission believes that in many instances, the cost of retrofitting an existing facility could be as expensive as applying BACT to a new facility. In order to establish an estimate of program costs in the proposed preamble, the commission used the $10,000 per ton limit as a limit typically considered in current BACT review, depending on the type of facility and pollutant to be controlled. In actuality, the cost of retrofitting an existing facility could be lower or, in some cases, higher than $10,000 per ton, annualized. The commission will consider the age and remaining useful life of a facility when determining GACT, including the consideration of cost, as appropriate.

Mobil requested that the commission expressly provide for phase-in of control requirements consistent with other federal or state regulatory requirements. TxOGA and Coastal commented that clarification is necessary to ensure that phase-in of control requirements is not considered a deferral under §116.816. The commenter provided suggested language to be added to §116.811(3)(C). BP Amoco and TIP also commented that language should be added to distinguish between deferrals and phase-in of controls.

The commission agrees that deferral of control requirements under §116.816 is different than phase-in of VERP controls. As previously noted with regard to timelines for installation of controls, the commission recommends phase-in of controls on a case-by-case basis in permit conditions. While federal or state requirements may be one of the reasons that phase-in of controls would be allowed, there may be other reasons for allowing phase-in of controls. Providing an exhaustive list of other reasons in the rule would be unintentionally limiting; therefore, the rule language has not been revised.

PC commented in support of the commission's position that nothing in the legislation overrules the applicant's responsibility to meet federal requirements, e.g., NSPS, NESHAPs, maximum available control technology, or SIP requirements.

The commission agrees, and retained the provisions regarding federal requirements in the adoption.

The EPA commented that the provisions of §116.811(4), (8), (9), and (11) apply to new or modified sources and do not appear to apply to grandfathered sources, but that these provisions may apply to facilities which use PERCs. The commenter stated that these provisions must also ensure that a facility applying for a PERC continues to meet all applicable federal provisions. In addition, EPA stated that the commission must add the phrase, "applicable requirements of the Texas SIP, including such provisions as reasonably available control technology." A separate EPA commenter added that §116.811 should be amended to state that the amount of VERP allowances should not exceed the 1990 Emissions Inventory (EI) or the emissions reported in any Rate-of-Progress (ROP) SIP submitted for an ozone nonattainment area.

The commission believes that it is appropriate to include the listed federal provisions, as proposed, because it is conceivable that a VERP control requirement could trigger federal review, e.g., a flare is considered GACT and the resulting products of combustion exceed federal trigger levels. While it is unlikely for this to occur, since the benefit of flaring would conceivably outweigh any increase in products of combustion, the commission believes that listing the federal requirements ensures that they will be complied with, if triggered. The commission agrees that VERPs are only for unmodified facilities, but could also include new facilities, if that new facility is a required control device. The listed federal provisions apply to any VERP permit, including those that use PERCs. The commission does not believe that it "must add" a reference to the SIP regulations, since §116.811(1) requires compliance with all rules and regulations of the commission. Therefore, the rule was not revised.

Regarding VERP allowances (reductions), the commission did not propose the VERP program as a SIP submittal. Therefore, the commission cannot, in this adoption, commit the VERP reductions to the SIP. However, the commission may do so in a future SIP submittal or use a portion, or all, of the reductions in SIP attainment demonstration modeling. Therefore, the rule has not been amended to address VERP reductions as they relate to the EI or ROP.

B&P commented that the rules should state that a VERP cannot be used to authorize construction or operation of a new source or a modification of an existing source, rather than require grandfathered facilities to meet applicable nonattainment NSR and PSD requirements.

The commission agrees that VERPs should not be used to authorize construction or modifications. However, the commission has not modified the rules, as requested. Section 116.811(8) and (9) are intended only to require VERP applicants to comply with the existing rules for PSD and nonattainment permit review. The commission must verify compliance with state and federal rules before issuing permits.

TIP commented that §116.811(7) should be deleted. The commenter stated that the provision allowing the commission to require additional engineering data after VERP issuance is overly broad and would allow the commission to exceed its statutory authority.

The commission disagrees that §116.811(7) should be deleted or that it exceeds statutory authority. The provision is necessary to require and verify compliance with permit conditions. While it may not be appropriate to require performance demonstrations in most cases under the VERP program, the commission needs the ability to require performance demonstrations in such instances as implementation of unproven control technology, or where there is uncertainty with the emission factors used to determine emission rates.

The EPA commented that §116.811(7) should be more definite to ensure compliance using the appropriate testing, monitoring, and recordkeeping that the commission established in the permit after evaluating the permit application and considering relevant information on the operating and production parameters which affect the emissions. See 40 CFR 51.212(c).

Section 116.811(7) allows the commission to require and verify compliance with permit conditions. Performance demonstrations may vary from VERP to VERP, and it is inappropriate to include those details here. Therefore, §116.811(7) has not been revised in response to this comment.

GPM commented that requiring modeling will be very costly and will cause unnecessary delays. The commenter stated that the commission is required to expedite VERPs within two miles of certain sensitive receptors, and the inclusion of modeling will be counter to that directive. BP Amoco commented that modeling should not be required where permitting efforts result in reduction in emissions. TIP commented that the commission should further define when it may require modeling or monitoring under §116.811(10), as guidance has not been provided and that modeling or monitoring should not be required when the VERP has resulted in decreased emissions.

The commission agrees that no modeling will be required if a VERP results in emission reductions. An abbreviated health effects review would not require modeling. However, the commission believes that modeling is appropriate in certain instances and will consider the criteria included in the previous discussion, relating to the level of health effects review, when determining whether it is appropriate. The commission does not agree that modeling is an unnecessary delay to the extent that it would be appropriate to ensure the protection of off-property receptors, including the listed sensitive receptors within two miles. The cost of modeling may be mitigated, especially for small businesses, since commission staff can sometimes perform the appropriate modeling.

Representatives Maxey, Burnam, Dukes, McClendon, and Zbranek recommended that the commission require applicants to delineate, within the application, the actual emissions reductions projected under the VERP. EDF commented that §116.811(12) should be amended (and reflected in the PI-1V) to require applicants to include an estimate of emission reductions resulting from a VERP. This will facilitate public review of applications.

The rule, as proposed and adopted, allows the commission to require additional support information in the application form; therefore, no change is needed in response to this comment. The current NSR practice requires a table to be submitted with permit applications which identifies proposed emission rates on a unit-by-unit basis. This practice will continue under the VERP Program. Every VERP issued will have an allowable emission rate, which can be easily compared to the actual emission rates represented in the 1997 Grandfathered Sources Survey or to the EI. An allowable rate should be equivalent to the maximum actual emissions expected by an applicant after implementation of controls.

The CAP commented that the commission should offer suggestions on BACT, GACT, and ten-year old BACT for different types of facilities, and should be made available prior to the application deadlines to help small businesses mitigate the cost of submitting an application and the cost of hiring a consultant.

The commission currently maintains a list of ten-year old BACT and will make the list available to small businesses. As GACT determinations are made, the commission will similarly develop a list and make it available.

TIP commented that the commission should modify §116.811(12)(E) to clarify that an applicant may identify more than one date for the installation and operation of emission reduction projects. The commenter stated that such a change would clarify that a facility may phase-in emission controls if multiple changes are required.

The commission agrees that phasing-in of controls is often appropriate. If more than one facility is included in a VERP application, the commission assumes that multiple dates for installation of controls will be provided, on a facility-by-facility basis. Section 116.811(12)(E) is broad enough to allow this, and has not been revised. Further clarification will be provided as needed.

GPM commented that the commission should withdraw the 3,000-foot requirement from the rules, since imposing special requirements on grandfathered facilities within 3,000 feet of a school seems inconsistent with the goal of encouraging participation.

The proposed and adopted rules do not contain any requirements for grandfathered facilities within 3,000 feet of a school. When issuing a permit to construct or modify a facility, TCAA, §382.052 requires the commission to consider adverse effects at schools within 3,000 feet. However, Chapter 116, Subchapter H will not authorize new or modified facilities, so that requirement has not been included. TCAA, §382.0519(f) does require the commission to give priority to applications for facilities less than two miles from schools, daycare centers, hospitals, or nursing homes. This requirement was included in the proposed and adopted rule in §116.813(b).

EDF commented that PERCs should not be used to shift the burden of pollution exposures from one group to another, and that the alternative control measures should control the same pollutants as the facility in question emits. The commenter stated that PERCs should not be used to provide relief to the general population at the expense of continued toxic releases that affect a specific neighborhood. Failure to craft this program is likely to bring the state civil rights environmental justice lawsuits. One individual commented that the commission should not allow emission reduction credit programs or emission reduction credit trading programs. These programs ensure that environmental justice concerns will not be addressed, as some people will have emission reductions in their area, while others will be forced to breathe air which will harm their health. Two individuals, C&S, and MCA commented that the commission should not give emission reduction credits for phantom reductions. The same individuals and C&S added that the commission should not allow bait and switch reductions and that PERCs must result in quantifiable emission reductions with real penalties or retraction of the permit if the reductions fail to happen. MCA and LWV added that PERCs must result in quantifiable emission reductions before they qualify as conditions for issuance of a VERP, and that real penalties or retraction of the permit must occur if reductions fail to happen. LWV added that the commission should monitor PERCs.

TCAA, §382.05193(b) requires the commission to develop and implement a PERC program for facilities that have made a good faith effort to meet VERP controls, but cannot reduce the facility's emissions to the degree necessary to obtain a VERP. The commission agrees that emission reductions should be real, and in addition, should be enforceable, permanent, quantifiable, and surplus. These criteria are all contained in §116.812(c) and are used in the EPA's and commission's emission reduction credit trading programs. The commission also agrees that no particular population should be adversely impacted by the PERC program. The VERP program requires the commission to ensure that public health and physical property are protected, regardless of whether controls, PERCs, or deferrals are used to meet the VERP requirements. If there are no emission reductions at a facility, the commission will use the criteria mentioned previously for determining what level of health effects review should be performed. If the commission cannot verify that the emissions from the grandfathered facility are protective of public health, the commission will be unable to issue a VERP permit.

TCAA, §382.05193 and the adopted rules provide that PERCs must reduce net emissions from one or more sources in the state in an amount and type sufficient to prevent air pollution to a degree comparable to the amount of the reduction in the facility's emissions that would be necessary to meet the permit requirement. While it may not be appropriate in all cases for the reduction to be pollutant for pollutant, the commission interprets comparable to mean similar in amount and potential adverse impacts and that the reduction will have the same benefit for attainment of the NAAQS and is an air contaminant of similar environmental significance.

Two individuals, MCA, and LWV commented that the commission should require PERCs in the same airshed as the plant trying to get a permit.

The commission agrees, and has maintained this provision in the adopted rules.

One individual commented that the commission should not allow the purchase of autos to be used as a method of reducing emissions, because there is no way of knowing if the autos were actually being driven, or how much they were driven. The commenter stated that the commission should reduce emissions at the source. SC commented that the commission should certify that any automobiles used for PERCs are destroyed and that they are not piled up in a neighborhood with gasoline in the fuel tanks.

TCAA, §382.05193(c)(2) specifically provides that PERCs may be created by the purchase and destruction of high emission automobiles or other mobile sources. Therefore, the commission did not remove this option from the adopted rules. However, the rules require applicants to prove that these projects will result in real, quantifiable, and enforceable reductions. The commission believes that this will ensure the removal of operating vehicles, rather than those that are simply abandoned. The commission also believes that it has broad enough authority to ensure that places where automobiles are stored will not adversely impact neighborhoods.

PC asked how reductions used to create PERCs would be quantified and commented that the commission should use other states and federal credit programs for values, or have a hearing to establish values.

The commission will use emission factors, monitoring, or any other verifiable method for quantifying reductions and will review other state and federal programs as necessary.

PC asked how the commission would assure that there are real penalties if emission reductions do not occur, and commented that the commission should require annual reports and conduct random audits to assure that real reductions are occurring.

PERCs will be implemented through the VERP permit and the commission will utilize its well-established enforcement program to ensure that permit holders are complying with all conditions of the VERP. Reports and audits may be required as conditions of the permit, if appropriate.

PC asked how long will credits would have value, and commented that the commission should require credits to be used within the year, unless they are excess credits resulting from an early retirement or extra emission reductions. The program should operate for just ten years.

The commission has made no changes in response to this comment. The rules, as proposed and adopted, require the reductions used to create PERCs to be permanent. Additionally, once a PERC is used to meet the requirements for obtaining a VERP, it will be retired.

TRPC commented that the renewable power industry in Texas is expanding to meet the SB 7 renewables mandate, and that retail electric providers are becoming familiar with renewable power through their implementation of the SB 7 mandate. The TRPC agrees with the commission proposal that renewable power required under SB 7 is not eligible to be used in the PERC program. However, it will be easy for retail electric providers to procure additional output from renewables and to integrate it as a replacement for fossil-based power. The commenter stated that offsetting pollution for the remaining lifetime of a grandfathered facility through renewable power will require contracts whose length coincides with the useful life of the grandfathered facility, which is feasible since wind power projects have useful lives as great as 25 to 30 years. To help reduce the cost of power from renewables, the commission may certify renewable power as a pollution reduction technology eligible for exemption from state property taxes and eligible to use pollution abatement bonds issued by local governments. The commenter further stated that the commission has an interest in ensuring that renewable power, whether locally generated or imported from another region, actually offsets fossil-based generation within the airshed of the grandfathered facility, and that the commission should state in the rules that renewable power imported from other regions can be used to offset fossil-based generation that would otherwise serve the grandfathered facility. Finally, the commenter stated that the commission proposal is potentially problematic in this regard, since the commission would require a demonstration that the renewable power is displacing permitted generation from a specifically designated power plant in the same airshed. A more practicable approach to consider would be reducing overall power generation within the airshed and/or allowing the purchase and retirement of allowances issued under SB 7.

The commission will explore whether or not it has the authority to declare a renewable energy source, such as wind power, to be a pollution control device for the purposes of property tax exemptions and pollution abatement bonds. The commission would only do so if the wind power resulted in real, quantifiable, enforceable, surplus, and permanent reductions in emissions. The commission would allow renewable power imported from other regions to be used as PERCs, as long as it produces a verifiable reduction in emissions in the same airshed as the grandfathered facility is located, and meets other PERC criteria. The reduction would not have to come from the same power plant, but would have to come from the same airshed. The commission agrees that it might be possible to create a PERC by purchasing and retiring allowances created under SB 7 as long as they are not used to meet the requirements of that program. The commission did not adopt any of these concepts into the rules, since more exploration of these concepts is needed at this time.

PC commented that the commission should develop the PERC program to allow the use of renewable energy in an emissions credit trading scheme, and that the commission should adopt, by reference, the capacity factors developed by the Public Utility Commission to convert renewable capacity to energy for purposes of calculating avoided emissions. The commenter stated that allowing utilities to create emission reductions from permitted plants is unlikely to assure any real reductions, since the reductions would probably occur at peaking units, which are used infrequently. In order for the PERC program to result in real reductions, the rules should be modified to require permit reductions based on the last five years of actual emissions. PC stated that to allow the rules to work in a competitive electric industry, the commission should allow a retail electric provider to sell renewables to a grandfathered facility and assume that there will be a reduction per megawatt hour at the power plants in the area. Or, the commission could allow the retail electric provider to buy and retire NO _x allowances from the Senate Bill 7 emissions banking and trading program. The commenter stated that the commission can reduce the cost of renewable energy by declaring renewable plants to be pollution control devices, which would exempt owners from property taxes and allow them to qualify for pollution abatement bonds issued by local governmental units.

As previously stated, the commission believes that the concept of using renewable energy to create PERCs is worthy of additional exploration. At this time, the commission believes that it is premature to revise the rules to include renewable energy provisions. If appropriate, provisions can be implemented through guidance or future rulemaking.

SEED and TCE commented that the ratio of reductions should be consistent with federal standards or 1.2 to 1, and that for every credit of reduction, there must be a greater actual reduction.

The commission has made no changes in response to this comment. TCAA, §382.05193(c) requires a "comparable" reduction, and does not specify a ratio.

EDF commented that the rules fall short of encouraging smart use of PERCs by not clearly outlining what information is needed from industry seeking a PERC. The commenter further stated that the requirements for enforceability, permanency, etc., are the correct criteria, however, leaving the details to guidance documents makes it impossible to evaluate the adequacy of the PERC program. The rules also seem to not fully appreciate the complexity of making such determinations in a regulatory setting and the amount of resources needed by the agency to administer such a program.

Because the commission recognizes the complexity of the PERC program, the commission believes that it is only appropriate to capture the basic framework in the rules. The implementation procedures for this program will be very detailed and potentially fluid as the program develops. Further, the commission is gaining experience with some of the allowed projects for the first time. Therefore, the commission believes that it is premature to propose a high level of detail in the rules. As the PERC program is implemented, the commission will seek input from interested parties, at a minimum, through the public comment for issuance of individual VERPs.

The EPA commented that the commission should address how it will determine the baseline for crediting PERCs, and that the plan should be consistent with the approved plan for demonstrating attainment and maintenance of the NAAQS.

The commission addressed consistency with the NAAQS in both the proposed and adopted rules by requiring that PERCs be surplus to state or federal laws, regulations, and agreed orders. Therefore, the baseline for PERCs will be the actual emissions from the facility as adjusted by any applicable current state or federal laws, regulations, or agreed orders.

The EPA commented that §116.812(b)(3) could allow a source whose actual emissions are less than its permitted allowables to reduce its allowable emissions to its current actual emissions and credit the difference between the old and new allowable as a PERC, although there is no reduction in actual emissions. The commenter stated that this would have no environmental benefit and is inconsistent with §116.812(c)(5), which requires a real reduction in emissions. The EPA stated that the commission could clarify §116.812(b)(3) by appropriately cross-referencing §116.812(c)(5) and ensuring that §116.812(b)(3) does not supersede §116.812(c)(5).

All of the criteria in §116.812(c) apply to "any proposed PERC." Therefore, the rule has not been revised.

EPE commented that the commission should allow for the transfer and trading of PERCs between airsheds, as allowed in the commission's current banking and trading rules, in order to provide economic drivers and benefits to participating companies. The commenter also stated that the commission should allow all enforceable emission reductions, including allowables, to be eligible for PERCs to encourage participation in the VERP program.

The commission has made no changes in response to this comment. TCAA, §382.05193(f) provides that PERCs are not transferable. The commission interprets this to mean that they are not tradable. In addition, TCAA, §3822.05193(b) requires PERCs to be generated in the same airshed as the grandfathered facility being permitted. The commission disagrees that it is appropriate to use allowable emissions to create PERCs. The commission is not aware of any emission reduction credit program that recognizes allowable emissions, and further, believes that emission reductions should have actually occurred before credits can be generated.

EPE commented that the commission should clarify whether PERCs can involve any criteria pollutant or whether they must be in-kind, pollutant for pollutant, and that the PERC provisions should allow substitution, since the goal of the VERP program is to reduce pollutants.

The commission has made no changes in response to this comment. TCAA, §382.05193(c) and the adopted rules provide that PERCs must reduce net emissions from one or more sources in the state in an amount and type sufficient to prevent air pollution to a degree comparable to the amount of the reduction in the facility's emissions that would be necessary to meet the permit requirement. The commission believes that comparable means similar in amount and potential adverse impacts and that the reduction will have the same benefit for attainment of the NAAQS and is an air contaminant of similar environmental significance. Therefore, the commission believes that pollutant for pollutant reductions would be appropriate in most cases.

TIP supports the commission proposal to allow PERCs to offset emissions when GACT cannot be practically achieved. The commenter stated that facilities should be allowed to use PERCs for all emission reduction activities initiated after the proposal date of these rules, and that the commission should confirm that such emission reduction activities will be creditable to the facility under §116.812(a).

The commission encourages reductions as soon as possible and believes that it may be appropriate for any PERC created specifically for the purpose of obtaining a VERP to be used as long as the reductions are real, quantifiable, enforceable, surplus, and permanent.

TxOGA, Coastal, and Mobil commented that the commission should clarify that any legitimate emission reduction project may be used to generate PERCs. The commenters stated that a facility should be allowed to implement any emission reduction project that reduces net emissions of a type sufficient to prevent air pollution to a degree comparable to the amount of reduction that would be necessary to comply with §116.811(3). The proposed regulations appear to limit a facility to using only one of the legislatively listed projects for a PERC. TIP and GPM commented that reductions of emissions below the levels required in exemptions from permitting should be creditable for a VERP under §116.812, and that §116.812(b)(3) seems to limit PERCs to permitted facilities; therefore, language should be added to include exempted facilities or facilities permitted by rule.

The commission did not intend to limit PERC projects to those listed in the proposed rule. The statute does not limit the types of projects, and the commission has amended the rule to clarify this.

TIP and GPM commented that §116.812(a) should be rewritten. The term "excessive emissions" gives the impression of noncompliance. TIP added that if §116.812(a) is rewritten, the definition of excessive emissions in §116.16 should be eliminated. BMOH also commented that §116.811(3)(D)(iii) should be reworded to make the definition of excessive emissions unnecessary, because the definition is inflammatory and ultimately unnecessary, since it easily equated with unauthorized emissions. BMOH stated that the commission should also reword §116.812(a), similarly.

The commission agrees with suggested changes and has revised the rule accordingly.

BMOH commented that the commission should define the term "significantly," as used in §116.812(b)(3), so as to ensure that it is not to be equated with the term "significant" as it applies to 30 TAC Chapter 106.

The commission has made no changes in response to these comments. Since the commission did not propose a definition for this term, it feels that it is inappropriate to create a definition at adoption without specific input from interested parties. However, the commission agrees that the term "significantly" in §116.812(b)(3) should not be equated with the term "significant" as that term is used in the context of Chapter 106 (relating to Exemptions from Permitting), and will implement the provision accordingly.

BMOH commented that the commission should provide guidance and clarification of what the term "comparable" means. The commenter asked if the commission intends that area-wide modeling of emission reduction credits will be necessary to show that the PERCs are "sufficient to prevent air pollution to a degree comparable" to those that would otherwise be required under a VERP. BMOH felt that the term should mean similar in amount and potential adverse impacts.

The commission agrees that the term "comparable" should mean similar in amount and potential adverse impacts and would add that the reduction will have the same benefit for attainment of the NAAQS and is an air contaminant of similar environmental significance. The commission does not believe that area-wide modeling will be necessary to show that PERCs generate comparable emission reductions.

BMOH commented that the commission must grant PERCs if an applicant satisfies the conditions stated in the rules, as provided for by §382.05193(b). The commenter stated that the rule appears to provide some unspecified discretion to the commission to deny PERCs, and that if there are conditions under which PERCs will not be granted, this must be stated in the rule itself.

The commission will grant PERCs that meet all of the criteria established in the rule, including the requirement that comparable reductions must be real, quantifiable, enforceable, permanent, and surplus, and that the commission is able to verify that the emissions from the grandfathered facility are protective of public health and property, which is a condition of VERP issuance. Therefore, the commission has clarified §116.812(a) to alleviate the appearance of unspecified discretion.

B&P commented that the commission should revise the proposed definition of permanent in §116.812(c)(2) by removing the statement that permanent means unchanging, because an emission reduction could be permanent even though it changes (i.e., the emission reduction could increase).

The commission has made no changes in response to this comment. The commission would consider additional reductions from a project which generated a PERC to be a new reduction. Any reductions relied upon for a PERC would have to remain unchanged and permanent.

GHASP, TCEA, and NFN commented that the commission should give priority to the permitting of grandfathered facilities within two miles of schools, daycare centers, and nursing homes. NFN added that these facilities should receive the most careful scrutiny by staff. GHASP also commented that priority should be given to other centers where the population is known to be especially vulnerable to the effects of air pollution.

TCAA, §382.0519(f) requires prioritization of review of VERP applications located less than two miles from the outer perimeter of a school, daycare facility, hospital, or nursing home. The commission will scrutinize all applications.

TIP commented that the commission should give priority to grandfathered or formerly grandfathered facilities that have submitted applications that will result in substantial reductions in ozone precursors.

The review of VERP applications is a top commission priority. TCAA, §382.0519(f) requires prioritization of review of VERP applications located less than two miles from the outer perimeter of a school, daycare facility, hospital, or nursing home. The commission will consider the substantiality of reductions in ozone precursors among other factors when considering second-tier prioritization.

One individual commented that the commission should not allow deferrals, noting that it would allow people to be harmed by one pollutant while reducing another. The individual stated that if a grandfathered facility cannot meet the requirements of the VERP program, the commission has no business permitting it.

The commission has made no changes in response to this comment. Deferrals of certain air contaminants are specifically authorized by TCAA, §382.0519(e) if substantial reductions are made in emission of other air contaminants that meet commission priorities. One of the factors that the commission will consider when granting a deferral is the benefit to public health from the reduction of other specific air contaminants versus the deferral. In addition, the commission may not issue a VERP, including a VERP which contains a deferral, unless the public health is protected.

PC commented that the commission should define what constitutes economic hardship and technical impracticability. Without definition, technical impracticability becomes a loophole that could be an excuse for almost any plant to argue that it cannot clean up. The commenter stated that the rules should propose a ratio of reductions, such as 1.5 tons of reduction for every ton emitted, and that the rules should have a ten-year limit on deferrals to avoid creation of great-grandfathered plants. The EPA commented that deferral projects should have a time limit.

The commission declines to define economic hardship and technical impracticability because both are terms that are circumstantial in nature. Since this is a term used to determine eligibility for use of deferrals in lieu of VERP controls, the commission believes that each case should be determined on its own merit. Information concerning the annualized cost of controlling emissions will be an essential component of any application requesting a deferral. TCAA, §382.0519(e) and the adopted rules require substantial emission reductions of other air contaminants if reductions in certain specific air contaminants are to be deferred. The ratio of reduction is also circumstantial and will be based on commission priority to meet statewide air quality needs. The commission does not believe it is necessary to have a ten-year limit on deferrals, because anticipated state or federal regulations will, in all likelihood, require reductions in the emissions deferred in that time period.

TCE and SEED commented that they are concerned that the deferral provisions would allow ALCOA's Milam County facility to continue to emit 60,000 tons per year of sulfur dioxide (SO ₂ ) that contributes to attainment problems in DFW. SEED and TCE also commented that the economic hardship provision for ALCOA is not warranted, given that it claims that $100 million in scrubbers would force it to close its doors when they have just recently purchased Reynolds Aluminum for $5.6 billion in cash.

TCAA, §382.0519(e) requires substantial emission reductions of other air contaminants if reductions in certain specific air contaminants are to be deferred. Any deferral will be based on commission priority to meet statewide air quality needs. The commission believes that anticipated state or federal regulations will, in all likelihood, require reductions in any emissions deferred.

TCE and SEED suggested additional criteria for determining when deferrals are appropriate: evaluation of the impact the emissions have on nonattainment or near-nonattainment areas, and a truth in hardship provision that requires proof of economic hardship with disclosure to the public so that the true economic cost of the control strategy to the state could be assessed. B&P commented that §116.816(d)(3) should be revised so that it provides for the consideration of impact of the reduction and the deferral on attaining or maintaining the NAAQS.

The commission has made no changes in response to these comments. The commission believes that the rules, as proposed and adopted, will allow the commission to consider the impact or benefit of deferrals on nonattainment and near-nonattainment areas. Information concerning the cost of controlling emissions will be an essential component of any application requesting a deferral.

EDF commented that the commission should explicitly state in §116.816(b) that the substantial emission reductions to be made in other specific air contaminants as a condition of a deferral need to be in addition to the requirements that would normally apply as part of a VERP.

The commission agrees that emission reductions needed for a deferral would be in addition to the amount of reductions of other specific air contaminants otherwise required by the VERP program. For example, if NO _x is reduced in lieu of SO ₂ , then the NO _x reductions used for a deferral would be in addition to the NO _x reductions otherwise required by VERP controls. Language in §116.816(d)(2) has been revised to clarify this requirement.

EDF commented that the rules should require submission of: 1) data on the economic health of the company; 2) length of time the company will commit to keep the plant operational, if a deferral is granted; and 3) which populations would benefit and which would be adversely impacted by a deferral.

The commission has made no changes in response to this comment. The commission believes that information concerning the cost of controlling emissions will be the most essential component of any application requesting a deferral. Since the commission believes that anticipated state or federal regulations will, in all likelihood, require reductions in any emissions deferred, commitments concerning length of time that a plant will remain operational are unnecessary. Any deferral will be based on commission priority to meet statewide air quality needs. In addition, the commission may not issue a VERP unless public health is being protected, therefore, the review of any deferral will include an analysis of benefit and impacts on off-property receptors.

EPE commented that the commission should define exceptional economic hardship, and the commenter also recommended that it be defined on the basis of cost of control or cost per ton of pollutant removed. EPE stated that the commission should also provide guidance on what constitutes specific technical impracticability.

The commission declines to define economic hardship because it is a term that is circumstantial in nature. Since this is a term used to determine eligibility for use of deferrals in lieu of VERP controls, the commission believes that each case should be determined on its own merit. The commission agrees that information concerning the cost of controlling emissions on a per ton basis will be an essential component of any application requesting a deferral. The commission believes that technical impracticability must be considered along with economic hardship, and is also circumstantial in nature. The commission will provide guidance, as necessary.

The EPA commented that §116.816(d)(3) requires the commission to consider the impact of emission reduction on attaining the NAAQS, and EPA understands the paragraph to mean that if the TNRCC plans to rely upon the VERP in its strategy to attain and maintain compliance with a NAAQS, it will consider such planning requirements in its decision to defer. The commenter understands that the commission will not defer implementation of a VERP that will interfere with attainment and maintenance of the NAAQS, or is otherwise inconsistent with the requirements of plan and control strategy.

Section 116.816(d)(3) allows the commission to consider the benefit that reductions of "other" specific air contaminants will have on attainment or maintenance of a NAAQS when deferring the requirement to reduce "certain" air contaminants. In other words, if a facility cannot reduce SO ₂ due to economic hardship or technical impracticability, the commission might consider the benefit that a substantial reduction in NO _x would have on attainment or maintenance of the NAAQS for ozone. If the commission could determine that the reduction in NO _x would benefit the commission's priority to attain and maintain the ozone NAAQS, when weighed with its priority to protect public health and property, the deferral in SO ₂ reductions could be granted, if the other criteria for granting a deferral are met. The commission may not issue any VERP which violates any commission regulation, including those intended for attainment and maintenance of the NAAQS. However, the commission is not committing to rely on VERP reductions in its strategy to attain and maintain compliance with the NAAQS in this adoption, but may do so in future SIP submittals. Therefore, the commission does not entirely agree with the EPA's understanding.

BMOH commented that there is no language in the statute that supports the commission's contention that deferrals be limited to exceptional economic hardship or technical impracticability problems. The commenter stated that while it is reasonable to review statements of legislative intent to illuminate the meaning of statutory terms, it is not appropriate to impose additional requirements based on statements of legislative intent. The granting of a deferral should be based upon the two criteria listed in the statute.

The commission believes that it is appropriate to limit deferrals to instances of economic hardship or technical impracticability problems. TCAA, §382.0519(e) provides the requirements for obtaining a deferral and allows the commission discretion in whether or not to grant a deferral, based on air quality priorities. In order to appropriately exercise this discretion, the commission believes that it is proper to look to legislative intent for guidance, and where appropriate, put that guidance in the rules. This specific issue was debated in the Legislature during the discussions concerning SB 766. Based on those discussions, the commission believes that deferrals are intended for use only when a facility has clearly documented to the commission that exceptional economic hardship or specific technical impracticability problems are a barrier to implementing the reductions that would be required by the permit. Further, it was expected that the discretionary authority to defer required emission reductions would be used by the commission only in very exceptional cases. Therefore, the commission has not revised the rules.

TIP commented that the commission should add language to §116.820 to make it clear that the commission intends to interpret modification consistent with existing interpretations.

The term "modification" is defined in both TCAA, §382.003, and in Chapter 116. The commission does not intend to interpret that term any differently for the purposes of the VERP program. Therefore, the rule has not been revised.

The EPA commented that it understands that once a facility obtains a VERP, any subsequent modification of that facility must go through NSR under Chapter 116, Subchapter B.

The commission agrees with that understanding.

EPE is concerned that the rules, as proposed, impose NSR requirements for major modifications to all modifications at a VERP facility, including modifications that would be considered minor at permitted facilities, and suggested revised language.

A VERP cannot be used for a modification. TCAA, §382.0519(d) requires any subsequent modification of a facility permitted under a VERP to use the regular NSR process. The purpose of §116.820 is to implement that requirement, and does not add any additional requirements, such as imposing NSR requirements for major modifications on all modifications at VERP facilities; therefore, the rules have not been revised.

GHASP commented that the commission should require adequate public notice of proposed permits in the news media, guaranteeing coverage of the entire affected area. TCEA and LWV commented that the commission should provide adequate and timely notice to the public. TCEA and NFN added that the commission should not depend on publication only in local newspapers. One individual commented that notice should be published in the largest circulation newspaper in the area and throughout the airshed. PC commented that the commission should give information about permit applications and proposed hearings to newspapers in communities affected by transport and make this information available on the commission's website. Three individuals commented that the commission should publish notice of VERP hearings in all news media in affected areas. Six individuals commented that notice of VERP hearings should be published statewide or in all affected areas statewide, not just in local newspapers. One individual commented that notice of a VERP hearing should be published within 100 miles of the facility. Finally, one individual commented that hearing notices should be published across the entire country. Two individuals commented that the commission should require public hearings.

TCAA, §382.05191 requires an applicant to publish notice of intent to obtain a VERP in accordance with TCAA, §382.056, which outlines the procedures required of applicants for air permits. TCAA, §382.05191 also provides alternate means of notice for small business VERP applicants. Permits must be noticed in a newspaper of general circulation in the municipality in which the facility is located or the nearest municipality. If applicable, bilingual newspaper notice is required. In all cases, applicants must post signs at the facility, and the permit application must be posted in a public place. In addition, HB 801, 76th Legislature, revised the public notice requirements for commission permits and provided additional opportunities for input, e.g., earlier notice to encourage public participation. In addition to the previous notice requirements, notices of intent to obtain a permit must include information about the opportunity to be included on mailing lists to receive updates on specific applications and the opportunity for public meetings. In addition, information regarding pending permit applications is posted on the commission's World Wide Web home page.

TCAA, §382.05191 also requires that the commission provide an opportunity for a public hearing, the submission of public comment, and notice of a decision on a VERP in the same manner as provided by TCAA, §382.0561 and §382.0562, which are the hearing and notice requirements for federal operating permits. Notice of VERP hearings are published in the same manner as notice of intent to obtain a permit, as previously noted. Because the commission believes that the notice requirements will provide ample information to ensure effective public participation, the rules have not been revised.

One individual commented that the commission should require both contested case hearings and notice and comment hearings so that the public can maximally protect itself from air pollution discrimination. Two individuals commented that the commission should require public hearings. One individual, TCE, and SEED commented that they are opposed to restricting hearings that have been deemed unreasonable. One individual added that "unreasonable" is an arbitrary term subject to abuse by the commission. The EPA commented that the commission should define what is a "reasonable" or "unreasonable" request, or cross-reference appropriate definitions, as necessary. LWV commented that the commission should provide opportunities for the public to contest the issuance of a VERP if the plant poses harmful health or environmental effects that need to be addressed.

The commission has made no changes in response to these comments. The public notice provisions in the rules implement TCAA, §382.05191, which requires that the commission provide an opportunity for a public hearing, the submission of public comment, and notice of a decision on a VERP in the same manner as provided by TCAA, §382.0561. That section provides the hearing and notice requirements for federal operating permits, and provides that the commission is not required to hold a hearing if the basis of a request by a person who may be affected is determined to be unreasonable. Therefore, reasonableness is the standard by which the commission must evaluate the basis of a hearing request. The commission believes that "reasonable" is a term that is circumstantial, but with a common understanding, and therefore does not need to be defined. Under §116.842, the commission must respond in writing to any person who commented during the public comment period, or at a hearing. That response must include a statement that any person affected by the decision of the commission may petition for rehearing and may seek judicial review. The effects of the facility on the health of the public can be a subject of the comments or hearing, as the commission cannot issue a VERP that is not protective of public health.

The EPA commented that §116.840(b) allows any person affected by the emissions from a grandfathered facility to request a hearing, and that the commission should address the need to provide opportunity for persons affected by a PERC to make such a request. EPA also referenced earlier comments on HB 801.

Any grandfathered facility obtaining a VERP must provide notice and opportunity for hearing to the public, regardless of whether controls or PERCs are used. Therefore, persons affected by a PERC, i.e., those affected by the grandfathered facility will have that opportunity. The commission may not have the authority to require public notice and opportunity for a hearing at the sites where the PERCs are actually generated. For example, if a wind power electric generating facility is constructed, and it emits no air contaminants, the commission does not have the authority to require a permit for that facility. By their nature, facilities at which PERCs are generated should not have increased emissions. Therefore, the commission would have no authority for requiring a permit, and therefore, public notice and opportunity for a hearing. If, for some reason, generating a PERC caused a significant increase in emissions at a facility, those increased emissions would have to be authorized by a permit with public notice and opportunity for hearing under the existing NSR rules. Therefore, the commission has addressed the need for a person affected by a PERC to have the opportunity to request a hearing. The commission will require public notice and opportunity for public hearing in accordance with the rule implementing HB 801, to the extent that they were not modified by SB 766. Therefore, the commission refers the EPA to the response to its comments provided in the adoption preamble for the rules implementing HB 801 in the September 24 and October 15, 1999 issues of the Texas Register (24 TexReg 8147 and 9015).

The EPA commented that §116.840(c) and §116.841(a) only apply to initial issuance of VERPs. The commenter stated that the commission should address why it is not requiring notice and comment hearings for subsequent revisions which significantly change a previously permitted VERP. Although §116.820 will address this concern with respect to modifications permitted under Chapter 116, Subchapter B, it may not cover changes which are not covered under Subchapter B.

All modifications of VERP permits must comply with Chapter 116, Subchapter B, which may subsequently allow modification under other chapters or subchapters, as appropriate. Any modifications would have to be done under the normal NSR permitting system, not the VERP system. The normal NSR system utilizes contested case hearings, when triggered, not notice and comment hearings. Therefore, there is no need to address why the commission is not requiring notice and comment hearings for VERP modifications.

The CAP commented that the commission should provide examples of the types of alternative notice that will be considered acceptable under 30 TAC §39.606. These examples should be included in the application package for a small business so that business owners can begin planning an approach to notice that will satisfy the commission.

The commission agrees, and will work with the CAP and interested parties to provide examples.

One individual commented that the commission should not limit incorporation of materials by reference in §116.841(g), because not doing so wastes paper and places the burden on citizens.

The commission disagrees that the criteria provided in the rule for incorporation by reference is limiting. The criteria ensures that documents supporting comments on permits are easily obtained and verifiable, since these documents will be included in the public record concerning a VERP application.

Seven individuals, GHASP, TCEA, NFN, LWV, and SC commented that the commission should establish fees at a level that will cover the real costs of administering the program. LWV added that this would ensure opportunities for public education and effective public participation in all aspects of the decision-making process. TCE and SEED suggested using a sliding scale fee that would be linked to emission reductions; the larger the reduction, the greater the savings. They believe that the $450 flat fee sends the wrong signal, since the stimulus for using a market-based mechanism has proven to be efficient and this is a golden opportunity. PC commented that fees should vary by the size of the emissions and/or by the length of time it will take to process applications, and that the commission should bill at $250 per hour for application processing. The commenter stated that the fees for GACT and PERCs are inadequate because these applications will require a great deal of analysis and staff work. EDF commented that the fees are too low, considering the amount of review required to consider fairly the permit applications. The commenter stated that the agency will be forced to rob other parts of the agency to pay for special permits for grandfathered plants.

The application fee for new or modified facilities is 0.15% of the capital cost of a project with a $450 minimum fee and a $75,000 maximum fee. This fee structure has proven adequate to cover the cost of implementing the NSR permitting program, historically. On the average, the commission expects VERP applications to be less complicated than applications for new or modified facilities, especially when ten-year old BACT is proposed and emission reductions result in an abbreviated health effects review. Therefore, the commission believes that the $450 flat fee is sufficient. Because $450 is a relatively affordable fee for most businesses, providing a sliding scale fee which would provide any amount of incentive would require raising the upper end to a level which would not encourage companies to apply for a VERP.

The CAP commented that the commission should require a flat fee of $100 for VERPs for small businesses. The commenter stated that since this is a voluntary program, fees at $450, and especially at $1,000 will serve as a strong disincentive for participation by small businesses.

The commission agrees, and will require a $100 flat fee for small businesses that use either ten-year old BACT or GACT, and has changed the rules accordingly. Because of the complexity of verifying and tracking PERCs and determining whether a deferral would result in a reduction which helps the commission meet its air quality priorities, the commission has not revised the rules with regard to the $1,000 fees.

TIP and BMOH supported a flat application fee of $450 for all VERP applications. GPM commented that the proposed PERC fee is too expensive, and that although the commission should cover the costs of the program, fees should not be punitive, since the permitting of grandfathered facilities is voluntary. BMOH commented that the commission has failed to provide a basis for why extensive commission staff time will be required to verify the conditions of deferrals and to validate PERCs. The commenter stated that the proposal continues to attempt to penalize deferral and PERC applications, because extensive staff may also be required to verify ten-year old BACT. BMOH further commented that the preamble provides no analysis of resource requirements necessary to process permit applications and does not present a comparative analysis of the differences between the three various permit options. If the commission has such information, BMOH requested that it be provided, and the comment period extended, so that interested persons may comment upon it.

The commission has not made changes in response to these comments. In order to grant a PERC, the commission must first determine that a good faith effort has been made to meet the VERP controls (through control cost analysis, availability of technology, etc.). Additionally, the commission must analyze projects, some of which it has no previous experience reviewing, to determine that resulting reductions compensate for a facility's excessive emissions in an amount and type sufficient to prevent air pollution to the degree comparable to the reductions which would have been necessary using VERP controls. The commission would also have to verify that these reductions are enforceable, permanent, quantifiable, real, and surplus.

Similarly, in order to grant a deferral, the commission must verify that substantial reductions in air contaminants will help the commission meet its air quality priorities and verify that the applicant has demonstrated exceptional economic hardship or that technical impracticability problems are a barrier to implementing the reduction which would have been required using VERP controls. In addition, before issuing a VERP under any option, the commission must verify that the public health and property will be protected. Implementing these two approaches is expected to be more resource intensive than verifying ten-year old BACT or GACT, since there is currently a list of ten-year old BACT, and since the starting point for GACT is well known by commission staff. Given the level of review, and the complexity of the issues involved, the commission believes that it is appropriate to assess the fee, as proposed.

EDF commented that an upgrade in control method should be required at renewal if a new technology has entered the market place or if the cost of a technology formerly deemed to be uneconomic has decreased during the life of the permit.

TCAA, §382.05192 requires VERPs to be renewed consistent with the provisions of TCAA §382.055. Under that section of the TCAA, the commission may impose more stringent requirements only to avoid a condition of air pollution or to ensure compliance with otherwise applicable air quality regulations. Therefore, the rules have not been revised.

One individual commented that the commission should develop no standard permits for VERP facilities, that a health effects review should be done and made public in a timely manner for each facility, and that standard permits are less rigorous, provide less oversight, and provide no meaningful public input. Four individuals commented that the commission should not allow standard permits in nonattainment counties. SC commented that the commission should limit the use of standard permits, and one individual, GHASP, TCEA, NFN, and LWV commented that the commission should limit the use of standard permits to minor sources.

The commission believes that it may be appropriate to create standard permits for VERPs when all of the conditions of the VERP program can be met, including protection of public health and property. Standard permits are a proven mechanism for permitting similar facilities that must meet similar requirements and will provide a streamlined process for encouraging VERP applications. The commission is currently in the process of developing a VERP standard permit for cotton gins and is considering standard permits for other types of similar facilities.

The requirements in standard permits are as rigorous as case-by-case permits. TCAA, §382.05195(a)(3) requires BACT to be implemented in standard permits, except for grandfathered facilities which apply for a standard permit prior to September 1, 2001. TCAA, §382.0519 requires ten-year old BACT or GACT at grandfathered facilities, and the commission will develop any standard permits for grandfathered facilities consistent with those standards. In addition, standard permits are enforced just as any other permit issued by the commission. Therefore, the commission does not believe that standard permits are less rigorous or result in less oversight. The commission conducts a protectiveness review while developing standard permits which should be valid for facilities which meet the requirements of the standard permit. In addition, the requirements of standard permits will be made public through mechanisms in §116.603 as part of the development process. Therefore, the commission does not believe that it is appropriate to do a health effects review for each facility that uses a standard permit.

Because the limitations and requirements of standard permits would be identical to those in numerous case-by-case permits, the commission does not believe that it is appropriate to limit the use of standard permits in nonattainment counties. The commission agrees that standard permits cannot be used to authorize major new sources or major modifications under the FCAA. However, to the extent that major sources do not trigger federal permitting requirements, the use of a standard permit could be allowed, if otherwise appropriate, i.e., the facility can meet standard permit control requirements.

ATINGP commented that the commission should consider developing a VERP standard permit for compressor stations and amine plants with ten-year old BACT for attainment areas and expand the language of proposed §116.602(b)(1) to clarify that a standard permit could be developed as a VERP. ATINGP supports the voluntary program in SB 766, as it provides much needed flexibility to the members in making a determination in the VERP program. Many of the grandfathered facilities owned and operated by the members are similar in nature and design; therefore, ATINGP believes that they would be candidates for a standard permit.

TCAA, §382.05193(a)(3) allows the commission the flexibility to develop VERP standard permits. The commission believes that it may be appropriate to create standard permits for VERPs when all of the conditions of the VERP program can be met, including protection of public health and property. Standard permits are a proven mechanism for permitting similar facilities that must meet similar requirements and will provide a streamlined process for encouraging VERP applications. Therefore, the commission is considering developing a VERP standard permit for compressor stations and amine plants, and will work with interested parties, including ATINGP, in making the determination. However, the commission believes that §116.602(b)(1) is broad enough to allow standard permits to be developed based on the controls specified under the VERP program. Therefore, the rule has not been revised.

The EPA commented that it understands that standard permits are issued to minor sources or for minor modifications at major sources and that standard permits could be issued to facilities required to have a federal operating permit. The commenter asked if these standard permits could be incorporated into a facility's federal operating permit through Chapter 122's permit modification provisions.

Chapter 116, Subchapter F does not allow standard permits to be used to authorize facilities which would be major new sources, major modifications, or reconstructions of major sources under the FCAA. Therefore, facilities at major sources authorized by standard permits would be included for reference only in federal operating permits, just as for any other state NSR authorization.

GPM commented that the commission should clarify that major grandfathered sources can use standard permits if ten-year old BACT is being met without further reductions. The commenter stated that the proposed rules appear to require emission reductions even if ten-year old BACT is being met.

The commission believes that it may be appropriate to create standard permits for VERPs when all of the conditions of the VERP program can be met, including ten-year old BACT, where appropriate. Further reductions, i.e. stricter controls, would not be required unless needed to ensure that the standard permit is protective of public health and property. Chapter 116, Subchapter F does not allow standard permits to be used to authorize major new sources or major modifications under the FCAA. However, to the extent that a modification at a major source does not trigger federal permitting requirements, the use of a standard permit could be allowed, if otherwise appropriate, i.e., the facility can meet standard permit control requirements. The rules have not been revised in response to this comment.

The CAP commented that the commission should better explain how existing authorizations will be impacted by new standard permit requirements. The commenter supports the expanded use of standard permits, but the commission should explain what changes will be necessary at small businesses currently operating under exemptions from permitting and what is the schedule for those changes.

This adoption does not directly affect the authorizations most often used by small businesses, i.e., exemptions from permitting and permits by rule. The new procedures adopted at this time for developing standard permits outside of rules will make it easier for the commission to develop and amend standard permits without sacrificing input from the public or interested parties. The commission does expect that some of the more widely used and complex exemptions from permitting and permits by rule will be redeveloped as standard permits. For example, the exemptions from permitting and permits by rule for concrete batch plants will likely be redeveloped as standard permits as soon as these new procedures are in place. However, the commission does not anticipate making decisions on redevelopment of other exemptions from permitting or permits by rule until the spring or summer of 2000. At that point, interested parties, including the CAP, will be consulted.

BMOH commented that the commission should clarify the proposed preamble discussion to explicitly provide that standard permits for grandfathered applicants will not require the installation of additional controls, except in the case that a grandfathered facility must obtain a standard permit to install reasonable available control technology under other requirements.

The commission agrees that the preamble could be clarified regarding the two types of standard permits which are not required to implement BACT, i.e., VERP standard permits and pollution control standard permits. The adoption preamble has been reworded to more clearly draw a distinction between these two types of standard permits. Standard permits for VERP applicants will require either ten-year old BACT or GACT.

The EPA commented that the term "APA" in §116.601(b) is not defined.

The tern "APA" is the Texas Administrative Procedure Act, which contains the procedures for rulemaking that the commission must follow. The term is defined in 30 TAC §3.2(2), concerning Definitions.

Mobil commented that the commission should amend the rules to allow, but not require, existing adopted standard permits to continue in force for facilities already authorized by them. The commenter stated that future issued standard permits would be utilized to permit the activities of applicants subsequent to the effective date of the amended rules. Facilities currently authorized under existing adopted standard permits should be allowed to maintain their existing authorization without the threat of having the terms and conditions under which they were constructed to be amended after the fact. Mobil further stated that this has been a basic precept of regulatory action in Texas and it could be considered an inappropriate taking by the state. B&P commented that the commission should limit the applicability of §116.605(d)(1) to issued standard permits.

The rule as proposed and adopted would allow existing standard permits to continue in force for facilities already authorized by them, unless the standard permit is repealed under the APA, and amended and reissued under the procedures outlined in §116.603. However, the commission does not agree that authorization by a standard permit allows a facility to be grandfathered from future changes to those terms and conditions. TCAA, §382.05195(f) requires that a facility authorized to emit air contaminants under a standard permit shall comply with an amendment to the standard permit. Section §382.05195(f) does not differentiate between adopted and issued standard permits.

The new provisions in §382.05195 and the rules implementing them do not meet the statutory elements for being a taking under Chapter 2007, Government Code. A "taking" as defined in §2007.002 as "a governmental action that affects private real property, in whole or in part or temporarily or permanently, in a manner that requires the governmental entity to compensate the private real property owner as provided by the Fifth and Fourteenth Amendments to the United States Constitution or Section 17 or 19, Article I of the Texas Constitution," or a governmental action that "affects and owner's private real property that is the subject of the governmental action, in whole or in part or temporarily or permanently, in a manner that restricts or limits the owner's right to the property that would otherwise exist in the absence of the governmental action and is the producing cause of a reduction of at least 25 percent in the market value of the affected private real property...." "Private real property" is defined as "an interest in real property recognized by common law, including a groundwater or surface water right of any kind, that is not owned by the federal government, this state, or a political subdivision of this state."

The proposal stated that the commission does not believe this action is a taking because it does not restrict private property in a manner that restricts or limits the owners right to the property that would exist in the absence of the proposed rules. 30 TAC §101.17 provides, in part, that a variance or a permit is granted in person, and does not attach to the realty to which it relates. Thus, a permit issued by the commission does not create a property right or restrict the use of real property. The new statutory requirement to comply with amended standard permits does not restrict an interest in private real property, (i.e. land). Rather, it requires owners to comply with revised rules in order to continue to operate facilities that emit air contaminants. Construction and operation under the terms of a standard permit is not mandatory. If a standard permit is revised (or revoked) such that the owner is no longer able to meet that standard permit, other NSR authorizations may be obtained. Nothing in the adopted rules compels owners to meet certain conditions in order to continue operating. Further, §2007.003(b) provides that the provisions of that statute do not apply to actions that are taken in response to a real and substantial threat to public health and safety, that significantly advances the health and safety purpose, and imposes no greater burden than is necessary to achieve the health and safety purpose. Since the revision or revocation of a standard permit will most likely result in conditions that are more restrictive, and thus more protective of public health and safety, these provisions meet the exception in §2007.003(b).

B&P commented that §116.601(b) should be revised to provide that standard permits adopted by the commission may remain in effect even after they are repealed to ensure consistency with the time frames proposed in §116.601(e), which allows a person to rely on repealed standard permits for some time after they are repealed.

The commission agrees with the comment and has changed the rule accordingly.

The EPA commented that §116.601(d) makes it appear conceivable that an existing standard permit that the commission repeals and replaces might survive for 19.9 years without undergoing renewal. The commenter stated that the commission should address whether this is the intended effect.

The commission agrees that if an adopted standard permit is repealed and replaced with an issued standard permit, and if the commission automatically converts the registrations as provided in §116.601(d), then renewal would occur on the tenth anniversary of the converted registration. Therefore, some facilities might have as long as 19.9 years between paperwork actions required by the registrant.

TxOGA commented that the commission should maintain a clear distinction between existing program requirements for adopted standard permits and new requirements for issued standard permits under the new program. SB 766 removed the requirement that standard permits be adopted by rule, but did not rescind the authority of the commission to permit construction or modification of facilities under existing standard permits previously adopted by rule. Therefore, TxOGA recommended that the proposed rule be amended to provide that: 1) adopted standard permits may be amended as provided under the APA; 2) registrations in effect under an adopted standard permit at the time the standard permit is amended shall continue in effect unless the permittee elects to re-register the facility construction or modification under, and subject to the terms of, the amended adopted standard permit; and 3) a person having a facility registered under an adopted standard permit that is repealed and replaced with an issued standard permit has the option (but not the requirement) to re-register the facility construction or modification under, and subject to the terms of, the issued standard permit as an alternative to continuing to operate under the terms of the repealed standard permit. The commenter stated that the recommended revisions would eliminate the provisions that existing authorizations to operate under adopted standard permits be subject to periodic renewal and that they could be revoked in the event that those standard permits were at some future date repealed. These provisions create additional work for industry and the agency and introduce an element of uncertainty as to future control requirements that make use of the standard permit much less desirable than in the past. TxOGA further stated that these provisions are not mandated by statute for amended standard permits, do not exist in any other part of the NSR program, and are inconsistent with the objectives of the standard permit program, chiefly streamlining. If additional controls are needed, the existing commission regulatory structure provides a more appropriate mechanism for adoption of such requirements. B&P commented that the commission should modify the rules to reflect the fact that a facility permitted under an adopted standard permit is not bound by amendments to the standard permit, whether achieved by an actual amendment or replacement with an issued standard permit. The commenter stated that while it is true that an issued standard permit must be met on an evolving basis, it is not true of existing adopted standard permits.

The commission agrees that SB 766 did not remove the authority of the commission to authorize construction or modification of facilities under existing, adopted standard permits, to the extent that those adopted standard permits are not amended. TCAA, §382.05195(f) requires that a facility authorized to emit air contaminants under a standard permit shall comply with an amendment to the standard permit. Section 382.05195(f) does not differentiate between adopted and issued standard permits. TCAA, §382.05195(e) requires the commission to establish rules for the amendment of a standard permit. Therefore, the commission believes that it is inappropriate to amend a standard permit under the APA, since the TCAA was just amended to require the development of this new process. The commission disagrees that additional work for industry and the agency will result from the new standard permit issuance procedures. The new procedures should make it easier for the commission to develop and amend standard permits, as needed, to provide a streamlined permitting process. Because standard permits are one-size-fits-all, and facilities authorized under standard permit are not subject to a full health effects review on a case-by-case basis, the commission feels that it is necessary to be able to revise standard permits as needed to ensure that the standard permit continues to reflect current technology and emission factors, and to ensure that facilities authorized by standard permit do not become a new class of grandfathered facilities. Therefore, the rules have not been revised.

The EPA commented that the commission should address whether §116.602(b)(2) is, by definition, only limited to minor source permitting, and that the commission should also address whether there are significance levels and where they are defined.

As proposed and adopted, §116.610 lists the general requirements that registrants for standard permits must meet. Section 116.610(b) and (d) prohibit authorization of new major sources, major modifications, or reconstruction of major sources, as defined in the referenced sections, from being authorized by a standard permit.

The EPA commented that the commission should ensure that the public notice provisions in §116.603 address the EPA comments submitted for the proposed rules implementing HB 801, that were provided in a letter dated August 16, 1999.

The EPA comments on the HB 801 rules referred to specific sections of 30 TAC Chapters 39 and 55, which provide the public participation requirements for case-by-case permitting. The public participation requirements in §116.603 are meant to provide a framework for issuance of standard permits similar to the APA framework for adoption of standard permits. Standard permits are not subject to Chapters 39 or 55. The commission refers the EPA to the analysis of testimony for the rules that implement HB 801 in the September 24 and October 15, 1999 issues of the Texas Register (24 TexReg 8147 and 9015).

The EPA commented that the commission should include in §116.604(4), the criteria which was discussed on page 7153 of the proposed preamble. The commenter stated that the rule should include a replicable procedure and the criteria that the commission will use to determine whether automatic registration is appropriate. The EPA stated that this will ensure that any decision to automatically renew a standard permit is consistent with state and federal requirements.

The commission believes that discussion of its intent regarding the concept for automatic renewal in the preamble is sufficient, since automatic renewal is a permissive, non-punitive option. The commission will not automatically renew a registration inconsistent with state or federal requirements, regardless of whether that specific criteria is listed in the rule.

BMOH commented that the commission should provide at least a 180-day renewal notice to registrants, as is the case for other permit renewals.

The commission agrees, and §116.604(3) has been revised accordingly.

While reviewing the provisions of §116.605(d)(3)(D), the staff noted that the rule referred to "best achievable control technology." This term has been corrected to refer to "best available control technology.

GPM and BP Amoco commented that the commission should add language to provide a grace period for facilities to comply with an amended standard permit, when the standard permit renewal period is imminent. The commenters stated that the commission should allow facilities that are within two years of renewal the option to renew at the subsequent renewal if changes cannot be quickly made to comply with the revised standard permit. TIP commented that the commission should provide much-needed flexibility in those facilities that are within two years of standard permit registration renewal when the commission adds new requirements or limitations to a standard permit, and that the facility should be required to come into compliance with the revised standard permits at the second renewal date after the standard permit amendment. The commenter stated that as written, the provision results in fundamental inequities based on different facilities having different standard permit renewal dates. While some facilities may have close to ten years to comply with the amended standard permit, others will be forced to come into compliance in as little as one or two years. EPE commented that the commission should allow a minimum of 24 months to comply with amendments to standard permits that require changes in control equipment or will involve significant capital expenditures.

The commission agrees that a grace period is appropriate, unless the amendment is necessary to protect public health, when it amends a standard permit and has revised the rules to include a minimum two-year grace period.

B&P commented that §116.605(e) should be revised to provide that registration is required at the same time the facility is required to comply with the amended standard permit under §116.605(d)(1).

The commission believes that the rule as proposed allows for registration and compliance dates to coincide and gives the commission the flexibility to set earlier registration dates in each standard permit. Delaying registration until the compliance date will not give commission staff adequate time to review the registration. Thus, a facility may not have the assurance that they meet the requirements of the revised standard permit prior to the compliance date. Therefore, the rule has not been revised.

The EPA asked, regarding §116.605, "If a standard permit is amended or revoked at a facility required to have a federal operating permit, would this amendment or revocation be reflected in the facility's Federal Operating Permit through Chapter 122's permit modification provisions"?

Chapter 116, Subchapter F does not allow standard permits to be used to authorize facilities which would be major new sources, major modifications, or reconstructions of major sources under the FCAA. Facilities at major sources authorized by standard permits would be included for reference only in federal operating permits, just as for any other state NSR authorization. Therefore, any amendment or revocation of a standard permit which is listed for reference only in a federal operating permit would be reflected using the administrative revision process.

EPE commented that the commission should revise §116.605(f) to specify a time period for applying for a permit or for an authorization under Chapter 106 if a standard permit is revoked. The commenter stated that the commission should also specify that a facility operating under a standard permit that has been revoked may continue to operate under the conditions of the revoked permit until the new permit is either approved or denied.

The commission believes that the revocation of a standard permit will be a rare event. If a standard permit is revoked, the notice to the registrant will specify a date for compliance with another appropriate authorization. The commission believes it would be inappropriate to allow the facility to continue to operate under a revoked standard permit if a revocation were based on health concerns. Therefore, no time period has been specified in the rule.

TxOGA commented that the commission should specifically provide that more stringent requirements or limitations in an amended issued standard permit, or revocations of an issued standard permit, shall be made applicable to a facility registered under the existing standard permit only when continued operation under the existing permit requirements contravenes the TCAA. The commenter stated that the commission was given broad discretion to amend or revoke an issued standard permit in such a manner that the new requirements or revocation would have to be applicable only to facilities constructed or modified under that standard permit after the effective date of the amendments, consistent with current NSR authority. This could be done by making new requirements date-specific, with permittees having the option to voluntarily re-register facilities under, and subject to the requirements of, the amended issued standard permit. In the case of revoked standard permits, the statutory intent could be accomplished by making the revocation prospective only. TxOGA believes that the proposed §116.605(d)-(f) may be broad enough to provide the agency with the discretion allowed by the statute, but they urged that the commission clarify its regulation to clearly state the extent of the agency's discretion in this regard.

TCAA, §382.05195(f) states that a facility authorized to emit air contaminants under a standard permit shall comply with an amendment to the standard permit. It does not limit the commission's discretion regarding the basis for an amendment. The proposed rules provided criteria the commission would consider when determining whether to amend or revoke a standard permit. The commission does not believe that the statute intends grandfathering in the context of standard permits, and that the statute provides a consistent regulatory basis for all facilities using standard permits. Therefore, the rule has not been revised to limit the applicability of amendments to standard permits to instances where the intent of the TCAA has been contravened. The commission disagrees that there is discretion under §382.05195(f) to provide the option for existing, unmodified facilities to continue operating under the previous version of the standard permit, indefinitely. However, as standard permits are amended or revoked, the commission will consider on a case-by-case basis whether existing facilities should continue to operate for a specified, extended period of time under the previous version of the standard permit.

BMOH commented that the commission should clarify that standard permits for existing facilities will only be amended to require additional controls if the commission finds that a condition of air pollution exists or there is a change in the method of operation of the unit operating under the standard permit. The commenter recommended either deleting §116.605(d)(3)(D); clarifying that existing registrants need not comply with amended standard permits to implement changes in BACT; creating additional standard permits for facilities constructed or modified after a certain date; or allowing them to convert a standard permit into a traditional NSR permit with the standard permit terms and conditions. The commenter stated that while SB 766 requires permittees to comply with amended permits, it does not limit the commission from establishing multiple standard permits for similar facilities based upon the date the facility was last modified. By way of comparison, under NSR, a facility is not subject to continual changes unless a modification is made. BMOH also commented that the commission should clarify its intentions on updating standard permits to reflect current BACT and to provide assurances in the rules that existing registrations will not be adversely affected by permit amendments to update BACT. GPM, BP Amoco, and TIP commented that the commission should set a very high bar for amending or revoking standard permits, and that standard permits should only be revisited if the permit is no longer protective of public health. The commenters disagreed with the provisions of §116.605(d)(3)(D) which would potentially revisit standard permits based on technology requirements, and stated that these provisions are inconsistent with other NSR provisions.

TCAA, §382.05195(f) states that a facility authorized to emit air contaminants under a standard permit shall comply with an amendment to the standard permit. Section 382.05195(f) does not limit the commission's discretion regarding the basis for an amendment. The commission believes that the statute intended for all similar facilities using standard permits to meet the same standard permit. Since the statute requires facilities to meet amended standard permits, the commission does not believe that it provides for the concept of grandfathering in the context of standard permits. In addition, the statute was amended to require BACT for all non-VERP standard permit applications. Accordingly, the commission believes that it is required to amend standard permits, at least for new or modified facilities, if BACT changes. Therefore, the rule has not been revised to limit the applicability of amendments to standard permits to instances where a condition of air pollution exists, there is a change in the method of operation, or BACT has changed. For the same reason, the commission believes that it would be inconsistent with the statute to maintain multiple standard permits applicable to similar facilities. The commission agrees that it might be appropriate to convert authorizations under a standard permit to an NSR permit if all the procedures for NSR initial issuance are followed, including public notice requirements. The rule has not been revised because applicants can apply for an NSR permit under the current rules. The commission believes that the appropriate flexibility for existing facilities would best be provided through the use of extended compliance dates in amended standard permits. The commission will consider, on a case-by-case basis, whether existing facilities should continue to operate for a specified, extended period of time under the previous version of the standard permit. Because of the ability to extend compliance dates in amended standard permits for existing facilities, and the opportunities that the issuance procedures provide for input by interested parties, the commission does not believe that existing registrations will be adversely affected by standard permit amendments.

BMOH commented that the commission should provide advanced written notice to existing registrants of proposed amendments to ensure full public participation in the process by those whose interests are directly affected.

The commission agrees that written notice will be provided to registrants and any persons requesting to be on a mailing list concerning amendment or revocation of a specific standard permit. Accordingly, §116.605(c) has been revised.

BMOH commented that there is no reason or basis under the TCAA for the commission to consider the amount of time that has elapsed since the last amendment to a specific standard permit when determining whether a standard permit should be amended. The commenter stated that the commission should focus on air pollution issues, and that for it to impose more rigorous controls merely due to the amount of time that has elapsed is not consistent with the TCAA.

By including the provision for consideration of time in §116.605(d)(3)(E), the commission was trying to provide some assurance that standard permits would not be frequently amended, unless requested by the affected parties or the public. However, since the commission has agreed to provide extended compliance dates for existing facilities, when appropriate, in each amended standard permit, the commission agrees that §116.605(d)(3)(E) is unnecessary, and it has been deleted.

BMOH commented that the commission provides no support for its conclusion that the proposed rules requiring compliance with amended standard permits will not have an adverse affect on the public. The commenter stated that the commission provides only conclusory statements in this regard; therefore, the analysis is flawed and does not comport with the APA.

Section 2001.0225 of the Government Code states that "before adopting a major environmental rule subject to this section, a state agency shall conduct a regulatory analysis that: considers the benefits and costs of the proposed rule in relationship to state agencies, local governments, the public, the regulated community, and the environment." If this comment was directed at adverse effects on the "public" as stated, those effects are largely unknown but are not anticipated to be significant.

If the comment was directed at adverse effects on the regulated community, it is anticipated that the proposed amendments related to revisions of standard permits could have adverse implications to certain facilities, but the standard permit process is optional and voluntary. It is not known how widespread adverse effects might be. However, the commission will work with interested and affected parties when amending standard permits to mitigate any adverse effects and has added language to §116.605 to clarify that compliance with an amended standard permit would not occur earlier than two years after the amendment, unless public health is being adversely affected.

In addition, §2001.0225 requires an analysis of the rule if the rule meets the definition of a "major environmental rule" and also meets the applicability requirements stated in the Act. If the rule is disqualified for either the definition or the applicability requirements, there is no requirement to accomplish the analysis. Because the commission believes that the provisions regarding standard permits do not constitute a major environmental rule and because the rule was also disqualified by failing to meet the applicability requirements, a full regulatory impact analysis is not required.

The CAP commented that the commission should establish methods for sharing registrations among multiple government agencies or units within the commission. A small business owner attempting to comply with numerous different regulations can unintentionally file these copies incorrectly, and may not be aware of any local programs having jurisdiction. The preference is one central contact at the commission who would make the information available to other agencies or relevant commission programs.

The CAP commented that the commission should establish methods for sharing registrations among multiple government agencies or units within the commission, and that a small business owner attempting to comply with numerous different regulations can unintentionally file these copies incorrectly, and may not be aware of any local programs having jurisdiction. The commenter's preference is one central contact at the commission who would make the information available to other agencies or relevant commission programs.

The commission agrees that appropriate methods should be developed to assist small businesses in their submittal of registrations to the commission and to local governments and commits to developing this assistance. The Air Permits Division and the Small Business and Environmental Assistance program, with input from the CAP, will work together to develop an acceptable solution.

GPM, BP Amoco, and TIP commented that §116.614 should be revised to indicate that no fee would be required for automatic standard permit renewal, since minimal agency time should be required on behalf of individual applicants.

The commission agrees, and has revised §116.614 accordingly.

The CAP commented that the commission should consider a flat fee of $100 for small businesses, and as a substitute, allow payment by installments as a secondary alternative. The commenter stated that the $450 fee in the proposal might present a financial challenge to small businesses when considered in addition to the expenses of complying with the standard permit.

The commission agrees that it may not always be appropriate to charge a fee for standard permits used by small businesses. For example, if an existing permit by rule is changed into a standard permit, the commission would need to consider the amount of agency review time that would be required when assessing whether or not a fee should be charged. If the commission determines that no fee or a lower fee should be charged for that particular standard permit, §116.614 allows the commission the discretion to make that determination on a case-by-case basis. Therefore, the rules have not been revised in response to the comment.

BMOH commented that the fee for a standard permit registration should fall in the range of $100-150, and that the preamble does not provide any analysis that the fee is necessary to recoup the commission's costs for administering the program as required by §382.062 of the TCAA.

The commission did not propose to change the existing fee of $450 for standard permit registrations. Instead, the proposal revised the rules to allow the commission the discretion to charge a fee, if any, other than $450 for a particular standard permit. If, in the future, the commission elects to charge a fee other than $450, the analysis will be provided on a case-by-case basis at that time and affected parties will have the opportunity to comment. Therefore, the rules have not been revised in response to the commenter.

Subchapter A. DEFINITIONS

The Texas Natural Resource Conservation Commission (TNRCC or commission) adopts new §116.18, Electric Generating Facility Permits Definitions; §116.910, Applicability; §116.911, Electric Generating Facility Permit Application; §116.912, Electric Generating Facility Permit Application for Electing Electric Generating Facilities; §116.913, General and Special Conditions; §116.914, Emissions Monitoring and Reporting Requirements; §116.916, Permits for Grandfathered and Electing Electric Generating Facilities in El Paso County; §116.920, Public Participation for Initial Issuance; §116.921, Notice and Comment Hearings for Initial Issuance; §116.922, Notice of Final Action; §116.930, Modifications; and §116.931, Renewal. Sections 116.18, 116.910 - 116.914, 116.916, 116.920 - 116.922, and 116.931 are adopted with changes to the proposed text as published in the September 10, 1999 issue of the Texas Register (24 TexReg 7163). Section 116.930 is adopted without changes and will not be republished. The new sections will be submitted as a proposed revision to the state implementation plan (SIP).

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

Senate Bill 7 (SB 7), 76th Legislature, 1999, amended Texas Utilities Code (TUC), Title 2, concerning Public Utility Regulatory Act, Subtitle B, concerning Electric Utilities, and created a new TUC, Chapter 39, concerning Restructuring of Electric Utility Industry. SB 7 requires the commission to implement the permitting and allowance requirements of new TUC, §39.264, concerning Emissions Reductions of "Grandfathered Facilities." Section 39.264 requires electric generating facilities (EGF) that were existing on January 1, 1999, and that were not subject to the requirement to obtain a permit under Texas Clean Air Act (TCAA), §382.0518(g) to obtain a permit from the commission. These facilities are referred to as grandfathered facilities. A grandfathered facility is one that existed at the time the Legislature amended the 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.

These new sections are adopted concurrently with amendments and new sections in 30 TAC Chapter 101, concerning General Rules. The new Division 2, concerning Emission Banking and Trading of Allowances, in the new Chapter 101, Subchapter H, concerning Emissions Banking and Trading, sets out the allowance system to be used to assist grandfathered and electing EGFs in meeting the emission reduction requirements of TUC, §39.264. The purpose of the rulemaking in these chapters is to implement permit and emission control requirements, including emission banking and trading of allowances (EBTA), for grandfathered and electing EGFs and related permit application and public notice procedures. The permit application and public notice procedures are the subject of these amendments to Chapter 116. The adopted amendments to Chapter 101 are published in this issue of the Texas Register .

TUC, §39.264 requires owners or operators of grandfathered EGFs to apply for a permit to emit nitrogen oxides (NO _x ) and, for coal-fired grandfathered EGFs, sulfur dioxide (SO ₂ ) and particulate matter (PM) through opacity limitations. These applications are due on or before September 1, 2000. A grandfathered EGF that does not obtain a permit may not operate after May 1, 2003, unless the commission finds good cause for an extension. It is the intent of TUC, §39.264 that for the 12-month period beginning May 1, 2003, and for each 12-month period following, annual emissions of NO _x from grandfathered EGFs not exceed 50% of the NO _x emissions reported to the commission for 1997. Furthermore, it is the intent of the legislation that emissions of SO ₂ from coal-fired grandfathered EGFs not exceed 75% of the SO ₂ emissions reported to the commission in 1997. The described emission limitations may be satisfied by using control technology or by participating in the banking and trading of allowances. In addition, TUC, §39.264(e) requires electric generating facility permit (EGFPs) for coal-fired, grandfathered EGFs to contain appropriate opacity limitations provided by the commission's rules in §111.111, of this title, Requirements for Specified Sources, thus permitting emissions of particulate matter.

Persons, municipal corporations, electric cooperatives, and river authorities owning permitted EGFs may elect to become subject to the permitting requirements and emission reductions. A municipal corporation, electric cooperative, or river authority may exclude any grandfathered EGF with a nameplate capacity of 25 megawatts or less from permitting and emission reduction requirements. TUC, §39.264(d) requires notice of the intent to exclude these grandfathered EGFs by January 1, 2000.

SECTION BY SECTION DISCUSSION

The new §116.18 contains the following definitions. The definitions of "Allowance," "Coal," "Coal-fired," "Compliance account," "Control period," "Electric generating facility," "Electing electric generating facility," "Grandfathered electric generating facility," and "Person" were all revised to cross-reference concurrently adopted definitions of these terms in 30 TAC §101.330, Definitions. "Nameplate capacity" means the maximum electrical output (expressed in megawatts) that an EGF can sustain over a specified period of time when not restricted by seasonal or other deratings. This definition is consistent with the definition used in the Federal Clean Air Act (FCAA) Amendments of 1990, Acid Rain Program. The commission believes that using this definition will reduce any confusion for grandfathered EGFs that are potentially subject to both the Acid Rain Program and the EBTA program proposed under Chapter 101, Subchapter H, Division 2. A "Peaking unit" is an EGF that has: 1) an average capacity factor of no more than 10% during the past three calendar years; and 2) a capacity factor of no more than 20% in each of those calendar years. "Capacity factor" is either: 1) the ratio of an EGF's actual annual electric output (expressed in megawatt-hours) to the EGF's nameplate capacity times 8,760 hours; or 2) the ratio of an EGF's annual heat input (in millions of British thermal units (MMBtu)) to the EGF's maximum design heat input (in MMBtu) times 8,760 hours. Both terms, "Peaking unit" and "Capacity factor," are consistent with the same terms in the FCAA Acid Rain Program.

Section 116.910 states that a permit under this Subchapter I would authorize emissions of NO _x for any grandfathered EGF, and PM through opacity limitations and emissions of SO ₂ for coal-fired grandfathered EGFs. Owners or operators of electing EGFs may opt to obtain allowances under the EBTA in Chapter 101, Division 2. The electing EGF's existing new source review (NSR) permit will be altered using the procedures in §116.116(c). This NSR permit alteration will ensure that the existing NSR permit is changed to cross-reference to the EGFP. Section 116.910 specifies that the owner or operator who is authorized to act for the owner of a grandfathered or electing EGF is responsible for complying with Subchapter I. Consistent with TUC, §39.264(d), a municipal corporation, electric cooperative, or river authority may exclude any grandfathered EGF with a nameplate capacity of 25 megawatts or less from Subchapter I. The municipal corporation, electric cooperative, or river authority must notify the commission by January 1, 2000, of its intent to exclude those grandfathered EGFs. In response to comments, the commission has revised §116.910(d) to allow municipal corporations, electric cooperatives, or river authorities to notify the commission of its intent to obtain a permit after January 1, 2000. Applications must still be submitted by the statutory deadline of September 1, 2000. A new §116.910(g) was added to the adopted rule that excludes an EGF that generates electric energy primarily for internal use, but that during 1997 sold, to a utility power distribution system, less than one-third of its potential electrical output capacity or less than 219,000 megawatt-hours. This exclusion eliminates cogeneration facilities that the commission believes were not intended to be included in this program. The reference to 219,000 megawatt-hours is added to exempt small cogenerators who may exceed the one-third limitation. This is more consistent with the Acid Rain Program exemption for affected units.

TUC, §39.264 requires grandfathered EGFs to obtain a permit from the commission that authorizes the emission of NO _x and, for coal-fired EGFs, PM through opacity limitations and SO ₂ . Grandfathered EGFs also emit products of combustion such as carbon monoxide (CO) and volatile organic compounds (VOC). At a coal-fired grandfathered EGF, the emissions may include mercury as well. The commission believes that the TUC, §39.264 authorization was only intended to authorize NOx and, if applicable, PM through opacity limitations and SO ₂ . The commission also believes that the intent of TUC, §39.264 was to eliminate the grandfathered status of EGFs. However, it is unclear how TUC, §39.264 authorizes or requires the permitting of anything other than NO _x and for coal-fired EGFs, PM through opacity limitations and SO ₂ . Furthermore, if the commission were to permit these other air contaminants in an EGFP, it is unclear what standards should be applied to these air contaminants. Therefore, the commission will use the emission control standards of the voluntary emission reduction permit (VERP) program adopted concurrently in this issue of the Texas Register under 30 TAC Chapter 116, Subchapter H, Voluntary Emission Reduction Permits. These other air contaminants from the EGFs will be reviewed under the requirements of the VERP program, but would only go through the public notice process one time.

The commission believes that it is appropriate to rely on the control methods and health effects requirements of the VERP program for the other air contaminants. The VERP program provides control method options that depend on the location of a grandfathered facility. The VERP program also describes the suggested methods for a health effects review for grandfathered facilities. The reliance on the VERP control methods and health effects review will provide a consistent basis of review for the other emissions from all grandfathered EGFs. The commission does not think it is appropriate to merely include other emissions in a grandfathered EGF's permit without a review of control methods and, if necessary, impacts. This is consistent with the commission's longstanding policy to not treat certain facilities as being "permitted" simply because the facilities are consolidated into an existing permit. For example, a facility that was originally authorized by an exemption will continue to be authorized under the exemption even though the exemption is consolidated with an NSR permit during an amendment or at renewal. The final rules do not require applicants to permit these other air contaminants from EGFs.

Many power plants may have other grandfathered support facilities such as fuel storage tanks or coal handling facilities that are not EGFs. Because TUC, §39.264 addresses only those facilities which generate electricity for compensation, these support facilities are not explicitly required to obtain a permit under TUC, §39.264. To encourage the permitting of grandfathered support facilities, these facilities could apply for a VERP which would be consolidated with the EGFP. This would enable all the grandfathered facilities and EGFs at a site to go through a consolidated permitting process. Thus, all grandfathered facilities and EGFs would only go through the public notice process one time.

To address electing EGFs, §116.910(b) provides that the existing NSR permit be altered using the procedures in §116.116(c), Alterations. The altered NSR permit would continue to authorize emissions of all air contaminants, and would include a reference to the EGFP. The EGFP will contain the general and special conditions for electing EGFs. The unchanged, existing NSR permit conditions would not be subject to public notice since that permit will only be altered to reflect the existence of the EGFP.

The new §116.911 contains application procedures for grandfathered and electing EGFs to obtain an EGFP. As specified by TUC, §39.264(e), the new §116.911 requires owners or operators of grandfathered and electing EGFs to apply for a permit on or before September 1, 2000. The section also contains information concerning general content of the permit application for both grandfathered and electing EGFs. Emissions of air contaminants other than NO _x or, if applicable, PM through opacity limitations and SO ₂ from an electing EGF already authorized by Chapter 116, are not required to be authorized under this subchapter. An EGFP will include provisions for measurement of emissions, monitoring, and reporting to calculate actual emissions over a control period. Although control technology is not explicitly required under TUC, §39.264, grandfathered or electing EGFs may propose the use of controls in their initial applications. The new provisions in §116.911(a)(2) require new controls to comply with specified provisions in §116.617, Standard Permits for Pollution Control Projects. The commission believes that relying on these existing procedures for the installation of controls will provide an efficient review process. The new §116.911(a)(3) specifies that, in cases where there are increased emissions from the addition of new controls, air dispersion modeling and/or ambient monitoring may be required to determine off-property impacts. TUC, §39.264(e) requires coal-fired EGFs to comply with the opacity limits specified in commission rules. Applicants must submit an application for an EGFP under the seal of a Texas licensed professional engineer, consistent with §116.110(e), concerning Applicability.

In response to comments, the commission deleted the references to federal rules and regulations in §116.911 and §116.913. This deletion will simplify the application process for EGFPs. However, EGFs must comply with any applicable federal requirements, including, but not limited to, nonattainment review, Prevention of Significant Deterioration (PSD) review, New Source Performance Standards (NSPS), National Emission Standards for Hazardous Air Pollutants (NESHAPS), and NESHAPS for Source Categories. EGFs that are affected sources under FCAA, §112(g), concerning Modifications, must comply with those requirements. The issuance of an EGFP does not modify or limit the applicability of these federal programs. If, during the review of an application for an EGFP the commission determines that the EGF is not in compliance with any applicable state or federal standards, the commission will initiate the appropriate enforcement action which may include a requirement to obtain an NSR permit or the applicable federal permit.

EGFs that are currently authorized under Chapter 116 may elect to participate in the EBTA under Chapter 101, Subchapter H, Division 2. The proposed §116.912 contained application requirements for electing EGFs that were in addition to those contained in the proposed §116.911. Those requirements are now in §116.911(b). Since an existing NSR permit may authorize multiple facilities, the permit application submitted under Subchapter I should identify which EGFs are to be included in the EGFP. The application must include documentation of the emissions from the 1997 Emissions Scorecard from the United States Environmental Protection Agency (EPA) Acid Rain Program, or if that information is not available, the actual emissions from that electing EGF for calendar year 1997. Applications must contain documentation of actual emissions as well as fuel consumption, fuel heating values, and heat input in MMBtu for calendar year 1997. This information will be used to calculate allowances for these EGFs and provide the data needed to meet the requirements of TUC, §39.264(i)(3), which restricts the banking and trading of allowances that result from reduced utilization and shutdown.

The new §116.912 was renamed "Electing Electric Generating Facilities." The proposed §116.912 contained the application content requirements for electing EGFs. These requirements were moved to the new §116.911(b). Section 116.912 now contains the requirements for opting in and out of the permitting program. An electing EGF may opt out of the requirements of this subchapter under certain conditions. The electing EGF must notify the commission of its intent to opt out prior to the beginning of the next control period and may not opt out during a control period. This notification requirement would prevent an EGF from opting out in order to avoid being out of compliance with the requirement to not exceed its allowances. The decision to opt out will become effective at the beginning of the control period following notification to the commission. All allowances for the electing EGF will be voided by the commission and may not be banked for subsequent use. Since the EGF would no longer be subject to the restrictions of the EBTA, it would be inappropriate to use those allowances at other EGFs, and no allowances will be allocated for subsequent control periods. Once an EGF has opted out, the EGF may not participate in the EBTA at any future date. Since TUC, §39.264 states that EGFs must elect to participate prior to September 1, 2000, there is not a subsequent opportunity for those EGFs to reelect. The commission believes that a one-time election and a one-time opt out provide sufficient flexibility without undermining the program. The owner or operator shall request an alteration to the electing facility's NSR permit to remove the conditions pertaining to the EGFP. This alteration would restore the NSR permit to its prior status.

The new §116.913 contains general conditions applicable to every EGFP unless specified differently in the permit, and authorizes the commission to include special conditions in the permit. An EGFP would authorize NOx emissions from EGFs, and from coal-fired EGFs, SO2 emissions and PM through opacity limitations. The EGF must comply with the EBTA in Chapter 101, Subchapter H, Division 2. In response to comments, former §116.913(a)(1)(C), concerning emissions of air contaminants other than NO _x , SO ₂ , and PM through opacity limitations from grandfathered EGFs, as defined in §116.10, concerning General Definitions, was reorganized and its provisions are now in §116.913(a)(2) and (3). An EGFP may permit emissions of all other air contaminants from grandfathered EGFs, provided the requirements of Chapter 116, Subchapter H are met. VERPs for grandfathered facilities as defined in §116.10 at sites with grandfathered or electing EGFs may be consolidated with an EGFP. The provisions for the EBTA require EGFs to maintain allowances in a compliance account. The EBTA in Chapter 101 contains all provisions for managing allowances. For emissions of NO _x and, where applicable, SO ₂ , the EGF shall hold in its account, on June 1 after every control period, a quantity of allowances equal to or greater than the amount of that air contaminant emitted since May 1 of the previous year. Holders of EGFPs shall comply with this requirement beginning May 1, 2004. Beginning May 1, 2004, holders of EGFPs must report annual actual emissions of NO _x and, if applicable, SO ₂ , for the previous control period. This emissions report must be submitted by June 30 of each year, and will be used to determine compliance with the requirement that the EGF hold allowances equal to or greater than the emissions over a given control period. The adopted section implements TUC, §39.264(e) and requires coal-fired EGFs to comply with the opacity limits specified in commission rules.

The new §116.914 specifies monitoring and reporting requirements for EGFPs, and the adoption was reorganized for clarity in response to comments. The commission is required by TUC, §39.264(k) to provide methods for use in determining compliance with permits and methods for monitoring and reporting actual emissions of NO _x and, if applicable, SO ₂ . Title 40 Code of Federal Regulations (CFR) Part 75, concerning Continuous Emission Monitoring Under the Acid Rain Program (Acid Rain Program), contains monitoring requirements for SO ₂ for affected units under that program. Since the acid rain program already requires extensive monitoring, the adopted rule authorizes the use of that monitoring for EGFs that are subject to the acid rain program for compliance with Subchapter I. EGFs not subject to the Acid Rain Program would have three choices in monitoring. The EGF may choose to meet either Part 75 monitoring requirements, or the requirements of Title 40 CFR Part 60, or the EGF may provide an alternative monitoring plan that would be incorporated into the permit conditions. Part 60 requirements are adopted as an alternative to Part 75 in order to be consistent with current NSR practices for facilities not required to comply with Part 75. Since Part 60 monitoring may be less accurate than Part 75 monitoring, the adopted rule requires Part 60 monitored data to have a relative accuracy of greater than 10% (i.e., measured values within 90-100% of the correct value). To account for this inaccuracy, the monitored value must be multiplied by a factor of 1.1. This factor has been included to account for the inequity between the monitoring accuracy of Parts 75 and 60. The commission believes that this factor, proposed in the Ozone Transport Commission's (OTC) Model Rule, is appropriate for the EBTA as well, based on the similarity of the OTC requirements and the goals of TUC, §39.264. The OTC Model Rule implements a NO _x emission budget program to reduce ambient ozone concentrations. Although Texas is not required to participate in the OTC budget program, the commission believes that it is appropriate to model this budget rule after the OTC model rule. Additionally, EGFs with a heat input of less than 100 MMBtu/hour could use Appendix E of 40 CFR Part 75 to estimate NO _x emissions. Appendix E relies on stack testing of the facility to develop a relationship between the emission rate and heat input. The commission believes that it is appropriate to structure the monitoring requirements of Subchapter I on these existing requirements because many EGFs are currently using Part 75 and Part 60 monitoring methods. Data collected from these monitoring requirements would be used to calculate annual emissions that are reported to the commission for the purpose of demonstrating compliance with allowances. The new §116.914 also specifies that data collected from the monitoring of EGFs shall be detailed in an annual report as required under §116.913(a)(7). The commission will develop a form, AR-1, specifying the requirements of the report, which would be due on June 30 of each year.

The new §116.916, concerning Permits for Electric Generating Facilities in El Paso County, was renamed to "Permits for Grandfathered and Electing Electric Generating Facilities in El Paso County." Consistent with TUC, §39.264(q), §116.916 would exempt EGFs in El Paso County from NO _x allowance requirements if the commission or EPA determines that reductions in NO _x emissions would lead to increased ambient levels of ozone. Currently, NO _x reductions are not required for facilities in the El Paso nonattainment area because EPA has granted a waiver under FCAA, §182(f). Under this waiver, NOx reductions are not required if the attainment demonstration for compliance with the ozone National Ambient Air Quality Standard (NAAQS) can be made without a NO _x control strategy. The existence of this waiver is not consistent with the provisions of TUC, §39.264(q) because it has not been demonstrated, under the §182(f) waiver or otherwise, that NO _x reductions would increase ambient ozone in El Paso County. These EGFs would still be required to obtain a permit under 30 TAC Chapter 116, Subchapter I regardless of the determination that NOx reductions are counterproductive in controlling ambient ozone levels in the El Paso Region. The commission believes that this requirement is appropriate, since TUC, §39.264(e) provides that EGFs without a permit may not operate after May 1, 2003, and TUC, §39.264(q) refers only to reduction requirements, not permitting requirements. Regardless of this determination, grandfathered EGFs in El Paso County would still be required to obtain a permit under Subchapter I.

The new §116.920 would require that applicants for initial issuance of an EGFP publish notice of intent to obtain a permit in accordance with 30 TAC Chapter 39, Subchapter K, concerning Public Notice of Air Quality Applications. Subchapter K implements the new requirements of TCAA, §382.056, as amended by the 76th Legislature by House Bill (HB) 801, an act relating to Public Participation in Certain Environmental Permitting Procedures of the TNRCC. TUC, §39.264 provides that public participation for initial issuance of an EGFP 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, and require the commission to send notice of final action to persons who comment during the comment period or during a hearing. The adopted requirements of §116.920, 116.921, and 116.922 are based on the sections in 30 TAC Chapter 122, concerning Federal Operating Permits, that implement the requirements of TCAA, §382.0561 and §382.0562. Section 116.920 provides that any person who may be affected by emissions from the EGF may request a notice and comment hearing on an EGFP application within 30 days after the publication of Notice of Receipt of Application and Intent to Obtain Permit under §39.418, concerning Notice of Receipt of Application and Intent to Obtain Permit. Grandfathered support facilities that elect to obtain a VERP and have it consolidated with an EGFP may publish a combined notice. Electing EGFs that are included in an EGFP are only included for the purpose of authorizing NO _x emissions, and if applicable, PM through opacity limitations and SO ₂ . The conditions of the electing EGF's existing NSR permit would be altered to cross-reference the EGFP. Since the rule was revised to require alterations to the electing EGF's existing NSR permit, the provision in §116.920(c), concerning public notice for emissions of air contaminants other than NOx , or if applicable, SO ₂ , was deleted. The existing NSR permit conditions would not be subject to public notice. Any conditions in the EGFP concerning the electing EGFs would be subject to public notice. Persons affected by a decision to issue or deny an EGFP will be entitled to petition for a rehearing under the appropriate procedure in Chapter 50, concerning Action on Applications and Other Authorizations, and may seek judicial review under TCAA, §382.032, concerning Appeal of Commission Action. The commission made clerical changes to §116.920 to include references to grandfathered and electing EGFs and renumbered that section, since §116.920(c) was deleted. Section 116.920(g), now §116.920(f), was revised to clarify that a person affected by a decision of the commission to issue or deny an EGFP may seek judicial review. This change makes this subsection consistent with the language in §116.922(b)(3).

The commission made clerical revisions to §116.921 to add the terms "grandfathered" and "electing EGFs" as well as to delete references to draft permits and refer instead to draft EGFPs. The new §116.921 contains the hearing requirements for the initial issuance of EGFPs. The rule allows the commission to decide whether to hold a hearing based on the reasonableness of a request. The commission is not required to hold a hearing if the basis of the request by a person who may be affected by emissions from the grandfathered or electing EGF is determined to be unreasonable. If a hearing is requested by a person who may be affected by emissions from the grandfathered or electing EGF, and that request is reasonable, the commission will hold a hearing. The section requires that notice of hearing on a draft EGFP be published in the public notice section of one issue of a newspaper of general circulation in the municipality or the nearest municipality where the EGF is located. The notice must be published at least 30 days prior to a hearing. The notice is published at the applicant's expense and the rule specifies the content of the notice. The rule provides the procedures for the submittal of comments at a hearing and specifically states that the period for submitting written comments extends to the close of the hearing and may be extended beyond the close of the hearing. Any person, including the applicant, may submit comments on whether the draft EGFP contains inappropriate conditions or whether the preliminary decision to issue or deny the EGFP is inappropriate. Commenters shall raise all issues and submit all comments supporting their position by the end of the public comment period. This requirement will assist the commission in developing its response to comments as required by new §116.922. To ensure a complete record of the comments, the rule prohibits the incorporation by reference of supporting materials for comments unless the materials meet the criteria in §116.921(g). The commission is required to keep a record of all comments submitted or raised at a hearing and to have an audio recording or written transcript of the hearing, and the record is available to the public. Draft EGFPs may be revised based on comments pertaining to whether the permit provides for compliance with the requirements for an EGFP.

The new §116.922 was revised to include a reference to the draft EGFP. The new §116.922 requires the commission to individually notify persons who commented, either 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 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 under the appropriate procedure in Chapter 50, concerning Action on Applications and Other Authorizations, and may seek judicial review under TCAA, §382.032.

TUC, §39.264 does not provide procedures for the modification of an EGFP. The commission believes that the requirements of the TCAA concerning modifications of existing facilities still apply. Therefore, the new §116.930 requires that any modifications to any facility in an EGFP are subject to the permitting requirements of the TCAA and the existing modification requirements in 30 TAC Chapter 116, Subchapter B.

Consistent with TUC, §39.264(r), the new §116.931 requires EGFPs to be renewed under the requirements of 30 TAC Chapter 116, Subchapter D, concerning Permit Renewals. The commission made a clerical revision to this section to delete the abbreviation of EGFP.

FINAL REGULATORY IMPACT ANALYSIS

The commission has reviewed the rulemaking in light of the regulatory analysis requirements of Texas Government Code, §2001.0225, and has determined that the rulemaking meets the definition of a "major environmental rule" as defined in that statute. "Major environmental rule" means a rule the specific intent of which is to protect the environment or reduce risks to human health from environmental exposure, and that may adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state. The adopted amendments to Chapter 116 are intended to protect the environment or reduce risks to human health from environmental exposure and may have adverse effects on grandfathered and electing EGFs which could be considered a sector of the economy. However, the analysis required by §2001.0225(c) does not apply, because the adopted amendments do not meet any of the four applicability requirements of a major environmental rule. The new sections do not exceed a standard set by federal law, exceed an express requirement of state law, or exceed a requirement of a delegation agreement, and they are not adopted solely under the general powers of the agency. The amendments to Chapter 116 are adopted specifically to implement TUC, §39.264. TUC, §39.264 requires grandfathered EGFs apply for a permit by September 1, 2000, and obtain a permit by May 1, 2003, or cease operating, absent a showing of good cause to continue operating. The adopted amendments allow the permitting of all other air contaminants for grandfathered EGFs using the VERP process. Support facilities may be permitted under a VERP which may be consolidated with an EGFP. There is no federal law or delegation agreement with a federal agency that requires the permitting of grandfathered EGFs.

TAKINGS IMPACT ASSESSMENT

The commission has completed a takings impact assessment for the adopted rules. The following is a summary of that assessment. These new sections implement the requirements of TUC, §39.264. This section requires owners or operators of grandfathered EGFs to apply for a permit on or before September 1, 2000, and obtain a permit or cease operation by May 1, 2003. It is the intent of §39.264 that for the 12-month period beginning May 1, 2003, and for each 12-month period following, annual emissions of NO _x from grandfathered EGFs not exceed 50% of the NO _x emissions reported to the commission for 1997. Furthermore, it is the intent of the legislation that emissions of SO ₂ from coal-fired EGFs not exceed 75% of the SO ₂ emissions reported to the commission in 1997. NO _x and SO2 allowances will be allocated to EGFs by January 1, 2000. To assist EGFs in meeting the reduction requirements, a banking and trading program is adopted concurrently in Chapter 101. Although EGFs are required to make specific emission reductions, these facilities have alternatives available under the banking program that may allow the EGF to avoid installing add-on controls. Further, allowances can be transferred under the banking program so that EGFs have opportunities to buy and sell allowances in order to respond to business needs. The new sections do not affect private property in a manner that restricts or limits an owner's right to the property that would otherwise exist in the absence of the governmental action. Consequently, this adoption does not meet the definition of a takings under Texas Government Code, §2007.002(5). The reductions obtained from the issuance of EGFPs will assist in the efforts of the commission to attain the NAAQS. This action is taken in response to a real and substantial threat to public health and safety and significantly advances the health and safety purpose and imposes no greater burden than is necessary to achieve the health and safety purpose.

COASTAL MANAGEMENT PROGRAM CONSISTENCY REVIEW

The commission has determined that this rulemaking relates to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act of 1991, as amended (Texas Natural Resources Code, §§33.201 et seq.), and the commission's rules in 30 TAC Chapter 281, Subchapter B, relating to Consistency with Texas Coastal Management Program. As required by 31 TAC §505.11(b)(2) and 30 TAC §281.45(a)(3), relating to actions and rules subject to the CMP, commission rules governing air pollutant emissions must be consistent with the applicable goals and policies of the CMP. The commission has reviewed this action for consistency with the CMP goals and policies in accordance with the regulations of the Coastal Coordination Council. For the new sections related to the authorization of EGFPs, the commission has determined that the rules are consistent with the applicable CMP goal expressed in 31 TAC §501.12(1) of protecting and preserving the quality and values of coastal natural resource areas, and the policy in 31 TAC §501.14(q), which requires that the commission protect air quality in coastal areas. This adoption is intended to reduce overall emissions of NO _x and, if applicable, SO ₂ from grandfathered EGFs. This action is consistent with 40 CFR because it does not authorize an emission rate in excess of that specified by federal requirements.

PUBLIC HEARING AND COMMENTERS

The commission conducted public hearings concerning this adoption in El Paso and Lubbock on October 1, 1999, in Austin on October 4, in Irving on October 5, in Houston on October 7, and in Beaumont on October 7.

The following submitted written comments or provided testimony during the public comment period which closed on October 11, 1999: EPA-Acid Rain Division (EPA-ARD); EPA-Clean Air Markets Division (EPA-CAMD); EPA-Air Permits Division (EPA-APD); EPA-Air Planning Section (EPA-APS); The University of Texas System, Office of General Counsel (UT); Enron, Central and South West Services, Inc. (CSW); TXU Business Services (TXU); Brazos Electric Power Cooperative, Inc. (Brazos); Baker & Botts, L.L.P.-Texas Industry Project (Baker & Botts); Clark & Seay, L.L.C. (Clark & Seay); Southwestern Public Service Company (SPS); Entergy Gulf States, Inc./Entergy Texas (Entergy); El Paso Electric Company (EPE); Lloyd, Gosselink, Blevins, Rochelle, Baldwin & Townsend, P.C.-City of Garland (Lloyd Gosselink); League of Women Voters of Texas (LWV-TX); The Center for Energy and Economic Development (CEED); Association of Electric Companies of Texas, Inc. (AECT); Reliant Energy (Reliant); Entergy Services Inc. (Entergy Services); Environmental Defense Fund (EDF); City of Austin/Austin Energy (AE); Sustainable Energy and Economic Development Coalition (SEED); Public Citizen, Texas Clean Water Action, Texas Communities Project (PC); City Public Service of San Antonio (CPS); Bracewell & Patterson (B&P); Lubbock Power & Light & Water (LP&L); Clark, Thomas & Winters (CT&W); Central & South West, City of Austin, City Public Service, El Paso Electric, Entergy, Reliant Energy, Southwestern Public Service, and TXU (Group A); (Group A); Mothers for Clean Air (MCA); Neighbors for Neighbors (NFN); and 17 individuals.

ANALYSIS OF TESTIMONY

One individual commented that the commission should exercise its authority to require significant reductions at power plants in East Texas, with another individual adding that the reductions should be permanent. Three individuals stated that the commission should enforce reduced emissions from grandfathered electric generating facilities, and two more individuals added that the commission should be as strict as possible in that enforcement.

While this adoption addresses grandfathered EGFs only, the commission is developing rules that will apply NO _x restrictions on all EGFs in the East Texas Region. The specific level of emissions required from these facilities will be determined on computer analysis that indicates what reductions should be required to assist the affected nonattainment areas in meeting the NAAQS. The net reductions required under this adoption are permanent. The commission will exercise its full enforcement power as authorized by statute, rule, or as governed by enforcement policy. This adoption requires mandatory permitting for emissions of NO _x and, if applicable SO ₂ and PM through the commission's opacity standards, the rules provide options for the permitting of other air contaminants from grandfathered EGFs.

Four individuals stated that the commission should seek improvements that address SO ₂ , particularly to improve visibility in Big Bend. Another individual added that the commission must require a larger NO _x and SO ₂ reduction to reduce acid rain and ozone in Texas nonattainment areas.

In cooperation with EPA and the National Park Service, the commission is analyzing the nature and location of required reductions to address reduced visibility in Big Bend National Park. This analysis is incomplete and therefore, the commission believes that requiring reductions specifically to the Big Bend area prior to the completion of this analysis is premature. The authority granted to the commission under TUC, §39.264 and other existing authority allows the commission to seek additional reductions in SO ₂ as needed. As stated previously, the commission is addressing additional NO _x reductions that may be required to assist in the attainment of the NAAQS in a separate rulemaking. There are no areas in Texas that are nonattainment for SO ₂ , and the commission is not aware of any areas that are adversely affected by acid rain.

One individual stated that the commission should not allow a cap and trade or banking system because it avoids environmental justice issues and perpetuates emissions in low-income areas. The same individual suggested that the exclusion for individual units to be regulated under TUC, §39.264 be lowered to ten megawatts from 25 megawatts. This individual also stated that the commission estimate of cost of compliance with the requirements of the adoption is low, and it appears that the commission is allowing low-grade technology to be applied to the regulated units.

The trading and banking provisions of this adoption are required elements of the reduction program under TUC, §39.264. SB 7 provides that total annual emissions of NO _x from grandfathered EGFs will not exceed 50% of the NO _x emissions in 1997 as reported to the commission and that for coal-fired grandfathered EGFs, the total annual emissions of SO ₂ will not exceed 75% of the emissions during 1997, as reported to the commission. SB 7 also provides that the trades of allowances will only occur within the same region, either East Texas, West Texas, or El Paso. The effect of this will be an overall 50% reduction in NO _x and a 25% reduction in SO2 within the region. SB 7 does not require a specific level of reduction at any individual grandfathered EGF. The exemption level for individual generating units of 25 megawatts is specified in TUC, §39.264(d). As discussed elsewhere in the adoption preamble, the commission has also excluded EGFs that generate power primarily for internal use, but that during 1997 sold one-third of their generated power or less than 219,000 megawatt-hours to the utility power distribution system. The commission believes that excluding these EGFs is consistent with SB 7 and will not negatively affect the overall emission reductions required by the program. Lowering the exemption to ten megawatts will require small generators to participate in the EBTA and permitting program and will achieve little environmental benefit in relation to the cost of compliance with the program. The commission has based its estimate of the cost of applying control technology to attain the 0.14 pound per MMBtu on the February 1999 joint Public Utility Commission of Texas (PUCT) and TNRCC report, Electric Restructuring and Air Quality: A Preliminary Analysis of Reductions and Costs of Nitrogen Oxides Controls from Electric Utility Boilers in Texas. The estimate does not limit the amount EGFs must spend to meet the EBTA and accounts for technology of necessary sophistication to meet the requirements of this adoption.

The Honorable Lon Burnam, State Representative, District 90, commented concerning the implementation of SB 7 and its impact on consumers from an economic perspective. Mr. Burnam expressed his concerns that the commission implement the provisions of SB 7 free from the influence of lobbyists. Mr. Burnam urged the commission to consider public health in the process of implementing SB 7.

The provisions of SB 7 concerning deregulation of the electric industry will be implemented by the PUCT. The commission conducted six hearings in order to seek the public comment of citizens, the regulated community, and environmental groups. The hearings were conducted in El Paso, Lubbock, Austin, Irving, Houston, and Beaumont. Prior to proposal, the commission held a stakeholder meeting to seek input from interested persons. Notice of this meeting was provided on the commission's web page. In addition, pre-proposal drafts of the rules were posted on the commissions's web page with a request for comments. The commission believes that the adopted rules are consistent with SB 7 and remains committed to implement the program in a fair and impartial manner. Since EGFs are being permitted under the requirements of TUC, §39.264, which does not require a health effects review, no review is included in this adoption. The commission believes that this program will reduce ambient levels of NO _x and SO ₂ and improve the overall air quality of the state. These reductions will assist the commission in its efforts to attain the health-based NAAQS.

Clark & Seay and MCA commented that all power plants that are in or near an area with unsafe air should be required to meet the 0.14 pounds/MMBtu standard used in federal laws and to the level to which all grandfathered plants will be required to be cleaned up. In addition, LWV-TX commented that the rules in general be expanded to require all power plants that are in areas with unsafe air or that contribute to those nonattainment areas meet the same standard.

This adoption implements the requirements of TUC, §39.264 and application of this statute is limited to grandfathered EGFs and those EGFs that elect to participate in the permitting and trading program. The intent of SB 7 is not to achieve attainment with the NAAQS, but to permit and reduce emissions from grandfathered EGFs. While the implementation of SB 7 will provide emission reductions in areas near grandfathered EGFs, the commission recognizes that it will likely be necessary to adopt rules that will require air pollution control in attainment areas as well as additional rules for nonattainment areas. These controls would not only apply to emissions of NO _x from grandfathered EGFs, but permitted EGFs and other sources of NO _x as well. Further, specific emission rates will be established that have been determined necessary to meet air quality standards. Rules implementing these additional controls are scheduled for proposal in late 1999 or early 2000. The commission is not aware of any federal standards that require EGFs to meet a NO _x emission restriction of 0.14 pounds/MMBtu.

EDF commented that TUC, §39.264(n)(1) includes two specific penalties for facilities that exceed their allowances. The commenter noted that the proposed rules did not include any administrative penalties, and recommended that they be added at a level sufficient to deter noncompliance. EDF recommended three times the current market value of allowances.

The commission does not typically address the amount of administrative penalties in specific rules. Rather, penalty amounts are established in accordance with the commission's penalty policy. All enforcement cases not referred to the Office of the Attorney General go through staff preparation of an administrative penalty recommendation in accordance with the commission's penalty policy. Staff obtains an agreement or litigates to obtain an order against the respondent that requires the payment of penalties. The commission determines the amount of the penalty in accordance with the commission's enforcement rules and penalty guidance. The statutory language requires "enforcing an administrative penalty" and not "assessing" an administrative penalty.

Reliant requested that the published list of grandfathered EGFs be revised by deleting the Cedar Bayou Units 1 and 2 (Account Number CI-0012-D) because the units are no longer grandfathered and are permitted under Permit Number 1532. In addition, Reliant provided heat input information for facilities that were missing from the proposed list. CPS commented that V.H. Unit 1 should be corrected from 2,946,936 MMBtu to 2,949,512 MMBtu, as was submitted to EPA in the Acid Rain Database.

The commission will make these corrections to the list entitled "Nitrogen Oxide and Sulfur Dioxide Allowances for Grandfathered Electric Generating Facilities."

EPE commented that the language in TUC, §39.102(c) and §39.264(i) illustrate EPE's exemption from Chapter 39 and EPE's ability to elect to designate a facility to become subject to §39.264 and they noted that EPE is a "person" under PURA.

The commission agrees that EPE is a "person" under the TUC. The commission has not revised the rule to exempt EPE from the program requirements. TUC, Subchapter C, Retail Competition, §39.102, concerns retail customer choice, and exempts from TUC Chapter 39, any electric utility that has a system-wide freeze for residential and commercial customers that is in effect from September 1, 1997 and extends beyond December 31, 2001, that has been found by a regulatory authority to be in the public interest. Subchapter C also contains §39.264, which requires any EGF that existed on January 1, 1999, that is not subject to the requirement to obtain a permit under TCAA, §382.0518(g), to apply for and obtain a permit from the commission.

Section 39.264 was added to SB 7 during the final weeks of the 76th Legislative Session. Its very specific intent is to require grandfathered EGFs to obtain a permit from the commission and to obtain reductions of NO _x and SO ₂ in the regions as defined by the bill. TUC, §39.264 contains several specific references to the El Paso area that make it clear that the Legislature intended EGFs in that area to be subject to the permitting and allowance program. TUC, §39.264(g) requires the commission to develop rules that define the "El Paso Region." TUC, §39.264(h) specifies an emission rate for the El Paso Region. TUC, §39.264(p) specifically requires the commission to develop rules to allow EGFs in the El Paso Region to meet emissions allowances by using credits from reductions made in Ciudad Juarez, United States of Mexico. Finally, TUC, §39.264(q) allows the commission to exempt EGFs in the El Paso Region if the commission determines that reductions in NO _x would result in an increased amount of ambient ozone levels in El Paso County.

The Code Construction Act, §311.021, Texas Government Code, provides that "In enacting a statute, it is presumed that: (1) compliance with the constitutions of this state and the United States is intended; (2) the entire statute is intended to be effective; (3) a just and reasonable result is intended; (4) a result feasible of execution is intended; and (5) public interest is favored over any private interest." If TUC, §39.102 were read to exclude EGFs in the El Paso Region from the provisions of Chapter 39, the specific provisions of TUC, §39.264, concerning the El Paso Region, would be rendered ineffective. As prescribed by the Code Construction Act, the commission must interpret the provisions of Chapter 39 so that all sections can be given effect. To do otherwise would contravene the intent of the Legislature. Thus, the commission agrees that EPE is exempt from the provisions regarding customer choice in TUC, Chapter 39. However, if EPE were exempted from the permitting and EBTA requirements, the provisions of TUC, §39.264, concerning the El Paso Region, would be meaningless. The commission agrees that EPE may use the provisions of §116.912, concerning Electing EGFs.

Lloyd Gosselink commented that the rules do not address the use of oil as a backup fuel at a gas- fired facility. The commenter stated that under certain curtailment situations, gas may not be available, and gas-fired facilities may be required to switch to oil as a fuel source, and that under these conditions, facilities should not be penalized for any additional NO _x emissions.

The commission believes that a facility has the latitude to use any fuel as long as actual emissions comply with its allotted allowances, and the use is authorized by the appropriate NSR authorization. The commission does not believe it is appropriate to revise the rules to include an exception to exceed allowances in the case of a curtailment because SB 7 does not allow for this exception. If a curtailment occurs, and emissions of NO _x exceed an EGF's allowances, the commission will rely on its enforcement policy to determine the appropriate response. Use of previously unused fuels may constitute a modification and require an NSR permit. The rules have not been revised in response to this comment.

LWV-TX commented that the TNRCC should restrict pollution trading in ways that assure significant reductions in air pollution.

SB 7 requires the commission to allocate allowances to grandfathered EGFs in defined regions of the state. The specific intent of SB 7 is that total annual emissions of NO _x from grandfathered EGFs will not exceed 50% of the NO _x emissions in 1997 as reported to the commission and that for coal-fired grandfathered EGFs, the total annual emissions of SO ₂ will not exceed 75% of the emissions during 1997, as reported to the commission. The adopted rules provide the requirements for both the permitting of these grandfathered EGFs, and an emission banking and trading program. Both of these programs are critical to the successful reduction of the NO _x and SO ₂ emissions contemplated by SB 7. The EBTA contains restrictions on trading that will ensure that the required emission reductions are enforceable. The commission believes that the required reporting and monitoring, along with the statutorily defined enforcement provisions, will ensure that the program achieves the reductions intended by TUC, §39.264. The commission believes that the implementation and enforcement of the adopted rules will ensure that the reductions mandated by SB 7 occur and that no modification to the rule is necessary.

CEED commented that the preamble referenced adopting additional requirements for EGFs in nonattainment areas, indicating further reductions of 88% in Dallas/Fort Worth (DFW) and 90% in Houston/Galveston (HGA) areas. The commenter stated that the emissions inventory shows that these point sources only represent a minor source of NO _x emissions, since the majority of emissions are generated by on-road and off-road mobile and area sources, and that the inclusion of these statements regarding the further need to reduce emissions from EGFs continues to focus attention on sources which will not solve nonattainment problems in these areas. CEED also commented that the proposal preamble statements that EGFs must consider local impacts of allowance transfers and that "EGFs emit significant amounts of NO _x , which has been shown to heavily influence local ozone levels" are comments without any qualifications to specific EGFs and perpetuate the opinion by some that all EGFs emit significant levels of emissions. CPS supports the removal of all references to SIP requirements from the SB 7 regulations. An example is on page 7140 of the proposal preamble, where it states that "...EGFs must consider local impacts of allowance transfers...." Furthermore, the preamble states that "These EGFs (in near-nonattainment areas) emit significant amounts of NO _x which has been shown to heavily influence local ozone levels." CPS disagrees which this statement. First, the mandatory SB 7 program was designed to be flexible, and allow reductions to be made in the most cost-effective manner. Second, the utility plants in San Antonio, owned by CPS, do not contribute heavily to local ozone levels, as indicated by previous modeling performed by Alamo Area Council of Governments under the direction of the TNRCC. Therefore, TNRCC's concern that SB 7 allowance trading will jeopardize the regional strategy is unwarranted, at least for the near-nonattainment area of San Antonio.

The reductions mandated by SB 7 only apply to grandfathered EGFs in the defined regions of Texas. These reductions from grandfathered EGFs will be significant; however, it is unlikely that the reductions will be sufficient to address the need to further reduce emissions in both attainment and nonattainment areas. The commission believes that to achieve attainment with the NAAQS, it will be necessary to reduce emissions from all sources, both stationary and mobile, in both attainment and nonattainment areas. The reductions that will be achieved under the adopted rules will be significant towards reaching attainment. In addition, the commission believes that NO _x emissions from EGFs are not minor, but significantly contribute to ground-level ozone formation. The preamble comments regarding the potential impacts of trading on near-nonattainment areas were included to recognize that emissions in near- nonattainment areas may have a negative impact on that areas ability to remain in attainment. Emission inventory information indicates that NO _x emissions from EGFs are approximately 47% of the stationary source NO _x emissions in the East Texas Region.

EPA-CAMD commented that the cost effectiveness numbers of $4,000 per ton of NO _x removed in the absence of emissions trading, or $2,000 per ton of NO _x removed with emissions trading, seem far too high. For example, in the May 25, 1999 Final Rule under §126 of the FCAA (64 FR 28300), EPA determined an average cost- effectiveness of $1,468 per ton of NO _x removed from electric generating units greater than 25 megawatts with emissions trading. Estimates for cost effectiveness of NO _x control under Ozone Transport Committee NO _x Budget Program range from $950- 1,600 per ton. Furthermore, the commenter noted that some gas-fired units can achieve an average NO _x emission rate of 0.14 lb/MMBtu simply using combustion controls.

The commission supports the preamble language. The listed values were based on information developed for the joint Public Utility Commission of Texas (PUCT) and TNRCC report published in February 1999, entitled Electric Restructuring and Air Quality: A Preliminary Analysis of Reductions and Costs of Nitrogen Oxides Controls From Electric Utility Boilers in Texas. For simplicity in the report, the costs of emission reductions were analyzed on a unit-by-unit basis. Thus, the potential for "over-compliance" for certain generating units in cases where it may be more cost-effective was not captured in the analysis. A subcommittee of the Ozone Transport Assessment Group (OTAG) has analyzed market-based emission trading options, such as the EBTA, estimating potential savings of as much as 50%, compared to the costs of unit-by-unit compliance. This analysis is applied to all utility generating units in the state, which may overstate the magnitude of the estimated compliance costs. The commission believes that, in practice, the costs of permitting and participation in the EBTA will be much less that what was estimated in the proposal.

EPA-APD commented on its understanding that the TNRCC will use emission reductions which occur under these regulations to help demonstrate attainment and maintenance of NAAQS. The commenter further understood that the reductions will not be used for offsets and netting under NSR. With this understanding, EPA-APD supported the adoption of these regulations if the TNRCC adequately addresses the remaining comments.

The EBTA and EGFP programs will be submitted as a revision to the SIP. The resulting reductions will be used by the commission to further its attainment goals. Allowances cannot be used to satisfy emission offset requirements under federal NSR; thus, they will not be used as netting for PSD or for offsets under a nonattainment NSR permit.

EPA-APD asked whether standard permits will be incorporated into a facility's federal operating permit through 30 TAC Chapter 122's permit modification provisions. AE recommended that once an EGFP is issued, any needed revisions to the site's federal operating permit (FOP) should be automatically incorporated as administrative corrections and not require an additional public comment period associated with changes to the FOP.

The commission does not anticipate developing a standard permit for use by grandfathered EGFs for the purpose of complying with TUC, §39.264. However, a grandfathered EGF is not prohibited from using any of the standard permits that are currently available. At this time, the commission's FOP program does not include the commission's NSR program as an applicable requirement. Only PSD, nonattainment permits, and case-by-case maximum available control technology (MACT) review under FCAA, §112(g) or (j), are required to be included in a FOP as applicable requirements. If and when the EPA determines that the commission's NSR program is an applicable requirement, holders of FOPs may be required to include references to standard permits in their FOP. If a FOP must be revised to address changes to applicable requirements as a result of the EGFP, then, depending on the nature of the revision, the appropriate revision process under Chapter 122 would be used.

PC recommended substituting renewable energy for electricity or energy used at a grandfathered facility, stating that this could provide a low cost way to reduce emissions and result in the building of additional new clean energy sources. The commenter stated that concurrent rulemaking at the PUCT to implement the renewable portfolio standard in SB 7 has resulted in the development of capacity factors and other evaluation procedures that can be useful to the commission in converting renewable capacity to energy for purposes of calculating avoided emissions and provide for a periodic update for that factor. PC stated that these rules developed by the PUCT should be incorporated by reference into the commission's rules.

The purpose of this rulemaking is to obtain emissions reductions from EGFs based on the specific provisions of SB 7; in particular, the 50% NO _x reductions and the 25% SO ₂ reductions, if applicable. These reductions are to be made based on certain emission rates set forth in TUC, §39.264(h). It is possible that a grandfathered or electing EGF could make reductions relying on the use of renewable energy and that the factors developed by the PUCT may be used to evaluate such a proposal. Since the commission can consider the rules of the PUCT among many sources of information to make such decisions, the commission does not believe it is necessary to incorporate the PUCT rules into Chapter 101 or 116. The commission agrees that using renewable energy to achieve emission reductions is a viable option and one that might result in cost savings to certain facilities. As the commission continues to develop the permitting and EBTA programs, issues concerning renewable energy can be considered. In addition, if a grandfathered or electing EGF substitutes renewable energy, the resulting emissions should be lower, requiring less allowances for compliance, thus creating an economic incentive.

PC believes that the proposed rules will fail to assure that emissions are actually reduced. PC believes that the utilities are unlikely to offer a reduction at any plant other than those that are oldest and used the least. Many of these plants are permitted as base-load plants which operate 60-80% of the time, but are kept only for peak use and are used infrequently, less than 20% of the year. Thus, a facility might be glad to modify its permit by reducing permitted emissions that it would never really produce. PC recommends that the rule should be modified to require permit reductions based on the last five years of actual emissions.

The commission believes that the specified emission rates in the statute and the corresponding rules will achieve the target reductions. The intent of SB 7 is to achieve overall reductions of 50% NO _x emissions and 25% SO ₂ emissions. An electing EGF would receive allowances equal to actual 1997 emissions, not permit allowable emissions, and would only be able to generate surplus allowances by reducing emissions below actual 1997 levels. Also, an electing EGF may not transfer or bank allowances that are conserved as a result of reduced utilization or shutdown unless the reduced utilization or shutdown results from the replacement of thermal energy from the electing EGF with thermal energy generated by any other EGF. Further, since SB 7 provides that 1997 is the base year for determining reductions, the commission does not believe it has the authority to require permit reductions based on the last five years of actual emissions. Therefore, the commission has not changed the rules in response to this comment. Therefore, the commission has not revised the rule in response to this comment.

PC commented that the rules adopted for the implementation of SB 7 should be structured in such a way as to allow the purchase and retirement of NOx allowables issued under the SB 7 program to be used as project emission reduction credits under SB 766. PC recommended two alternatives. First, the TNRCC could allow a retail electric provider (REP) to sell renewables to the owner of a grandfathered facility and assume that there will be a reduction in emissions per megawatt hour (MW) at the average rate of emissions per MW for the power plants in the area. The commenter stated that this is the least costly way to assure that the program will work, and since Texas is effectively an isolated electrical grid, will assure that emissions are reduced in the state. The EPA has recognized the OTAG debates that add-on units that produce solar electricity or solar water heaters mitigate emissions. PC argued that a wind turbine, a solar water heater, or gases from landfills can similarly be rated based on capacity, converted into energy, and emissions reductions could thus be calculated. Secondly, TNRCC could allow the REP to buy and retire NO _x credits from the SB 7 trading program established in Chapter 101. This will assure that the emissions are actually reduced in the 60-county east Texas airshed, but it would add to the cost. The commenter further stated that since the transaction is on the open market, it may be far less costly than permit emission reductions purchased from the competitor; and the commission can significantly reduce the cost of the renewable energy used in the program by declaring that the renewable plants built to meet a contracted load under this program are pollution control devices as defined in Health and Safety Code, Chapter 383. If renewable energy installations are certified under Health and Safety Code, §383.004, the certification will exempt the owners from property taxes and allow them to qualify for pollution abatement bonds issued by local governmental units as provided by Health and Safety Code, §383.021. The combination of these two financial benefits could erase the premium price of renewable energy and make it the most cost-effective way to reduce emissions.

The commission will explore whether it has the authority to declare a renewable energy source, such as wind power, to be a pollution control device for the purposes of property tax exemptions and pollution abatement bonds. As the EBTA and permitting programs continue to develop, the commission can consider issues such as the use of add-on units that produce solar electricity or solar water heaters to reduce emissions. The commission agrees that REPs can buy and retire SB 7 allowances under Chapter 101 and that this transaction might be approved for use as a project emission reduction credit under the VERP program established by SB 766, as long as those allowances are not used to meet the requirements of SB 7.

One individual commented that health effects reviews should apply not only for grandfathered plants, but secondary sources as well.

The rules were not revised in response to this comment. The permitting program required by TUC, §39.264 does not include a health effects review. Emissions from grandfathered EGFs other than NO _x , and for coal-fired EGFs, SO ₂ and PM may be permitted using the VERP program requirements. If an owner or operator chooses to permit grandfathered support facilities at sites with EGFs, the owner or operator may submit an application for a VERP under Chapter 116, Subchapter H. The VERP program provides for a health effects review.

One individual commented that companies have been grandfathered long enough and that the commission should tighten permitting regulations. SEED and two individuals commented that grandfathered energy producers should undergo a health effects review.

Since EGFS are being permitted under the requirements of TUC, §39.264, which does not require a health effects review, no review is included in this adoption. The commission believes that this program will reduce ambient levels of NO _x and SO ₂ and improve the overall air quality of the state. These reductions will assist the commission in its efforts to attain the health-based NAAQS.

MCA commented that all grandfathered power plants should meet today's BACT or the federal NSPS for pollutants such as CO, SO ₂ , PM, and VOCs, and that this is especially important in areas such as the HGA region where there is not yet a demonstration of compliance with the ozone standard and where the area is bordering violation of the PM standard. NFN and LWV-TX commented that all grandfathered power plants should meet today's BACT or the federal NSPS if they are located in nonattainment areas or east of IH-35 and north of IH-37. Ten individuals commented that all grandfathered plants east of I-35 and north of I-37 must be required to use BACT or NSPS for pollutants such as CO, particulate, and VOC. One individual also recommended that the rules require grandfathered power plants to meet BACT or NSPS for other pollutants, as well as CO, PM ₁₀ , and all fluoro-organic compounds. Three individuals commented that grandfathered plants should use BACT. One individual commented and supported the comments of SEED and other environmental groups targeting power plants, and suggested that the commission require BACT for power plants in the Metroplex area, require compliance with federal laws, and use a wide net in a wide geographic area, since pollution comes from sources far away from Dallas. Two individuals added that the commission should require reductions in CO and VOC as well as NOx and SO ₂ , with one stating that control of radioactivity should also be included in the adoption. One commenter stated that the commission should allow no emissions of NOx , VOC, or particulate greater than any United States-built power plant.

The commission has made no changes in response to these comments. SB 7 does not prescribe specific control requirements. However, the commission notes that all EGFs must comply with any applicable NSPS and other federal standards. The use of BACT is only required if a grandfathered EGF is modified, consistent with the state or federal definition of "modification." EGFs applying for a permit under these adopted rules that do not initiate a modification to the EGF will only be subject to the specific reduction requirements of TUC, §39.264.They are required to achieve the 50% reduction in NOx or the 25% reduction in SO ₂ , whichever is applicable, or meet the reduction requirements through the EBTA. TUC, §39.264 does not specifically require reductions or permitting of other pollutants; however, the adopted rules allow for the permitting of other air contaminants using the control technology and review process established in Chapter 116, Subchapter H, concerning the VERP program for grandfathered facilities.

In addition, SB 7 did not distinguish between grandfathered EGFs located in nonattainment areas versus attainment areas, nor does it require BACT or NSPS if an EGF is located in a nonattainment area. The commission has rules that address emissions from facilities in nonattainment areas, including EGFs and will be proposing additional rules that will require emission reductions from EGFs in both nonattainment and attainment areas east of IH-35 and east of IH-37. The commission will propose rules that address power plants and other sources in the DFW area and eastern Texas that will consider the effects of transport.

PC urged the commission to reduce emissions for all power plants in the 60-county Texas Clean Air Strategy area to no more than 0.10 pounds/MMBtu for coal and 0.06 pounds/MMBtu for natural gas plants. PC noted that the commission estimated in its February 1999 study that if these standards were adopted, NO _x emissions would drop by 96,000 tons per year. PC commented that the commission should propose rules at the earliest possible opportunity that require emission reductions in the 60-county area east of IH-35 and north of IH-37 to 0.14 pounds/MMBtu because data from the commission and from OTAG documents that this is the most cost-effective way to reduce ozone emissions in the state and is less costly than other options being considered, like inspection and maintenance and reducing emissions from grandfathered facilities or reformulating gasoline or buying low emission vehicles. If the commission were to enact this standard, PC estimates that an additional 80,000 tons per year of NO _x would be removed from the airshed. PC stated that the 0.14 pounds/MMBtu standard was assumed by the Legislature for the grandfathered facilities and had it been in place during the ozone season of 1997 and 1998, PC believes that 40-70% of the ozone exceedances in DFW could have been avoided. PC added that a level of 0.05 pounds/MMBtu would reduce even further the emissions from grandfathered units. Six individuals commented that all power plants should be required to meet the 0.14 pounds/MMBtu standard for NO _x .

Before the end of 1999, the commission will propose rules and additional amendments to the SIP that require reduction in NO _X emissions for permitted electric generating utilities and other industrial sources. The reductions are intended to reduce the amount of ozone and ozone precursor gases transported into DFW and other nonattainment areas. These rules will be proposed concurrently with several other rules as part of a program to reduce NO _X in the eastern portion of Texas. The commission has identified mobile sources as significant contributors to ozone levels, particularly in DFW, and intends to require reductions from these sources as well. The SIP amendments will target significant emission sources and require NO _X reductions where they will be most effective and do not unnecessarily burden a particular segment of the economy. The specific NO _X emission limits are also established according to these goals. The reductions achieved under the adoption of these rules implementing SB 7 will also be a part of this program.

SEED and PC commented that SB 7 must be read broadly to require the creation of a de novo permitting standard that at least provides for parity between Texas-grandfathered plants and new plants built today. SB 7 strictly indicated that the Legislature's intent was to remove special historical exemptions for older power plants to eliminate unfair competitive advantages and excess pollution, and that in SB 7, the Legislature intended that grandfathered units face the same permitting hurdles as those faced by new plants built today. TUC, §39.264(e) requires that grandfathered units must apply for de novo permits on or before September 1, 2000. TUC, §39.264(f) requires the TNRCC to develop rules for this permitting process. TUC, §39.264(g)-(j) instructs the TNRCC to also develop a system for allowances for sulfur and nitrogen emissions and set forth specific starting allowance formulas. The commenters stated that nowhere did the Legislature indicate that the TNRCC should not exercise its general organic authority in existing regulatory framework in reviewing and acting upon these de novo permit applications. The Legislature went even further and stated that it does not intend to "limit the authority of the TNRCC to require further reductions of nitrogen oxides, sulfur dioxide, or any other pollutant from generating facilities subject to" the law. Additionally, the Legislature provided for stranded cost recovery of unit cleanup costs. Finally, the Legislature also authorized cost recovery where the "amount and location of resulting emission reductions is consistent with the air quality goals and policies of the TNRCC." The commenters also stated that de novo permitting of grandfathered facilities should include at least NSR for NO _x and SO ₂ as well as appropriate limits for air toxics and mercury, and that grandfathered facilities should at least meet the NSR performance requirements that would have to be met by new coal or gas plants sited in Texas today. Reasons for this include concerns with ozone, nitrogen enrichment in estuaries, acid deposition, haze, PM2.5, and mercury and other hazardous air pollutants. SEED included health effects and coal combustion wastes. PC commented that, in particular, the rules should provide that EGFs be treated as would any new coal, oil, or gas power plant applying for de novo permitting. At a minimum, the TNRCC should thus require EGF's seeking permitting under the rules to meet BACT or lowest achievable emission rate (LAER) standards for NO _x and SO ₂ depending on whether the units are located in an attainment or nonattainment area. In addition, the TNRCC should require these applying plants to meet appropriate net carbon dioxide limits and toxic emission limits for mercury and other air toxics.

SEED and PC commented that the TNRCC should take supplemental comments on specific performance criteria to be met under de novo grandfathered facility permitting. In its narrative to the present proposal, the TNRCC states that if it embraced permitting standards beyond the minimum specified in SB 7, it "is unclear what standards these air contaminants should be held to." SEED commented that it is reasonably possible for these standards to be developed, and for nitrogen and sulfur that BACT and LAER provide an appropriate departure point. SEED and PC recommended that further supplemental comments be solicited in the second phase of this proceeding to allow for a more detailed discussion. SEED and PC commented that they are in support of the provisions in proposed §116.911 and §116.913, in that they retain the TNRCC's authority in the de novo permitting process.

The commission does not agree that the intent of TUC, §39.264 was to require de novo permitting of EGFs under the TCAA. While TUC, §39.264(e) requires EGFs to apply for a permit on or before September 1, 2000, that section goes on to say that the permit shall require the EGF to achieve emission reductions or allowances as provided by §39.264. TUC, §39.264(h) provides specific direction to the commission to base allowances on 1997 heat input, and it states emission rates for each of the defined regions. The heat input formulas were designed to achieve the 50% NO _x reductions and the 25% SO ₂ reductions. The commission does not believe that it is appropriate to revise those formulas to require further reductions from grandfathered EGFs under the SB 7 program. The provisions of TUC, §39.264 do not specifically prohibit the commission from relying on the permitting requirements of the TCAA; however, the commission believes that had the Legislature intended this result, it would have placed the EGF permitting requirements in TCAA, Chapter 382. In fact, early drafts of SB 766, which did amend the TCAA, contained the permitting and allowance provisions for EGFs. Even though the EGFs included in an EGFP will not undergo a BACT and impacts analysis for initial issuance, future modifications to the EGFs themselves will be required to be processed under Subchapter B of Chapter 116. The permitting and EBTA programs will achieve a certain amount of reductions based on the provisions of TUC, §39.264. The provision in TUC, §39.264(s) recognizes that the commission has the existing authority to require additional reductions from EGFs. The commission does not believe that this section was intended to support further reductions from EGFs under the SB 7 program. Rather, it appears that the section was worded to recognize the fact that under existing law, the commission may require additional reductions from EGFs through other commission rules, such as the reasonably available control technology rules.

Even though EGFPs will not be issued using the procedures in the TCAA, these permits will not authorize noncompliance with any applicable state or federal standards, including NSPS, NESHAPS, MACTs, and federal NSR permitting requirements. The commission does not believe that it is appropriate to require grandfathered EGFs to meet the NSPS for new coal or gas plants, or to meet BACT or LAER, depending on location. As previously noted, TUC, §39.264 provided specific emission rates and goals that are to be used to implement the program. If a grandfathered EGF has made a major modification under the PSD or nonattainment NSR programs, then the facility must comply with those programs. This is a separate requirement from SB 7 and is not negated by the issuance of an EGFP.

Section 116.910(e) provides that emissions of air contaminants other than NO _x , and if applicable PM and SO ₂ may be permitted by an EGFP if the grandfathered EGFs meet the requirements of Chapter 116, Subchapter H, concerning VERPs. Section 116.910(f) provides that other grandfathered facilities at a site may be permitted in an EGFP if these facilities meet the requirements to obtain a VERP. SB 7 does not require the permitting of any air contaminants other than NO _x , and if applicable PM and SO ₂ . Therefore, the commission chose to rely on the VERP program created by SB 766 to provide a basis of review for other air contaminants from grandfathered EGFs or grandfathered facilities so that all facilities at a site may be permitted. SB 766 provides specific control and other requirements for the permitting of grandfathered facilities. Since the Legislature passed SB 7 and SB 766 during the same session, the commission believes it is appropriate to review the grandfathered facilities and the other emissions from a grandfathered EGF using the VERP process. The commission does not believe that it is necessary to take additional comments on this issue at this time.

CSW, Entergy, Entergy Services, Reliant, CPS, Group A, and AECT commented that the permitting program as described in proposed §§116.911-116.913 is contrary to the permitting program contemplated by §39.264 of SB 7. The commenters stated that based on the language in §39.264 and the legislative history underlying it, it is clear that the SB 7 permitting program is supposed to be very different than the existing commission NSR permitting program. However, the SB 7 permitting program that proposed §§116.911-116.913 would establish is very similar to the existing commission NSR permitting program and clearly was patterned after the language in §116.111 and §116.115 of the NSR permitting program. CPS noted that in SB 7, the Legislature envisioned a program similar to EPA's Acid Rain Program.

The commenters stated that the existing NSR permitting program is a review-intensive, command and control system. Under the existing NSR permitting program rules, a permit application is subjected to a detailed and complex review that includes a BACT review, off-site impacts review, and a review to determine compliance of the proposed new or modified facility with NSPS, NESHAPs, and other state and federal air quality rules. TUC, §39.264 clearly provides that an EGF may meet its NO _x and/or SO ₂ allowance(s) without adding or implementing any emissions control whatsoever. Instead, §39.264 provides that an EGF may meet its NOx and/or SO ₂ allowance(s) through emissions trading, in lieu of adding or implementing emissions controls. Moreover, nothing in §39.264 specifies, or even indicates, that if the owner/operator chooses to add or implement emissions control to cause the EGF to meet its NO _x and/or SO ₂ allowance(s), that any commission review of such emissions control is to be conducted or that the commission must approve of such control. The commenters further stated that TUC, §39.204 establishes a permitting program that gives owners/operators of EFGs great flexibility in their use of NO _x and/or SO ₂ allowances in exchange for severe penalties if they do not comply with their allowable allocation. AE believes that the permit program envisioned under §39.264 should be designed to be very simple and straightforward. AE believes that the application should be very short if the applicant chooses to use the FCAA required continuous emission monitoring systems (CEMS) and will use allocations derived from the Acid Rain Database.

Based on the foregoing reasons, the commenters believe that §§116.911-116.913 should be significantly simplified so that the SB 7 permitting program is less like the review-intensive, command control approach of the existing NSR permitting program, and more like the flexible permitting program that is described by the language of §39.264 of SB 7 and was contemplated by the Texas Legislature when it drafted and passed SB 7.

The commission agrees with the commenters that the permitting program required under TUC, §39.264 is narrowly constructed to permit grandfathered EGFs and to achieve a target reduction of NO _x and, if applicable, SO ₂ . The commission has made significant revisions to the sections in Chapter 116, Subchapter I that have simplified the application content sections and in general, the requirements of the permit program. For example, the requirements to demonstrate compliance with federal standards have been deleted. Further, the provisions regarding control methods in §116.911(a)(2) have been rewritten to address applications that propose new control technology in order to meet the emission limitations of TUC, §39.264. Subsection (a) now refers to the standard permit for the installation of controls as the basis for the review that will be used by the commission to approve these new controls. The specific revisions and responses to comments for §§116.911-116.913 follow this response.

EPA-APD commented that §§116.911(a), 116.914(f)(2), and 116.915(b) refer to miscellaneous forms. The commenter stated that the TNRCC should address why these forms are not included in the proposed rulemaking and subject to public review and comment.

The text of the application forms are not part of the rules; however, the commission welcomes comment at any time whenever forms, instructions, and guidance documents can be improved or clarified. Section 116.915, concerning Emission Control Changes, has been deleted from the adopted rule package for reasons discussed elsewhere in this adoption preamble.

B&P commented that §116.18(2)(B) should be revised so that the EGF's maximum design heat input is measured in MMBtu per hour versus MMBtu to calculate capacity factor.

The commission agrees, and has revised the definition of "Capacity factor" in §116.18(2)(B) accordingly.

Reliant commented that §116.910(a) should be revised as follows: "The owner or operator of a grandfathered facility (as defined in 116.10 of this title (relating to general definitions)) at sites with EGFs ...." As proposed, the word "grandfathered" is not defined in this section of the regulations. The commenter suggested that the commission refer to §116.10 to avoid ambiguity.

The commission has not revised §116.910(a) in response to this comment. The commission instead chose to revise the definition of "Electric generating facility" and to include a definition of "Grandfathered EGF" to make a clear distinction that a "Grandfathered EGF" means an EGF that is not subject to the requirement to obtain a permit under TCAA, §382.0518(g). Section 116.910(a) was also revised in response to this comment.

Lloyd Gosselink commented that §116.910(a) does not apply to municipal utilities or electric cooperatives. TUC, §39.002 (Applicability) provides that Chapter 39 (except for §§39.157(e), 39.203 and 39.904) does not apply to a municipally-owned utility or an electric cooperative. Thus, TUC, §39.264 does not apply. Lloyd Gosselink recommended that §116.910(a) be revised to read: "The owner or operator of a grandfathered electric generating facility (EGF) shall apply for a permit to operate that facility under this Subchapter. This requirement does not apply to a municipally owned utility or an electric cooperative." PC commented that SB 7 requires emission reductions from grandfathered power plants owned by investors or municipalities.

The commission has made no changes in response to this comment. TUC, §39.002, addresses the applicability of Chapter 39, Restructuring of Electric Utility Industry. That section excludes "municipally owned utilities" and "electric cooperatives" from the requirements of Chapter 39, with some exceptions. TUC, §39.264 was added to SB 7 during the final days of the legislative session. Its very specific intent is to require grandfathered EGFs to obtain a permit from the commission and to obtain reductions of NO _x and SO ₂ in the regions as defined by the bill.

The Code Construction Act, §311.021, Texas Government Code, provides that "In enacting a statute, it is presumed that: (1) compliance with the constitutions of this state and the United States is intended; (2) the entire statute is intended to be effective; (3) a just and reasonable result is intended; (4) a result feasible of execution is intended; and (5) public interest is favored over any private interest." Although the commenter is correct in noting that TUC, §39.002 specifically excludes municipally owned utilities, that section must be read in context with the rest of Chapter 39.

TUC, §39.264 defines an "electric generating facility" as a facility that generates electricity for compensation and is owned or operated by a person in this state, including a municipal corporation, electric cooperative, or river authority. No definition of "municipal corporation" is provided in SB 7; thus, it is appropriate to consider the definition of "municipally owned utility" for guidance on what was intended to be covered by the term "municipal corporation." The term "municipally owned utility" is defined in TUC, §11.003(11) as a "utility owned, operated, and controlled by a municipality or by a nonprofit corporation the directors of which are appointed by one or more municipalities." It is reasonable to interpret the term "municipal corporation" to be the same as the term "municipally owned utility," since the terms are both used in the context of the electric utility industry in SB 7. Since the definition of "electric generating facility" includes "municipal corporations," it is appropriate to conclude that the Legislature intended for municipal corporations to be specifically included in the permitting program. The Legislature specifically noted exceptions for applicability in TUC, §39.264, and in spite of the undefined term "municipal corporation," the commission believes that the specific permitting requirements of TUC, §39.264 control over the general applicability requirements of TUC, §39.002. By interpreting TUC, §39.264 in this manner, a just and reasonable result occurs, since the interpretation enables the affected sections of Chapter 39 to be effective. The exemption provided by TUC, §39.002 allows municipal utilities and electric cooperatives to be exempt from the deregulation provisions. Municipal corporations and electric cooperatives with EGFs with nameplate capacities of 25 megawatts or less are not required to participate in the EBTA or the permitting program. Those over that amount must obtain permits and participate in the EBTA. Since TUC, §39.264 does not specifically exempt municipal corporations and electric cooperatives with EGFs with nameplate capacities over 25 megawatts, the commission does not believe it is appropriate to exclude those EGFs. The commission believes that the applicability exceptions in TUC, §39.002 are intended to exempt EGFs from the competition provisions of Chapter 39, not the permitting program.

EPA-ARD commented that various paragraphs in §116.910 are not clear as to who is taking action. For example, subsection (b) presumes that it is the owner or operator, and subsection (e) presumes that it is the commission.

The commission believes that clarification of the rules is warranted. The commission believes the proposed rule was clear as to who was taking action in §116.910(b), concerning electing facilities; however, to ensure clarity, the commission has revised subsection (b) to include a reference to "owners or operators." The commission has not revised §116.910(e), since that subsection was intended to address which air contaminants can be permitted under the requirements of Subchapter H and which may be permitted using the procedures in Chapter 116, Subchapter I, concerning the VERP program.

Reliant, TXU, Brazos Electric, Entergy, Entergy Services, Group A, AECT, and CPS commented that electing EGFs should not be subject to a full permit review as part of their electing, but that instead, their allowances should be issued through a permit alteration. The commenters stated that the proposal's requirements for electing EGFs are far more complex than intended in SB 7. SB 7 only requires that electing EGFs must be allocated NO _x and SO ₂ allowances and that they specify the identity of the electing EGFs. SB 7 has no other requirements for electing EGFs. The commenters stated that §116.910(a) and (b) and §116.913 should be revised to meet these goals. A similar comment was received from EPA-APD, noting that §116.912 should be clarified that all conditions in the existing permits of electing EGFs should continue to apply and are carried into the EGF permit. The TNRCC must authorize any changes or revisions to the conditions of the existing NSR permit (including PSD and nonattainment (NA) review permits) consistent with Chapter 116, Subchapter B.

The commission believes that SB 7 allows an EGF not covered by TUC, §39.264 to become subject to the requirements of TUC, §39.264, which include the requirement to obtain an EGFP. The commission agrees that the process to include electing EGFs in the Subchapter I permitting program can be simplified. Accordingly, the commission has revised §116.910(b) to allow for the electing EGF's NSR permit to be altered consistently with the requirements for alterations in §116.116(c). Electing EGFs must notify the commission of their intent to be included in the EGF permit program under Subchapter I for the purpose of obtaining allowances for NO _x and, if applicable, SO ₂ . The commission believes that it is necessary to alter the NSR permit to include a cross-reference to the EGFP. Electing EGFs must submit a separate application by September 1, 2000. After reviewing both the application for the EGFP and the alteration, the EGFP that goes to public notice will include only those conditions that are required under Subchapter I. The terms and conditions of the altered NSR permit will not be subject to public notice. The EGFP may include certain provisions from the NSR permit that are necessary to ensure compliance with the allowance system. Because the rule has been revised to include the permit alteration procedures, the references to "combined permits" have been deleted from §116.18(4) and §116.912(a)(3) and (4) and (b)(6). Further, to simplify the provisions for electing EGFs, many of the provisions in §116.912, concerning application content for electing EGFs, were moved to §116.911. Section 116.912(b) is now §116.912(a) and contains the provisions for opting in and out of the permitting program.

EPA-APD commented that §116.910(b) requires electing facilities to consolidate existing NSR terms into the EGFP. EPA-APD interpreted this to include all applicable terms of the existing NSR permit, including terms and conditions of PSD, nonattainment, and minor NSR permits. EPA- APD requested confirmation of this interpretation.

As discussed previously in this adopted preamble, the commission has deleted the procedures for combining NSR permits with EGFP from the adopted rule. Since the existing NSR permits will only be altered to include a reference to the EGFPs for the electing EGF, the terms and conditions of the NSR permit will continue to apply.

EPA-ARD suggested moving §116.910(c) closer to the beginning, since it is basic to the entire section.

The commission has made no changes in response to this comment. The commission believes that the organization of §116.910 is clear as to the rule's applicability.

LP&L requested that the commission add the following sentence to §116.910(d): "If the municipal cooperation, electric cooperative, or river authority reevaluates its intent to exclude the Electric Grandfathered Facilities (EGFs) it notified the commission of prior to January 1, 2000, it may choose to elect to permit any of those EGFs at a later date." LP&L believes that this statement, if added, would bring more exempted EGFs into the emissions trading and allowance program after they have had a chance to fully evaluate the compliance costs associated with the EGF permit.

The commission believes that a municipal corporation, electric cooperative, or river authority with grandfathered EGFs with a nameplate capacity of 25 megawatts or less or electing EGFs owned by these entities can decide to participate in the permitting program under Subchapter H at a date later than January 1, 2000, by using the provisions in §116.912, concerning electing EGFs. However, applications for EGFPs must be submitted by September 1, 2000. Section 116.910(d) has been revised to allow municipal corporations, electric cooperatives, or river authorities to reevaluate their decision to exclude certain EGFs and to participate in the permitting program. Further, §101.333(4)(A)(ii), now §101.333(5)(A)(ii), has been revised to provide that allowances for municipal corporations, electric cooperatives, or river authorities, that choose to participate in the permitting and EBTA program, will be issued by January 1, 2001.

B&P commented that §116.910(e) states that the permitting requirements apply to "any EGF" or "coal fired EGFs." The commenter stated that this language should be revised to provide that the permitting requirements apply only to grandfathered and electing EGFs, and that "emissions of other air contaminants from EGFs ...," should be changed to refer to only grandfathered EGFs. EPA- ARD commented that clarification is needed in §116.910(e) on whether the trading program only applies to coal-fired facilities, since only coal-fired EGFs are permitted for SO ₂ .

The commission agrees, and has added the term "grandfathered and electing EGFs" to §116.910(e). The rule has also been revised to clarify that emissions other than NO _x , SO ₂ , or PM from grandfathered EGFs may be permitted using an EGFP, provided that the conditions of Subchapter H are met concerning VERPs. The EBTA applies to grandfathered and electing EGFs that emit NO _x and, if coal- fired, SO ₂ .

CSW, Reliant, TXU, Lloyd Gosselink, CEED, Entergy Services, and AECT commented on §116.910(e) and §116.913(a) that the TNRCC does not have statutory authority to impose ten-year old BACT on contaminants other than NO _x and SO ₂ . CSW commented that the intent of SB 7 is to permit all other air contaminants at their existing (grandfathered) allowables. LP&L commented that §116.913(a)(1)(C) and all other references to EGFs meeting the requirements of Chapter 116, Subchapter H, should be deleted from the proposed regulations, and that the language as stated in SB 7 does not authorize the commission to apply emission control standards other than NO _x and SO ₂ . The legislation also does not authorize the commission to develop and regulate EGF permits as those permits in the VERP program. B&P commented that §116.913(a)(1)(C) provides that each EGFP will include a general condition that authorizes emissions of air contaminants other than NO _x and SO2 from EGFs meeting the requirements of Chapter 116, Subchapter H. The commenter stated that the section should be revised, since emissions of other air contaminants from electing EGFs will not be authorized under Chapter 116, Subchapter H.

The permitting program established by SB 7, which is contained within the TUC rather than the TCAA, addresses only emissions of NO _x , SO ₂ , and, by including a standard for opacity, PM. Other pollutants, such as VOC and CO, were not addressed and therefore, are not required to undergo a permitting process under TUC, §39.264. The commission believes the intent of SB 7 was also to eliminate the grandfathered status of EGFs. However, SB 7 did not specify the criteria for permitting air contaminants other than those addressed by SB 7, nor does it require the permitting of other air contaminants from grandfathered EGFs. The commission believes that it is not appropriate to merely include the existing allowable emission rates for emissions other than NO _x , or, if applicable, SO ₂ for grandfathered EGFs in an EGFP. This is consistent with the commission's longstanding policy to not treat certain facilities as being "permitted" simply because the facilities are consolidated into an existing permit. For example, a facility that was originally authorized by an exemption will continue to be authorized under the exemption even though the exemption is consolidated with an NSR permit during an amendment or at renewal. Since the Legislature passed SB 7 and SB 766 during the same session, the commission believes that it is appropriate to review the grandfathered facilities and the emissions of contaminants not addressed by SB 7 from a grandfathered EGF using the VERP process. SB 766 provides specific control and other requirements for the permitting of grandfathered facilities. In order to provide an option for the complete permitting of grandfathered EGFs under the TCAA, §116.910(e) provides that emissions of air contaminants other than NO _x , SO ₂ , and PM may be permitted by an EGFP if the grandfathered EGF meets the requirements of the VERP program. Section 116.910(e) does not require grandfathered EGFs to permit emissions other than NO _x , SO ₂ , or PM. The choice to permit other air contaminants from grandfathered EGFs or grandfathered non-EGFs remains with the applicant. The rule provides that if those emissions or non-EGFs are to be permitted, they will be reviewed using the VERP process. Section 116.913(a)(1)(C) has been deleted. A new §116.913(a)(2) and (3) is included in the final rule. Section 116.913(a)(2) provides that an EGFP may permit emissions of all other air contaminants from grandfathered EGFs, provided the EGFs meet the requirements of the VERP program. Section 116.913(a)(3) allows grandfathered EGFs to consolidate a VERP with an EGFP.

EPA commented that §116.910(e) states that "other contaminants may be permitted ...." EPA-APD asked if this means that a facility can remain grandfathered for VOC, PM, CO, and lead. Secondly, EPA-APD stated that it appears that §116.913(a)(1)(C) requires inclusion of these contaminants in the permit.

The permitting program established by SB 7, which is contained within the TUC rather than the TCAA, addresses only emissions of NO _x , SO ₂ , and, by including a standard for opacity, PM. Other pollutants, such as VOC and CO, were not addressed and therefore, are not required to undergo a permitting process under TUC, 39.264. Because the TCAA requires that facilities rather than pollutants be permitted, the EGF itself would remain grandfathered since not all emissions from the EGF would have been through a permit review process. In order to facilitate the permitting of grandfathered EGFs under the TCAA, §116.910(e) provides that emissions of air contaminants other than NO _x , SO ₂ , or PM may be permitted by an EGFP if the grandfathered EGFs meet the requirements of Chapter 116, Subchapter H, relating to VERP, which provides specific control and other requirements for the permitting of grandfathered facilities. Since the Legislature passed SB 7 and SB 766 during the same session, the commission believes that using the VERP process is appropriate to review the pollutants not addressed by SB 7. The adopted rule does not require owners or operators to permit the other pollutants from grandfathered EGFs. This is an option that may be exercised by the owner or operator. As stated previously in this adopted preamble, TUC, §116.913(a)(1)(C) was deleted.

EPA-ARD commented that clarification is needed in §116.911(a) regarding the definition of "authorized representative" and asked if this is the same person as "authorized account representative."

The authorized representative referred to in §116.911(a) is any person who is authorized to sign a form PI-1-U on behalf of the applicant. This requirement is consistent with §116.111, concerning general applications for permits under Chapter 116. The "authorized account representative" is the person who is authorized to transfer or otherwise manage allowances under Chapter 101 concerning the EBTA. The rule has not been revised in response to this comment.

Reliant commented that references to other applicable requirements (i.e., nonattainment, PSD, and §112(g)) are unnecessary and should be deleted. However, if retained, Reliant recommended that the language be revised to clarify that these programs would apply only if the EGF is undergoing a modification or other action triggering applicable requirements. B&P commented that §116.911(a)(3) and (4) should simply state that the proposed Subchapter I cannot be used to authorize construction or operation of a new source or a modification of an existing source. EPA-APD commented that §116.911(a)(3), (4), and (5) require an EGF to comply with applicable requirements of nonattainment review, PSD, and reconstructed major sources. The commenter stated that these provisions apply to new and modified sources and do not appear to apply to "grandfathered sources," and that these provisions may apply to sources which elect to opt into the program. EPA- APD further commented that first, these sections must also ensure that an electing source continues to meet all applicable provisions. Secondly, the TNRCC must add "applicable requirements of the Texas State Implementation Plan including such provisions as reasonably available control technology."

Lloyd Gosselink commented that §116.913(a)(9) should be deleted, because NSPS requirements are imposed on facilities that were constructed or modified after the publication of the applicable standard. The commenter also stated that §116.913(a)(10) should be deleted, because NESHAPS requirements are imposed on facilities that were constructed or modified after the publication of the applicable standard. Lloyd Gosselink also commented that §116.913(a)(11) should be deleted, because the requirements for NESHAPS for source categories are imposed on facilities that were constructed or modified after the publication of the applicable standard.

The commission has revised the rule in response to these comments. Section 116.911(a)(3)-(5)and §116.913(a)(9)-(11) have been deleted. These paragraphs dealt with NSPS, NESHAPs, NESHAPs for source categories, nonattainment review, PSD review, and construction or reconstruction of major sources of hazardous air pollutants. The commission agrees that TUC, §39.254 does not require EGFs to address the applicability of, or compliance with, federal standards as a condition of obtaining an EGFP or for participation in the EBTA. However, even though these paragraphs have been deleted, EGFs must still comply with these federal standards, if they are applicable. If, during the review of an application for an EGFP, the commission discovers that an EGF is out of compliance with any federal standards, the commission will initiate the appropriate enforcement action.

CSW, Entergy Services, and AECT commented that §116.911(a)(1) should be deleted in that such requirements are adequately addressed in §116.914 except for cases where alternative monitoring methods are used. CSW also commented that §116.914(d) should be revised to require submission of information to support alternative monitoring requests as soon as possible, but not later than May 1, 2002.

The commission has revised §116.911(a)(1) in response to this comment to clarify that an application must contain sufficient information for the commission to evaluate the proposed monitoring. The commission does not believe that this subsection should be deleted, since information is needed to know what emissions monitoring and reporting requirement the applicant has chosen. In addition, if the applicant is submitting a plan to comply with §116.914(d) (now §116.914(b)), it is necessary for the commission to review and approve the monitoring plans. The commission believes that the initial application submitted by September 1, 2000 should include contain sufficient detail regarding alternative monitoring requests. The commission needs sufficient time to review all monitoring proposals to ensure consistency and reliability. During the application review process, the commission will work with applicants to further refine the alternative monitoring proposal as necessary. The commission has not revised §116.914(d) (now §116.914(b)) in response to this comment.

AECT and Entergy Services commented that §116.911(a)(6) should be deleted because the proposed §116.911(a)(6) does not relate to grandfathered facilities, but rather to the use of standard permits described in §116.915 for pollution control projects. The commenters stated that in many instances, use of the §116.915 standard permit will not occur by September 1, 2000, the date the SB 7 permit application is due. Therefore, it will not be possible in many cases to include in the SB 7 permit application the information requested in §116.911(a)(6). B&P commented that in §116.911(a)(6), there is a reference to §116.915(b)(2), which does not exist. Also, B&P commented that §116.911(a)(6) is not necessary because there should be no rules that require air quality impacts analysis where there is an increase in emissions. TXU also commented that §116.911(a)(6) should be deleted because that language is not supported by §39.264 of SB 7. SB 7 does not impose any type of control technology, but specifically allows flexibility to determine what controls, if any, will be used to achieve necessary reductions. For the same reason, Reliant commented that certain parts of §116.915 should be revised to be consistent with §116.617 (Standard Permit). Specifically, §116.915 deviates from §116.617 in two respects. First, the review time should be 30 days, not the proposed 45 days; second, the proposal omits the language allowing for emission increases associated with a derate resulting from the installation of control equipment. Reliant commented that the proposed §116.915(d) does not have a counterpart in §116.617, and should be deleted, or state that these federal requirements apply if the EGF is undergoing a modification or other action triggering review under these requirements.

The commission has deleted §116.915 from the adopted rules in response to these comments. The commission will withdraw this proposed section. Since Chapter 116, Subchapter F, §116.617, Standard Permits for Pollution Control Projects, already provides the procedures for installing pollution control projects, it will simplify the adopted rule to include a cross-reference in §116.911(a)(2) to specific sections in Chapter 116, Subchapter F. The commission has revised §116.911(a)(6) (now §116.911(a)(3)) to delete the reference to §116.915 and to refer to the new §116.911(a)(2), regarding controls. This paragraph is necessary, because the commission may require modeling or monitoring to ensure public health and safety when evaluating proposed controls which cause an increase in emissions.

CSW, Reliant, TXU, Entergy, Entergy Services, B&P, Group A, AECT, and CPS commented that §116.911(a)(2) should be deleted, because that language is not supported by §39.264 of SB 7. The commenters stated that SB 7 does not impose any type of control technology, but specifically allows flexibility to determine what controls if any will be used to achieve necessary reductions.

The commission agrees that the TNRCC cannot require a grandfathered or electing EGF to use any specific control technology to ensure that their actual emissions do not exceed their allotted allowances. However, the commission does believe that if controls are going to be used to meet their emission requirements, the commission must ensure that the requirements of §116.911(2) are met. The language in §116.911(a)(2) has been revised to reference §116.617, regarding the requirements for pollution control projects, which will provide the commission sufficient information on any proposed emission controls. The requirements in §116.617 are intended to allow for the addition of new controls in a streamlined manner while ensuring that any associated emission increases will not cause adverse off-property health impacts.

EPA-ARD commented that §116.911(b) would be clear if stated in the active voice, and recommended the following language: "The owner or operator of a grandfathered EGF must submit an application for a permit on or before September 1, 2000." EPA-ARD also commented that "Grandfathered EGF" is not defined.

The commission agrees that the suggested language is clearer, and has revised the rule. The revised language is now in §116.911(c). The commission has also defined the term "Grandfathered EGF" in §116.18(9).

B&P commented that §116.911(c) should be revised to provide that applications for EGFP must be submitted under the seal of a professional engineer (P.E.) only when the capital cost of the project is greater than $2 million as provided in §116.110(e). AE questioned the need for a P.E. seal (in §116.911(c)) on a streamlined application, and stated that a P.E. seal may be required if the applicant chooses an alternate means of demonstrating compliance, such as one that would require specific engineering calculations.

The commission agrees that submittal of an EGFP application under the seal of a licensed P.E. should be done only in accordance with §116.110, as was the intent of the proposed §116.911(c). The commission has reworded this concept to clarify the intent, and moved the language to §116.911(d).

B&P commented that §116.912(a) states that electing EGFs shall submit an application "to authorize" NO _x and SO ₂ emissions. The commenter stated that the TNRCC needs to revise this language, since electing EGFs are already authorized under their NSR permit.

The commission agrees that electing EGFs already had authorization to emit NO _x and SO ₂ ; however, submitting an application under Chapter 116, Subchapter I is requesting a new authorization for NO _x , and if applicable SO ₂ . This authorization is necessary to allow the electing facility to obtain allowances and to participate in the EBTA. The commission believes that this is consistent with the requirements of TUC, §39.264(i). Therefore, the rule has not been revised in response to this comment. The commission notes that the NSR authorization for the NO _X , and if applicable, SO ₂ and PM from electing EGFs continues in effect as enforceable permit conditions. Section 116.912(c)(1) and (2) was moved to §116.911(a)(3) in order to consolidate the application requirements for grandfathered and electing EGFs.

EDF commented that §116.912(b) allows electing EGFs to opt out of the program, and that this is not allowed in SB 7, but appears to have been added to offer additional flexibility to utility companies. The commenter stated that facilities have ample time to decide whether or not to opt in, and that this provision is not necessary. EDF commented that if the TNRCC chooses to revise the provision, the commission should allow electing EGFs to opt out only before the first control period. One individual commented that once an EGF opts into the program, it should always be in.

The rule has not been revised in response to these comments. The commission agrees that TUC, §39.264 does not expressly provide for electing EGFs to opt out of the program. However, opting out is not prohibited. Since electing EGFs are voluntarily participating in the program and are already authorized by a NSR permit, emissions reductions will not be jeopardized by allowing opting out. The commission believes that it is appropriate to allow electing EGFs to notify the commission of the decision to opt out prior to the beginning of the next control period. As the implementation of the permitting and allowance program proceeds, future rules and regulations may require operational changes at electing EGFs that may not be consistent with its allowances. Further, electing EGFs may modify a facility, thereby making its participation impracticable. The commission believes that it is appropriate to give this flexibility to an owner/operator who voluntarily participates in this program. The provisions for opting out of the program are now in §116.912(a).

B&P commented that §116.912(b)(1) and (2) should be replaced with the statement that an electing EGF's decision to opt out will become effective at the beginning of the control period following notification of the TNRCC. The commenter also stated that proposed §116.912(b)(3), (4), and (6) should be revised so that each begins with the statement, "once an EGF has opted out."

The provisions in §116.912 have been reorganized in response to this comment. The commission agrees that the rule should address when the decision to opt out will become effective and has included that language.

EPA-APD commented that §116.913(a)(1)(B) should clearly define a coal-fired EGF that is subject to limitations of SO ₂ . The commenter stated that it is clear that the rule applies to EGFs that fire 100% coal, but that the rule should further clarify whether these requirements apply to EGFs which fire coal in combination with other fuels and EGFs which are capable of, but not presently firing coal.

The commission has not revised §116.913(a)(1)(B) in response to the comment. The commission agrees that it is appropriate to define "coal" and "coal-fired," and has revised §101.330 and §116.18 to include the following definitions: (1) "Coal" means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society for Testing and Materials Designation ASTM D388-92 "Standard Classification of Coals by Rank" (as incorporated by reference in Title 40 Code of Federal Regulations, §72.13 (effective June 25, 1999)); (2) "Coal-fired" means the combustion of fuel consisting of coal (as defined in §116.18(3)) or any coal-derived fuel (except a coal-derived gaseous fuel with a sulfur content no greater than natural gas), alone or in combination with any other fuel. The definition is independent of the percentage of coal or coal-derived fuel consumed during any control period.

EPA-APD commented that it is not clear how §116.913(a)(2) differs from §116.913(a)(1), and that if the intent is to consolidate for sources other than an EGF, e.g., a non- related boiler, it may be more clear to include the distinction in the rule.

Proposed §116.913(a)(2) (now §116.913(a)(3)) provided that the owner or operator of grandfathered facilities could consolidate the EGFP with a VERP issued under Chapter 116, Subchapter H. Proposed §116.913(a)(1) set out the applicability of the EGFP and stated that it authorized NOx from all grandfathered or electing EGFs and, where applicable, SO ₂ . Section 116.913(a)(1)(C) provided that emissions from EGFs besides NO _x or SO2 could be permitted using the requirements of the VERP program. The rule has been revised to separate §116.913(a)(1)(C) and to create a new §116.913(a)(2). This clarifies that the VERP requirements are not part of the mandatory EGFP program.

Reliant commented that §116.913(a)(5) should be revised to read that an EGF should hold a quantity of allowances for emissions of NO _x and SO ₂ in its compliance account by June 30 instead of May 1.

The commission agrees that allowing EGFs a period of time to reconcile their allowance accounts is appropriate, but has revised §116.913(a)(5) (now §116.913(a)(6)) to allow a 30-day reconciliation period rather than the 60-day period requested by Reliant. The commission believes that 30 days is sufficient for reconciliation. EGFs now have until June 1 after every control period to sell or purchase allowances in order to reconcile the amount of allowances in their compliance account to ensure that the number of allowances in their account are equal to, or exceed, the amount of emissions from the prior control period.

EPA-ARD commented that §116.913(a)(6) is unclear in defining who is responsible for submitting reports of NO _x and SO ₂ emissions to the permits section, and that quarterly reports may be more applicable so that sources can be evaluated each quarter instead of all at one time. Reliant commented that the report of annual actual emissions required by §116.913(a)(6) shall be submitted by August 1 instead of June 1. This would allow an additional 60 days for reconciliation. The commission revised §116.913(a)(6), now §116.913(a)(7), to refer to owners or operators. The commission believes that requiring reports of trades within 30 days of the trade, and the annual report, will provide sufficient time for a determination of compliance with the EBTA and the EGFP. The commission has revised §116.913(a)(7) to refer to the report required under §101.336(b), which requires a report of the amount of emissions of each allocated air contaminant during the preceding control period. This will clarify the reporting requirements, since it might have been unclear that the report under §116.913(a)(7) is the same as the report required under §101.336(b). The commission believes that submittal of these reports as quickly as reasonably possible is critical to expedite the review and reconciliation of compliance accounts to allot allowances for the next control period. The commission believes that 60 days is a reasonable time frame for this purpose; therefore, the rule has not been revised to allow the reports to be submitted by August 1.

B&P commented on §116.913(a)(6) and suggested that the word "prior" be added before "control period."

The commission agrees that §116.913(a)(6), now §116.913(a)(7), should be revised and has added the words "from the prior" before control period. This will clarify that the reports that are due are those that reflect the actual annual emissions from the previous control period.

EPA-APD noted that §116.913(a)(7) requires coal-fired EGFs to meet opacity limitations in 30 TAC §111.111. The commenter stated that for permitted EGFs which opt-in to the program, such EGF must also meet a more stringent opacity limit as specified in a permit issued by the TNRCC under Chapter 116 or issued by EPA under 40 CFR §52.21.

The commission agrees that if an electing EGF has an opacity limitation in its existing NSR authorization, the electing EGF must comply with the most stringent limitation. Further, the electing EGF cannot remove any existing control technology unless the modification is authorized under Chapter 116, Subchapter B. The rule was not revised in response to this comment; however, because §116.913 was revised for other reasons, §116.913(a)(7) is now §116.913(a)(8).

Reliant, Entergy, Group A, and CPS commented that §116.913(a)(8) should be deleted because SB 7 does not impose any requirement to use or not use any control technologies. Brazos Electric commented that this proposed section would prevent an electing EGF from switching to more efficient control technology or methodologies. Entergy commented that SB 7 establishes severe mandatory and permissive penalties to EGFs that exceed its allowances; thus, it is unnecessary and redundant for the proposal to contain these permit-related provisions. EPA-APD noted that §116.913(a)(8) does not permit removal of existing control technology, and that the rule should clarify whether replacement of equipment or retirement of a part of the source should be exempt from this provision.

The commission agrees that SB 7 does not impose any requirements regarding the use of control technology and has deleted §116.913(a)(8). The commission believes that a limitation of the removal of control technology is already addressed by §116.930, concerning modifications. An electing EGF is free to modify its facility as long as it obtains the appropriate NSR approval. Therefore, this provision has been deleted from §116.913(a)(8).

Lloyd Gosselink commented that §116.913(b) should be deleted, because this section fails to provide notice of what conditions might be anticipated by the TNRCC.

The commission has not revised the rule in response to this comment. The commission anticipates that special conditions may be necessary, for example, to include requirements for alternative monitoring plans or for controls that an applicant may propose to meet allotted allowances. The commission does not intend to use special conditions to place restrictions on grandfathered or electing EGFs that are more restrictive that the requirements of SB 7.

EPA-ARD commented that in §116.914(a)(1), it may be beneficial to refer to "the most current version" of 40 CFR Part 75 instead of a specific published version. This would alleviate the need to revise the regulation whenever federal rules are revised.

In order to ensure that EGFs can locate the most current version of state or federal regulations, the commission believes it is appropriate to include the date that the regulation or law was promulgated or last revised.

EPA-ARD commented that monitoring requirements in §116.914(c) for EGFs not subject to 40 CFR Part 75 should be identical to the monitoring requirements for EGFs that are subject to 40 CFR Part 75 to ensure that the amount of emissions that each allowance represents will be equivalent from one EGF to another. The commenter stated that in addition, EGFs that volunteer to join the trading program should likewise be required to monitor their emissions in accordance with 40 CFR Part 75 to ensure monitoring consistency and to not allow any cost advantage due to relaxed emissions monitoring requirements.

The commission has not revised the rule in response to this comment. However, §116.914 was reorganized for clarity. The prior §116.914(c) is now §116.914(b). The commission believes that it is appropriate to continue using 40 CFR Part 75 monitoring for those EGFs already subject to the Acid Rain Program. However, the commission does not see a basis for requiring EGFs not subject to the Acid Rain Program to implement monitoring that is more costly and beyond the requirements of 40 CFR Part 60. 40 CFR Part 60 as currently used with EGFs provides a sufficient level of accuracy that does not justify requiring the implementation of a new monitoring system. The commission believes that the use of the 1.1 adjustment factor will minimize differences in reported emissions.

EPA-ARD commented on §116.914(c) that if relative accuracies greater than 10% are allowed, an adjustment factor of 1.1 should be applied for monitors as in the OTC NO _x Budget Program.

The commission agrees, and the proposed and adopted rule reflect this understanding. In addition, the commission has added the descriptive phrase "adjustment factor" in relation to the 1.1 multiplier to §116.914(b)(2). The rule has not been revised in response to this comment.

AE commented that it is not clear in §116.914(c) whether the TNRCC is referring to all CEMS that exceed 10% relative accuracy, or just CEMS that are not subject to 40 CFR 75 that are over the 10% relative accuracy. The commenter stated that the sentence should be changed to read: "For all CEMS not subject to 40 CFR 75 that exceed 10% relative accuracy, actual emissions must be determined by multiplying the CEMS data by 1.1." However, Reliant commented that monitors on facilities not subject to 40 CFR 75 should not be required to apply the 1.1 factor, because 40 CFR 60 does not require it and is widely recognized and utilized by industry and regulatory agencies.

The commission agrees, and has reorganized §116.914(c), now §116.914(b)(2), to clearly indicate that the 1.1 adjustment factor only applies to CEMs data using a monitoring system other than 40 CFR Part 75. The 1.1 adjustment factor does not apply to CEMs data obtained under 40 CFR Part 75 because 40 CFR Part 75 invalidates any data with deviation greater than 10%.

To maintain consistency between 40 CFR Part 75 which allows adjustments up to 10% relative accuracy, any alternative monitoring including 40 CFR Part 60 will be required to apply the 1.1 adjustment factor. 40 CFR Part 60 allows up to a 20% relative accuracy, while 40 CFR Part 75 allows up to 10%. The 1.1 adjustment factor compensates for the 10% discrepancy. Therefore, the rule has not been revised to remove to remove the 1.1 adjustment factor.

EPA-ARD commented that §116.914(d) should provide standards for alternative monitoring such as what is listed under 40 CFR Part 75. EPA-APD commented that any monitoring alternatives must be approved by EPA or address why EPA approval is not applicable in this case.

In the adopted rules, the commission moved §116.914(d) to a new §116.914(b)(3) for purposes of clarity. The commission believes that the majority of grandfathered and electing EGFs are already using 40 CFR Part 75 or Part 60 monitoring, and that the majority of grandfathered and electing EGFs not required to monitor under 40 CFR Part 75 will rely on 40 CFR Part 60 for monitoring. If an EGF proposes a monitoring alternative outside of 40 CFR Part 75 or Part 60, the commission will review the proposal using existing NSR guidance for approving alternate monitoring systems. The commission does not believe that it is necessary to obtain EPA approval of alternative monitoring proposals. If an EGF which is already required to use either Part 75 or Part 60 monitoring, proposes to deviate from those programs, EPA approval must be obtained. The commission does not believe that many EGFs will propose alternative monitoring. In those instances, commission staff has ample experience and guidance to approve alternative monitoring systems. Many permits issued by the commission provide for case-by-case monitoring of discrete emission points or factors. These day-to-day decisions are not individually approved by the EPA. Since the alternative monitoring will likely be similar to Part 75 or Part 60 monitoring, the commission should be able to review and approve these alternative proposals. Commission decisions concerning alternative monitoring will be subject to public notice, since each EGFP will be subject to public notice prior to initial issuance. Interested persons and the EPA may comment on all the conditions of the permit including those relating to monitoring. The alternative plan could only be implemented after agency approval.

Reliant commented that §116.914(e)(3) should be removed because §116.914(e) sets forth the minimum requirements to be contained in a monitoring report. The commenter stated that subsection (e)(3) is ambiguous in this context and should be removed.

Section 116.914(e)(3), now §116.914(c), requires other information as needed; for example, periodic calibration results and maintenance logs. This requirement for supporting information was included to make clear that information submitted to support all monitoring protocols would need to be in sufficient detail to satisfy staff as to its effectiveness.

On the subject of public notification of an intent to apply for a permit, one individual stated that the commission should require contested case hearings in addition to notice and comment hearings. Two individuals suggested that the commission require the use of all media in an affected area for permit notice, and three more individuals stated that the commission should require publication across the state. An individual stated that the commission should require the printing of public notice in the newspaper of largest circulation in the area of the proposed permit and throughout the airshed.

TUC, §39.264(r) provides that applicants for EGFPs must publish notice in accordance with TCAA, §382.056. Section 382.056 outlines the procedures required of applicants for air permits. Permits must be noticed in a newspaper of general circulation in the municipality in which the facility is located or in the nearest municipality. If applicable, bilingual newspaper notice is required. In all cases, the applicant must post signs at the facility and the permit application must be available for review in a public place. In addition, HB 801, 76th Legislature, revised the public notice requirements for commission permits and provided additional opportunities for input, e.g., earlier notice to encourage public participation. In addition to the previous notice requirements, notices of intent to obtain a permit must include information about the opportunity to be included on mailing lists to receive updated on specific applications and the opportunity for public meetings. Because the commission believes that the notice requirements will provide ample information to ensure effective public participation, the rules have not been revised.

The commission is required to provide an opportunity for a public hearing and the submission of comment and send notice of a decision on an application in the same manner as provided by TCAA, §382.0561 and §382.0562. These sections set out the requirements for public participation for FOPs. Hearings for FOPs are not required to be conducted under the APA. Since EGFPs are to be issued using the same process as that for FOPs, hearings for EGFPs are also not required to be held under the contested case provisions of the APA. The commission does not believe it is necessary to hold two different types of hearings for EGFPs. If any facility authorized by an EGFP is modified, as that term is defined for state or federal purposes, the facility is required to obtain appropriate authorization under Chapter 116, Subchapter B. That modification would be subject to public notice and an opportunity to request a contested case hearing. The rules have not been changed in response to the comment.

One individual commented that the rules do not allow sufficient time for public comment on individual permits. The individual objected having to raise all issues by the end of the public comment period, and opposed the commission's not allowing incorporation by reference of hearing material, since this causes increased copying costs for citizens, discourages public participation, and wastes natural resources. The individual objected to the terms "reasonable" and "unreasonable" that the commission proposed in the evaluation of hearing requests.

The adopted rules allow 30 days for the submission of public comment and, if a hearing is requested and held, the comment period automatically extends to the end of the hearing. A 30-day comment period is used for all air permits, except renewals and concrete batch plants, that are subject to public notice and, in the experience of the commission, that time period has proved to be sufficient for interested persons to submit comments on permits. Further, TUC, §39.264 directs the commission to provide notice consistent with the requirements of the TCAA which requires a 30-day public comment period. In order for the commission to respond to comments in a timely manner, it is important for all comments to be submitted within a specified time period. This ensures that all comments are considered at the same time. The rules do not prohibit incorporation by reference of existing documents. Rather, they provide criteria that ensures that the documents supporting comments on permits are easily obtained and verifiable, since these documents will be included in the public record concerning an EGFP application.

Since TUC, §39.264 requires that public notice and opportunity for a hearing be done in the same manner as for FOPs, the commission is not required to hold a hearing if the basis of a request by a person who may be affected is determined to be unreasonable. Thus, reasonableness is the standard by which the commission must evaluate a hearing request on an EGFP. The commission believes that "reasonable" is a term that is circumstantial, but with a common understanding. The reasonableness of each request must be considered in light of the particular permit, the application, and the arguments raised by the protestant. For example, a hearing request based on water concerns would not be a reasonable basis for a hearing on an EGFP. Similarly, emissions from non-EGFs at a site would not be relevant to the issuance of an EGFP. Because reasonableness is very case-specific, the commission does not believe that it is appropriate to revise the rule in response to this comment.

AE commented that the term "APA" is not defined in §116.920(c).

The rule has not been revised in response to this comment. Section 3.2 of 30 TAC Chapter 3, Definitions, defines the Texas Administrative Procedure Act, Texas Government Code, Chapter 2001 and abbreviates this term as "APA." Section 3.1, Applicability, provides that words and terms, when listed in Chapter 3 and used in commission rules, shall have the meanings in that chapter, unless the context clearly indicates otherwise. However, a definition in Chapter 3 shall not apply to another chapter of the commission rules if the word or term is defined in that chapter. Since Chapter 116 does not define "APA" differently from the definition in Chapter 3, the term does not need further definition.

NFN commented on §116.920, that the publication of notice of permit hearing should not only be published in the local area, but also in the largest nearby metropolitan areas that might be affected. LWV-TX commented that the rules should require public notice in all news media in all affected areas, not just in the local newspaper. This will give citizens every opportunity for meaningful input into the permitting process. PC urged the commission to require real notice of public hearings to press in all affected areas, not just in the nearest municipality. The commenter stated that the rules only require that the local newspaper be notified, but surely this type of information could be given by the TNRCC to newspapers in communities affected by transportation and also made available on the website. One individual commented that the rules should require more public notice beyond a small ad in a newspaper and urged the use of community newspapers in addition to large newspapers in large cities. PC commented that public notice should be given in the municipality adjacent to a plant due to the fact that there are people who are affected who live upwind or downwind and are affected by transport of emissions from power plants.

The rule has not been revised in response to these comments. TUC, §39.264(r) requires applicants for EGFPs to publish notice of intent to obtain a permit in accordance with TCAA, §382.056, which outlines the procedures required of applicants for air permits. Permits must be noticed in a newspaper of general circulation in the municipality in which the facility is located or the nearest municipality. If applicable, bilingual notice is required. In all cases, applicants must post signs at the facility. HB 801 revised the public notice requirements for commission permits. In addition to the previous notice requirements, notices of intent to obtain a permit must include information about the opportunity to be included on mailing lists to receive updates on specific applications and the opportunity for public hearings. The commission is required to provide an opportunity for public hearing and for the submission of public comment and to send notice of a decision on the application in the same manner as provided by TCAA, §382.0561 and §382.0562, which are the hearing and notice requirements for FOPs. The commission believes that these procedures adequately notify persons who may be affected by emissions from EGFs. The adopted rule requires that notice be provided in the nearest municipality if no newspaper of general circulation is available in the municipality where the EGF is located. Since the commission is proposing additional SIP rules intended to address the issue of transport, the opportunity to comment on transport issues will occur during the public comment period on those rules instead of during the consideration of individual EGFPs. The rule has not been revised in response to this comment.

Reliant commented that §116.921(a) should be revised to require public notice only for grandfathered EGFs and not for electing EGFs, since they have already undergone public review for their existing permit.

The commission revised the provisions in Subchapter I, concerning the inclusion of NSR permits for electing EGFs in an EGFP. Because the NSR permit will now only be altered to include a reference to the EGFP, the provision in §116.920(c), concerning public notice, is no longer necessary. Only the EGFP will be subject to public notice and if necessary, it will include provisions from the NSR permit. The NSR permit itself will not be subject to public notice.

EPA-APD noted that under §116.921(a), the notice and comment hearing requirements only apply to the initial issuance of an EGFP. The commenter stated that the TNRCC should address why it is not requiring notice and comment hearing for subsequent revisions to the EGFP.

The rule has not been revised in response to this comment. Section 116.930 provides that modifications to EGFs must comply with Chapter 116, Subchapter B. Therefore, any modification to an EGF would have to be done under existing NSR permitting procedures. The NSR procedures utilize contested case hearings and not notice and comment hearings. Since §116.921 is specifically for initial issuance and §116.930 is for modifications to EGFs, the commission does not believe it is necessary to revise §116.921(a).

EPA-APD commented that §116.921(b) should define what is a "reasonable" or "unreasonable" request for hearing, and that if these terms are defined elsewhere in the regulations or in the statute, a cross-reference to the applicable definition or provision of the regulation or statute would be helpful.

TUC, §39.264(r) requires applicants for EGFPs to publish notice of intent to obtain a permit in accordance with TCAA, §382.056. The commission is required to provide an opportunity for public hearing, for the submission of public comment, and to send notice of a decision on the application in the same manner as provided by TCAA, §382.0561 and §382.0562, which are the hearing and notice requirements for FOPs. TCAA, §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 standard by which the commission must evaluate the basis of a hearing request. The commission believes that "reasonable" is a term that is circumstantial, and that the reasonableness of each request must be considered in light of the particular permit, the application, and the arguments raised by the protestant. For example, a hearing request based on water concerns would not be a reasonable basis for a hearing on an EGFP. Similarly, emissions from non-EGFs at a site would not be relevant to the issuance of an EGFP. Because reasonableness is very case-specific, the commission does not believe that it is appropriate to revise the rule in response to this comment.

AE commented that §116.921(e) states that a written transcript or tape recording must be made available to the public without stating which entity is responsible for providing this.

Because the hearings for EGFPs are notice and comment hearings, the commission does not anticipate using court reporters to create transcripts for the hearings. Commission staff will oversee each hearing and will create an audio recording of the proceedings. Copies of this tape can be obtained from the commission upon request. The commission will charge a reasonable fee to cover the cost of coping, the cost of the tape, and the transcription of the tape.

Reliant commented that §116.930 should be deleted or should clarify that other permitting options are available.

Section 116.930 provides that modifications to EGFs must comply with Chapter 116, Subchapter B. Subchapter B allows modifications under other chapters or subchapters, as appropriate. Therefore, any modification to an EGF would have to be done under NSR permitting procedures. The commission believes that this section is necessary to ensure that permit holders are aware of the process to modify EGFs and has not deleted the section in the adopted rule.

Subchapter A. DEFINITIONS